3/7-80-1/12
United States
Environmental Protection
Agency
Research and Development
Division of Energy
Demonstrations and Tec
Muscle Shoals AL 3566
Office of Environmental
Engineering and Technology
Washington DC 20460
EPA 600 7-80-142
August 1980
NATO-CCMS Flue
Gas Desulfurization
Pilot Study
Phase II
Applicability Study
Interagency
Energy/Environment
R&D Program
rt
"7
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3 Ecological Research
4 Environmental Monitoring
5 Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9 Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects, assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EDT-114
May 1980
NATO-CCMS
FLUE GAS DESULFURIZATION PILOT STUDY
PHASE II - APPLICABILITY STUDY
Prepared by
R. L. Torstrick, S. V. Tomlinson, J. R. Byrd, and J.D. Veitch
Tennessee Valley Authority
Division of Energy Demonstrations and Technology
Office of Power
Muscle Shoals, Alabama 35660
and
Richard W. Gerstle
PEDCo Environmental, Inc.
Cincinnati, Ohio 45246
EPA-TVA Interagency Agreement D9-E721-GO, Task 1 (TV-41967A)
Program Element No. INE 828
EPA Project Officer: Frank T. Princiotta
United States Environmental Protection Agency
Washington, D.C. 20460
1980
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FOREWORD
Under the auspices of the North Atlantic Treaty Organization's
Committee for the Challenges to Modern Society (NATO-CCMS), a two
phase study of Flue Gas Desulfurization was conducted.
The rapid evolution of flue gas desulfurization technology along
with increasing interest in this technology for reducing sulfur dioxide
emissions prompted the NATO-CCMS to form a Study Group to assess and
summarize information on these systems. This study initiated early in
1977 at a meeting of the member countries' delegates in London. The
United States through its Environmental Protection Agency was the lead
or pilot country with Norway and the Federal Republic of Germany the
co-pilot countries. This study group met at approximately 6-month
intervals to review progress, comment on completed work, and plan the
succeeding steps.
The initial phase of this study consisted of a survey of existing
FGD systems used on larger combustion processes in the NATO countries
and Japan. Twelve FGD systems were surveyed and reports summarizing
their status were prepared - NATO-CCMS Report No. 95.
This report comprises the second phase of this study, also built
upon the early survey results by studying the applicability of nine FGD
processes for typical North American and European fuels.
ii
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ACKNOWLEDGMENT
This report was prepared by the Flue Gas Desulfurization Study Group
of the NATO Committee on the Challenges of Modern Society. Mr. Frank T.
Princiotta of the U.S. Environmental Protection Agency served as chairman.
Acknowledgment should be given to the U.S. Tennessee Valley Authority (TVA)
and PEDCo Environmental, Inc., for their major role in preparing early
drafts of the report. TVA and PEDCo prepared this report to the specific
guidelines of the committee; ultimately the committee reviewed, revised, and
approved the publication of the report. The members of the study group were:
Country
Canada
Denmark
Germany
(Co-Pilot Country)
Greece
Italy
Netherlands
Norway
(Co-Pilot Country)
Name
Mr. M. E. Rivers
Mr. T. Bambrough
Mr. B. Colliander
Dr. P. Davids
Dr. G. Reimann
Dr. G. Weisser
Mr. E. Mavromichalis
Mr. D. Merluzzi
Mr. R. Bosma
Mr. F. van der Brugghen
Dr. 0. Erga
Dr. H. Kolderup
Mr. G. Gaupset
Mr. A. Tokerud
Affiliation
Environment Canada
Air Pollution Control Directorate
ELSAM (Electrical Cooperative)
Umwe1tb un de s amt
(Federal Environmental Agency)
Federal Ministry of the Interior
Battelle Institute
Public Power Corporation of
Greece
ENEL (State Power Company)
Energy Research Foundation
Energy Research Foundation
Foundation of Scientific and
Industrial Research
Foundation of Scientific and
Industrial Research
State Pollution Control Authority
A/S Norsk Viftefabrikk
iii
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Country Name
United Kingdom Dr. J. Bettelheim
Mr. S. Dearnley
Mr. A. Littler
Mr. M. F. Tunnicliffe
United States
(Pilot Country)
Mr. N. Nicholson
Mr. F. Princiotta
Mr. R. L. Torstrick
Mr. R. Gerstle
Affiliation
Central Electricity Research
Laboratory
Department of Energy
Central Electricity
Generating Board
HM. Deputy Chief
Alkali and Clean Air Inspector
Davy Powergas, Ltd.
U.S. Environmental Protection
Agency
U.S. Tennessee Valley Authority
PEDCo Environmental, Inc.
IV
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PREFACE
The tjorth Atlantic Treaty Organization Committee on the Challenges
of Modern Society (NATO-CCMS) Flue Gas Desulfurization (FGD) Study Group
prepared status reports on 12 FGD processes. Results of this work are
summarized in NATO Report No. 95 titled "Flue Gas Desulfurization Pilot
Study Phase I - Survey of Major Installations - Summary of Survey Reports
on Flue Gas Desulfurization Processes."
The Phase I reports were reviewed by the NATO-CCMS delegates in
April 1978 and nine of the processes were selected for comparative
economic evaluations as Phase II of the study. The purpose of the
Phase II study is to provide procedures and technical and economic data
for the selection of FGD processes for specific applications. The study
consists of technical feasibility and economic evaluations developed by
the U.S. Tennessee Valley Authority (TVA) and a decision-chart selection
procedure developed by PEDCo Environmental, Inc.
The basis of the economic evaluations is an FGD system for a new
Midwestern U.S. 500-MW power plant. The FGD system is designed for
removal of 90% of the S02 in the flue gas. Six fuels, consisting of
bituminous coals, lignite, and oil, are evaluated. Scaling procedures
are provided for projection of costs for other conditions such as
different power plant sizes and fuels with different sulfur levels.
The decision-chart system consists of an elimination procedure
which rates the applicability of the processes relating the FGD process
characteristics to specific site conditions. The system is an initial
selection procedure which allows FGD selection efforts to be focused on
the most promising processes.
v
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DISCLAIMER
This report was prepared by the Tennessee Valley Authority and has
been reviewed by the Office of Environmental Energy and Technology, U.S.
Environmental Protection Agency, and approved for publication. It has
also been reviewed and agreed to in principle by the NATO-CCMS Flue Gas
Desulfurization (FGD) Study Group. Approval does not signify that the
contents necessarily reflect the views and policies of the Tennessee
Valley Authority or the U.S. Environmental Protection Agency, or of any
representative of the NATO-CCMS FGD Study Group, nor does mention of
trade names or commercial products constitute endorsement or recommenda-
tion for use.
-------
CONTENTS
Preface v
Figures ix
Tables x
Abbreviations and Conversion Factors xi
Executive Summary xiii
Introduction and Discussion .... 1
Processes Evaluated 5
Limestone Scrubbing with Untreated Sludge Waste Disposal ..... 5
Lime Scrubbing with Untreated Sludge Waste Disposal 5
Double-Alkali Scrubbing with Untreated Sludge Waste Disposal ... 5
Seawater Scrubbing with Ocean Disposal of Oxidized Waste 6
Lime Scrubbing with Oxidation and Dewatered Gypsum Waste Disposal . 6
Jet-Bubbling Limestone Scrubbing with Dewatered Gypsum Disposal . . 6
Magnesium Oxide Scrubbing with Sulfuric Acid Production 6
Sodium Sulfite Scrubbing with Sulfuric Acid and Sulfur Production . 7
Dry Carbon Adsorption with Sulfur Production 7
Premises'for Economic Evaluations 8
Design Premises 8
Power Plant 8
Fuel 8
Flue Gas Composition 8
Removal Efficiencies 10
FGD Systems 10
Economic Premises 12
Capital Costs 12
Annual Revenue Requirements 14
Byproduct Sale 17
Scaling 17
Scaling Factors 17
Scaling Procedure 19
Annual Revenue Requirements 21
Accuracy of Results and Technical Qualifications 25
Results 26
Elements in Selecting an FGD System 39
Factors Involved in FGD Process Selection 39
Major Raw Material Requirements 39
Major End Products 41
Performance Requirements 41
Plant Site Considerations 41
Example Use 41
vii
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Process Rating 43
System Status 46
Raw Materials 46
Byproducts 47
Control Efficiency 47
Energy Needs 47
Costs 48
Suppliers of FGD Systems 51
References 54
Appendixes
A Limestone Sludge Process A-l
B Lime Sludge Process B-l
C Double-Alkali Sludge Process C-l
D Seawater Process D-l
E Lime Gypsum Process (Saarberg-Holter Process) E-l
F Jet-Bubbling Limestone Process - Chiyoda Thoroughbred 121
Process F-l
G Magnesium Oxide Process G—l
H Sodium Sulfite Process (Wellman-Lord) H-l
I Carbon Adsorption Process 1-1
viii
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FIGURES
Number Page
S—1 Base-case unit investment range for alternate processes . . xxii
S-2 Base-case unit revenue requirement range for alternate
processes xxiii
1 Effect of relative product rate on relative pond cost
(relative product rate for 500-MH, 3.5% sulfur coal
equals 1.0; based on 15% solids sludge settling to
40Z solids) 20
2 Effect of power plant size on scaling factor for
operating labor and supervision cost 20
3 Base-case unit investment range for alternate processes , . 37
4 Base-case unit revenue requirement range for alternate
processes 38
5 PGD selection matrix 40
6 Example selection matrix for an inland, new 500-MH power
plant with strict effluent restrictions burning high-
sulfur oil 42
7 Example selection matrix for an existing seacoast plant
with limited area and 15 years remaining life, burning
1Z sulfur coal 44
8 FGD rating chart 45
9 Process applicability rating chart applied to example
No. 1 49
10 Process applicability rating chart applied to example
No. 2 50
IX
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TABLES
Number Page
S-l Summary - Base-Case FGD Design Assumptions xvii
S-2 Summarized Results - Energy, Land, Capital Investment,
and Annual Revenue Requirements xx
1 Projected As-Fired Fuel Composition for Base Case and
Alternate Fuels 9
2 Estimated Flue Gas Compositions for Power Units Without
Emission Control Facilities 11
3 Cost Indexes and Projections 13
4 Projected Mid-1980 Unit Costs for Raw Materials, Labor,
and Utilities 15
5 Scaling Data for Power Plant Size and Fuel Variations ... 18
6 Capital Investment Scaling Illustration - Limestone
Sludge Process Base Case Scaled to 200 MW 22
7 Annual Revenue Requirements Scaling Illustration -
Limestone Sludge Process Base Case Scaled to 200 MW .... 23
8 Limestone Sludge Process Material, Energy, and Cost
Summary 27
9 Limestone Sludge Process Size Variations, Material,
Energy, and Cost Summary 28
10 Lime Sludge Process Material, Energy, and Cost Summary ... 29
11 Double-Alkali Sludge Process Material, Energy, and Cost
Summary 30
12 Seawater Process Material, Energy, and Cost Summary .... 31
13 Lime Gypsum (Saarberg-Holter) Process Material, Energy,
and Cost Summary 32
14 Jet-Bubbling Limestone (Chiyoda Thoroughbred 121)
Process Material, Energy, and Cost Summary 33
15 Magnesium Oxide Process Material, Energy, and Cost
Summary 34
16 Sodium Sulfite (Wellman-Lord) Process Material, Energy,
and Cost Summary 35
17 Carbon Adsorption Process Material, Energy, and Cost
Summary ..... 36
18 Suppliers of FGD Systems in the United States 52
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ABBREVIATIONS
ABBREVIATIONS AND CONVERSION FACTORS
bbl
Btu
cal
C
cm
°C
°F
ESP
FD
FGD
FRP
ft
g
gal
gpm
ha
hp
hr
ID
in.
in. head
j
k
kg
kW
kWh
L/G
Ib
M
m
meq
mm
mol
MW
Nm3
NOX
pa
ppm
psi
Psig
rpm
$
sec
sft3
SOX
SS
TCA
TM
tons
actual cubic feet
42 U.S. gallon barrel
British thermal unit
calorie
U.S. cents
centimeter
degree Celsius
degree Fahrenheit
electrostatic precipitator
forced draft
flue gas desulfurization
fiberglass reinforced polyester
foot
gram
U.S. gallon
U.S. gallon per minute
hectares
horsepower
hour
induced draft
inch
inches l^O head
joule
thousand (kilo-)
kilogram
kilowatt
kilowatthour
liquid to gas
pound
million (106)(mega-)
meter
milliequivalent
millimeter
mole
megawatt
normal cubic meter (at 0°C)
nitrogen oxides
pascal
parts per million
pounds per square inch
pounds per square inch, gauge
revolutions per minute
U.S. dollar
second
standard cubic foot (60°F)
sulfur oxides
stainless steel
Turbulent Contact Absorber (TM)
registered trademark
short tons
xi
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CONVERSION FACTORS
To convert from
English units
To
Multiply by
acre
barrels of oil
British thermal unit
degrees Fahrenheit-32
feet
square feet
cubic feet
a
gallons
grains (troy)
grains per cubic foot
inches H20 head
pounds
pounds per square inch
miles
mills
short tons^
standard cubic feet
per minute (60°F)
hectare
liters
kilocalories
degrees Celsius
meters
square meters
cubic meters
liters
grams
grams per cubic meters
pascals
kilograms
pascals
meters
U.S. dollars
metric tons
normal cubic meters
per hour (0°C)
0.405
158.97
0.252
0.555
0.3048
0.093
0.0283
3.785
0.0648
2.288
249
0.4536
6895
1609
0.001
0.907
1.608
a. All gallons are expressed as U.S. gallons in this report.
b. All tons, including tons of sulfur, are expressed in short
tons in this report.
xii
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NATO-CCMS
FLUE GAS DESULFURIZATTON PILOT STUDY
PHASE II - APPLICABILITY STUDY
EXECUTIVE SUMMARY
INTRODUCTION
The Phase I reports on 12 flue gas desulfurization (FGD) processes
for the North Atlantic Treaty Organization Committee on the Challenges
of Modern Society (NATO-CCMS) FGD Study Group were reviewed by the NATO-
CCMS delegates in April 1978 and 9 of the processes were selected for
comparative economic evaluations as Phase II of the study. The purpose
of the Phase II study is to provide procedures and technical and economic
data for the selection of FGD processes for specific applications. The
study consists of technical feasibility and economic evaluations developed
by the U.S. Tennessee Valley Authority (TVA) and a decision-chart
selection procedure developed by PEDCo Environmental, Inc.
The basis of the economic evaluations is an FGD system for a new
Midwestern U.S. 500-MW power plant. The FGD system is designed for
removal of 90% of the S02 in the flue gas. Six fuels, consisting of
bituminous coals, lignite, and oil, are evaluated. Scaling procedures
are provided for projection of costs for other conditions such as
different power plant sizes and fuels with different sulfur levels.
The design and economic bases of this study differ from the Phase I
study because of updated information and standardizations to provide
comparable results between processes. The results of this study should
be compared to the Phase I results with caution. It should also be
recognized that the data are based on U.S. conditions and that simpli-
fying assumptions are made in the design model. These factors must be
borne in mind when using the cost comparisons. Site-specific conditions
may substantially alter the cost relationships of the processes.
The decision-chart system consists of an elimination procedure
which rates the applicability of the processes relating the FGD process
characteristics to specific site conditions. The system is an initial
selection procedure which allows FGD selection efforts to be focused on
the most promising processes.
xiii
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PROCESSES EVALUATED AND ACCURACY OF RESULTS
The nine process evaluations in this study are based on data from a
number of sources. Because of differences in the stage of development
and amount of information available, the accuracy ranges of the economic
results differ. Stage of development is difficult to quantify and is
not considered in these evaluations. The accuracy ranges can, however,
be related to the amount of information available. Normally, actual
investment costs may be expected to depart from those shown in the
economic evaluation by a factor of 0.7 to 1.5. Because of the extensive
information available for some of the processes evaluated, however,
smaller ranges can be projected. The accuracy ranges of each process,
based on the amount of information available, are shown in the tabulated
results. The nine processes evaluated are discussed below.
Limestone Scrubbing with Untreated Sludge Waste Disposal
The process evaluated is a generic design based on extensive TVA
data from prototype and operational facilities and on general industry
information. It is an updated version of the process described in the
Phase I report.
Lime Scrubbing with Untreated Sludge Waste Disposal
The process evaluted is a generic design based on TVA data from
prototype studies and on general industry information. It is also an
updated version of the process reported in the Phase I report.
Double-Alkali Scrubbing with Untreated Sludge Waste Disposal
The process evaluated is a generic design based on prototype tests
of system components. The process is an updated version of the process
reported in the Phase I report.
Seawater Scrubbing with Ocean Disposal of Oxidized Waste
The process evaluated is based on the Flakt-Hydro process in opera-
tion on industrial boilers (of 50-MW total equivalent capacity) at
Porsgrunn, Norway. Information was obtained from the Phase I report
with supplemental data provided by the Foundation of Scientific and
Industrial Research at the University of Trondheim, Norway, and A/S
Norsk Viftefabrikk, Oslo, Norway. Because the process assumes that only
seawater from the power plant condensers is used in the scrubbers, the
3.5% and 2.0% sulfur coals are not evaluated.
Lime Scrubbing with Oxidation and Dewatered Gypsum Waste Disposal
The process is based on the Saarberg-Holter process described in
the Phase I report and additional information from Davy Powergas,
Inc., the U.S. licensee. A 40-MW prototype was started up in 1974 and a
175-MW unit in 1979, both in West Germany.
xiv
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Jet-Bubbling Limestone Scrubbing with Dewatered Gypsum Disposal
This process is based on the Chiyoda Thoroughbred 121 process that
was developed from the Chiyoda Thoroughbred 101 process reported in the
Phase I report. The process is based on information supplied by
Chiyoda International Corporation.
Magnesium Oxide Scrubbing with Sulfuric Acid Production
The process evaluated is a generic design based on general industry
information. It is an updated version, incorporating several process
changes, of the process described in the Phase I report.
Sodium Sulfite Scrubbing with Sulfur and Sulfuric Acid Production
The process evaluated is based on Wellman-Lord scrubbing with
regeneration of 862 and production of sulfuric acid. An alternate
process based on Wellman-Lord/Allied Chemical technology for producing
elemental sulfur is also included. It is an updated version of the
process described in the Phase I report, incorporating several process
changes. Additional information was provided by Davy Powergas, Inc.,
the Allied Chemical Company, and the Northern Indiana Public Service
Company.
Dry Carbon Adsorption with Sulfur Production
The process evaluated is based on the Bergbau-Forschung Foster
Wheeler RESOX^ process using published information and additional infor-
mation' from the Foster Wheeler Corporation. The SOX removal process was
developed by Bergbau-Forschung GmbH. A 50-MW unit is operational at
Lunen, West Germany. A Foster Wheeler RESOX® SC>2 reduction process is
used to reduce the SC>2 to elemental sulfur using anthracite.
PREMISES FOR THE ECONOMIC EVALUATIONS
The design and economic premises used were developed by TVA and
others for comparative FGD cost studies using representative U.S. power
plant conditions. The base case is a frontal-fired, balanced-draft 500-MW
power plant constructed in the period 1977 to 1980 in the U.S. Midwest
for startup in 1980. The plant is assumed to have a 30-year lifetime of
117,500 operating hours and to operate 6,000 hours in the first year.
Fly ash removal of 99.2% by electrostatic precipitators (ESP) upstream
of the FGD system is not included in FGD costs. The base case fuel is a
3.5% sulfur, 16% ash, 5,830 kcal/kg high heat rate bituminous coal. For
this fuel and all other solid fuels it is assumed that 95% of the sulfur
and 80% of the ash are emitted in the flue gas. For oil all of the
sulfur in the fuel is assumed emitted in the flue gas.
The FGD systems are assumed to be installed downstream from the ESP
units. For the wet systems the flue gas is supplied from a common
plenum to four parallel trains of SOX removal equipment including booster
xv
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FD fans and reheat provisions. Presaturators to cool the gas from 149°
to 53°C and mist eliminators to reduce liquid entrainment to 0.1Z are
provided. Indirect steam reheat (or direct-fired for oil-fired units
used in the FGD process) is provided to reheat the gas entering the
stack plenum to 79°C. The dry adsorption process is similar except two
trains are used and reheat is not required. Costs for chloride removal
facilities are included for the regenerable processes, however, costs
for chloride disposal facilities are excluded. The FGD system consists
of the common plenum and all equipment downstream to the stack plenum,
including all raw material and effluent processing equipment and land
requirements. Removal efficiencies are assumed to be 90% of the S(>2,
50% of the 803, 95% of the chloride, and 75% of the remaining fly ash
in the flue gas. Specific conditions for the FGD processes are shown in
Table S-l.
The economic premises are based on U.S. regulated utility economics
and financing. The costs estimated consist of capital costs for construc-
tion of the FGD system and annual revenue requirements for the first-
year operation. All costs are based on Midwestern U.S. costs using mid-
1979 as the basis of capital costs and mid-1980 as the basis for annual
revenue requirements. Capital costs consist of all direct and indirect
costs for equipment, land, materials, labor, fees, services, and other
construction costs required to install the FGD system. Annual revenue
requirements, based on a first-year, 6000-hour operation, consist of all
raw material, labor, utility, and other conversion costs and indirect
costs such as capital charges, taxes, and overheads. Byproduct sales
for processes producing elemental sulfur, t^SO^, gypsum and sodium
sulfate are included as credits. For the gypsum-producing processes,
however, costs for disposal of gypsum may be obtained where necessary by
substituting a disposal charge for stacking or landfill of the gypsum in
place of the credit. These costs are projected to range between $4 and
$9 per ton of dry solids, depending on site-specific conditions.
Case Variations
Case variations, in which design assumptions are varied to determine
effect on costs, are also evaluated. Except for the seawater process,
0.8%, 1.4%, and 2.0% sulfur bituminous coal; 0.5% sulfur lignite; and
2.5% sulfur oil fuels are included. The seawater process is not evaluated
for the 2.0% and 3.5% sulfur coals because those coals would require
additional seawater in addition to condenser water. Other case variations
consist of 200-, 700-, and 1000-MW power plant sizes for the limestone
sludge process; reheat to 53°C for the seawater process; and a sulfur
production case for the Wellman-Lord process.
In addition to the case variations reported it is possible to scale
other power plant size and fuel variaions using relative gas and product
rates and scaling factors. Data and procedures for scaling are provided
in the report.
xvi
-------
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-------
RESULTS
Process and economic evaluation results are shown in Table S-2.
The accuracy ranges for the base case capital investment and annual
revenue requirements are shown in Figures S-l and S-2. All capital
investments are in mid-1979 U.S. dollars; all revenue requirements are
in mid-1980 U.S. dollars.
ELEMENTS IN SELECTING AN FGD SYSTEM
Decisions on selection of an FGD process for a particular situation
must consider four site-specific conditions: raw material costs, the
desired end product, performance requirements, and plant site conditions.
By development of a chart-based matrix which defines and relates FGD
process characteristics, the site-specific conditions can be compared
with the FGD process characteristics to eliminate impracticable processes.
After elimination of impracticable processes, the remaining processes
can be rated by a similar procedure to identify their relative feasibility.
The system applies ratings to the FGD system operability, process require-
ments, and costs. These ratings are then compared with the specific
site requirements to further define the more practical processes.
Detailed procedures and charts for using the procedure are included in
the report.
xix
-------
TABLE S-2. SUMMARIZED RESULTS - ENERGY, LAND, CAPITAL INVESTMENT,
AND ANNUAL REVENUE REQUIREMENTS
Energy
consumption, 7, Land,
Process of input energy hectares
Limestone Sludge
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
200 MW, 3.5% S in coal
700 MW, 3.5% S in coal
1000 MW, 3.5% S in coal
Lime Sludge
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
Double-Alkali Sludge
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
Seawater
0.8% S in coal
1.4% S in coal
0.5% S in lignite
2.5% S in oil
1.4% S in coal, low reheat
Lime Gypsum
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
Jet-Bubbling Limestone
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
3.
3.
3.
3.
3.
2.
3.
3.
3.
3.
3.
3.
3.
3.
2.
2.
2.
2.
2.
2.
1.
4.
4.
4.
3.
2.
2.
2.
3.
3.
2.
2.
3.
3.
3.
3.
3.
2.
3
2
2
3
3
7
4
3
3
3
1
2
2
3
5
5
4
5
5
5
9
2
2
2
5
8
9
9
2
7
9
5
4
3
3
4
3
6
42
56
78
127
34
70
64
163
213
35
47
66
107
28
57
38
49
67
104
36
53
2
2
2
2
2
5
5
5
5
5
5
5
5
5
5
5
5
Annual revenue
Capital investment requirements
M$
40.
41.
45.
53.
39.
40.
26.
71.
93.
37.
38.
42.
47.
37.
37.
40.
42.
46.
53.
39.
40.
29.
30.
29.
27.
28.
35.
36.
39.
44.
34.
34.
42.
42.
43.
47.
42.
38.
0
6
5
1
0
6
3
0
9
8
9
0
7
2
3
5
2
0
2
6
7
6
0
1
9
6
5
5
2
0
9
8
0
0
8
0
1
5
$/kW
80
83
91
106
78
81
132
101
94
76
78
84
96
74
75
81
84
92
J07
79
81
59
60
58
56
57
71
73
78
88
70
70
84
84
88
94
84
77
M$
11
11
12
14
10
11
7
19
26
11
11
12
15
10
11
11
11
13
16
10
11
8.
8.
8.
8.
7.
9.
10.
11.
13.
9.
10.
10.
10.
11.
12.
11.
10.
.
7
7
5
6
8
8
3
4
7
6
3
9
9
4
2
0
2
2
5
6
6
9
4
0
7
4
1
5
6
0
8
4
2
8
1
0
8
9
Mills /kWh
3,
3,
4.
4.
3.
3.
5.
4,
4,
3.
3.
4.
5,
3,
3.
3
3.
4.
5
3,
4.
2.
2.
2.
2.
2.
3.
3c
3,
4,
3.
3.
3,
3.
3.
4.
3,
3,
.7
.9
.2
,9
.7
,8
.9
.7
.4
7
.8
.2
.0
.6
.8
.7
.9
.4
.3
.6
.0
.9
.9
.8
.9
.6
.3
,4
.8
.6
.2
,5
.7
,6
.8
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(continued)
XX
-------
TABLE S-2 (continued)
Process
Magnesium Oxide
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
Sodium Sulfite
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
3.5% S in coal, sulfur
production
Energy
consumption, %
of input energy
3.9
4.1
4.8
6.3
3.8
3.7
4.1
4.6
5.7
8.1
3.9
4.5
9.9
Land,
hectares
3
3
3
3
3
3
3
3
3
3
3
3
3
Capital investment
M$
48.9
52.0
58.1
68.4
47.1
44.6
46.8
50.3
56.9
68.7
44.8
44.2
71.3
$/kW
98
104
116
137
94
89
94
101
114
137
90
88
143
Annual revenue
requirements
M$
12.9
13.7
15.1
17.5
12.6
12.0
12.2
13.1
14.8
17.9
11.8
11.8
21.0
Mills/kWh
4.3
4.6
5.0
5.9
4.2
4.0
4.1
4.4
4.9
6.0
3.9
3.9
7.0
Carbon Adsorption
0.8% S in coal
1.4% S in coal
2.0% S in coal
3.5% S in coal
0.5% S in lignite
2.5% S in oil
0.6
0.8
1.0
1.7
0.5
0.9
51.2
54.2
60.8
73.5
49.5
53.7
102
108
122
147
99
107
13.9
15.8
20.0
28.5
12.8
17.5
4.6
5.3
6.7
9.5
4.3
5.9
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-------
NATO-CCMS
FLUE GAS DESULFURIZATION PILOT STUDY
PHASE II - APPLICABILITY STUDY
INTRODUCTION AND DISCUSSION
The Phase I report (1) prepared for the North Atlantic Treaty
Organization Committee on the Challenges of Modern Society (NATO-CCMS)
Flue Gas Desulfurization (FGD) Study Group describes 12 FGD processes
using data derived from a number of sources. During the April 1978
meeting of the NATO-CCMS delegates in Norway the 12 processes were
reviewed and 9 were selected for further economic evaluation as Phase II
of the NATO-CCMS study.
This Phase II study was prepared jointly by the U.S. Tennessee
Valley Authority and PEDCo Environmental, Inc. It consists of economic
analyses of the nine FGD processes for a variety of fuels and power
plant sizes and a selection matrix procedure for selection of an FGD
process based on plant site characteristics and technical requirements.
The economic evaluations can be used to identify the most economical
processes. A limited technical and state-of-development review of each
process is provided as a further aid in assessing accuracies and appli-
cability of the data. The selection matrix provides a method of narrowing
the number of FGD processes to be considered for a particular applica-
tion by a process of elimination.
The technical and economic evaluations are based on cost analysis
procedures developed by TVA for a number of FGD economic evaluations
conducted during the past several years. The evaluations are made using
consistent design and economic premises which permit equitable com-
parisons of different processes. The design premises define a representa-
tive U.S. electric utility SOO^IW power plant. Six fuels—bituminous
coals, lignite, and oil—are evaluated. The economic premises are based
on U.S. regulated-utility economics and are calculated in U.S. dollars.
The premises permit cost projections to other power plant sizes and to
other cost-base years by use of scaling factors and economic indexes.
The selection matrix system for identification of feasible FGD
processes provides a procedure which relates specific site conditions
and requirements to the capabilities and characteristics of each FGD
-------
process. Impracticable processes are excluded from consideration and
the remaining processes are weighed. The system is an initial-selection
procedure which allows FGD process selection efforts to be narrowed,
thus focusing attention on the most promising processes for a particular
application.
It must be emphasized that the data for this report are derived on
a different base than the data in the Phase I report (1,2). Therefore,
there is no overall relationship between the data in the Phase I report
and this report and comparisons must be made with extreme caution. The
differences result from both updated technology and updated design and
economic premises.
It is also very important when studying the cost data in this
report that the underlying technical and economic assumptions are fully
understood. The economic bases in particular relate only to present
U.S. conditions. The report only derives comparative costs and its
value does not lie as much in the absolute values as in illustrating the
relativities between the FGD processes and the economic significance of
elements within each process.
The economic premises should be carefully noted. While it would
undoubtedly have been helpful to the participating countries to have
utilized premises more appropriate to West Europe, it was not possible
to do so within the scope of this report. It is possible that if this
were to be done it would show significant changes in relativities. To
obtain the results various simplifying technical assumptions have unavoid-
ably had to be made. Each FGD process involves the disposal of some
solid or liquid waste products to the surrounding environment. Liquid
effluents can include purged reagents or, more commonly, soluble chlorides
derived from the coal. Solid wastes contain some soluble materials
which can leach into the ground. With the processes that produce gypsum,
some or all of the byproduct may be salable but some may need to be
discarded as waste, depending upon market conditions. With the processes
that produce sulfuric acid, elemental sulfur, or sodium sulfate it must
be presumed that all the output is sold.
An aspect which also deserves mention is that some of the FGD
processes studied in this report are linked to a single contracting
company or group whereas others are offered by several contractors. In
the latter case a variety of equipment designs may be available with
differing investment and revenue requirements.
All of the matters mentioned above have an effect upon the overall
economics of the FGD installation and in certain circumstances the
effect may completely alter the relativities of process costs. The
importance of these factors must be borne in mind when studying the cost
comparisons. Reference may usefully be made to Section 5 of the NATO-
CCMS Summary Report, No. 95 (2).
Unless the qualifications outlined in the preceding paragraphs are
taken fully into consideration there is a risk that conclusions may be
-------
drawn that will not correspond with the real circumstances. The cost
data in this report represent a "coarse sieve." They can be valuable in
delineating the major cost areas of the FGD processes and in directing
attention to areas where improvements may be sought.
The primary objective of this study is to evaluate FGD processes in
terms of their applicability and economics. As such, the FGD processes
are considered as an entity, separate from other control procedures
which may also be necessary in the overall power plant operation to
control emissions and effluents. Fly ash control, for example, is not
included in these evaluations although it is a necessary adjunct to
power plant operations with many fuels. Other wastes such as nitrogen
oxides, bottom ash, blowdown, waste water, and storage area runoff may
also require control. An integrated waste-control system incorporating
all necessary aspects of waste control for a particulate site may offer
economic advantages. In evaluating the FGD processes in this study for
a particulate site, therefore, it may be advantageous to consider control
of nitrogen oxides and fine particulates as well as sulfur, and the
ultimate disposal of collected waste products in an integrated emission-
effluent control system.
Many important items have not been studied in great detail in
Phases I and II of this study. New FGD techniques are being developed,
designed primarily to overcome technical and economic imperfections of
the present generation of FGD processes. Spray-drying techniques are
examples of these developments. Existing systems are being improved to
decrease energy consumption. Other important developments are the
application of gas - gas reheat systems, the simplification of scrubbers,
the increase of the reactivity of the absorbent using minor amounts of
additives, and improved mist eliminator designs.
For economic considerations, the expected lifetime of the installa-
tion is an important variable. FGD systems have now been in operation
for several years and it could be of great value to evaluate maintenance
records as a means of determining expected lifetimes.
A very important problem is the use or disposal of the sulfur-
containing byproduct in an environmentally acceptable way. Especially,
disposal of sludge and possibly gypsum can create problems. Leaching of
soluble compounds can be a potential danger to the quality of groundwater.
In this context it is very important to develop potential applications
for sludge and to find new applications for gypsum.
It is hardly possible to operate wet FGD systems without a waste
water purge, either from a prescrubber or from the main scrubbing loop.
This waste water can introduce the necessity of a waste water treatment.
In addition to FGD other techniques to decrease S02 emissions are
in use or in the development stage. Fuel desulfurization, such as hydro-
desulfurization of fuel oils and coal cleaning, fluidized-bed combustion
of fuel oils and coal, and coal gasification, is being investigated.
-------
The NATO-CCMS Study Group has noted the continuing improvement in
existing FGD systems, the development of new FGD systems, the growing
concern about secondary pollution by solid and liquid wastes, and the
use and development of other techniques to decrease S(>2 emission to the
atmosphere, such as fluidized-bed combustion and spray drying/absorption
processes. Because of these developments, consideration of processes
for meeting SC^ emission regulations should not be limited to those
processes included within this study. With the growing international
interest in SC>2 control, the study group is strongly of the opinion that
a continuing examination and review of existing and newly developed FGD
systems and the secondary pollution problems related to these systems
should be undertaken within the NATO-CCMS forum. In a later phase other
desulfurization techniques can be evaluated. Having developed already a
strong working relationship and understanding, the present NATO-CCMS
Study Group should be fully capable of this task.
-------
PROCESSES EVALUATED
LIMESTONE SCRUBBING WITH UNTREATED SLUDGE WASTE DISPOSAL
The process evaluated is a generic design based on the large body
of information available on limestone scrubbing. TVA also has a consid-
erable amount of internal data from the EPA-sponsored Shawnee test
program and the 550-MW Widows Creek power plant scrubbing unit. A
computer program has been developed for calculating limestone and lime
scrubbing economics which is used in economic evaluations of these
scrubbing processes (3). TVA has published a detailed evaluation of
these processes (4). An updated definitive economic and energy-use
evaluation has also been published (5). Because of the large body of
technical, operational, and economic data on the limestone process,
actual investments could vary within a range of 0.85 to 1.20 times the
projected capital investment results.
LIME SCRUBBING WITH UNTREATED SLUDGE WASTE DISPOSAL
The process evaluated is a generic design based on the extensive
information available for this process, including considerable data from
the Shawnee test program. A computer program is used to conduct economic
evaluations of lime scrubbing processes. Except for absorbent feed
preparation and details of operating conditions and stoichiometry the
process is similar to the limestone sludge process. In addition to a
previous study of this process (4), an updated definitive economic and
energy-use evaluation of this process has been published (6). Because
of the large amount of information on the lime process, actual invest-
ments could vary within a range of 0.85 to 1.20 times the projected
capital investment results.
DOUBLE-ALKALI SCRUBBING WITH UNTREATED SLUDGE WASTE DISPOSAL
The process evaluated is a generic design based on a substantial
body of industry information and experience with components of the
system. Large-scale application of the entire process in utility use is
only in the construction stage, however. A definitive economic evalua-
tion of this process prepared by TVA has been published (5). Because of
the large amount of information available on process components, although
operational information is limited, actual investments could vary within
a range of 0.80 to 1.30 times the projected capital investment results.
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SEAWATER SCRUBBING WITH OCEAN DISPOSAL OF OXIDIZED WASTE
The process evaluated is based on the Flakt-Hydro process using
information obtained from the Foundation of Scientific and Industrial
Research at the University of Trondheim, Norway, and A/S Norsk Vifte-
fabrikk, Oslo, Norway. The process is in operation on three industrial
boilers of A/S Norsk Hydro, Porsgrunn, Norway (with a total capacity
equivalent to a 50-MW power plant) using glass-fiber-reinforced poly-
ester scrubbers and alkali neutralization of the waste stream. The
process evaluated in this study uses neoprene-lined steel scrubbers and
condenser cooling water for absorption and neutralization. In addition,
only the low-sulfur coals and oil are evaluated because it is assumed
that only condenser water is used for scrubbing. Higher sulfur coals
would require additional seawater or alkali addition. Actual invest-
ments could vary within a range of 0.70 to 1.50 times the projected
capital investment results.
LIME SCRUBBING WITH OXIDATION AND DEWATERED GYPSUM WASTE DISPOSAL
The process evaluated is based on the Saarberg-Holter process using
additional data supplied by Davy Powergas, Inc., Houston, Texas. The
process was developed by Saarberg-Holter Umwelttechnik GmbH, Saarbrucken,
West Germany. Although the extent of developmental work on this process
is somewhat limited in comparison to other processes it has been under
development and evaluation for several years and is currently being
installed both on operational utility boilers and on industrial
processes. Davy Powergas is the U.S. licensee for the process. Actual
investments could vary within a range of 0.70 to 1.50 times the projected
capital investment results.
JET-BUBBLING LIMESTONE SCRUBBING WITH DEWATERED GYPSUM DISPOSAL
The process evaluated is based on the Chiyoda Thoroughbred 121
process, an evolution of the Chiyoda Thoroughbred 101 process described
in the NATO-CCMS Phase I study. The amount of developmental work on
this process is also not as extensive as for other processes. The
design is based on information supplied by Chiyoda International Corpora-
tion, Seattle, Washington. The process is being evaluated on a 23-MW
prototype unit at the Scholz Steam Plant of Gulf Power Company in Sneads,
Florida. Actual investments could vary within a range of 0.70 to 1.50
times the projected capital investment results.
MAGNESIUM OXIDE SCRUBBING WITH SULFURIC ACID PRODUCTION
The process evaluated is based on a generic design representing
general industry information. The magnesium oxide process in the
Phase I study is based on a 1975 TVA evaluation (4). Since that time
additional operating experience has been gained with developmental and
prototype units. In particular, modifications have been made in the
-------
dewatering and drying steps and additional heat recovery capabilities
have been incorporated. An updated definitive economic and energy—use
evaluation of the -magnesium oxide process has been published (6). This
information has been incorporated into the current study. Actual invest-
ments could vary within a range of 0.80 to 1.30 times the projected
capital investment results.
SODIUM SULFITE SCRUBBING WITH SULFURIC ACID AND SULFUR PRODUCTION
The process evaluated is based on Wellman-Lord scrubbing process
with regeneration of S02 and production of sulfuric acid. An alterna-
tive process based on Wellman-Lord/Allied Chemical technology for pro-
ducing elemental sulfur with natural gas reduction is also included. A
definitive economic evaluation of the Wellman-Lord/Allied Chemical
process was made by TVA in 1975 (4). This evaluation is the basis of
the Phase I study. A considerable amount of additional information on
this process based on additional development and prototype and commer-
cial operating experience has been obtained since the 1975 evaluation,
and is incorporated into this evaluation. In addition to published
information, data were supplied by Davy Powergas, Inc., Lakeland, Florida,
the Allied Chemical Company, New York, and the Northern Indiana Public
Service Company, Gary, Indiana. The major changes are the use of
double-effect instead of single-effect evaporators, elimination of the
antioxidant, use of common wall scrubber units, sulfate control by high
temperature crystallization, smaller process tanks, additional credit
for condensate, and carbon-steel sulfur storage tanks. A definitive
economic evaluation of this process incorporating these changes will be
published in 1980. Actual investments could vary within a range of 0.80
to 1.30 times the projected capital investment results.
DRY CARBON ADSORPTION WITH SULFUR PRODUCTION
The process evaluated is based on the Bergbau Forschung - Foster
Wheeler process. The design is based on published information and
additional information provided by Foster Wheeler Corporation, Livingston,
New Jersey. The SOX removal process was developed by Bergbau Forschung
GmbH, Essen, West Germany, and has had extensive developmental and
operational investigation for several years. A Foster Wheeler RESOX®
process using anthracite is used to reduce the S02 to sulfur.
Although a considerable body of design and operating data is
available, equipment cost information for this study is limited. Because
of this, actual investments could vary within a range of 0.70 to 1.50
times the projected capital investment results.
-------
PREMISES FOR ECONOMIC EVALUATIONS
The premises and assumptions for the economic evaluations have been
used by TVA for a number of FGD economic studies. These premises were
reviewed at the April 1978 NATO-CCMS meeting. The base-case premises
are designed to represent a typical U.S. power plant. Case variations
in which fuel type or sulfur content is varied are included to determine
the sensitivity of costs to these variations in conditions.
DESIGN PREMISES
The design premises define all major power-plant, fuel, emissions,
and SOX removal requirements necessary to design an FGD system. These
general premises are discussed below. Additional premises specific to
the individual processes are included with the discussion of each process
in the appendixes.
Power Plant
A new, balanced-draft, horizontal, frontal-fired boiler design is
used for the coal-fired cases. A tangential-fired boiler is used for
the oil-fired case. The base case is a 500-MW unit. Case variations of
200-, 700-, and 1000-MW sizes are included for the limestone sludge
process. The power plant is assumed to have a 2,268 kcal/kWh (9,000
Btu/kWh) heat rate and an operating lifetime of 117,500 hours over a
30-year period. A 6000 hr/yr operating schedule is used for the annual
revenue requirements analysis.
Fuel
Six fuel variations are used—four bituminous coals of different
sulfur content, lignite, and oil. A 3.5Z sulfur coal is used for the
base case of all processes except the seawater process. For this process
the 1.4Z sulfur coal is used as the base case. Table 1 shows the composi-
tion, high heating value (HHV), and feed rates of the various fuels.
j?lue Gas Composition
Flue gas compositions for the coal and lignite fuels are based on
combustion of pulverized fuel and a total air rate of 133% of the stoichio-
metric requirements. This includes 20Z excess air to the boiler and 13%
air inleakage at the air preheater. Flue gas composition for the oil
fuel is based on a total air rate of 115Z of the stoichiometric require-
8
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ments, including 5% excess air to the boiler and 10% air inleakage at
the air preheater. An ambient air temperature of 27°C (80°F) and a 60%
relative humidity is used for all cases.
SOX in the flue gas is assumed to consist of 99% S02 and 1% 803.
For the coal- and lignite-fired cases 80% of the ash and 95% of the
sulfur in the fuel is assumed to be emitted in the flue gas as fly ash
and SO . For the oil-fired case 100% of the ash and sulfur in the oil
A
is assumed to be emitted in the flue gas. In addition 0.4% of the oil
to the boiler is assumed to be emitted as particulate matter. For the
coal- and lignite-fired cases the flue gas is assumed to contain 0.06%
by volume NOX, calculated as NO. For the oil-fired case the flue gas is
assumed to contain 0.02% by volume NOX. Flue gas compositions and rates
based on these assumptions are shown for each fuel in Table 2.
Removal Efficiencies^
For all coal- and lignite-fired cases 99.2% of the fly ash is
assumed removed in ESP units. ESP units are not used for the oil-fired
case. The presaturators and scrubbers are assumed to remove 90% of the
S02, 50% of the S03, 95% of the chloride, and 75% of the remaining fly
ash in the flue gas. (In the coal- and lignite-fired cases the fly ash
removed by the presaturator and scrubbers is the residual ash that is
not removed by the ESP units.)
FGD Systems
The FGD system is installed downstream from the ESP units (or air
preheaters in the oil-fired case). Flue gas from the power plant is
routed through a single plenum which distributes the gas to parallel FGD
equipment trains. The plenum is equipped with flow controls to shut
down individual FGD trains but it is not provided with bypass capabilities,
Four trains of FGD equipment are used for the wet processes and two
trains are used for the dry, carbon-adsorption process. For the case
variations 2, 6, and 8 trains are used for 200-, 700-, and 1000-MW power
plant sizes. Each train is equipped with a forced-draft (FD) booster
fan (in respect to the FGD facilities) to compensate for the additional
pressure drop in the FGD system. Presaturators and mist eliminators are
provided for wet-process absorbers. The flue gas is assumed to enter
the presaturator at 149°C (300°F) and enter the absorber at 53°C (127°F).
The mist eliminator is assumed to reduce the entrained moisture content
of the flue gas leaving the absorber to 0.1%. For wet processes reheat
is provided to heat the flue gas to 79°C (175°F) before it is exhausted
to the stack plenum. It is recognized, however, that requirements for
reheat for plume buoyancy, corrosion control, and opacity are site
specific and may vary.
The FGD systems are assumed to include the plenum which receives
the flue gas from the ESP units or air preheaters and all FGD equipment
downstream to the stack plenum. All equipment and facilities necessary
to operate the system, including raw material processing and waste
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disposal or treatment, are included. Wastes, excluding small purge
streams, are assumed to be disposed of on land one mile from the facility.
ECONOMIC PREMISES
The economic premises are divided into capital investment premises
for installation of the system and annual revenue requirement premises,
for its operation over the life of the power plant. The premises are
further divided into sections to facilitate calculation and to establish
cost areas for comparison and analysis. The estimates are based on
generalized flow diagrams, material balances, equipment lists, plot
plans, and various layouts of electrical equipment, piping, and instru-
mentation, along with other design and operating information. Capital
cost information for process items is obtained from engineering-contracting,
processing, and equipment companies; TVA purchasing and construction
data; and authoritative publications on costs and estimating. Minor
equipment costs are based on literature sources or derived as a function
of major equipment costs. Revenue requirements are based on current
U.S. labor and supervisory rates, purchased power costs, costs derived
from literature sources, and current industrial practice. All costs are
in U.S. dollars and are based on costs in the Midwestern United States.
The premises are designed to represent projects in which design
begins in mid-1977 and construction is completed in mid-1980, followed
by a mid-1980 startup. Capital costs are assumed 50% expended in mid-
1979. Therefore, projected capital costs are assumed to correspond to
mid-1979 and revenue requirements are projected to 1980. Scaling to
other time periods can use mid-1979 as the basis for capital costs and
mid-1980 as the basis for revenue requirements.
The premises are based on regulated utility economics which allow
the power company to earn a specified return on investment. The FGD
system cost is combined with the total power plant Investment and,
therefore, increases the rate base upon which the utility return on
investment is based. Thus, a return on equity is included in any process
evaluation under regulated economics. This cost of investment is added
to the annual revenue requirements as part of capital charges. The
capital structure is assumed to be 60% debt and 40% equity. Interest on
bonds is assumed to be 10% and the return to stockholders 14%.
Capital Costs
Capital costs are categorized as direct investment, indirect invest-
ment, contingency, other capital charges, land costs, and working capital.
Total fixed investment consists of the sum of direct and indirect capital
investment and a contingency based on direct and indirect investment.
Total depreciable investment consists of total fixed investment plus the
other capital charges. Investment costs are projected from Chemical
Engineering annual cost indexes (7) as shown in Table 3. The costs are
based on construction of a proven design and an orderly construction
program without delays or overruns caused by equipment, material, or
labor shortages.
12
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TABLE 3. COST INDEXES AND PROJECTIONS
Year 1974 1975 1976a 1977a 1978a 1979a 1980a 1981a
Plant
Material*3
Labor0
165.4
171.2
163.3
182.4
194.7
168.6
197.9
210.3
183.8
214.7
227.1
200.3
232.9
245.3
218.3
251.5
264.9
237.9
271.6
286.1
259.3
293.3
309.0
282.6
a. Projections.
b. Same as index in Chemical Engineering for "equipment, machinery,
supports."
c. Same as index in Chemical Engineering for "construction labor."
Direct Investment—
Direct capital costs include all costs, excluding land, for materials
and labor to install the complete FGD system. Included are site prepara-
tion, excavation, buildings, storage facilities, landscaping, paving,
and fencing. Process equipment consists of all major equipment and all
equipment ancillary to the major equipment, such as piping, instrumenta-
tion, electrical equipment, and vehicles. Services, utilities, and
miscellaneous costs involved in construction are estimated as 6% of the
direct investment.
Indirect Investment—
Indirect investment costs consist of various contractor charges and
fees and construction expenses. The following cost divisions and
determinations are used.
Engineering design and supervision—ED&S cost is calculated as a
function of the complexity of the system as determined by the number of
major equipment items. The formula used is:
ED&S (in $) = (8900)(1.294)(number of major process equipment pieces)
+ (5% to 15%)(battery-limit investment)
A separate procedure, based on pond construction expense, is used
to determine ED&S cost for the pond area.
Pond ED&S (in $) = (0.076)(direct pond investment in M$)°'67(106)
The sum of these costs appears in indirect investment as ED&S
expense.
Architect and engineering contractor expenses—A&E expense is
calculated as 25% of the portion of ED&S associated with major equipment
and battery-limit units. For cases involving disposal ponds, 10% of the
ED&S associated with pond construction is estimated as A&E expense.
13
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Construction expense—Construction expense is based on direct
investment by the following equation:
Construction expense (in $) = [0.25 (a)0'83 + 0.13 (b)°*83](1Q6)
where a = direct investment in M$ excluding pond investment costs
b = direct pond cost in M$
Contractor fees—A correlation between contractor fees and direct
investment is used to estimate the cost of contractor fees.
Contractor fees (in $) = (0.096)(total direct investment in M$) * (10 )
Contingency—Contingency is assumed to be 20% of the sum of direct
and indirect investments.
Other Capital Charges—
Other capital charges consist of an allowance for startup and
modifications and interest during construction. The allowance for
startup and modifications is 10% of the total fixed investment excluding
pond construction. Interest during construction is 12% of the total
fixed investment. It is based on the simple interest which would be
accumulated at 10% per year under the assumed construction and expenditure
schedule, using the 60% debt-40% equity capital structure.
Land—
Total land requirements, including the waste disposal area for the
life of the power plant, are assumed to be purchased at the beginning of
the project. A land cost of $3500/acre is used.
Working Capital—
Working capital consists of money invested in raw materials and
supplies, products in process, and finished products; cash retained for
operating expenses; accounts receivable; accounts payable; and taxes
payable. For these premises, working capital is assumed to be equivalent
to the sum of 3 weeks of raw material costs, 7 weeks of direct costs,
and 7 weeks of overhead costs.
Annual Revenue Requirements
Annual revenue requirements are based on a 6000 hr/yr operating
schedule using the same operational profile and remaining life assumptions
that were used for the power plant design premises. Costs are projected
to 1980 dollars to represent a mid-1980 startup. The revenue requirements
are divided into direct costs for raw materials and conversion and
indirect costs for capital charges and overheads.
Direct Costs—
Projected direct costs for labor and electricity are shown in
Table 4. Operating labor and supervision is based on the quantity,
size, and complexity of the major process equipment. Labor for analyses
14
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TABLE 4. PROJECTED MID-1980 UNIT COSTS
FOR RAW MATERIALS, LABOR, AND UTILITIES
Raw Materials
Limestone
Labor
Operating labor
Analyses
$/unit
7.72/metric ton
7.00/U.S. ton
12.50/man-hr
17.00/man-hr
Utilities
Fuel oil (No. 6)
Steam (500 psig)
Process water
0.11/liter
0.40/gal
0.504/Mcal
2.00/MBtu
0.032/kliter
0.12/kgal
200 MW
500 and
700 MW
Electricity
1000 MW
0.031/kWh 0.029/kWh 0.028/kWh
15
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is based on the number of chemical analyses and physical tests needed
for process control. Electrical requirements are determined from the
installed horsepower of operating electrical equipment (excludes the
horsepower of spare equipment). Each motor in operation is assumed to
be operating at rated capacity although this results in higher power
consumptions than would actually occur. Electricity costs are based on
purchase from an independent source with full capital recovery provided.
Maintenance costs are based on a percentage of the direct investment
costs excluding field disposal and pond construction. They are adjusted
for the size and complexity of the process, considering operating experi-
ence with the processes or similar operations, and are assumed to be
constant over the life of the plant, the increase in costs balanced by
the decline in operating hours. Pond or field disposal maintenance is
estimated as 3% of pond or field disposal construction cost. The follow-
ing maintenance rates are applied to the direct investment excluding
pond or field disposal construction cost.
