PB-242
DETAILED COST ESTIMATES FOR ADVANCED EFFLUENT
DESULFURIZATION PROCESSES
TENNESSEE VALLEY AUTHORITY
PREPARED FOR
ENVIRONMENTAL PROTECTION AGENCY
JANUARY 1975
DISTRIBUTED BY:
Knr
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y, S, DITOTNENT OF COMMERCE
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TECHNICAL REPORT DATA
(Please read Inunctions on the reverse before complet*""*-
NO.
EP.\-oOU/2-7vOUo
2.
-. TITLE AND
Detaddd G>:>t Estimates for Advanced Effluent
Processes
7 AUTHOfllS)
C. G. McGlameiy, R. L. Torstrick, W. J. Broadfoot,
J. P. Simpson, L. J. Henson, S. V, Tomlinson, J. F. Young
PB 241
141
5. REPORT DATS
January 1975 (.date of approval)
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION ROPORT NO,
TV A Bulletin Y-90
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Tennessee Valley Authority
Musde Shoals, AL 35660
10. PROGRAM ELEMENT NO.
1AB013
11. CONTRACT/GRANT NOT
EPAIAG-134
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EPA-600/2-75-006
DETAILED COST ESTIMATES FOR ADVANCED EFFLUENT
DESULFURIZATION PROCESSES
by
G. G. McGlamery, R. L. Torstrick, W. J. Broadfoot,
J. P. Simpson, L. J. Henson, S. V. Tomlinson, J. F. Young
Tennessee Valley Authority
Muscle Shoals, Alabama 35660
{TVA Bulletin Y-90)
Interagency Agreement EPA IAG-134(D) Part A
Program Element No. 1AB013
EPA Project Officers: R. E. Harrington, Washington, D.C.
J. 0. Smith, Research Triangle Park, NC
Prepared for
Office of Research and Development
U.S. Environmental Protection Agency
Washington, D.C. 20460
January 1975
IO/
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, Environ-
mental Protection Agency, have been grouped into five series. These five
broad categories were established to facilitate further development and
application of environmental technology. Elimination of traditional grouping
was consciously planned to foster technology transfer and a maximum
interlace .in related fields. The five .series are:
I. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the Environmental Protection Technology
scries. This scries describes research performed to develop and demonstrate
instrumentation, equipment, and methodology to repair or prevent environ-
mental degradation from point and nonpoint sources of pollution. This work
provides the new or improved technology required fof the control and
treatment of pollution sources to meet environmental quality standards.
This report has been reviewed by the Office of Research and Development.
Approval does not signify that the contents necessarily reflect the views and
policies of the Environmental Protection Agency, nor does mention of trade
names or commercial products constitute endorsement or recommendation
for use.
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ABSTRACT
A detailed, segmented, highly visible cost comparison of the five leading stack gas desulfurization
processes was conducted. Using data available in late 1973, complete economic evaluations were prepared
for limestone slurry scrubbing, lime slurry scrubbing, magnesia slurry scrubbing- regeneration to sulfuric
acid, sodium solution scrubbing - S02 reduction to sulfur, and catalytic oxidation (Cat-Ox). Assuming the
process technology to be proven in application, a prescribed set of representative power plant, process
design, and economic premises was established. For each process design, projections are included for a base
case (500-MW, 3.5% S in coal, new unit) and 16 other variations in power unit size, fuel type (coal or oil),
sulfur in fuel, unit status (new vs. existing), solids disposal method (off-site vs. on-site ponding), and SOj
removal (80% vs. ()0%). Capital investment, annual operating costs (7,000 hr/yr) and lifetime operating
costs (over a 30-year declining operating profile) were estimated for the base case and each variation. Using
sensitivity analysis, effects of variations in energy costs, raw material costs, maintenance costs, cost of
capital, operating labor cost escalation, and net sales revenue were studied. A 3-year construction schedule
ending in mid-1975 is assumed for a midwestern location. Investment costs (mid-1974 dollars) can be scaled
or altered to reflect any predictable project schedule, escalation rate, or location. Definition of the systems
estimated, sources of cost data, and recommended equipment size-cost scale factors are given.
The ranges in estimated capital cost of these processes are substantial. For example, the installed costs of
the limestone slurry system were estimated to range from $23/kW to about $113/kW, depending on unit
size, unit status, fuel type, sulfur content of fuel, solid disposal method, and overall project scope.
Furthermore, due to the high level of construction cost inflation in recent years, these estimates probably
would be subject to substantial escalation for a project initiated now or in future years.
in
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CONTENTS
Abstract iii
List of Figures v
List of Tables viii
EXECUTIVE SUMMARY 1
Process Definition 1
Major Design and Cost Factors 2
Presentation of Results 3
Conclusions 8
INTRODUCTION 11
PROCESS BACKGROUND 13
Limestone-Lime Slurry Scrubbing 13
Magnesia Slurry Scrubbing - Regeneration 15
Sodium Solution Scrubbing - S02 Reduction to Sulfur o 16
Catalytic Oxidation 17
POWER PLANT, PROCESS DESIGN, AND ECONOMIC PREMISES 19
Power Plant 19
Process Design 21
Economic 25
SYSTEMS ESTIMATED 30
Limestone Slurry Process 30
Lime Slurry Process 39
Magnesia - Slurry Regeneration 46
Sodium Solution-SOj-Reduction Process 59
Catalytic Oxidation Process 68
ECONOMIC EVALUATION AND COMPARISON 79
Procedures 79
Sensitivity Analyses 83
Results 83
Accuracy of Results 157
CONCLUSIONS . 166
Investment 166
Operating Cost 166
REFERENCES 168
APPENDIX A , 171
APPENDIX B 172
APPENDIX C 415
iv
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FIGURES
1 Limestone slurry process. Flow diagram and
material balance-base case 31
2 Limestone slurry process. Control
diagram—base case 32
3 Limestone slurry process. Venturi and mobile bed
scrubber system-plan and elevation-base case . 33
4 Limestone slurry process. Materials handling and
feed preparation system layout—plan-base case . 34
5 Limestone slurry process. Overall plot
plan-base case 35
6 Lime slurry process. Flow diagram and material
balance-base case 40
7 Lime slurry process. Control diagram-base case . 41
8 Lime slurry process. Two-stage venturi scrubber
system-plan and elevation- base case 42
9 Lime slurry process. Materials handling and feed
preparation system layoul plan-base case . . 43
10 Lime slurry process. Overall plot plan—base case.. 44
11 Magnesia slurry - regeneration process. Flow
diagram-base case 48
12 Magnesia slurry - regeneration process. Material
balance-base case 49
13 Magnesia slurry - regeneration process. Control
diagram-base case 50
14 Magnesia slurry - regeneration process. Two-stage
venturi scrubber system-plan and
elevation—base case 51
15 Magnesia slurry - regeneration process. Fluid bed
dryer-calciner layout-plan-base case 52
16 Magnesia slurry - regeneration process. Fluid bed
dryer-calciner layout-elevation—base case . . 53
17 Magnesia slurry - regeneration process. Sulfuric
acid unit layout-plan 54
18 Magnesia slurry - regeneration process. Sulfuric
acid unit layout-elevation 55
19 Magnesia slurry - regeneration process. Overall
plot plan-base case 56
20 Sodium solution - SO2 reduction process. Flow
diagram—base case 60
21 Sodium solution - S02 reduction process. Material
balance—base case 61
22 Sodium solution - S02 reduction process. Venturi
and valve-tray scrubber system-plan
and elevation-base case 62
23 Sodium solution - S02 reduction process. S02
regeneration -reduction and purge treatment
system layout—elevation—base case 63
24 Sodium solution - S02 reduction process. S02
regeneration—reduction and purge treatment
layout-plan- base case -. 64
25 Sodium solution - SO2 reduction process. Overall
plot plan- base case 65
26 Catalytic oxidation process. Flow diagram
and material balance—base case ........ 69
27 Catalytic oxidation process. Control
diagram—base case 70
28 Catalytic oxidation process. S02 conversion
and absorption system layout—plan—base case . 71
29 Catalytic oxidation process. S02 conversion and
absorption system layout-elevation—base case . 72
30 Catalytic oxidation process. Overall plot
plan—base case 73
31 Catalytic oxidation process. S02 conversion and
absorption system layout-elevation-existing case . 74
32 Catalytic oxidation process. S02 conversion
system layout-plan-existing case 75
33 All processes. Effect of power unit size on
total capital investment: new coal-fired units . 98
34 All processes. Effect of power unit size on
total capital investment: new oil-fired units . . 98
35 All processes. Effect of power unit size on
total capital investment: existing
coal-fired units 98
36 All processes. Effect of sulfur content of coal
on total capital investment: new 500-MW
coal-fired units 98
37 All processes. Effect of sulfur content of
oil on total capital investment: new 500-MW
oil-fired units 99
38 All processes. Effect of power unit
size on unit investment cost, dollars
per kilowatt'new coal-fired units 99
39 All processes. Effect of power unit size
on unit investment cost, dollars per killowatt:
new oil-fired units 99
40 All processes. Effect of sulfur content of
coal on unit investment cost, dollars per
kilowatt: new 500-MW coal-fired units 99
41 All processes. Effect of sulfur content of oil
on unit investment cost, dollars per killowatt:
new 500-MW oil-fired units 99
42 Limestone slurry process. Effect of years
remaining life on total capital
investment: existing coal-fired units 100
43 All processes. Effect of power unit size
on total average annual operating cost: new
coal-fired units under regulated economics ... 130
44 All processes. Effect of power unit size on total
average annual operating cost: new oil-fired
units under regulated economics 130
45 All processes. Effect of power unit size on
total average annual operating cost: existing
coal-fired units under regulated economics ... 132
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46 All processes. Effect of power unit size on
average unit operating cost: new coal-fired
units under regulated economics 132
47 All processes, liffect of power unit size on
average unit operating cost: new oil-fired
units under regulated economics 132
48 All processes. Effect of power unit size on
average unit operating cost: existing coal-fired
units under regulated'economics . . . 132
49 All processes. Effect of sulfur content of coal on
total average annual operating cost: new 500-MW
coal-fired units under regulated economics ... 132
50 All processes. Effect of sulfur content of oil on
total average annual operating cost: new 500-MW
oil-fired units under regulated economics ... 133
51 Limestone slurry process. Effect of annual on-stream
time on total average annual operating cost:
new coal-fired units under regulated economics . 144
52 Sodium solution - SOj reduction process. Effect
of annual on-stream time on total average annual
operating cost: new coal-fired units
under regulated economics 144
53 Catalytic oxidation process. Effect of
annual on-stream time on total average annual
operating cost: new coal-fired units
under regulated economics 144
54 Limestone slurry process. Effect of
variations in capital charges on total average
annual operating cost: new coal-fired
units under regulated economics 144
55 Magnesia slurry - regeneration process.
Effect oi variations in capital charges on
total average annual operating cost: new
coal-fired units under regulated economics . . . 145
56 Catalytic oxidation process. Effect of
variations in capital charges on total average
annual operating cost: new coal-fired
units under regulated ecnonmics 145
57 Magnesia slurry - regeneration process.
Effect of variations in labor cost on
total average annual operating cost: new
coal-fired units under regulated economics . . . 145
58 Magnesia slurry - regeneration process. Effect
of variations in maintenance cost on total
average annual operating cost: new coal-
unit sunder regulated economics 145
59 Sodium solution - S02 reduction process.
Effect of variations in energy cost on total
average annual operating cost: new coal-fired
units under regulated economics ' . . 146
60 Catalytic oxidation process. Effect of
variations in energy cost on total average
annual operating cost: new coal-fired i^
units under regulated economics 146
61 Sodium solution - SOa reduction process.
Effect of variations in steam cost on total
average annual operating cost: new coal-fired
units under regulated economics
62 Limestone slurry process. Effect of
variations in limestone price on total
average annual operating cost: new coal-fired
units under regulated economics
63 Lime slurry process. Effect of
variations in lime price on total average
annual opera ting cost: new coal-fired
units under regulated economics
64 Limestone slurry process. Effect of
variations in limestone price and in disposal
method on total average annual operating cost:
new coal-fired units under regulated economics
65 Magnesia slurry - regeneration process. Effect
of variations in MgO losses on total average
annual operating cost: new coal-fired units
under regulated economics
66 Sodium solution - S02 reduction process.
Effect of antioxidant use on total
average annual operating cost: new
coal-fired units under regulated economics . .
67 Catalytic oxidation process. Effect of
variations in number of cleanings (and
resulting catalyst loss) on total average
annual operating cost: new coal-fired units
under regulated economics .
68 All processes. Effect of power unit size on
cumulative present worth of total increase or
decrease in cost of power to consumers: new
coal-fired units under regulated economics . .
69 All processes. Effect of power unit size on
cumulative present worth of total increase or
decrease in cost of power to consumers: new
oil-fired units under regulated economics . .
70 All processes. Effect of power unit size on
levelized unit operating cost: new coal-fired
units under regulated economics
71 AH processes. Effect of p6W6r unit size on
levelized unit operating cost: new oil-fired
units under regulated economics
72 All processes. Effect of power unit size on
levelized unit operating cost: existing
coal-fired units under regulated economics . .
73 All processes. Effect of sulfur content of coal.
on levelized unit operating cost: new 500-MW
coal-fired units under regulated economics . .
74 All processes. Effect of sulfur content of oil
on levelized unit operating cost: new 500-MW
oil-fired units under regulated economics . .
75 Limestone slurry process. Effect of years
remaining life on levelized unit operating
146
146
147
. 147
147
147
148
148
148
155
155
155
155
156
VI
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cost: existing coal-fired units
under regulated economics 157
76 Limestone slurry process. Effect of variation
in limestone price and in disposal method on
cumulative present worth of total increase or
decrease in cost of power to consumers: new
coal-fired units under regulated economics ... 157
77 Limestone slurry process. Effect of variatiorts
in investment on levelized unit operating cost:
new coal-fired units under regulated economics . 158
78 Lime slurry process. Effect of variations in
investment on levelized unit operating cost: new
coal-fired units under regulated economics ... 158
79 Magnesia slurry - regeneration process. Effect
of variations in investment on levelized unit
operating cost: new coal-fired units
under regulated economics 158
80 Sodium solution - SOa reduction process. Effect
of variations in investment on levelized
unit operating cost: new coal-fired
units under regulated economics 158
81 Catalytic oxidation process. Effect of
variations in investment on levelized
unit operating cost: new coal-fired
units under regulated economics 158
82 Magnesia slurry - regeneration process.
Effect of variations in sulfuric acid revenue
on levelized unit operating cost: new coal-fired
units under regulated economics 158
83 Magnesia slurry - regeneration process. Effect
of variations in sulfuric acid revenue on
levelized unit operating cost: new oil-fired
units under regulated economics 159
84 Sodium solution - S02 reduction process.
Effect of variations in sulfur revenue on
levelized unit operating cost: new coal-fired
units under regulated economics 159
85 Sodium solution - SOj reduction process.
Effect of variations in sulfur revenue on
levelized unit operating cost: new oil-fired
units under regulated economics 159
86 Catalytic oxidation process. Effect of
variations in sulfuric acid revenue on
levelized unit operating cost: new coal-fired
units under regulated economics . 159
87 Catalytic oxidation process. Effect of
variations in sulfuric acid revenue on
levelized unit operating cost: new oil-fired
units under regulated economics 160
88 Limestone slurry and sodium solution - S02
reduction processes. Effect of annual labor
cost escalation on cumulative present worth of
total increase or decrease in cost of power to
consumers: new coal-fired units under
regulated economics 160
89 Limestone slurry process. Effect of
variations in cost of money on levelized
unit operating cost: new coal-fired
units under regulated economics 160
90 Lime slurry process. Effect of variations in
cost of money on levelized unit operating cost:
new coal-fired units under regulated economics 160
91 Magnesia slurry - regeneration process. Effect
of variations in cost of money on levelized unit
operating cost: new coal-fired units
under regulated economics 161
92 Sodium solution - SO2 reduction process. Effect
of variations in cost of money on levelized
unit operating cost: new coal-fired
units under regulated economics 161
93 Catalytic oxidation process. Effect of
variations in cost of money on levelized
unit opera ting cost: new coal-fired
units under regulated economics 161
vii
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TABLES
S-l EFA-Sponsored Stack Gas Desulfurization
Demonstration Systems 1
S-2 Summary-Total Capital Investment
Requirements 4
S-3 Limestone Slurry Process Investment
with Modified Project Scope 5
S-4 Projected Overall Investment Estimate Accuracy
Based on Available Data and Depth
of Investigation 6
S-5 Summary- Total Average Annual Operating Costs
(Excluding Credit for Byproducts) 7
S-6 Comparison of Projected Annual Operating
Costs and Product Credits for Base Case
Estimates at 7,000 Hours Annual Operation . . 8
S-7 Summary-Cumulative Discounted Process Costs
and Equivalent Levelized Unit Increase
Cost of Power Over the Life of the Power Unit
(Including Credit for Byproducts) 9
S-8 Lifetime Byproduct Production and Credit
Base Case, 500-MW New, Coal-Fired, 3.5%
S, 30 Years Remaining Life 10
1 EPA-Sponsored Stack Gas Desulfurization
Demonstration Systems 11
2 Power Unit Input Heat Requirements 19
3 Assumed Power Plant Capacity Schedule ... 19
4 Estimated Flue Gas Compositions for Power Units
Without Emission Control Facilities 20
5 Power Plant Flue Gas and Sulfur
Dioxide Emission Rates 21
6 EPA Emission Standards for New
Steam Generating Facilities 21
7 Required Removal Efficiencies 21
8 Particulate and Sulfur Dioxide Control Devices . 23
9 Assumed Operating Parameters for Scrubbing
Systems Applied to New Coal-Fired Power Units
(Design Conditions-3.5% S Coal, 2,200 ppm
S02 in Inlet Gas, 90% Nominal S02 Removal) . 23
10 Indirect Investment and Allowance Factors . . 27
11 Projected 1975 Unit Costs for Raw Materials,
Labor, and Utilities 28
12 Product Credit 29
13 Estimated Overall Annual Maintenance Costs . 29
14 Annual Capital Charges for
Power Industry Financing 29
15 Flue Gas Reheat Requirements -
Limestone Slurry Process 37
16 Assumed Pressure Drop Distribution for
Specification of Funs Limestone
Slurry Process 37
17 Flue Gas Reheat Requirements- Lime
Slurry Process 45
18 Assumed Pressure Drop Distribution for
Specification of Fans-Lime Slurry Process . . 46
19 Flue Gas Reheat Requirements-Magnesia
Slurry - Regeneration Process 57
20 Assumed Pressure Drop Distribution for
Specifications of Fans-Magnesia Slurry •
Regeneration Process 57
21 Flue Gas Reheat Requirements-Sodium
Solution - S02 Reduction Process 66
22 Assumed Pressure Drop Distribution for
Specification of Fans-Sodium
Solution - SO2 Reduction Process 66
23 Electrostatic Precipitator Requirements-
Catalytic Oxidation Process 76
24 Assumed Pressure Drop Distribution for
Specification of Fans-Catalytic
Oxidation Process 77
25 Relative Quantities of Gas and Sulfur
to be Processed in Comparison with
the Base Case Quantities . 80
26 Sensitivity Variations Studied in the
Economic Cost Projections 84
27 Limestone Slurry Process Total
Capital Investment Summary 85
28 Lime Slurry Process Total
Capital Investment Summary 85
29 Magnesia Slurry - Regeneration Process Total
Capital Investment Summary 86
30 Sodium Solution - 80s Reduction Process
Total Capital Investment Summary 86
31 Catalytic Oxidation Process Total
Capital Investment Summary 87
32 Comparison of Investment Requirements
for SOj Removal Processes at 90%
and 80% S02 Removal 87
33 Investment Requirements for SOj Removal
Installations on Existing Power Units
Requiring Additional Facilities for Removal
of Particulates Comparison with Standard ... 87
34 Comparison of Investment Requirements
for Limestone and Lime SOj Removal Processes
Designed for On-site and Off-site Waste
Solids Disposal 87
35 Limestone Slurry Process Total Capital
Investment Requirements Base Case Summary-
Process Equipment and Installation
Analysis (Thousands of Dollars) 88
36 Limestone Slurry Process Total Capital
Investment Requirements Existing Case Summary-
Process Equipment and Installation
Analysis (Thousands of Dollars) 89
viii
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37 Lime Slurry Process Total Capital
Investment Requirements Base Case Summary-
Process Equipment and Installation
Analysis (Thousands of Dollars) 90
38 Lime Slurry Process Total Capital
Investment Requirements Existing Case Summary-
Process Equipment and Installation
Analysis (Thousands of Dollars) 91
39 Magnesia Slurry - Regeneration Process
Total Capital Investment Requirements Base Case
Summary-Process Equipment and Installation
Analysis (Thousands of Dollars) 92
40 Magnesia Slurry - Regeneration Process Total
Capital Investment Requirements Existing Case
Summary-Process Equipment and Installation
Analysis (Thousands of Dollars) 93
41 Sodium Solution - S02 Reduction Process
Total Capital Investment Requirements Base
Case Summary-Process Equipment and
Installation Analysis (Thousands of Dollars) . . 94
42 Sodium Solution - S02 Reduction Process
Total Capital Investment Requirements Existing
Case Summary-Process Equipment and
Installation Analysis (Thousands of Dollars). . . 95
43 Catalytic Oxidation Process Total Capital
Investment Requirements Base Case Summary-
Process Equipment and Installation
Analysis (Thousands of Dollars) 96
44 Catalytic Oxidation Process Total Capital
Investment Requirements Existing Case Summary-
Process Equipment and Installation
Analysis (Thousands of Dollars) 97
45 Investment Distribution for Major Cost Areas-
Base Case Total Capital Investment 98
46 limestone Slurry Process Equipment List and Cost 101
47 Lime Slurry Process Equipment List and Cost . 106
48 Magnesia Slurry - Regeneration Process
Equipment List and Cost 110
49 Sodium Solution - SO2 Reduction
Process Equipment List and Cost 116
50 Catalytic Oxidation Process Equipment
List and Cost 123
51 Limestone Slurry Process Total Average
Annual Operating Costs Summary 127
52 Lime Slurry Process Total Average
Annual Operating Costs Summary 128
53 Magnesia Slurry - Regeneration Process Total
Average Annual Operating Costs Summary . . 129
54 Sodium Solution - SO2 Reduction Process Total
Average Annual Operating Costs Summary . . 130
55 Catalytic Oxidation Process Total Average
Annual Operating Costs Summary 131
56 Comparison of Average Annual Operating Costs
for S02 Removal Processes at 00% and
80%SO2 Removal 131
57 Average Annual Operating Cost for SOj
Removal Installations on Existing Power Units
Requiring Additional Facilities for Removal of
Particulates-Comparison with Standard .... 131
58 Comparison of Average Annual Operating
Costs for Limestone and Lime SOj Removal
Processes Using On-site and Off-site
Waste Solids Disposal 132
59 Limestone Slurry Process Total
Average Annual Operating Costs Base Case
Summary-Area Contribution Analysis .... 134
60 Limestone Slurry Process Total Average
Annual Operating Costs Existing Case
Summary-Area Contribution Analysis .... 135
61 Lime Slurry Process Total Average Annual
Operating Costs Base Case Summary-
Area Contribution Analysis 136
62 Lime Slurry Process Total Average Annual
Operating Costs Existing Case Annual Operating
Cost Summary-Area Contribution Analysis . . 137
63 Magnesia Slurry - Regeneration Process Total
Average Annual Operating Costs Base Case
Summary-Area Contribution Analysis .... 138
64 Magnesia Slurry - Regeneration Process Total
Average Annual Operating Costs Existing Case
Summary-Area Contribution Analysis .... 139
65 Sodium Solution - S02 Reduction Process Total
Average Annual Operating Costs Base Case
Summary—Area Contribution Analysis 140
66 Sodium Solution - S02 Reduction Process Total
Average Annual Operating Costs Existing
Case Summary-Area Contribution Analysis 141
67 Catalytic Oxidation Process Total
Average Annual Operating Costs Base Case
Summary-Area Contribution Analysis .... 142
68 Catalytic Oxidation Process Total Average
Annual Operating Costs Existing Case
Summary-Area Contribution Analysis .... 143
69 Major Operating Cost Components Included in
the Base Case Total Annual Operating Cost . . 144
70 Limestone Slurry Process Actual and
Discounted Cumulative Total and Unit
Increase (Decrease) in Cost of Power
over the Life of the Power Unit 149
71 Lime Slurry Process Actual and
Discounted Cumulative Total and Unit
Increase (Decrease) in Cost of Power
over the Life of the Power Unit 150
72 Magnesia Slurry - Regeneration Process Actual
and Discounted Cumulative Total and Unit
Increase (Decrease) in Cost of Power
over the Life of the Power Unit 151
73 Sodium Solution - S02 Reduction Process
Actual and Discounted Cumulative Total and
ix
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Unii Increase (Decrease) in Cost of Power
over (he Life of the Power Unit ........ 152
74 Catalytic Oxidation Process Actual.and
Discounted Cumulative TptaTandiUnit
Increase (Decrease) in Cost of Power
• over the Life of the Bower Upit . 153
75 Lifetime Byproduct Production and Credit . , 154
76 Comparison of Cumulative Lifetime
Discounted Process Costs for. S02 Removal
Processes at 90% and.,80% S02 Removal ... 156
77 Cumulative Lifetime Discounted Process Costs
for SO2 Removal Installations on Existing
Power Units,Requiring Additional Facilities
for Removal of Participates -Comparison
,with Standard 156
78 Comparison of Cumulative Life!ime:Discpunted
Process Cost for Limestone and Lime S02
Removal Processes Utilizing On-site and
Off-site .Waste Solids, Disposal 157
79 Limestone Slurry Process Investment
with Modified Project Scope 162
80 Limestone Slurry Process—Investment
Estimate Accuracy Analysis 163
81 .Lime Slurry Process—Investment
Estimate Accuracy Analysis 163
82 Magnesia Slurry -.Regeneration Process-
Investment Estimate Accuracy Analysis .... 164
83 Sodium Solution - S02 Reduction Process-
Investment Estimate Accuracy Analysis .... 164
84 Catalytic Oxidation Process-Investment
Estimate Accuracy Analysis .......... 165
85 Projected Overall Investment Estimate
Accuracy Based on Available
Data and Depth of Investigation 165
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Executive
Summary
After several years of intensive process development,
several power plant stack gas SOj removal systems are now
advancing from the pilot-plant stage to demonstration-scale
applications. With the installation of these demonstration-
size facilities on power units around the United States, it
should now be possible to more accurately predict their
costs so that utility executives can better choose between
alternatives.
Under the provisions of the Clean Air Act of 1967
and its 1070 ammendments, the Federal Environmental
Protection Agency has funded research and development
on S02 removal processes including several conceptual
design and cost studies. In these earlier efforts, many
design assumptions were necessary and cost estimate
accuracy was questionable since technology was in an
infant state and available design data were limited.
Equipment costs were sketchy since most vendors had yet
to fabricate and erect the large gas scrubbing devices
required for full-scale systems. Furthermore, very little
corrosion data were available to predict materials of
construction for the services involved. In many cases,
optimism of the process developers tended to maximi/.e
process potential and to minimize problem areas such as
erosion, scaling, solids disposal, sulfite oxidation, mist
elimination, gas reheat, operational turndown, and pH
control.
Finally, after many pilot-plant tests and both encour-
aging and disappointing experiences, five processes have
emerged from the many proposed as the leading systems for
demonstration. These are the limestone slurry process and
the lime slurry process, both of which are throwaway
systems (no salable byproduct), and the magnesia slurry •
regeneration, sodium solution scrubbing • SOj reduction,
and catalytic oxidation processes which produce salable
sulfuric acid or elemental sulfur. In cooperation with
participating utilities and process developers, EPA is cur-
rently funding large-scale test and demonstration projects
on each of these processes. The processes and the associated
projects are shown in table S-l.
Now that many of the unknowns for these systems have
surfaced, remedies been prescribed, and large-scale projects
started, more accurate assessment of process costs should
be possible. The objective of this study is to prepare a set of
highly visible,detailed, capital and operating cost estimates
for comparison of the five leading processes on a common
uniform basis.
PROCESS DEFINITION
A brief description of the subject processes and the
organizations supplying representative system data for this
Table S-1. EPA-Sponsored Stack Gas Desulfurization Demonstration Systems
EPA-sponsored process
(byproduct)
Limestone slurry scrubbing
(sludge)
Lime slurry scrubbing
(sludge)
Magnesia slurry scrubbing -
regeneration
(W;?. sul fu ik acid)
Catalytic oxidation
(reheat)
(80% sulfuric acid)
Sodium scrubbing -
regeneration
(sulfur)
Cooperating
utility
TVA
TVA
Boston Edison
Illinois Power
Northern Indiana
Public Service
Co.
Process
developer
Bechtel and
others
Chemico,
Bechtel, and
others
Chemico-Basic
Monsanto
Davy Powergas
Allied Chemical
Location
Shawnee unit 1 0
Paducah, Ky.
Shawnee unit 10
Paducah, Ky.
Mystic Station 6
Boston, Mass.
Wood River Station 4
East Alton, 111.
D. H. Mitchell
Station 1 1
Gary, Ind.
