EPA-600/2-76-150
June 1976
Environmental Protection Technology Series
SIMPLIFIED PROCEDURES FOR ESTIMATING
FLUE GAS DESULFURIZATION SYSTEM COSTS
Industrial Environmental Research Laboratory
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into five series. These five broad
categories were established to facilitate further development and application of
environmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic. Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to develop and
demonstrate instrumentation, equipment, and methodology to repair or prevent
environmental degradation from point and non-point sources of pollution. This
work provides the new or improved technology required for the control and
treatment of pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the U.S. Environmental
Protection Agency, and approved for publication. Approval
does not signify that the contents necessarily reflect the
views and policy of the Agency, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/2-76-150
June 1976
SIMPLIFIED PROCEDURES
FOR ESTIMATING
FLUE GAS DESULFURIZATION SYSTEM COSTS
by
Thomas C. Ponder, Jr. , Lario V. Yerino, Vishnu Katari,
YatendraShah, and Timothy W. Devitt
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
Contract No. 68-02-1321, Task 12
ROAPNo. 21ADE-010
Program Element No. 1AB013
EPA Task Officer: Charles J. Chatlynne
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
This report was furnished to the U.S. Environmental Pro-
tection Agency by PEDCo-Environmental Specialists, Inc.,
Cincinnati, Ohio under Contract No. 68-02-1321. The contents
of this report are reproduced herein as received from the
contractor. The opinions, findings, and conclusions expressed
are'those of the author and not necessarily those of the
U.St Environmental Protection Agency.
11
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ACKNOWLEDGMENT
This report was prepared for the U.S. Environmental
Protection Agency by PEDCo-Environmental Specialists, Inc.,
Cincinnati, Ohio. The Project Director was Mr. Timothy W.
Devitt; the Project Manager, Mr. Thomas Ponder, Jr. Prin-
cipal investigators were Messrs. Lario V. Yerino, Vishnu
Katari, and Yatendra M. Shah.
Dr. C. J. Chatlynne was Project Officer for the U.S.
Environmental Protection Agency. The authors appreciate the
assistance and cooperation extended to them by members of
the U.S. Environmental Protection Agency, and process
vendors.
111
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TABLE OF CONTENTS
Page
ACKNOWLEDGMENT iii
LIST OF FIGURES vii
LIST OF TABLES viii
1. INTRODUCTION ' 1-1
2. COST COMPONENTS FOR FLUE GAS DESULFURIZATION 2-1
SYSTEMS
2.1 Capital Cost Components 2-1
2.2 Annual Operating Costs 2-4
3. RELATIVE COSTS OF FLUE GAS DESULFURIZATION 3-1
SYSTEMS
3.1 Costs of FGD Systems at Model Plants 3-1
3.2 Factors Affecting FGD Process Selection 3-22
4. SURVEY OF FGD SYSTEM COSTS 4-1
5. USE OF THE COST ESTIMATING MANUALS 5-1
5.1 Plant Data 5-1
5.2 Retrofit Information 5-4
5.3 Updating Cost Estimates 5-6
5.4 Cost Estimation Manuals 5-8
APPENDIX A - LIME SLURRY SYSTEM MANUAL A-l
APPENDIX B - LIMESTONE SLURRY SYSTEM MANUAL B-l
APPENDIX C - DOUBLE ALKALI SYSTEM MANUAL C-l
v
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TABLE OF CONTENTS (continued)
Page
APPENDIX D - MAGNESIUM OXIDE SYSTEM MANUAL D-l
APPENDIX E - WELLMAN-LORD SYSTEM MANUAL E-l
APPENDIX F - RAPID PROCEDURES FOR ESTIMATING F-l
CAPITAL AND ANNUAL COSTS FOR FIVE
PROCESSES
APPENDIX G - METRIC SYSTEM CONVERSION FACTORS G-l
VI
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LIST OF FIGURES
Figure Page
3-1. Lime Slurry System 3-5
3-2 Limestone Slurry System 3-9
3-3 Double Alkali System 3-12
3-4 Magnesium Oxide Slurry System 3-16
3-5 Wellman-Lord System 3-20
3-6 Incremental Effect of Sulfur Content of Coal 3-25
on Model Plant Capital Cost (Model Plant
Characteristics: 500 MW/existing).
5-1 Cost Escalation Curve 5-7
5-2 Impact of Cost Escalation 5-9
Vll
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LIST OF TABLES
Table Page
2-1 Major FGD System Equipment Summary 2-3
3-1 Summary of Characteristics and Assumptions 3-3
for Model Plants
3-2 Lime Scrubbing Costs 3-8
3-3 Limestone Scrubbing Costs 3-11
3-4 Double Alkali Scrubbing Costs 3-14
3-5 Magnesium Oxide Scrubbing Costs 3-18
3-6 Wellman-Lord Scrubbing Costs 3-23
3-7 Effects of Site-Specific Variables on FGD Systems 3-26
4-1 Summary of Utility Industry Survey 4-4
4-2 Ranges of Costs Reported for Flue Gas 4-12
Desulfurization Systems
5-1 Plant Survey Form 5-2
5-2 Typical Increased in Capital Costs with Various 5-5
Retrofit Requirements
Vlll
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1. INTRODUCTION
This study was sponsored by the U.S. Environmental
Protection Agency to provide assistance to EPA's Industrial
Environmental Research Laboratory at Research Triangle Park
(IERL-RTP) in economic comparisons of flue gas desulfuriza-
tion (FGD) systems.
* '
The primary objective is to identify all items that
affect the capital and annualized operation costs of FGD
systems. Direct capital costs cover such items as equip-
ment, piping, electrical and structural materials, site
development, insulation, and painting; indirect costs cover
such items as interest, engineering expenses, contractor
fees, taxes, and contingency costs. Annualized operating
cost items include raw materials, utilities, operating
labor, capital charges, insurance, taxes, and depreciation.
A second objective of this study is to prepare proce-
dures for estimating the capital costs and the annualized
operating costs of five FGD systems: lime, wet limestone,
magnesium oxide, Wellman-Lord, and double alkali.
A third objective is to compare the costs estimated by
these procedures with actual costs incurred by operators of
1-1
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selected FGD installations. Any differences between the
estimated and the actual costs are accounted for, and the
estimating procedures modified when necessary.
Section 2 presents the various cost elements comprising
total installed capital and annualized operating costs of
FGD systems.
Section 3 identifies the characteristics of 12 model
plants for use in these analyses and develops cost values
for the lime, limestone, magnesium oxide, Wellman-Lord, and
double alkali systems at these model plants.
Section 4 compares costs derived by use of the cost
estimating procedures developed in this study with costs of
actual and planned installations as reported by industrial
users.
Input data required for use of estimating procedures
are presented in Section 5, with discussion of cost updating
methods and retrofit difficulty factors. Detailed cost
estimating manuals are presented for the five FGD processes
in Appendices A through E. Simplified procedures for rapid
estimation of capital and annualized FGD costs are given in
Appendix F.
1-2
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2. COST COMPONENTS FOR FLUE GAS DESULFURIZATION SYSTEMS
Total costs of flue gas desulfurization systems include
both capital and annualized costs. Capital costs are direct
and indirect. Direct costs are those of plant equipment,
instrumentation, piping, electrical and structural mate-
rials, site work, insulation, painting, and piling, and the
accompanying costs of installation or application. Indirect
costs include interest assessed during construction; con-
tractors fees and expenses; engineering, freight, and off-
site expenses; and taxes and allowances; and contingencies.
Annualized operating costs are both fixed and variable.
Variable costs include those of utilities, labor, mainten-
ance, and in some cases overhead. Fixed costs include those
of depreciation, interim replacement, insurance, taxes, and
capital charges. The various components of capital and
annualized costs are discussed in greater detail in Sections
2.1 and 2.2.
2.1 CAPITAL COST COMPONENTS
The major capital cost components of an FGD system
consist of plant equipment, installation, site development
and indirect costs.
2-1
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2.1.1 Plant Equipment, Installation, and Site Develop-
ment Costs
Table 2-1 lists the major process equipment required
for FGD systems. Installation of this equipment requires
foundations; steel work for support; buildings; piping and
ducting for effluents, slurries, sludge, steam, overflows,
acid, drainage, and make-up water; control panels; instru-
mentation; insulation of ducting, buildings, piping, and
other equipment; painting; and in some instances, piling.
Site development includes right-of-way for sludge disposal;
site clearing and grading; construction of access roads and
walkways; establishment of rail, barge, or truck facilities;
parking facilities; landscaping; and fencing.
2.1.2 Indirect Costs
Indirect costs include the following elements:
Land required for the FGD process, including a sludge
waste or regeneration facility, storage, and right-of-
ways.
Interest accrued during construction on borrowed capi-
tal.
Contractor's fee and expenses, including costs for
field labor payroll; supervision field office; per-
sonnel; construction offices; temporary roadways;
railroad trackage; maintenance and weld shops; parking
lot; communication; temporary piping and electrical and
sanitary facilities; safety security of all types—
fire, material, medical, etc; construction tools and
rental equipment; unloading and storage of materials;
travel expenses; permits; licenses; taxes; insurance;
overhead; legal liabilities; field testing of equip-
ment; start-up; and labor relations.
2-2
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Table 2-1. MAJOR FGD SYSTEM EQUIPMENT SUMMARY
Equipment
Description
Material handling-raw
materials
Feed preparation-raw
materials
SO- scrubbing
Flue gas reheat
Gas handling
Sludge disposal
Utilities
Cake processing
Regeneration
Purge treatment
Equipment for the handling and transfer of raw materials includes unloading
facilities, conveyors, storage areas and silos, vibrators, atmospheric emission
control associated with these facilities, and related accessories.
Equipment for the preparation of raw materials to produce a scrubbing slurry
consists of feed weighers, crushers, grinders, classifiers, ball mills, mixing
tanks, pumps, agitators, and related accessories.
Equipment of a nonregenerative system for scrubbing the SO2-laden flue gas in-
cludes scrubbers, demisters, effluent hold tanks, agitators, circulating pumps,
pond water return pumps, and related accessories. In addition, scrubbing equip-
ment for a regenerative system includes converter, catalyst storage, conveyors,
and related accessories.
To increase plume buoyancy and minimize condensation the scrubber exhaust gas is
heated from about 125° to 175°F. Equipment required includes an economizer,
air/steam or fluid heaters, condensate tanks, pumps, soot blower, and related
accessories.
Equipment to handle the boiler flue gas includes booster fans, ductwork, flue
gas bypass system, turning vanes, supports, platforms, and related accessories.
Nonregenerative FGD systems require a clarifier, pumps, vacuum filtration, sludge
fixation equipment, and related accessories.
Equipment to supply power to the FGD equipment consists of switch-gear, breakers,
transformers, and related accessories.
Equipment for processing the by-product of regenerative FGD systems includes a
rotary kiln, fluid bed dryer, conveyor, storage silo (MgSC>3, etc.), vibrator,
combustion equipment and oil storage tanks, waste heat boiler, hammer mills etc.
Or, evaporators, crystallizers, strippers, tanks, agitators, pumps, compressors,
etc. Or H2S04 absorber and cooling, mist eliminator, pumps, acid coolers, tanks,
etc.
Equipment for regeneration of the scrubber medium of a regenerative system consists
of: coke material handling system, storage, weight feeder, conveyor, rotary kiln,
fluid bed calciner, dust collector, storage silo (MgO, etc.), vibrator, combustion
equipment and oil storage tanks, waste heat boiler, hammer mill, etc. Or, evapo-
rators, crystallizers, strippers, tanks, agitators, pumps, compressors, etc. Or
H_SO. absorber and cooling, mist eliminator, pumps, acid coolers, tanks, etc.
Equipment for the removal of sodium sulfate includes refrigeration, pumps, tanks,
crystallizer, centrifuge, dryer, dust collector, conveyors, storage, and related
equipment.
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Engineering costs, including administrative, process,
project, and general; design and related functions for
specifications; bid analysis; special studies; cost
analysis; accounting; reports; consultant fees; pur-
chasing; procurement; travel expenses; living expenses;
expediting; inspection; safety; communications; model-
ing; pilot plant studies; royalty payments during
construction; training of plant personnel; field en-
gineering; safety engineering; and consultant services.
Legal expenses, including those for securing permits,
right-of-way sections, etc.
Freight, including delivery costs on FGD process and
related equipment shipped F.O.B.
Off-site expenditures, including those for power house
modifications; interruption to power generation; and
service facilities added to the existing plant facili-
ties.
Taxes, including sales, franchise, property, and excise
taxes.
Insurance, covering liability for equipment shipped and
at site; fire, other casualty, personal injury, death;
damage to property; embezzlement; delay; and noncompli-
ance.
Shakedown and contingency costs, including those of
malfunctions; alterations to design equipment; premium
time for repairs; start-up utilities; start-up mate-
rials for process; price changes due to inflation; and
wage scale increases.
Spare parts stock to permit 100 percent process avail-
ability, including pumps, valves, controls, special
piping and fittings, instruments, spray nozzles, and
similar items.
2.2 ANNUAL OPERATING COSTS
Annual operating costs of a flue gas desulfurization
system include the following elements:
2-4
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Raw materials, including those required by the FGD
process for sulfur dioxide control, system loss, and
sludge fixation.
Utilities, including water for slurries, cooling and
cleaning; electricity for pumps, fans, valves, lighting
controls, conveyors, and mixers; fuel for reheating of
flue gases; and steam for FGD process.
Maintenance and repairs, consisting of both manpower
and materials to keep the unit operating efficiently.
The function of maintenance is both preventive and
corrective to keep outages to a minimum.
Overhead, a business expense that is not charged dir-
ectly to a particular part of a process, but is allo-
cated to it. Overhead costs include administrative,
safety, engineering, legal, and medical services,
payroll; employee benefits; recreation; and public
relations.
Fixed charges, which continue for the estimated life of
the process, including costs of the following:
0 Depreciation - the charge for losses in physical
assests due to deterioration (wear and tear,
erosion and corrosion) and other factors, such as
technical changes that make physical assets
obsolete.
0 Interim replacement - costs expended during the
year for temporary or provisional replacement of
equipment that has failed or malfunctioned.
0 Insurance - costs of protection from loss by a
specified contingency, peril, or unforeseen event.
Required coverage could include losses due to
fire, personal injury or death, property damage,
embezzlement, explosion, lightning, or other
natural phenomena.
0 Taxes, including franchise, excise, and property
taxes leveed by a city, county, state, or Federal
government.
0 Capital costs due to interest on borrowed funds.
2-5
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3. RELATIVE COSTS OF FLUE GAS DESULFURIZATION SYSTEMS
3-1 COSTS OF FGD SYSTEMS AT MODEL PLANTS
The capital and annualized costs of FGD systems can
vary significantly depending upon design and site-specific
factors. Factors having a major cost impact are plant size
(capacity), remaining life, and capacity factor; FGD process
and design; sulfur content and heating values of the coal;
maximum allowable SO- emission rate; status of FGD installa-
tion (new plant or retrofit); particulate control require-
ments; and replacement power requirements.
As a means of developing cost estimates and illustrat-
ing the impacts of site and process factors on capital and
annualized costs of different FGD systems, 12 models of
'typical* utilities plants are defined. The 12 model plants
incorporate three variable cost elements: plant size
(capacity), installation status, and degree of SO2 control
required. The designated boiler capacities of 250, 500, and
1000 MW cover a size range representative of U.S. power
plant boilers. Both new plant and retrofit applications are
considered for each plant size. Further, each plant size is
analyzed in terms of two S02 control requirements: use of
3-1
-------
high-sulfur coal (3.5% S) with an S02 limitation of 1.2
lb/10 Btu (Federal New Source Performance Standard), and
use of low-sulfur coal (0.6% S) with an S02 limitation of
0.15 lb/10 Btu (stringent local S02 regulations such as
Clark County, Nevada).
Other variables such as remaining plant life and plant
capacity factor are selected to be representative of each
model plant. Operating costs for such components as raw
materials and utilities, which vary with geographical loca-
tion, are considered to be representative of a midwest loca-
tion. Table 3-1 identifies the characteristics and major
assumptions for the model plants.
Cost summaries based on the model plant characteristics
are developed for each of the five FGD systems in the fol-
lowing sections. These costs are in January 1975 dollars;
they do not include escalation during the project period.
3.1.1 Lime Scrubbing System
The lime scrubbing system, as shown in Figure 3-1,
utilizes a lime slurry as the sulfur dioxide absorbent
medium. The sulfur dioxide reacts with the limestone to
form calcium sulfite (CaS03), which is removed from the
system as a waste product. Flue gases from the boiler pass
through an electrostatic precipitator or venturi scrubber
3-2
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Table 3-1. SUMMARY OF CHARACTERISTICS AND ASSUMPTIONS FOR MODEL PLANTS
I
U)
Model plant parameters
Plant capacities, megawatts
Plant status
Coal characteristics
SO_ control requirement
Location
Boiler data
Capacity factor
Heat rates, flue gas flow
rates and remaining life
Flue gas temperature
Characteristics and assumptions
250, 500, and 1000 (single boilers)
New and existing (retrofit)
Low sulfur coal: 0.6% S, 9000 Btu/lb
High sulfur coal: 3.5% S, 12,000 Btu/lb
Low sulfur coal: 0.15 lb/10, Btu
High sulfur coal: 1.2 lb/10 Btu (Federal
Performance Standard)
Midwest Location-East North Central Region
Assumed 0.6 for all 12 plants
., Flue gas
Capacity, Heat rate, flow rate,
MW Btu/kWh acfm/MW
250 new 9,200 3,175
250 existing 9,500 3,275
500 new 9,200 3,080
500 existing 9,200 3,140
1000 new 8,700 2,980
1000 existing 9,000 3,080
Assumed 310 °F for all plants
New Source
Remaining
boiler
life, yr.
35
15
35
20
35
25
Detailed Cost Estimated for Advanced Effluent Desulfurization Processes, prepared for
Control Systems Laboratory, Office of Research and Development, U.S. Environmental
Protection Agency, under Interagency Agreeement EPA IAG-134(d) Part A, by G.G.
McGlanery, et al., Tennessee Valley Authority, pp. 66,60. May 1974.
-------
Table 3-1 (continued). SUMMARY OF CHARACTERISTICS AND ASSUMPTIONS FOR MODEL PLANTS
Model plant parameters
Characteristics and assumptions
u>
i
Operating cost factors
Raw materials
Lime cost
Limestone cost
Soda ash cost (Wellman-Lord)
Sulfuric acid credit
(Wellman-Lord)
Salt cake credit (Wellman-
Lord)
Electricity cost
Taxes
Capital cost
Sludge disposal
FGD system life
Retrofit characteristics
Based on East North Central Regional averages
$20.00/ton delivered
$6.00/ton delivered
$55.00/ton
$20.00/ton
$40.00/ton
15 mills/kWh
4%
9%
Assumed on-site disposal of stabilized (fixed) sludge,
Assumed 20 years for depreciation purposes.
Longer duct runs, tight space constraints, increased
construction labor costs.
-------
U)
I
Ul
ENTRAINMENT SEPARATOR
EFFLUENT SLURRY SURGE
TANK & PUMPS
\TO TH SLURRY
TRAINS 1H PUMP
I*-1 .SEAL
\ z » (<
_____ _____ t .
1 _
J ABSORBER TO j «J ,
^_— " ™ H-f-"
x'S. /
V^ T<
I I < '
I T 1.*
*"
RC. ABSORBER CIRC. ^*~
WPS TANK & PUMPS Tn f*~ ^
TRAINS \£_
LIME SLURRY
FEED PUMPS
1
1 ^
'""- — ~r '
CLARIFIER C_3— —
WATER
__ MAKE-UP
\ji \
' '
LIME
SLURRY
STORAGE
TANK
^
LINE STORAGE SILO
L
. A ' . A
\/\/
T T
I I
« — Y T
WEIGH FEEDER
V ADDITIVES HOPPER
ROTARY
( ? ) "N "
^- *S SLUDGE fIXATION TANK
N^
FIXED SLUDGE TO DISPOSAL-
Figure 3-1. Lime slurry system.
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for removal of particulate matter. A booster fan is used to
overcome the pressure drop in the scrubbing system.
Flue gas from the electrostatic precipitator or venturi
scrubber enters the absorber tower near the base, where it
is quenched with water for cooling before it ascends through
the absorption section of the tower. Quenching is not
required if the absorber is preceded by a venturi. The
absorber contains two or three stages, where the ascending
flue gas is brought into contact with the lime slurry.
Solids concentrations range from 4 to 15 percent. Sulfur
dioxide removal efficiencies are usually 85 percent or
greater.
The scrubbed gas passes through a demister and is
reheated prior to discharge to the atmosphere. Reheating
provides for plume buoyancy and raises the gas temperature
sufficiently above the dew point to prevent excessive con-
densation.
Lime slurry is prepared on-site by slaking the lime to
form a slurry. The lime system incorporates handling and
conveying equipment, lime storage silos, slakers, and
slurry storage tanks.
Partial water recovery is achieved through solid/liquid
separations. The slurry leaving the absorber goes to the
absorber-circulation tank, where hydrated CaSO- and CaSO
3 4
3-6
-------
crystals are precipitated. A bleed stream carries these
solids to a gravity clarifier, where the crystals, fly ash,
and unreacted lime settle. The overflow from the clarifier
and the filtrate return to the circulation tank. The
underflow from the clarifier is filtered in a rotary filter
to produce a sludge with a moisture content of about 60
percent. The sludge is stabilized (fixed) with chemical
additives in a mixing tank to prevent leaching, then is
pumped or trucked to a permanent disposal site.
Capital and annualized model plant costs for the lime
scrubbing system are shown in Table 3-2.
3.1.2 Limestone Scrubbing System
The limestone scrubbing system, as shown in Figure 3-2,
utilizes a limestone (CaCO_) slurry as the sulfur dioxide
absorbent medium. The process is the same as that of the
lime scrubbing system just described, except that limestone
slurry is prepared on-site by a wet ball milling process to
reduce crushed limestone to a slurry in which 95 percent of
the particles are less than 325 mesh. The limestone system
requires an open limestone storage area, handling and con-
veying equipment, limestone storage silos, wet ball mills,
and slurry storage tanks.
Process steps entailing the circulation tank, the
clarifier, and equipment used in the production, treatment,
3-7
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Table 3-2. LIME SCRUBBING COSTS
Model plant
characteristics
250 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S .
Capital ,
$/kW
76.64
64.29
63.78
51.92
62.52
53.90
53.42
48.17
53.08
48.94
50.44
44.21
$ MM
19.16
16.07
15.95
12.98
31.27
26.95
26.71
24.09
53.08
48.94
50.44
44.21
Operating
and
maintenance,
mills/kWh
2.785
2.256
1.696
1.230
2.137
2.024
1.155
1.086
1.903
1.849
1.053
0.971
Annual i zed
Fuel
and
electricity,
mills/kWh
0.484
0.484
0.566
0.566
0.466
0.466
0.532
0.532
0.476
0.476
0.544
0.544
Fixed
costs,
mills/kWh
3.885
2.483 -
3.241
2.000
2.416
2.082
2.063
1.860
2.050
1.890
1.948
1.708
Total ,
mills/kWh
7.154
5.223
5.503
3.796
5.020
4.572
3.751
3.478
4.429
4.215
3.545
3.223
$ MM
9.400
6.863
7.231
4.988
13.193
12.015
9.858
9.140
23.279
22.154
18.633
16.940
OJ
00
-------
OJ
I
REHEATER
ENTRAINMENT SEPARATOR
-<>FROM
_t\ TRAINS
(TRUCK
HOPPER OR R.R.)
FROM ESP
JJ
^ 'l FROM TRAINS
VENTURI CIRC. TANKS
1
* '
TO ASH
DISPOSAL
POND
•<-y
\y
\-
U-!
•^•ff-
CLEAN GAS TO STACK
PLENUM
FAN
FIDE CSS — .
*•
mt***
*=-<
— *-(
VENTUR
1
EFFLUENT SLURRY SURGE
TANK & PUMPS
VENTURI CIRC. ABSORBER CIRC.
TANK & PUMPS TANK & PUMPS
CLARIFIER
-*-TO SLUDGE DISPOSAL
Figure 3-2. Limestone slurry system.
-------
and disposal of sludge are identical to those of the lime
system.
Capital and annualized model plant costs for the lime-
stone are shown in Table 3-3.
3.1.3 Double Alkali Scrubbing System
The double alkali scrubbing system, as shown in Figure
3-3, uses sodium sulfite solution to remove the sulfur
dioxide from the flue gases. The scrubbing solution is
regenerated by reaction with lime.
Flue gases from the boiler pass through an electro-
static precipitator or venturi scrubber for particulate
removal. A booster fan is used to overcome the pressure
drop in the scrubbing system.
Flue gas from the electrostatic precipitator or venturi
scrubber enters the absorber tower near the base, where it
is quenched with water for cooling before it ascends through
the absorption section of the tower. Quenching is not
required if the absorber is preceded by a venturi. The
absorber contains two or three stages, where the ascending
flue gas is brought into contact with the sodium sulfite
solution. Solid concentrations range from 4 to 15 percent.
Sulfur dioxide removal efficiencies are usually 85 percent
or greater.
The scrubbed gas passes through a demister and is
reheated prior to discharge to the atmosphere. The liquid
3-10
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Table 3-3. LIMESTONE SCRUBBING COSTS
Model plant
characteristics
250 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Capital ,
SAW
90.92
77.08
73.33
59.94
71.61
62.59
62.95
54.28
70.11
59.85
54.84
48.52
$ MM
•
22.73
19.27
18.83
14.99
35.81
31.30
31.48
27.14
70.11
59.85
54.84
48.52
Operating
and
maintenance ,
mills AWh
1.967
1.795
1.342
1.165
1.624
1.473
1.398
0.992
1.530
1.394
0.946
0.864
Annual i zed
Fuel
and
electricity,
mills/kWh
0.516
0.516
0.586
0.586
0.499
0.499
0.586
0.586
0.499
0.499
0.558
0.558
Fixed
costs,
mills AWh
•
3.511
2.975
2.832
2.314
2.766
2.416
2.432
2.093
2.707
2.310
2.118
1.874
Total ,
mi 11s AWh
5.994
5.286
4.760
4.065
4.889
4.388
4.388
3.671
4.736
4.203
3.622
3.296
$ MM
7.876
6.946
6.255
5.341
12.848
11.531
11.531
9.647
24.892
22.091
19.037
17.323
u>
I
-------
and disposal of sludge are identical to those of the lime
system.
Capital and annualized model plant costs for the lime-
stone are shown in Table 3-3.
3.1.3 Double Alkali Scrubbing System
The double alkali scrubbing system, as shown in Figure
3-3, uses sodium sulfite solution to remove the sulfur
dioxide from the flue gases. The scrubbing solution is
regenerated by reaction with lime.
Flue gases from the boiler pass through an electro-
static precipitator or venturi scrubber for particulate
removal. A booster fan is used to overcome the pressure
drop in the scrubbing system.
Flue gas from the electrostatic precipitator or venturi
scrubber enters the absorber tower near the base, where it
is quenched with water for cooling before it ascends through
the absorption section of the tower. Quenching is not
required if the absorber is preceded by a venturi. The
absorber contains two or three stages, where the ascending
flue gas is brought into contact with the sodium sulfite
solution. Solid concentrations range from 4 to 15 percent.
Sulfur dioxide removal efficiencies are usually 85 percent
or greater.
The scrubbed gas passes through a demister and is
reheated prior to discharge to the atmosphere. The liquid
3-10
-------
Table 3-3. LIMESTONE SCRUBBING COSTS
Model plant
characteristics
250 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Capital ,
$/kW
90.92
77.08
73.33
59.94
71.61
62.59
62.95
54.28
70.11
59.85
54.84
48.52
$ MM
22.73
19.27
18.83
14.99
35.81
31.30
31.48
27.14
70.11
59.85
54.84
48.52
Operating
and
maintenance,
mills/kWh
1.967
1.795
1.342
1.165
1.624
1.473
1.398
0.992
1.530
1.394
0.946
0.864
Annual i zed
Fuel
and
electricity,
mills/kWh
0.516
0.516
0.586
0.586
0.499
0.499
0.586
0.586
0.499
0.499
0.558
0.558
Fixed
costs,
mills/kWh
•
3.511
2.975
2.832
2.314
2.766
2.416
2.432
2.093
2.707
2.310
2.118
1.874
Total ,
mills/kWh
5.994
5.286
4.760
4.065
4.889
4.388
4.388
3.671
4.736
4.203
3.622
3.296
$ MM
7.876
6.946
6.255
5.341
12.848
11.531
11.531
9.647
24.892
22.091
19.037
17.323
-------
U)
I
M
N)
TO STACK
REHEATER ENTRAPMENT
SECTION -^ SEPARATOR
STEAM (OPT.
TO BOILER
HOUSE
TO VENT TANK
\/
T- VIBR. FEEDER
VENTURI ABSORBER
CIRC.TANK FEED TANK
AND PUMPS AND PUMPS
FIXED SLUDGE TO DISPOSAL POND ETC.-*
s —
\ BYPASS
HSS &..L-
Of ^
FROM POND
TO POND
\
fmtfUimJ
SLUDGE FIXATION TANK
Figure 3-3. Double alkali system.
-------
stream containing sulfur dioxide, which has reacted with the
sodium sulfite, and some fly ash enters a tank. Part of the
liquor from this tank may be recycled to the scrubber inlet
and the balance goes to a reactor/clarifier tank, in which
lime and/or limestone is reacted with the liquor to regen-
erate the sodium sulfite. This occurs because the calcium
in the lime/limestone reacts with the absorbed sulfur
dioxide to form insoluble calcium sulfate. Clarified and
regenerated scrubbing liquor is then recycled from this tank
to the scrubber. Insoluble calcium-sulfur compounds are
precipitated and removed from this clarifier tank.
A side stream from the primary clarifier is further
treated in a regeneration step to treat and remove nonregen-
erable sodium sulfate compounds.
Limestone slurry is prepared on-site by a wet ball
milling process to reduce crushed limestone to a slurry with
95 percent of the particles less than 325 mesh. The lime-
stone system entails an open limestone storage area, han-
dling and conveying equipment, lime storage silos, wet ball
mills, and slurry storage tanks.
Capital and annualized model plant costs for double
alkali are shown in Table 3-4.
3-13
-------
Table 3-4. DOUBLE ALKALI SCRUBBING COSTS
Model plant
characteristics
250 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Capital,
S/kW
99.54
83.83
89.78
74.05
93.03
81.88
77.76
66.77
84.13
^6.09
73.36
54.51
$ MM
74.87
20.96
22.45
18.51
46.52
40.94
38.88
33.39
84.13
76.09
73.36
54.51
Operating
and
maintenance ,
mills/kWh
2.124
1.918
1.558
1.356
1.761
1.615
1.306
1.162
1.756
1.650
1.196
0.948
Annual i zed
Fuel
and
electricity,
mills/kWh
0.590
0.590
0.607
0.607
0.508
0.508
0.573
0.573
0.518
0.517
0.585
0.585
Fixed
costs,
mills/kWh
•
3.844
3.237
3.467
2.864
3.593
3.163
3.003
2.583
^
3.250
2.939
2.833
2.105
Total .
mills/kWh
6.558
5.745
5.632
4.827
5.862
5.286
4.882
4.318
5.523
5.106
4.614
3.638
$ MM
8.617
7.549
7.400.
6.343
15.405
13.892
12.830
11.348
29.029
26.837
24.251
19.121
U)
I
-------
3.1.4 Magnesium Oxide Scrubbing System
The magnesium oxide scrubbing system, as shown in
Figure 3-4 uses a slurry of magnesium oxide to absorb sulfur
dioxide. The sulfur dioxide is recovered from the magnesium
salt by calcining.
The process steps are similar to those of the lime/
limestone scrubbing systems in the early stages. Solids
content of the magnesium oxide slurry ranges from 4 to 10
percent. Sulfur dioxide removal efficiencies are 85 percent
or greater. The scrubbed gas passes through a demister and
is reheated.
The bleed from the absorption system enters the cen-
trifuge, where the crystals of magnesium sulfite, magnesium
sulfate, and unreacted magnesium oxide are separated from
the mother liquor. The mother liquor is returned to the
absorption system and the centrifuged wet cake enters the
dryer for removal of both the sulfur and bound moisture.
The hot flue gas from the dryer is mixed with absorber
outlet gas, and the heat content of the dryer flue gas
provides reheat to the absorber outlet gas.
The anhydrous MgS03 and MgS04 mixture is then conveyed
to a storage silo before transportation by covered trucks,
barges, or rail cars to the recovery acid plant. The same
carriers return regenerated MgO (with make-up) to an MgO
3-15
-------
TYPICAL PROCESS FLOWSHEET
MAGNESIA SLURRY - HS0
CO
I
M
CTi
*TIM>
TDWWtT
Figure 3-4. Magnesium oxide slurry system.
-------
silo at the power plant. The MgO slurry is prepared with
regenerated MgO, make-up MgO, and make-up water. The MgO
slurry is added as make-up to the absorption recycle liquid
system.
The dry crystals of MgS03, MgS04, and MgO shipped by
truck from the power plant are weighed and pneumatically
conveyed to an MgS03 storage silo. The-dry crystals are
then fed to a direct-fired rotary calciner (or fluidized
bed) and calcined to generate S02 gas and regenerate MgO.
Coke is added to reduce the residual MgSO. to MgO and S02-
The hot flue gas containing 12 to 16 percent S0? and
dust enters the hot cyclone, where essentially all the dust
is collected and returned to the calciner. The flue gas
then enters a venturi scrubber for final dust cleaning and
adiabatic saturation. The saturated flue gas is cooled to
100°F in a direct-contact cooler. The cleaned, cooled flue
gas enters the drying tower and the sulfuric acid plant for
production of 98 percent H2SO4 acid. The regenerated MgO is
cooled, conveyed to the MgO storage silo and recycled back
to the power plant site for reuse.
Capital and annualized model plant costs for the
magneisum oxide system are shown in Table 3-5.
3-17
-------
Table 3-5. MAGNESIUM OXIDE SCRUBBING COSTS
Model plant
characteristics
250 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0. 6% S
New, 0.6% S
1000 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S •
Capital,
$/kW
101.07
90.80
76.43
62.93
84.93
74.89
65.43
55.73
76.31
96.06
57.62
50.54
$ MM
25.27
22.70
19.11
15.73
42.47
37.45
32.72
27.89
76.31
96.06
57.62
50.54
Operating a
and
maintenance,
mills/kWh
1.862
1.727
1.364
1.186
1.493
1..359
1.067
0.938
1.181
1.204
0.942
0.796
Annual i zed
Fuel
and
electricity,
mills/kWh
0.488
0.478
0.581
0.505
0.459
0.459
0.529
0.529
0.479
0.479
0.517
0.517
Fixed
costs,
mills/kWh
3.903
3.507
2.952
2.431
2.705
2.383
2.527
2.153
2.947
2.197
2.225
1.952
Total , _
mills/kWh
6.253
5.712
4.897
4.122
4.657
4.201
4.123
3.620
4.607
3.880
3.684
3.265
$ MM
8.216
7.506
6.435
5.416
12.24
11.040
10.835
9.513
24.214
20.393
19.363
17.161
OJ
M
00
No credits included.
-------
3.1.5. Wellman-Lord Scrubbing System
The Wellman-Lord S02 recovery system, as shown in
Figure 3-5, is based on the ability of an aqueous solution
of sodium sulfite/bisulfite to react with sulfur dioxide at
relatively low temperatures and release it when subjected to
evaporation.
Flue gases from the boiler pass through an electro-
static precipitator or venturi for particulate removal. A
booster fan is used to overcome the pressure drop in the
scrubbing system.
Flue gas from the electrostatic precipitator or venturi
enters the absorber tower near the base, where it is quenched
with water for cooling before it ascends through the absorp-
tion section of the tower. Quenching is not required if the
absorber is preceded by a venturi. The absorber contains
two or three stages, where the ascending flue gas is brought
into contact with the aqueous solution of sodium sulfite/
bisulfite. The lead sodium sulfite is fed into the tower
near the top and flows downward, passing through each stage
countercurrently to the flow of the gas. As sulfur dioxide
is absorbed in the solution, sulfite converts to bisulfite.
The scrubbed flue gas exits the absorber, passed
through a demister, and is reheated before discharging to
the atmosphere. More than 85 percent of the sulfur dioxide
3-19
-------
TO SULFUR OR
BOOSTER Fi
OJ
I
ro
o
t I I J
EVAPORATOR HEATERS
/~•*[ ABSORBER
FEED PUMP
MAKE-UP WATER
Figure 3-5. Wellman-Lord system.
-------
in the flue gas is removed in the absorber.
The solution is discharged from the base of the absorp-
tion section of the tower into a sodium bisulfite storage
tank. Use of this tank and the companion sodium sulfite
storage tank permits regulation of the feed and provides
enough surge capacity to allow the absorber to operate
independently of the rest of the process.
From the storage tank, the solution enters an evapora-
tor, where low-pressure steam heats the solution, driving
off sulfur dioxide and water vapor. Sodium sulfite is
precipitated and a dense slurry of crystals is formed. To
reduce the steam requirement, double-effect evaporators are
used. The overhead from the first evaporator condenses in
the reboiler of the second evaporator. The overheads from
the second evaporator and the noncondensable fractions from
the first evaporator are passed through a partial condenser.
From the partial condenser the sulfur dioxide/water mixture
is rectified in a stripper. The overheads from the stripper
pass through another partial condenser to remove the aqueous
phase. The noncondensables from this condenser, containing
about 90 percent sulfur dioxide by weight (10 percent water
vapor), are further processed to recover sulfuric acid,
elemental sulfur, or liquid S02. Condensate from the
reboiler, the stripper bottoms, and fresh make-up water are
3-21
-------
used to redissolve the sodium sulfite crystals in a dissol-
ving tank. The solution, primarily sodium sulfite, is
pumped from the dissolving tank to the sulfite storage tank.
To prevent buildup of sodium sulfate and other inert
materials such as fly ash, some of the liquid leaving the
abosrber is purged from the system. This purge stream is
chilled to precipitate the sodium sulfate crystals. The
crystals and fly ash are separated with a centrifuge, then
washed and dried. The treated purge stream is recycled to
the system. Caustic soda or soda ash is added to replenish
the sodium ion lost from the system in the purge stream.
Capital and annualized model plant costs for the
Wellman-Lord system are shown in Table 3-6.
3.2 FACTORS AFFECTING FGD PROCESS SELECTION
Several factors have major impact on selection of an
FGD process for a given set of site specific conditions.
These factors include sulfur removal requirements, land
availability, sludge disposal, by-product markets, flue gas
volume, availability of raw materials, availability of steam
and natural gas, and utility costs.
The quantity of SO- to be removed at an FGD installa-
tion is dictated by the difference between the S0_ emission
rate, which varies directly with the sulfur content of the
fuels, and the emission rate allowed by the applicable
regulation. The S02 removal requirements affect the size of
the facilities for treatment and disposal of sludge produced
3-22
-------
Table 3-6. WELLMAN-LORD SCRUBBING COSTS
Model plant
characteristics
250 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
500 megawatt capacity
Retrofit, 3.5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
1000 megawatt capacity
Retrofit, 3. '5% S
New, 3.5% S
Retrofit, 0.6% S
New, 0.6% S
Capital,
$/kW
99.73
86.07
74.66
62.36
91.54
82.49
67.79
59.06
85.47
78.42
63.74
57.07
$ MM
24.93
21.52
18.67
15.59
45.77
41.25
33.90
29.53
85.47
78.42
63.74
57.07
Operating
and
maintenance ,
mills/kWh
1.743
1.562
1.408
1.247
- 1.424
1.304
1.105
0.990
1.236
1.143
0.945
0.857
Annualized
Fuel
and
electricity,
mills/kWh
0.881
0.881
0.787
0.787
0.871
0.871
0.778
0.778
0.857
0.857
0.773
0.773
Fixed
costs,
mills/kWh
3.160
2.727
2.365
1.975
2.902
2.613
2.148
\
1.871
2.709
2.484
2.019
1.808
Total ,
mills/kWh
5.783
5.170
4.560
4.009
5.196
4.788
4.031
3.639
•
4.802
4.484
3.737
3.438
$ MM
7.599
6.793
5.992
5.268
13.655
12.583
10.593
9.563
25.239
23.568
19.642
18.070
u>
I
N)
U)
No credits included.
-------
in nonregenerative systems. The effect of S02 removal
requirements on capital cost is illustrated in Figure 3-6,
which shows the differential for a model 500 MW existing
plant over a range of coal sulfur contents (allowable S02
emission rate of 1.2 Ib/MM Btu). As the figure shows, costs
of the Wellman-Lord system are much more sensitive to SC>2
removal requirements than are costs of the other systems.
Land availability, sludge disposal, and by-product
markets are interrelated. Abundance of land reduces sludge
disposal costs and makes nonregenerable systems somewhat
more favorable. Good markets for by-products favor regen-
erative systems.
