-------
TECHNICAL REPORT DATA
(Plrair rflJ Inurjctiuns on the it.tnt be/ort completing)
NO.
EPA/600/3-36/031g__
-i TITLE AMD SUBTITLE
User's Manual for the Integrated Air Pollution Control
System Design and Cost-estimating Model (Version
II); Volume I
5. BEPOHT OATg
6. PERFORMING ORGANIZATION CODE
7 AuTMOHlS)
P. J. Palmisano and B. A. Laseke
3. RECIPIENT'S ACCESSION NO.
PP.R7-l?77fi3-
September 1986
I. PERFORMING ORGANISATION REPORT NO
PN 3650-4
3 PERFORMING ORGANIZATION NAME AND AOOREiS
PE1 Associates, Inc.
P.O. Box 46100
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
11 CONTRACT7GRAPJT NO.
68-02-3995, Task 4
12 SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711
13 TYPE OF REPORT AND PERIOD COVERED
User's Manual; 10/84 - 5/86
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES AEERL project officer is Norrnan Kaplan. Mail Drop 63,
2556. Volume II is Appendix C (the IAPCS source listing). EPA-600/8-86-031
919/541-
c is
_the related disk.
is. ABSTRACT T-ne manual describes and is a guide to the user of Version II of the Integra-
ted Air Pollution Control System (IAPCS-II), a computerized simulation model for
estimating the costs and predicting the performance of sulfur dioxide, nitrogen oxi-
des, and particulate matter control systems for coal-fired utility boilers. It gives
the design bases of the modules comprising the model and the structure of the pro-
gram itself, as well as the bases for a number of model enhancements available to
the user. The model includes conventional and emerging technologies that effect pre-,
in situ, and post-combustion emission control. The model can accept any combination
of the technology modules built into the system. Interactions are reflected in a mater-
ial balance tabulation of the exit of each module. Alterations in the material balance
are used to account for integrated performance and cost effects. The emission con-
trol technologies contained in IAPCS-II can be selected in either isolated or integra-
ted configurations. IAPCS-II incorporates a number of enhancements to the design
premises of the emission control modules, as well as *.he model's user access and
versatility. Enhancements to the control modules involved upgrades to five modules:
wet desuli'urization, low-NOx combustion, limestone injection multistage burner
(LIMB), electrostatic precipitator, and fabric filter.
KEY WOHOS AND DOCUMENT ANALYSIS
DESCRIPTORS
b IDENTIFIERS'OPEN ENO6O TERMS
c. COSATi I icij Group
Pollution Coal
Cost Estimating Combustion
Mathematical Models Emission
Economics Sulfur Dioxide
Boilers Nitrogen Oxides
Utilities Particles
Pollution Control
Stationary Sources
Particulate
LIMB
Fabric Filters
13B
05A.04A
12A
05C
13 A
21D
21B
14G
0713
13 DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS ( Fins Report/
Unclassified
21 NO.CPPAGtS
135
20 SECURITY CLASS ( This page J
Unclassified
SI. PRICE
EPA Form 2220-1 (»-73)
-------
NOTICE
This document has been reviewed in accordance with
U.S. Environmental Protection Agency policy and
approved for publication. Mention of trade names
or commercial products does not constitute endorse-
ment or recommendation for use.
11
-------
ABSTRACT
The Integrated Air Pollution Control System (AIPCS) is a. computerized
simulation model developed for EPA1 a Air and Energy Engineering Research
Laboratory (AEERL) to estimate the costs and predict the performance of
sulfur dioxide (SC>2), nitrogen oxides (NOX), and paniculate matter (PM) emis-
sion control systems for coal-fired utility boilers. The model includes conven-
tional and emerging technologies that effect pre-. in situ, and post-combustion
emission control. The model can accept any combination of the technology "mod-
ules" built into the system. Interactions are reflected in a material balance tab-
ulation of .the exit of each module. Alterations in the material balance are used
to account for integrated performance and cost effects. The emission control
technologies contained in IAPCS can be selected in either "isolated" or "inte-
grated" configurations.
This version of IAPCS (I A PCS-II) was completed in April 1986. It incor-
porates a number of enhancements to the design premises of the emission
control modules as well as the model's user access and versatility. Enhance-
ments to the control modules involved upgrades to the wet flue gas desulfur-
ization (FGD) rr.odule, upgrades to the low-NOx combustion module, upgrades
to the limestone injection multistage burner (LIMB) module, and upgrades to
the electrostatic precipitator (ESP) and fabric filter (FF) modules. Other im-
portant enhancements to IAPCS-II include expanding the solid waste handling
and disposal mcdule, housing the model on a microcomputer (personal compu-
ter), providing EPRI and TVA economic premises, and expanding the user-
activated parameter file.
The User's Manual describes the second version of IAPCS. This manual
provides a guide to the user of the model. It presents the design bases of the
individual modules comprised by the model and the structure of the program
itself, as well as the bases for a number of model enhancements now available
to the user.
Since program "bugs" and other errors may be discovered by model users,
it is requested that the errors be conveyed to the AEERL project officer by mail
(U.S. EPA, MD-4. Research Triangle Park. NC 27711) or by phone (919/541-
2556). If and when the model is upgraded, the compiled version (diskette) will
be changed and dated to identify it. Users may contact the AEERL Technical
Information Service (phone 919/541-2218) to determine the latest version of the
model, and how to obtain it.
iii
-------
CONTENTS (continued)
Page
1. Summary of Installation and Operation Procedures
For IAPCS-II 7-1
8. References 8-1
Appendix A Parameter File Listing A-l
Appendix B Example Output B-l
Appendix C Program Source Listing (Volume II) C-l
FIGURES
Number Page
3-1 IAPCS-II Input Requirements 3-2
3-2 TVA Indirect Capital Cost Format 3-5
3-3 EPRI Indirect Capital Cost Format 3-5
3-4 Example of TVA Annual Cost Format 3-9
3-5 Example of EPRI Annual Cost Format 3-10
4-1 Bench-Scale SO2 Removal Performance Curve 4-27
4-2 Demonstration plant SO2 Performance Curve 4-28
6-1 General Flow Diagram of the IAPCS Program 6-4
6-2 Subroutine Tree Diagram 6-7
vi
-------
CONTENTS
Page
Figures iv
Tables v
Metric Equivalents vi
1. Background and Purpose 1-1
2. Capabilities of IAPCS-II 2-1
3. General Model Description 3-1
3.1 Input requirements 3-1
3.2 Cost formats 3-4
3.3 System files and routines 3-13
3.4 Output format arid options 3-19
3.5 Optimization and rerun 3-21
4. Description of IAPCS-II Technology Modules 4-1
4.1 Physical coal cleaning 4-1
4.2 Low-NO combustion 4-3
4.3 Limestone injection multistage burner 4-4
4.4 Spray humidification 4-6
4.5 Lime Spray Drying 4-11
4.6 Wet flue gas desulfurization 4-15
4.7 Dry sorbent injection 4-21
4.8 Electrostatic precipitator 4-31
4.9 Fabric filter 4-34
5. Integrated Characteristics of the System 5-1
6. Computer Program Structure 6-1
6.1 Program environment 6-1
6.2 Program structure 6-3
6.3 User information 6-6
6.4 IAPCS-II program listing 6-9
-------
TABLES
Number Page
1-1 IAPCS Control Modules 1-3
3-1 TVA Indirect Cost Format 3-6
3-2 EPRI Indirect Cost Format 3-7
3-3 Maintenance Labor and Material Cost Factors 3-11
3-4 Default Unit Costs Used in IAPCS-II 3-12
3-5~ Estimated Characteristics and Costs of Raw ana
Cleaned Coals 3-14
4-1 Estimated Alkaline Components of Coal By Rank 4-2
4-2 Design and Operating Parameters of LNC Module
of IAPCS-II 4-4
4-3 Design and Operating Parameters of LIME Module
of IAPCS-II 4-7
4-4 SO Captures of LIMB Module of IAPCS-II 4-8
4-5 Design and Operating Parameters of LSD Module
of IAPCS-II 4-16
4-6 Shawnee Model Design Parameters and Economic
Conditions 4-19
4-7 Design and Operating Parameters of FGD Module
of IAPCS-II 4-22
4-8 Typical Nahcolite Ore Composition 4-25
6-1 IAPCS-II Disk Files 6-2
vii
-------
METRIC EQUIVALENTS
Nonmetric units are used, for the most part, in this manual
for the reader's convenience. Readers more familiar with metric
units may use the following factors to convert to that system.
Nonmetric Times Yields metric
acre
Btu
Op
ft
ft-
ft:'
gal.
HP
in.
Ib
ton
yd2
yd3
4047
1.06
5/9(°F-32)
C.305
0.093
28.3
3.79
9.81
2.54
0.454
907.2
0.836
0.765
m2
kJ
°C
m
m2 .
L
L
kW
cm
kg
kg
m2
m3
via
-------
SECTION 1
BACKGROUND AND PURPOSE
The cost of installing and operating air emission control
equipment to meet sulfur dioxide (SO ), particulate matter (PM),
and nitrogen oxide (NO ) emission standards have grown signifi-
cantly and now represent a large portion of the total powerplant
costs. The significance of these costs has led to the emergence
of the concept of integrated environmental control of utility
powerplant air emissions within the last several years.
One logical means of addressing the design and operation of
an air emission control system is to consider that system as an
integral part of the powerplant. By optimizing the interactions
of control device^, the integrated control concept can effect the
necessary control level at a minimal cost.
The. Integrated Air Pollution Control System (IAPCS) is a
computerized simulation model developed for the Air and Energy
Engineering Research Laboratory (AEERL) of EPA to estimate the
costs and predict the performance of SO,.,, NO , and PM emission
control systems for coal-fired utility boiler?. The model in-
cludes conventional and emerging technologies that effect pre-,
in situ, and post-combustion emission control. The model can
accept any combinat-.cn of the technology "modules" built into the
system. Interactions are reflected in a material balance tabula-
1-1
-------
tion of the exit of each module. Alterations in the material
balance are used to account for integrated performance and cost
effects. The emission control technologies: contained in IAPCS
can be selected in either "isolated" or "integrated" configura-
tions .
The power of IAPCS lies in its ability to reflect integrated
effects of various control configurations. This allows the ana-
lyst to identify synergistic interactions and thus optimize per-
formance and cost in terms of integrated cost effectiveness. The
specific technologies that are contained in IAPCS are presented
in Table 1-1.
The first version of IAPCS (IAPCS-I) was developed in Novem-
ber 1983. This version was a mainframe computer model housed at
EPA's National Computer Center (NCC). The second verrion of
IAPCS (IAPCS-II) was completed in April 1986. This version in-
corporates a number of enhancements to the design premises of the
emission control modules as well as the model'3 user access and
versatility. Enhancements to the control modules involved up-
grades to the flue gas desulfurization (FGD) module (the latest
version of the Shawnee FGD model was incorporated; see Subsection
4.6, flue gas detulfurization); upgrades to the low-NO combus-
X
tion module (see Subsection 4.2, Low-NO Combustion); upgrades to
yi
the limestone injection multistage burner (LIMB) module (see
Subsection 4.3, Limestone Injection Multistage Burner); and
upgrades to the electrostatic precipitator (ESP) and fabric
1-2
-------
TABLE 1-1. 1APCS CONTROL MODULES
Pre-combustion
In sit'j
Post-combustion
Technology
Physical coal cleaning
Low-NO combustion
LIMD
ESP
Fabric filter
Spray humidification
Dry sorbent injection
Wet FGD
Lime spray drying FGD
Pollutant(s) contro11ed
N0y
A
so2
PM
PM
SO,
S02/PMC
S02/PMC
a The product coal is de-ashed and desulfurized. Some NO reduction is re-
flected du* to alteration of the combustion conditions and nitrogen content
of the clea-ned coal.
Spray humidific?tion improves PM collection by conditioning the gas up-
stream of the ESP. Some S02 may be absorbed by the spray water.
c Some FGD configurations provide supplemental PM control in the scrubbing
. system.
Removal of PM (and the S02 reaction solid products) occurs in the spray
dryer chamber and downstream PM control system.
1-3
-------
filter (FF) modules (see Subsection 4.8, Electrostatic Precipita-
tor, and Subsection 4.9, Fabric Filter). Other important en-
hancements to IAPCS-II include expanding the solid waste handling
and disposal module, housing the model on a microcomputer (per-
sonal computer), providing EPRI and TVA economic premises, and
expanding the user-activated parameter file.
This User's Manual describes the second version of IAPCS.
This manual provides a guide to the user cf the model. It pre-
sents the design base.s of the individual modules comprised by the
model and the structure of the program itself, as well as the
bases for a number of model enhancements now available to the
user.
The manual is organized into seven sections {Volume I) and
three appendices (Volume I and Volume II). Section 2 describes
the capabilities of the model. Section 3 describes the user
input requirements and output format and options. Section 4
describes the specific design bases used for each of the control
modules. Section 5 presents the integrated aspects of the model.
Section 6 describes the program environment and structure and
provides user information. Section 7 describes step-by-step
procedures to operate and to troubleshoot the model in the event
of operation problems. Appendices A, B, and C present a listing
of th? parameter files, example hardcopy output, and a program
listing, respectively.
1-4
-------
SECTION 2
CAPABILITIES OF IAPCS-II
The IAPCS-II design and cost-estimating model was developed
to estimate the cost and performance of air emission control
equipment for coal-fired utility boilers. The model includes
both conventional and emerging control technologies. The follow-
ing is a listing of the control technologies (modules) included:
° Physical coal cleaning (PCC)
0 Low-NO combustion (LNC)
0 Limestone injection multistage burner (LIMB)
0 Electrostatic precipitator (ESP)
c Fabric filter (FF)
0 Spray humidification (SH)
° Dry sorbent injection (DSI)
0 Lime spray drying (LSD)
0 Wet flue gas desulfurization (FGD)
As designed, the model accepts any combination of these
technologies. System interactions are reflected in a material
balance tabulation at the exit of each module. The PCC, LNC, and
LIMB modules (pre-combustion and in situ technologies) are all
applicable to the boiler unit; the effects of these devices are
accounted in a material balance column reflecting flue gas condi-
tions at the air heater exit. An "uncontrolled" material balance
column is calculated before the boiler control modules are ac-
counted so that the net effect of emission control can be calcu-
lated on a system basis. Output from the model reports the
reduction in S02, PM, and NO emissions; associated capital and
-------
annualized costs of such reductions; and associated cost-effec-
tiveness values (dollars per ton of pollutant removed across the
entire emission control system).
A parameter file and a user-prompted optimization routine
are two important features of this model. As each module was
developed, the important design parameters were included in a
parameter file. These parameters may be. subsequently changed by
the user for a given application. The parameter file is designed
to permit the user to modify the important values to reflect
those of choice.
The first run of the model for a user-specified control
configuration makes use of default performance values for each
module (i.e., the costs reflect the design-specified maximum
performance levels of the control equipment). When the output
from the initial run has been completed, the user can exercise
the option to enter into an optimization routine which permits
sequential revision of the performance levels of certain indi-
vidual modules for a single pollutant. The user must iterate
runs to effect a desired pollutant mass emission rate/overall
system removal efficiency.
The model also includes certain other important design fea-
tures. One of these includes an optional "debug" output in
identifying interim calculated values for each control module in
control system. An iteration of the input for each run is pro-
vided first to ensure that cost and performance data are attached
to the specifics and date of that run.
2-2
-------
The model is available as a computer program through NTIS in
the form of MS-DOS formatted microcomputer diskettes (5.25-in.
(double-sided) floppy disks). The model is structured in Micro-
TM
soft FORTRAN 77 (not necessary to run the program), and it can
be used on an IBM PC/XT or AT (or compatible) microcomputer.
2-3
-------
SECTION 3
GENERAL MODEL DESCRIPTION
This section describes the overall scope of IAPCS-II from
its input requirements, cost formats, files and routines, and
output formats to its optimization.
3.1 INPUT REQUIREMENTS
A typical run entails a number of requests for input from
the user. The input questions are presented in Figure 3-1.
3.1.1 Input Format
These items either provide basic data for the given run or
specifically affect the outcome of the run. Input requests
include boiler data, fuel characteristics, and the control con-
figuration. The boiler data are used to quantify the unir/
system generating performance. The coal characteristics are used
to estimate the emissions from firing a given quantity of coal,
and the user specifies the controls to be utilized. The firing
configuration (i.e., wall- or tangentially fired) is used to
estimate uncontrolled emissions and to specify the appropriate
N0,r control device from the LNC module.
With regard to requested boiler data, boiler size is limited
to single units from 100 to 1300 MW. The capacity factor is used
in annual cost calculations. The bottom ash configuration is
3-1
-------
ENTER FIRING CONFIGURATION OF BOILER:
1. WALL-FIRED
2. TANGENTIALLY FIRED
ENTER BOILER SIZE IN MW>
ENTER BOILER CAPACITY FACTOR (%}>
ENTER CONSTRUCTION STATUS(1=NEW, 2=RETROFIT)>
ENTER DATE AND COMMERCIAL OPERATION OF BOILER>
ENTER TEMPERATURE AT AIR HEATER EXIT>
ENTER ACFM AT THE AIR HEATER EXIT:ENTER 0 TO CALCULATE>
ENTER SELECTION OF TYPICAL COAL(l) OR SPECIFIC CHARACTERISTICS(2}>
ENTER COAL CHOICE:
1. BITUMINOUS - PENNSYLVANIA
2. BITUMINOUS - OHIO
3. BITUMINOUS - WEST VIRGINIA
4. BITUMINOUS - ILLINOIS
5. SUBBITUMINOUS - WYOMING
6. LIGNITE - NORTH DAKOTA>
ENTER COAL CLEANING LEVEL:
1. RUN-OF-MINE SORTED AND SCREENED
2. PHYSICAL COAL CLEANING>
ENTER BOILER BOTTOM ASH CONFIGURATION:
1. DRY-BOTTOM
2. WET-BOTTOM>
SELECT IAPCS CONFIGURATION FROM THE FOLLOWING:
MODULE POLLUTANT(S)
1. LOW-NO BURNERS, OVERFIRE AIR NO
2. LIMB NOX, SO,
3. COAL CLEANING PAPJ, S09
4. SPRAY HUMIDIFICATION (SH) PART, SO-
5. ESP PART i
6. FABRIC FILTER (FF) PART
7. LIME SPRAY DRYING (LSD) S0?
8. LIMESTONE/LIME FGD (FGD) SO,
9. DRY SORBFNT INJECTION (DSI) SO,
THE FOLLOWING RULES APPLY TO SELECTING A CONFIGURATION:
1 - METHOD 4 MAY NOT BE USED WITH METHODS 7 or 9
2 - METHOD 5 OR 6 MAY NOT PRECEDE (BUT MAY FOLLOW) 7 OR 9
3 - METHODS MUST BE IN ASCENDING NUMERICAL ORDER (EXCEPT AS IN 2 ABOVE)
4 - METHODS MAY NOT BE REPEATED IN THE SAME SYSTEM. (GENERALLY THE POST
COMBUSTION MODULES FOLLOW THE GAS PATH)
ENTER OPTION NUMBERS IN ORDER (SEPARATE BY COMMAS)
SELECT OUTPUT OPTION:
1. OUTPUT TO PRINTER
2. OUTPUT TO SCREEN
3. BOTH ABOVE
Figure 3-1. IAPCS-II input requirements.
3-2
-------
used in emission estimating. Flue gas temperature is an import-
ant parameter for flue gas material balance calculations and the
design of all subsequent control modules.
With regard to requests concerning coal characteristics,
coal may be identified by either of two mechanisms. The user may
select a "typical coal" or input the characteristics of any spe-
cific coal to be used. So that the fuel cost premium and emis-
sions from firing cleaned coal can be evaluated, these properties
must be input before and after cleaning. If the user selects a
standard coal, the coal-cleariing level input allows the program
to use run-cf-mine (ROM) or cleaned coal characteristics for
these standard cases.
3.1.2 Default Values - The Standard Case Option
The user may opt for ar interactive run or enter the name of
an input batch file on disk. Depending on the selected option:
0 The user will specify data for specific runs via the
questions presented in Figure 3-1.
0 The model will search a data disk for a specific input
file and use it to initiate the run.
Any number of input files are possible (up to the maximum
that are stored on a disk). This option permits a run to be
input very quickly, and it requires only two responses from the
user. Standard case runs are for demonstrational purposes, but a
sequential batch of input files can be used to make a series of
runs.
3-3
-------
3.2 COST FORMATS
Emission control cost estimates must be comparable in terms
of base year dollars, cost categories, and overall content (i.e.,
cost components). To facilitate comparisons, IAPCS-II has adopt-
ed the bases and format of cost estimation used by the Tennessee
T
Valley Authority (TVA)" and the Electric Power Research Institute
2
(EPRI) , which are generally accepted as "incV.istry standards."