Unit size
and type
10MW
coal
10MW
coal
155 MW
oil
110MW
coal
115MW
coal
Expected
startup
Under way
Under way
Completed
Mid- 1974
Late 1975
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xludy arc given below. The pi ores;; data represent Ihc Hlulu
of technology in laic ll>7.1.
I. Limestone slurry scrubbing- Stack gas is washed
with a reciiculating slurry (pll of 5.8-6.4) of lime-
stone und reacted calcium salts in water using a
two-stage (venturi and mobile bed) scrubber system
for paniculate and S02 removal. Limestone feed is
wet ground prior to addition to the scrubber effluent
hold tank. Calcium sulfite and sulfate salts are
withdrawn to a disposal area for discard. Reheat of
stack gas to 175°F is provided. Design is based on
data taken from EPA-TVA-Bechtel Shawnee test
program.
1. Lime slurry scrubbing—Stack gas is washed with a
recirculating slurry (pH of 6.0-8.0) of calcined
limestone (lime) and reacted calcium salts in water
using two stages of venturi scrubbing. Lime is
purchased from "across the fence" calcination opera-
tion, slaked, and added to both circulation streams.
Calcium sulfite and sulfate are withdrawn to a disposal
area for discard. Reheat of stack gas to 175°F is
provided. Design is based on data provided by
Chemical Construction Corporation (Chemico),
3. Magnesia slurry scrubbing - regeneration of
H^SOn—Stack gas is washed using two separate
stages of venturi scrubbing-the first utilizing water
for removal of particulates, and the second utilizing a
recirculating slurry (pH 7.5-8.5) of magnesia (MgO)
and reacted magnesium-sulfur salts in water for
removal of £O2. Makeup magnesia is slaked and
added to cover only handling losses since sulfates
formed are reduced during regeneration. Slurry from
the S02 scrubber is dewatered, dried, calcined, and
recycled during which concentrated S02 is evolved to
a contact sulfuric acid plant producing 98% acid.
Reheat of stack gas to 175°F is provided. Design is
based on data supplied by Chemico-Basic
Corporation.
4. Sodium solution scrubbing - SOi regeneration and
reduction to sulfur—Stack gas is washed with water
in a venturi scrubber for removal of particulates and
then washed in a valve tray scrubber with a recircu-
lating solution of sodium salts in water for S02
removal. Makeup sodium carbonate is added to cover
losses due to handling and oxidation of sodium
sulfite to sulfate. Sodium sulfate crystals are purged
from the system, dried, and sold. Water is evaporated
from the scrubbing solution using a single-effect
evaporator to crystalline and thermally decompose
sodium bisulfite, driving off concentrated SO2. The
resulting sodium sulfite is recycled to the scrubber
and the SO2 is reacted with methane for reduction to
elemental sulfur. Reheat of stack gas to 175°F is
provided. The regeneration and reduction areas are
designed Ibr 1(X)% of power plant load. Design for
the scrubbing - evaporator - crystalltzer system is
provided by Davy Powergas, Inc. (Wellman-Lord
process), and data for the S02 reduction unit are
provided by Allied Chemical Corporation,
5. Catalytic oxidation—In the "integrated" design,
890°F stack gas is first cleaned of particulates (to
0.005 gr/scf) by a high-temperature electrostatic
precipitator; then, the S02 is catalytically converted
to SO3 and available excess heat is recovered, For a
"reheat" design, stack gas at 300° F is reheated to
890° F by heat exchangers and direct fuel oil firing
prior to conversion of S02 to S03. In either case, the
S03 reacts with moisture in the stack gas to form
H2S04 mist which is scrubbed in a packed tower
using a recirculating acid stream to yield 80% acid.
Mist is removed by a Brink mist eliminator and the
clean 254° F gas is exhausted to the stack. Both
integrated and reheat designs are based on data
supplied by Monsanto Company, developers of the
Cat-Ox process.
Representative flow diagrams, material balances, control
diagrams, plant layouts, and equipment arrangements are
included in the report for the base case (new 500-MW
coal-fired unit, 3.5% S in fuel, 90% S02 removal) of each
process. Together with detailed equipment descriptions,
this background defines the systems estimated.
MAJOR DESIGN AND COST FACTORS
From previous economic studies, the following factors
are considered to be the most important; therefore, their
effects on S02 control costs are defined.
1. Project schedule and location—Project assumed to
start in mid-1972 with 3-year construction period
ending mid-1975. Midpoint of construction costs
mid-1974, Chemical Engineering Cost lndex-160.2.
Startup-mid-1975. A midwestern plant location is
assumed.
2. Power unit size—Costs for three unit sizes-200,
500,1,000-MW-are projected.
3. Fuel type—Systems for both coal- and oil-fired
units are costed: coal-12,000 Btu/lb, 12% ash,
oil-18,500 Btu/lb, 0.1% ash.
4. Sulfur content of fuel—Costs for three sulfur levels
are evaluated for each fuel-2.0%, 3.5%, and 5.0%
for coal; 1.0%, 2.5%, and 4.0% for oil.
5. Plant status Although systems for both new and
existing power units are evaluated, only a simple,
moderately difficult (scrubbing system installed in
vacant space beyond the stack) retrofit is estimated
since such systems can vary over such a wide range
of configurations and restrictions. New units are
-------
designed for a 30-year life, 127,500 hours of
operation. Costs for new and existing systems are
not directly comparable.
6. S02 removal Since all five processes are capable
of 90% S02 removal and future demands for
emission control may exceed present standards, 90%
removal is specified as the base value. For those
processes in which cost effective design changes
could be identified, 80% removal is also projected.
7. Particulate removal—Costs are included for 98.7%
paniculate removal (to meet EPA standard of 0.1
Ib/million Btu heat input) on new coal-fired systems
except Cat-Ox which requires 99.9% removal (for
process reasons, restricted to 0.005 gr/scf prior to
entering converter). Existing units are assumed to be
already equipped with 98.7% electrostatic precipita-
tors; therefore, only incremental additional precipi-
tator is required. Because of this provision, the
investment and operating cost results for existing
coal-fired systems appear lower than for new units.
To cover this disparity, a special case is examined
where full particulate removal must be added to an
existing unit. Oil-fired units do not require dust
removal facilities.
8. Raw materials and catalysts—Assuming startup in
1975, midwestern 1975 delivered prices are
projected and sensitivity analysis is used to evaluate
variance.
9. Labor—1975 midwestern operating labor rates are
projected. Sensitivity analysis is used to evaluate
overall operating labor cost variance. Operating
labor is escalated over the life of the project for
only a few special cases to show effect.
10. Utilities—Recent energy cost escalation is recog-
nized and 1975 values are projected (59). Values
used in operating cost estimates for utilities supplied
by power plant cover all costs for generation
including return on investment, depreciation, and
income taxes.
11. Maintenance—Various levels are analyzed by
sensitivity analysis.
12. Capital charges - -Regulated (profit and taxes
included) economic basis is used. Annual operating
cost estimates utilize a base value of 14.9% of fixed
investment (10% cost of money). Level is varied by
sensitivity analysis.
13. On-stream time Annual operating costs are pro-
jected for operating times of 7,000,5,000,3,500, and
1,500 hr/yr. Later, these values are used to project a
lifetime cost over a predefined 30-year declining
operating schedule.
14. Solids disposal—Both on-site ponding and off-site
disposal costs are evaluated for limestone and lime
processes. On-site ponding includes prorated costs
for calcium solids to cover pumping and piping to
and from the pond, plus the 40-foot-deep, clay-lined
pond. Off-site disposal includes proration of a
thickener, filter, piping, pumps, cake conveyors, and
loader at the power unit. Off-site charges are levied
on a fee per ton of wet solids basis assumed to cover
all contractor expenses for hauling, treatment, and
final disposal. Sensitivity analysis is used to evaluate
variance.
15. Net sales revenue—Base values-$8/ton 100%
H2S04 as98%H2S04,$6/ton 100%H,S04 as 80%
H2S04, $25/short ton for sulfur, $20/ton for
sodium sulfate are used. Variances are covered by
sensitivity analysis.
Other important design and cost assumptions defined for
consistent evaluation are:
1. Fly ash disposal facilities (ponds, pipes, pumps) are
not included. Water balance is based on closed-loop
operation.
2. System design assumed not "first of kind"; no
redundancy is included; only pumps are spared;
experienced design and construction team is assumed
utilized.
3. Stack gas reheated to 175°F except Cat-Ox process.
4. Product storage—30 days except for Na2S04-7 days.
5. Equipment, material, and construction labor short-
ages with accompanying overtime pay incentive not
considered.
PRESENTATION OF RESULTS
For each of the five processes evaluated, a base case
(500-MW, 3.5% S in coal, new unit) incorporating recog-
nized technology is established and 16 cases including
variations in power unit size, fuel type (coal vs. oil), sulfur
in fuel, unit status (new vs. existing), sludge solids disposal
method (off-site vs. on-site ponding) and S02 removal (80%
vs. 90%) are projected. Sensitivity analyses are used to
study other variations such as energy costs, raw material
costs, maintenance costs, cost of capital, net sales revenue,
and operating labor cost escalation. Several methods are
used to present the results. For investment data, the
following types of displays are presented for each process:
Total capital investment-tabulation of total investments
presented for each case (tables 27-31).
Case variations-area investment summaries presented
for each of the 16 case variations (see tables in
Appendix B).
Equipment list, cost, size-scale factor, and data source-
presented for base case (new 500-MW coal-fired unit
burning coal with 3.5% S) (tables 46-50).
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Sutniniiil/i'd IIIIHCSS ;iu:a [•ijuipiiK'Hl ami installation
cost lm;:iktlasc case ;nii! existing
500-MW•syslum -(.tables (5-44).
For annual operating costs covering 7,000 hr/yr
operation, three types of displays are used for each process.
Total average annual operating cost-tabulation of total
annual operating costs presented for each case (tables
51-55).
Case variations -operating cost summaries presented for
each of the 16 case variations (see tables in Appendix
B).
Summarized effect of individual-process areas-on total
costs-presented for base case and existing 500-MW
case (tables 59-68).
The lifetime operating costs are based on a prescribed
30-year* operating profile 7,000 hours the first 10 years;
5,000 hours the next 5 years; 3,500 hours the next 5 years;
1,500 hours the last 10 years; average for 30 years-4,250
hr/yr. Two types of displays are used.
Net increase (decrease) in cost of power-tabulation of
total lifetime operating costs,presented.for all cases,
actual and discounted (tables 70-74).
Case
Coal-fired power unit
90% SO? removal; on-sile solids disposal
200 MW N 3.5% S
200MWK3.5%S
500MWE3.5%S
500MWN2.0%S
500MWN3.5%S
500MWN5.0%S
1,OOOMWE3.5%S
1,000 MWN 3.5%S
80% SOi removal; on-site solids disposal
500 MW N 3.5% S
90% SOj removal; off-site solids disposal
500 MW N 3.5% S
90% SOj removal; on-sile solids disposal
(existing unit without existing
particulate collection facilities)
500 MW 1C 3.5% S
Case1 vaiialiuns computer profiles of lifetime operating
costs presented for each of the 16 case variations (see
tables in Appendix B).
Capital Investment
A summary of the total capital investment requirements
for the 16 case variations of all five processes is presented in
table S-2. The relative ranking of the processes for new
3.5% S in coal-fired units (base case) in order of increasing
investment is as follows;
1. Lime slurry
2. Limestone slurry
3. Magnesia slurry • regeneration
4. Sodium solution - S02 reduction
5. Catalytic oxidation
In comparing these rankings, it should be pointed out
that the lime slurry process does not provide facilities for
calcining limestone, and includes a minimum of facilities
for storage of the calcined material.
A similar comparison for existing 3.5% S coal-fired
power units which already meet particulate emission
regulations shows the following process rankings:
Table S-2.
Years
life
posal
30
20
25
" 30
30
30
25
30
posal
30
;posal
30
Summary-Total
Limestone, process
$
13,031,000
11,344,000
23,088,000
22,600,000
25,163,000
27,343,000
35,133,000
37,725,000
24,267,000
20,532,000
$/k\V
65
56
46
45
.2
.7
il
.2
50.3
54
35
37
48
41
.7
.1
.7
.5
.1
Capital Investment Requirements3*0
Lime process
$
11,749,000
13,036,000
26,027,000
20,232,000
22,422,000
24,272,000
38,133,000
32,765,000
21,586,000
18,323,000
$/kW
58.7
65.2
.52.1
40.5
44.8
48.5
38.1
32.8
43.2
36.6
Magnesia .process
$
14,139,000
14,372,000
26,026,000
22,958,000
26,406,000
29,355,000.
38,717,000
38,865,000
25,568,000
-
$/kW
70.7
71.9
52.1
45.9
52.8
58.7
38.7
38.9
51.1
-
Sodium process
$
16,198,000
17,149,000
31,208,000
26,706,000
30,491,000
33,709,000
47,721,000
45,832,000
29,127,000
-
$/kW
81.0
85.7
62.4
53,4
61.0
67.4
47.7
45.8
58.3
-
Cat-Ox processb
$
19,537,000
17,735,000
37,907,000
42,520,000
42,736,000
42,928,000
62,913,000
69,889,000
-
-
S/kW
97.7
88.7
75.8
85.0
85.5
85.9
62.9
69.9
-
-
25 29,996,000 60.0 26,090,000 52.2 32,213,000 64.4 37,957,000 75.9 43,816,000 87.6
Oil-fired power unil
90% SOj removal; on-sile solids disposal
200 MW N 2.5% S
500 MWN I.O%S
500 MW N 2.5% S
500 MW N 4.0% S
500 MW !•; 2.5%, S
1.OOP MWN 2.5% S
10.324,000 51.6 13,069,000 65.3
15,198,000 30.4 28,067,000 56.1
30 8,263.1100 41.3 9,482,000 47.4 8,861.000 44.3
30 12,935,000 25.') 15,961,000 31.9 12.695.000 25.4
30 15,473.000 30.9 18.148.000 36.3 16.080.000 32.2 18,949,000 37.9 28,277,000 56.6
30 17,481,000 35.0 19,861,000 39.7 18,765,000 37.5 21,893,000 43.8 28,449,000 56.9
IS 18,657,000 37.3 21,817,000 43.6 20,376,000 40.8 24,445.000 48.9 32,824,000 65.6
30 23,384.00(1 23.4 26.341.000 26.3 23.656.000 23.7 28,765,000 28.8 46.356,000 46.4
aMidwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974. Minimum in process
storage; only pumps are spared. Investment requirements for disposal of fly ash excluded. Construction labor shortages with accompanying
overtime pay incentive not considered.
"All Cat-Ox installations require particular removal to 0.005 pr/scf prior to entering converter. Because existing units are assumed to already
meet EPA standards (0.1 Ib particulalc/MM: Btu of heal input), only incremental additional precipitator is required.
cThese investment costs depend heavily on project definition. For example, modifying the project scope of the limestone process as shown in
table S-3 can increase the system cost for a new 500-MW. coal-fired unit from $5(U/kW to $ 113/kW.
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1. Limestone slurry
2. Magnesia slurry - regeneration
3. Lime slurry
4. Sodium solution - S()2 reduction
5. Catalytic oxidation
Table S-3. Limestone Slurry Process
Investment with Modified Project Scope
Investment
$/kW
Base investment-limestone slurry process
(including fly ash removal hut not disposal)
500-MW new coal-fired unit burning coal with
3.5% S, 12% ash, 90% S02 removal, 30-year
life, 127,500 hours operation, on-site solids
disposal, proven system, only pumps spared,
no bypass ducts, experienced design and
construction team, no overtime. 3-year
program, 5% per year escalation, mid-1974
cost basis for scaling
Overtime to accelerate project or cover
local demand requirements (50% of
construction labor requirements)
Research and development costs for first
of a kind process technology (as allowed
by FPC accounting practice)
Power generation capital for lost capacity
(normally covered by appropriate
operating costs for power used in
process)
Reliability provisions with added
redundancy of scrubbers, other equipment,
ducts and dampers, instrumentation for
changeover (assumes no permission to
run power plant without meeting SO2
removal emission standards at all times)
Additional bypass ducts and dampers
Retrofit difficulty—moderate, space
available beyond stack, less than three
shutdowns required for lie-ins, field
fabrication feasible
Fly ash pond including closed-loop
provisions
500-ft stack added to project cost
Air quality monitoring system, 2-15
mile radius, 10 stations
Cost escalation of 10%/year instead of 5%
Possible delay of up to 2 years in
equipment and material deliveries (11)77
completion instead of 1075)
Total
50.30
3.20
5.00
4.50
6.00
2.00
10.00
5.50
6.00
0.70
4.80
15.00
13.00
The change in relative position of the lime slurry process
ranking for existing units is a direct result of the assump-
tion that two vcnturi scrubbers in series per gas train are
required in the lime slurry process for removal of SOj from
(he gas, with or without the presence of fly ash. For each of
the other aqueous scrubbing processes, existing units
already meeting particulate emission regulations require
only one scrubber per gas train. A savings would result for
the lime slurry process for both new and existing applica-
tions and for the limestone slurry process for new units if a
single scrubber capable of removing both particulate and
S02 is available. In a separate TVA comparison of scrubber
alternatives for the lime slurry process not included in this
report, costs for a two-stage venturi lime system and a
venturi-mobile bed lime system on a new coal-fired unit are
shown to be reasonably close. However, for an existing
coal-fired power plant, the mobile bed scrubber option
requires about 22% less capital and 14% less operating cost
than the venturi-venturi scheme. For similar reasons as
given above, the process investment rankings for oil-fired
units are the same as those for existing coal-fired units.
Another important result derived by comparing the
investment projections in this study is the relatively minor
investment savings realized (3.2%4.5%) in designing for
80% SCh removal as compared to 90%.
The projected investments for limestone and lime slurry
processes designed for off-site solids disposal represent
savings equivalent to approximately 18% of the comparable
projected on-site investment case. However, these projec-
tions do not include the capital for off-site waste treatment
facilities which may be required; the contract fee ($4/ton
of wet solids) for off-site disposal is assumed to include the
necessary capital charges.
Accuracy—In reviewing the capital investment esti-
mates for the five processes, it must be understood mat the
base case process definitions and estimates represent a
proven system with a generalized investment. As an
indication of how the project scope and corresponding
investment could vary, the effect of "add ons" to the
limestone slurry process base case estimate is shown in table
S-3. Such "add ons" as delays in equipment delivery,
physical space limitations, additional redundancy require-
ments, taller stacks, inclusion of a closed-loop fly ash
disposal pond, and overtime to accelerate the project
completion schedule could more than double the
investment for the limestone slurry process.
Excluding these additional costs, but considering only
the data available for this appraisal, the depth of investiga-
tion, and the reliability of the cost data, the projected
overall investment accuracy for each of the processes is
given in table S-4.
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Annual Operating Cost
Table S-5 presents a summary of the total average annual
operating costs for the 16 case variations of all five
processes excluding credit for any byproducts produced.
Corresponding to new 3.5% S coal-fired units, the relative
ranking of average annual operating costs for the processes
(base case) is as follows:
1. Limestone slurry
2. Lime slurry
3. Catalytic oxidation
4. Magnesia slurry • regeneration
5. Sodium solution - S02 reduction
Some important effects are not readily seen in com-
paring the ranking of processes for only one plant size and
sulfur, level. As determined in this study, the relative
ranking of operating costs of the various processes is
sensitive to changes in the assumed sulfur content of the
fuel. As an illustration, a 500-MW, 1% S oil-fired power unit
using the catalytic oxidation process has the third highest
ranking operating cost of the five processes; but for fuel oils
with sulfur contents greater than 4.0%, this process is the
lowest in rank. As the results suggest, the catalytic
oxidation process might show the greatest promise for small
units burning high-sulfur oil. Although the sodium process
is not the lowest ranking process for any of the cases
presented in this study, it becomes more competitive in
ranking for low-sulfur fuel oil-fired units. At the expense of
small additional investment, its operating cost could be
lowered by designing the process with multiple-effect
evaporators thereby reducing the overall energy
requirements about 18%.
The relative ranking of operating costs for existing 3.5%
S coal-fired power units which already meet particulate
emission regulations is shown below; however, it should be
noted that magnesia and lime scrubbing.costs are essentially
the same.
1. Limestone slurry
2 (Magnesia slurry - regeneration
(Lime slurry
3. Catalytic oxidation
4. Sodium solution - SO] reduction
In all of. the projected annual operating cost estimates,
capital charges arc the most significant components
Table S-4. Projected Overall Investment
Estimate Accuracy Based on Available Data
and Depth of Investigation
Process
Percent range
Limestone slurry
Lime slurry
Magnesia slurry - regeneration
Sodium solution - regeneration
Catalytic oxidation (Cat-Ox)
+20 to -5
+20 to -10
+25 to-15
+25 to -10
+20 to-10
followed by maintenance, energy, and raw material costs in
varying orders of importance. For the magnesia and sodium
processes which require thermal energy for regeneration of
absorbent, steam or fuel oil are the second most significant
components. Lime cost (which requires thermal energy in
preparation) is the second most predominant itertt for the
lime slurry process, 'whereas maintenance is second in
predominance for the limestone slurry and catalytic
oxidation processes.
The effect on annual; operating costs of designing for
80% S02 removal as compared to 90% is relatively small.
Operating cost savings range from 3.6% to 4.2% of the
projected operating costs at 90% removal for the limestone
and lime slurry processes.
Although investment costs for off-site disposal of solids
in the limestone and lime slurry processes are projected to
be less than for on-site disposal, the total operating costs
for off-site disposal cases corresponding to a cost of $4/ton
of wet solids are 6.2% to 8.0% greater than the comparable
on-site disposal cases.
The effect of excluding product credits from the annual
operating cost estimates is illustrated in table S-6 which
compares the projected annual operating costs for the five
base case processes with the revenue from sale of
byproducts.
Lifetime Operating Cost
Assumed credits for salable byproducts are reflected in
the lifetime operating costs. Table S-7 presents a summary
of the cumulative discounted process costs and equivalent
levelized unit increase (decrease) in the cost of power over
the life of the power unit for the five processes. Table S-8
shows the revenue assumed for each product and the actual
and discounted cumulative credit for products which are
included in the cumulative discounted process costs for the
base case. With some exceptions, the relative ranking and
trends in levelized unit operating costs are somewhat similar
to those projected and discussed for annual operating costs.
Lifetime levelized unit operating- costs are slightly higher
than corresponding average annual unit operating costs
because of the declining operating profile of the power
unit. The average on-stream time over the life of the plant is
only 4,250 hr/yr, compared to the higher on-stream time of
7,000 hr/yr utilized for the annual operating cost estimates.
The limestone and lime slurry processes appear to show
the most economic promise for new coal-fired power units
at all unit sizes and sulfur levels considered in this study.
For new oil-fired units utilizing low-and medium-sulfur oil,
the limestone and magnesia processes show the most
promise. However, the Cat-Ox process shows the most
promise for high-sulfur oils. Because of credit for process
heat, the levelized unit operating cost projected for the
catalytic oxidation process declines with increasing sulfur
-------
Table S-5. Summary-Total Average Annual Operating Costs3^ (Excluding Credit for Byproducts)
Case
Coal-fired power unit
90% SO; removal: on-site solids disposal
200MWX3.5" S
200 MW E 3.5": S
500MWE3.5ccS
500 MW \ 2.0% S
500 MWN 3.5% S
500MWN5.0%S
1.000MWE3.5%S
1, 000 MWN 3. 5% S
80% SO2 removal; on-site solids disposal
500 MW N 3.5% S
90% SO2 removal; off-site solids disposal
500 MW N 3.5% S
90% SO2 removal (existing unit
without existing paniculate
collection facilities)
500MWE3.5%S
Oil-fired power unit
90% S02 removal; on-site solids disposal
200 MWN 2.5% S
500 MWN 1.0% S
500 MW N 2.5% S
500 MW N 4.0% S
500 MW E 2.5% S
1, 000 MWN 2.5% S
Limestone process
Years
life
30
20
25
30
30
30
25
30
30
30
25
30
30
30
30
25
30
Total annual
operating
cost, S
3,921,500
3,867,100
7:892,600
6,774,700
7,702,700
8,522,200
12,752,900
11,874,100
7,378,000
8,376,500
9,573,400
2,842,000
4,732,500
5,564,400
6,281,800
6,587300
8,987,400
Mills/
kWh
2.80
2.76
2.26
1.94
2.20
2.43
1.82
1.70
2.11
2.39
2.74
2.03
.35
.59
.79
.88
.28
Lime process
Total annual
operating
cost. S
4.163.900
4.822;000
9 ,6 12, 400
6.915,100
8,101,900
9,170,100
15301,400
12,553,100
7,806,900
8,641,000
9,728,300
3,413,500
5,748,600
6,852,800
7,742,300
8,001,500
10,795,200
Mills/
kWh
2.97
3.44
2.75
1.98
2.31
2.62
2.19
1.79
2.23
2.47
2.78
2.44
1.64
1.96
2.21
2.29
1.54
Magnesia process
Total annual
operating
cost. S
4.776,800
5,091.200
9,607.900
7,523,400
9,210,800
10,768,500
15,481.900
14,347,000
8,789,700
-
11,227,300
3,204,400
4,633,100
6,092,700
7,393,500
7,308,700
9,715,900
Mills/
kWh
3.41
3.64
2.75
2.15
2.63
3.08
2.21
2.05
2.51
-
3.21
2.29
1.32
1.74
2.11
2.09
1.39
Sodium process
Total annual
operating
cost, S
5,971,700
7377.700
14,658,000
9,101,700
11,601,500
13,983300
15,118.500
18,391,300
10,834,300
-
16,389,200
4,269,200
5,854,700
8,305,100
10,640,500
10,261 ,600
13,686,200
Mills/
kWh
4.27
5.27
4.19
2.60
331
4.00
3.59
2.63
3.10
-
4.68
3.05
1.67
237
3.04
2.93
1.96
Cat-Ox process
Total annual
operating
cost, S
4,232.700
5,849,400
12,399.600
8,801,200
8,873,900
8,940,500
21,460,800
13,957,600
-
-
13,598,300
2,750,100
5,743,600
5,677,500
5,565,100
11,126,100
8,911,900
Mills
kWh
3.02
4. IS
3.54
2.51
2.54
2.55
3.07
1.99
-
-
3.S9
1.96
1.64
1.62
1.59
3.18
1.27
aPower unit on-stream time, 7,000 hr/yr. Midwest plant location, 1975 operating costs. Investment and operating cost for disposal of fly ash excluded.
''These operating costs reflect capital investments shown in table S-2; they would increase if capital costs associated with additions to the scope such as shown in table S-3 were included.
-------
Table S-6. Comparison of Projected Annual Operating
Costs and Product Credits for Base Case Estimates
at_7,00p Hours Annual Operation
_^._ .^
average annual ; Annual credit Net annual
operating ;jor byproducts, operating
Process cost, $ • $a cost, $
Limestone
Lime
Magnesia
Sodiumb
Cat-Ox
7,702,700
8,101,900
9,210,800
11,601,500
8,873,900
I
' -
883,200
1,077,500
659,400
7,702,700
8,101,900
8,327,600
10,524,000
8,214,500
Corresponds to credit of $8/ton 100% HaSO4 as 98% H2SO4 for
magnesia slurry process; $2S/short ton sulfur, $20/ton NajSO4 for
the sodium solution process; and $6/ton 100% H^SC^ as 80%
H2SO4 for the Cat-Ox process.
Corresponds to process utilizing a single-effect evaporator for
regeneration pf SOj. The effect of using a double-effect evaporator
on overall steam and energy requirements and total annual
operating costs are discussed on page 133.
content of the fuel for both coal- and oil-fired units. In
comparison with the projected annual operating costs, the
relative higher costs on a lifetime basis which considers
credit from sale of acid, indicate the strong influence of the
declining operating profile assumed for the life of the plant
and capital charges which are highest for the catalytic
oxidation process.
CONCLUSIONS
The relative ranking of processes according to invest-
ment and operating costs varies with power unit size,, fuel
type, sulfur content of fuel, and plant status, with no single
process being the most favorable for all of the cases
considered in this study. Naturally, the particular premises
used to set up the comparisons have an effect on the
results. Under the premises selected the lime process has the
lowest investment for new coal-fired power units; except
for low (1.0%) sulfur oil-fired applications for which the
magnesia process investment is lowest, the limestone
process has the lowest investment for the other oil-fired
units. In addition, there is some shifting of process ranking
when the effect of sulfur content of fuel is evaluated.
However, the investment for the Cat-Ox process is the
highest of the five systems in all cases.
The relative ranking of processes based on annual
operating costs indicates that the limestone process is
lowest for all coal-fired units, but, process rankings for
oil-fired units change with variations in sulfur content of
the fuel. For the new 500-MW oil-fired plants, the magnesia
process has the lowest annual operating cost for 1.0% S fuel
oil, and the Cat-Ox process has the lowest cost for units
burning 4.0% S oil. In between these sulfur levels, however,
the limestone process is the most favorable. For most of the
case variations, sodium scrubbing has the highest operating
cost.
Capital charges are the largest component of operating
costs for all processes. Although energy costs are also
noticeable for all processes, they are the most significant
for the sodium and magnesia processes which require
thermal energy for regeneration of absorbent. Multiple-
effect evaporation would reduce sodium scrubbing energy
costs about 18%. Energy costs are more significant for
oil-fired than for coal-fired installations because of the
higher equivalent price of fuel. For all processes, labor cost
is a minor component; Cat-Ox has both the lowest labor
and energy costs.