High flue gas volumes favor the sodium compound ab-
sorbing systems, which have lower pressure drops and L/G
ratios. High costs of electricity also favor the sodium
compound systems. High costs of steam penalize the Wellman-
Lord system. Scarcities of fuel oil and natural gas affect
the magnesium oxide system adversely. Table 3-7 summarizes
the impacts of different variables on each of the processes.
3-24
-------
I
to
U1
+40
+30
+20
+10
z
UJ
cc
to
o
o
-10
-20
Q-
<
0 -30
-40
LOCATION OF MODEL PLANT
CHARACTERISTICS
I
123456
SULFUR CONTENT OF COAL, wt.%
Figure 3-6. Incremental effect of sulfur content of coal on model plant capital
Cost (model plant characteristics: 500 MW/existing).
-------
Table 3-7. EFFECTS OF SITE-SPECIFIC VARIABLES ON FGD SYSTEMS
Impact
High utilities
No natural gas
or oil
Scaling
Sulfur removal
Land availability
Sludge disposal
High steam cost
Raw material
availability
Flue gas volume
Lime
-
+
-
-
-
Limestone
-
+
-
-
-
Double
alkali
+
+
+
-
-
+
Wellman-
Lord
+
+
-
+
+
-
+
Magnesium
oxide
-
+
+
+
Key
Black
Favors process
Does not favor process
Does not affect process
3-26
-------
4. SURVEY OF FGD SYSTEM COSTS
A survey of the utility industry was conducted by the
Edison Electric Institute (EEI) to determine the costs of
FGD systems. EEI contacted all utilities known to have an
FGD system that is operational or under construction, or who
plan to install such a system. The utilities were asked to
complete a 14-page questionnaire, providing information
about the system and its costs. Responses encompassed 43
systems. As anticipated, the reported costs cover a broad
range; variations are attributable both to site-specific
factors and to nonuniformity with respect to items included
in the cost estimates.
PEDCo's analysis of the EEI data centers on adjusting
the estimates to a common basis to determine representative
costs. No attempt is made to verify the costs reported by
any utility or to evaluate system design. Adjustments focus
primarily on the following items:
0 Costs are adjusted to January 1975 dollars. Costs
are reported in dollar values ranging from the
years 1970 to 1980.
0 Costs of particulate control are included. Since
the purpose of the study is to estimate the
incremental cost for S02 control, particulate
control costs are deducted either on the basis of
4-1
-------
data contained in the cost breakdowns or as a per-
centage of the total direct equipment cost. The
percentage reduction varies with system design.
0 Indirect charges are adjusted, usually upward, to
provide adequate funds for engineering, field
expenses, overheads, interest during construction,
start-up, and contingency.
0 Replacement power costs are deducted, since only a
few utilities report such costs and these are
determined by a variety of methods. Thus the
adjusted costs do not include replacement power.
0 Sludge disposal costs are adjusted to reflect the
costs of S02 scrubber sludge disposal only (i.e.,
not disposal of fly ash) and to provide for dis-
posal over the anticipated lifetime of the FGD
system. This latter correction is necessary
because several utilities report costs for demon-
stration sludge disposal systems that would last
only a fraction of the FGD system life.
0 Costs of a regeneration facility and acid or
sulfur recovery facility are added for those
regenerable systems not reporting such costs.
To the extent possible, all cost adjustements are made
on the basis of the cost breakdown data provided on the
questionnaire. Where these data are inadequate, costs
adjustments are based upon system design parameters. In
some cases, no adjustments are possible because of insuf-
ficient data; in others, no adjustments are warranted be-
cause of unique circumstances (e.g., a demonstration unit
with funds included for experimentation).
The adjusted costs for all systems with sufficient data
(30 systems), range from $50 to $205 kW with an average of
$91/kW (a = 33.90). Both the upper end of the range and the
4-2
-------
average costs are high because of an exceptionally high cost
reported by the New England Power Company for a prototype
FGD system; the utility stated that their reported values
should be considered "upper limits." Excluding the costs
reported by New England Power Company, the costs range from
$50 to $137 kW, with an average value of $85/kW. Adjusted
costs for lime- and limestone-based systems reported by 19
utilities range from $50 to $88/kW, with an average of
$70/kW (a = 9.48). These adjusted costs agree substantially
with those developed by use of the cost estimating manuals.
The values reported by individual facilities, the
factors considered in the cost adjustments, and the adjusted
costs are presented in Table 4-1. Table 4-2 compares esti-
mates derived by use of the cost estimating manuals with the
adjusted estimates reported by utilities and manufacturers.
4-3
-------
Table 4-1. SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
Alabama Electric Cooperative
Tombigbee Units 2 & 3
Jackson, Alabama
Process - Limestone
Status - Under Consideration
Start-up Date: 3/78, 1/79
Allegheny Power Service Corp.
Pleasants Power Station Units 1 & 2
Willow Island, West Virginia
Process - Lime
Status - Under Consideration
Start-up Date: 8/78, 8/79
Arizona Public Service Company
Choi la Unit 1
Joseph City, Arizona
Process - Limestone
Status - Operational
Start-up Date: 12/73
Boston Edison Company
Mystic Station
Charlestown, Massachusetts
Process - Magnesium Oxide
Status - Operational
Start-up Date: 4/72
Central Illinois Public Service Co.
Newton Station Unit 1
Newton, Illinois
Process - Lime/Limestone
Status - Evaluating Bids
Start-up Date: 12/77
Capaci ty
MW
357
510
1236
1236
•
59.9
119.8
150
150
600
600
Reported Costs
Capital
$ Millions
40.464
(1975)
6.55
5.01
(Actual
Costs)
$/KW
113.34
109.35
33.4
Comments
1. Deleted costs for particulate control
1. No costs available
1. Adjusted costs from 1973 to 1975
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
2 years to 22 years
4. Added limestone preparation and
sludge disposal costs
5. Considered costs for system representa-
tive for treating full 119.8 MW;
only difference between the modules is
that module B is not packed
1. Added regeneration system costs
2. Added reheat costs
3. Added acid plant costs
4. Increased costs from demonstration
unit to permanent installation
1. No costs available; bids being
evaluated
1975 Adjusted Costs
CaoitaL
$ Mil 1 ions
29.047
7.036
17.005
S/KW
81.36
58.73
113.37
* Top number is the F60 system capacity; bottom number Is the total capacity of the units to which the FGD system is applied.
-------
Table 4-1 (continued). SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
Cincinnati Gas & Electric Company
Miami Fort Station Unit 8
North Bend, Ohio
Process - Lime
Status - Planned
Start-up Date: 1/78
Columbus & 'Southern Ohio Electric Co.
Conesville Generating Station
Units 5 & 6
Conesville, Ohio
Process - Lime
Status - Under Construction
Start-up Date: 5/75, 5/76
Dallas Power & Light Company
Texas Electric Service Co.
Texas Power & Light Co.
Martin Lake Steam Electric
Station Units 1, 2, 3, & 4
Rusk County, Texas
Process - Limestone
Status - Under Construction
or Planned
Start-up Date: 2/77, 8/77,
12/76, 12/79
Dallas Power & Light Company
Texas Electric Service Co.
Texas Power & Light Co.
Monticello Steam Electric
Station Unit 3
Titus County, Texas
Process - Limestone
Status - Planned
Start-up Date: 12/78
Capacity
MW
500
500
822
822
1500 (1 & 2)
1500
750
750
Reported Costs
Capital
$ Millions
40.702
(1978)
38.661
(1975)
50.436
(1974)
$/KW
81.40
47.03
33.62
Comments
1. Adjusted costs from 1978 to 1975
2. Added sludge disposal and trans-
portation costs
3. Deleted replacement capacity cost
1. Added indirect costs
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
5 years to 33 years.
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate control
3. Added indirect costs
4. Adjusted pond life and costs from
7 years to 35 years
5. Costs are identical for Unit 2;
costs given for Units 3 8 4 were
incomplete
6. 1500 MW of capacity
1. Costs given were incomplete
1975 Adjusted Costs
rap if i
$ Millions
36.616
61.563
75.082
S/KW .
73.23
74.89
50.12
I
Ul
Top number is the FGD system capacity; bottom number is the total capacity of the units to which the FGD system is applied.
-------
Table 4-1 (continued). SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
Detroit Edison Company
St. Clair Power Plant Unit 6
Belle River, Michigan
Process - Limestone
Status - Under Construction
Start-up Date: 5/75
Detroit Edison Company
Monroe Units 1 , 2, 3, & 4
Monroe County, Michigan
Process - Limestone
Status - Under Construction
Start-up Date: 1981
Duquesne Light Company
Frank R. Phillips Station
Units 1, 2, 3, 4, 5, & 6
Wireton, Pennsylvania
Process - Line
Status - Operational
Start-up Date: 1973
General Public Utilities Service
Corp. (Penna. Electric Co. & N.Y.
State Electric & Gas Company)
Homer City Station Unit 3
Homer City, Pennsylvania
Process - Lime
Status - Planned
Start-up Date: 10/77
Illinois Power Company
Wood River Unit 1
East Alton, Illinois
Process - Catalytic Oxidation
Status - Operational
Start-up Date: 8/74
Capacity
MW
170
325
3000
3000
138.3
414.9
650
650
103
103
Reported Costs
Capital
$ Millions
13.088
(1975)
344.0
(1981)
32.346
(1974)
60.192
(1977)
8.2957
(1975)
$/KW
80.54
114.67
77.96
92.60
80.54
Comments
1. Increased costs from test module to _
permanent installation
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
1 year to 20 years
4. Added limestone preparation costs
1. Adjusted costs from 1981 to 1975
2. Detailed cost breakdown was not
available
1. Adjusted costs from 1974 to 1975
2. Deleted costs for particulate control
3. Adjusted pond life and costs from
3 years to 20 years
1. Adjusted costs from 1977 to 1975
2. Decreased costs for 25% system redun-
dancy
3. Added interest costs
4. Added contingency and start-up costs
5. Deleted replacement power costs
1. Adjusted costs from 1970 to 1975
2. Added interest costs
3. Electrostatic precipitator costs
allowed since the system requires
essentially ash free flue gas
1975 Adjusted Costs
Capital
$ Millions
13.693
262.6
10.456
47.750
»
10.649
S/KW
80.55
87.53
75.60
73.46
103.39
a Top number is the FGO system capacity; bottom number is the total capacity of the units to which the FGD system is applied.
-------
Table 4-1 (continued). SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
Indianapolis Powsr & Light Co.
Petersburg Generating Station
Unit 3
Petersburg, Indiana
Process - Limestone
Status - Planned
Start-up Date: 4/77
Kansas Power & Light Co.
Lawrence 4 & 5
Lawrence, Kansas
Process - Limestone Injection
Status - Operational
Start-up Date: 1/68, 6/71
Kentucky Utilities Company
Green River Power Station
Units 1, 2, & 3
Central City, Kentucky
Process - Lime
Status - Under Construction
Start-up Date: 5/75
Montana Power Company
Colstrip Units 1 & 2
Colstrip, Montana
Process - Lime
Status - Under Construction
Start-up Date: 7/75, 5/76
New England Power Company
Bray ton Point Unit 1
Somerset, Massachusetts
Process - Metal Oxide
Status - Under Construction
Start-up Date: 1/77
Capacity3
MW
532
532
525
525
60
60
716
716
75
250
Reported Costs
Capital
$ Millions
32.856
(1974)
3.966
(1975)
65.266
(1975)
14.811
(1975)
$/KW
61.76
66.10
91.15
197.48
Comments
1. Adjusted costs from 1974 to 1975
2. Deleted costs for particulate control
3. Increased contingency
4. Added sludge disposal costs
1. No costs available
1 . Turnkey contract costs reported
2. Insufficient cost breakdown to
permit cost adjustments
1. Deleted costs for particulate control
2. Added sludge disposal costs - pond
and equipment.
1 . Added start-up costs
2. Demonstration unit; costs not
representative of full scale system
1975 Adjusted Costs
Capital
$ Mil 1 ions
39.120
3.966
51.990
15.341
S/KW
73.53
66.10
72.61
204.55
a Top number is the FGD system capacity; bottom number Is the total capacity of the units to which the FGO system is applied.
-------
Table 4-1 (continued). SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
New England Power Company
Brayton Point Unit 3
Somerset, Massachusetts
Process - Metal Oxide
Status - Under Construction
Start-up Date:
•«
Northern Indiana Public Service Co.
Dean H. Mitchell Plant Unit 11
Gary, Indiana
Process - Well man/All led
Status - Under Construction
Start-up Date: 4/76
Northern States Power Company
Sherburne County Generating Plant
Units 1 & 2
Becker, Minnesota
Process - Limestone
Status - Under Construction
Start-up Date: 5/76, 5/77
Ohio Edison Company
Bruce Mansfield Plant Units 1 & 2
Shippingport, Pennsylvania
Process - Lime
Status - Under Construction
Start-up Date: 12/75, 4/77
Philadelphia Electric Company
Eddystone Generating Station Unit 1
Chester, Pennsylvania
Process - Magnesium Oxide
Status - Under Construction
Start-up Date: 6/75
Capacity
MW
654
654
115
115
1360
1360
1834
1834
103.3
325
• '" - • •• - --]-•] a.
Reported Costs
Capital
$ Millions
95.0
(1975)
13.441
(1975)
60.0
(1975)
213.2
(1977)
20.189
$/KW
145.26
116.88
44.12
116.25
186.42
Comments
1. Added start-up costs
2. Utility states that these costs
reported should be considered the
upper 1 imit
1. Wellman-Lord system with Allied
Sulfur recovery process
2. Insufficient cost breakdown to
permit cost adjustments.
1. Added indirect costs
2. Decreased costs for 9» system redundancy
3. Adjusted pond life and costs from
12 years to 30 years
4. Increased sludge disposal costs
5. Available cost breakdown insufficient
to permit proper adjustments
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate removal
3. Decreased costs to remove approximately
20% system redundancy
4. Reduced pond cost to account for S02
control only. Original pond & sludge
transport treatment system cost was 42%
of total direct capital cost compared
to typically reported values of 10- 15%
1. Adjusted costs from 1972 to 1975
2. Deleted costs for particulate removal
3. Added interest
4. Added acid plant & ancillaries
1975 Adjusted Costs
Capital
$ Mil 1 ions
98.4
13.441
95.689
142.699
14.837
S/KW
150.46
116.88
70.36
77.81
137.00
.JS-
1
CO
a Top number is the FGD system capacity; bottom number is the total capacity of the units to which the FGD system is applied.
-------
Table 4-1 (continued). SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
Potomac Electric Power Company
Oickerson Unit 3
Oickerson, Maryland
Process - Magnesium Oxide
Status - Operational
Start-up Date: 9/73
Public Service of New Mexico
San Juan Station Unit 1
Waterflow, New Mexico
Process - Hellman/Allied
Status - Planned
Start-up Date: 12/76
Public Service of New Mexico
San Juan Station Unit 2
Waterflow, New Mexico
Process - Well man/All led
Status - Planned
Start-up Date: 6/77
Public Service of New Mexico
San Juan Station Unit 3
Waterflow, New Mexico
Process - Wei Iman/ Allledl
Status - Under Consideration
Start-up Date: 5/78
Public Service of New Mexico
San Juan Station Unit 4
Waterflow, New Mexico
Process - Hell man/At lied
Status - Under Consideration
Start-up Date: 5/80
•^•••••••••^•••A^VMW^Vi^H-llH^^^^WM^B
Capacity
MW
95
184
350
350
350
350
550
550
550
550
• !!•!• ^•111 •!• Mir— Ill —
Reported Costs
Capital
$ Millions
6.500
(1973)
44.755
(1974)
44.755
(1974)
59.199
(1974)
71.137
(1980)
S/KW
68.42
127.87
127.87
107.63
129.34
Comments
1. Adjusted costs from test module to
permanent installation
2. Adjusted costs from 1973 to 1975
3. Added interest costs
4. Added regeneration and acid plant cost
1. Adjusted costs from 1976 to 1975
2. Decreased costs for 33% system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100" oversized: no cost
adjustment made
1. Adjusted costs from 1977 to 1975
2. Decreased costs from 33% system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100% oversized; no cost
adjustment made
1. Adjusted costs from 1978 to 1975
2. Decreased costs for 25* system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100% oversized; no cost
adjustment made
1. Adjusted costs from 1980 to 1975
2. Decreased costs for 25% system
redundancy
3. Deleted particulate removal costs
4. Chemical plant 100% oversized; no cost
adjustment made
1975 Adjusted Costs
Capital
$ Millions
13.68
39.348
39.348
52.431
52.431
S/KW
144.00
112.42
112.42
95.33
95.33
*»
I
vo
a Top number is the FGD system capacity; bottom number Is the total capacity of the units to which the FGO system is applied.
-------
Table 4-1 (continued). SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
Salt River Project
Navajo Generating Station
Units 1. 2 & 3
Process - Lime/Limestone
Status - Under Construction
Start-up Date:
South Carolina Public Service Auth
Winyah Generating Station Unit 2
Georgetown, South Carolina
Process - Limestone
Status - Planned
Start-up Date: 5/77
South Mississippi Elec. Power Ass.
R. 0. Morrow Sr. Generating Plant
Purvis, Mississippi
Process - Limestone
Status - Planned
Start-up Date: 6/77
Southern California Edison Company
Mohave Generating Station Unit 2
South Point, Nevada
Process - Lime
Status - Operational
Start-up Date: 1/74
Southern California Edison Company
Mohave Generating Station Unit 1
South Point, Nevada
Process - Limestone
Status - Operational
Start-up Date: 10/74
Southern California Edison Company
Highgrove Generating Station
Col ton, California
Process - Lime.
Status - Operational
Start-up Date: 1/73
Capacity3
MW
2250
2250
140
280
275.28
444
169.85
790
169.85
790
•t
f
10
45
Reported Costs
Capital
$ Mil 1 ions
6.819
(1975)
7.80
(1975)
17.1
(10/74)
0.400
(1973)
S/KW
48.71
45.92
100.68
40.00
Comments
1 . No costs available
1. Deleted costs for particulate removal
2. Added interest costs
3. Added sludge disposal costs
4. Added utilities & services costs
1 . No costs available
1. Demonstration program. Unable to
separate costs or make accurate cost
adjustments
1. Demonstration program. Unable to
separate costs or make accurate cost
adjustments
1. Demonstration program. Unable to
separate costs or make accurate cost
adjustments
1975 Adjusted Costs
Capital
$ Mi 1 1 ions
7.756
$/KH
55.40
I
M
O
a Top number is the FGD system capacity; bottom number 1s the total capacity of the units to which the FGD system 1s applied.
-------
Table 4-1 (continued). SUMMARY OF UTILITY INDUSTRY SURVEY
Company
Plant
Location
1
Southern California Edison Company
Mohave Generating Station Units 1 & 2
South Point, Nevada
Process - Lime
Status - Planned
Start-up Date: 6/77
Southern California Edison Company
Kaiparowits Generating Station
Units 1, 2, 3 & 4
Page, Arizona
Process - Lime
Status - Under Consideration
Start-up Date: 1980
Tennessee Valley Authority
Widows Creek Steam Plant Unit 8
Stevenson, Alabama
Process - Limestone
Status - Under Construction
Start-up Date: 2/77
Virginia Electric & Power Company
Mt. Storm
Kt. Storm, Virginia
Process - Limestone
Status - Under Construction
Start-up Date: 12/77
Capacity9
MW
••••••••••VM^MVwnvM^HViivmm
1580
1580
3000
3000
550
550
1147.11
1662.48
*
Reported Costs
Capital
$ Millions
MB^Mfl*^HH^^M^»«B«MII^HHWBM
1.79.0
(1977)
300
(1980)
55.636
(1977)
85.739
(1978)
$/KW
•^•^V^HI^M^M^B^M
81.65
100.00
101.16
74.74
Cnmments
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate removal
3. Decreased costs for 25% system
redundancy
4. Added sludqe pond costs
5. Adjusted sludge disposal costs
1. Adjusted costs from 1980 to 1975
2. No cost breakdown available to
permit proper adjustments
1. Adjusted costs from 1977 to 1975
2. Deleted costs for particulate removal
3. Increased sludge disposal costs
1. Adjusted costs from 1977 to 1975
2. Increased indirect costs
3. Added sludge disposal costs for SO-
disposal for 23 years
4. Deleted coal refuse from sludge
disposal costs
1975 Adjusted Costs
Canital
$ Millions
•^•••^•••^^^^••••••^^•••MIV
94.891
189.05
37.681
84.873
$/KW _ .
60.06
63.02
55.51
73.99
a Top number Is the FGD system capacity; bottom number Is the total capacity of the units to which the F60 system is applied.
-------
Table 4-2. RANGES OF COSTS REPORTED FOR FLUE GAS DESULFURIZATION SYSTEMS
FGD
Process
Regenerable
Nonregenerable
( 1 ime/1 ime s tone )
Manufacturers
New
b
33-74
Retrofit
b
42-78
PEDCo a
New
57-86
49-77
Retrofit
63-99
55-91
Utility industry
As reported
New
107°
33-129
Retrofit
33-197
40-115
Adjusted
New
95C
50-81
Retrofit
115-205
59-87
*>.
I
M
to
Values obtained by use of PEDCo's cost-estimating manuals
Tto costs were available from manufacturers.
Only one plant reported in this category.
-------
5. USE OF THE COST ESTIMATING MANUALS
The cost estimation manuals incorporate nomographs to
simplify preparation of cost estimates. Although the cost
values also can be developed by use of equations, the
nomographs are presented as a rapid and accurate means of
preparing the estimate. With these manuals a person pro-
ficient in the use of nomographs can generate a site-spe-
cific cost estimate in about 4 hours. For applications that
involve constraints on time and labor, simplified cost
estimation procedures are also presented for each of the FGD
systems. By use of these greatly abbreviated procedures, an
estimate may be completed in about half an hour.
The following sections describe the input materials
required for use of the cost estimation manuals.
5.1 PLANT DATA
Basic information concerning plant operations may be
compiled on a survey form. Table 5-1 illustrates a com-
pleted plant survey form. Most of the information on this
form can be obtained from FPC Form 67. Note that values for
generating capacity, fuel usage, and flue gas volume should
be at maximum continuous operation. Operating data are to
5-1
-------
Table 5-1. PLANT SURVEY FORM
Boiler No.
Type of furnace
MW at maximum continuous
Age of unit, years
Life, years remaining
Capacity factor, yr. 74
Maximum continuous fuel,
ton/hr or gal/min
Maximum continuous,
MM Btu/hr
acfm at 310°F
Fly ash/total ash, %
Efficiency of existing
particulate control
Pulverized
75
20
13
45
30.8
690
238125
85
85
Cyclone
150
15
18
60
61.6
1380
476250
10
95
Cyclone
150
15
18
60
61.6
1380
476250
10
95
Pulverized
500
3_
30
70
205.36
4600
1.54xlO(
85
99
Cost of electricity/KWH (Plant) = $ 0.02 . Cost of water/M gas. (Plant)
Coal, cost/ton $ 25.00 = $Q.20/M gal
% sulfur by weight 3.5
% ash by weight 11.2
HHV, BTU/lb 11,200
Oil, cost/bbl $ N.A.
% sulfur by weight N.A.
BTU/gal N.A.
Specific gravity N.A.
S02 permissible 1.5
Fly ash permissible 0.12
Ib S02/MM Btu
Ib fly ash/MM Btu
State or
Federal regulations
5-2
-------
Table 5-1 (Continued). PLANT SURVEY FORM
Estimated land cost per acre (current) $ 2000
Possible interference determining the location
of flue gas desulfurization (FGD) system:
Congestion between stack and plant x Yes No
Congestion between stack and/or plant
with property line, coal pile, etc. Yes No
Identify problem areas and location: Generation yard is
directly behind stacks.
Terrain Open site for placing auxiliary systems.
Conduits Conduits are on the opposite side of the boilers from
the stack.
Possible obstructions Although stacks are on the ground, the
transmission yard will cause long ducts to open areas at each end
of the building.
Source of CaCC>3 available Martin-Marietta
and % purity 95
5-3
-------
be used in preference to design data; use of both can lead
to erroneous results.
5.2 RETROFIT INFORMATION
Application of FGD systems to existing plants usually
entails higher costs than those for application to similar
new plants. Whereas an FGD system for a new plant can be
incorporated into the overall plant design, retrofitting
requires that the system be adapted to the given plant
configurations; space is usually limited, and ongoing plant
operations further constrain installation of the system.
Configuration of equipment in the plant governs the
location of the FGD system. For instance, if the boiler
stack is on the roof of the boiler house, as it is in
many older plants, the FGD system may have to be placed at
ground level; this placement could entail long ducting runs
from the absorber to the stack or could require construction
of a new stack. At some plants the stack is situated
directly adjacent to the boiler house or particulate control
device, a placement that often necessitates locating the FGD
system at some distance, even hundreds of feet away. At
some plants, especially those located in urban areas, the
available space at ground level is inadequate to accommodate
the entire FGD system. In such cases either the FGD scrub-
ber units must be stacked, one on top of the other, or
5-4
-------
additional land must be acquired adjacent to the plant
property.
Terrain of the power plant site also affects the capi-
tal cost of the FGD system by sitework and structural re-
quirements. Hilly terrain requires considerable grading and
filling to prepare the site for construction of foundations
and possible additional structural components. Subsurface
conditons can necessitate piling to provide adequate support
for the concrete foundations of the FGD system.
Other capital cost components that can be increased
because of space restrictions are construction labor and '
expenses, interest charges during construction (because of
longer construction periods), contractor fees and expenses,
and allowances for shakedown. Table 5-2 summarizes the
capital cost impacts of several retrofit requirements.
Table 5-2. TYPICAL INCREASED IN CAPITAL COSTS WITH
VARIOUS RETROFIT REQUIREMENTS
Retrofit requirements
Long duct runs
Tight space
Delayed construction (1 year delay)
Hilly terrain
New stack
Overall
Capital costa
increase, %
4-7
1-18
5-15
0-10
6-20
1-70
5-5
-------
The cost manuals account for retrofit difficulty in the
following areas:
1. Conveyors
2. Ducting
3. Overall labor and material factors.
To increase conveyor and ducting, the user estimates the
length of ducting and conveyors to the nearest 100 feet.
The cost manual uses actual distances in the calculation of
ducting and conveyor costs. The overall labor and material
factors adjust the costs for easy, moderate, and difficult
retrofits. In general, an easy retrofit entails ample space
around the stack and open areas for the auxiliary processes
(limestone preparation, sludge processing). In moderate
retrofit, either the conduits or transmission yard block
access to the stacks, stacks are roof-mounted, or areas for
auxiliary processes are limited. In a difficult retrofit,
areas for the auxiliary processes are limited and access to
the stacks is limited or stacks are roof-mounted.
5.3 UPDATING COST ESTIMATES
The manuals are based on December 1973 cost data.
Since that time, costs have escalated greatly. Figure 5-1
shows a cost escalation curve. In updating the cost esti-
mates the equipment costs derived from the manual are
multiplied by a factor from the cost escalation curve. For
5-6
-------
2.2
Ul
I
0.8
1969
1971
1973 1975 1977
YEAR ENDING
1979
1981
1983
1985
Figure 5-1. Cost escalation curve.
-------
example, the factor for use in December 1970 would be 1.30.
The curve is based on data from Chemical Engineering's
(C.E.) equipment cost index. The December 1973 index was
adjusted to equal 1.0. The escalation curve in the manual
can be updated by use of the C.E. index.
Installation of an FGD system from initial design
through construction and subsequent acceptance tests re-
quires approximately 3 years. Price escalation during this
period directly affects the total capital cost of the
project; consequently, cost estimates must account for some
percentage of increase in costs. Since progress occurs at
different rates throughout the life of the project, so too
does the outlay of expenditures. Figure 5-2 illustrates the
effect of escalation on capital cost by showing the percent
increase of capital cost for a range of escalation rates
over a 3-year construction period. The expenditures rate
assumes 14 percent of the total installed cost expended at
the end of 14 months, 24 percent at the end of 20 months,
and 100 percent at the end of 3 years.
5.4 COST ESTIMATION MANUALS
Cost estimation manuals for the lime, limestone,
Wellman-Lord, magnesium oxide, and double alkali systems are
presented in Appendices A through E.
5-8
-------
50
45 -
40 —
s
•n 35
30 —
o
o
uu
a.
25 —
20 —
15 —
10 —
5 —
0
I ' I
3 YEARS
(START TO COMPLETION)
i i i i I i i i i 1 i i i i
5 10 15
ANNUALIZED COST ESCALATION RATE, %
20
Figure 5-2. Impact of cost escalation.
5-9
-------
The simplified estimation procedures are given in
Appendix F. These simplified procedures require the same
input data as the full-scale estimation manuals. Although
the capital costs estimated by the simplified procedures
will correlate with those developed from the full manuals,
the degree of detail is greatly reduced and the estimates
cannot be fine-tuned to site-specific conditions.
5-10
-------
APPENDIX A
LIME SCRUBBING
NOTE: For purposes of clarity and continuity, Tables and
Charts have been numbered sequentially in this
report with no differentiation between Tables and
Charts.
LIME SCRUBBING A-l
-------
INFORMATION REQUIRED
Boiler No-
Type of furnace
MW at maximum continuous
Age of unit, years
Life, years remaining
Capacity factor, yr.
Maximum continuous fuel,
ton/hr or gal/min
Maximum continuous,
MM BTU/hr
acfm at °F
Fly ash/total ash, %
Efficiency of existing
particulate control, %
Cost of electricity/KW (Plant) = $
Coal, cost/ton $
% sulfur by weight
% ash by weight
HHV, BTU/lb
Oil, cost/bbl
% sulfur by weight
BTU/gal
Specific gravity
SO- permissible
Fly ash permissible
_. Cost of water/M gal
(Plant) = $
Ib S00/MM BTU _. .
2' State or
Ib fly ash/MM BTU Fe<*eral regulations
LIME SCRUBBING
A-2
-------
INFORMATION REQUIRED (continued)
Estimated land cost per acre (current) $
Possible interference determining the location
of flue gas desulferization (FGD) system:
Congestion between stack and plant Q Yes Q No
Congestion between stack and/or olant with Q Yes Q No
property line, coal pile, etc.,
Identify problem areas and location:
Terrain.
Conduits.
Possible obstructions.
Source of' CaO available.
and % purity .
LIME SCRUBBING A~3
-------
SO2 EMISSION DETERMINATION
To determine the SO2 emissions (Ib/MM BTU) in the flue gas, Chart 1:
Enter % sulfur by weight of fuel (oil or coal) on|T]
Enter heating value of fuel (BTU/lb)'on (~2~|
Connect
1 and 2 and extend to 3 and record and read:
SO
2 emissions (Ib/MM BTU) in flue gas
u.
10
1
=3
z:
to
§
in
UJ
24,
;
22
20
18
16
H
12
10
i
8:
ei
4:
^
0=
UJ
•z.
FERENCE
UJ
O£
^rf— — — ;
n
24^
- 22;
20i
lei
T4:
12:
10
8
6
4
2
0;
n
3
ZS
CQ
to
0
H- 1
co
. z:
UJ
Chart 1. S02 EMISSION DETERMINATION
Assumptions:
(1) 95% of sulfur in coal converted to S02
(2) 100% of sulfur in oil converted to S02
LIME SCRUBBING
A-4
-------
S02 REMOVAL REQUIREMENTS
To calculate SO2 emissions (Ib/MM BTU) to be removed:
Enter from page A-4, Chart 1, item 3 the Ib/MM BTU
Enter from the data sheet, allowable S02 emissions
(Ib/MM BTU) from the State or Federal regulations
Subtract
from
to calculate S02 emissions
(Ib/MM BTU) to be removed
LIME SCRUBBING
A-5
-------
LIME REQUIREMENTS
To determine the lime requirements (Ib/hr) Chart 2:
Enter the SO2 emissions (_lb/MM BTU) to be removed on item [IF
from page A-5, item [
record
Enter stoichiometric requirements of lime on item
Connect
and
and extend to
and read and record:
Lime requirements (Ib/MM BTU)
Record from the data sheets the heat input (MM BTU/hr)
Multiply
8 times
9 and record:
Lime requirements (Ib/hr)
Multiply
by
and record:
Ib SO_/ hr removed
12
If unknown, use 1.1.
LIME SCRUBBING
A-6
-------
0-r-
1--
03
3--
Q
LU
2 4-
C£.
LU
CO
CO
o
CO
•s. ::
CM
O
co
8-r
Q— 1
10-£
"61
40-1-
36--
32--
28--
24--
- - CQ
THEORETICAL 20
LIME
REQUIREMENT
8
4
3
2
1
o
-------
FLY ASH EMISSION RATE CALCULATIONS FOR VENTURI DETERMINATION
To calculate fly ash emitted:
If the fly ash emitted (Ib/MM BTU) in 13J after passing through
an existing particulate emission collector per boiler is
greater than the allowable rate from the data sheet, the use
of venturi is necessary. Use the following equation to
calculate
(% ash in coal) (% fly ash*) (1-n )_* BTU/lb x 10 = Ib/MM BTU
100 100 _£_
100
= (0. ) (0. ) (1-0. )T x 10 = Ib/MM BTU
where
= Efficiency of particulate emission collector system
c
BTU/lb = Heat value of fuel (MM BTU/lb)
% ash = from the data sheet
If fly ash removal is required for any or all of the units,
VENTURI COST CALCULATIONS will be used.
*If the percent of fly ash to ash is not known, use the
appropriate tabulated values for the boiler under consideration.
Type boiler - coal-fired fly ash to ash, %
General pulverized 80
Dry bottom 85
Wet bottom 65
Cyclone 10
LIME SCRUBBING A-8
-------
SLUDGE GENERATED
To determine the dry sludge (Ib/hr) generated, item 16 , Chart 3:
From page A-8, item 13
(Ib/MM BTU)
enter the calculation of fly ash
From page A-5, item(_5Jenter Ib SO2/MM BTU
From page A- 7, Chart 2 item 8 enter Ib CaO/MM BTU
8 =
total dry sludge (Ib/MM BTU)
From data sheet, heat input maximum continuous rating, record
here as (MM BTU/hr)
13
5
14
Dry Sludge =
x
x
15
16
Ib/hr
_lb/hr
16] * 2000 =.
. ton/hr
Wet sludge - Enter
on
17 , Chart 3 and divide by percent
weight dry sludge on \L8\ = Sludge slurry, • Ib/hr
H
* 0.6* =
Ib/hr
m
*If other than 60 percent by weight is used in determining
wet sludge identify . %
% by weight dry
Enter [le] on \1T\., Chart 3, enter.
sludge on [18
Connect
and [18) and extend to (l9| and read:
Wet Sludge (Ib/hr) =
19
LIME SCRUBBING
A-9
-------
•==•4000
Chart 3. SLUDGE GENERATED
LIME SCRUBBING
A-10
-------
VENTURI AND ABSORBER COSTS
To determine the costs of venturi and absorber (including demister)
using lime, Chart 4;
First, determine number of scrubber trains -
Enter acfm at °F of flue gas from the data sheet on [Jo) , either
per boiler or combined plant total if °F is the same for all
boilers.
Enter temperature of flue gas (°F) on [21
Connect [i2C)| and [iT] and extend to
at 125°C (saturated) and enter
and read flue gas acfm
acfra at 125°F and sat. [22
If acfm at 125°F is greater than 375,000 divide [22J by a number less
than 375,000 to give a whole number of Venturis and/or absorbers for
each boiler.
acfm per venturi and/or absorber
(22| =
24| number of Venturis
and/or absorbers per
boiler or power plant.
23
A venturi, or an absorber, or a combination of a venturi and absorber
is sometimes called a train.
LIME SCRUBBING
A-ll
-------
10-T-
9--
8--
6— •*
o
o
X
3--
O-l-
5--
4--
NOTE:
IF FLUE GAS FLOW IS
450,000 acfm AT 300°F
ENTER 450,000 AS 4.5 x 105
ON [20| , ENTER 300°F ON
_ EXTEND ENTRIES TO \22
AND READ 3.75 x 1Q5 OR
375,000 acfm AT 125°F
AND SATURATED
--3
::
--5
CM
4J
03
--6
03
O
X
>-
--7
--8
--9
-1-10
Chart 4. acfm CORRECTED TO 125 °F AND SATURATED
LIME SCRUBBING
A-12
-------
VENTURI AND ABSORBER COSTS
Then determine absorber costs (no venturi required) Chart 5;
Enter item
from page A-12, Chart 4 on Chart 5
on
Enter for the absorber the cost factor of 1.3 on
26
Connect
cost
and
and extend to
27 and read absorber
Or determine venturi and absorber costs (if a venturi is required)
Enter item
from page A-12, Chart 4 on Chart 5 on 25
Enter the cost factor of 2.2 on
Connect
and
and extend to 27
and read venturi
and absorber costs $
Or determine venturi costs (no absorber):
Now enter item
22] from page A-12, Chart 4 on Chart 5 on
Enter the venturi cost factor of 0.9 on
Connect
costs
and
and extend to
and read venturi
V+A
25
26
27
V
LIME SCRUBBING
A-13
-------
0-r-
o
z:
-
2- —
6--
•> ;_
ABSORBER AND VENTURI
VENTURI ONLY-
SEE CHART 4 FOR
EXPLANATORY NOTE
Chart 5. SCRUBBER COSTS
LIME SCRUBBING
A-14
-------
HOLDING TANK CAPACITY
To determine the holding tank capacity for absorber and/or venturi
Chart 6:
Enter flue gas acfm from page A-12, Chart 4, item
on Chart 6,
item
Enter L/G (liquid flow rate, gpm/1000 acfm at 125°F) on
301
Connect
and
30 and extend to 31
Liquid flow rate (gal/min)
Liquid flow rate (gal/min)
, read and record:
for absorber
31
V
for venturi
Enter retention time
**
on
32
Connect
and
and extend to
, read and record:
Tank capacity (gal) per absorber
(gal) per venturi
33
V
* If unknown, use 40 for absorber and venturi.
** If unknown, use 5 min.
LIME SCRUBBING
A-15
-------
i x io!_
Q
OO
O
^-1x105
LO
CM
o
5^
z
-------
HOLDING TANK AGITATOR COSTS
To determine the cost of agitators per tank, Table 7:
Compare tank capacity (gallons) from page A-16, Chart 6,
item
and /or
*»
V
on Table 7 under tank capacity in
gallons column and record:
Cost of agitators per tank - absorber $
venturi $
Total cost of venturi and/or absorber:
( (si . +
V
) x No. of venturi or
absorbers from item
) x
134
= $
35
LIME SCRUBBING
A-17
-------
AGITATOR COST
Table 7. AGITATOR COST
Tank capacity, gal.
0 to 34,000
34,000 to 67,000
67,000 to 101,000
101,000 to 135,000
135,000 to 162,000
162,000 to 188,000
188,000 to 220,000
220,000 to 251,000
251,000 to 283,000
Acritators
No.
1
2
3
4
5
6
7
8
9
|34 or 34 , cost, $
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
LIME SCRUBBING
A-18
-------
HOLDING TANK COSTS
To determine the tank cost the values in the chart are based on
2
using $12.50/ft for a field-fabricated, rubber-lined tank, Chart 8:
Enter tank capacity (gallons) on |36| from page A-16, Chart 6.
items [33] A and |33| v, move vertically to [37
From [3_7| move horizontally to [38[ , read and record:
Tank cost per absorber $___
38
Cost per venturi $_
38
V
Total Cost:
t 38
[38] v )x No. of absorbers |24j = cost of holding tanks [3J
)x = $ [39
LIME SCRUBBING
A-19
-------
I I I I |ll I I I I I I I Ml l|l|l| I I i lliil|l | i | l|l|l|l|'l I I ' I |IMI| I
I I I I I I I I I I I I I I I I I
i i i i hull i 111 ill
i x 10
1 x TO3
TANK CAPACITY, gal.
Chart 8. HOLDING TANK COSTS
LIME SCRUBBERS
A-20
-------
HOLDING TANK PUMP COSTS
To determine the total pump cost for absorbers and/or venturi, Chart 9:
Enter gpm on [40] from page A-16, Chart 6, item |Ji] for the
absorber and [31| for the venturi. Select minimum number of
pumps on |41| (note 10,000 gpm per pump*is maximum), use minimum
number of pumps per train and add 1 spare pump per tank.
Connect |40| and [41] and extend to |42| , read and record:
Flow rate (gpm) per pump absorber; venturi
gpm/pump
24]
No. of trains
Tabulate: No. of pumps
Absorber
Venturi :
For total pump cost for venturi and/or absorber connect |42|
and enter
on
Pump cost per tank $
43| and extend to [44] , read and record:
ven tur i
44
absorber; $.