3.2.1 Capital Cost Formats
The format for the direct capital costs entails one or
several line items for each of the control modules in a given
control configuration. Major components for a given module are
itemized.
Indirect components, which are an integral part of capital
cost estimates, are standardized and presented at the system
level in IAPCS-II. The two formats, TVA and EPRI, are presented
in Figures 3-2 and 3-3, respectively.
Interpretation of the TVA and EPRI guidelines resulted in
the assignment of percentages in IAPCS-II for each of the indi-
rect components for each of the control modules. The TVA indi-
rect costs are calculated as percentages of the total direct
investment (except for contingency, working capital, interest
during construction, and allowance for startup and modifica-
tions) . The EPRI indirect costs are calculated as a percentage
of the process capital cost (except for the preproduction costs,
inventory capital, and land). The IAPCS-II values for indirect
costs in the TVA and EPRI formats are provided in Tables 3-1 and
3-2, respectively.
3-4
-------
INDIRECT INVESTMENT
Engineering design and supervision
Architect ar.d 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
TOTAL CAPITAL INVESTMENT
Figure 3-2. TVA indirect capital cost format.
PROCESS CAPITAL
General Facilities
Engineering/Home Office
Project Contingency
Process Contingency
Sales Tax
TOTAL PLAN COST
Royalty Allowance
Preproduction Costs
Inventory Capital
Initial Catalyst
Land
TOTAL CAPITAL REQUIREMENT
Figure 3-3. EPRI indirect capital cost format.
3-5
-------
CO
I
CD
Indirect component
Engineering design
and Supervision
Architect and
engineering
contractor
Construction
expense
Contractor fees
Contingency
Total (% of TDI)
Royalties
Working capital
Interest during
construction
Allowance for startup
and modifications
Lond9
Di-vk^r-^M^i^-^i^ir* r\f +^4-^7 r\
LNC
6
1
14
4
20
50
0
c
4.84d
10
NAh
•i v rt ^» +• -i r\ v / ."*
LIMB
8
3
18
6
20
62
0
c
4.84d
10
S4700/
acre
r- -f rvn-i r\$- i~\ v i-
hGU
6-8
1-3
14-18
4-6
10
37.5-
48.5
0
c
15. 6e
8
$4700/
acre
~ r\ n +• ^ c-
LbU
7
2
16
5
20
56
0
c
15. 6e
10
S4700/
acre
A t~ c- 1 1 rr
UM
6
1
14
4
20
50
0
c
4.84d
10
$47007
acre
irv f t _ »/r» a v
bH
6
1
14
4
20
50
0
c
4.84d
10
NA
r r\ n c f1 v»i i f
tiK
6
1
14
4
20
50
0
c
15. 6e
10
S4700/
acre
"•f'T^n £-/~lini
i-|-
6
1
14
4
20
50
0
c
15. 6e
10
$4700y
acre
rl i t 1 n
noted.
Percentage of direct plus indirect.
c 1 month of raw materials
1.5 months of conversion costs
1.5 months of plant and administrative overhead
3" of tutal direct investment
Assumes 3-year construction schedule.
Percentage of direct plus indirect plus
contingency.
9 TVA's $6000/acre (1985 dollars)
o'eescalated by 8-1/2 % per year.
Not applicable.
Metric equivalents are given in front
ratter of this manual.
-------
TABLE 3-2. LPRl INDIRECT COST FORMAT*
Indirect Component
General facilities
Engineering and home
office fees
Project contingency
Process contingency
Sales tax
Total % of process
capital
Royalty allowance
Preproa'uctioo costs
Inventory capital
Initial catalyst
Landd
LNC
10
1C
15
10
0
45
0
b
c
C
NA
LIMB
10
10
30
30
0
80
0
b
c
0
$62157
acre
FGD
10
10
15
10
0
45
0
b
c
0
$62157
acre
LSD
10
10
15
15
0
50
0
b
c
0
$62157
acre
DSI
10
10
20
20
0
60
0
b
c
0
$62157
acre
SH
10
10
20
20
0
60
0
b
c
0
NA
ESP
10
10
15
10
0
45
0
'0
c
0
$62157
acre
FF
10
10
15
10
0
45
0
b
c
0
$621'
acre
Percentage of process capital cost, except as noted.
1 month of fixed operating cost
1 month of variable operating cost
2% of total plant investment
Fuel cost (see text)
" 60-o'ay supply of consumables.
d $5500 in 1980 dollars escalated at 8.5%/yr = $6215 in mid-1982 dollars (based on EPRI's apparent
escalation rate).
NA - Not applicable.
-------
\
\
3.2.2 Annual Cost Formats
As in the case of capital cost estimates, TVA and EPRI use
different formats and bases to present annual costs- Figure 3-4
presents TVA's format and Figure 3-5 presents EPRI's format.
Each format stops short of providing the particular method and
line item components used for levelizing the costs. These proce-
dures are described later (in Section 3.3.6).
The maintenance labor and materials estimated by the TVA
format for a given system are actually percentages of the total
direct investment rather than man-hours and actual material
estimates for FGD. This idea was expanded to include all IAFCS-
II modules; the percentages used are presented in Table 3-3.
These sane percentages are used to estimate maintenance
labor and materials in the EPRI format. The number is distrib-
uted as 40 percent labor and 60 percent materials, and the labor
nan-hours are back-calculated.
In the EPRI format, annual O&M costs are presented as a
fixed and variable component. Equations presented in the EPRI
2
Technical Assessment Guide provide the basis for calculating
these components.
3.2.3 Unit Costs
Costs of labor, certain materials, reagents and chemicals,
and waste disposal are specified in Table 3-4 for TVA and EPRI
cost formats. Calculations performed by IAPCS-II yield the
quantities of labor, materials, and waste generated by a specific
configuration, and unit costs are applied to estimate the annual
cost.
3-J
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Direct Costs - First Year
Raw materials
Limestone
Lime
Nahcolite
Annual
quantity
Tons
Tons
Tons
Unit
cost, $
/ton
/ton
/ton
Total annual
cost
Conversion costs
Operating labor and supervision
System
Solids, disposal facility
Solids disposal cost
Wet
Dry
Utilities
Process water
Electricity
Reheat
Maintenance
Labor and material
Analysis Man-h
Total conversion cost?,
Total direct costs
Indirect Costs - First Year
Overheads
Plant and administrative
Marketing (10% of byproduct sales)
Man-h
Man-h
Tons
Tons
Tons
103 gal
kWh
106Btu
/man-h
/man-h
/ton
/ton
/ton
/1Q3 93!
/kWli
/106Btu
/man-h
Total first-year operating and maintenance costs
Figure 3-4. Example of TVA annual cost format.
3-9
-------
Operating S maintenance costs
Operating labor
System
Solids disposal
Maintenance labor
Maintenance material
Admin. & support labor
Solids disposal
Wei;
Dry
Fixed component
Variable component
Consumables
Limestone
Lime
Nahcolite
Water
Reheat
Electricity
Total O&M Costs
Annual
quantity
Man-h
Man-h
Man-h
$
S
Tons
Tons
Unit
cost;$
/man-h
/man-h
40?
602
30°* O&M
/ton
/ton
Total annual
cost
Tons /ton
Tons /ton
Tons /ton
102gal /103gal
106Btu /105Btu
kWh Mills/kWh
Figure 3-5. Example of EPRI annual cost format.
3-10
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TABLE 3-3. MAINTENANCE LABOR AND MATERIAL COST FACTORS
Maintenance labor
and materials LNC LIMB FGD LSD PS I SH ESP FF
TVA factors (percent 2 4 7-9a 5-7a 4244
of total direct
investment)
EPRI factors (percent 2 4864244
of total process
capital)
Decreasing from high to low with increasing boiler size. For waste disposal,
a fixed 3 percent of the waste disposal equipment plus construction cost is
used.
3-11
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TABLE 3-4. DEFAULT UNIT COSTS USED IN IAPCS-II
(June 1982 dollars)
Item TVA EPRI
Lime, S/ton 71.49 47.47
Limestone, S/ton 11.99 13.56
Nahcolite, 5/ton
Calcitic hydrate 71.49 70.00
Dolomitic hydrate 75.00 75.00
Calcitic pressure hydrate 85.00 85.00
Dolomitic pressure hydrate 90.00 90.00
Operating and supervision labor, $/h 15.18 17.24
Waste facility labor rate, $/h 19.18 17.24
Analysis labor rate, S/h 20.77
Electricity, mills/kWh 43.9 39.8
Water, S/1000 gal 0.13 0.57
Waste disposal
Wet, S/tcn 15.70 11.64
Dry, S/ton 5.00 5.65
Overhead (plant) 60
% O&M Labor
Steam reheat, S/100 Ib
Reheat, S/10G Btu 4.23 5.51
3-12
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3.3 SYSTEM FILES AND ROUTINES
Several of the files and. calculating routines used in IAPCS-II
are "system-wide" (i.e., not limited to one particular control
technology module). This important aspect of integrated desiqn
eliminates equipment redundancy.
3.3.1 Standard Coals
For simplification of input requirements regarding coal
characteristics, a set of six standard coals is provided uhat
contains the proximate analyses for run-of-mine (ROM) and physi-
cally cleaned coals. Weight recovery, Btu recovery, and total
cost (in $/ton of raw coal) are also shown for the cleaned coal.
Estimated characteristics of the standard coals are shown in
Table 3-5.
3.3.2 Emission Calculations
Once IAPCS-II has been provided with the coal characteris-
tics, 5. set of calculations is used to estimate the SO.,, NO , and
Z. j\
PM emissions associated with that coal. The EPA AP-42 emission
factors used as a basis for these calculations are responsive to
boiler bottom type (wet or dry) and coal type (rank) for PM; coal
type for SO_; and firing configuration, bottom type, and c ,al
type for NO .
X
Some new features in IAPCS-II are based on EPA comments.
For SO- emission calculations, the AP-42 basis is used; however,
the user can select a separate default value of 100 percent
conversion of sulfur to SO- through a parameter file option.
This option permits easy comparison of FGD costs with those of
TVA or allows a conservative design approach to be assumed.
3-13
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TABLE 3-5. ESTIMATED CHARACTERISTICS AND COSTS OF RAW AND CLEANED COALS
(All analyses are on a whole coal basis.)
Raw coal
Coal 1 Coal 2 Coal 3 Coal 4 Coal 5 Coal 6
PA OH WVA IL MN ND
Armstrong Jefferson Logan No. 6 Rosebud Lignite
Btu/lb
Ash, %
S, %
H20, %
Cleaned coal
Btu/lb
Ash, %
S, %
H20, %
Wt. recovery, %
Btu recovery, %
o
PCC costs
Total capital, $106
Annual capital,
$/ton raw
O&M, $/ton raw
Total annual , S/ton
11,952
15.9
2.23
3.3
12,596
10.0
1.42
5.6
88
95
22.23
1.77
2.80
4.57
11,922
13.0
3.43
5.0
12,845
6.6
2.74
4.4
85
91
13.11
1.05
2.80
3.85
12,058
16.6
0.89
3.5
13,611
4.6
0.83
5.4
82.5
95
15.38
1.22
2.80
4.02
10,359
20.6
4.27
9.6
11,507
10.7
3.50
11
78
88
11.62
0.94
2.80
3.74
8,789
8.15
0.56
25.2
9.C50
6.46
0.43
24
96.2
97.5
13.37
1.07
2.80
3.87
7,500
5.9
0.94
32
7,840
5.3
0.54
30
97.4
98.9
12.74
1.02
2.80
3.82
Note: Cited costs assume coal production of 500 tons/h, 11 h/day,
365 days/yr, and capital recovery factor (CRF) of 16%.
3-14
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For PM, an 80/20 split of ash is assumed as the topside and
bottom ash fractions in the calculations. In this case, the user
has the option of applying the AP-42 emission factors contained
in the parameter file. The AP-42 emission factors result in fly
ash estimates significantly lower than the 80/20 split. This
ratio has .been used for a number of years, however, and is widely
accepted for PM control device design.
The NO emissions are calculated by thi- same method that was
X
used in IAPCS-I. These values are in excellent agreement with
estimates of utilities and boiler manufacturers. All AP-42
emission factors are expressed as percentages in IAPCS-II.
3.3.3 Boiler Performance
The net heat rate of the boiler is calculated by IAPCS-II
primarily to show the energy penalty the control system has on
the operation of the unit. A standard routine is used to esti-
4
mate the net heat rate. The unit's thermal efficiency is based
on the heating value of the coal. This thermal efficiency is
used to adjust a minimum heat rate upward, and the losses to the
system for auxiliaries are added (in Btu/kWh). The gross heat
rate is then calculated, and power losses due to each of the
control technology modules selected is added to the heat rate.
In this case, the net heat rate reflects the total Btu/kWh re-
quired for the selected boiler and control system.
3.3.4 Fans
Another system-level calculation routine is provided to add
booster fans for the selected integrated control system. The
3-15
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design of the induced-draft booster fans and the estimated costs
are based on the total gas-side pressure drop and the gas flow
rate. Many different control configurations are possible; there-
fore, the FANS module may be used to calculate forced-draft fan
costs where appropriate. This user option is included in the
parameter file for the FANS module. The basis for the module is
a routine extracted directly from the Shawnee Model.
3.3.5 Waste Disposal
The Shawnee Model routine for construction and operation of
an onsite waste disposal is also used at the system level. No
pond options are provided in IAPCS-II because many of the control
.combinations could only make use of collected wastes in a dry
form. Conventional FGD systems generate a wet waste, which must
be disposed on a routine basis. The model permits three waste
disposal scenarios:
0 All of the waste can be disposed of offsite. For this
option, the waste disposal fee is used to calculate an
annual cost.
0 The waste can be split (in any ratio) between offsite
and onsite. This option results in a capital cost
estimate for the onsite facility, annual costs for its
operation, and annual offsite disposal costs.
0 All of the waste can be disposed of on site. In this
case, the capital costs of building the site and the
annual costs for its operation and maintenance will be
calculated.
3.3.6 Economics
The model permits escalation and deescalation of the base-
year dollars for a given run. The system costs in 1982 dollars
may be adjusted forward. Chemical Engineering cost indices or
3-16
-------
the annual inflation rate (both stored in the parameter file) are
used to effect these adjustments to the base year. The costs of
labor, reagents and chemicals, and utilities also must be adjust-
ed, as the startup year costs (first-year O&M costs) usually
differ from costs during the first year of construction (capital
costs).
Several cost components are used to compute annual O&M
costs. These include a capital component so that a single number
representing a system cost may be used for comparative purposes.
Capital cost components used in O&M calculations include:
0 Depreciation
° Annual interim replacement
0 Insurance and property taxes
0 Federal income and investment credit taxes
These can be combined into a levelized annual capital charge, as
shown by TVA1 and EPRI.2
3.3.7 Parameter File
The parameter file is a critical facet of IAPCS-II. Through
it, changes affecting the design, performance, and cost of indi-
vidual modules may be facilitated. Access to this file permits
the user to obtain maximum flexibility in depicting a given
control scenario and to update and revise control technologies as
data become available.
After the user has selected an interactive run (the first
input question) and selected either the TVA or EPRI economic
format (the second input question), he is presented with a menu
of parameter file options:
3-17
-------
1. Switch to another existing parameter file.
2. Edit parameter file/create a new parameter file.
3. Display parameter file explanation.
4. Print cut parameter group.
5. Leave this menu and begin input sequence.
6. Stop the program without making a run.
When IAPCS-II is started, the default parameter file is
loaded. The name of the default parameter file ir "PARMFILE."
This name, along with the economic format chosen, is displayed at
the top of the screen. Every parameter file is associated with
either the TVA or the EPRI economic format. It is possible for
two parameter files with different economic formats to have the
same name (e.g., there is a PARMFILE.TVA and a PARMFILE.EPR) .
Option 1 allows the user to load in a different parameter
file saved previously under the same economic format. Option
2 allows the user to change values in the current parameter file
and subsequently save these changes for future use. The user
will be prompted for a name for the new parameter file and warned
if the file already exists. It is strongly suggested the user
never save new parameters into the default parameter files (PAKM-
FILES). If the changes made to the parameter file are not saved,
they will be in effect for the current run only.
Option 3 displays a brief description of the parameter file.
Option 4 prints cut a group of related parameters (e.g., LIMB
parameters, economic parameters). Option 5 begins the main input
section of the model, which is followed by model execution.
3-18
-------
Option 6 allows the user to quit at this point; this permits the
user to modify a parameter file without making a run.
The parameter file access method (menu option 2) has been
revised in IAPCS-II so that the user can select the group desired
and change the values of items in that group. Validation of
parameter changes is reported with each model run. A summary
listing of the parameter file is presented in Appendix A.
3.4 OUTPUT FORMAT AND OPTIONS
The model provides the user with eight separate outputs.
Each of these is described in this section. An example run
illustrating the output format of IAPCS-II is presented in Ap-
pendix B.
3.4.1 User Input Summary
For assurance that each run is complete, the first output is
a reiteration of the inputs provided by the user. Any changes
the user has made to the parameter file are reported, along with
all of the requested input items. For a batch file run, the same
report is generated by using these inputs.
3.4.2 Module-Specific Output
Brief statements describing the primary design character-
istics of the selected control modules are reported for the user.
3.4.3 Boiler Performance
For heat input and coal consumption, the higher heating
value of the coal must be used. It is important to note that
heat rate and boiler thermal efficiency are for a unit with no
controls and all auxiliaries included. After the energy penalty
3-19
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has been calculated from the sum of each module in a given con-
trol configuration, the gross heat rate or the system's net
generation can be calculated. This value reflects actual capaci-
ty with the given control configuration relative to the input
(nominal) boiler size.
Heat input, boiler efficiency, net heat rates, and coal con-
sumption are calculated by using the ROM or cleaned coal charac-
teristics (if selected). This permits quantification of the
benefit in heat rate from firing the cleaned coal in the system.
Only the performance parameters for the cleaned coal (if PCC is
selected) are presented in the output table.
3.4.4 Material Balance
Material balance components are calculated at the exit of
each control module. The "uncontrolled" column calculates a
baseline estimate using the ROM coal characteristics so that the
overall system pollutant reduction effects can be calculated;
i.e., the uncontrolled column does not reflect any of the boiler-
related (pre-combustion and in situ) controls (e.g., PCC, LIMB,
or LNC).
3.4.5 Emission Reduction
The overall system emission reduction is reported in a
summary table. This table presents the mass flow rate (Ib/h),
percent removal, and unitized mass and volume emission rates
(lb/106 Btu and ppm) for PM, S02, and NCx- Because this table is
generated directly from the material balance, it is dependent on
the emission estimation routine. The uncontrolled emissions of
3-20
-------
PM, SO,,, and NO for a given coal are calculated at the boiler's
i— j\
air heater exit. Inasmuch as LNC, LIMB, and PCC may be used as a
control option, the ROM coal properties are used to generate an
initial uncontrolled baseline, which is reported in column 1 of
the material balance. All emissions are estimated by using the
heat input (from the performance routine) and AP-42 emission
factors. If any of the three boiler controls is not used, the
uncontrolled baseline is repeated in column 2; if any control
configuration is specified, column 2 of the material balance
reflects the effects.
3.4.6 Capital Cost Estimate
The capital cost estimate for the designated control config-
uration is the next output (See Appendix B).
3.4.7 Annual Cost Estimate
The annual cost estimate for the designated control config-
uration is the next output (See Appendix B).
3.4.8 Cost-Effectiveness
An output of the system's cost-effectiveness is then pro-
vided. The cost per ton ($/ton) of PM, SO , and NO removed is
^ A
calculated for comparison purposes by using the levelized annual
requirements.
3.5 OPTIMIZATION AND RERUN
At the completion of a run, the user is asked whether opti-
mization of the selected control system is desired. A target
emission rate (in lb/10 Btu) may be entered, and the system per-
formance and costs will be rerun automatically.
3-21
-------
This optimization routine allows the user to alter the
effective efficiency of a chosen control device. If the user
elects to optimize, the user will be prompted to enter a new
"target" emission rate, in pounds per million Btu, for the pol-
lutant appropriate to the control module selected. (It is only a
"target" oecause if other modules are in the system, they may
also affect the final emission rate, and only one module is
optimizable at a time.) For the LIMB module, the SO- emission
rate may be either higher or lower than the initial emission
rate. For all other modules, the new emission rate must be
higher than the initial emission rate.