Inclusion of product revenue in the base case lifetime
operating cost estimates for the magnesia scrubbing, sodium
scrubbing, and the catalytic oxidation process reduces the
total lifetime operating costs only about 5% to 7%.
The cumulative effect of operating the various processes
(base case) over the life of the power unit is equivalent to
discounted unit cost increases ranging from S7.63 to
$10.14 per ton of coal burned in comparison with a coal
purchase price of $13.00 per ton projected for this study.
Other cases vary from as low as $6.03 per ton of coal to as
high as $19.96 per ton of coal burned. Generally, the cost
of power to consumers could be expected to increase about
10% to 30% for stack gas scrubbing depending on scale of
application, characteristics of each electrical power genera-
tion and transmission system and inflationary trends. For
all case variations examined in this study, projected 1975
stack gas scrubbing operating costs range from 1.57 to 7.90
mills/kWh.
-------
Table S-7. Summary—Cumulative Discounted Process Costs and Equivalent Levelized Unit
Increase (Decrease) in Cost of Power Over the Life of the Power Unit3 (Including Credit for Byproducts)
Case
Coal-fired power unit
90% SOj removal ; on-site solids disposal
200MWN3.5%S
200MWE3.5%S
500MWE3.5%S
500 MW N 2.07c S
500MWN3.5%S
500MWN5.0%S
1,OOOMWE3.5%S
1,OOOMWN3.5%S
Years
life
30
20
25
30
30
30
25
30
Limestone process
Cumulative Levelized
present increase
worth net (decrease)
increase in unit
(decrease) operating
in cost of cost,
power,b $ mills/kWhc
40,142,800 3.66
29,067,800 4.73
70,550,000 3.09
69,314,200 2.53
78,439,900 2.86
86,426,800 3.15
111,985,400 2.45
120,015,500 2.19
Lime process
Cumulative Levelized
present increase
worth net (decrease)
increase in unit
(decrease) operating
in cost of cost,
power,b $ mills/kWhc
41,112,500 3.75
34,979,000 5.69
84,117,600 3.69
68,709,000 2.50
79,593,300 2.90
89,293,900 3.25
130,977,300 2.87
121,789,900 2.22
Magnesia process
Cumulative Levelized
present increase
worth net (decrease)
increase in unit
(decrease) operating
in cost of cost,
power,b $ mflls/kWhc
44,860,300 4.09
36,106,200 5.87
78,292,200 3.43 '
71,503,600 2.61
84,249,500 3.07
95,621,900 3.49
121,156,200 2.66
126,808,00 2.31
Sodium process
Cumulative Levelized
present increase
worth net (decrease)
increase in unit
(decrease) operating
in cost of cost,
power,b $ mills/kWhc
55,045 000 5.02
48,568,300 7.90
113,985,500 5.00
85,604,900 3.12
104,292,300 3.80
121,660,300 4.43
188,464,400 4.13
160,375,200 2.92
Cat-Ox process
Cumulative Levelized
present increase
worth net (decrease)
increase in unit
(decrease) operating
in cost of cost,
power,b $ mills/kWhc
44,823,500 4.08
42,423,000 6.90
106,607,800 4.67
95,780,300 3.49
94,320300 3.44
92,805,300 3.38
181,013,700 3.97
148,117,600 2.70
80% SO2 removal; on-site solids disposal
500 MW N 3.5% S 30
90% SOj removal; off-site solids disposal
500MWN3.5%S 30
90% SO2 removal (existing unit without
existing particulate collection
facilities)
500MWE3.5%S 25
75,259,300 2.74
80,426,200 2.93
87,143300 3.82
76,687,900 2.80
80,903,300 2.95
84,924,200 3.72
81,119,800 2.96
98,245,000 3.58
93,875,800 4.12
130,713,900 5.73
119,124,800 5.22
Oil-fired power unit
90% SO2 removal; on-site solids disposal
200 MW N 2.5% S
500MWN1.0%S
500MWN2.5%S
500 MW N 4.0% S
500 MW E 2.5% S
1,OOOMWN2.5%S
30
30
30
30
25
30
28,281,000
46,404,800
54,743,900
61,808,400
58,358,800
87,171,700
2.58
1.69
2.00
2.25
2.56
1.59
33,612,500
56,505,800
66,727,200
74,929,500
70,126,200
103,411,900
3.06
2.06
2.43
2.73
3.07
1.88
30,089,900
44,030,300
55,673,400
65,572,800
61,393,300
85,962,400
2.74
1.61
2.03
2.39
2.69
1.57
39,147,900
55,025,400
74,204,600
91,887,900
82,852,700
118,705,700
3.57
2.01
2.70
3.35
3.63
2.16
29,653,800
63,574,000
61,591,500
59,249,500
96,305400
96,899,300
2.70
2.32
2.25
2.16
4.22
1.77
*Basis:
Over previously defined power unit operating profile. 30-yrlife; 7,000 hr-10 yr, 5,000 hr-5 yr, 3,500 hr-5 yr, 1,500 hr-10 yr.
Midwest plant location, 1975 operating costs.
Investment and operating cost for disposal of fly ash excluded.
Constant labor cost assumed over life of project.
^Discounted at 10% to initial year.
cEquivalent to discounted process cost over life of power unit.
-------
Table S-8. Lifetime Byproduct Production and Credit
Base Case, 500-MW New, Coal-Fired, 3.5% S, 30 Years Remaining Life
Equivalent lifetime
production
Process
Magnesia
slurry -
regeneration
Sodium
solution -
SOj reduction
Catalytic
oxidation
Product
100%H2S04a
Sulfur
Na2S04
100%H2S04b
Short tons
2,011,500
595,000
237,000
2,002,500
Net revenue
$/short ton
8.00
25.00
20.00
6.00
Cumulative revenue
Actual $
16,092,000
19,627,500
12,015,000
Discounted $
6,923,300
8,446,300
5,168,900
aAs 98% H2S04.
bAs80%H2SO4.
10
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Introduction
For the past several years, the increasing emission of air
pollutants to the environment from a multitude of sources
has prompted industry and government on all levels to seek
ways to reduce and control their discharge. Supported by
funds provided by Congress in the Air Quality Act of 1967,
the Clean Air Act of 1970, and subsequent appropriations,
investigations have been directed toward determining the
sources, causes, and effects of air pollution in the United
States and considerable effort has been expended to
research and develop mclliods of air pollution control.
One emission source receiving heavy attention is the
large, stationary power plant burning fossil fuel. The
primary pollutants entitled from these plants are particu-
lates, sulfur dioxide, and nitrogen oxides. A typical
500-MW unit burning coal containing 3.5% S and 12% ash
would, without any pollution controls, release each day up
to 273 tons of S02, 405 Ions of participates, and 53 tons
of nitrogen oxides. Will) Hie promulgation of the new-
source emission standards lor largo steam generators by the
Federal Environmental Protect ion Agency (10), the need
for workable, reliable pollution control techniques has
become critical to the future of fossil fuel power
generation.
Of the three primary pollutants, control methods for
S02 have commanded the greatest research and develop-
ment interest for several years. Methods for particulate
control such as stack gas electrostatic precipitators are
considered to be commercial and reasonably reliable by the
utility industry. Currently, effective techniques for nitrogen
oxide control have narrowed to boiler design and flame
temperature modifications. In contrast, SOj control investi-
gations are being directed at both the front and the rear of
a boiler-operating train including such concepts as fuels
desulfurization, fuels gasification with sulfur removal, and
wet or dry stack gas cleanup systems.
Probably the most advanced of .these concepts are the
stack gas S02 removal systems. Over the last few years, no
less than 50 different processes have received attention and
at least 5 have advanced from the pilot-plant stage to
demonstration-scale installations.
Through the cooperative efforts of EPA, process
developers, and several interested utilities, large-scale test
programs are now under way for limestone scrubbing and
lime scrubbing processes, both of which produce sludge for
discard, and magnesia scrubbing • regeneration, catalytic oxi-
dation, and sodium scrubbing - SO? reduction processes
which produce recovered sulfuric acid or sulfur. The test
and demonstration systems with their sponsors, size,
location, and startup dates are shown in table 1.
EPA is providing a large part or all of the funding for
these particular installations. In addition to these, several
other full-scale S02 removal systems are being operated,
Table 1. EPA-Sponsored Stack Gas Desulfurization Demonstration Systems
EPA-sponsored process
(byproduct)
Limestone slurry scrubbing
(sludge)
Lime slurry scrubbing
(sludge)
Magnesia slurry scrubbing -
regeneration
(98% sulfuric acid)
Catalytic oxidation
(reheat)
(80% sulfuric acid)
Sodium scrubbing -
regeneration
(sulfur)
Cooperating
utility
TVA
TVA
Boston I'ldison
Illinois Power
Northern Indiana
Public Service
Co.
Process
developer
Bechtel and
others
Chemico,
Bechtel, and
others
Chemico-Basic
Monsanto
Davy Powergas
Allied Chemical
Location
Shawnee Unit 10
Paducah, Ky.
Shawnee Unit 10
Paducah, Ky.
Mystic Station 6
Boston, Mass.
Wood River Station 4
East Alton, 111.
D. H. Mitchell
Station 1 1
Gary, Ind.
Unit size
and type
10MW
coal
10 MW
coal
155 MW
oil
110MW
coal
115MW
coal
Expected
startup
Under way
Under way
Completed
Mid- 1974
Late 1975
11
-------
constructed, or planned by a number of utilities at their
own expense; a list is given in Appendix C (11).
At this time, probably the two questions uppermost in
the minds of the utility industry regarding stack gas SQj
removal processes are system reliability and cost. Reliability
will slowly emerge as the equipment, materials of construc-
tion, and operation of each process show improved per-
formance. As necessary, spare capacity may be specified for
the more rigorous duties and provisions for interruptible
service may need to be established.
Like reliability, accurate costs for S02 removal systems
will emerge over a period of time; however, for decision
purposes, detailed, comparative estimates are needed today
to guide management's financial planning. Furthermore, the
expected impact of pollution control on the cost of power
to consumers is always on Ihc minds of utility managers.
Unfortunately, like most new concepts emerging from
research and development, SO2 removal systems have a
history of increasing costs as more is learned and better
process definition is established. Cost estimates of the late
I960's were considerably lower than recent projections due
to the early optimistic view of the investigators that the
system unknowns would probably offset one another,
simplified designs would prevail, and inexpensive materials
of construction could be utilized. In most cases, these
estimates could not be compared and were confusing
because different systems, premises, and data sources were
involved. Early capita! estimates for stack gas scrubbing
systems were as low as $5.00/kW of power unit capacity
and as high as $40.00-$50.00/kW (25, 37, 56, 57, 60) and
initial operating cost estimates indicated a range of $0.75 to
$1.50/ton of coal burned (0.25-0.80 mills/kWh). As time
passed and pilot-plant results became known, the magni-
tude of the estimates increased (7, 26, 28, 40, 43), and as
we know now, much higher costs can be expected.
The technologies associated with the five leading
processes have advanced to the demonstration stage and
large-scale systems are being offered for sale. Installations
are being designed and constructed, and equipment and
materials purchased; therefore, it is felt that more accurate
cost estimates can be prepared.
The objective of this study was to prepare detailed,
comparable estimates of capital and operating cost for the
five most advanced S02 removal systems on a common,
uniform basis and to display the results in a highly visible
manner. The latest available process and equipment
development, design, and economic data were used. The
estimates are generally applicable to most power units in
the Uriited States with a specific base case to represent each
process. The effect of all important design and economic
variables was determined by the use of sensitivity analysis,
The evaluation of each process includes a flow diagram,
material balance, recommended equipment lists and lay-
outs, and detailed capital investment and operating cost
estimates for the base case, plus summarized estimates for
each variation from the base case. Key variations cover unit
size, fuel type, sulfur in fuel, plant status (new vs. existing),
on-stream time, energy cost, maintenance cost, labor cost
escalation, raw material cost, capital charges, and percent
S02 removal. For the throwaway processes, off-site versus
on-site solids disposal costs are evaluated and for recovery
processes, sensitivity to net revenue changes is projected.
Using the evaluation techniques established in a series of
process conceptual design reports previously prepared by
TVA for EPA (28, 56, 57), the best applications of each
process are shown.
-------
Process
Background
Although the majority of research and development,
design, and construction effort on the five systems evalu-
ated in this study has occurred during the past 5 to 10
years, some of the basic work was performed as early as the
1930's. Much of this is still applicable and has been used to
guide researchers of today. For perspective, a brief discus-
sion of the process chemistry, history, and characteristics
for these five processes is given here.
LIMESTONE-LIME SLURRY SCRUBBING
Of all the stack gas S02 removal systems, limestone and
lime slurry processes have received the most attention.
During recent years, scientists and engineers have examined
the chemistry of the systems, curried out bench-scale and
pilot-plant studies, prepared various designs for full-scale
demonstrations, and in some cases, operated these for
limited periods.
In regard to the chemistry, there is some agreement for
the following series of reactions occurring during SG2
absorption by an aqueous scrubbing liquor.
When lime is substituted for limestone as the scrubbing
agent, the additional reactions shown below also occur.
S02(g)^S02(aq)
HSO3- + H+
0)
(2)
(3)
When using limestone, it simultaneously dissolves into
the scrubbing liquor as shown in equations 4 and 5.
CaC03 (s) «* CaCO, (aq) (4)
Sulfite ion combines with calcium to yield the very
insoluble calcium sulfitc hemihydralc.
Carbon dioxide, either in the Hue gas or from calcium
carbonate interacts with water as shown in equations 7 and
S.
C02(g
HOV
C'0,=
(7)
(8)
In addition, siillllo ion may be ultimately converted to
gypsum via the following reactions:
CaO + H20 •* Ca(OH)2 (s)
Ca(OH)2 (s) * Ca(OH)2 (aq)
Ca(OH)2 (aq) * Ca++ + 20HT
Ca(OH)2 (aq) + CO 3 = * CaC03 (aq) + 20H"
-» S04
(9)
(10)
(11)
(12)
(13)
(1 4)
(15)
The pH of lime slurries is higher than that of limestone
slurries because of the additional hydroxide ion supplied by
the slaked lime. The first use of limestone, lime, or their
related compounds in an aqueous medium as an absorbent
for S02 was over 40 years ago at the Battersea and
Bankside power stations in London (21, 42). A once-
through system was utilized. About the same time (early
1930's), the Imperial Chemical Industries-James Howden
and Company, Ltd. (32), tried a circulating liquor system
using lime or chalk at the Tir John (Swansea) and Fulham
(London) power stations. This 35- to 40-MW system was
the first effort to develop a closed-loop (water) process.
The Tir John installation was abandoned early; however,
the Fulham unit operated until World War II when it was
shut down because the plume was thought to be attracting
enemy aircraft.
In the early 1950's, TV A (55) conducted some brief
pilot-plant studies using a 10% limestone slurry in a packed
tower.
In more recent times (1965), Wisconsin Electric Power
and Universal Oil Products (UOP) carried out a 1-MW joint
program (38) on a coal-fired 120-MW boiler using the
"turbulent contact absorber" (TCA) (a scrubber filled with
mobile plastic spheres). The device showed considerable
promise by removing 85% of the S02 and 99% of the fly
ash. Another program (1966-1967) was conducted by
Combustion Engineering (CE) (37) and Detroit Edison in
which limestone was injected into a boiler to get low-cost
calcination and react the CaO with SOj in the gas. The
reaction products were then caught in a downstream
scrubber (National Dust Collector Hydro-Filter-a marble
bed device). Results were encouraging with 98% S02
removal and 99.5% removal of the dust.
As interest in SO2 removal systems escalated in the late
1%0's. scvoral other companies initiated research and
development work on limestone and lime scrubbing
processes. Such U.S. concerns as Babcock and Wilcox
Company (B and W), Chemical Construction Corporation
13
-------
(Chemico), Rescarch-Collrcll, /.urn Industries, and Peabody
Coal Company developed data lor commercial systems
using limestone scrubbing, and Cbemico, Combustion
Engineering (CE), and Combustion Equipment Associates
(CEA) worked with lime scrubbing. 'In addition, EPA and
TVA joined with Bechtel Corporation in an extensive
research program on a TVA boiler at Shawnee Steam Plant
(near Paducah, Kentucky). Outside the United States, AB
Bahco Ventilation in Sweden; Gottfried Bischoff KG in
Germany, Mitsubishi Heavy Industries in Japan, and
NI10GAZ (State Research Institute of Industrial and
Sanitary Gas Cleaning) in the USSR have researched
limestone-lime scrubbing.
On the basis of their early pilot work, CE built four
scrubber systems in the period 1968-1972, all embodying
boiler injection of limestone followed by scrubbing in
marble-bed scrubbers.
Boiler size. Number of
_ Company Station MW scrubbers
Union Electric Meramec 140 2
Kansas Power and Light Lawrence 125 2
Kansas Power and Light Lawrence 420 6
Kansas City Power and
Light Hawthorne 2 x 140 4
Notwithstanding the promising pilot-plant operation at
Detroit Edison, all of the early full-scale units had major
difficulties with corrosion, erosion, solids deposition (both
"mud" deposits and scaling), arid dcmisler plugging. Solids
deposition occurred not only in the scrubber but also in the
boiler. Removal of SO? was not as high as in the pilot
plant.
The Union Electric operation has been abandoned and
one of the Hawthorne scrubbers has been converted to
limestone slurry scrubbing. The other units are still being
operated and some progresses being made in resolving the
problems. However, it seems generally accepted now that
injecting limestone into the boiler is not a good practice.
CE has shifted emphasis to introduction of lime or
limestone into the scrubber loop rather than into the boiler.
CE's latest effort was at Louisville Gas and Electric's
Paddy's Run station ((>!), where two 35-MW marble-bed
scrubbers were started up in April 1973. The absorbent,
introduced into the pump tank in the scrubber loop, is
byproduct lime (hydrated) from a nearby carbide opera-
tion. The system has operated efficiently and reliably for
short periods since startup, and is generally regarded as one
of the best applications of lime-scrubbing technology.
B and W concentrated on use of limestone, first carrying
out a pilot-plant program in its own laboratories and later
building a two-scrubber installation on a 160-MW boiler at
Commonwealth Edison's Will Comity station near Chicago.
One scrubber is of the TCA type described earlier and the
other a perforated-plate type developed by B and W. The
system, started up in February 1972, has been subject to
continuing problems and is still not operating satisfactorily.
In addition to problems in the scrubber and demister, Will
County has had trouble with mist passing through the
demister and corroding the steam-heated tube-type
reheaters.
The La Cygne (Kansas) plant of Kansas City Power and
Light, a single 800-MW boiler fitted with seven B and W
scrubber trains, was started up in June 1973. Each train
consists of a venturi scrubber for particulate removal
followed by a perforated-plate scrubber for S02. Problems
similar to those at Will County have been encountered.
Although they offer a limestone scrubbing process,
Chemico has been more active in lime slurry scrubbing. In
March 1972, a Chemico-designed two-train system (two
Venturis in series in each train) was started up on a 156-MW
coal-fired power boiler at Mitsui Aluminum's Omuta plant
in Japan (45). The absorbent is byproduct carbide lime,
similar to that used at Louisville Gas and Electric as
described earlier. Since the boiler is equipped with efficient
electrostatic precipitators, little or no particulate removal is
required in the scrubbers. Mitsui Aluminum has reported
little difficulty in operation and the system apparently has
operated reliably.
In the United States, Chemico has installed a 400-MW
venturi system at Duquesne Light's Phillips station near
Pittsburgh. There are four scrubber trains, each with a
single venturi for particulate removal; one of the trains also
has a second venturi in series to test S02 removal. The
particulate scrubbers were started up in late 1973. The
Phillips installation was to be a test of the Chemico process
under conditions more analogous to the U.S. power
industry than those in Japan.
Research-Cottrell, a major manufacturer of electrostatic
precipitators, has developed a limestone-scrubbing system
based on use of a scrubber packed with an open type of
packing similar to that generally used in cooling towers.
After an initial pilot-plant test program at an American
Electric Power station ui Ohio, Research-Cottrell built a
two-train system on a 115-MW boiler at the Cholla station
of Arizona Public Service in Arizona. The system was
started up in late 1973.
One of the more extensive limestone-lime scrubbing
programs is the joint EPA-Bechtel-TVA program started in
1970 (5). The EPA-funded test demonstration facility at
TVA's Shawnee Steam Plant is probably the most versatile
and sophisticated S02 prototype in the world. The test
program is under the direction of Bechtel and the facility is
operated by TVA. Three 10-MW scrubbers of different
types are operated in parallel, each fully instrumented and
feeding data into an advanced data processing system. All
phases of lime-limestone scrubbing are being studied, from
operating parameter optimization to equipment reliability
14
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Over $12 million has already been spent Hy EPA for work
here.
In the planned program, emphasis will be placed on
sludge disposal (41, 44), which is generally regarded as the
main unresolved problem in lime-limestone scrubbing. Test
ponds will be constructed to evaluate both waste pond
disposal and methods for sludge "stabilization" (conversion
to a nonleachable and structurally stable solid).
The process design data used in this study for limestone
scrubbing are based primarily on the Shawnee (5) test work
and those for lime scrubbing are based on Chemico
technology (45). Chemico's assistance also included a
review. In addition, available information from some of the
other mentioned full-scale facilities influenced the designs.
MAGNESIA SLURRY SCRUBBING • REGENERATION
A detailed background of Iliis process can be found in
the EPA-TVA conceptual design report published during
1973 (28). Around the world, development work on the
magnesia scrubbing process has followed at least three
major technological routes since the early thirties. Russian,
Japanese, and American developers have concentrated on
the use of magnesium sulfite-magnesium oxide slurries
having a basic pH; whereas, a German company, Crillo-
Werke AG, has researched the use of an absorbent activator,
manganese dioxide, with the slurry. In addition, using
technology associated with sulfile paper pulping practice, at
least one American company has also investigated the use
of magnesium sulfitcs in acidic solution so that simulta-
neous particulale and S02 removal can be accomplished
with a single scrubber in coal-fired unit application. The
basic slurry process is the most advanced system and,
therefore, is the one evaluated in this study.
There arc three series of reactions which occur in the
magnesia slurry scrubbing - regeneration process. In the first
series, the scrubbing step, the following reactions
predominate:
S02 absorption, lerm-scnleil by the reactions:
5H20+ Mg(01l)2 » SO, -> Mj>SO.,-6ll20 I (16)
S02 + MgSO.,-6lljO -> Mg(llSO;,)2 + 511 20 (17)
Bisulfite neutrali/alion, represented by the reaction:
Mg(HSO,)2 + MgO + i1112O->2MgSO3-6H20 4 (18)
MgS04-6H20 will also be occluded in the MgS03-6H20.
The chemical reactions which occur in the dryer are:
Magnesium sulfite oxidation, represented by the
reaction:
2MgSO., + O2-» 2MgS01
(19)
Magnesium sulfite hcxahydrale crystals are removed
from the scrubbing system and either sent directly to a
dryer or thermally converted to MgS03-3H2G and then
dried. It is expected thi.t some MgSO4-7H2O and perhaps
MgS03-3H20 £ MgS03 + 3H20 1
MgS03-6H2o£MgS03°+6H2Ot
MgS04-7H2O^MgS04a"7H2Ot
(20)
(21)
(22)
The dry crystals are calcined at 800° to 1100°C in the
presence of coke or a reducing atmosphere to regenerate
MgO and S02. The reactions occurring in the calciner are:
MgS03 -» MgO + S02 t
C+ 1/202-»CO
CO + MgS04 -> C02 + MgO + S02 t
(23)
(24)
(25)
The magnesium oxide is cycled back to the scrubber
system and the S02 is sent to a sulfuric acid plant.
In the United States, development of the magnesia
scrubbing - regeneration process for S02 control has been
undertaken primarily by two companies-Chemico-Basic (a
joint company formed by Chemical Construction Corpora-
tion, New York, and Basic Chemicals, Cleveland, Ohio) and
Babcock and Wilcox Company, Barberton, Ohio. In
addition, a contractor-constructor. United Engineers and
Constructors, Philadelphia, is actively involved in design
technology.
Chemico-Basic was the first U.S. company to market a
complete magnesia scrubbing - regeneration process for sul-
furic acid production using S02 from power plants,
smelters, or sulfuric acid plant waste gases. Pilot-plant test
work was completed at several locations, including parti-
culate scrubbing at the Holtwood Station of Pennsylvania
Power and Light; Crane Station of Baltimore Gas and
Electric; and Dickerson Station of Potomac Electric Power;
and S02 scrubbing at Canal Electric Company, Sandwich,
Massachusetts; Olin Corporation (sulfuric acid plant) in
Baltimore, Maryland; and Cleveland Electrical Illuminating
Company in Cleveland, Ohio. Most of these pilot plants
processed about 1,500 cfm of gas or 0.50-0.75-MW
equivalent.
One of the more important contributions on magnesia
slurry scrubbing is a study (8) completed in 1970 by B and
W for the Office of Research and Monitoring of EPA. In a
pilot plant (2,000 acfm) at the Alliance, Ohio, Research
Center, data were obtained on both particulate and S02
scrubbing in a venturi-type scrubber and S02 removal in a
mobile-bed scrubber (termed Floating Bed Absorber). Tests
were made of the effect, of liquid:gas ratio, pressure drop,
slurry composition (including pH and sulfate concentra-
tion), stoichiomctry. fly ash, preslaking of MgO, and
scrubber liquid residence time on S02 removal. In addition,
evaluations were made of the scaling problem, SO2 forma-
tion in the coal burners, and NOX removal. The particulate
and SO2 removal data derived in this study should
be very useful in the design of power plant scrubber
systems.
15
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Because of the advanced development of the basic
magnesia slurry process, it was selected by EPA as one of
the more promising S02 control processes ready for
demonstration in a commercial-size installation. In July
1970, EPA, an electric utility ^company (Boston Edison),
and a design engineering firm (Chemico-Basic) combined as
a group to fund, design, build, and operate the magnesia
scrubbing system at Boston Edison's Mystic Station No. 6,
a 155-MW steam generating,,unit located in Everett,
Massachusetts. The station, ran oil-fired facility, was
equipped with a single-stage venturi scrubber system to
remove S02 from the stack gases. The magnesium sulfite
slurry formed is dewatered and dried and the crystals
shipped to an existing sulfuric acid plant owned by Essex
Chemical Corporation located at Runford, Rhode Island.
There the material is calcined to release S02 for the 98%
acid unit and the resultant magnesium oxide shipped back
to the power plant.
During a 2-year test period beginning in 1972 (27), a
program was undertaken to lest various operating param-
eters, optimize emission control under a power plant
operating cycle, demonstrate reliability, and accurately
define system operating cost. At the end of the test and
evaluation program, a report will be prepared presenting the
results.
A second system utilizing magnesia slurry scrubbing has
been installed by Potomac Electric Power Company at their
Dickerson, Maryland, station, Unit No. 3. Half of the flue
gas from a 195-MW coal-fired unit is treated by a two-stage
venturi scrubber system to remove both particulates and
S02. Particulate removal is expected to exceed 99%, and
S02 removal will be 90% plus. Startup is under way. The
magnesium sulftte from the S02 scrubber will be
dewatered, dried, and then shipped to the Essex Chemical's
sulfuric acid plant in Rhode Island for processing in the
EPA unit associated with the Boston Edison project.
Potomac Electric Power Company funded the scrubbing
portion of the system which was designed by Chemico and
constructed by Brown and Rool.
A third installation of magnesia scrubbing is located at
the Eddystone Slation of Philadelphia Electric. The
120-MW coal-fired system, designed and built by United
Engineers and Constructors (1), is scheduled for startup in
late 1974.
For the most part, the process design of the magnesia
scrubbing system evaluated in this study is based on the
Boston Edison demonstration unit. Some incorporated
modifications such as fluid bed drying and calcining remain
to be proven in practice; however, in all cases, the
alterations have been reviewed by Chemico.
SODIUM SOLUTION
SCRUBBING-S02 REDUCTION TO SULFUR
Technology related to scrubbing SOj with soluble,
inorganic sodium compounds also dates back to the
Johnstone (24) work of the late 1920's and early 1930's.
Even in the initial days of S02 removal research, the
desirable qualities of high sodium absorbent solubility and
low vapor pressures were recognized. Most of the early
efforts utilized sodium carbonate or sodium hydroxide to
form sulfite-bisulfite scrubbing solutions. One of the early
drawbacks encountered was high sulfate formation
(oxidation).
During recent years, the versatility of sodium solution
scrubbing has received even more attention as process
developers sought to use the system to produce either
salable liquid S02, sulfuric acid, or elemental sulfur, or as
the first step of a throwaway "double alkali" process. The
apparently less troublesome scrubbing step has induced
several developers to combine it with their proprietary
downstream processing technology creating a variety of
systems for sale.
Some of the organizations presently involved in the use
of sodium scrubbing processes for stack gas SO2 removal
are Davy Powergas Inc., Lakeland, Florida; Combustion
Equipment Associates, New York, New York; Universal Oil
Products, Des Plaines, Illinois; Stone and Webster - Ionics,
Boston, Massachusetts; and Envirotech Corporation,
Lebanon, Pennsylvania. A list of full-scale systems from
these developers is given in Appendix C. Other companies
are combining the sodium ion with organics for S02
removal.