V
for venturi
*If gpm per pump is 5,000 or less calculate cost as follows:
Record gpm from page A-16, Chart 6, item J31J ft for absorber
item
Number of trains from page A-ll, item 24
Number of pumps per tank 1+1 spare
Absorber pump costs:
) x (0.79) x
v
2 x (
1.58 x (.
El
47
46J
LIME SCRUBBING
A-21
-------
HOLDING TANK PUMP COSTS (Continued).
Venturi pump costs:
2 x ( 46 ) x (0.92) x
1.84 x (.
= $
Pump costs, total: from calculation (1 to 5,000 gpm/pump)
U~-J ^
_ + = $
V
V
Pump costs, total: from Chart 9
+
44
V
(5001 to 10,000 gpm/purap)
= $.
LIME SCRUBBING
A-22
-------
40,000-r-
36.000- -
32,000
ZB.ooo: :
E
D.
OV
24.000- -
O
20,000- -
16,000- -
12,000
8000-
5000-
0-i.
-T-0
-1000
-2000
-3000
-4000
5000
-6000
7000,
/
- -8000
9000
-1- 0,000
42"
4 PUMPS
3/PUMPsH
2 PUMPS \
1 PUMPV
/
/
44
>k
^^ '
LU
O
LU :
01 . '-
il :
* 1
:
i
~
•M
V
44
T-65.000
r60,000
=•55.000
^50,000
:45.000
-40,000 :
••
j-35,000 :
r-30,000 :
r25,000 ^
20.000 ;
:
15,000 -
10,000 7
5000 :
-
0 -
4^
T-60.000
-55,000
^50.000
:45,000
j-40.000
;35,000
:30,000
25,000
20,000
15,000
10,000
5000
0
L
Chart 9. HOLDING TANK VARIABLE PUMP COSTS
LIME SCRUBBING
A-23
-------
FAN COSTS
To determine fan costs, Chart 10:
Enter acfm at °F of flue gas from the data sheet on 50
Select appropriate curve for pressure drop on 51
Move vertically from [50] to |51| and then from [51] horizontally to
52| read and record:
Fan costs $
52
*Typical pressure drops: Absorber 21" (18" + 3"); Absorber and
venturi 28" (25" +3")
LIME SCRUBBING
A-24
-------
IT"
H
3
M
w
O
w
w
H
21
Q
I
to
Ul
XIOa acfm AT°F
Chart 10. FAN COSTS
-------
HEAT EXCHANGER COST
To determine heat exchanger cost, Chart 11;
Enter item
from page A-12, Chart 4 on Chart 11, item
Move vertically upward to item
for AT
From |54[ move horizontally to the left to |55j , read and record:
Cost for heat exchangers $
55
If unknown, use 50°.
LIME SCRUBBING
A-26
-------
M I I IIII llliliiiiiiH |i|i|im
I i III i hi i i i i In i . hull hull i hhlilil i i i i hill hlllllllill 11
1 X 1Q3 I I I Illli
1 x 104
1 x 105 1 x 106
acfm AT 125 °F
Chart 11. HEAT EXCHANGER COSTS
LIME SCRUBBING
A-27
-------
SOOT BLOWER COST
To determine soot blower cost, Chart 12;
Enter item [23) from page A-ll, Chart 12, item
56
Move vertically upward to [57
From |57| move horizontally to the left to |58| and read:
Cost per train
- $_
Record from page A-12r chart 4,item |24
58]
., number of trains
Cost of soot blowers:
58] x
$ x
24
.= $
LIME SCRUBBING
A-28
-------
70,000
60,000
: sal
„ 50,000
a:
UJ
Q_
g
o
_i
CO
o
o
to
40,000
o 30,000
o
o
20,000-
10,000
"I I i i i i i i i i | i i i i i i i i i
2500 fpm GAS VELOCITY
i 1 i i i
J_
TOO,000 200,000 300,000 400,000 500,000
acfm AT 125°F AND SATURATED [55"
Chart 12. SOOT BLOWER COSTS
LIME SCRUBBING
A-29
-------
REHEAT COST
To calculate the cost of reheat, Chart 13;
Enter acfm at 125°F and saturated of the flue gas from page A-12
Chart 4, item (22| on Chart 13, item [60J
Select and enter AT of 50°F of reheat on item |61| , or AT used
Connect items |60| and |6l| and extend to item [62
Enter costs ($/MM BTU) reheat from calculation below on
item [63
Connect items |62| and [63] and extend to item [64] , read and
record:
Cost ($/hr) reheat
64
Annual reheat cost:
Weighted capacity
factor from data
sheet,
.x 8760 hr/yr x 0._
= $
= reheat cost/yr |65
65
*Reheat Cost -
Coal: To correct from 12,000 BTU/lb and $10/ton
=665 x ($/ton)
BTU/lb.
= $.
./MM BTU
Oil: To correct from 149,000 BTU/gal. and $10/bbl
=31,707 x ($/bbl)
BTU/1h= $—
/MM BTU
LIME SCRUBBING
A-30
-------
acfm AT 125 °F DRY AND SATURATED
H
w
O
§
w
w
H
3
O
X
o
Sj r< I I I | I I H|lHlMhHl|l|l|iri I I I I I I ll|lll||llll| I |l|l|l|l
2 ^ + 4
• -"
ft
1
M
U)
*
REHEAT MM B
tr) ro 1 ' 1 ' 1 ' 1 ' 1 ' ' .' ' ' 1 1 1 1 I 1 1 | 1 1 t"l — III til 1 lllmttTrrrrritTtTT
— ' «O O3 «J A Ul * U rsj — * tr> ns -L A. < n L til /
g I§s§i§l § 1 oosssso s/
- -4-
5S
-S
fU/hr
v| 1 1 — 1 — 1 — rnrp 1 1 1 1 jllll Ml M | M 1 r }~l — j — I — r J
M r^M300 ~-i ui •**tnai
i/i i inn"
*>
o _ _
o o o ooo
O O o OOO
o o goo o
REHEAT COST, $/hr
-------
DUCT COSTS
To calculate ducting cost:
Assumption-
The length of flue duct from the main discharge duct to the
venturi (if used) is variable in feet and also the return to
the main discharge duct after SO2 and/or particulate removal.
For the specific boiler if more than 1 venturi and/or absorber
is required use the multipliers listed in Table 14. Compute each
boiler separately, unless identical to each other in absorber or
venturi acfm at 125°F and saturated.
From data sheet,
acfm at °F
2 2
Area duct (from main) in; = ft = 2A
3,500 ft/min
2 2
Perimeter length: X = = ft
•y-
ft2 = ft
6A = 6x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.39/lb =
7.02 x ft perimeter = $ cost/linear ft
Page A-ll, Chart 4,
item [22|
2 2
Area duct (to main) out: '~' ft = 2X
2,500 ft/min
Perimeter length: ^ _ \ f.2
~v—" "
6A = 6 x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.445/lb =
8.01 x ft perimeter = $ cost/linear ft {67
LIME SCRUBBING A-32
-------
DUCT COST
Table 14. MULTIPLIER FOR DUCT COST
No. of absorbers
and/or Venturis
per boiler
1
2
3
4
5
6
7
8
9
10
Venturi and
absorber
in
110
190
250
305
356
410
453
490
535
579
. .. — — -
Venturi or
absorber only
in
70
114
180
225
266
310
346
378
415
452
— — __ — —
Venturi plus
absorber
out
70
113
143
175
205
235
262
288
315
343
Venturi or
absorber only
out
50
93
123
155
183
208
242
268
295
324
Duct cost in -
(in) cost/
linear ft
x
Table 14
multiplier
Estimated ft to\
main duct*-30'
-30'
= Duct cost (in)
.) =
Duct cost out -
Estimated
distance to
67]
(out) cost/ Table 14
linear ft x ^multiplier main duct**-5Q'l
-50x'
Duct cost (out)(69J
.x (
Total duct cost -
~68\ duct cost (in) + |69| duct cost (out)
$ _+ $—
70 total duct cost
.= $
* If congested area add 230 ft for estimated ft.
** If congested area add 200 ft for estimated ft.
LIME SCRUBBING
A-33
-------
LIME PREPARATION.AREA COSTS
To calculate conveyor cost, Chart 15;
Step 1: Estimate distance (ft) from storage silo area to sites and record
(ft) [7^0] from storage silo area to silos (day bins)
Step 2: Record from page A-6, item
10
Ib/hr CaO *• 2,000 =
_lb/hr CaO
_ton/hr CaQ
Enter ton/hr Chart 15 at |7l| and move vertically upward
to |72| then move horizontally to the left
to
73 and record $.
.conveyor cost |73
If 70[ is greater or less than 600 ft.
Enter ton/hr at |7l| and move vertically upward
to |74| and then move horizontally to the left
to [73| and record $. conveyor cost/100 ft
Number of 100 ft lengths that |70| is greater or less than
600 ft |75| n Ce»tiir«ted by ther observer)
± C III
± ( 1
) = $ adjusted cost [76]
.) = $_± [76]
Conveyor cost:
[73l „
.= $
.conveyor cost [77]
Assumptions:
Cost of the conveyor system installed: 2-inground hoppers, 2-15°
incl. conveyors
(conveyor at 50' elev., conveyor covered , 2 trippers.)
Conveyor lengths: 2-300' inclined, 1-600' to silos, walkways.
LIME SCRUBBING
A-
-------
f
H
CO
n
§
DO
W
H
a
ADD OR DEDUCT/1001
O
n
rt
n
o
o
o
en
^3
cn
9500 O 10,500 11,500 12,500 13,500 14,500
|l I M I I I I l|l I I I I I I I I H I I I I | I I I[I I I I I I I I I |l I I I I I I I I |
240,000
CO
en
I I I I I I I I I I | I I I I I I I I I
| I I I I I I I I I 1 I I I I I | I I I || I | I I I I I I | I I I I I I I I I | I I I I I I I I
TOTAL COST, $
-------
FLUE GAS SHUTOFF AND BYPASS VALVES
To calculate flue gas shutoff and bypass valve costs:
Assumption-
Based on 4 vanes/axis in short dimension based on height of 20 ft
and width of 10 ft..
Stainless steel at $141.6/ft ; carbon steel at $99.I/ft2 ; fabricated
Flue gas valve (in) at main duct to create a bypass
From the data
sheet acfm at /
°F /Boiler = ft2
3,500
W = 2 ft-' w x 2 = * 2 = height, ft, H.
Valve cost A = (1.5 x H) I(99.1)±* (3.1) (H-20) (0.5H-10)]
*H greater than 20 ft, sign is +, less than 20 ft sign is ~
H H • H
= (1.5 x ) [(99.1)i (3.1) ( -20) (0.5 -10)]
= $ carbon steel 78
Flue gas valve (out) at main duct to create a bypass
Page A-12, chart 4,
item
22
acfm
Boiler =-27500 = ft2
-ft2; W x 2 = x 2 = ft (height H)
(H) ^ (HI OU
Valve cost B = (1.5 x ) [(141. 6)± (4.5) ( -20) (0.5 .-10)]
.stainless steel '79
Flue gas valve (in) to absorber and/or venturi train
Page A-12, chart 4,
item J22J acfm at /
toiler = Area,ft
(124 No. of Venturis or absorbers) x 3,500
LIME SCRUBBING A-36
-------
FLUE GAS SHUTOFF AND BYPASS VALVES (continued)
.x 3,500
_= Area, ft2 = 2W2
W
; W x 2 =.
x 2
_ft, height (H)
Valve cost C
= (Height (H) * 0.5 Height (H) [(99.1)- (3.1) (H-20) (0.5H-10)]
".(H) _ (H) (H)
= U.5 x ) [(99.1)-(3.1) ( -20) (0.5 -10)]
carbon steel
Valve cost D = ' _
Page A-ll, item" 24 \
No. of Venturis and/or absorbers/ x (valve costp 80|) = [81
L
.) x (.
-) = 5.
Flue gas valve (out) from absorber and/or venturi
Page A-12, Chart 4, item 2:
1.08 acfm at 175°F
2,500
\22
0.000432 x
. 2
•ft2; W x 2,
Venturi and/or absorber = ff
ft2 = 2W2
x 2 = ft, (H)
Valve cost
J
-:
= (1.5
J(H) Iff)
) [(141.6)-(4.5) ( _ -20) (0.5 _ -10)]
= $ _ stainless steel [52
Valve costp =
Page A-ll, item 24
o
= (
No. of Venturis and/or absorbers/ x (valve costE [82J ) -
) x ( ) = $
83]
Valving cost per boiler
Valve cost^ =
78
83i
V
A
V
B
D
total valve cost
LIME SCRUBBING
A-37
-------
LIME OPERATING AND STORAGE SILO COSTS
To calculate costs of silos for operating 3 day and 12 day storage
of lime, Chart 16:
Enter item \ 7I\ * from page A-35, Chart 15 on Chart 16, item 85
then move vertically upward to item [86
then move horizontally left to item [87 and read:
Cost for silos for operating 3 days $
87
Storage silo cost is based on storage capacities indicated:
Enter item [7l] from page A-35, Chart 15 on Chart 16, item
85
then move vertically upward to item |88
then move horizontally left to item |87| and read:
Cost of 12 days storage silo $
87
B
Fixation silo cost -
A
1/3 x item |87
.33 x
= $ cost
= $
89
Lime cost for start-up, 12 day storage plus 3 days operating -
/Item |71|
I from I x $25./ton x 24 hours/day x 15 days = $ costs [90]
\Chart 15
_)x 9000 = $
to correct 90 for current costs:
x $/ton current cost CaO
25
= $ corrected costs 90
25
90|
Lime costs 90
LIME SCRUBBING
A-38
-------
LIME OPERATING AND STORAGE SILO COSTS (Continued)
* If tonnage usage is under 4.7 tons/hour of CaO use the table below
for storage silo costs -
tons /hr |7l| = $_
Ib/hr
0 - 500
501 - 2,000
2001 - 5,000
5001 - 9,400
No. of
silos
1
1
2
3
cost/
ancilliary
equipment
87 *
.. ... A + R
9,000
15,000
36,000
65,000
87
A + B
LIME SCRUBBING
A-39
-------
1 x 10' ..
1 x 106 .
oo
o
1x10°-
10
20 30 40 50 60 70 80 90 100 110 120 130 140
CaO, ton/hr
85
Chart 16. LIME OPERATING AND STORAGE SILO COSTS
LIME SCRUBBING
A-40
-------
SLURRY TANKS, MIXERS AND PUMPS COST
To calculate slurry tank costs, Charts 17, 18 and 19
Enter from page A-35, item [7^ Chart 15 on Chart 17 on item 15:
then connect item [¥T] with 15%* on item [92] , extend to item [93
read and record:
slurry storage gallons..
Select number of tanks required:
Maximum storage capacity per tank 600,000 gallons if [93} is
93
greater than 600,000 gallons,divide [9~3] by a number up to 600,000
to get an even number of tanks
94
If storage capacity is less than 34,170 gal.:
Enter item 93 on Chart 18, item 95 , move vertically upward
to item |96[ , then move horizontally left to item |97| , read
and record:
Total cost of slurry storage tank $
-Hz
If storage capacity is between 34,170-600,000 gal.:
Enter item (93J on Chart 19, item [98] , move vertically upward
to item [9~9] , then move horizontally left to item |100] , read
and record:
Total cost of slurry storage tank $
100
If storage capacity is over 600,000 gal.:
Divide [93] by [94] , record gallons per tank
*If slurry percentage other than 15%, use available value.
LIME SCRUBBING
A-41
-------
SLURRY TANKS, MIXERS AND PUMPS COST (Continued)
Enter item |101] on Chart 19, item 98J , move vertically upward
to item |99| , then move horizontally to item |100| , read and
record cost of each tank.
Cost of each slurry tank $_
jiooj
Total cost of slurry storage tanks
= cost/tank |100| x No. of tanks [94
= x .
= $
102|
Mixer cost
From Chart 17, item |93| ** note the storage capacity required,
then select proper range from Table 20, under tank capacity, gal.
item |103| (if |93| is less than 600,000 gal.J
No. of mixers.
Total mixer costs $
105
** if item \93\ is greater than 600,000 gallons then enter item |lOl|
on item
103] to determine number of mixers required -
T.otal mixer cost =105
No. of mixers/tank.
Mixer cost/tank.
No. of tanks_
x
105
94 = $ 106
1061
LIME SCRUBBING
A-42
-------
SLURRY TANKS, MIXERS AND PUMPS COST (Continued)
Pump cost
Enter from page A-35, item 71 Chart 15 on Chart 21
on
item 1107| , then connect item [107| with slurry percentage
on item |108| , extend to item |109|
Connect item [109| with 200 ft head on item |110l , extend
to item [llll , read and record:
Pump costs/tank $
Total pump costs = [111
94 = $ [112
= $
112
SCRUBBING COSTS
A-43
-------
150t
120--
100- -
90--
80--
70- :
60--
50
s. 30- •
o
20--
2--
91
1 x 103--,-
1 x 10'
Q.
O
UJ
to
o
>-
cc.
Chart 17. SLURRY TANKS, MIXERS AND PUMPS COST
SCRUBBING COSTS
A-44
-------
SOOO
TANK CAPACITY 12,000-34,170 gal
4200
12,000 14,000 16,000 18,000 20,000 22,000 24,000 26,000 28,000 30,000 32,000 34,170
53,000r CAPACITY, gal
48,001
TANK CAPACITY 34,170-600,000 gal
S 28,000
8000
34,170 100,000
200,000 300,000
CAPACITY,
400,000
500.000 600.000
Charts 18 and 19. SLURRY TANKS, MIXERS AND PUMPS COST
SCRUBBING-CQJWS
A-45
-------
MIXER COSTS
TABLE 20
Item
Tank capac
0 -
40,393 -
80,785 -
121,177 -
161,569 -
201,961 -
242,353 -
282,745 -
323,137 -
363,529 -
403,921 -
444,313 -
484,705 -
525,097 -
565,489 -
103 Item
104| Item 105|
ity, gal. No. of mixers Cost of mixers, $
40,392 1
80,784 2
121,176 3
161,568 4
201,960 5
242,352 6
282,744 7
323,136 8
363,528 9
403,920 10
444,312 11
484,704 12
525,096 13
565,488 14
600,000 15
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
22,000
24,000
26,000
28,000
30,000
LIME SCRUBBING
A-46
-------
CO
o
§
H
3
Q
O
O
to
>
•J
T-70,000
- -60,000
- -50,000
- -40,000
o
O
-30,000
- -20.000
- -10,000
J-o
5000
Chart 21. SLURRY TANKS, MIXERS AND PUMPS COST
-------
COST OF SLAKER AND PUMP
To calculated slaker and pump costs:
Enter from page A-35, item
Chart 15 on Chart
22
on
item |113| , move vertically upward to item |114| , then
move horizontally left to item [115| and read:
Slaker and pump cost $
115
LIME SCRUBBING
A-48
-------
400,000r
36Q.OOOI-
320,0 OOf
Flu*
280, 000 P
E
r '
- 240.000P /
L.l /
i /
5 . t /
"> iso.oooh /
120,000h /
80, 000 P /
40, 000 p /
gPi i i i i i i i i 1 i i i i r I i i i 1 i I i I i I I F I 1 I .i..Ll_l_Lli..
0 20 40 60 80
/
/OH
/
•i
«
«
b
•
«•
UK
•
•
v
*«
«
^M
«l
•1
-
•
.
]
1 11 J_1_I_LJ_1_1_| 1 J 1 1 1 1 1 i i , i il
100 120 14
CaO USAGE, toa/hr
Chart 22. SLAKER AND PUMP
LIME SCRUBBING
A-49
-------
SOLID DISPOSAL
To find the cost of clarifier and vacuum filtration equipment and
pump combined, Chart 23t
Chart 23 gives the cost of the following system
Clarifier 150 ft diameter
Overflow pump head, 250 ft
Under flow pump head, 250 ft
Filtrate-return pump head, 350 ft
Sludge pump head 1000 ft
Under flow emergency pump
Vacuum filter, 50 ton/hr
Sludge mix tank and mixer
Water make-up pump
Enter item |16| (dry sludge, ton/hr) , from page. A-9 on item 116
Select number of clarifier units, same size (each 50 ton/hr of dry
sludge requires 1 clarifier unit) =_
units
From item [llgj move vertically upward to item |l28J ( Bhp system
curve) , then continue upward to item
(equipment cost curve) .
From item
117J move horizontally to the right to item 11? for hp
of equipment.
hp of equipment x No. of units = total hp required=_
IS! Hill
-hp
121
From item |ll9J move horizontally to the left to item |12Q| for equip-
ment, $ /unit |120J
Item |12Q| x item |117{ = total cost |122|
x = $
122
LIME SCRUBBING
A-50
-------
1X10
10,000
CURVES ARE CLARIFIER
LIMITED (1501 0) AND
VACUUM
FILTER (50 tons/hr)
1X10
0 5 10 15 20 25 30 35 40 45 50
ton/hr SLUDGE DRY FOR CLARIFIER AND V.F.
Chart 23. SOLID DISPOSAL
LIME
A-51
-------
POND ACREAGE AND POND EXCAVATING/DIKING COSTS
To determine the cost of pond acreage, excavating/diking costs,
Chart 24:
Enter from page A-9, item 16] (ton/hr dry sludge) on Chart 24,
item |l23) then move vertically upward to the respective
weighted capacity factor, item 124
From item |124| move horizontally left to item |i.2S| (acre ft/yr)
and reference line l-2€ and read:
Select plant remaining life on item |t2"?|
Connect items 126 and 127| and extend to item L-28' (pond acre ft)
and read:
From item 3.2&J move horizontally left to item tJ2ff| (pond reference
scale)
From item [1-2$ move vertically down to item JL3QJ' (pond cost)
*
and read:_$ [l3Cildry sludge
* If wet sludge, no waste return 1.67 x |12g.
.pond acre-ft wet sludge
Enter item [131} on Chart 24, item P.28SJ and move horizontally left to
item [129
From item [129.J move vertically down to item p.3Qj (pond cost) and read:
$ , [I3.Z| wet sludge
Select proper item
£321 and record as pond cost, $_
LIME SCRUBBING
A-52
-------
t-l
H
CO
O
to
ta
H
U1
U>
i i i i i t
i.i it
. i.i
i i t
-LJJ
.01
.1
5 t ? Bt.l
S t 7 § »!
5 < 7 a »10
i oooc
5 6 > moo
100.000
tons/hr dry llud9f
t rOM) COST
1000
1.000.000
5 t 7 • 9)0.000
10.000.000
Chart 24. POND COST
-------
MOBILE EQUIPMENT
From Richardson's - capacity to move 60 ton/hr lime
from storage pile
Cost $44,000
Requirements: based on ton/hr required
Same unit as above for fixation process capable'of
handling 1,300,000 gal./wk of fixed sludge
LIME SCRUBBING A_54
-------
EQUIPMENT COST - LIME
Equipment
1. Absorber
2. Venturi and Absorber
3. Venturi
4. Absorber and/or Venturi holding
tanks agitators
5. Absorber and/or Venturi
holding tanks
6. Circulation holding tank pumps
7. I.D. Fans
8. Heat Exchangers
9. Soot Blowers
10. Ducting
11. Conveyors
12. By-Pass Valving
13. 3 Day Storage Silos
14. 12 Day Storage Silos
15. Fixation Silo
16. Lime slurry h'old tanks
17. Lime Mixers (hold tank)
18. Lime Pumps (holding tank)
19. Slaker, etc.
20. Solids disposal-clarifier, vacuum
filtration, pumps
21. Mobile Equipment
22. New roadways or RR siding at $50/ft.,
estimated length
Item
Cost $
V+A
£ 84
or 8:
A+B-
B
or
or
Total Equipment Cost
A-55
-------
EQUIPMENT COST
Total costs:
Year of FGD system operation
Select from cost factor index multiplier from chart 25 for the
year above
Predicted costs of equipment
(total costs) x (cost factor index multiplier)
( ) x ( ) = $
Predicted pond cost
= (Pond cost from |130| or [132| )x(cost factor index multiplier)
P
= x
LIME SCRUBBING A-56
-------
en
O
W
bd
I
U1
-J
1971
1973
1975 ' 1977 1979
YEAR ENDING
1981
1983
1985
Chart 25
-------
CAPITAL INVESTMENT COSTS—LIME
Direct costs:
Seled
"A" Me
"B" Lc
"C"
: system required
iterial
ibor
Retrofit
Easy
Moderate
Difficult
1
Absorber
1.646 Aa
0.814 Xa
Absorber & venturi
1.639 Xa
0.822 -Xa
Materials and labor
Absorber
0
0.047Aa
0.093;?
Absorber-venturi
0
0.039Xa
0.077Xa
Cost,$
•—!*«»•
X = Equipment cost, predicted from page A-56
"A" + "B" + "C" = $_
"D" Raw materials: Chart 15, item |7l] page A-34
ton/hr CaO
15 day ,
x storage x $/ton =
x
360
= $_
If unknown use $25/tOn
"E" Pond cost> predicted from page A-56 = $_
"F" Direct costs ("A" + "B" + "C" + !'E") above = $_
"G" Direct costs ("A" to "E" inclusive) = $_
"H" Direct costs ("A" + "B" + "C") above = $
Indirect costs:
"J" Interest (at 8%)f contractor fees and expenses, engineering,
freight, off-sitertaxes, start-up, spares
(0.33 "G") + (0.1 "H") + (0.065 "F") =
(U.33 x ) + (0.1 x ) -f (0.065 x ) = $
"K" Contingency:
0.2 ("j" +" "F") = 0.2 (.
.) = $
"L" Total costs for capital investment
"G" + "J" + "K" = +
= $
Cost/Kilowatt:
L
MW's x 1,000
.x 1,000
,/KW
LIME SCRUBBING
A-58
-------
TOTAL ANNUAL OPERATING COSTS—LIME
Utilities -
Water: Lime; scrubbing
64 gal./MW for 3.0% S coal
-A 5.5 gal./MW for each - 1.0% S .in coal
133]
13 41
52, gal./MW for 3.0% S oil
-A 4 gal./MW for each - 1.0% S in oil
Lime,
(gal./MW - gal./MW corr. for t % si x hr/yr x weighted
capacity fact.x water costs/1000 gal.) = yearly
cost water/MW
(l3|j or |.135j - |134| or [J36
$0.02
.) x 1000 x 8760 x.
$
cap. factor
L37-,
/Coal or
Oil
/Base % S \
; 1% S 'corrJ |137|
(.
x
X
MW
137]
.= $_
Reheat:
From page A-31, Chart 13, item [65] determine $/reheat
(see calculation sheet)
$ __/yr
For AT
LIME SCRUBBING
A-59
-------
TOTAL ANNUAL OPERATING COSTS—LIME
Operating labor cost:
MW's
100- 699
700-1200
1201-2500
2501-
Men/Shift
3,16
3.33
4.50
5.33
Men/shift x hr/yr x $/hr =
x 8760 x 6.50 =
x 56,940 = $_
,/yr
Corrected cost: |138,' xf$/hr (manpower )\= $ /yr
\ 6.50 /
Supervision:
0.15 x 56,940 x men/shift =
8541 x ' $,
Corrected cost: 133 x .15 = $._
—— \^
Maintenance:
Capital costs, total
0.046 x = $.
,/yr
./yr
_/yr
1381
039
Overhead:
Capital cost, total
(0.023 x
+ Men/shift
.) + (13,100 x ) =
_)+{ )=
= $
./yr
LIME SCRUBBING
A-60
-------
TOTAL ANNUAL OPERATING COSTS—LIME
Fixed costs -
A.
100
Plant life, yrs*''
B Capital = %/yr
%/yr depreciation, straight-line
C. Taxes, insurance/ interim replacement - 4.65%
% /yr fixed costs
Total fixed costs = A -f-^B + C =
( fixed costs,%/yr) x (total capital cost) =
( - %/yr) x(_ _}.= $
/yr
Sludge disposal:
Pumping to another site, off-plant
MW KW/MW ,?/KWH**or*** .hr/yr x weighed CF
0.0011 x x 1000 x x 8760 x =
9.64 x
MW $/KWH** or *** weighed CF
x x = $
,/yr
Truck disposal costs/14 miles:
ton dry sludge/hr $ 8?
8.47 tons dry sludge/truck hr
(57.25 rain/trip) ($17.20/truck hr/driver)
From Chart 3, item [Ti] , tons dry sludge/hr.
weighed CF
x 19,570 x
16
16
-= $_
/yr
* Plant life, years: either remaining boiler life in years from start
of ?GD sySteTor 15 year life for FGD system, use lowest number of
years for life.
** or *** see page A-63
LIME SCRUBBING
A-61
-------
TOTAL ANNUAL OPERATING COST—LIME
Raw materials -
Lime:
Page. A-35 Chart 15, item 71 _
weighed CF x $/tona = cost/yr.
= 8760 x CF
* 8760 x
x $/ton£
x
tdh/hr caO x hr/yr x
x Chart 15, item |7l| =
x = $
145
Fixation
Chart 3, item
page A-10 Ib/hr dry sludge x hr/yr x
weighed CF x $/tonb x 1/2000 Ib ton =
= 4.38 x CF
x
x Chart 3, item |16| = cost per year
x _ = $ _
Utilities:
Electrical, use appropriate
Limer-"burning coal =
MW x
0.022 x
weighed
x $/KWH** x CF x hr/yr - $ cost/yr
or ***
x 1000 x
= 1.93 x 10 x.
MW $/KWH* * CF
or ***
87.60 = $
147
/yr =
'•• ....... • .......... --- • -i
(on coal/abs. + vent.)
147]
= 1.84 x 10 x_
MW $/KWH* * CF
or ***
_= $
(on coal/abs.)
/yr = pl
Lime?—burning fuel oil =
MW
1.314 x 105 x
$/KWH** CF
or ***
x
X
_= $
(on oil/abs.)
/yr =
a or b or
**
**-*
see next page
LIME SCRUBBING
A-62
-------
a If unknown use $25/ton.
b If unknown use $4/ton
** If unknown use 0.00675/KWH based on coal at $10/ton and 12,000
BTU/lb.
y
* ** If unknown use 0.0185/KWH based on oil at $8.40/bbl and 149,000
BTU/gal.
A-63
LIME SCRUBBING
-------
TOTAL ANNUAL OPERATING COSTS - LIME
Summary sheet
Item
Cost, $
1. Ttfater
2. Reheat
3. Operating labor
4. Supervision
5. Maintenance
6. Overhead
7. Fixed costs
8. Sludge disposal, pumping
9. Sludge disposal, trucking
10. Lime
11. Fixation
12. Electrical
A+V
Total annual operating costs
Cost per kilowatt-hour:
(total annual operating cost)
hr/yr x (plant rating in MW's) x 1,000 x (weighed capacity factor)
( ) = $ /KWH
8760 x (
) x 1,000 x (
LIME SCRUBBING
A-64
-------
APPENDIX B
LIMESTONE SCRUBBING
NOTE: For purposes of clarity and continuity, Tables and
Charts have been numbered sequentially in this
report with no differentiation between Tables and
Charts.
LIMESTONE SCRUBBING B-l
-------
INFORMATION REQUIRED
Boiler No.
Type of furnace
MW at maximum continuous
Age of unit , years
Life, years remaining
Capacity factor, yr.
Maximum continuous fuel,
ton/hr or gal./min
Maximum continuous,
MM BTU/hr
acfm at °F
Fly ash/total ash, %
Efficiency of existing
particulate control, %
Cost of electricity/KW (Plant)
Coal, cost/ton $
% sulfur by weight
% ash by weight
HHV, BTU/lb
. COsf of water/M gal. (Plant)
Oil, cost/bbl §
% sulfur by weight
BTU/gal
Specific Gravity
SO- permissible
Fly ash permissible.
Ib S02/MM BTU
Ib fly ash/MM BTU
State or
Federal regulations
LIMESTONE SCRUBBING
B-2
-------
INFORMATION REQUIRED (continued)
Estimated land cost per acre (current) $.
Possible interference determining the location
of flue gas desulferization (FGD) system:
Congestion between stack and plant Q yes Q No
Congestion between stack and/or plant with Q Yes Q No
property line, coal pile, etc.
Identify problem areas and location:
Terrain.
Conduits.
Possible obstructions.
Source of CaCO^ available.
and % purity .
B-3
LIMESTONE SCRUBBING
-------
S02 EMISSION DETERMINATION
To determine the SO2 emissions (Ib/MM BTU) in the flue gas,
Enter % sulfur by weight of fuel (oil or coal) on[T|
Enter heating value of fuel (BTU/lb) on IT]
Chart 1:
Connect 11|and 2 and extend to 3 land record and read:
in
SO- emissions (Ib/MM BTU) in flue gas.
s
i
CO
E
V-4
CO
f
Chart 1. S02 EMISSION DETERMINATION
Assumptions:
(1) 95% of sulfur in coal converted to S02
(2) 100% of sulfur in oil converted to SO2
LIMESTONE SCRUBBING
B-4
-------
SO REMOVAL REQUIREMENTS
To calculate S02 emissions (Ib/MM BTU) to be removed:
Enter from page B- 4, Chart 1, item [Tithe Ib/MM BTU.
Enter from the data sheet, allowable SO- emissions
(Ib/MM BTU) from the State or Federal feegulatioas-
Subtract [4Jfrom [3jto calculate SO~ emissions
(Ib/MM BTU) to be removed
B-5
LIMESTONE SCRUBBING
-------
LIMESTONE REQUIREMENTS
To determine the limestone requirements (Ib/hr) and sulfur dioxide
rate (Ib/hr), Chart 2;
Enter the S00 emissions (Ib/MM BTU) to be removed on item \6\
£*
from pageB-5; item [5] ; record |6|
Enter stoichiometric* requirements for limestone on item JTJ*
Connect
and 7 and extend to \B\ and read and record:
Limestone requirements (Ib/MM BTU)
Record from the data sheets the heat input (MM BTU/hr).
Multiply |_8
by
and record:
Limestone requirements (Ib/hr)
Multiply
9 and record: Ib S00/hr removed
* If unknown/ use 1.3.
LIMESTONE SCRUBBING
B-6
-------
Q
LU
I '
LU
ee it:
LU
CO
40-r-
36--
32--
THEORETICAL
LIMESTONE
REQUIREMENT
24--
20--
.
16- -:-
Chart 2. LIMESTONE REQUIREMENTS
LIMESTONE SCRUBBING
B-7
-------
FLY ASH EMISSION RATE CALCULATIONS -FOR VENTURI DETERMINATION
To calculate fly ash emitted:
If the fly ash emitted (Ib/MM BTU) in |l3| after passing through an
existing particulate emission collector per boiler is greater than
the allowable rate from the data sheet, the use of venturi is
necessary. Use the following equation to calculate [13
|13| = [(% ash in coal*}(% fly ash*) (1-n ) * BTU/lbl x 106 = Ib/MM BTU
TTHJ iuu j^O T J
= [0. ) (0. ) (1-0. )*_____ J * 1(T = Ib/MM BTU
where
n = Efficiency of particulate emission collector system
c
BTU/lb = Heat value of fuel
% ash = from the data sheet
If fly ash removal is required for any or all of the units VEM5URI COST
CALCULATIONS will be used.
*If the percent of fly ash to ash is not known use the appropriate
tabulated values for the boiler under consideration.
Type boiler - coal-fired fly ash to ash, %
General pulverized 80
Dry bottom 85
Wet bottom 65
Cyclone 10
LIMESTONE SCRUBBING B-8
-------
SLUDGE GENERATED
To determine the dry sludge (Ib/hr) generated, item pi , chart 3;
Prom page.
B-8
B-8
_, item |13| enter calculation of fly ash (Ib/MM BTU)
(Dj
[Tl
From page _ , item [5] enter Ib S00/MM BTU
From page_ll2 — , Chart 2 item [J] enter Ib CaC03/MM BTU
13 + 5 + 8
[l4| total dry sludge(lb/MM BTU)
From data sheet, heat input maximum continuous rating, record
here as (MM BTU/hr)
Dry Sludge |14| x [15
= _x
16] Ib/hr
_= Ib/hr
16] T 2000 = ton/hr
_% by weight dry
Enter |16| on |17| , Chart 3, enter
sludge on fis]
Connect [TT] and [l8J and extend to (T9J and read:
Wet Sludge (Ib/hr) =
* If unknown, use 60%.
LIMESTONE SCRUBBING
B-9
-------
4000
Chart 3. SLUDGE GENERATED
LIMESTONE SCRUBBING
B-10
-------
VENTURI AND ABSORBER COSTS
To determine the costs of venturi and absorber (including demister)
using limestone, Chart 4:
First, determine number of scrubber trains -
Enter acfm at °F of flue gas from the data sheet on J20J , either
per boiler or combined plant total if °F is the same for all
boilers.
Enter temperature of flue gas (°F) on [2lj
Connect [2p| and [zH and extend to [22J and read flue gas acfm
at 125°C (saturated) and enter acfm at 125°F and sat. [22]
If acfm at 125°F is greater than 375,000 divide [22J by a number less
than 375,000 to give a whole number of Venturis and/or absorbers for
each boiler.
acfm per venturi and/or absorber
23
[2~2J = |24| number of Venturis
".—- and/or absorbers per
1231 boiler or power plant.
A venturi, or an absorber, or a combination of a venturi and absorber
is sometimes called a train.
Assumptions: Costs are based on -
(a) Venturi throat velocity at 150 ft/sec
(b) Absorber velocity at 10 ft/sec
LIMESTONE SCRUBBING B-ll
-------
-r-0
--2
o
NOTE:
IF FLUE GAS FLOW IS
450,000 acfm AT 300°F .
ENTER 450,000 AS 4.5 x 105
ON 20 , ENTER 300°F ON
21 EXTEND ENTRIES TO 22
AND READ 3.75 x 10$ OR
375,000 acfm AT 125°F
AND SATURATED
•5 o
in
cvi
10
x
>•
--8
•10
Chart 4. acfm CORRECTED TO 125 *P AND SATURATED
LIMESTONE SCRUBBING
-------
VENTURI AND ABSORBER COSTS
Then determine absorber costs (ho venturi required) Chart 5;
Enter item |22| from pages-12, Chart 4 on Chart 5 on~ |ii|
Enter for the absorber the cost factor of 1.65 on [26
Connect |25| and |26| and extend to \2T\ and read absorber cost
27]
Or determine venturi and absorber costs (if a venturi is required) Chart 5
Enter item |22| from page B-12, Chart 4 on Chart 5 on J25J
Enter for the train the cost factor of 2.55 on f26l
Connect |25] and |26J and extend to |27J and read venturi and absorber
costs $
27
V + A
* To correct for velocity differential in absorber-
10
A
fp
correct cost of absorber 2&
Or determine venturi costs (no absorber): Chart 5
Now enter item [J22] from page B-12, Chart" 4 on Chart 5 "on Q
Enter the venturi cost factor of 0.9 on [26]
and read venturi costs
Connect
and
and extend to
27j
LIMESTONE SCRUBBING
B-13
-------
0-T-
o:
CO
Q
z
-
2--
3--
4-1
7--
O— »
9--
ABSORBER AND VENTURI
ABSORBER ONLY
VENTURI ONLY
SEE CHART 4 FOR
EXPLANATORY NOTE
Chart 5. SCRUBBER COSTS
LIMESTONE SCRUBBING
B-14
-------
HOLDING TANK CAPACITY
To determine the holding tank capacity for absorber and/or venturi
Chart 6:
Enter flue gas acfm from pageB-12, Chart 4, Item [23j on Chart 6,
item [2~9J
Enter L/G*( liquid flow rate>rgpra/lGOd^acfra^t 12:5°F) on J3Q]
Connect |29| and |30| and extend to [31| , read and record:
Liquid flow rate (gal,/min)_
|31| _ for absorber
Liquid flow rate (gal./iainj_
Enter retention time on [32]
Select retention time:**
for venturi
Connect JJ and 32 and extend to |33| , read and record:
Tank capacity (gal.) per absorber
(gal.) per venturi
33J
33| v
* If unknown, use L/G = 65 for absorber and L/G - 15 for venturi
** If unknown, use 10 minutes for absorber and 4 mznutes for venturi
LIMESTONE SCRUBBING
B-15
-------
1 x lOi,-
~ -1 x 10*
g
£'
- -1 x 105
Chart 6. FLOW RATE AND TANK CAPACITY
LIMESTONE SCRUBBING
B-16
-------
HOLDING TANK AGITATOR COSTS
To determine the cost of agitators per tank, Table 7;
Compare tank capacity (gallons) from page,B-16^Chart 6, item J33
and/or |33| v on Table 7 under tank capacity in gallons column
and record:
Cost of agitators per tank - absorber $_
venturi
$
31A
[34] „
Total cost of venturi and/or absorber:
(!31A
\ x No. of venturi or
' 14 ^ * •
absorbers from item 24
.= $_
LIMESTONE SCRUBBING
B-17
-------
Table 7. AGITATOR COST
Tank capacity, gal.