Projected maintenance rate, %
of direct investment excluding
Process pond or field disposal cost
Limestone sludge 8
Lime sludge 8
Double-alkali sludge 8
Seawater 6
Lime gypsum 6
Jet-bubbling limestone 6
Magnesium oxide 7
Sodium sulfite 6
Carbon adsorption 7
Indirect Costs—
Indirect costs consist of capital charges and overheads. Straight-
line depreciation of 3.3% is used. Following U.S. Federal Energy Regula-
tory Commission (FERC) recommendations, an allowance for interim replacement
is included. This allowance is increased to 0.7% from the usual average
of about 0.35% because of the unknown life span of FGD systems. The
insurance and property tax allowance, based on FERC practice, is 2.0% of
the total depreciable capital investment. Cost of capital, based on the
assumed capital structure and applied as an average charge, is 8.6% of
the depreciable capital investment.
Methods of calculating overheads vary. The method used in these
premises is based on information from several published sources. Plant
overhead is assumed to be 50% of the total conversion cost excluding the
cost of utilities. Utilities are excluded to avoid overcharging energy-
intensive processes. Administrative overhead is assumed to be 10% of
the operating labor and supervision cost.
16
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Byproduct Sale
For processes in which a salable byproduct is produced, 10% of the
total revenue is included in the overhead costs for marketing overhead
and the total sales revenue is accounted for in the annual revenue
requirements as a credit.
SCALING
The FGD case variation costs in this study are projected from the
500-MW base case using scale factors and ratios. With the exception of
the seawater process the 3.5% sulfur fuel variation is used as the base
case. For the seawater process the base-case fuel is the 1.4% sulfur
coal because the 2.0% and 3.5% sulfur coals are not evaluated. The
scaling procedure for projecting results of the base-case evaluation for
other power plant sizes and fuel sulfur contents are described and
illustrated below. Similar procedures may be used for projecting results
for other applications not included in this study. Table 5 shows scaling
data for power plant size and fuel variations.
Scaling Factors
Relative Gas and Product Rates—
Flue gas rates are functions of power plant size, fuel character-
istics, and combustion conditions. The flow rate and composition of
flue gas for each fuel type are shown in Table 2 of the premises. Using
the 500-MW, 3.5% sulfur coal base case as the datum, relative gas rates
for power plant size and fuel variations can be determined. As an
example, the relative gas rate for the 500-MW oil-fired case based on
the gas rates shown in Table 2 is calculated as (23,550 m3/min)/(28,280
m^/min) = 0.833. For cases in which the actual flue gas rates are not
known, relative gas rates for other size variations can be determined by
multiplying the relative gas rate for a specific plant by the size ratio
and heat rate ratio of the plant in question to the known plant. For
example, the relative gas rate for a 200-MW oil-fired power plant is
f200 MWV2319 kcal/kWh\ _
\500 MWy\2268 kcal/kWh,/ ~
The product rate is a function of several variables: power plant
size and heat rate, sulfur content of fuel, percentage of the sulfur in
the fuel which is emitted as gaseous S02, and the removal efficiency of
the FGD system. For the base case the product rate is
(500,000 kW)(2,268 kcal/kWh)(1 kg fuel/5,830 kcal) x
(0.0312 kg S/kg fuel)(0.95 kg S emitted/kg S) x
(0.90 kg S removed/kg S emitted) = 5,188 kg/hr S removed
A similar calculation for the 500-MW oil-fired case (substituting 0.025
kg sulfur/kg fuel, 1.00 kg sulfur emitted/kg sulfur, and 10,480 kcal/kg)
17
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-------
results in a projected emission rate of 2,437 kg/hr of sulfur. The
relative product ratio, again using the base case as the datum, is
therefore
(2,437 kg/hr)/(5,188 kg/hr) = 0.47
Relative product rates for other power plant sizes can be calculated
using the known relative product rate and the size and heat-rate ratios
in the same manner as described for the gas rate.
Number of Trains—
The number of scrubber trains for the range of power plant sizes
evaluated in this study is varied between two and eight depending on
power plant sizes. The number is based on an assumed scrubber capacity
of 125-MW/train for FGD processing equipment. The numer of trains
affects gas-related process equipment costs and ED&S costs. Product-
related equipment areas such as the raw material and disposal areas are
independent of the number of scrubbing trains and are, therefore,
assumed to consist of the same number of processing trains regardless of
power plant size.
Cost-Capacity Factors—
Costs for FGD processing areas for the case variations are projected
from the base-case estimate using the "six-tenths factor" method for
exponentially scaling costs as a function of the relative throughput
ratio raised to an exponential power (8). Cost-capacity exponential
scaling factors for each processing area are given in the equipment
lists for each process.
TV. i • f *-u f Cost (A) /Capacity (A)\£XP
The scaling equation is of the form 7; r=\ = 1 7T~^—7"—/^\ )
6 M Cost (B) \Capacity (B)/
Pond Construction—
Pond construction costs are calculated individually for the case
variations based on the lifetime quantity of sludge to be disposed.
Pond design (depth and area) is optimized to result in a minimum cost
pond; consequently, the cost does not vary linearly with product rate.
The relationship between relative construction cost and relative product
rate for limestone and lime sludges that settle to 40% solids is shown
in Figure 1.
jcaling Procedure
Scaling of direct costs for plant size and fuel variations can be
conducted using the factors discussed above. Procedures described in
the premises are used for projecting indirect costs. For illustrating
the procedures of scaling, calculations for the 200-MW, 3.5% sulfur
limestone sludge process results using the base-case data are given
below.
19
-------
2.0
en
O
Q
Z
O
w
a:
1.0
I I I I I I I I I I
1.0
RELATIVE PRODUCT RATE
2.0
Figure 1. Effect of relative product rate on
relative pond cost (relative product
rate for 500-MW, 3.5% sulfur coal
equals 1.0; based on 15% solids
sludge settling to 40% solids).
as
o
o
z
I
I
I
I
200 400 600 800
POWER PLANT SIZE, MW
1000
7igure 2. Effect of power plant size on scaling
factor for operating labor and super-
vision cost.
20
-------
Capital Investment Costs—
Procedures for scaling limestone process capital investment require-
ments are illustrated in Table 6 for the 200-MW, 3.5% sulfur fuel case.
Process equipment costs are scaled for each processing area using the
cost-capacity factors. For equipment areas whose sizes are dependent on
gas rate, the number of absorber trains (if different from the base
case) must also be included. For areas whose sizes are dependent on
product rate the number of trains is assumed constant.
For areas that are primarily dependent on gas rate, the equipment
cost is:
exp
cost B = cost A [TB/TA][GB/TB)/(GA/TA>]
For areas dependent on product rate the equipment cost is:
exp
Cost B = Cost A [PB/PA]
where:
Cost A is the datum process equipment cost for the equipment area,
Cost B is the process equipment cost being scaled for the same area,
6^ and Gg are the relative gas rates,
PA and Pg are the relative product rates,
TA and Tg are the number of trains, and
exp is the cost-capacity factor for the equipment area shown in the
equipment lists.
Services and miscellaneous costs are estimated as a percentage of
the equipment costs as described in the premises. Scaled pond construc-
tion costs excluding land are shown in Figure 1. ED&S costs are calcu-
lated using the formula based on the number of major equipment items.
In the illustration the 200-MW power plant is assumed to utilize two
trains. Inspection of the equipment list shows a reduction of gas-
related major equipment items to 69 (from 89 for the 500-MW power plant
with 4 trains).
The remaining items including indirect investment costs, contin-
gency, other capital charges, and working capital are calculated as
described in the premises.
Land costs for the waste disposal pond are scaled using Figure 1.
Land costs for stacking and intermittent storage are scaled using the
relative product rates. Process land costs for the installed equipment
can be acceptably scaled using the power plant size ratio.
Annual Revenue Requirements
Raw material and conversion costs are scaled using the appropriate
relative gas and product rates and scale factors as described below and
illustrated in Table 7.
21
-------
TABLE 6. CAPITAL INVESTMENT SCALING ILLUSTRATION -
LIMESTONE SLUDGE PROCESS BASE CASE SCALED TO 200 MW
Process Equipment
Area Basis
1 Product
2 Product
3 Gas
4 Gas
5 Gas
6 Product
Total
Services and miscellaneous
(6% of total)
Pond construction
Total direct investment
(500-MW cost) (scaling formula)
(1,824)(0. 409/1. OOO)0-73 =
(2,062)(0. 409/1. 000)0- 70 =
(4,950)[(0.409/2)/(1.000/4)]°-63 (2/4) =
(9,458)[(0.409/2)/(1.000/4)]°-74 (2/4) =
(l,292)[(0.409/2)/(1.000/4)]°-75 (2/4) =
(2, 164) (0.409/1. OOO)0-54 =
(approx 0.496 from Figure 7) (5,481) =
200-MW cost, k$
950
1,103
2,158
4,076
556
1,335
10,178
611
2 , 717
13,506
Indirect Investment
ED&S (8,900)(1.294)(69) + (0.076)(2.717)°'67(106) =
795,000 + 148,000 = 943
A&E (795)(0.25) + (148X0.10) = 214
Construction expense [(0.25)(10.789)°-83 + (0.15)(2.717)°-83](106) = 2,098
Contractor fees (0.096)(13.506)°-76(106) = 694
Total 17,455
Contingency (17,455)(0.20) = 3,491
Total fixed investment 20,946
Other Capital Charges
Allowance for startup and
modifications (20,946 - 2,717X0.10) = 1,823
Interest during construction (20,946)(0.12) = 2,514
Total depreciable investment 25,283
Disposal land (approx 0.489 factor from Figure 7)
(1,098,000 - 21,000)(0.490) = 546
Process land (6 acres)(3,500)(200/500) = 8
Working capital 465
TotaJ capital investment 26,302
22
-------
TABLE 7. ANNUAL REVENUE REQUIREMENTS SCALING ILLUSTRATION -
LIMESTONE SLUDGE PROCESS BASE CASE SCALED TO 200 MW
(500-MW cost) (scaling formula) 200-MW _cost
Direct Costsa
Raw materials (1,181)(0.409) = 483
Conversion costs
Operating labor and
supervision (301)(0.68 from Figure 8) = 205
Steam (839)(0.409) = 343
Process water (27)(0.409) = 11
Electricity [(47,967 - 600)(0.409) + 600](0.031 $/kWh) = 619
Maintenance (13,506 - 2,717)(0.08) + (2,717)(0.03) = 945
Analyses (55)(0.409)0'6 = 32
Total conversion costs 2,155
Total direct costs 2,638
Indirect Costs
Depreciation, interim replacement, insurance
at 6% of total depreciable investment
Average cost of capital and taxes at 8.6%
of total capital investment
Plant overhead at 50% of conversion costs
less utilities
Administrative overhead at 10% of
operating labor
Total indirect costs
Total annual revenue requirements
a. For cases in which the unit costs for raw materials or utilities vary
with consumption, annual quantities should be scaled in the same manner
as discussed below, and then the appropriate unit costs should be
applied to the scaled quantity to calculate annual cost.
23
-------
Raw Materials—
Since raw material consumption is generally a function of the
quantity of sulfur removed rather than the amount of flue gas to be
scrubbed, raw material quantities are scaled proportional to the rela-
tive product rate.
Operating Labor and Supervision—
Labor and supervision requirements for FGD systems are not linear
functions of either plant size or relative gas or product rates. For
each process, operating labor and supervision requirements are estimated
for the base case application considering process complexity and the
type of byproduct produced. Although requirements are likely to change
to a slight degree with changes in the design assumptions, the magnitude
of the change is slight except for cases in which the plant size is
varied. For this study operating labor and supervision requirements are
not modified to account for fuel variations. These requirements are
varied, however, to account for changes resulting from variations in
power plant size. Figure 2 shows the relationship between power unit
size and relative labor and supervision requirements utilized for pro-
jecting labor requirements.
Utilities—
With the exception of electricity, utilities are scaled as functions
of either the relative gas or relative product rates. Utilities such as
reheat energy and fan electricity are scaled proportionally to the
relative gas rate, whereas utilities such as fuel oil for calcination or
electricity for I^SC^ production are scaled proportionally to the relative
product rate. Base case utility requirements for utilities such as
process steam, process water, fuel oil, and heat credit are obtained
from the material balance. Electricity requirements are obtained from
the equipment lists where the motor horsepower is identified. In
addition to this electricity, however, a part of the electrical con-
sumption is Utilized for functions such as lighting and does not vary
with relative gas and product rates. In this study 600,000 kWh (100 kW
x 6000 hr) is used. This quantity must be subtracted from the total
base case electricity requirement and recombined after scaling as
illustrated in Table 7.
Analyses—
Analyses costs for the case variations are scaled by multiplying
the base case analyses requirements by the relative product ratio raised
to the 0.6 exponential power.
Other Costs—
The remaining annual revenue requirement costs are determined as
percentages of the above scaled costs or capital investment costs as
described in the premises.
24
-------
ACCURACY OF RESULTS AND TECHNICAL QUALIFICATIONS
In the projection of FGD economics the stage of development
and the amount of information available to estimate process costs are
major factors affecting accuracy of the results. The stage of develop-
ment is an indication of the process modifications which may be required
to achieve reliable commercial operation and is difficult to quantify in
terms of cost increases or decreases likely to result from technological
advances. Although the processes in this study differ widely in stage
of development, no attempt is made to numerically differentiate accura-
cies on this basis.
The amount of information available upon which to base economic
evaluations (site characteristics, detailed process design data, and
operating experience, for example) reduces the uncertainty of process
costs by defining in greater detail premises upon which cost estimates
are based. The accuracy of cost estimates as a function of information
available is generally established.
Based on a comparison of the data available for estimating costs of
some of the FGD processes in this study with American Association of
Cost Engineers guidelines (9) for capital cost estimating, the capital
costs of actual installations may vary from these cost estimates within
a range of +50% (actual costs may be higher) to -30% (actual costs may
be lower). This range of variations does not include the effect of
project scope variations such as designing with spare scrubbing trains
or eliminating reheat.
Estimates of revenue requirements are not expected to exhibit as
much variability as the capital cost estimates. Since the projections
of raw material and utility requirements are generally based on actual
test data or process chemistry, calculated quantities are generally
considered to be more accurate than the capital cost estimates. However,
capital charges based on capital cost account for a major portion of
revenue requirements. Considering the range of variability discussed
above for capital costs, the revenue requirements may vary from these
cost estimates within a nominal range of +25% (actual costs may be
higher) to -15% (actual costs may be lower). However, the accuracy
graphs in the appendixes reflect the specific range of accuracy associ-
ated with projected changes in the investment, rather than the nominal
+25% to -15% discussed above.
The economic evaluations of some of the processes in this study are
based on previous detailed evaluations prepared for the U.S. Environ-
mental Protection Agency. For these processes information in consider-
able detail is available and the ranges of accuracy can be reduced. The
ranges of accuracy for the cost estimates in this study thus vary from
the preliminary-evaluation range of +50% to -30% to smaller ranges of
+30% to -20% and +20% to -15%, depending on the information available
for the particular process. The estimated ranges of accuracy for the
processes evaluated, based on the amount of information available and
previous experience with similar estimates, are discussed in the descrip-
tion of processes evaluated and are shown in the results.
25
-------
RESULTS
Process and economic evaluation results for the nine FGD processes
evaluated are summarized in Tables 8 through 17. Detailed results, flow
diagrams, material balances, and equipment lists are shown in Appendixes A
through I. Figures 3 and 4 show the economic results graphically,
illustrating the accuracy ranges projected for each process. Capital
costs are in mid-1979 U.S. dollars. Revenue requirements are in mid-
1980 U.S. dollars.
Because the evaluations included within this report are based on
generalized premises and limited actual cost data are available for some
of the processes, no attempt is made to compare the projected costs with
costs for actual site-specific installations. Limited cost data for
actual installations may be obtained from the Phase I reports or from
the periodic PEDCo reports (10).
26
-------
TABLE 8. LIMESTONE SLUDGE PROCESS MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials, kg/hr
Limestone
End product
Sludge
m3/hr
ft3/hr
kg/hr
Ib/hr
wt % solids
Energy
Reheat, kcal/hr
Electricity, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Waste disposal, ha
Total - ha
- acres
Costs3
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
0.8
6,000
13.3
470.0
17,561
38,715
40
18.06 M
16.98 M
35.04 M
139.2 M
3.27
3.7
38.6
42.3
104.5
39,995,000
34,112,000
47,838,000
11,151,700
9,933,800
12,775,200
Coal
1.4
8,900
19.77
698.0
26,079
57,493
40
17.45 M
16.66 M
34.11 M
135.6 M
3.18
3.7
51.8
55.5
137.1
41,634,000
35,526,000
49,778,000
11,539,200
10,279,000
13,219,500
Coal
2.0
14,000
31.35
1,107.1
41,364
91,190
40
17.53 M
17.14 M
34.67 M
137.5 M
3.23
3.7
74.6
78.3
193.5
45,516,000
38,863,000
54,387,000
12,574,200
11,206,400
14,397,200
Coal
3.5
25,500
56.93
2,010.4
75,112
165,590
40
17.62 M
18.13 M
35.75 M
141.9 M
3.33
3.7
123.0
126.7
313.1
53,083,000
45,376,000
63,358,000
14,638,000
13,064,500
16,736,100
Lignite
0.5
4,300
9.70
342.4
12,792
28,200
40
18.52 M
17.27 M
35.79 M
141.9 M
3.34
3.7
29.8
33.5
82.8
39,036,000
33,285,000
46,704,000
10,945,400
9,752,100
12,536,500
Oil
2.5
12,000
26.73
943.9
35,265
77,744
40
14.67 M
14.40 M
29.07 M
115.5 M
2.71
3.7
65.8
69.5
171.7
40,643,000
34,705,000
48,559,000
11,385,400
10,168,000
13,008,300
a. Accuracy range: +20% to -15%.
27
-------
TABLE 9. LIMESTONE SLUDGE PROCESS SIZE VARIATIONS,
MATERIAL, ENERGY, AND COST SUMMARY
MW
Fuel
Percent sulfur
Raw materials, kg/hr
Limestone
End product
m3/hr
ft3/hr
kg/hr
Ib/hr
wt % solids
Energy
Reheat, kcal/hr
Electricity, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Waste disposal, ha
Total - ha
- acres
o
Costs
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
200
Coal
3.5
10,400
23.28
822.0
30,713
67,710
40
7.21 M
7.72 M
14.93 M
59.2 M
3.39
3.1
61.0
64.1
158.3
26,302,000
22,481,000
31,397,000
7,029,100
6,260,400
8,054,000
500
Coal
3.5
25,500
56.93
2,010.4
75,112
165,590
40
17.62 M
18.13 M
35.75 M
141.79 M
3.33
3.7
123.0
126.7
313.1
53,083,000
45,376,000
63,358,000
14,638,000
13,064,500
16,736,100
700
Coal
3.5
35,300
78.82
2,783.1
103,983
229,240
40
24.39 M
24.74 M
49.13 M
194.95 M
3.30
3.8
159.0
162.8
402.3
70,967,000
60,657,000
84,713,000
19,734,300
17,619,200
22,554,300
1,000
Coal
3.5
49,300
110.07
3,886.7
145,216
320,140
40
34.07 M
33.68 M
67.75 M
268.83 M
3.26
4.2
209.0
213.2
526.9
93,941,000
80,296,000
112,135,000
26,384,700
23,573,800
30,132,600
a. Accuracy range: +20% to -15%.
28
-------
TABLE 10. LIME SLUDGE PROCESS MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials, kg/hr
Lime
End product
Sludge
m3/hr
ft3/hr
kg/hr
Ib/hr
wt % solids
Energy
Reheat, kcal/hr
Electricity, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Waste disposal, ha
Total - ha
- acres
Costs3
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
0.8
2,400
10.22
360.3
13,394
29,529
40
18.00 M
16.82 M
34.82 M
138.2 M
3.25
2.5
32.5
35.0
86.5
37,795,000
32,244,000
45,196,000
11,064,200
9,912,000
12,600,400
Coal
1.4
3,500
15.17
535.0
19,891
43,851
40
17.39 M
16.34 M
33.73 M
133.9 M
3.14
2.5
44.8
47.3
H6.9
38,912,000
33,216,000
46,507,000
11,498,200
10,320,100
13,069,200
Coal
2.0
5,600
24.07
848.6
31,549
69,553
40
17.47 M
16.54 M
34.01 M
135.0 M
3.17
2.5
63.5
66.0
163.1
41,952,000
35,841,000
50,099,000
12,644,700
11,386,000
14,323,000
Coal
3.5
10,200
43.70
154.1
57,290
126,300
40
17.56 M
16.89 M
34.45 M
136.7 M
3.21
2.5
104.0
106.5
262.4
47,743,000
40,853,000
56,932,000
14,972,100
13,562,700
16,851,500
Lignite
0.5
1,700
7.44
262.4
9,756
21,509
40
18.46 M
17.21 M
35.67 M
141.5 M
3.33
2.5
25.5
28.0
69.2
37,165,000
31,695,000
44,458,000
10,836,300
9,698,200
12,353,800
Oil
2.5
4,800
20.52
723.4
26,898
59,298
40
14.62 M
13.88 M
28.50 M
113.1 M
2.51
2.5
54.9
57.4
141.8
37,286,000
31,855,000
44,526,000
11,387,700
10,271,300
12,876,100
.
a. Accuracy range: +20% to -15%.
29
-------
TABLE 11. DOUBLE-ALKALI SLUDGE PROCESS MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials, kg/hr
Lime
Soda ash
End product
Sludge
m3/hr
ft3/hr
kg/hr
Ib/hr
wt % solids
Energy
Reheat, kcal/hr
Electricity, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Waste disposal, ha
Total - ha
- acres
Costs3
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
0.8
2,277
186
6.98
246.6
9,075
20,006
55
18.06 M
8.08 M
26.14 M
103.7 M
2.48
4.9
33.0
37.9
150.4
40,537,000
32,581,000
52,472,000
11,173,000
9,528,500
13,639,700
Coal
1.4
3,381
277
10.37
366.2
13,476
29,710
55
17.45 M
7.99 M
25.44 M
101 M
2.41
4.9
44.0
48.9
194.0
42,179,000
33,926,000
54,559,000
11,793,600
10,091,700
14,346,600
Coal
2.0
5,363
439
16.45
580.9
21,375
47,123
55
17.53 M
8.33 M
25.86 M
102.6 M
2.45
4.9
62.0
66.9
265.5
46,045,000
37,075,000
59,500,000
13,080,000
11,258,600
15,811,900
Coal
3.5
9,737
797
29.87
1,054.9
38,815
85,570
55
17.62 M
9.03 M
26.65 M
105.8 M
2.52
4.9
99.0
103.9
412.3
53,231,000
43,004,000
68,662,000
16,010,600
14,359,800
19,169,400
Lignite
0.5
1,659
136
5.09
179.6
6,610
14,573
55
18.52 M
8.18 M
26.70 M
106 M
2.54
4.9
31.1
36.0
89.1
39,595,000
31,817,000
51,261,000
10,828,000
92,177,000
13,234,300
Oil
2.5
4,572
374
14.03
495.3
18,223
40,175
55
14.67 M
7.02 M
21.69 M
86.1 M
1.91
4.9
48.0
52.9
209.9
40,659,000
32,733,000
52,546,000
11,879,500
10,251,200
14,321,700
a. Accuracy range: +30% to -20%.
30
-------
TABLE 12. SEAWATER PROCESS MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
End product
Seawater
liters/hr
kg/hr
Ib/hr
Energy
Reheat, kcal/hr
Electricity, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Total - ha
- acres
Costs
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
1.4
71,385,400
72,124,300
158,864,200
28.70 M
15.91 M
44.61 M
177.0 M
4.22
2.4
2.4
6
30,048,000
21,157,000
44,868,000
8,707,100
6,972,700
11,597,700
Coal
0.8
51,526,200
52,041,400
114,731,700
29.69 M
14.89 M
44.58 M
176.9 M
4.22
2.4
2.4
6
29,590,000
20,838,000
44,177,000
8,667,100
6,960,500
11,511,800
Lignite
0.5
35,692,700
36,062,200
79,432,100
30.46 M
13.88 M
44.34 M
175.9 M
4.21
2.4
2.4
6
29,068,000
20,471,000
43,397,000
8,516,800
6,840,700
11,310,300
Oil
2.5
83,214,800
84,071,900
185,346,900
24.13 M
15.47 M
39.60 M
157.1 M
3.49
2.4
2.4
6
27,937,000
19,691,000
41,682,000
8,575,600
6,968,800
11,253,400
Low reheat
coal
1.4
71,385,400
72,124,300
158,864,200
14.46 M
15.91 M
30.37 M
120.5 M
2.82
2.4
2.4
6
28,582,000
20,106,000
42,707,000
7,837,700
6,185,700
10,590,900
a. Accuracy range: +50% to -30%.
31
-------
TABLE 13. LIME GYPSUM (SAARBERG-HOLTER) PROCESS
MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials, kg/hr
Lime
Formic acid
Flocculant
Nalco
End product
Gypsum
m3/hr
ft5/hr
kg/hr
Ib/hr
wt % solids
Energy
Reheat, kcal/hr
Electricity, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Byproduct storage, ha
Total - ha
- acres
Costs3
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
0.8
2,255
1.8
0.18
0.02
6.06
214.1
8,263
18,200
80
18.14 M
12.59 M
30.73 M
121.94 M
2.89
4.46
0.4
4.86
12
35,481,000
24,988,000
52,970,000
9,825,900
7,791,500
13,216,300
Coal
1.4
3,344
2.7
0.26
0.03
9.00
317.6
12,260
27,000
80
17.53 M
13.76 M
31.29 M
124.16 M
2.93
4.46
0.4
4.86
12
36,472,000
25,701,000
54,424,000
10,303,700
8,214,400
13,785,800
Coal
2.0
5,297
4.3
0.42
0.04
14.27
503.9
19,445
42,830
80
17.61 M
16.34 M
33.95 M
134.71 M
3.17
4.46
0.4
4.86
12
39,173,000
27,631,000
58,407,000
11,443,300
9,201,300
15,179,800
Coal
3.5
9,625
7.9
0.76
0.08
25.92
915.3
35,320
77,800
80
17.70 M
22.00 M
39.70 M
157.53 M
3.67
4.46
0.4
4.86
12
44,024,000
31,114,000
65,541,000
13,706,300
11,192,900
17,895,300
Lignite
0.5
1,634
1.3
0.13
0.01
4.41
155.7
6,008
13,230
80
18.61 M
12.13 M
30.74 M
121.98 M
2.89
4.46
0.4
4.86
12
34,905,000
24,574,000
52,124,000
9,571,100
7,568,900
12,908,000
Oil
2.5
4,525
3.7
0.36
0.04
17.17
429.8
16,586
36,530
80
14.74 M
13.78 M
28.52 M
113.17 M
2.51
4.46
0.4
4.86
12
34,802,000
24,557,000
51,878,000
10,347,600
8,362,400
13,656,200
a. Accuracy range: +50% to -30%.
32
-------
TABLE 14. JET-BUBBLING LIMESTONE (CHIYODA THOROUGHBRED 121) PROCESS
MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials, kg/hr
Limestone
End product
Gypsum
m^/hr
ft3/hr
kg/hr
Ib/hr
wt % solids
Energy
Reheat , kcal/hr
Electricity, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Byproduct storage, ha
Total - ha
- acres
Costs3
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
0.8
4,067
6.19
218. A2
8,421
18,565
80
18.61 M
17.32 M
35.93 M
142.57 M
3.35
4.46
0.4
4.86
12
42,002,000
29,538,000
62,774,000
10,948,500
8,524,700
14,988,200
Coal
1.4
6,048
9.18
324.30
12,503
27,565
80
17.98 M
16.97 M
34.95 M
138.68 M
3.26
4.46
0.4
4.86
12
42,007,000
29,545,000
62,776,000
10,919,500
8,496,000
14,958,600
Coal
2.0
9,586
14.57
514.42
19,834
43,725
80
18.07 M
17.42 M
35.49 M
140.82 M
3.31
4.46
0.4
4.86
12
43,819,000
30,826,000
65,474,000
11,360,700
8,831,900
15,575,600
Coal
3.5
17,400
26.45
934.14
36,015
79,400
80
18. 16 M
18.35 M
36.51 M
144.87 M
3.40
4.46
0.4
4.86
12
47,017,000
33,091,000
70,227,000
12,160,100
9,446,000
16,683,500
Lignite
0.5
2,964
4.50
159.06
6,132
13,520
80
19.09 M
16.63 M
35.72 M
141.74 M
3.34
4.46
0.4
4.86
12
42,095,000
29,602,000
62,917,000
10,998,700
8,568,900
15,048,200
Oil
2.5
8,180
12.42
438.54
16,908
37,275
80
15.12 M
14.64 M
29.76 M
118.09 M
2.62
4.46
0.4
4.86
12
38,532,000
27,118,000
57,556,000
10,219,200
8,003,400
13,912,300
a. Accuracy range: +50% to -30%.
33
-------
TABLE 15. MAGNESIUM OXIDE PROCESS MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials
MgO, kg/hr
Catalyst, liters/hr
Agricultural limestone, kg/hr
End product
Sulfuric acid
liters/hr
kg/hr
Ib/hr
wt 7, H2S04
Energy
Reheat, kcal/hr
Electricity, kcal/hr
Oil, kcal/hr
Heat credit, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Total - ha
- acres
Costs3
Capital investment 48
Low range 39
High range 63
Annual revenue requirements 12
Low range 10
High range 15
Coal
0.8
51
0.1
431
2,041
3,735
8,233
100
18.57 M
16.38 M
7.90 M
(0.84 M)
42.01 M
166.7 M
3.89
4.86
4.86
12
,926,000
,252,000
,436,000
,949,500
,999,500
,874,400
Coal
1.4
76
0.1
832
3,026
5,538
12,210
100
17.95 M
16.57 M
11.73 M
(1.25 M)
45.00 M
178.6 M
4.14
4.86
4.86
12
52,043,000
41,757,000
67,472,000
13,651,200
11,576,400
16,763,000
Coal
2.0
119
0.2
1,255
4,800
8,785
19,367
100
18.03 M
17.87 M
18.60 M
(1.98 M)
52.52 M
208.4 M
4.81
4.86
4.86
12
58,108,000
46,632,000
75,324,000
15,114,300
12,759,400
18,592,700
Coal
3.5
218
0.3
420
8,717
15,951
35,167
• 100
Id. 12 M
20.66 M
33.78 M
(3.60 M)
68.96 M
273.6 M
6.26
4.86
4.86
12
68,434,000
54,934,000
88,685,000
17,546,900
14,809,500
21,652,700
Lignite
0.5
38
0.1
398
1,485
2,717
5,990
100
19.05 M
16.38 M
5.75 M
(0.61 M)
40.57 M
161. C M
3.58
4.86
4.86
12
47,115,000
37,798,000
61,090,000
12,573,900
10,697,100
15,389,100
Oil
2.5
103
0.1
0
4,090
7,484
16,500
100
15.09 M
12.94 M
15.86 M
(1.69 M)
42.20 M
167.4 M
3.72
4.86
4.86
12
44,591,000
35,799,000
57,779,000
11,984,600
10,208,300
14,646,600
a. Accuracy range: +30Z to -2
34
-------
TABLE 16. SODIUM SULFITE (WELLMAN-LORD) PROCESS
MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials
Sodium carbonate, kg/hr
Catalyst, liters/hr
Agricultural limestone, kg/hr
Filter aid, kg/hr
Natural gas, m-Vhr
End product
100% sulfurlc acid
liters/hr
kg/hr
Ib/hr
Sodium sulfate
kg/hr
Ib/hr
Sulfur
kg/hr
Ib/hr
Energy
Reheat, kcal/hr
Process steam, kcal/hr
Electricity, kcal/hr
Natural gas, kcal/hr
Heat credit, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Total - ha
- acres
Costs3
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
0.8
218
0.07
431
2
1,887
3,453
7,613
277
610
-
-
15.47 M
10.90 M
17.99 M
-
(0.46 M)
43.90 M
174.2 M
4.13
111
3.2
8
46,836,000
37,581,000
60,719,000
12,218,300
10,434,500
14,893,900
Coal
1.4
323
0.10
832
4
2,803
5,129
11,307
410
903
-
-
14.95 M
16.19 M
18.68 M
-
(0.69 M)
49.13 M
194.9 M
4.64
3.2
3.2
8
50,307,000
40,372,000
65,210,000
13,081,000
11,164,000
15,956,500
Coal
2.0
512
0.16
1,254
6
4,446
8,136
17,937
650
1,433
-
-
15.02 M
25.68 M
20.90 M
-
(1.09 M)
60.51 M
240.1 M
5.73
3.2
3.2
8
56,939,000
45,706,000
73,789,000
14,802,200
12,629,900
18,060,200
Coal
3.5
930
0.29
420
11
8,073
14,774
32,570
1,181
2,603
-
-
15.10 M
46.64 M
25.73 M
-
(1.98 M)
P.5.49 M
339.2 M
8. 14
3.2
3.2
8
68,722,000
55,187,000
89,025,000
17,886,400
15,257,400
21,829,800
Lignite
0.5
159
0.05
398
2
1,375
2,516
5,546
201
443
-
-
15.87 M
7.94 M
17.72 M
-
(0.34 M)
41.19 M
163.4 M
3.78
3.2
3.2
8
44,837,000
35,975,000
58,131,000
11,754,700
10,048,100
14,314,400
Oil
2.5
437
0. 14
-
5
3,790
6,935
15,290
555
1,223
-
-
12.57 M
21.90 M
15.44 M
-
(0.93 M)
48.98 M
194.4 M
4.53
lil
3.2
8
44,215,000
35,504,000
57,280,000
11,801,900
10,124,600
14,317,700
Sulfur
produr t inn
coal
i.5
930
-
42(1
1 ]
2,311
-
-
-
1,181
2,601
4,802
10,857
15.10 M
47.20 M
25.59 M
20.56 M
(2.79 M)
105.66 V
419.3 M
9.93
3.2
3.2
8
71 ,342,000
57,343,000
92,341 ,000
21 ,015,700
18,296,500
24,094,700
a. Accuracy range: +30% to -20%.
35
-------
TABLE 17. CARBON ADSORPTION PROCESS MATERIAL, ENERGY, AND COST SUMMARY
Fuel
Percent sulfur
Raw materials
Sand, kg/hr
Char, kg/hr
Anthracite coal, kg/hr
End product
Sulfur
Ib/hr
kg/hr
Char fines and RESOX waste
Ib/hr
kg/hr
Energy
Electricity, kcal/hr
Process steam, kcal/hr
Fuel oil, kcal/hr
Heat credit, kcal/hr
Total - kcal/hr
- Btu/hr
- % input
Land
Process, ha
Total - ha
- acres
Costs3
Capital investment
Low range
High range
Annual revenue requirements
Low range
High range
Coal
0.8
106
544
1,179
2,533
1,149
2,267
1,028
3.86 M
0.15 M
6.33 M
(3.46 M)
6.88 M
27.3 M
0.61
4.86
4.86
12
51,195,000
33,109,000
69,978,000
13,899,100
10,747,500
18,174,700
Coal
1.4
151
816
1,754
3,800
1,724
3,400
1,542
4.08 M
0.23 M
9.41 M
(5.14 M)
8.58 M
34.0 M
0.76
4.86
4.86
12
54,220,000
39,533,000
78,698,000
15,803,600
12,844,600
20,735,200
Coal
2.0
257
1,300
1,255
6,000
2,752
5,366
2,434
3.83 M
0.36 M
14.92 M
(8.16 M)
10.95 M
43.4 M
0.97
4.86
4.86
12
60,834,000
44,350,000
88,308,000
19,982,700
16,658,600
25,522,900
Coal
3.5
454
2,359
5,035
10,900
4,944
9,733
4,415
6.01 M
0.66 M
27.10 M
(14.82 M)
18.95 M
75.2 M
1.68
4.86
4.86
12
73,511,000
53,617,000
106,666,000
28,489,400
24,473,000
35,183,500
Lignite
0.5
76
408
862
1,867
847
1,633
741
3.74 M
0.11 M
4.61 M
(2.52 M)
5.94 M
23.6 M
0.52
4.86
4.86
12
49,485,000
36,153,000
71,704,000
12,780,100
10,094,500
17,256,100
Oil
2.5
212
1,104
2,359
5,133
2,328
4,567
2,071
3.99 M
0.31 M
12.72 M
(6.96 Ml
10.06 M
39.9 M
0.89
4.86
4.86
12
53,730,000
39,104,000
78,105,000
17,542,000
14,600,600
22,445,100
a. Accuracy range: +50% to -30%.
36
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ELEMENTS IN SELECTING AN FGD SYSTEM
Many complex interrelated factors affect FGD process selection for
a specific site. To facilitate selection two decision aids are presented
in this section. These aids are designed to help the user eliminate FGD
processes which are not applicable to his plant and to rate those processes
that apply. After these steps are completed, additional detailed informa-
tion is required to further delineate the applicability of a specific
process to a plant. However, by initially selecting the more applicable
FGD processes, a considerable amount of effort and expense can be saved
because preliminary engineering design and cost estimates need be prepared
for fewer processes. It must be emphasized that these decision aids
will not provide the user with an optimum system for his case, but will
only guide him to a number of possible processes that meet his initial
requirements.
FACTORS INVOLVED IN FGD PROCESS SELECTION
In making a preliminary selection of FGD processes, four main areas
of concern must be evaluated: (1) raw material requirements, (2) end
products, (3) performance requirements, and (4) plant site considerations.
An evaluation of these factors will eliminate some types of FGD
processes from further consideration. Planning resources can then be
directed to processes which are applicable to the specific site.
Figure 5, an FGD selection matrix, summarizes key factors applied
to the 12 FGD processes identified for the Phase I study in 1977. The
cross-hatched boxes in this figure represent those raw materials, end
products, performance requirements, or other special conditions applicable
to that process. It must be emphasized that the cross-hatched boxes
under the performance requirements category should be eliminated with
time as processes are demonstrated for alternate fuels. Under the
performance area, cross-hatching is provided where a process has not
been demonstrated. If a process is applicable only to new plants, it is
cross-hatched in the last column. This figure is used by asking questions
which apply to each key factor as described below.
Major Raw Material Requirements
1. Are large quantities of limestone available?
2. Are large quantities of lime available?
39
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3. Are large quantities of seawater available?
4. .Are large quantities of gaseous or liquid fuel available?
5. Are large quantities of hydrogen available?
Major End Products
6. Can a calcium-sulfur sludge be tolerated?
7. Can acidic seawater be discharged?
8. Can large quantities of gypsum be sold or discarded?
9. Can sulfuric acid or sulfur be sold?
Performance Requirements
10. Can a process that has not achieved full-scale operation on
high-sulfur (2.0% or greater) coal be used?
11. Can a process that has not achieved full-scale operation on low-
sulfur (less than 2.0%) coal be used?
12. Can a process that has not achieved full-scale operation on
high-sulfur oil be used?
Plant Site Considerations
13. Is the FGD process to be applied to a new plant?
Example Use
When an answer to any of the above questions is no, the column
under that condition should be crossed out. To select applicable
processes, processes are eliminated where a cross-hatched box coincides
with a crossed-out area. Two examples will illustrate this preliminary
selection process.
Example No. 1—
Plant conditions: new 500-MW plant burning high-sulfur oil,
located inland with strict water effluent restrictions. The plant is in
an industrial area with byproduct lime available and a demand for sulfuric
acid, but with limited space. Oil and gas are available but hydrogen is
not. High equipment availability is required. After obtaining this
site information, the FGD selection matrix is used to narrow the FGD
choices by asking the questions previously listed, as shown in Figure 6.
Under raw materials, limestone, seawater, and hydrogen are not
available and columns 1, 3, and 5 are crossed out. Under end products,
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C C
o C
•H 3
CU CO
H C
0) O
CO -H
4-1
0) U
tH -H
a 1-1
0 4J
co ca
X CU
txC
•H
fe
42
-------
sludge and acidic seawater cannot be tolerated and columns 6 and 7 are
crossed out. Columns 10 and 11 dealing with coal do not apply. Column 12
is crossed out because a process that has not achieved full-scale opera-
tion on high-sulfur oil cannot be used. Column 13 is not crossed out
because this is a new plant.
Reading horizontally across the table, a cross-hatched area which has
been crossed out eliminates the corresponding process from consideration.
Examination of the crossed-out chart as shown in Figure 6 shows the
following processes remain for further consideration.
Lime gypsum
Magnesium oxide
Sodium sulfite
Example No. 2—
Plant conditions: existing plant burning 1.0% sulfur coal located
on a seacoast with very limited open area and about 15 years of life
remaining. A medium availability and 80% control efficiency are required.
Limestone is available, but little liquid or gaseous fuel is available
and no market for sulfur byproducts is evident.
Utilizing the selection matrix again (Figure 7), columns 2, 4, and
5 are crossed out because those raw materials are not available. Columns (
and 9 are also crossed out because there is no space for sludge disposal
and no sulfur market. Gypsum storage may be possible for a while, but
it will have to be transported from the site after about 10 years.
Under performance requirements, only the low-sulfur-coal column applies.
Because a full-scale demonstration is not required (though desirable),
this column is not crossed out. Column 13 is crossed out because this
is not a new plant. As shown in Figure 7 this leaves the seawater and
gypsum processes (except those using lime) remaining for further
consideration.
PROCESS RATING
After a preliminary screening of FGD processes applicable to a
specific case, a rating of these processes will further identify those
that appear to be most feasible. Such a rating will not select the
single best process but will help to establish priorities for studying
processes.
There is no single uniform method for rating FGD processes which is
used throughout the utility industry. A suggested rating chart is shown
in Figure 8. This chart contains rating factors from 1 to 4 applied to
six selection criteria for 12 FGD processes. The listed ratings, or
"R factors," are based on judgements for each of the conditions which
make up the criteria area as shown in the figure. Thus, under the first
item, if an FGD process has been applied to many units, it is assigned a
high score. A weighting factor is inserted by the user under the column
labeled "W." This weighting factor enables the user to more heavily
43
-------
LJ
•o
3
CO
O)
CD
CVJ
o> w
I I
a S=
U =3
— CO
•s >.
ffl
cu
13
§
CO
CD
•O
-! C
X CU
W M
r~
HI
60
•H
-------
CRITERIA
DEFINITION
VI
•o
Ul
>,
1/1
Number installed
Sizes installed
Process controlability
Mechanical technology
Average availability
Maintenance required
Space (equipment &
storage of reagents
and solid products
Ability to follow load
RATING 'R1
1234
Few Many
Small Large
Complex Simple
Complex Simple
Low High
High Low
Large Small
Poor Good
PROCESSES SURVEYED
OJ
0
\
c
CT
C
o
I
I
>
a
^E
_1
E
3
c
O
\
I
'll
fi
a
c
«
E
°
-a
-3
M a anesium oxide
Sodium sulfite
c
c
T;
c
O
rt
O
a.
•o
c
t,
a)
a
o
o
O
'R1 VALUES
4
4
3
3
2
2
2
3
4
4
3
2
2
3
3|3
3 |2
3
2
3
3
2
3
1
2
4
4
4
3
43
4J3
4
4
4
2
2
3
4
3J3
4|3
3
3
3
3
2
2
2
3
3
2
1
2
2
3|3!3|2J3J2
3
3
2
3
3|3 f|3
3
2
3
3
2
3
2
3
3
3
3
3
2
1
3
3
1
1
2
2
1
1
3
3
0
t
o
CT>
C
4_>
JZ
cr>
aj
s
I/*
1_
OJ
c
5
o
w
STATUS SUBTOTAL
Raw
material
needs
Absorbent availability
Fresh water requirements
Reducing agent
Low High
High Low
High Low
2
2
4
2
2
4
9
2
4
2
3
4
2
2
4
2
2
4
2
2
4
^
3
4
3
3
2
3
3
3
3
4
2
3
4
1
RAW MATERIAL SUBTOTAL
i/i
t/i
•o x>
£QJ
QJ
a. c
>>
CQ «a
Marketable quality
Sludge amount
Water treatment
requirements
Poor Good
Large Small
Large Small
1
1
3
1
1
3
1
1
3
1
3
1
3
3
2
3
3
2
3
3
2
4
3
3
4
4
3
4
4
3
4
4
4
4
4
4
BYPRODUCT SUBTOTAL
Control
achievable
S02
Particulates
NOX
Hal ides
Low High
Low High
Low High
Low High
3
3
1
4
3
3
1
4
4
3
1
4
3
3
1
T
3
3
1
4
4
3
1
4
4
3
1
4
3
3
2
3
4
3
1
4
4
2
1
4
2
3
3
2
3
2
2
2
CONTROL SUBTOTAL
>,
S- T3
OJ OJ
C GJ
UJ SI
Reheat
Pump & fan requirements
Other
Yes No
High LCM
High Low
1
2
3
1
3
3
1
3
3
1
3
3
1
2
3
1
3
3
1
3
3
1
3
3
1
3
2
1
3
2
4
2
2
4
2
2
ENERGY SUBTOTAL
1/1
4-1
O
t_>
Capital /installed kW*
Operating/kWh*
High Low
High Low
* See cost section of report.
2
3
3
3
2
2
4
4
2
2
3
3
2
2
3
3
1
2
1
2
1
1
1
1
COST SUBTOTAL
GRAND TOTALS
PROCESSES
SELECTED
'R' x 'W
1
Figure 8. FGD rating chart.
45
-------
weight those factors most important at his site. A range of 0 to 10 is
suggested although a smaller range can be used. Thus, if a condition is
not very important, it is weighted with a 0 or 1 factor. For example,
nitrogen oxides (NOX) control may not be required and would be weighted
very low. Conversely, cost factors might be very important and would be
weighted with a 9 or 10. In the current study, R factors are assumed
constant for all process variations. In reality, however, these factors
may vary for a specific process depending on such considerations as type
fuel (i.e., coal vs oil), type application (new vs retrofit), or other
specific considerations.
System Status
This criterion is based on the number of similar processes in
operation and on the general operability of the FGD process. The number
and sizes of processes in operation are an indicator of a successful
system. The lime and limestone processes are the most widely used and
are rated the highest. Conversely, those processes that have been
applied on a limited basis are rated lower.
The mechanical technology and process controllability are indicators
of process operability. The simpler processes are rated higher than
those which involve more complex processing steps. The magnesium oxide
and dry processes are rated slightly lower than the wet processes because
they have shown poorer performance in these areas.
Average availability relates FGD process operation to boiler opera-
tion and is a measure of ability to operate when needed. The magnesium
oxide, copper oxide, and carbon adsorption processes are rated low in
this area because they have reported poor availabilities.
Maintenance requirements relate largely to design and operation and
depend less on the actual type of FGD process. The indicated factors
are based on engineering judgements on limited information from operating
processes.
Space requirements depend on quantities of raw material required,
mechanical equipment size, and the amount of sludge for disposal. Those
processes that produce sludge are rated lowest because of the large area
needed for storage of the sludge over the life of the power unit.
Although regenerable processes require extra mechanical equipment, they
are rated higher because they do not require sludge disposal sites.
Raw Materials
This criterion deals with absorbent, water, and reducing fuel
availabilities. Those processes, such as the lime- and limestone-based
processes, that require absorbent in direct proportion to the SC>2
removal are rated the lowest in this area since they require relatively
large amounts of absorbent compared to regenerable processes. Processes
that require very little absorbent, such as the regenerable processes,
46
-------
are rated higher. Fresh water is required fairly equally by all of the
wet processes. The two dry adsorption processes require very little
water.
A reductant such as hydrogen is required by the copper oxide process
and reducing fuels are required by those regenerable processes that
produce sulfur as a final product or require calcination. These
processes are rated lower for that reason.
Byproducts
This criterion relates to the solid and liquid streams produced by
the FGD process. If a marketable product is produced, the process is
rated higher compared to those which produce no marketable byproduct.
Those processes that produce a semimarketable product such as gypsum are
rated at an intermediate level. The amount of sludge produced is also
significant in rating FGD processes. Those processes that produce large
amounts of sludge are rated lower and those that produce little or no
sludge are rated higher.
Waste water treatment requirements vary widely depending on the
local regulations and the specific site conditions. However, all of the
wet processes have some type of effluent discharge although the quantity
varies depending on the particular FGD process. The dry processes which
require no waste water treatment are rated the highest in this area.
Control Efficiency
The ability of an FGD process to achieve high SC>2 removal efficiency
is also an important rating criterion. The actual efficiency achieved
is most affected by the process design; almost any process can be designed
for high control efficiency. Those processes that are rated the highest
are reported to more easily achieve high SOX control efficiency. Particu-
late control is frequently performed in separate equipment such as an
electrostatic precipitator (ESP) or scrubber ahead of the FGD system.
However, the FGD process can also remove some particulate matter and are
rated fairly evenly in this regard.
NOX controls are reported to be effective only in the dilute sulfuric
acid process, which is no longer offered commercially, and the two dry
processes. NOX removal by the other scrubbing processes has not been
well documented but is apparently marginal.
The ability to control other gaseous emissions such as chlorides
and fluorides must occasionally also be considered in selecting an FGD
process. The wet processes can apparently reduce these compounds more
effectively than the dry systems.
jSnergy Needs
This important criterion is most affected by the reheat required,
high pressure drop through the system, and other miscellaneous needs
47
-------
such as high liquid to gas ratios and extensive sludge-handling systems.
Reheat is generally required by the wet-scrubbing processes and these
are rated lower. The two dry processes do not require reheat and are
rated the highest. Pressure drop is again largely a function of design
and can vary widely from system to system with the same FGD process.
Other large energy needs are not generally required by the wet-scrubbing
processes that produce sludge. However, the regenerable processes
require additional pumping and product recovery equipment and are thus
rated somewhat lower because of additional energy needs. The two dry
processes also require additional energy for regeneration. Wide differ-
ences in requirements are not apparent.
Costs
System cost is generally one of the most important rating criterion.
The economic evaluation section of this report details the costs for
individual systems. The ratings reflect these estimated costs. The
lime, limestone, and seawater processes are rated higher because they
generally cost less to install. Regenerable process installed costs
tend to be higher than nonregenerable process costs, but sale of the
byproduct can somewhat reduce the operating cost. The following criteria
were used to rate process cost:
Installed cost Operating cost,
'R' value range, $/kW mills/kWh
1
2
3
4
>120
100-120
80-100
<80
>6
5-6
4-5
<4
To utilize the rating system, the weighting factor is multiplied by
the rating factor for the selected FGD process. The resulting products
are added and the totals are compared with one another. The highest
value indicates which process best meets the user's needs.
The examples previously used are also applied here to illustrate
the use of the rating chart. Figure 9 rates the four FGD processes
selected from the matrix approach. Weighting factors that emphasize
high efficiency and availability are chosen and each product of R times
W is calculated and summed. Total ratings for the lime gypsum, magnesium
oxide, and sodium sulfite processes are 487, 405, and 453 respectively.
Because the lime gypsum system has been widely used for oil-fired installa-
tions, it scores highest in the system status and needs area.
Figure 10 presents the rating for example No. 2, the coal-fired
seacoast plant. The weighting factors emphasize minimum space and cost
requirements. In this case, the seawater process scores highest and is
followed by the jet-bubbling limestone, double-alkali, and limestone
gypsum processes.
48
-------
CRITERIA
DEFINITION
•o
(U
QJ
C
•0
l/t
3
-^
3
0
«]
4 ^t
:
.1
,°
c
e
1
1
:
-
0
E
3
frt
•u
£Z
O
(fl
£
.2
!°
CO
VALUES
er
c
a
o
tfi
•a
A
C
O
s
0
UJ
-o
01
a
c
o
o
cr»
.c:
(U
aj
5
0
'U1
PROCESSES
SELECTED
Lime/gypsum
Magnesium oxide
Sodium sulfite
'R' x 'W
ik^bbb 3il|l| 9 36 isl27
2)4
[3 13(4)3
4|3
3
3|3J4|3 3
2!3
2
2
3
3
2
2
3 2|3
2
1
3|3|2|2|2|2
3|3|2
4 3l3l3|3 1
T
3
2J2
9
6
7
2 |1 | 10
3|4|2 3|3i3!2J3|l|l
2
4
2
2
3|3|4|3I3
Raw
material
needs
Absorbent availability
Fresh water retirements
Reducing agent
Low High
2)2)2
STATUS
2
3
2
3
3
3|3|3
3
3
3|3
5
3
36|l8 27
18|l2|l2
21|14|21
30 1 10|30|
15 10 15 |
6
9
9
5 15 15) 15
SUBTOTAL
2l2l2l2 2)3 b 3 3
High Low |2|2l2|3|2 2 |2 3 13
Hign Low
4
4
8
3 14 |4 5
4|4|4|4|4|4 2|3|2|l| 8
RAW MATERIAL
O GJ
C- C
C3 oO
Marketable quality
Sludge amount
Water treatment
requirements
Poor Good
Large Small
La rge Sma 1 1
1
1
3
1
1
111
3
3
1
3
1
3
3
SUBTOTAL
3
3 3J3
2
2
2
4
4k
314J4
3
3
3
4
4
4
4
4
4
9
5
9
BYPRODUCT SUBTOTAL
trol
lievable
o u
CJ na
S07
Particulates
NOX
Hal ides
Low High
Low High
Low High
Low High
3|3 4
sh
3
3|3 4
3i3l3
4 13 |4 |4 J2 bl 10
3 3
2|3 2 10
lil|l|l|l[l|l 2J1 113 \2 8
4|4J4J3 4J4|4|3|4 4
CONTROL
X
Cl i/l
CU (U
c u
UJ 2
Reheat
Pu;r.o 4 fan requirements
Other
Yes No
High Low
High Low
1
1
1 1
1
1
2l3l3l3l2l3
3|3|3
Vt
O
O
Capital/installed kW*
Operating/kWh*
High Low
High Low
* See cost section of report.