The system given treatment in this study is the Wellman-
Lord scrubbing process (Davy Powergas) coupled with
Allied Chemical (Morristown, New Jersey) technology for
S02 reduction to elemental sulfur. Such a system is to
undergo EPA-sponsored demonstration (47) at the D. H.
Mitchell Station of the Northern Indiana Public Service
Company (NIPSCO) near Gary, Indiana.
The principal chemical reactions involved are discussed
below. The scrubbing step is primarily sodium sulfite
conversion to sodium bisulfite.
Na2S03.+ S02 +H2O-+ 2NallS03
(26)
The bisul file-rich absorbent is then thermally
decomposed in an evaporator - crystallizer.
2NaHS0
(crystals) U SO2 1 + H20t (27)
At this point the concentrated SO? from the Wellman-
Lord process is processed in the Allied Chemical reduction
unit by a series of reactions. Half of the S02 is reduced by
equation 28:
2SO* T CH4 -* COj + 2H20 + 2S
(28)
16
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A major portion of Ihc remaining SO2 is converted as
follows:
3S02 + 2CI14 -* 2C02 + 2H2O + 2H2S + S (29)
The resulting H2S is then reacted with SO2:
S02->2H20
(30)
The Wellman-Lord process (62) was conceived in mid-
1966, successfully demonstrated on a bench-scale opera-
tion, and proven to be feasible in late 1966. After early
pilot-plant experience (35) on a Tampa Electric Company
station and a Baltimore Gas and Electric Company unit in
1967-1969, modifications to the system were made and the
first commercial unit was installed in July 1970 at the
Paulsboro, New Jersey, sulfuric acid plant of the Olin
Corporation. This early installation treated successfully
about 45,000 scfm of acid plant tail gas. Since then, several
systems have been installed and operated on a variety of
offgas feeds in both (he United Slates and Japan.
One of the early successes (52) was a unit attached to an
oil-fired boiler at the Japan Synthetic Rubber Company
plant near Chiba, Japan. This unit started up in August
1971 processing about 124,000 scfm (75 MW) of stack gas.
Thus far, reliability has approached 95%-100% for 2 years
of operation reducing S02 from 1,500 to 150 ppm.
Another unit installed in 1973 on a 220-MW unit at the
Chubu (Japan) Electric Power Company has been said to
operate with load variations from 35% to 105%.
One of the initial problems encountered with the process
was high oxidation of sulfite to sulfate which is a liability
since disposal of sodium sulfate is difficult and makeup
requirements would be expensive. It is too soluble to be
dumped and the end use markets are not very large (glass,
detergent, pulp, and paper processing). Recent development
efforts, however, have led to the successful use of an
inhibitor and process alterations which minimize this
difficulty.
The Allied Chemical (22) phase of the process system is
a recent proprietary development coming from smelter
offgas control. In laic 1970, Allied completed installation
of a catalytic SO2 reduction system at the Falconbridge
Nickel Mines, Ltd., facility near Sudbury, Ontario, Canada.
The quantity of gas treated at Falconbridge (500 long
tons/day of sulfur) was equivalent to flue gas from 2,000
MW of power generation when fired with 3% sulfur coal.
The initial commercial installation w;,s so large that most of
the applications lo power plants will require scaledown
from this si/e rather than scalcup. This system operated for
about 2 years before shutdown due to shortages in feed
from the smelter.
The Allied reduction process currently uses natural gas
as a source of methane; however, work is under way to alter
the system to other more plentiful reductants. The process
can handle SO2 concentrations as low as 4%- to 5% and as
high as 100% where oxygen is limited. In those process
gases where oxygen content is too high or SOj concentra-
tion is too low for direct application, the process may be
joined with one of several regenerable flue gas scrubbing
processes which recovers the S02 in a concentrated,
low-oxygen gas stream. It is this procedure which will be
used in the demonstration on the 115-MW coal-fired No. 11
unit at the NIPSCO D. H. Mitchell Station. This installation
will be equally funded by EPA and NIPSCO and is expected
to cost about $11 million to construct. It is the only
EPA-sponsored system to produce elemental sulfur. Startup
is expected by late 1975.
In the full-scale system, 420,000 acfm of stack gas at
288°F will be scrubbed in a multitray device with the
effluent processed to yield about 4,230 Ib/hr of 85% S02
gas for feed to the Allied Chemical reduction unit. Sulfur
produced in the system (20 long tons per day) will be sold
by Allied.
As with the other projects funded by EPA, the Mitchell
demonstration will be studied to assess emission control
capability, operating reliability, flexibility, and costs. A
three-phase evaluation program is projected including (1)
preliminary engineering and cost estimates provided by
Davy Powergas in late 1972, (2) procurement of equip-
ment, construction and startup by late 1975, and (3) a
1-year operation by Allied funded entirely by NIPSCO.
For the sodium scrubbing - S02 reduction process
evaluation in this study, information supplied by Davy
Powergas and Allied Chemical was used to prepare the
process design and cost estimates. Most of this material is
still considered proprietary and, therefore, cannot be
released at this time; however, the evaluation is
representative of the process and has been reviewed by the
developers.
• CATALYTIC OXIDATION
The catalytic oxidation process evaluated in this study is
the proprietary Cat-Ox process developed by the Monsanto
Company, St. Louis, Missouri. For many years, Monsanto
has been a leader in technology for catalytic oxidation of
S02 to S03 when burning sulfur for the manufacture of
sulfuric acid. Their experience and expertise of this field
were used as a starting point in the development of the
Cat-Ox process which normally produces about 80%
sulfuric acid. The primary chemical reactions of the process
are:
2S02
2S03
(31)
(32)
The S02 in the stack gas combines with oxygen and
moisture already in the gas. The concentration of acid
which can be made depends primarily on SO2 concen-
17
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(ralion and the exit temperature of the stack gas to the
atmosphere. Tooling the gas too low will dilute the
resultant product hy moisture condensation.
The process is best suited for installation on a new unit
so that the original design can provide the high temperature
(850°-900°F) needed to convert S02 to S03. Reheat of
the gas is necessary if installation is on an existing unit.
Research on the process was started in 1961 as a joint
project of Monsanto Company, Pennsylvania Electric
Company, Air Preheater Company, and Research-Cottrell,
Inc., at the Seward station of Pennsylvania Electric. Later,
Monsanto assumed principal interest and with cooperation
from Metropolitan Edison built a 15-MW prototype (50) at
their Portland, Pennsylvania, station. This unit was com-
pleted and placed on-stream in the fall of 1967. Approxi-
mately 63,000 acfm of stack gas taken from the 250-MW
No. 1 boiler at Portland was passed through the prototype.
Fly ash removal w;is particularly critical to protect the
oxidation catalyst and the high-temperature, high-efficiency
precipitator installed was found to be very effective for this
service.
Alter about a year's operation, the project was pro-
nounced successful in late 1968 and ready for sale to
utilities; this process was the first to be ready for
demonstration.
In 1970, EPA agreed to partly finance a full-scale
demonstration of a reheat Cat-Ox system or. an existing
110-MW coal-fired unit of Illinois Power at the Wood River
Station near East Alton, Illinois. Illinois Power agreed to
furnish $3.8 million and EPA $3.5 million for the project.
Monsanto's Enviro-Chem Systems, Inc., provided the
technology for the installation on No. 4 boiler.
The detailed engineering was started in November 1970
and on-site construction started January 1971. The unit
was ready for operation by mid-1973; however, a limit of)
the natural gas supply for reheating the stack gas from 3iO°
to 850°F required a delay for modification of the reheat
burner system. System startup is now scheduled for
September 1974. Final cost for the project is now expected
to be $8,150,000 or $74/kW (31).
S02 conversion to S03 is expected to be 90% or better;
however, leakage across seals of the heat exchangers allows
about 5% of the gas to bypass the converter resulting in an
overall system efficiency of about 85%. Due to the
high-efficiency electrostatic precipitator, the screening
effect of the converter bed, and the efficient absorbing
tower and mist eliminator, particulate emission is virtually
negligible.
An extended test program is planned by EPA for the
demonstration unit. The Mitre Corporation (12) has been
contracted to carry out the test and evaluation program.
For a period of 5 years, Monsanto Enviro-Chem will be
responsible for disposal of the byproduct acid from the
system. The revenues from the acid sales will be split 75%
to Illinois Power and 25% to Monsanto. Approximately
19,000 tons/yr of 100% equivalent acid are expected to be
produced.
The Cat-Ox system designs used in this study are based
on Monsanto's design manual for the Wood River unit and
have been reviewed by Monsanto.
18
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Power Plant,
Process Design,
And Economic Premises
To compare the five stack gas desulfurization systems
under uniform conditions, a set of specific design assump-
tions are presented to aid in flowsheet, equipment, and
economic calculations. Criteria for each of the processes are
presented to establish efficiencies, production rate, and
other process design characteristics necessary to evaluate
die five individual processes simultaneously. The economic
premises are prepared with consideration of the many
factors that can affect costs.
POWER PLANT
Historical FPC data (17) and TVA power plant experi-
ence serve as a basis for establishing values for such
parameters as power unit size, unit heat rate, lifetime plant
capacity schedule, boiler type, and remaining years of
operation for existing units. Although the available data
vary over a wide range, the values used are considered to be
representative of the more typical modern boiler units less
than 10 years old for which stack gas desulfurization
systems would be considered.
Fuels
There are distinct and important differences between
control systems for power units burning coal or oil;
therefore, coverage includes both fuels with emphasis on
coal because it. is the fuel of greatest pollution potential.
Fuel compositions vary considerably; however, as in
previous conceptual design reports, the following repre-
sentative (28) fuel charaelcrislies are selected to evaluate
the economics of SO, removal.
I. Coal Although coals of relatively low sulfur and
ash content and high heating value are the most
desirable, a wide range of coals are currently being
used; therefore, coals with sulfur contents of 2.0%,
3.5%, and 5.0%, total heating value of 12,000 Btu/lb,
and ash content, of 12% are considered.
2. Oil—Since sulfur content of fuel oil is generally less
than for coal, concentrations of 1.0%, 2.5%, and
4.0% sulfur are assumed. A No. 6 fuel oil with an API
gravity of 15" and an ash content of 0.1% is assumed
to be a representative fuel with a total heating value
of 18,500 Btu/lb or 140,000 Blu/gal for all sulfur
levels (46).
Operation
The size of fossil-fueled power plants currently ranges up
to 1,300 MW. Although a considerable portion of the
future generating capacity will be from power units 500
MW or larger, many older and smaller units, 200 MW or
less, will be utilized in years to come. To determine the
effect of power plant size and status on the economics of
SO2 removal, three unit sizes, 200, 500, and 1,000 MW, are
given detailed attention for both new and existing units.
Power plant efficiencies vary with size and status. Repre-
sentative heat rates used in this study are shown in table 2.
Based on power plant evaluation guidelines suggested by
the FPC (14), the expected operating life of a new
fossil-fueled power unit is about 30 years. Historically, the
highest operating rates (on-stream time) occur during the
first 10 years of operation and decline thereafter.
Reflecting TVA experience (51), table 3 shows the power
plant operating schedule assumed for this study. This
schedule represents a total on-stream time of 127,500 hours
over the life of the plant.
When considering S02 control processes for power
plants, both the tendency of units to decline in utilization
over their operating life and the load variation on a
short-term basis because of electrical demand variation can
be significant. For recovery processes in particular, the
Table 2. Power Unit Input Heat Requirements
Size, MW
1,000
1,000
500
500
200
200
Table
Status
New
Existing
New
Existing
New
Existing
3. Assumed Power
Heat rate, Btu/kWh
8,700
9,000
9,000
9,200
9,200
9,500
Plant Capacity Schedule
Annual
Operating Capacity factor % kWh/kW
year (nameplate rating) capacity
80~ ' ~ 7,000
57 5,000
40 3,500
17 1,500
48.5 4,250
1-10
11-15
16-20
21-30
Average for 30-year life
19
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associated large investment requirements and market com-
mitmenls usually make it desirable to operate the recovery
system at a high capacity factor to minimize the effect of
the continuing fixed capital charges on unit production
costs.
Those recovery processes which sequentially absorb SOi
and later regenerate the S02 for recovery of the absorbent
(magnesia slurry - regeneration and sodium solution - SQj
reduction processes) could be designed with supplemental
storage facilities for the absorber effluent. This would allow
the regeneration facilities to be designed for smaller
throughput capacities resulting in a slight investment
savings since they would be capable of regenerating the
absorbent in storage when the power plant is operating at a
reduced load. Because of the relatively high operating
capacity (80%) assumed for the initial years of operation of
the power plant, however, this method of design and
operation is not utilized in the current study.
Since chemical plants are not normally designed to
operate at capacities greater than 90%, the maximum
amount of regeneration capacity which could be saved in
comparison to the base operating capacity of the power
plant is only 12.5%. For the sodium process this amounts
to an investment savings of approximately 4% and an
operating cost savings of 1.4%. The investment savings for
this method of design would only be significant /'or existing
power units with low anticipated load factors.
Since existing power units can be expected to have fewer
remaining years of operation at high capacity factors,
power plant age is also an important parameter. In this
study, existing 200-MW units are assumed to be 10 years
old, with a remaining life of 20 years, or 57,500 operating
hours; and 500-MW and 1,000-MW units are assumed to be
5 years old, with a remaining life of 25 years, or 92,500
operating hours.
Design
To serve as a basis for flowsheet calculations, it is
desirable to define distinct flue gas compositions for both
coal- and oil-fired systems. In doing so, however, it should
be recognized that these parameters vary with both power
plant design and fuel, and many variations can be
encountered (')). For' this study, balanced draft boiler
design is assumed along with the following combustion -
emission parameters.
I. Coal-fired units Hue gas compositions are based on
combustion of pulverized coal with 20%excess air to
the boiler, and 13% additional air inleakage'at the air
preheaver. These values reflect operating experience
with TVA hori/onlal, frontal-fired, coal-burning
units. It is assumed that 75% of the ash present in
coal is emitted as lly ash and 42% of the sulfur in the
coal is emitted as SO2.
2. Oil-fired units A tangential-fired boiler is considered
for oil-fired power units with flue gas compositions
estimated assuming 5% excess air to the boiler with
an estimated 10% air inleakage at the preheater. It is
also assumed that all of the ash and sulfur In the fuel
oil is emitted.
Flue gas compositions include a SOX concentration, fly
ash loading, and NOX concentration as presented in table 4.
These parameters depend primarily upon sulfur and ash
content of the fuel, excess air, air inleakage, and boiler
design. Nitrogen oxide compositions of flue gas are based
on representative data for common boiler types for both
coal- and oil-fired units (2, 3, 48); fly ash emission is based
on relatively high ash emission factors to insure satisfactory
design for removal of participates.
Existing coal-fired units are assumed to have 98.7%
efficient electrostatic precipitators already in operation
which meet Federal new source emission standards. For
new coal-fired units, fly ash collection facilities are pro-
vided in the process designs. Fly ash emission assumed from
new and existing oil-fired units does not exceed the EPA
particulate emission standard; therefore, these power plants
do not require fly ash collection facilities.
Some aspects of design and economics for S02 removal
units depend on fan and duct configuration and, for some
processes, on the number of economizers and air heaters;
therefore, consideration is given to their corresponding
locations. A balanced-draft power unit without an S02
removal unit normally requires one induced-draft fan per
duct capable of overcoming a pressure drop of approxi-
mately 15 inches downstream of the boiler. In the design of
new power plants with S02 removal facilities it is assumed
Table 4. Estimated Flue Gas Compositions for
Power Units Without Emission Control Facilities
Coal-fired boiler
Fuel and pulverized coal (hori- Oil-fired boiler
boiler type zontal, frontal-fired) (tangential-fired)
Sulfur content
offuel,%bywt 2.0 3.5 5.0 1.0 2.5 4.0
Flue gas
composition,
% by volume
Nitrogen 74.62 74.55 74.4973.8373.73 73.64
Carbon dioxide 12.57 12.55 12.5412.5212.37 12.21
Oxygen 4.86 4.86 4.85 2.55 2.55 2.54
Water 7.77 7.76 7.7511.0311.1911.37
Sulfur dioxide 0.12 0.22 0.31 0.05 0.14 0.22
Nitrogen oxides 0.06 0.06 0.06 0.02 0.02 0.02
Fly ash loading
Grains/sot" dry 4.11 4.11 4.11 0.0360.0360.036
Grains/scfwet 3.79 3.79 3.79 0.0320.0320.032
20
-------
lahle S. I'ower I'ljiii flue Gas and Sulfur Dioxide (.mission Rates
Power plan!
size, MW
Coal-fired units
200
200
500
500
500
500
1,000
1,000
Oil-fired units
200
500
500
500
500
1,000
aGas flows to new Cat-Ox
the air heaters.
Type
plant
New
Existing
Existing
New
New
New
Existing
New
New
New
New
New
Existing
New
installations are
Sulfur
content
of fuel, %
3.5
3.5
3.5
2.0
3.5
5.0
3.5
3.5
2.5
1.0
2.5
4.0
2.5
2.5
different from those shown
GasflowtoSOj8
recovery systems,
Macfm(310°F)
630
650
1,570
1,540
1,540
1,540
3,080
2,980
530
1,300
1,300
1,300
1,320
2,510
Equivalent S0a
emission rate to
S02 recovery systems
lbS02/hr
9,310
9,610
23,270
13,010
22,760
32,510
45,520
44,000
4,960
4,850
12,140
19,420
12,410
23,470
above because of the higher gas temperature (890°F) and relocation of
that the balanced-draft system includes the same capacity
F.D. fan; one I.D. fan is provided per duct downstream of
the SO2 removal system to overcome the remaining
pressure drop resulting from power generation and the
additional pressure drop attributed to SO^ removal. Since
existing power units are already equipped with a 15-inch
l.D. fan, existing SOj removal facilities are provided with
one supplemental fan per duct in series and adjacent to the
existing fan to supply the additional energy required for the
scrubbing facilities. In existing Cat-Ox processes, however,
the supplemental fan is located downstream of the recovery
unit. In this evaluation, 200-MW power units are assumed
to have two economizers, air heaters, and exhaust dpcts,
and 500- and 1,000-MW units are assumed to be equipped
with four of each.
The design of S02 removal facilities is dependent upon
actual quantities of gas and SO2 as well as gas compositions
indicated earlier. Calculated flue gas and equivalent S02
emission rates are tabulated in table 5.
PROCESS DESIGN
Emission Standards
The EPA has established emission standards (10) for new
steam generating facilities as shown in table 6. in this
report, process and equipment design will meet the
standards for particulate and SOj emission.
Degree of Removal
From the analyses of flue gas and Federal emission
standards it can be seen that required S02 removal
efficiencies vary depending on the sulfur content and type
of fuel. The required removal efficiencies for particulates
and SO? are given in table 7 for the various fuels and sulfur
levels considered in this study. Base case design provisions
Tabie 6. EPA Emission Standards for
New Steam Generating Faciiities
Allowable emission, Ib/rnil3ion
Btu heat input
Paiticulates
Sulfur dioxide
Coal-fired unit
0.1
1.2
OU-fired unit
0.1
0.8
Table 7. Required Removal Efficiencies
Sulfur content
of fuel, %
Degree of
particulate removal, %
Degree of
SOj removal,'
Coal-fired units
2.0
3.5
5.0
Oil-fired units
1.0
2.5
4.0
98.7
98.7
98.7
—
—
-
58.9
76.3
83.4
26.0
70.4
81.5
21
-------
arc lor ''0% SO7 removal rather lluin lor iiicclitig ininiinuin
requirements or for operating ;il maximum piocess capa-
bility. Special cases with design provisions for 80% S()j
removal (corresponding to a guaranteed design to exceed
the emission regulation of 76.3%) are prepared for new
500-MW, 3.5% S, coal-fired units for comparison of
economics with the base case.
Scrubber Redundancy, Bypass,
Turndown, and Shutoff
Scrubbing system design assumes that technology used
in each process is proven, has been demonstrated, and is not
"first of a kind." No special redundancy provisions are
assumed necessary for power-SO2 scrubbing system
reliability.
Several methods are available lo provide turndown
capabilities of the control systems resulting from changes in
power supply requirements including:
I, Multiple scrubbing (rains.
2. Variable How control to individual scrubbers.
3. Compartmentalized scrubbers.
4. Individual scrubber bypasses.
5. Connecting plenum ducts between trains.
These different methods affect both duct and scrubber
design and, unfortunately, little experience is available to
indicate which method is best. For this study, boiler ducts
are assumed to exhaust to a common plenum connecting
the scrubbing trains. Separate ducts from the plenum to
each scrubbing liain are equipped with dampers for
individual sciubber shutoff for maintenance or power plant
turndown. Scrubber circulation systems are provided with
constant speed pumps based on pumping rates corre-
sponding to the design L/C. Because of the reliability
implied in the assumption that these processes are not "first
of a kind," other special design provisions for individual
scrubber shutdown, are not provided. If one of the
scrubbing trains is required to shut down, the power
generation facilities would be required lo cut back on
operation so as not lo exceed (he design conditions for any
individual scrubber. The common feed plenum provides for
the shutdown of a scrubbing train during restricted opera-
tion of power plants due to low electrical demand or
required maintenance of the S02 removal facilities.
Bypass ducts for maintaining full power generation
capacity during shutdown of one or more scrubbing trains
are not provided excepl for the Cat-Ox process. For this
process, they are required to prevent contamination of the
catalyst and acid during power plant startup when the
electrostatic precipilators may not yet be operating at
design efficiency. For illustrative purposes, the additive cost
effect of designing a limestone scrubbing system with
bypass ducts is shown in table 79(p. I62)of the "Economic
Evaluation and Comparison" section under "Accuracy of
Results." The results for other systems might vary
depending on layout.
Particulate and Sulfur
Dioxide Control Devices
Venturi scrubbers are chosen for control of particulates
in the limestone, lime, magnesia, and sodium scrubbing
processes since they are generally considered to be the least
cost alternative. The Cat-Ox process, however, requires a
high degree of particulate removal (to 0.005 gr/scf) prior to
conversion of S02 to S03 at elevated temperatures for
both coal- and oil-fired units; therefore, fly ash is removed
by high efficiency electrostatic precipitators. As discussed
earlier, all existing coal-fired units are assumed to be
equipped with 98.7% efficient electrostatic precipitators;
therefore, only the Cat-Ox process requires additional
facilities for supplemental particulate control. Table 8
indicates the various devices selected for particulate and
SO2 control in the current study.
Although specific design conditions for SOj removal
systems may vary from installation to installation corre-
sponding to expected fluctuations in the analysis of the fuel
or proposed operating requirements, the projected
operating parameters for each base case scrubbing system
are presented in table 9.
Mist Eliminator Selection
The use of a mist eliminator in the S02 scrubber is
desirable for the following purposes:
I. To reduce the heat load on the stack gas reheater.
2. To decrease the deposition of liquid and entrained
.solids in ducts and equipment located downstream
from the scrubber.
3. To reduce the amount of entrained solids emitted to
the atmosphere.
For maximum efficiency and extended service, mist
eliminators should be designed for proper gas distribution
and include facilities for removing any accumulated solids.
Several types of mist eliminators are being used. From
limited experience and scrubber vendors' recommendations,
the following mist eliminators are selected for each of the
processes:
Process Mist eliminator
Limestone Chevron vane
Lime Chevron vane
Magnesia Chevron vane
Sodium Fleximesh
Cat-Ox Brink fiber demister
.Reheat
The need for stack gas reheat for plume buoyancy after
aqueous scrubbing has been recognized, but the degree of
22
-------
Table 8. Particulate and Sulfur Dioxide Control Devices
__
Coal-fired units
Limestone
Lime
Magnesia
SodiQm
Cat-Ox
Oil-fired units
Limestone
Lime
Magnesia
Sodium
Cat-Ox
Status
New
Existing
New
Existing
New
Existing
New
Existing
New
Existing
New
Existing
New
Existing
New
Existing
New
Existing
New
Existing
Particulate control
control
One-stage venturia
ESP
One-stage venturi"
ESP
One-stage venturi
ESP
One-stage venturi
ESP
High temperature,
high efficiency, ESP
ESP + additional ESP
for removal to 0.005 gr/scf
High temperature, ESP
ESP
Two-bed mobile bed
Three-bed mobile bed
One-stage venturi^
Two-stage venturi*'
One-stage venturi
One-stage venturi
Valve-tray absorber
Valve-tray absorber
Packed-bed absorber
Packed-bed absorber
Three-bed mobile bed
Three-bed mobile bed
Two-stage venturi^
Two-stage venturi"
One-stage venturi
One-stage venturi
Valve-tray absorber
Valve-tray absorber
Packed-bed absorber
Packed-bed absorber
fSpent SC>2 scrubber effluent used as scrubbing media.
Approximately 78% of the required lime is fed to the first ventari
Table 9. Assumed Operating Parameters for Scrubbing Systems Applied to New Coal-Fired Power Units
(Design Conditions-3.5% S Coal, 2,200 ppm SO2 in Inlet Gas, 90% Nominal SO2 Removal)
Process Limestone Lime Magnesia Sodium
Cat-Ox
1.20
Stoichiometry
Design gas velocity, ft/sec
Particulate scrubber
SOx scrubber
L/G, gal/mcf
Particulate scrubber
SOX scrubber
Design pressure drop, in H2O
Particulate scrubber
SOx scrubber
Percent solids in slurry
Particulate scrubber
SOX scrubber
Liquid residence time, minutes
Particulate scrubber effluent
SOx scrubber effluent
a99.9% high temperature ESP.
"Separate circulation loops are provided for each stage.
i.10
1.05
1.05
125-140
10
IS
70
A
)
10
10
8+ fly ash
8
tcs
nt 5
10
125
100
40
40
10
6
5+ fly ash
5
3
3
125-140
75
15
20
8.5
4.5
5
10
3
3
125-140
8
15
3°
8.5
10.0
5
0
3
_a
8
5
23
—
-
23
-------
reheat required has not been well established. The effect of
temperature on plume buoyancy and ground-level concentra-
tion of stack gas constituents was studied in detail for the
limestone - wet scrubbing conceptual design (57). The
results indicated that with a .high degree of S02 removal
(80% or above), the stack gas temperature is not critical.
However, to prevent high ground-level concentrations
during adverse conditions, reheat to 175°F is provided in
these comparative designs.
Some reheat is obtained from exhaust gas compression
when I.D. fans are used, but additional heat is needed to
reach 175°F at the stack exit. Approximately 4°F of
reheat are assumed lost as the gas passes through the stack.
The magnesia process obtains some reheat from the dryer
offgas. For new coal-fired power units, indirect steam
reheat is provided since new power units can be designed to
supply steam to the scrubbing area. In cases of existing
coal-fired and both new and existing oil-fired power units.
direct stack gas reheat is provided from the combustion of
fuel oil.
The Ca!-0x process does not require stack gas reheat
since the scrubbed gas exits at a temperature of 254°F.
Existing ("iil-Ox units, however, require reheat of the Hue
gas upstream of the converter. This reheat is supplied by
direct oil-fired gas reheat; however, operation of the Wood
River Cat-Ox installation has indicated Ihe need to control
particulate formation to a high degree during combustion
of the oil to prevent fouling of the converter catalyst.
Of the various methods for reheat of the stack gas,
indirect steam and direct oil-fired reheat are probably the
simplest to install, most reliable for their respective
applications, and are probably in the mid-cost range as
compared to other choices.
Raw Materials
Listed below are the raw materials which are utilized in
the five desuIfufixation processes, with assumptions for
inventory and typical characteristics given. Raw materials
and cuuiiysts which are considered proprietary are not
shown.
I. IJmeslone
Purchase si/e Ox 1-1/2 in.
Analysis ')()% CaC'();, (dry), 5% H,O
Limestone'ground as (>()% solids slurry
Ground si/.e 70% -200 mesh
Bulk density • 95 Ib/ft3.
Storage capacity .?0 days ,
2. Lime
Analysis 95% CaO, I % SiO2 , 2% Mgt)
Si/.e is -i-1/4 in. +3/4 in.
Buik density 55 Ib/ft '
Storage capacity 5 days (from "across (lie fence"
calcination plant)
3. Magnesium oxide
Calcined magnesite-98% MgO
Fine crystalline powder
Bulk density-20-30 Ib/ft3
Makeup MgO storage—30 days
4. Coke (petroleum)
Analysis
Typical-4.2% S, 0.1% ash, 9.0% volatile matter,
100 ppm vanadium
Contract-5.0% S maximum, 1.0% ash maximum,
7.0% volatile matter minimum, 200 ppm
vanadium maximum
Size is-1-1/2 in.
Calorific value-15,510 Btu/lb
Storage-30 days
5. Sodium carbonate
Analysis-99.8% Na2C03 (58.36% Na20)
Light soda ash
Bulk density--35.5 Ib/ft3
Storage capacity~5 days
6. Vanadium pentoxide catalyst
Pellets
Size-100%+7/32 in. diameter, 7/16 in. long
Bulk density-36.8 Ib/ft3
In-Procsss Storage
To give some flexibility of operation, in-process storage
is included to provide for interrupted service of certain
equipment. The amount of in-process storage provided for
each process is shown below.
1. Limestone process
a. Crusher feed bin-8 hr.
b. Slurry feed tank-8 hr.
c. Pond feed tank-62,000 gal (includes sufficient
surge capacity for shutdown of scrubbers).