0 to 34,000
34,000 to 67,000
67,000 to 101,000
101,000 to 135,000
135,000 to 162,000
162,000 to 188,000
188,000 to 220,000
220,000 to 251,000
251,000 to 283,000
NO.
1
2
3
4
5
6
7
8
9
Agitators
" li*JA°r HUv' cost' ?
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
LIMESTONE SCRUBBING
B-18
-------
HOLDING TANK COSTS
To determine the tank cost the values in the chart are based on
• 2
using $12.50/ft for a field-fabricated, rubber-lined tank, Chart 8:
Enter tank capacity (gallons) on [36] from page B-16,Chart 6,
items [33] ft and (33J v/ move vertically to [3~7
From [37] move horizontally to [38] , read and record:
Tank cost per absorber $_
Cost per venturi $_
38
Total Cost:
C [38]
38
v )x No. of absorbers |24| = cost of holding tanks
)x = $ [39]
LIMESTONE SCRUBBING
B-19
-------
i i i i liiiil I li hlihlilii i i i i Iniil i I i hlililthl i i i i
1 x 1031
1 x 103
1 x 104
TAHK CAPACITY, gal.
1 x 105
Chart 8. HOLDING TANK COSTS
LIMESTONE SCRUBBING
B-20
-------
HOLDING TANK PUMP COSTS
To determine the total pump cost for absorbers and/or venturi, chart 9
Enter gpm on [Ip] from page B-16,Chart 6, item [all for the
absorber and glj for the venturi. Select minimum number of
pumps on
(note 10,000 gpm per pump*is maximum), use minimum
number of pumps .per train and add 1 spare pump .per tank.
Connect [4o| and [4l| and extend to J42J , read and record:
Flow rate (gpm) per pump _ absorber; _ venturi
41
|42|
gpm/pump
[24]
No. of trains
Tabulate: No. of pumps
Absorber
Venturi
For total pump cost for venturi and/or absorber connect [42\
and enter [41] on [43] and extend to [44] , read and record:
. ven tur i
Pump cost per tank $.
absorber; $.
44]
*If gpm per pump is 5,000 or less calculate cost as follows:
Record gpm from page B-l 6 ,Chart 6, item J3J
item [|:
Number of trains from page B-l 1/item [24J
Number of pumps per tank 1+1 spare
Absorber pump costs:
) x (0.79) x .'0
) x
2 x (
1.58 x L
for absorber.
for venturi.
LIMESTONE SCRUBBING
B-21
-------
HOLDING TANK PUMP COSTS (Continued).
Venturi pump costs:
2 x (
) x (0.92) x
1.84 x (.
= $
Pump costs, total: from calculation (1 to 5,000 gpm/pump)
A
_ + = $
v
Pump costs, total: from Chart 9
+ US A-
44
V
(5001 to 10,000 gpm/pump)
= $.
LIMESTONE SCRUBBING
B-22
-------
40,
-T-0
•HO.OM
4 PUMPS
3/PUMPS\
7
2 PUMPS \
••
«l
•
«
•P
«l
UJ ~
0
z :
£ :
£ :
B 1
«•
V
«•
4
•
•V9»VW
• •
• .
•"
- .
- .
^60.000 :
•
=-55.000 :
. •
"
_
„ •
_ *
E-so.ooo ;
n. .
— <•
~
.
=•45.000 :
^ *
•. ™
=•40.000 :
V
r-35,000 :
~
r30.QOO :
— ^
rZB.OOO \
_ -
~ ™
r20.000 :
* *
• q
• -
«•
rlS.OOO j
•
«
-10,000 ~
•*
m
.
» •
^5000 :
„ •
. -
» —
. •
• 4
* A *
•fl •
p40.000
i-55.000
^50.000
j-45.000
j-40.000
•35.000
:30,000
•25.000
-20,000
^15.000
;10.000
^5000
•
»
^0
Chart 9. HOLDING TANK VARIABLE PUMP COSTS
LIMESTONE SCRUBBING
B-23
-------
FAN COSTS
To determine fan costs, Chart 10;
Enter acfm at °F of flue gas from the data sheet on |50]
Select appropriate curve for pressure drop* on |5l|
Move vertically from [50] to |5l) and then from [51] horizontally to
|S2l read and record:
Fan costs $ {52J
* Typical pressure drop: : Absorber 18" ;
absorber and venturi 27"
LIMESTONE SCRUBBING _ _A
B—24
-------
I I I I I I I I | I I I I l i I i i l l M i i i i
10
Chart 10. BOOSTER FAN COSTS
-------
HEAT EXCHANGER COST
To determine heat exchanger cost, Chart lit
Enter item |22| from page B-12,Chart 4, on Chart 11, item |53|
Move vertically upward to AT*
From [54] move horizontally to the left to [is] , read and records
Cost for heat exchangers $ |55|
* If unknown, use AT = 50°F
LIMESTONE SCRUBBING B-26
-------
i|'l'l«l i I I I I I I I I |lil Ifrillf.! |I4J|IJ11 I I I | II I I I PH IM1TIU f' I* l>
acf* AT 125 »F
Chart 11. HEAT EXCHANGER COSTS
LIMESTONE SCRUBBING
B-27
-------
SOOT BLOWER COST
To determine soot blower cost, Chart 12;
Enter item [23] from page. B-ll, on Chart 12, item )56j
Move vertically upward to [57J
From [5?1 move horizontally to the left to [58] and read:
Cost per train . $ [5)3
Record from page B-ll,' , item [Z4J_ , number of trains
Cost of soot blowers:
[58] x [24J
$ x
= $
LIMESTONE SCRUBBING
B-28
-------
60,000
*t 50,000
af
ft.
j£ 40,000
0 30,000
i
20,000
10,000
0
-
-
•
m
m
•
•
»
100,000
2500
....... 1
200,000
fpm GAS VELOCITY
... .1
300,000
'
-
•i "
00,000 500,000
acfm AT 125'F AND SATURATES
Chart 12. SOOT BLOWER COSTS
LIMESTONE SCRUBBING
-------
REHEAT COST
To calculate the cost of reheat, Chart 13;
Enter acfm at 125°F and saturated of the flue gas from page B-12
Chart 4, item [22| on Chart 13, item [60
Select and enter AT*< fell
Connect items [60J and [6ll and extend to item |62] record_
Enter costs ($/MM BTU) reheat**from calculation below, on
item l63l
Connect items [62] and |63| and extend to item [64] , read and
record:
Cost ($/hr) reheat
64
Annual reheat cost:
64
Weighted capacity
factor from data "
sheet = reheat cost/yr
_x 8760 hr/yr x 0._
= $
*If unknown, use AT = 50°F
**Reheat Cost -
Coal: To correct from 12,000 BTU/lb and $10/ton
($/ton)
665 x-
_BTU/lb
= $.
./MM BTU
Oil: To correct from 149,000 BTU/gal. and $10/bbl
($/bbl)
=» 31,707 x-
^BTU/gal.
= $
./MM BTU
LIMESTONE SCRUBBING
B-30
-------
a
• A 1 W
i x 10!
^m
••
<••
•M
•*•
•M
••
1 x 10§
m
«•
•M
<•
•M
«•
•
4
M
•
•
•
1 x 104-
•
»
. -
•
MB
•
P
•
m
m
•P <•
•
M
.
m fc—
P— 1? T^U 1 ^ CQ •
L +75 -F f :
: AT gj
• £E
**** •
« | j
•
•
• •
• «
•>
•>
Bj
•
ft •
<•
<
•
"
B •
•
<•
•
,
*•
«
V
<•
<•
M
-1
•i
-2
p
•
:3
»
u
=•5
-6
-7
-9
-10
»
-20
;\
:3o
1-40
-50
Leo
-70
-80
-90
-too
V
-200
•
•300
-400
-500
-600
-700
-800
-400
-1000
Chart 13. REHEAT COSTS
LIMESTONE SCRUBBING
B-31
-------
DUCT COSTS
To calculate ducting cost:
Assumption-
The length of flue duct from the main discharge duct to the
venturi (if used) is variable in feet and also the return to
the main discharge duct after SO- and/or particulate removal.
For the specific boiler if more than 1 venturi and/or absorber
is required use the multipliers listed in Table 14. Compute each
boiler separately, unless identical to each other in absorber or
venturi acfm at 125°F and saturated.
From data sheet,
acfm at °F
2 2
Area duct (from main) in; = ft = 2X
3,500 ft/min
Perimeter length:
2
ft
-v-
ft
6X = 6x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.39/lb =
7.02 x ft perimeter = $ cost/linear ft [6?
Page B-12 Chart
4, item \22
Area duct (to main) outt = ft - 2X
2,500 ft/min
2
Perimeter length: 2X = ft
X =|/ ft2 = ft
y-
6X = 6 x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.445/lb =
8.01 x ft perimeter = $ cost/linear ft
LIMESTONE SCRUBBING B-32
-------
DUCT COST
Table 14. MULTIPLIER FOR DUCT COST
No. of absorbers
and/or Venturis
per boiler
1
2
3
4
5
6
7
8
9
10
Venturi and
absorber
in
110
190
250
305
356
410
453
490
535
579
Venturi or
absorber only
in
70
114
180
225
266
310
346
378
415
452
Venturi plus
absorber
out
70
113
143
175
205
235
262
288
315
343
Venturi or
absorber only
out
50
93
123
155
183
208
242
268
295
324
Duct cost in -
(in) cost/ Table 14
Estimated ft to
+ main duct-(30J )
linear ft ^multiplier
-30 ) =
Duct cost (in)|68
J I68|
**
Duct cost out -
(out) cost/ Table 14
Estimated
distance to
67$
linear ft A ^multiplier main duct -0>0'
,x ( J+( -50 )
Duct cost (out)[69]
= _$_
Total duct cost -
6~8] duct cost (in) + [69J duct cost (out) = .total duct cost
$ _ + $ _ = $
70
* If congested area add 230 ft for estimated ft.
** If congested area add 200 ft for estimated ft.
BUKUMBING
B-33
-------
LIMESTONE PREPARATION AREA COSTS
To calculate conveyor cost, Chart 15;
Estimate distance (ft) from storage pile area to sites and record
(ft) [7~o] from storage pile area to silos
Record from page. B-6 item [To
Ib/hr CaCO3
ton/hr CaC03
Ib/hr CaCO3 -r 2,000 =.
Enter ton/hr Chart 15 on 7_1 and move vertically upward
to |721 then move horizontally to the left
to 73| and record $_
.conveyor cost
73
If |70| is greater or less than 600 ft.
Enter ton/hr at |7l| and move vertically upward
to |74| and then move horizontally to the left
73] and record $ conveyor cost/100 ft
D
to
Number of 100 ft lengths that |70| is greater or less than
600 ft J?5lD
+ ( 173
+ (
75
D ) = |76 adjusted cost
) = $_
Conveyor cost:
[73] „
.= $
.conveyor cost \J7\
Assumptions:
Cost of the conveyor system installed: 2-inground hoppers, 2-15°
incl. conveyors
Xiivjx* w~>ii v cy WJ- o
(conveyor at 50' elev., conveyor covered , 2 trippers.)
Conveyor lengths: 2-300 ' inclined, 1-600' to silos, walkw
LIMESTONE SCRUBBING
B-34
-------
H
-a»
ri
M
en
O
(X)
w
H
03
U)
Ul
o
H
ui
•
O
8
[wj ADD OR DEDUCT/100'
9500 O 10.500 11,500 12.500
It M I I I I M|l I I I I I I I I | I I I I I I I I III I I
13,500 14.500
I I I I 11 I I I I M I I |
160,000
230,000
240,000
-------
FLUE GAS SHUTOFF AND BYPASS VALVES
To calculate flue gas shutoff and bypass valve costs:
Assumption-
Based on 4 vanes/axis in short dimension based on height of 20 ft
and width of 10 ft,
Stainless steel at $141.6/ft2; carbon steel at $99.I/ft2
Flue gas valve (in) at main duct to create a bypass
From the data
sheet acfm at /
°F /Boiler = ft2 = 2 W
3,500
w =l/ _ ft2. w x 2 = jc 2 = height, ft
Valve cost A = (1.5 x H) 1(99.1)** (3.1) (H-20) (0.5H-10)]
*H greater than 20 ft, sign is +, less than 20 ft sign is -
(H) (H) (H)
= (1.5 x ) [(99.1)± (3.1) ( -20) (0.5 .-10)]
= $ carbon steel 78
Flue gas valve (out) at main duct to create a bypass
PageB-12,, Chart 4,
item |22|
22
-27506 7 Boiler ^500 = ft2 = 2 W2
-ft2; W x 2 = x 2 = ft (height H)
(H) (H) (H)
Valve cost B = (1.5 x ) [(141.6)±* (4.5) ( -20) (0.5 .-10)]
.stainless steel p)9|
Flue gas valve (in) to absorber and/or venturi train
Page B-ll
item 23 acfm at
^j] acrm at /
_F /Boiler = Area, ft
No. of Venturis or absorbers) x 3,500
LIMESTONE SCRUBBING B-36
-------
FLUE GAS SHUTOFF AND BYPASS VALVES (continued)
23
71
.x 3,500
_= Area,ft2 = 2 W2
ft ,• W x 2 =.
.Height(H) ,ft
Valve cost C
= (Height (H) ± 0.5 Height (H) [(99.1)- (3.1) (H-20) (0.5H-10)]
"CH) (H) (H)
= (1.5 x ) [(99.1)-(3.1) ( -20) (0.5 -10)]
carbon steel
Valve cost D =
chart 4, item 24 \
vNo. of Venturis and/or absorbers/ x (valve cost-
L
.) x (.
-) = $.
sop = [sil
Flue gas valve (out) from absorber and/or venturi
Page TB-ll-f item [23
1.08 acfm at 175°F
2,500
0.000432 x
•ft2; W x 2.
y Venturi and/or absorber = ft
ft2 = 2 W2
x 2 = ft, (H)
Valve cost
= (1.5
E
(H)
(H) (H)
) [(141.6)-(4.5) ( ^-20) (0.5 -10)]
= $ stainless steel [82|
Valve costp =
7 PaqeB-ll, item 24| \
\No. of Venturis and/or absorbers/
- ( ) x ( i =
Valving cost per boiler
Valve cost = 78 + 79 +
= V V
VA B
+ +
= $
x (valve cost,, [82 ) =
£i *•• — ••
: $ 83
81 + 83|
V V
D F
+
total valve c<
[83|
|84l
DSt "841
DCRUBBING
B-37
-------
BALL MILL COSTS
To calculate ball mill costs and horsepower (hp), Chart 16;
From page B-31, Chart 15, item 71 ' ton/hr CaCO3
71
x 1.2 (excess capacity)= Ball mill capacity
_x 1.2 = .ton/hr ball mill capacity [85
If [85] is less than 100 ton/hr, [§5| 4- 2 = ton/hr/ball mill |86|
* 2= ton/hr/ball mill [§js|
Enter |86| or |93| on Chart 16 on |87| and move vertically upward
to [8~8] then horizontally to the left
to [89] and read: $ /ball mill
89 x No. of ball mills from 85
= total cost of ball mill 90
-x,( )= $-
-total ball mill cost [90]
Horsepower of ball mill:
Enter [86] or [93] on Chart 16 on [87] and move vertically upward
9l] x No. of ball mills from [85
to [90[ then horizontally to the right
to |jj| and read: hp/ball mill [91
= total ball mill hp J92J
x C j =r .total hp
*If |85jis greater than 100 ton/hr, select capacity to be less than
50 ton/hr per ball mill and equal capacities
85| *' (minimum No. of ball mills with capacities under 50 ton/hr) = [93]
[85]
.) = ton/hr [93
LIMESTONE SCRUBBING
B-38
-------
1X10!
x NT
Six 10*
i i—n—i
L II
1 x ™*l I I t » » I 1 I
1 ITS 2 2753 4 5 67
8 910 15 20 25 30 40 50 60
x 10'
BALL MILL CAPACITY, ten/tor
Chart 16. BALL MILL COSTS AND HORSEPOWER
LIMESTONE SCRUBBING
B-39
-------
BALL MILL TANK AND PUMPS
To calculate costs of ball mill tank and pumps, Chart 17;
Enter item [71] from pageB-31, Chart 15 on Chart 17, item
move vertically upward to item
move horizontially to the left to item
S.
x [NO
94
95
then
then
and read:
tank
of tanks (equal to No. of ball mills from pagej*zl£,
item |85[)J
= total tank and pump costs f97
.* C-
total tank cost 97
LIMESTONE SCRUBBING
B-40
-------
3100
r I | I I I I i I I I i I M i I I I | I i
I I I I I I I I I I I I I I I I I I I I I 1 I L 1 J I I I I I i I I I
1100
20 30
CaC03, ton/hr
Chart 17. BALL HILL AND PUMP COSTS
LIMESTONE SCRUBBING
B-41
-------
LIMESTONE STORAGE AND FIXATION STORAGE SILO COSTS
To calculate cost of 3- and 30- day storage,. Chart 18;
Enter item pTl] * , pageBr35,Chart- 15 on Chart 18, item |98| then
move vertically upward to item
move horizontally to the left to item
Cost for 30-day storage of limestone $.
100 and read
ST
Enter item |71| *, page.SzJ;L5jChart>l5-on-OJhart 18, item |98| then
move vertically upward to item 101| then
move horizontally to the left to item
Cost of 3 day storage = $
Total cost of storage = ]100| gT + flOQ
silo cost |100|
|oojs
** Fixation silo cost -
1/3 x item |100| g = cost |101| = 0.33 x_
.= $
If tonnage usage is under 8.3 ton/hr of CaC03 use table below
Ib/hr
0 - 500
501 - 2,000
2001 - 5,000
5001 - 10,000
10001 - 16,600
No. of
silos
1
1
1
2
2
100 s cost/
ancilliary
equipment
4,000
5,000
9,000
20,000
23,000
** Under 8.3 ton/hr of CaCQ3 use $9,000 for fixation silo costs
LIMESTONE SCRUBBING
B-42
-------
1X10
1X10
o
CJ
vo
*«>•
«B
ro
o
o
1X10
1X10
R.M. 30 DAYS
SILOS 3 DAYS
25 50 75 100 125 150 175 200 225 250 275 300 325 350
CaC03> ton/hr
Chart 18. LIMESTONE STORAGE COST
LIMESTONE SCRUBBING
B-43
-------
SOLID DISPOSAL
To find the cost of clarifier and vacuum filtration equipment and
pump combined, Chart 19;
Chart 19 gives the cost of the following system and limitations:
Clarifier, 150 ft diameter
Overflow pump head, 250 ft
Under flow pump head, 250 ft
Filtrate-return pump head, 350 ft
Sludge pump, head 1000 ft
Under flow emergency pump
Vacuum filter, 50 ton/hr
Sludge mix'tank and mixer
Water make-up pump
Enter item [16] (dry sludge, ton/hr) ,from page" B^
art 3 on item i2
Select number of clarifier units, same size (each 50 ton/hr of dry
sludge requires 1 clarifier unit) = units ]I03|
From item [102| move vertically upward to item |104| (• Sh^ system
curve), then continue upward to item J105 (equipment cost curve).
From item |l04| move horizontally to the right to item |106| for hp
of equipment.
hp of equipment x No. of units = total hp required=:_
(106
_hp
x
From item |l05| move horizontally to the left to item |108[ for equip-
ment, $ /unit |lO8]
Item |108| x No. of units |103| = total cost |l09l
x = $ []J09
LIMESTONE SCRUBBING
B-44
-------
1 x 10
10,000
1 x 10
o
o
1 x 10
1 x 10
ton/hr SLUDGE DRY FOR SOLID DISPOSAL EM
Chart 19. SOLID DISPOSAL COSTS
LIMESTONE SCRUBBING
B-45
-------
CaCO3 SLURRY TANK AND PUMP COSTS
To find the cost of CaCO., slurry tank and pump, Chart 20;
Enter item |71| from pageBr35, Chart 15, limestone, ton/hr on Chart 20.
item 11101
From item |110| move vertically upward to item [lll| (pump cost curve),
then continue upward to item |112| (CaCO, slurry tank curve) .
From items |lll| and |112| move horizontally left to item [113| read and
record:
$ pump cost
$
.slurry tank cost [113[ T
Under 15 ton/hr compute tank and pumping cost from table below
ton/hr
13 - 15
10 - 13
7-10
5-7
3-5
1-3
0-1
113 _
j.
Tank cost, $
36,000
32,000
26,000
20,000
16,000
10,000
5,000
113
•• — L
Pump Cost, $
6,000
5,100
4,100
3,200
2,500
1,700
1,200
LIMESTONE SCRUBBING
B-46
-------
CaC03 SLURRY TANK AND PUMP COSTS
Table for mixers -
Select ton/hr of CaCO^ and corresponding cost of mixers:
ton/hr CaCO3
0 12.6
12.6 - 25.2
25.2 - 37.8
37.8 - 50.4
50.4 - 63.0
63.0 - 75.6
75.6 - 88.2
88.2 -100.8
100.8 -113.4
113.4 -126.0
126.0 -138.6
138.6 -151.2
151.2 -163.8
163.8 -176.4
176.4 -187.5
Mixer cost, $
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
22,000
24,000
26,000
28,000
30,000
ton/hr
187.5 -
201.6 -
226.8 -
252.0 -
277.4 -
302.4 -
327.6 -
352.8 -
CaC03
201.6
226.8
252.0
277.4
302.4
327.6
352.8
375.0
Mixer cost, $
32,000
36,000
40,000
44,000
48,000
52,000
56,000
60,000
Total cost:
.mixer cost
113]
M
+ $
+ $
—LIMESTONE SCRUBBING
B-47
-------
1X10'
iIII111 iiTiTi ii 111ii iM iii ii ii 11) 111 ii iiiiMIin11111111 M 11111'II11±
.****
1X103
8
1X10
1X10'
111IIII11II11II111 III 11
1111 11111 111 11 11111 1111111111111 111111111111 I
0 25 50 75 100 125 150 175 200 Z25 250 275 300 325 3S0
CaC03,ton/hr |^|
Chart 20. COST OF CaO and CaCO3 SLURRY TANKS
LIMESTONE SCRUBBING
B-48
-------
POND ACREAGE AND POND EXCAVATING/DIKING COSTS
To determine the cost of pond acreage, excavating/diking costs,
Chart 21:
Enter from pages-10,Chart.3 item [J6| (ton/hr dry sludge) Chart 21,
item [115[ then move vertically upward to the respective
weighted capacity factor, item [116
From item |116| move horizontally left to item |117J (acre ft/yr)
and reference line |118[ and read:
Select plant remaining life on item |119
Connect items |118| and |119| and extend to item |120| (pond acre-ft)
and read: Il20|
From item |120| move horizontally left to item |l2l] (pond reference
scale)
From item [121] move vertically down to item |122| (pond cost)
and read:_J$ |122| dry sludge
If wet sludge, no waste return 1.67 x 120) =.
|123|
.pond acre-ft wet sludge
Enter item 123 on Chart 21, item |120| and move horizontally left to
item 121
From item fl2l] move vertically down to item [122] (pond cost) and read:
$ |124| wet sludge pond cost
Select proper item |l22l or |124| and record as pond cost, $ J125|
LIMESTONE SCRUBBING
B-49
-------
Chart 21. POND COST
-------
MOBILE EQUIPMENT
From Richardson's - capacity to move 60 ton/hr limestone
from storage pile
Cost $44,000
Requirements: based on ton/hr required
Same unit as above for fixation process capable of
handling 1,300,000 gal./wk of fixed sludge
.qr-m;p.KT:;;G B-51
-------
EQUIPMENT COST - LIMESTONE
Equipment
1. Absorber
2. Venturi and absorber
3. Venturi
4. Absorber and/or venturi
holding tanks agitators
5. Absorber and/or venturi
holding tanks
6. Circulation holding tanks pumps
7. I.D. fans
8. Heat exchangers
9. Soot blowers
10. Ducting
11. Conveyors
12. Bypass valving
13. Ball mills
14. Ball mill tank and pumps
15. Dry storage
16. Fixation silo
17. Solids disposal - clarifiers,
vacuum filtration, pumps
18. Limestone slurry tanks and
pumps
Item
Cost, $
[271 V+A
LIMESTONE SCRUBBING
B-52
-------
EQUIPMENT COST
19. Mobile equipment Page B_50
20, New roadways or RR siding at Page B-50
$50/ft, estimated length
Total equipment costs:
Year of FGD system operation
'Select cost factor index multiplier from Page B-52
for th* year »t»ove
Predicted equipment coots.-
(total costs) x Ccost factor index multiplier)
( ) x ( ) = $
Predicted pond cost = pond cost x cost factory index multiplier
from item 11221 or O5l
x
LIMESTONE SCRUBBING B-53
-------
tr1
H
25
td
o
§
w
W
CO
m
1969
1971
1973
1975
1977
YEAR ENDING
1979
1981
1983
1985
-------
CAPITAL INVESTMENT COSTS—LIMESTONE
Direct Costs:
Seled
"A" M<
"B" Lc
"C"
t system required
iterial
abor
Retrofit
Easy
Moderate
Difficult
Absorber j
or venturi :
1.646Xa
0.814X
Absorber & venturi
1.639X
0.822X
Materials and labor
Absorber
0
0.047X
0.093X
Absorber- venturi
0
0.039X
0.077X
Cost, $
X = Equipment cost, predicted from page B-53
"A" + "B" + "C" = $
'D" Raw materials: Chart 15, item |7l| page
30 day ,
ton/hr CaCO., x storage x $/ton =
720
x
_
-------
TOTAL ANNUAL OPERATING COSTS—LIMESTONE
Utilities -
Water: Limestone scrubbing
66 gal./MW for 3.0% S coal
±A6 gal./MW for each ± 1.0% S in coal
55 gal./MW for 2.0% S oil
±A-5 gal./MW for each ± 1.0% S in oil
128]
Limestone:
Cgal./MW - gal./MW corr. for % S) x hr/yr x weighted capacity
factor x water costs/1,000 gal. = Yearly cost water/MW
130|
(|126| or [128
or
129 ) x C.F.
$0.02
x 8760 x 1,000 gal. = $/MW
$
/Coal \ /Base;% S \
\or oil/; \% S corr./ ;
130] x
x
MW
.= $
Reheat:
From page B-31, Chart 13, item [651 determine $/reheat
(see calculation sheet)
$
For AT
130
./yr [1311
./yr [65
LIMESTONE SCRUBBING
B-56
-------
TOTAL ANNUAL OPERATING COSTS—LIMESTONE
Operating labor cost:
MW'S
100- 699
700-1200
1201-2500
2501-
Men/Shift
3.33
3.67
5.00
6.00
Men/shift x hr/yr x $/hr = |132|
.x 8760 x 6.50 = |132s
_x 56,940 = $.
Corrected cost: |132|
Supervision:
(manpower
650
/yr
$ /yr
Maintenance:
Capital costs, total
0.046 x _= $.
Vyr
132
0.15
Corrected
x 56,940 x
8541 x
cost:
132
men/shift = 1«
= $
x 0.15 = $
33
/vr
/yr
[l33|
133J
Overhead:
Capital cost, total
(0.023 x .
•f Men/shift
.) + (13,100 x )
= $
LIMESTONE SCRUBBING
B-57
-------
TOTAL ANNUAL OPERATING COSTS—LIMESTONE
Fixed costs -
A. 100 _ %/yr depreciation, straight-line
Plant life, yrs*~
B Capital = %/yr
C. Taxes, insurance/ interim replacement - 4.65%
Total fixed costs = A J|Q^ + C = o. /yr fixed costs
(Yr fixed costs) x (total capital cost) =
(O, ) xj[ 1= $ /yr
Sludge disposal:
Pumping to another site, off-plant
MW KW/MW $/KWH**or*** ,hr/vr x weighed CF
0.0016 x x 1000 x x 8760 x =
MW $/KWH** or *** weighed CF
14,016 x x x = $ /yr |137|
Truck disposal costs/14 miles:
8.47 tonsddrySsludge/trucK hr x $17'20 x 1-1 x 876° x CF =
(57.25 rain/trip) ($17.20/truck hr/driver)
From Chart 3, item |16| , tons dry sludge/hr |16|
weighed CF
.x 19,570 x = $ /yr |138|
* Plant life, years: either remaining boiler life in years from start
of FGD system or 15 year life for FGD system, use lowest number of
years jfor life.
** ***
or see next page
LIMESTONE SCRUBBING B-58
-------
TOTAL ANNUAL OPERATING COST—LIMESTONE
Raw Materials -
Limestone:
z35, Chart 15, item |7l| ton/hr CaCO-, x hr/yr x
*t3 f^TI* •«»• £ /Am n-K 3 _ ~« J_ / fi ^\*»%1 ••»
weighed CF x $/tona = cost/yr.
Chart 15, item [7l| x hr/yr x CF x $/tona = cost/yr [l39
8760 x = $ 11391
Fixation.
Pagej-jn, chart 3,
item |ji61 , . .
hr/yr weighed
iu-/_jj- weignea
_lb/hr dry sludge x Ib/ton x CF x $/tonb = cost/yr [140
x 4.38 x x = $ 140
Utilities:
Electrical, use appropriate
Limestone—-burning coal =
MW x x $/KWH* x Weighed CF x hr/yr = cost/yr
0.025 x x 1,000 x x x 8760 = $ [141
MW $/KWH CF
2.19 x 105 x x x = $ /vr =
(on coal/abs. + vent)
$ 1141| A+V
1.971 x 105 x x x = $ /yr =
(on coal/abs. or vent.)
.[141
Limestone—burning fuel oil =
MW $/KWH** CF
1.374 x * x = $ = $ EH)
(on oil/abs.)
alf unknown use $6.32/ton
blf unknown use $4/ton of dry sludge
**If unknown use 0.00675/KWH based on coal at $10/ton and 12,000 BTU/lb
If unknown use 0.0185/KWH based on oil of $8.40/bbl and 149,000 BTU/gal
LIMESTONE SCRUBBING B~59
***
-------
TOTAL ANNUAL OPERATING COSTS - LIMESTONE
Summary sheet
Item Cost, $
1. Water
2. Reheat
3. Operating labor
4. Supervision
5. Maintenance
6. Overhead
7. Fixed costs
8. Sludge disposal, pumping
9. Sludge disposal, trucking
10. Limestone
11. Fixation
12. Electrical
135
136
MO I
141]
A+V
0
Total annual operating costs.
Cost per kilowatt-hour:
(total annual operating cost)
hr/yr x (plant rating in MW's) x 1,000 x (weighed capacity factor)
( ) = $ /KWH
8760 x (
) x 1,000 x (
LIMESTONE SCRUBBING
B-60
-------
APPENDIX C
DOUBLE ALKALI SCRUBBING
NOTE: For purposes of clarity and continuity, Tables and
Charts have been numbered sequentially in this
report with no differentiation between Tables and
Charts.
DOUBLE ALKALI SCRUBBING C-l
-------
DOUBLE-ALKALI
INFORMATION REQUIRED
Boiler No.
Type of unit furnace
MW at maximum continuous
Age of unit, years
Life, years remaining
Capacity factor, yr.
Maximum continuous fuel,
ton/hr or gal. /rain
Maximum continuous,
MM BTU/hr
acfm at 9F
Fly ash/total ash, %
Efficiency of existing
particulate control, %
•
1
Cost of electricity/kW (Plant) =$
Coal, cost/ton $
% sulfur by weight
% ash by weight
HHV, BTU/lb
.. Cost of water/M gal. (Plant)
Oil, cost/bbl
% sulfur by weight
BTU/gal
Specific gravity
SO2 permissible
Fly ash permissible
Ib SO2/MM BTU
Ib fly ash/MM BTU
State or
Federal regulations
DOUBLE ALKALI SCRUBBING
C-2
-------
INFORMATION REQUIRED (continued)
Estimated land cost per acre (current) $
Possible interference determining the location
of flue gas desulferization (FGD) system:
Congestion between stack and plant Q Yes Q No
Congestion between stack and/or plant with Q Yes Q No
property line, coal pile, etc.,
Identify problem areas aad location: _j
Terrain
Conduits.
Possible obstructions.
Source of NapCO-,- available.
and % purity _
Source of CaO available!
% purity
C-3
DOUBLE ALKALI SCRUBBING
-------
S02 EMISSION DETERMINATION
To determine the S0_ emissions (Ib/MM BTU) in the flue gas,
Enter % sulfur by weight of fuel (oil or coal) on(T]
Enter heating value of fuel (BTU/lb) on
Chart 1:
Connect 11|and I 2]and extend to 3 and read and record:
Tl
SO- emissions (Ib/MM BTU) in flue gas
3:
>-
CO
co 6
9
10;
n
24,
22
20
18
§ 16
ft
r~
CD
| ':
"~. 12
to
g
•— «
i °:
uj
>*\Sf 8:
"V. .
6
4
'
0
LU
Z
: O
Z
LU
CZ
", u.
LU
QC
^^£ ^^w
24
22
20
18
16
t-4;
12
10
8
6
4
2
0
o
1 „
r^
CO
1
to
0
. to
LU
CM
O
to
Chart 1. S02 EMISSION DETERMINATION
Assumptions:
(1) 95% of sulfur in coal converted to S02
(2) 100% of sulfur in oil converted to S02
DOUBLE ALKALI SCRUBBING
C-4
-------
SO2 REMOVAL REQUIREMENTS
To calculate S02 emissions (Ib/MM BTU) to be removed:
Enter from page C-4 , Chart 1, item (Tithe Ib/MM BTU_
Enter from the data sheet, allowable S0? emissions
(Ib/MM BTU) from the State or Federal regulations —
Subtract [_4J from |_3J to calculate S07 emissions
(Ib/MM BTU) to be removed
DOUBLE ALKALI SCRUBBING . C"5
-------
LIME REQUIREMENTS
To determine the lime requirements (Ib/hr) Chart 2;
Enter the SO2 emission (Ib/MM BTO) to be removed on item [J
from page C-5, item [¥] ; record _ [IFj
Enter stoichiometric* requirements for lime on item [T]
Connect j_6j and \7\ and extend to [¥] and read and record:
Lime requirements (Ib/MM BTU) _ |T]
Record from the data sheets the heat input (MM BTU/hr)
Multiply [Fix .[sl and record:
Lime requirements (Ib/hr)
Multiply j~6"| t>y and record: Ib S00/hr removed
X\ £t
_ m
c
*
If unknown, use 1.1.
DOUBLE ALKALI SCRUBBING C-6
-------
On-
40-i-
364-
324-
284-
244-
THEORETICAL 20-
LIME
EQUIREMENT
-t- co
1.50
1.30
164-
124-
3--
2--
1--
O-1-
o
(O
8
Chart 2. LIMESTONE REQUIREMENTS
DOUBLE ALKALI SCRUBBING
C-7
-------
Na COMPOUND IN CIRCULATION
MAKE-UP SODIUM CARBONATE REQUIREMENTS
To determine the Na compound required - Chart 3
Enter from page C-5, item [|] SO- (Ib/MM BTU) to be removed
on item [5] , Chart 3
Enter Na compound stoichiometric requirements* on LlOi
Connect
and
and extend to,
, read and record
Na compound requirements (Ib/MM BTU):
To determine the amount of make-up sodium carbonate required - Chart 3
Enter make-up percentage** of sodium carbonate on (ij)
Enter from page G-5, item [¥] S02 (Ib/MM BTU) to be removed
on item [9j , Chart 3
Connect Hf! and O extend to [H
Na2C03
read and record
Ib/MM BTU El
* If unknown, use 1*05.
** If unknown, use 5%.
DOUBLE ALKALI SCRUBBING
C-8
-------
•
.
•
•1
•
m
*
4
m
«
•
<
<
M
•
i
•
•
Q
UJ
g
§=>
oct-
-S-
C>£
*~3-
«J
s
5» -
•
«•
4
•M
••
•
«
«
V
—
-IU.U
•9'° 0.003T
-8.0
* •
.7.0 0.004-
» «
Le.o o.oos^
! 0.006-:
•5.0 0.007-
0.008-
U.O 0009-
0.01-
t
m
-3.0
»
0.02-
.
-2.0
0.03-
0.04-
4-2 :
0.05^
--3 0.06-;
r°-9 ::f °b^
-0.8 - -8
•• wU
:07 TfO
rO.7
% MAKE-UP
-0.6 SODIUM CARBONATE
: 12 °-2-
-0.5 u -
» ""
^o.4 °-3:
0.4:
9 m
-0.3 O.ST
O^B *
.6-
0.7:
0.8:
-0.2 0.9-
1.0-
r V
•
2.0-
-0.1 1
•
m
m
: 0.2-*-
^. • •
••
r °-3: :
••
0.4- •
0.5- -
0.6^
0.7- •
0.8- •
0.9^
1 0-
, I • W
.3
:« e
•v fr"~ .
.1 «
:3 Oil i
. «J *-_ — J ^^
" 3 2 n-
n np •» C«U
: /! ^0.95 ___^^~— — ^^
^fli^r^^" ^ :
-3C « « ^ ' » vO ^_
-1 | 3-o-
-3 Na+ COMP. ° ;
-•E STOICHIOMETRIC S. 4>Qj
»— «
§ 5.0-;
^ V?
^ 6.0-
• ~? •
^ 7.0-
:i a.o:
9.0:
10-
1
". t-
r 20.
^
30~
~ rr
: Ll
•» »
•V
3
to. 09
•ri
[9|
Chart 3. Na+ COMPOUND AND SODIUM CARBONATE REQUIREMENTS
nnrmr.w STK-BTT c-r-pnppr^r: £-9
-------
FLY ASH EMISSION RATE CALCULATIONS FOR VENTURI DETERMINATION
To calculate fly ash emitted:
If the fly ash emitted (Ib/MM BTU) in |l4] after passing through an
existing particulate emission collector per boiler is greater than
the allowable rate from the data sheet, the use of venturi is
necessary. Use the following equation to calculate
% ash in coal )(% fly ash*V(l-n ) -f BTU/lb | x 10 6 = Ib/MM BTU
KXO 100 -,-mT , I
= [(0. _ ) (0 -- ) (1-0. _ ) 4. •*•"" j * IQ° = _ Ib/MM BTU
where
n = Efficiency of particulate emission collector system
o
BTU/lb » Heat value of fuel (MM BTU/lb)
_. ^ _ ___. - - — — - - .- — — -.— *„, ._.. . - —
% ash = from the data sheet
If fly ash removal is required for any or all of the units VENTURI COST
CALCULATIONS will be used.
*If the percent of fly ash to ash is not known use the appropriate
tabulated values for the boiler under consideration.
Type boiler - coal-fired fly ash to ash, %
General pulverized 80
Dry bottom 85
Wet bottom 65
Cyclone 10
DOUBLE ALKALI SCRUBBING C-10
-------
SLUDGE GENERATED
To determine the dry sludge (Ib/hr) generated, item (l6| , Chart 4;
From page C-10, item |T4| enter calculation of fly ash (Ib/MM BTU)
(HI
From page G~ 5 , item [f] enter Ib SO./MM BTU
From page C-7 , chart 2 item 0 enter Ib CaO/MM BTU
From page C- 9 , Chart 3 item [13] enter Ib Na2C03/MM BTU G>]
B + GO + [§] + [§] = Us] total dry sludge tlb/MM BTU)
Us!
From data sheet, heat input maximum continuous rating, record
here as (MM BTU/hr)
Dry Sludge =
Wet sludge - Enter [17) on [Is] , Chart 4 and divide by percent
weight dry sludge on [Is] = Sludge slurry, ' Ib/hr
-s- 0.6* =
Ib/hr
fl. 61
|15| x 1
X
El?
6 = [17! Ib/hr
Ib/hr
I - 2000 = FT] A ton/hr
ton/hr Il7
*If other than 60 percent by weight is used, use that value, on [if
DOUBLE ALKALI SCRUBBING
C-ll
-------
^4000
Chart 4. SLUDGE GENERATED
DOUBLE ALKALI SCRUBBING
•C-12
-------
VENTURI AND ABSORBER COSTS
To determine the costs of venturi and absorber (including demister)
using Na+ compound, Chart 5
First, determine number of scrubber trains -
Enter acfm at °F of flue gas from the data sheet on [2J] , either
per boiler or combined plant total if °F is the same for all
boilers.
Enter temperature of flue gas (°F) on [22J
Connect [2J] and [22) and extend to [23} and read flue gas acfm
at 125°C (saturated) and enter acfm at 125°F and sat. J2]
If acfm at 125°F is greater than 375,000 divide [23} by a number less
than 375,000 to give a whole number of Venturis and/or absorbers for
each boiler.
acfm per venturi and/or absorber
24
23| = J2J5] number of Venturis
"" and/or .absorbers per
boiler or power plant.
A venturi, or an absorber, or a combination of a venturi and absorber
is sometimes called a train.