2
3
3 3
2
2
2 2
5
SUBTOTAL
1
1
3i3
3l3|3|3
ENERGY
4
2
3
4|2|3
3
1
1
4
4
3J3l2 2
2|2
2
2
7
7
5
SUBTOTAL
2
2
COST SUB
3
1
3|2
ll
21
1
1
9
Ijl 8
TOTAL
GRAND TOTALS
%°M ^
16
24 24|
10! islisj
32 16 24
58 55 63
27
15
18
60
36
36
20|20
27
83
27
83
40|40J40|
30 30
20
888
20 20 20
98
7
98|88
7
21 21
15 10
43J 38
27
9
7
21 1
10
38 j
9
24|l6|l6
51|25l25
v.»\d^1
Figure 9. Process applicability rating chart applied to
example No. 1.
49
-------
CRITERIA
DEFINITION
•o
(U
OJ
C
t>O
13
rO
4-J
E
QJ
.4-1
LO
>>
to
Number installed
Sizes installed
Process controlabil ity
Mechanical technology
Average availability
Maintenance required
Space (equipment &
storage of reagents
and solid products
Ability to follow load
RATING 'R'
1234
Few Many
Small Large
Complex Simple
Complex Simplq
Low High
High Low
Large Small
Poor Good
PROCESSES SURVEYED
mestone/sludqe
_i
C"
T2
O
•v
e
_j
O"
~
v>
K
-£
rtt
!
D°
Seawater
E
c^
\
c
o
E
_J
e
=>
a
>j
E
_l
e
Q
CT
\
!
i
Q
c
0
ttj
!
I
"
o
E
-
a?
c;
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rt
2
z
I
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0
«
Carbon a dsorotion
5
0]
o
Q
O
O
'R VAtUES
4
4
3
3
4
4
3
.£
2
3
I|A 4 3
3
2
2|4|4|3|3|2
4J3J3 3|3 2
3
1
3|2
2 2
1
1
2
3|3 4|3|3|3 3|2|3|2 2
2!3;2|4_3|3 3 |3 1 |3 |2
2
2
3
3
2
3
3
2
4)2
4
3 4
2
3
3J3 3
2
3
2
3
2
3
2|3|1
3
3
3
3
3
3
1
1
3
3
Owner's Weighting (0-10)
W
5
5
7
7
8
8
10
8
STATUS SUBTOTAL
Raw
material
needs
Absorbent availability
Fresh water requirements
Reducing agent
Low High
High Low
High Low
2
2
4
2
9
2 2
4
4
2
3
4
2
2
4
2
2
2
3
2)2 3 3
3
3
3 4
4 J4 4 J2 3
2
3
4
1
9
5
10
RAW MATERIAL SUBTOTAL
i/>
-o -a
O CJ
i- •>
CO aO
Marketable quality
Sludge amount
Water treatment
requirements
Poor Good
Large Small
Large Small
1
1
3
]^
1
3
1
1
3
J-
3
1
3
3
2
3
3
2
3
3
2
4
3
3
4
4
3
4
4
3
4
4
4
4
4
A
0
10
5
BYPRODUCT SUBTOTAL
Control
achievable
S02
Particulates
NOX
Hal ides
Low High
Low High
Low High
Low High
3
3
1
3
4
3 3
1 1
A] 4 4
3
3
3
3
1 1
3 4
41413 4
3J3 3 3
1
4
1|2
4
4
2
2
0
3
2
1 |l |3 |2
4 4
2
2
8
8
5
2
CONTROL SUBTOTAL
:>,
en c/i
cu QJ
C GJ
uj zz:
Reheat
Puinp & fan requirements
Other
Yes No
Hign Low
High Low
1
2
3
I
1
1
3l3l3
3
3 3
1
2
3
1
3
3
1
1
3l3
3
3
1
3
2
1
4
3 2
2
2
4
o
2
8
8
5
ENERGY SUBTOTAL
4->
O
o
Capital/installed kW*
Operating/kWh*
High Low
High Low
* See cost section of report.
2
3
3
3
2
4
0
24(2
3
3
~
3
1
1
•^2 2
1
1
1
•i
10
7
COST SUBTOTAL
GRAND TOTALS
PROCESSES
SELECTED
Seawater
Limestone/ gypsum
Double alkali/ gypsum
Jet bubbling limestone
'R' x 'W
5I20
10
20
28 21
15 15
15 15
21 21
28|21 21 2L
32)24 24 24
32
40
32
^
18
16 |24
20
24
^
18
20
24
&
18
15 | 10)10
40 40 40
73
0
30
5
35
24
24
5
6
59
8
24
15
47
40
28
68
$
68 |68
0
30
10
40
24
24
5
0
30
10
24
20
"24~
•v*
18
15
40
73
0
30
15
40 Jl5
32 24
24
5
24
~10
8|8| 6
61
8
69 64
8
16|24
15
15
3947
20
20
14|14
8
24
15
47
30
21
34|34| 51
^w
Figure 10. Process applicability rating chart applied to
example No. 2.
50
-------
SUPPLIERS OF FGD SYSTEMS
Information on FGD systems can be obtained from a number of sources.
Suppliers of FGD systems in the United States are shown in Table 18.
Direct contacts with these people can be made to obtain further detailed
information on their system.
51
-------
01
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-------
REFERENCES
1. Flue Gas Desulfurization Pilot Study, Phase I - Survey of Major
Installations. Published by PEDCo Environmental, Inc., Cincinnati,
Ohio, USA, 1979, as the following NATO appendixes [separate covers]:
Appendix 95-A, Limestone/Sludge Flue Gas Desulfurization Process.
F. Princiotta (U.S. Environmental Protection Agency, Washington,
D.C.), R. W. Gerstle and E. Schindler (PEDCo Environmental).
Appendix 95-B, Lime/Sludge Flue Gas Desulfurization Process. N.
Haug (Umweltbundesamt, Berlin), G. Oelert and G. Weisser (Battelle-
Institut e.V., Frankfurt am Main, West Germany). Appendix 95-C,
Double Alkali/Sludge Flue Gas Desulfurization Process. Princiotta,
Gerstle, and Schindler. Appendix 95-D, Sea Water Scrubbing Flue Gas
Desulfurization Process. R. I. Hagen and H. Kolderup, Foundation of
Scientific and Industrial Research at the University of Trondheim
(SINTEF), Norway. Appendix 95-E, Limestone_/Gypsum Flue Gas Desulfu-
rization Process. Princiotta, Gerstle, and Schindler. Appendix 9.5-F,
Lime/Gypsum Flue Gas_Desulfurization Process. Haug, Oelert, and
Weisser. Appendix 95-G, Double Alkali/Gypsum Flue Gas Desulfurization
Process. Princiotta, Gerstle, and Schindler. Appendix 95-H, Flue
Gas Desulfurization by Scrubbing with Dilute Sulfuric Acid.
Princiotta, Gerstle, and Schindler. Appendix 95-1, Magnesium Oxide
Flue Gas Desulfurization Process. Princiotta, Gerstle, and Schindler.
Appendix 95-J, Sodium Sulfite Scrubbing Flue Gas Desulfurization
Process. Princiotta, Gerstle, and Schindler. Appendix 95-K,
Carbon Adsorption Flue Gas Desulfurization Process. Haug, Oelert,
and Weisser. Appendix 95-L, Copper Oxide Flue Gas Desulfurization
Process. Princiotta, Gerstle, and Schindler.
2. Flue Gas Desulfurization Pilot Study Phase I - Survey of Major
Installations - Summary of Survey Reports - Flue Gas Desulfurization
Processes. NATO Report No. 95, PEDCo Environmental, Inc., Cincinnati,
Ohio, USA, 1979.
3. Stephenson, C. D., and R. L. Torstrick. Shawnee Lime/Limestone
Scrubbing Computerized Design/Cost-Estimate Model Users Manual.
Bull. ECDP B-3, Tennessee Valley Authority, Muscle Shoals, Ala., USA,
and EPA-600/7-79-210, U.S. Environmental Protection Agency, Washington,
D.C., 1979.
4. McGlamery, G. G., R. L. Torstrick, W. J. Broadfoot, J. P. Simpson,
L. J. Henson, S. V. Tomlinson, and J. F. Young. Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes. Bull. Y-90,
Tennessee Valley Authority, Muscle Shoals, Ala., USA, and
54
-------
EPA-600/2-75-006, U.S. Environmental Protection Agency, Washington,
D.C., 1975. [Lime, limestone, magnesium oxide, and sodium sulfite
processes are included in this study.]
5. Tomlinson, S. V., F. M. Kennedy, F. A. Sudhoff, and R. L. Torstrick.
Definitive SOX Control Process Evaluations: Limestone, Double-
Alkali, and Citrate FGD Processes. Bull. ECDP B-4, Tennessee
Valley Authority, Muscle Shoals, Ala., USA, and EPA-600/7-79-177,
U.S. Environmental Protection Agency, Washington, D.C,, 1979.
6. Anderson, K. D., J. W. Barrier, W. E. O'Brien, and S. V. Tomlinson.
Definitive SOX Control Process Evaluations; Limestone, Lime, and
Magnesia FGD Processes. Bull. ECDP B-7, Tennessee Valley Authority,
Muscle Shoals, Ala., USA, and EPA-600/7-80-001, U.S. Environmental
Protection Agency, Washington, D.C., 1980.
7. Economic Indicators. Chem. Eng., Vol. 81, 82, and 83, 1974, 1975,
1976.
8. Happel, J., and D. G. Jordan. Chemical Process Economics. 2d Ed.,
Marcel Dekker, Inc., New York, 1975. pp. 218-221.
9. American Association of Cost Engineers, Morgantown, W. Va., USA.
10. Smith, M., and M. Melia. EPA Utility FGD Survey; July-September 1979,
EPA-600/7-79-022f, U.S. Environmental Protection Agency, Washington,
D.C. [issued every three months. Referenced report is most recent
report.]
55
-------
APPENDIX A
LIMESTONE SLUDGE PROCESS
PROCESS DESCRIPTION
The limestone slurry process, shown in Figure A-l, is designed to use a
mobile-bed absorber, with presaturator and mist eliminator. The mist elimi-
nator is equipped for upstream and downstream wash with fresh makeup water.
The flue gas from the common plenum is cooled in the presaturator, scrubbed
with limestone slurry in the absorber, passes through the mist eliminator,
and is reheated before being vented to the stack plenum.
Limestone slurry is recirculated through the absorber and an external
surge tank. The slurry is maintained at 15% solids by withdrawal of a purge
stream and addition of fresh slurry. The reaction of SO- with CaCOg in the
limestone is assumed to produce 80% calcium sulfite hemihydrate (CaSO--1/2H20)
and 20% gypsum (CaSO^-Zl^O). The purge stream containing these salts, un-
reacted limestone, and minor impurities is pumped one mile to an earthen-
diked, clay-lined pond where it settles to a sludge of about 40% solids.
Supernate water is returned from the pond for reuse in the process.
The feed preparation area consists of two trains of crushers and wet
ball mills serving all four absorber trains. As-received 40 mm maximum-size
crushed limestone is further reduced in crushers and processed in wet ball
mills to a 60% solids slurry with a particle size of about 70% less than
0.003 mm that is metered to the scrubber slurry loop.
The base-case material balance is shown in Table A-l and the base-case
equipment list is shown in Table A-2. The cost factor for scaling is shown
for each area in the equipment list.
SPECIFIC PROCESS PREMISES
1. The flue gas is assumed to be cooled from 149° to 53°C (300° to
127°F) in the presaturator at an L/G ratio of 0.5 liter/in3
(4 gal/103 aft3).
2. The absorber is a mobile-bed type (TCA) with a flue gas super-
ficial velocity of 3.8 m/sec (12.5 ft/sec) and a pressure drop,
including the mist eliminator, of 2.14 kPa (8.6 inches H20). An
L/G ratio of 6.7 liters/m3 (50 gal/103 aft3).
3. Stoichiometry is 1.4 moles of CaC03 to 1.0 mole of S02 removed
and 1.0 mole of CaC03 to 2.0 moles of HC1 removed.
A-l
-------
ENERGY REQUIREMENTS
For base-case conditions, reheat of the cleaned gas from 53°C to 79°C
requires 42.2 x 10 kg/hr (93,050 Ib/hr) of 243°C (470°F) steam at 3.55 x 10
kPa absolute pressure (500 psig) equivalent to about 17.62 x 10^ kcal/hr.
The electrical power demand for the base-case limestone sludge process
is about 7,995 kW or 1.6% of the rated output of a 500-MW power plant. For
6,000 hours of operation, the annual electrical energy consumption is 48.0 x
106 kWh.
The total equivalent energy consumption for the base case is approximately
37.7 x 106 kcal/hr or 3.3% of the input energy required for the 500-MW power
unit. Summarized energy requirements for all cases are listed in Table A-3.
BYPRODUCT MANAGEMENT
ESP units remove 99.2% of the fly ash from the flue gas and, therefore,
only a small amount of fly ash is found in the FGD process sludge. (Fly ash
emission from oil-fired units does not exceed the EPA particulate emission
standard and fly ash collection facilities are not included in oil-fired
power plant design.) Projected mass flow rates of wastes for the base case
are shown below.
Component kg/hr Ib/hr
CaSO -1/2H20
CaSO:r'2H20
CaCO^
CaCl-
Mg
Fly ash
Inerts
16,550
5,670
6,448
433
39
149
1,236
36,480
12,500
14,215
955
85
329
2,726
30,525 67,290
Based on a 30-year life for both the power unit and the FGD units, the
sludge disposal pond for the base case requires approximately 123 ha
(305 acres). It is designed for an optimum depth of approximately 6.1 m
(20 ft). Pond size is listed by case in Table A-4.
ECONOMIC EVALUATION
Capital investment and annual revenue requirement summaries for the
base case, five fuel variations, and three power plant size variations are
shown in Tables A-5 and A-6. The detailed results are shown in Tables A-7
through A-24. The same results showing the range of estimated accuracies
are shown graphically in Figures A-2 and A-3. The effect of fuel sulfur
content on costs is shown in Figure A-4.
A-2
-------
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A-3
-------
TABLE A-l. LIMESTONE SLUDGE PROCESS
MATERIAL BALANCE - BASE CASE (3.5% SULFUR COAL)
Stream No.
Description
1
2
t
4
3
h
7
H
9
10
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, NmJ/hr (0"C)
Gas flow. sft3/min (60°F)
Liauid flow, liters/min
Liauid flow, eal/min
Temperature. °C
Particulates, kg/hr
Particulates, Ib/hr
1
Coal to boiler
194
428,600
2
Combustion air
to air heater
2,062
4,546,200
1,615,700
1.005.000
27
3
Gas to
presaturator-
absorber
2,225
4,906,000
1,697,700
I 1.056.000
149
199.1
439
4
Gas to reheater
2,316
5,106,900
1,182.100
1.127.200
38.6
10.2
53
49.8
110
5
Gas to stack
2,316
5,106,900
1,815.000
1.128.900
79
49.8
110
Stream No.
Description
1
i
1
4
5
h
7
8
9
Iff
Total stream, 1000 kg/hr
Total stream, Ib/hr
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, "C
Pressure, kPa (abs)
Pressure, psig_
Specific gravity
Undissolved solids, %
6
Steam to
reheater
42
93,050
243
3.550
500
7
Makeup water
to absorber
141
310,400
2,347
620
|_ 8
Limestone to
preparation
facilities
26
56,240
9
Settled sludge
75
165,590
949
251
1.32
40
h
7
8
9
10
_5
ft
7
8
9
10
A-4
-------
TABLE A-2. LIMESTONE SLUDGE PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area size-cost
Area
1.
2.
3.
1 — Materials
Item
Car shaker
Car puller
Handling
No.
1
1
Hopper, limestone 1
Description
Top mounting with crane
25 hp with 5 hp return
12 ft x 20 ft x 2 ft bottom,
exponent
Total
material
cost,
1979 $
9,000
50,000
9,300
0.73
Total
labor
cost,
1979 $
2,100
2,100
8,700
unloading
4. Feeder, limestone
unloading
5. Conveyor, lime-
stone unloading
6. Conveyor, lime-
stone stocking
(incline)
7. Conveyor, lime-
stone stocking
8. Tripper 1
9. Mobile equipment 1
10. Hopper, reclaim 2
11. Feeder, live 2
limestone storage
12. Pump, tunnel sump 2
20 ft deep, 4,800 ft3, carbon
steel
Vibrating pan, 42 in. wide x
60 in. long, 3 hp, 250 tons/hr
4,800
Belt, 36 in. wide x 10 ft long, 2,200
5 hp, 250 tons/hr, 130 ft/min
Belt, 36 in. wide x 320 ft 48,000
long, 30 hp, 15° slope, 250
tons/hr, 130 ft/min
Belt, 36 in. wide x 200 ft
long, 7-1/2 hp, 250 tons/hr,
130 ft/min
1,100
1,000
15,400
30,000 10,100
1 hp, 30 ft/min 14,800 2,800
3
Scraper tractor, 22 to 24 yd 181,000
capacity
7 ft x 7 ft, 4 ft deep, 60° 10,700 1,900
slope, carbon steel
Vibrating pan, 24 in. wide x 7,000 2,100
40 in. long, 1 hp, 15 tons/hr
Vertical, 60 gpm, 70 ft head, 6,800 1,600
5 hp, carbon steel, neoprene
lined, (1 operating, 1 spare)
(continued)
A-5
-------
TABLE A-2 (continued)
13.
14.
15.
16.
17.
18.
19.
Area
1.
2.
3.
Item No.
Conveyor, live 1
limestone feed
Conveyor, live 1
limestone feed
(incline)
Elevator, live 1
limestone feed
Bin, crusher 2
feed
Dust collecting 1
system
Dust collecting 1
system
Dust collecting 1
system
Subtotal
2 — Feed Preparation
Item No .
Discharge, feeder 2
bin
Feeder, crusher 2
Crusher 2
Total
material
cost,
Description 1979 $
Belt, 30 in. wide x 100 ft 14,400
long, 2 hp, 100 tons/hr,
60 ft /rain
Belt, 30 in. wide x 190 ft 26,600
long, 5 hp, 35 ft lift, 100
tons/hr, 60 ft/min
Continuous, bucket 12 in. x 8 30,800
in. x 11-3/4 in., 20 hp, 75 ft
lift, 100 tons/hr, 160 ft/min
13 ft dia x 21 ft high, with 10,900
cover, 3/8 in. carbon steel
Cyclone, 2,100 aft3/min, motor- 5,900
driven fan
3
Cyclone, 6,200 aft /min, motor- 14,200
driven fan
Bag filter, polypropylene bag, 12,000
14,400 aft^/min, automatic
shaker system (1/2 cost in
feed preparation area)
488,400
Total
labor
cost,
1979 $
5,100
9,900
1,800
15,700
4,800
11,100
28,200
125,500
Area size-cost
exponent 0 . 70
Total
material
cost,
Description 1979 $
Vibrating, 15 tons/hr, carbon 19,500
steel
Weigh belt, 18 in. wide x 14 15,800
ft long, 2 hp, 15 tons/hr
Gyratory, 0 x 1-1/2 to 3/4 107,500
in., 75 hp, 15 tons/hr
(continued)
A-6
Total
labor
cost,
1979 $
4,200
2,000
11,900
-------
TABLE A-2 (continued)
Item
4. Ball mill
Ball charge
5. Hoist
6. Tank, milled
product
Lining
7. Agitator, milled
product tank
8 . Pump , milled
product tank
9. Tank, slurry
feed
Lining
10. Agitator, slurry
Total
material
cost,
No. Description 1979 $
2 Wet, open system, 8 ft dia x
13 ft long, 350 hp, 340 tons/
day
1 Electric, 5 ton, 7-1/2 in.
1 7-1/2 ft dia x 7-1/2 ft high,
2,440 gal, open top, four 7-1/2-
in. baffles, agitator supports,
carbon steel
(20 min residence time)
1/4 in. neoprene lining
1 36 in. dia, 10 hp, neoprene
coated
2 Centrifugal, 116 gpm, 60 ft
head, 7-1/2 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
1 21-1/2 ft dia x 22 ft high,
58,600 gal, open top, four 21-
1/2-in. -baffles, agitator
supports, carbon steel
(8 hr residence time)
1/4 in. neoprene lining
1 Two turbines, 84 in. dia, 75
424,500
31,100
8,300
1,300
1,300
12,000
5,400
10,500
10,700
58,000
Total
labor
cost,
1979 $
35,200
-
2,100
2,200
1,600
1,200
1,500
18,500
13,100
6,000
11.
feed tank
Pump, slurry feed 2
tank
12. Dust collecting 1
system
hp, neoprene coated
Centrifugal, 116 gpm, 60 ft
head, 7-1/2 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
3
Cyclone, 8,200 aft /min, motor-
driven fan
5,400
1,500
16,300 12,700
(continued)
A-7
-------
TABLE A-2 (continued)
13.
Item
Dust collecting
No.
1
Description
Bag filter, polypropylene
Total
material
cost,
1979 $
12,000
Total
labor
cost,
1979 $
28,200
system
Subtotal
bag, 14,400 aft-Vmin, automatic
shaker system (1/2 cost in
materials handling area)
739,600 141,900
Area 3—Gas Handling
Area size-cost
exponent 0.68
Item No .
1 . Fans 4
Description
Forced draft, 14.8 in. static
Total
material
cost,
1979 $
1,427,900
Total
labor
cost,
1979 $
93,100
head, 875 rpm, 1,200 hp,
fluid drive, double width,
double inlet
Subtotal
1.427,900 93,100
Area 4—SO,, Absorption
Area size-cost
exponent 0.74
Item
No,
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
1. S0_ absorber
2. Tank, recircu- 4
lation
TCA scrubber, 31 ft long x
14 ft wide x 40 ft high, 1/4
in. carbon steel, neoprene
lining, 316 SS grids, nitrile
foam spheres, FRP spray
headers, 316 SS chevron vane
entrainment separator
32 ft dia x 32 ft high,
192,500 gal, open top, four
32 in. wide baffles, agitator
supports, carbon steel
(10 min residence time)
(continued)
2,813,700 242,300
92,200 169,000
A-8
-------
TABLE A-2 (continued)
2.
3.
Item No .
(continued)
Lining
Agitator, recir- 4
Description
1/4 in. neoprene lining
132 in. dia, 60 hp, neoprene
Total
material
cost,
1979 $
93,100
220,000
Total
labor
cost,
1979 $
113,800
81,800
culation tank
4. Pump, presatura-
tor
5. Pump, slurry 10
recirculation
6. Pump, makeup
water
coated
Centrifugal, 1,274 gpm, 60 ft
head, 50 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
Centrifugal, 7,954 gpm, 100
ft head, 500 hp, carbon
steel, neoprene lined
(8 operating, 2 spare)
Centrifugal, 1,240 gpm, 200 ft
head, 150 hp, carbon steel
(1 operating, 1 spare)
48,900 11,200
442,800 39,100
33,200 7,900
7. Soot blowers
Subtotal
40 Air, retractable
260,000 225,800
4,003,900 890,900
Area 5—Reheat
Area size-cost
exponent 0.75
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Reheater
Steam, tube type, 3,665 ft ,
one-half of tubes made of
Inconel 625 and one-half made
of Cor-Ten
856,000 39,200
2.
Soot blowers
Subtotal
20
Air,
retractable
130
986
,000
,000
112
152
,900
,100
(continued)
A-9
-------
TABLE A-2 (continued)
Area 6—Solids Disposal
Area size-cost
exponent 0.54
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Tank, pond feed 1
Lining
2. Agitator, pond 1
feed tank
3. Pump, pond feed 2
16 ft dia x 32 ft high,
48,100 gal, open top, four
16 in. baffles, agitator
supports, carbon steel
1/4 in. neoprene lining
Two turbines, 60 in. dia, 5
hp, neoprene coated
Centrifugal, 803 gpm, 150 ft
head, 75 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
10,100 19,200
10,700 13,000
9,000 900
27,200
*Size of pond feed tank not a function of residence time.
7,700
4 . Pump , pond
return
Subtotal
2 Centrifugal, 552 gpm, 150 ft
head, 50 hp, carbon steel
(1 operating, 1 spare)
23,000
80,000
6,300
47,100
A-10
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A-ll
-------
TABLE A-4. LIMESTONE SLUDGE PROCESS POND SIZE
Case
200-MW unit
Coal, 3.5% sulfur
500-MW unit
Coal, 3.5% sulfur
(base case)
Coal, 0.8% sulfur
Coal, 1.4% sulfur
Coal, 2.0% sulfur
Lignite, 0.5% sulfur
Oil, 2.5% sulfur
700-MW unit
Coal, 3.5% sulfur
1000-MW unit
Coal, 3.5% sulfur
Area,
hectares (acres)
61
123
39
52
75
30
66
159
209
(150)
(305)
(96)
(128)
(185)
(74)
(163)
(394)
(516)
Depth,
meters (ft)
5.2
6.1
4.6
4.9
5.4
4.6
5.2
6.4
6.9
(17)
(20)
(15)
(16)
(18)
(15)
(17)
(21)
(23)
TABLE A-5. LIMESTONE SLUDGE PROCESS CAPITAL INVESTMENT
To^al capital investment
Case $ $/kW
200-MW unit
Coal, 3.5% sulfur 26,302,000 132
500-MW unit
Coal, 3.5% sulfur 53,083,000 106
(base case)
Coal, 0.8% sulfur 39,995,000 80
Coal, 1.4% sulfur 41,634,000 83
Coal, 2.0% sulfur 45,511,000 91
Lignite, 0.5% sulfur 39,036,000 78
Oil, 2.5% sulfur 40,637,000 81
700-MW unit
Coal, 3.5% sulfur 70,967,000 101
1000-MW unit
Coal, 3.5% sulfur 93,941,000 94
A-12
-------
TABLE A-6. LIMESTONE SLUDGE PROCESS ANNUAL REVENUE REQUIREMENTS
Case
200-MW unit
Coal, 3.5% sulfur
500-MW unit
Coal, 3.5% sulfur
(base case)
Coal, 0.8% sulfur
Coal, 1.4% sulfur
Coal, 2.0% sulfur
Lignite, 0.5% sulfur
Oil, 2.5% sulfur
700-MW unit
Coal, 3.5% sulfur
1000-MW unit
Coal, 3.5% sulfur
$
7,029,100
14,638,000
11,151,700
11,539,200
12,573,100
10,945,400
11,384,500
19,734,300
26,384,700
Mills/kWh
5.86
4.88
3.72
3.85
4.19
3.65
3.79
4.70
4.40
$/ton coal
(bbl oil)
burned
13.37
11.39
7.85
10.77
10.24
6.41
(2.55)
11.09
10.61
$/MBtu
heat
input
0.64
0.54
0.41
0.43
0.47
0.41
0.42
0.53
0.51
$/ton
sulfur
removed
501
429
1,397
973
669
1,883
710
415
397
A-13
-------
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in
3.5 0.8 1.4 2.0 0.5 2.5 3.5
CASE VAR FAT IONS IDENTIFIED BY FUEL TYPE AND SULFUR CONTENT OF FUE
Figure A-2. Limestone sludge process capital investment range
O O O 0
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M>I/$ '1N3W1S3ANJ
A-14
-------
1 1
• — I
- ' 1
, — 1
a o -
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A-15
-------
w
a
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Z
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i-J
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u
50
40
30
20
10
500-MW units
90% S02 removal
• Oil-fired unit
X Oil-fired unit
0 Total capital investment
X Average annual revenue
requirement
I
I
Figure A-4.
10 20 30 40
SULFUR REMOVED, k SHORT TONS/YR
Limestone sludge process. Effect of sulfur removed on
capital investment and annual revenue requirements.
A-16
-------
TABLE A-7. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 3.5% S In coal;
90% S02 removal; pond disposal of waste solids)
Investment, $
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1
2
4
9
1
2
21
1
23
5
28
1
3
1
6
7
42
3
5
50
1
1
53
,824
,062
,950
,458
,292
,164
,750
,305
,055
,481
,536
,240
274
,915
,226
,655
,038
,229
,675
,068
,972
,098
,013
,083
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
% of
total direct
investment
6,
7.
17,
33.
4.
7.
76.
4
80.
19.
100.
4.
1.
13,
4 (
23.
24.
148.
12,
17,
178,
3,
3,
186,
.4
,2
.3
.2
5
.6
.2
.6
,8
.2
.0
,3
,0
,7
,3
,3
,7
,0
.9
.7
.6
.9
.5
.0
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F).
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-17
-------
TABLE A-8. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
168,700 tons
24,060 man-hr
419,600 MBtu
223,300 kgal
47,967,300 kWh
3,220 man-hr
Unit
cost, $
7.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
Total
annual
cost, $
1,180,900
1,180,900
300,800
839,200
26,800
1,391,100
2,008,800
54,700
4,621,400
5,802,300
% of average
annual revenue
requirements
8.07
8.07
2.06
5.73
0.18
9.50
13.73
0.37
31.57
39.64
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 4.88
3,058,300
4,565,100
1,182,200
30,100
8,835,700
14,638,000
$/ton coal $/MBtu heat
burned input
11.39 0.54
20.89
31.19
8.08
0.20
60.36
100.00
$/ton
S removed
429
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,221 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°c (175°F).
Sulfur removed, 30,947 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $28,536,000; total depreciable investment, $50,972,000; and total
capital investment, $53,083,000.
All tons shown are 2,000 Ib.
A-18
-------
TABLE A-9. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 0.87* S in coal;
907, 502 removal; pond disposal of waste solids)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Investment, $
% of
total direct
inves tment
631,000
746,000
5,034,000
9,628,000
1,315,000
987,000
18,341,000
1,101,000
19,442,000
1,748,000
21,190,000
3.0
3.5
45.4
6.2
86.6
JL-J
91.8
8.2
100.0
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
1,112,000
262,000
3,142,000
978,000
5,494,000
5,337,000
32,021,000
5.3
1.2
14.8
25.9
25.2
151. 1
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,027,000
3.843,000
38,891.000
364,000
7_4CMOO
39,995,000
14.3
18.1
183.5
1.7
3.5
188.7
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79 C (175 F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-19
-------
TABLE A-10. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 0.8% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Oper.ating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
39,400 tons 7.00/ton
24,060 man-hr 12.50/man-hr
429,900 MBtu 2.00/MBtu
109,400 kgal 0.12/kgal
44,911,500 kWh 0.029/kWh
1,350 man-hr 17;00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
275,800
275,800
300,800
859,800
13,100
1,302,400
1,607,800
23,000
4,106,900
4,382,700
2.47
2.47
2.69
7.71
0.12
11.68
14.42
0.21
36.83
39.30
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
2,333,500
3,439,600
965,800
30,100
6,769,000
11,151,700
20.93
30.84
8.66
0.27
60.70
100.00
Equivalent unit revenue requirements
Mills/kWh
$/ton coal
burned
$/MBtu heat
input
$/ton
S removed
3.72
7.85
0.41
1,397
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,288,938 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 7,238 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $21,190,000; total depreciable investment, $38,891,000; and total
capital investment, $39,995,000.
All tons shown are 2,000 Ib.
A-20
-------
TABLE A-ll. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 1.4% S in coal;
90% S02 removal; pond disposal of waste solids)'
•/. of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps )
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
4
9
1
1
18
1
19
2
22
1
3
1
5
5
33
3
3
40
41
843
984
,915
,392
,283
,223
,640
,118
,758
,342
,100
,136
264
,238
,009
,647
,549
,296
,095
,996
,387
478
769
,634
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
3
4
22
42
5
5.
84
5.
89
10
100
5
1
14,
4
25
25
150
14
18.
182,
2,
3,
188,
.8
.5
.2
.5
.8
.5
.3
.1
.4
.6
.0
.1
,2
.7
.6
.6
.1
.7
.0
.0
.7
,2
.5
.4
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79 C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-21
-------
TABLE A-12. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 1.4% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
58,600 tons 7.00/ton
24,060 man-hr 12.50/man-hr
415,500 MBtu 2.00/MBtu
124,000 kgal 0.12/kgal
44,071,000 kWh 0.029/kWh
1,710 man-hr 17. 00 /man-hr
Total % of average
annual annual revenue
cost, $ requirements
410,200
410,200
300,800
831,000
14,900
1,278,100
1,650,900
29,100
4,104,800
4,515,000
3.55
3.55
2.61
7.20
0.13
11.08
14.31
0.25
35.58
39.13
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.85
2,423,200
3,580,500
990,400
30,100
7,024,200
11,539,200
$/ton coal $/MBtu heat
burned input
10.77 0.43
21.00
31.03
8.58
0.26
60.87
100.00
$/ton
S removed
973
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,941 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 10,748 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,100,000; total depreciable investment, $40,387,000; and total
capital investment, $41,634,000.
All tons shown are 2,000 Ib.
A-22
-------
TABLE A-13. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 2.0% S in coal;
90% S02 removal; pond disposal of waste solids)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1
1
4
9
1
1
19
1
20
3
24
1
3
1
5
6
36
3
4
43
45
,180
,359
,930
,420
,287
,569
,745
,185
,930
,346
,276
,173
268
,474
,084
,999
,055
,330
,298
,360
,988
675
848
,5U
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
4.
5,
20.
38,
5,
6,
81.
4,
86
13.
100.
4,
1.
14.
4.
24.
24.
149.
13.
18.
181.
2.
3.
187.
.9
.6
,3
.7
.3
,5
,3
.9
.2
.8
.0
.8
.1
3
5
,7
,9
.6
6
.0
.2
.8
5
5
Basis
'.SIS
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79 C (175 F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-23
-------
TABLE A-14. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 2.0% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
92,900 tons 7.00/ton
24,060 man-hr 12.50/man-hr
417,400 MBtu 2.00/MBtu
155,100 kgal 0.12/kgal
45,350,500 kWh 0.029/kWh
2,250 man-hr 17.00/man-hr
Total % of average
annual annual revenue
cost , $ requirements
650,300
650,300
300,800
834,800
18,600
1,315,200
1,774,800
38,300
4,282,500
4,932,800
5.17
5.17
2.39
6.64
0.15
10.47
14.11
0.30
34.06
39.23
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 4.19
2,639,300
3,913,900
1,057,000
30,100
7,640,300
12,573,100
$/ton coal $/MBtu heat
burned input
10.24 0.47
20.99
31.13
8.41
0.24
60.77
100.00
$/ton
S removed
669
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,113,161 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 17,043 metric tons/yr (18,790 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $24,276,000; total depreciable investment, $43,988,000; and total
capital investment, $45,511,000.
All tons shown are 2,000 Ib.
A-24
-------
TABLE A-15. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% SOj removal; pond disposal of waste solids)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
502,000
598,000
5,118,000
9,817,000
1,341,000
831,000
18,207,000
1,092,000
19,299,000
1,365,000
20,664,000
1,096,000
260,000
3,085,000
959,000
5,400,000
5,213,000
31,277,000
2,991,000
3,753,000
38,021,000
289,000
726,000
39,036,000
% of
total direct
investment
2.4
2.9
24.8
47.5
6.5
4.0
88.1
5.3
93.4
6.6
100.0
5.3
1.3
14.9
4.6
26.1
25.2
151.3
14.5
18.2
184.0
1.4
3.5
188.9
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-25
-------
TABLE A-16. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
28,700 tons 7.00/ton
24,060 man-hr 12. 50/man-hr
441,000 MBtu 2.00/MBtu
101,700 kgal 0.12/kgal
45,686,400 kWh 0.029/kWh
1,110 man-hr 17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
200,900
200,900
300,800
882,000
12,200
1,324,900
1,584,900
18,900
4,123,700
4,324,600
1.84
1.84
2.75
8.06
0.11
12.10
14.48
0.17
37.67
39.51
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.65
2,281,300
3,357,100
952,300
30,100
6,620,800
10,945,400
$/ton lignite $/MBtu heat
burned input
6.41 0.41
20.84
30.67
8.70
0.28
60.49
100.00
$/ton
S removed
1,883
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Lignite burned, 1,549,900 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 5,270 metric tons/yr (5,810 tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $20,664,000; total depreciable investment, $38,021,000; and total
capital investment, $39,036,000.
All tons shown are 2,000 Ib.
A-26
-------
TABLE A-17. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new oil-fired power unit, 2.5% S in oil;
90% S02 removal; pond disposal of waste solids)
Pi rec t__I nves_tm_en_t
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators* and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four direct oil-fired reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect .Inyes_ttngn.t.
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
A)lowanee for startup and modifications
Interest during construction
Iota] depreciable investment
Land
K'orLing capita 1
Iota1 capita 1 investment
% Of
total direct
Investment, $ investment
1,051,000
1,215,000
4,371,000
8,257,000
1,127,000
1,439,000
17,460,000
1,048,000
18,508,000
2,961,000
21,469,000
1,159,000
266,000
3,138,000
987,000
5,550,000
5,404,000
32,423,000
2,946,000
3,891,000
39,260,000
600,000
__7_7_7_iOOp
40,637,000
4.9
5.7
20.3
38.5
5.2
6.7
81.3
4.9
86.2
13.8
100.0
5.4
1.2
14.6
4.6
25.8
25.2
151.0
13.7
18.2
182.9
2.8
_1J2
189.3
Basis
hvaluation represents project beginning mid-1977, end ing mid-1980, Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) bv direct oil-fired reheat.
Minimum in-process storage; only pumps are spared.
1H sposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FCD process investment
estimate, begins with common feed plenum downstream of the ESP.
( (instruct ion labor shortages with accompanying overt ime pay incentive not considered.
A-27
-------
TABLE A-18. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new oil-fired power unit, 2.5% S in oil;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
79,200 tons 7.00/ton
24,060 man-hr 12. 50/man-hr
2,425,900 gal 0.40/gal
131,100 kgal 0.12/kgal
38,099,900 kWh 0.029/kWh
2,050 man-hr 17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
554,400
554,400
300,800
970,400
15,700
1,104,900
1,570,000
34,900
3,996,700
4,551,100
4.87
4.87
2.64
8.52
0.14
9.70
13.79
0.31
35.10
39.97
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.79
2,355,600
3,494,800
952,900
30,100
6,833,400
11,384,500
$/bbl oil $/MBtu heat
burned input
2.55 0.42
20.69
30.71
8.37
0.26
60.03
100.00
S/ton
S removed
710
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Oil burned, 710 x 106 liters/yr (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
S removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $21,469,000; total depreciable investment, $39,260,000; and total
capital investment, $40,637,000.
All tons shown are 2,000 Ib.
A-28
-------
TABLE A-19. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(200-MW new coal-fired power unit,.3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (two TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (two indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
950,000
1,103,000
2,158,000
4,076,000
556,000
1,335,000
10,178,000
611,000
10,789,000
2,717,000
13,506,000
943,000
214,000
2,098,000
694,000
3,949,000
3,491,000
20,946,000
1,823,000
2,514,000
25,283,000
554,000
465,000
26,302,000
7.0
8.2
16.0
30.2
4.1
9.9
75.4
4.5
79.9
20.1
100.0
7.0
1.6
15.5
5.1
29.2
25.9
155.1
13.5
18.6
187.2
4.1
3.4
194.7
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79 C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-29
-------
TABLE A-20. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(200-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
69,000 tons
16,440 man-hr
171,600 MBtu
91,300 kgal
19,968,500 kWh
1,890 man-hr
Unit
cost, $
7.00/ton
12.50/man-hr
2.00/MBtu
0.1 2 /kgal
0.031/kWh
17.00/man-hr
Total
annual
cost, $
483,000
483,000
205,500
343,200
11,000
619,000
944,600
32,100
2,155,400
2,638,400
% of average
annual revenue
requirements
6.87
6.87
2.92
4.88
0.16
8.81
13.44
0.46
30.67
37.54
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Equivalent unit revenue requirements
1,517,000
2,262,000
591,100
20,600
4,390,700
7,029,100
$/ton coal $/MBtu heat
Mills/kWh burned input
5.86 13.37 0.64
21.58
32.18
8.41
0.29
62.46
100.00
$/ton
S removed
501
Basis
1980 revenue requirements
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 476,810 metric tons/yr (525,700 tons/yr), 2,318 kcal/kWh (9,200 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 12,721 metric tons/yr (14,025 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $13,506,000; total depreciable investment, $25,283,000; and total
capital investment, $26,302,000.
All tons shown are 2,000 Ib.
A-30
-------
TABLE A-21. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(700-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
Z of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (six TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (six indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
2
2
7
13
1
2
29
1
31
7
38
1
5
1
8
9
56
4
6
68
1
1
70
,313,
,590,
,029,
,374,
,824,
,580,
,710,
,783,
,493,
,100,
,593,
,538,
342,
,041,
,542,
,463,
,411,
,467,
,937,
,776,
,180,
,408,
,379,
,967,
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
6
6
18
34
4
6
77
4
81
18
100
4
0
13
4
21
24
146
12
17
176
3
3
183
.0
.7
.2
.7
.7
.7
.0
.6
.6
.4
.0
.0
.9
.0
.0
.9
.4
.3
.8
.6
.7
.6
.6
.9
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-31
-------
TABLE A-22. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(700-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
233,600 tons
7.00/ton
29,440 man-hr 12.50/man-hr
1,635,200
1,635,200
368,000
580,800 MBtu
309,100 kgal
66,175,600 kWh
3,920 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
1,161,600
37,100
1,919,100
2,732,400
66,600
6,284,800
7,920,000
8.29
8.29
1.86
5.89
0.19
9.72
13.85
0.34
31.85
40.13
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Mills /kWh
Equivalent unit revenue requirements 4.70
4,090,800
6,103,200
1,583,500
36,800
11,814,300
19,734,300
$/ton coal $/MBtu heat
burned input
11.09 0.53
20.73
30.93
8.02
0.19
59.87
100.00
$/ton
S removed
415
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,614,460 metric tons/yr (1,780,000 tons/yr), 2,243 kcal/kWh (8,900 Btu/kWh).
Stack gas reheat to 79°C (175 F).
Sulfur removed, 43,064 metric tons/yr (47,480 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $38,593,000; total depreciable investment, $68,180,000; and total
capital investment, $70,967,000.
All tons shown are 2,000 Ib.
A-32
-------
TABLE A-23. LIMESTONE SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(1000-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (eight TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (eight indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal ,
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , $
2,951,000
3,270,000
9,672,000
18,443,000
2,519,000
3,090,000
39,945,000
2,397,000
42,342,000
9,357,000
51,699,000
1,814,000
403,000
6,431,000
1,925,000
10,573,000
12,454,000
74,726,000
6,537,000
8,967,000
90,230,000
1,844,000
1,867,000
93,941,000
% of
total direct
investment
5.7
6.3
18.7
35.7
4.9
6.0
77.3
4.6
81.9
18.1
100.0
3.5
0.8
12.4
3.7
20.4
24.1
144.5
12.6
17.4
174.5
3.6
3.6
181.7
Basis
Evaluation represents project beginning mio-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79 C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
A-33
-------
TABLE A-24. LIMESTONE SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(1000-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
326,200 tons 7.00/ton
36,470 man-hr 12.50/man-hr
811,100 MBtu 2.00/MBtu
431,700 kgal 0.12/kgal
92,175,200 kWh 0.028/kWh
'
4,790 man-hr 17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
2,283,400
2,283,400
455,900
1,622,200
51,800
2,580,900
3,668,100
81,400
8,460,300
10,743,700
8.65
8.65
1.73
6.15
0.20
9.78
13.90
0.31
32.07
40.72
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total annual revenue requirements
Equivalent unit revenue requirements
5,413,800
8,078,900
2,102,700
45,600
15,641,000
26,384,700
$/ton coal $/MBtu heat
Mills/kWh burned input
4.40 10.61 0.51
20.52
30.62
7.97
0.17
59.28
100.00
$/ton
S removed
397
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 2,254,530 metric tons/yr (2,485,700 tons/yr), 2,192 kcal/kWh (8,700 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 60,134 metric tons/yr (66,300 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $51,699,000; total depreciable investment, $90,230,000; and total
capital investment, $93,941,000.
All tons shown are 2,000 Ib.
A-34
-------
APPENDIX B
LIME SLUDGE PROCESS
PROCESS DESCRIPTION
Lime slurry scrubbing differs from limestone scrubbing in this study
only in the raw material used as S02 absorbent and in the method of preparing
the scrubbing slurry. The process is shown in Figure B-l.
Pebble lime is slaked in two parallel slakers at a slurry concentration
of 60% solids and combined with scrubber effluent slurry and recycle pond
water to control the concentration of the recirculating slurry at approxi-
mately 15% solids. The flue gas is cooled in a presaturation chamber and
passed through a mobile-bed absorber. The lime slurry circulates through the
absorber where it reacts with the S02 in the cooled flue gas. Mist elimina-
tors equipped for upstream and downstream wash with fresh makeup water
control entrainment carryover in the gas stream. A bleedstream from the
recirculation tank is pumped to an earthen-diked, clay-lined pond one mile
away where it settles to form a sludge containing approximately 40% solids.
The sludge is assumed to be 80% CaS03'l/2H20 and 20% gypsum. Pond supernate
is recycled to the slakers and the absorber recirculation tank to maintain
closed-loop operation. Scrubber outlet gas is reheated to 79°C (175°F) by
indirect steam heat before entering the stack.
The base-case material balance is shown in Table B-l and the base-case
equipment list is shown in Table B-2.
SPECIFIC PROCESS PREMISES
1. The flue gas is assumed to be cooled from 149°C to 53°C (300°F to
127°F) in the presaturator at an L/G ratio of 0.5 liter/m3
(4 gal/103 aft3).
2. The absorber is a mobile-bed type with a flue gas superficial
velocity of 3.8 m/sec (12.5 ft/sec) and a pressure drop of 2.14
kPa (8.6 in. H20), including the mist eliminator. An L/G ratio
of 7.4 liters/m3 (55 gal/10-* aft3) is used.
3. Stoichiometry is 1.05 moles of CaO to 1.0 mole of S02 removed and
1.0 mole of CaO to 2.0 moles of HC1 removed.
B-l
-------
ENERGY REQUIREMENTS
For base-case conditions, reheat of the cleaned gas from 53°C to 79°C
requires 42.1 x 103 kg/hr (92,740 Ib/hr) of 243°C (470°F) steam at 3.55 x
1(H kPa absolute pressure (500 psig), equivalent to about 17.56 x
106 kcal/hr.
The electrical power demand for the base-case lime-sludge process is
about 7448 kW or 1.5% of the rated output of a 500-MW power plant. For
6000 hours of operation, the annual electrical energy consumption is
44.7 x 106 kWh.
The total equivalent energy consumption for the base case is approxi-
mately 36.41 x 10^ kcal/hr or 3.2% of the input energy required for the
500-MW power unit. Summarized energy requirements for all cases are listed
in Table B-3.
BYPRODUCT MANAGEMENT
Electrostatic precipitators remove 99.2% of the fly ash from the flue
gas and, therefore, only a small amount of fly ash is found in the FGD
process sludge. (Fly ash emission from oil-fired units does not exceed the
EPA particulate emission standard and fly ash collection facilities are not
included in oil-fired power plant design.) Projected mass flow rates of
byproduct wastes for the base case are shown below.
Component Kg/hr Lb/hr
CaS03.l/2H20
CaS04-2H20
Ca(OH)2
CaCl2
Mg
Fly ash
Inerts
16,550
5,670
451
433
123
149
102
36,480
12,500
995
955
271
329
225
23,478 51,755
Based on a 30-year life for both the power unit and the FGD unit, the
sludge disposal pond for the base case requires approximately 104 hectares
(256 acres). It is designed for an optimum depth of approximately 5.8 meters
(19 ft). Pond size is listed by case in Table B-4.
ECONOMIC EVALUATION
Capital investment and annual revenue requirements for the base case
and five fuel variations are summarized in Tables B-5 and B-6. The detailed
results are shown in Tables B-7 through B-18. The results, including accuracy
ranges, are shown graphically in Figures B-2 and B-3. The effect of fuel
sulfur content on costs is shown in Figure B-4.
B-2
-------
§
VJ
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B-3
-------
TABLE B-l. LIME SLUDGE PROCESS
MATERIAL BALANCE - BASE CASE (3.5% SULFUR COAL)
1
I
)
',
3
h
7
H
9
JO
Stream No.
escription
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, Nn,3/hr (Cl°r.)
Gas flow. sftVmin (60°F
Liguid flow, liters/min
Liquid flow, Ral/tnin
Temperature! °C
Particulates. kg/hr
Particulates, Ib/hr
1
C
194
428,600
2
2.062
4,546,200
1,615,700
1.005.000
27
3
Gas to
2.225
4,906.000
1^697,100
1.056.000
149
199.1
439
4
2.307
5.088.000
1.805.000
1.122.700
38.4
10
53
49.8
110
5
2.308
5,088,000
1.807.800
1.124.500
79
49.8
110
Stream No.
Description
1
2
!
4
5
fi
7
8
9
10
Total stream, 1000 kg/hr
Total stream, Ib/hr
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Pressure, kPa (abs)
Pressure, psig
Specific gravity
Undissoived solids, %
6
Steam to
reheater
42.1
92,740
243
3,550 x 103
500
7
Makeup water
to absorber
130
285,800
2,162
571
8
Lime to
preparation
facilities
10.2
22,500
Q
Settled sludge
57.3
126,300
730
193
1.31
40
B-4
-------
TABLE B-2. LIME SLUDGE PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area size-cost
Area 1 — Materials Handling exponent 0.74
Total
material
cost ,
Item No. Description 1979 $
Total
labor
cost ,
1979 $
1. Conveyor, lime
storage
(enclosed)
2. Elevator, lime
storage
3. Silo, lime
storage
4. Feeder, reclaim
5. Conveyor, live
lime feed
(enclosed)
6. Elevator, live
lime feed
7. Bin, lime feed 2
Dust collecting 1
system
Belt, 24 in. wide x 1,500 ft
long, 30 hp, 100 tons/hr,
150 ft/min
Continuous, bucket 16 in. x
8 in. x 11-3/4 in., 75 hp,
120 ft lift, 100 tons/hr,
160 ft/min
50 ft dia x 74 ft straight
side, 145,300 ft3, 60° slope
3/8 in. carbon steel
Vibrating pan, 3-1/2 hp,
40 tons/hr
Belt, 18 in. wide x 100 ft
long, 2 hp, 40 tons/hr,
100 ft/min
Continuous, bucket 11 in.
x 6 in. x 8-3/4 in., 50 hp,
50 ft lift, 40 tons/hr, 160
ft/min, with diverter gate
10 ft dia x 15 ft high,
w/cover, carbon steel
Bag filter, polypropylene
bag, 8,800 aft3/min, 7-1/2 hp,
automatic shaker system
(1/2 cost in feed preparation
area)
155,800
102,900
12,200
23,400
56,000
5,400
10,700
52,300
2,400
88,400 246,100
2,100
4,800
1,100
11,300
28,200
Subtotal
454,800 348,300
B-5
-------
TABLE B-2 (continued)
Area 2—Feed Preparation
Area size-cost
exponent 0.57
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Feeder, lime
bin discharge
2. Feeder, slaker
weigh
3. Slaker
4. Tank slaker
product
Lining
5. Agitator, slaker
product tank
6. Pump, slaker
product tank
7. Tank, slurry
feed
Lining
8. Agitator, slurry
feed tank
9. Pump, slurry
feed tank
2 Vibrating, 3-1/2 hp 9,200 3,700
Screw, 12 in. dia x 12 ft 12,000 1,400
long, 1 hp, 6 tons/hr
7 ft wide x 31 ft long, 10 hp
slaker, 2 hp classifier,
6 tons/hr
116,300 12,100
3-1/2 ft dia x 4 ft high, 288 600 1,100
gal, open top, four 3-1/2 in.
baffles, agitator supports,
carbon steel,
(10 min residence time)
1/4 in. neoprene lining 700 800
Two turbines, 14 in. dia, 7,600 2,200
1-1/2 hp, neoprene coated
Centrifugal, 25 gpm, 60 ft 5,100 1,800
head, 2 hp, carbon steel,
neoprene lined
(2 operating, 1 spare)
16 ft dia x 17-1/2 ft high,
26,300 gal, open top, four
16 in. baffles, agitator
supports, carbon steel,
(8 hr residence time)
1/4 in. neoprene lining
Two turbines, 64 in. dia,
20 hp, neoprene coated
5,700 10,800
6,300 7,700
26,100 1,600
Centrifugal, 50 gpm, 60 ft 3,500 1,200
head, 3 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
(continued)
B-6
-------
TABLE B-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
10. Dust collecting 1
system
Bag filter, polypropylene
bag, 8,800 aft3/min, 7-1/2 hp,
automatic shaker system
(1/2 cost in materials handling
area)
10,700
28,200
Subtotal
203,800
72,600
Area 3 — Gas Handling
Item No.