2. Lime process
Process bin-8 hr
3. Magnesia process
a. MgS03 storage siio-1 day.
b. .Recycle MgO storage silo-1 day.
c. First-stage venturi scrubber surge tank-40,600 gal
(includes sufficient surge capacity for shutdown of
first-stage venturi scrubber).
4. Sodium process
a. Soda ash storage bin—5 days.
b. Dissolving tank—8 hr.
c. Surge tank-8 hr.
d. Centrate tank—3 min.
5. Cat-Ox process—none required.
Solids Disposal
One important design consideration for the limestone
and lime slurry processes is the method for waste solids
24
-------
disposal. The following I wo alternatives me utilized in this
study.
I. On-site disposal-A common pond for fly ash and
calcium solids is assumed for new power units. For
existing coal-fired power units, the existing ash
disposal pond is enlarged to accommodate the
calcium solids. This method of disposal is based on
the following assumptions:
a. Pond life is same as power plant remaining life
defined earlier in power plant design premises.
b. About one-sixth of the total interstitial water is
put into pond for startup.
c. Pond is lined with impervious clay and has a depth
of 40 ft.
d. Water is recycled back to the scrubbers to
minimize the consumption of fresh water and to
eliminate contamination of nearby streams.
e. Sludge contains 60% free water.
f. Pond evaporation and seepage equals rainfall.
2. Off-site alternative—A special case is evaluated (for
both the limestone and lime slurry processes) in
which the fly ash and calcium solids are trucked to
and disposed of off-site. Each process is designed
with a slurry dewatering system to produce a disposal
cake containing 50% solids. Sufficient charges (44)
per ton of wet solids are applied to cover trucking
and stabilization off-site.
Product Storage Capacity
The amount of storage which should be provided for a
product depends largely upon its consumption rate for each
end use. Since sulfuric acid, sulfur, and sodium suifate ars
intermediate products which usually undergo further
processing, the largest burden is often passed on to the
industrial consumer rather than the producer. However, to
provide for large consumer and cyclic markets such as the
phosphate fertilizer industry, storage requirements of 30
days 01 more are not uncommon. In this study, product
storage requirements are as follows:
Process
Product
Magnesia
Sodium
Sodium
Tat-Ox
Molten sulfur
Sodium suiJute
XO%1I2SO.,
ECONOMIC
Storage
30 days
30 days
7 days
30 days
To evaluate the economics of several processes at the
same time, a set of common criteria (6, 51) :s assumed
including plani location, cost indices, raw material prices,
method of financing, taxes, and other special provisions.
Two of the more significant items of comparison are capital
investment and operating costs.
Capital Investment
The numerous investment estimates are based on a
midwestern location with assumed land costs of
$3,000/acre and represent projects beginning mid-1972,
ending mid-1975, with an average cost basis for scaling of
rrrid-1974. Other projects may be scaled from mid-1974 to
the midpoint of project expenditures. The first 6-12
months are for design and the last 24 months for
construction during the 30-36 months project. Fixed
investments are prepared using the following Chemical
Engineering plant cost index and projections (58).
Year
1962 1963 1964 1965 1966 1967 1968
Material 100.6 100.5 101.2 102.1 105.3 107.7 111.5
Labor 105.6 107.2 108.5 109.5 112.5 115.8 120.9
Year 1969 1970 1971 1972a 1973a 1974a
Material H6.6 123.8 130.4 135.4 142.2 153.8
Labor 128.3 137.4 146.2 152.2 161.3 177.9
aProjections.
Other special provisions or assumptions required to
prepare uniform cost estimates are as follows:
1, Equipment, material, and construction labor
shortages with accompanying overtime pay
incentive are not considered.
2. Service facilities such as maintenance shops, stores,
communications, security, and offices are estimated
or allocated on the basis of process requirements
using current TV A practice as a guide.
3. Direct investments for each of the processes include
cost for 1 mile of paved roads.
4. Railroad facilities vary with each process depending
upon raw material and utility usage in addition to
the type process, i.e., throwaway or recovery.
5. Electrical switchyard locations are arbitrarily
assumed to be approximately 300 yards from the
control rooms.
6. Control room location varies with each process
depending upon equipment size and configuration
whereas the Cat-Ox process shares the power plant
control room. In the other processes, the control
rooms are located adjacent to the scrubbing
facilities and approximately 200 feet from the
powerhouse.
7. As required for each process, necessary electrical
substations and conduit, steam, natural gas, fuel oil
storage, process water, fire and service water, and
compressed air distribution facilities are included in
the investment.
25
-------
K. liiHlmmcnl aii gcncrnlloii lucllilios are included I'oi
cad i process. Steam Is assumed nol available from
Hie power plant cycle al existing unils. Fuel oil is
used to replace steam whenever possible lor existing
coal-fired and both new and existing oil-fired units.
In the sodium process regeneration area for existing
units, a package boiler is used for steam generation.
Where it is acceptable to tap into the existing steam
cycle (availability for production of power) a
savings in steam costs could be incurred because of
the low cost of coal in comparison to fuel oil.
Generation facilities for electricity are not included
in the investments.
9. Process water utilization is based on closed-loop
operation.
10. Spare pumps are provided to prevent operational
shutdowns due to pump failure; however, no other
spare equipment is included.
11. Solids disposal ponds are assumed to be 1 mile from
the scrubbing systems.
12. New coal-fired units are designed for the removal of
both fly ash and S02. The catalytic oxidation
process utilizes an electrostatic precipitator for
removal of fly ash upstream of the S02 removal
facilities. The aqueous scrubbing processes utilize
wet scrubbing devices for removal of both fly ash
and S02. As illustrated in tables 3544 and 59-68,
both investment and operating costs for removing
fly ash are included in the process economics but
both investment and operating costs for ash disposal
are excluded.
Existing coal-fired units are assumed to
already be equipped with electrostatic precipitators
capable of meeting .the EPA fly ash emission
standard (98.7% removal) and supplementary facili-
ties for disposal. Therefore, with the exception of
the Cat-Ox process, investment and operating costs
for existing units do not include supplementary fly
ash collection facilities. The Cat-Ox process requires
a higher degree of fly ash removal (99.9% overall
removal for coal-fired units and 84.4% removal for
oil-fired units) to prevent accelerated blinding of the
catalyst and contamination of acid. Additional
electrostatic precipitators are supplied for the Cat-
Ox process" -to increase the overall collection
efficiency to these levels.
13. In the limestone and lime slurry processes where fly
ash and calcium solids are removed and disposed
together, the investment and operating costs for the
disposal urea are prorated to include only the costs
attributed to calcium solids disposal.
14. For new units, the incremental investment or
operating cost attributed to fans is estimated as the
difference in investment or, operating cost of the
higher clingy Ian mid a IS inch A I' capacity fan
which would be required if scrubbiing facilities were
not to be installed. For existing units the total
investment and operating costs of the supplemental
funs are included.
15. Direct investment costs include construction facili-
ties equivalent to 5% of the direct area investments.
These allowances are based on TVA experience and
include costs for mobile equipment, temporary
lighting, construction roads, raw water supply,
safety and sanitary facilities, and other similar
expenses incurred during construction, but not
broken down and assigned to any specific area.
In addition to direct costs which include equipment,
installation, labor and materials, and construction facilities,
indirect costs for the project, which include engineering
design and supervision, construction field expense, contrac-
tor's fees, and contingency are included in the investment
estimates. The engineering design and supervision and
contingency factors are based on proven design, not "first
of a kind" installation. The percentages of direct invest-
ment used to estimate these items are shown in table 10.
These factors are based on established methods for esti-
mating indirect investment costs and agree with the general
range of projected values indicated in various cost esti-
mating sources (34). Slightly lower values of engineering
design and supervision are projected for the throwaway
processes than for the recovery processes reflecting less
complex engineering design and construction.
In keeping with FPC accounting practice, allowances are
included for startup and modification plus interest during
construction. Startup and modification allowances are
estimated as 10% of subtotal fixed investment for the
recovery processes, compared to 8% for the throwaway
processes reflecting the greater complexity of product
producing processes. Interest during construction is esti-
mated as 8% of the subtotal fixed investment for each
process. This factor is equivalent to the simple interest
which would be accumulated at an 8% per year rate
assuming a capital structure of 50% debt-50% equity (see
table 14) and a 3-year project expenditure schedule as
indicated below:
Project Expenditure Schedule
Year
Total
Fraction of total expenditure
as borrowed funds
Simple interest al 8%/year
as percent of total expenditure
Year 1 debt
Year 2 debt
Year 3 debt
Accumulated interest as
percent of total expenditure
1/8 1/4 1/8 1/2
3
4
1
26
-------
Table 10. Indirect Investment and Allowance Factors
Thmwaway processes,
of direct investment
Power
and
unit size
status
Engineering design
and supervision3
200
New
11
MW
Exist-
ing
12
500
New
9
MW
Exist-
ing
10
1 ,000 MW
New
8
Exist-
ing
9
Construction field
expense
Contractor's fees
Contingency3
Total indirects
Allowance for startup and modification (8% of subtotal
fixed investment); interest during construction at 8%/year
rate (8% of subtotal fixed investment)
13
7
1!
42
15
9
12
48
11
5
10
35
13
7
11
41
10
5
9
32
12
7
10
38
Power unit size
and status
Recovery processes,
percentage of direct investment
200 MW
500 MW 1,000 MW
New
Exist-
ing
New
Exist-
ing New
Exist-
ing
Engineering design
and supervision3 13
Construction field
expense 13
Contractor's fees 7
Contingency21 11
Total indivects 44
14 11 12 10 11
15
9
12
50
11
5
10
37
13
7
11
43
Allowance for startup and modification (10%
fixed investment); interest during construction
rate (8% of subtotal fixed investment)
10 12
5 7
9 10
34 40
of subtotal
at 8%/year
2Based on proven design rather than a "first of a kind" installation,
a minimum amount of contingency is included. For a "first of a
kind'' installation, contingency would normally be greater than
that shown above.
Operating Cost Basis
To prepare meaningful operating cost estimates, several
more ground rules and inputs must be defined. Some of
these have been discussed previously, such as those parame-
ters necessary to produce flowsheet calculations. Others are
defined here to permit calculation of annual, lifetime, and
unit operating costs.
All annual operating cost display sheets are based upon
7,000 hours of operation per year. Process operation
schedules are assumed to be the same as the power plant
operating profiles and remaining life assumptions given in
the power plant design premises.
Operating costs related to the removal and disposal of
fly ash are estimated similar to the investment costs. Cost
for new coal-fired units include the removal of fly ash,
whereas existing coal-fired and both new and existing
oil-fired units (except for Cat-Ox) do not. However,
operating costs are prorated to exclude costs for the
disposal of fly ash.
Charges for the disposing of solids off-site include
investment, treatment, transportation, and land costs. The
base trucking, off-site treatment, and land costs for
disposing calcium solids is assumed to be $4/ton (44) of
wet solids (50% free moisture in cake).
Raw material, labor, and utility costs are projected to
1975. Although costs for these items vary throughout the
country, representative values projected for this study (59)
are shown in table 11. (All tonnages are expressed as short
tons.)
Unit costs for steam and electricity generated by the
power plant are based on actual production cost including
labor, fuel, depreciation, rate base return on investment,
and taxes.
In the evaluation of lifetime economics, credit from sale
of byproducts is deducted from the yearly projections of
operating cost to give the net effect of the pollution process
on the ccst of power. Table 12 shows the base product
credits assumed in the study (13, 18, 29, 30, 36, 53) and
the range of values for which the sensitivity of lifetime
economics to net product revenue is evaluated (see figures
82-87).
Maintenance costs are estimated on the basis of direct
investment and are varied for each process as a function of
unit size corresponding to an assumed economy of scale.
The maintenance percentages applied are considered "best
estimates" and are derived by using comparable percentages
for common process areas as illustrated in operating cost
breakdown tables 59-68 shown in the "Economics section."
Table 13 shows the estimated equivalent overall annual
maintenance factors which are applied to the direct
investment for each process, corresponding to an annual
operating schedule of 7,000 kWh/kW capacity. Maintenance
factors for other operating schedules are scaled exponen-
tially. In addition to utilizing the base factors indicated in
the table, the sensitivity of operating costs to variations in
maintenance requirements for the magnesia slurry scrub-
bing process is evaluated and presented in figure 58 of the
"Results" section.
Estimation of operating cost is complicated by the fact,
as discussed in the ammonia scrubbing conceptual design
study (56), that projects for sulfur and nitrogen oxides
control in power plants may be financed on different
bases-the regulated power industry basis, the nonregulated
chemical industry practice, or a combination of the two.
This has a major effect on capital charge items such as
depreciation and taxes. This study is based upon regulated
27
-------
company economics and :i breakdown of the capital charges
is given in table 14. The depreciation rate is straight line
based on (he remaining life of the power plant after the
pollution control process is installed.
In estimating the regulated capital charges associated
with stack gas scrubbing, the conventional method of
considering the overall life of the power plant is used. The
FPC recognizes' the conclusion of the National Power
Survey that a 30-year service life is reasonable for steam-
electric plants (14). Because some items have life spans less
than 30 years, however, the FPC has designated interim
replacements as an allowance factor to be used in esti-
mating annual operating costs to provide for the replace-
ment of such items. Use of this allowance following FPC
recommended practice provides for financing the cost of
replacing such short-lived units. An average allowance of
about 0.35% of the total investment is normally provided.
However, to provide for the unknown life span of S02
control facilities, n somewhat larger allowance factor is used
for new units. An insurance allowance is also included in
the capital charges based on FPC practice.
Debt-equity ratio is another component of capital
charges for which variations of ratios may be expected.
However, FPC data (15, 16) indicate that the long-term
debt for privately owned electric utilities varied only
slightly from 51.5% to 54.8% of total capitalization during
the period 1965-1973. For this study, a 50/50 debt-equity
ratio is assumed, corresponding to an overall cost of money
of 10%.
Since most regulatory (19, 54) commissions base the
annual permissible return on investment on the remaining
depreciation base (that portion of the original investment
yet to be recovered or "written off), a portion of the
annual capital charge included in. the lifetime operating
Table 11. Projected 1975 Unit Costs for Raw Materials, Labor, and Utilities
Raw materials
$/unit
Limestone
Lime
Lime process
MgO process
Sodium process
Magnesium oxide
Coke
Vanadium pentoxide catalyst
MgO process
Cat-Ox process
Sodium carbonate
Antioxidant (sodium process-scrubbing)
Catalyst (sodium process - S02 reduction)
Labor
Operating labor
Analyses
Utilities (59)
200 MW
500 MW
Fuel oil, No. 2
Fuel oil, No. 6
Natural gas
Steam (500 psig)
Coal-fired units
Oil-fired units
Process water0
Electricity
Coal-fired untis
Oil-fired units
Heat credit
Coal-fired units
Oil-fired units
030/gal
0.23/gal
1.00/mcf
0.80/M Ib
1.50/Mlb
0.011/kWh
0.019/kWh
0.60/MM Bin
1.60/MMBtu
0.70/M Ib
1.40/Mlb
0.02-0.08/M galc
8Varies according to annual quantity requirements.
"Unit costs supplied by Allied .Chemical; catalyst not identified.
cVaries according to water volume requirements which are process dependent.
4.00/ton
20.50-26.00/tona
26.00/ton
26.00/ton
155.00/ton
15.00/ton
1.65/liter
1.65/liter
52.00/ton
2.00/lb
b
8.00/man-hr
12.00/hr
l.OOOMW
0.30/gal
0.23/gal
1.00/mcf
0.30/gal
0.23/gal
1.00/mcf
0.60/M Ib
1.30/Mlb
0.010/kWh
0.018/kWh
0.60/MM Btu
1.60/MMBtu
0.009/kWh
0.017/kWh
. . 0.60/MM Btu
1.60/MMBtu
28
-------
Table 12. Product Credit
Process
Magnesia
Sodium
Sodium
Cat-Ox
Products
98%H2S04
Sulfur
Sodium sulfate
80% H2S04
Assumed
Base
$8/shorl ton
100%H2S04
$25/short ton
$20/short ton
$6/short ton
100%H2S04
revenue
Variations
$0432
$I5-$40
-
$0-$30
Table 14. Annual Capital Charges
for Power Industry Financing
Table 13. Estimated Overall Annual Maintenance Costs
Percentage of direct
Process
Limestone
Lime
Magnesia
Sodium
Cat-Ox
200 MW
9
9
8
7
5
500 MW
8
8
1
6
4
investment
1 ,000 MW
7
7
6
5
3
costs declines uniformly over the life of the power
plant.
Because of the wide variations that exist in the
breakdov/n of capital charges, the sensitivity of operating
costs to variations in capital charges and cost of money is
presented in figures 54-56 and 89-93 of the "Results"
section.
Plant, administrative, and marketing overheads are costs
which vary from company to company. With consideration
of the various methods used in industry and illustrated in a
variety of cost estimating sources (4, 34), the following
method of estimating overheads is used.
Plant overheads are estimated as 20% of the subtotal
conversion costs, which includes the projected costs for
labor, utilities, maintenance, and analyses. Administrative
overheads for the throwaway processes are estimated as
!0% of operating labor and supervision. For the magnesia
process, administrative and marketing overhead is estimated
as 11% of the subtotal conversion costs. Sodium and
Cat-Ox administrative and marketing.overheads are esti-
mated on the basis of llie relative difficulty in marketing
the various products in comparison to magnesia product
marketing costs.
Working Capital
Working capital consists of the totiii amount of money
invested In raw materials and supplies carried in stock,
As percentage of
original investment
Years remaining life
30 25 20
Depreciation-straight line (based
on years remaining life of power unit) 3.33 4.00 5.00
Interim replacements (equipment
having less than 30-yr life) 0.67 0.40 -
Insurance 0.50 0.50 0.50
Total rate applied to
original investment
Cost of capital (capital structure
assumed to be 50% debt and 50% equity)
Bonds at 8% interest
Equity at 12% return to stockholder
Taxes
Federal (50% of gross return or
same as return on equity)
State (national average for states
in relation to Federal rates)
Total rate applied to
depreciation base
4.50 4.90 5.50
As percentage
of outstanding
depreciation base8
4.00
6.00
6.00
4.80
20.80b
aOriginal investment yet to be recovered or "written off."
bApplied on an average basis, the total annual percentage of original
fixed investment would be 4.5% + Vi (20.80%) = 14.90%.
finished products in stock and semifinished products in
the process of being manufactured, accounts receivable,
cash kept on hand for monthly payment of operating
expenses, such as salaries, wages, and raw material pur-
chases, accounts payable, and taxes payable. Several
methods are illustrated throughout the literature for
estimating the working capital requirements of a given
process (4, 34). For this study, working capital Is
defined as the equivalent cost of 3 weeks of raw
materials, 7 weeks of direct operating costs, and 7
weeks of overheads. Working capital requirements are
calculated for each case evaluated and presented at the
bottom of the annual operating cost estimates shown
in Appendix B.
29
-------
Systems
Estimated
Process descriptions, flowsheets, layout drawings, and
equipment requirements for the five processes are pre-
sented in this section. Each process is subdivided into
several major functional areas to facilitate comparisons
of investment and operating costs for similar processing
steps. Costs for land, piping, electrical, instrumentation,
ductwork, structures, foundations, and painting are
included in each area along with the process equipment.
Discussion of specific items which may be required for
process design, but are assumed to be supplied by the
power facility or whose costs are prorated between the
power unit and the control facility, are provided where
applicable.
Following current practices, the material of construction
for ductwork between the powerhouse and the scrubbers is
insulated Cor-Ten. Ductwork between the scrubbers and the
stack gas reheater system is epoxy-lined mild steel for the
limestone, lime, magnesia, and sodium processes and
insulated Cor-Ten for the Cat-Ox process. The I.D. fans and
the ductwork between the reheater and the stack are
Cor-Ten since these areas require some protection from
reheat failure. Unless otherwise noted, materials of
construction for process equipment are. assumed to be
carbon steel.
Process descriptions and drawings are presented for each
of the five processes followed by an area-by-area analysis of
equipment requirements and methods of costing based
upon the "Power Plant, Process Design, and Economic
Premises" section.
LIMESTONE SLURRY PROCESS
Removal of SO2 from power plant stack gas using the
limestone slurry process is accomplished by contacting the
gas with a recirculating slurry containing wet-ground
limestone and reaction products in a multi-bed mobile bed
absorber. Incoming 0 x 1-1/2 inch limestone is received by
either truck or rail and conveyed to a 30-day storage pile
located about 150 feet from the grinding facilities. The
limestone is reduced to about 0 x 3/4 inch using gyratory
crushers, wet-ground to 70% -200 mesh in two parallel ball
mills; and stored as a 60% solids slurry in a feed tank with 8
hours storage capacity.
The limestone makeup slurry is fed to the absorber hold
tanks where it is combined with effluent slurry from the
scrubbers and recycle pond water to maintain a 10% solids
slurry. The S02 is reacted with the slurry by circulation
through the mobile bed absorbers which are equipped with
chevron-type entrainment separators designed for upstream
wash with fresh makeup water. A bleed stream of partially
spent slurry overflows to the particulate scrubber hold
tanks and is circulated through the particulate venturi
scrubber for removal of fly ash. The overflows from these
tanks are fed to one pond feed tank with a surge capacity
equal to the liquor holdup in the scrubbers. Existing
coal-fired and both new and existing oil-fired units do not
require particulate removal, therefore, the S02 absorber
hold tank overflow is fed directly to the pond feed tank.
For new coal-fired units, the spent slurry, consisting of
calcium compounds and fly ash, is pumped to the on-site
pond where it settles to about a 40% solids slurry. Pond
water is recycled to the wet bal! mills and to the SO?
absorber hold tanks to maintain a closed-loop process. A
special case is evaluated in which the spent slurry is pumped
to a slurry dewatering system to produce a disposal cake
containing 50% solids; the cake is trucked to and disposed
of off-site. The slurry dewatering system includes thickener
tanks and rotary vacuum filters for processing the under-
flows from the thickener. Overflows from the thickeners
are recycled to the wet ball mills and to the SOj absorber
hold tanks. The total land requirement for the base case
limestone slurry process is broken down as follows:
Process function
Land required,
acre
Fly ash and S02 removal
Waste disposal
Fly ash
Calcium solids
8.0
75.0
131.0
Excluding the disposal area required for fly ash as
discussed in the premises, the total amount of land included
in the limestone slurry process cost estimate is 139.0 acres.
The flow diagram, material balance, control diagram, plot
plan, and process layout and elevation drawings for the base
case are shown in figures 1-5. The major areas are described
in the following section.
Limestone Receiving and Storage
This area includes facilities for receiving raw limestone
(-1-1/2 in.) by truck or rail, a storage stockpile, and live
30
-------
KtIL
OK
r
. , mrs
Honm. motm» ccunnms newo* tnu\
M '' •w»D»r~
t rtriuLL Pi I
X-L HILLS l_l Q
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UfSOWTOi TO A* TO AW TO
~ • ' *•*" ..1 !S!L-
SPtonc Muwnr i
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•ATI. LBS./ Hft
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4^00 | 4.SX1
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SPEClTC OTAVlTT
21
urn
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t II
viscosiT?. en
UtaOBSOLVfA SOLOS. *
pH
i
IT
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tz
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179
NOTES:
JS&.
_«™_
*l
AMOME?
,.,
KE NOTE 9
IX
TO
IS9
LWKiTOK
TOflCMW
14
SLUKT TO
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— T7S —
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1. CALCULATIONS SASC0 0*t
ItO* STOIC NIOMCTR 1C LlMSTOBC: SO« C^O, |D*T). i* 4,0
91 t SWLPU* m COAL (D*T)
12 « ASM COAL (AS rWCDt
s»\ OP sw.ru* • COAL CVOLVCS AS sot
T9t OP ASH Ml COAL EVOLVtS AS PLT ASM
tSSt REMOVAL OP PAWTICULATCS TO SCMMC*
*0\ SO, •CMOHAL
POHO CVAPOKATiOM AMD SCCPAM COUALS ftMNP*LL
t PAATKULATCS SHOULD H UMCD TO CAS TO SCT TOTAL STRCAM RATE
> ITWAM ttUMCft* S.S. IO-« • tS-21 AM ORE tf POU* SMMJMI f
4 STRCAH MMNKKS IS.t4 • H AM OM OP TWO SIMLA* STHCMU
SLU**TTO
24 O
HCCTCLE
SLUNMT TO
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ILUMTY TO
23 H
STWtOL ID TAM.K
• THOUSAHO
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SA.EH.T. •
WCBFLOWTO
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343
109
S
Ul
Figure 1. Limestone slurry process. Flow
diagram and material balance-base case.
-------
PULVERIZLO
COAL
HOPPERS, FEEDERS a CONVEYORS
MOTE; STANDARD ISA IDENTIFICATION LETTERS USED ON INSTRUMENTATION.
SOOT BLOWER CONTROLS NOT SHOWN.
•. ONE ANALYZER WITH 4 ALTERNATE FEEDS.
« ONE INTEGRATOR FOR 4 FLOWS
Figure 2. Limestone slurry process. Control diagram—base case.
-------
ELEVATION
Figure 3. Limestone slurry process. Venturi and
mobile bed scrubber system-plan and elevation-base case.
33
-------
~T
r
UHfSTOHE PILE
a
o
>
o
o
X
Figure 4. Limestone slurry process. Materials handling and
feed preparation system layout—plan—base case.
-------
Ul ,
* ;
a •
5
(
R 0
C O A i.
5 T O X A 6
i o
SOOf
ROOM
BLDG
a on. ex.
ROOW
—i
future
;*
future
O A O
a
0 A D
O A D
Figure 5. Limestone slurry process. Overall plot plan—base case.
-------
in-process limestone storage facilities upstream of the feed
preparation aiea. The following equipment is provided:
1. One 94-ft3-capacity limestone receiving hopper
equipped with a 2.5-hp vibrator.
2. One 2.5-hp limestone vibratory feeder.
3. One 2.5-hp belt conveyor.
4. One 20-hp limestone stocking conveyor.
5. Three 65-ft3 feed hoppers located beneath the pile,
each equipped with 1-hp vibrating feeders.
6. One 3.0-hp conveyor under pile.
7. Two 5-gpm, 0.25-hp, rubber-lined tunnel sump
pumps.
8. One 15-hp elevator to live storage area.
9. One 5,000-ft3 twin-compartment limestone feed bin
equipped with two 1-hp vibrators.
10. One railroad trackside vibrating car shaker.
11. One 2,000-cfm and one 6,000-cfm dust collecting
system including inertial separators, cyclones,
hoppers, fans, and drives.
12. One fabric dust collector designed to filter 14,000
cfm of gas (one-half the cost is included in this area;
the other half is included in the feed preparation
area).
Feed Preparation
This area includes the equipment for converting the raw
limestone to a 70% -200 mesh, 60% solids slurry for feed to
the scrubbers. The following equipment is provided:
1. Two parallel 1.5-hp limestone weigh feeders fed by
2 vibrating bin discharge feeders.
2. Two parallel 50% capacity, 25-hp gyratory crushers
for reducing the stone size from -1-1/2 in. to -3/4 in.
3. Two parallel 1-hp elevators which discharge into the
wet ball mills.
4. Two parallel 50% capacity, 450-hp wet ball mills for
grinding the stone from -3/4 in. to 70% -200 mesh.
5. One 1,920-gal rubber-lined mills product tank
equipped with baffles and a 1-hp rubber-coated
agitator.
6. Two parallel (( operating and 1 spare), 96-gpm, 3-hp
rubber-lined centrifugal pumps.
7. One 46,080-gal rubber-lined slurry feed tank
(providing for 8 hr of slurry storage) equipped with
baffles and a 10-hp rubber-coated agitator.
8. Two parallel (1 operating and 1 spare), 96-gpm,
3-hp rubber-lined centrifugal pumps.
9. One 86-ft-longx 73-ft-wide x 30-ft high building for
housing the grinding facilities.
10. One '5-ton electric hoist.
11. One 8,000-cfm dust collecting system including an
inertia! separator, cyclone, 2 dust hoppers, fan, and •
drive.
S2. One fabric dust collector designed to filter 14,000
cfm of gas (one-half of cost is included in this area;
the other half is included in the materials handling
area).
Participate Scrubbers and Inlet Ducts
The following flue gas distribution and particulate
scrubbing facilities for new coal-fired power units are
included in this area:
1. Four flue gas ducts between the air heater discharge
duct outside the powerhouse and the inlet flue gas
plenum.
2. One inlet flue gas plenum interconnecting each of the
4 flue gas ducts.
3. Four flue gas ducts between the inlet plenum and the
particulate scrubber, including 1 damper per duct.
4. Four 36-ft-long x 5-ft-wide x 20-ft-high rubber-lined
venturi scrubbers equipped with variable throats.
5. Four 28-ft-longx 41-ft-wide x 13-ft-high rubber-lined
sumps for distribution of flue gas from the venturi
scrubbers to the mobile bed S02 absorbers (one-half
of the cost is included .in this area; the other half is
included in the S02 scrubbing area).
6. Twenty soot blowers (5 per scrubber).
7. Four 25,700-gal, 13-ft-diameter x 26-ft-high open-
top, rubber-lined carbon steel effluent hold tanks
with four 5-hp rubber-coated agitators.