DOUBLE ALKALI SCRUBBING C~13
-------
10
9--
8--
7--
6— —
o
03
o
X
4--
>-
3--
5--
--2
--3
--5
-
NOTE:
IF FLUE GAS FLOW IS
450,000 acfm AT 300°F
ENTER 450,000 AS 4.5 x 105
ON 20 , ENTER 300°F ON
21 EXTEND ENTRIES TO 22
AND READ 3.75 x 1Q5 OR
375,000 acfm AT 125°F
AND SATURATED
— —9
Chart 5, acfm CORRECTED TO 125 °F AND SATURATED
DOUBLE ALKALI SCRUBBING
-J-10
II
C-14
-------
VENTURI AND ABSORBER COSTS
Then determine absorber costs (no venturi required) Chart 6;
Enter item |23| from page C-14, Chart 5 on Chart 6 on |26J
Enter for the absorber the cost factor of 1.65 on J27|
Connect J26] and J2?] and extend to J28j and read absorber cost
Or determine venturi and absorber costs (if a venturi is required) Chart 6
Enter item |23[ from page C-14, Chart 5 on Chart 6 on J26|
Enter for the train the cost factor of 2.55 on J27J
Connect J2j5j and |27J and extend to pi] and read venturi and
absorber costs $
28
V + A
Or determine venturi costs (no absorber): Chart 6
Now enter item J23J from page C-14, Chart 5 on chart 6 on J26J
Enter the venturi cost factor of 0.9 on |27|
Connect |j| and 0 and extend to J28| and read venturi costs
$
DOUBLE ALKALI SCRUBBING
C-15
-------
3 — —
c;
rs
I—
<: 4.
n
U-
o
LT>
c\j
<+-
u
to
o
X
>-
7—- —
COST FACTOR
ABSORBER AND VENTURI
SEE CHART 5 FOR
:: EXPLANATORY NOTE
ABSORBER ONLY
VENTURI ONLY
Chart 6. SCRUBBER COSTS
DOUBLE ALKALI SCRUBBING
C-16
-------
HOLDING TANK CAPACITY
To determine the holding tank capacity for absorber and/or venturi
Chart 7;
Enter flue gas acfm from page C-1,6, chart 5, item |24] on Chart 7,
item J29]
Enter L/G* (liquid flow rate, gpm/1000 acfm at 125°F) on [|oj
29 and [30| and extend to |3l[ , read and record:
Connect
Liquid flow rate (gal./min)
Liquid flow rate (gal./min)
Enter retention time** on [32]
Connect |3l| and |32l and extend to
Tank capacity (gal.) per absorber
(gal.) per venturi
V
for absorber
for venturi
, read and record:
33] ,
* If unknown, use 20
** If unknown, use 6 min.
DOUBLE ALKALI SCRUBBING
C-17
-------
1 x 104_
-T-l X 103
—I x 104
en
*
>-
\—
i—«
o
D. '
^
-------
HOLDING TANK AGITATOR COSTS
To determine the cost of agitators per tank, Table 8;
Compare tank capacity (gallons) from page C-18, Chart 1, item (33)
*»
and/or p] v on Table 8; under tank capacity in gallons column
and record:
Cost of agitators per tank - absorber $ [3!
venturi $
Total cost of venturi and/or absrober:
34 ) x No. of venturi of
absorbers from
page C-13, item |1
= $
Table 8. AGITATOR COST
Tank capacity, gal.
0 to 34,000
34,0.00 to 67,000
67,000 to 101,000
101,000 to 135,000
135,000 to 162,000
162,000 to 188,000
188,000 to 220,000
220,000 to 251,000
251,000 to 283,000
Aaitators
No.
1 -
2
3
4
5
6 .
7
8
9
|34|Aor [34_ y, cost, $
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
DOUBLE ALKALI SCRUBBING
C-19
-------
s
G
W
IT"
W
TABULATE THE COST OF TANK, PUMP AND AGITATOR AS BELOW, IP VENTURI IS REQUIRED,
PREPARE SEPARATE TABLES FOR VENTURI AND ABSORBED. PLANT TOTALS
39
T'
, AND |35| SHOULD INCLUDE ABSORBER AND VENTURI EQUIPMENT,
Boiler
No.
(A)
Flue
gas
rate,
acfm
®
Flue
gas
temp,
F.
©
Flue
gas a
125° F,
acfm
®
No. of
trains
(i)
Flue
gas rate
@125°F
per train
(F)
Tank
cost
per
train,
$
(G)
Tank
cost
per
boiler,
$
©X®
Total/plant
Pump
cost
per
train,
$
®
Pump
cost
per
boiler,
$
"H)X(E)
^*^_S v^^x
Agitator
cost
per
train,
$
Agitator
cost
per
train,
$
(J)X(E)
PI T 45 _, 35 _,
en
o
§
ro
w
o
i
to
o
-------
HOLDING TANK COSTS
To determine the tank cost the values in the chart are based on
2
using $12.50/ft for a field-fabricated, rubber-lined tank, Chart 9
Enter tank capacity (gallons) on J36J from page C^I8 , Chart T,
items [33] A and [33] , move vertically to [37
From [37] move horizontally to [38J , read and record:
Hi A
Tank cost per absorber $.
per venturi $_
Total Cost:
( [31
(
V
No. of absorbers
from page;C-13,
)x item \25
cost of
holding
tanks..
-= $_
39
DOUBLE ALKALI SCRUBBING
C-21
-------
I I I |H M I I | I 1 l|l|l|l|'l 1 ' I I |I'M| I | I | IMI'I'I'I I I I I |MU
31 I I I I III I I I I I I I I Illllllll I I 1 I 1 I I I 11 I 1 I I I Illllilll I I I I I I
1 x 103 1 x 104 1 x 105
TANK CAPACITY, gal.
Chart 9. HOLDING TANK COSTS
•DOUBLE ALKALI SCRUBBING
36
C-22
-------
HOLDING TANK PUMP COSTS
To determine the total pump cost for absorbers and/or venturi, Chart 10;
Enter gpm on go| from page.c-18, chart 7, item "0 A_jEor the
absorber and \:3l| y for the venturi. Select minimum number of
pumps, (note 10,000 gpm per pump is maximum), use minimum
number of pumps per train and add 1 spare pump per tank. Record
number of pumps selected per absorber
43] . and per venturi.
Connect [40| and [4l] and extend to [42] , read and record:
Flow rate (gpm) per pump absorber; venturi 40
A'
Tabulate: No. of pumps
Absorber
Venturi
Absorber pump costs:
gpm/pump
No. of trains
[42]
cost/pump
43|A )
]
X
X
25
x (
...X .(
42 A >
rx
]
= $.
44]
Venturi pump costs:
) x
25] x (
X (
)Ȥ
Pump costs, total: from Chart 11
V
DOUBLE ALKALI SCRUBBING
C-23
-------
10,000 „_
9,ooo::
8,000: L
7,000;:
6,ooo; i
4,ooo;:
3,000;:
2,000::
1,000;:
5000 gpm
or less
—12.000
; :i4,000
; iie.ooo
; iis.ooo
BO
Q
«/>
: 120,000
s ::
=3 .
; 122,000
8
o.
-.24,000
;: 26,000
: 128,000
2 130,000
±32,000
Chart 10. PUMP COSTS
DOUBLE ALKALI SCRUBBING
C-24
-------
FAN COSTS
To determine fan costs, Chart u:
Enter acfm at °F of flue gas from the data sheet on J46]
Select appropriate curve for pressure drop* on [47]
Move vertically from [46] to [47J and then from [47] horizontally to
48 read and record:
Fan costs $_
4-8
* Typical pressure drop: Absorber 21 "
absorber and venturi 31"
(includes 3" safety)
(includes 3" safety)
DOUBLE ALKALI SCRUBBING
C-25
-------
G
O
G
ro
en
O
§
H
a
o
o
to
I '' M' I I I I | I I I I I I I I I | M I I I I I 1 I |
i ' ' ' I i i i I I I i i I I I I I i I I I I I I i i I i i i i i i I I i I i i I i i i I i i i i i i i I I I I i t I I I I I I I I I I I i I i I I I I I i i i i
XI0° acfm AT°F
Chart 11.
-------
HEAT EXCHANGER COST
To determine heat exchanger cost, Chart 12;
Enter item [23| from page_C-i6/ Chart 6, on Chart 12, item 149
Move vertically upward to item |5Q for AT*
From
5.0]', move horizontally to the left to
read and record:
Cost for heat exchangers $.
51
* If unknown, use AT = 50'
DOUBLE ALKALI SCRUBBING
C-27
-------
1 x 106-
Of
Ul
C3
<_>
X
Ul
t/i
o
liliil i li llUlil i i i j_Luj i JiuJiiilli li hli.lil i it i 11 i i
1 x 103
1 x 104
1 x 105 1 x 106
acfm AT 125 °F
Chart 12. HEAT EXCHANGER COSTS
DOUBLE ALKALI SCRUBBING
C-28
-------
SOOT BLOWER COST
To determine soot blower cost, Chart 13:
Enter item [24] from pageC-i4 ,Chart 5 on Chart 13, item
Move vertically upward to [5~3
From jSj] move horizontally to the left to [S4J and read:
Cost per train
Record from page C-l4, chart 'iT, item {2J5
., number of trains
Cost of soot blowers:
H x
$ x
= $
55
DOUBLE ALKALI SCRUBBING
C-29
-------
70,000
60,000
50,000
CtL
LU
Q.
40,000
o
_j
ca
o
o
I/)
o 30,000
co
o
o
20,000
10,000
; ' '
.
•
)-
- 54
^
)-
i -
iiiiiiiitlii
i i i i i i i 1 1 i i i i
2500
1 T-| 1 | 1 1 1 1 1 1 1 1
fpm GAS VELOCITY
•
i i | i i i i i i i i i
53
*
-
-
-
~
*
100,000 200,000 300,000 400,000
acfm AT 125°F AND SATURATED
500,000
Chart 13. SOOT BLOWER COSTS
DOUBLE ALKALI SCRUBBING
C-30
-------
REHEAT COST
To calculate the cost of reheat, Chart 141
Enter acfm at 125°F and saturated of the flue gas from page C-i4
Chart 5, item \23\__ on Chart 14, item J5JS
Select and enter AT*-of reheat on item fs?
Connect items [56] and [§7} and extend to item [S8J . record (sal
Enter costs ($/IlM BTU) reheat**from calculation below on
item 59
Connect items |58| and [59] and extend to item
record:
Cost ($/hr) reheat
, read and
Annual reheat cost:
Weighted capacity
factor from data
sheet
.x 8760 hr/yr x 0..
= reheat cost/yr
= $
61
*If unknown, use 50% F.
**Reheat Cost -
Coal: To correct from 12,000 BTU/lb and $10/ton
($/ton)
= 665 x
_BTU/lb
_ <*
./MM BTU
Oil: To correct from 149,000 BTU/gal. and $10/bbl
($/bbl)
= 31,707 x-
_BTU/gal.
= $
./MM BTU
DOUBLE ALKALI SCRUBBING
C-31
-------
1 x 107
-T-l
R 1x10°.
Q
u.
o
CVJ
« 1 x 10^ -
.10,000
-9000
:8000
:7000
-6000
j-5000
Uooo
-J-3000
Chart 14. REHEAT COSTS
DOUBLE ALKALI SCRUBBING
C-32
-------
DUCT COSTS
To calculate ducting cost:
Assumption-
The length of flue duct from the main discharge duct to the
venturi (if used) is variable in feet and also the return to
the main discharge duct after S02 and/or particulate removal.
For the specific boiler if more than 1 venturi and/or absorber
is required use the multipliers listed in Table 15. Compute each
boiler separately, unless identical to each other in absorber or
venturi acfm at 125°F and saturated.
From data sheet,
acfm at °F
2 2
Area duct (from main) in: = ft = 2W
3,500 ft/min
Perimeter length:
X2 = - ft2
.ft2 =_ ft
6X = 6x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.39/lb =
7.02 x ft perimeter = $ cost/linear ft .[62]
Page C-14 Chart
S, item 23
2 2
Area duct (to main) out: = ft ~ 2W
2,500 ft/min
Perimeter length:
X -I/ ft2 = ft
6A = 6 x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.445/lb =
8.01 x ft perimeter = $ cost/linear ft [53]
DOUBLE ALKALI SCRUBBING C-33
-------
DUCT COST
Table 15. MULTIPLIER FOR DUCT COST
No. of absorbers
and/or Venturis
per boiler
1
2
3
4
5
6
7
8
9
10
Venturi and
absorber
in
110
190
250
305
356
410
453
490
535
579
Venturi or
absorber only
in
70
114
180
225
266
310
346
378
415
452
Venturi plus
absorber
out
70
113
143
175
205
235
262
288
315
343
Venturi or
absorber only
out
50
93-
123
155
183
208
242
268
295
324
Duct cost in -
(in) cost/
linear ft
x
62 $
Table 15
multiplier
Estimated ft to
main duct-(30')
-30
= Duct cost (infr 64
=_£_
64
**
Duct cost out -
(out) cost/
1'inear ft x
63 $
Table 15
Estimated
distance to
multiplier main duct -(50'
.x (.
_ Duct cost (out);|j65|
-50 ) =_$_
Total duct cost -
64
duct cost (in) + 65 duct cost (out)
+ $
= .total duct cost
.= $
66
* If congested area add 230 ft for estimated ft.
** If congested area add 200 ft for estimated ft.
DOUBLE ALKALI SCRUBBING
C-34
-------
FLUE GAS SHUTOFF AND BYPASS VALVES
To calculate flue gas shutoff and bypass valve costs:
Assumption-
Based on 4 vanes/axis in short dimension based on height of 20 ft
and width of 10 ft,
Stainless steel at $141.6/ft2; carbon steel at $99.I/ft2., fabricated
Flue gas valve (in) at main duct to create a bypass
From the data
sheet acfm at , ~
°F /Boiler = ft2 = 2VT
3,500 /
=[/ - 2
W = - - ft/* w x 2 = _ X 2 = height, ft
Valve cost A = (1.5 x H) f(99.1)i* (3.1) (H-20) (0.5H-10)]
*H greater than 20 ft, sign is +, less than 20 ft sign is -
(H) (H) (H)
= (1.5 x _ ) [(99.1)± (3.1) ( _ -20) (0.5 _ .-10)]
= $ _ carbon steel [is?]
Flue gas valve (out) at main duct to create a bypass
Page C-l4, Chart 5,
item
acfm
at * /Boiler =
500 2/5QQ = f *
-ft2; W x 2 = x 2 = ft (height H)
(H) (H) (H)
Valve cost B = (1.5 x ) [(141.6)±* (4.5) ( -20) (0.5 -10)]
= stainless steel [68];.
Flue gas valve (in) to absorber and/or venturi train
Page. C-14, Chart 5,
item
/
25
o •
&
;•
acfm at /
/Boiler
' (No. of Venturis or aosorcers)
x 3,500
= Area, ft2
DOUBLE ALKALI SCRUBBING C-35
-------
FLUE GAS SHUTOFF AND BYPASS VALVES (continued)
_= Area, ft2 = "2W2
.x 3,500
ft ,• W x 2 =.
. Height(H),ft
Valve cost C
= (Height (H) ± 0.5 Height (H) ) [(99.1)-(3.1) (H-20) (0.5H-10)]
(H) (H) (H)
= (1.5 x ) [(99.1)-(3.1) ( -20) (0.5 -10)]
= carbon steel
Valve cost D =
Page-
o. of Venturis and/or absorbers/ x (valve cost- 69|) =
( ) x (
-) = 5.
70
Flue gas valve (out) from absorber and/or venturi
Page, C-l3, item 25 .
1.08 acTm at 175°F
2,500
0.000432 x
•
Venturi and/or absorber = ft
.ft2 =
•ft2; W x 2.
.x 2 =
.ft,(H)
Valve cost
'E
(H)
= (1.5_
(H) (H)
) [(141.6)-(4.5) ( -20) (0.5 -10)]
= $ stainless steel l7l|
Valve costp =
/ Page C-13, i
\No. of Ventur
item 25
Venturis and/or absorbers/ x (valve cost,, 71]) =
£
) = $
Valving cost per boiler
Valve cost,, =
68
170
V
A
V
B
V
D
= $
total valve cost
DOUBLE ALKALI SCRUBBING
C-36
-------
LIME PREPARATION-AREA COSTS
To calculate conveyor cost, Chart 16.;
Step 1: Estimate distance (ft) from storage silo area to sites and record
(ft) |74| from storage silo area to silos
Step 2: Record from page C-6y item GO
; 3
Ib/hr CaO
Ib/hr CaO *• 2,000 = ' ton/hr CaO J75}.
Enter ton/hr Chart 16 at [75[ and move vertically upward
to
then move horizontally to the left
to |77| and record $
conveyor cost
If 74 is greater or less than 600 ft.
Enter ton/hr at [75| and move vertically upward
to |78[ and then move horizontally to the left
to 77 and record $ conveyor cost/100 ft
Number of 100 ft lengths that [74j is greater or less than
600 ft
7g] p (estimated fay the observer)
D X
± C |77
± ('_
D
) = $ adjusted cost [80
80.-
Conveyor cost:
.= §
.conveyor cost [8l|
DOUBLE ALKALI SCRUBBING
C-37
-------
o
§
w
f
w
p
H
o
§
w
w
H
Z
o
o
w
oo
o
O
cr
O
O
w
K
O
50
O
O
en
(-3
cn
ADD OR DEDUCT/1001
9500 10,500 11,500 12,500 13,500 14,500
|l 1 ' I I I I I 111 I I I I I 1 I I M I I I I I I I l|l I I I I I I I I [I I I I I I I I I |
160,000
o
Oi
o
I
S:
rr
190,000
200,000
210,000
220,000
230,000
I II I I I I I M 1 I II I | | II I | I I I I I I I II I I I M I I I I I | I II I I I I I l:
TOTAL COST, $ q
1 I I I I I I I I I i I I I I I I I I I
240,000
i i . 1 . i i i i i i i I 1i i i I \i i
-------
LIME OPERATING AND STORAGE SILO COSTS
To calculate costs of silos for operating 3 day and 12 day storage
of lime, Chart .17:
Enter item [75| * from page C-38, Chart 16 on chart" 17,
then move vertically upward to item [83
then move horizontally left to item [84] and read:
Cost for silos for operating 3 days $_
84
Storage silo cost is based on storage capacities indicated:
Enter item J75] from page C-3_8/. Chart 16 on Chart"!?, itenT
then move vertically upward to item J85
then move horizontally left to item J84J. and read:
Cost of 12 days storage silo $ '
84
B
Fixation silo cost -
A
1/3 x item [84
0.33 x
= $ cost
.= $
Lime cost for start-up, 12 day storage plus 3 days operating -
/Item [75
I from
\Chart 17
x $25/ton x 24 hours/day x 15 days = $ costs [87]
_)x 9000 = $_
Lime costs
to correct |87| for current costs:
\87\ x $/ton current cost CaO = $ corrected costs [87]
25
87]
25
* If tonnage usage is under 4.7 ton/hr of CaO use the table on
following page for storage silo costs.
DOUBLE ALKALI SCRUBBING
C-39
-------
LIME OPERATING AND STORAGE SILO COSTS (continued)
Ib/hr
0 - 500
501 - 2,000
2001 - 5,000
5001 - 9,400
No. of
silos
1
1
2
3
cost/
ancilliary
eguipment
M* A + B
9,000
15,000
36,000
65,000
ton/hr
= $
A+B
DOUBLE ALKALI SCRUBBING
C-40
-------
1 x 10
1 x 106
•bO-
o
o
1 x TO5
1 X I"4' I • • • '
I'"' 11 111 11 i i 111 111 | 11 111 | 11 11 i 111 | I' i 11 11 i i 11 11 i
0 10
11 ! I I I Lf I I I 11 11 I I I 111 11 11 I 1 11 I I I I I I I I 111 I I I I I 11 I
«i 60 70 80 90 100 110 120 130 1
CaO, ton/hr
Chart 17. LIME OPERATING AND STORAGE SILO COSTS
DOUBLE ALKALI SCRUBBING c~41
-------
SLURRY HOLD TANKS, MIXERS AND PUMPS COST
To calculate slurry tank costs
Enter from pageC-38, item 75] Chart 16 on Chart 1.8 on item [88
then connect item 88 with 15%* on item 89 , extend to item 90
read and record:
slurry storage gallons,.
Select number of tanks required:
Maximum storage capacity per tank 600,000 gallons if [90
greater than 600,000 gallons,divide |90[ by a number |91| up to £00^000
to get an even number of tanks
If storage capacity is less than 34,170 gal.:
Enter item 90 on Chart 19, item 92 , move vertically upward
to item , 93 , then move horizontally left to item [94| , read
and record:
Total cost of slurry storage tank $_
;94
**
If storage capacity is between 34,170-600,000 gal.:
Enter item
on Chart 25, item |95|: , move'vertically upward
to item [96] , then move horizontally left to item |97| , read
and record:
Total cost of slurry storage tank $
97
**
If storage capacity is over 600,000 gal.:
Divide |90[ by |9l| , record gallons per tank
98
*If slurry percentage other than 15%, use available %
DOUBLE ALKALI SCRUBBING
C-42
-------
SLURRY HOLD TANKS, MIXERS AND PUMPS COST (continued)
Enter item [98] on Chart 21, item [95
, move vertically upward
to item [96J , then move horizontally to item [97] , , read and
record cost of each tank.
Cost of each slurry tank $
. 97 **
Total cost of slurry storage tanks
= cost/tank [97] x No. of tanks [92
= x
= $
99
**
Mixer cost
From Chart 19, item [90] ** note the storage capacity required,
then select proper range from Table 21, under tank capacity, gal,
item |100| if |90| is less than 600,000 gal.
No. of mixers
Total mixer costs $
** if item [9C>1 is greater than 600,000 gallons then enter item [98
on item
100[ to determine number of mixers required -
T.otal mixer cost = 102
No. of mixers/tank.
Mixer cost/tank.
No. of tanks_
x
102
91
91 = $ 103
C-43
-------
SLURRY HOLD TANKS, MIXERS AND PUMPS COST (continued)
Pump cost
Enter from page C-38, item
Chart 16 on Chart 22 on item 104
then connect item [104| with slurry % on item |105] , extend to
item |106|. Connect item -|10_6]- with 200 ft head on item |107| /
extend to item ]108| , read and record:
Pump costs/tank $ |108|
Total pump costs = |108| x 91 = $ [109]
x = $ |109|
DOUBLE ALKALI SCRUBBING
C-44
-------
1 x 10?.
Chart 18. SLURRY TANKS, MIXERS AND PUMPS COST
DOUBLE ALKALI SCRUBBING
C-45
-------
SOOOr
7000 -
o
o
6000-
TANK CAPACITY 12,000-34,170 gal
5000 '
4200
12,000 14,000 16,000 18,000 20,000 22,000 24,000 26,000 28,000 30,000 32,000 34,170
53,00 r CAPACITY, gal
TANK CAPACITY 34,170-600,000 gal.
8000
34,170 100,000
200,000 300,000 400,000
CAPACITY, gal./TANK
500,000
600,000
Charts 19 and 20. SLURRY TANKS, MIXERS AND PUMPS COST
DOUBLE ALKALI SCRUBBING — C-46
-------
MIXER COSTS
Table 21. MIXER COSTS
Item lOOl
Tank capacity, gal.
0 - 40,392
40,393 - 80,784
80,785 - 121,176
121,177 - 161,568
161,569 - 201,960
201,961 - 242,352
242,353 - 282,744
282,745 - 323,136
323,137 - 363,528
J 363,529 - 403,920
'.
403,921 - 444,312
444,313 - 484,704
484,705 - 525,096
525,097 - 565,488
565,489 - 600,000
Item 101
No. of mixers
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
Item 104
Cost of mixers, $
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
22,000
24,000
26,000
28,000 .
30,000
DOUBLE ALKALI SCRUBBING
C-47
-------
D
O
H
cn
O
W
tfl
H
O
I
*k
oo
•T-70,000
-H60.000
^f-SO.OOO
4-40,000
-t-30,000
4-20,000
10,000
loll
Chart 22. SLURRY TANKS, MIXERS AND PUMP COST
-------
COST OF SLAKER, AND PUMP
To calculate slaker, and pump costs:
Enter from page C-38,item {75] Chart 16 on Chart 23 on
item 1110] , move vertically upward to item {iHj , then
move horizontally left to item hi2! and read:
Slaker and pump cost $_
112
DOUBLE ALKALI SCRUBBING
C-49
-------
*t uu i uuu ^^r^T
36Q.OOO -
i i i 11 i i i i I i i i i i i i i i i i i i i i i i i i I i i i i i i
20
40
60 80
CaO USAGE, ton/hr
100
140
Chart 23. COST OF SLAKER, AND PUMP
DOUBLE ALKALI SCRUBBING
C-50
-------
REACTOR TANK COSTS
To determine reactor tank costs, Charts 24 and 25
From page C-5, item 5
lb/MM BTU of SO,
From data sheet, maximum continuous heat input
Multiply :
_MM BTU/hr 114|
x
x.
Ib S02/hr
Enter item |llg] on [116| on Chart 24
Select appropriate point* for % solids on III?
join
and 117 and extend to 118
and read
Lime slurry, gpm_
.[118
From the same point on |116| go through pivot point [119[ to
120 and read
Absorber underflow, gpm_
120]
Total reactor flow gpm = lime slurry gpm + absorber underflow gpm
[120|
+ =
121
Enter [l2l| on Chart 25 on |122| , select retention time** on [123
Connect |122| and [123] and extend to |l24| and read
Total reactor capacity, gal.
Also read No. of tanks
,|124
125]
If number of tanks at 125 is 3 or less, add 1 stand-by tank;
if number of tanks at [125[ is 3 or more, add 2 stand-by tanks to
obtain actual number of tanks_ |l26
Actual No. of tanks [125] + stand-by tanks = b.26|
* If unknown, use 15% Solids
** If unknown, use 30 Min.
DOUBLE ALKALI SCRUBBING
C-51
-------
REACTOR TANK COSTS (Continued)
Capacity of each reactor/ gal.
127
Reactor agitator cost: Table 8
Enter |127| in tank capacity, gal. on page£-l9,Chart 8 and
record Agitator cost/reactor = $ [128|
Reactor tank cost: Chart 9
Enter item [12'71 on page C-2 2, Chart 9, item [36] and move
vertically to [37| then horizontally to [381 , record tank cost
. = $ |129|
Reactor cost = Tank cost + Agitator cost
1301
Total reactor costs = Cost/Reactor x No. of Reactors
[130
126|
= Total reactor
costs
= $
131
DOUBLE ALKALI SCRUBBING
C-52
-------
SP.G. 1.145
SP.G. 1.100
G. 1.060
Chart 24. REACTOR FLOW
DOUBLE ALKALI SCRUBBING
C-53
-------
Chart 25. REACTOR TANK CAPACITY
DOUBLE ALKALI SCHU33I1IG
C-54
-------
SODA ASH STORAGE AND OPERATING SILOS COSTS
From page C~9,item
—_lb/MM BTU of Soda Ash |132|
From data sheet, maximum continuous heat input MM BTU/hr
134] Ib soda Ash/hr
X
[134
Soda Ash ton/hr
134
2000
1341
2000
ton/hr
Enter item |135| ** on Chart 17 on [82J and move vertically upward
to item [83] , then move horizontally to JJJ4J and read
Cost of operating silos = $
Storage Silo Costs:
136
Enter item J135J on Chart 17 on [82| then move vertically upward
to [85| , then move horizontally to the left to |84| and read
Cost of 12 day Storage Silos = $
136
B
Soda Ash Cost for Start-up: (12 day storage + 3 day operation)
135 x cost of Soda Ash $/ton* x 24 x 15 =
135]
-x 360 = $
137
* Obtain from data sheet.
** If [Us] is less than 4.7 ton/hr use the table below for Storage Silo
Costs:
Ib/hr of
0 -
501 -
2001 -
5001 -
Soda Ash
500
2000
5000
9400
$ 138
9,000
15,000
36,000
65,000
DOUBLE ALKALI SCRUBBING
C-55
-------
SOLID DISPOSAL
To find the cost of clarifier and vacuum filtration equipment and
pump combined, Chart 26;
Chart 26 gives the cost of the following system and limitations:
Clarifier 150 ft diameter
Overflow pump head, 250 ft
Under flow pump head, 250 ft
Filtrate-return pump head, 350 ft
Sludge pump head 1000 ft
Under flow emergency pump
. Vacuum filter, 50 ton/hr
Sludge mix tank and mixer
Water make-up pump
Enter item [T7^(dry sludge, ton/hr), from page.£-12 Chatfc 4 on 135?;
Select number of clarifier units, same size (each 50 ton/hr of dry
sludge requires 1 clarifier unit) = units |140[
From item J139] move vertically upward to item |141| ( Bhp system
curve), then continue upward to item [142 (equipment cost curve).
From item tl4lj move horizontally to the right to item |143| for hp
of equipment.
hp of equipment x No. of units = total hp required=_
x
_hp 144
From item [142| move, horizontally to the left to item 145 for equip-
ment, $ /unit 145|
Item [145| x item |140f = total cost [146
x = $
DOUBLE ALKALI SCRUBBING
C-56
-------
1 x 10
1 x 10
•«/»•
3
i x 10
i'i|i n in 11 ii i MM ii rul0,000
1 x -in^ ,[ i i I i .. i i i t I I I i I I I I I I I I i I I I I 11 I 1.1 I I I ill I I I I I I I I I.I I I I I I I 0
, x (U M , , , . , . . yQ. 2-Q -- j— — gg
ton/hr SLUDGE DRY FOR SOLID DISPOSAL
Chart 26. SOLID DISPOSAL COSTS
DOUBLE ALKALI SCRUBBING
C-57
-------
POND ACREAGE AND POND EXCAVATING/DIKING COSTS
To determine the cost of pond acreage, excavating/diking costs,
Chart 27:
(ton/hr dry sludge)
Enter from page C-12, Chart 4 on item
16
A
on Chart 26, item |l4?| then move vertically upward to the
respective weighted capacity factor, item |l48|
From item |.148| move horizontally left to item ,14 g (acre-ft/yr)
and reference line 150 and read:
149
Select remaining plant life on item
Connect items pL5-Q[. and [jL51| and extend to item (152J (pond acre-ft)
and read:
152
From item ]152| move horizontally left to item |15J3|. (pond reference
scale)
From item Jl53ymove vertically down to item |154[ (pond cost)
and read: $
|154 dry sludge
"If wet sludge, no waste return 1.67 x Jl52| =.
.pond acre-ft wet sludge 155
Enter item [155] on Chart 27. item [152]' and move horizontally left to
item
From item 153| move vertically down to item [X54[ (pond cost) and read:
$
156| wet sludge pond cost
Select proper item 154 or J156J and record as pond cost, $.
DOUBLE ALKALI SCRUBBING
C-58
-------
Chart 27. POND COST
-------
EQUIPMENT COST
Equipment
1. Absorber
2. Venturi and absorber
3. Venturi
4. Absorber and/or venturi
holding tanks agitators
5. Absorber and/or venturi
holding tanks
6. Circulation holding tanks pumps
7. I. D. fans
8. Heat exchangers
9. Soot blowers
10. Ducting
11. Bypass valving
12. Conveyors
13. Operating silos, Lime
14. Storage silos, Lime
15. Fixation silo
16. Slurry hold tanks
17. Slurry agitators
18. Slurry pumps
19. Slaker, Pump
20. Reactor tank
21. Soda ash operating silos
22. Soda ash storage silos
23. Solids disposal equipment
24. New roadways or RR siding at
$50/ft, estimated length
Cost, $
V+A
39
A
B
86
or
138]
Total equipment
cost $
DOUBLE ALKALI SCRUBBING
C-60
-------
Total equipment cost from page C - 60
Year of FGD system operation
Select from cost factor index multiplier from page C-6 2, for the
year above
Predicted costs:
(total costs) x (cost factor index multiplier)
( ) x ( ) = $
Predicted pond cost
= Pond cost from page C-58 x Cost factor index
multiplier
x = $
DOUBLE ALKAtl SCRUBBING c~61
-------
O
O
G
W
t*
W
CO
O
§
H
a
O
O
I
-------
CAPITAL INVESTMENT COSTS
Direct costs:
Select
"A" Me
"B" Lc
"C"
: system required
iterial
ibor
Retrofit
Easy
Moderate
Difficult
I
Absorber
"2.08" Aa
1.27 .\
Absorber S.venturi
2.07- .v*
1.28 :\
Materials and labor
Absorber
0
0.047X
0.093X
Absorber- venturi
0
0.039X
0.077A
Cost, $
.
A = Equipment cost, predicted from page C-61
"A" + "B" + "C" = $
"D" Raw materials:
item |87| plus .
item 1'
"E" predicted Pond-costs page €-61
= $_
"F" Direct costs ("A" + "B" + "C" ,+ "E") above = $_
"G" Direct costs ("A" to "E" inclusive) = $_
"H" .Direct costs ("A" + "B" + "C") above = $_
Indirect costs:
"J" Interest (at 8%)f contractor fees and expenses, engineering,
freight, off-site,taxes, start-up, spares -
CO. 33 "G") + (.0.1 "H") + CO. 065 "F") =
(0.33 x ) + (0.1 x ) + (0.065 x ) = $
"K" Contingency:
0.2 ("J" -I- "F") =0.2 ( +_
"L" Total costs for capital investment
J = $_
G" + "J" + "K" =
= $
Cost/Kilowatt:
L
MW's x 1,000
./KW
.x 1,000
DOUBLE ALKALI SCRUBBING
C-63
-------
TOTAL ANNUAL OPERATING COSTS
Utilities -
Water: Na+ scrubbing
64 gal./MW for 3.0% S coal
iA5.5 gal./MW for each ± 1.0% S ift coal
52 gal./MW for 2.0% S oil
±A-4 gal./MW for each ± 1.0% S in oil
Limestone:
Cgal./MW - gal./MW corr. for % S) x hr/yr x weighted capacity
factor x water costs/1,000 gal.
»
( 158
(
or
/Coal \ /
\or oil/; \
160 - ^.59 or 161
+
Base;% S \
% S corr./ ; 162
* ' /'
= Yearly cost water/MW 16
) x C.F.
$0.02
) x x 8760 x 1,000 gal. -
$ 16
•
x MW 163]
x . = . $ /vr
2
$/MW
2
163
Reheat:
From page r-^9f item
(see calculation sheet)
determine $/reheat
$
For AT
DOUBLE ALKALI SCRUBBING
C-64
-------
TOTAL ANNUAL OPERATING COSTS
Operating labor cost:
MW's
Men/Shift
100- 699
700-1200
1201-2500
2501-
3.16
3.33
4.5
5.33
Men/shift x hr/yr x $/hr = '|164
x 8760 x 6.50 =
x 56,940
1.64]
./yr
Corrected cost:
Supervision:
164| xf
$/hr (manpower j\=
6.50
./yr
Corrected cost:
Maintenance:
Capital costs, total
0.046 x = $.
164]
40 3
41 :
164
•c men/shift = ,!'(
K = S
, x 0.15 = $.
55
/yr
/yr
igs
165
16 61
Overhead:
Capital cost, total
(0.023 x
+ Men/shift
.) + (13,100 x _ ) =
)=
./yr
DOUBLE ALKALI SCRUBBING
C-65
-------
TOTAL ANNUAL OPERATING COSTS
Fixed costs -
A. 100 _ %/yr depreciation, straight-line
Plant life, yrs*
B Capital = %/yr
C. Taxes, insurance> interim replacement - 4.65%
Total fixed costs = A_^B_±_C_ _ Q> ^yr fixed costs
(Yr fixed costs) x (total capital cost) =
(0. ) xj 1.= $ /yr
Sludge disposal:
Pumping to another site, off-plant
MW KW/MW $/KWH**or*** .hr/yr x weighed CF
0.0016 x x 1000 x x 8760 x =
MW $/KWH** or *** Weighed CF
14,016 x x x = $ /yr
Truck disposal costs/14 miles:
ton dry sludge/hr ,•.•,-,-,„ , ,
8.47 tons dry sludge/true* hr X $17'2° X 1'1 x 876° x CF =
(57.25 min/trip) ($17.20/truck hr/driver)
From Chart 4, item [Tel, tons dry sludge/hr
16 , weighed CF
~ £^.
x 19,570 x = $ /yr
* Plant life, years: either remaining boiler life in years from start
of FGD system or 15 year life for FGD system, use lowest number of
years for life.
** ***
or see next page
DOUBLE ALKALI SCRUBBING C-66
-------
TOTAL ANNUAL OPERATING COST
Raw Materials -
Lime
Chart 37, item
^
weighed CF x $/tona = cost/yr.
.ton/hr CaC03 x hr/yr x
Chart 17, item 75 x hr/yr x CF x $/tona = cost/yr
. * 8760 *= $
Soda Ash:
item |135|
.ton/hr
cost soda ash/ton
from data sheets x 8760 x C.F. = $
Fixation
item 16
_, Chart 5,
A
hr/yr weighed
jtt. *IJ-/ i3- WG-i-yiicva
lb/hr dry sludge x Ib/ton x CF x $/ton" = cost/yr [173
x 4.38 x x = $ |173
Utilities:
Electrical, use appropriate
Lime-burning coal =
MW x x $/KWH* x Weighed C.F. x hr/yr = cost/yr
0.028 x x 1,000 x x
x 8760 = $
(174
MW $/KWH C.F.
2.31x 105 x x x = $.
(on coal/abs. + vent.)
$
/yr
174]
A+V
2*-08 x 105 x
x
/yr =
(on coal/abs. or vent.)
$ H74l
DOUBLE ALKALI SCRUBBING
C-67
-------
TOTAL ANNUAL OPERATING COST (Continued)
Lime — burning fuel oil =
MW $/KWH** CF
1.49 x _ x _ x _ = $ _ = $ _ _ 174
0
(on oil/abs.)
a If unknown use $6.32/ton
If unknown use $4/ton of dry sludge
** If unknown use 0.00675/KWH based on coal at $10/ton and 12,000 BTU/lb
*** If unknown use 0.0185/KWH based on oil of $8.40/bbl and 149,000 BTU/gal.
DOUBLE ALKALI SCRUBBING C-68
-------
TOTAL ANNUAL OPERATING COSTS
Summary Sheet
Item
. Cost, $
1. Water
2. Reheat
3. Operating labor
4. Supervision
5. Maintenance
6. Overhead
7. Fixed costs
8, Sludge disposal, pumping
9. Sludge disposal, trucking
10. Lime
11. Soda Ash
12. Fixation
13. Electrical
164
A+V
Totaj. annual operating costs
Cost per kilowatt-hour:
(total annual operating cost)
hr/yr x (plant rating in MW's) x 1,000 x (weighed capacity factor)
( ) = $ /KWH
8760 x (
) x 1,000 x (
, DOUBLE ALKALI SCRUBBING
C-69
-------
APPENDIX D
MAGNESIUM OXIDE SCRUBBING
NOTE: For purposes of clarity and continuity, Tables and
Charts have been numbered sequentially in this
.report with no differentiation between Tables and
Charts.
MAGNESIUM OXIDE SCRUBBING D-l
-------
INFORMATION REQUIRED
Boiler No.
Type of furnace
MW at maximum continuous
Age of unit , years
Life, years remaining
Capacity factor, yr.
Maximum continuous fuel,
ton/hr or gal./min
Maximum continuous,
MM BTU/hr
acfm at °F
Fly ash/total ash, %
Efficiency of existing
particulate control , %
»-
Cost of electricity/KW (Plant) =£.
Coal, cost/ton $
% sulfur by weight .
% ash by weight
HHV, BTU/lb
. Cost of water/M gal. (Plant)
= $
Oil, cost/bbl $.
% sulfur by weight
BTU/gal
Specific Gravity
S02 permissible
Fly ash permissible.
Ib S02/MM BTU
Ib fly ash/MM BTU
State or
Federal regulations
MAGNESIUM OXIDE SCRUBBING
D-2
-------
INFORMATION REQUIRED (continued)
Estimated land cost per acre (current) $_
Possible interference determining the location
of flue gas desulferization (FGD) system:
Congestion between stack and plant Q Yes Q No
Congestion between stack and/or clant with Q Yes Q No
property line, coal pile, etc.,
Identify problem areas and location:
Terrain.
Conduits.
Possible obstructions.
Source of MgO 'available.
i
and % purity .
MAGNESIUM OXIDE SCRUBBING D 3
-------
S02 EMISSION DETERMINATION
To determine the SO- emissions (Ib/MM BTU) in the flue gas,
Enter % sulfur by weight of fuel (oil or coal) on[Tj
Enter heating value of fuel (BTU/lb) on
Chart 1;
Connect 1 and 2 and extend to 31and read "and record:
31
S0~ emissions (Ib/MM BTU) in flue gas
or
»—
CO
UJ 5
to 6
24,
22
20
18
§ 16
i u
1Z
to
o
i— *
2 io
H"^
UJ
rt^ ^
*^\8 8:
••V
6
4
2-
0
UJ
2:
Z;
LJJ
o:
t * i
uJ
UJ
-<— ^
24^
- 22^
20i
18:
16
t4!