The effective efficiency of a control module is changed
either by simulating a bypass of a fraction of the gas stream (as
is the case with the fabric filter and wet FGD modules) or by
simply changing the capture efficiency of the control vnit (LIMB,
ESP, and Lime Spray Drying). In the former case, the emission
rate should be selected such that a minimum of 10 percent of the
gas stream will be bypassed because less than this amount would
not be cost-effective.
V7ith the exception of LIMB optimization with a lower emis-
sion rate, all optimizations have the effect of lowering the cost
of the control system at the expense of increased emissions.
The bypass fraction and new removal efficiency are cal-
culated as follows:
3-22
-------
Bypass fraction = Ec "
Efficiency = MIN(n,l - Ec/Eu)
where: EC = Controlled emissions (Ib/MM Btu)
Eu = Uncontrolled emissions (Ib/MM Btu)
n = Maximum removal efficiency
The target emission rate should be chosen to ensure that
impossible situations do not occur (e.g., emissions greater than
those at the inlet to the control device). Once the target
emission rate has been chosen, the calculational and outpuc
portion of the program will re-execute.
It should be noted that although this process is called
optimization, it will not necessarily result in a more cost-
effective solution.
3-23
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SECTION 4
DESCRIPTION OF IAPCS-II TECHNOLOGY MODULES
The IAPCS-II model is designed on a modular basis; i.e., a
given control technology accepts the flue gas, coal, and unit
characteristics from the previous module. These data are then
used to generate the design, performance calculations, and esti-
mates of capital and annual costs. The architecture of a modular
program is such that it offers the user the greatest flexibility
for revising any existing control device and for adding new
technologies as they are identified.
This section presents the design and cost bases used for
each of the nine modules in IAPCS-I.
4.1 PHYSICAL COAL CLEANING
Physical coal cleaning is a control module for both the
typical and user-specified coal source. The PCC module either
assumes the before and after characteristics (typical coal) or
requires the user to provide the details.
Run-of-mine coal costs usually include cursory sorting and
screening charges for coal preparation. Physical coal cleaning
processes are specifically designed for the coal source and de-
pend on the unique washability characteristics of the particular
coal. Because coal characteristics and washability vary greatly,
data from Versar, Inc., and Hoffman-Holt were used for six
typical coals in the United States.
4-1
-------
Although different coal cleaning facilities are assumed for
each of the six coals, they essentially reflect PCC capacity
captive to a 500-MW unit. The fuel cost premium is that cost (in
$/ton raw coal) required to generate adequate cleaned coal for
the unit.
When the user specifies one of these coals, the costs and
properties become the source of an annual fuel cost premium (if
physically cleaned) and of emission calculations.
Ash properties, specifically alkalinity, are very important
in the design of air emission control systems in the model.
Because typical coal data do not include ash properties, default
values were assumed on the basis of coal rank. These values for
the major alkaline components of calcium oxide (CaO), magnesium
oxide (MgO), and sodium oxide (Na_O) are presented in Table 4-1.
The reactive fraction is that portion of alkalinity that is
available for SO reaction. These reactive fractions are based
on a study of Combustion Engineering's information on the suo-
n
ject and on engineering judgment. The CE text indicates the
relative insignificance of potassium oxide (K_0) as a reactive
alkali; thus, it is not included in the listing of alkaline
components.
TABLE 4-1. ESTIMATED ALKALINE COMPONENTS OF COAL BY RANK
Alkaline component
o T ash, %
CaO
MgO
Na20
Total
Reactive fraction
4-2
Li tuminous
(Illinois)
5.2
0.9
0.4
6.5
0
Subbituminous
(Montana)
13.5
4.6
2.8
20.9
25
Lignite
(N. Dakota)
21.1
6.4
4.4
31.9
20
-------
If the user specifies a coal, all of the coal properties
must be input for the ROM and PCC source. Alkalinity for a
specified coal is the sum of CaO, MgO, and Na20 components of the
ash. The Na,,O content is identified separately because ESP
design is highly dependent on this value.
The PCC module modifies the unit/system performance, emis-
sion calculations, and cost of downstream control equipment.
4.2 LOW-NO COMBUSTION
X
The low-NO combustion (LNC) technology module contained in
J"w
Q
IAPCS-II was originally part of the EPA LIMB Model (see Subsec-
tion 4.3). Two low-NO combustion processes are offered in
jC
IAPCS-II: overfire air and low-NO burner. Overfire air (OFA)
ft-
is most applicable to tangentially-fired boilers. Low-NO burner
yi
(LNB) is most applicable to wall-fired boilers (front and op-
posed) . Both technologies are offered in IAPCS-II for both new
and retrofit applications.
For tangentially-fired PC boilers, one OFA port is provided
for each column of burners. A NO^ reduction of 25 percent is
A
assumed for OFA. For wall-fired PC boilers, low-NOx staged-
combustion burners are provided. A NO reduction of 50 percent
yi
is assumed for LNB. For retrofit applications, all retrofit
costs are built into the cost algorithms.
A summary of the design and operating parameters of the LNC
module of IAPCS-II is presented in Table 4-2.
4-3
-------
TABLE 4-2. DESIGN AND OPERATING PARAMETERS OF LNC
MODULE OF IAPCS-II
Plant application New/retrofit
Boiler application Pulverized coal
Boiler firing configuration Wall-fired and tangentially-fired
Plant size, MW 100 to 1300
Process options Overfire air (tangentially-fired)
NO control, percent:
A
Low-NO burner (wall-fired)
x
Overfire air 25 (base case)
Low-NO burner 5G (base case)
A
Economic conditions TVA premises
EPRI premises
4.3 LIMESTONE INJECTION MULTISTAGE BUPNER
The LIMB technology module of IAPCS-II has its genesis in
two other models: IAPCS-I and the EPA LIMB Model.
The original version of IAPCS included a LIMB technology
module. This module was developed on research information avail-
able at the time, which was admittedly sparse. The LIMB module
was capable of predicting performance and estimating cost for
limestone (calcite} injection only in a PC wall-fired, dry-bottom
boiler using specially designed, staged-combustion, low-NO burn-
A
ers. The major capital cost elements of limestone storage and
preparation, staged-combustion burners, additional soot-blowing
capacity, and economizer upgrades were included. Modifications
to the boiler's bottom configuration and the major convective
structures of superheater, reheater, air heater, and cavity were
excluded. Limestone consumption was established by setting the
4-4
-------
calcium-to-sulfur (Ca/S) molar stoichiorrugtric ratio at 3:1 for 50
percent S02 capture. Downstream effects to the PM collection
system were accounted for in the ESP and FF modules based on the
additional solids loading and particle resistivity. The addi-
tional solid waste material was accounted for in the waste dis-
posal module.
The enhancement of IAPCS from Version I to Version II in-
volved extensive modifications and refinements to the LIMB rod-
ule. A number of events occurred shortly after the release of
IAPCS-I that facilitated these enhancements. A significant
number of publications were released containing pertinent and
detailed LIMB and LIMB-related research resulLs. This was, in
part, stimulated by the First Joint Symposium on Dry SO,, and
Simultaneous SO-/NO Control Technologies sponsored by EPA and
£. JC
EPRI and held in November 1984. In addition, the LIMB Applica-
tions Branch of AEERL developed their own LIMB cost model (EPA
9
LIMB Model) to support internal research activities. This model
incorporated a number of LIMB technology advancements and versa-
tility not present in the LIMB module of IAPCS-I. Accordingly, a
decision was made to upgrade the LIMB module by usi.ng the latest
research results and incorporating a number of features of the
EPA LIMB model.
The more significant improvements to the LIMB technology
module of IAPCS-II included expansion in the selection of sor-
bents from one to eight, allowing the selection of sorbents pre-
pared offsite (preprocessed) or on site (plant-site processing),
4-!
-------
updating S02 capture predictions based on the latest experimental
data, incorporation of boiler quench rates as an SO capture
variable, expansion in the selection of furnace-firing configura-
tions, expansion in the selection of sorbent injection methods,
ability to uncouple sorbent injection and low-NO combustion,
ability to cost upgrades to the existing boiler and ESP, improve-
ments in the ability to tailor cost and performance estimates to
conditions of existing boilers, and improvements in the sensitiv-
ity of the downstream ESP to alterations in particle resistivity.
These improvements coincide with improvements made to the model's
overall versatility and accessibility. A summary of the basic
design and operating parameters of the LIMB module of IAPCS-II is
presented in Table 4-3. Table 4-4 is a summary of the S0_ captures
of the LIML Module of IAPCS-II.
4.4 SPRAY HUMIDIFICATION
Spray humidification involves the injection of water into
the flue gas stream upstream of the PM collection device. The
primary objective of humidification is to reduce gas volume and,
therefore, the size of the PM collection device. This will
result in a concomitant reduction in the capital cost of the PH
collection device; moreover, if the PM collection device is an
ESP, additional secondary gains will result from a decrease in
fly ash resistivity and an increase in surface conductivity. The
FF module does not benefit from these secondary factors and may,
in fact, experience blinding and cake release problems as the
flue gas dew point is approached.
4-6
-------
TABLE 4-3. DESIGN AND OPERATING PARAMETERS OF LIMB MODULE OF IAPCS-II3
Plant application
Boiler application
Boiler firing configuration
Plant size
Sorbent options
Sorbent Ca/S Ratio
Boiler quench rate, °F/s
S0? capture, percent
Sorbent injection
Process options
Processing areas
Sorbent storage, handling,
and preparation
Sorbent injection
Boiler modifications
Downstream modifications
Waste handling and disposal
Process design
Economic conditions
New/retrofit /
Pulverized coal /
Wall-fired and tangentially-fired ^
100-1300 MW .
Limestone
Lime /
Calcite
Dolomite0
Calcitic hydrate (base case)
Dolomitic hydrate
Calcitic pressure hydrate0
Dolomitic pressure hydrate
Specified by user (bdse case 2.0) ""'
Specified by user (base case - 700)
Specified by user selection of Cr./S and
boiler quench.rate (base case = 40)— ^
Upper-furnace injection
With/without low-MOv conditions
On-site/off-cite sofbent preparation
Dry ball mill (limestone)
Slaker/dry ball mill (lime)
Pneumatic
Burners (LNB as separate module)
Soot blowers
Economizer (retrofit)
ESP upgrade (retrofit)
ESP gas conditioning (retrofit)
System
Specified by user (LIMB parameter file)
TVA premises
EPRI premises
a Base case values represent model default conditions.
On-site sorbent preparation.
0 Off-site (preprocessed) sorbent preparation.
-------
TABLE 4-4. S02 CAPTURES OF LIMB MODULE OF IAPCS-II3
Ca/S
Quench rate = 900
limestone 15-16 26-29 35-43 42-56
hydrate 19-20 35-40 53-56 69-70
CPHC 27-33 48-54 68-71 88-94
Quench rate = 700
limestone 17-19 29-31 38-44 45-57
hydrate 24-26 40-46 57-62 73-76
CPH 33-38 54-62 75-79 92-95
Quench rate = 500
limestone 18-22 31-33 41-45 48-58
hydrate 28-32 45-52 61-68 77-82
CPH 40-43 60-70 81-89 95+
Quench rate 300
limestone 19-25 32-36 44-46 51-59
hydrate 33-38 49-58 66-74 82-88
CPH 46-48 67-78 88-95 95+
a S02 capture is expressed as a percentage.
Quench rate is expressed as °F per second for the sulfation "windov;" of
2200°F to 1600°F.
C CPH = calcitic pressure hydrate.
4-8
-------
tfo experience with SH on a utility boiler at any level of
application (pilot, prototype, demonstration, commercial) has
been reported. Therefore, the design concept represents an
approach which is based on a quench tower typically used to
condition the flue gas stream prior to scrubbing.
The following design factors form the basis of the S;i module:
0 Gas residence time in the spray humidification chamber
is 0.4 second (which is typical for a gas partial
quench tower in a scrubbing application).
0 The spray water feed rate is regulated by gas satura-
tion approach temperature, which :.s assumed to be
160°F. Water feed requirements are designed to be
three times the theoretical water feed requirements.
0 The spray chamber is a typical horizontal section of
duct run. These dimension assumptions preclude any
significant PM dropout considerations in the spray
chamber (i.e., no dropout below 3000 ft/rain).
0 The spray chamber is serviced by a circumferential
spray ring at the inlet, a collection sump, a sloped
duct wall (1-degree pitch) to aid drainage, and a mist
eliminator with intermittent self-cleaning via soot-
blowers. The spray ring is a conventional design with
feed nozzles placed at 60-degree intervals. The spray
chamber is constructed of unlined, normal-gauge carbon
steel. The mist eliminator is a vertical, single-
stage, three-pass chevron design with wide vane spac-
ing; it is constructed of thick-walled thermoplastic
(e.g. , Noryl) .
0 The mist eliminator pressure drop is nominally 1.0 in.
H20. A freeboard (distance between the end of the
spray chamber and the mist eliminator inlet) of approx-
imately one-third the length of the spray chamber is
provided for the mist eliminator. Self-cleaning is
provided by intermittent water sprays using retractable
high-pressure water lances (steam soot blowers).
0 The collection/feed tank is a conventional vessel (no
agitation) sized for 8-h surge capacity.
4-9
-------
0 The recycle pumps are conventional centrifugal design
(one in service and one on standby). Pump capacity is
sized at three times the theoretical water requirement
plus 10 percent oversize.
0 The feed pumps are conventional centrifugal design (one
in service and one on standby). Pump capacity is sized
to continuously replace the purge stream that is con-
tinuously discharged at a rate of 1 percent of total
liquid inventory.
0 No gaseous absorption, PM collection, or dropout occurs
in the spray chamber. Approximately 1 percent of the
moisture droplets remain entrained in the gas stream
(99 percent knockout).
0 A minimum 160°F saturation approach temperature pre-
cludes the necessity of downstream corrosion protection
through the use of either protective liners or high
alloys.
0 A complete instrumentation complement is provided,
including temperature-flow indicator/control for the
spray humidification chamber, flow and level controls
for the liquid circuit, and differential pressure
control across the mist eliminator.
The moisture content, pressure, temperature, and volume are
the only gas characteristics changed across the spray humidifica-
tion chamber.
The primary downstream impact is the reduction in gas volume
caused by a drop in temperature. The sizes of the approach duct
and PM collection device are affected accordingly. Moreover, if
the downstream collector is an ESP, changes in fly ash resistivi-
ty and surface conductivity will cause an additional reduction in
the SCA of the ESP- For reasons previously outlined, the FF is
not similarly affected.
A minimum saturation approach temperature of 160°F provides
an ample' safety margin above the saturation point; thus, special
corrosion protection measures are not provided for the downstream
equipment (e.g., special coatings or alloys).
4-10
-------
4.5 LIME SPRAY DRYING10 16
This module, which was not updated in IAPCS2, represents
state-of-the-art as of November 1983. Users interested in the
most current Lime Spray Drying technology should see the user's
manual for the EPA/TVA Lime Spray Drying model (EPA-600/8-86-016.
June 1986) .
Lime spray drying technology uses a concentrated alkali
slurry in a spray dryer. The spray dryer for SO- control must be
operated in conjunction with a PM control device. As ohe absor-
bent slurry is dried and SO2 is absorbed by the alkali, PM is
introduced into the flue gas. Approximately 70 percent of the PK
can be entrained and must be removed by the downstream control
device. A choice between the use of an FF or an ESP should net
be based on economics alone. The ESP can process gases with a
higher moisture content than can the FF, which allows the spray
dryer to operate closer to tht- dew point cf the gas and thus
results in the introduction of more slurry to reduce the SO-
level. Additional SC- removal, however, has been found to occur
on the filter cake that forms on the bags in the FF. Because
lowering the approach temperature tends to increase both the
quantity of SO- removed and the possibility of downstream conden-
sation, the LSD module is based on a 30°F approach temperature.
This temperature permits up to 85 percent SO2 removal in the
spray dryer under certain conditions and not cause blinding in an
FF due to excessive moisture. No incremental reduction in S00 is
*,.
given for the use of an ESP; a maximum 20 percent removal of the
4-11
-------
incoming SO2 into the FF is credited if that PM control option is
chosen.
The absorbent slurry can be introduced into the gas stream
either via a rotary atomizer or dual-fluid nozzles. Because more
data are available and the technology has been proven, this model
utilizes the rotary atomizer scheme. The absorbent reacts with
the S02 during intimate contact as a liquid solution or slurry.
Very little additional SO^ removal takes place after the solution
4.
has dried. The liquid droplets dry before leaving the vessel and
the dry reaction products and fly ash are removed from the flue
gas by the downstream PM control equipment.
The spray dryer reduces the flue gas volume by lowering gas
temperature and removing a fraction of the S0_ . In the design
used, the flue gas temperature is lowered to 160°F (which is
assumed to be 30°F above the typical saturation point). The
system must be operated at a temperature above the saturation
point to assure that all of the dropletr. dry before they reach
the vessel walls or enter any downstream PM equipment. Another
factor of concern is condensation in downstream ductwork and
equipment, which could cause corrosion.
A key factor in the design of this system is the efficient
utilization of the absorbent. This is accomplished by two means.
The first is to allow a fairly close approach temperature (30°F)
that permits longer drying times for evaporation of more liquid.
With increased liquid rates, the amount of absorbent can be
increased, which subsequently results in increased S0? removal
4-12
-------
efficiencies. The second means is to recycle a portion of the
collected solids. The first pass of the lime absorbent yields
approximately 50 percent utilization. The recycling of about 55
percent of all solid material back into the slurry system could
raise this overall utilization to the 75 to 80 percent range.
Additional SO- can be removed by using the alkalinity avail-
able in the fly ash during a recycle scheme. The available alka-
linity in the fly ash varies with coal type, and only about 80
percent utilization of the reactive alkalinity was assumed. An
overall stoichiometric ratio was used that took into considera-
tion the combined alkalinity from the fresh lime and the recycled
lime, and alkalinity in the fly ash. The ratio is based on moles
of calcium equivalents per mole of S02 in the flue gas. This
definition differs from that normally shown for spray dryers of
moles of calcium per mole of SO- removed. Although this defini-
tion makes calculations simpler, a comparison of the two ratios
shows that this method results in values that appear to be low.
The ratio used, in this model is 1.53, which is the same as a
ratio of 1.8 for an S02 removal of 85 percent.
Another factor that affects the design is the solids content
of the slurry. The LSD module establishes the maximum amount of
solids in the absorbent slurry at 35 percent, which is both well
within the pumpable range and sufficiently high to achieve the
desired SO- removal efficiencies.
Calculation of the fresh lime usage rate is based on the
assumption that some of the needed alkalinity will be supplied by
4-13
-------
the recycle stream. More reactive solids leave the dryer in the
gas stream rather than in the bottoms fraction. Approximately 30
percent of all solids in the slurry will be in the bottoms frac-
tion and will be discarded. The 70 percent solids in the flue
gas are captured in the PM control device. About 78 percent of
the solids in the flue gas are recycled via a slurry system to
the absorbent solution circuit, which equates to approximately 55
percent of all solids recycled. The fresh lime feed rate is
determined on the basis of this recycle rate and a utilization of
50 percent of the lime alkalinity and 80 percent total of any fly
ash alkalinity available, the difference of this summation, and
the required alkalinity for maximum SO., removal. The maximum
amount of water that can be evaporated at the inlet temperature
and with the 30°F approach is used to check the maximum slurry
content (35 percent). If the needed fresh lime exceeds the
solids content allowable for the 85 percent SO- removal set
point, a correction is made. The fresh lime feed rate is low-
ered, which not only reduces the solids content to the 35 percent
mark but also reduces the overall SO,, removal efficiency. The
final quantity of lime needed is prepared in a ball mill/slaker.
Redundant components are provided for all major equipment
items. These items include pumps, a ball mill, and a classifier.
Spare spray r'ryers would be installed on medium to large systems
to handle 25 percent capacity. The small systems can have up to
100 percent redundancy if only one dryer is needed to make the
system operable.
4-14
-------
The largest dryer module available has a 45-foot diameter
and can handle 550,000 acfm with a residence time of 10 to 12
seconds. The total system pressure drop has been estimated at
approximately 6 in. HO.
The ability of the user to decrease the overall efficiency
of this system involves the use of a gas bypass. The system will
then remove the SO., content of the quantity of flue gas that is
to be treated. This treated gas is then mixed with the bypass
gas before going to the next module.
As mentioned previously, two of the reasons for the popular-
ity of LSD technology are 1) the waste streams are dry and 2) the
system design is fairly simple. The dryer bottoms waste is con-
veyed to a storage silo for final disposition. Another benefit
of the simplicity of the overall system is that it requires less
energy tc operate than wet FGD. The power consumption, including
the PM control device for operational systems, is less than 1
percent of the gross unit generating capacity. This cost does
not include the incremental fan horsepower required to overcome
the system and PM control device pressure drop (which is treated
in IAPCS-II on a system-wide basis).