1 . Fans 4
Area size-cost
exponent 0.68
Total
material
cost,
Description 1979 $
Forced draft, 14.8 in. static 1,427,900
Total
labor
cost,
1979 $
93,100
head, 875 rpm, 1,200 hp, fluid
drive, double width, double
inlet
Subtotal
1,427.900 93,100
Area size-cost
exponent 0.74
Item No. Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
1. SOo absorber 4
2. Tank, recircul-
ation
Lining
TCA scrubber, 31 ft long x 14
ft wide x 40 ft high, 1/4 in.
carbon steel, neoprene lining,
316 SS grids, nitrile foam
spheres, FRP spray headers,
316 SS chevron vane entrain-
ment separator
33 ft dia x 32-1/2 ft high,
207,950 gal, open top, four
33 in. baffles, agitator
supports, carbon steel,
(10 min residence time)
1/4 in. neoprene lining
(continued)
2,813,700 252,300
92,800 177,000
97,800 119,600
B-7
-------
TABLE B-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
Agitator,
recirculation
tank
Pump, pre-
saturator
5. Pump, slurry
recirculation
6. Pump, makeup
water
10
132 in. dia, 60 hp, neoprene
coated
Centrifugal, 1,190 gpm, 60 ft
head, 50 hp, carbon steel,
neoprene lined
(4 operating, 2 spares)
Centrifugal, 8,710 gpm, 100 ft
head, 500 hp, carbon steel,
neoprene lined
(8 operating, 2 spares)
Centrifugal, 2,280 gpm, 200 ft
head, 250 hp, carbon steel,
(1 operating, 1 spare)
220,000 81,800
48,900 11,200
442,800 39,100
49,900
8,800
7.
Soot blowers
Subtotal
40
Air,
retractable
4
260
,025
,000
,900
225
915
,800
,600
Area 5—Reheat
Area size-cost
exponent 0.75
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Reheater
2. Soot blowers
Subtotal
20
Steam, tube type, 3,600 ft2
one-half tubes made of
Inconel 625 and one-half made
of Cor-Ten
Air, retractable
856,000 39,200
130,000 112,900
986,000 152,100
B-8
-------
TABLE B-2 (continued)
Area 6—Solids Disposal
Area size-cost
exponent 0.54
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Tank, pond feed 1
Lining
2. Agitator, pond 1
feed tank
3. Pump, pond feed 2
4. Pump, pond
return
*16-l/2 ft dia x 32-1/2 ft 10,600 20,200
high, 51,980 gal, open top,
four 16-1/2 in. baffles, agi-
tator supports, carbon steel
1/4 in. neoprene lining
Two turbines, 66 in. dia,
25 hp, neoprene coated
11,200 13,700
17,800 1,500
Centrifugal, 610 gpm, 150 ft 14,400 3,000
head, 60 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Centrifugal, 420 gpm, 150 ft 10,500 3,000
head, 40 hp, carbon steel
(1 operating, 1 spare)
Subtotal
64,500
41,400
cSize of pond feed tank not a function of residence time.
B-9
-------
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B-10
-------
TABLE B-4. LIME SLUDGE PROCESS POND- SIZE
Case
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
Area
hectares (acres)
104
33
45
64
26
55
(256)
(82)
(110)
(158)
(64)
(135)
Depth
meters (ft)
5.8
4.6
4.9
5.2
4.3
5.2
(19)
(15)
(16)
(17)
(14)
(17)
TABLE B-5. LIME SLUDGE PROCESS CAPITAL INVESTMENT
Total capital investment
Case
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
$
47,743,000
37,795,000
38,912,000
41,952,000
37,165,000
37,286,000
$/kW
96
76
78
84
74
75
B-ll
-------
TABLE B-6. LIME SLUDGE PROCESS ANNUAL REVENUE REQUIREMENTS
Case
Mills/kWh
$/ton coal
(bbl oil)
burned
$/MBtu
heat
input
$/ton
S removed
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
14,972,100
11,064,200
11,498,200
12,644,700
10,836,300
11,387,700
4.99
3.69
3.83
4.21
3.61
3.80
11.64
7.79
10.73
10.30
6.34
(2.55)
0.55
0.41
0.43
0.47
0.40
0.42
438
1,386
970
672
1,865
710
B-12
-------
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B-13
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B-14
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TABLE B-7. LIME SLUDGE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MVI new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
7, of
total direct
Investment, ? investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
503 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1
4
9
1
1
19
1
20
it
25
1
3
1
5
6
37
3
4
45
1
47
,324
859
,950
,280
,292
,975
,680
,181
,861
,617
,478
,041
229
,574
,125
,969
,289
,736
,312
,528
,576
917
,250
,743
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
5.
3.
19.
36.
5.
7.
77.
4.
SI.
18.
100.
4.
0.
14.
4.
23.
24.
148.
13.
17.
1718.
3.
4.
187.
2
4
4
4
1
8
3
6
9
1
0
1
9
0
4
4
7
1
0
8
9
6
9
4
a. Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stacl* gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
B-16
-------
TABLE B-8. LIME SLUDGE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; pond disposal of waste solids)
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost. $ requirements
Direct Costs
Raw materials
Lime
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
67,500 tons
40.00/ton
24,060 man-hr 12.50/man-hr
2.700.000
2,700,000
300,800
418,200 MBtu
205,600 kgal
44,688,600 kWh
3,220 man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
836,400
24,700
1,296,000
1,807,400
54,700
4,320,000
7,020,000
18.03
18.03
2.01
5.59
0.16
8.66
12.07
0.37
28.86
46.89
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 4.99
2,734,600
4,105,900
1,081,500
30,100
7,952,100
14,972,100
$/ton $/MBtu heat
coal burned input
11.64 0.55
18.26
27.43
7.22
0.20
53.11
100.00
$/ton
S removed
438
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,221 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 30,947 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment. $25,478,000; total depreciable investment, $45,576,000; and total
capital investment, $47,743,000.
All tons shown are 2,000 Ib.
B-17
-------
TABLE B-9. LIME SLUDfiE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MU new coal-fired power unit, 0.8% S in coal;
907, S02 removal; pond disposal of waste solids)
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Oas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
452,000
376,000
5,034,000
9,447,000
1,315,000
901,000
17,525,000
1,052,000
18,577,000
1,500,000
20,077,000
929,000
217,000
3,008,000
938,000
5,092,000
5,034,000
30,203,000
2,870,000
3,624,000
36,697,000
306,000
792,000
37,795,000
% of
total direct
investment
2.3
1.9
25.1
47.0
6.5
4.5
87.3
5.2
92.5
7.5
100.0
4.6
1.1
15.0
4.7
25.4
25.1
150.5
14.3
18.0
182.8
1.5
3.9
188.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Miniminum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
B-18
-------
TABLE B-10. LIME SLUDGE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS
(500-MW new coal-fired power unit, 0.8% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Lime
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ _ cost, $ _ requirements
15,800 tons
40.00/ton
24,060 man-hr 12.50/man-hr
632,000
632,000
300,800
428
165
44,498
1
,500
,900
,900
,350
MBtu
kgal
kWh
man-hr
2.
0.
0.
17.
00/MBtu
12/kgal
029/kWh
00/man-hr
1
1
4
4
857
19
,290
,531
23
,022
,654
,000
,900
,500
,200
,000
,400
,400
5.71
5.71
2.72
7.75
0.18
11.66
13.84
0.21
36.36
42.07
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mllls/kWh
Equivalent unit revenue requirements 3.69
2,201,800
3,250,400
927,500
30,100
6,409,800
11,064,200
$/ton $/MBtu heat
coal burned input
7.79 0.41
19.90
29.38
8.38
0.27
57.93
100.00
$/ton
S removed
1386
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6000 hr/yr.
Coal burned, 1,288,938 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 7,238 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $20,077,000; total depreciable investment, $36,697,000; and total
capital investment, $37,795,000.
All tons shown are 2,000 Ib.
B-19
-------
TABLE B-ll. LIME SLUDGE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 1.4% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainroent separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect' investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
605,000
470,000
4,915,000
9,215,000
1,283,000
1,116,000
17,604,000
1,056,000
18,660,000
2,005,000
20,665,000
950,000
219,000
3,068,000
959,000
5,196,000
5,172,000
31,033,000
2,903,000
3,724,000
37,660,000
405,000
847,000
38,912,000
% of
total direct
investment
2.9
2.3
23.8
44.6
6.2
5.4
85.2
5.1
90.3
9.7
100.0
4.6
l.l
14.9
4.6
25.2
25.0
150.2
14.0
18.0
182.2
2.0
4.1
188.3
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
B-20
-------
TABLE B-12. LIME SLUDGE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS
(500-MW new coal-fired power unit, 1.4% S in coal;
90% 303 removal; pond disposal of waste solids)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of average
annual revenue
requirements
Direct Costs
Raw materials
Lime
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
23,400 tons
40.00/ton
24,060 man-hr 12.50/man-hr
936,000
936,000
300,800
414,100 MBtu
167,200 kgal
43,220,400 kWh
1,710 man-hr
2. 00 /MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
828,200
20,100
1,253,400
1,553,000
29,100
3,984,600
4,920,600
_ 8.14
8.14
2.62
7.20
0.17
10.90
13.51
0.25
34.65
42.79
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
inves tment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.83
2,259,600
3,346,400
941,500
30,100
6,577,600
11,498,200
$/ton $/MBtu heat
coal burned input
10.73 0.43
19.65
29.11
8.19
0.26
57.21
100.00
$/ton
S removed
970
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,941 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 10,748 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct Investment, $20,665,000; total depreciable investment, $37,660,000; and total
capital investment, $38,912,000.
All tons shown are 2,000 Ib.
B-21
-------
TABLE B-13. LIME SLUDGE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 2.0% S in coal;
90% S02 removal; pond disposal of waste solids)
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S(>2 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
851,000
612,000
4,930,000
9,243,000
1,287,000
1,432,000
18,355,000
1.101,000
19,456,000
2,867,000
22,323,000
983,000
223,000
3,248,000
1.017,000
5,471,000
5,559,000
33,353,000
3,049,000
4,002,000
40,404,000
572,000
976,000
41,952,000
% of
total direct
investment
3.8
2.7
22.1
41.4
5.8
6.4
82.2
5.0
87.2
12.8
100.0
4.4
1.0
14.5
4.6
24.5
24.9
149.4
13.7
17.9
181. 0
2.6
4.3
187.9
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
B-22
-------
TABLE B-14. LIME SLUDGE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 2.0% S in coal;
90% SC>2 removal; pond disposal of waste SQlids)
Direct Costs
Raw materials
Lime
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
37,200 tons
24,060 man-hr
416,000 MBtu
179,400 kgal
43,743,700 kWh
2,250 man-hr
Unit
cost, $
40. 00 /ton
12.50/man-hr
2. 00 /MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
Total % of average
annual annual revenue
cost, $ requirements
1,488,000
1,488,000
300,800
832,000
21,500
1,268,600
1,642,500
38,300
4,103,700
5,591,700
11.77
11.77
2.38
6.58
0.17
10.03
12.99
0.30
32.45
44.22
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
2,424,200
3,607,900
990,800
30.100
7,053,000
12,644,700
19.17
28.53
7.84
0.24
55.78
100.00
Mills/kWh
$/ton
coal burned
$/MBtu heat
input
Equivalent unit revenue requirements
4.21
10.30
0.47
$/ton
S removed
672
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,113,161 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 17,043 metric tons/yr (18,790 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,323,000; total depreciable investment, $40,404,000; and total
capital investment, $41,952,000.
All tons shown are 2,000 Ib.
B-23
-------
TABLE B-15. LIME SLUDGE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% S02 removal; pond disposal of waste solids)
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
358,000
314,000
5,118,000
9,633,000
1,341,000
758,000
17,522,000
1,051,000
18,573,000
1,175,000
19,748,000
914,000
216,000
2,974,000
927,000
5,031,000
4,956,000
29,735,000
2,856,000
3,568,000
36,159,000
243,000
763,000
37,165,000
% of
total direct
investment
1.8
1.6
25.9
48.8
6.8
3.8
88.7
5.4
94.1
5.9
100.0
4.6
1.1
15.1
4.7
25.5
25.1
150.6
14.5
18.0
183.1
1.2
3.9
188.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
B-24
-------
TABLE B-16. LIME SLUDGE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% S02 removal; pond disposal of waste solids)
Annual
quantity
Total % of average
Unit annual annual revenue
cost, $ cost, $ requirements
Direct Costs
Raw materials
Lime
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
11,500 tons
40.00/ton
24,060 man-hr 12,50/man-hr
460,000
460,000
300,800
439,600 MBtu
166,300 kgal
45,522,200 kWh
1 ,110 man-hr
2.00/MBtu
0.1 2 /kgal
0.029/kWh
17. 00 /man-hr
879,200
20,000
1,320,100
1,521,100
18,900
4,060,100
4,520,100
4.24
4.24
2.78
8,11
0.18
12.18
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total 'depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills /kWh
Equivalent unit revenue requirements 3.61
2,169,500
3,196,200
920,400
30,100
6,316,200
10,836,300
$/ton lignite $/MBtu heat
burned input
6.34 0.40
20.02
29.50
8.49
0.28
58.29
100.00
$/ton
S removed
1865
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 7,000 hr/yr.
Lignite burned, 1,549,882 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 5,270 metric tons/yr (5,810 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $19,748,000; total depreciable investment, $36,159,000; and total
capital investment, $37,165,000.
All tons shown are 2,000 Ib.
B-25
-------
TABLE B-17. LIME SLUDGE PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new oil-fired power unit, 2.5% S in oil;
90% S02 removal; pond disposal of waste solids)
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four TCA scrubbers including presaturators and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four direct oil-fired reheaters)
Solids disposal (onsite disposal facilities including feed tank,
agitator, slurry disposal pumps, and pond water return pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
756,000
558,000
4,371,000
8,101,000
1,127,000
1,313,000
16,226,000
974,000
17,200,000
2,458,000
19,658,000
968,000
221,000
2,925,000
923,000
5,037,000
4,939,000
29,634,000
2,718,000
3,556,000
35,908,000
493,000
885,000
37,286,000
% of
total direct
investment
3.8
2.8
22.2
41.3
5.7
6.7
82.5
5.0
87.5
12.5
100.0
4.9
1.1
14.9
4.7
25.6
25.1
150.7
13.8
18.2
182.7
2.5
4.5
189.7
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by direct oil fired reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
B-26
-------
TABLE B-18. LIME SLUDGE PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new oil-fired power unit, 2.5% S in oil;
90% S02 removal; pond disposal of waste solids)
Direct Costs
Raw materials
Lime
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total 7, of average
Unit annual annual revenue
cost, $ cost, $ requirements
31,700 tons
40.00/ton
24,060 man-hr 12.50/man-hr
1,268,000
1,268,000
300,800
2
36
,418
150
,723
2
,100
,600
,100
,050
gal
kgal
kWh
man-hr
0.
0.
0.
17.
40/gal
12/kgal
029/kWh
00/man-hr
1
1
3
5
967
18
,065
,449
34
,835
,103
,300
,100
,000
,700
,900
,800
,800
11.14
11.14
2.64
8.49
0.16
9.35
12.73
0.31
33.68
44.82
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
$/bbl oil
Mills/kWh burned
Equivalent unit revenue requirements 3.80 2.55
2,154,500
3,206,600
892,700
30,100
6,283,900
11,387,700
$/MBtu heat
input
0.42
18.92
28.16
7.84
0.26
55.18
100.00
$/ton
S removed
710
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Oil burned, 710 x 106 liters/yr (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $19,658,000; total depreciable investment, $35,908,000; and total
capital investment, $37,286,000.
All tons shown are 2,000 Ib.
B-27
-------
APPENDIX C
DOUBLE-ALKALI SLUDGE PROCESS
PROCESS DESCRIPTION
The double-alkali process evaluated in this study has been generalized
from several concentrated-mode double-alkali processes in the United States.
A two-tray tower absorber with presaturator and mist eliminator is used.
The scrubbing liquor is a solution of sodium salts of which sodium sulfite
(Na2S03> is the major active component. The S02 reacts with the Na2S03
to form sodium bisulfite (NaHS03> . A bleedstream of absorber liquor is
treated with slaked lime to precipitate calcium sulfur salts and regenerate
the
Pebble lime is slaked and then reacted with a bleedstream of absorber
effluent in agitated tanks. The reaction product, predominately calcium
sulfite, flows to a thickener where the slurry is concentrated to 40% solids.
This stream is further dewatered using drum filters to produce a cake con-
taining 55% solids. The filter is designed with two wash sections to minimize
sodium loss. The filter cake is conveyed to a reslurry tank where it is
mixed with pond return water to a 15% solids slurry. The slurry is pumped
to an earthen-diked clay-lined pond one mile away where the solids in the
slurry settle to form a sludge containing approximately 40% solids. Makeup
soda ash is added to the regenerated scrubber liquor at the thickener over-
flow storage tank.
The flow diagram for double-alkali sludge is shown in Figure C-l. The
base-case material balance and equipment list are shown in Tables C-l and C-2.
SPECIFIC PROCESS PREMISES
1. The flue gas is cooled from 149°C (300°F) to 53°C (127°F) and saturated
in the presaturator. The presaturator has an L/G ratio of 0.5 liter/m3
(4 gal/103 aft3).
2. A two-tray tower absorber with a superficial velocity of 2.1 m/sec
(7 ft/sec), and a pressure drop, including the mist eliminator, of
1.25 kPa (5 inches H20) is used. An L/G ratio of 0.5 liter/m3
(4 gal/103 aft3) is used for recycle liquor to the absorber and an
L/G ratio of 0.4 liter/m3 (3 gal/aft3) is used for the regenerated
scrubbing liquor to the absorber.
C-l
-------
3. Stoichiometry is 1.0 mole of CaO to 1.0 mole of 862 removed and 1 mole
of CaO to 2 moles of HC1 removed.
4. Oxidation of 10% of the S02 removed to sulfate is assumed. The
remainder is assumed to be in sulfite form.
ENERGY REQUIREMENTS
For base-case conditions, reheat of the cleaned gas from 53°C to 79°C o
requires 42.2 x 103 kg/hr (93,060 Ib/hr) of 243°C (470°F) steam at 3.55 x 10
kPa absolute pressure (500 psig), equivalent to about 17.62 x 10^ kcal/hr.
The electrical power demand for the base case is estimated to be about
3,981 kW or 0.8% of the rated output of a 500-MW power plant. For 6,000
hours of operation, the annual electrical energy consumption is 23.9 x 10^ kWh.
The total equivalent energy consumption for the base case is approxi-
mately 28.61 x 106 kcal/hr or 2.5% of the input energy required for the 500-
MW power unit. Summarized energy requirements for all cases are listed in
Table C-3.
BYPRODUCT MANAGEMENT
ESP units remove 99.2% of the fly ash from the flue gas and, therefore,
only a small amount of fly ash is found in the FGD process sludge. (Fly ash
emission from oil-fired units does not exceed the EPA particulate emission
standard and fly ash-collection facilities are not included in oil-fired
power plant design.) Projected mass flow rates of byproduct wastes for the
base case are shown below.
Component
CaS03-l/2H20
CaS04«2H 0
Ca(OH)2
Na2S03
Na2S04
NaCl
Mg
Fly ash
Inert s
Kg/hr
18,266
2,158
209
319
148
456
117
149
98
21,920
Lb/hr
40,270
4,758
461
703
326
1,006
258
329
215
48,326
Based on a 30-yr life for both the power unit and the FGD unit, the
sludge disposal pond for the base case requires approximately 99 hectares
(245 acres). It is designed for an optimum depth of approximately 5.8 meters
(19 feet). Pond size is listed by case in Table C-4.
C-2
-------
ECONOMIC EVALUATION
Capital investment and annual revenue requirement summaries for the
base case and five fuel variations are shown in Tables C-5 and C-6. Detailed
economic results are shown in Tables C-7 through C-18. The results showing
the estimated range of accuracy are shown in Figures C-2 and C-3. The effects
of different fuel sulfur contents are shown in Figures C-4 and C-5.
C-3
-------
S
OS
&
cd
•H
CO
CO
CD
u
o
p.
ca
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C-4
-------
TABLE C-l. DOUBLE-ALKALI SLUDGE PROCESS
MATERIAL BALANCE - BASE CASE (3.5% SULFUR COAL)
Stream No.
Description
1
!.
i
4
rj
h
7
8
1
10
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, Nm^/hr (0°C)
Gas flow, sft3/min (60°F)
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Particulates, kg/hr
Particulates, Ib/hr
1
Coal to boiler
194
428,600
2
Combustion air
to air heater
2.062
4,546,200
1,615,700
1,005,000
27
3
Gas to
presaturator-
absorber
2.225
4,906,000
1,697,700
1,056,000
149
199.1
439
4
Gas to reheater
2,317
5.107.500
1,812,400
1,127,300
38.6
10.2
53
49.8
110
5
Gas to stack
2.317
5.107.500
1,815,300
1.129.100
79
49.8
110
Stream No.
Description
1
2
i
i.
5
6
7
8
9
If)
Total stream. 1000 ke/hr
Total stream, Ib/hr
Liquid flow, liters/min
Liquid flow, gal/min
Temperature. °C
Temperature, °F
Pressure, Pascals (abs)
Pressure, psig
Specific aravitv
Undissolved solids. %
6
Steam to
reheater
42
93,060
243
470
3.55 x 106
500
7
Process makeup
water
129
283.200
2.143
566
8
Lime to
preparation
facilities
10
21.470
9
Makeup soda ash
1
1,755
10
Filtered sludge
39
85,570
1.3
55
h
7
8
9
10
7
8
9
10
C-5
-------
TABLE C-2. DOUBLE-ALKALI SLUDGE PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area 1—Materials Handling
Area size-cost
exponent 0.72
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Conveyor, lime
storage
(enclosed)
2. Elevator, lime
storage
3. Silo, lime
storage
4. Feeder, reclaim 1
Conveyor, live
lime feed
(enclosed)
Elevator, live
lime feed
7. Bin, lime feed
8. Conveyor, soda
ash storage
9. Silo, soda ash
storage
Vibrators
Belt, 24 in. wide x 1,500 ft
long, 30 hp, 100 tons/hr,
150 ft/min
Continuous, bucket 16 in. x
8 in. x 11-3/4 in., 75 hp,
120 ft lift, 100 tons/hr,
160 ft/min
50 ft dia x 74 ft straight
side, 145,300 ft3, 60° slope,
3/8 in. carbon steel
Vibrating pan, 3-1/2 hp,
40 tons/hr
Belt, 18 in. wide x 100 ft
long, 2 hp, 40 tons/hr.
100 ft/min
Continuous, bucket 11 in. x
6 in. x 8-3/4 in., 50 hp,
50 ft lift, 40 tons/hr, 160
ft/min, with diverter gate
10 ft dia x 15 ft high,
w/cover, carbon steel
1 Pneumatic, vacuum, 40 hp
16 ft dia x 32 ft straight
side, 5,930 ft3, 60° slope,
carbon steel
155,800 52,300
102,900
2,400
88,400 246,100
12,200
23,400
56,000
5,400
65,000
10,400
2,100
4,800
1,100
11,300
20,000
16,400
5,600
1,200
(continued)
C-6
-------
TABLE C-2 (continued)
Item
No.
Description
10. Dust collect-
ing system
Subtotal
Total
material
cost,
1979 $
Bag filter, polypropylene 12,000
bag, 8,800 aft3/min, 7-1/2 hp,
automatic shaker system
Total
labor
cost,
1979 $
28,200
537,100 385,900
Area 2—Feed Preparation
Area size-cost
exponent 0.55
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Feeder, lime
bin discharge
2. Feeder, slaker
weigh
3. Slaker
4. Tank, slaker
product
Lining
5. Agitator, slaker
product tank
6. Pump, slaker
product tank
7. Tank, slurry
feed
Lining
Vibrating, 3-1/2 hp, carbon
steel
Screw, 12 in. dia x 12 ft
long, 1 hp, 5-1/2 tons/hr
7 ft wide x 28 ft long, 10 hp
slaker, 2 hp classifier, 5-1/2
tons/hr
7 ft dia x 6 ft high, 1,727
gal, open top, four 7 in.
baffles, agitator supports,
carbon steel
(10 min residence time)
1/4 in. neoprene lining
30 in. dia, 5 hp, neoprene
coated
Centrifugal, 140 gpm, 100 ft
head, 7-1/2 hp, carbon steel,
neoprene lined
(2 operating, 1 spare)
31 ft dia x 31 ft high,
171,600 gal, open top, four
31 in. baffles, agitator
supports, carbon steel
(8 hr residence time)
1/4 in. neoprene lining
(continued)
C-7
9,200
12,000
1,800
2,000
17,500
11,100
3,700
1,400
116,300 12,100
3,200
2,400
1,700
2,300
21,400 39,000
21,900 26,700
-------
TABLE C-2 (continued)
8.
9.
10.
11.
Item No .
Agitator, slurry 1
feed tank
Pump , slurry 2
feed tank
Feeder, soda 1
ash silo discharge
Feeder, soda 1
Description
1 turbine, 124 in. dia, 25
hp, neoprene coated
Centrifugal, 325 gpm, 100
ft head, 20 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Rotary air lock, 2 hp
Weigh belt, 18 in. x 20 ft
Total
material
cost,
1979 $
29,300
8,600
5,000
5,400
Total
labor
cost,
1979 $
1,700
3,000
500
2,000
12.
ash solution
tank
Tank, soda ash
solution
long, 1-1/2 hp, 1 ton/hr
12-1/2 ft dia x 12-1/2 ft
high, 11,100 gal, open top,
four 12.5 in. baffles,
agitator supports, carbon
steel (8 hr residence)
3,700
6,200
13.
14.
15.
Lining
Agitator, soda 1
ash solution tank
Pump, soda ash 2
solution tank
Dust collecting 1
system
Subtotal
1/4 in. neoprene lining
48 in. dia, 5 hp, neoprene
coated
21 gpm, 60 ft head, 1 hp,
carbon steel, neoprene lined
(1 operating, 1 spare)
Bag filter, polypropylene
bag, 8,800 aft3/min, 7-1/2
hp, automatic shaker system
(one-half cost in material
handling)
3,600
9,000
3,500
12,000
293,300
4,300
900
1,200
28,200
140,500
(continued)
C-8
-------
TABLE C-2 (continued)
Area size-cost
Area 3 — Gas Handling
Item No.
1 . Fans 4
Subtotal
exponent
Total
material
cost,
Description 1979 $
Forced draft, 8 in. static 772,000
head, 700 rpm, 800 hp, fluid
drive
772,000
0.68
Total
labor
cost,
1979 $
68,000
68,000
Area size-cost
Area 4 — S00 Absorption
Item No .
1. S09 absorber 4
exponent
Total
material
cost,
Description 1979 $
Tray tower, 31 ft dia x 40 3,316,800
0.79
Total
labor
cost,
1979 $
490,000
2. Tank, recircu-
lation
Lining
3. Agitator, recir-
culation tank
4. Pump, presatu-
rator
5. Pump, liquor
recirculation
ft high, 3/8 in. carbon
steel, flake lined; 2-316 SS
sieve trays, 316 SS nozzles,
polypropylene entrainment
separator
28 ft dia x 30 ft high,
137,350 gal, open top, four
28 in. baffles, agitator
supports, carbon steel
(10 min residence time)
1/4 in. neoprene lining
108 in. dia, 25 hp, neoprene
coated
Centrifugal, 1,274 gpm, 60 ft
head, 50 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
Centrifugal, 1,910 gpm, 100 ft
head, 100 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
(continued)
C-9
76,000 135,200
75,600 92,400
117,300 6,800
48,900 11,200
64,000 11,900
-------
TABLE C-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
6. Pump, bleed to
reaction tank
7. Pump, makeup
water
8. Soot blowers
Subtotal
6 Centrifugal, 870 gpm, 100 ft
head, 50 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
2 Centrifugal, 360 gpm, 150 ft
head, 30 hp, carbon steel
(1 operating, 1 spare)
40 Air, retractable
34,700 11,200
12,700 2,800
260,000
4,006,000
225,800
987,300
Area 5—Reheat
Area size-cost
exponent 0.75
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Reheater
2. Soot blowers
Subtotal
4 Steam, tube type, 3,600 ft ,
one-half tubes made of
Inconel 625 and one-half
made of Cor-Ten
20 Air, retractable
856,000
39,200
130.000 112,900
986,000 152,100
Area 6—Reaction
1. Tank, reaction
Area size-cost
exponent 0.50
Item No. Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
26 ft dia x 15 ft high,
59,570 gal, four 26 in.
baffles, agitator supports,
carbon steel
(30 min residence time total)
(continued)
20,600
36,200
C-10
-------
TABLE C-2 (continued)
1.
2.
3.
•Item No.
(continued)
Lining
Agitator, reaction 2
tank
Pump, reaction 2
1/4 in.
100 in.
coated
Description
neoprene lining
dia, 25 tip, neoprene
Centrifugal, 3,480 gpm, 50
Total
material
cost,
1979 $
18,800
56,600
31,200
Total
labor
cost,
1979 $
22,800
5,800
10,200
tank
Subtotal
ft head, 100 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
127,200
75,000
Area 7 — Solids Separation
Item No. Description
1. Thickener 1 Carbon steel tank, 162 ft
Area size-cost
exponent 0.47
Total
material
cost,
1979 $
134,100
Total
labor
cost,
1979 $
342,900
2.
Lining
Rake motor and
mechanism
Pump, underflow
slurry
3. Tank, thickener
overflow storage
Lining
dia x 8 ft high; concrete
basin, 4 ft high
1/4 in. neoprene lining
7-1/2 hp
Centrifugal, 302 gpm, 100 ft
head, 20 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
33 ft dia x 15 ft high,
96,000 gal, open top, four
33 in. baffles, agitator
supports, carbon steel
1/4 in. neoprene lining
(continued)
C-ll
20,200 24,600
422,000 140,700
9,300
3,000
14,000 23,800
12,800
16,600
-------
TABLE C-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
4. Agitator,
thickener over-
flow storage
tank
5. Pump, scrubbing
liquor return
6. Filter
7. Pump, filter
wash water
8. Conveyor,
132 in. dia, 25 hp, neoprene 28,500 1,700
coated
Centrifugal, 955 gpm, 125 ft
head, 60 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
41,600 11,400
Rotary vacuum, 12 ft dia x 14 251,300 25,500
ft face, 20 total hp
270 gpm, 80 ft head, 15 hp, 5,000 1,300
carbon steel
(1 operating, 1 spare)
Belt, 18 in. wide x 100 ft 23.400 4,800
filter cake long, 3 hp, 45 tons/hr,
100 ft/min
Subtotal
Area 8 — Solids Disposal
Item No. Description
962,200 596,300
Area size-cost
exponent 0.52
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Tank, filter 1
cake reslurry
Lining
2. Agitator,
filter cake
reslurry tank
7 ft dia x 11 ft high, 3,170
gal, open top, four 7 in.
baffles, agitator supports,
carbon steel
(5 min residence time)
1/4 in. neoprene lining
Two turbines, 28 in. dia,
5 hp, neoprene coated
(continued)
C-12
1,500
2,800
1,600 2,000
9,000 900
-------
TABLE C-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
3.
4.
Pump, pond
feed
Pump, pond
return
Subtotal
Centrifugal, 570 gpm, 150 ft
head, 50 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Centrifugal, 392 gpm, 150 ft
head, 40 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
22,600
21,100
6,300
5,900
55,800 17,900
C-13
-------
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C-14
-------
TABLE C-4. POND SIZE, DOUBLE-ALKALI SLUDGE PROCESS
Case
500 -MW unit
Coal, 3.5% sulfur
(base case)
Coal, 0.8% sulfur
Coal, 1.4% sulfur
Coal, 2.0% sulfur
Lignite, 0.5% sulfur
Oil, 2.5% sulfur
Area,
hectares (acres)
99
33
44
62
31
48
(245)
(81)
(108)
(153)
(78)
(119)
Depth
meters (ft)
5.8
4.6
4.9
5.2
4.3
4.9
(19)
(15)
(16)
(17)
(14)
(16)
TABLE C-5. DOUBLE-ALKALI SLUDGE PROCESS CAPITAL INVESTMENT
Total capital investment
Case $ $/kW
500-MW unit
Coal, 3.5% sulfur 53,231,000 107
(base case)
Coal, 0.8% sulfur 40,537,000 81
Coal, 1.4% sulfur 42,179,000 84
Coal, 2.0% sulfur 46,045,000 92
Lignite, 0.5% sulfur 39,595,000 79
Oil, 2.5% sulfur 40,659,000 81
C-15
-------
TABLE C-6. DOUBLE-ALKALI SLUDGE PROCESS ANNUAL REVENUE REQUIREMENTS
$/ton coal $/MBtu $/ton
(bbl oil) heat sulfur
Case $ Mills/kWh burned input removed
500-MW unit
Coal, 3.5% sulfur 16,010,600 5.34 12.45 0.59 469
(base case)
Coal, 0.8% sulfur 11,173,000 3.72 7.86 0.41 1,400
Coal, 1.4% sulfur 11,793,600 3.93 11.01 0.44 995
Coal, 2.0% sulfur 13,080,000 4.36 10.66 0.48 696
Lignite, 0.5% sulfur 10,828,000 3.61 6.34 0.40 1,863
Oil, 2.5% sulfur 11,879,500 3.96 (2.66) 0.44 741
C-16
-------
(U
0)
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2.0
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ED BY FUEL
DENT
8
CASE VARIATIONS
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investmen
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C-17
-------
1 1 1 1
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CASE VARIATIONS IDENTIFIED BY FUEL TYPE AND SULFUR CONTENT OF FUEL, %
igure C-3. Double-alkali sludge process annual revenue requirement range
00 vo -3- «M
C-18
-------
500-MW units
90% S02 removal
100
80
a
«v
H
w
60
P-,
u 40
X Oil-fired unit
20
I
I
J_
10 20 30 40
SULFUR REMOVED, k SHORT TONS/YR
•
Figure C-4. Double-alkali sludge process. Effect of
sulfur removed on capital investment.
C-19
-------
T
500-MW units
90% S02 removal
50
CO
H
40
-------
TABLE C-7. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 3.5% sulfur
in coal; 90% SO, removal; onsite solids disposal)
% of
total direct
Investment, $ Investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silos, and
bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
SC>2 absorption (four tray towers including presaturator and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1,975,000
918,000
4,269,000
9,489,000
1,292,000
385,000
2,554,000
1,395,000
22,277,000
1,337,000
23,614,000
4,679,000
28,293,000
1,423,000
324,000
3,917,000
1,218,000
6,882,000
7,035,000
42,210,000
3,753,000
5,065,000
51,028,000
900,000
1,303,000
53,231,000
7.0
3.2
15.1
33.5
4.6
1.4
9.0
4.9
78.7
4.8
83.5
16.5
100.0
5.0
1.1
13.9
4.3
24.3
24.9
149.2
13.3
17.9
180.4
3.2
4.6
188.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; F£D process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
C-21
-------
TABLE C-8. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 3.5% sulfur in
coal; 90% SO, removal; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
64,400 tons
5,270 tons
31,900 man-hr
419,600 MBtu
203,790 kgal
23,884,000 kWh
3,220 man-hr
Unit
cost , $
40.00/ton
90.00/ton
12.50/man-hr
2.00/MBtu
0.1 2 /kgal
0.029/kWh
17. 00 /man-hr
Total % of average
annual annual revenue
cost, $ requirements
2,576,000
474,300
3,050,300
398,800
839,200
24,500
692,600
2,029,500
54,700
4,039,300
7,089,600
16.09
2.96
19.05
2.49
5.24
0.15
4.33
12.68
0.34
25.23
44.28
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Equivalent unit revenue requirements
3,061,700
4,577,900
1,241,500
39,900
8,921,000
16,010,600
$/ton coal $/MBtu heat
Mills/kWh burned input
5.34 12.45 0.59
19.13
28.59
7.75
0.25
55.72
100.00
$/ton sulfur
removed
469
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,200 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 30,950 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $28,293,000; total depreciable investment, $51,028,000; and total
capital investment, .$53,231,000.
All tons shown are 2,000 Ib.
C-22
-------
TABLE C-9. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MH new coal-fired power unit, 0.8% sulfur in
coal; 90% SO removal: onsite solids disposal)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silos, and
bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four tray towers including presaturator and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
693
413
4,342
9,669
1,315
186
1,290
656
18,564
1,114
19,678
1,615
21,293
1,314
313
3,158
981
5,766
5,412
32,471
3,086
3,897
39,454
326
757
40,537
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
3.3
1.9
20.4
45.4
6.2
0.9
6.0
3.1
87.2
5.2
92.4
7.6
100.0
6.2
1.5
14.8
4.6
27.1
25.4
152.5
14.5
18.3
185.3
1.5
3.6
190.4
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79 C (175 F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
C-23
-------
TABLE C-10. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 0.8% sulfur in
coal; 90% SO- removal; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
15,060 tons
1,230 tons
31,900 man-hr
429,900 MBtu
167,100 kgal
21,374,200 kWh
1,350 man-hr
Unit
cost, $
40.00/ton
90.00/ton
12.50/man-hr
2 . 00/MBtu
0.1 2 /kgal
0.029/kWh
17.00/man-hr
Total
annual
cost, $
602,400
110,700
713,100
398,800
859,800
20,100
619,900
1,622,700
23,000
3,544,300
4,257,400
% of average
annual revenue
requirements
5.39
0.99
6.38
3.57
7.69
0.18
5.55
14.52
0.21
31.72
38.10
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.72
2,367,200
3,486,200
1,022,300
39,900
6,915,600
11,173,000
$/ton coal $/MBtu heat
burned input
7.86 0.41
21.19
31.20
9.15
0.36
61.90
100.00
$/ton sulfur
removed
1,400
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,288,900 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 7,240 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirements for removal and disposal of fly ash excluded.
Total direct investment, $21,293,000; total depreciable investment, $39,454,000; and total
capital investment, $40,537,000.
All tons shown are 2,000 Ib.
C-24
-------
TABLE C-ll. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 1.4% sulfur in
coal; 90% SO removal; onsite solids disposal)
Direct Investment
Materials handling (conveyors, elevators, feeder, silos, and
bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
SC>2 absorption (four tray towers including presaturator and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
922,000
513,000
4,239,000
9,413,000
1,283,000
227,000
1,553,000
805,000
18,955,000
1,137,000
20,092,000
2,091,000
22,183,000
1,334,000
315,000
3,256,000
1,012,000
5,917,000
5,620,000
33,720,000
3,163,000
4,046,000
40,929,000
420,000
830,000
42,179,000
% of
total direct
investment
4.2
2.3
19.1
42.4
5.8
1.0
7.0
3.6
85.4
3.2
90.6
9.4
100.0
I 6.0
1.4
14.7
4.6
26.7
25.3
152.0
H.3
18.2
184.5
1.9
3.7
190.1
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
C-25
-------
TABLE C-12. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 1.4% sulfur in
coal; 90% SO. removal; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
22,360 tons
1,830 tons
31,900 man-hr
415,500 MBtu
167,900 kgal
21,149,300 kWh
1,710 man-hr
Unit
cost, $
40.00/ton
90.00/ton
12. 50 /man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
17.00/man-hr
Total
annual
cost, $
894,400
164,700
1,059,100
398,800
831,000
29,200
613,300
1,670,100
29,100
3,562,500
4,621,600
% of average
annual revenue
requirements
7.58
1.40
8.98
3.38
7.05
0.17
5.20
14.16
0.25
30.21
39.19
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
2,455,700
3,627,400
1,049,000
39.900
7,172,000
11,793,600
20.82
30.76
8.89
0.34
60.81
100.00
Equivalent unit revenue requirements
Mills/kWh
3.93
$/ton coal
burned
11.01
$/MBtu heat
input
0.44
$/ton sulfur
removed
995
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,900 metric tons/yr (1,071,600 tons/yr), 2,268 Ucal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 10,750 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,183,000; total depreciable investment, $40,929,000; and total
capital investment, $42,179,000.
All tons shown are 2,000 Ib.
C-26
-------
TABLE C-13. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 2.0% sulfur in
coal; 90% S02 removal; onsite solids disposal)
.Direct Investment
Materials handling (conveyors, elevators, feeder, silos, and
bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheat er and stack)
S02 absorption (four tray towers including presaturator and
entrainment separators, recirculation tanks, agitators, and
pumps)
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
1,286,000
661,000
4,252,000
9,451,000
1,287,000
286,000
1,928,000
1,023,000
20,174,000
1,210,000
21,384,000
2,950,000
24,334,000
1,366,000
318,000
3,495,000
1,086,000
6,265,000
6,120,000
36,719,000
3,377,000
4,406,000
44,502,000
578,000
965,000
46,045,000
% of
total direct
investment
5.3
2.7
17.5
38.8
5.3
1.2
7.9
4.2
82.9
5.0
87.9
12.1
100.0
5.6
1.3
14.3
4.5
25.7
25.2
150.9
13.9
18.1
182.9
2.4
3.9
189.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
C-27
-------
TABLE C-14. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 2.0% sulfur in
coal; 90% S0_ removal; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
35,470 tons
2,900 tons
31,900 man-hr
417,400 MBtu
179,300 kgal
22,031,800 kWh
2,250 man-hr
Unit
cost, $
40. 00 /ton
90.00/ton
12.50/man-hr
2.00/MBtu
0.1 2 /kgal
0.029/kWh
17.00/man-hr
Total
annual
cost, $
1,418,800
261,000
1.679,800
398,800
834,800
21,500
638,900
1,719,600
38,300
3,651,900
5,331,700
% of average
annual revenue
requirements
10.85
1.99
12.84
3.05
6.38
0.16
4.89
13.15
0.29
27.92
40.76
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 4.36
2,670,100
3,959,900
1,078,400
39,900
7,748,300
13,080,000
$/ton coal $/MBtu heat
burned input
10.66 0.48
20.41
30.27
8.25
0.31
59.24
100.00
$/ton sulfur
removed
696
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,113,200 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 17,040 metric tons/yr (18,790 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $24,334,000; total depreciable investment, $44,502,000; and total
capital investment, $46,045,000.
All tons shown are 2,000 Ib.
C-28
-------
TABLE C-15. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new lignite-fired power unit, 0.5% sulfur
in lignite; 90% SO. removal; onsite solids disposal)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silos, and
bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four tray towers including presaturator and
entrainment separators, recirculation tanks, agitators, and
pumps )
Stack gas reheat (four indirect steam reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
553,000
347,000
4,414,000
9,869,000
1,341,000
159,000
1,111,000
555,000
18,349,000
1,101,000
19,450,000
1,309,000
20,759,000
1,300,000
312,000
3,099,000
962,000
5,673,000
5,286,000
31,718,000
3,041,000
3,806,000
38,565,000
312,000
718,000
39,595,000
2
1
21
47
6
0
5
2
88
5
93
6
100
6
1
14
4
27
25
152
14
18
185
1
3
190
.7
.7
.3
.5
.4
.8
.3
.7
.4
.3
.7
.3
.0
.3
.5
.9
.6
.3
.5
.8
.7
.3
.8
.5
.4
.7
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
C-29
-------
TABLE C-16. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new lignite-fired power unit, 0.5% sulfur in
lignite; 90% SO. removal; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
10,970 tons
900 tons
31,900 man-hr
441,000 MBtu
167,800 kgal
21,640,400 kWh
1,110 man-hr
Unit
cost, $
40.00/ton
90.00/ton
12.50/man-hr
2.00/MBtu
0.1 2 /kgal
0.029/kWh
17. 00 /man-hr
Total
annual
cost, $
438,800
81,000
519,800
398,800
882,000
20,100
627,600
1,595,300
18,900
3,542,700
4,062,500
% of average
annual revenue
requirements
4.05
0.75
4.80
3.68
8.15
0.19
5.80
14.73
0.17
32.72
37.52
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
2,313,900
3,405,200
1,006,500
39,900
6,765,500
10,828,000
21.37
31.45
9.29
0.37
62.48
100.00
$/ton lignite $/MBtu heat $/ton sulfur
Mills/kWh burned input removed
Equivalent unit revenue requirements
3.61
6.34
0.40
1,863
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Lignite burned, 1,549,900 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 5,270 metric tons/yr (5,810 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $20,759,000; total depreciable investment, $38,565,000; and total
capital investment, $39,595,000.
All tons shown are 2,000 Ib.
C-30
-------
TABLE C-17. DOUBLE-ALKALI- SLUDGE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new oil-fired power unit, 2.5% sulfur in
oil; 90% S0_ removal; onsite solids disposal)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silos, and
bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S02 absorption (four tray towers including presaturator and
entrainment separators, recirculation tanks, agitators, and
pumps )
Stack gas reheat (four direct oil-fired reheaters)
Reaction (tanks, agitators, and pumps)
Solids separation (thickener, drum filters, tanks, agitators,
pumps, and conveyor)
Solids disposal (onsite disposal facilities including reslurry
tank, agitator, slurry disposal pumps, and pond water return
pumps )
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Pond construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1
3
8
1
1
17
1
18
2
21
1
3
5
5
32
3
3
39
40
,146
606
,770
,208
,127
264
,790
942
,853
,071
,924
,314
,238
,343
316
,131
979
,769
,401
,408
,009
,889
,306
459
894
,659
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
5.
2.
17.
38.
5.
1.
8.
4.
84.
5.
89.
10.
100.
6.
1.
14.
4.
27.
25.
152.
14.
18.
185.
2.
4.
191.
4
9
8
7
3
2
4
4
1
0
1
9
0
3
5
8
6
2
4
6
2
3
1
1
2
4
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by direct oil-fired reheat.
Minimum in-process storage; only pumps are spared.
Disposal pond located 1 mi from power plant.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
C-31
-------
TABLE C-18. DOUBLE-ALKALI SLUDGE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new oil-fired power unit, 2.5% sulfur in
oil; 90% SO- removal; onsite solids disposal)
Direct Costs
Raw materials
Lime
Soda ash
Annual
quantity
30,240 tons
2,470 tons
Unit
cost, $
40.00/ton
90.00/ton
Total
annual
cost, $
1,209,600
222,300
% of average
annual revenue
requirements
10.18
1.87
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
31,900 man-hr 12.50/man-hr
2,425,900 gal
150,500 kgal
18,570,900 kWh
0.40/gal
0.12/kgal
0.029/kWh
2,050 man-hr 17.00/man-hr
1,431,900
398,800
970,400
18,100
538,600
1,583,300
34.900
3,544,100
4,976,000
12.05
3.36
8.17
0.15
4.54
13.33
0.29
29.84
41.89
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements 3.96
2,358,400
3,496,700
1,008,500
39,900
6,903,500
11,879,500
$/bbl oil $/MBtu heat
burned input
2.66 0.44
19.85
29.43
8.49
0.34
58.11
100.00
$/ton sulfur
removed
741
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Oil burned, 710 x 106 liters/yr (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175°F).
Sulfur removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $21,238,000; total depreciable investment, $39,306,000; and total
capital investment, $40,659,000.
All tons shown are 2,000 Ib.
C-32
-------
APPENDIX D
SEAWATER PROCESS
PROCESS DESCRIPTION
The seawater process, shown in Figure D-l, uses seawater from the power
plant condensers as the scrubbing agent. Because the amount of condenser
seawater is limited, the 3.5% and 2.0% sulfur coals are not included in the
seawater process evaluation. The 149 C (300 F) flue gas is cooled to 53 C
(127 F) in a presaturator and scrubbed in a countercurrent packed tower
absorber to remove S0_, S0~, HC1, C0?, and some residual fly ash. Seawater
at 26 C (79 F) is used in both the presaturator and absorber in a one-pass
flow. The flue gas is cooled to 27°C (81°F) in the S02 absorber.
Presaturator and absorber effluent at a pH of approximately 3.0 (based
on SO- content only) is treated with additional condenser seawater to
increase the pH to 6, treated with sparged air to oxidize 75% of the sulfite
to sulfate, and returned to the sea. The chemical oxygen demand of the
waste is estimated to be 3.1 mg 02/liter or less. Reheat of the flue gas
to 79 C (175 F) is included in the process. A case variation of reheat to
53°C (127°F) is also included.
The base-case material balance and equipment list are shown in Tables
D-l and D-2.
SPECIFIC PROCESS PREMISES
1. A packed-bed absorber with a presaturator and mist eliminator is
used. Pressure drop in the unit is 1.05 kPa (4.2 inches ELO) and
the superficial velocity in the absorber is 1.8 m/sec (6 ft/sec).
2. The presaturator L/G ratio is 0.5 liter/m (4 gal/10 aft3) and the
absorber L/G ratio is 8.0 liters/m3 (60 gal/10* aft3).
3. The total alkalinity of the seawater is assumed to be 2.4 meq/liter
as CaCO..
4. Oxidation of SO to SO. is assumed to be 75% in the oxidation tank.
x 4
5, Only condenser seawater from the power plant is used for neutraliza-
tion; no alkali or additional seawater is added.
D-l
-------
ENERGY REQUIREMENTS
For base-case conditions, reheat of the cleaned gas from 27 C to 79 C
requires 68.7 x 103 kg/hr (151,500 Ib/hr) of 243°C (470°F) steam at 3.55 x
10^ kPa absolute pressure (500 psig) equivalent to about 28.70 x 106 kcal/hr.
The electrical power demand for the seawater process, base case, is
estimated to be about 7,012 kW or 1.4% of the rated capacity of a 500-MW
power plant. For 6,000 hours of operation, the annual electrical energy
consumption is 42.1 x 106 kWh.
The total equivalent energy consumption for the base case is approxi-
mately 47.79 x 10" kcal/hr or 4.2% of the input energy required for the
500-MW power unit. Summarized energy requirements for all cases are listed
in Table D-3.
BYPRODUCT MANAGEMENT
ESP units remove 99.2% of the fly ash from the flue gas and, therefore,
only a small amount of fly ash is found in the effluent which is pumped
offshore for disposal. (Fly ash emission from oil-fired units does not
exceed the EPA particulate emission standard and fly ash collection facil-
ities are not included in oil-fired power plant design.) Projected mass
flow rates of byproduct wastes for the base case are shown below.
Component Kg/hr Lb/hr
Total effluent
S0 =
S03
HC1
Fly ash
72,124,300
4,040
1,110
470
50
158,864,200
8,900
2,450
1,050
120
Approximate chemical oxygen demand (COD) for this effluent is estimated at
3.1 mg 02/liter.
ECONOMIC EVALUATION
Capital investment and annual revenue requirements for the seawater
process are summarized in Tables D-4 and D-5. Detailed results are shown
in Tables D-6 through D-15. The accuracy ranges are shown graphically in
Figures D-2 and D-3. The effect of sulfur content on these costs is
shown in Figure D-4.
D-2
-------
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D-3
-------
TABLE D-l. SEAWATER PROCESS
MATERIAL BALANCE - BASE CASE (1.47. SULFUR COAL)
Stream No.
Description
1
i
i
4
5
6
7
8
9
10
Total stream, 1000 kB/hr
Total stream, Ib/hr
Gas flow, Nm^/hr (0°C)
Gas flow, sft3/min (60op
Liauid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Particulates, kg/hr
Particulates, Ib/hr
1
Coal to boiler
162
357,200
2
Combustion air
to air heater
2060.8
4^543,200
1,610,600
1,001,900
26.7
3
Gas to
presaturator-
absorber
2211.7
4,876,000
1,676,900
1.043.300
148.9
72.6
160
L
Gas to reheater
2151.5
4,743,300
1,604,000
997,800
35.8
9.5
27.2
18.1
40
^
Gas to stack
2151.5
4,743,300
1,606,700
999.500
79.4
18.1
40
Stream No.