12
:
10
8
6
4
2
0
• §
. «j
*— *
: t—
• -Q
*
00
rr
o
to
s
UJ
• CM
• O
: to
Chart 1.
SO2 EMISSION DETERMINATION
Assumptions:
(1) 95% of sulfur in coal converted to S
(2) 100% of sulfur in oil converted to S0
MAGNESIUM OXIDE SCRUBBING
P-4
-------
S02 REMOVAL REQUIREMENTS
To calculate SO2 emissions (Ib/MM BTU) to be removed:
Enter from page_0z.4, Chart 1, item (Tithe Ib/MM BTU.
Enter from the data sheet, allowable S0? emissions
(Ib/MM BTU) from the State or federal regulations —
Subtract [_4j from |_3_| to calculate SO9 emissions
(Ib/MM BTU) to be removed
MAGNESIUM OXIDE SCRUBBING
-------
MAGNESIUM OXIDE REQUIREMENTS
To determine the MgO requirements (ib/hr) Chart 2;
H
Enter the SO- emissions (Ib/MM Btu) to be removed on
item
from page D-5, item [5J ; record_
Enter stoichiometric requirements for MgO on item [7
Connect
and
and extend to
and read and record:
MgO requirements (Ib/MM Btu)
8
Record from the data sheets the heat input (MM Btu/hr)
Multiply 8 by
and record:
MgO requirements (Ib/hr)
10
* If unknown, use 1.05
Multiply [6j by [9| and record: Ib S02/hr removed
MAGNESIUM OXIDE SCRUBBING
D-6
-------
0-r-
OQ
14
r—
A
Q - -
7--
8-: r
MgO
STOICHIOMETRIC
-r-10
o~
Ul
••r-5
- -4
. --3
o . -
f ::
Chart 2. MgO REQUIREMENTS - Ib/hr.
MAGNESIUM OXIDE SCRUBBING
D-7
-------
FLY ASH EMISSION RATE CALCULATIONS FOR VENTURI DETERMINATION
To calculate fly ash emitted:
If the fly ash emitted (Ib/MM BTU) in 13 after passing through an
existing particulate emission collector per boiler is greater than
the allowable rate from the data sheet, the use of venturi is
necessary. Use the following equation to calculate |13]
tl3J = ((% ash in coal )(% fly ash*> (1-n ) -=- BTU/lb 1 x 106 = Ib/MM BTU
10° 1DO c J
= 0. ) (0. ) (1-0. ) 4. 1 x IQ6 = Ib/MM BTU
where
n = Efficiency of particulate emission collector system
c
BTU/lb = Heat value of fuel (MM BTU/lb)
% ash = from the data sheet
*
If fly ash removal is required for any or all of the units VENTURI COST
•
CALCULATIONS will be used.
*If the percent of fly ash to ash is not known use the appropriate
tabulated values for the boiler under consideration.
Type boiler - coal-fired fly ash to ash, %
General pulverized 80
Dry bottom 85
Wet bottom 65
Cyclone 10
MAGNESIUM OXIDE SCRUBBING D~8
-------
SLUDGE GENERATED
To determine the dry sludge (Ib/hr) generated, Chart 3;
:*
From page D-8 , item [O] enter calculation of fly ash (Ib/MM BTU)
[HI
From data sheet, heat input maximum continuous rating, record
here as (MM BTU/hr)
Dry Sludge = fl3
14
[15] Ib/hr
Ib/hr
14]
15
2000
ton/hr
Enter |15| on |16| , Chart 3, enter %» by weight dry
sludge on 17
Connect 16 and 17 and extend to [18] and read:
fill
Wet Sludge (Ib/hr) =
Water returned from pond, Ib/hr = |19|
Ib/hr fl9|
*if unknown use 10%
MAGNESIUM OXIDE SCRUBBING
D-9
-------
Chart 3. SLUDGE GENERATED
MAGNESIUM OXIDE SCRUBBING
D-10
-------
VENTURI AND ABSORBER COSTS
To determine the costs of venturi and absorber (including demister)
using lime-, Chart 4;
First, determine number of scrubber trains -
Enter acfm at °F of flue gas from the data sheet on ^ , either
per boiler or combined plant total if °F is the same for all
boilers.
Enter temperature of flue gas (°F) on 21
Connect |20| and |2l| and extend to |22| and read flue gas acfm
at 125°C (saturated) and enter acfm at 125°F and sat. [22!
If acfm at 125°F is greater than 375,000 divide [22] by a number less
than 375,000 to give a whole number of Venturis and/or absorbers for
each boiler.
acfm per venturi and/or absorber (23J
[24] number of Venturis
and/or absorbers per
boiler or power plant.
A venturi, or an absorber, or a combination of a venturi and absorber
is sometimes called a train.
MAGNESIUM OXIDE SCRUBBING D-ll
-------
10
9--
8--
7--
6- -
O
-
--9
-1-10
|22|
D-12
-------
VENTURI AND ABSORBER COSTS
Then determine absorber costs (ho venturi required) Chart 5:
Enter item [22J from pageJ2r}.2chart 4 on Chart 5 on [25J
Enter for the absorber the cost factor of 1.1 on f26l
Connect |25| and |26| and extend to |27| and read absorber cost
$ [27]
Or determine venturi and absorber costs (if a venturi is required)
Enter item [2~2] from pageD^12Chart 4 on Chart 5 on f25l
Enter for venturi the cost factor of 2.Q on
26]
Connect |25| and |26| and extend to [27] and read venturi and
absorber costs $
V + A
Or determine venturi costs (no absorber):
from pageo=_JL2Chart 4 on Chart 5 on |2!
\26\
Now enter item
Enter the venturi cost factor of 0.9 on
Connect |25| and |26| and extend to |27| and read venturi costs
$
MAGNESIUM OXIDE SCRUBBING
D-13
-------
0-r-
24-
< 4
-------
HOLDING TANK CAPACITY
To determine the holding tank capacity for absorber and/or venturi
Chart 6:
Enter flue gas acfm from page D-ll, item |3] on Chart 6,
item [29]
Enter L/G* (liquid flow rate, gpm/1000 acfm at 125°F) on Sol
Connect
29 and
and extend to |31 , read and record:
Liquid flow rate (gal/min) |3lL for absorber
Liquid flow rate (gal/min)
Enter retention time on 32| **
3lL for venturi
Connect 31 and 32
and extend to 33 , read and record:
Tank capacity (gal) per absorber
(gal) per venturi
A
V
*If unknown use L/G - 40 for absorber and L/G =15 for venturi
**If unknown/ use 10 minutes for absorber and 4 minutes for venturi,
MAGNESIUM OXIDE SCRUBBING
D-15
-------
1 x lot—
-r-1 X 103
1X1 O
Chart 6. FLOW RATE AND TANK CAPACITY
MAGNESIUM OXIDE SCRUBBING
D-16
-------
HOLDING TANK AGITATOR COSTS
To determine the cost of agitators per tank, fable 7;
Compare tank capacity (gallons) from page_jQ=.16r~Chsrt.6*v
and/or |33| ^ on Chart 7 under tank capacity in gallons column
and record:
Cost of agitators per tank - absorber
venturi ,
Total cost of venturi and/or absorber:
34|
34
33
( [34] + 3
+..
4 v ) x No. of venturi or
v absorbers from item |24
) x - $
.
35
Table 7. AGITATOR COST
Tank capacity, gal.
0 to 34,000
34,000 to 67,000
67,000 to 101,000
101,000 to 135,000
135,000 to 162,000
162,000 to 188,000
188,000 to 220,000
220,000 to 251,000
251,000 to 283,000
Agitators
No.
1 -
2
3
4
5
6 .
7
8 -
9
34 Aor [34 y, cost, 5
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
MAGNESIUM OXIDE SCRUBBING
D-17
-------
o
cn
H
C
5
o
X
H
O
£J
CO
o
w
H
a
o
TABULATE THE COST OF TANK, PUMP AND AGITATOR AS BELOW, IF VENTURI IS REQUIRED,
PREPARE SEPARATE TABLES FOR VENTURI AND ABSORBER. PLANT TOTALS
39
49
,, AND
SHOULD INCLUDE ABSORBER AND VENTURI EQUIPMENT.
Boiler
No.
®
Flue
gas
rate,
acfm
(D
Flue
gas
temp,
F.
©
Flue
gas a
125° F,
acfm
©
No. of
trains
(D
Flue
gas rate
@125°F
per train
®
Tank
cost
per
train,
$
©
Tank
cost
per
boiler,
$
(G)X(E)
Total/plant
Pump
cost
per
train,
$
®
Pump
cost
per
boiler,
$
(H)X(E)
Agitator
cost
per
train,
$
(j)
Agitator
cost
per
train,
$
(j)x(E)
on |4 91 "? S
•*=* m \*y\ m J-> m
D
I-1
oo
-------
HOLDING TANK COSTS
To determine the tank cost the values in the chart are based on
2
using $12.50/ft for a field-fabricated, rubber-lined tank, Chart 8;
Enter tank capacity (gallons) on |36| from pageJDz.l6,_.Chart 6,
items [3~3
and 33
v, move vertically to [37
From |3-7| move horizontally to [38J , read and record:
Tank cost per absorber $
38
Cost per venturi $_
38]
V
Total Cost:
|38| v )x No. of absorbers [24] = cost of holding tanks
Jx
= $
MAGNESIUM OXIDE SCRUBBING
D-19
-------
1 ' i I" ii I I M I'MI'I'I'I i i i i |ini| i | i | il'l'l'l'l ' i ' ' l"ii|
1 x 1Q3' -' ' ' ' I" ' 'I I I | I i Ii lililll i i i i 111111 i I i 11 lililihl i i | i 111
1 x 103
1 x 104
TANK CAPACITY, gal.
1 x TO5
il
Chart 8. HOLDING TANK COSTS
MAGNESIUM OXIDE SCRUBBING
D-20
-------
HOLDING TANK PUMP COSTS
To determine the total pump cost for absorbers and/or venturi, Chart 9:
Enter gpm . on [To] from page_Drji,6Chart 6, item |3T| a for the
A
absorber and J3l] v for the venturi. Select minimum number of
pumps on [4l| (note 10,000 gpm* per pump is maximum), use minimum
number of pumps* per train and add 1 spare pump per tank.
Connect [40] and [4l] and extend to J42J , read and record:
Flow rate (gpm) per pump_ absorber; venturi
Tabulate: No. of pumps
Absorber
Venturi
gpm/pump
[24]
No. of trains
For total pump cost for venturi and/or absorber
A'
Enter 41 . ,
41] v on [43JA, [43
V
Connect
42 and 43
and extend to 144] , read and record:
Connect |42| and [43] v and extend to |44| , read and record:
. Variable cost per pump $_
.absorber; $_
44
_venturi
* If gpm per pump is less than or 5,000 gpm calculate cost as follows:
record gpm from page_D=a6 Chart 6 item |3l| A for the absorber.
and item |3lJ v for the venturi_
number of trains from pageJirll item [24]
) x (. (24) ) = $ [47]
) x ( - ) = $
45
46
number of pumps per train 1+1 spare
absorber pump costs: 2 x .79 x (
1.58 x (
1.84 X ( [HI ) x ( [24] ) = $ [47] y
1.84 x ( _ ) x ( _ ) = $ _ [47] v
MAGNESIUM OXIDE SCRUBBING D-21
-------
HOLDING TANK PUMP COSTS (Continued).
Pump costs, total: from calculations [(1 gpm to 5,000 gpm per pump)]
— £
49
Pump costs, total: from Chart 9 Q 5,001 gpm to 10,000 gpm per pumpf]
EHy + [481A
+ = $
49
MAGNESIUM OXIDE SCRUBBING
D-22
-------
40,000-r
36,000+
32,000 +
28,000+
a
en-
24,000+
O
u.
20,000+
16,000+
12,000+
8000+
50004-
0-L
*•!
«•
»
•M
E
CL
O>
•V
O.
IT
— j
Q- •
O .
_l •
u_ -
•
\j
"
ftp
••
r°
-1000
' /
-3000 ' ' /
: 4 PUMPsY
J-4000 /
i 3/PUMPS\
-5000 /
;• /
: /
-6000 / 2 PUMPS V
: 4
1
-7000/
/ . 1 PUMP\
-8000
-9000
-10,000
•i
>fc ~
v
m
V
LU
CJ -
z :
LU
o; . :
LU
1 1 . ;
LU ;
C£. -
••
•
^
V
•*
••
j-65.000
• ^
-
•
j-60,000
-.
m.
^ —
i-55,000
• ;
. •
-so.ooo ;
• _
•
U5. 000 :
. -
«•
UO.OOO :
* ••
-35.000 :
• • *
r M
-30,000
' —
-23,000 \
_
rZO.ooo :
• *
ris.ooo -
-10,000 "
»
-5000 ~
»
-o ;
r-60.000
j-55.000
: 50.000
"
j-45.000
~: 40,000
:35,000
730.000
-25,000
: 20, 000
M5.000
-10,000
-5000
-0
ID 44] 44) gl
Chart 9. HOLDING TANK VARIABLE PUMP COSTS
MAGNESIUM OXIDE SCRUBBING
D-23
-------
FAN COSTS
To determine fan costs, Chart 10;
Enter acfm at °F of flue gas from the data sheet on [5~OJ
Select appropriate curve for pressure drop on [sT]
Move vertically from |50| to [51| and then from |5l| horizontally to
52| read and record:
Fan costs $
52
Typical pressure drops: Absorber 19" (16" -I- 3M);
Absorber and venturi 28" (25" + 3")
MAGNESIUM OXIDE SCRUBBING
D-24
-------
8
H
§
o
X
H
D
W
03
O
H
a
o
o
i
N>
(J1
I t t t 1 1 1 I I I ! ! t I t i r I ! I t I T f I 1 I I t I I ! I 1 f I f I ! I l__t_l_t l_LJ_t tlllll MFIItltllllfllirfl
XI0° acfm AT °F
Chart 10. FAN COST
-------
HEAT EXCHANGER COST
To determine heat exchanger cost, Chart lit
Enter item |22| from pageJD^12Chart 4 on Chart 11 , item [53
Move vertically upward to item |54|
From (541 move horizontally to the left to |55| , read and record;
Cost for heat exchangers $ [55]
*If unknown, use AT = 50°F
MAGNESIUM OXIDE SCRUBBING
D-26
-------
""''""l'' ' ' I1'M|iiii|ini| iimii|i| MM iiiiiniiiiiiiin
1 x in3h i i i in i iiiminiii. in I i i i i lii i ilmUnil i I ill lilil i II i Inn
1 x 104 1 x 105 1 x 106
acfm AT 125 "F
Chart 11. HEAT EXCHANGER COSTS
MAGNESIUM OXIDE SCRUBBING
D-27
-------
SOOT BLOWER COST
To determine soot blower cost, Chart 12;
Enter item 53) from page_D.-ll • on Chart 12, item 56
Move vertically upward to [57
From [57] move horizontally to the left to |58| and reads
Cost per train §__
From pageJi-11, item 24 record, number of trains
Cost Okf soot blower
— HI = HI
$
X
X.
.= $.
MAGNESIUM OXIDE SCRUBBING
D-28
-------
70,000
60,000
50,000
o:
UJ
CO
a:
o
to
00
40,000
UJ
O
CO
30,000
o
o
20,000
,10,000
Ql i I I i i i
'I'l i | i ' i i i i i i i | i i i i i i i
2500 fpm GAS VELOCITY
100,000
..it i iii
• I ' ' • •
200,000
'..'.* * • 'ii
300,000
_L
400,000
acfm AT 125°F AND SATURATED
500,000
(561
Chart 12. SOOT BLOWER COST
MAGNESIUM OXIDE SCRUBBING
D-29
-------
REHEAT COST
To calculate the cost of reheat, Chart 13;
Enter acfm at 125°F and saturated of the flue gas from page D-12
Chart 4, item (22) on Chart 13, item |60|
Select and enter AT* of reheat on item 61
Connect items |60| and |6l| and extend to item |62
Enter costs ($/MM BTU) reheat from calculation below_
_on
item 63
Connect items [62] and f63| and extend to item [64| , read and
record:
Cost ($/hr) reheat
64
Annual reheat cost:
64
Weighted capacity
factor from data
sheet, "
.x 8760 hr/yr x 0..
= reheat cost/yr 165]
= $ |65l
*If unknown, use AT = 50°F
**Reheat Cost -
Coal: To correct from 12,000 BTU/lb and $10/ton
=665 x ($/ton)
BTU/lb.
= $.
./MM BTU
Oil: To correct from 149,000 BTU/gal. and $10/bbl
=31,707 x ($/bbl)
.BTU/lb
= $
/MM BTU
MAGNESIUM OXIDE SCRUBBING
D-30
-------
1 x 10
••
••
<•
••
g 1 x 106-
t-
2 -.
ID
i_
<
O "
< -1
>-
o:
a j
u. ~
O
in
CM
i—
t-
<
^
S 1 x 105-
«•
••
*•
••
HUH
•«•
4HI
«•
1 x 104-
[6
*•
V «
_
-• ••
^ m
* ™
• .
• *•
^
^ .
A
IP
.
••
ta
•••
V
*
•> ™
A
HP
: +33 -F ^;
^^,
: B "
- ^4- «;(V-*F •>• tir '
__— — — - — ^— • T3lr r ' CO •
[ +75 »F i ;
: t :
AT g J
•ac :
LLI :
C£ -
6l| j
••
* _
_ —
^
•>
!••
-
••
. —
•" .
. -
• •
V
•* •
.
«
^ •
••
• VI
^
— •>
^
••
-i
«•
«•
p— ^
» ^
_ «•
• ^
-2 =
^m
• _
* «
• OH
• V
-3
.
•• ^
-4
• ^
U :
:6 r
-7 Z
-8 -
-9
-10 :
*• _
^
.
_ -
-20 => -
h-
:\ J |— ;
r3o^s. ^. *-.-
\^ •€/* 3- ~ -
-40 ^\ - 2-- ^
: \t; .. -
-50 ^, :
: C£\l- -
-60- sz x l
:7o So.sJX,. -
rso £. X j
-90 a: \
-•inn X.
-100 r4\ \
63 1 X^:
«
••
-200 :
«
rsoo -
TI ^
• j •*
r*00 i
=•500 •:
-600 '•
-700 "
-800 J
^900
HOOO
••
oi 62 y
.10,000
-9000
rSOOO
r7floo
-6000
rSOOO
=•4000
r3000
^2000
-1000
-900
-800
-700
-600
rSOO
§400
— »—
~ -c
r300 ^
h. A
-290 {-
01
o
o
(_
^90 3C
r80. ^
C-70 tt
-60
r50
E-40
r30
!•
:20
-10
^
-6
^5
- *
r^
r3
V
w
*
^
•1
-1
S]
Chart 13,
MAGNESIUM OXIDE SCRUBBING
REHEAT COSTS
D-31
-------
DUCT COSTS
To calculate ducting cost:
Assumption-
The length of flue duct from the main discharge duct to the
venturi (if used) is variable in feet and also the return to
the main discharge duct after SO- and/or particulate removal.
For the specific boiler if more than 1 venturi and/or absorber
is required use the multipliers listed in Table 14. Compute each
boiler separately, unless identical to each other in absorber or
venturi acfm at 125°F and saturated.
From data sheet,
acfm at °F
2 2
Area duct (from main) in; = ft = 2x
3,500 ft/min
Perimeter length:
2 * 2
\* = = ft"1
•V-
ft2 = ft
6A = 6x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.39/lb =
7.02 x ft perimeter = $ cost/linear ft |66j
Pacje D-12, Chart
.4, item [22
2 2
Area duct (to main) out: = ft = 2x
2,500 ft/min
Perimeter length:
A =|/ ft2 = ft
6A = 6 x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.445/lb =
8.01 x ft perimeter = $ cost/linear ft [§2
MAGNESIUM OXIDE SCRUBBING D-32
-------
DUCT COST
Table 14. MULTIPLIER FOR DUCT COST
No. of absorbers
and/or Venturis
per boiler
1
2
3
4
5
6
7
8
9
10
Venturi and
absorber
in
110
190
250
305
356
410
453
490
535
579
'• * •
Venturi or
absorber only
in
70
114
180
225
266
310
346
378
415
452
•— ^^— • fc i • • .!•
Venturi plus
absorber
out
70
113
143
175
205
235
262
288
315
343
!• -^^^^Hl ll»^^^»»» II [••••••••••.^^
Venturi or
absorber only
out
50
93
123
155
183
208
242
268
295
324
Duct cost in -
/ Estimated ft to
(in) cost/ Table 14 + main duct*-30'
linear ft Imultiplier :
Iccl v( j. -30'
= Duct cost (in)|68|
\ _
Duct cost out -
Estimated
distance to
(out) cost/ Table 14
linear ft x ^multiplier main duct**-5Q'l
Duct cost (out)|69
.x (
Total duct cost -
68] duct cost (in) + J69] duct cost (out)
$ + $_
= |70| total duct cost
.= $ (70l
* If congested area add 230 ft for estimated ft.
** If congested area add 200 ft for estimated ft.
MAGNESIUM OXIDE SCRUBBING
D-33
-------
FLUE GAS SHUTOFF AND BYPASS VALVES
To calculate flue gas shutoff and bypass valve costs:
Assumption-
Based on 4 vanes/axis in short dimension based on height of 20 ft
and width of 10 ft..
Stainless steel at $141.6/ft; carbon steel at $99.I/ft2 ; fabricated
Flue gas valve (in) at main duct to create a bypass
From the data
sheet acfm at / -5 2
°F /Boiler = ft2 = 2w
3,500
W = l/ ^ ft2; W x 2 = jc 2 = height, ft, H.
Valve cost A = (1.5 x H) I(99.1)±* (3.1) (H-20) (O.SH-IO)J
*H greater than 20 ft, sign is +, less than 20 ft sign is -
H H H
= (1.5 x ) [(99.1)± (3.1) ( -20) (0.5 -10)]
= $ carbon steel ["78
•
Flue gas valve (out) at main duct to create a bypass
/•I 1_ _. — J_ A
Chart 4
item [22] acfm / \22\
^4- Q TT /
500 /Boiler = -2-5QO = ft2 = 2w2
= I/
ft2; W x 2 = _ x 2 = _ ft (height H)
(H) CHI CHI
Valve cost B = (1.5 x _ ) [(141. 6)±* (4.5) ( _ -20) (0.5 _ -10)]
= _ stainless steel
'79
Flue gas valve (in) to absorber and/or venturi train
Chart 4
item [22 acfm at / „
°" /Boiler = Area, ft
24 (No. of Venturis or absorbers) x 3,500
MAGNESIUM OXIDE SCRUBBING D-34
-------
FLUE GAS SHUTOFF AND BYPASS VALVES (continued)
22
.x 3,500
_= Area, ft2 = 2w2
W
ft- ?• W x 2 =.
x 2 =
_ft, height (H)
Valve cost C
= (Height (H) * 0.5 Height (H) [(99.1)-(3.1) (H-20) (0.5H-10)]
'(H) (H) (H)
= U.5 x ) [(99.1)-(3.1) ( -20) (0.5 -10)]
= carbon steel [go
Valve cost D =
/ - .._. , Chart 4:, item glj \
\No. of Venturis and/or absorbersj x (valve costp (8~b~|) = [8T
= ( : ) x ( ) = $ gj'
Flue gas valve (out) from absorber and/or venturi
Chart 4, item [23] /
1.08 acfm at 175°F / ? *2
2,500 , _, /Venturi and/or absorber = ft^ = 2w
0.000432 x
ft'
. 2
•ft2; W x 2.
.x 2 =
.ft,(H)
Valve cost^ <=
fc
(H) .(H) (H)
= (1.5 ) [(141.6)-(4.5) ( -20) (0.5 -10)]
= $ _stainless steel |82J
Valve cost,, =
r
^No.
= (_
.Chart 4,item
\
of Venturis and/or absorbers/ x (valve cost |92| ) =
x (
.) = $_
m
Valving cost per boiler
Valve cost- =
78
V
A
V
B
V
[83J
V,,
— C
total valve cost
MAGNESIUM OXIDE SCRUBBING
D-35
-------
FLY ASH SLUDGE PUMP TO ASH POND COSTS
To determine the total pump cost for Venturis, Chart 15:
Enter from page D-10Chart 3, item 18 on Chart 15, item [85
Enter head in feet on item |86| , if unknown and distance from
pump to ash pond is approximately 2000 feet and level use
150 foot head, if another head is used enter on item [86] and
record "'• [86] ;
Connect |85| and |_86j and extend to [87
Enter specific gravity of sludge on item
, if unknown use
1.1, if another specific gravity is used enter on item
and record 3k
Connect [87J and [88| and extend to (89|
Connect [89| and |90j and extend to [91[ , read and record
cost per pump $
Total pump cost:
spare = 2 x [91] = Total cost [91
2 x
T
MAGNESIUM OXIDE SCRUBBING
D-36
-------
-r-40000
^6000
..6500
§
Chart 15. Pump Costs
MAGNESIUM OXIDE SCRUBBING
D-37
-------
FLY ASH RETURN WATER PUMP
To determine the total pump cost for water return
Record from page_D=LO Chart 3, item |19 ; Ib/hr
Total pump cost:
( 1 pump
plus 1 Chart 3,.
spare) item [19
£200
y
Chart 3
x TTTnr x 0.04314' = $ pump cost [92
item [19|
0.0433 x = $ pump cost |92|
MAGNESIUM OXIDE SCRUBBING D-38
-------
WATER MAKE-UP PUMP
Record from page D-12 Chart 4, item [22] ,• _acfm at 125" F
Pump cost:
2 x 0.167 Ib HgO/hr/acfm x acfm at 125°F [22
500 Ib/hr/gal/min. —Vx0.03&l -x200=:$ [93]
Chart 4.
item [22]
=«0.0048 x = $ [93]
MAGNESIUM OXIDE SCRUBBING
D-39
-------
MgO, 3 DAY OPERATING AND 12 DAY STORAGE SILOS
To determine the cost of the material handling equipment including the
following; silos, bucket elevators, conveyors, trippers, in-ground
receiving hoppers and weigh feeders to slurry tanks, Table 16.
Ib/hr MgO
Record from page D-7 Chart 2, item |10| or [10| ;
= ton/hr MgO
or
10]
2000
Table 16.
Compare [94] with Chart 16 ton/hr MgO column
94]
ton/hr MgO
0 - 0.5
0.5 - 2.5
2.5 - 6.25
6.25 - 10.83
10.83 - 21.67
21.67 - 33.3
33.3 - 44.17
44.17 - 55.42
55.42 - 66.67
66.67 - 90
95
25,700
35,100
44,400
53,700
63,100
72,400
96,300
96
102,800
140,400
177,600
214,800
252,400
289,600
385,200
97 '•
36,600
41,800
47,000
54,800
61,400
64,800
66,900
[98
9,000
15,000
36,000
165,000
217,300
269,000
323,300
376,900
426,800
548,400
Select tonnage range that |94] would encompass and move horizontally
to the right to column [98] read and record:
98]
MAGNESIUM OXIDE SCRUBBING
D-40
-------
SLURRY PUMP AND TANK COSTS
To determine the slurry tank and pump cost, Chart 17;
Enter from pageJD-? Chart 2, item [To) -onChart 19 item ~99—
move vertically to item [Too] and then horizontally to the
left for tank and pump cost $
MAGNESIUM OXIDE SCRUBBING D-41
-------
175,000
w
w
H
i
o
X
H
a
en
o
§
ra
w
H
2
O
O
H*
to
150,000
a.
ex:
ce.
to
8
75,000]
50,000
25,00
20,000 40,000 60,000 80,000 100,000 120,000 140,000 160.000
Ib/hr MgO [99]
Chart 17. SLURRY PUMP AND TANK COST
-------
CENTRIFUGE
To determine centrifuge costs, Chart 18;
Enter from page D-12Chart 4, item \22\ on Chart 18 item |102|
Connect item |102| with the percent sulfur on Il03l,
extend to 104 , read and record:
1Q4|
Enter |104| on |105j and move vertically to 106 and from
[106| horizontally to [107| , read and record
Total centrifuge cost $
MAGNESIUM OXIDE SCRUBBING
D-43
-------
M
CO
H
§
o
X
H
o
M
CO
o
w
H
a
o
1.400.000..
Chart 18
0' 100,
......... • 11111111 MI M» i« i MI ' i' I' 11 in' f»• •' i • ij i itt-" 'M'.tJJ'' • 'It.'if*''' Mi'JA*'' 'J '.ll'J-'" 'J Vll'J'_" 1' LJ_*
.MO MO.OOO 3M.OBO 46o.oa5 oo.ooo fljo.ooo T5o.OH 86TJ.6M Wllow T.ow.oA T.100.6W V.jM.ooo
Ib/hr of bleed-off
Mg S03-x H20
Chart 18. CENTRIFUGE COSTS
-------
DRYER
To determine dryer costs, Chart 19;
Enter from page D-44 , Chart 18, item [l04[ oh Chart I9~Tteitf
Move vertically from item |108[ to |109| and then horizontally to
1110.1 i read and record
$
MAGNESIUM OXIDE SCRUBBING
D-45
-------
g
w
en
H
a
3
o
X
H
a
M
en
o
§
w
w
1,500,00
1,250,000
o 1,000,000
CO
o
750,000
500,000]
250,000
o
i
*-
a\
nft i T r r i i i i I t > i ^ i I i i i I i I i i I I I I i i i i i i i i i i I i 1 i t i i i i i t i i i i i i i i i I i i i i i i 11 i I i i i i i t i i i I
(jl 200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 T7600,000
Ib/hr BLEED-OFF [?08]
Chart 19. DRYER COSTS
-------
CENTRATE TANK AND PUMP
To determine costs for centrate tank and pump, Chart 20:
Enter from page D-44, Chart 18, item |l'04| on Chart 20, item 111]
Move vertically to [112| and from |112| move horizontally to [113|
read and record costs of 2 tanks and 2 pumps with a spare pump
$ [1131
MAGNESIUM OXIDE SCRUBBING
D-47
-------
o
2
W
01
o
X
H
D
W
CO
O
§
to
w
H
2
O
70,000r
• ~ "ft i i..... r....t i i J...1 i 1 I....I IT* i i
ii i t i i i I i iiit fii » t 111 i i t i i i I i i i i t i t I i I i t
5,000 800,000 1,000,
lb/hr BLED-OFF
1,200,000 1,400,
rrm
i i
1,600,000
o
oo
Chart 20. CENTRATE TANKS & PUMP COSTS
-------
BREAKER HAMMERMILL/RUN OUT CONVEYOR/STORAGE SILOS
To determine cost of breaker hammermill, 24 foot vibrating runout
conveyor, bucket ;elevatory MgSOa storage silo and coke storage silo
with bucket elevator, and in-ground receiving hopper, Table 21.
t6h/hr of MgSO3 =
%S in coal
0.00137 x from data
sheet
Ib/hr coal
x from data
sheet
= 0.00137 x 0.
Table 21
ton/hr MgSO^
115
0
1
1.67 -
2.5 -
3.33 -
5
6.67 -
j
1
1.67
2.5
3.33
5
6.67
8.33
8.33 - 10
10 - 13.33
13.33 - 16.67
16.67 - 20
20 - 25
Mill and
vib . conv .
116
12,500
12,500
12,700
12,700
13,000
13,100
13,200
13,400
13,600
13,700
14,100
14,300
Bucket elev. ,
conv . and
tripper 117|
5,600
5,700
5,800
6,000
6,200
14,300
14>frOO
14,9a0
18,500
19,400
20,100
21,700
MgSO, storage
siloS 118 $
1/9000
1/12,000
1/15,000
1/18,000
1/21,000
2/18,000
2/21,000
2/24,000
3/21,000
3/24,000
4/21,000
5/21,000
Coke storage
silos and
Bucket elev.
119
14,600
14,600
14,600
14,600
14,600
14,600
14,600
14,600 -
14,600
14,600
14,600
14,600
Total
cost
|120
42,000
45,000
48,000
51,000
55,000
78,000
84,000
91,000
110,000
120,000
133,000
156,000
If [H4] is greater than 25 ton/hr divide |114| by number of whole units
required
(equal to or
s = less than
25 ton/yr)
122|
MAGNESIUM OXIDE SCRUBBING
D-49
-------
BREAKER HAMMERMILL/RUN OUT CONVEYOR/STORAGE SILOS {continued)
Enter |114| or [122] in column [115] Table 21, selecting the proper
ton/hr, then move horizontally to column [120] , read and record:
$ " [120]
If [122| is used:
x
121
= Total cost
_
-------
DRYER DUST COLLECTOR, BAGHOUSE AND BLOWER
To determine the costs of dryer cyclone dust collector, fabric
baghouse and blower, Chart 22:
From page.D-44 item |104| , read and record
Ib/hr bleed off
If item |104| exceeds 1.6 x 106 Ib/hr;
104| =
Enter item |104| or item |124| on Chart 22, item [125] move
vertically upward to |126| and then horizontally to fl27| ,
read and record:
Cost of equipment $_
127]
Total cost:
x
x
124]
cost of dust collector,
= baghouse and blower
* $ [128"
MAGNESIUM OXIDE SCRUBBING
D-51
-------
o
H
H
a
en
o
w
(0
H
2!
O
600,000
500,000
400,00
300,000
200,000
100,01
200,
' '','''II' ' " 'J ''JLU ' "J 'jJ 'JJJ' '.'*' '.'"L." ' " L1 '*''' I'JjJ
600,000 800,000 1,000,000 1,200,000 1,400,000 TTBW.OOO
BLEED OFF, Ib/hr
01
to
Chart 22. DUST COLLECTION
-------
CALCINER
To determine the costs of a calciner, Chart 23;
Enter from pageD-44 Chart 18 item |104| on Chart 23 item [129]
move vertically to item [130| and from item [130
horizontally to item [13l| , read and record
Calciner cost,$
CYLCONE DUST COLLECTOR AND FABRIC FILTER BAGHOUSE AND BLOWER
To determine the costs of the dust collectors and blower:
From page D- 52
Chart 22
Item
128|
Read and record
x 0.9 = $
dust collectors and
blower cost
MAGNESIUM OXIDE SCRUBBING
D-53
-------
I
en
H
G
3
O
X
H
a
M
en
O
a
w
to
H
a
o
3,000,000
2,500,000
2,000,000
1,500,000
1,000,000
500,000
' I
Xfl
I I I I I I I I I I I I I I
200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000 1,600
Chart 23. CALCINER COST
-------
HAMMERMILL/RUN OUT CONVEYOR/STORAGE SILOS
To determine the cost of the hanunermill, run out 24' vibrating
conveyor, bucket elevator, MgO storage silo and discharge
unit, Chart 24;
From page D-49,Table 21 item |114| record here
x 0.39 = ton/hr MgO |133
x 0.39 =
133 ton/hr/MgO
Enter [133| on Chart 24, item [I34l and move vertically upward to
135| and then horizontally to |136| , read and record
$
136|
cost MgO storage
silos, conv., mill
MAGNESIUM OXIDE SCRUBBING
D-55
-------
800,000
700,000
600,000
500,000
•400,000
300,000
200,000
100,000
i 111 i i i i i i i i i I i i i i i i i i i ( i i i i i i i i i i i
20
40
60 80
MgO, ton/hr
100 , , 120
140
Chart 24. MILL/CONVEYOR/SILOS COSTS
MAGNESIUM OXIDE SCRUBBING
D-56
-------
POND ACREAGE AND POND EXCAVATING/DIKING COSTS
To determine the cost of pond acreage, excavating/diking costs,
t
Chart 25i
Enter from page D-10 Chart 3, item 15 (ton/hr dry fly ash) on Chart
" A
item [137[ then move vertically upward to the respective
weighted capacity factor, item
From item [l38J move horizontally left to item \J39\ (acre-ft/yr)
and reference line .140 and read:
.1139
Select plant remaining life on item [141J
Connect items [140| and |1.4J| and extend to item [142] (pond acre-ft)
read and record:
L42|
From item [142[ move horizontally left to item PL43] (pond reference
scale)
From item [143| move vertically down to item |l44| (pond cost)
_ *
read and record:
L44
dry sludge
*If wet sludge, no waste return 12.5 x J142J =.
_pond acre-ft wet sludge[.14.5
Enter item |145| on Chart 24, item $A2\ and move horizontally left to
item 143
From item [143) move vertically down to item p.44:| (pond cost) and read
$
and record
L44 TT wet sludge
~——-* w
Select proper item [l44[?or 114-4^and record as pond cost, $_
MAGNESIUM OXIDE SCRUBBING
D-57
-------
10.000,-
USt THIS HEFfRtNCE LINE
fffl! HMD LIFE SIZE
Chart 24. POND COST
-------
EQUIPMENT COST - MgO
Equipment
1. Absorber
2. Venturi and Absorber
3. Venturi
4. Absorber and/or Venturi holding
tanks agitators
5. Absorber and/or Venturi holding
tanks
6. Circulation holding tank pumps
7. I. D. Fans
8. Heat exchangers
9. Soot blowers
10. Ducting
11. Bypass valving
12. Sludge pump
13. Water return pump
14. Water make-up pump
15. 3 and 12 day storage silos
16. Slurry pumps and tank
17. Centrifuge
18. Dryer
19. Centrate tank and pump
20. MgSO, storage silos/ conw hammermill
21. Baghouse, dust collector, etc
22. Calciner
23. MgO storage silo, conv. hammermill
24. New roadways or RR siding at $50/ft.,
estimated length
Total equipment cost •$
MAGNESIUM OXIDE SCRUBBING
Item
[27l ,
Cost $
V+A
T
I [84]
or
or
D-59
-------
EQUIPMENT COST
Total equipment cost from page D- 59
Year of FGD system operation
Select from cost factor index multiplier from page D-61 for the
year above
Predicted equipment costs:
(total costs) x (cost factor index multiplier)
( ) x (_____ ) = $
Predicted pond cost
= Pond cost from 145 x cost factor index multiplier
x = $
MAGNESIUM OXIDE SCRUBBING D-60
-------
§
w
en
H
i
o
X
H
o
M
O
da
w
H
a
o
1971
1973
1975
a
i
1977
YEAR ENDING
1979
1981
1983
1985
-------
CAPITAL INVESTMENT COSTS—MgO
Direct costs:
Seled
"A" Me
"B" L<
11 C"
t system required
aterial
ibor
Retrofit
Easy
Moderate
Difficult
1
Absorber
1.7913 A*
^r486 X
Absorber & venturi
1.776 A
1.472 A
Materials and labor
Absorber
0
0.047X
0.093A
Absorber-venturi
0
0.039A
0.077A
Cost,$
A = Equipment cost, predicted from page.D-60
"A" + "B" + "C" = $_
"D" Raw materials: Chart 2, item |10| or |10
15 day
page
Ib/hr MgO
x storage
x 360
MW's "
x $lb
x
b _
= $
% S
Coke 2.25 x x
b If unknown use 0.075/lb
c If unknown use $40/ton
"E" predicted pond costs page D-60 = ^-
"F" Direct costs ("A" + "B" + "C" + "E") above = $_
"G" Direct costs ("A" to "E" inclusive) = $_
"H" Direct costs ("A" + "B" + "C") above = $_
x c$/ton = $
Indirect costs:
"J" Interest (at 8'%)/ contractor fees and expenses, engineering,
freight, off-site,taxes, start-up, spares -
(0.33 "G") + (0.1 "H") + (0.065 "F") -
(0.33 x ) + (0.1 x ) + (0.065 x ) = $
MAGNESIUM OXIDE SCRUBBING
D-62
-------
CAPITAL INVESTMENT COSTS~MgO (continued)
"K" Contingency:
0.2 ("J" + "F") = 0.2 ( + ) = $.
"L" Total costs for capital investment
"G" + "J" + "K" = + + .
' = $
Cost/Kilowatt:
L = = $
MW's x 1,000 x 1,000
MAGNESIUM OXIDE SCRUBBING D-63
-------
TOTAL ANNUAL OPERATING COSTS—HgO
Utilities -
Water: MgO scrubbing
77 gal./MW for 3.0% S coal
-A 6.6 gal./MW for each - 1.0% S in coal
1481
65 gal./MW for 3.0% S oil
-h, 5 gal./MW for each - 1.0% S in oil
MgO.
(gal./MW - gal./MW corr. for •% si x hr/yr x weighted
capacity fact, x water costs/1000 gal.) = yearly
cost water/MW
Ml:
or
148 or 150
$0.02 cap. factor
) x 1000 x 8760 x . = $'/lTtJ
$
/Coal or
/Base.% S \
; I % S ''corr.j
X
x
MW
Jl&l
.= $_
Vyr
Reheat:
From page D-31 Chart 13, item 65 determine $/reheat
( see calculation sheet)
For AT
MAGNESIUM OXIDE SCRUBBING
D-64
-------
TOTAL ANNUAL OPERATING COSTS—J4gO
Operating labor cost:
MW's
100- 699
700-1200
1201-2500
2501-
Men/Shift
5 '
5.33
6.33
7,16-
Men/shift x hr/yr x $/hr =
x 8760 x 6.50 =
x 56,940 « $_
,/yr
Corrected cost: Il53l x/$/hr (manpower )\= $ /yr
\ 6.50 / '
Supervision:
0.15 x 56,940 x men/shift =
8541 x = $ /yr
Corrected cost: P-5J] x .15 = $.