A summary of the basic design and operating parameters of
the LSD module of IAPCS-II is presented in Table 4-5.
4.6 WET FLUE GAS DESULF'JRIZATION
It is strongly recommended that the user obtain.a copy of
Reference 1 in order to understand the operation and parameters
of this module.
4-15
-------
TABLE 4-5. DESIGN AND OPERATING PARAMETERS OF LSD MODULE OF IAPCS-I1
Process options
Process design
SOp removal efficiency, maximum percent
S0? removal across PM collector, percent:
ESP
FF
PM carryover, percent
Saturation approach temperature, °F
Reagent stoichiometric ratio, equivalent Ca/S
Sorbent utilization, percent
Reactive ash alkalinity, percent
Slurry recycle fraction, percent
Slurry recycle solids, percent by weight
Lime preparation
Spray dryer design (typical):
Diameter, ft
Gas flow rate, acfm
Gas-side pressure drop, in H?0
Residence time, seconds
Spare capacity, percent:
Lime slurry
Spray dryer—rotary
atomizers
85
0
Specified by user
(base case = 20)
70
160
1.53
85
80
55
35
Ball mill/slaker
45
550,000
6
10-12
25-100
4-16
-------
Flue gas desulfurization represents the most comprehensively
modeled SO2 emission control technology for coal-fired utility
boilers. This is because of FGD's level of commercial develop-
ment and widespread commercial application in the utility indus-
try, the variety of FGD processes commercialized or under devel-
opment, the controversial nature of FGD with respect to cost and
performance expectations, and the perception of FGD technology as
a benchmark for comparison with other SO~ control technologies.
The majority of FGD modeling work has been sponsored by EPA
and EPRI. The most recognized and comprehensive effort has been
conducted by TVA under contract to EPA. From 1968 to 1980, EPA
sponsored research on the development of lime/limestone slurry
FGD technology at the Alkali Scrubbing Test Facility located at
TVA's Shawnee Steam Plant. The experimental test data collected
during these tests were used to develop a computer model to
project conceptual designs and estimate costs for lime/limestone
slurry processes. The computer model was developed through the
integration of two separate computer programs to calculate mate-
rial balances, flow rates, and stream compositions and economics.
The resulting model contains two separate programs—one which
calculates the major equipment requirements and costs and total
capital investment and the other which calculates annual revenue
requirements.
Development of the Shawnee Model comme jed in 1974. During
the subsequent 10-year period, the model was periodically updated
to reflect refined technology and economic conditions. The most
4-17
-------
dramatic change came about in 1980 with the adoption of a revised
set of design and economic premises. This change was attributed
to changing economic conditions, fuel use patterns, developments
in economic evaluation techniques, developments in FGD tech-
nology, and developments in environmental legislation.
The most recent version of the model, the Shawnee Flue Gas
Desulfurization Computer Model (Shawnet Model) was completed in
July 1984 and released in March 1985. The Shawnee Model is
capable of projecting a complete conceptual design for lime/lime-
stone slurry FGD processes utilizing different absorber towers
(e.g., spray tower, TCA, venturi scrubber-spray tower absorber),
with and without chemical additives (e.g., magnesium oxide, adip-
ic acid), with any of five sludge disposal options (untreated,
forced oxidation, chemical fixation, on-site ponding, off-site
landfill). The Shawnee Model estimates the capital investment
(direct and indirect costs) for seven facility areas (i.e., raw
material handling, raw material preparation, gas handling, SC>
scrubbing, oxidation, reheat, and waste disposal) and annual and
lifetime revenue requirements. A summary of the basic design
parameters and economic conditions is presented in Table 4-6.
The Shawnee Model is accessible in several forms. The
original version is a mainframe computer model that is suitable
for loading onto an IBM-370 or compatible mainframe computer.
The ~K)del is also available in a microcomputer version as part of
IAPCS-II. The FGD module of IAPCS-II contains the complete ver-
sion of the Shawnee model. As part of the enhancements of IAPCS
4-18
-------
TABLE 4-6. SHAWNEE MODEL DESIGN PARAMETERS AND ECONOMIC CONDITIONS
DESIGN PARAMETERS
Plant application
Plant size, MW
Coal sulfur, percent
S02 loading, ppmv/lb S02 per 106 Btu
Scrubber gas velocity, ft/s
Number of absorbers
Number of spare absorbers
S02 removal, percent
Liquid-to-gas (L/G) ratio, gal/1000 acf
Slurry hold tank residence time, min
Recycle slurry solids, percent
Maximum reheat temperature, °F
Processing areas
Process options
Process additive options
Absorber options
Forced oxidation options
Reheat options
Solid waste treatment options
Solid waste disposal options
(continued)
New
100-1300
1-5
600-4000/1.7-9.0
8-12.5
0-10
0-2
1-100
25-120
2-25
5-15
225
Raw material handling
Raw material preparation
Gas handling
S0? scrubbing
Oxidation
Peheat
Waste disposal
Lime/limestone slurry
Adi pic acid/magnesium oxide
Spray tower
TCA tower
Venturi-spray tower
Within loop
Slurry hold tank
Indirect steam
Flue gas bypass
Indirect steam/gas bypass
combination
Untreated
Chemical fixation
Forced oxidation
Onsite/landfill
Unlined/clay/synthetic
Thickener/filter
4-19
-------
TABLE 4-6 (continued)
ECONOMIC CONDITIONS
Indirect Capital Investment, Percent of Total Direct Investment
Engineering design and supervision
A-E
Construction expense
Contractor fees
Contingency
Total
Royalties
Working capital
Interest during construction
Allowance for startup/modifications
Land, $/acre
Annual Revenue Requirements
Direct costs
6-8
1-3
14-18
4-6
10
35.45
0
a
15.6
8
4700
Raw materials
Conversion costs
Operating labor ar.d super-
vision
Utilities
Maintenance
Analysis
Indirect. Costs, percent
Overheads
Marketing
Levelized Capital Charges, Percent of Total Capital
10
e
Weighted cost of capital
Depreciation (sinking fund factor)
Annual interim replacement
Levelized accelerated tax depreciation
Levelized investment tdx credit
Levelized income tax
Insurance and property taxes
Total charge
10
3.15
0.72
(1.44)
(2.39)
3.96
3.50
16.5
One month of raw materials, plus 1.5 months of conversion costs, plus 1.5
months overhead, plus 3 percent of total direct investment.
Three-year construction schedule.
Sixty percent of total conversion minus utilities.
Ten percent of total by-product sales.
Thirty-year plant life.
4-20
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from Version I to Version II, the FGD module was upgraded to in-
clude the Shawnee Model. This procedure required the integration
and downloading of two mainframe models — the Shav/nee Model and
IAPCS—the former being approximately four times the size of the
latter into which it was incorporated. The Shawnee Model was
integrated into IAPCS while retaining its mainframe version
capabilities. Moreover, as part of IAPCS-II, the model now
possesses a number of additional features. They include:
0 Improved user friendliness provided by the microcom-
puter's simplified operating environment and IAPCS-II's
operating protocol.
0 Integrated modeling capability with the other IAPCS
technology modules.
" The ability to cost FGD systems using TVA or EPRI
economic premises.
0 The ability to cost retrofit applications.
A summary of the basic design parameters and economic conditions
of the FGD module as contained within IAPCS-II are presented in
Table 4-7.
4.7 DRY SORBENT INJECTION18~24
The injection of sodium in dry powder form into the ductwork
upstream of the PM collector exists as a technology module in
IAPCS-II. The dry sorbent injection (DSI) module is contained in
both versions of IAPCS. No revisions were made to the module's
design and operating premises during the enhancement of IAPCS
from Version I to Version II (excluding those enhancements to the
model's overall accessibility and operation that expanded the
4-2]
-------
TABLE 4-7\ DESIGN AND OPERATING PARAMETERS OF FGD MODULE OF IAPCS-II
a
Design Parameters'
Plant application
Plant size, MW
Coal sulfur, percent
S00 loading, ppmv/lb per 10 Btu
Absorber gas velocity, ft/s
Number of absorbers
Number of spare absorbers
S0« removal, percent
L/G ratio, gal/1000 acf
Slurry hold tank residence time,
Recycle slurry solids, percent
Maximum reheat temperature
Processing Areas
FGD
System
Process Options
Process additive options
Absorber options
Forced oxidation
Reheat options
Solid waste treatment options
Solid w?ste disposal options
Economic Conditions
TVA premises
EPRI premises
New/retrofit
100-1300 MW
Unlimited
Unlimited
8-12.5 (base case = 10)
0-10 (base case - 4)
0-2 (base case = 1)
0-100 (base case 89)
25-120 (base case = 106)
min. 2-25 (base case = 18)
5-15 (base case - 10)
225 (base case - 175)
Raw material handling
Raw material preparation
S0? scrubbing
Oxidation
Reheat
Gas handling
Waste disposal
Limestone slurry (base case)
Lime slurry
Adipic acid/magnesium oxide
Spray tower (base case)
TCA
Venturi-spray tower
Slurry hold tank
Indirect steam (base case)
Flue gas bypass
Combination
Chemical fixation
Forced oxidation (base case)
Onsite/landfill (base case)
Thickener/filter (base case)
Base case values represent model-supplied defaults
4-22
-------
conditions under which DSI and all other technology modules can
be evaluated).
Dry sorbent injection technology involves the introduction
of a dry sorbent into the gas stream for chemical conversion of
S02 to a waste salt that is subsequently removed in a downstream
PM collection device. Based on this control technology concept,
a number of process design configurations are possible that meet
the following criteria:
0 Additive: sodium alkali, calcium alkali, calcium-
magnesium alkali, ammonia, fly ash
c Sorbent injection mode: continuous, intermittent,
batch
0 Particulate collection: ESP, FF
0 Byproduct disposition: waste disposal, product re-
covery
Several other variations are possible within each grouping
cited above; however, the overall number of specific design
configurations that is feasible in IAPCS-II strategy are limited
because of the maturity of the technology, inherent design limi-
tations, resource constraints, and disposal considerations.
Without going into undue detail and lengthy explanation, the
process design configuration that meets the foregoing criteria is
the continuous injection of a sodium-based alkali with the utili-
zation of a FF as the downstream collector and the disposal of
the collected reaction products in an environmentally acceptable
manner.
4-23
-------
A limited number of variations of the basic process design
configuration warrant investigation for model strategies. These
variations are based on the following information:
1. Five sodium-based alkalies are available for DSI:
nahcolite, trona, commercial-grade sodium, bicarbonate,
and commercial-grade soda ash. The major factors
affecting additive selection include effectiveness of
removing SO,, cost, resource availability and access
(in quantities suitable to support a commercial facili-
ty) , auxiliary handling and disposal, and compatibility
with other integrated operations. In accordance with
these factors, nahcolite appears to represent the most
practical additive for DSI.
2. The sorbent injection mode can be continuous, intermit-
tent, or batch feed. Continuous feed involves sorbent
injection into the gas stream (in the approach duct) to
maintain a desired stoichiometric ratio. Continuous
injection represents the most practical mode despite
limitations in attainable S02 removal (due to "lead
time" requirements to build up filter cake on the bags
following a cleaning cycle).
3. The collected reaction products are disposed of.
Recovery and reuse of the reaction products are econom-
ically prohibitive and technically questionable at the
present time.
1.7.1 Design Basis
The nahcolite. is prepared in a ball mill and injected con-
:inuously (pneumatically) into the approach duct to the down-
stream PM collector. The collected reaction products are insolu-
lilized and hauled away to a landfill.
Design factors are as follows:
1. Nahcolite is the onJy additive considered for DSI for
IAPCS strategies. Specified (typical) chemical charac-
teristics are noted in Table 4-8.
4-24
-------
TABLE 4-8. TYPICAL NAHCOLITE ORE COMPOSITION*1
Component Weight, %
Sodium bicarbonate (NaHC03) 70
Magnesium carbonate 3
Calcium carbonate 7
Inerts 20
Green River formation source.
Chloride (NaCl) less than 0.05 percent
(assume no presence).
2. The mined nahcolite is crushed to 0.25-in. rock for
transport and ground to a 200- to 400-mesh particle
size in a r'ry ball mill at the plant for injection into
the gas stream.
3. The nahcolite mill product is injected pneumatically
into the approach duct approximately 100 ft upstream cf
the PM collector.
4. Pirticulate matter dropout is ignored. All PM goes to
the downstream collector. At normal gas velocities
(approximately 6000 ft/min), no dropout should occur
(with minor exceptions for bends and transitions).
Dropout becomes a factor for velocities under 3COO
ft/min, which represents a 50 percent turndown allow-
ance.
5. The overall reaction between S02 and nahcolite proceeds
as follows:
4NaHC03 + 2S02 + O2 -> 2Na2S0lt + 4C02 t + 2H20
Two moles of NaHCO3 are required for each mole of S02
absorbed. Normalized stoichiornetric ratio (NSR) is
defined as a measure of the amount of sodium injected
relative to the sulfur present in the flue gas. An NSR
of 1.0 implies 2 moles of sodium (or NaHCO3) per mole
of S02 absorbed. Therefore, at NSR of 1.5, 3 moles of
NaRCOj per mole of S02 absorbed are required.
6. Nahcolite injection is fixed at an NSR of 1.5. Nahco-
lite additive feed rates (NFR) are calculated as fol-
lows :
.3 moles NaHCOa. , '34 Ib .mole S02.
NtK " ( mole S02 ' Vole NaHC03' { 64 Ib '
4-25
-------
1.43 Ib nahcolite 5.6 Ib nahcolite
(1 Ib NaHC03) ~ Ib S02 absorbed
where NFR = nahcolite feed rate, Ib/lb S02 absorbed
1.43 = 70 percent NaHC03 purity correction
7. Research on attainable S02 removal efficiencies for DSI
technology has been limited to low-sulfur coal applica-
tions (less than 1000 ppm S02) and FF collection.
Performance data reported for bench-scale testing and
demonstration plant testing are somewhat contradictory
with respect to the effect of operating parameters on
attainable S02 removals. Figure 4-1 presents S02 per-
formance curves for bench-scale testing. These results
suggest a significant difference between steady-state
and average S02 removals as a function of cleaning
cycle time. This difference is c>ttributed to no S02
removal during the first 10 to 15 minutes after the
onset of injection following cleaning because cf insuf-
ficient filter cake buildup on the bags ("induction").
The average SO2 removals therefore represent integrated
values for the period between cleaning cycles. Figure
4-2 presents an SO2 performance curve for demonstration
plant testing. These results represent steady-state
values. Moreover, these results, although not shown
graphically, demonstrated that the normal cleaning
cycle (i.e., 3 hours for this demonstration) had very
little effect on S02 removal efficiency. A decrease of
1 to 4 percent was observed throughout the test.
In accordance with these test results, an SO2 removal
efficiency of 80 percent is provided for the DSI/FF
configuration in IAPCS-II. This value represents a-
conservative estimate for an annual performance period
for a commercially unproven technology based upon the
assumed operating parameters (NSR = 1.5, particle size
of 200 to 400 mesh, T. = 300°F, coal sulfur <1.5
percent, S02 _<1000 ppmV.e
8. Dry sorbent injection technology involves two types of
S02 removal mechanisms: suspension capture (S02 cap-
ture by nahcolite particles in the gas stream) and
filter cake capture (SO2 capture by filter cake buildup
on the bag surface). Suspension capture occurs in the
approach duct between the sorbent injection point and
the collector inlet. Suspension capture is a strong
function of operating temperature and stoichiometric
ratio and a weak function of residence time. For the
model operating conditions (NSR = 1.5, T = 300°F,
4-26
-------
O STEADY STATE
A 90 MINUTE AVERAGE
H60 MINUTE AVERAGE
1.0 1.5
NSR
BENCH-SCALE
Figure 4-1. Bench-scale S0? removal performance curve0
A/C = 2.3, T = 265°F, and particle size = 200 mesh.
4-27
-------
100
80
60
CM
O
to
40
20
LOAD
'BH
NAHCOLITE ~
MASS MEAN DIA,
O 25 MW
@ 25 MW
A 25 MW
D 18 MW
295-318°F
340-347°F
300°F
296-298'F
16u
16p
34 w
1.0
2.0
NSR
Figure 4-2. Demonstration plant S0? performance curvec
A/C = 1.5 - 1.9 and T = 260°F - 350°F.
4-28
-------
injection point 100-ft upstream of collector), experi-
mental test results indicate very little S02 removal
via suspension capture in the approach duct. Thus,
DSI/ESP configuration represents an inappropriate
selection in IAPCS-TI (i.e., no SO2 removal).
Injecting sorbent into the flue gas stream results in
an increased PM loading to the FF and, subsequently,
the amount of PM collected in the FF? however, experi-
mental results indicate only slight effects on the FF's
pressure drop/time characteristic. Furthermore, no
increases have been observed in outlet loadings. The
increased levels of PM loading and collection are
estimated per the following:
0 5.6 Ib nahcolite/lb S02 absorbed
0 ncr. = 80 percent (see Item No. 5)
2
0 Increased loading = 4.5 Ib nahcolite/lb inlet SO
2
0 Increased collection = (4.5 Ib nahcolite/lb inlet
SO2) x fabric filter n
10. Experimental test programs have shown varied results
with respect to the effect of nahcolite injection on
NO emission reduction. Recent results indicate that
j^
the nitric oxide (NO) component of NO .. is removed to a
limited degree. Removal of NO is a strong function of
NSR. At an NSR of 1.0, approximately 15 percent of the
NO is removed. At an NSR of 1.75, approximately 25
percent of the NO is removed.. Assuming linearity for
this range, an NSR of 1.5 interpolates an NO removal of
approximately 22 percent.
11. The contribution of fly ash alkalinity to S02 removal
in DSI has been the subject of limited research. Major
conclusions indicate that there is no significant
removal of SO2 by suspension capture in the approach
ductwork (e.g., actual results were less than 3 per-
cent) and that the SO2 removal by filter cake capture
is a function of fly ash concentration and SO2 loading.
This latter conclusion suggests that a high A/C ratio
and S02 concentration are needed to effect significant
removals. (Pilot plant results verify this conclusion
in that SO2 removals of 8 to 33 percent were measured
for S02 levels of 400 and 4000 ppm at an air-to-cloth
(A/C) ratio of 3:1.) These conclusions are further
verified by dry lime sorbent injection testing that
demonstrated low S02 capture for calcium oxide (the
major alkali component of fly ash). Therefore, for the
IAPCS-II model, credit was not be taken for alkalinity
contributed by the captured fly ash.
4-29
-------
12. The waste products associated with nahcolite DSI tech-
nology exhibit the following characteristics:
0 They contain approximately 40 percent spent nahco-
lite and 60 percent fly ash.
0 They are extremely soluble, on the order of 100
times more soluble in water than are calcium-based
wastes.
0 They are low in moisture, density, compressive
strength, and structural integrity.
These characteristics indicate that sodium-based wastes
cannot be simply disposed of in a landfill. They will
require special processing prior to final disposal. To
this end, two broad techniques (or combinations there-
of) are available: waste treatment (insolubilization
via fixation or stabilization) and site treatment (dry
impoundments, mine-fill). For IAPCS-II, waste treat-
ment in the form of "conventional" fixation appears
universally acceptable and applicable. Conversely,
site treatment techniques appear to be unwieldy, expen-
sive, and site-specific.
Conventional chemical fixation involves the addition of
lime and fly ash (as well as water) to the sodium
wastes to generate an inert material environmentally
suitable for landfill. Because no calcium compounds
are present in the spent nahcolite, more lime may be
needed to drive the pozzolanic reaction, especially for
nonalkaline ashes associated with Eastern U.S. coals.
13. Nahcolite reactivity is a function of inlet flue gas
temperature; the optimum temperature is 550CF. Below
typical cold-side temperatures (275° to 325CF), S02
capture falls off dramatically. Minimum inlet gas
temperature is 275°F. Therefore, DSI downstream of
spray huiaidification represents an illegal combination.
4.7.2 Material Balance Considerations
The only change that occurs in the gas stream across the
injection point is an increase in PM loading (3.9 Ib of nahcolite
per Ib of inlet S0~). No SO- or NO absorption occurs (no suspen-
sion removal). No PM dropout occurs in the approach duct to the
4-30
-- .v
-------
downstream collection device. No significant changes occur in
gas temperature and pressure.
4.8 ELECTROSTATIC PRECIPITATOR
The enhancement of IAPCS from Version I to Version II in-
volved extensive modifications and refinements to the ESP module.