8. Six 4,900-gpm, 300-hp rubber-lined centrifugal slurry
recirculation pumps (4 operating and 2 spares).
Existing coal-fired units are assumed to be equipped
with 98.7% efficient electrostatic precipitators and do not
require additional particulate scrubbing facilities. Fly ash
emission from new and existing oil-fired power units does
not exceed the EPA particulate emission standard;
therefore, these units also do not require particulate
removal facilities.
S02 Scrubbers and Ducts
The following equipment is provided:
1. Four 28-ft-long x 41-ft-wide x 13-ft-high rubber-lined
sumps for distribution of flue gas from the venturi
scrubber to the mobile bed.SOj absorber (one-half of
cost is included in this area; the other half is included
in the particulate scrubbing area).
2. Four 41-ft-long x 13-ft-wide, x 41-ft-high two-bed,
rubber-lined carbon steel mobile bed absorbers with
stainless steel grids, high density polyethylene
spheres, stainless steel chevron-type entrainment
separators designed for upstream wash with fresh
makeup water, and provisions for adding a future
entrainment wash tray.
3. Forty soot blowers (10 per scrubber).
. 4. Four exit flue gas ducts between S02 scrubber outlet
36
-------
and I.D. Ian inlet. For existing units, flue gas ducts
and inlet plenum between the outlet of the supple-
mental l-\l). fan and the inlet to the stack gas plenum
are included.
5. Four 240,000-gal, 40-ft-diameter x 26-ft-high open-
top, rubber-lined carbon steel effluent hold tanks
with four 50-hp rubber-coated agitators.
6. Ten 11,500-gpm, 500-hp, rubber-lined, centrifugal
slurry recirculation pumps (8 operating and 2 spares).
7. Two 1,240-gpm, 100-hp vertical, multiple-stage
turbine makeup water pumps (1 operating and 1
spare).
Stack Gas Reheat
This area includes facilities for reheating the gas to
obtain an outlet stack gas temperature of 175°F.
New power units are designed with I.D. fans downstream
of the scrubbers which discharge into the stack gas plenum;
some of the reheat is obtained as the gas is compressed in
passing through the fans. However, approximately 4°F of
reheat are lost as the gas passes through the stack. The
additional reheat required f.o obtain 175°F at the stack
outlet is supplied by the stack gas reheat facilities. Fans for
existing power units are located upstream of the scrubbers;
therefore, all of the required reheat for existing systems
must be obtained from the stack gas reheat facilities. Since
the saturation temperature for coal- and oil-fired systems is
different, and the pressure and temperature increase in
passing through the fan varies with coal- and oil-fired
systems, different amounts of reheat are required for each
design. Table 15 shows the temperature increase in degrees
Fahrenheit required to obtain an exit temperature of
17S°F at the stack outlet.
A new 500-MW coal-fired power unit is designed with
four 2,028-ft2 indirect steam (500 psig) tube-type heat
exchangers (one per duct) constructed within the exit flue
gas ducts upstream of the fan. One-half of the tubes
(scrubber side) are Incond 625 and the oilier half (fan side)
are Cor-Tcn. Twenty soot blowers are provided (5 per
reheater) for periodic cleaning of the tubes. Existing
coal-fired units and new and existing oil-fired units are
designed with or.e direct oil-fired reheater per duct which
discharges hot combustion gases directly into the duct.
Fans
A new balanced-draft coal-tired power unit without
pollution control facilities normally requires one I.D. fan
per duct capable of overcoming a pressure drop of 15
inches downstream of the boiler. TI.e increased pressure
drop resulting i'rom the addition of stack gas scrubbing
facilities to the power unit varies with power unit type
(coal- or oil-fired), plant status (new or existing), and
process design. This additional energy is supplied by the
installation of either greater capacity fans for new units or
supplemental fans for existing units. For new power units,
the investment and operating cost attributed to the
scrubbing facilities are estimated as the difference between
the investment or operating costs of the higher energy fins
in comparison with a 15-inch capacity fan. For existing
power units, the total investment and operating cost of the
additional fans are included. Table 16 identifies the
pressure drop distribution provided for each of the various
system designs.
The cost for a plenum to the stack is not included in the
investment estimate; it has been assumed that this equip-
ment is required by the power unit. The following are
included in the base case investment and operating cost
estimates:
1. Incremental costs for four 3,250-hp (41 in. A p)
induced draft fans prorated for 26 inches of pressure
drop attributed to particulate and S02 removal.
2. Four exit flue gas ducts between the I.D. fans and the
stack gas plenum.
The new fans provided for existing power units are
located adjacent to and in series with the existing I.D. fans.
The costs for this area include the ductwork between the
tie-in to the existing duct and the inlet of the fan.
Table 15. F!ue Gas Reheat Requirements-
Limestone Slurry Process
Power unii
Type Status
Coal fired New
Coal fired Existing
Oil fired New
Oil fired Existing
Required temperature
increase, °F
38
53
34
46
Table 16. Assumed Pressure Drop Distribution for
Specification of Fans-Limestone Slurry Process
Pressure drop distribution,
Power unit inches H^O attributed to
SOj removal Power Gas
Fuel Status efficiency. % production cleaning Total
Coal
Coal
Oil
Oil
Coal
Coal
New
Existing
New
Existing
New
Existing
90
90
90
90
80
90
15.0
_a
15.0
_a
15.0
_a
26 .Ob
21.0
19.0
21.0
24 .Ob
28. Ob
41.0
21.0
34.0
21.0
39.0
28.0
(requiring particulate
scrubber)
aExisting power units already have fans which overcome the
pressure drpp attributed to power production.
^Includes pressure drop attributed to both particulate and SOj
removal.
37
-------
Calcium Solids Disposal
For new coal-fired power units utilizing on-site solids
disposal, the solids disposal area is designed for both fly ash
and calcium solids disposal in a single pond. For consistent
comparison of processes, however, the costs associated with
fly ash disposal are excluded from the estimate. The costs
for the solids disposal pumps, disposal line to the pond,
pond, pond liner, and pond water return pumps and piping
are prorated using a 0.637 factor which is the fraction of
calcium solids in the calcium - fly ash mixture to be
disposed; only the portion of costs attributed to calcium
solids disposal is included in the estimates. Existing
eoal-fired power units and both new and existing oil-fired
units require a single pond for disposal of calcium solids
only. The following items are included in the base case
estimate:
1. One 63,000-gal, 21-ft-diameter x 26-ft-high rubber-
lined open-top tank (sized with a liquid holdup
capacity equivalent to the total liquid holdup in the
particulate and S02 scrubbers) with a 7.5-hp rubber-
coated agitator.
2. Prorated cost for four 1,130-gpm, 50-hp rubber-lined
pond feed pumps (2 in series operating and 2 in series
spare).
3. Prorated cost for 1 rubber-lined solids disposal line to
pond (~1 mile).
4. Prorated cost for one 40-ft-deep, 206-acre clay-lined
disposal pond with concrete sump; lifetime pond
capacity-127,500 operating hr; 131.0 acres are
attributed to calcium solids disposal. Lifetime pond
capacities for existing 200-MW units are equivalent to
57,500 operating hr; the 500- and 1 yOOO-MW existing
units have disposal ponds with capacities equivalent
io 92,500 operating hr.
5. Prorated cost for two 1,000-gpm, 75-hp carbon steel
recycle pond water pumps with stainless steel
impellers.
6. Prorated cost for i carbon steel pond water return
line.
For off-site solids disposal, the following items are
provided:
1. One 63,000-gul 21-ft-diameter x 26-ft-high rubber-
lined open-top tank with a 7.5-hp rubber-coated
agitator.
2. Prorated cost for two 1,000-gpm, 25-hp rubber-
lined carbon steel thickener feed pumps (1
operating and 1 spare).
3. Prorated cost for two 140-ft-diameter x 16-ft
8-in.-high rubber-lined thickener tanks with
thickener rakes, supports, and drive.
4. Prorated cost for one 1,920-gal thickener overflow
receiving tank.
5. Prorated cost for two 566-gpm, 10-hp carbon steel
overflow return pumps (1 operating and 1 spare).
6. Prorated cost for three 210-gpm, 3-hp rubber-lined
thickener underflow pumps (2 operating and 1
spare).
7. Prorated cost for 2 rotary vacuum filters 12-ft-
diameter x 18-ft-long, equipped with 150-hp
vacuum pumps, filtrate receiver, and 10-hp filtrate
recycle pumps.
8. Prorated cost for one 1-hp horizontal belt conveyor.
9. Prorated cost for one 10-hp inclined belt conveyor.
10. Prorated cost for one 21,200-ft3 cake loading silo
equipped with bin vibrators.
Utilities
The availability of certain utilities (steam, water, and
electricity) to the pollution abatement facilities is depen-
dent upon the power plant status (new vs. existing). For
utilities which may be obtained from the power plant,
investment costs for distribution to the processing area are
included and the utility price consists of all actual
production costs including capital charges. For utilities
which cannot be obtained- from the power plant, the total
investment and operating cost for generation and^ distri-
bution is included. The investment estimate includes cost
for the following:
1. One instrument air supply system including air
compressor, air dryer, and air header to the process
control equipment.
2. One 500-psig steam supply system from the boiler to
the indirect steam reheat facilities, including steam
header, and condensate return piping to the boiler
feed water system. Existing coal-fired and both new
and existing oil-fired units are designed with a direct
fuel oil-fired reheat and fuel oil supply system,
including 1 fuel oil unloading station, 1 storage tank,
2 fuel oil feed pumps, and insulated piping above
ground between the feed pumps and the oil-fired
reheat system.
3. Allocation for fire and service water supply to the
processing area including area piping.
4. Process water supply header from condenser
discharge sump to the scrubbing facilities.
5. Electrical facilities including 200 ft of feeder cable
and conduit from the power plant to the processing
area. The investment for existing units includes costs
for a new transformer and approximately 900 ft of
feeder cable and conduit from the switchyard to the
processing area.
6. Sanitary and storm sewers including approximately
250 ft of 24-in. vitrified clay pipe.
38
-------
Service Facilities
Costs for the following items are included in this area:
1. Vehicles—1 gasoline-powered, 2-yd3 -capacity pay-
loader, and allocation to power unit for use of plant
vehicles.
2. Buildings and equipment-one 5,000-ft2 maintenance
and instrument shop; one 2,200-ft2 building,
including process and motor control facilities,
laboratory, lockers, offices, and restrooms; allocation
to power unit for one 2,000-ft2 stores area.
3. Railroads-costs for % mile of track, 3 switches, and
2 car pullers.
4. Parking lot, walkways, and approximately 1 mile of
paved roads.
5. Landscaping, fencing, and security.
Units with direct oil-fired reheat systems include an
additional 800 feet of railroad and 2 switches in this area
for fuel oil receiving and handling.
Construction Facilities
Based on TV A experience, the costs for temporary
facilities required during construction are projected as 5%
of the subtotal area investments to include projected costs
for the various craft sheds, temporary offices, and restroom
facilities.
coal-fired and both new and existing oil-fired units which
do not require fly ash removal facilities. In every case,
reacted slurry from the second-stage venturi scrubbing loop
is fed to the first-stage venturi scrubbing loop.
The spent slurry consisting of. calcium compounds and
fly ash for new coal-fired units is pumped to the pond
where it settles to about a 40% solids slurry. Pond water is
recycled to the lime slakers and venturi scrubbing loops. A
special case in which the calcium compounds and fly ash
from new coal-fired units are trucked to and disposed of
off-site is evaluated similar to the limestone slurry process.
The total land requirement for the base case lime slurry
process is broken down as follows:
Process function
Land required,
acre
Fly ash and S02 removal
Waste disposal
Fly ash
Calcium solids
5.5
75.0
113.0
Excluding the disposal area required for fly ash as
discussed in the premises, the total amount of land included
in the lime slurry process cost estimate is 118.5 acres. The
flow diagram, material balance, control diagram, plot plan,
process layouts, and elevation drawing are shown in figures
6-10 for the base case, followed by the area-by-area process
equipment descriptions.
LIME SLURRY PROCESS
The lime slurry process removes S02 from power plant
stack gas by contacting the gas with a recirculaiing slurry
stream containing slaked lime and reaction products in two
venturi absorbers in series for each parallel gas train. The
incoming pebble lime, from an "across the fence" limestone
calcination plant, is received in bins sized for 5 days'
storage and conveyed to an 8-hour process bin which serves
as supply to the slakers. The lime is slaked in two parallel
slakers at a slurry concentration of 25% solids and
subsequently diluted with pond water to 15% solids. A
slurry feed tank with a residence time of 8 hours is
provided for in-process storage.
Approximately 78% of the lime slurry is fed to the
first-stage venturi scrubbers where the fly ash and 70% of
the SOa is removed. The remaining portion of the slaked
lime slurry is fed along with recycle pond water to the
recirculation loops for the second-stage S02 absorbers.
These absorbers are equipped with chevron-type entrain-
ment separators designed for upstream wash with fresh
makeup water. Approximately 70% of the remaining SO2
in the gas is removed in the second-stage absorbers. To
achieve the required SOj removal efficiency, two venturi
absorber stages are also utilized to remove S02 for existing
Lime Receiving and Storage
This area includes facilities for receiving pebble lime
from an "across the fence" limestone calcination plant,
storage in bins for 5 days, and live in-process storage for
supply to the slakers. The following equipment is provided:
1. One 15-hp enclosed belt conveyor.
2. One 7.5-hp enclosed belt conveyor.
3. Four Il,800-ft3l-capacity lime storage bins equipped
with 16 bin vibrators.
4. Four storage bin discharge feeders (rotary air lock
type).
5. One 5-hp conveyor-elevator between the storage bins
.and the process bin.
6. One 4,320-ft3-capacity process bin equipped with 8
bin vibrators.
7. Two process bin discharge feeders (Votary air lock
type).
Feed Preparation
The pebble lime is slaked as a 25% solids slurry in two
parallel slaking systems and diluted with pond water to a
15% solids slurry. In-process storage is provided before
feeding the slurry to the absorption system. The following
equipment is provided:
39
-------
STREAM MO
OCSCWTTQH
$£*' LK /m
tfu
rEMPOATWeE. -F
SPECIFIC BJUVfTY
VISCOSITY, CPS
JMOtSMLVCO SOUM,*
«
RATE, LBS./W1
scfy
•wmcuurres. LM. /w
TZMPEXJrruftC, •*
SPCoric otAvfTY
vlSCOSITYf CPS
UMbfSSOLVCD SO.CS, %
»M
,
COAL
TO
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2
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AIM TO
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(.10
r — TI — i — ™ — i
93 4 U
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nr*»Qt*cm
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109
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3
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AM TO
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535
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TO
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7. 498M
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TO
AA HEATER
— »4^i —
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ft*S TO
ZOOM
rejo.
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310 125
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USED SLURRY
.FLY ASM
134
40
SEE NOTES
«
FAN
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POND
i»»y
tfXIWTCS
10
ATMOSPHEK
1. I3TM
175
POMP mtz*
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*ou
— 1!?™
it
STEAM
TO «M
REHEATEft
470
12
ttAX£-UP
WATER TO
a**o«»
r»7
XE NOTES
13
POMJMATEJf
TO
C43
14
roScRCW
CONVEYOR
I CALCULATION* BASED ON:
HO* *TOtCHK}yCTRlC LIME: *3\ C*O
S.SX SULFUR IN COAL (DRY)
12% A*H COAL US FIREC)
9t\ OF SULFUR IN COAL CVGLVE4 AS SOt
TS % Of ASH * COAL EVOLVES AS fLY ASH
PONO EVAPORATION EQUAL TO RAINFALL
. ! ,.
sivr
TO
DISPOSAL
3 KATES FO* L
OF •OttO L*t
PONO PO* ST
17
SLUM* TO
SYSTEM
3TO
125
1.0*
15
I*
LMG
SLumrrm
SOfAMOMCX
205
SETTLES SOLIDS MTCK5T
AffTUP
1*
SLjUMTY TO
BOeAaRMBt
iioy
2O
13.1 «
HE ABOUT OME- SIXTH
TTWL HjO IS PUT «TO
a rwousAMO
•ecu
1 PAHTICULATCS SHOULD BE ADDED TO e*S TO
•ET TOTAL STREAM RATE
3. STRCAM VMtKtn t-t. IH3 • «-Z*AnE CMC CT
FOUR SHI1LA* STREAMS
4. STREAM MUMOCRS M-}« a SO ARC OIC OF
TWO ItHLAff STItEAHS
Figure6. Lime slurry process. Flow diagram and material balance-base case.
-------
NOTE; STANDARD I.S.A. IDENTIFICATION LETTERS USED ON INSTRUMENTATIOtt.
SOOT BLOWER CONTROLS NOT SHOWN.
a. ONE ANALYZER WITH 4 ALTERNATE FEEDS
b ONE INTEGRATOR FOR 8 PLOWS.
Figure 7. Lirne slurry process. Control diagram—base case.
-------
nut «*s
oucr.
FLUttUO.
DUCT-,
*
\ /
V
A
\ f
M
ELEVATION
Figures. Lime-slurry process. Two-stage venturi
scrubber system-plan and elevation-base case.
42
-------
*e~
r-C
BIN
STORAGE BIN
SLAKBK.
CONVEYOR.
v
ENCLOSED
SCEEM CCNV&ORS
re0C£SS 4 MOTOR. CONJISOL BLDG,
KOOM
190' (APPEOX.)
>\ I
\i
/\
l V
Figure 9. Lime slurry process. Materials handling
and feed preparation system layout—plan—base case.
*
-------
i X I
I £ I
HH
o
J
rf r-
N
PI
I I
c o
s r o /z
O A £>
at. os.
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ruKo/ff
tf £
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«l 0 * 0
t r
Rgure 10. Lime slurry process. Overall plot plan-base case.
-------
I. Two I-lip screw conveyors.
2. Two parallel 11,600 Ib/hr slakers, 20-ft-long x 5.5-ft-
wide x 9-ft-high.
3. Three parallel (2 operating and 1 spare), 185-gpm,
5-hp rubber-lined centrifugal pumps.
4. One 177,600-gal rubber-lined slurry feed tank (pro-
viding for 8 hr of slurry storage) equipped with
baffles and a 15-hp rubber-coated agitator.
5. Two parallel (1 operating and 1 spare) 370-gpm, 5-hp
rubber-lined centrifugal pumps.
Particulate - S02
Scrubbers and Inlet Ducts
The lime slurry process requires a two-stage venturi
absorption system with approximately 70% of the SOa
removed in the first-stage venturi and approximately 70%
of the remaining S02 removed in the second stage. The
following facilities for distribution of flue gas and removal
of particulates and S02 are included in this area:
1. Four flue gas ducts between the air heater discharge
duct outside the powerhouse and the inlet flue gas
plenum. For existing units, flue gas ducts between
the supplemental F.D. fan and the inlet flue gas
plenum are included.
2. One inlet flue gas plenum interconnecting each of the
four flue gas ducts.
3. Four flue gas ducts between the inlet plenum and
the particulate scrubber, including one damper per
duct.
4. Four 28-ft-diameter x 54.5-ft-high rubber-lined
venturi scrubbers equipped with variable throats and
stainless steel chevron-type entrainment separators
designed for upstream wash with fresh makeup water.
5. Four flue gas ducts between the particulate - S02
scrubbers and the S02 absorbers (one-half of the cost
is included in this area; the other half is included in
the S02 scrubbing area).
6. Ten 6,500-gpm, 350-hp rubber-lined centrifugal
slurry recirculation pumps (8 operating and 2 spare).
7. Two 660-gpm, 50-lip vertical, multiple-stage turbine
makeup water pumps (I operating and 1 spare;
one-half of the cost is included in this area; the other
half is included in the S02 scrubbing area).
8. Twenty soot blowers (5 per scrubber).
As previously stated, existing coal-fired units are
assumed to be equipped with 98.7% efficient electrostatic
precipitators. Although existing coal-fired units and both
new and existing oil-fired units do not require the first-stage
scrubber to remove fly ash, it is required for removal of
S02.
Table 17. Flue Gas Reheat Requirements-
Lime Slurry Process
Power unit
Type Status
Coal fired New
Coal fired Existing
Oil fired New
Oil fired Existing
Required temperature
increase, °F
38
54
33
47
SO2 Scrubbers and Ducts
Costs for the second stage of the two-stage venturi SOi
removal system are included in this area. This scrubber and
process equipment are similar to the first stage with the
exception that a variable throat is not provided for the
venturi. The following facilities for the distribution of flue
gas are included:
1. Four flue gas ducts between the particulate- SC^
scrubbers and the S02 absorbers (one-half of the cost
is included in this area; the other half is included in
the particulate • S02 scrubbing area).
2. Four exit flue gas ducts between the SOj scrubber
outlet and I.D. fan inlet. For existing units, flue gas
ducts between the SOj scrubber outlet and the inlet
to the stack gas plenum are included.
Stack Gas Reheat
The reheat area includes facilities for reheating the gas to
obtain an outlet stack gas temperature of 175°F. This
system is similar to the reheat system described for the
limestone slurry process. Table 17 shows the temperature
increase in degrees Fahrenheit required to obtain an exit
temperature of 175°F at the stack outlet.
Fans
Fan location, method of costing, and duct configuration
in the lime and limestone slurry processes are similar with
the exception of pressure drop. Table 18 identifies the
pressure drop distribution provided for each of the various
system designs.
Calcium Solids Disposal
For new coal-fired power units utilizing on-site solids
disposal, the solids disposal area is designed for both fly ash
and calcium solids disposal. However, investment costs for
disposal of fly ash are excluded from the estimate similar to
the method of costing described for the limestone slurry
process. A prorate factor of 0.60 corresponds to the
fraction of calcium solids in the calcium - fly ash mixture to
be disposed. Existing coal-fired power units and both new
45
-------
Table 18. Assumed Pressure Drop Distribution for
Specification of Fans—Lime Slurry Process
Pressure drop distribution,
Power
Fuel Status
Coal New
Coal Existing
Oil New
Oil Existing
Coal New
Coal Existing
unit
S02 removal
efficiency, %
90
90
90
90
80
90
inches H20 attributed to
Power
production
15.0
_a
15.0
_a
15.0
_a
S02
removal Total
26.0b 41.0
22.0 22.0
20.0 35.0
22.0 22.0
24.5b 39.5
26.0b 26.0
(requiring particulate
scrubber)
aExisting power units already have fans which overcome the
pressure drop attributed to power production.
"Includes pressure drop attributed to both particulate and SO2
removal.
and existing oil-fired units require a disposal system for
calcium solids only. The following equipment is included in
the base case estimate:
1. Prorated cost for six 167-gpm, 15-hp rubber-lined
centrifugal pond feed pumps (4 operating and 2
spare).
2. Prorated cost for 1 rubber-lined solids disposal line to
pond ("-"I mile).
3. Prorated cost,for one 40.-ft-deep, 188-acre clay4ined
disposal pon'3; lifetime pond capacity—127,500
operating hr; 113.0 acres are attributed to calcium
solids disposal. Lifetime pond capacity for existing
200-MW units are equivalent to 57,500 operating hr;
the 500- and 1,000-MW existing units have disposal
ponds with capacities equivalent to 92,500 operating
hr.
4. Prorated cost for two 670-gpm, 50-hp carbon steel
recycle pond water pumps with stainless steel
impellers.
5. Prorated cost for 1 carbon steel pond water return
line.
For off-site solids disposal, the equipment required is
similar to that described for off-site disposal with the
limestone process, except somewhat smaller in size. Only
the portion attributed to calcium solids disposal is included
in the estimate.
Utilities
The utilities area for the lime and limestone slurry
processes are similar. A list of the equipment included in
the estimate is given in the limestone slurry process utilities
area description.
Service Facilities
This area includes costs for the following items:
1. Vehicles—allocation to power unit for use of plant
vehicles.
2. Buildings and equipment-one 5,000-ft2 maintenance
and instrument shop; one 2,200-ft2 building,
including process and motor control facilities,
laboratory, lockers, offices, and restrooms; allocation
to power unit for one 2,000-ft2 stores area.
3. Railroads—costs for 1,100-ft of track, 1 switch, and 1
car puller.
4. Parking lot, walkways, and approximately 1 mile of
paved roads.
5. Landscaping, fencing, and security.
Units with direct oil-fired reheat systems include an
additional 800 feet of railroad track and two switches in
this area for fuel oil receiving and handling.
Construction Facilities
Construction facilities are projected as 5% of the
subtotal area investments similar to the method used for
the limestone slurry process.
MAGNESIA - SLURRY REGENERATION
In the magnesia slurry - regeneration process, fly ash is
removed by wet scrubbing flue gas in a venturi by contact
with a slurry of fly ash in water; S02 is absorbed in a
separate venturi scrubber utilizing magnesium oxide as the
absorbent. Magnesium sulfite formed in the S02 absorber is
thermally regenerated to MgO, combined with required
makeup MgO and recycled to the S02 absorber. The
amount of makeup MgO is assumed to be approximately
2% per cycle. Fresh makeup MgO is unloaded from covered
hopper cars by a pneumatic conveying system and stored in
a bin before being fed to a slurry tank. Here the makeup
MgO and regenerated MgO are slurried into a bleed stream
of recycle liquor from the S02 absorber and recycled to the
S02 absorption area. The particulate scrubber is designed
to operate closed loop utilizing a recycle pond water-fly
ash slurry as the scrubbing media. Humidification losses are
added as fresh makeup water; this water is added as an
upstream wash for the chevron-type entrainment separator
in each of the S02 absorbers. The fly ash slurry is
neutralized with slaked lime as required and pumped to the
power plant ash disposal pond.
Effluent from the S02 absorber, containing approxi-
mately 10% solids, is passed through wet screens for
thickening to a 40% solids slurry. The MgS03-6HjOin the
slurry is thermally converted to MgS03-3H20 and
pumped to two parallel centrifuges for separation of the
46
-------
solids from the liquor. The centrate and underflow from
(lie wet screens are collected in a liquor lunk, and relumed
to Hie slurry preparation area and the S02 absorber loop in
the proper proportions.
The centrifuge cakes are dried in an oil-fired single-stage
fluid bed dryer and 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 exhausted to the stack gas plenum for
reheat.
The MgS03 solids discharged from the dryer, cyclone,
and bag filter are transferred to an in-process storage bin
and fed to an oil-fired fluid bed calciner which contains a
single calcination bed designed to operate at 1600°F and
two air preheat-product cooling stages. The MgS03 is
calcined in the presence of coke to generate MgO and S02
by direct combustion of fuel oil in the upper stage. The
MgO is drawn from the lower cooling stage at a temperature
of 225°F and fed to the slurry preparation area.
The off-gas from the calciner containing SO 2 is partially
cleaned in a cyclone, cooled to about 700°F in a waste heat
boiler, mixed with the required amount of air for producing
sulfuric acid, 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 recycled to the calciner for
layout convenience and to insure calcination of the fines.
A complete 400 tons/day conventional contact sulfuric
acid plant is provided for production of 98% acid utilizing
the dry inlet gas cleanup system in the calcination area. The
sulfuric acid is stored in tanks with an overall storage
capacity equivalent to 30 days' production. Tail gas from
the acid plant is recycled to the S02 scrubbers.
The total land requirement for the base case process for
new coal-fired units is approximately 7.8 acres excluding
the land requirement for disposing of fly ash. The flow
diagram, material balance, control diagram, plot plan,
layouts, and elevations are shown in figures 11-19 for the
base case, followed by the area-by-area process equipment
descriptions.
Magnesium Oxide and Coke
Receiving and Storage
This area includes facilities for receiving, by truck or rail,
and storing magnesium oxide and coke. The following are
provided:
1. One pneumatic MgO unloading - conveying system
equipped with a 150-hp blower and a 2-hp rotary
lock.
2. One 7,(>3()-!V1 covered-lop MgO storage silo with a
l)-ft conical bottom.
3. One 94-ft3 coke receiving hopper with vibrator
and a 12-ft-long x 10-ft-wide x K-t't-deep unloading
pit.
4. One 25-hp Z-type coke conveyor-elevator with a
capacity of 15 tons/hr.
5. One 4,130-ft3 covered-top coke storage silo with a
7.5-ft conical bottom.
6. One 5-gpm, 0.25-hp sump pump.
Feed Preparation
This area includes equipment for producing a slurry of
MgO for recycle to the scrubbing area. The following are
supplied:
1. One 2-hp recycle MgO weigh feeder equipped with a
1-hp vibrating hopper.
2. One 2-hp makeup MgO weigh feeder equipped with a
1-hp vibrating hopper.
3. One 5-hp Z-type carbon steel conveyor-elevator with
a capacity of 8.5 tons/hr.
4. One 105,700-gal, open-top, rubber-lined carbon steel
MgO slurrying tank equipped with a 20-hp
rubber-coated agitator.
5. Two 263-gpm, 15-hp rubber-lined slurry recycle
pumps (1 operating and 1 spare).
Paniculate Scrubbers and Inlet Ducts
The particulate scrubbing area for new coal-fired power
units includes costs for the following flue gas distribution
and particulate scrubbing facilities:
1. Four flue gas ducts between the air heater discharge
duct outside the powerhouse and the inlet flue gas
plenum.
2. One inlet flue gas plenum interconnecting each of
the four flue gas ducts.
3. Four flue gas ducts between the inlet plenum and
the particulate scrubber, including one damper per
duct.