" c
Maintenance:
Capital costs, total
0.046 x = $.
./yr
154]
Overhead:
Capital cost, total
(0.023 x
MAGNESIUM OXIDE SCRUBBING
+ Men/shift
.) + (13,100 x ) =
_}+( )=
= $
OL56]
D-65
-------
TOTAL ANNUAL OPERATING COSTS—MgO
Fixed costs -
A. 10.0 _ %/Yr depreciation, straight-line
Plant life, yrs*
B Capital = %/yr %
C. Taxes, insurance/ interim replacement - 4.65%
Total fixed costs = A XOO * C = */Yr fixed costs
( fixed costs,%/yr) x(total capital cost) =
( . %/yr) x( 1= $ /yr
Fly ash disposal
Pumping to another site, off-plant
MW KW/MW $/KWH**or***.hr/yr x weighed c*F.
0.0011 x x 1000 x x 8760 x =
MW $/KWH** or *** weighed C'.F.
9.64 x x x = $ /yr |l58l
Truck fly ash disposal costs/14 miles:
ton dry sludge/hr
8.47 tons dry sludge/truck hr
(57.25 min/trip) ($17.20/truck hr/driver)
x $17.20 x 1.1 x 8760 x CF =
From Chart 3, item 15J:+, tons dry sludge/hr_
15
A
15; weighed CF
x 19,570 x = $
* Plant life, years: either remaining boiler life in years from start
of FGD system or 15 year life for FGD system, use lowest number of
years for life.
** or *** see next page
MAGNESIUM OXIDE SCRUBBING D-66
-------
TOTAL ANNUAL OPERATING COST—MgO
Raw materials -
MgO
Page D-7 Chart 2, item
or
ton/hr Mgo x hr/yr x
MgO make-up percent weighed C.F. x $/tona = cost/yr.
= 8760 x C.F. x 10% x $/tona
= 8760 x
x Chart 2, item lO
or
x 0.1 x
160|
Coke: 54.6 x MW x %S x capacity factor x $/tonb = coke cost
b
54.6 x
x 0.
x
x
= $
[161
Oil: 955,000 x MW x %S x capacity factor x $/galc = Fuel oil costs
drying calciner
955,000 x
x 0.
= $
162]
Utilities:
Electrical, use appropriate
MgO—burning coal =
= 1.57 x 105 x
MW $/KWH**
or
***
x
MW $/KWH**
or ***
/yr =
(on\coal/abs. + vent.)
\
A+V
= 1.50 x 10 x
MgO—burning fuel oil •
MW $/KWH**
or ***
1.07 x 105 x x
= $ /yr =
(on coal/abs.)
|163
_/yr =
(on oil/abs.)
163[
a If unknown use $150/ton.
b If unknown use $40/ton.
c If unknown use ($12/bbl) $0.2857/gal.
** If unknown use 0-00675/KWH based on coal at $10/ton and 12,000
BTU.
*** If unknown use 0.0185/KWH based on oil at $8.40/bbl and 149,000
BTU/gal.
MAGNESIUM OXIDE SCRUBBING D-67
-------
TOTAL ANNUAL OPERATING COSTS—MgO
Summary sheet
Item
Cost, $
1. Water
2. Reheat
j
3. Operating labor
4. Supervision
5. Maintenance
6. Overhead
7. Fixed costs
8. Sludge fly ash disposal,
pumping
9. Sludge fly ash disposal,
trucking
10. MgO
11. Coke
12. Oil
13. Electrical
A+V
Total annual operating costs $
Cost per kilowatt-hour:
(total annual operating cost)
hr/yr x (plant rating in MW's) x 1,000 x (weighed capacity factor)
) =
8760 x (
) x 1,000 x (
/KWH
MAGNESIUM OXIDE SCRUBBING
D-68
-------
APPENDIX E
WELLMAN-LORD SCRUBBING
NOTE: For purposes of clarity and continuity, Tables and
Charts have been numbered sequentially in this
Appendix with no differentiation between Tables and
Charts.
WELLMAN-LORD SCRUBBING E-l
-------
INFORMATION REQUIRED
Boiler No.
Type of furnace
MW at maximum continuous
Age of unit , years
Life, years remaining
Capacity factor, yr.
Maximum continuous fuel,
ton/hr or gal./min
Maximum continuous,
MM BTU/hr
acfm at °F
Fly ash/total ash, %
Efficiency of existing
control (particulate
matter)
Cost of electricity/KW (Plant) =£_
Coal, cost/ton $
% sulfur by weight
% ash by weight
HHV, BTU/lb
. Cost of water/M gal. (Plant)
= $
Oil, cost/bbl $
% sulfur by weight
BTU/gal
Specific Gravity
SO- permissible
Fly ash permissible.
Ib S02/MM BTU
Ib fly ash/MM BTU
State or
Federal regulations
WELLMAN-LORD SCRUBBING
E-2
-------
INFORMATION REQUIRED (continued)
Estimated land cost per acre (current) $
Possible interference determining the location
of flue gas desulferization (FGD) system:
Congestion between stack and plant Q Yes Q No
Congestion between stack and/or plant with Q Yes Q No
property line, coal pile, etc.,
Identify problem areas and location:
Terrain.
Conduits.
Possible obstructions.
Source .of Na-CO, available.
and % purity .
WELLMAN-LORD SCRUBBING E~3
-------
S02 EMISSION DETERMINATION
To determine the SO2 emissions (Ib/MM BTU) in the flue gas, Chart 1;
Enter % sulfur by weight of fuel (oil or coal) on(l]
Enter heating value of fuel (BTU/lb) on
Connect
SO
2 emissions (Ib/MM BTU) in flue gas
CO
10
on
2
acord and read:
24,
22
2ft
***^
18
-j ;
§ 16
o
s 14;
*
•t Ifc
2 io
UJ
^-\8 8
fr
4
?
0
UJ
*— 4
_J
' O
z
111
^u
o:
UJ
u.
UJ
^^
^ ^
3
:
**\
22-
20;
18;
lei
t4j
12;
10:
8
4
2
0
•
: _i
: 1—
• i
i ^
i
: z
: O
h- 4
t— »
: z:
. iii
UJ
sT
§
Chart 1. SO2 EMISSION DETERMINATION
Assumptions:
(1) 95% of sulfur in coal converted to S02
(2) 100% of sulfur in oil converted to S02
WELLMAN-LORD SCRUBBING
E-4
-------
so2 'REMOVAL REQUIREMENTS
To calculate S02 emissions (Ib/MM BTU) to be removed:
Enter from page E-.4, chart 1, item E) the Ib/MM BTIL
Enter from the data sheet, allowable SO- emissions
(Ib/MM BTU) from the State or Federal regulations-
Subtract [4] from [3j to calculate S0~ emissions
(Ib/MM BTU) to be removed
WELLMAN-LORD SCRUBBING
E-5
-------
Na2C03 REQUIREMENTS
To determine the Na-CO., requirements, Chart 2;
Enter S02 emissions (Ib/MM BTU) to be removed on item
from page E-5, item [5]
Enter from the data sheets the maximum continuous input
(MM BTU/hr) on item \J]
Connect items [6] and |7| , extend to item |_8| and read and
record:
nn
S02 to be removed (Ib/hr).
Connect item |_8j to pivot point | 9| , extend to item [10
read and record:
Na2C03 requirements (Ib/hr).
10
Enter weighed capacity factor from data sheet on item flT
Connect items |10| and [11], extend to item |12| , read and
record:
Na2C03 requirements (ton/yr).
WELLMAN-LORD SCRUBBING
E-6
-------
10-i-
1-0
1000-r-
I
lr»
O
en
o
(X)
H
3
Q
fJ
-J
m 7-
i
rf
«• 6-'
S t
S
LU
OC.
LU
CO
£
to
§ 4-
»-t
-------
FLY ASH EMISSION RATE CALCULATIONS -FOR VENTURI DETERMINATION
To calculate fly ash emitted:
If the fly ash emitted (Ib/MM BTU) in [13 after passing through an
existing particulate emission collector per boiler is greater than
the allowable rate from the data sheet, the use of venturi is
necessary. Use the following equation to calculate |13
13] = (% ash in coal )(% fly ash*) (1-n ) * BTU/lb x 10 = Ib/MM BTU
TOT) TOO
= JO -- ) (0= _ ) (1-0. _ ) 4- _ ] * 106 = _ Ib/MM BTU
where
nc = Efficiency of particulate emission collector system
BTU/lb = Heating value of fuel
% fly ash = from the data sheet
If fly ash removal is required for any or all of the units VENTURI COST
CALCULATIONS will be used.
*If the percent of fly ash to ash is not known use the appropriate
tabulated values for the boiler under consideration.
Type boiler - coal-fired fly ash to ash, %
General pulverized 80
Dry bottom 85
Wet bottom 65
Cyclone 10
WELLMAN-LORD SCRUBBING E-8
-------
VENTURI AND ABSORBER COSTS
To determine the costs of venturi and absorber (including demister)
using Na_CO3 , Chart 3:
First, determine number of scrubber trains -
Enter acfm at °F of flue gas from the data sheet on [u] , either
per boiler or combined plant total if °F is the same for all
boilers.
Enter temperature of flue gas (°F) on [Is
Connect (T4J and [Tif| and extend to [T&l and read flue gas acfm
at 125°C (saturated) and enter acfm at 125°F and sat.
If acfm at 125°F is greater than 375,000 divide [16] by a number less
than 375,000 to give a whole number of Venturis and/or absorbers for
each boiler.
acfm per venturi and/or absorber (]
17
18 number of Venturis
and/or absorbers per
boiler or power plant.
A venturi, or an absorber, or a combination of a venturi and absorber
is sometimes called a train.
Assumptions: Costs are based on -
(a) Venturi throat velocity at 150 ft/sec
(b) Absorber velocity at 10 ft/sec, duel demisters
WELLMAN-LORD SCRUBBING E_9
-------
10-r-
6- -
u
(O
o
X
3--
2--
-T-0
5--
4--
0-1-
P
NOTE:
IF FLUE GAS FLOW IS
450,000 acfm AT 300°F .
ENTER 450,000 AS 4.5 x 105
ON 20 , ENTER 300°F ON
21 EXTEND ENTRIES TO 22
AND READ 3.75 x 105 OR
375,000 acfm AT 125°F
AND SATURATED
Chart 3- acfm CORRECTED TO 125 °F AND SATURATED
WELLMAN-LORD SCRUBBING
--2
o
UJ
Q
CM
4J
03
e
C. O
mff ^" W dvrt
I o
r—
X
>-
--9
-MO
E-10
-------
VENTURI AND ABSORBER COSTS
Then determine absorber costs (no venturi required) Chart 4:
Enter item 16] from page E-10,Chart 3 on Chart 4 on 19
Enter for the absorber the cost factor of 2.05 on 20
Connect [19j and |2Q| and extend to |2l| and read absorber cost
21
Or determine venturi costs (no absorber): Chart 5
Now enter item 16 from page E-10,Chart 3 on Chart 4 on |19|
Enter the venturi cost factor of 0.9 on 20
Connect [19 and 20 and extend to 21 and read venturi costs
*To correct for velocity differential in absorber-
_corrected cost of absorber 2l|
WELLMAN-LORD SCRUBBING
E-ll
-------
0-T-
o
un
C\J
O
fO
O
X
>-
2- -
3 — —
Q
UJ
I—
Qi ±
I—
1/5
Q
cC
6--
7— —
8--
C— Jf
19
COST FACTOR
ABSORBER ONLY
VENTURI ONLY
SEE CHART 3 FOR
EXPLANATORY NOTE
Chart 4. SCRUBBER COSTS
WELLMAN-LORD SCRUBBING
-j-25
--24
--23
--22
-1-21
-20
-4-19
•-18
--17
-j-16
-15
-j-14
--13
-4-12 2"
x
--10 >-
•faO-
-5
-4
4-3
-2
n>
-1
21
E-12
-------
VENTURI HOLDING TANK CAPACITY
If venturi is required, determine the holding tank capacity
for venturi as follows:
Chart 5:
Enter flue gas acfm from page E-9, Chart 3, item
on Chart 5,
item
Enter L/G* (liquid flow rate, gpm/1000 acfm at 125°F) on item
Connect items 23
and
, extend to item
, read and record;
Liquid flow rate (gal./min)
[2 5) for venturi
Enter retention time** on item
26
Connect item
25
and
26 , extend to item
, read and record:
Tank capacity (gal.) per venturi
* if unknown, use 15.
** if unknown, use 4 min.
27
V
WELLMAN-LORD SCRUBBING
E-13
-------
1 x 10*
GC
O
1 x 105--
LO
CM
O
«0
1X106--
1 x 105-r
-T-1 X 103
1 x 101 _
1 x 103- -
1 x 102- -
25
- -1 x 104
01
A
>-
h-
h—I
CJ
-------
VENTURI HOLDING TANK AGITATOR COSTS
To determine the cost of agitators per tank, Chart 6;
Compare tank capacity (gallons) from page E-13, Chart 5, item J27J
and/or \21\ v on Table 6; under tank capacity in gallons column
and record:
Cost of agitators per tank - $
Total cost of venturi agitators:
V
) x No. of Venturis
Chart 3, item |18|
:om page E-9 , = [2<
) x
= $
WELLMAN-LORD SCRUBBING
E-15
-------
AGITATOR COST
Table 6. AGITATOR COST
Tank capacity, gal.
0 to 34,000
34,000 to 67,000
67,000 to 101,000
101,000 to 135,000
135,000 to 162,000
162,000 to 188,000
188,000 to 220,000
220,000 to 251,000
251,000 to 283,000
Acritators
No.
1
2
3
4
5
6
7
8
9
128 v, cost, $
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
WELLMAN-LORD SCRUBBING
E-16
-------
HOLDING TANK COSTS
To determine the tank cost the values in the chart are based on
2
using $12.50/ft for a field-fabricated, rubber-lined tank, Chart 7;
Enter tank capacity (gallons) on item
30
from page E-14, Chart 5,
27
v, move vertically to item [3!
From item |3l| move horizontally to item 32 , read and record:
Tank cost per venturi $
32
V
Total cost:
V
x No. of Venturis from page E-9 = cost of holding tanks
item 18
x
= $
33
WELLMAN-LORD SCRUBBING
E-17
-------
""I |i| 'I'l'l'l'l '
|MII| I I I I l|l|l|'|'l I I I I |IMI
' I i I Iniil I I I hhlihlil i i i i hull i I i Mi
1 x 103
1 x TO4 1 x TO5
TANK CAPACITY, gal.
Chart 7. HOLDING TANK COSTS
WELLMAN-LORD SCRUBBING
£-18
-------
VENTURI HOLDING TANK PUMP COSTS
Chart 8
Prom page E-10, Chart 3, item [16
enter on item
34
of chart 8
for venturi
Enter L/G of
15
for the venturi on item
on the venturi side
Connect items 34
and 35
and extend to item
36
Connect item
Connect item
36 with hp vent., item |37| and extend to item |38|
38 with R
venturi
. , item 39 and extend to item
40i
Extend item 40 horizontally to the right to item 4lJ (cost per
pump curve) and read cost ($) on the venturi side:
Unit No., Cost per
boiler ; • pump $ x
; x
? x
T "*
; x
t x
• x
• x
? x
; x
Combined ; x
follow the same procedure
absorber pumps total cost
Item 18
X
X
X
X
X
X
X
X
X
X
X
Total
for absorber
= $
Include
spare Total pump cost-
pump venturi-, $
2
2
2
2
2
2
2 _
2
2
2
2 I
cost S Z 41-
pump cost and note
E 41
V
A
WRLLMAN-LORD SCRUBBING E-19
-------
300,000-r
f
o
8
o
§
Cd
w
H
22
O
250.000+
200,000+
DC. CO
°
^fg 150,000+
O UJ
100,000+
50,000+
coo a:
0-rO H- 100CW-6000
••1000 15007000
10002000 20008000
7000 4500+14,000
4000-S-8000 500015,000
9000 550016,000
100010,000
SOOO-^-lO.OOO 6000^ il7,000
6500*18,000
Tl
Chart 8. HOLDING TANK PUMP COST
-------
FAN COSTS
To determine fan costs, Chart 9 :
Enter acfm at °F of flue gas from the data sheet on
Select appropriate curve for pressure drop* on J43J
Move vertically from 42
to
and then from 43 horizontally to
441 read and record:
Fan costs $
* Typical pressure drop: Absorber
absorber and venturi
2T"
30"
"(including 3" safety)
(including 3" safety)
WELLMAN-LORD SCRUBBING
E-21
-------
S!
W
f
a
i
§
en
O
»
a
w
03
H
I
N>
to
IF AP IS UNKNOWN USE:
AP=30" FOR VENTURI AND
AP=21" FOR ABSORBER ONLIY
i i I i i i i i i i i i M i i i i i i i.i I i i i i i i i i i I i i t i i i i I i I i i I I I I I i i I I i I I i i i i i I i i i i i i 1.1
yTT i i i i | i i 11 i i i i i i i i i i i i i i i
XI0Q acfm AT°F
Chart 9. FAN COST
-------
HEAT EXCHANGER COST
To determine heat exchanger cost, Chart TO ;
Enter item Q6J from page E-10,Chart 3, on Chart 10, item
45
Move vertically upward to item [55J for AT = 50°F, if another
AT is used record °F
6] , read and record:
From
551 move horizontally to the left to
Cost for heat exchangers $.
56]
WELLMAN-LORD SCRUBBING
E-23
-------
zi i I i 1 1 1 1 1 IIIIIIIHII 1 1 1 1 ii ii ii i i i i 1 1 1 i i |iu i|ini| 1 1 1 1 1 |i iii i n I it 1 1 i
1 x 106
LU
1 X 105
a:
o
s
1 x 104
mi mini i
1x10^ ' ' ' ' l[ ' ' ' ll" ' I'111* ' I ' I' I" I" ' ' ' ' I i I i i IHI i liml i 11 11 Ii 111 i i i i Ii i i i Iniillliil i Ii It Ii Ii
1 x 104 1 x ID* 1 x 106 [54]
acfm AT 125 eF
Chart 10. HEAT EXCHANGER COSTS
WELLMAN-LORD SCRUBBING
E-24
-------
SOOT BLOWER COST
To determine soot blower cost, Chart 11 :
Enter item |17| from page E-9, Chart 3 on Chart 11, item
57
Move vertically upward to 581
From 1581 move horizontally to the left to [59] and read:
Cost per train
. $_
59
Record from page E-9, Chart 3, item QSJ , number of trains
Cost of soot blowers:
59
.= $
60
WELLMAN-LORD SCRUBBING
E-25
-------
70,000
60,000
50,000
a:
LU
Q.
40,000
O
CO
O
O
CO
o 30,000
CO
o
20,000
10,000
2500 fpm GAS VELOCITY!
i till
i. I
100,000
200,000
300,000
400,000
500,000
acfm AT 125CF AND SATURATED
Chart 11. SOOT BLOWER COSTS
WELLMAN-LORD SCRUBBING
E-26
-------
REHEAT COST
To calculate the cost of reheat, Chart 12;
Enter acfm at 125°F and saturated of the flue gas from page
on Chart 12, item [6l]
Chart 3, item Q6J
Select and enter AT* on item
* if unknown, use 50°
62
Connect items |61| and 162] and extend to item [63] record
Enter costs (S/llM BTU) reheat* from calculation below on
item |64|
Connect items [63] and [641 and extend to item [65] , read and
record:
Cost ($/hr) reheat
651
Annual reheat cost:
Weighted capacity
factor from data
sheet
.x 8760 hr/yr x 0..
= reheat cost/yr
= $
*Reheat Cost -
Coal: To correct from 12,000 BTU/lb and $10/ton
($/ton)
= 665 x
_BTU/lb
= $.
_/MM BTU
Oil: To correct from 149,000 BTU/gal. and $10/bbl
(S/bbl)
= 31,707 x-
JTU/gal.
= $
./MM BTU
WELLMAN-LORD SCRUBBING
E-27
-------
• *•» i w _
V
V
V
•1
g 1 x 10*
I—
13 _
co
o •:
••
or :
u_ ;
o
CM
H-
* i x io5.
••
«•
•n
mm
^v
mm
mi
•
•
•
«
1 x 104-
61
mi
m,
Hf
mt
m.
m «
V
. —
•
^
•
••
••
.
mm
.
Al
—
L —
»
V
—
__ ^
L +75 'F I :
: AT § J
n: :
LLJ :
'*' H
62 j
*
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m, "
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^
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*
• «
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.
.
•
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«•
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mi
m
mi
mi
m
mi
. mm
mt
T-l
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turn
• «
«i
*• ^
_ "•
' ••
-2 =
«•
•
• —
^
:3 :
•
« 4M
-4
- ~
i5 '
-6 .
-8 ^
-9 -
-10 :
^
•. ~
iH
•H
-20 ^> :
I—
>\ co 6
'-30 \, E 4^
• ^^i -^? 3- — —
;-40 ^xJ 2" \
^•60 ^^\~ --
-70 2 n 5- ^\ "=
-80 p= " <, :
790 S \s^ "
64 \, -
^
-200 -
f urn
, mi
' «•
:300 i
^
-400 -E
-500 4
-600 :
-700 :
-800
-900
-1000
mt
_1 0,000
-9000
r8000
-7000
-6000
j-5000
Uooo
'-3000
m
'-2000
^
^Oo0o0
r800
T700
-600
r500
1400
=•300 £J.
-200 H-"
co
O
0
1—
-loo 2
r90 =c
r80 ^
-70 OL
-60
-50
§•40
m
r30
m
m
#
^
•*
mtf
E4
V
h
»
m
-2
^
•V
^
-1
63 651
Chart 12. REHEAT COSTS
WELLMAN-LORD SCRUBBING
E-28
-------
DUCT COSTS
To calculate ducting cost:
Assumption-
The length of flue duct from the main discharge duct to the
venturi (if used) is variable in feet and also the return to
the main discharge duct after SO- and/or particulate removal.
For the specific boiler if more than 1 venturi and/or absorber
is required use the multipliers listed in Table .13. Compute each
boiler separately, unless identical to each other in absorber or
venturi acfm at 125°F and saturated.
From data sheet,
acfm at °F
2 2
Area duct (from main) in; = ft = 2X
3,500 ft/min
Perimeter length:
X2 = = ft2
•f-
ft
6X = 6x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.39/lb =
7.02 x ft perimeter = $ cost/linear ft [67]
Page E-10,chart
3 , item [16
2 2
Area duct (to main) out: = ft = 2X
Perimeter length:
•v-
ft2 = 'ft
6X = 6 x ft = ft perimeter
Cost: ft perimeter x 18 Ib/linear ft x $0.445/lb =
8.01 x ft perimeter = $ cost/linear ft |68
WELLMAN-LORD SCRUBBING E-29
-------
DUCT COST
Table 13. MULTIPLIER FOR DUCT COST
No. of absorbers
and/or Venturis
per boiler
1
2
3
4
5
6
7
8
9
10
Venturi and
absorber
in
110
190
250
305
356
410
453
490
535
579
Venturi or
absorber only
in
70
114
180
225
266
310
346
378
415
452
Venturi plus
absorber
out
70
113
143
175
205
235
262
288
315
343
Venturi or
absorber only
out
50
93-
123
155
183
208
242
268
295
324
Duct cost in -
(in) cost/
linear ft
x
Table 13
multiplier
67j$_
Estimated ft to\
main duct-(30')
-30
Duct cost
_$
**
Duct cost out -
/ Estimated
(out) cost/ Table 13 distance to
1'inear ft x ^multiplier main duct -(501
68]$-
.x (.
J+C
_ Duct cost (out)[70]
-50 ) =_$_
Total duct cost -
69] duct cost (in) + [To] duct cost (out)
$ + $.
= .total duct cost [?T
.= $ [7T
* If congested area add 230 ft for estimated ft.
** If congested area add 200 ft for estimated ft.
WELLMAN-LORD SCRUBBING
E-30
-------
FLUE GAS SHUTOFF AND BYPASS VALVES
To calculate flue gas shutoff and bypass valve costs:
Assumption-
Based on 4 vanes/axis in short dimension based on height of 20 ft
and width of 10 ft..
Stainless steel at $141.6/ft2; carbon steel at $99.I/ft2
Flue gas valve (in) at main duct to create a bypass
From the data
sheet acfm at
°F /Boiler = ft2 = 2W2
3,500
W =!/ ^ ft2; W x 2 = x 2 = height, ft
Valve cost A = (1.5 x H) [(99.1}±* (3.1) (H-20) (0.5H-10)]
*H greater than 20 ft, sign is + , less than 20 ft sign is -
(H) (H) (H)
= (1.5 x ) [(99.1)± (3.1) ( -20) (0.5 .-10)]
= $ carbon steel
Flue gas valve (out) at main duct to create a bypass
Page E-lp,chart 3 Chart 3
item [Te] acfm / Item (l6|
at °F
27500 - 2500
-ft2; W x 2 = x 2 = ft (height H)
(H) (H) (H)
+*
Valve cost B = (1.5 x ) [(141.6)± (4.5) ( -20) (0.5, -10)]
stainless steel 73
Flue gas valve (in) to absorber and/or venturi train
From data acfm at
/Boiler _____ = Area, ft
2
( 18 No. of Venturis or absorbers) x 3,500
WELLMAN-LORD SCRUBBING E-31
-------
FLUE GAS SHUTOFF AND BYPASS VALVES (continued)
18
_= Area, ft2 = 2W2
.x 3,500
W =
ft ,• W x 2 =.
. Height(H),ft
Valve cost C
= (Height (H) ± 0.5 Height (H) ) [(99.1) - (3.1) (H-20) (0.5H-10)]
tH) (H) (H)
= U.5 x ) [(99.1)-(3.1) ( -20) (0.5 -10)J
carbon steel
Valve cost D =
/ Page E-9, item 18 \
yNo. of Venturis and/or absorbers) x (valve cost
.) x (.
-) = $.
74
75
75
Flue gas valve (out) from absorber and/or venturi
Page E-9, item 17
1.08 acfm at 175°F
2,500
0.000432 x.
W =
•ft2; W x 2.
i ->
Venturi and/or absorber = ft
ft2 = 2W2
x 2 = ft, (H)
Valve cost
= (1.5.
E
(H)
.) [(141.6)-(4.5) (
= $
(H) (H)
-20) (0.5 _ -10)]
stainless steel 1 76
Valve cost,, =
r
Page E-9, item 18
/Pa
\No.
= ( ) x (
of Venturis and/or absorbers/ x (valve cost |76j ) =
JLJt
-) = $_
77
Valving cost per boiler
Valve cost,, =
m.
B
V
D
= $_
WELLMAN-LORD SCRUBBING
total valve cost
78
E-32
-------
ABSORBER FEED SURGE TANK AND SULFITE STORAGE TANK COSTS
From page E-7, item |T| Chart 2, record Ib S0,/hr
^*
lb S02/hr x 25.4 = gal. Na2SO3
24 hr, 25% slurry storage
79
Enter gallons Na2S03 item |79| on Chart 7, item |30| and move vertically
upward to intersect the curve, item 31 then move horizontally
to the left item [32| read and record:
$ x 2 = $
tank cost [ftp
WELLMAN-LORD SCRUBBING
E-33
-------
AGITATOR COSTS FOR ABSORBER FEED SURGE AND SULFITE STORAGE TANKS
From page E-32, item 7SJ enter gallons* at appropriate level on
Chart 6 and read number of agitators required per tank
$
and read agitator cost:
81
*(If capacity required is greater than 283,000 gal., divide capacity
by 283,000 =
Capacity, gal.
.number of tanks required
283,000
If a decimal number appears raise to the next highest whole
number. Divide capacity (gallons) by highest whole number
Capacity, gal.
.(whole No.)
.capacity gallons per tank
Enter this capacity (gallons) on Table 6 to determine agitators
per tank required above)
Table 6
whole Cost of Absorber feed
number agitators/ surge and Agitator
of tanks x tank, $ x sulfite tanks = costs, $
x
WELLMAN-LORD SCRUBBING
E-34
-------
STORAGE SILO COSTS
Chart 14
From page E-7, Chart 2, item |_8J recorded, enter this on Chart 14 item |82|
and move horizontally to item
Record
83
tons Na2CO3 required.
Enter item [83] on item |84| and determine largest silo or number
of silos by keeping the number of silos to a minimum and enter
whole number by connecting item [84] to item |85| (tons/silo
selected) connect and extend items |84| and |85| to item [86]
and read:
86 No. of silos;
J85J tons/silo (use larger re-
corded number
on chart).
Enter selected 85 on 87
Connect items |86| and |87| and extend to item |88] and read
Total Silo cost $
88
WELLMAN-LORD SCRUBBING
E-35
-------
I
F
o
o
§
ro
tu
H
i
U)
J_ ^- -
x 3:
C\J
o
o-a
*
m
2-
m
m
3-=
tt
•ri
•
mt
mi
tf
4
*
7-
"
V
V
«
«•
•
••
9*
*
«
*
te
•
•
•
^
»
V
••
m
°:
«
«•
*
*
^
» v
: *-
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- » '*
r co
; >*
mt
m
m
m
•»
«
•
••
V
m
•
m
m
m
m
m
m
m
|82
o :
^m? ^
** 3-
C\J \
»^
^ _
*
^
4-
•h
^
V
V
ta
*
«i
5^
» Mi
8-
- 40-
~ 56-
; 72-
M» -
• m
• •
- 7 120^;
: x leo-
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o
- ^ -
z 200v
_ •
* ""
I o 240-
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UJ . .
cp320-
- 8 •
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m
m
•
•»
- 400-
-0 o-i
:16 -
-32 -
-48 '-
-64 '-
-
-80 1000-
. H
• «•
~ «.
— .
- .
»
*
2000^
- .
oo
- S
CM
03
"- ** 30d6^
•V •
W w
— •
1 4000-
« *
••
. «•
.
m m
• m
~- 5000-
82 I83' I
— T
«
«
mi
«i
6000-
*
••
VI
•
•»
••
«
**
• —
«
^
m
••
••
•*
mm-
m>
V
•*
m-
mm
m
V
•*
•
••
••
m
134
S--
-1243
ton/SILO
2--
O-i-
20,000- -
195
1243
ton/SILO
40,000- -
000- -
80,000- -
100.000- -
120.000-1-
bO
O
u.
o
CO
o
o
Chart 14. STORAGE SILO COSTS
-------
VIBRATOR FEEDER COSTS
From page E-35, Chart 14 enter item 83 below and divide bv 720 to
procure ton/hr Na2C03 makeup required and then add cost factor
for feeder FD
From page E-35, Chart 14 multiply item
/Chart 14
?5 + \Itera [83
x
720
720
)1
)]
86 for total feeder costs
Chart 14
Item 86
x
= $
Total
feeder costs
WELLMAN-LORD SCRUBBING
E-37
-------
DISSOLVING TANK AND AGITATOR COSTS
Chart 15
From page E-7, chart 2, item \8\, enter this on item fgol and move
vertically upward to item [92
Then move horizontally to item |93| and read tank and agitator
costs:
$ _ cost of dissolving tank and agitator |93j
Pump costs and gpm:
From page EL--7, Chart 2, item 8 , enter this on item (9o| and
move
vertically upward to items
and
Then move horizontally to items |95| and 1 93) and read pump
cost and gpm:
cost of pump 93
gpm
WELLMAN-LORD SCRUBBING
E-38
-------
1 x 10!
s
8
en
o
»
§
w
H
2
O
nlOOO
M
I
w
vo
1 'I"'l ' I 'I'l'l'l i l
i i 11 III,I . I flliililil I r i i i . ll ml . I illtiillll I . I I I i I lull i I i Uli Mi
I I i I i lull i I i ! ilitilil i I I I I • I I i.,l i I tlllll/l
] x 10
lb S02/hr
Chart 15. DISSOLVING TANK AND AGITATOR COSTS
-------
EVAPORATOR FEED PREHEATER AND PREHEATER PUMP COST
Chart 16
From page E-7, Chart 2, enter item 8| on Chart 16, item
96
Connect item 961 with evaporator feed preheater point on item [97
and extend to item 98] and read:
$ cost of evaporator feed preheater |98
H
Connect the same point on item
with 100 ft head* on item 97
and extend to item |98| and read:
$
cost of preheater pump
* If different head in feet is used, record.
.feet.
WELLMAw-LORD SCRUBBING
E-40
-------
10,000-
9000-
8000-
7000-
6000-
4000-
3000-
2000-
100C
EVAP. FEED PRENCATER
Chart 16. EVAPORATOR FEED PREHEATER AND PREHEATER PUMP COSTS
WELLMAN-LORD SCRUBBING
E-41
-------
EVAPORATOR AND FEED PUMP COSTS
Chart 17
From page E-7/ Chart 2, enter item _8J on Chart 17, item [99J and move
vertically to items [100| and |l01)
Then from item |100| move horizontally to item IJJDlq and read:
cost of evaporators
and read:
EV
From item |10Tj move horizontally to item
$ _ cost of evaporator feed pumps
102J
WELLMAN-LORD SCRUBBING
E-42
-------
25
f
O
O
V
G
H
23
O
M
I
100
1000
10.000
S02, lb/hr
100.000
Chart 17. EVAPORATOR AND FEED PUMP COSTS
-------
EVAPORATOR REBOILER AND PRIMARY CONDENSER COSTS
Chart 18
From page E-7, Chart 2, enter item [_8j On Chart 18, item [Tol]
)1 and extend
Connect item 103 with appropriate point on item
to item [105 and read and record:
$_
$_
$_
.cost of reboiler 1st stage
.cost of reboiler 2nd stage
_cost of condenser, primary
ro|
_cost of condenser, SO~
SO.
WELLMAN-LORD SCRUBBING
E-44
-------
10,000
§
en
O
W
Od
H
a
o
M
I
*»
cn
Chart 18. EVAPORATOR REBOILER AND PRIMARY CONDENSER COSTS
-------
CONDENSATE RECEIVER AND PUMP COSTS
Chart 19
From page E-7, Chart 2, enter item Sjon Chart 19, item |106
Connect item
106 with 2-hr retention time on item 107 and
extend to item 108 . Read and record
Enter [108 on item 109 move horizontally right to items [110
and Hill
From these points on items |110| and [111| move down to item |112
and read:
$ cost of condensate receivers [JT2|
$ cost of condensate pump
WELLMAN-LORD SCRUBBING
E-46
-------
s:
w
a
o
CO
o
JO
c
ro
ro
M
a
Q
w
i
10-ar
COST, $
Chart 19. CONDENSATE RECEIVER AND PUMP COSTS
-------
STRIPPER COSTS
Chart 20
From page E-7, chart 2, enter item |_8j on Chart 20, item [113
Connect item 113) with item 114 pivot point and extend to
Read and record
115
on item
116 move horizontally to item 117 then
move vertically down to item |118| and read:
$ cost of stripper [118
WELLMAN-LORD SCRUBBING
E-48
-------
f
O
O
»
a
w
tu
M
I
10-T-
1 I I
11 11lflll
' ' ' I I ' ' t I I llM tl 1 I , ll .1.1
I 1 M I I I I Ijllll I I .1.1. Ill 1 It I I . I ll I I III I I I I . I.I.
1 x 10'
1 x 10^
A
COST, $
1 x 10
Chart 20. STRIPPER COSTS
-------
STRIPPER PUMP COSTS
Chart 21
From page E-7, Chart 2, enter item 81 on Chart 21, item |119
Connect item |l!9| with 100 ft head, item |120] extend to
item 121 and read:
stripper pump cost |121|
WELLMAN-LORD SCRUBBING
E-50
-------
1.8 x 10_
J.6 x
1.4 x 10D--
1.2 x 105—
j_ 1 x 105--
CM
O
l/t
8 X 1(F--
6 x 104- -
4 x 10
,411
2 x 1(T
O-1-
- :3 x 103
- -6 x 103
-:2.4 x 10*
- -2.7 x 10*
•i-3 x 104
Chart 21. STRIPPER PUMP COSTS
WELLMAN-LORD SCRUBBING
E-51
-------
S02 BLOWER COSTS
Chart 22
From page E-7, Chart 2, item [_8Jrecorded, enter this on Chart 22,
item
Connect item 122 with the point 0.145, item 123 and extend
to item 124
Connect item |124| with the point C»n, item [125| and extend
to item 126 and read:
$
.cost for SO- blower |126
WELLMAN-LORD SCRUBBING
E-52
-------
1.8 x 10V
1.5 x 105i
1.2 x 10&-t
CM .
S 9 x 10*-
6 x
3 x
1044
Q22
4 x 103+
8 x 103i
0.145 o
0.165
1.6 x 104-
2 x 10H J-
2.4 x 104X
2.8 x
Chart 22. S02 BLOWER COSTS
WELLMAN-LORD SCRUBBING
E-53
-------
DISSOLVING TANK, AGITATOR AND PUMP COSTS
Chart 23
From page E-7, Chart 2, enter item | 8 | on Chart 23, item \127] and move
vertically upward to intersect items |128J , |129| and [ 130 j
From each of these points move horizontally to item |131
and read:
$ cost of tank |1311 T
$ cost of agitator |132|
$ '
_cost of pump
WELLMAN-LORD SCRUBBING
E-54
-------
5 x 104-
4.5 x 1
t 1 I _J- 1^ P d i- t L ] | i 1 1 I i i I
40,000 80,000 120,000 r——, 160,000 200,C
|T27
S02. Ib/hr
Chart 23. DISSOLVING TANK, AGITATOR AND PUMP COSTS
WELLMAN-LORD SCRUBBING
E-55
-------
REFRIGERATION UNIT COSTS
Chart 24
From page E-10,Chart 3, item |16| , enter on Chart 24, item 133
Connect this value/ item 133 with appropriate point on item 134
Extend item |134 to item |135| (reference line) then move
horizontally to the right or left as noted, read and record cost ofi
Crystallizer
Purge stream H.E.
Refrigeration H.E.
Refrigeration unit
Glycol tank
Centrate tank
Glycol pump
Variable cost of crystallizer pump
Total cost of crystallizer pump
+ 10,000
VAR
$
$
$
$
$
$
$
$
$
135
135
135
135
135
135
135
135
CR
PS
RE
RU
GST
CT
GP
VAR
135
WELLMAN-LORD SCRUBBING
E-56
-------
10-T-
-i-O
-T-0
X.10QO
Chart 24. REFRIGERATION UNIT COSTS
WELLMAN-LORD SCRUBBING
E-57
-------
DRYER AND ELEVATOR COSTS
Chart 25
From page E-7, Chart 2, read value of item|_8] and enter on Chart 25, item |136
Connect item 1136 j with item |137| and extend to item 11381 and
read and record:
H20 Ib/hr
138
Connect item 11381 with item 139 and extend to item 140 and
read and record:
Cost of dryer and elevator $_
140
WELLMAN-LORD SCRUBBING
E-58
-------
-1-7
2 x 10°-r-
1.8 x 105i
Chart 25. DRYER AND ELEVATOR COSTS
WELLMAN=LQED-S£RUBBING
E-5Q
-------
H2S04 TURNKEY PLANT COST
Charts 26 and 27
From page E-7, Chart 2, item [8] recorded, enter on Chart 26, item [141
Connect item 1.1411 with item 1142 and extend to. item 143
Connect item 143 with item |144 (plant's capacity factor)
and extend to item [145| , read and record:
tons per day ]
plant |145
From Chart 26, enter item 11451 on Chart 27, item
move
horizontally right to intersect item 147
From the intersection on item 1147| move vertically down to
item J148.| , read and record:
$ cost of H-SO.. plant
148
WELLMAN-LORD SCRUBBING
E-60
-------
tons/day AT 1.0 CAPACITY
FACTOR AND 20% EXCESS
x 103
tons/day CORRECTED
FOR CAPACITY FACTOR
x 103
T-3
Chart 26. H9SOA TURNKEY PLANT CAPACITY
WELLMAN-LORD SCRUBBING
E-61
-------
1 x 10; -
1 x
1 x 10
-jrn f 11 n 1 I II I '
i i i 11
TTT;
i l iii I i i
l|,lililjl I I I I ll | I I illll ll Hi llj Illllll I I I II t I
6 810 20 40 60 80 100 ZOO
COST, $ x 105 ITTOi
Chart 27. H2$04 TURNKEY PLANT COST
WELLMAN-LORD SCRUBBING
E-62
-------
MAKE-UP WATER PUMP COSTS
Chart 28
From page E-10,Chart 3, enter item fl?] on Chart 28,
item 149
Connect item |149| with, item [ISO] extend to item [TsTI read
and record:
gpm 151
From page E-59, Chart 25., item |138j recorded, enter on Chart 28, item |152|
Connect item |T52| with item |153| extend to item |154| read
and record:
_gpm 154
Add:
[154
.total gpm make-up water
WELLMAN-LORD SCRUBBING
E-63
-------
10-r-
°
i.