The most significant refinement involved the incorporation of
aspects of a model developed for EPA by Research Triangle
Institute and the incorporation of the resistivity prediction
2 6
method developed for EPA by Southern Research Institute. Based
on the ESP module contained in Version I of IAPCS, three tempera-
ture-resistivity relationships were incorporated: volume resis-
tivity, surface resistivity influenced by adsorbed water, and
surface resistivity influenced by adsorbed acid. These tempera-
ture-resistivity relationships were used to adjust the specific
collection area (SCA) predicted by the ESP module. The ESP
module in IAPCS-II is now sensitive to fly ash alkalinity, mois-
ture content, and sulfuric acid vapor with regard to resistivity;
however, a parameter file value is always used for resistivity
when LIME, is present in the system.
The module's cost equations estimate costs for the ESP,
ductwork, and ash handling system. A fan is not included in this
module (i.e., fan requirements are accounted for on a system
basis). The ESP cost equations are for ccld-side ESP's. The
equipment installation costs are estimated as a percentage of the
total equipment costs and added to the equipment cost to calcu-
late the total direct cost of an E£P system. Operating and
4-31
-------
maintenance (O&M) costs are estimated by equations that calculate
O&M labor, supervision, maintenance materials, and electricity
and water requirements. Cost equations for ESP and ductwork are
based on information prepared by PEI.
A new option in IAPCS-II allows for calculation of upgrade
cost (additional plate area) for the ESP due to performance
degradation of an existing ESP in the presence of LIMB. Calcula-
tion of upgrade-only costs will occur only if the following three
conditions are true:
I. LIMB is present.
2. The system is a retrofit.
3. The appropriate parameter file value is set to 1 (the
default).
If any of the above are false, costs for a new ESP will be calcu-
lated. The ESP performance will be reflected in any case.
The ESP is a cold-side insulated unit with a maximum possi-
ble PM removal efficiency of 99.9 percent. The cost estimated by
the module depends on the flue gas flow rate and the SCA measured
in square feet of plate area per 1000 acfm. The calculated SCA
depends on the ash resistivity and the required PM removal effi-
ciency. The matrix used to estimate the SCA requirements is
based on data presented by EPA as having been derived from the
27
EPA/SRI ESP computer model.
This matrix is used in the module to predict the SCA; re-
quired removals and resistivities other than those in the matrix
are interpolated by the program.
4-32
-------
The basis of the ductwork cost is the same as that described
for a FF (see Subsection 4.9). Estimates of duct layout and cost
are based on typical ESP parameters: gas velocity, plate spac-
ing, length-to-height ratio, flow rate, and SCA.
The ash handling system is based on design and costs devel-
oped for use in a U.S. Department of Energy study of coal conver-
o o
sion of 15 Florida powerplants. These costs are in mid-1982
dollars and reflect an ash storage silo configuration rather than
direct sluicing to an assumed onsite pond.
The ash system included for the ESP and FF modules consists
of the following components:
0 Under-device collection hoppers
0 Pneumatic piping
0 Vacuum producer
0 Dust collector (s) for the ash silo(s)
0 Three-day ash storage silos
This system has a number of advantages. Silo storage per-
mits access to the fly ash in the case of concomitant use of an
ESP or FF with lime spray drying. With this method of SO- con-
trol, large portions of the collected fly ash are used in the
recycle slurry. Further, soluble wastes (e.g., from the dry
sorbent injection module) may be safely stored prior to disposal.
Costs for this dry storage system are.higher than for an equiva-
lent wet disposal system, unless the cost of a lined pond is
included in the sluicing system. Capital cost validations were
confirmed with vendors for use in the preparation of the co^t
algorithms.
4-33
-------
Annual operating labor costs are based on the gas flow rate
to the ESP, and an estimated 15 percent of these costs are for
supervision. Maintenance materials are also estimated as a func-
tion of gas flow rate and are assumed to be equal to the mainte-
nance labor cost.
The cost of electricity for operation of the ESP is based on
a power density of 2.0 watts per square foot of ESP plate area
and the number of operating hours per year. Electricity and
water costs for the ash handling system also depend on the plant
capacity factor and the quantity of ash that is collected and
transported.
4.9 FABRIC FILTER
The module's cost equations estimate costs for an FF, duct-
work, and ash handling equipment. An incremental fan cost based
on the increased pressure drop in the FF is calculated as a sys-
tem cost, not part of the FF cost. Installation costs are esti-
mated as a percentage of the total equipment cost and are then
added to this cost to determine the total direct cost of the FF
system. The O&M costs are estimated by use of equations that
calculate O&M labor, supervision, maintenance materials, rebag-
ging expenses, electricity usage, and water requirements. Fabric
filter and ductwork cost equations are based on information
7 ft
published by EPA.
The FF is a reverse-air unit with a maximum removal effi-
ciency of 99.7 percent. The estimated cost is dependent upon the
flow rate and the air-to-cloth (A/C) ratio. The module assumes a
4-34
-------
default value of 2.0 acfm/ft2. When combined with the LIMB mod-
ule in an integrated system, the A/C ratio is assumed to be 1.5.
The ductwork is sized to provide a flue gas velocity of 3500
feet per minute. Although large utility systems generally use
rectangular ducts for ease of fabrication, circular ductwork is
assumed in this module to simplify calculations. Circular ducts
are structurally stronger and have more flow rate for a given
perimeter than rectangular ducts. The ductwork is insulated to
prevent condensation. The ductwork cost model considers two
different layouts: one for boilers with a capacity less than 650
MW and one for boilers in the 650- to 1300-MW range. The basic
difference between the two layouts is the length of the ductwork.
The fan cost is based on the flue gas flow rate and the
horsepower of the fan motor. The motor horsepower depends on the
pressure drop and the overall fan and motor efficiency.
The ash-handling system is a dry system. The pneumatic
piping, vacuum producer, and silo costs are based on the tons of
ash that are collected each hour by the FF.
The number of plant operating personnel required is based on
flow rate. Supervision is calculated to be 15 percent of the
operating labor cost. Maintenance labor is a function of the
size of the and maintenance materials and replacement parts are
assumed to be equal to the maintenance labor cost. Electricity
costs are calculated as a function of the horsepower of the
reverse-air fan and vacuum motors, the capacity factor of the
4-35
-------
plant (a measure of its operating time), and the cost of elec-
tricity. Water costs for the ash handling system also depend
upon the plant capacity factor and the quantity of ash that is
collected and transported.
4-36
l
x
-------
SECTION 5
INTEGRATED CHARACTERISTICS OF THE SYSTEM
The IAPCS-II model has been developed in part to provide a
unique view of the performance of an air emission control system
made up of individual modules. To this end, the performance of
the entire system is output, as well as the material balance
associated with each module in a specified control system.
Solid waste quantities are summed by module, and the cost of
disposal of both wet and dry waste components aie presented. The
ash storage and handling system of the PM collection device is
special in that it has the built-in capability to recycle por-
tions as required. A system that comprises storage silos and a
conveyor network is more costly than one that calls for direct
disposal to an ash pond, but the importance of recycle (espe-
cially of highly alkaline fly ash) cannot be overlooked.
Another integrated feature of the model involves the use of
a system fan module. The individual pressure drops for any
assembled control system are used to determine the overall horse-
power and cost of the induced-draft fan(s). This is a less
costly option for addressing the fan requirements than on a
module-by-module basis.
5-1
-------
The material balance is the single most important integrated
characteristic of the program. The relative significance of ap-
plication of a given technology on a system basis can be readily
assessed.
Finally, the emission summary and the cost-effectiveness
outputs permit easy comparison of integrated control configura-
tions from an economic standpoint.
5-2
-------
SECTION 6
COMPUTER PROGRAM STRUCTURE
6.1 PROGRAM ENVIRONMENT
TM
IAPCS-II has been converted to Microsoft FORTRAN 77 (Ver-
TM TM
sion 3.2) for use on the IBM PC AT or XT microcomputer.* The
model cannot be used on a floppy-disk-based system. The system
must include at least 512 kilobytes of random access memory and
run under the DOS 2.1 (XT) or 3.1 (AT) (or higher) operating
system. The user should have at least 1.5 megabytes available on
the hard disk.
The executable program files and all supporting data files
are provided on floppy disks in the PC DOS BACKUP format. Table 6-1
contains a description of these files.
The original version of IAPCS was designed as an interactive
system; IAPCS-II allows input via a "batch" file created with a
word processor or spreadsheet program. Section 6.3 provides
details on input requirements. Output reports can be transmitted
either to the console screen or the printer, or both at the
user's option.
*
IBM PC AT and IBM PC XT are trademark names of the IBM
Corporation.
6-1
-------
TABLE 6-1. IAPCS-II DISK FILES3
File name
MODULES.EXE
INPUT.EXE
OUTPUT.EXE
IAPCS.BAT
PARMFILE.TVA
T'ARMFILE.EPR
LOSTHELP.DOC
OPTHELP.DAT
PARMHELP.DAT
a
Description
Program executable file to size and cost control
modules.
Program executable file to gather input data and
perform initial gas stream and coal-cleaning
calculations.
Program executable file to site and cost system fan:
and waste disposal. Also makes economic
calculations and prints output reports.
DOS batch command file to run executsbles
sequentially.
TVA default parameter file.
EPRI default parameter file.
Help information for escalation.
Help information for optimization.
Help information for parameter editor.
Other temporary files are created by the program.
6-2
-------
6.2 PROGRAM STRUCTURE
6.2.1 Basic Structure
The program is designed to simulate numerically the effect
of the emission control modules, selected and tequenced by the
user, on the gas stream. Resources required by each module are
allocated and stored when the module is encountered. This leads
to a modular programming approach in that each module is general-
ly represented by a subroutine. The control configuration there-
fore determines when and if each of these subroutines is called.
Figure 6-1 illustrates the IAPCS-II program flow control.
Program flow is directed by the DRIVER, which initiates most
subroutine calls. Provisions for the PCC control option are also
made within DRIVER; there is no separate PCC subroutine. Sub-
routine INPUT solicits user input and reads a parameter file (see
file descriptions) of "preliminary" design and cost parameters.
INPUT also prints an input summary—the first output section.
Subroutine UNCNTL calculates 1) initial gas stream characteris-
tics, 2) the amount of bottom ash, 3) initial system performance,
and. 4) uncontrolled emissions.
Each of the control module routines selected is called by
DRIVER in the order specified by the user. Both direct and
indirect capital costs are calculated individually by each mod-
ule subroutine. Annual resource quantities are calculated here;
however, these are summed over the entire system and cost factors
applied in the output routine. Material balance calculations are
6-3
-------
Figure 6-1. General flow diagram of the IAPCS program.
6-4
-------
performed, and the gas stream characteristics (stored globally)
are modified for use by subsequent module subroutines. Data
pertinent to the design of certain modules are printed by the
module subroutines; this forms the becond output section.
Subroutine FANS is used to size and cost system fans.
Subroutine OUTPUT makes final boiler/system performance calcula-
tions, totals capital costs, and calculates annual costs. The
final six output sections are printed here. These are Boiler
System Performance, System Material Balance, Emission Summary,
Capital Costs, Annual Costs, and Cost-Effectiveness.
The user may optin-ize the cost for a particular emission
rate through subroutine OPT. This option will calculate a re-
moval efficiency for a control module chosen by the user and
rerun the program. The user is required to input a target emis-
sion rate.
Further program documentation may be foan-d in the source
program listing (Appendix B).
6.2.2 IAPCS-II Modifications
Although the program is conceptually the same in IAPCS-II as
in IAPCS-I, several structural changes were necessary because of
the incorporation of the Shawnee Model into IAPCS-II. The
Shawnee Model program alone is approximately four times the size
of IAPCS-I. Because the new program is so large, it was divided
into three smaller programs. The function of the first program
(INPUT) is to collect input data and make the "uncontrolled"
calculations. It then passes these data to the second program
(MODULES) via a temporary disk file. MODULES contains a driver
6-5
-------
program that calls, in the proper sequence, all control modules
selected by the user. It then writes all necessary calculated
values in a disk file for use by the third program (OUTPUT),
OUTPUT calculates costs and writes the final output report.
Figure 6-1 shows the division of IAPCS-II operations among the
three programs.
A batch file has been created to execute three IAPCS-II pro-
grams sequentially so that it appears to the user as if only one
program is executed.
As stated previously, the Shawnee Model has replaced the
original IAPCS-I FGD algorithms and subroutine. IAPCS-II still
regards FGD as a single subroutine (refer to the subroutine tree
diagram in Figure 6-2). Certain user options, and therefore
subroutines, were not included, however. Also, the fan and waste
disposal cost algorithms are included with subroutines in the
OUTPUT program of IAPCS-II.
6.3 USER INFORMATION
IAPCS-II is provided on floppy disks and is loaded onto a
hard disk by using the DOS RESTORE command.
IAPCS-II has two input methods: batch and interactive. The
interactive method is the same as in the original version of
IAPCS; the user is queried by the program for all pertinent in-
formation. All questions asked by the program must be answered;
defaults, when shown, must be entered by the user.
6-6
'&-tt&i&&t'yte
-------
1
-J
DATA GENERATE
BY H*
INPUT
CATE TO BE
USED BY
OUTPUT
V.
1APCS2
Figure 6-2. Subroutine tree diagram.
-------
The batch method of input entails the use of batch files of
input data created by a spreadsheet or word processor program.
This method is not as straightforward as the interactive method
and should be undertaken only by users with a working knowledge
of a suitable spreadsheet of an ASCII word processor program.
The advantage of this method over the interactive method is the
ability to save input data so that multiple runs with similar
data can be made without the need to reenter all the input. An
internally documented template for a batch input file (Figure
6-3) is provided on the IAPCS-II program disks. To use this
template, the user calls up the template file into a standard
ASCII word processor, makes changes, and then saves the file
under another name.
The line entries (records) in the template file correspond
to the interactive input entries. The actual input data are
contained at the beginning of each record up to the vertical bar.
At least one blank space should follow the input data entry
(immediately preceding the vertical bar). Text describing the
input element follows the bar. This descriptive information can
be deleted if desired.
Batch files may vary in length based the type of coal used
(typical, ROM, or clean), the number of modules, and the number
of modules to be optimized. If the user enters a typical coal
type code, all ROM characteristics (all entries from coal type to
cleaning level) must be deleted. If a clean, user-defined coal
is desired, the characteristics for the clean coal should immedi-
ately follow the ROM characteristics.
6-8
-------
EXAMPLE OF IAPCS2 BATCH FILE I COMMENT LINE 1
TEMPLATE. . I COMMENT LINE 2
1 I 1= TVA ECONOMIC FORMAT? 2= EPRI FORMAT
TVAPARMS I PARAMETER FILE NAME; MUST BE CONSISTENT WITH ECONOMIC FORMAT:
2 i— i- WALL FIRED; 2= TANGENTIAL
500 I BOILER SIZE, MW
62.8 I CAPACITY FACTOR, '/.
1 I CONSTRUCTION STATUS, 1 NEW, 2 = RETROFIT
1986 I DATE OF COMMERCIAL OPERATION, YYYY
300 I INITIAL GAS TEMPERATURE, DEC.F
2 I 1= TYPICAL COAL TYPE! 2= USER-DEFINED COAL
1 I TYPICAL COAL TYPE (1-6) OR GENERAL COAL TYPE (1-3) FOR USER COAL
11700
3. 36
15.1
0
0
i?
0. 1
0
4.00
40. 45
40. 45
N
1
1
1
8
N
END
*** ALL ENTRIES HERE DOWN TO CLEANING OPTION GMI"
*** FOR TYPICAL COAL
ROM HHV, BTU/#
ROM 7. SULFUR
ROM '/. ASH
ROM COST, S/TON
ROM '/. NA20
ROM •/. ALKALINITY
ROM '/. CHLORINE
ROM '/. FE203
ROM 7. MOISTURE
ROM X. VOLATILE MATTER
ROM '/, FIXED CARBON
CLEAN COAL OPTION:.Y OR N FOR USER COAL; 2(YES) OR 1 FOR TYPICAL
— 1= DRY BOTTOM; 2=WET *** INSERT CLEAN COAL SPECS ABOVE THIS LINE
PRINTOUT OPTION: 1- PRINTER:2= DISPLAY;3= BOTH.
NUMBER OF CONTROL MODULES.
CONTROL MODULE NUMBERS. ONE LINE FOR EACH MODULE NUMBER!
OPTIMIZATION OPTION: Y(ES) OR N(O>;
Fiaure 6-3. Batch input file template.
6-9
-------
Two further points should be noted regarding batch files.
The two blank lines at the beginning of the file must always be
present. Also, the user may configure the batch file so that a
subsequent batch run is begun after the current run terminates.
This "chaining" is done by entering the name of the next batch
file on the final record of the current batch file.
Errors resulting in program termination frequently occur
because an incorrect number of input records are in the batch
file or because records are our of sequence. If an error occurs
during a batch run, the user should check to make sure the number
and order of records are consistent with regard to coal type and
cleaning level, number of modules, and optimization.
Once the user has installed the program and decided on an
input method, he/she is ready to run. The user logs int.o the
IAPCS directory and types: IAPCS ("" is the command to
press the carriage return). This command invokes the DOS command
file that executes the three IAPCS-TI programs.
Depending on the input options selected, output will be sent
to the screen, to the printer, or to both. After the output is
printed, the user is asked if he/she wishes to optimize. If so,
a new emissions rate must be entered. All calculations and
output are then repeated. The user may optimize as often as
desired.
6.4 IAPCS-II PROGRAM LISTING
Appendix C represents the entire IAPCS-II program listing.
A large amount of the program documentation is provided in the
comment statements of the listing.
6-10
-------
SECTION 7
SUMMARY OF INSTALLATION AND OPERATION PROCEDURES FOR IAPCS-II
1. Configure system files.
It is recommended that the CONFIG.SYS file (usually in the
root directory of the boot drive) contain the command "BREAK=ON";
this will allow the user to stop a run at any time during execu-
tion.
If an IBM PC/AT (or compatible) is used with an 80287 math
coprocessor, the following command must be in the AUTOEXEC.BAT
file when the system is booted:
SET NO87 = FALSE
The user should refer to the DOS manual for information
regarding CONFIG.SYS and AUTOEXEC.BAT.
2. Create a directory on a hard disk for the IAPCS files.
The user should log onto the root directory of the "C" drive
(or other hard disk) ot his/her computer and then enter the
following DOS commands:
MD IAPCS
CD IAPCS
Once the directory has been created ("MD"), only the "CD" need be
performed when the program is subsequently accessed.
3. Restore all files into the IAPCS directory.
The user should enter the following command:
RESTORE A: C:
7-1
-------
He/she will be prompted to insert the program disks in sequence.
[The above three steps need only be performed once (except
for the "CD" command in step 2 which must be entered each time
the program is run).]
4. Run the program.
The user should enter the following command:
IAPCS
The program will then begin operation. During the course of a
run, several extraneous messages may appear on the screen; these
are normal and should be ignored. Examples of these massages are
"FALSE" and File not found.
The input to the program is in five basic sections or
"screens." These are discussed separately elsewhere in the
manual, but are summarized below:
a) Input method option and economic format.
Entering an "I" followed by a carriage return in re-
sponse to the initial- question will cause the inter-
active input sequence to proceed. Otherwise, the IAPCS-
directory will be searched for the fully qualified
batch input file named by the user and no further user
prompts will be given. There will be a noticeable
delay after this screen.
b) Parameter menus and submenus.
The user should enter menu option numbers or other
information as prompted. In general, entering a zero
for a submenu option will return the user to a higher
menu level. Option 5 on the parameter menu will move
the user to the next input section.
c) General design input.
Input questions will scroll past as the user responds
to questions. The user should stay within stated
ranges for numeric entries.
7-2
-------
d) Control system configuration.
Option numbers for control modules are listed. Selec-
ted option numbers should be entered in order, on one
line, separated by commas. Although any combination of
modules may be entered, nonsensical configurations may
result in an error termination of the program or un-
trustworthy output. It is advised that the user abide
by the configuration rules displayed on the screen.
After the system configuration has been entered, the
user will be given an opportunity to edit his/her
entries. The program will then run, and output will be
printed and/or displayed.
e) Optimization.
If an optimizable module is in the control system, the
user will be given an opportunity to optimize. The
user must select one module to be optimized and select
a target emission rate for the pollutant that this
module removes. Please note that all modules except
LIMB must be given an emission rate higher than the
calculated value that is displayed on the screen. Also
emission rates that would result in negative efficien-
cies may cause the program to abort or cause other
unpredictable results.
5. Troubleshooting
The following are potential problems that may be encountered
when running IAPCS-II:
° Parameter file does'not exist
The user should check to make sure that the economic
format used is consistent with the one used when the file
was created. The DOS command "dir" should be used to verify
the file's existence.
0 Program continuously gives error messages (or terminates
with a single error message)
The user should hold down the control key ("Ctrl") and
press "Scroll Lock" (Break). This should be done repeatedly
until the program stops. If the break set is not on (see
number 1 above), the user may have to re-boot.