Description
1
i
i
4
5
h
7
8
9
10
Total stream, 1000 kg/hi
Total stream. Ib/hr
Gas flow. Nm^/hr (0°C)
Gas flow, sft3/min (6QOE
Liquid flow, liters/min
Liquid flow, aal/min
Temperature. °C
Pressure, kPa (abs)
Pressure, psig
6
Steam to reheatei
68.7
151.500
)
243.3
3.55 x 103
500
7
Seawater to
presaturator-
absorber
15.444.6
34.049,700
255^020
67,370
26.1
8
Seawater to
neutralizer
56 ,.557
124.683.900
933.280
246.790
26.1
<)
Air to oxidizer
46.6
102.800
36.400
h 22,700
26.7
10
Effluent to sea
72.124
158,864,200
li.190j.170
314,440
26.1
_
7
H
9
10
h
J
8
9
10
D-4
-------
TABLE D-2. SEAWATER PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area 1—Materials Handling
Area size-cost
exponent
No equipment in this area
Area 2—Feed Preparation
Area size-cost
exponent
No equipment in this area
Area 3—Gas Handling
Area size-cost
exponent 0.68
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Fan
Subtotal
Forced draft, 8.2 in.
static head, 700 rpm, 800
hp, fluid drive, double
width, double inlet
772,000 68,000
772,000 68,000
Area 4—S00 Absorption
Area size-cost
exponent 0.80
£-... . .
Item No. Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
1. Absorber, SO,,
Packed tower, 38 ft long x
19 ft wide x 50 ft high,
1/4 in. carbon steel, neo-
prene lining, FRP internals,
FRP chevron vane entrainment
separator
3,496,000 300,000
(continued)
D-5
-------
Item
TABLE D-2 (continued)
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
2. Pump, seawater
6 Centrifugal, 16,850 gpm, 70 305,500
ft head, 700 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
45,800
3.
Area
1.
Soot blowers
Subtotal
5 — Reheat
Item
Reheater
40 Air, retractable 260,000
4,061,500
225,800
571,600
Area size-cost
exponent 0.74
Total
material
cost,
No. Description 1979 $
4 Steam, tube type, 5,580 ft2, 1,123,900
Total
labor
cost,
1979 $
56,600
one-half tubes made of In-
conel 625 and one-half made
of Cor-Ten
2. Soot blowers
Subtotal
20 Air, retractable
130,000 112,900
1,253,900 169,500
Area 6—Neutralization
Area size-cost
exponent 0.59
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Tank, neutraliza- 1
tion
2. Pumps, neutraliza- 7
tion tank
Subtotal
90 ft long x 8 ft wide x 25
ft high, 134,660 gal, open
top, concrete
(3 min residence time)
Vertical circulating, 49,360
gpm, 20 ft head, 400 hp, Al-
bronze
(5 operating, 2 spare)
15,600 41,600
1,050,000 200,000
1,065,600 241,600
(continued)
D-6
-------
TABLE D-2 (continued)
Area 7—Oxidation and Disposal
Area size-cost
exponent 0.68
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
Tank, oxidation
Lining
Blower, oxidation
air
Subtotal
22 ft dia x 21-1/2 ft high,
61,140 gal, open top, carbon
steel
(6 min residence time)
1/4 in. neoprene lining
Two-stage centrifugal,
11,340 sft3/min, 700 hp,
316 SS
40,700 73,000
33,600 41,100
345,200 3,000
419,500 117,100
D-7
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D-8
-------
TABLE D-4. SEAWATER PROCESS CAPITAL INVESTMENT
Case
Total
capital investment
$ $/kW
500-MW unit
Coal, 1.4% sulfur
(base case)
Coal, 0.8% sulfur
Lignite, 0.5% sulfur
Oil, 2.5% sulfur
Coal, 1.4% sulfur
(low-temperature alternate)
30,048,000 60
29,590,000
29,068,000
27,937,000
28,582,000
59
58
56
57
TABLE D-5. SEAWATER PROCESS ANNUAL REVENUE REQUIREMENTS
Case
Mills/kWh
$/ton coal
(bbl oil)
burned
$/MBtu
heat input
$/ton S
removed
500-MW unit
Coal, 1.4% S
(base case)
Coal, 0.8% S
Lignite, 0.5% S
Oil, 2.5% S
Coal, 1.4% S
(low-temperature
alternate)
8,707,100
8,667,100
8,516,800
8,575,600
7,837,700
2.90
,89
,84
.86
.61
8.13
10
98
92
7.31
0.32
0.32
0.32
0.32
0.29
735
1,086
1,466
535
661
D-9
-------
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S 50 -
w
w 40
w
2
w
w
j
p
H
iz
w
t-J
t-t
u
30
20
10
I
500-MW units
90% S02 removal
-x-
1
i r
Capital investment
Revenue requirements
-h
Low reheat
alternate
—r-
t
Low reheat
alternate
Oil-fired case
X Oil-fired case
1
1
5 10 15 20
SULFUR REMOVED, k SHORT TONS/YR
Figure D-4. Seawater process. Effect of sulfur removed on capital
investment and annual revenue requirement.
D-12
-------
TABLE D-6. SEAWATER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, coal-fired power unit,
1.4% sulfur in coal, 90% SO removal)
% of
total direct
Investment, $ investment
Direct Investment
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to reactor, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO. absorption (four absorbers including entrainment
separators and seawater pumps)
Reheat (four indirect steam reheaters)
Neutralization (tanks, agitators, and pumps)
Oxidation and disposal (tanks and air compressor)
Subtotal direct investment
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,519,000
7,069,000
1,594,000
2,367,000
815,000
15,364,000
922,000
16,286,000
392,000
98,000
2,534,000
800,000
3,824,000
4,022,000
24,132,000
2,413,000
2,896,000
29,441,000
21,000
586,000
30,048,000
21.6
43.4
9.8
14.5
5.0
94.3
5.7
100.0
2.4
0.6
15.6
4.9
23.5
24.7
148.2
14.8
17.8
180.8
0.1
3.6
184.5
Basis
Plant represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process
investment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
D-13
-------
TABLE D-7. SEAWATER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, coal-fired power unit,
1.4% sulfur in coal, 90% SO removal)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of net average
annual revenue
requirements
Direct Costs
Conversion costs
Operating labor and supervision
Utilities
Steam
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
17,520 man-hr 12.50/man-hr
638,200 MBtu
42,074,400 kWh
2.00/MBtu
0.029/kWh
1,710 man-hr 17.00/man-hr
219,000
1,276,400
1,220,200
977,200
29,100
3,721,900
3,721,900
2.52
14.66
14.01
11.22
0.33
42.74
42.74
Indirect Costs
Capital charges
Depreciation, interim replacements,
and insurance at 6.0% of total
depreciable investment
Average cost of capital and taxes
at 8.6% of total capital investment
Overheads
Plant, 50% of conversion costs less
utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
1,766,500
2,584,100
612,700
21,900
4,985,200
8,707,100
20.29
29.68
7.04
0.25
57.26
100.00
Mills/kWh
Equivalent unit revenue requirements
2.90
$/ton
$/ton coal $/MBtu heat sulfur
burned input removed
8.13
0.32
735
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,941 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 10,748 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $16,286,000; total depreciable investment, $29,441,000; and total capital
investment, $30,048,000.
D-14
-------
TABLE D-8. SEAWATER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, coal-fired power unit,
0.8% sulfur in coal, 90% S02 removal)
% of
total direct
Investment, $ investment
Direct Investment
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to reactor, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO. absorption (four absorbers including entrainment
separators and seawater pumps)
Reheat (four indirect steam reheaters)
Neutralization (tanks, agitators, and pumps)
Oxidation and disposal (tanks, agitators, pumps, and
air compressor)
Subtotal direct investment
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,600,000
7,267,000
1,636,000
1,953,000
653,000
15,109,000
907,000
16,016,000
392,000
98,000
2,499,000
790,000
3,779,000
3,959,000
23,754,000
2,375,000
2,850,000
28,979,000
21,000
590,000
29,590,000
22.5
45.4
10.2
12.2
4.1
94.4
5.6
100.0
2.5
0.6
15.6
4.9
23.6
24.7
148.3
14.8
17.8
180.9
0.1
3.7
184.7
Basis
Plant represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process
investment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
D-15
-------
TABLE D-9. SEAWATER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, coal-fired power unit,
0.8% sulfur in coal, 90% SO. removal)
Direct Costs
Conversion, costs
Operating labor and supervision
Utilities
Steam
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Total % of net average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
17,520 man-hr 12.50/man-hr
706,900 MBtu
39,378,100 kWh
2.00/MBtu
0.029/kWh
1,410 man-hr 17.00/man-hr
219,000
1,413,800
1,142,000
961,000
24,000
3,759,800
3,759,800
2.53
16.30
13.18
11.09
0.28
43.38
43.38
Indirect Costs
Capital charges
Depreciation, interim replacements,
and insurance at 6.0% of total
depreciable investment
Average cost of capital and taxes
at 8.6% of total capital investment
Overheads
Plant, 50% of conversion costs less
utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
1,738,700
2,544,700
602,000
21.900
4,907,300
8,667,100
20.06
29.36
6.95
0.25
56.62
100.00
Mills/kWh
Equivalent unit revenue requirements
2.89
$/ton coal
burned
$/ton
$/MBtu heat sulfur
input removed
6.10
0.32
1,086
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,288,938 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 7,238 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $16,016,000; total depreciable investment, $28,979,000; and total capital
investment, $29,590,000.
D-16
-------
TABLE D-10. SEAWATER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, lignite-fired power unit,
0.5% sulfur in lignite, 90% S02 removal)
% of
total direct
Investment, $ investment
Direct Investment
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to reactor, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO, absorption (four absorbers including entrainment
separators and seawater pumps)
Reheat (four indirect steam reheaters)
Neutralization (tanks, agitators, and pumps)
Oxidation and disposal (tanks, agitators, pumps, and
air compressor)
Subtotal direct investment
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,663,000
7,415,000
1,667,000
1,572,000
509,000
14,826,000
890,000
15,716,000
392,000
98,000
2,460,000
779,000
3,729,000
3,889,000
23,334,000
2,333,000
2,800,000
28,467,000
21,000
580,000
29,068,000
23.3
47.2
10.6
10.0
3.2
94.3
5.7
100.0
2.5
0.6
15.7
5.0
23.7
24.7
148.5
14.9
17.8
181. 1
0.1
3.7
185.0
Basis
Plant represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process
investment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
D-17
-------
TABLE D-ll. SEAWATER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, lignite-fired power unit,
0.5% sulfur in lignite, 90% S02 removal)
Direct Costs
Conversion costs
Operating labor and supervision
Utilities
Steam
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Total % of net average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
17,520 man-hr 12.50/man-hr
725,200 MBtu
36,716,500 kWh
2.00/MBtu
0.029/kWh
1,130 man-hr 17.00/man-hr
219,000
1,450,400
1,064,800
943,000
19.200
3,696,400
3,696,400
2.57
17.03
12.50
11.07
0.23
43.40
43.40
Indirect Costs
Capital charges
Depreciation, interim replacements,
and insurance at 6.0% of total
depreciable investment
Average cost of capital and taxes
at 8.6% of total capital investment
Overheads
Plant, 50% of conversion costs less
utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
1,708,000
2,499,900
590,600
21,900
4,820,400
8,516,800
20.05
29.35
6.92
0.28
56.60
100.00
Equivalent unit revenue requirements
Mills /kWh
2.84
$/ton
lignite
burned
4.98
$/MBtu heat
input
0.32
$/ton
sulfur
removed
1,466
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Lignite burned, 1,549,882 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 5,270 metric tons/yr (5,810 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $15,716,000; total depreciable investment, $28,467,000; and total capital
investment, $29,068,000.
D-18
-------
TABLE D-12. SEAWATER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, oil-fired power unit,
2.57, sulfur in oil, 90% SO, removal)
% of
total direct
Investment, $ investment
Direct Investment
Gas handling (common feed plenum and booster fans , gas
ducts and dampers from plenum to reactor, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO absorption (four absorbers including entrainment
separators and seawater pumps)
Reheat (four direct oil-fired reheaters)
Neutralization (tanks, agitators, and pumps)
Oxidation and disposal (tanks, agitators, pumps, and
air compressor)
Subtotal direct investment
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,128,000
6,157,000
1,404,000
2,592,000
906,000
14,187,000
851,000
15,038,000
392,000
98,000
2,371,000
753,000
3,614,000
3,730,000
22,382,000
2,238,000
2,686,000
27,306,000
21,000
610,000
27,937,000
20.8
41.0
9.3
17.2
6.0
94.3
5.7
100.0
2.6
0.6
15.8
5.0
24.0
24.8
148.8
14.9
17.9
181.6
0.1
4.1
185.8
Basis
Plant location represents project beginning mid-1977, ending mid-1980. Average
cost basis for scaling, mid-1979.
Stack gas reheat to 79 C (175°F) by direct oil-fired reheat.
Only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process
investment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
D-19
-------
TABLE D-13. SEAWATER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, oil-fired power unit,
2.5% sulfur in oil, 90% S02 removal)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of net average
annual revenue
requirements
Direct Costs
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
17,520 man-hr 12.50/man-hr
3,988,900 gal
40,935,200 kWh
0.40/gal
0.029/kWh
1,880 man-hr 17.00/man-hr
219,000
1,595,600
1,187,100
902,300
32,000
3,936,000
3,936,000
2.55
18.61
13.84
10.52
0.37
45.89
45.89
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
1,638,400
2,402,600
576,700
21.900
4,639,600
8,575,600
19.11
28.02
6.72
0.26
54.11
100.00
Equivalent unit revenue requirements
$/ton
$/bbl oil $/MBtu heat sulfur
Mills/kWh burned input removed
2.86
1.92
0.32
535
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream tine, 6,000 hr/yr
Oil burned, 710 x 106 liters (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175 F).
Sulfur removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $15,038,000; total depreciable investment, $27,306,000; and total capital
investment, $27,937,000.
D-20
-------
TABLE D-14. SEAWATER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, coal-fired power unit, 1.4% sulfur
in coal, 90% SO- removal, low reheat temperature)
% of
total direct
Investment, $ investment
Direct Investment
Gas handling (common feed plenum and booster fans, gas
ducts and dampers from plenum to reactor, exhaust gas
ducts and dampers from absorber to reheater and stack)
SO. absorption (four absorbers including entrainment
separators and seawater pumps)
Reheat (four indirect steam reheater s)
Neutralization (tanks, agitators, and pumps)
Oxidation and disposal (tanks, agitators, pumps, and
air compressor)
Subtotal direct investment
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
3,519,000
7,069,000
834,000
2,367,000
815,000
14,604,000
876,000
15,480,000
392,000
98,000
2,429,000
770,000
3,689,000
3,834,000
23,003,000
2,300,000
2,760,000
28,063,000
21,000
498,000
28,582,000
22.7
45.7
5.4
15.3
5.2
94.3
5.7
100.0
2.5
0.6
15.7
5.0
23.8
24.8
148.6
14.9
17.8
181.3
0.1
3.2
184.6
Basis
Plant represents project beginning mid-1977, ending mid-1980. Average cost basis
for scaling, mid-1979.
Stack gas reheat to 53°C (127°F) by indirect steam reheat.
Only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process
investment estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
D-21
-------
TABLE D-15. SEAWATER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, coal-fired power unit, 1.4% sulfur
in coal, 90% SO, removal, low reheat temperature)
Direct Costs
Conversion costs
Operating labor and supervision
Utilities
Steam
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Total % of net average
Annual Unit annual annual revenue
quantity cost, $ cost, $ requirements
17,520 man-hr 12.50/man-hr
344,200 MBtu
42,074,400 kWh
2.00/MBtu
0.029/kWh
1,710 man-hr 17.00/man-hr
219,000
688,400
1,220,200
928,800
29.100
3,085,500
3,085,500
2.79
8.78
15.57
11.85
0.37
39.36
39.36
Indirect Costs
Capital charges
Depreciation, interim replacements,
and insurance at 6.0% of total
depreciable investment
Average cost of capital and taxes at
8.6% of total capital investment
Overheads
Plant, 50% of conversion costs less
utilities
Administrative, 10% of operating labor
Total indirect costs
Total average annual revenue requirements
1,683,800
2,458,000
588,500
21.900
4,752,200
7,837,700
21.48
31.36
7.52
0.28
60.69
100.00
$/ton
$/ton coal $/MBtu heat sulfur
Mills/kWh burned input removed
Equivalent unit revenue requirements
2.61
7.31
0.29
661
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,941 metric tons/yr (1,071,600 tons/hr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 53°C (127°!').
Sulfur removed, 10,748 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $15,480,000; total depreciable investment, $28,063,000; and total capital
investment, $28,582,000.
D-22
-------
APPENDIX E
LIME GYPSUM PROCESS
(SAARBERG-HOLTER PROCESS)
PROCESS DESCRIPTION
The Saarberg-Holter process, shown in Figure E-l, removes SO- using a
clear alkaline scrubbing solution in a ROTOPART, a patented modular-design
absorber. The flue gas enters the ROTOPART vessel at 149°C (300°F) and is
adiabatically cooled to 53 C (127 F) by contact with clear scrubbing solu-
tion. The flue gas and the scrubbing solution are cocurrently contacted in
vertical scrubbing tubes of the ROTOPART vessel. .The scrubbing tubes have
no packing but are equipped with injection nozzles and special shedding
rings to promote liquid-gas contact. S0_, SO , HC1, and some residual fly
ash are removed from the gas stream. Gas and washing fluid are centrifugally
separated in the separator section of the ROTOPART vessel. No further de-
misting is required.
SO in the flue gas reacts with CaCl- and Ca(OH)2 in the scrubbing
solution to form soluble Ca(HSO_)~ and HCl. The system uses formic acid
as a buffering agent to maintain a pH of about 4.5. The acidic absorber
effluent flows by gravity to an oxidizer vessel where air blown through the
liquid oxidizes Ca(HSO ) to CaSO.-ZIUO and H^SO,. Ca(OH)- is added at the
oxidizer to neutralize tne liquid and to replenish calcium in the solution.
Makeup formic acid is also added at the oxidizer.
Oxidizer effluent is pumped to a thickener where the suspension of
CaSO^-2H20 crystals is thickened to a 15% solids slurry. Slurry from the
thickener is filtered to produce an 80% solids cake. The filter cake is
conveyed to a storage area. Filtrate is recycled to the thickener and
thickener overflow at a pH of 10.5 is returned to the absorber for use as
scrubbing liquid.
The base-case material balance and equipment list are shown in Tables
E-l and E-2.
SPECIFIC PROCESS PREMISES
1. The ROTOPART has a superficial velocity of 12.2 m/sec (40 ft/sec)
in the scrubber tubes and a pressure drop through the unit of
2.44 kPa (9.8 inches H20). The L/G ratio is proprietary.
E-l
-------
2. The stoichiometry of 1.01 moles of CaO to 1.00 mole of SO- removed and
1.0 mole of CaO to 2.0 moles of HC1 removed.
3. Complete oxidation of SO^ removed to sulfate in the form of gypsum
is assumed.
ENERGY REQUIREMENTS
For base-case»conditions, reheat of the cleaned gas from 53 C to 79 C
requires 42.4 x 10 kg/hr (93,460 Ib/hr) of 243°C (470°F) steam at 3,550 kPa
absolute pressure (500 psig), equivalent to about 17.7 x 10" kcal/hr.
The electrical power demand for the base-case lime gypsum process is
about 9701 kW or 1.9% of the rated output of a 500-MW power plant. For 6000
hours of operation, the annual electrical energy consumption is 58.2 x 10° kWh.
The total equivalent energy consumption for the base case is approximately
39.70 x 106 kcal/hr or 3.7% of the input energy required for the 500-MW power
unit. Summarized energy requirements for all cases are listed in Table E-3.
BYPRODUCT MANAGEMENT
Electrostatic precipitators remove 99.2% of the fly ash from the flue gas
and, therefore, only a small amount of fly ash is found in the FGD process
byproduct. (Fly ash emission from oil-fired units does not exceed the EPA
particulate emission standard and fly ash collection facilities are not
included in oil-fired power plant design.) Projected mass flow rates of
byproduct for the base case are shown below.
Component Kg/hr Lb/hr
CaS04-2H20
CaS03-l/2H20
CaCl2
Mg(OH)
Fly ash
Inerts
27,640
82
440
295
149
102
60,880
180
968
650
329
225
28,708 63,232
The process is evaluated on the basis of 30-day storage of gypsum byprod-
uct. A 0.4 hectare (1 acre) storage area has been provided for the base case
and all fuel variations.
ECONOMIC EVALUATION
Capital investment and annual revenue requirements for the base case and
five fuel variations are shown in Tables E-4 and E-5. The detailed results
are shown in Tables E-6 through E-17. The estimated accuracy ranges of the
economic analysis are shown in Figures E-2 and E-3. The effect of fuel sul-
fur content on costs is shown in Figure E-4.
E-2
-------
00
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E-3
-------
TABLE E-l. SAARBERG-HOLTER PROCESS
MATERIAL BALANCE - BASE CASE (3.5% S COAL)
Stream No.
1
i
i
.'i
'i
h
7
H
9
10
Description
Total stream, 1000 kfi/hr
Total stream, Ib/hr
Gas flow, Nm3/hr (0°C)
Gas floWj sft3/min (60°F)
Liquid flow, liters/min
Liquid flow, Ral/min
Temperature. °C
Particulates. ksj/hr
Particulates, Ib/hr
1
Coal to boiler
194
428,600
2
Combustion air
to air heater
2,062
4,546,200
1,615,700
1,005,000
27
3
Gas to
absorber
2,225
4,906,000
1,697,700
1,056,000
149
199
439
4
Gas to reheater
2.428
5,352.900
1,903,200
1,183,900
40.4
10.7
53
50
110
5
Gas to stack
2.428
5,352.900
1,906,200
1.185.800
79
50
110
Stream No.
1
1
1
4
')
6
7
8
9
Iff
Description
Total stream, 1000 kg/hr
Total stream. Ib/hr
Gas flow. Nm3/hr (0°C)
Gas flow. sft3/min (60°F1
Liauid flow, liters/min
Liauid flow, sal/rain
Temperature. °C
Pressure, Pascals (abs)
Pressure, osle "
b
Steam to
reheater
42
93.500
243
3.55 x 106
•iOO
7
Process
makeup water
216
475.300
3.600
950
8
Lime
to system
10
21.200
9
Formic acid
7.9 x 10-J
17.3
10
Oxidation air
56.4
124^200
44,000
27.400
Stream No.
Description
1
j
J
4
r)
h
7
H
9
10
Total stream, 1000 ks/hr
Total stream, Ib/hr
Liquid flow, liters/min
Liquid flow, pal/min
Undissolved solids, %
Particulates, kx/hr
Particulates, Ib/hr
Bulk density, kg/m3
Bulk density, Ib/ft3
11
Oxldizer off-gas
58.4
128 700
12
Gypsum
35
77,800
80
ljJ60
85
1
I
4
5
h
7
_8_
9
10
E-4
-------
TABLE E-2. SAARBERG-HOLTER PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area I—Materials Handling
Area size-cost
exponent 0.74
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Conveyor, lime
storage
(enclosed)
2. Elevator, lime
storage
3. Silo, lime
storage
4. Feeder, reclaim 1
Conveyor, live
lime feed
(enclosed)
Elevator, live
lime feed
7. Bin, lime feed 2
8. Dust collecting 1
system
Belt, 24 in. wide x 1,500 ft
long, 30 hp, 100 tons/hr,
150 ft/min
Continuous, bucket 16 in. x
8 in. x 11-3/4 in., 75 hp,
120 ft lift, 100 tons/hr,
160 ft/min
50 ft dia x 74 ft straight
side, 145,300 ft3, 60° slope,
3/8 in. carbon steel
Vibrating pan, 3-1/2 hp, 40
tons/hr
Belt, 18 in. wide x 100 ft
long, 2 hp, 40 tons/hr,
100 ft/min
Continuous, bucket 11 in. x
6 in. x 8-3/4 in., 50 hp,
50 ft lift, 40 tons/hr, 160
ft/min, with diverter gate
10 ft dia x 15 ft high,
w/cover, carbon steel
Bag filter, polypropylene
bag, 8,800 aft3/min, 7-1/2
hp, automatic shaker system
(1/2 cost in feed prepara-
tion area)
155,800 52,300
102,900 2,400
88,400 246,100
12,200 2,100
23,400 4,800
56,000 1,100
5,400 11,300
10,700 28,200
Subtotal
454,800 348.300
(continued)
E-5
-------
TABLE E-2 (continued)
Area 2 — Feed Preparation
1.
2.
3.
4.
5.
6.
7.
8.
Item No .
Feeder, lime bin 2
discharge
Feeder, slaker 2
weigh
Slaker 2
Tank, slaker 2
product
Lining
Agitator, slaker 2
product tank
Pump, slaker 3
product tank
Tank, slurry 1
feed
Lining
Agitator, slurry 1
Description
Vibrating, 3-1/2 hp
Screw, 12 in. dia x 12 ft
long slaker, 1 hp, 6 tons/hr
7 ft wide x 31 ft long, 10
hp, 2 hp clarifier, 6 tons/hr
4 ft dia x 4 ft high, 380 gal,
open top, four 4 in. baffles,
agitator supports, carbon steel
(10 min residence time)
1/4 in. neoprene lining
Two turbines, 16 in. dia, 1-
1/2 hp, neoprene coated
Centrifugal, 31 gpm, 60 ft
head, 2 hp, carbon steel,
neoprene lined
(2 operating, 1 spare)
18 ft dia x 17-1/2 ft high,
33,300 gal, open top, four
18 in. baffles, agitator
supports, carbon steel
(8 hr residence time)
1/4 in. neoprene lining
Two turbines, 72 in. dia,
Area size-cost
exponent 0.55
Total
material
cost,
1979 $
9,200
12,000
116,300
700
800
7,600
5,100
7,000
7,200
33,100
Total
labor
cost,
1979 $
3,700
1,400
12,100
1,300
1,000
2,200
1,800
12,600
8,800
2,100
feed tank
9. Pump, slurry
feed tank
30 hp, neoprene coated
Centrifugal, 62 gpm, 60 ft
head, 5 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
3,800
1,200
(continued)
E-6
-------
TABLE E-2 (continued)
10.
Area
1.
Area
1.
2.
3.
Item No .
Dust collecting 1
system
Subtotal
3 — Gas Handling
Item No.
Fans 4
Subtotal
4 — S00 Absorption
Item No.
S0_ absorber 4
Pump, absorber 12
feed
Soot blowers 40
Subtotal
Description
Bag filter, polypropylene
bag, 8,800 aft3/min, 7-1/2
hp, automatic shaker system
(1/2 cost in material handling)
Description
Forced draft, 13.8 in. static
head, 875 rpm, 1,250 hp,
fluid drive, double width,
double inlet
Description
ROTOPART, length 80 ft, 4
washing ducts (dia - 6 ft
4 in.), 7 cast iron spray
nozzles/duct, capacity -
395,000 aft3/min
Proprietary
(8 operating, 4 spares)
Air, retractable
Total Total
material labor
cost, cost,
1979 $ 1979 $
10,700 28,200
213,500 76,400
Area size-cost
exponent 0.68
Total Total
material labor
cost, cost,
1979 $ 1979 $
1,427,900 93,100
1,427,900 93,100
Area size-cost
exponent 0.93
Total Total
material labor
cost, cost,
1979 $ 1979 $
2,236,000 210,000
555,500 70,700
260,000 225,800
3,051,500 506,500
(continued)
E-7
-------
TABLE E-2 (continued)
Area 5 — Reheat
Item No.
Area size-cost
exponent 0.75
Total Total
material labor
cost, cost,
Description 1979 $ 1979 $
1. ' Reheater
Steam, tube type, 3,770 ft ,
one-half tubes made of Inconel
625 and one-half made of Cor-
Ten
858,000 41,200
2.
Soot blowers
Subtotal
20
Air,
retractable
130
988
,000
,000
112
154
,900
,100
Area 6—Oxidation
Area size-cost
exponent 0.78
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Oxidation
vessel
2.
Lining
Blower, oxida-
tion air
3. Pump, oxidizer 4
drain
4. Pump, makeup
water
Subtotal
43 ft dia x 43 ft high,
464,280 gal, covered, carbon
steel
Epoxy lined
Three-stage centrifugal,
6,850 sft-Vmin, 600 hp,
316 stainless steel
Centrifugal, 225 gpm, 50
ft head, 10 hp, carbon
steel
(2 operating, 2 spares)
Centrifugal, 455 gpm, 75 ft
head, 20 hp, carbon steel
(2 operating, 2 spares)
430,700 345,900
172,500 210,900
439,200 63,200
15,400 3,000
17,100 5,900
1,074,900 628,900
(continued)
E-8
-------
TABLE E-2 (continued)
Area 7—Thickening and Solids Separation and Storage
Area size-cost
exponent 0.47
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Thickener
Rake and motor
mechanism
2. Pump, thickener
underflow
3. Filter
4. Pump, filtrate 4
5. Conveyor, filter 1
cake (horizontal)
6. Conveyor, filter 1
cake (incline)
7. Mobile equipment 1
Subtotal
Concrete construction, 130
ft dia x 33 ft high, 3,275,000
gal, concrete basin, 4 ft high
7-1/2 hp
Centrifugal, 370 gpm, 60 ft
head, 15 hp, carbon steel,
neoprene lined
(2 operating, 2 spares)
Rotary, vacuum, 11-1/2 ft
dia x 14 ft face, 20 total
hp
Centrifugal, 320 gpm, 60 ft
head, 15 hp, carbon steel,
neoprene lined
(2 operating, 2 spares)
Belt, 18 in. wide x 50 ft
long, 3 hp, 40 tons/hr,
100 ft/min
Belt, 18 in. wide x 100 ft
long, 3 hp, 40 tons/hr, 100
ft/min
Front-end loader, 23 yd /hr
488,400 1,196,000
799,600 266,600
16,200
16,200
9,800
23,400
80,000
5,900
256,300 26,800
5,900
3,900
4,800
1,689,900 1,509,900
E-9
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-------
TABLE E-4. SAARBERG-HOLTER PROCESS CAPITAL INVESTMENT
Total capital
Investment
Case
500-MW unit
Coal, 3.5% sulfur
(base case)
Coal, 0.8% sulfur
Coal, 1.4% sulfur
Coal, 2.0% sulfur
Lignite, 0.5% sulfur
Oil, 2.5% sulfur
$
44,024,000
35,481,000
36,472,000
39,173,000
34,905,000
34,802,000
$/kW
88
71
73
78
70
70
TABLE E-5. SAARBERG-HOLTER PROCESS ANNUAL REVENUE REQUIREMENTS
Case
Mills/kWh
$/ton coal
(bbl oil)
burned
$/MBtu
heat
input
$/ton
sulfur
removed
500-MW unit
Coal, 3.5% sulfur
(base case)
Coal, 0.8% sulfur
Coal, 1.4% sulfur
Coal, 2.0% sulfur
Lignite, 0.5% sulfur
Oil, 2.5% sulfur
13,706,300 4.57
9,825,900
10,303,700
11,443,300
9,571,100
10,347,600
,28
,43
,81
,19
3.45
10.66
6.96
9.62
9.32
5.60
(2.32)
0.51
0.36
0.38
0.42
0.35
0.38
402
1,231
870
609
1,647
646
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40
30
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I
500-MW units
90% S02 removal
• Oil-fired unit
X Oil-fired unit
• Capital investment
X Annual revenue requirements
I I I
10 20 30 40
SULFUR REMOVED, k SHORT TONS/YR
Figure E-4. Saarberg-Holter process. Effect of sulfur removed
on capital investment and annual revenue requirements.
E-14
-------
TABLE E-6. SAARBERG-HOLTER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 3.5% sulfur in coal;
90% SOj removal; gypsum production)
— '
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
SO. absorption (four ROTOPART scrubber-separators, tank, and pumps)
Stack gas reheat (four indirect steam reheaters)
Oxidation (oxidation vessels, blowers, and pumps)
Solids disposal (thickeners, filters, conveyors, pumps, and front-
end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
1,324,000
898,000
4,950,000
7,518,000
1,296,000
2,260,000
3,876,000
22,122,000
1,327,000
23,449,000
40,000
23,489,000
976,000
243,000
3,438,000
1,057,000
5,714,000
5,841,000
35,044,000
3,500,000
4,205,000
42,749,000
42,000
1,233,000
44,024,000
% of
total direct
investment
5.6
3.8
21.1
32.0
5.5
9.6
16.5
94.1
5.7
99.8
0.2
100.0
4.2
1.0
14.6
4.5
24.3
24.9
149.2
14.9
17.9
182.0
0.2
5.2
187.4
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment estimate
begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
E-15
-------
TABLE E-7. SAARBERG-HOLTER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 3.5% sulfur
in coal; 90% SO removal; gypsum production)
Annual
quantity
Direct Costs
Raw materials
Lime
Formic acid
Flocculant
Nalco
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
63,600
103,800
10,000
1,000
31,900
421,500
342,100
58,208,700
3,220
tons
Ib
Ib
Ib
man-hr
MBtu
kgal
kWh
man-hr
40
0
1
1
12
2
0
0
17
Unit
cost, $
.00 /ton
.25/lb
.00/lb
.00/lb
.50 /man-hr
.00/MBtu
.12/kgal
.029/kWh
.00/man-hr
Total /
annual
cost, $
2,544
26
10
1
2,581
398
843
41
1,688
1,408
54
4,433
7,014
,000
,000
,000
,000
,000
,800
,000
,100
,100
,100
,700
,800
,800
£ of net average
annual revenue
requirements
18
0
0
0
18
2
6
0
12
10
0
32
51
.56
.19
.07
.01
.83
.91
.15
.30
.32
.27
.40
.35
.18
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,564,900
3,786,100
930,800
39,900
70,000
7,391,700
14,406,500
18.72
27.62
6.79
0.29
0.51
53.93
105.11
Byproduct Sales Revenue
Byproduct gypsum 233,400 tons
Net average annual revenue requirements
3.00/ton
(700,200)
13,706,300
(5.11)
100.00
Equivalent unit revenue requirements (net)
Mills/kWh
4.57
$/ton
$/ton coal $/MBtu heat sulfur
burned input removed
10.66
0.51
402
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,221 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kKli).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 30,947 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $23,489,000; total depreciable investment, $42,749,000; and total
capital investment, $44,024,000.
All tons shown are 2,000 Ib.
E-16
-------
TABLE E-8. SAARBERG-HOLTER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 0.8% sulfur
in coal; 90% SO. removal; gypsum production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
SO absorption (four ROTOPART scrubber-separators, tank, and pumps)
Stack gas reheat (four indirect steam reheaters)
Oxidation (oxidation vessels, blowers, and pumps)
Solids disposal (thickeners, filters, conveyors, pumps, and front-
end loadet)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment (
Land
Working capital
Total capital investment
451,000
404,000
5,034,000
7,691,000
1,319,000
728,000
2,047,000
17,674,000
1,060,000
18,734,000
40,000
18,774,000
976,000
243,000
2,853,000
892,000
4,966,000
4,748,000
28,488,000
2,845,000
3,418,000
34,751,000
42,000
688,000
35,481,000
2.4
2.1
26.8
41.0
7.0
3.9
10.9
94.1
5.7
99.8
0.2
100.0
5.2
1.3
15.2
4.7
26.4
25.3
151.7
15.2
18.2
185.1
0.2
3.7
189.0
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment estimate
begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
E-17
-------
Direct Costs
TABLE E-9. SAARBERG-HOLTER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 0.8X sulfur
in coal; 90% SO. removal; gypsum production)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of net average
annual revenue
requirements
Raw materials
Lime
Formic acid
Flocculant
Nalco
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
14,900 tons
24,300 Ib
2,340 Ib
234 Ib
40.00/ton
0.25/lb
1.00/lb
1.00/lb
31,900 man-hr 12.50/man-hr
596,000
6,100
2,300
200
604,600
398,800
431,900 MBtu
350,500 kgal
33,307,000 kWh
1,350 man-hr
2. 00 /MBtu
0.12/kgal
0.029/kWh
17. 00 /man-hr
863,800
42,100
965,900
1,125,200
23,000
3,418,800
4,023,400
6.07
0.06
0.02
6.15
4.06
8.79
0.43
9.83
11.45
0.23
34.79
40.94
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Byproduct gypsum 54,600
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
2,085,100
3,051,400
773,500
39,900
16,400
5,966,300
9,989,700
tons 3.00/ton (163,800)
9,825,900
$/ton coal $/MBtu heat
Mills/kWh burned input
3.28 6.96 0.36
21.22
31.05
7.86
0.41
0.17
60.73
101.67
(1.67)
100.00
$/ton
sulfur
removed
1,231
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,288,936 metric tons/yr (1,412,100 tons/yr), 2,263 kcal/kWh (9,000 Btu/kwh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 7,240 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $18,774,000; total depreciable investment, $34,751,000; and total
capital investment, $35,481,200.
All tons shown are 2,000 Ib.
E-18
-------
TABLE E-10. SMRBERG-HOLTER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 1.4% sulfur
In coal; 90% SO- removal; gypsum production)
7. of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S0_ absorption (four ROTOPART scrubber-separators, tank, and pumps)
Stack gas reheat (four indirect steam reheaters)
Oxidation (oxidation vessels, blowers, and pumps)
Solids disposal (thickeners, filters, conveyors, pumps, and front-
end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
605,000
502,000
4,915,000
7,450,000
1,287,000
990,000
2,434,000
18,183,000
1,091,000
19,274,000
40,000
19,314,000
976,000
243,000
2,923,000
911,000
5,053,000
4,873,000
29,240,000
2,920,000
3,509,000
35,669,000
42,000
761,000
36,472,000
3.1
2.6
25.4
38.6
6.7
5.1
12.6
94.1
5.7
99.8
0.2
100.0
5.1
1.3
15.1
4.7
26.2
25.2
151.4
15.1
18.2
184.7
0.2
3.9
188.8
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment estimate
begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
E-19
-------
TABLE E-ll. SAARBERG-HOLTER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 1.4% sulfur
in coal; 90% S0~ removal; gypsum production)
Direct Costs
Raw materials
Lime
Formic acid
Flocculant
Nalco
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost. $
Total
annual
cost, $
% of net average
annual revenue
requirements
2,100 tons
36,000 Ib
3,470 Ib
347 Ib
40.00/ton
0.25/lb
1.00/lb
1.00/lb
31,900 man-hr 12.50/man-hr
884,000
9,000
3,500
300
896,800
398,800
417,400 MBtu
338,700 kgal
36,389,100 kWh
1,710 man-hr
2. 00 /MBtu
0.1 2 /kgal
0.029/kWh
17.00/man-hr
834,800
40,600
1,055,300
1,157,600
29,100
3,516,200
4,413,000
8.58
0.09
0.03
8.70
3.87
8.10
0.39
10.25
11.23
0.28
34.12
42.82
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6/£
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,140,100
3,136,600
792,800
39,900
24,300
6,133,700
10,546,700
20.77
30.45
7.69
0.39
0.24
59.54
102.36
Byproduct Sales Revenue
Byproduct gypsum 81,000 tons 3.00/ton (243,000) (2.36)
Net average annual revenue requirements 10,303,700 100.00
Equivalent unit revenue requirements (net)
$/ton
$/ton coal $/MBtu heat sulfur
Mills/kWh burned input removed
3.43
9.62
0.38
870
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,941 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 10,748 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $19,314,000; total depreciable investment, $35,669,000; and total
capital investment, $36,472,000.
All tons shown are 2,000 Ifa.
E-20
-------
TABLE E-12. SAARBERG-HOLTER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 2.0% sulfur
in coal; 90% S02 removal; gypsum production)
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
SO absorption (four ROTOPART scrubber-separators, tank, and pumps)
Stack gas reheat (four indirect steam reheaters)
Oxidation (oxidation vessels, blowers, and pumps)
Solids disposal (thickeners, filters, conveyors, pumps, and front-
end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
851,000
647,000
4,930,000
7,480,000
1,291,000
1,419,000
2,981,000
19,599,000
1,176,000
20,775,000
40,000
20,815,000
976,000
243,000
3,110,000
964,000
5,293,000
5,222,000
31,330,000
3,129,000
3,760,000
38,219,000
42,000
912,000
39,173,000
% of
total direct
investment
4.1
3.1
23.7
35.9
6.2
6.8
14.3
94.1
5.7
99.8
0.2
100.0
4.7
1.2
14.9
4.6
25.4
25.1
150.5
15.0
18.1
183.6
0.2
4.4
188.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 79 C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment estimate
begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
E-21
-------
TABLE E-13. SAARBERG-HOLTER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 2.0% sulfur
in coal; 90% SO™ removal; gypsum production)
Annual
quantity
Direct Costs
Raw materials
Lime
Formic acid
Flocculant
Nalco
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
35
57
5
31
419
340
43,229
2
,000
,200
,510
551
,900
,300
,300
,800
,550
tons
Ib
Ib
Ib
man-hr
MBtu
kgal
kWh
man-hr
40
0
1
1
12
2
0
0
17
Unit
cost, S
.00/ton
.25/lb
.00/lb
.00/lb
. 50/man-hr
.00/MBtu
.12/kgal
.029/kWh
.00 /man-hr
Total 7,
annual
cost, $
1,400
14
5
1,420
398
838
40
1,253
1,247
43
3,823
5,243
,000
,300
,500
600
,400
,800
,600
,800
,700
,700
,400
,000
,400
of net average
annual revenue
requirements
12,
0
0,
0,
12,
3
7.
0.
10,
10.
0.
33.
45.
.23
.12
.05
.01
.41
.49
,33
,36
.96
,90
.38
,42
83
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10X of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,293,100
3,368,800
845,000
39,900
38,600
6,585,400
11,828,800
20.04
29.43
7.38
0.35
0.34
57.54
103.37
Byproduct Sales Revenue
Byproduct gypsum 128,500 tons 3.00/ton (385,500)
Net average annual revenue requirements 11,443,300
Equivalent unit revenue requirements (net)
$/ton
$/ton coal $/MBtu heat sulfur
Mills/kWh burned input removed
3.81
9.32
0.42
609
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,113,161 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 17,043 metric tons/yr (18,790 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $20,815,000; total depreciable investment, $38,219,000; and total
capital investment, $39,173,000.
All tons shown are 2,000 1*.
E-22
-------
TABLE E-14. SAARBERG-HOLTER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new lignite-fired power unit, 0.5% sulfur
in lignite; 90% SO removal; gypsum production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorbers to reheater and stack)
SO. absorption (four ROTOPART scrubber-separators, tank, and pumps)
Stack gas reheat (four indirect steam reheaters)
Oxidation (oxidation vessels, blowers, and pumps)
Solids disposal (thickeners, filters, conveyors, pumps, and front-
end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
357,000
339,000
5,118,000
7,871,000
1,345,000
567,000
1,779,000
17,376,000
1,043,000
18,419,000
40,000
18,459,000
976,000
243,000
2,815,000
880,000
4,914,000
4,674,000
28,047,000
2,801,000
3,366,000
34,214,000
42,000
649,000
34,905,000
1.9
1.8
27.7
42.7
7.3
3.1
9.6
94.1
5.7
99.8
0.2
100.0
5.3
1.3
15.2
4.8
26.6
25.3
151.9
15.2
18.3
185>
0.2
3.5
189.1
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment estimate
begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
E-23
-------
TABLE E-15. SAARBERG-HOLTER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new lignite-fired power unit, 0.5% sulfur
in lignite; 90% SO- removal; gypsum production)
Annual
quantity
Direct Costs
Raw materials
Lime
Formic acid
Flocculant
Nalco
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
10
17
1
31
443
359
32,075
1
,800
,700
,700
170
,900
,000
,600
,300
,110
tons
Ib
Ib
Ib
man-hr
MBtu
kgal
kWh
man-hr
Unit
cost, $
40
0
1
1
12
2
0
0
17
.00 /ton
.25/lb
.00/lb
.00/lb
.50/man-hr
.00/MBtu
.12/kgal
.029/kWh
.00 /man-hr
Total % of net average
annual annual revenue
cost, $ requirements
432
4
1
438
398
886
43
930
1,106
Hi
3,383
3,821
,000
,400
,700
200
,300
,800
,000
,200
,200
,300
,900
,400
,700
4
0
0
4
4
9
0
9
11
0
35
39
.51
.05
.02
-
.58
.17
.26
.45
.72
.56
.20
.46
.94
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment ^
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Byproduct gypsum 39,700 tons
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
2,052,800 21
3,001,900 31
762,000 7
39,900 0
11,900 0
5,868,500 61
9,690,200 101
3.00/ton (119,100) (1
9,571,100 100
$/ton
lignite $/MBtu heat
Mills /kWh burned input
3.19 5.60 0.35
.45
.36
.96
.41
.12
.30
.24
.24)
.00
$/ton
sulfur
removed
1,647
Basis
1980 revenue requirements. ,
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6.000 hr/yr.
Lignite burned, 1,549,900 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 5,270 metric tons/yr (5,810 short tons/vr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $18,459,000; total depreciable investment, $34,214,000; and total
capital investment, $34,905,000.
All tons shown are 2,000 Ib.
E-24
-------
TABLE E-16. SAARBERG-HOLTER PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new oil-fired power unit, 2.5% sulfur
in oil; 90% SO removal; gypsum production)
Direct Investment
Materials handling (conveyors, elevators, feeder, silo, and bin)
Feed preparation (feeders, slakers, tanks, agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack)
S0» absorption (four ROTOPART scrubber-separators, tank, and pumps)
Stack gas reheat (four direct oil-fired reheaters)
Oxidation (oxidation vessels, blowers, and pumps)
Solids disposal (thickeners, filters, conveyors, pumps, and front-
end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
% of
total direct
Investment, $ investment
756,000
593,000
4,371,000
6,338,000
1,130,000
1,252,000
2.779,000
4.1
3.2
23.9
34.7
6.2
6.8
15.2
17,219,000 94.1
1.033,000 5.7
18,252,000 99.8
40,000 0.2
18,292,000
100.0
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
976,000
243,000
2,794,000
874,000
4,887,000
4,636,000
27,815,000
2,777,000
3.338,000
33,930,000
42,000
830,000
34,802,000
5.3
1.3
15.3
4.8
26.7
25.3
152.0
15.2
18.3
185.5
0.2
4.5
190.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for scaling,
mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment estimate
begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
E-25
-------
TABLE E-17. SAARBERG-HOLTER PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new oil-fired power unit, 2.5% sulfur
in oil; 90% SO. removal; gypsum production)
Direct Costs
Raw materials
Lime
Formic acid -
Flocculant
Nalco
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
29,900 tons
48,700 Ib
4,700 Ib
470 Ib
31,900 man-hr
2,436,800 gal
284,800 kgal
36,465,100 kWh
2,050 man-hr
Unit
cost, $
40.00/ton
0.25/lb
1.00/lb
1.00/lb
12.50/man-hr
0.40/gal
0.12/kgal
0.029/kWh
17.00/man-hr
Total % of net average
annual annual revenue
cost, $ requirements
1,196,000
12,200
4,700
500
1,213,400
398,800
974,700
34,200
1,057,500
1,096,300
34,900
3,596,400
4,809,800
11.56
0.12
0.05
-
11.73
3.85
9.42
0.33
10.22
10.59
0.34
34.75
46.48
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,035,800
2,993,000
765,000
39,900
32,900
5,866,600
10,676,400
19.67
28.91
7.39
0.30
0.32
56.70
103.18
Byproduct Sales Revenue
Byproduct gypsum 109,600 tons
Net average annual revenue requirements
3.00/ton
(328,800)
10,347,600
(3.18)
100.00
Equivalent unit revenue requirements (net)
$/ton
$/bbl oil $/MBtu heat sulfur
Mills/kWh burned input removed
3.45
2.32
0.38
646
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Oil burned, 710 x 106 liters/yr (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79 C (175 F).
Sulfur removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $18,292,000; total depreciable investment, $33,930,000; and total
capital investment, $34,802,000.
All tons shown are 2,000 Ib.
E-26
-------
APPENDIX F
JET-BUBBLING LIMESTONE PROCESS
CHIYODA THOROUGHBRED 121 PROCESS
PROCESS DESCRIPTION
The Chiyoda Thoroughbred 121 process, shown in Figure F-l, is a forced-
oxidation limestone-scrubbing process which produces gypsum. It was devel-
oped from Chiyoda's dilute sulfuric acid process, the Thoroughbred 101.
Absorption, oxidation, and crystallization are accomplished in the same
reactor vessel. The flue gas is cooled in a presaturator chamber and fed to
the agitated jet-bubbling reactor. Air and a limestone slurry of 15% solids
are introduced to the reactor where S02 is absorbed from the flue gas, oxidized
to S04, and reacted with the limestone to form gypsum (calcium sulfate
dihydrate). A bleedstream containing the gypsum crystals is pumped to a
thickener. The thickener underflow containing 40% solids is filtered to
approximately 80% solids. The filter cake is conveyed to a storage area and
the filtrate is returned to the system for use in the wet ball mills. The
material balance and equipment list are shown in Tables F-l and F-2.
SPECIFIC PROCESS PREMISES
1. The reactor for absorption, oxidation, and neutralization is a Chiyoda
jet-bubbling reactor equipped with a presaturator and mist eliminator.
Pressure drop is 3.94k Pascals (15.8 inches H20). Complete oxidation
of absorber S02 to gypsum is assumed.
2. A stoichiometry of 1.0 mole of CaC03 to 1.0 mole S02 removed and 1.0
mole of CaC03 to 2.0 mole of HC1 removed is used.
ENERGY REQUIREMENTS
For base case conditions, reheat of the cleaned gas from 53°C to 79°C
requires 43.5 x 103 kg/hr (95,900 Ib/hr) of 243°C (470°F) steam at 3.55 x 103
kPa absolute pressure (500 psig) equivalent to about 18.16 x 10^ kcal/hr.
The electrical power demand for the Chiyoda Thoroughbred 121 process,
base case, is estimated to be about 8,090 kW or 1.6% of the rated production
of a 500-MW power plant. For 6,000 hours of operation, the annual electrical
energy consumption is 48.5 x 10^ kWh.
F-l
-------
The total equivalent energy consumption for the base case is approxi-
mately 38.53 x 106 kcal/hr or 3.4% of the input energy required for the 500-MW
power unit. Summarized energy requirements for all cases are listed in
Table F-3.
BYPRODUCT MANAGEMENT
ESP units remove 99.2% of the fly ash from the flue gas and, therefore,
only a small amount of fly ash is found in the FGD process byproduct. (Fly
ash emission from oil-fired units does not exceed the EPA particulate emission
standard and fly ash collection facilities are not included in oil-fired
power plant design.) Projected mass flow rates of byproduct for the base
case are shown below.
Component kg/hr Ib/hr
CaS04-2H20 27,751 61,180
CaCl2 456 1,005
Mg 27 60
Fly ash 149 329
Inerts 884 1,948
29,267 64,522
The process is evaluated on the basis of 30-day storage of salable gypsum
byproduct. A 0.4 hectare (one-acre) storage area has been provided for base
case and all fuel variation estimates.
ECONOMIC EVALUATION
Capital investment and annual revenue requirements for the base case and
five fuel variations are shown in Tables F-4 and F-5. The detailed results
are shown in Tables E-6 through F-17. The estimated accuracy ranges of the
economic analysis are shown in Figures F-2 and F-3. The effect of fuel
content on costs is shown in Figure F-4.
F-2
-------
E
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F-3
-------
TABLE F-l. CHIYODA THOROUGHBRED 121 PROCESS
MATERIAL BALANCE - BASE CASE (3.5% S COAL)
1
2
J
4
5
h
7
8
9
10
Stream No.
Description
Total stream, 1000 kg/hr
Total streamf Ib/hr
Gas flow, Nm-Vhr (0°C)
Gas £lo«, sft3/min(60°F)
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Particulates, kg/hr
Particulates, Ib/hr
1
Coal to boiler
194
428,600
2
Combustion air
to air heater
2,062
4,546,200
1,615,700
1,005,000
27
3
Gas to
absorber-
2,225
4,906,000
1,697,700
1,056,000
149
199.1
439
4
2,387
5,262,600
1,867,800
1,161,900
39.7
10.5
53
49.8
110
5
Gas to stack
2,387
5,262,600
1,870,700
1,163,700
79
49.8
110
Stream No.