Chart 28. MAKE-UP WATER, gpm
WELLMAN-LORD SCRUBBING
E-64
-------
MAKE-UP WATER PUMP COSTS
Chart 29
From page E-63, Chart 28, item EH) enter on Chart 29, item [156
Connect item [V56] with 100 ft head on item [W] and extend
to item 158
NOTE: If gpm and head used exceeds 100 hp, divide gpm
to give a whole number of pumps and proceed as
above to item |158] , number of pumps used
161
PU
Connect this point on item |T58| with 200 (cost reference) on
item H5^1 extend to item |160| , read and record cost:
$ cost
Pump costs:
x
x
PU
162] make-up water pump cost
_= $.
162
WELLMAN-LORD SCRUBBING
E-65
-------
0-r
500 --
1000--
a. 1500--
O>
2000- -
2500- '
3000-1-
HD, ft
100-T-
80--
60--
Q. . .
40--
20--
0-100 hp COST
0-rO
5000- -10,000
100
10,000- -20,000
COST
REF.
15,000^ -30,000
20,000-2-40,000
T60|
Chart 29. MAKE-UP WATER PUMP COSTS
WELLMAN-LORD SCRUBBING
E-66
-------
EQUIPMENT COST
Description
1. Venturi
2. Absorber
3. Agitators
4. Holding or circulation tank
5. Pumps, recirculation, venturi
6. Pumps, recirculation, absorber
7. Booster fan
8. Heat exchanger
9. Soot blowers
10. Ducting
11. DtfEfting valves
12. Feed surge and sulfite storage tanks
13. Agitator for |80|
14. Storage silos
15. Vibrators for
16. Dissolving tank and agitators
17. Dissolving tank pump
18. Evaporator feed preheater
19. Evaporator feed preheater pump
20. Evaporator
21. Evaporator feed pump
Item
mi v
A
Total,$
V
71
78
81
[93
11.02
H
P
EV
WELLMAN-LORD SCRUBBING
E-67
-------
EQUIPMENT COST
Description
22. Evaporator reboiler-lst stage
23. Evaporator reboiler-2nd stage
24. Primary condenser
25. S02 condenser
26. Condensate receiver
27. Condensate pump
28. Stripper
29. Stripper pump
30. SO2 blower
31. Dissolving tank
32. Agitators for dissolving tank
33. Dissolving tank pumps
34. Purge stream heat exchanger
35. Refrigeration unit
36. Refrigeration heat exchanger
37. Glycol tank
38. Glycol pumps
39. Crystallizer
40. Crystallizer pump
41. Centrate tank
42. Dryer and elevator
Item
Total,$
El
E2
SO.
1135
GST
GLP
CRY
CT
WELLMAN-LORD SCRUBBING
E-68
-------
EQUIPMENT COST
Description Item Total> $
43. Make-up water pump
Total Equipment Cost
Total predicted equipment cost = Cost Index Factor Total Equipment
from Chart 30 x cost
x = $
Predicted turnkey cost of H2S04 plant =
H0SO, Plant Cost Cost Index Factor
3m 148 x from Chart 30
x = $
WELLMAN-LORD SCRUBBING E-69
-------
§
CO
o
§
00
H
2!
O
M
I
-j
o
1971
1973
1975 ' 1977
YEAR ENDING
1979
1981
1983
1985
Chart 30. COST INDEX FACTOR
-------
CAPITAL INVESTMENT COSTS—WELLMAN-LORD
Direct costs:
ii/-•"
t system required
aterial
abor
Retrofit
Easy
Moderate
Difficult
Absorber
1.83 Xa
1.445 X
0.98 X
0.528 X
Absorber-Venturi
-1.752 X
"I. 4 65 X
0.99 X
0.607 X
Materials and Labor
Absorber
0
0.047 X
0.093 X
Absorber-Venturi
0
0.039 X
0.077 X
Cost,$
Check
One
X = Eredicted Equipment cost from page E-69
"D" Raw materials: Chart 2, item (T
Ib/hr Na2Co3
x 720 x $0.024/lb£
"E" Predicted turnkey cost of H-SO. plant
"F" Direct costs ("A" + "B" + "C" + "D") above
"G" Direct costs ("A" through "E" incl.) above
"H" Direct costs ("A" + "B" + "C") above
Indirect costs:
t
"J" Interest, contractor fee and expenses, engineering, freight,
offsite, taxes, start-up, spares.
0.33"G" + 0.1"H" + 0.065"A" =
_+ +_ =
11K" Contingency
0.2 ("J" + "F") =
0.2C
i$42.00-$54.00/ton as of 12-30-74 "Chemical Marketing Report"
WELLMAN-LORD SCRUBBING
E-71
-------
CAPITAL INVESTMENT COSTS—WELLMAN-LORD
"L" Total costs for Capital Investment:
"G" + "J" + "K"
Cost/kilowatt:
II T II
x 1,000
= $.
megawatts x 1,000
— = $ /kw
WELLMAN-LORD SCRUBBING E-72
-------
TOTAL ANNUAL OPERATING COSTS—WELLMAN-LORD
Raw Materials-
From pageE-7, Chart 2, item fl2] recorded,
ton/yr Na2CO3
From "Chemical Marketing Report" of December 30, 1974 cost/ton
Na2C03 is $42-00 to $54.00 use $48.00/ton
ton/yr Na-CO., x $
[63 yearly cost raw materials
Cost:
.x $48.00/ton = $
Utilities-
Electrical:
(0.03 x.
x $0.
1774 x
.MW x 8760 x 0..
.weighed capacity factor
from data sheet
MW
/KWH x 1000 KW/MW) =
weighed
Capacity factor
x 0
I64{ cost/yr
.= $.
Water:
(total gpm)
weighed
capacity factor
x 60 min/hr x 8760 hr/yr x 0.
x $0.02 cost of water/1000 gal. = |165|
1000
Chart 28, item |155|
total gpm x
CF
165) cost/yr
10.5 x
x 0.
.= $.
WELLMAN-LORD SCRUBBING
E-73
-------
TOTAL ANNUAL OPERATING COSTS — WELLMAN-LORD
Utilities-
Fuel for reheat:
Chart 3, item \16\
combined
acfm at 125°F
[PG reheat AT 50op] ; (59.4 x ) +
Chart 2, item |j[
Ib S02/hr
[evaporator feed preheater] ; (317.5 x ) +
Chart 2, item [¥]
Ib S02/hr
[condensate stripper] ; (1065 x ) +
Chart 2, item [_8
Ib S02/hr
[dryer] ; (74 x ) =
Chart 3, item 16 comb. Chart 2, item [8|
acfm-at 125°F Ib SO2/hr
(59.4 x ) + (1456.5 x
166| cost/year
Operating labor-
MW's: 0-1300 1301-3000
Direct: Men/shift 5 7
( men/shift x 8760 hr/yr x $6.50/man-hr) =
57,000 x men/shift = $ [16.7] cost/year
WELLMAN-LORD SCRUBBING E_74
-------
TOTAL ANNUAL OPERATING COSTS--WELLMAN-LOKD
Supervision: 0.15 x |l67f=0.15 x
Maintenance-
168
Labor and materials: 4% of "L", total capital investments
0.04 x "L"
J169) cost/year
Supplies: 15% of labor and materials:
0.006 x "L" = $
J.70) cost/year
Overhead-
Plant: 50% of operation and maintenance:
Tfif" +
1681
+
m +173
Payroll: 20% of operating
r*
0.2 x (
Fixed costs-
168
.) = $_
cost/year
cost/year
1.00
Straight line depreciation: Equip. life*(Plant life
but not to exceed 20 yrs.)
Interim replacement
Insurance
Taxes
Capital cost
= 0.
173
% of fixed investment = [f73| + |J74
T76| +
o.
0.0035
0.003
0.04
0.08
0.
HI
1791 cost/year
WELLMAN-LORD SCRUBBING
E-75
-------
TOTAL ANNUAL OPERATING COSTS—WELLMAN-LORD
Other costs-
Acid handling costs/year =
Acid resale/year =
Other costs/year (indicate)
Total annual cost-
+
f6|
isg +
Cost/KWH-
Total annual cost
8760 hrYyr x.
$
_MW x 1000 KW/MW
,-7
x 1.14 x 10 ) r_
$ 0.
$.
$.
$
+ [T69| + |T70|
MW =
./KWH [184
|83| cost/year
If hourly rate different than $6.50, correct |167| x
new rate
6.50
= $_
167|
it*
167| if applicable
WELLMAN-LORD SCRUBBING
E-76
-------
ANNUAL OPERATING COSTS
Description
1. Raw Materials
2. Untilities: Electrical
3 - Water
Reheat
3. Operations: Labor
Supervision
4. Maintenance: Labor and Materials
Supplies
5. Overhead: Plant
Payroll
6. Fixed Costs
7. Other Costs: Acid Handling
Acid Resale
Other
Total Annual Costs:
Cost/KWH
Total
*"" * i
183) x (1.14 x 10"') =
./KWH
WELLMAN-LORD SCRUBBING
E-77
-------
APPENDIX F
RAPID PROCEDURES FOR ESTIMATING CAPITAL
AND ANNUAL OPERATING COSTS FOR FLUE GAS
CLEANING SYSTEMS (FGC)
RAPID PROCEDURES F~1
-------
RAPID PROCEDURES FOR ESTIMATING CAPITAL AND ANNUAL
OPERATING COSTS FOR FLUE GAS CLEANING SYSTEMS (FGC)
PLANT DATA
Complete the following operating data form for all
boilers at the plant.
Maximum continuous capacity, MW
Capactiy factor, %
Boiler remaining life, years
Fuel consumption/hour
Flue gas rate, ft3/min
Flue gas temperature, °F
Allowable S02 rate, lb/106 Btu
Allowable particulate rate,
lb/106 Btu
Estimated duct run, ft
Ash content of fuel, %
Sulfur content of fuel, %
Heating value of fuel, Btu/unit
Efficiency of existing parti-
culate control device, %
1
2
3
4
Boiler No.
Using the parameters listed above, calculate the values of
the following factors to be used in the cost equations.
RAPID PROCEDURES
F-2
-------
A: Ash Removal Rate, ton/hr
Using the proper emission factor from AP-42, and
efficiency of existing control equipment, calculate ash
removal rate (ton/hr) . Add together ash removal rate
for each boiler to obtain plant rate A. If no ash
removal is required, use value of A = 0 in the cost
equations.
S: SO., Removal Rate, ton/hr
Using the proper emission factor from AP-42, and allow-
able rate, calculate S02 removal rate (ton/hr) . Add
together SO- removal rate for each boiler to obtain
total plant rate S.
G: Plant Flue Gas Rate — ft3/min at 300 °F
Calculate the flue gas rate at 300°F (G, , G9, --- G ) for
Jm £ iC
each boiler using the following equation:
Flue gas rate of 300°F = actual flue gas rate x
_ 760 _
460 + temp, of flue gas
Add GI + G2 + G3 --- + GX to get G
N: Number of Scrubbing Trains at the Plant
Calculate number of trains for each boiler.
450,000 450,000, 450,000
Round off Nlf N2, N3 . . . Nx to next whole number.
N = N +N + N- • . . . + N = total number of trains.
123 x
RAPID PROCEDURES F~3
-------
DF: Duct Factor
Calculate duct factor for each train.
_ Estimated duct run for train 1
1 300
DF2 = Estimated duct run for train 2 etc
300
Average DF = DF1 + DF2 + DF3 ' ' ' + DFN
N
CF: Average Capacity Factor
CP1 x mi + CF2 x MW2 . . . + C
MW, 4- MW, + MW, . . . + MW
-L ^ j
CF, = Capacity factor for Boiler 1
MW, = Capacity in MW for Boiler 1
BRLY: Average Boiler Remaining Life in Years
BRLY = BRLY1 x ^l + BRLY2 x ^2 ' • • + BRLY
MW + MW9 . . . + MW
JL i&> .?C
BRLY. = Boiler remaining life for Boiler 1
(if BRLY is >20 assume BRLY = 20)
The input factors discussed above are common for all FGC
systems and are required for calculating the capital costs.
The input factors for annual operating costs are different
for each system. These factors are discussed at the
beginning of each annual cost procedure.
RAPID PROCEDURES F-4
-------
LIME FGC CAPITAL COST
A. LIME PREPARATION
Conveyor
Storage silos
Slaker
Pumps and motors
Storage tank
B- S02 SCRUBBING
Absorbers
Fans and motors
Pumps and motors
Tanks
Reheaters
Soot blower
Ducting
Valves
C. SLUDGE DISPOSAL
Clarifiers
Vacuum filters
Tanks and mixers
Fixation chemical
storage
Pumps and motors
EQUATION
3800 S + 248,600
18,440 S + 165,000
945 S + 5338/S
5,548 S + 32,000
When S<34 = 2,778 S + 18,000
When S>34 = 3856 S
Subtotal - A
3.374 G
0.71 G (Abs only)*
0.983 G (Abs + Vent)
0.16 + 36,000 N
9.02 (|)2/3 x N + 47.64 (|)1/3
0.828 G
0.3605 G + 25,100 N
417.60/GN x DF
0.268 G
Subtotal - B
COST, $
x N
37,475/2.0132 S + A
15,093 S + 7,496 A + 310,400
2/3
236.48 [2.0132 S + A]
+ 1618.6 [2.0132 S + A]
1229 S + 22,000
1/3
0.0148 G + 2308 S + 1,146 A + 12,000
* Use only one appropriate equation.
RAPID PROCEDURE: LIME
F-5
-------
SLUDGE DISPOSAL; (Continued) EQUATION COST, $
Sludge Pond 64,155/(2.1032 S + A) CF x BRLY
Mobile equipment 1207 S + 22,000
New roadways, 30,000 N
RR siding
Subtotal - C
D. PARTICULATE REMOVAL: (Needed only when particulate control
is necessary, otherwise these costs are zero).
Venturi scrubber 2.205 G
Tanks 9.02 (|) 2/3 x N + 47.64 (|) -1/3 x N
Pumps and motors 0.1 G + 36,000 N
Subtotal - D
TOTAL (A + B + C + D)
t ADJUSTED DIRECT COST = ESC. FACTOR x TOTAL
INDIRECT COST
Interest during construction 0.1 t
Field labor and expenses 0.1 t
Contractor fees and expenses 0.05 t
Engineering 0.10 t
Freight 0.0125 t
Offsite 0.03 t
Spares 0.015 t
Taxes 0.005 t
Allowance for Shakedown 0.05 t
t^ TOTAL INDIRECT COST
CONTINGENCY = 0.2 ( t + t., )
GRAND TOTAL = 1.2 ( t + t )
S/kW = GRAND TOTAL
7 MW x 1000
RAPID PROCEDURE: LIME F-6
-------
LIME FGC ANNUAL OPERATING COST
Obtain following cost and mileage data for the plant under
consideration:
Electricity, mills/kWh = ELCO
Lime, $/ton = LMCO
Labor, $/hr = LBCO
Sludge Trucking Distance, miles = TMGE
Reproduce the following plant data as computed/listed
in lime capital cost estimation procedure:
Plant Capacity, MW = MW
Number of Scrubbing Trains = N
Gas Flow Rate, acfm @ 300°F = G
SO, Removal Rate, T/hr = S
^
Ash Removal Rate, T/hr = A
Capacity Factor = CF
Remaining Life = BRLY
Total Capital Cost = GRTL
Use the equations listed on the following pages to obtain
annual operating cost.
RAPID PROCEDURE: LIME F-7
-------
A. OPERATING COST
Raw Material
EQUATION
COST, $
Lime 8,876 x S x LMCO x CF
Fixation ehemical 29,200(2.0328 + A)x CF
Utilities
Electricity*
Water
Reheat
Labor
Direct Labor*
Supervision
Maintenance
Labor and
Materials
Supplies
Overhead
Plant
0.044 x G x ELCO x CF
(Coal burning with Abs +
Vent)
0.040 x G x ELCO X CF
(Coal burning with Abs)
0.028 x G X ELCO x CF
(Oil burning with Abs)
0.0142 x G x ELCO x CF
0.021 x G x ELCO X CF
17,520 x LBCO(N<4)
26,280 x LBCO (N=5 or 6)
4,380 x N x LBCO (N>6)
0.15 x direct labor
0.04 x GRTL
0.006 x GRTL
0.50 x (Labor +
maintenance)
* Use only one appropriate equation.
RAPID PROCEDURE: LIME
F-8
-------
Overhead (continued)
Payroll
B. FIXED COST
Depreciation
Interim Replacement
Taxes
Insurance
Capital Charges
C. TRUCKING COST
Sludge Trucking
EQUATION
0.20 x labor
COST, $
A. Total Operating Cost = $
GRTL/BRLY
0.0035 x GRTL
0.04 x GRTL
0.003 X GRTL
0.09 x GRTL
B. Total Fixed Cost = $
(2.0132S + A) x 29,200
x TMGE x CF = $
D = TOTAL ANNUAL COST = A+B+C
Mills/kWh = D/(8,760 x CF x MW)
= $
RAPID PROCEDURE: LIME
F-9
-------
LIMESTONE FGC CAPITAL COST
A. LIMESTONE PREPARATION
EQUATION
COST, $
Conveyors
Storage silo
Ball mill
Pumps and motors
Storage tanks
B. SO2 SCRUBBING
Absorbers
Fans and motors
Pumps and motors
Tanks
Reheaters
Soot blowers
Ducting
Valves
C. SLUDGE DISPOSAL
Clarifiers
Vacuum filters
Tanks and mixers
8,025 S + 248,600
4,794 S + 32,816
16,050 S + 375,000
11,640 S + 4,000 N + 30,500
4,588 S + 16,630/S H- 234 S2/3
Subtotal - A
4.2824 G
0.53 G (Abs. only)*
0.8425 G (Abs + Vent)
0.232 G + 24,000 N
0.089 G + 108.60/NG
0.828G
0.3605 G + 25,100 N
417.60/GN x DF
0.268 G
Subtotal - B
37,475^3.14 S + A
23,540 S + 7,496 A + 310,400
236.48 [3.14 S + A]
2/3
+ 1618.6 [3.14 S + A]
1/3
Fixation chemical 1582 S + 10,940
storage
Pumps and motors 0.0148 G + 3600 S + 1146 A + 12,000
* Use only one appropriate equation.
RAPID PROCEDURE: LIMESTONE
F-10
-------
C. SLUDGE DISPOSAL; (Continued) EQUATION COST, $
Sludge pond 64,155>/(3.14 S + A) CF x BRLY
Mobile equipment 1,883 S + 22,000
New roadways, 30,000 N
RR siding
Subtotal - C
D. PARTICULATE REMOVAL; (Needed only when particulate control
is necessary, otherwise costs are not to be calculated).
Venturi scrubber 2.205 G
Tanks 0.011 G + 31.25/GN
Pumps and motors 0.056 G + 20,000 N
Subtotal - D
TOTAL: (A + B + C + D)
t ADJUSTED DIRECT COST = ESCAL. FACTOR X TOTAL
INDIRECT COST;
Interest during construction 0.1 t
Field labor and expenses 0.1 t
Contractor fees and expenses 0.05 t
Engineering 0.1 t
Freight 0.0125 t
Offsite 0.03 t
Spares 0.015 t
Taxes 0.005 t
Allowance for shakedown 0.05 t
t, TOTAL INDIRECT COST
CONTINGENCY 0.2,. . ,
\ -c. f ^ ;
GRAND TOTAL 1.2 , . v
It + tl )
GRAND TOTAL
?/KW MW x 1000
RAPID PROCEDURE: LIMESTONE F-ll
-------
LIMESTONE FGC ANNUAL OPERATING COST
Obtain following cost and mileage data for the plant under
consideration:
Electricity, mills/kWh = ELCO
Limestone, S/ton = LSCO
Labor, $/hr = LBCO
Sludge Trucking Distance, miles = TMGE
Reproduce the following plant data as computed/listed
in limestone capital cost estimation procedure:
Plant Capacity, MW = MW
Number of Scrubbing Trains = N
Gas Flow Rate, acfm @ 300°F = G
SO2 Removal Rate, T/hr = S
Ash Removal Rate, T/hr = A
Capacity Factor = CF
Remaining Life = BRLY
Total Capital Cost = GRTL
Use the equations listed on the following pages to obtain
annual operating cost.
RAPID PROCEDURE: LIMESTONE F-12
-------
A. OPERATING COST
Raw Material
Limestone
Fixation Chemical
Utilities
Electricity*
Water
Reheat
Labor
Direct Labor*
Supervisxon
Maintenance
Labor and
Materials
Supplies
Overhead
Plant
EQUATION
18,747 x S x LSCO x CF
29,200(3.143 + A)x CF
0.044 x G x ELCO x CF
(Coal burning with Abs +
Vent)
0.040 x G x ELCO X CF
(Coal burning with Abs)
0.028 x G X ELCO x CF
(Oil burning with Abs)
(0.129G + 2520S) x
0.0049 x ELCO x CF
0.021 x G x ELCO x CF
17,520 x LBCO(N<4)
26,280 x LBCO (N=5 or 6)
4,380 X N x LBCO (N>6)
0.15 x direct labor
COST, $
0.04 x GRTL
0.006 x GRTL
0.50 x (Labor +
maintenance)
* Use only one appropriate equation.
RAPID PROCEDURE: LIMESTONE
F-13
-------
Overhead (continued)
Payroll
B. FIXED COST
Depreciation
Interim Replacement
Taxes
Insurance
Capital Charges
C. TRUCKING COST
Sludge trucking
EQUATION
0.20 x labor
COST, $
A. Total Operating Cost = $
GRTL/BRLY
0.0035 x GRTL
0.04 x GRTL
0.003 x GRTL
0.09 x GRTL
B. Total Fixed Cost = $
(3.14S + A) x 29,200
x TMGE x CF = $.
D = TOTAL ANNUAL COST = A+B+C = $
Mills/kWh = D/(8,760 x CF x MW)
RAPID PROCEDURE: LIMESTONE
F-14
-------
DOUBLE ALKALI FGC CAPITAL COST
A. Na2C03 PREPARATION
Storage silos and
conveyors
Feed tank
Pumps and motors
B. LIME PREPARATION
Storage silos and
conveyors
Slaker
Slaker pump and
motor
C. SO2 SCRUBBING
Absorber
Fan and motor
Pumps and motors
Tanks
Reheater
Soot blower
Ducting
Valves
EQUATION
82,040 + 465 S
29.19 S2/3 + 55.33 S1/3
8,000
Subtotal - A
COST, $
When S<_35 = 5732 S + 262,000
When D>35 = 6008 S + 244,400
472.44 S + 2,669/S
260 S + 7,000
Subtotal - B
1.347 G
0.39 G (Abs + Vent)*
0.265 G (Abs only)
14,000 N + 0.0251 G
3.192 (|)2/3 x N + 20 (§)1/3 x N
0.251 G
0.0986 G
160/GN x DF
0.103 G
N'
Subtotal - C
* Use only one appropriate equation.
RAPID PROCEDURE: DOUBLE ALKALI
F-15
-------
D. REGENERATION AND SLUDGE DISPOSAL EQUATION COST/ $
Reactor When S<26.75 = 2000 S + 8694/S
When S>26.75 = 1589 S + 9235/S
Fixation silos 5470 + 379 S
Clarifiers 14,990/2.1 S + A
Vacuum filters 3,936 S + 1874 A + 77,600
Tanks and mixers 118.24 [2.1 S + A]2//3 ,-
+ 809.29 [2.1 S + A] '
Pumps and motors 0.0037 G + 602 S + 286.4 A + 3,000
Subtotal - D
E. PARTICULATE REMOVAL; (Needed only when particulate
control is necessary otherwise, these costs are not
to be calculated).
Venturi scrubber 0.735 G
Tanks 3.192 (§)2/3 x N + 20 (§)1/3 x N
N N
Pumps and motors 14,000 N + 0.0251 G
Subtotal - E
a Total equipment cost =(A+B+C+D+E) _
b Total installed cost* = Absorber only 3.397 x a
Absorber + venturi 3.389 x a _
c Sludge pond cost = 64,155/(2.1 S + A) CF x BRLY
d New roadways, RR siding = 30,000 N
t ADJUSTED DIRECT COST = ESC. FACTOR X ( b + c + d )
* Use only one appropriate equation.
RAPID PROCEDURE: DOUBLE ALKALI F-16
-------
INDIRECT COSTS EQUATION COST, $
Interest during construction 0.1 t
Field labor and expenses 0.1 t
Contractor fees and expenses 0.05 t
Engineering 0.1 t
Freight 0.0125 t
Offsite 0.03 t
Spares 0.015 t
Taxes 0.005 t
Allowance for shakedown 0.05 t
^ TOTAL INDIRECT COST
CONTINGENCY = 0.2 ( t + t^ )
GRAND TOTAL = 1.2 ( t + t± )
GRAND TOTAL
MW x 1000
RAPID PROCEDURE: DOUBLE ALKALI F 17
-------
DOUBLE ALKALI FGC ANNUAL OPERATING COST
Obtain following cost and milage data for the plant under
consideration:
Electricity, mills/kWh = ELCO
Lime, $/ton = LSCO
Soda Ash, $/ton = SACO
Labor, $/hr = LBCO
Sludge Trucking Distance, miles = TMGE
Reproduce the following plant data as computed/listed
in double alkali capital cost estimation procedure:
Plant Capacity, MW = MW
Number of Scrubbing Trains = N
Gas Flow Rate, acfm @ 300°F = G
SO2 Removal Rate, T/hr = S
Ash Removal Rate, T/hr = A
Capacity Factor = CF
Remaining Life = BRLY
Total Capital Cost = GRTL
Use the equations listed on the following pages to obtain
annual operating cost.
RAPID PROCEDURE: DOUBLE ALKALI F-18
-------
A. OPERATING COST
Raw Material
EQUATION
COST, $
Lime 8,876 x S x LMCO x CF
Soda Ash 727 x S x SACO x CF
Fixation Chemical 29,200(2.01328 + A)x CF
Utilities
Electricity*
Water
Reheat
Labor
Direct Labor*
Supervision
Maintenance
Labor and
Materials
Supplies
Overhead
Plant
0.044 x G x ELCO x CF
(Coal burning with Abs +
Vent)
0.040 x G x ELCO X CF
(Coal burning with Abs)
0.028 x G X ELCO X CF
(Oil burning with Abs)
0.0142 x G x ELCO x CF
0.021 x G x ELCO x CF
17,520 x LBCO(N<4)
26,280 x LBCO (N=5 or 6)
4,380 x N x LBCO (N>6)
0.15 x direct labor
0.04 x GRTL
0.006 x GRTL
0.50 x (Labor +
maintenance)
* Use only one appropriate equation.
RAPID PROCEDURE: DOUBLE ALKALI
F-19
-------
Overhead (continued)
Payroll
B. FIXED COST
Depreciation
Interim Replacement
Taxes
Insurance
Capital Charges
C. TRUCKING COST
Sludge trucking
EQUATION
0.20 x labor
COST, $
A. Total Operating Cost = $
GRTL/BRLY
0.0035 x GRTL
0.04 x GRTL
0.003 x GRTL
0.09 x GRTL
B. Total Fixed Cost = $
(2.0132S + A) x 29,200
x TMGE x CF = $
D = TOTAL ANNUAL COST = A+B+C =
Mills/kWh = D/(8,760 x CF x MW)
$
RAPID PROCEDURE: DOUBLE ALKALI
F-20
-------
MAGNESIUM OXIDE FGC CAPITAL COST
A. MgO PREPARATION
Storage silos
Slurry tank
Pump and motor
B. S02 SCRUBBING
Absorbers
Fans and motors
Pumps and motors
Tanks
Reheater
Soot blower
Ducting
Valves
EQUATION
When S _>9: 7527 S + 115,480
When S <9: 4754 S + 16,436
1395.3 S + 7960/S
500 S + 2,000
Subtotal - A
0.898 G
Abs 0.208 G*
Abs + vent 0-312 G
0.083 G + 16,000 N
0.087 G + 62.77/GN
0.1873 G
0.0986 G
160/GN x DP
0.103 G
COST, $
Subtotal - B
C. PURGE TREATMENT AND REGENERATION
Storage silo
Centrifuge
Dryer
Centrate tank and
pump
Pump and motor
12,110 S + 40,000
0.215 G
0.15 G + 200,000
0.007 G + 9,000
0.00526 G
Subtotal - C
* Use only one appropriate equation.
RAPID PROCEDURE: MAGNESIUM OXIDE
F-21
-------
D. PARTICULATE REMOVAL EQUATION COST, $
(Calculate these costs only if particulate removal is
involved).
Venturi scrubber 0.735 G
Tanks 3.192 (|)2/3 x N + 20(|)1/3 x N _
Pumps and motors 0.0568 G + 1902 A + 12,000 N + 3,000.
Calciner 29,800/A _
Dust collectors 0.0533 G + 90,000 _
Subtotal - D
a Total equipment cost = (A + B + C + D)
b Total installed cost* = absorber only = 3.243 a
absorber and venturi = 3.287 a
c Sludge pond = 64,155/A x CF x BRLY
d New roadways, RR siding = 30,000 N
t ADJUSTED DIRECT COST = ESC. FACTOR X ( b + c + d )
INDIRECT COST
Interest during construction 0.1 t
Field labor and expenses 0.1 t
Contractor fees and expenses 0.05 t
Engineering 0.1 t
Freight 0.0125 t
Offsite 0.03 t
Spares 0-015 t
Taxes 0.005 t
Allowance for shakedown 0.05 t
t1 TOTAL INDIRECT COST
CONTINGENCY 0.2 ( t + t± )
GRAND TOTAL 1.2 ( t + t-j)
S/VW = GRAND TOTAL
9/ m x 1000
* Use only one appropriate equation.
RAPID PROCEDURE: MAGNESIUM OXIDE F-22
-------
MAGNESIUM OXIDE FGC ANNUAL OPERATING COST
Obtain following cost and mileage data for the plant under
consideration:
Electricity, mills/kWh = ELCO
MgO, $/ton = MGCO
Coke, $/ton = COKC
Labor, $/hr = LBCO
Sludge Trucking Distance, miles = TMGE
Fuel Oil, $/gal. = FOLC
Reproduce the following plant data as computed/listed
in MgO capital cost estimation procedure:
Fuel Sulfur Content, percent = PSC
Plant Capacity, MW = MW
Number of Scrubbing Trains = N
Gas Flow Rate, acfm @ 300°F = G
SO» Removal Rate, T/hr = S
Ash Removal Rate, T/hr = A
Capacity Factor = CF
Remaining Life = BRLY
Total Capital Cost = GRTL
Use the equations listed on the following pages to obtain
annual operating cost.
RAPID PROCEDURE: MAGNESIUM OXIDE F-23
-------
A. OPERATING COST
EQUATION
COST, $
Raw Material
MgO
Coke
Utilities
Electricity*
Water
Reheat
Labor
Direct Labor*
Supervision
Maintenance
Labor and
Materials
Supplies
Overhead
Plant
608.8 x S x CF x MGCO
0.000182G x PSC x CF x COKC
0.044 x G x ELCO x CF
(Coal burning with Abs +
Vent)
0.04 x G x ELCO X CF
(Coal burning with Abs)
0.028 x G X ELCO x CF
(Oil burning with Abs)
0.0172 x G x ELCO x CF
(0.021 x ELCO + 3.18 x
PSC x FOLC) x G x CF
17,520 x LBCO(N<4)
26,280 x LBCO (N=5 or 6)
4,380 x N x LBCO (N>6)
0.15 x direct labor
0.04 x GRTL
0.006 x GRTL
0.50 x (Labor +
maintenance)
* Use only one appropriate equation.
RAPID PROCEDURE: MAGNESIUM OXIDE
F-24
-------
Overhead (continued)
Payroll
B. FIXED COST
Depreciation
Interim Replacement
Taxes
Insurance
Capital Charges
C. TRUCKING COST
Sludge Trucking
EQUATION
0.20 x labor
COST, $
A. Total Operating Cost = $.
GRTL/BRLY
0.0035 x GRTL
0.04 x GRTL
0.003 x GRTL
0.09 x GRTL
B. Total Fixed Cost = $
29,200 x T-MGE x A X CF = $
D = TOTAL ANNUAL COST = A+B+C
Mills/kWh = D/(8,760 x CF x MW)
= $
RAPID PROCEDURE: MAGNESIUM OXIDE
F-25
-------
WELLMAN LORD FGC CAPITAL COST
A. Na2C03 PREPARATION
Storage silo
Vibrating feeder
Storage tank
Agitators
Pumps and motors
B. SO., SCRUBBING
Absorbers
Fans and motors
Pumps and motors
Reheaters
Soot blowers
Ducting
Valves
C. PURGE TREATMENT
Refrigeration unit
Heat exchanger
Tanks
Dryer
Elevator
Pumps and motors
EQUATION
10,800 + 5,993 S
3,750 + 2 S
2,185.5 S2/3 -I- 17,103 S1/3
9,000 + 1,300 S2/3
1,200 + 56.64 S
Subtotal - A
5.025 G
Abs only = 0.3806 G*
Abs + vent = 0.5552 G
0.147 G
0.877 G
0.361 G + 25,100 N
417.60/GN x D.F.
0.268 G
Subtotal - B
0.1428 G
0.022 G
780 S2/3 + 8414 S1//3 + 0-018 G
14,000 + 1,036 S
10,000
0.04844 G + 26,130 S + 4,000
COST, $
* Use only one appropriate equation.
RAPID PROCEDURE: WELLMAN LORD
F-26
-------
C. PURGE TREATMENT; (Continued) EQUATION
Centrifuge
Crystallizer
Storage silo
COST, $
Feeder
New roadways,
RR siding
D. REGENERATION
Pumps and motors
Evaporators and
reboilers
Heat exchangers
Tanks
Stripper
Blower
0.2964 G
0.343 G
10,800 + 5,993 S
3,750 + 2 S
30,000 N
Subtotal - C
75,000 + 4,992 S2/3 + 30,781 S
463,880 S + 23,624 S2/3
64,603 S
13,707 S
2/3
3,500 + 37,170/S
20,300 S
Subtotal - D
E. PARTICULATE REMOVAL; (Needed only when particulate control
is required, otherwise these costs are not to be calculated).
Venturi scrubber 2.205 G
0.011 G + 31.52/GN
0.056 G + 20,000 N
Subtotal - E
TOTAL = (A + B + C + D + E)
t ADJUSTED DIRECT COST = ESC. FACTOR X TOTAL
Tanks
Pumps and motors
RAPID PROCEDURE: WELLMAN LORD
F-27
-------
INDIRECT COSTS
EQUATION
COST, $
Interest during construction
Field labor and expenses
Contractor fees and expenses
Engineering
Freight
Offsite
Spares
Taxes
Allowance for shakedown
Acid plant 880,133 x (S x CF)
tl TOTAL INDIRECT COST
CONTINGENCY 0.2 ( t +
GRAND TOTAL 1.2 ( t +
GRAND TOTAL
0.1 x t
0.1 x t
0.05 x t
0.1 x t
0.0125 x t
0.03 x t
0.015 x t
0.005 x t
0.05 x t
0.596
$/kW =
MW x 1000
RAPID PROCEDURE: WELLMAN LORD
F-28
-------
WELLMAN LORD PGC ANNUAL OPERATING COST
Obtain following cost data for the plant under
consideration:
Electricity, mills/kWh = ELCO
Soda Ash, $/ton = SASH
Labor, $/hr = LBCO
Sludge Trucking Distance, miles = TMGE
H2SO4 Market Cost, $/ton = SADC
Na2SO. Market Cost, $/ton = NATC
Reproduce the following plant data as computed/listed
in Wellman-Lord capital cost estimation procedure:
Plant Capacity, MW = MW
Number of Scrubbing Trains = N
Gas Flow Rate, acfm @ 300°F = G
SO, Removal Rate, T/hr = S
Ash Removal Rate, T/hr = A
Capacity Factor = CF
Remaining Life = BRLY
Total Capital Cost = GRTL
Use the equations listed on the following pages to obtain
annual operating cost.
RAPID PROCEDURE: WELLMAN LORD F-29
-------
A. OPERATING COST
Raw Material
Soda Ash
Utilities
Electricity
Water
Reheat
Labor
Direct Labor*
Supervision
Maintenance
Labor and
Materials
Supplies
Overhead
Plant
EQUATION
972 x SASH x CF x S
0.05 x G x ELCO x CF
(0.022G + 3500S)x ELCO x CF
(0.021G + 15,4008) x
ELCO x CF
17,520 x LBCO(N<4)
26,280 x LBCO (N=5 or 6)
4,380 x N x LBCO (N>6)
0.15 x direct labor
COST, $
0.04 x GRTL
0.006 x GRTL
0.50 x (Labor +
maintenance)
* Use only one appropriate equation.
RAPID PROCEDURE: WELLMAN LORD
F-30
-------
Overhead (continued)
Payroll
B. FIXED COST
Depreciation
Interim Replacement
Taxes
Insurance
Capital Charges
C. CREDITS
H2S04
EQUATION
0.20 x labor
COST, $
A. Total Operating Cost = $
GRTL/BRLY
0.0035 x GRTL
0.04 x GRTL
0.003 x GRTL
0.09 x GRTL
B. Total Fixed Cost = $
11,826 x S x CF X SADC.
874 x S X CF x NATC
C. Total Credit
D. TOTAL ANNUAL COST = A + B - C
Mills/kWh = D/(8,760 x CF x MW) =
RAPID PROCEDURE: WELLMAN LORD
F-31
-------
APPENDIX G
METRIC SYSTEM CONVERSION FACTORS
METRIC SYSTEM
CONVERSION FACTORS
-------
APPENDIX G. METRIC SYSTEM CONVERSION FACTORS
Length
Units
1 in. =
1 ft
1 yd
1 mile =
Area
Units
1 in. =
1 ft2
1 yd2
1 mile =
Volume
Units
1 in. =
1ft3
1 qt
1 gal (U.S.)
Mass
Units
1 oz (avdp) =
1 Ib (avdp)
1 ton
Energy
Units
1 cal
cm
2.54
30.48
91.44
1.609344 x
2
cm
6.4516
929.0304
8361.273
2.589988 x
cm
16.38706
28316.85
946.353
3785.412
g
28.34952
453.5924
907184.7
Btu
3.965667
x 10~3
m
0.0254
0.3048
0.9144
105 1.609344 x 103
2
m
6.4516 x 10~4
0.09290304
0.8361273
1010 2.589988 x 106
liter
0.01638706
28.31685
0.946353
3.785412
kg Metric ton
0.02834952
0.4535924
907.1837 0.9071847
kWh
1.1622222...
x 10"6
METRIC SYSTEM
CONVERSION FACTORS
G-2
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/2-76-150
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE Simplified Procedures for Estimating
Flue Gas Desulfurization System Costs
5. REPORT DATE
June 1976
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)T.C. Ponder Jr. , L.V.Yerino, V.Katari,
Y.Shah, andT.W.Devitt
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORQANIZATION NAME AND ADDRESS
PEDCo-Environmental Specialists, Inc.
Suite 13, Atkinson Square
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
1AB013; ROAP 21ADE-010
11. CONTRACT/GRANT NO.
68-02-1321, Task 12
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 5/74-3/76
14. SPONSORING AGENCY CODE
EPA-ORD
15. SUPPLEMENTARY NOTES JJERL-RTP task officer for this report is Charles J. Chatlynne,
Mail Drop 61, Ext 2915.
16. ABSTRACT
repOr^ gives procedures for estimating the capital costs and annualized
operating costs for five flue gas desulfurization (FGD) systems: lime, wet limestone,
magnesium oxide, Wellman-Lord, and double alkali. Two methods are given for
calculating the costs for the five systems: a detailed, flexible nomograph procedure,
and a rapid equation procedure. All items that affect the capital and annualized
operating costs of FGD systems in these estimating procedures are identified. Costs
estimated by the procedures are compared with actual costs incurred by FGD system
operators. Any differences between the estimated and actual costs are accounted for;
the estimating procedures are modified when necessary.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATl Field/Group
Air Pollution
Flue Gases
Desulfurization
Cost Estimates
Calcium Oxides
Limestone
Alkalies
Air Pollution Control
Stationary Sources
Flue Gas Desulfurization
Wellman-Lord
Double Alkali
13B
21B
07A,07D
14A,05A
07B
08G
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
iGES
20. SECURITY CLASS (Thispage)
Unclassified
_2Q8_
22. PRICE
EPA Form 2Z20-1 (9-73)
------- |