The program may get into this error loop (or, more
likely, simply terminate with an error message) for several
reasons. Some typical reasons are:
7-^.
-------
An input item or parameter has an unreasonable
value (possibly zero or negative).
A nonsensical control system was specified.
- Batch file input records are missing or out of
sequence.
An invalid optimization was attempted.
On an AT with a math coprocessor, N087 = FALSE was
not specified (See 1. Above).
The computer "just sits there" (no output, no hard disk
activity)
Although this is sometimes natural (especially when wet
FGD is present in the system), if it continues for longer
than 5 minutes the user should attempt to "break"; however,
rebooting will probably be necessary. (To perform a "warm-
boot" , user should hold down the "Ctrl", "Alt", and "Del"
keys simultaneously and then release them.)
Any of the problems capable of causing an error termi-
nation or loop could also cause this problem.
7-4
-------
> SECTION 8
REFERENCES
1. Sudhoff, ?. A., and R. L. Torstrick. Shawnee Flue Gas
Desulfurization Computer Model User's Manual. EPA-
600/8-85-006 (NTIS PB85-243111); TVA/OP/EDT-84/37, March
1985.
2. EPRI 1981. Technical Assessment Guide — 1981 Edition.
Electric Power Research Institute.
3. U.S. Environmental Protection Agency. Supplement No. 13 for
AP-42. Compilation of Air Pollutant Emissions Factors,
Third Edition (NTIS PB83-126557); Research Triangle Park,
North Carolina. August 1982.
4. Bechtel, Inc. Coal-Fired Power Plant Capital Cost Esti-
mates. EPRI report number TPS-78-810 Palo Alto, California.
May 1981.
5. Versar, Inc. Effect of Physical Coal Cleaning on Sulfur
Content and Variability, EPA-600/7-80-107 (NTIS PB8C-210529);
U.S. Environmental Protection Agency, May 1980.
6. Hoffman-Holt, Inc. Engineering/Economic Analysis of Coal
Preparation with Flue-Ga^ Desulfurization for Keeping Higher-
Sulfur Coals in the Energy Market. Silver Springs, Maryland,
1982.
7. PEDCo Environmental, Inc., and Black and Veatch. Limestone
FGD Scrubbers: Users Handbook, EPA-600/8-81-017 (NTIS
PB82-106212); U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina, August 1981.
8. Singer, J. (editor). Combustion Fossil Power Systems.
Combustion Engineering, Inc. 1981. p. 3-12 to 3-22.
9.. Lachapelle, D. G. , et al. EPA's LIMB Cost Model: Development
and Comparative Case Studies. In: Proceedings: First
Joint Symposium on Dry SO0 and Simultaneous S02/NO Control
Technologies, Volume 2, EPA-600/9-85-020b (NTIS PB$5-232361),
July 1985.
3-1
-------
10. Davis, R. A., et al. Dry Scrubber Maintains High Efficiency.
Power Engineering, October 1979. p. 85.
11. Meyler, James. Dry Flue Gas Scrubbing. A Technique for the
1980's. Combustion. February 1981, Vol. 52, No. 8, pg. 23.
12. Joy Manufacturing/Niro Atomizer. Flue Gas Desulfurization
by Dry Scrubbing in Spray Dryer Absorbers. A presentation
of papers from a Niro Seminar at the company's headquarters,
September 19"*8.
13. Estcourt, V. F., et al. Tests of a Two-Stage Combined Dry
Scrubber/SO2 Absorber Using Sodium or Calcium. Presented at
the 40th American Power Conference, April 1978.
14. Burnett, T. A., et al. Spray-Dryer FGD: Technical Review
and Economic Assessment. In: Proceedings Symposium on Flue
Gas Desulfurization, Houston, October 1980, Volume 2, EPA-
600/9-81-019b (NTIS PB81-243164), April 1981.
15. Ireland, P. A. Status of Spray-Dryer Flue Gas Desulfuriza-
tion, CS-2209, Final Report, Electric Power Research Insti-
tute, Palo Alto, California, 1982.
16. Blythe, G. M., et al. Survey of Dry SO2 Control Systems,
EPA-600/7-80-030 (NTIS PB80-166853), U.S. Environmental
Protection Agency, February 1980.
17. McGlamery, G. G., et al. FGD Economics in 1980. In:
Proceedings: Symposium on Flue Gas Desulfurization, Hous-
ton, October 1980, Volume 1. EPA-600/9-81-019a {NTIS
PB81-243156), April 1981.
18. Muzio, et al. Bench-Scale Study of the Dry Removal of S02
with Nahcolite and Trona. EPRI CS-1744, Research Project
982-8. March 1981.
19. Muzio, et al. Dry S02-Particulate Removal for Coal-Fired
Boilers. Volume 1: Demonstration of SO2 Removal on a 22-MW
Coal-Firing Utility Boiler by Dry Injection of Nahcolite.
EPRI CS-2P94, Research Project 1682-2. March 1983.
20. Lapp, et al. 1980. Use of Nahcolite for Coal-Fired Power
Plants. Environmental and Economic Considerations in Energy
Utilizations - Proceedings of the 7th National Conference on
Energy and the Environment. November 20 - December 3, 1980.
21. Stearns, Conrad and Schmidt Consulting Engineers, 1981.
Recovery, Utilization, and-Disposal of Solid By-Products
Generated by Dry Flue Gas Desulfurization Systems: State of
the Art and Research Needs. CS-1765, Research Project
1260-16. March 1981.
8-2
-------
22. Muzio, et al. Demonstration of S02 Removal on a Coal-Fired
Boiler by Injection of Dry Sodium Compounds. In: Proceedings:
Symposium on Flue Gas Desulfurization, Volume 2, EPA-6CO/9-83-
020b (NTIS PB84-110584), October 1983.
23. Radian 1982. Characteristics of Waste Products from Dry
Scrubbing Systems. EPRI CS-2766, Research Project 1870-2.
December 1982.
24. Parsons, E. L., Jr., et al. S02 Removal by Dry FGD. In:
Proceedings: Symposium on Flue Gas Desulfurization, Houston,
October 1980, Volume 2, EPA-600/9-81-019b (NTIS
PB81-243164), April 1981.
25. Viner, A. S., and D. S. Ensor. Computer Programs for Esti-
mating the Cost of Particulate Control Equipment. U.S.
Environmental Protection Agency, April 1984. EPA-600/7-84-
054 (NTIS PB84-183573).
26. Bickelhaupt, R. E. Fly Ash Resistivity Prediction Improve-
ment with Emphasis on Sulfur Trioxide. EPA-600/7-86-010
(NTIS PB86-178126), March 1986.
27- Sparks, L.E. U.S. EPA, AEERL. Letter to B. A. Laseke, PEI
Associates, Inc. November 25, 1985.
28. PEDCo Environmental, Inc. Coal Conversion of Fifteen Flor-
ida Power Plants. Prepared for the Department of Energy.
December 1982.
8-3
-------
APPENDIX A
PARAMETER FILE LISTING
A-l
-------
EPRI DEFAULT PARAMETER FILE
A-2
-------
PARMFILE.EPR
System Wide
VALUE
.8845
7914.
DESCRIPTION
100.0
.5001?
.9950
.0000
1.000
7.500
10.00
10.00
15.03
10. 00
.0000
.0300
. 0000
3.000
35.00
.0000
32. e0
5.000
.0000
9999.
75.00
95.00
5280.
1.000
12.00
1.000
BASE THERMAL EFFICIENCY
GROSS HEAT RATE, BTU/KWH
BOILER MET HEAT RATE (CALCULATED IF ZERO), BTU/KWH
BOILER LOAD, %
SOLID COMBUSTIBLE LOSS, X
COMBUSTIBLE LOSS CORRECTION FACTOR, FRACTION
FLOW RATE, ACFM (CALCULATED IF ZERO)
DEFAULT HA20 CONTENT OF ASH, %
SALES TAX AND FREIGHT, % PROCESS CAPITAL (WASTE)
ENGINEERING AMD HOME OFFICE FEES, '/. PROCESS CAPITAL (WASTE)
GENERAL FACILITIES, % PROCESS CAPITAL
-------
PARHFILE.FPR
aes;s3= = = sic = E = ca
Unctrl Coal
VALUE DESCRIPTION
.3000 DEFAULT PARTICULATE OVERHEAD RATIO, IF ZERO, AP 42 USED, FRACT
.0002. DEFAULT S02 OVERHEAD RATIO. IF ZERO, AP 42 EMISSION FACTORS USED
.5000 PARTICULATE DRY-BOTTOM EMISSION FACTOR(A?42 SUPLMT.13 REV),FRACT
.3500 PARTICULAPE WET-BOTTOM EMISSION FACTOR (IBID), FRACTION
.3150 PARTICULATE LIGNITE EMISSION FACTOR (IBID), FRACTION
.9750 SG2 BITUMINOUS EMISSION FACTOR (IBID), FRACTION
.8750 S02 SUB-BITUMINOUS EMISSION FACTOR (IBID), FRACTION
.7500 S02 LIGNITE EMISSION FACTOR (IBID), FRACTION
,5250 NOX WALL FIRED BITUMINQUS/SUB-BITUM DRY-BOTTOR (IBID), FRACTION
.3500 NOX WALL FIRED LIGNITE DRY-BOTTOM (IBID), FRACTION
.3750 NOX TANGEN. FIRED BITUMTNOUS/SUB-BITUH. DRY BOTTOM (IBID), FRACT
.2000 NOX TANGENTIAL LIGNITE DRY-BOTTOM
.8502 NOX ALL WET-BOTTOM (AS ABOVE)
9820. PC F-FACTOR (IBiD, DSCF/MMB7U)
.2000 EXCESS AIR, FRACTION
A-4
-------
PARHFILE.EPR
Fan
VALUE DESCRIPTIQH
10,00 ENGINEERING AND HOME OFFICE FEES. X PROCESS CAPITAL (FANS)
10.00 GENERAL FACILITIES, % PROCESS CAPITAL (FAHS)
15.00 PROJECT CONTINGENCY. % PROCESS CAPITAL (FANS)
10.08 PROCESS CONTINGENCY, % PROCESS CAPITAL (FAHS)
.008® SALES TAX, % PROCESS CAPITAL (FANS)
.0300 ROYALTY ALLOWAliCE, V. PROCESS CAPITAL (FANS)
4.000 MAINTENANCE LABOR AND MATERIAL, % TOTAL PROCESS CAPITAL (FAKS)
.0000 INVENTORY CAPITAL, % PROCESS CAPITAL (FANS)
1.000 FAH RETROFIT FACTOR, DIMENSIONLESS
A-5
-------
PARMFILE.EPR
Economic
VALUE
10.00
30.00
15.00
11.00
50.0S
11.50
15.00
15.30
50.00
8.500
2.000
.6000
3.000
.0000
30.30
.0000
.0000
8507.
325.0
3¥ . 7
264.9
113.0
DESCRIPTION
0 & M LEVELIZATION FACTOR (CALCULATED IF ZERO), DIMENSIOKLESS
CAPITAL LEVELIZATION FACTOR (CALCULATED IF ZERO), DIPSEMSIONLESS
ITC INVESTMENT TAX CREDIT, '/.
BOOK LIFE, YEARS
TAX LIFE, YEARS
COST OF DEBT, 7.
DEBT RATIO, '/.
COST PREFERRED STOCK, '/.
PREFERRED RATIO, %
COST OF COKKON STOCK, '/. (COMMON RATIO= 100'/.-PR-OR)
FEDERAL AND STATE INCOME TAX, */.
Bl
Pi
CD
DR
CP
PR
CE
TX
El INFLATION RATE, V.
PTI PROPERTY TAX AND INSURANCE, %
ER REAL ANNUAL ESCALATION RATE, %
TDM: 1=ACC.DEPR, J2=STRT.LN.OVER Bl;3=STRT.LN.ON ACRS SCHED.
DISCOUNT RATE, % CALCULATED FROM ABOVE IF 0
ADMINISTRATIVE AND SUPPORT LABOR FACTOR <% OF O&H LABOR)
YEAR OF CAP COSTS(YYMM), IF 0. , JUKE, 1982 (BASE YEAR) USED
YEAR OF O&M COSTS(YYHK), IF 0., JUHE, 1982 (BASE YEAR) USED
DATE OF CE AND OSH INDICES, YYMM
CE PLANT INDEX FOR CORRESPONDING YEAR AND MONTH OF COST
CE MATERIAL INDEX FOR CORRESPONDING YEAR AND MONTH OF COST
CE LABOR INDEX FOR CORRESPONDING YEAR AHD MONTH OF COST
0&M INDEX FOR CORRESPONDING YEAR AND MONTH OF COST (6/82=100)
A-6
-------
'" ' '
VALUE
PARHFIL;:. EPR
LSD
DESCRIPTION
1.530 STOICHIOMETRIC RATIO (LSD)
80.00 UTILIZATION OF FLY ASH ALKALINITY, % (LSD)
53.00 AVERAGE MOLECULAR WEIGHT OF ALKALINITY IN FLY ASK
.7250 FRESH LIME COMPONENT OF SLURRY, FRACTION (LSD)
85.80 MAXIMUM EFFICIENCY OF LSD, '/ (LSD)
35.00 MAXIMUM SOLIDS IN SLURRY BY WEIGHT, 7.
4.636 MAXIMUM REACTIVE ALKALINITY/MEGAWATT (LSD)
10.00 MAXIMUM EFFICIENCY OF FLY ASH ALKALINITY, % (LSD)
1.5G0 MODIFIED PARTICULATE LOADING EXITING SPRAY DRYER, FRACT. (LSD)
160.0 SPRAY DOWN TEMPERATURE, DEG.F (LSD)
6.000 PRESSURE DROP ACROSS DRYER, IN. H20 (LSD)
2.000 INSTALLATION FACTOR, DIMENSIONLESS (LSD)
10.00 GENERAL FACILITIES, 7. PROCESS CAPITAL (LSD)
10.00 ENGINEERING AND HOME OFFICE FEES, 7. PROCESS CAPITAL (LSD)
15.00 PROJECT CONTINGENCY, 7. PROCESS CAPITAL (LSD)
15.00 PROCESS CONTINGENCY, '/. PROCESS CAPITAL (LSD)
.0000 SALES TAX, % PROCESS CAPITAL (LSD)
.04)00 ROYALTY ALLOWANCE FACTOR, % PROCESS CAPIT/L (LSD)
.0000 REACTIVE ALKALINITY FACTOR FOR BITUMINOUS COAL, FRACTION (LSD)
.2500 REACTIVE ALKALINITY FACTOR FOR SUB-BITUMINOUS COAL, FRACTION (LS
.2000 REACTIVE ALKALINITY FACTOR FOR LIGNITE COAL, FRACTION (LSD)
.4302E+05 OPER/TlNG AND SUPERVISION LABOR.. KANHOURS/YEAR (LSD)
.4300 L3D ELECTRIC USEAGE, '/. GROSS KILOWATTS (LSD)
1.500 LSD REPLACEMENT PARTS COST FACTOR, 7. TOTAL EQP COST (LSD)
6.000 MAINTENANCE LABOR AND MATERIAL, 7. OF TOT. PROCESS CAP. (LSD)
.0000 INVENTORY CAPITAL, 7. PROCESS CAPITAL (LSD)
1.000 LSD RETROFIT FACTOR, DIMENSIONLESS
A-7
-------
PARMFSLE.EPR
Low Kox/Over
VALUE DESCRIPTION
118.80 ENGINEERING AND HOME OFFICE FEES, X PROCESS CAPITAL (INBOF)
18.00 GENERAL FACILITIES, % PROCESS CAPITAL (LHB'JF)
15.00 PROJECT CONTINGENCY,, X PROCESS CAPITAL
10.00 PROCESS CONTINGENCY, X PROCESS CAPITAL (LNBOF)
.21000 ROYALTY ALLOWANCE COST FACTOR, X PROCESS CAPITAL (LNBOF)
,0000 SALES TAX, X PROCESS CAP'ITAL (LNEOF)
2.003 MAINTENANCE LABOR AND MATERIAL, % OF TOT. PROCESS CAP. (LNEOF)
.0000 INVENTORY CAPITAL, X PROCESS CAPITAL (LNBOF)
-------
PARMFILE.EPR
asamiasos: SKtsarssa
Fabr. Filter
VALUE DESCRIPTION
1.030 AIR-TO-CLOTH RATIO, CFM/SQUARE FOOT (FF)
19.70 FABRIC FILTER EFFICIENCY, X (Ff)
0.80 MINIHUH BYPASS, X (FF)
1.020 INSTALLATION AND FREIGHT COST FACTOR, DIMEHSIONLESS (FF)
,0.4)0 ENGINEERING AND HOfiE OFFICE FEES, % PROCESS CAPITAL (FF)
,8U'0 GENERAL FACILITIES, X PROCESS CAPITAL (FF)
,5.00 PROJECT CONTINGENCY, X PROCESS CAPITAL (FF)
IB.03 PRGCE5JS CONTINGENCY, X PROCESS CAPITAL (FF)
SALES TAX, X PROCESS CAPITAL (FF)
ROYALTY ALLOWANCE, X PROCESS CAPITAL
-------
PARMFILE.EPR
ESP
VALUE
DESCRIPTION
99.90 MAXIMUM REMOVAL EFFICIENCY, % = 53051W) UNITS, DIMENSIONLESS (ESP)
103.0 SIZING FACTOR FOR ASH SILOS, TONS/HOUR/SILO (ESP)
10.00 ENGINEERING AND HOME OFFICE FEES, 7. OF PROCESS CAPITAL (ESP)
10.00 fiENERAL FACILITIES, X OF PROCESS CAPITAL (ESP)
15.00 PROJECT CONTINGENCY, '/. OF PROCESS CAPITAL (ESP)
10.00 PROCESS CONTINGENCY, "/. OF PROCESS CAPITAL (ESP)
,0000 SALES TAX, '/. OF PROCESS CAPITAL (ESP)
.0000 ROYALTY ALLOWANCE, '/. OF PROCESS CAPITAL (ESP)
15.00 PERCENT SUPERVISION TO OPERATING LABOR, '/. (ESP)
20.00 WATER TO ASH BY WEIGHT, % (ESP)
1.000 PRESSURE DROP ACROSS ESP, IN. H20
,0000 S02 EFFICIENCY OF ESP PRECEEDED BY LIMB, '/. (ESP)
,0000 S02 EFFICIENCY OF ESP PRECEEDED BY SPRAY HUMIDIFICATION,'/.(ESP >
.0000 SQ2 EFFICIENCY OF ESP PRSCEEDED BY LSD, V. (ESP)
,0000 E02 EFFICIENCY OF ESP PRECEEDED BY DSI, '/. (ESP)
',4.000 MAINTENANCE LABOR AND MATERIAL, '/. TOT. PROCESS CAPITAL(ESP)
,0000 ASH RESISTIVITY, 1©**9 OHH-CH (CALCULATED FROM COAL SULFUR IF ©>
1500. ASH RESISTIVITY IN PRESENCE OF LIMB, 10»«9 OHM-CM
.0000 INVENTORY CAPITAL, % PROCESS CAPITAL (ESP)
1.000 ESP RETROFIT FACTOR, DIMENSIONLESS
A-10
-------
PARMFILE.EPR
LIMB
VALUE DESCRIPTION
2.000 STOICHIOMETRIC RATIO (LIMB)
7.000 1-CALC.LMST 2-DOL. LHST 3-CALC. HYD 4-DOL. HYD 5-CPH S-DPH7-LS8-L
95.00 SORBENT PURITY, '/. (LIMB)
5.000 NUMBER OF JOBS (LIHB)
10.00 ENGINEERING AND HOME OFFICE FEES, % PROCESS CAPITAL (LIMB)
10.00 GENERAL FACILITIES, '/. PROCESS CAPITAL (LIMB)
,25.00 PROJECT CONTINGENCY, % PROCESS CAPITAL (LIKB)
20.00 PROCESS CONTINGENCY, % PROCESS CAPITAL (LIHB)
,0000 SALES TAX, % PROCESS CAPITAL (LI.iB)
,&000 ROYALTY ALLOWANCE, % PROCESS CAPITAL COST (LIMB)
,5000 CAPTURE EFFICIENCY RANGE SPAM, FRACTION
15.00 SUPERVISION, % OPERATING MANHOURS (LIHB)
700.0 QUENCH RATE, DEG. F/SEG
',4.000 MAINTENANCE LABOR AND MATERIAL, % OF PROCESS CAPITAL (LIMB)
1.000 ASSUME ESP COST IS UPGRADE FOR LIMB RETROFIT < 1 = TRUE, 0 = FAL£E)
!,B000 FRACTION FLYASH, REMAINDER IS BOTTOM ASH (LIMB)
115.00 ADDITIVE S03 CONCENTRATION, PPM
A-11
-------
PARMFILE.EPR
Spray Humid.