Description
1
2
1
4
5
6
7
8
9
Iff
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, NmJ/hr (0°C)
Gas flow, sft3/min(60°F)
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Pressure, kPa (abs)
Pressure, psig
Bulk density, kg/mj
6
Steam to
reheater
44
95,900
243
3,550 x 103
500
7
Makeup water
to absorber-
reactor
120
265,000
2,004
530
8
Limestone
to system
18
40,159
9
Air to
absorber-
reactor
68
148,900
52,800
32,900
10
Product gypsum
36
79,400
1,360 (80% sol)
h
7
a
9
10
ft
7
8
9
10
F-4
-------
TABLE F-2. CHIYODA THOROUGHBRED 121 PROCESS
BASE CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area
1.
2.
3.
1 — Materials
Item
Handling
No.
Car shaker 1
Car puller 1
Hopper, limestone 1
Description
Top mounting with crane
25 hp puller, 5 hp return
12 ft x 20 ft x 2 ft bottom
Area size-cost
exponent 0.73
Total Total
material labor
cost, cost,
1979 $ 1979 $
9,000 2,100
50,000 2,100
, 9,300 8,700
unloading
4. Feeder, limestone 1
unloading
5. Conveyor, lime- 1
stone unloading
6. Conveyor, lime-
stone stocking
(incline)
7. Conveyor, lime-
stone stocking
8. Tripper 1
9. Mobile equipment 1
10. Hopper, reclaim 2
11. Feeder, live
limestone
storage
20 ft deep, 4,800 ft3,
carbon steel
Vibrating pan, 42 in. wide 4,800 1,100
x 60 in. long, 3 hp, 250
ton/hr
Belt, 36 in. wide x 10 ft 2,200 1,000
long, 5 hp, 250 ton/hr,
130 ft/min
Belt, 36 in. wide x 320 ft 48,000 15,400
long, 30 hp, 15° slope, 250
ton/hr, 130 ft/min
Belt, 36 in. wide x 200 ft 30,000 10,100
long, 7-1/2 hp, 250 ton/hr,
130 ft/min
1 hp, 30 ft/min 14,800 2,800
Scraper tractor, 22-24 181,000
yd- capacity
7 ft x 7 ft, 4 ft deep, 10,700 1,900
60° slope, carbon steel
Vibrating pan, 24 in. wide 7,000 2,100
x 40 in. long, 1 hp, 15
ton/hr
(continued)
F-5
-------
TABLE F-2. (continued)
Item No.
Total
material
cost,
Description 1979 $
Total
labor
cost,
1979 $
12. Pump, tunnel sump 2
13. Conveyor, live
limestone feed
14. Conveyor, live
limestone feed
(incline)
15. Elevator, live
limestone feed
16. Bin, crusher
feed
17. Dust collecting
system
18.
19.
Dust collecting
system
Dust collecting
system
Vertical, 60 gpm, 70 ft
head, 5 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Belt, 30 in. wide x 100 ft
long, 2 hp, 100 ton/hr,
60 ft/min
Belt, 30 in. wide x 190 ft
long, 5 hp, 35 ft lift,
100 ton/hr, 60 ft/min
Continuous, bucket, 12 in.
x 8 in. x 11-3/4 in., 20
hp, 75 ft lift, 100 ton/hr,
160 ft/min
13 ft dia x 21 ft high,
w/cover, 3/8 in. carbon
steel
Cyclone, 2,100 aft3/min,
motor-driven fan
Cyclone, 6,200 aft3/min,
motor-driven fan
Bag filter, polypropylene
bag, 14,400 aft3/min,
automatic shaker system
(1/2 cost in feed prepara-
tion area)
6,800
14,400
26,600
30,800
10,900
5,900
14,200
12,000
Subtotal
1,600
5,100
9,900
1,800
15,700
4,800
11,100
28,200
488.400 125,500
(continued)
F-6
-------
TABLE F-2. (continued)
Area 2—Feed Preparation
Area size-cost
exponent 0.70
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Discharge, feeder 2
bin
2. Feeder, crusher 2
3. Crusher
4. Ball mill
Ball charge
5. Hoist
6. Tank, mills
product
Lining
7. Agitator, mills
product tank
8. Pump, mills
product tank
Vibrating, 10 ton/hr, 19,500 4,200
carbon steel
Weigh belt, 18 in. wide 15,800 2,000
x 14 ft long, 1-1/2 hp,
10 ton/hr
Gyratory, 0 x 1-1/2 to
3/4 in., 50 hp, 10 ton/hr
Wet, open system, 8 ft
dia x 13 ft long, 350 hp,
300 ton/day
Electric, 5 tons, 7-1/2
hp,
82,200 11,700
424,500 35,200
31,100
8,300 2,100
6-1/2 ft dia x 7 ft high, 900 1,800
1,740 gal, open top, four
6-1/2 in. baffles, agitator
supports, carbon steel
(20 min residence time)
1/4 in. neoprene lining
2 turbines, 22 in. dia,
3 hp, neoprene coated
1,000 1,300
6,200 700
Centrifugal, 80 gpm, 60 3,800 1,200
ft head, 5 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
(continued)
F-7
-------
TABLE F-2. (continued)
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
9. Dust collecting
system
10. Dust collecting
system
Subtotal
Cyclone, 8,200 aft3/min, 16,300 12,700
motor-driven fan
Bag filter, 14,400 aft3/min, 12,000 28,200
automatic shaker system
(1/2 cost in materials
handling area) __
621,600 101.100
Area 3—Gas Handling
Area size-cost
exponent 0.68
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Fans
Subtotal
Forced draft, 22 in.
static head, 875 rpm,
2,000 hp, fluid drive,
double width, double
inlet
1,811,300 118,100
1.811.300 118.100
Area 4—S02 Absorption-Oxidation-Neutralization
Area size-cost
exponent 0.90
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Reactor, jet
bubbling
Presaturator
Agitator
Mist eliminator
Proprietary
Proprietary
Proprietary
Proprietary
(continued)
F-8
-------
TABLE F-2. (continued)
Item No.
2. Compressor, 4
oxidation air
3. Pump, jet
bubbling reactor
underflow
4. Tank, clarified 1
water
Lining
5. Pump, clarified 2
water tank
6. Tank, slurry 1
feed
Lining
7. Agitator, slurry 1
Total
material
cost,
Description 1979 $
Proprietary
Proprietary
10-1/2 ft dia x 12 ft 2,300
high, 7,800 gal, open
top, carbon steel
(10 min residence time)
1/4 in. neoprene lining 2,400
Centrifugal, 690 gpm, 10,800
100 ft head, 40 hp,
carbon steel, neoprene
lined
(1 operating, 1 spare)
34-1/2 ft dia x 35-1/2 25,400
ft high, 248,300 gal,
open top, four 34-1/2 in.
baffles, agitator supports,
carbon steel
(8 hr residence time)
1/4 in. neoprene lining 25,900
138 in. dia, 60 hp, 54,700
Total
labor
cost,
1979 $
4,400
2,900
3,700
47,600
31,700
4,100
feed tank
8. Pump, slurry
feed tank
9. Pump, makeup
water
neoprene coated
Centrifugal, 465 gpm,
60 ft head, 20 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
Centrifugal, 481 gpm, 200
ft head, 50 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
(continued)
8,600
23,000
3,000
6,300
F-9
-------
TABLE F-2. (continued)
10.
Area
1.
Item
Soot blowers
Subtotal
5 — Reheat
Item
Reheater
Total Total
material labor
cost, cost,
No. Description 1979 $ 1979 $
40 Air, retractable 260,000 225,800
Area size-cost
exponent 0.75
Total Total
material labor
cost, cost,
No. Description 1979 $ 1979 $
4 Steam, tube type, 3,700 856,000 39,200
2. Soot blowers
20
one-half of tubes
made of Inconel 625 and
one-half made of Cor-Ten
Air, retractable
130.000 112.900
Subtotal
Area 6 — Solids Separation and Storage
Item No. Description
1. Thickener 1 Carbon steel tank, 70 ft
986.000 152.100
Area size-cost
exponent 0.56
Total Total
material labor
cost, cost,
1979 $ 1979 $
27,700 67,900
Lining
Rake motor and
mechanism
dia x 8 ft high, 230,300
gal, concrete basin, 4 ft
high
1/4 in. neoprene lining
5 hp
(continued)
8,700
256,500
10,600
85,500
F-10
-------
TABLE F-2. (continued)
Item
2. Pump, thickener
No.
2 Gen
Description
itrifugal, 530 gpm, 60
Total
material
cost,
1979 $
8,600
Total
labor
cost,
1979 $
3,000
underflow
3. Pump, thickener 2
underflow
4. Filter, rotary 2
drum
5. Pump, filtrate
6. Conveyor,
filtercake
7. Conveyor, incline 1
8. Pump, stack sump 2
9. Mobile equipment 1
Subtotal
ft head, 20 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
Centrifugal, 240 gpm, 100
ft head, 20 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
Including vacuum pumps,
filtrate pumps, filtrate
receiver
Centrifugal, 190 gpm, 60
ft head, 7-1/2 hp, carbon
steel, neoprene lined
Belt, 18 in. wide x 50 ft
long, 1/2 hp, 40 ton/hr,
100 ft/min
Belt, 18 in. wide x 100 ft
long, 3 hp, 40 ton/hr,
100 ft/min
Centrifugal, 160 gpm, 100
ft head, 10 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
Front-end loader, 23
yd3/hr
8,600
7,700
9,800
23,400
7,700
80,000
3,000
255,500 25,900
2,900
3,900
4,800
1,500
694.200 209.000
F-ll
-------
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F-12
-------
TABLE F-4. CHIYODA THOROUGHBRED 121 PROCESS
CAPITAL INVESTMENT
Total capital investment
Case
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
$
47,017,000
42,002,000
42,007,000
43,819,000
42,095,000
38,532,000
$/kW
94
84
84
88
84
77
TABLE F-5. CHIYODA THOROUGHBRED 121 PROCESS ANNUAL REVENUE REQUIREMENTS
Case
Mills/kWh
$/ton coal
(bbl oil)
burned
$/MBtu heat
input
$/ton
S removed
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
12,160,100
10,948,500
10,919,500
11,360,700
10,998,700
10,219,200
4.05
3.
3,
3.
.65
.64
,79
3.67
3.41
9.46
7.70
10.19
9.26
6.44
2.29
0.45
0.41
0.40
0.42
0.41
0.38
356
1,372
921
605
1,893
638
F-13
-------
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CASE VARIATIONS IDENTIFIED BY FUEL TYPE AND SULFUR CONTENT OF FUEL, %
Figure F-2. Chiyoda 121 process capital investment range.
O O O 0
^O CN OO -*
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IVIIdVO
F-14
-------
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§ 40
w
W
I 30
H
W3
W
20
10
T
500-MW units
90% S02 removal
• Oil-fired unit
X Revenue requirements
• Capital investment
X Oil-fired unit
10
20
30
40
SULFUR REMOVED, k SHORT TONS/YR
Figure F-4. Chiyoda 121 process. Effect of sulfur removed
on capital investment and annual revenue requirement.
F-16
-------
TABLE F-6. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 3.5% S in coal;
90% SOi removal; gypsum production)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to reactor, exhaust gas ducts and dampers
from reactor to reheater and stack)
S02 absorption, oxidation, and neutralization (four jet bubbling
reactors including presaturators and entrainment separators,
compressors, tanks, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids separation and storage (thickener, filters, conveyors,
pumps, and front-end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment , $
1,824,000
1,670,000
5,526,000
12,166,000
1,292,000
1,486,000
23,964,000
1,438,000
25,402,000
40,000
25,442,000
1,011,000
251,000
3,673,000
1.123.000
6,058,000
6,300.000
37,800,000
3,776,000
4,536,000
46,112,000
42,000
863,000
47,017,000
% of
total ilirect
investment
7.2
6.6
21.7
47.8
5.1
5.8
94.2
5.7
99.8
0.2
100.0
4.0
1.0
14.4
4.4
23.8
24.8
148.6
14.8
17.8
181.2
0.2
3.4
184.8
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
F-17
-------
TABLE F-7. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; gypsum production)
Direct Costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of net average
annual revenue
requirements
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
115,200 tons
7.00/ton
26,060 man-hr 12.50/man-hr
432,400 MBtu
190,600 kgal
48,539,000 kWh
2.00/MBtu
0.12/kgal
0.029/kWh
3,220 man-hr 17.00/man-hr
806,400
806,400
325,800
864,800
22,900
1,407,500
1,525,300
54,700
4,201,100
5,007,500
6_. 63
6.63
2.68
7.11
0.19
11.58
12.54
0.45
34.55
41.18
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion v.osts less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Byproduct gypsum 238,190
Net average annual revenue requirements
Equivalent unit revenue requirements (net)
2,766,700
4.043,500
952,900
32,600
7l.sno
7,867,200
12,874,700
tons 3.00/ton (714.600)
12,160,100
$/ton coal $/MBtu heat
Mills/kWh burned input
4.05 9.46 0.45
22.75
33.25
7.84
0.27
0.59
64.70
105.88
(5.88)
100.00
$/ton
S removed
356
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,221 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 30,947 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $25,442,000; total depreciable investment, $46,112,000; and total
capital investment, $47,017,000.
All tons shown are 2,000 Ib.
F-18
-------
TABLE F-8. CHITODA THOROUGHBRED 121 PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 0.8% S in coal;
90% S02 removal; gypsum production)
Direct Investment
Materials handling (hoppers, fpedprs, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to reactor, exhaust gas ducts and dampers
from reactor to reheater and stack)
S02 absorption, oxidation, and neutralization (four jet bubbling
reactors including presaturators and entrainment separators,
compressors, tanks, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids separation and storage (thickener, filters, conveyors,
pumps, and front-end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, S
631,000
605,000
5,620,000
12,434,000
1,315,000
658.000
21,263,000
1,276,000
22,539,000
40,000
22,579,000
1,011,000
251,000
3,327,000
l,026,nnn
5,615,000
5.639.000
33,833,000
3,379,000
4,060,000
41,272,000
42,000
688,000
42, 002 ,-000
% of
total direct
investment
2.8
2.7
24.9
55.1
5.8
2.9
94.2
5.6
99.8
0.2
100.0
4.5
1.1
14.7
24.8
25.0
149.8
15.0
18. p
182.8
0.2
3.0
186.0
a. Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
F-19
-------
TABLE F-9. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICSa
(500-MW new coal-fired power unit, 0.8% S in coal;
90% S02 removal; gypsum production)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
26,900 tons 7.00/ton
26,060 man-hr 12.50/man-hr
443,000 MBtu 2.00/MBtu
179,900 kgal 0.12/kgal
45,810,100 kWh 0.029/kWh
1,350 man-hr 17.00/man-hr
Total % of net average
annual annual revenue
cost, $ requirements
188,300
188,300
325,800
886,000
21,600
1,328,500
1,353,500
23,000
3,938,400
4,126,700
1
1
2,
8
0,
12
12.
0,
35.
37.
.72
.72
.98
.09
.20
.13
.36
.21
.97
,69
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 5'0% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,476,300
3,612,100
851,200
32,600
16.700
6,988,900
11,115,600
22.62
32.99
7.77
0.30
0.15
63.83
101.52
Byproduct Sales Revenue
Byproduct gypsum 55,685 tons
Net average annual revenue requirements
3.00/ton
(167,100)
10,948,500
(1.52)
100.00
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
3.65 7.70 0.41 1,372
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,288,938 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 7,238 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,579,000; total depreciable investment, $41,272,000; and total
capital investment, $42,002,000.
All tons shown are 2,000 Ib.
F-20
-------
TABLE F-10. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 1.4% S in coal;
90% S02 removal; gypsum production)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to reactor, exhaust gas ducts and dampers
from reactor to reheater and stack)
S02 absorption, oxidation, and neutralization (four jet bubbling
reactors including presaturators and entralnment .separators,
compressors, tanks, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids separation and storage (thickener, filters, conveyors,
pumps, and front-end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
843,000
767,000
5,487,000
12,057,000
1,283,000
822,000
21,259,000
<« 1,276,000
f*
22,535,000
40,000
22,575,000
1,011,000
251,000
3,326,000
1.026rOOO
5,614,000
5.638,000
33,827,000
3,379,000
4.059.000
41,265,000
42,000
700.000
42,007,000
% of
total direct
investment
3.7
3.4
24.3
53.4
5.7
3.6
94.2
5.6
99.8
0.2
100.0
4.5
1.1
14.7
24.8
149.8
15.0
18 .0
182.8
0.2
186.1
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
F-21
-------
TABLE F-ll. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 1.4% S in coal;
90% S02 removal; gypsum production)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
40,000 tons 7.00/ton
26,060 man-hr 12.50/man-hr
428,200 MBtu 2.00/MBtu
176,200 kgal 0.12/kgal
44,891,500 kWh 0.029/kWh
1,710 man-hr 17. 00 /man-hr
Total % of net average
annual annual revenue
cost, $ requirements
280,000
280,000
325,800
856,400
21,100
1,301,900
1,353,300
29,100
3,887,600
4,167,600
2.
2.
2.
7.
0.
11.
12.
0.
35.
38.
56
56
98
84
19
92
40
27
60
16
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,475,900
3,612,600
854,100
32,600
24 ..800
7,000,000
11,167,600
22.67
33.09
7.82
0.30
0.23
64.11
102.27
Byproduct Sales Revenue
Byproduct gypsum
Net average annual
Equivalent unit revenue
82,700*
revenue requirements
requirements (net)
tons 3.00/ton
10
$/ton coal
Mills/kWh burned
3.64 10.19
(248,100)
,919,500
$/MBtu heat
input
0.40
(2.27)
100.00
$/ton
S removed
921
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,941 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 10,748 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,575,000; total depreciable investment, $41,265,000; and total
capital investment, $42,007,000.
All tons shown are 2,000 Ib.
F-22
-------
TABLE F-12. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new coal-fired power unit, 2.0% S in coal;
90% S02 removal; gypsum production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to reactor, exhaust gas ducts and dampers
from reactor to reheater and stack)
S02 absorption, oxidation, and neutralization (four jet bubbling
reactors including presaturators and entrainment separators,
compressors, tanks, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids separation and storage (thickener, filters, conveyors,
pumps, and front-end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
1,180,000
1,101,000
5,504,000
12,105,000
1,287,000
1,064,000
22,241,000
1,334,000
23,575,000
40,000
23,615,000
1,011,000
251,000
3,453,000
1.061.000
5,776,000
5.878..000
35,269.000
3.523,000
4.232,000
43,024,000
42,000
753^000
43,819,000
5.0
4.7
23.3
51.3
5.4
4.5
94.2
5.6
99.8
0.2
100.0
4.3
1.1
14.6
4.5
24.5
24.9
149.4
14.9
17.9
182.2
0.2
iLJ
185.6
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
F-23
-------
TABLE F-13. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new coal-fired power unit, 2.0% S in coal;
90% S02 removal; gypsum production)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
63,400 tons 7.00/ton
26,060 man-hr 12.50/man-hr
430,200 MBtu 2.00/MBtu
180,900 kgal 0.12/kgal
46,094,900 kWh 0.029/kWh
2,250 man-hr 17.00/man-hr
Total % of net average
annual annual revenue
cost, $ requirements
443
443
325
860
21
1,336
1,415
38
3,998
4,442
,800
,800
,800
,400
,700
,800
,700
^300
,700
,500
3.90
3.90
2.87
7.57
0.19
11.77
12.46
_oa4_
35.20
39.10
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,581
3,768
889
32
39
7,311
11,754
,400
,400
,900
,600
V400
,700
,200
22.72
33.17
7.83
0.29
0.35
64.36
103.46
Byproduct Sales Revenue
Byproduct gypsum
Net average annual
Equivalent unit revenue
131,170
revenue requirements
requirements (net)
tons 3.00/ton _
11
$/ton coal
Mills/kWh burned
3.79 9.26
(393.500)
,360,700
$/MBtu heat
input
0.42
(3.46)
100.00
$/ton
S removed
605
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,113,161 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 17,043 metric tons/yr (18,790 short tons/yr).
Investment and revenue requireme'nt for removal and disposal of fly ash excluded.
Total direct investment, $23,615,000; total depreciable investment, $43,024,000; and total
capital investment, $43,819,000.
All tons shown are 2,000 Ib.
F-24
-------
TABLE F-14. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENTa
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% S02 removal; gypsum production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to reactor, exhaust gas ducts and dampers
from reactor to reheater and stack)
S02 absorption, oxidation, and neutralization (four jet bubbling
reactors including presaturators and entrainment separators,
compressors, tanks, and pumps)
Stack gas reheat (four indirect steam reheaters)
Solids separation and storage (thickener, filters, conveyors,
pumps, and front-end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
502,000
484,000
5,714,000
12,726,000
1,341,000
551.000
21,318,000
1,279,000
22,597,000
40,000
22,637,000
1,011,000
251,000
3,334,000
1,028,000
5,624,000
5,652,000
33,913,000
3,387,000
C4, 070, 000
41 ,370,000
42,000
683,000
42,095,000
2.
2.
25.
56.
5.
2.
94.
5.
99.
0.
100.
4.
1.
14.
4^
24.
Ji^
149.
15.
JA
182.
0.
3_
186.
2
1
2
3
9
4
1
7
8
2
0
5
1
7
i
8
H
8
0
H
8
2
_0
0
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
F-25
-------
TABLE F-15. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90X S02 removal; gypsum production)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
19,600 tons 7.00/ton
26,060 man-hr 12.50/man-hr
454,500 MBtu 2.00/MBtu
183,100 kgal 0.12/kgal
46,635,800 kWh 0.029/kWh
1,110 man-hr 17.00/man-hr
Total % of net average
annual annual revenue
cost, $ requirements
137,200
137,200
325,800
909,000
22,000
1,352,400
1,357,000
18,900
3,985,100
4,122,300
1.
1.
2.
8.
0.
12.
12.
0.
36.
37.
25
25
96
26
20
30
34
17
23
48
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of .total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
2,482,200
3,620,200
850,900
32,600
12,200
6,998,100
11,120,400
22.57
32.91
7.74
0.30
0.11
63.63
101.11
Byproduct Sales Revenue
Byproduct gypsum 40,560 tons
Net average annual revenue requirements
3.00/ton
(121.700)
10,998,700
(1.11)
100.00
$/ton lignite $/MBtu heat $/ton
Mills/kWh burned input S removed
Equivalent unit revenue requirements (net)
3.67
6.44
0.41
1,893
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Lignite burned, 1,549,882 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 5,270 metric tons/yr (5,810 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,637,000; total depreciable investment, $41,370,000; and total
capital investment, $42,095,000.
All tons shown are 2,000 Ib.
F-26
-------
TABLE F-16. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT3
(500-MW new oil-fired power unit, 2.5% S in oil;
907, S02 removal; gypsum production)
Direct Investment
Materials handling (hoppers, feeders, conveyors, elevator, bins,
shaker, and puller)
Feed preparation (feeders, crushers, ball mills, hoist, tanks,
agitators, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to reactor, exhaust gas ducts and dampers
from reactor to reheater and stack)
S02 absorption, oxidation, and neutralization (four jet bubbling
reactors including presaturators and entrainment separators,
compressors, tanks, and pumps)
Stack gas reheat (four direct oil-fired reheaters)
Solids separation and storage (thickener, filters, conveyors,
pumps, and front-end loader)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding gypsum field
Gypsum field construction
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modification
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
1,051,000
984,000
4,879,000
10,317,000
1,127,000
973,000
19,331,000
1,160,000
20,491,000
40,000
20,531,000
1,011,000
251,000
3,075,000
9 54 ,.000
5,291,000
5,164,000
30,986,000
3,095,000
3,718,000
37,799,000
42,000
691,000
38,532,000
% of
total direct
investment
5.1
4.8
23.8
50.3
5.5
4.7
94.2
5.6
99.8
0.2
100.0
4.9
1.2
15.0
4.6
25.7
25.2
150.9
15.1
18.1
184.1
0.2
3.4
187.7
a. Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by direct oil-fired reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
F-27
-------
TABLE F-17. CHIYODA THOROUGHBRED 121 PROCESS
SUMMARY OF AVERAGE ANNUAL REVENUE REQUIREMENTS - REGULATED UTILITY ECONOMICS3
(500-MW new oil-fired power unit, 2.5% S in oil;
90% S02 removal; gypsum production)
Direct Costs
Raw materials
Limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual Unit
quantity cost, $
54,100 tons 7.00/ton
26,060 man-hr 12.50/man-hr
2,500,000 gal 0.40/gal
151,700 kgal 0.12/kgal
38,719,500 kWh 0.029/kWh
2,050 man-hr 17.00/man-hr
Total % of net average
annual annual revenue
cost, $ requirements
378,700
378,700
325,800
1,000,000
18,200
1,122,900
1,230,700
34,900
3,732,500
4,111,200
3.71
3.71
3.19
9.78
0.18
10.99
12.04
0.34
36.52
40.23
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross average annual revenue requirements
Byproduct Sales Revenue
Byproduct gypsum 111,830 tons 3.00/ton
Net average annual revenue requirements
$/bbl oil
Mills/kWh burned
Equivalent unit revenue requirements (net) 3.41 2.29
2,267,900
3,313,800
795,700
32,600
33,500
6,443,500
10,554,700
(335.500)
10,219,200-
$/MBtu heat
input
0.38
22.19
32.43
7.78
0.32
0.33
63.05
103.28
(3.28)
100.00
$/ton
S removed
638
a. Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Oil burned, 710 x 10^ Hters/yr (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct'investment, $20,531,000; total depreciable investment, $37,799,000; and total
capital investment, $38,532,000.
All tons shown are 2,000 Ib.
F-28
-------
APPENDIX G
MAGNESIUM OXIDE PROCESS
PROCESS DESCRIPTION
The magnesium oxide process is an absorbent-regenerating process
which produces sulfuric acid. The flue gas is scrubbed with an MgO slurry,
producing MgS03 and MgSO^, which are dried and calcined to regenerate S02
and MgO. The S02 is processed to sulfuric acid and the MgO is returned to
the system. The process flow diagram is shown in Figure G-l. The base-case
material balance and equipment list are shown in Tables G-l and G-2. A
spray grid absorber with a chloride scrubber and mist eliminator is used.
Makeup and regenerated MgO are slurried into a bleedstream of liquor from
the absorber and recycled to the absorber. Humidification losses are added
as a fresh water upstream wash for the mist eliminator.
Effluent from the absorber, containing approximately 15% solids, is
pumped to two parallel centrifuges to separate the solids from the liquor.
The centrate is returned to the absorber system. The centrifuge cake is
dried in an oil-fired rotary dryer. The dryer off-gas is cleaned in a
cyclone and fabric dust collector. A portion of the gas is recycled to the
dryer combustion chamber for temperature control and the remainder is
routed to the absorbers.
The discharge from the dryer and filters is transferred to an oil-
fired fluid-bed calciner which contains a single calcination bed operating
at 871°C (1600°F). The calciner off-gas, containing S02, is partially
cleaned in a cyclone, cooled to about 371°C (700°F) in a waste heat boiler,
and fed to a fabric filter for final cleaning before entering the sulfuric
acid unit. The MgO collected in the cyclone and bag filter is returned to
the absorber feed preparation system.
A complete 390 metric ton/day contact sulfuric acid plant is provided
for production of 98% acid from the S02 gas. The sulfuric acid is stored
in 30-day-capacity tanks. Tail gas from the acid plant is recycled to the
absorber.
G-l
-------
SPECIFIC PROCESS PREMISES
1. The flue gas is assumed cooled from 149°C (300°F) to 53°C (127°F)
and saturated in the presaturator chloride scrubber. The pre-
saturator chloride scrubber L/G ratio is 0.5 liter/ra3 (4 gal/103 aft3)
2. A mobile-bed absorber with a superficial velocity of 3.8 m/sec
(12.5 ft/sec) and a pressure drop, including the mist eliminator,
of 1.99 kPa (8 inches H20). The absorber L/G ratio is 3 liters/m3
(20 gal/aft3).
3. The stoichiometry is 1.05 moles of MgO to 1.0 mole of S02 removed.
ENERGY REQUIREMENTS
For base-case conditions, reheat of the cleaned gas from 53°C to 79°C
requires 43.4 x 103 kg/hr (95,700 Ib/hr) of 243°C (470°F) steam at 3.55 x
10* kPa absolute pressure (500 psig) equivalent to about 18.12 x 106 kcal/hr.
The electrical power demand for the base-case magnesium oxide process
is about 9,109 kW or 1.8% of the rated output of a 500-MW power plant. For
6,000 hours of operation, the annual electrical energy consumption is
54.65 x 106 kWh.
Fuel oil provides energy for the dryer and calciner. The total fuel
oil consumption of approximately 3,690 liters/hr (975 gal/hr) is equivalent
to 33.78 x 106 kcal/hr.
Waste heat is recovered in the acid production area and in the cal-
cining area to produce 5.76 x 103 kg/hr (12,700 Ib/hr) of 186°C (367°F)
steam at 1.14 x 10^ kPa absolute pressure (150 psig). This steam is
equivalent to 3.6 x 10^ kcal/hr and is considered a heat credit in the
determination of total equivalent energy consumption.
The total equivalent energy consumption for the base case is approxi-
mately 70.97 Mkcal/hr or 6.26% of the input energy required for the 500-MW
power unit. Summarized energy requirements for all cases are listed in
Table G-3.
BYPRODUCT MANAGEMENT
ESP units remove 99.2% of the fly ash from the flue gas and, therefore,
only a small amount of fly ash is found in the chloride scrubber effluent.
(Fly ash emission from oil-fired units does not exceed the EPA particulate
emission standard and fly ash collection facilities are not included for
these units.) Projected mass flow rates of the byproducts for the base
case are shown below. HC1, SO^, and ash are collected in the chloride
scrubber and disposed of in the ash pond.
G-2
-------
Component Kg/hr Lb/hr
Product acid: 98% H2S04 16,300 35,900
Chloride purge: HC1 290 630
803 40 80
Ash 150 330
The process is evaluated on the basis of 30-day storage of 98% sulfuric
acid byproduct. Two 3,250 m? (858,000 gal) carbon steel tanks have been
provided for the base-case design.
ECONOMIC EVALUATION
Capital investment and annual revenue requirement summaries for the
magnesium oxide process are shown in Tables G-4 and G-5. Detailed results
are shown in Tables G-6 through G-17. The results, showing the estimated
ranges of accuracies, are also shown in Figures G-2 and G-3. The costs in
terms of sulfur removed are shown in Figure G-4.
G-3
-------
I
00
cfl
g
M-l
CO
CO
CJ
o
i-l
ex
0)
-o
•H
X
o
CO
0)
a
o
-------
TABLE G-l. MAGNESIUM OXIDE PROCESS
MATERIAL BALANCE - BASE CASE (3.5% SULFUR COAL)
Stream No.
Description
1
i
t
/,
3
d
7
K
9
10
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, Nm^/hr (0°C)
Gas floWj sftj/min (60°F
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Particulates, kg/hr
Participates, Ib/hr
1
Coal to boiler
194
428,600
2
Combustion air
to air heater
2,062
4,546,200
1,615,700
1,005,000
27
3
Flue gas
to chloride
scrubber
2,225
4,906,000
1,697,700
1.056,000
149
199.1
439
4
Gas to reheater
2,407
5^306^000
1,883,900
1.171.900
40.1
10.6
53
49.8
110
5
Gas to stack
2,407
5,306,000
1^86,800
1.173,800
79
49.8
110
Stream Wo.
Description
1
1
1
4
ri
ft
1
K
9
IP,
Total stream^ 1000 kg/hr
Total stream, Ib/hr
Gas flow, NmJ/hr (0°C)
Gas flow, sftJ/min (60°F
Liquid flow^ liters/min
Liquid flow, gal/min
Temperature, °C
Pressure, Pascals (abs)
Pressure, psig
Specific gravity
6
Steam to
reheater
43.4
95,700
243
3.55 x 10&
500
7
Process
makeup water
110
241,500
1,827
483
8
Magnesium
oxide to
preparation
facilities
.2
480
9
Limestone to
neutralization
tank
.4
9iO
10
Combustion air
to dryer and
calciner
62
136.600
48,500
30.200
27 ..
Stream No.
Description
1
>
)
4
ri
h
I
8
9
10
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, NmJ/hr (0°C)
Gas flow, sftj/min (60°F
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Pressure, Pascals (abs)
Pressure, psig
Specific gravity
11
Fuel oil to
dryer and
calciner
3.2
7,100
60
16
0.91
12
Dryer off-gas
66
146,500
61^060
37,980
204
13
Steam from heat
recovery
facilities
5.8
12,700
186
1.14 x 106
150
14
Oxidation air
for sulfuric
acid productioi
35
77,000
26,200
16,300
27
15
Acid plant
off-gas
47
102,400
35,370
22,000
71
Stream No.
1
i
1
4
'i
6
/
«
9
IU
Description
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, Nmi/hr (0°C)
Gas flow, sft-Vmin (60°F
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, UC
Pressure, Pascals ^abs)
Pressure, psig
Specific gravity
16
Cooling water
to acid plant
1,310
2,887,900
21,950
5,800
27
17
Boiler
feed water
5.8
12,700
95
25
38
18
Product
sulfuric acid
(98% H2S04)
16.3
35,900
150
40
1.82
G-5
-------
TABLE G-2. MAGNESIA SLURRY-REGENERATION PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area 1—Materials Handling
Area size-cost
exponent 0.64
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Conveyor, makeup
MgO
2. Silo, makeup MgO
storage
3. Bin, makeup MgO 1
feed
4. Feeder, makeup
MgO
5. Conveyor, recycle 1
MgO feed
6. Bin, recycle MgO 1
feed
7. Feeder, recycle 1
MgO
8. Car shaker
9. Conveyor, lime-
stone
10. Silo, limestone
storage
11. Bin, limestone
feed
1 Pneumatic, pressure, 100 hp
28 ft dia x 41 ft straight
side height, 25,250 ft3, 60°
slope, 3/8 in. carbon steel
10 ft dia x 14 ft straight
side height, w/cover, carbon
steel
Vibrating screw, 8 in. dia x
4 ft long, 1 hp, 1,025 ft3/hr,
8 tons/hr
Pneumatic, pressure, 10 hp
10 ft dia x 14 ft straight
side height, w/cover, carbon
steel
Vibrating screw, 8 in. dia x
4 ft long, 1 hp, 1,025 ft3/hr,
8 tons/hr
Top mounting with crane
Pneumatic, pressure, 75 hp
19 ft dia x 29 ft straight
side height, 8,200 ft3, 60°
slope, 3/8 in. carbon steel
5-1/2 ft dia x 8-1/2 straight
side height, w/cover, carbon
steel
(continued)
80,000 20,000
30,300 69,000
3,300
5,500
5,500
9,000
51,800
5,500
500
43,000 20,000
3,300 5,500
500
2,100
12,200
13,000 33,000
1,500 2,200
G-6
-------
TABLE G-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
12. Tank, fuel oil
13. Pump, fuel oil
Subtotal
46 ft dia x 48 ft high,
596,800 gal, w/cover, carbon
steel
Centrifugal, 11 gpm, 200 ft
head, 2 hp, carbon steel
(1 operating, 1 spare)
53,700 99,900
3,500 1,300
303,400 271,700
Area 2—Feed Preparation
Area size-cost
exponent 0.51
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Preslaker mixer 1
2. Tank, slurry feed 1
Blade, 14 in. dia x 8 ft long, 6,200 1,000
5 hp
28 ft dia x 29 ft high, 133,600 18,400 33,600
gal, open top, four 28 in.
baffles, agitator supports,
carbon steel
(8 hr residence time)
Lining
3. Agitator, slurry 1
feed tank
4. Pump, MgO slurry 2
feed tank
Subtotal
1/4 in. neoprene lining
112 in. dia, 30 hp, neoprene
coated
Centrifugal, 310 gpm, 150 ft
head, 30 hp, carbon steel,
neoprene coated
(1 operating, 1 spare)
18,400
33,100
16,100
92,200
22,400
3,500
5,900
66,400
(continued)
G-7
-------
TABLE G-2 (continued)
Area 3—Gas Handling
Area size-cost
exponent 0.68
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Fans
Subtotal
Forced draft, 15 in., 890
rpm, 1,500 hp, fluid drive,
double width, double inlet
1,573,500 95,500
1,573,500 95.500
Area size-cost
exponent 0.79
— -_,
Item No. Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
1. S02 absorber
2. Tank, SO 4
absorber ^circu-
lation
Lining
Agitator, SO
absorber
recirculation
tank
Pump, SO
absorber recycle
Spray grid tower, 29 ft long
x 15 ft wide x 38 ft high,
1/4 in. carbon steel, neoprene
lining; FRP spray headers, 316
stainless steel chevron vane
entrainment separator
23 ft dia x 11-1/2 ft high,
35,700 gal, open top, four 23
in. baffles, agitator supports,
carbon steel
(10 min residence time)
1/4 in. neoprene lining
92 in. dia, 15 hp, neoprene
coated
Centrifugal, 3,230 gpm, 100 ft
head, 200 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
3,274,100 200,000
27,100 49,200
28,200 34,400
80,800 5,600
74,800 17,200
(continued)
G-8
-------
TABLE G-2 (continued)
Item
5 . Pump , makeup
water
6. Soot blowers
Subtotal
No. Description
3 Centrifugal, 926 gpm, 150 ft
head, 75 hp, carbon steel
(2 operating, 1 spare)
40 Air, retractable
Total
material
cost,
1979 $
50,400
260,000
3,795,400
Total
labor
cost,
1979 $
13,200
225,800
545,400
Area size-cost
Area 5 — Reheat
Item
1 . Reheater
No . Description
2
4 Steam, tube type, 3,754 ft ,
exponent
Total
material
cost,
1979 $
858,000
0.75
Total
labor
cost,
1979 $
41,200
one-half of tubes made of
Inconel 625 and one-half made
of Cor-Ten
2.
Area
Soot blowers 20 Air, retractable
Subtotal
6 — Chloride Removal
Item No. Description
130,000 112,900
988,000 154,100
Area size-cost
exponent 0.75
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Chloride scrubber 4
Venturi-spray chamber combina- 1,834,200 439,200
tion, Venturi: 13 ft dia x
25 ft overall height, variable
throat, carbon steel, elastomer
and tile lined, insulated
(continued)
G-9
-------
TABLE G-2 (continued)
Item No. Description
1. (continued) Spray chamber: 20 ft x 29
ft x 9 ft high, carbon steel,
elastomer and tile lined,
Hastelloy G nozzles with
stellite tips; Hastelloy G
mist eliminator
2. Tank, chloride 4 14 ft dia x 11 ft high,
recycle 12,700 gal, open top, four
14 in. baffles, agitator
supports, carbon steel
(10 min residence time)
Lining 1/4 in. neoprene lining
3. Agitator, 4 56 in. dia, 5 hp, neoprene
Total
material
cost,
1979 $
13,300
14,700
36,100
Total
labor
cost,
1979 $
25,400
17,900
3,400
chloride recycle
tank
4. Pumps, venturi
recirculation
5. Pumps, spray
chamber recircu-
lation
6. Feeder, lime-
stone feed bin
discharge
7. Tank, chloride
neutralization
Lining
8. Agitator, chlo-
ride neutrali-
zation tank
coated
Centrifugal, 3,140 gpm, 60 88,700 23,900
ft head, 100 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
Centrifugal, 3,140 gpm, 150 ft 159,400 28,300
head, 250 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
Weigh, screw, 6 in. dia x 5,300 200
10 ft long, 1 hp, 900 Ib/hr
13 ft dia x 11 ft high, 10,900
gal, open top, four 13 in.
baffles, carbon steel
(30 min residence time)
5,900 10,800
1/4 in. neoprene lining 4,000
64 in. dia, 7-1/2 hp, neo- 12,000
prene coated
(continued)
4,900
1,000
G-10
-------
TABLE G-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
9. Pump, chloride 2
purge
10. Pump, pond water 2
return
Subtotal
Centrifugal, 362 gpm, 200 ft
head, 40 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Centrifugal, 317 gpm, 150 ft
head, 25 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
21,100 6,200
18,200 6,100
2,212,900 567.300
Area 7—Slurry Processing
Area size-cost
exponent 0.68
Item
No,
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Centrifuge
2. Tank, centrate 1
Lining
3. Agitator, cen- 1
trate tank
4. Pump, centrate 2
5. Conveyor, dryer 1
feed
Subtotal
40 in. dia x 140 in. long,
solid bowl, stainless steel,
300 hp
15 ft dia x 7 ft high, 9,250
gal, open top, four 15 in.
baffles, agitator supports,
carbon steel
(10 min residence time)
1/4 in. neoprene lined
60 in. dia, 2 hp, neoprene
coated
Centrifugal, 950 gpm, 150 ft
head, 100 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Screw, 16 in. dia, 15 ft long,
5 hp, 45 tons/hr, carbon steel
654,000 70,000
2,600 5,000
2,900 3,500
4,600 600
23,200 7,500
4,400 1,500
691,700 88,100
(continued)
G-ll
-------
TABLE G-2 (continued)
Area 8 — Drying
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
Item No .
Dryer, MgS03 1
Fan, combustion 1
air
Conveyor, dryer 1
product
Conveyor, MgSO_ 1
Bin, MgS03 1
storage hold
Feeder, MgSO 1
storage
Conveyor, reserve 1
MgSO,. storage
Tripper 1
Bucket tractor, 1
mobile equipment
Hopper, MgS03 1
reserve storage
Feeder, reserve 1
MgS03
Conveyor, reserve 1
MgS03 feed
Silo, MgSO live 1
Area size-cost
exponent 0.53
Total
material
cost,
Description 1979 $
Rotary, 15 ft dia x 90 ft 1,299,300
long, 200 hp, carbon steel
Forced draft, 5 in. static 18,500
head, 24,900 aft3/min, 30 hp
Screw, 16 in. dia, 15 ft long, 4,400
15 hp, 20 tons/hr, carbon steel
Pneumatic, pressure, 100 hp 80,000
5 ft dia x 8 ft straight side 900
height, w/cover, carbon steel
Belt, 14 in. wide, 1 hp, 18 10,000
tons/hr
Belt, 14 in. wide x 100 ft 17,300
long, 2 hp, 18 tons/hr, 100
ft/min
5 hp, 30 ft/min 18,000
o
Scraper tractor, 1-1/2 yd 48,800
capacity
7 ft x 7 ft x 7 ft deep, 60° 400
slope, carbon steel
Rotary stargate, 2 hp, 50 7,900
tons/hr
Pneumatic, pressure, 100 hp 80,000
18 ft dia x 27 ft straight 13,800
Total
labor
cost,
1979 $
1,689,100
3,700
1,500
20,000
1,700
1,000
5,500
3,000
800
300
20,000
30,200
storage
14. Feeder, calciner 1
(enclosed)
side height, 6,900 ft3, 60°
slope, 3/8 in. carbon steel
Weigh belt, 18 in. wide, 1 hp,
18 tons/hr
(continued)
8,500
900
G-12
-------
TABLE G-2 (continued)
15.
16.
17.
18.
Item
Conveyor,
calciner feed
Dust collector
Dust collector
Fan, dryer
off-gas
Subtotal
No. Description
1 Belt, 18 in. wide x 10 ft
long, 1 hp, 18 tons/hr, 100
ft/min
3
1 Cyclone, 92,300 aft /min
1 Bag filter, 92,300 aft3/min
1 Induced draft, 23 in. static
head, 92,300 aft3/min, 500 hp
Total
material
cost,
1979 $
2,000
48,400
54,600
126,400
1,839,200 1
Total
labor
cost,
1979 $
800
5,600
13,700
25,300
,823,100
Area size-cost
Area
1.
9--Calcining
Item
Calciner
No . Description
1 Fluid bed, 13 ft x 40 ft high,
exponent
Total
material
cost,
1979 $
474,000
0.68
Total
labor
cost,
1979 $
393,200
2. Dust collector
3. Air preheater
4. Waste heat
boiler
5. Cooler, solids
6. Bin, MgO cooler
12 in. fire brick, 10 in.
insulating brick, carbon steel
shell
1 Multiclone, 49,800 aft3/min
1 Tube type, 10,650 ft2, 316L
stainless steel tubes, heads,
and shell
1 Tube type, 600 ft2, 316L
stainless steel tubes, heads,
and shell
1 Tubed shell type, 5,650 ft2,
6 ft dia x 50 ft long, 20 hp,
twenty-seven 3 in. tubes
1 6 ft dia x 7 ft straight side
height, w/cover, carbon steel
(continued)
64,400 7,000
143,900 143,900
21,900 21,900
248,000 25,000
1,000 1,800
G-13
-------
TABLE G-2 (continued)
7.
8.
9.
10.
Area
1.
Area
1.
Item No .
Dust collector 1
Blower, combus- 1
tion air
Conveyor, recycle 1
MgO
Silo, recycle MgO 1
storage
Vibrators 4
Subtotal
10—98% Sulfuric Acid
Item No .
Complete H-SO, 1
unit
Subtotal
11 — Acid Storage and
Item No.
Tanks, sulfuric 2
Description
Bag filter, 49,900 aft3/min,
Single-stage centrifugal,
7,400 aft3/min, 250 hp, 316
stainless steel
Pneumatic, pressure, 15 hp
43 ft dia x 65 ft straight
side height, 94,400 ft3, 60°
slope, 3/8 in. carbon steel
1/2 hp
Production
Description
Complete 98% sulfuric acid
unit, battery limits
Shipping
Description
53 ft dia x 52 ft high,
Total Total
material labor
cost, cost,
1979 $ 1979 $
39,300 9,800
123,900 37,200
31,300 8,000
69,200 160,700
5,400 1,200
1,222,300 809,700
Area size-cost
exponent 0.70
Total Total
material labor
cost, cost,
1979 $ 1979 $
6,576,000
6,576,000
Area size-cost
exponent 0.68
Total Total
material labor
cost, cost,
1979 $ 1979 $
213,100 330,500
acid storage
858,200 gal, w/cover, carbon
steel, insulated
(30 day capacity)
(continued)
G-14
-------
TABLE G-2 (continued)
Total Total
material labor
cost, cost,
Item No. Description 1979 $ 1979 $
2. Pump, tank 2 Centrifugal, 400 gpm, 100 ft 10,500 3,100
discharge head, 40 hp, carbon steel
(1 operating, 1 spare)
Subtotal 223.600 333,600
G-15
-------
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G-16
-------
TABLE G-4. MAGNESIUM OXIDE PROCESS CAPITAL INVESTMENT
Capital
investment
Case
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
$
68,434,000
48,926,000
52,043,000
58,108,000
47,115,000
44,591,000
$/kW
137
98
104
116
94
89
TABLE G-5. MAGNESIUM OXIDE PROCESS ANNUAL REVENUE REQUIREMENTS
Case
Annual revenue requirements
Mills/kWh
$/ton coal
(bbl oil)
burned
$/MBtu
heat
input
$/ton S
removed
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
17,546,000 5.85
12,949,500
13,651,200
15,114,300
12,573,900
11,984,600
4.
4.
5.
4,
32
55
04
19
3.99
13.65
9.11
12.74
12.31
7.36
(2.68)
0.65
0.48
0.51
0.56
0.47
0.44
514
1,623
1,152
804
2,164
748
G-17
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G-18
-------
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G-19
-------
o-
w
w
w
w
H
2
W
H
f—I
(X.
100
80
60
40
20
)( Capital investment
• Revenue requirements
X Oil-fired unit
I
Oil-fired unit
I
I
I
10 20 30 40
SULFUR REMOVED, k SHORT TONS/YR
Figure G-4. Magnesium oxide process. Effect of sulfur removed on
capital investment and annual revenue requirements.
G-20
-------
TABLE G-6. MAGNESIUM OXIDE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 3.52 S in coal;
90% SO- removal; sulfuric acid production)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, tank, agitator, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorbers to reheater and stack)
S0~ absorption (four spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator,
and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
765,000
326,000
5,098,000
5,447,000
1,306,000
5,066,000
1,211,000
5,307,000
2,461,000
6,576,000
1,077,000
34,640,000
2,078,000
36,718,000
154,000
36,872,000
1,922,000
477,000
5,002,000
1,489,000
8,890,000
9,153,000
54,915,000
5,476,000
6,590,000
66,981,000
42,000
1,411,000
68,434,000
7. of
total direct
investment
2.1
0.9
13.8
14.8
3.5
13.7
3.3
14.4
6.7
17.9
2.9
94.0
5.6
99.6
0.4
100.0
5.2
1.3
13.6
4.0
24.1
24.8
148.9
14.9
17.9
181.7
0.1
3.8
185.6
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
G-21
-------
TABLE G-7. MAGNESIUM OXIDE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 3.5% S In coal;
90% SO removal; sulfuric acid production)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of
annual revenue
requirements
1,440 tons
1,800 liters
2,780 tons
40,000 man-hr
5,585,100 gal
431,500 MBtu
2,251,400 kgal
54,652,000 kWh
85,600 MBtu
3,720 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
432,000
4,500
41,700
478,200
500,000
2.46
0.03
0.24
2.73
2.S
0.40/gal
2. 00 /MBtu
0.12 /kgal
0.029/kWh
2.00/MBtu
17. 00 /man-hr
2,234,000
863,000
270,200
1,584,900
(171,200)
2,574,900
63,200
7,919,000
8,397,200
12.73
4.92
1.54
9.03
(0.98)
14.67
0.36
45.13
47.86
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 105,500 tons
Net annual revenue requirements
Equivalent unit revenue requirements
4,018,900
5,885,400
1,569,100
50,000
263,800
11,787,200
20,184,400
25.00/ton (2,637,500)
17,546,900
$/ton coal $/MBtu heat
Mills/kWh burned input
5.85 13.65 0.65
22.90
33.54
8.95
0.28
1.50
67.17
115.03
(15.03)
100.00
$/ton
S removed
514
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,200 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 30,950 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,872,000; total depreciable investment, $66,981,000; and total
capital investment, $68,434,000.
All tons shown are 2,000 Ib.
G-22
-------
(500-MW new coal-fired power unit, 0.8 :, S in cp
90% SO removal; sul furic acid production:
Direct Investment
Materials handling (conveyors, silos, bins, and feedi^-,)
Feed preparation (mixer, tank, agitator, and pumps--.)
Gas handling (common feed plenum and booster fans, ga^ ducu
and dampers from plenum to absorber, exhaust gaF durts ar-1
dampers from absorbers to reheater and stack)
S0? absorption (four spray grid towers, including pntraimnent
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entraiumt-nt
separators, tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, ,1% i t-itor,
and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sul f uric acicl
production)
Acid storage (storage and shipping facilities for 30-clav
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construct ion
Incremental ash pond cost
Total direct investment
7, .-if
total direct
Investment, S investment
2,381/100
_ _4()l ,001)
•'i.'! S4, GOO
i. '-sj.ooo
'.'•. 'i] ,uon
iVi, 1)0(1
'-ri.!->9; ,000
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Basis
Evaluation represents project beginning mid-19/7, ending mu!-J ')8o. Ai/,-ra<>p rost b.jsi-; for
scaling, mid-1979.
Stack, gas reheat to 79 C (175 F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposil e^ciiuk'1; FCD proces.- investment
estimate begins with common feed plenum downstream of tne FSP.
Construction labor shortages with accompanying overtime p.v, incentive not considered.
G-23
-------
TABLE G-9. MAGNESIUM OXIDE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 0.8% S in coal;
90% SO. removal; sulfuric acid production)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of
Unit annual annual revenue
cost „$ cost^ j> r e qujLreinen ts
340 tons
420 liters
2,850 tons
40,000 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
102,000
1,100
42,800
145,900
500,000
0.79
0. 33
1.12
3.86
1
43
,305
442
823
,336
20
1
,800
,100
,200
,000
,000
,555
gal
MBtu
kgal
kWh
MBtu
man-hr
0
2
0
0
2.
17
.40/gal
.00/MBtu
.12/kgal
.029/kWh
.00 /MBtu
. 00/man-hr
1
1
5
5
522
884
98
,256
(40
,806
26
,055
,200
,300
,200
,800
,700
,000)
,600
,400
,000
,900
4
6
0
9
(0
13
_0
39
40
.03
.83
.76
.71
.31)
.95
.21
.04
.16
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 24,700
Net annual revenue requirements
Equivalent unit revenue requirements
2,880,200
4,207,600
1,166,500
50,000
61,800
8,366,100
13,567,000
tons 25.00/ton (617,500)
12,949,500
$/ton coal $/MBtu heat
Mills/kWh burned input
4.32 9.11 0.48
22.24
32.49
9.01
0.39
0.48
64.61
104.77
(4.77)
100.00
S/ton
S removed
1,623
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,289,200 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 7,240 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $25,897,000; total depreciable investment, $48,003,000; and total
capital investment, 548,926,000.
All tons shown are 2,000 Ib.