4. Four 28-ft-diameter x 48.5-ft-high rubber-lined
venturi scrubbers equipped with variable throats and
stainless steel chevron vane entrainment separators.
5. Four epoxy-lined flue gas ducts between the par-
ticulate scrubber outlet and the SOj scrubber inlet
(one-half of cost is included in this area; the other
half is included in the S02 scrubbing area).
6. Twenty soot blowers (5 per scrubber).
7. Two 880-gpm, 50-hp vertical, multistage turbine
makeup water pumps (1 operating and 1 spare).
8. Four 40,600-gal, rubber-lined carbon steel surge
tanks with 20-hp rubber-coated agitators.
9. Six 4,740-gpm, 300-hp rubber-lined centrifugal
recirculation pumps (4 operating and 2 spares).
10. Six 113-gpm, 7.5-hp rubber-lined centrifugal slurry
disposal pumps (4 operating and 2 spares).
i I. Allocation for facilities for neutralizing S02
absorbed in the particulate scrubber.
47
-------
-U
00
Figure 11. Magnesia slurry - regeneration process. Flow diagram—base case.
-------
STREAM NO ; . I 2
DESCRIPTION ! T0 ! AIR TO
: BOILER AIR HEATER
SCFM »4M
6PM
PARTICULATES, LBS /m
TEMPERATURE, *F "0
SPECIFIC CRAVfTY
VISCOSITY. CPS !
UNDISSOLVEO SOLIDS.% i
pM ,
STREAM KO ' 21
22
*£CYCLE ' SLURRY
DESCRIPTION SiuRRY T0 pUR(*E
TREATMENT
RATE. LBS /HR \ 3, 104 M DEPENDS UPON
SCry klAGMESUAND
GPM 5.M2 ' MAKE-UP
PARTICULATES4-BS./HH. [ WATER
TEMPERATURE, 'F.
SPECFtC CRAVfTT
IMPURITIES
FLY ASH
VISCOSITY. CPS . - ID.TRA.W.IENT.
UNOtSSOLVED SOLIDS,% ' ETC.
*H , t
STREAM NO. «l
: CYCLONE
DESCRIPTION ! DOST TO
CONVEYOR
RATE, LBS./HR. S.OCS
SCFM )
6PM . - !
PMTKULATE3, LBS^ML,
TEM**CRATURC. f.
SPECIFIC OUVITY
VISCOSITY. CPS
UNDOSOUED SOUDC.% '
l»« j
STREAM NO. 81
MAKE-UP
DESCRIPTION g&TO
RATE. LBS /MR 300
SCFM
GPM • <
PARTICULATES.LB6./HR.
TEMKRATURE.*F.
SPECIFIC GRAVTTY
VISCOGITY.CPS
UNDISSOLVED SOLID. ^
pH
«2
COLLECTOR
899
62
U-0 SLURRY
TO SO.
ABSORBER
36. 5M
65.7
l.ll
15
3
BOILER
888 M
4
GAS
TO
ECONOMOER
943M
33.7M
535
890
5
GAS
TO
AIR HEATER
943M
33.7M
705
t
23
SLURRY
TO
SCREEN
272M
24
UNDERFLOW
TO LIQUOR
TANK
22IM
499 421
43
DRYER
PRODUCT TO
CONVEYOR
33. 4 M
400
63
• DRYING
TOWER
OUTLET GAS
129 M
25. IM
too
1.05
3.1
44
FEEDER
XSCHARGE TO
CONVEYOR
39.4M
64
"SSrlE?"
GAS
I29M
24.1 M
840
25
OVERFLOW TO
CONVERSION
TANK
51 M
61.3'
1.25
40
45
COKE
TO
CONVEYOR
218
65
"roWS0"
OUTLET GAS
103 M
22M
I6O
6
GAS TO
PARTICULATE
SCRUBBER
260M
8,435
310
•-
26
STEAM TO
CONVERSION
TANK
12.8 M
366
46
FEED
TO
CALCINER
39.9M
6G
MAKE-UP
WATER TO
DRYING 10WEI
1.143
2.29
7
GAS
TO SOt
ABSORBED
6
GAS
TO
RE HEATER
280M : 286M
)
42J 56.8
127
27
SLURRY
TO
CENTRIFUGE
I02M
170
180
L2O
31
47
OIL
TO
CALCINER
3.220
67
RECYCLE AOD
TO
DRYMGTOMEf
I.OQ5M
I.IIO
too
LSI
127
2B
TREATED
LIQUOR TO
LIQUOR TANK
SEE STREAM
22 NOTE
48
AIR
TO
CALCINER
46.3M
10.1 M
KB
RECYCLE AOD
10 STOPPING
TOWER
129 M
146
163
1.77
9
GAS
TO
2B6M
56.6
160
29
LIQUOR
TO LIQUOR
TANK
686M
130
LOG
4,6
49
CYCLONE
7L6M
13 IM
1.980
1.600
6*
RECYCLE AOD
TOABBURPnUN
TOWER
993 M
I.IIO
1*0
179
10
GAS
TO
Z86M
56.8
174
JO
LIQUOR
TO
RECYCLE
I.02IM
1.944
1.05
3.3
50
CALCINER GAS
TO WASTE
HEAT BOILER
71. 6 M
I3.IM
297
TO
RETICLE ACD
TO
COOLERS
I55M
173
II
STEAM
TO GAS
47O
31
RECYCLE
LIQUOR
223M
425
51
STEAM
TO
STEAM PLANT
3.23O
366
71
RECYCLE ACO
»CO COOLERS
I23M
137
12
MAKE-UP
WATER TO
PART SCRBR.
110
32
LIQUOR TO
SLURRY1NG
TANK
I29M
246
52
CALCIMERC-AS
TO
QUENCH AIR
7I.6M
13.1 M
297
697
72
PRODUCT
ACID TO
STORAGE
32.2 M
35.4
3
IOO
1.82
13
RECYCLE
SLURRY TO
PART. SCRBR.
4,740
1.03
3
33
FEED
TO
DRYER
66.4 M
53
QUENCH AIR
TO
CALCINER GAS
62.6M
I3.6M
73
COOLING
WATER TO
ACD COOLERS
2.378M
4.75*
14
15
PART. SCRBMJ PARTICULATE
SLURRY TO ! SLURRY
SURGE TANKI PRODUCT
4,649
127
103
1 L09
3
34
OIL TO
COMBUSTION
CHAMBER
2,943
IS
35
AIR TO
COMBUSTION
CHAMBER
6O5M
I3.2M
54
COMBINED
GASES TO BAG
COLLECTOR
I34M
26 9 M
297
4OO
74
55
COMBKID
GASFS TO
HtSO* UNIT
I54M
26.9M
3
75
16
WATER
95.1
36
DRYER GAS
TO
CYCLONE
I36M
33M
5,9*0
400
56
CYCLONE OUST
TO
CALCINER
1.683
76
17
MAKE-UP
WATER TO SOt
ABSORBER
14. 1
1*
RECYCLE
SLURRY TO
SO. ABSORBS
'
6.320
1
37
DRYER GAS
TO BAG
COLLECTOR
I36M
35 M
894
57
CONVEYOR
294
77
M
RECYCLE GAS
45.SM
ILBM
L4
SB
CALCINER
PRODUCT TO
CONVEYOR
16. 9M
229
78
1*
SOtABBOWE^
SLURRY TO
PUMP
6.341
127
39
DRYER GAS
TO
STACK
90.IM
23JM
Z.G
59
MISC
HANDLING
LOSSES
240
79
20
RECYCLE
AND PRODUCT
SLURRY
6,341
1.09
IO
8
40
COMBINED
OASES TO
ATMOSPHERE
5.246M
1. 167M
2 JO
175
60
RECYCLE
MgO TO
CONVEYOR
16.6 M
BO
NOTES:
I. CALCULATION* BASED ON:
«. 105% STOKHIOMETRIC MAGNESIA
k 3 5% SULFUR IN COAL (DRY BASIS)
c 129. ASH COAL (AS FIRED BASIS)
«. 92% OF SULFUR IN COAL EVOLVES AS SOi
*. 75% OF ASH IN COAL EVOLVES AS FLY ASH
I. 99.5% REMOVAL OF PARTICULATES TO SCRUBBER
I 90% SO! REMOVAL
2.PARTICULATES SHOULD BE ADDED TOGAS TO GET TOTAL STREAM RATE.
3.STREAM NUMBERS 6-21, 23-25. 31 S 62 ARE ONE OF FOUR SIMILAR STREAMS.
4. STREAM NUMBERS 27 ft 29 ARE ONE OF TWO SIMILAR STREAMS.
SYMBOL M TABLE
M THOUSAND
Figure 12. Magnesia slurry - regeneration process. Material balance-base case.
-------
Figure 13. Magnesia slurry - regeneration process. Control diagram—base case.
-------
snot
ELEVATION
Figure 14. Magnesia slurry- regeneration process.
Two-stage venturi scrubber system—plan and elevation—base case.
51
-------
J — *^IIC SIB OHf
Figure 15. Magnesia slurry - regeneration process.
Fluid bed dryer—calciner iayout-plan-hase case
-------
Figure 16. Magnesia slurry - regeneration process.
Fluid bed dryer—calciner layout-elevation—base case.
-------
R
^98% ACID COOLERS
O
D
CONVERTER
-93% ACID COOLERS
PRODUCT ACID COOLERS
93 % ACID PUMP TANK
98% ACID PUMP TANK
PUMP
PRIMARY HEAT
EXCHANGERS
STRIPPING PUMP
= SB* ABSORPTION
TOWER
93% DRYING TOWER
STRIPPING
TOWER
START-UP
FURNACE
START-UP FAN
MAIN GAS BLOWER
172'- o" (APPHOX.I
CONVERTER
COOLING AIR
FAN
CONVERTER HEAT
EXCHANGER
GAS PREHEATER
I
Figure 17. Magnesia slurry - regeneration process. Sulfuric acid unit layout—plan.
-------
93% PRYING TOWER
VENT
98% ABSORPTION TOWER
CONVERTER
PRIMARY
HEAT EXCHANGERS
MAIN GAS
BLOWER
START-UP
FAN
STRIPPING
TOWER
START-UP FURNACE
IT2-O' (APPROX.t
CONVERTER COOLING
AIR FAN
*— CONVERTER
HEAT EXCHANGER
GAS PREHEATER
Figure 18. Magnesia slurry - regeneration process. Sulfuric acid unit layout—elevation.
-------
o\
5TOKAS£
o o
UN LOAD I fit! STJ.
o
o
b
0
n
fc
\
r>i
fb
Figure 19. Magnesia slurry-regeneration process. Overall plot plan—base case.
-------
Existing coal-fired power units which are already
designed to meet particulate emission regulations, and both
new and existing oil-fired power units do not require the
particulate scrubbing facilities described above.
SOi Scrubbers and Ducts
The following equipment is provided:
1. Four flue gas ducts between the particulate scrubber
outlet and the S02 scrubber inlet (one-half of cost is
included in this area; the other half is included in the
particulate scrubbing area).
2. Four 28-ft-diameter x 48.5-ft-high rubber-lined
venturi scrubbers with stainless steel chevron vane
entrainment separators.
3. Twenty soot blowers (5 per scrubber).
4. Four exit flue gas ducts between the S02 scrubber
outlet and I.D. fan inlet. For existing units, flue gas
ducts between the outlet of the supplemental F.D.
fan and the inlet to the stack gas plenum are
included.
5. Six 6,320-gpm, 300-hp rubber-lined centrifugal
recirculation pumps (4 operating and 2 spares).
Stack Gas Reheat
This area includes facilities for reheating the gas to
obtain an outlet stack gas temperature of 175°F. The
reheat method utilized in the magnesia slurry - regeneration
process is similar to the method utilized in the limestone
slurry process with one exception. A small portion of
reheat for the magnesia slurry - regeneration process (about
S°F) is obtained by mixing filtered dryer off-gas (tempera-
ture approximately 400 °F) with the scrubbed flue gas in
the stack gas plenum. Table 19 shows the temperature
increase in degrees Fahrenheit required to obtain an exit
temperature of 175° F at the stack outlet.
A new 500-MW coal-fired power unit is designed with
four 1,658-ft2 indirect steam (500-psig) tube-type heat
exchangers (one per duct) conslructed within the exit flue
gas ducts upstream of the fan. One-half of the tubes
(scrubber side) are Inconel 625 and the other half (fan side)
are Cor-Ten. Twenty soot blowers are provided (5. per
reheater) for periodic cleaning of the tubes.
Existing coal-fired units and new and existing oil-fired
units are designed with four direct oil-fired reheaters which
discharge hot combustion gases into each duct.
Fans
Fan location, method of costing, and duct configuration
for the magnesia slurry - regeneration process are similar to
that described for the limestone slurry process with the
exception of pressure drop. Table 20 identifies the pressure
drop distribution provided for each of the various system
designs.
The following are included in the base case investment
and operating cost estimates:
1. Incremental costs for four 3,000-hp (38 in. AP)
induced draft fans. Prorated for 23 inches of pressure
drop attributed to particulate and S02 removal.
2. Four exit flue gas ducts between I.D. fans and stack
gas plenum.
Slurry Processing
The liquor containing absorbed S02 is pumped from the
absorbers to the slurry processing area for thickening,
thermal conversion of MgS03-6H20 to MgS03-3H20 and
separation of solids prior to drying. This is achieved with
the following equipment:
1. Four 316 stainless steel wet screens mounted in
4-ft-long x 5-ft-wide x 8-ft-high vertical housings.
2. One 5,000-gal, rubber-lined liquor tank, 9-ft-
diameterx 10-1/2-ft-high.
3. Two 1,440-gpm, 50-hp rubber-lined liquor pumps (1
operating and 1 spare).
4. One 6,300-ga!, 12-ft-diameter x 7-1/2-ft-high,
stainless steel, field fabricated conversion tank with
a 20-hp stainless steel agitator.
Table 19. Flue Gas Reheat Requirements-
Magnesia Slurry - Regeneration Process
Power unit
Type Status
Coal fired New
Coal fired Existing
Oil fired New
Oil fired Existing
Required temperature
increase, °F
33
47
31
40
Table 20. Assumed Pressure Drop
Distribution for Specifications of
Fans-Magnesia Slurry - Regeneration Process
Pressure drop distribution,
Power unit inches H^O attributed to
Fuel
Coal
Coal
Oil
Oil
Coal
Coal
S02 removal
Status efficiency, %
New
Existing
New
Existing
New
Existing
90
90
90
90
80
90
Power
production
15.0
_a
15.0
_a
15.0
_a
S02
removal
23 .Ob
• 12.5
10.5
12.5
21.5b
23 .Ob
Total
38.0
12.5
25.5
12.5
36.5
23.0
(requiring particulate
scrubber)
aExisting power units already have fans which overcome the
pressure drop attributed to power production.
blncludes pressure drop attributed to both particulate and SO2
removal.
57
-------
5. One 1,200-ft2 stainless steel steam coil.
6. Two 340-gpm, 10-hp, rubber-lined conversion tank
pumps (1 operating and 1 spare).
7. Two parallel, 36-in.-diameter, x 72-in.-long, stainless
steel solid bowl centrifuges equipped with two
200-hp motors.
8. One 100-gal condensate tank.
9. One 25-gpm, 5-hp condensate pump.
10. One 20-ft-long x 16-in.-diameter horizontal stainless
steel screw conveyor equipped with a 5-hp motor.
11. One 40-ft-long x 16-in.-diameter vertical stainless
steel screw conveyor equipped with a 5-hp motor.
Drying
Costs for the following magnesium sulfite drying equip-
ment and the dryer exhaust gas distribution and cleaning
system are included in this area:
1. One 18-ft-diameter x 40-ft-high single-stage,
refractory-lined, carbon steel, fluid bed dryer
equipped with a 10-ft-diameter x 16-ft-long oil-fired
combustion chamber, a 250-hp fluidizing-combustion
air blower and a refractory-lined cyclone to partially
clean the dryer off-gas.
2. One 46-n-long x 12.5-ft-wide x 21-ft-high fabric dust
collector designed to filter 57^900 acfm of gas at
400°F.
3. One 250-hp l.D. exhaust gas fan.
4. One 25-hp, Z-type conveyor-elevator for transporting
the dust collector, cyclone, and dryer solids to the
MgS03 storage silo.
5. One 25,500-ft3 MgSOs storage silo equipped with a
vibrating hopper.
x 20-ft-long boiler and a 30-in.-diameter x 20-ft-long
feed water tank.
8. One 34-ft-long x 12.5-ft-wide x 21-ft-high fabric
dust collector designed to filter 40,000 acfm of gas
at400°F.
9. One 15-hp, Z-type conveyor-elevator for
transporting MgO from the calciner to the recycle
MgO silo.
10. One 18,950-ft3 recycle MgO storage silo equipped
with a vibrating hopper.
11, One 2.5-hp Z-type conveyor-elevator for recycling
fines from the bag filter to the fluid bed calciner
feed conveyor-elevator.
Sulfuric Acid Plant
This area provides costs for 1 complete 400 tons/day
conventional contact sulfuric acid plant, utilizing the dry
iniet gas cleanup system provided in the calcination area.
The sulfuric acid unit tail gas is fed to the SOj absorber to
eliminate SOX emission resulting from the production of
acid.
Sulfuric Acid Storage and Shipping
The following sulfuric acid storage and loading facilities
are included in the base case investment estimate:
1. Three 500,000-gal carbon steel storage tanks.
2. Two 400-gpm, 40-hp sulfuric acid loading pumps (1
operating and 1 spare).
3. One railroad car loading dock.
4. One dike constructed around the sulfuric acid storage
tanks.
Calcining
This area includes facilities for calcining MgS03 to
regenerate MgO and produce SO^ for sulfuric acid
produc'don. Tne following equipment is provided:
3. One 2-hp MgS03 vibratory feeder.
2. One 2-hp MgSO3 weigh feeder.
3. One 1 -hp coke vibratory feeder.
4. One 2-hp coke weigh feeder.
5. One 25-hp Z-type conveyor-elevator for trans-
porting MgSO3 from the storage silo to the fluid
bed calciner.
6. One 16-ft-diameter x 38-ft-high refractory-lined,
carbon steel, fluid bed calciner equipped with 1
calcining bed and 2 air preheat - MgO cooling beds.
Fuel oil is atomized directly into the calcining bed.
Combustion air is supplied by a 400-hp blower. A
refractory-lined cyclone is provided to partially
clean the calciner off-gas.
7. One waste heat boiler system with a 22-in.-diameter
Utilities
Facilities for the generation and distribution of utilities
for the magnesia slurry - regeneration process are similar to
the limestone slurry process facilities except for the
quantities involved and the requirement of fuel oil distribu-
tion and storage facilities for both new and existing units.
All units utilize fuel oil for drying and calcining. A
660,000-gallon storage tank and two 24,000-gallon hold
tanks are provided for the base case installation. Existing
coal-fired and both new and existing oil-fired units provide
for additional fuel oil storage for stack gas reheat similar to
the reheat method for the limestone slurry process.
Service Facilities
The following items are included in the estimate for each
of the various system designs:
1 Vehicles—allocation to power unit for use of plant
vehicles.
58
-------
2. Buildings and equipment-one 5,800-ft2 maintenance
and instrument shop; one 5,000-ft2 building
including process and motor control facilities, labora-
tory, lockers, offices, and restrooms; allocation to
power unit for one 2,300-ft2 stores area.
3. Railroads—costs for 3,600-ft of track, 5 switches, and
2 car pullers.
4. Parking lot, walkways, and approximately 1 mile of
paved roads.
5. Landscaping, fencing, and security.
Construction Facilities
Construction facilities are projected as 5% of the
subtotal area investments similar to the method used for
the limestone slurry process.
SODIUM SOLUTION - S02 REDUCTION PROCESS
In the sodium solution - S02 reduction process, fly ash
is removed by wet scrubbing flue gas in a venturi by contact
with a slurry of fly ash in water; S02 is absorbed from the
gas by an aqueous sodium sulfite scrubbing solution in a
separate scrubber. For this regeneration process, makeup
soda ash is added to replace the sodium value lost in
handling and as byproduct sodium sulfate formed in the
scrubber and removed as purge. The makeup soda ash is
pneumatically conveyed from hopper cars or trucks to a
storage bin and fed to a tank where it is slurried in water
along with antioxidant. The antioxidant is added to
minimize the oxidation of sulfites to sulfates in the
absorber. The soda ash and antioxidanf slurry is pumped to
a Na2S03 dissolving tank for generation of the scrubber
solution. Recycle pond water and makeup humidifica-
tion water are fed to the venturi parliculate scrubbers,
for removal of fly ash from the gas as in the magnesia
process. The fly ash slurry is neutralized with slaked
lime as required and pumped to the power plant ash
disposal pond.
Separate scrubbing loops are provided for each cf the
three trays in the valve-tray S02 absorber. The absorbers
are equipped with fleximesh mist eliminators. A purge
stream consisting of approximately 58% of the absorber
effluent is routed to a purge treatment area where it is
cooled for crystallization and subsequent removal of
sodium sulfate from the liquor. After purge, the liquor is
recombined with the remaining absorber effluent. The
sodium sulfate is dried in a rotary dryer and conveyed to a
product storage bin. Steam is used in new coal-fired units to
provide heat for the dryer; whereas, existing coal and both
new and existing oil-fired units utilize fuel oil as a heat
source. Thfe dryer off-gas is cleaned with a cyclone and
fabric filter and routed to the scrubbing system.
The combined absorber effluent and purge stream, after
removal of the sodium sulfate, is pumped to a single-effect
evaporator-crystaliizer in the regeneration area to crystallize
Na2S03 and regenerate S02 for the reduction area. The
off-gas containing regenerated S02 from the evaporator-
crystallizers is cooled to condense some of the water vapor.
Most of the remaining moisture is removed as the S02 gas Is
compressed. The condensate is used to solubilize the
Na2S03 for return to the S02 absorber.
The compressed S02 gas is fed to the Allied Chemical
reduction unit where it is mixed with natural gas and
indirectly preheated by the cooling of reduced gas. The
combined gases flow into a reduction reactor system where
these are reduced to S, H2S, C02, and H20. The reduced
gas mixture is cooled in a hot water/gas heat exchanger
before entering a condenser-converter-condenser system
where most of the H2S and S02 are converted to S. The S
formed during the reaction is condensed. A coalescer is
used to remove the small drops of sulfur prior to treatment
of the tail gas. The molten sulfur is collected in a sulfur
receiving pit and stored in steam-heated tanks for shipment.
The tail gas from the reduction unit is incinerated with
natural gas and air to oxidize any H2S formed during the
reduction process to S02 and is returned to the scrubbing
system.
The total land requirement for the base case process for
new coal-fired units is approximately 7.7 acres excluding
the land requirement for fly ash disposal. The flow diagram,
material balance, plot plan, layouts, and elevations for the
sodium solution - S02 reduction process are shown in
figures 20-25 for the base case and an area-by-area
description is given.
Soda Ash and Antioxidant
Receiving, Storage, and Preparation
This area includes facilities for receiving, by truck or rail,
and storing soda ash, and equipment for producing a
mixture of soda ash and antioxidant. The following
equipment is provided:
1. One pneumatic soda ash unloading conveying system,
2. One 4,500-ft3 soda ash closed-top storage bin
equipped with 2 bin vibrators.
3. One 1-hp vibrating feeder.
4. One 2-hp soda ash weigh feeder equipped with a 1-hp
vibrating hopper.
5. One 1-hp antioxidant feeder.
6. One 11,800-gal rubber-lined mixing tank equipped
with baffles and a 3-hp rubber-coated agitator.
7. Two 25-gpm, 1-hp, rubber-lined horizontal,
centrifugal, mixing tank pumps (1 operating and 1
spare).
59
-------
t tr*4rx*3t
CM* .naxjni'r
*rr** #**ft~ & •< I—• srf***
jr**f**n**r WJ ^ .f<
e+umfMtr+rr _ —J
•w tte*rr**
******•+******
**tt*r+***rx* I
sr-ha-T]
Figure 20. Sodium solution - SO2 reduction process. Flow diagram—base case.
-------
STREAK NO
OtSCRPTiON
RATE. LBS./HR
SCFM
tut
TEMPERATURE. *F
STtCFIC GRAVITY
VISCOSITY. CK
IMDOSOLVED SOUOS. *
PH
STREAM no
OESCIWTIO*
RATE. US im
SCFM
MKTICU.ATES. UK /HR
TCMTCWURE. -F.
srEcrc WAVITY
VISCOSITt CPS
UROtSSOLVEO SOLIDS. %
•»
STREAM DO
KSCRTKM
scrM
9fU
PWTICULATES. US /MR
TEMPERATURE. 'F
SPECIFIC MAvmr
VISCOSITY. CPS
UN0590LVEO SOUOS,*
•H
STREAM NO
OCSCRIPTIOH
RATE. L*S /H»
SCFM
•ra
PftRTICULATes. LB3 'MR
TEMPERATURE, -F
SreOFC SRAV1TY
vnCOSTTY. CPS
msscuCD ta.es. %
p«
1
COAL
TO
BOILER^
21
FEED SOU/TO
TO
SOtABSOfVO
87ZM
4t
TO
[MIPR.-CRYSTR
68 6M
• i
GAS
FROM
MCINERATOR
Z36M
5,430
1.290
2
"A^To'0"
MR HEJTES
»B4M
MO
22
MECTCLE
TO
THIRD STWE
513 U
4Z
rODBSOUTMG
TAMK
03
• 2
COOLM6
WT EH TO CM
CXWMtEaSCM
T4M
I4i
3
coMurnc*
AJR TO
•OILEH
M»y
933
23
WCTCLE
TO
*O0U
43
TO pmuurr
CONDEM9CH
39.4U
• 3
STEAM
TO sun*
STOMAGC
5OOO
2M
4
«AS
TO
ECONOMIZER
4,404 H
M3M
35.™
t»0
24
REClCLETO
FIRST si»6c
AWOMOCUCT
TOSH
44
TO
rrmuncm
ii.ru
•4
CONOEMJ.TE
TO
STEAM CUNT
ZZSM
490
9
OA9
TO
Am HEATCT
4.4O4H
»43M
M^»*
709
29
LIQUOR
TO
SURGE TANK
9ZCM
1 *49 1
49
' STEAM
TO
STRIr»PCM
zzo
•9
«
•AS TO
» ARTICULATE
•ctttjae"
it2tzy
g»o>«
310
zc
LIOUOR
TO CMR.LER-
CRTSnUJZEII
214 M
1 "* 1
«•
4«
COWCNSATC
TO
nwrxmt.
K13
•4
7
«AS
TO SOt
A»SOR»ER
I.3ITH
Z»H
127
27
E&9OU.TDN
TO CMLLER-
U3*5M
I t.»0T
23
I 07
47
TO OSSOUflME
TANK
191
• 7
•
«AS
TO
RE HEATER
1. 312 M
2SOM
127
2i
OX3LM6WATEF
TO HEFRI6
SV3TEM
389 y
44
GAS
TO
COMPRESSOR
1.2M
• •
9
•AS
TO
FAN
290 U
163
29
SLURRY
TO
CCMTKIFU6E
214 H
39
49
COWCNSATE
•9
.0
GAS
TO
ITMOSPHCRE
1-1*0"
175
30
CENTRATE
TO
HEATER
205y
98
30
GAS
TO
SOi REDUCTION
2.Z0O
Z50
7O
M 12 j '3 14 (3
STEAM MAKE _P ! HECXCLE Burr- »CRWt. MATICULATC
TO CAS »ATE=* TO "SLURRY TO SLURRT TO SLURRY
REHEATED -°*pr SCR9R. PAR" SCRBBJSUR6C TANK PWOOUCT
01 4 '4O *.f*3« IO3
470 i '2T
.C3 1.09
5 . 19
3 1
3 • ' !Z !3 34 35
CAKE S"£AM '3 345 »'jR«C ' LIQUOR
-C STEAM /AR c^OM "0 TQ
CONVEYOR HEATER ORYE^ 9>*t E'*PR-CFYSTR
3.3SO ' Z0.4 y t«8M . 3.T12 78 IM
40Ty i
t*C Z30
51 '52 33 3* !5
frs :ro f eco GAS - PURGE -c coMoejeE:w
9O»«Dutm» -4€ATER T5 DRYER $r*M* "JUnT aeu COOLER
1. 130 5 4.0
6
20C . 220 ' ISC Z3C
:
|
-: ! T2 j rj 74 ' 79
!
1 : :
i i
I
1 ;
i i
1C
RECYCLE
POND
WATER
99 |
3«
FEED
TO
EWR.-CRY3TR
60.1 MM
96
DCSUPER-
MEATER
470
7«
17
yAKE-UP
WATER TO
1XING TANK
212
37
SLURRY
FROM
aMm-arrsnt
•OHM
97
STORAGE a
SHIPPING
*•"*
104
TT
N
SOOA ASH
TO
MIXING TANK
38
SLURRY
TO
HEATER
99.9 MM
98
79
(9
TO
MIXING TAMK
493
39
FEED
TO
HEATER
•OMM
99
NATURAL GAS
TO
MCJNERATOR
• 3
79
2O
DISSOLVING
TANK
13. 3 H
M~I
NX)
i to
40
STEAM
TO
HEATER
II9M
220
•0
AIR
TO
MOWRATOH
*•"* —
1.*30
TO
K
NOTES.