VALUE
DESCRIPTION
3500. GAS VELOCITY IN S. H. CHAMBER, FT/MIH (SH)
1.250 EXTRA FABRICATION COST FACTOR (l.+25%)
-------
PARKFILE.EPR
DSI
VALUE
3. 000
70.00
65.00
1.500
80.00
10,00
10.00
20.20
20.00
.0000
.0000
2400.
4.000
1.500
.0000
.0000
1.1
DESCRIPTION
HOLAR STOICHIOMETRIC RATIO (DSI)
NAHCOLTTE PURITY, 7. (DSI)
PERCENT SOLIDS IN FIXATION WASTE STREAM (DSI)
FIXATION COST FACTOR, DIKENSIONLESS (DSI)
DSI EFFICIENCY , 7. (DSI)
ENGINEERING AND HOKE OFFICE FEES, % (DSI)
GENERAL FACILITIES, % PROCESS CAPITAL (DSI)
PROJECT CONTINGENCY, % PROCESS CAPITAL (DSI)
PROCESS CONTINGENCY, % PROCESS CAPITAL (DSI)
SALES TAX, % PROCESS CAPITAL (DSI)
ROYALTY ALLOWANCE, 7. PROCESS CAPITAL (DSI)
OPERATING AND SUPERVISION HAHHOURS/YEAR (DSI)
MAINTENANCE LABOR AND MATERIAL, % TOTAL PROCESS CAPITAL (DSI)
NORMAL STOICHIOMETRIC RATIO (DSI)
INITIAL CATALYST, 7. TOTAL PROCESS CAPITAL (DSI)
INVENTORY CAPITAL, '/. PROCESS CAPITAL (DSI)
DSI RETROFIT FACTOR, DIHENSIONLESS
A-13
-------
PARMFILE.EPR
FED System
VALUE
DESCRIPTION
9
|0
iOE-01
80
00
80
00
30
00
0.
00
50
00
00
00
00
00
M0
00
00
00
03
SRIN STOICHIOHETRIC P.ATIO (FGD)
XS02 MAXIMUM REHOVAL EFFICIENCY, '/, (FGD)
FGD RETROFIT FACTOR, DIHEHSIONLESS
KLG L/C RATIO FOR SCRUBBER, GALLONS/ 1000 CU. FT.
ISR L/G, EFFICIENCY CONTROL VARIABLE (0,1,2)
XESP PARTICIPATE COLLECTION OPTION (©,1,2)
XRH REHEAT OPTION (0,2)
TSK TEMPERATURE OF STACK GAS, DEC. F.
TSTEAM TEMPERATURE OF REHEATER STEAM, DEG. F.
HVS HEAT OF VAPORIZATION OF REHEATER STEAM, BTU/LB
IASH UNIT OF MEASURE OPTIOH FOR PARTICIPATE REMOVAL* 0r 1, 2, 3)
ASHUPS VALUE FOR PARTICIPATE REMOVAL UPSTREAH FROM SCRUBBER
VLG L/G RATIO IN VENTl'RI, GALLONS/I©©^ CU FT
VTR VENTURI/OXIDATION HOLD TANK RESIDENCE TIKE, MIN
V SCRUBBER GAS VELOCITY, FT/SEC
VRH SUPERFICIAL GAS VELOCITY THROUGH REHE/.TER, FT/SEC
TR RECIRCliLATION/OXIDATION HOLD TANK RESIDENCE TIKE, MIH
IALK ALKALI ADDITION OPTIOH (1,2)
IADD CHEMICAL ADDITIVE OPTION (0,1,2)
WPMGO SOLUBLE MGO IH LIffESTONE OR LIKE, WT % DRY BASIS
XNGOAD SOLUBLE MGO ADDED TO SYSTEM, LB/100 LB LIMESTONE
AD ADIPIC ACID IN SCRUBBING LIQUID, PPttW
ADDC ADIPIC ACID DEGRADATIOH CONSTANT
WPI INSOLUBLES IH LIMESTONE-LIME ADDITIVE, WT X DRY BASIS
WPM MOISTURE IH LIMESTONE-LIKE ADDITIVE, LB/103 LB DRY BASIS
WPS SOLIDS IN RECYCLE SURRY TO SCRUBBER, WT %
PSD SOLIDS IN SLUDGE DISCHARGE, WT %
RS THICKENER SOLIDS SETTLING RATE, FT/HR
PSC PERCENT SOLIDS IN THICKENER UNDERFLOW, WT X
IFOX FORCED OXIDATION OPTION (0,1,2,3)
OX OXIDATION OF SULFITE IN SRUBBER LIQUID, MOLE X
SRAIR AIR STOICHIOMETRY VALUE, ROLES OXYGEN/MOLE S02 ABSORBED
PSF PERCENT SOLIDS IN FILTER CAKE, WT X
FILRAT FILTRATION RATE, TONS/SQ FT/DAY
PHL.IME RECALCULATION LIQUOR PH
IVPD VENTURI -P- OPTIOH (0,1)
VPD VALUE FOR EITHER -P- OR THROAT VELOCITY, IN H20 OR FT/SE
DELTAP OVERRIDE -P- FOR ENTIRE SYSTEM, IN H20
PRES SCRUBBER PRESSURE, PSIA
IFAN FAN OFTION (0,1)
ISCRUB SCRUBBING OPTION (1,2,3,4,5,6)
XNS NUMBER OF TCA STAGES
XNG NUMBER OF TCA GRIDS
HS HEIGHT OF SPHERES PER STAGE, IN
WINDEX LIMESTONE HARDNESS WORK INDEX FACTOR, DIMENSIONLESS
HPTONW FINENESS OF GRIND INCEX FACTOR, HP/TON
NOREDN NUMBER OF SPARE SCRUBBER TRAINS
PCNTRN ENTRAINMEHT LEVEL OF WET GAS, WT 7.
NSPREP NUHBE:; OF SPARE PREPARATION UNITS
HOTRAN NUMBER OF OPERATING SCRUBBER TRAINS
EXSAIR EXCESS AIR, X
A-14
-------
PARHFILE.EPR
siarGffiesssGiBttKffiftss
FGD Econs
VALUE DESCRIPTION
.0000 SALES TAX. % PROCESS CAPITAL
.000S ROYALTY ALLOWANCE, X PROCESS CAPITAL (FGD)
.0300 MAINTENANCE LABOR AND MATERIALS, % PROCESS CAPITAL
4.P00 TXSAT SALES TAX RATE, %
3.500 FRRAT FREIGHT RATE, V,
6.000 SERVRT SERVICES, UTILITIES, AND MISCELLANEOUS, % TPC
A-15
-------
PARMFILE.EPR
VALUE
Coat based
JUNE,
1986
DESCRIPTION
78.70 SULFUR COST <$/TON>
20.87 OPERATING AND SUPERVISION LABOR COST ($/HR)
25.05 ANALYSIS LABOR COST (6/HR)
.4819E-01 ELECTRICITY COST ($/KWH)
.6902 WATER COST ($/1000GAL>
6.672 STEAM REHEAT COST (6/HHBTU)
30.27 CALCITE (S/TOM)
84.76 CALCITIC HYDRATE COST (S/TON)
109.0 NAKCOLITE COST
-------
^^^y*1:'''™'y}7^^
TVA DEFAULT PARAMETER FILE
A-17
-------
VALUE
PARHFILE. TVA
System Wide
DESCRIPTION
.8846 BASE THERMAL EFFICIENCY
7924. GROSS HEAT RATE, BTU/KWH
9500. BOILER NET HEAT RATE (CALCULATED IF ZERO), BTU/KWH
100.0 BOILER LOAD, X
.5000 SOLID COMBUFTIBLE LOSS, X
.9950 COKBUSTIBLE LOSS CORRECTION FACTOR, FRACTION
.0000 FLOW RATE, ACFM (CALCULATED IF ZERO)
7.500 TAXES AND FREIGHT, % DIRECT COST (WASTE)
1.000 A-E CONTRACTOR, % DIRECT COST (WASTE)
2.000 ENGINEERING DESIGN AND SUPERVISION, X DIRECT COST (WASTE)
8.000 CONSTRUCTION EXPENSE COST FACTOR, '/. DIRECT COST (WASTE)
5.000 CONTRACTOR'S FEE COST FACTOR, '/. DIRECT COST (WASTE)
20.00 CONTINGENCY COST FACTOR, % D*I (WASTE)
.0000 ROYALTIES, % DIRECT COST (WASTE)
15.60 INTEREST DURING CONSTRUCTION, X. D+I (WASTE)
.0000 ALLOWANCE FOR STARTUP AND MODIFICATION, '/. D*I (WASTE)
3.000 KAINTEHANCE LABOR AND MATERIAL, % OF DIRECT COST UASTE)
35.00 ANNUAL RAINFALL, IN. /YEAR
.0030 SEEPAGE RATE, CH/SEC
32.00 ANNUAL EVAPORATION, IN. /YEAR
5.303 SLUDGE DISPOSAL OPTION ( 4-THIC1CENER/FILTER/FIXATION, 5-LANDFILL)
.0000 SLUDGE FIXATION OPTION (0-NO FIXATION, i-SLUDGE-FLY, ASH-LIKE)
9999. TOTAL AVAILABLE LAHD FOR CONSTRUCTION OF WASTE FACILITY, ACRES
75.00 UNCOMPACTED WASTE BULK DENSITY, LB/CU FT
95.00 COMPACTED WASTE BULK DENSITY, LB/CU FT
5280. DISTANCE FROM UTILITY AREA TO DISPOSAL SITE, FT
1.000 DISPOSAL SITE LINING ( 1-CLAY, 2-SYNTHETIC, 3-NO LINER)
12.00 CLAY DEPTH, IN
1.000 FRACTION ON-STTE DISPOSAL
A-18
-------
PARHFILE.TVA
Unctrl Coal
VALUE
DESCRIPTION
.8000 DEFAULT PARTICULATE OVERHEAD RATIO, IF ZERO, AP 42 IS USED,FRAC.
.9503 DEFAULT S02 OVERHEAD RATIO,IF ZERO,AP 42 EMISSION FACTORS USED
.50(23 PARTICULATE DRY-BQTTOH EMISSION FACTOR(AP42 SUPLMT13 REV. >, FRAC
.3500 PARTICULATE WET-BOTTOM EMISSION rACTOR (IBID), FRACTION
.3150 PARTICULATE LIGNITE EMISSION FACTOR (IBID), FRACTION
.9503 S02 BITUMINOUS EMISSION FACTOR (IBID), FRACTION
.6750 S02 SL'BBITUMINOuS EMISSION FACTOR (IBID), FRACTION
.7500 S02 LIGNITE EMISSION FACTOR (IBID), FRACTION
.5250 NOX WALL FIRED BITUP1INOUS/SUB-BITUM DRY-BOTTOM (IBID), FR/CTIQH
.3500 NQX WALL FIRED LIGHITE DRY-BOTTOM (IBID), FRACTION
.3753 NOX TAHGEN. FIRED BITUMINOUS/SUS-BITUH. DRY BOTTOM (IBID), FRACT
.2000 NOX TANGENTIAL LIGHITE DRY-BOTTOM
,8500 NOX ALL WET-BOTTOM (AS ABOVE)
9820. PC F-FAC^OR (IBID, DSCF/HMBTU)
.3900 EXCESS AIR, FRACTION
940.0 # AIR/MMBTU FIRED (IBID)
A-19
-------
PARMFILE.TVA
Fan
VALUE DESCRIPTION
1.000 A-E CONTRACTOR, '/. DIRECT COST (FANS)
6.000 EKGIKEERIHG DESIGN AND SUPERVISION, % DIRECT CAPITAL (FANS)
14.00 CONSTRUCTION EXPENSE COST FACTOR, % DIRECT CAPITAL (FANS)
4.000 CONTRACTOR'S FEE COST FACTOR, 7. D + I (FANS)
10.00 CONTINGENCY COST FACTOR, % D+I (FANS)
.0000 ROYALTIES, '/. D*I (FANS)
6.000 ALLOWANCE FOR STARTUP AND MODIFICATIONS, % D+I CAPITAL (FAHS)
4.030 KAIN7ENANCE LABOR AND MATERIAL, V. OF DIRECT COST (FANS)
15.60 INTEREST DURING CONSTRUCTION, '/. D + I COST (FANS)
1.000 FAN RETROFIT FACTOR, DIMENSIOMLESS
A-20
-------
r,,,^,,r^^^5^^
PARMFILE.TVA
==============
Economic
VALUE
DESCRIPTION
68.00 OVERHEAD CHARGE ON O&ft LABOR < ?, >
14.70 LEVELI2ED CAPITAL CHARGi: RATE (CALCULATED IF ZERO), DIMENSIONLES
1.886 O&H LEVELIZATION FACTOR (CALCULATED IF ZERO), DIHEHSICNLESS
15.30 CONTINGENCY ('A OF DM COST)
5.000 STARTUP & SPARES (X OF D&I COST)
15,60 INTEREST DURING CONSTRUCTION('/. OF D&I COST)
10.00 WEIGHTED COST OF CAPITAL (CALCULATED I? ZERO), %
.5000 TRACTION OF LONG TERM DEBT
9.000 COST OF CAPITAL, 7,
.150® FRACTION OF PREFERED STOCK
10.00 COST OF PREFERED STOCK, 'A
.3500 FRACTION OF COHHON STOCK
11.40 COST OF COMMON STOCK, %
30.00 ECONOMIC LIFE, YEARS
30.00 TAX LIFE, YEARS
30.00 BOOK ' IFE, YEARS
.5000 INCOME TAX RATE
10.00 INVESTMENT TAX CREDIT RATE, X
.250SE-01 INSURANCE AND PROPERTY TAXES
.1000 DISCOUNT RATE
8506. YEAR OF CAP COSTS(YYHM), IF ©.
870S. YEAR OF O&K COSTS(YYNH), IF 0.
8508. DATE OF CE INDICES (YYHM)
325.0 CE PLANT INDEX FOR CORRESPONDING YEAR AND HONTH OF COST
366.8 CE MATERIAL INDEX FOR CORRESPONDING YEAR AHD MONTH OF COST
292.2 CE LABOR INDEX FOR CORRESPONDING YEAR AHD MONTH OF COST
113,0 O&H IND5.X FOR CORRESPONDING YEAR AHD HORTH OF COST (6/82 = 100)
JUHE, 1982 (BASE YEAR) USED
JUNE, 1982 (BASE YEAR) USED
A-21
-------
^
PARMF1LE.TVA
LSD
VALUE
DESCRIPTION
1.530 ST01CHIOHETRIC RATIO (LSD)
80.00 UTILIZATION OF FLY ASH ALKALINITY, % (LSD)
53.00 AVERAGE MOLECULAR WEIGHT-OF ALKALINITY IN FLY ASH
7250 FRESH LIME COMPONENT OF SLURRY, FRACTION (LSD)
,5.00 MAXIMUM EFFICIENCY OF LSD, % < LSD)
15.00 MAXIMUM SOLIDS IN SLURRY BY WEIGHT, '/.
i.636 MAXIMUM REACTIVE ALKALINITY/MEGAWATT (LSD)
,0.80 MAXIMUM EFFICIENCY OF FOR FLY ASH ALKALINITY, './. (LSD)
,.560 MODIFIED PARTICULATE LOADING EXITING SPRAY DRYER, FRACT (LSD)
160.0 SPRAY DOWN TEMPERATURE, DEG. F (LSD)
.000 PRESSURE DROP ACROSS DRYER, IK. H2O (LSD)
:.000 INSTALLATION FACTOR, OIMEMSIOHLESS (LSD)
7.030 ENGINEERING DESIGN AND SUPERVISION, % DIRECT CAPITAL (LSD)
2,030 A-E CONTRACTOR, '/. DIRECT COST (LSD)
16.00 CONSTRUCTION EXPENSE COST FACTOR, '.'. DIRECT CAPITAL (LSD)
5.000 CONTRACTOR FEE COST FACTOR, % DIRECT CAPITAL (LSD)
20.0S CONTINGENCY COST FACTOR, '/.DIRECT&INDIRECT CAPITAL (LSD)
,0000 ROYALTIES, '/. DIRECT + INDIRECT (LED)
,0000 REACTIVE ALKALINITY FACTOR FOR BITUMINOUS COAL, FRACTION (LSD)
,2500 REACTIVE ALKALINITY FACTOR FOR SUB-BITURINQUS COAL, FRACTION (LS
,20e0 REACTIVE ALKALINITY FACTOR FOR LIGNITE COAL, FRACTION (LSD)
IB. 00 ALLOWANCE FOR START-UP AND MODIFICATIONS , % D + I CAPITAL
-------
PARHFILE.TVA
3SC = £"=3C = 3SSS
Low Nox/Over
VALUE DESCRIPTION
1.000 A-E CONTRACTOR, 'A DIRECT COST (LHBQF)
6.000 ENGINEERING DESIGN AND SUPERVISION, % DIRECT CAPITAL (LNBOD
14.00 CONSTRUCTION EXPENSE COST FACTOR, '/. DIRECT CAPITAL (L.HBOF)
4.000 CONTRACTOR FEE COST FACTOR, % DIRECT CAPITAL (LNBOF)
10.00 ALLOWANCE FOR STARTUP AND MODIFICATION, % D£I CAPITAL (LNBOF)
,0000 ROYALTIES, % DIRECT + INDIRECT (LNBOF)
20.00 CONTINGENCY COST FACTOR, % 0£I CAPITAL (LNBOF)
.1.000 MAINTENANCE LABOR AND MATERIALS, X DIRECT (LNBOF)
4.840 INTEREST DURING CONSTRUCTION COST FACTOR, '/, DRI CAPITAL (LNBOF)
T-,-23
-------
fpHP?CT*'awl
PARMFILE.TVA
Fabr. Filter
DESCRIPTION
VALUE
(2,000 AIR-TO-CLOTH RATIO, CFH/SQUARE FOOT
2.020 INSTALLATION AND FREIGHT COST FACTOR, DIMEHSIONLESS (FF)
1.000 A-E CONTRACTOR, 7. DIRECT (FF)
6.000 ENGINEERING DESIGN AND SUPERVISION FACTOR, X DIRECT CAPITAL (FF)
14.00 CONSTRUCTION EXPENSE COST FACTOR, 7. DIRECT CAPITAL (FF)
4.000 CONTRACTOR FEE COST FACTOR, 7. DIRECT CAPITAL (FF)
28.0171 CONTINGENCY COST FACTOR, X DIRECT & INDIRECT CAPITAL (FF)
,8000 ROYALTIES, % DIRECT (FF)
18,00 ALLLOWANCE FOR STARTUP AMD MODIFICATIONS, X D + I COST (FF)
15.00 PERCENT SUPERVISOION TO OPERATING LABOR, X (FF)
20.00 WATER TO ASH RATIO BY WEIGHT, X (FF)
1,000 PRESURE DROP ACCROSS FABRIC FILTER, IN. H20 (FF)
20.00 SO2 EFFICIENCY OF FF PRECEEDED BY LIMB, 7. REMOVAL (FF)
,0800 S02 EFFICIENCY OF FF PRECEEDED BY SPRAY HUMID., X REMOVAL (FF)
20.00 502 EFFICIENCY OF FF PREDEEDED BY LSD, X REMOVAL (FF)
J50.00 S02 EFFICIENCY OF FF PRECEEDED BY DS7., X REMOVAL (FF)
K.8P0 HAlHTEHAHCE LABOR AND HATERIALS, X DIRECT < FF)
15.60 INTEREST DURING CONSTRUCTION, X D + I COST (FF)
|l,800 FABRIC FILTER RETROFIT FACTOR, DIMEHSIONLESS
A-24
-------
~.^V<3**7?=500MW) UNITS (ESP)
100.0 SIZING FACTOR FOR ASH SILOS, TOMS/HOUR/SILO (ESP)
1.000 A-E CONTRACTOR, 7. DIRECT COST (ESP)
6.000 ENGINEERING DESIGN AND SUPERVISION FACTOR, 7. OF DIRECT COST (ESP
14.00 CONSTRUCTION EXPENSE COST FACTOR, 7. OF DIRECT COST (ESP)
4.000 CONTRACTOR'S FEE COST FACTOR, 7. OF DIRECT (ESP)
20.00 CONTINGEHCY COST FACTOR, 7. OF DIRECT & INDIRECT COSTS (ESP)
.0000 ROYALTIES, 7. DIRECT + INDIRECT (ESP)
15.00 PERCENT SUPERVISION TO OPERATING LABOR, 7. (ESP)
20.00 WATER TO ASH RATIO BY WEIGHT, 7. (ESP)
1.000 PRESSURE DROP ACROSS ESP, IN. H20
.0000 S02 EFFICIENCY OF ESP PRECEEDED BY LIHB, 7. (ESP)
.0000 S02 EFFICIENCY OF ESP PRECEEDED 9Y SPRAY HUHIDIFICATION, 7. (ESP)
,0000 S02 EFFICIENCY OF ESP PRECEEDED BY LSD, 7. (ESP)
,0000 S02 EFFICIENCY OF ESP PRECEEDED BY DSI, 7, (ESP)
4.000 MAINTENANCE LABOR AND MATERIALS, 7. DIRECT (ESP)
10.00 ALLOWANCE FOR STARTUP AND MODIFICATION, % OF D + I COSTS (ESP)
.0000 ASH RESISTIVITY, 10aa9 OHM-CM (CALCULATED FROM COAL SULFUR IF 0)
1500. ASH RESISTIVITY IN PRESENCE OF LIMB, 10»»9 OHM-CM
15.60 INTEREST DURING CONSTRUCTION, 7. D + I COST (ESP)
1,000 ESP RETROFIT FACTOR, DIMEMSIONLESS
A-25
-------
PARMFILE.TVA
Spray Humid.