G-24
-------
TABLE G-10. MAGNESIUM OXIDE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 1.4Z S in coal;
907. SO. removal; sulfuric acid production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, tank, agitator, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorbers to reheater and stack)
SO. absorption (four spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator.
and pumps )
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
5
5
1
5
3
1
3
25
1
27
27
1
3
1
7
6
41
4
5
51
52
389
190
,062
,403
,297
,031
590
,030
,199
,137
524
,852
,551
,403
234
,637
,688
418
,941
,196
,243
,976
,856
.162
,023
,041
42
960
,043
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
1.
0.
18.
19.
4.
18
2.
11.
4.
11.
I (
93-
5
99.
0.
100.
6.
1.
14.
4.
26.
25.
151.
15,
18.
184,
0,
3,
188,
, 4
7
3
,6
7
.2
1
,0
.3
4
,9
.6
.6
,2
8
.0
1
5
3
,3
2
.2
,4
.1
.2
,7
,2
.5
,4
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79 C (175 F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
G-25
-------
TABLE G-ll. MAGNESIUM OXIDE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 1.4% S in coal;
90% SO removal; sulfuric acid production)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of
annual revenue
requirements
500 tons
620 liters
5,500 tons
40,000 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
150,000
1,600
82,500
234,100
500,000
1.10
0.01
0.60
3.66
1,939,100 gal
427,300 MBtu
1,023,000 kgal
43,840,000 kWh
29,700 MBtu
1,972 man-hr
0.40/gal
2.00/MBtu
0.1 2 /kgal
0.029/kWh
2.00/MBtu
17. 00 /man-hr
775,600
854,600
122,800
1,271,400
(59,400)
1,925,200
33,500
5,423,700
5,657,800
5.68
6.26
0.90
9.31
(0.43)
14.10
0.25
39.73
41.44
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
i,Obi,500
4,475,700
1,229,400
50,000
91,600
8,909,200
14,567,000
22.43
32.79
9.00
0.37
0.67
65.26
106.71
Byproduct Sales Revenue
100% sulfuric acid 36,630 tons 25.00/ton (915,800) (6.71)
Net annual revenue requirements 13,651,200 100.00
Equivalent unit revenue requirements
S/ton coal $/MBtu heat $/ton
Mills/kWh burned input S removed
4.55
12.74
0.51
1.152
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 972,200 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 10,750 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, 327.637,000: total depreciable investment, 551.041,000. and total
capital investment, $52,043,000.
All tons shown are 2,000 Ib.
G-26
-------
TABLE G-12. MAGNESIUM OXIDE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 2.0% S in coal;
90% S0~ removal; sulfuric acid production)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, tank, agitator, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorbers to reheater and stack)
S0? absorption (four spray grid towers, including entrainment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator,
and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
522,000
241,000
5,078,000
5,425,000
1,301,000
5,046,000
808,000
3,869,000
1,641,000
4,334,000
' 718,000
29,013,000
1,741,000
30,754,000
300,000
31,054,000
1,777,000
439,000
4,342,000
1,307,000
7,865,000
7,784,000
46,703,000
4,641,000
5,604,000
56,948,000
42,000
1,118,000
58,108,000
7. of
total direct
investment
1.7
0.8
16.4
17.5
4.2
16.2
2.6
12.5
5.3
14.0
2.3
93.5
5.6
99.1
0.9
100.0
5. 7
1.4
14.0
4.2
25.3
25.1
150.4
14.9
18.1
18 i.4
0.1
3.6
187.1
Basib
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost* basis for
scaling, mid-1979.
Stack gas reheat to 79 C (175 F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
G-27
-------
TABLE G-13. MAGNESIUM OXIDE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 2.0% S in coal;
90% SO- removal; sulfuric acid production)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
7. of
annual revenue
requirements
790 tons
990 liters
8,300 tons
40,000 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
237,000
2,500
124.500
364,000
500,000
1.57
0.02
0.82
2.41
3.31
3,075,700 gal
429,300 MBtu
1,406,500 kgal
47,269,000 kWh
47,100 MBtu
2,601 man-hr
0.40/gal
2.00/MBtu
0.1 2 /kgal
0.029/kWh
2.00/MBtu
17. 00 /man-hr
1,230,300
858,600
168,800
1,370,800
(94,200)
2,161,800
44,200
6,240,300
6,604,300
8.14
5.68
1.12
9.07
(0.62)
14.30
0.29
41.29
43.70
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
3,416,900
4.997,300
1,353,000
50,000
145,300
9,962,500
16,566,800
22.61
33.06
8.95
0.33
0.96
65.91
109.61
Byproduct Sales Revenue
100% sulfuric acid
Net annual revenue requirements
58,100 tons 25.00/ton (1,452,500) (9.61)
15,114,300 100.00
Equivalent unit revenue requirements
Mills/kWh
5.04
$/ton coal
burned
12.31
$/MBtu heat
input
0.56
$/ton
S removed
804
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,413,400 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 17,000 metric tons/yr (18,790 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $31,054,000; total depreciable investment, $56,948,000; and total
capital investment, $58,108,000.
All tons shown are 2,000 Ib.
G-28
-------
TABLE G-14. MAGNESIUM OXIDE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% SO removal; sulfuric acid production)
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, tank, agitator, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorbers to reheater and stack)
SO absorption (four spray grid towers, including entralnment
separators, tanks, agitators, and pumps)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator,
and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
Investment, $
246,000
132,000
5,271,000
5,665,000
1,356,000
5,259,000
363,000
2,075,000
738,000
1,907,000
323,000
23,335,000
1,400,000
24,735,000
149,000
24,884,000
1,594,000
395,000
3,611,000
1,105,000
6,705,000
6,318,000
37,907,000
3,776,000
4,549,000
46,232,000
42,000
341,000
47,115,000
% of
total direct
investment
1.
0
21.
22.
5,
21.
1.
8.
3.
7.
1
93.
5
99
0
100
6
1
14
4
26
25
152,
15.
J8.
185.
0.
3.
189.
.0
.5
, 2
,8
,4
,1
5
3
0
7
.3
.8
.6
.4
.6
.0
.4
.6
.5
.4
.9
.4
.3
_ 2
.3
.8
.2
.4
4
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
G-29
-------
TABLE G-15. MAGNESIUM OXIDE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% SO. removal; sulfuric acid production)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of
Unit annual annual revenue
cost, $ cost, $ requirements
250 tons
310 liters
2,630 tons
40,000 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
75,000
800
39,500
115,300
500,000
0.60
0.01
0.31
0.92
3.98
951,100 gal
453,500 MBtu
714,000 kgal
43,330,000 kWh
14,600 MBtu
1,286 man-hr
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17. 00 /man-hr
380,400
907,000
85,700
1,256,600
(29,200)
1,735,900
21,900
4,858,300
4,973,600
3.03
7.21
0.68
9.99
(0.23)
13.80
0.17
38.63
39.55
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
2,773,900
4,051,900
1,128,900
50,000
44,900
8,049,600
13,023,200
22.06
32.22
8.98
0.40
0.36
64.02
103.57
Byproduct Sales Revenue
100% sulfuric acid
Net annual revenue requirements
17,970 tons
25.00/ton
(449,300)
12,573,900
(3.57)
100.00
Equivalent unit revenue requirements
$/ton lignite $/MBtu heat $/ton
Mllls/kWh burned input S removed
4.19
7.36
0.47
2,164
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Lignite burned, 1,549,900 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 5,270 metric tons/yr (5,810 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $24,884,000; total depreciable investment, $46,232,000; and total
capital investment, $47,115,000.
All tons shown are 2,000 Ib.
G-30
-------
TABLE G-16. MAGNESIUM OXIDE PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new oil-fired power unit, 2.5% S in oil;
90% SO removal; sulfuric acid production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, bins, and feeders)
Feed preparation (mixer, tank, agitator, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers from plenum to absorber, exhaust gas ducts and
dampers from absorbers to reheater and stack)
SO. absorption (four spray grid towers, including presaturators
and entrainment separators, tanks, agitators, and pumps)
Stack gas reheat (four direct oil-fired reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Slurry processing (centrifuge, conveyor, tank, agitator,
and pumps)
Drying (dryer, conveyors, silos, fans, tanks, and pumps)
Calcining (calciner, cooler, bin, fans, conveyors, and silos)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total process areas excluding pond construction
Incremental ash pond cost
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
471,000
222,000
4,502,000
5,676,000
1,130,000
0
724,000
3,556,000
1,472,000
3,873,000
644,000
22,270,000
1,336,000
23,606,000
_
23,606,000
1,347,000
337,000
3,448,000
1,061,000
6,193,000
5,960,000
35,759,000
3,576,000
4,291,000
43,626,000
42,000
923,000
44,591,000
2.0
0.9
19.1
24.0
4.8
0
3.1
15.1
6.2
16.4
2.7
94.3
5.7
100.0
_
100.0
5.7
1.4
14.6
4.5
26.2
25.3
151.5
15.1
18.2
184.8
0.2
3.9
188.9
Basis
ISIS
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by direct oil-fired reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
G-31
-------
TABLE G-17. MAGNESIUM OXIDE PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new oil-fired power unit, 2.5% S in oil;
90% SO- removal; sulfuric acid production)
Direct Costs
Delivered raw materials
MgO
Catalyst
Agricultural limestone
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Total % of
Unit annual annual revenue
cost, $ cost, $ requirements
680 tons
850 liters
0 tons
40,000 man-hr
5,117,300 gal
0 MBtu
1,172,200 kgal
34,232,000 kWh
40,200 MBtu
2,363 man-hr
300.00/ton
2.50/liter
15.00/ton
12.50/man-hr
204,000
2,100
0
206,100
500,000
1.70
0.02
0_
1.72
4.17
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
2,046,900
0
140,700
992,700
(80,400)
1,652,400
40,200
5,292,500
5,499,600
17.09
0
1.17
8.28
(0.67)
13.79
0.34
44.17
45.89
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
2,617,600
3,834,800
1,096,300
50,000
123,800
7,722,500
13,222,100
21.84
32.0
9.15
0.42
1.03
64.44
110.33
Byproduct Sales Revenue
100% sulfuric acid
Net annual revenue requirements
49,500 tons 25.00/tor, (1,237,500) (10.33)
11,984,600 100.00
Equivalent unit revenue requirements
Mills/kWh
3.99
$/bbl oil
burned
2.68
$/MBtu heat
input
0.44
$/ton
S removed
748
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Oil burned, 710 x 106 liters/yr (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175 F).
Sulfur removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $23,606,000; total depreciable investment, $43,626,000; and total
capital investment, $44,591,000.
All tons shown are 2,000 Ib.
G-32
-------
APPENDIX H
SODIUM SULFITE PROCESS (WELLMAN-LORD)
PROCESS DESCRIPTION
The Wellman-Lord process is a sodium sulfite-based scrubbing process
that produces SOo. The S0? can be liquefied, or processed to sulfuric
acid or elemental sulfur. The system evaluated is Wellman-Lord scrubbing
combined with a sulfuric acid plant. An additional case variation is
included that uses an Allied Chemical methane reduction unit for sulfur
production. The flow diagram is shown in Figure H-l. The base-case
material balance and equipment list are shown in Tables H-l and H-2 .
The flue gas from the common plenum enters a chloride scrubber where the
gas is cooled and the chlorides are removed. From this scrubber the
flue gas passes countercurrently to a recirculating sodium sulfite
solution in a three-stage valve tray absorber where the SC>2 reacts with
the sodium sulfite to form sodium bisulfite and a very small amount of
sodium sulfate. Liquor is individually recirculated in each of the
three stages to maintain efficient mass transfer. Each absorber has a
chevron-type entrainment separator to control entrainment carryover in
the gas stream.
A portion of the scrubber effluent is processed to remove Na2SC>4 by
evaporation and selective crystallization in a steam-heated, forced-
circulation evaporator serving all four scrubber trains. The clear
overflow, enriched in NaHS03, ^s returned to the regeneration area. The
bottoms, consisting of a slurry enriched in Na2SO^ crystals, are centrifuged
to produce a solid containing about two-thirds Na2SO^ and one-third Na2S03-
The centrate is returned to the regeneration area; the solids are dried in
a steam-heated dryer and conveyed to a storage silo for sale or discard.
There is a potential market available in the paper industry for this
material.
The regeneration system consists of two trains of double-effect,
forced-circulation evaporators. Scrubber effluent, combined with liquid
from the sulfate removal process, is heated and 60% is pumped to the first-
effect evaporators and 40% to the second-effect evaporators. The first
effect is steam heated; the second effect is heated by combined first-
effect vapor and sulfate crystallizer vapor. Some ^28203 formed in the
first-effect evaporator is removed by a purge stream. Evaporator and
stripper overhead vapor, containing H20 and S02, is dried and compressed.
The concentrated S02 stream is routed to a processing plant. S02~bearing
condensate from the second-effect evaporator heater, the condensers, and
the compressor is steam stripped and combined with evaporator bottoms.
The resulting mixture, enriched in Na2SO-j, is returned to the absorber
system.
H-l
-------
The concentrated SC>2 stream is converted to I^SO^ in a single-
contact, single absorption acid plant. The tail gas containing unreacted
SC>2 is returned to the scrubber. The Allied Chemical methane reduction
process is used for a sulfur production case variation. In this process,
about 60% of the SC>2 from the Wellman-Lord plant is reduced directly to
elemental sulfur by reaction with methane in a primary reduction reactor.
Gas leaving the primary reactor, containing H2S and S02 in a molar ratio
of 2:1, is routed to a catalytic Claus converter where total conversion
of SC>2 to S is increased to about 95%. Sulfur condensed from the gas
stream after the primary and secondary reactors, is pumped to storage.
Noncondensed gases from the last sulfur condenser are pumped to an
incinerator to oxidize remaining sulfur compounds back to SC^. After
incineration the gases are recycled back to the SC>2 absorbers.
SPECIFIC PROCESS PREMISES
1. The flue gas is cooled from U9°C (300°F) to 54°C (130°F) in the
chloride scrubber at an L/G ratio of 1.3 liters/m3 (10 gal/103
aft3).
2. A 3-stage valve tray absorber with 2 chimney trays and a superficial
velocity of 3 m/sec (10 ft/sec), an L/G ratio of 0.4 liter/m3
(3 gal/103 aft3), and a pressure drop, including the mist eliminator
of 2.9 kPa (11.6 in. H20).
3. Stoichiometry is 2.0 mole of Na2COg to 1.0 mole of Na removed in
the sulfate purge stream.
ENERGY REQUIREMENTS
For base-case conditions, reheat of the cleaned gas requires 36.2 x
103 kg/hr (79,700 Ib/hr) of 243°C (470°F) steam at 3.55 x 103 kPa
absolute pressure (500 psig), equivalent to about 15.1 x 10^ kcal/hr.
In the purge area, the sulfate dryer uses 0.7 x 103 kg/hr (1,600 Ib/hr)
of 243 C (470 F) saturated steam and the sulfate crystallizer uses 10.3
x 103 kg/hr (22,800 Ib/hr) of 121°C (250°F) steam at 2.10 x 103 kPa (15
psig) absolute pressure. Total consumption in the purge area is equivalent
to 6.1 x 10 kcal/hr. Steam consumption for the first effect evaporators
and the stripper in the regeneration area is 70.4 kg/hr (155,100 Ib/hr)
of 121°C (250 F) saturated steam, equivalent to 40.5 x 106 kcal/hr. The
acid plant produces 3.6 x 103 kg/hr (7,900 Ib/hr) of 121°C (250°F)
saturated steam, equivalent to 1.98 x 10" kcal/hr. This is taken into
account as a heat credit for the process.
The electrical power demand for the base case is about 11,300 kW or
2.3% of the rated capacity of a 500-MW power plant. For 6,000 hours of
operation, the annual electrical energy consumption is 68.1 .x 10" kWh.
The total equivalent energy consumption for the base case is approximately
92.35 x 106 kcal/hr or 8.1% of the input energy required for the 500-MW
power unit. Summarized energy requirements for all cases are listed in
Table H-3.
H-2
-------
BYPRODUCT MANAGEMENT
Electrostatic precipitators remove 99.2% of the fly ash in the
flue gas. Most of the remainder is removed in the chloride scrubber;
therefore, it is assumed that the byproducts contain little, if any, fly
ash. (Fly ash emission from oil-fired units does not exceed the EPA
particulate emission standard and fly ash collection facilities are not
included in oil-fired power plant design.) Projected mass flow rates of
byproduct streams for the base case are shown below.
Sulfuric acid:
Sodium sulfate:
Total
Chloride purge: HC1
S03
Ash
Component
98% H2SO^
Na2S04
Na2S03
Other Na salts
kg/hr
15,100
680
450
50
Ib/hr
33,300
1,500
1,000
100
1,180 2,600
290
40
150
630
80
330
The byproduct sulfuric acid is stored in a tank of 30-day capacity
until sold. For the purposes of this study the sodium sulfate is assumed
to be sold.
ECONOMIC EVALUATION
Capital investment and annual revenue requirement summaries for the
base case, five fuel variations, and a case variation with sulfur produc-
tion are shown in Tables H-4 and H-5. Detailed results are shown in
Tables H-6 through H-19. The results showing the range of estimated
accuracies are also shown graphically in Figures H-2 and H-3. The
effect of fuel sulfur content on cost is shown in Figure H-4.
H-3
-------
60
CO
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I
rH
U-l
CO
CO
0)
o
o
^
(X
-2
o
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33
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60
•rl
H-4
-------
TABLE H-l. WELLMAN-LORD/SULFURIC ACID PROCESS
MATERIAL BALANCE - BASE CASE (3.5S! SULFUR COAL)
Description
1
>
)
',
',
d
7
H
9
in
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, Nm3/hr (0°c)
fias Flnv, sfr3/mln CfiO°F')
Liquid flow, liters/min
Temperature, °C
Parrirulates f kg/hr
PartiQulateSr Ib/hr
1
Coal to boiler
194
428,600
2
Combustion air
to air heater
-"1,061
4,546,200
1,615,700
1,005.000
27
3
Flue gas to
chloride
scrubber
2,225
4,906,000
1.697,700
1 056.000
149
199.1
439
4
Gas to reheater
2,349
5,178,300
1,839,100
1.143.700
39
10
57
49.8
110
5
Gas to stack
2^349
5,178,300
1.842,000
1.145.500
79
49.8
110
Sl*T-*iam Nn
Description
1
J
1
'j
<-,
7
8
y
10
Total stream, 1000 kg/hr
Total stream. Ib/hr
Gas flow, Nm3/hr (Qoc)
Gas fir™, sfr3/min C60OF
Liquid flow, liters/min
Liauid flow, eal/min
Temperature. °C
Pressure, Pascals (abs)
Pressure, psifi
6
Steam to reheat
and purge area
36.9
81 ,100
243
3.<;s v in6
500
7
Process
makeup water
106
233,600
1,767
467
8
Makeup soda ash
to storage
0.9
2,050
9
Limestone to
neutralization
tank
0.4
930
10
Process steam
80.7
177.900
121
7.07 * Ifj5
15
Stream No.
Description
1
2
)
4
i
f,
?
K
9
10
Total .stream, 1000 kg/hr
Tofal st-rpam Ib/hr
Gas flow, Nm3/hr (0°C)
Gas flow, sft3/min (60°F)
Liquid fTowr liters/min
T.imiirl flow pal/min
Temperature. °C
Pressure. Pascals Cabs)
Pressure. t>sig
11
Cooling water
3.015
6,646,700
50.100
13. iOO
27
12
Filter aid
(100)
13
Oxidation air
to acid plant
40.5
89.200
31,700
19,700
27
14
Purge area
off-gas
0.4
1,000
510
320
132
15
Boiler feedwater
to acid plant
3.6
7 qnn
60
16
82
*Intermittent stream
Stream No.
1
2
! 1
4
5
6
/
H
9
10
Description
Total stream. 1000 k?/hr
Total stream, Ib/hr
Gas flow, Nm3/hr (QOC)
Gas flow, sfr.3/min C600F)
Lianirl flow, liters/min
Liauid flow. sal/min
Temperature, QC
Pressure, Pascals (abs)
Pressure, psig
Specific gravity
16
Steam to
steam plant
3.6
7.900
121
2.07 x 105
15
17
Acid plant
off-gas
33.1
73.000
25 , 700
16.000
77
18
Product
sodium sulfate
1.2
2,600
19
Product
sulfuric acid
(98% H2S04)
15.1
33 , 300
138
36.5
1.82
H-5
-------
TABLE H-2. WELLMAN-LORD PROCESS
BASE-CASE EQUIPMENT LIST DESCRIPTION AND COST
Area size-cost
Area
1.
2.
1 — Materials Handling
Item No. Description
Car shaker 3 Top mounting with crane
Tank, soda ash 1 34 ft dia x 35 ft high,
exponent
Total
material
cost,
1979 $
9,000
42,100
0.62
Total
labor
cost,
1979 $
2,100
66,600
storage
3. Pump, soda ash
feed
4. Dust collecting
system
5. Conveyor, limestone 1
6. Silo, limestone i
storage
/, Bin, limestone
feed
Subtotal
237,/30 gal, w/cover, carbon
steel, insulated, 3 spargers
in bottom (30 day storage
capacity)
Centrifugal, 10 gpm, 60 ft
head, 1.0 hp, carbon steel
(1 operating, 1 spare)
3,300
1 Bag filter, polypropylene bag, 13,300
4,000 aft /min, automatic
shaker system
Pneumatic, pressure, 75 hp
19 ft dia x 29 ft straight
side, 8,200 ft, 60° slope,
3/8 in. carbon steel
5-1/2 ft dia x 8-1/2 straight
side height, w/cover, carbon
steel
51,800
13,000
1,500
1,200
3,300
12,200
33,000
2.200
134,000 120,600
Area_ 2—Feed Preparation _
No equipment in this area.
(continued)
11-6
-------
TABLE H-2 (continued)
Area 3—Gas Handling
Area size-cost
exponent 0.68
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Fans
Subtotal
Forced draft, 19.7 in.
static head, 1,750 hp,
fluid drive, double width,
double inlet
1,705,400 97.600
1,705.400 97,600
Area 4—S(X, Absorption
Area size-cost
exponent 0.86
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. S00 absorber
Pump, SO- absorber
recirculation
Pump, absorber
effluent
Filter, absorber
product
Sump, effluent
4 Valve tray, 24 ft x 24 ft x
50 ft high, concrete, tile
lined, 3-316 stainless steel
valve trays, 2-316 stainless
steel chimney trays, 1-316
stainless steel mist elimina-
tor
16 Centrifugal, 550 gpm, 20 ft
head, 10 hp, carbon steel,
neoprene lined
(12 operating, 4 spare)
6 Centrifugal, 170 gpm, 200 ft
head, 25 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
2 Pressure leaf, 60 in. dia x
11 ft long, 28 vertical
leaves, 316 stainless steel,
insulated
1 8 ft x 8 ft x 8 ft deep, con-
crete, tile lined, grating
covered
1,414,400 564,800
60,700 12,600
49,200 9,500
202,800 102,800
7,000 8,000
(continued)
H-7
-------
TABLE H-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
6. Agitator, effluent
sump
7. Pump, effluent
sump
8. Tank, absorber
product
9. Pump, absorber
product tank
10. Heater, absorber
product
11. Soot blowers
Subtotal
1 32 in. dia, 2 hp, neoprene 6,200
coated
2 Centrifugal, submerged, 100 5,300
gpm, 60 ft head, 5 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
1 57 ft dia x 57 ft high,
1,088,100 gal, w/cover,
concrete, tile lined,
insulated
(24 hr residence time)
2 Centrifugal, 680 gpm, 100 11,600
ft head, 50 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
1 Plate and frame type heat 9,100
exchanger, 400 ft , 316
stainless steel, insulated
40 Air, retractable
700
1,500
168,700 112,500
3,700
2,300
260.000 225,800
2.195,000 1.044,200
Area 5—Reheat
Area size-cost
exponent 0.75
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Reheaters
2. Soot blowers
Subtotal
4 Steam, tube type, 3,170 ft ,
one-half tubes made of In-
conel 625 and one-half made
of Cor-Ten
20 Air, retractable
787,200 37,200
130,000 112,900
917,200 150,100
(continued)
H-8
-------
TABLE H-2 (continued)
Area 6 — Chloride Removal
Item . No .
1. Chloride scrubber 4
Description
Venturi-spray chamber corn-
Area size-cost
exponent 0.75
Total Total
material labor
cost, cost,
1979 $ 1979 $
1,834,200 439,200
2. Tank, recirculation
Lining
3. Agitator, recircu-
lation tank
4. Pump, venturi
recirculation
5. Pump, spray chamber
recirculation
6. Tank, neutralization
Lining
bination, venturi: 13 ft
dia x 25 ft overall height,
variable throat, carbon
steel, elastomer and tile
lined, Hastelloy® G throat
Spray chamber: 24 ft x 20 ft
x 11 ft high, carbon steel,
elastomer and tile lined,
Hastelloy® G nozzles with
stellite tips; Hastelloy® G
mist eliminator
4 20 ft dia x 6 ft high, 14,100
gal, w/cover, four 20 in.
baffles, agitator supports,
carbon steel, insulated
(10 min residence time)
1/4 in. neoprene lining
4 80 in. dia, 1-1/2 hp, neoprene
coated
6 Centrifugal, 3,140 gpm, 60 ft
head, 100 hp, carbon steel,
neoprene lined
(4 operating, 2 spare)
6 Centrifugal, 3,140 gpm, 150
ft head, 250 hp, carbon
steel, neoprene lined
(4 operating, 2 spare)
14,100 26,900
15,300
15,200
1 11-1/2 ft dia x 6 ft high,
4,660 gal, w/cover, four 11-
1/2 in. baffles, agitator
supports, carbon steel, insulated
(30 min residence time)
1/4 in. neoprene lining
(continued)
18,700
2,200
88,700 23,900
159,400 28,300
1,300 3,500
1,400 1,800
H-9
-------
TABLE H-2 (continued)
1
7.
8.
Item No .
Agitator, neutrali- 1
zation tank
Pump, pond feed 2
Description
46 in. dia, 1 hp, neoprene
coated
Centrifugal, 130 gpm, 150 ft
Total
material
cost,
1979 $
2,700
11,200
Total
labor
cost,
1979 $
500
3,000
9. Pump, pond water
return
10. Feeder, limestone
feedbin discharge
11. Pump, raw water
12. Pump, chloride
scrubber water
booster
Subtotal
head, 15 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Centrifugal, 300 gpm, 150 ft
head, 25 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Weigh, screw, 6 in. dia x 10
ft long, 1 hp, 900 Ib/hr
Centrifugal, 650 gpm, 150 ft
head, 60 hp, carbon steel
(1 operating, 1 spare)
Centrifugal, 450 gpm, 150 ft
head, 40 hp, carbon steel
(1 operating, 1 spare)
16,200 5,900
5,300
18,200
200
6,000
17.000 5,900
2,200,200 566,000
Area 7—Sulfate Crystallization
Area size-cost
exponent 0.66
Total
material
1.
2.
Item
Preheater, crystal -
lizer feed
Crystallizer, sul-
No.
1
1
Description
2
Plate and frame type, 90 ft ,
316 stainless steel, insulated
9 ft dia x 12 ft straight
cost,
1979 $
3,900
651,800
Total
labor
cost,
1979 $
1,100
66,800
fate
side, 316 stainless steel,
insulated
(package price includes
heater, recirculation pump,
and recirculation piping)
(continued)
H-10
-------
TABLE H-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
3. Receiver, conden-
sate
4. Pump, condensate
5. Pump, centrifuge
feed
6. Centrifuge
7. Tank, centrate
8. Agitator, centrate
tank
9. Pump, centrate
tank
10. Dryer
11. Dust collecting
system
12. Hopper, sulfate
surge
1 2-1/2 ft dia x 3 ft high, 300 500
110 gal, w/cover, carbon steel,
insulated
(2 min residence time)
2 Centrifugal, 45 gpm, 60 ft 3,400 1,200
head, 2 hp, carbon steel,
(1 operating, 1 spare)
2 Centrifugal, 9 gpm, 60 ft 4,800 1,500
head, 3/4 hp, 316 stainless
steel
(1 operating, 1 spare)
1 Solid bowl, continuous, 40 90,800 10,000
hp, 316 stainless steel
1 5 ft dia x 6 ft high, 880 2,700 1,900
gal, w/cover, four 5-in.
baffles, agitator supports,
316 stainless steel, insulated
(10 min residence time)
1 Two turbines, 20 in. dia, 1-1/2 3,800 600
hp, 316 stainless steel
2 Centrifugal, 80 gpm, 100 ft 11,700 1,800
head, 7-1/2 hp, 316 stainless
steel
(1 operating, 1 spare)
Porcupine processor, twin
screw, 316 stainless steel,
insulated
262,200 27,300
1 Bag filter, polypropylene 9,000 2,200
bag, 520 aft3/min, automatic
shaker system
1 6-1/2 ft dia x 10 ft high, 4,600 3,600
330 ft3} w/cover, carbon steel
(continued)
H-ll
-------
TABLE H-2 (continued)
13.
14.
15.
Item No.
Conveyor, sulfate 1
Silo, sulfate stor- 1
age
Feeder, sulfate 1
silo discharge
Subtotal
Description
Pneumatic, pressure, 15 hp
29 ft dia x 44 ft straight
side height, 29,100 ft3, 60°
slope, 3/8 in. carbon steel
(30 day storage capacity)
Vibrating pan, 2 hp, 120
tons/hr
Total
material
cost,
1979 $
31,300
55,500
3,800
1,139,600
Total
labor
cost,
1979 $
8,000
121,200
100
247,800
Area size-cost
Area
1.
8 — Regeneration
Item No.
Preheater, first 1
Description
Plate and frame type, 340
exponent
Total
material
cost,
1979 $
6,800
0.70
Total
labor
cost,
1979 $
1,600
effect evaporator
feed
2. Preheater, second 1
effect evaporator
feed
3. Evaporator system, 2
double effect unit.
4. Receiver, first
effect condensate
ft , 316 stainless steel,
insulated
2
Plate and frame, 100 ft , 316
stainless steel, insulated
17 ft dia x 17 ft straight
side, 316 stainless steel
(package price includes
heaters, recirculation pumps,
and recirculation piping)
3-1/2 ft dia x 4-1/2 ft
high, 320 gal, w/cover,
carbon steel, insulated
(2 min residence time)
4,600 1,400
3,000,000 300,000
1,200 1,900
(continued)
H-12
-------
TABLE H-2 (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
5. Receiver, second 2
effect condensate
6. Pump, first effect 4
condensate
Pump, second effect 4
condensate
8. Tank, dissolving 1
Lining
9. Agitator, dis-
solving tank
10. Pump, dissolving
tank
11. Separator, mother 2
liquor
12. Pump, mother liquor 2
3 ft dia x 4-1/2 ft high, 2,500 1,700
240 gal, w/cover, 316 stain-
less steel, insulated
(2 min residence time)
Centrifugal, 145 gpm, 60 ft 11,200 3,000
head, 7-1/2 tip, carbon
steel
(2 operating, 2 spare)
Centrifugal, 110 gpm, 60 ft 22,800 3,600
head, 5 hp, 316 stainless
steel
(2 operating, 2 spare)
15-1/2 ft dia x 15-1/2 ft 11,000 16,600
high, 21,880 gal, w/cover,
four 15-1/2 in. baffles,
agitator supports,
carbon steel, insulated
(30 min residence time)
1/4 in. neoprene lining 6,400 7,800
Two turbines, 58 in. dia, 12,000 1,000
7-1/2 hp, neoprene coated
Centrifugal, 660 gpm, 100 11,600 3,800
ft head, 50 hp, carbon
steel, neoprene lined
(1 operating, 1 spare)
4 ft diaQx 2 ft straight 3,800 2,600
side, 60° slope, 316 stain-
less steel, insulated
Centrifugal, 2 gpm, 60 ft 3,300 1,200
head, 1/2 hp, 316 stainless
steel
(1 operating, 1 spare)
(continued)
H-13
-------
TABLE H-2 (continued)
13.
Item
Tank, absorber
No.
1
Description
57 ft dia x 57 ft high,
Total
material
cost,
1979 $
168,700
Total
labor
cost,
1979 $
112,500
feed
. Pump, absorber
feed tank
15. Stripper
16. Pump, stripper
bottoms
17. Condenser, primary 2
18. Condenser, secon-
dary
19. Pump, cooling
water
20. Blower, product
gas
21. Tank, central
condensate
22. Pump, condensate
return
Subtotal
1,088,100 gal, w/cover,
concrete, tile lined,
insulated
Centrifugal, 660 gpm, 100 ft 11,600 3,800
head, 50 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
5 ft dia x 20 ft overall 12,100 7,000
height, 316 stainless
steel, insulated
Centrifugal, 530 gpm, 100 ft 9,600 3,000
head, 30 hp, carbon steel,
neoprene lined
(1 operating, 1 spare)
Shell and tube type, 5,800
ft2, 316 stainless steel
tubes, heads, and shell
Shell and tube type, 4,700
ft2, 316 stainless steel
tubes, heads, and shell
Centrifugal, 5,450 gpm, 150
ft head, 450 hp, carbon
steel
(2 operating, 1 spare)
Centrifugal, single stage,
15,400 aft3/min, 600 hp,
316 stainless steel
9 ft dia x 8-1/2 ft high, 3,100 4,700
4,050 gal, w/cover, carbon
steel, insulated
(10 min residence time)
Centrifugal, 360 gpm, 150 ft 16.200 5,900
head, 30 hp, carbon steel,
(1 operating, 1 spare)
3,886.900 822.100
141,300 141,300
121,500 121,500
101,700 15,000
203,900 61,200
(continued)
H-14
-------
TABLE H-2 (continued)
Area 9—98% Sulfuric Acid Production
Area size-cost
exponent 0.70
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Complete H,SO,
unit z *
Subtotal
1 Complete 98% sulfuric acid
unit, battery limits
6.138,000
6,138,000
Area 10—Acid Storage and Shipping
Area size-cost
exponent 0.68
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Tank, acid
storage
2. Pump, acid
storage tank
discharge
Subtotal
51 ft dia x 53 ft high,
810,000 gal, w/cover,
carbon steel, insulated
(30 day capacity)
Centrifugal, 400 gpm, 100 ft
head, 40 hp, carbon steel
(1 operating, 1 spare)
207,600 320,400
10,500
3,100
218.100 323.500
H-15
-------
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H-16
-------
TABLE H-4. WELLMAN-LORD PROCESS CAPITAL INVESTMENT
Total capital
investment
Case
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
Coal, 3.5% S
(sulfur production)
$
68,722,000
46,836,000
50,307,000
56,939,000
44,837,000
44,215,000
71,342,000
$/kW
137
94
101
114
90
88
143
TABLE H-5. WELLMAN-LORD PROCESS ANNUAL REVENUE REQUIREMENTS
Case
500-MW unit
Coal, 3.5% S
(base case)
Coal, 0.8% S
Coal, 1.4% S
Coal, 2.0% S
Lignite, 0.5% S
Oil, 2.5% S
Coal, 3.5% S
(sulfur production)
$
17,886,400
12,218,300
13,081,000
14,802,200
11,754,700
11,801,900
21,015,700
Mills /kWh
5.96
4.07
4.36
4.93
3.92
3.93
7.00
$/ton coal
(bbl oil)
burned
13.91
8.60
12.21
12.06
6.88
(2.64)
16.34
$/MBtu
heat
input
0.66
0.45
0.48
0.55
0.44
0.44
0.78
$/ton S
removed
524
1,531
1,104
788
2,023
737
616
H-17
-------
1 1 1 1
c - -i
O -i O U
-» ^ _
<4-l 'O
r-l O
3 M
C/2 O.
tH
~ -H —
0
(U
4-1
C
„., ._ _ ao
•H
J
rH
- cfl -
O
. ,„_, ._ ,_„. "
i-H
— Cfl —
O
- ., .. "
I— 1
— CO -
O
U
c
— o -
u
1 1
3.5 0.8 1.4 2.0 0.5 2.5 3.5
CASE VARIATIONS IDENTIFIED BY FUEL TYPE AND SULFUR CONTENT OF FUEL, %
Figure H-2. Wellman-Lord process unit investment range.
o o o o
VO CM 00 i/$
H-18
-------
1 1 1 1
£
" .?! °
tH O
3 (-1
CO CX
iH
— -H ~
O
r— — — — — fl)
4-1
•H
- c -
nJ
13
- o —
rH
~ o —
u
1.4 2.0 0.5 2.5 3.5
NTIFIED BY FUEL TYPE AND SULFUR CONTENT OF FUEL, %
man-Lord process unit revenue requirement range.
a
oo
o
en
Z
O
M
H
-------
CO
H
2
W
a!
M
!=>
O1
a!
jjf
H
W
co
>
H
I—I
PH
<
u
100 -
80 -
60
40
20
X Capital investment
• Revenue requirement
Sulfur
production
X Oil-fired unit
Sulfur
production
Oil-fired unit
I
10 20 30
SULFUR REMOVED, k SHORT TONS/YR
40
Figure H-4. Wellman-Lord process. Effect of sulfur removed
on total capital investment and annual revenue requirement.
H-20
-------
TABLE H-6. WELLMAN-LORD PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 3.5% S in coal;
90% S02 removal; sulfuric acid production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker,
tanks, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
scrubber to absorber)
S0_ absorption (four absorbers and entrainment separators,
tanks, pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat
exchanger, pumps, agitator, tank, dryer, conveyors, centri-
fuge, bin, silo, and feeder)
SO., regeneration (evaporators, heat exchangers, strippers,
tanks, agitators, pumps, blower, and condensers)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
503,000
4,861,000
4,595,000
1,221,000
4,894,000
2,934,000
8,297,000
6,138,000
978,000
34,421,000
2,065,000
36,486,000
154,000
36,640,000
2,271,000
565,000
4,976,000
1,482,000
9,294,000
9,187,000
55,121,000
5,497,000
6,614,000
67,232,000
28,000
1,462,000
68,722,000
1.4
13.3
12.5
3.3
13.4
8.0
22.6
16.8
2.7
94.0
5.6
99.6
0.4
100.0
6.2
1.5
13.6
4.0
25.3
25.1
150.4
15.0
18.1
183.5
0.1
4.0
187.6
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
H-21
-------
TABLE H-7. WELLMAN-LORD PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 3.5% S in coal;
90% SOj removal; sulfuric acid production)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Total raw material cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
7. of
annual revenue
requirements
6,150 tons
1,760 liters
2,780 tons
70 tons
40,000 man-hr
103.00/ton
2.50/liter
15.00/ton
189.00/ton
12.50/man-hr
633,500
4,400
41,700
13,200
692,800
500,000
3.54
0.02
0.23
0.07
3.86
2.80
1,469,900 MBtu
4,950,800 kgal
68,060,600 kWh
47,200 MBtu
3,720 man-hr
2.00/MBtu
0.12/kgal
0.029/kwh
2.00/MBtu
17.00/man-hr
2,939,800
594,100
1,973,800
(94,400)
2,193,800
65,100
8,172,200
8,865,000
16.44
3.32
11.04
(0.53)
12.27
0.36
45.70
49.56
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion cost less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
4,033,900
5,910,100
1,379,500
58,100
262.200
11,643,800
20,508,800
22.55
33.05
7.71
0.32
1.47
65.10
114.66
Byproduct Sales Revenue
100% sulfuric acid
Sodium sulfate
Net annual revenue requirements
97,710 tons 25.00/ton (2,442,800) (13.66)
7,810 tons 23.00/ton (179,600) (1.00)
17,886,400
100.00
$/ton coal $/MBtu heat $/ton
Mills/kHh burned input S removed
Equivalent unit revenue requirements (net)
5.96
13.91
0.66
524
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,200 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 30,950 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $36,640,000; total depreciable investment, $67,232,000; and total
capital investment, $68,722,000.
All tons shown are 2,000 Ib.
H-22
-------
TABLE H-8. WELLMAN-LORD PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 0.8% S in coal;
90% S0_ removal; sulfuric acid production)
% of
total direct
Investment, $ Investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker,
tanks, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack, gas ducts from chloride
scrubber to absorber)
S0? absorption (four absorbers and entrainment separators,
tanks, pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat
exchanger, pumps, agitator, tank, dryer, conveyors, centri-
fuge, bin, silo, and feeder)
SO. regeneration (evaporators, heat exchangers, strippers,
tanks, agitators, pumps, blower, and condensers)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect Investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
204,000
4,944,000
4,691,000
1,243,000
4,982,000
1,124,000
3,004,000
2,222,000
364,000
22,778,000
1,367,000
24,145,000
156,000
24,301,000
1,997,000
496,000
3,541,000
1,085,000
7,119,000
6,284,000
37,704,000
3,755,000
4,524,000
45,983,000
28,000
825,000
46,836,000
0.8
20.4
19.3
5.1
20.6
4.6
12.4
9.1
1.5
93.8
5.6
99.4
0.6
100.0
8.2
2.0
14.6
4.5
29.3
25.9
155.2
15.4
18.6
189.2
0.1
3.4
192.7
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
H-23
-------
Direct Coses
TABLE H-9. WELLMAN-LORD PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 0.8% S in coal;
90% S02 removal; sulfuric acid production)
Annual
quantity
Unit
cost,
Total
annual
cost, $
% of
annual revenue
requirements
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Total raw material cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
1,440 tons
410 liters
2,850 tons
15 tons
40,000 man-hr
627,900 MBtu
1,286,400 kgal
47,601,500 kWh
11,000 MBtu
1,555 man-hr
103.00/ton
2.50/liter
15.00/ton
189.00/ton
12.50/man-hr
148,300
1,000
42,800
2,800
194,900
500,000
1.21
0.01
0.35
0.02
1.59
4.09
2.00/MBtu
0.1 2 /kgal
0.029/kWh
2.00/MBtu
17. 00 /man-hr
1,255,800
154,400
1,380,400
(22,000)
1,453,400
26,400
4,748,400
4,943,300
10.28
1.26
11.30
(0.18)
11.90
0.22
38.86
40.46
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6. OX of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion cost less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 22,840
Sodium sulfate 1,830
Net annual revenue requirements
Equivalent unit revenue requirements (net)
2,759,000
4,027,900
989,900
50,000
61,300
7,888,100
12,831,400
tons 25.00/ton (571,000)
tons 23.00/ton (42,100)
12,218,300
5/ton coal $/MBtu heat
Mills/kWh burned input
4.07 8.60 0.45
22.58
32.97
8.10
0.41
0.50
64.56
105.02
(4.67)
(0.35)
100.00
$/ton
S removed
1,531
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,289,200 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 7,240 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $24,301,000; total depreciable investment, §45,983,000; and total
capital investment, $46,836,000.
All tons shown are 2,000 Ib.
H-24
-------
TABLE H-10. WELLMAN-LORD PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 1.4% S In coal;
90% SO- removal; sulfurlc acid production)
Investment, $
% of
total direct
Investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker,
tanks, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack, gas ducts from chloride
261,000
1.0
SCTUDDer to aosoroer;
S0? absorption (four absorbers and entrainment separators,
tanks, pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainraent
separators, tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer, heat
exchanger, pumps, agitator, tank, dryer, conveyors, centri-
fuge, bin, silo, and feeder)
SO- regeneration (evaporators, heat exchangers, strippers,
tanks, agitators, pumps, blower, and condensers)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
4 ,Oi/ ,U
-------
TABLE H-ll. WELLMAN-LORD PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 1.4% S in coal;
90% SO™ removal; sulfuric acid production)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Total raw material cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of
annual revenue
requirements
2,135 tons
610 liters
5,505 tons
25 tons
40,000 man-hr
103.00/ton
2.50/liter
15.00/ton
189.00/ton
12.50/man-hr
219,900
1,500
82,600
4,700
308,700
500,000
1.68
0.01
0.63
0.04
2.36
3.82
1
49
741,
,823,
,414,
16,
1,
500
700
800
400
970
MBtu
kgal
kWh
MBtu
man-hr
2.
0.
0.
2,
17.
.00 /MBtu
.12/kgal
,029/kWh
.00/MBtu
. 00 /man-hr
1,483
218
1,433
(32
1,567
33
5,203
5,511
,000
,800
,000
,800)
,600
,500
,100
,800
11
1
10
(0
11
0
39
42
.35
.67
.95
.25)
.98
.26
.78
.14
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion cost less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 33,920
Sodium sulfate 2,710
Net annual revenue requirements
Equivalent unit revenue requirements (net)
2,961,500
4,326,400
1,050,600
50,000
91,000
8,479,500
13,991,300
tons 25.00/ton (848,000)
tons 23.00/ton (62,300)
13,081,000
$/ton coal $/MBtu heat
Mills/kWh burned input
4.36 12.21 0.48
22.64
33.07
8.03
0.38
0.70
64.82
106.96
(6.48)
(0.48)
100.00
$/ton
S removed
1,104
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit cm-stream time, 6,000 hr/yr.
Coal burned, 972,200 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 10,750 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $26,244,000; total depreciable investment, $49,359,000; and total
capital investment, $50,307,000.
All tons shown are 2,000 Ib.
H-26
-------
TABLE H-12. WELLMAN-LORD PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 2.0% S in coal;
90% SO. removal; sulfuric acid production)
Z of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker,
tanks, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack, gas ducts from chloride
scrubber to absorber)
SO- absorption (four absorbers and entrainment separators,
tanks, pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer , heat
exchanger, pumps, agitator, tank, dryer, conveyors, centri-
fuge, bin, silo, and feeder)
SO- regeneration (evaporators, heat exchangers, strippers,
tanks, agitators, pumps, blower, and condensers)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
348,000
4,842,000
4,577,000
1,216,000
4,874,000
1,980,000
5,468,000
4,045,000
652,000
28,002,000
1,680,000
29,682,000
300,000
29,982,000
2,137,000
529,000
4,218,000
1,273,000
8,157,000
7,628,000
45,767,000
4,547,000
5,492,000
55,806,000
28,000
1,105,000
56,939,000
1
16
15
4
16
6
18
13
2
93
5
99
1
100
1.
1.
14,
4,
27,
25.
152,
15,
18,
186,
0
3,
189.
.2
.1
.3
.1
.2
.6
.2
.5
.2
.4
.6
.0
.0
.0
.1
.8
.1
.2
.2
.4
.6
.2
.3
.1
.1
.7
,9
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
H-27
-------
TABLE H-13. WELLMAN-LORD PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 2.0% S in coal;
90% SO removal; sulfuric acid production)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Total raw material cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost. $
Total
annual
cost, $
% of
annual revenue
requirements
3,385 tons
970 liters
8,295 tons
40 tons
40,000 man-hr
969,100 MBtu
2,798,800 kgal
55,288,400 kWh
26,000 MBtu
2,600 man-hr
103.00/ton
2.50/liter
15.00/ton
189.00/ton
12.50/man-hr
348,700
2,400
124,400
7,600
483,100
500,000
2.35
0.02
0.84
0.05
3.26
3.38
2. 00/MBtu
0.1 2 /kgal
0.029/kWh
2. 00/MBtu
17.00/man-hr
1,938,200
335,900
1,603,400
(52,000)
1,787,900
44,200
6,157,600
6,640,700
13.09
2.27
10.83
(0.35)
12.08
0.30
41.60
44.86
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion cost less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 53,810
Sodium sulfate 4,300
Net annual revenue requirements
Equivalent unit revenue requirements (net)
3,348,400
4,896,800
1,166,100
50,000
144,400
9,605,700
16,246,400
tons 25.00/ton (1,345,300)
tons 23.00/ton (98,900)
14,802,200
$/ton coal $/MBtu heat
Mllls/kWh burned input
4.93 12.06 0.55
22.62
33.08
7.88
0.34
0.98
64.90
109.76
(9.09)
(0.67)
100.00
$/ton
S removed
788
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,113,400 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 17,050 metric tons/yr (18,790 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $29,982,000; total depreciable investment, $55,806,000; and total
capital investment, $56,939,000.
All tons shown are 2,000 Ib.
H-28
-------
TABLE H-H. WELLMAN-LORD PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new lignite-fired power unit, 0.5% S in lignite;
90% SO removal; sulfuric acid production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker,
tanks, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack, gas ducts from chloride
scrubber to absorber)
S0« absorption (four absorbers and entrainment separators,
tanks, pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Sulfate crystallization (evaporator-crystallizer , heat
exchanger, pumps, agitator, tank, dryer, conveyors, centri-
fuge, bin, silo, and feeder)
SO. regeneration (evaporators, heat exchangers, strippers,
tanks, agitators, pumps, blower, and condensers)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
168,000
5,026,000
4,797,000
1,267,000
5,080,000
912,000
2,406,000
1,780,000
293,000
21,729,000
1,304,000
23,033,000
149,000
23,182,000
1,965,000
488,000
3,405,000
1,047,000
6,905,000
6,017,000
36,104,000
3,596,000
4,333,000
44,033,000
28,000
776,000
44,837,000
0
21
20
5.
21
3
10
7
1
93
5,
99
0
100
8
2.
14
4,
29
26
155,
15,
18.
190,
0.
3.
193.
.7
.7
.7
.5
.9
.9
.4
.7
.3
.8
.6
.4
.6
.0
.5
.1
.7
.5
.8
.0
.8
,5
,7
.0
,1
,3
4
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
H-29
-------
TABLE H-15. TOLLMAN-LORD PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW lignite-fired power unit, 0.5% S In lignite;
90% SO. removal; sulfuric acid production)
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Total raw material cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
Annual
quantity
Unit
cost. $
Total
annual.
cost, $
% of
annual revenue
requirements
1,050 tons
300 liters
2,630 tons
10 tons
40,000 man-hr
567,000 MBtu
986,700 kgal
46,872,000 kWh
8,000 MBtu
1,285 man-hr
103.00/ton
2.50/liter
15.00/ton
189.00/ton
12.50/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
108,200
800
39,500
1.900
150,400
500,000
1,134,000
118,400
1,359,300
(16,000)
1,386,500
21.800
4,504,000
4,654,400
0.92
0.01
0.34
0.02
1.29
4.25
9.65
1.01
11.56
(0.14)
11.80
0.18
38.31
39.60
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion cost less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
2,642,000
3,856,000
954,200
50,000
44,700
7,546,900
12,201,300
22.47
32.80
8.12
0.43
0.38
64.20
103.80
Byproduct Sales Revenue
100% sulfuric acid
Sodium sulfate
Net annual revenue requirements
16,640 tons
1,330 tons
25.00/ton
23.00/ton
(416,000)
(30,600)
11,754,700
(3.54)
(0.26)
100.00
Equivalent unit revenue requirements (net)
$/ton lignite $/MBtu heat $/ton
Mills/kWli burned input S removed
3.92 6.88 0.44 2,023
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Lignite burned, 1,550,200 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 5,270 metric tons/yr (5,810 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $23,182,000; total depreciable investment, $44,033,000; and total
capital investment, $44,837,000.
All tons shown are 2,000 Ib.
H-30
-------
TABLE H-16. WELLMAN-LORD PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new oil-fired power unit, 2.5% S in oil;
90% SO- removal; sulfuric acid production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker,
tanks, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack, gas ducts from chloride
scrubber to absorber)
SO absorption (four absorbers, presaturators, and entrainment
separators, tanks, pumps, filters, agitators, and heat
exchangers)
Stack gas reheat (four direct oil-fired reheaters)
Chloride purge
Sulfate crystallization (evaporator-crystallizer, heat
exchanger, pumps, agitator, tank, dryer, conveyors, centri-
fuge, bin, silo, and feeder)
S0_ regeneration (evaporators, heat exchangers, strippers,
tanks, agitators, pumps, blower, and condensers)
Acid production (complete contact unit for sulfuric acid
production)
Acid storage (storage and shipping facilities for 30-day
production of sulfuric acid)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
315,000
4,292,000
4,888,000
1,065,000
-
1,781,000
4,887,000
3,615,000
585,000
21,428,000
1,286,000
22,714,000
1,981,000
495,000
3,339,000
1,031,000
6,846,000
5,912,000
35,472,000
3,547,000
4,257,000
43,276,000
28,000
911,000
44,215,000
1.4
18.9
21.5
4.7
-
7.8
21.5
15.9
2.6
94.3
5.7
100.0
8.7
2.2
14.8
4.5
30.2
26.0
156.2
15.6
18.7
190.5
0.1
4.0
194.6
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by direct oil-fired reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
H-31
-------
TABLE H-17. WELLMAN-LORD PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new oil-fired power unit, 2.5% S in oil;
90% SO^ removal; sulfuric acid production)
Annual
quantity
Direct Costs
Raw materials
Sodium carbonate
Catalyst
Agricultural limestone
Filter aid
Total raw material cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil (No. 6)
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
2,890
830
0
35
40,000
2,078,500
521,300
2,383,600
40,842,900
22,200
2,365
tons
liters
tons
tons
man-hr
gal
MBtu
kgal
kWh
MBtu
man-hr
Unit
cost, S
103
2,
15
189.