VALUE
3500.
1.253
3. 0®0
,1473E*05
1.100
70.00
100.0
50.00
1.850
2. 000
2,000
1.000
6.000
14.00
4.000
?0. 00
600.0
2.000
2.000
4. 840
10.00
1.!
DESCRIPTION
GAS VELOCITY IS S. H. CHAMBER, FT/HIM (SB)
EXTRA FABRICATION COST FACTOR (l.«-25X) (SH)
WATER USEAGE FACTOR, DIMENSIONLESS (SH)
SURGE TANK RETENTION TIME, HOURS (SH)
MAXIMUM TANK SIZE, CU. FT. (SH)
EXTRA PUtfPAGE FACTOR (JL * 10%) (SH)
PUMP EFFIECIENCY, % (SH)
PUMP HEAD ON FEED PUMPS, FT. (SH)
PUMP HEAD ON FRESH WATER PUMPS, FT. (SH)
TANK AND PUMP INSTALLATION FACTOR, DIHENSIONLESS (SH)
FEF.D PUMP REDUNDANCY, DIMENSIONLESS (SH)
FRESH WATER PUMP REDUNDANCY, DIKENSIQNLESS (SH)
A-E CONTRACTOR, 7. DIRECT COST (SH)
ENGINEERING DESIGN AMD SUPERVISION FACTOR, % DIRECT COST (SH>
CONSTRUCTION EXPENSE COST FACTOR, % DIRECT COST (SH)
CONTRACTOR'S FEE COST FACTOR, % DIRECT COST (SH)
CONTINGENCY COST FACTOR, '/. D6I COST (SH)
ROYALTIES, % DIRECT COST (SH)
OPERATING AND SUPERVISION MANHOURS/YEAR (SH)
MAINTENANCE LABOR AND MATERIALS, % DIRECT (SH1,
INCREMENTAL PRESSURE DROP, IN H20 (SH)
INTEREST DURING CONSTRUCTION, */. DS.I COST (SH)
ALLOWANCE FOR STARTUP AND MODIFICATION, '/. D&I COST (SH)
SPRAY HUMIDIFICATION RETROFIT FACTOR, DIMENSIONLESS
A-26
-------
PARMFILS.TVA
DSI
VALUE DESCRIPTION
3.000 MOLAR STQICHIOMETRIC RATIO (DSI)
70. P)0 NAHCOLITE PURITY, 7. (DSI)
65.00 PERCENT SOLIDS IN FIXATION WASTE STREAM (DSI)
1.500 FIXATION COST MULTIPLIER, DIMENSIONLESS (DSI)
60.09 DSI EFFICIENCY , f. (DSI)
1.000 A-E CONTRACTOR, X DIRECT COST (DSI;
10.00 ENGINEERING DESIGN AND SUPERVISION FACTOR, /'. (DSI)
14.00 CONSTRUCTION EXPENSE COST FACTOR, % DIRECT (DSI)
4.089 CONTRACTOR'S FEE COST FACTOR, % D + I (DSI)
20.00 CONTINGENCY COST FACTOR, % D+I (DSI)
,0000 ROYALTIES, '/, DIRECT COST (DSI)
2403. OPERATING AND SUPERVISION WAKHOURS (DSI)
4.000 MAINTENANCE LABOR AND MATERIALS, % OPERATING (DSI)
1.503 NORMAL STOICHIOMETRIC RATIO (DSI)
10.00 ALLOWANCE FOR STARTUP AND MODIFICATION, '/. D + I (DSI)
4.840 INTEREST DURING CONSTRUCTION, '/. D + I (DSI)
1.000 DSI RETROFIT FACTOP, DIMENSIONLESS
A-27
-------
PARMFILE.TVA
FGD System
VALUE
DESCRIPTION
1.400
99.00
1.000
106.0
,0000
,0000
I. 000
175.0
170.0
'51.9
I 000
6000E-01
!0. 00
i. 000
10. 00
15.00
). 000
1.000
0000
0000
1500
1500.
1.000
1.850
i. 000
1.000
15.00
2300
10.00
i. 000
15.00
!. 500
15.00
,.200
i. 200
0000
). 000
0000
14. 70
1.000
,. 000
1.000
1,000
i. 000
,0. 00
i. 700
..000
1000
1.000
I. 000
1.000
19.00
SRIN STOICHIOMETRIC RATIO (FGD)
XS02 REMOVAL EFFICIENCY (FGD)
FGD RETROFIT FACTOR, DIMENSIONLESS
XLG
ISR
XESP
XRH
TSK
TSTEAM
HVS
IASH
ASHUPS
VLG
VTR
V
VRH
TR
XIALK
IADD
WPMGO
XMGOAD
AD
ADDC
WPI
WPM
WPS
PSD
RS
PSC
IFOX
OX
SRAIR
PSF
FILRAT
PHLIKE
IVPD
VPD
DELTAP
PRES
I FAN
ISCRUB
XNS
XNG
HS
WINDEX
HPTONW
NOREDN
PCNTRN
PCTMNT
NSPREP
NOTRAN
EXSAIR
L/G RATIO FOR SCRUBBER, GALLONS/1000 CU. FT.
L/G, EFFICIENCY CONTROL VARIABLE (0,1,2)
PARTICULATE COLLECTION OPTION (0,1,2)
REHEAT OPTION (0,2)
TEMPERATURE OF STACK GAS, DEC. F.
TEMPERATURE OF REHEATER STEAM
HEAT OF VAPORIZATION OF REHEATER STEAM
UNIT OF MEASURE OPTION FOR PARTICULATE REMOVAL(0, 1, 2, 3>
VALUE FOR PARTICULATE REMOVAL UPSTREAM FROM SCRUBBER
L/G RATIO IN VENTURI, GALLONS/1000 CU 'FT
VENTURI/OXIDATION HOLD TANK RESIDENCE TIME, MIN
SCRUBBER GAS VELOCITY, FT/SEC
SUPERFICIAL GAS VELOCITY THROUGH REHEATER, FT/SEC
RECIRCULATION/OXIDATION HOLD TANK RESIDENCE TIME. KIN
ALKALI ADDITION OPTION (1,2) .
CHEMICAL ADDITIVE OPTION (0,1,2)
SOLUBLE MGO IN LIMESTONE OR LIME, WT '/. DRY BASIS
SOLUBLE MGO ADDED TO SYSTEM, LB/100 LB LINESTONE
ADIPIC ACID IN SCRUBBING LIQUID, PPMW
ADIPIC ACID DEGRADATION CONSTANT
INSOLUBLES IN LIMESTONE-LIME ADDITIVE, WT % DRY BASIS
MOISTURE IN LIMESTONE-LIME ADDITIVE, LB/100 LB DRY BASIS
SOLIDS IN RECYCLE SURRY TO SCRUBBER, WT '/.
SOLIDS IN SLUDGE DISCHARGE, WT %
THICKENER SOLIDS SETTLING RATE, FT/HR
PERCENT SOLIDS IN THICKENER UNDERFLOW, WT '/.
FORCED OXIDATION OPTION (0,1,2,3)
OXIDATION OF SULFITE IN SRUBBER LIQUID, MOLE '/.
AIR STOICHIQMETRY VALUE, MOLES OXYGEN/MOLE 502 ABSORBED
PERCENT SOLIDS IN FILTER CAKE, WT '/.
FILTRATION RATE, TONS/SO FT/DAY
RECIRCULATION LIQUOR PH
VENTURI -P- OPTION (0,1)
VALUE FOR EITHER -P- OR THROAT VELOCITY, IN H20 OR FT/SE
OVERRIDE -P- FOR ENTIRE SYSTEM, IN H7Q
SCRUBBER PRESSURE, PSIA
FAN OPTION (0,1)
SCRUBBING OPTION (1,2,3,4,5,6)
NUMBER OF TCA STAGES
NUMBER OF TCA GRIDS
HEIGHT OF SPHERES PER STAGE, IN
LIMESTONE HARDNESS WORK INDEX FACTOR, DIMENSIONLESS
FINENESS OF GRIND INDEX FACTOR, HP/TON
NUMBER OF SPARE SCRUBBER TRAINS
ENTRAINMENT LEVEL AS PERCENTAGE OF WET GAS, WT '/
MAINTENANCE RATE, EXCLUDING DISPOSAL SITE COST, '/. TDI
NUMBER CF SPARE PREPARATION UNITS
NUMBER OF OPERATING SCRUBBER TRAINS
EXCESS AIR, X
A-28
-------
PARKFILE.TVA
sesaatrzaaseB
FGD Econs
VALUE DESCRIPTION
7.00S ENGINEERING DESIGN AND SUPERVISION, % TDI (FGD)
2.003 ARCHITECT AND ENGINEERING CONTRACTOR, % TDI (FGD)
16.00 CONSTRUCTION FIELD EXPENSES, % TDI (FGD)
5.©Sa CONTRACTOR FEES, % TDI (FGD)
10.00 CONTINGENCY, % TDI + PROCESS INDIRECT INVESTMENT(FGD)
8.0130 ALLOWANCE FOR STARTUP AMD MODIFICATIONS, 7. TFI (FGD)
15.60 INTEREST DURING CONSTRUCTION (FGD)
4.000 TXRAT SALES TAX RATE, X
3. 500 FRRAT FREIGHT RATE, "/.
6.000 RERVRT SERVICES, UTILITIES, AND MISCELLANEOUS, X TPC
.0000 ROYALTIES, % TPC (FGD)
A-29
-------
PARMFILE.TVA
Coat based
JUHE,
1986
VALUE
76.75
17.92
22.65
24,52
.5189E-01
. 1509
5. 000
14. 16
84. 41
106.3
16. 18
5. 904
29.52
88. 55
iflfl. 4
106. 3
6286.
14. 16
84.41
3.677
5.988
481. 1
1416.
1.509
DESCRIPTION
. C30C0
SULFUR COST <$/TON)
OPERATING AND SUPERVISION LABOR COST ($/HR)
WASTE DISPOSAL FACILITY LABOR COST (S/HR)
ANALYSIS LABOR COST (8/HR)
ELECTRICITY COST CS/KWH)
WATER COST (S/100CGAL)
STEAM REHEAT COST <$/K LB)
CALCITE COST (9/TON)
CALCITic HYDRATE COST (S/TON)
KAHCOLITE COST (S/TON)
WASTE DISPOSAL, WET($/TON)
WASTE DISPOSAL, DRY (S/TON)
DOLOMITIC LIHESTONE COST, $/TON
DOLOMITIC LIKE COST, S/TON
CALCITIC PRESSURE HYDRATE, $/TON
DOLOKITIC PRESSURE HYDRATE, $/TON
LAND COST <$/ACRE)
LIMESTONE COST, $/TON
LIUE COST, S/TON
DUCTWORK HETAL FABRICATION AND INSTALLATION COST, S/LB (SH)
CLAY COST, S/CU YD
KGO UNIT COST, S/TON
ADIPIC ACID UNIT COST, S/TON
DIESEL FUEL COST, S/GAL
SYNTHETIC LINER MATERIAL UNIT COST, $/SQ YD
SYNTHETIC LINER LABOR UNIT COST, S/SQ YD
A-3C
-------
APPENDIX B
EXAMPLE OUTPUT
B-l
-------
INTEGRATED flIR POLLUTION CONTROL SYSTEM COSTING PROSROM
TEST
CflSE
USER INPUT SUMMftRY
BOILER SIZE: 500. MW
CAPACITY FRCTQR:65.0 %
WOLL FIRED, DRY BOTTOM
310. DEG.F
DOTE OF COMMERCIRL OPERATION OF BOILER: 1987
CONSTRUCTION STftTUS OF CONTROL SYSTEM: NEW
COOL CLEftNING LEVEL:
COOL CHARACTERISTICS
RUN-O^-MINE SORTED AND SCREENED
AT THIS CLEANING LEVEL:
HHV (BTU/tt)
SULFUR CONTENT C/O
ASH CONTENT (%)
COST ($/TON)
CHLORINE CONTENT (%)
MOISTURE CONTENT (*>
VOLATILE MATTER CONTENT (%)
FIXED CfiRBON CONTENT ("/•)
11952.3
£. £3
15.90
.00
. 00
3. 30
33. 80
47. 00
RSH CHARACTERISTICS OT THIS CLEANING LEVEL:
Nft£0 CONTENT (•/•> : .40
P.LKOLINITY C/.): 6.50
FE203 CONTENT C/.): 9.00
CONTROL SYSTEM COMFIGURRTION:
- FflBRIC FILTER (FF)
- LIMESTONE FGD (LFGD)
ECONOMIC PREMISES (TVR/EPRI):
B-2
-------
INTEGRATED OIR POLLUTION CONTROL SYSTEM COSTING PPOGRfiM
USER INPUT SUMMARY (CONTINUED)
PfiRRMETER FILE USED: PORMFILE. EPR
NO CHANGES WERE MODE TO THIS PARAMETER FILE FOR THIS RUN.
B-3
-------
FflBRIC FILTER
THE F-ABRIC FILTER IS DESIGNED TO REMOVE 99.7* OF THE PARTICULATE
LOADING WITH AN AIR-TO-CLOTH RATIO OF c . 0. . 0% OF THE FLUE GAS
IS BYPASSING THE FABRIC FILTER. THE FflBRIC FILTER REFLECTS A
REVERSE AIR CLEANING CONFIGURATION AND TEFLON-COATED FIBERGLASS
BAGS.
LIMESTONE FBD
THE CONFIGURATION OF THIS SYSTEM INCLUDES SPROY TOWER
ftBSORBERS. FORCED OXiDfiTlON IS USED TO STABILIZE THE FLURRY. NO
CHEMICAL ADDITIVE IS USED.
SPARE ABSORBER CAPACITY OF £5.% IS PROVIDED. THE L/G RATIO IS 106.0
AND DESIGN S0£ REMOVAL OF 69.0% OCCUKS IN THE TREATED GAS STREAM.
0. y. OF THE GAS STREAM IS BEING BYPASSED.
100.'?'. OF THE WASTES ARE DISPOSED OF IN AN DNSITE FACILITY.
FANS
THE TOTAL SYSTEM PRESSURE DROP IS 15.& IN. H£0.
THE SYSTEM REQUIRES 5 FAN(S) RATED AT 1£99. HP EACH.
B--4
-------
BOILER/SYSTEM PERFORMRNCE
(180V. CfiPRCITY CONDITION)
UNIT THERMfiL EFFICIENCY 87. 1%
BOILER NET HEOT ROTE 9935. 0 BTU/KWH
HEftT INPUT 4967. 5 MMBTU/H
COOL USE 207.8 TONS/H
ftNNURL CCf^L CONSUMPTION 1. 1Q33E+-06 TONS/YR
IPPCS ENERGY PENOLTY..
SYSTEM NET GENERATION.
72.6 BTU/KWH
496.4 Mt-J
SYSTEM MfiTERIRL BflLftNCE
(lei'Ziy. CRPRCITY CONDITION)
FLUL GAS, 1000
FLUE COS, 1000
TEMPERflnjRE,
MOISTURE,
OLKRLINITY,
PORTICULfiTE,
S02,
NC2
LB/H
ftCFM
DEG. F
LB/H
LB/H
LB/H
LB/H
LB/H
UNCONT-
ROLLED
5046.
1417.
310.
240650.
3436.
52867.
18073.
4364.
filR
HERTER
EXIT
5046.
1417.
310.
240650.
3436.
52867.
18073.
4364.
FF
4994.
1417.
310.
240650.
10.
159.
18073.
4364.
LFGD
5S84.
1362.
175.
528467.
10.
159.
1986.
4364.
EMISSION SUMMfiRY
POLLUTflNT
PftRTICULATE
S02
N02
LB/HR
159.
1966.
4364.
PERCENT
REDUCTION
99. 7
89. 0
. 0
LB/MMBTU
. 032
.400
.879
PPM(V)
166.
780.
B-5
-------
INSTALLED CAPITAL COSTS JUNE, 1SB£
FABRIC FILTER -—$ i?,&b3700
FF&DUCTIMG $ 11854900
FF ASH DISPOSAL $ 180880(3
LIMESTONE FGD $ 43770800
FGD MATERIAL HANDLING $ 1££74©0
FGD FEED PREPARATION * 3869800
FGD GAS HANDLING * 64439'ZnZi
FGD SC£ SCRUBBING $ ££405000
FGD OXIDflTICM $ £400000
FGD REHCRT $ 4544800
FGD SOLID SEPfiRfiTIDN S £830000
WASTE DISPOSAL * 4730000
FANS * 16164400
TOTAL DIRECT CAPITAL COSTS)) »»»»»»»»>» 4 78328980
INDIRECT COSTS * 43000500
GENERAL FACILITIES * 6386100
ENGINEERING/HOME OFFICE...* 4197500
PROJECT CONTINGENCY * 119B&5C0
PROCESS CONTINGENCY $ 5510600
SALES TAX , * 0
TOTAL PLANT COST. * 106409596
TOTAL PLANT INVESTMENT.,,...,...* 106409600
ROYALTY ALLOWANCE * 6876700
PREPRODUCTICN COSTS * 3148£00
INVENTORY CAPITAL * £040000
INITIAL CATALYST. 4 0
LAND $ 854900
B-6
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TOTfiL CftPITfiL REQUIREMENT) >»»»»»>» »»>*$
ft-*
TOTOL SYSTEM COST) »»»»»»»»»»»»»»* £42. 66/KU
B-7
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ANNUAL OPERATING COSTS
JUNE, 1982
ITEM
QUANTITY
ROTE
ANNUAL COST
OPERATING AND SUPERVISORY LABOR
SYSTEM
WASTE DISPOSAL FACILITY
ANALYSIS
MAINTENANCE LABOR
MAINTENANCE MATERIAL
ADMIN. & SUPPORT LABOR
FIXED COMPONENT
VARIABLE COMPONENT
.4817E+05 MANHRS
.3744E+05 MANHRS
5087. MANHRS
.5082E+07 *
. 5t38£E+07 *
.3743E+07 $
.7915E+07 $
.7915E+07 «
17. £4
£0.69
£0. 69
.40
.60
.30
.65
.35
$
$
$
$
$
$
*
$
330500
774600
105200
£03£800
3049100
1122900
5144800
£770300
CONSUMABLES
CALCITIC LIMESTONE
WATER
STEAM
ELECTRICITY
DIESEL FUEL
TOTAL FIRST YEAR O&M EXPENSE
LEVELIZED CARRYING CHARGES
BUSBAR COST OF POWER
LEVELIZED FIRST YEAR O&M
LEVELIZED CARRYING CHARGES
LEVELIZED ANNUAL REQUIREMENTS
.9015E+05 TONS
. £l£4E-(-0& K GAL
.5470E+0& K LBS
.59&6E+08 KWH
. l£03E-»-06 GAL
121329400 $
15871200 *
121329400 $
£5. 00
.57
5.51
. 04
1.60
16.3%
*
$
$
«
*
*
a
2253800
1 £ 1 1 00
30142S0
£374500
192500
153712-00
19627300
£.559
16. 3%
3569B500
40616500
19827300
60443800
FIRST YEAR BUSBAR COST OF POWER
LEVELIZED ANNUAL BUSBAR COST OF POWER
12.54 MILLS/KWH
£:l.£3 MILLS/KWH
PARTICULATE COST EFFECTIVENESS
502 COST EFFECTIVENESS
NOX COST EFFECTIVENESS
402.80 S/TON
1319.74 */TQN
.00 S/TON
B-8
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