12.
0,
2.
0.
0,
2,
17,
.00 /ton
,50/liter
.00 /ton
,00/ton
,50/man-hr
.40/gal
,00/MBtu
. 12 /kgal
.029/kWh
.00/MBtu
. 00/man-hr
Total % of
annual annual revenue
cost, $ requirements
297
2
6
306
500
831
1,042
286
1,184
(44
1,362
40
5,203
5,509
,700
,100
-
,600
,400
,000
,400
,600
,000
,400
,400)
,800
,200
,000
,400
2
0
0
2
4
7
8
2
10
(0
11
0
44
46
.52
.02
-
.06
.60
.24
.04
.83
.42
.04
.38)
.55
.34
.08
.68
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion cost less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
100% sulfuric acid 45,870
Sodium sulfate 3,670
Net annual revenue requirements
Equivalent unit revenue requirements (net)
2,596,600
3,802,500
951,500
50,000
123,100
7,523,700
13,033,100
tons 25.00/ton (1,146,800)
tons 23.00/ton (84,400)
11,801,900
$/bbl oil $/MBtu heat
Mills/kWh burned input
3.93 2.64 0.44
22.00
32.23
8.06
0.42
1.04
63.75
110.43
(9.72)
(0.71)
100.00
$/ton
S removed
737
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Oil burned, 710 x 106 liters/vr (4,464,300 bbl/yr), 2,268 kcal/MJh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175 F).
Sulfur removed, 14,530 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $22,714,000) total depreciable investment, $43,276,000; and total
capital investment, $44,215,000.
All tons shown are 2,000 Ib,
H-32
-------
TABLE H-18. WELLMAN-LORD PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new coal-fired power unit, 3.5% S in coal;
90% SO removal; sulfur production)
% of
total direct
Investment, $ Investment
Direct Investment
Materials handling (conveyors, silos, feeders, bins, shaker,
tanks, and pumps)
Gas handling (common feed plenum and booster fans, gas ducts and
dampers from plenum to absorber, exhaust gas ducts and dampers
from absorber to reheater and stack, gas ducts from chloride
scrubber to absorber)
SO, absorption (four absorbers and entrainment separators,
tanks, pumps, filters, agitators, and heat exchangers)
Stack gas reheat (four indirect steam reheaters)
Chloride purge (four chloride scrubbers and entrainment
separators, tanks, agitators, and pumps)
Sulfate crystallization (evaperator-crystallizer, heat
exchanger, pumps, agitator, tank, dryer, conveyors, centri-
fuge, bin, silo, and feeder)
SO regeneration (evaporators, heat exchangers, strippers,
tanks, agitators, pumps, blower, and condensers)
SO reduction (complete reduction unit)
Sulfur storage (storage and shipping facilities for 30-day
production of sulfur)
Subtotal
Services, utilities, and miscellaneous
Total excluding pond
Pond
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Other Capital Charges
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Total capital investment
503,000
4,861,000
4,595,000
1,221,000
4,894,000
2,934,000
8,297,000
7,600,000
710,000
35,615,000
2,137,000
37,752,000
154,000
37,906,000
2,373,000
590,000
5,118,000
1,521,000
9,602,000
9,502,000
57,010,000
5,686,000
6,841,000
69,537,000
28,000
1,777,000
71,342,000
1.3
12.9
12.1
3.2
12.9
7.7
21,9
20.1
1.9
94.0
5.6
99.6
0.4
100.0
6.3
1.5
13.5
4.0
25.3
25.1
150.4
15.0
18.0
183.4
0.1
4.7
188.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Stack gas reheat to 79°C (175°F) by indirect steam reheat.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
H-33
-------
TABLE H-19. WELLMAN-LORD PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new coal-fired power unit, 3.5% S in coal;
90% SO removal; sulfur production)
Annual
quantity
Unit
cost, $
Total
annual
cost, $
% of
annual revenue
requirements
Direct Costs
Raw materials
Sodium carbonate
Agricultural limestone
Filter aid
Natural gas
Catalyst
Total raw material cost
Conversion costs
Operating labor and supervision
Utilities
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
6,150 tons
2,780 tons
70 tons
489,600 kft3
40,000 man-hr
1,483,200 MBtu
4,190,400 kgal
67,690,100 kWh
66,400 MBtu
3,720 man-hr
103.00/ton
15.00/ton
189.00/ton
3.50/kft3
12.50/man-hr
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
633,500
41,700
13,200
1,713,600
16,700
2,418,700
500,000
2,966,400
502,800
1,963,000
(132,800)
2,269,700
65,100
8,134,200
10,552,900
3.01
0.20
0.06
8.16
0.08
11.51
2.38
14.11
2.39
9.34
(0.63)
10.80
0.31
38.70
50.21
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion cost less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
4,172,200
6,135,400
1,417,400
50,000
145,800
11,920,800
22,473,700
19.85
29.20
6.74
0.24
0.69
56.72
106.93
Byproduct Sales Revenue
Sulfur
Sodium sulfate
Net annual revenue requirements
31,960 tons
7,810 tons
40.00/ton
23.00/ton
(1,278,400)
(179,600)
21,015,700
(6.08)
(0.85)
100.00
Equivalent unit revenue requirements (net)
$/ton coal $/MBtu heat $/ton
Mllls/kWh burned input S removed
7.00
16.34
0.78
616
Basis
Midwest plant location, 1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,200 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Stack gas reheat to 79°C (175°F).
Sulfur removed, 30,950 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $37,906,000; total depreciable investment, $69,537,000; and total
capital investment, $71,342,000.
All tons shown are 2,000 Ib.
H-34
-------
APPENDIX I
CARBON ADSORPTION PROCESS
PROCESS DESCRIPTION
The Bergbau-Forschung/Foster Wheeler process uses dry carbon adsorption
followed by thermal regeneration to reactivate the adsorbent. A four-train
adsorption system, each with a two-stage absorber, is used. The adsorber
•stages are separate but adjacent vessels, each containing louvered moving beds
of activated char. The flow diagram is shown in Figure 1-1. The material
balance is shown in Table 1-1 and the equipment list is ^shown in Table 1-2.
Water is mixed with the hot flue gas to obtain an adsorber inlet tem-
perature of 121°C (250°F). The gas then moves in horizontal crossflow
through a vertical char bed where S02, 803, H20, and 02 are adsorbed.
Although some NOx removal has also been reported the process is not designed
for NOX removal. The char bed also filters out some residual fly ash in the
flue gas. The flue gas leaving the first stage is divided into upper and
lower flow streams. The upper stream flows to the first-stage adsorber ID
fan and then to the stack plenum. The lower stream flows to the second-
stage adsorber and then to a separate ID fan. Because of exothermic reactions
the gases are exhausted about 14°C above the adsorber inlet temperature.
Hence, there is no need for reheat.
The char moves by gravity in the adsorber beds. The velocity ranges
from 0.3 to 0.91 m/hr (1 to 3 ft/hr). Char leaving the adsorbers is satu-
rated with H2S04 formed by reaction between S02, 02, and H20. The saturated
char is screened to remove fly ash and char fines and transported to the
regeneration area. Saturated char and hot sand are gravity-fed into the
regenerator vessel which operates with a reducing atmosphere. Sand enters
the regenerator at 815°C (1500°F) and char enters at the flue gas temperature.
The saturated char is heated to 650°C (1200°F) to liberate the adsorbed gases
and return the char to its activated state. Some char reacts with oxygen
in the gas and is chemically consumed. Sand and regenerated char leave the
regenerator at 650°C (1200°F) and are separated by screens. The char is then
routed to the char cooling area and the sand is heated and returned to the
regenerator.
In the char cooling area, the char is cooled in two stages. First-stage
cooling by indirect heat exchange with cleaned flue gas lowers char tempera-
ture to 200 c. The temperature is reduced to 120°C in the second stage by
direct-contact water spray. The steam produced is unsuitable for use by the
steam plant. It can, however, be used to preheat boiler feedwater. Makeup
char is added to replace losses. The char is then transported back to the
1-1
-------
top of the adsorbers. The sand is simultaneously heated and pneumatically
elevated to the regenerator by combustion gases. The heater gas may be routed
either to the stack or to the adsorbers, depending on whether or not it
contains
TM
SC>2 reduction is accomplished by the Foster Wheeler RESGX process.
The SCL-rich gas is reacted with rice-sized anthracite coal to produce gaseous
elemental sulfur. S02 and air are injected at the bottom of a RESOX reactor
containing downward moving coal. The operating temperature is 800-850°C in
the main reaction zone. In addition to sulfur vapor, some H2S, COS, and CS2
are formed in the reactor. The product gases, flowing out the top of the
reactor at 350-400°C, are routed to a shell and tube exchanger to condense
the sulfur product and produce steam. Recovered sulfur is then collected and
pumped to storage. Noncondensed gases from the sulfur condenser are pumped
to an incinerator to oxidize the remaining sulfur compounds back to S02-
After incineration, the gases are cooled in a steam-producing waste heat
boiler and recycled back to the S02 adsorbers.
SPECIFIC PROCESS PREMISES
1. The adsorbers have superficial velocities of 7.6 m/sec (25 ft/sec) in
channels between the char beds and 0.3 m/sec (1 ft/sec) approaching
the char beds. Pressure drop is 0.5 kPa (2.0 inches t^O) in the first
stage and 0.3 kPa (1 inch H20) in the second stage.
2. The saturated char S02 loading is 7.5 kg of sulfur to 100 kg of char.
ENERGY REQUIREMENTS
For base-case conditions, steam consumption in the S02 reduction and
sulfur storage area totals 1,300 kg/hr (2,860 Ib/hr) of 148°C (298°F) steam
at 450 kPa absolute pressure (50.3 psig) equivalent to about 0.66 x 10*>
kcal/hr. In addition to the steam consumed in this area, steam is produced
in some areas. This, along with heat used to preheat boiler feedwater, is
taken into account as a heat credit. The waste heat boiler produces 4,600
kg/hr (10,100 Ib/hr) of 121°C (250°F) steam at 210 kPa absolute pressure
(15.1 psig) equivalent to about 2.79 x 10^ kcal/hr. The sulfur production
unit produces 17,400 kg/hr (38,300 Ib/hr) of 121°C (250°F) steam at 210 kPa
absolute pressure (15.1 psig) equivalent to about 10.58 x 10^ kcal/hr. The
waste heat from the char cooler is used to preheat boiler feedwater from
38°C (100°F) to 88°C (190°F). This is equivalent to about 1.45 x 106 kcal/hr.
The electrical power demand for the base-case carbon adsorption process
is about 2,650 kW or 0.53% of the rated capacity of a 500-MW power plant.
For 6,000 hours of operation, the annual electrical energy consumption is
15.92 x 106 kWh.
1-2
-------
Fuel oil is used as a source of energy at an annual rate of 15.48 x 10
liters (4.09 x 106 gal), equivalent to about 22.54 x 106 kcal/hr, to heat
sand. For SC^ reduction the annual consumption is 3.12 x 10° liters (0.82
x 10^ gal). The total fuel oil consumption for energy is equivalent to
27.10 x 10^ kcal/hr. There is no reheat steam required for this process.
The total equivalent energy consumption for the base case is approxi-
mately 19.02 x 106 kcal/hr or 1.68% of the input energy required for the
500-MW power unit. Summarized energy requirements for all cases are listed
in Table 1-3.
BYPRODUCT MANAGEMENT
ESP units remove 99.2% of the fly ash from the flue gas; some addi-
tional fly ash is removed with the char fines. The char fines and RESOX
waste may be burned in the boiler. These two materials have been assigned
a monetary value based on their heating values and are treated as salable
byproducts in the determination of net annual revenue requirements. (Fly
ash emission from oil-fired units does not exceed the EPA particulate
emission standard and fly ash collection facilities are not included in
oil-fired power plant design.) Projected mass flow rates of byproduct
streams are shown below.
Component Kg/hr Lb/hr
Sulfur: Sulfur 4,900 10,900
Other: Char fines 1,660 3,660
Fly ash 150 330
RESOX waste 2,600 5,700
4,410 9,690
ECONOMIC EVALUATION
Capital investment and annual revenue requirement summaries for the
base case and five fuel variations are shown in Tables 1-4 and 1-5. The
detailed results are shown in Tables 1-6 through 1-19. The same results
showing the range of estimated accuracies are shown graphically in Figures
1-2 and 1-3. The effect of fuel sulfur content on costs is shown in
Figure 1-4.
1-3
-------
00
cd
•H
I
0)
0)
0)
o
a
c
o
a,
>4
o
a>
-a
a
o
•8
«
u
(U
M
60
1-4
-------
TABLE 1-1. CARBON ADSORPTION PROCESS
MATERIAL BALANCE - BASE CASE (3.5% SULFUR COAL)
Description
1
;
)
/4
5
6
7
8
4
JO
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, Nm5/hr (0°C)
Gas flow, sft3/min (60°F,
Temperature, °C
Particulates, ks/hr
Particulates, Ib/hr
1
Coal
to boiler
194
428,600
2
Combustion air
to air heater
2.062
4,546,200
1,615,700
1,005,000
27
3
Flue gas
to adsorber
2.225
4,906,000
1,697,700
1,056,000
149
200
439
4
Gas to
stack
2.311
5,094,500
1,782,400
1,106,200
153
50
110
5
Makeup sand
0.45
1,000
Stream No.
Description
1
1
)
4
r>
h
7
8
9
If)
Total stream, 1000 kg/hr
Total stream, Ib/hr
Gas flow, NmJ/hr (0°C)
Gas flow, sf t3/min (60°F
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Pressure. kPa (abs)
Pressure. DSig
6
Fuel oil
2.7
5,980
50
13
7
Process air
55.0
121,200
42, $06
26,400
27
8
Makeup char
2.4
5,210
9
Process steam
1.3
2,860
148
0.45 x 10J
50.3
10
Boiler
f eedwater
22.0
48,400
370
100
38
Stream No.
Description
1
1
3
4
ri
h
/
X
9
ID
Total stream, 1000 kg/hi
Total stream, Ib/hr
Gas flow, Nm^/hr (OOC)
Gas flow, sft3/min(60°F)
Liquid flow, liters/min
Liquid flow, gal/min
Temperature, °C
Pressure. kPa (abs)
Pressure, psig
11
RESOX off -gas
38.3
84,400
32,700
20,300
149
12
Steam to
steam plant
22.0
48,400
121
0.2 x 103
15.1
13
Sand heater
off-gas
41.9
92,300
32,600
20,200
816
14
Char to
adsorber
74.6
164,600
121
15
Flue gas
cooling water
25.5
56,300
426
113
27
Stream No.
1
I
1
4
•>
6
7
8
9
IU
Description
Total stream, 1000 kg/hi
Total stream. Ib/hr
Liquid floWj liters/min
Liquid flow, gal/min
Temperature, °C
Undissolved solids, %
Gas flow, Nm3/hr (0°C)
Gas flow, sf t-Vmin (60°F)
Specific gravity
16
Anthracite
coal to RESOX
5.0
11,100
17
RESOX
waste coal
to boiler
2.6
5,700
18
Boiler
f eedwater
from
char cooler
28.9
63,800
482
127
85
19
Flue gas to
char cooler
171.8
378,800
135
132,400
82,300
20
Flue gas from
char cooler
171.8
378,800
371
132,400
82,300
(continued)
1-5
-------
TABLE 1-1. (continued)
fj^ream Nor
Description
1
2
)
4
5
h
7
8
9
1°
Total stream. 1000 kK/hr
Total stream, Ib/hr
Gas flow. Nm3/hr (0°C)
Gas flow. sft3/min(60°F)
Liquid flow, liters/min
Liquid flow, gal/min
Temoerature. °C
Pressure, kPa
Pressure, psig
21
Char fines
to boiler
1.8
3,990
135
22
Product sulfur
4.9
10,900
46
12
138
6
~y
8
9
10
4
5
h
7
8
9
10
4
5
ft
7
8
9
10
1-6
-------
TABLE 1-2. CARBON ADSORPTION PROCESS
BASE-CASE EQUIPMENT LIST
DESCRIPTION AND COST
Area 1 — Materials Handling
Item
1. Car shaker
2. Car puller
3. Hopper, unloading
No. Description
1 Top mounting with
crane
1 25 hp with 5 hp
return
1 12 ft x 20 ft x 2 ft
Area size-cost
exponent 0.63
Total
material
cost,
1979 $
9,000
50,000
9,300
Total
labor
cost,
1979 $
2,100
2,100
8,700
4. Feeder, unloading
5. Conveyor, unloading
6. Conveyor, stocking
(inclined, enclosed)
Conveyor, char
stocking
(enclosed)
Elevator, char
storage
bottom, 20 ft deep,
4,800 ft3, carbon
steel
Vibrating pan, 36 in. 4,800 1,100
wide x 60 in. long,
2 hp, 120 tons/hr
Belt, 30 in. wide x 10 2,000 1,000
ft long, 1 hp, 120
tons/hr, 200 ft/min
Belt, 30 in. wide x 27,000 10,000
200 ft long, 15 hp,
15° slope, 120 tons/hr,
200 ft/min
Belt, 30 in. wide x 40 9,100 4,400
ft long, 1-1/2 hp, 120
tons/hr, 200 ft/min
Continuous, bucket 16 44,900 2,000
in. x 12-5/8 in. x
17-5/8 in., 30 hp,
85 ft lift, 120 tons/
hr, 100 ft/min, with
diverter gate
(continued)
1-7
-------
TABLE 1-2. (continued)
Item
9. Silo, char storag<
No.
* 2
Description
40 ft dia x 40 ft
Total
material
cost,
1979 $
105,500
Total
labor
cost,
1979 $
241,600
10. Feeder, reclaim
11. Conveyor, live char
(inclined, enclosed)
straight side, 50,300
ft3, 60° slope, 3/8
in. carbon steel
Vibrating pan, 3
tons/hr
Belt, 14 in. wide x
200 ft long, 1-1/2 hp,
11° slope, 3 tons/hr,
25 ft/min
12.
13.
14.
15.
16.
Conveyor , sand
Bin, sand storage
Feeder, reclaim
Tank, fuel oil
Pump, fuel oil
Subtotal
1 Pneumatic, pressure,
125 hp
1 18-1/2 ft dia x 27 ft
straight side, w/cover
1 Vibrating pan, 1,000
Ib/hr
1 46-1/2 ft dia x 46-1/2
ft high, 590,800 gal,
covered top, carbon
steel
2 Centrifugal, 14 gpm,
200 ft head, 2 hp,
carbon steel
(1 operating, 1 spare)
100,000
13,300
7,000
53,300
3,500
487,300
20,000
23,200
2,100
99,200
1,300
434,000
(continued)
1-8
-------
TABLE 1-2. (continued)
Area 2—Feed Preparation
Area size-cost
exponent
Note; No equipment in this area.
Area 3—Gas Handling
Area size-cost
exponent 0.68
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
1. Fan, first-stage
adsorber
2. Fan, second-stage
adsorber
Subtotal
Induced draft, 4 in. 366,000 30,000
static head, 890 rpm, 400
hp, fluid drive, double
width, double inlet
Induced draft, 5 in. 370,000 30,000
static head, 890 rpm,
450 hp, fluid drive, double
width, double inlet
736,000 60,000
Area 4—S02 Adsorption
Area size-cost
exponent 0.79
Item
1. Adsorders, first stage
No.
4 M<
Description
sving-bed adsorber,
Total
material
cost,
1979 $
5,026,000
Total
labor
cost,
1979 $
401,000
2. Adsorbers, second
stage
58 ft long x 28 ft wide
x 84 ft high, 1/4 in.
carbon steel shell,
louvered beds, 5/8 in.
carbon steel louvers,
carbon adsorbent
Moving-bed adsorber, 2,933,500
58 ft long x 28 ft wide
x 54 ft high, 1/4 in.
carbon steel shell,
louvered beds, 5/8 in.
carbon steel louvers,
carbon adsorbent
(continued)
300,600
1-9
-------
TABLE 1-2. (continued)
Total
material
cost,
Item No. Description 1979 $
3. Feeder, adsorber 144 Weigh, vibratory, 10 172,800
Total
labor
cost,
1979 $
86,400
discharge
4. Conveyor, adsorber
discharge (enclosed)
5. Screens
6. Conveyor, char
collection
(enclosed)
Conveyor, char
surge bin feed
(enclosed)
Conveyor-elevator
char surge bin
9. Hopper, char
fines/fly ash
collection
10. Conveyor, char
fines/fly ash
11. Bin, char feed
Insulation
in. wide x 36 in.
long, 1,420 Ib/hr
Oscillating, 120 ft 202,400
long, 4 in. deep x 20
in. wide trough, 10
hp, 13 tons/hr, 20
ft/min, carbon steel
36 in. wide x 96 in. 31,100
long, carbon steel
Pivoted buckets, 30 104,600
in. x 24 in, 20 hp,
200 ft long, 100
tons/hr, 100 ft/min
Pivoted buckets, 30 68,000
in. x 24 in., 15 hp,
130 ft long, 100
tons/hr, 100 ft/min
Pivoted buckets, 30 96,300
in. x 24 in., 25 hp,
35 ft long, 130 ft lift,
100 tons/hr, 100 ft/min,
with diverter gate
36 in. wide x 96 in. long, 1,500
5 ft deep, 1/2 ft bottom
Pneumatic, pressure, 40
hp
18 ft dia x 24 ft
straight side, w/cover,
carbon steel
37,700
84,600
44,200
60,700
2,200
31,400
20,400
25,900
2,900
8,600
151,300
44,200
1-10
-------
Area 5—Reheat
TABLE 1-2. (continued)
Item
12. Pump, flue gas
cooling water
Subtotal
No. Description
2 Centrifugal, 110 gpm,
150 ft head, 15 hp,
carbon steel
(1 operating, 1 spare)
Total
material
cost,
1979 $
8,200
8,810,900
Total
labor
cost,
1979 $
1,600
1,137,200
Area size-cost
exponent 0.65
Note; No equipment in this area.
Area 6—Regeneration
Area size-cost
exponent 0.65
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Bin, saturated
char surge
Insulation
2. Feeder, surge bin
discharge
3. Regenerator
Lining
14 ft dia x 14 ft
straight side,
w/cover
Weigh, vibratory, 12
in. x 36 in. trough,
50 tons/hr, carbon
steel
Moving bed, 13 ft
inside dia x 26 ft
straight side, carbon
steel
12 in. firebrick, 8
in. insulation brick
(continued)
11,400
6,600
24,400
23,500
151,900
19,600
6,600
4,200
40,500
20,400
1-11
-------
TABLE 1-2. (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
4. Feeder, regenerator
discharge
5. Separator,
char/sand
Subtotal
primary
2. Char cooler,
secondary
Conveyor, char
cooling
3.
Heater, boiler
feedwater
Weigh, vibratory, 42
in. x 60 in. trough,
270 tons/hr, 316
stainless steel
8 ft wide x 24 ft
long, 316 stainless
steel
38,400
4,400
89.000
8.800
345.200 104,500
Area 7 — Char Cooling
Item
1. Char cooler,
Area size-cost
exponent 0.69
Total
material
cost.
No. Description 1979 $
2 Tube type* 2,650 ft2, 143,000
Total
labor
cost,
1979 $
122,800
316 stainless steel
tubes
Direct cooling spray 6,300 12,000
chamber, 5 ft wide x
30 ft long x 5 ft high,
carbon steel construc-
tion
Oscillating, 25 ft long, 10,000 3,000
4 in. deep x 36 in.
wide trough, 2 hp, 40
tons/hr, 50 ft/min,
carbon steel
Plate and frame, 350 7,500 1,000
ft2, 316 stainless
steel
(continued)
1-12
-------
TABLE 1-2. (continued)
Item
No.
Description
Total
material
cost,
1979 $
Total
labor
cost,
1979 $
4. Pump, char cooling
water circulation
5. Fan, flue gas
diversion
6. Hopper, cooled
char collection
7. Feeder, char hopper
discharge
8. Conveyor, cooled
char
Conveyor elevator,
first-stage
adsorber char
10. Conveyor-elevator,
second-stage adsorber
char
Subtotal
Centrifugal, 12 gpm,
60 ft head, 1/2 hp,
carbon steel, neoprene
lined
(1 operating, 1 spare)
Forced draft, 5 in.
static head, 116,300
aft3/min, 150 hp
5 ft wide x 20 ft long,
10 ft deep, w/cover,
carbon steel
Vibrating pan, 80
tons/hr
Pivoted buckets, 30 in.
x 24 in., 25 hp, 240
ft long, 80 tons/hr,
100 ft/min
Pivoted buckets, 20 in.
x 20 in., 25 hp, 200
ft long, 150 ft lift,
40 tons/hr, 100 ft/min
Pivoted buckets, 20 in.
x 20 in., 20 hp, 200 ft
long, 120 ft lift, 40
tons/hr, 100 ft/min
3,300
84,900
1,300
9,600
110,400
121,500
111.000
608.800
1,200
7,000
2,500
2,200
33,100
36,400
33,300
254,500
(continued)
1-13
-------
TABLE 1-2. (continued)
Area 8—Sand Heating
Area size-cost
exponent 0.69
Item
No.
Description
Total Total
material labor
cost, cost,
1979 $ 1979 $
1. Hopper, sand
collection
Lining
2. Feeder, sand hopper
discharge
3. Heater/elevator,
sand
Lining
4. Dust collector
5. Blower, air
6. Air preheater
7. Waste heat boiler
Subtotal
10 ft wide x 20 ft
long x 10 ft deep,
carbon steel
12 in. firebrick, 8
in. insulation brick
Weigh, screw, 24 in.
dia x 15 ft long, 40
hp, 230 tons/hr, 316
stainless steel
Pneumatic, pressure,
28 in. inside dia, 100
ft lift, 230 tons/hr,
carbon steel
12 in. firebrick, 8 in.
insulation brick
Cyclone, 38,100 aft3/
min, carbon steel,
refractory lined
Single-stage centrifu-
gal, 9,630 sft3/min,
400 hp, 316 stainless
steel
Tube type, 7,600 ft2,
316 stainless steel
shell, tubes, and
heads
Tube type, 3,200 ft3,
316 stainless steel
tubes and heads
8,400
25,000
77,200
33,800
111,000
131,200
299,600
67.200
16,000
7,000
4,200
64,400
14,900
6,000
3,000
235,200 235,200
67,200
988,600 417,900
(continued)
1-14
-------
TABLE 1-2. (continued)
Area
1.
9 — S02 Reduction
Item
S02 reduction
unit
Subtotal
Area
size-cost
exponent 0.80
Total
material
cost,
No. Description 1979 $
1 RESOX (TM), complete 7,800,000
unit, battery limit
7,800,000
Total
labor
cost,
1979 $
_
-
Area 10—Sulfur Storage and Shipping
Area size-cost
exponent 0.68
Item
1. Pit, sulfur
No.
1
Description
10 ft wide x 10 ft
Total
material
cost,
1979 $
3,600
Total
labor
cost,
1979 $
6,800
receiving
Insulation
Heater
2. Pump, sulfur
transfer
3. Tank, sulfur
storage
long x 10 ft deep,
w/cover, 304 stain-
less steel
Steam, 100 ft2, 400
ft of 1 in. schedule
40, 304 stainless
steel
Centrifugal, 13 gpm,
100 ft head, 2 hp, 316
stainless steel, high
temperature, steam
traced and insulated
(1 operating, 1 spare)
45 ft dia x 46 ft high,
696,900 gal, w/cover,
304 stainless steel
(continued)
1,000
1,000
5,000
83,700
1,500
1,500
500
275,000
1-15
-------
TABLE 1-2. (continued)
Item
3. continued
Insulation
Heater
Total
material
cost,
No. Description 1979 $
15,700
1 Steam, 300 ft2, 1,200 2,400
Total
labor
cost,
1979 $
15,700
4,000
4. Pump, sulfur
shipping
Subtotal
ft of 1 in. schedule
40, 304 stainless
steel
Centrifugal, submerged,
60 gpm, 100 ft head,
5 hp, 316 stainless
steel, steam traced
and insulated
6,500
600
118,900 305.600
1-16
-------
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TABLE 1-4. CARBON ADSORPTION PROCESS CAPITAL INVESTMENT
Case
Total capital investment
$ $/kW
500-MW unit
Coal, 3.5% sulfur
(base case)
Coal, 0.8% sulfur
Coal, 1.4% sulfur
Coal, 2.0% sulfur
Lignite, 0.5% sulfur
Oil, 2.5% sulfur
73,511,000 147
51,195,000 102
54,220,000 108
60,834,000 122
49,485,000 99
53,730,000 107
TABLE 1-5. CARBON ADSORPTION PROCESS ANNUAL REVENUE REQUIREMENTS
Case
Mills/kWh
$/ton coal
(bbl oil)
burned
$/MBtu heat
input
$/ton
sulfur
removed
500-MW unit
Coal, 3.5% sulfur 28,489,400 9.50
(base case)
Coal, 0.8% sulfur 13,899,100 4.63
Coal, 1.4% sulfur 15,803,600 5.27
Coal, 2.0% sulfur 19,982,700 6.66
Lignite, 0.5% sulfur 12,780,100 4.26
Oil, 2.5% sulfur 17,542,200 5.85
22.16
9.78
14.75
16.28
7.48
3.93
1.06
0.51
0.59
0.74
0.47
0.65
835
1,742
1,334
1,063
2,200
1,095
1-18
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CASE VARIATIONS IDENTIFIED BY FUEL TYPE AND SULFUR CONTENT OF FUEL, %
Figure 1-3. Carbon adsorption process annual revenue requirements range.
anN3Aa>i
1-20
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1-21
-------
TABLE 1-6. CARBON ADSORPTION PROCESS
SUMMARY OF ESTIMATED CAPITAL INVESTMENT
(500-MW new, coal-fired power unit,
3.5% sulfur in coal; 90% S02 removal; sulfur production)
Direct Investment
Materials handling (conveyors, elevators, feeders, silo,
and bin)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers to adsorber, exhaust gas ducts and dampers from
adsorber to stack)
S02 adsorption (four two-stage moving-bed adsorbers,
feeders, conveyors, screens, elevators, and bins)
Regeneration and product gas treatment (bins, feeders,
regenerators, tank, agitator, and pump)
Char cooling (two-stage char coolers, fan, conveyors,
and elevators)
Sand heating (heater/elevators and blowers)
RESOX S02 reduction (reduction unit complete, battery
limits)
Sulfur storage and shipping (tanks, heaters, and pumps)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Char charge
Total capital investment
Investment, $
2,132,000
3,970,000
13,120,000
1,675,000
1,385,000
2,768,000
7,800,000
727,000
33,577,000
2,015,000
35,592,000
2,448,000
612,000
4,848,000
1,450,000
9,358,000
8,990.000
53,940,000
5,394,000
6,473,000
65,807,000
42,000
3,507,000
4.155,000
73.511 ,000
% of
total direct
investment
6.0
11.1
36.9
4.7
3.9
7.8
21.9
2.0
94.3
5.7
100.0
6.9
1.7
13.6
4.1
126.3
25.3
151.6
15.1
18.2
184.9
0.1
9.8
11.7
206.5
,
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Investment requirements far fly ash removal and disposal excluded; FfiD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
1-22
-------
TABLE 1-7. CARBON ADSORPTION PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, coal-fired power unit,
3.5% sulfur in coal; 90% S02 removal; sulfur production)
Annual
quantity
Direct Costs
Raw materials
Sand 3,000 tons
Char 15,600 tons
Anthracite coal 33,300 tons
Total raw materials cost
Conversion costs
Operating labor and supervision 40,000 man-hr
Utilities
Fuel oil 4,917,800 gal
Steam 15,600 MBtu
Electricity 15,918,400 kWh
Heat credit 352,800 MBtu
Maintenance
Labor and material
Analyses 3,720 man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
Elemental sulfur 32,700 tons
RESOX waste coal 17,200 tons
Adsorber char fines 12,000 tons
Net annual revenue requirements
Mills /kWh
Equivalent unit revenue requirements (net) 9. 50
Unit
cost. $
7.50/ton
750. 00/ton
57. 00/ton
12.50/man-hr
0.40/gal
2. 00 /MBtu
0 l?/kaal
v . at Kgai.
0.029/kWh
2 . 00/MBtu
17.00/raan-hr
40. 00/ton
26.50/ton
19. 00/ton
$/ton
coal burned
22.16
Total
annual
cost, $
22,500
11,700,000
1,898,100
13,620,600
500,000
1,967,100
31,200
4. 900
461,600
(705,600)
2,491,400
63,200
4,813,800
18,434,400
3,948,400
6,321,900
1,527,300
50,000
199.200
12,046,800
30,481,200
(1,308,000)
(455,800)
(228,000)
28,489,400
$/MBtu
heat input
1.06
% of net
annual revenue
requirements
0.08
41.07
6.66
47.81
1.76
6.90
0.11
0.02
1.62
(2.48)
8.75
0.22
16.90
64.71
13.86
22.19
5.36
0.18
0.70
42.29
107.00
(4.59)
(1.61)
(0.80)
100.00
$/ton
sulfur removed
835
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,166,200 metric tons/yr (1,285,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Sulfur removed, 30,950 metric tons/yr (34,120 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $35,592,000; total depreciable investment, $65,807,000; and total
capital investment, $73,511,000.
All tons shown are 2,000 Ib.
1-23
-------
TABLE 1-8. CARBON ADSORPTION PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, coal-fired power unit,
0.8% sulfur in coal, 90% S02 removal; sulfur production)
% of
total direct
Investment. $ investment
Direct Investment
Materials handling (conveyors, elevators, feeders, silo,
and bin)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers to adsorber, exhaust gas ducts and dampers from
adsorber to stack)
S02 adsorption (four two-stage moving-bed adsorbers, feeders,
conveyors, screens, elevators, and bins)
Regeneration and product gas treatment (bins, feeders,
regenerators, tank, agitator, and pump)
Char cooling (two-stage char coolers, fan, conveyors,
and elevators)
Sand heating (heater/elevators and blowers)
RESOX S02 reduction (reduction unit complete, battery
limits)
Sulfur storage and shipping (tanks, heaters, and pumps)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Char charge
Total capital investment
853,000
4,037,000
13,369,000
652,000
508,000
1,016,000
2,441,000
220,000
23,146,000
1,389,000
24,535,000
1,644,000
411,000
3,560,000
1,093,000
6,708,000
6,249,000
37,492,000
3,749,000
4,499,000
45,740,000
42,000
1,153.000
4,260,000
51,195,000
3.5
16.4
54.5
2.7
2.1
4.1
9.9
1.1
94.3
5.7
100.0
6.7
1.7
14.5
4.4
27.3
25.5
152.8
15.3
18.3
186.4
0.2
4.7
17.4
208.7
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
1-24
-------
TABLE 1-9. CARBON ADSORPTION PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, coal-fired power unit,
0.8% sulfur in coal; 90% S02 removal; sulfur production)
Annual
quantity
Direct Costs
Raw materials
Sand
Char
Anthracite coal
Total raw materials cost
Conversion costs
Operating labor and supervision
Utilities
Fuel oil
Steam
Process water
Electricity
Heat credit
Maintenance
Labor and material
Analyses
Total conversion costs
Total direct costs
3,
7,
40,
1,149,
3,
41,
10,199,
82,
1,
700
600
800
000
800
600
500
000
500
560
tons
tons
tons
man-hr
gal
MBtu
kgal
kWh
MBtu
man-hr
Unit
cost, $
7.
750.
57.
12.
0.
2.
0.
0.
2.
17.
50/ton
00 /ton
00/ton
50/man-hr
40/gal
00 /MBtu
12/kgal
029/kWh
00/MBtu
00/man-hr
Total % of net
annual annual revenue
cost, $ requirements
5,
2,700,
444,
3,149,
500,
459,
7,
5,
295,
(165,
1,717,
26,
2,846,
5,996,
300
000
600
900
000
900
200
000
800
000)
500
500
900
800
0.
19.
3.
22,
,04
,42
.20
.66
3.60
3.
0.
0.
2,
(1,
12,
0.
20.
43,
.31
05
,04
,13
,19)
.35
.19
48
.14
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
Elemental sulfur 7,600 tons 40. 00/ton
RESOX waste coal 40,200 tons 26. 50/ton
Adsorber char fines 2,800 tons 19. 00/ton
Net annual revenue requirements
$/ton
Mills/kWh coal burned
Equivalent unit revenue requirements (net) 4.63 9.78
2,744,400
4,402,800
1,122,000
50,000
46 , 300
8,365,500
14,362,300
(304,000)
(106,000)
(53,200)
13,899,100
$/MBtu
heat input
0.51
19.75
31.68
8.07
0.36
0.33
60.19
103.33
(2.19)
(0.76)
(0.38)
100.00
$/ton
sulfur removed
1,742
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,288,900 metric tons/yr (1,421,100 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Sulfur removed, 7,240 metric tons/yr (7,980 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash, excluded.
Total direct investment, $24,535,000; total depreciable investment, $45,740,000; and total
capital investment, $51,195,000.
All tons shown are 2,000 Ib.
1-25
-------
TABLE 1-10. CARBON ADSORPTION PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, coal-fired power unit,
1.4% sulfur in coal; 90% S02 removal; sulfur production)
Direct Investment
Materials handling (conveyors, elevators, feeders, silo,
and bin)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers to adsorber, exhaust gas ducts and dampers from
adsorber to stack)
S02 adsorption (four two-stage moving-bed adsorbers, feeders,
conveyors, screens, elevators, and bins)
Regeneration and product gas treatment (bins, feeders,
regenerators, tank, agitator, and pump)
Char cooling (two-stage char coolers, fan, conveyors,
and elevators)
Sand heating (heater/elevators and blowers)
RESOX S02 reduction (reduction unit complete, battery
limits)
Sulfur storage and shipping (tanks, heaters, and pumps)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense '
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Char charge
Total capital investment
Investment , $
1,096,000
3,942,000
13,015,000
843,000
668,000
1,334,000
3,346,000
354,000
24,598,000
1,476,000
26,074,000
1,780,000
445,000
3,744,000
1,144,000
7,113,000
6,638,000
39,825,000
3,983,000
4,779,000
48,587,000
42,000
1,473,000
4,118,000
54,220,000
% of
total direct
investment
4.2
15.1
49.9
3.2
2.6
5.1
12.8
1.4
94.3
5.7
100.0
6.8
1.7
14.4
4.4
27.3
25.5
152.8
15.3
18.3
186.4
0.2
5.6
15.8
208.0
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
1-26
-------
TABLE 1-11. CARBON ADSORPTION PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, coal-fired power unit;
1.4% sulfur in coal; 90% S02 removal; sulfur production)
Annual
quantity
Direct Costs
Raw materials
Sand 1,000 tons
Char 5,400 tons
Anthracite coal 11,600 tons
Total raw materials cost
Conversion costs
Operating labor and supervision 40,000 man-hr
Utilities
Fuel oil 1,149,800 gal
Steam 5,400 MBtu
Process water 40,100 kgal
Electricity 10,811,300 kWh
Heat credit 122,500 MBtu
Maintenance
Labor and material
Analyses 1,970 man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
Elemental sulfur 11,400 tons
RESOX waste coal 6,000 tons
Adsorber char fines 4,200 tons
Net annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements (net) 5.27
Unit
cost, $
7.50/ton
7 50. OO/ ton
57.00/ton
12. 50 /man-hr
0.40/gal
2. 00 /MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17.00/man-hr
40.00/ton
26.50/ton
19.00/ton
$/ton
coal burned
14.75
Total
annual
cost, $
7,500
4,050,000
661,200
4,718,700
500,000
459,900
10,800
4,800
313,500
(245,000)
1,825,200
33,500
2,902,700
7,621,400
2,915,200
4,662,900
1,179,400
50,000
69,500
8,877,000
16,498,400
(456,000)
(159,000)
(79,800)
15,803,600
$/MBtu
heat input
0.59
% of net
annual revenue
requirements
0.05
25.63
4.18
29.86
3.16
2.91
0.07
0.03
1.98
(1.55)
11.55
0.21
18.36
48.22
18.45
29.51
7.46
0.32
0.44
56.18
104.40
(2.89)
(1.01)
(0.50)
100.00
$/ton
sulfur removed
1,334
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 971,900 metric tons/yr (1,071,600 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Sulfur removed, 10,750 metric tons/yr (11,850 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $26,074,000; total depreciable investment, $48,587,000; and total
capital investment, $54,220,000.
All tons shown are 2,000 Ib.
-------
TABLE 1-12. CARBON ADSORPTION PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, coal-fired power unit,
2.0% sulfur in coal; 90% S02 removal; sulfur production)
Direct Investment
Materials handling (conveyors, elevators, feeders, silo,
and bin)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers to adsorber, exhaust gas ducts and dampers from
adsorber to stack)
S02 adsorption (four two-stage moving-bed adsorbers, feeders,
conveyors, screens, elevators, and bins)
Regeneration and product gas treatment (bins, feeders,
regenerators, tank, agitator, and pump)
Char cooling (two-stage char coolers, fan, conveyors,
and elevators)
Sand heating (heater/elevators and blowers)
RESOX S02 reduction (reduction unit complete, battery
limits)
Sulfur storage and shipping (tanks, heaters, and pumps)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modifications
Interest during construction
Total depreciable Investment
Land
Working capital
Char charge
Total capital investment
Investment, $
1,465,000
3,954,000
13,068,000
1,137,000
918,000
1,835,000
4,836,000
485,000
27,698,000
1,662,000
29,360,000
2,004,000
501,000
4,132,000
1,252,000
7,889,000
7,450.000
44,699,000
4,470,000
5,364,000
54,533,000
42,000
2,126,000
4,133,000
60,834,000
% of
total direct
investment
5.0
13.5
44.5
3.9
3.1
6.2.
16.5
1.6
94.3
5.7
100.0
6.8
1.7
14.1
4.3
26.9
25.4
152.3
15.2
18.3
185.8
0.1
7.2
14.1
207.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process Investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
1-2 «
-------
TABLE 1-13, CARBON ADSORPTION PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, coal-fired power unit;
2.0% sulfur in coal; 90% S02 removal; sulfur production)
Annual
quantity
Direct Costs
Raw materials
Sand 1,700 tons
Char 8,600 tons
Anthracite coal 18,300 tons
Total raw materials cost
Conversion costs
Operating labor and supervision 40,000 man-hr
Utilities
Fuel oil 2,708,200 gal
Steam 8,600 MBtu
Process water 40,300 kgal
Electricity 10,165,000 kWh
Heat credit 194,300 MBtu
Maintenance
Labor and material
Analyses 2,600 man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
Elemental sulfur 18,000 tons
RESOX waste coal 9,500 tons
Adsorber char fines 6,600 tons
Net annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements (net) 6.66
Unit
COStj $
7. 50/ton
750.00/ton
57.00/ton
12.50/man-hr
0.40/gal
2.00/MBtu
0.12/kgal
0.029/kWh
2.00/MBtu
17 . 00/man-hr
40.00/ton
26. 50/ton
19.00/ton
$/ton
coal burned
16.28
Total
annual
cost, $
12,800
6,450,000
1,043,100
7,505,900
500,000
1,083,300
17,200
4,800
294,800
(388,600)
2,055,200
44,200
3,610,900
11,116,800
3,272,000
5,231,700
1,299,700
50,000
109^700
9,963,100
21,079,900
(720,000)
(251,800)
(125,400)
19,982,700
$/MBtu
heat input
0.74
X of net
annual revenue
requirements
0.06
32.28
5.22
37.56
2.50
5.42
0.09
0.02
1.48
(1.94)
10.28
0.22
18.07
55.63
16.37
26.18
6.50
0.25
0.55
49.85
105.48
(3.60)
(1.25)
(0.63)
100. 00
$/ton
sulfur removed
1,063
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Coal burned, 1,113,200 metric tons/yr (1,227,300 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Sulfur removed, 17,040 metric tons/yr (18,790 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $29.360,000; total depreciable investment, $54,533,000; and total
capital Investment, $60,834,000,
All tons shown are 2,000 Ib.
1-29
-------
TABLE 1-14. CARBON ADSORPTION PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, lignite-fired .power unit, 0.5% sulfur in lignite;
90% S02 removal; sulfur production)
% of
total direct
Investment, $ investment
Direct Investment
Materials handling (conveyors, elevators, feeders, silo,
and bin)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers to adsorber, exhaust gas ducts and dampers from
adsorber to stack)
S02 adsorption (four two-stage moving-bed adsorbers, feeders,
conveyors, screens, elevators, and bins)
Regeneration and product gas treatment (bins, feeders,
regenerators, tank, agitator, and pump)
Char cooling (two-stage char coolers, fan, conveyors,
and elevators)
Sand heating (heater/elevators and blowers)
RESOX S02 reduction (reduction unit complete, battery
limits)
Sulfur storage and shipping (tanks, heaters, and pumps)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Char charge
Total capital investment
699,000
4,105,000
13,645,000
529,000
409,000
817,000
1,895,000
218,000
22,317,000
1,339,000
23,656,000
1,563,000
391,000
3,454,000
1,063,000
6,471,000
6,025,000
36,152,000
3,615,000
4,338,000
44,105,000
42,000
973,000
4,365,000
49,485,000
2.9
17.4
57.7
2.3
1.7
3.4
8.0
0.9
94.3
5.7
100.0
6.6
1.6
14.6
4.5
27.3
25.5
152.8
15.3
18.3
186.4
0.2
4.1
18.5
209.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay Incentive not considered.
1-30
-------
TABLE 1-15. CARBON ADSORPTION PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, lignite-fired power unit;
0.5% sulfur in lignite; 90% S02 removal; sulfur production)
Annual
quantity
Direct Costs
Raw materials
Sand 500 tons
Char 2,700 tons
Anthracite coal 5,700 tons
Total raw materials cost
Conversion costs
Operating labor and supervision 40,000 man-hr
Utilities
Fuel oil 837,500 gal
Steam 2,700 MBtu
Process water 42,600 kgal
Electricity 9,911,000 kWh
Heat credit 60,100 MBtu
Maintenance
Labor and material
Analyses 1,290 man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
Elemental sulfur 5,600 tons
RESOX waste coal 2,900 tons
Adsorber char fines 2,000 tons
Net annual revenue requirements
Mills/kWh
Equivalent unit revenue requirements (net) 4.26
Total
Unit annual
cost, $ cost, $
7.50/ton 3,800
750.00/ton 2,025,000
57.00/ton 324,900
2,353,700
12.50/man-hr 500,000
0.40/gal 335,000
2.00/MBtu 5,400
0.12/kgal 5,100
0.029/kWh 287,400
2.00/MBtu (120,200)
1,655,900
17.00/man-hr 21,900
2,690,500
5,044,200
2,646,300
4,255,700
1 088 900
50,000
33,900
8,074,800
13,119,000
40.00/ton (224,000)
26.50/ton (76.900)
19. 00/ton (38,000)
12,780,100
$/ton $/MBtu
lignite burned heat input
7.48 0.47
% of net
annual revenue
requirements
0.03
15.84
2.54
18.41
3.91
2.62
0.04
0.04
2.25
(0.94)
12.96
0.17
21.05
39.46
20.71
33.30
ft ">?
O . Ji
0.39
0.27
63.19
102.65
(1.75)
(0.60)
(0.30)
100.00
$/ton .
sulfur removed
2,200
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/yr.
Lignite burned, 1,549,900 metric tons/yr (1,708,800 tons/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Sulfur removed, 5,271 metric tons/yr (5,810 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $23,656,000; total depreciable investment, $44,105,000; and total
capital investment, $49,485,000.
All tons shown are 2,000 Ib.
1-31
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TABLE 1-16. CARBON ADSORPTION PROCESS
SUMMARY OF CAPITAL INVESTMENT
(500-MW new, oil-fired power unit,
2.5% sulfur in oil; 90% S02 removal; sulfur production)
Direct Investment
Materials handling (conveyors, elevators, feeders, silo,
and bin)
Gas handling (common feed plenum and booster fans, gas ducts
and dampers to adsorber, exhaust gas ducts and dampers from
adsorber to stack)
S02 adsorption (four two-stage moving-bed adsorbers, feeders,
conveyors, screens, elevators, and bins)
Regeneration and product gas treatment (bins, feeders,
regenerators, tank, agitator, and pump)
Char cooling (two-stage char coolers, Can, conveyors,
and elevators)
Sand heating (heater/elevators and blowers)
RESOX S02 reduction (reduction unit complete, battery
limits)
Sulfur storage and shipping (tanks, heaters, and pumps)
Subtotal
Services, utilities, and miscellaneous
Total direct investment
Indirect Investment
Engineering design and supervision
Architect and engineering contractor
Construction expense
Contractor fees
Total indirect investment
Contingency
Total fixed investment
Allowance for startup and modifications
Interest during construction
Total depreciable investment
Land
Working capital
Char charge
Total capital investment
Investment , $
1,305,000
3,506,000
11,349,000
1,025,000
823,000
1,644,000
4,259,000
435,000
24,346,000
1,461,000
25,807,000
1,917,000
479,000
3,713,000
1,136,000
7,245,000
6,610,000
39,662,000
3,966,000
4,759,000
48,387,000
42,000
1,843,000
3,458,000
53,730,000
% of
total direct
investment
5.1
13.6
44.0
4.0
3.2
6.4
16.5
1.7
94.3
5.7
100.0
7.4
1.9
14.4
4.4
28.1
25.6
153.7
15.4
18.4
187.5
0.2
7.1
13.4
208.2
Basis
Evaluation represents project beginning mid-1977, ending mid-1980. Average cost basis for
scaling, mid-1979.
Minimum in-process storage; only pumps are spared.
Investment requirements for fly ash removal and disposal excluded; FGD process investment
estimate begins with common feed plenum downstream of the ESP.
Construction labor shortages with accompanying overtime pay incentive not considered.
1-32
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TABLE 1-17. CARBON ADSORPTION PROCESS
SUMMARY OF ANNUAL REVENUE REQUIREMENTS
(500-MW new, oil-fired power unit;
2.5% sulfur in oil; 90% S02 removal; sulfur production)
Annual Unit
quantity cost, $
Direct Costs
Raw materials
Sand 1,400 tons 7. 507 ton
Char 7,300 tons 750.00/ton
Anthracite coal 15,600 tons 57.00/ton
Total raw materials cost
Conversion costs
Operating labor and supervision 40,000 man-hr 12.50/man-hr
Utilities
Fuel oil 2,308,900 gal 0.40/gal
Steam 7,300 MBtu 2.00/MBtu
Process water 33,700 kgal 0.12/kgal
Electricity 10,555,000 kWh 0.029/kWh
Heat credit 165,600 MBtu 2.00/MBtu
Maintenance
Labor and material
Analyses 2,360 man-hr 17.00/man-hr
Total conversion costs
Total direct costs
Indirect Costs
Capital charges
Depreciation, interim replacements, and
insurance at 6.0% of total depreciable
investment
Average cost of capital and taxes at 8.6%
of total capital investment
Overheads
Plant, 50% of conversion costs less utilities
Administrative, 10% of operating labor
Marketing, 10% of byproduct sales revenue
Total indirect costs
Gross annual revenue requirements
Byproduct Sales Revenue
Elemental sulfur 15,400 tons 40.00/ton
RESOX waste coal • 8,100 tons 26.50/ton
Adsorber char fines 5,600 tons 19.00/ton
Net annual revenue requirements
S/bbl
Mills/kWh oil burned
Equivalent unit revenue requirements (net) 5.85 3.93
Total
annual
cost, $
10,500
5,475,000
889,200
6,374,700
500,000
923,600
14,600
4,000
306,100
(331,200)
1,806,500
40,100
3,263,700
9,638,400
2,903,200
4,620,700
1,173,300
50,000
93,700
8,840,900
18,479,300
(616,000)
(214,700)
(106,400)
17,542,200
$/MBtu
heat input
0.65
% of net
annual revenue
requirements
0.06
31.21
5.07
36.34
2.85
5.27
0.08
0.02
1.74
(1.89)
10.30
0.23
18.60
54.94
16.55
26.34
6.69
0.29
0.53
50.40
105.34
(3.51)
(1.22)
(0.61)
100.00
$/ton .
sulfur removed
1,095
Basis
1980 revenue requirements.
Remaining life of power plant, 30 yr.
Power unit on-stream time, 6,000 hr/hr.
Oil burned, 710 x 106 liters/yr (4,464,300 bbl/yr), 2,268 kcal/kWh (9,000 Btu/kWh).
Sulfur removed, 14,533 metric tons/yr (16,020 short tons/yr).
Investment and revenue requirement for removal and disposal of fly ash excluded.
Total direct investment, $25,807,000; total depreciable investment, $48,387.000; and total
capital investment, $53,730,000.
All tons shown are 2,000 Ib.
1-33
OU.S. GOVERNMENT PRINTING OFFICE:1980 311-132/96 1-3
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