I. CAUMLATIOM «ASCO ON
109% STOCWOHETRtc SOOKJU
35% SULFUR IN COALtDMY)
IZX ASM COAL IAS FIRED)
«X OF JULFUB in COAL CVOLVCS AS SOt
75% OF MM • COAL EVOLVES AS Fur ASH
*t3%mOVAL Or HMtTICULATES TO tCRUMOt
SOi DEMOVAL
2 numcULATES SHOULD BE AOOCD TO GAS TO CXT TOTAL STREAM RATE
X STREAM NUMBERS (-9.II-M • 21-29 ARE OMC OF FOUR SM«R STREAMS
4. STREAM njHtm S5-4» • U ARE Out Or TWO SIMILAR STKEAMI.
SYMBOLS »• TABLE
M THOUSAND
MM MILLION
Figure 21. Sodium solution -SO2 reduction process. Material balance-base case.
-------
ELEVATION
figure 22. Sodium solution - S02 reduction process.
Venturi and valve-tray scrubber system—plan and elevation—base case.
62
-------
Figure 23. Sodium solution -SOj reduction process. SO2 regeneration -
reduction and purge treatment system layout-elevation—base case.
-------
A
J
•
•
•»
r»
B
J
Figure 24. Sodium solution - SO2 reduction process. SO2 regeneration-
reduction and purge treatment layout—plan—base case.
-------
o
r>
Figure 25. Sodium solution -SO2 reduction process. Overall plot plan—base case.
-------
Paniculate Scrubbers and Inlet Ducts
i
The particulate scrubbing areas for the magnesia slurry -
regeneration process and the sodium solution- S02 reduc-
tion process are similar. A list of the flue gas distribution
and particulate scrubbing facilities included in the estimate
is given in the description for the magnesia slurry -
regeneration process particulate scrubbers and inlet duels
area.
S0;j Scrubbois and Ducts
The following equipment is provided:
1. Four line gas ducts helwee'u Ihe vcnluri ('articulate
scrubber outlet and (In* SO, scrubber inlet (one-hall'
. of cost is included iu this area; (he- oilier hall is
included in the parliciilale scrubbing;ue:i). .
2. l;om 3 I -fl diameter • x (tO-l'Hiigh carbon sled,
fiberglass-lined three-plate valve tray SO2 absorbers
with stainless steel internals and fleximesh rnist
eliminators with fiberglass lining.
3. Sixteen 1,000-gpm, 35-hp, rubber-lined, centrifugal
solution recycle pumps.
4. Four exit flue gas duels between the S02 scrubber
outlet and l.D. fan inlet. For existing units. Hue gas
ducts and inlel plenum arc included belween (he
outlet of die supplemental F.D. fan and the inlet to
the stack gas plenum.
Stack Gas Reheat
Thi^ reheat system is similar to the reheat system
described for the limestone slurry process stack gas reheat
area. Table 21 shows the temperature increase in degrees
Fahrenheit required to obtain an exit temperature of
175°F at the stack outlet.
Fans
Fan location, method of costing, and duct configuration
for the sodium solution - S02 reduction process are similar
to that described for the limestone slurry process with the
exception of pressure drop. Table 22 identifies the pressure
drop distribution provided for each of the various system
designs.
Purge Treatment
A purge stream of effluent from the S02 absorber is
routed to the purge treatment area for removal of sodium
sulfat6 from the system. The separation, drying, storage,
and shipping of sodium sulfale is achieved with the
following equipment:
i. One 500-ton refrigeration system.
2. Two 2,621-gpm, 200-hp, horizontal, centrifugal
ethylene glycol pumps (1 operating and i spare).
3. One 8,800-gal, 10-ft-diameter x 15-ft-high,
insulated, flat-top ethylene glycol tank.
4. One 12-ft-diameter x 18-ft-high, insulated, 304
stainless steel chiller-crystallizer tank with 8,400-ft2
cooling surface and a 5-hp rubber-coated agitator.
5. Two 350-gpm, 10-hp, horizontal, centrifugal
chiller-crystallizer pumps (1 operating and 1 spare).
6. One l',529-ft2, shell and tube, 316 stainless steel
feed cooler.
7. One 36-in.-diameter x 96-in.-long stainless steel solid
bowl centrifuge equipped with a 30HMip motor.
8. One 960-gal, closed-top, 316 stainless steel centrate
lank.
°. Two 350-gpm, 15-hp, rubber-lined, hori/.onlal,
centrifugal ccnlrate pumps.
10. One l-hp, enclosed, belt conveyor for transporting
sodium sulfale from the centrifuge and recycle
conveyor to the dryer.
II. One 12-ft-diametei x 60-ft-Iong rotary dryer.
12. One l-hp, enclosed, belt conveyor between the
dryer and elevator.
13. One 7.5-hp, bucket elevator for transporting sodium
sulfale to the recycle bin.
Table 21. Flue Gas Reheat Requirements-
Sodium Solution • SO2 Reduction Process
Power unit
Type Status
Coal fired New
Coal fired Existing
Oil fired New
Oil fired Existing
Required temperature
increase, °F
36
51
34
44
Table 22. Assumed Pressure Drop Distribution
for Specification of Fans-
Sod kTOjJp_lution_-_SOj Reduction Process
Pressure drop distribution,
Power unit
1 S02 removal
Fuel Status efficiency, %
Coal New
Coal Existing
Oil New
Oil Existing
Coal New
Coal Existing
90
90
90
90
80
90
inches H20 attributed to
Power
production
15.0
_a
' 15.0
_a
15.0
_a
S02
removal Total
26. 5B 41.5
16.0 16.0
14.0 29.0
16.0 16.0
24.0b 39.0
28.5b 28.5
(requiring particulate
scrubber)
aExisting power units already have fans which overcome the
pressure drop attributed to power production.
"Includes pressure drop attributed to both particulate and SO2
removal.
66
-------
14. One I-lip recycle sodium siilfalc weigh I'mh-r wllli n
I-lip vibrating feeder. ;
15. One 100-IV', closed-lop, side und bolloin teed,
recycle bin.
16. One 1-hp, enclosed, sodium sulfate, recycle belt
conveyor.
17. One 46-ft-long x 12.5-ft-wide x 21-ft-high, fabric
dust collector designed to filter 57,900 acfm of gas.
18. One 250-hp induced draft exhaust gas fan.
19. One fmned-tube steam/air heater with 735 ft2 of air
cooler area.
20. Two 1-hp enclosed belt dust conveyors.
21. One 3-hp, enclosed belt conveyor for loading the
sodium sulfate storage bin.
22. One 8,000-ft3, sodium sulfate. storage and loading
bin with divider and 4 bin vibrators.
Existing coal-fired and both new and existing oil-fired
units are equipped with an oil-fired drying system to
replace the steam/air heater and dryer provided for new
coal-fired units. The following equipment is provided for
the oil-fired drying system:
1. One 8-ft-diameter x 60-ft-long rotary dryer.
2. One 7.5-hp primary air fan.
3. One 30-hp secondary air fan.
4. One direct oil-fired heater system.
S02 Regeneration
The absorber effluent is pumped to the regeneration area
where Na2S03 is crystallized and S02 and H20 are evolved
by evaporating the NaHS03 solution. Most of the H20 is
removed from the single-effect evaporator-crystallizer vapor
and is used to solubilize the Na2S03 for return to the SOj
absorber. The following equipment is provided:
1. One 278,400-gal, rubber-lined, surge tank.
2. Two 600-gpm, 40-hp, rubber-lined, horizontal,
centrifugal surge tank pumps (1 operating and 1
spare).
3, Two 19,065-ft2, shell and tube heaters with carbon
steel shell and 304 stainless steel tubes and heads.
4. Two 24-ft-diameter x 26-ft-high, 304 stainless steel,
evaporator-crystallizers.
5. Two 70,000-gpm, 800-hp, 304 stainless steel, hori-
zontal, axial flow, evaporator-crystallizer circulation
pumps.
6. Two 7,593-ft2, shell and tube primary condensers
with carbon steel shell and 316 stainless steel tubes
and heads.
7. Two 2,013-ftJ, shell and tube secondary condensers
with carbon steel shell and 316 stainless steel tubes
and heads.
8. Two 3-ft-diameter x 16-ft-high, 316 stainless steel
strippers.
9. Two 152,300-gal, rubber-lined dissolving tanks
equipped wllli biifflex ami two I0-lip, rubber-coated
agitators.
10. Two 600-gpm, 40-hp, rubber-lined, horizontal,
centrifugal, dissolving tank pumps (1 operating and
1 spare).
11. Two 1,268-scfm, 250-hp compressors.
12. One 9,408-gal, insulated, horizontal, central
condensate tank.
13. Two 600-gpm, 30-hp, horizontal, centrifugal,
condensate pumps (1 operating and 1 spare).
14. One desuperheater with a 500-psig steam
throughput capacity of 250,000 Ib/lu.
As stated earlier in the premises, existing coal- and
oil-fired units are equipped with packaged boiler units to
provide steam for the regeneration area heaters and
strippers. The desuperheater is not required for the existing
units.
S02 Reduction
This area includes one complete S02 reduction unit with
a capacity of 112 short tons sulfur per day. Compressed
S02 gas is mixed wiih natural gas and preheated in a gas
heat exchanger by cooling reduced gas. A reduction reactor
system reduces the gas mixture to S, H2S, C02, and H20.
Subsequent cooling of the reduced gas occurs in a gas/steam
heat exchanger and the preheater discussed above. The
cooled reduced gas is passed through a condenser-
converter-condenser system where most of the H2S and
S02 is converted to S which is condensed. A coalescer is
utilized to remove small drops of entrained sulfur from the
tail gas before it is incinerated with natural gas and air to
convert any sulfur compounds in the offgas to S02. The
combustion gas is returned to the S02 absorber to
eliminate SOX emission resulting from the production of
sulfur. This Allied Chemical process is a recent proprietary
development and a complete description of the reduction
unit is not available.
Sulfur Storage and Shipping
The following facilities are included in the estimate for
sulfur storage and loading:
1. One 10-ft-long x 10-ft-wide x 10-ft-high sulfur-
receiving pit with insulation and a 304 stainless steel
cover.
2. Four 125-gpm, 10-hp, high-temperature, sulfur-
loading pumps with steam tracing and insulation (2
operating and 2 spare).
3. One 467,100-gal, closed-top, insulated sulfur storage
tank.
4. One railroad car loading dock.
5. One dike constructed around the sulfur storage
tank.
67
-------
Utilities
Facilities for the generation and distribution of utilities
for the sodium solution - S02 reduction process are similar
to those provided for the limestone slurry process, but
differ somewhat in quantities. However, new and existing
coal- and oil-fired units all require that steam be provided
for the S02 regeneration and sulfur storage areas. Existing
coal-fired units require fuel oil storage and distribution
facilities for reheat, drying, and producing steam for the
SOj regeneration and sulfur storage areas. New oil-fired
units are equipped with a 500-psig supply system from the
power unit for the SO? regeneration and sulfur storage
areas, and fuel oil storage and distribution facilities for
reheating and drying.
Service Facilities
The following items are included in the estimate:
1. Vehicles-allocation to power unit for use of plant
vehicles.
2. Buildings and equipment-one 5,800-ft2 maintenance
and instrument shop; one 5,000-ft2 building
including process and motor control facilities, labora-
tory, lockers, offices, and restroornsi allocation to
power unit for one 2,300-ft2 stores area.
3. Railroads-costs for 1,100 ft of track, 1 switch, and 1
car puller.
4. Parking lot, walkways, and approximately 1 mile of
paved roads.
5. Landscaping, fencing, and security.
Units with fuel oil storage and distribution facilities
include an additional 800 feet of railroad track and two
switches in this area for fuel oil receiving and handling.
Construction Facilities
Construction facilities are projected as 5% of the
subtotal area investments similar to the method used for
the limestone slurry process.
CATALYTIC OXIDATION PROCESS
The Cat-Ox process utilizes vanadium pentoxide catalyst
to convert S02 to S03 directly in the flue gas followed by
the absorption of the SO3 to produce nominal 80% acid.
Efficient conversion of S02 to S03 requires a gas tempera-
ture of approximately 850°-900°F. For new units (inte-
grated process) the facilities are designed for conversion
upstream of the economizers and air preheaters to eliminate
the necessity of additional heat transfer equipment. For
existing units (reheat process) direct oil-fired flue gas
reheaters are provided to reheat the gas to the proper
temperature prior to conversion and additional heat
exchangers are included to recover this heat downstream.
Based on the Wood River experience it is recognized that
the direct oil-fired reheat system should be designed for
external combustion with injection into the ducts, with
provisions for bypassing the converters during startup of
the reheaters.
Both new and existing units require high efficiency
electrostatic precipitators for reducing the particulate
loading of the gas to the converters to 0.005 gr/scf or less
to minimize fouling of the catalyst. Bypass ducts and
dampers around the converters and absorbers prevent
contamination of the catalyst and acid during startup. Even
with these precautions, there is a gradual buildup of fly ash
on the catalyst during operation. Conversion efficiency of
the catalyst is not affected by this buildup; however, there
is a gradual increase in pressure drcp across the converter
due to the collection of fly ash. Therefore, equipment is
provided to convey, clean, and return the catalyst to the
converter system. Approximately 2.5% of the total volume
of catalyst must be replaced per cleaning because of
catalyst losses resulting from screening and mechanical
breakage during the sifting operation. Under normal
conditions the catalyst must be cleaned about every 3
months.
Sulfur trioxide and a portion of the water vapor in the
ilue gas are absorbed in packed towers with a recirculating
stream of sulfuric acid from the heat recovery fluid loops.
Entrained sulfuric acid and mist particles formed as the gas
cools are removed by high efficiency Brink fiber demisters.
For energy conservation, about half of the heat of
absorption of SOj from an integrated unit is transferred to
the power plant boiler combustion air by means of a fluid
loop. Additional heat is transferred to boiler feed water in
the same manner. For a reheat unit, cooling water is used to
recover the heat of absorption. A steam/air heater for new
coal-fired units and a direct oil-fired reheater for oil-fired
units are provided to supply supplemental heat to the
combustion air.
For each process, the product acid is cooled further and
pumped to the product storage tanks for shipment.
Approximately 7.4 acres of land are required for new
500-MW coal-fired units utilizing the Cat-Ox process
excluding the land requirement for fly ash disposal. The
flow diagram, material balance, control diagram, plot plan,
layout, and elevation drawings are shown in figures 26-30
'for the integrated base case. Layout and elevation drawings
for a Cat-Ox reheat unit are presented in figures 31 and 32.
A description of the processing areas is given.
Startup Bypass Ducts and Dampers
To prevent contaminating the catalyst and acid with fly
ash during startup, the Cat-Ox process is equipped with
68
-------
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Figure 26. Catalytic oxidation process. Flow
diagram and material balance-base case.
-------
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-------
2B3 FT (APPROX.l
!;ATALYST LOADING CONVEYOR (ABOVE)
:ATALYST UNLOAONG CONVEYOR IBELOWI
/FLUB/AIR HEATER
\5TEAM/AIR HEATER
CC»OENSATE MtATES
MO I CIRCULATION «CC COOLER? (2)
HO 2 CIRCULATOK ICO COOLERS(2)
HO. I CIRCULAT1CM AOO COOLERS (2
CONOENSATE HEATER
CIRCULATIOX ACC COOLER PUMPS
MAKEUP CATALYST
RECEIVMG HOPPER
Figure 28. Catalytic oxidation process. SO2
conversion and absorption system layout—plan—base case.
-------
INLE1 PLENUM
CONOENSATE H£AT£R —
iRCJLATION 4CIO COOLERS
COMBUSTION AIR
TO BOILER
Figure 29. Catalytic oxidation process. SOj conversion
and absorption system layout—elevation-base case.
-------
D C
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-n
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STOWAGE
ROAD
2
a
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*
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O
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t>
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SERVICE
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Figure 30. Catalytic oxidation process. Overall plot plan-base case.
-------
Figure 31. Catalytic oxidation process. SO2 conversion and
absorption system layout—elevation—existing case.
-------
EXPANSION JOINT
(TYPICAL WHERE \
PUMPS
SIFTER FLY ASH
COLLECTION HOPPER
V ELEVATOR
DAMPER (TYPICAL'
WHERE SHOWN)
CAT4LYST
STORAGE BIN
Figure 32. Catalytic oxidation process. SO2
conversion system layout—plan—existing case.
-------
Table 23. Electrostatic Precipitator
Rcquircmcnts-Cataly tic-Oxidation Process
Power unit Removal efficiency Gas temperature,
TYEL
Coal fired
Coal fired
Coal fired
Oil fired
Oil fired
Status
New
Existing
Existing
New
Existing
Present
-
98.7
-
Additional
99.9
92.3
99.9
84.4
84.4
°F
890
310
310
890
310
startup bypass ducts. This area includes flue gas ducts and
dampers that bypass the converters and absorbers during
startup by routing the gas directly to the I.D. fan. Existing
units use dampers at the tie-in to the existing power unit
ducts to provide a startup bypass around the removal
facilities.
j
Electrostatic Precipitators
and Inlet Ducts
For both new and .existing units, fly ash is removed by
high efficiency electrostatic precipitators. Table 23 shows
the electrostatic precipitator requirements: to obtain 99.9%
removal efficiency (equivalent to 0.005 gr/scf) required for
operation of the Cat-Ox facilities.
Costs for the following fiue^gas distribution facilities are
included in this area:
1. One inlet Hue gas plenum interconnecting each of the
four flue gas ducts.
2. Four flue gas ducts between the inlet plenum and the
electrostatic precipitators, including one damper per
duct.
3. Four flue gas ducts between electrostatic precipi-
iators and converters (one-half of cost is included in
this area; the other half is included in the S02
conversion area).
Existing coal-fired and oil-fired units have four Hue gas
ducts between the power unit I.D. fan outlet and the inlet
plenum in addition to the ilue gas distribution facilities
described above.
Sulfur Dioxide; Converters and'Ducts
The following equipment is provided:
1. Four Ilue gas ducts between the electrostatic pre-
cipitators and converters (one-half of cost is
included in this area; the .other half is included in
' the electrostatic precipitator area).
2. Four 36-ft-long x 33-ft-wide x 50-ft-high converters
including platework, screens, insulation, catalyst
discharge gates, platforms, and paint.
3. One 5-hp enclosed belt conveyor (catalyst
unloading).
4. One 25-hp enclosed belt conveyor (catalyst
loading).
5. One 10-hp catalyst elevator.
6. One 10-ft-long.x 4-ft-wide, 3-hp catalyst sifter with
single deck screen.
7. One 938-ft3 fly ash collection hopper with closed
top.
8. One 7,634-ft3 catalyst storage bin with closed top.
9. Thirty-three pneumatic control knife gate valves and
32 hand-operated knife gate valves.
10. One 2-ft-long x 2-ft-wide x 75-ft-high catalyst
convolute cascade chute.
11. Four flue gas ducts between the converters and
economizers (one-half of cost is included in this
area; the other half is included in the heat recovery
area). For existing units, flue gas ducts between the
converters and absorbers are included (one-half of
cost is included in this area, the other half is
included in the sulfuric acid absorbers and coolers
area).
Heat Recovery and Ducts
For energy conservation purposes, this area includes
facilities for recovering heat from the hot combustion gases
downstream of the boiler and preheating combustion air
before it enters the boiler. The following equipment is
provided:
1. Four 8-ft-long x 7-ft-wide x 33-ft-high finned-tube,
gas-to-water economizers. (The costs of these econo-
mizers are not included in the investment estimate
as they are required by the power unit without
removal facilities. Although finned-tube econo-
mizes offer a potential savings over the conven-
tional bare tube-type, additional housing costs are
incurred as a result of locating the economizer
outside of the boiler building; therefore, an
investment credit was not claimed.)
2. Four 27-ft-long x 24-ft-wide x 7-ft-high gas-to-air
Ljungstrom air heaters (smaller air heaters and less
ductwork are required than with normal power
units; therefore, a credit is received from the power
plant for these facilities).
3. Four finned-tube steam/air heaters contained in a
2-ft-long x 30-ft-wide x 14-ft-higli housing.
4. Four finned-tube fluid/air heaters contained in a
9-ft-long x 30-ft-wide x 14-ft-high housing.
5.'Four 4,034-ft2, shell and tube condensate heaters.
6. Two 8,140-gal cooling water surge tanks.
7. Six 1,356-gpm,100-hp,single-stage,horizontal, split-
case, centrifugal cooling water recirculation pumps
(4 operating and 2 spare).
8. Four flue gas ducts between the converters and
economizers (one-half of cost is included in this
-------
urea; Ihc other half is included in the S02 converter
area).
9. Four tlue gas ducts between the economizers and air
heaters.
10. Four combustion air ducts between the powerhouse
and air heaters.
11. Four combustion air ducts between air heaters and
F.D. fan (one-half of cost is included in this area;
the other half is included in the fan area).
New oil-fired units are equipped with direct oil-fired
heaters to replace the steam/air heaters. Existing coal- and
oil-fired units include eight direct oil-tired reheaters and
four gas-to-gas heat exchangers to reheat the flue gas to
890° F prior to conversion and to recover the heat after
conversion.
Fans
Fan location, method of costing, and duct configuration
for the catalytic oxidation process are similar to thai
described for the limestone slurry process with the excep-
tion of pressure drop and supplemental fan location for
existing power units. Existing units for Cat-Ox use supple-
mental l.D. fans downstream of the absorbers instead of
supplemental F.D. fans in series with the power unit fans as
provided for the other processes. Table 24 identifies the
pressure drop distribution provided for each of the various
designs.
The base case investment and operating cost estimates
include the following:
i. Incremental costs for four 3,750-hp (46 in. ^P) |.D.
fans prorated for 31 in. of pressure drop attributed to
paniculate and S02 removal.
2. Four exit flue gas ducts between the l.D. fans and the
stack gas plenum.
For existing units, this area includes the ductwork
between ihe new l.D. funs downstream of the absorbers and
the tie-in to the existing plenum.
Sulfuric Acid Absorbers and Coolers
The following equipment is provided:
1. Two vertical, cylindrical lead line absorbers
including 3 in. ceramic packing, and Brink fiber
dcmisters.
2. Ten 90(>-gpm, 60-hp, liori/.ontal, centrifugal, high
silicon-iron acid circulation pumps (X,operating and
2 spa re).
3. Eight 12,200-ft2 shell and tube acid-to-fluid heat
exchangers (No. 1 circulation acid coolers) with
•impervious graphite tubes.
4. Two 7,510-gal coolant fluid surge tanks.
5. Six 1,250-gpm, 125-hp, single-stage, horizontal.
split-case, centrifugal coolant recirculation pumps (4
operating and 2 spare).
6. Four 8,070-ft2 shell and tube acid-to-water heat
exchangers (No. 2 circulation acid coolers) with
impervious graphite tubes.
7. Two 165-ft2 shell and tube acid-to-water heat
exchangers (product acid coolers) with imperivous
graphite tubes.
8. One 8,000-gal intermittent wash tank.
9. Two 800-gpm, 40-hp, single-stage, horizontal, split-
case, centrifugal, intermittent wash pumps (1
operating and I spare).
10. Four tlue gas ducts between air heater and l.D. fan
inlet.
Existing coal- and oil-fired units do not have the heat
recovery circulation loops; the following equipment is
provided for existing units:
1. Two absorbers and mist eliminators (same as for new
units).
2. Ten 906-gpm, 60-hp horizontal, centrifugal, high
silicon iron acid circulation pumps (8 operating and 2
spare).
3. Four 5,330-ft2 shell and tube .acid-to-water heat
exchangers (circulation acid-coolers) with impervious
graphite tubes.
4. Two 165-ft2 shell and tube acid-to-water heat
exchangers (product acid coolers) with impervious
graphite tubes.
5. One 8,000-gal intermittent wash tank.
6. Two 800-gpm, 40-hp, single-stage, horizontal, split-
case, centrifugal, intermittent wash pumps (1
operating and I spare).
7. Four flue gas ducts between converters and absorbers
(one-half of cost is included in this area; the other
half is in the S02 converter area).
8. Four flue gas ducts between the absorbers and the
inlet to the supplemental l.D. fan.
Table 24. Assumed Pressure Drop Distribution for
Specification of JFans-Catalytic Oxidation Process
Pressure drop distribution.
Power unit inches H20 attributed to
SO2 removal
Fuel
Coal"
Coal
Oil
Oil
Coal
Status effi
New
Existing
New
Existing
Existing
iciem
90~
90
90
90
90
'ower
aduction
15.0
a
15.0
a
_a
S02
removal
31.0b
39. 5 b
29 .Ob
39.5b
39.5b
Total
46.0
39.5
44.0
39.5
39.5
(without existing ESP)
"Existing power units already have fans which overcome the
pressure drop attributed to power production.
"Includes pressure drop attributed to both participate and SO2
removal.
77
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Sulfuric Acid Storage and Shipping
This area is similar to the magnesia slurry - regeneration
process sulfuric acid storage and shipping .area with the
exception that one additional 500,000-gallon storage tank
is provided to allow Tor storage of the lower concentration
acid. A. list of the equipment included in the estimate is
given in the magnesia slurry - regeneration process sulfuric
acid storage and shipping area.
Utilities
Facilities for the generation and distribution of utilities
for the Cat-Ox process are similar to the limestone slurry
process with two exceptions. For the Cat-Ox process, the
steam supply system is included in the heat recovery area
and the cooling water system is included in the sulfuric acid
absorbers and coolers area. The other equipment included
in the estimate is similar to that included in the limestone
slurry process utilities area.
Service Facilities
This area includes the following items:
1. Vehicles-allocation to power unit for use of plant
vehicles.
2. Building and equipment-One 5,000-ft2 maintenance
and instrument shop; allocation to power unit for
one 1,800-ft2 building, including process and motor
control facilities, laboratory, lockers, offices, rest-
rooms; allocation to power unit for one 2,000-ft2
stores area.
3. Railroads-costs for 1,000 ft of track, 1 switch, and 1
car puller.
4. Parking lot, walkways, and approximately 1 mile of
paved roads.
5. Landscaping, fencing, and security.
Units with direct oil-fired reheat systems include an
additional 800 feet of railroad track and two switches in
this area for fuel oil receiving and handling.
Construction Facilities
Construction facilities are projected as 5% of the
subtotal area investments similar to the method used for
the limestone slurry process.
78
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Economic
Evaluation
And Comparison
Based on the very definitive power plant, process design,
and economic premises previously outlined and the specific
equipment and installation requirements of each process as
described in the previous section, generali/cd capital invesl-
ment and operating cost estimates; both annual, anil
lifetime, are prepared for economic evaluation and I'ompaii
son of the five processes. For "stale of Ihc ail" estimating
purposes, the representative designs aie assumed to be
proven (not first of a kind); however, it is recogni/.i'd that
'(he current development and (leinonslialion stains ol Ihese
five professes does not justify s'ueh an assumption. Fnrlhei
testing anil operating experience may in lime invalidate (he
results of Ibis economic appraisal, however, it is presently
believed thai inflation will now be the primary cause of
future cost changes rather than advancements in technical
knowledge as in the past.
Although this exercise is probably the most intensive
effort, thus far, to predict, compare, and publish the
investment and operating costs of several stack gas SC>2
removal systems, the generali/.ed results derived will still
not cover all the possible power plant, process design,
economic variations, configurations, and combinations
which will be encountered in applications of these five
processes. Hopefully, the procedures used to prepare
and present this evaluation are sufficiently compre-
hensive, visible, and modular to permit easy alteration
of results to fit the many possible specific applica-
tions. The procedures used to project and display the
process investment and operating costs are described
below and the results of analysis follow. Also, sensi-
tivity analyses have been performed to evaluate the
effect of variation from the assumed value of key
inputs on control costs.
PROCEDURES
To provide highly visible, well-defined, and readily
comparable results of the economic evaluation, four
different methods are used for displaying capital invest-
ment- estimates. Three displays are used for presenting
annual operating costs with two others used for
presenting lifetime operating costs. A regulated private
utility-type costing is used for the process evaluation
(14)'. The procedures for projecting and displaying the
results arc discussed below.
Capital Investment
The projected capital investment estimates cor-
respond to a inidwestem power plant location and a
.* -year construction schedule beginning mid-ll'72,
ending mid-1 "75, with an expected midpoint of
projccl expenditures of mid-1974. The mid-l(>74 costs
assume the following estimated Chemical Knginccring (58)
indices: equipment machinery and supports 15.1.8; con-
struction labor 177.9; overall CE plant cost index 160.2.
The projected indices correspond to annual overall escala-
tion rale for equipment machinery and supports, and
construction labor varying from 4.0% to 10.0% per year.
Each of the four'methods of projecting investment and
displaying results, and the many considerations involved are
discussed below.
1. Base case equipment list and cost tables—Major
process equipment costs which are illustrated in
tables 46-50 and incorporated into each estimate are
derived from either budgetary estimates obtained
through extensive contacts with vendors, or actual
costs for similar process equipment purchased by
TVA. Authoritative publications (4, 21, 23, 33, 34,
39) on estimating are used for costs of the minor
items such as tanks and pumps. A detailed table
describing the base case equipment and costs,
exponential factors used for size scaling, and the
source of the base case cost data is presented for each
process.Table 46, page 101 in the "Results" section of
the report illustrates the method for presenting the
base case equipment description and cost data for the
limestone slurry process. The base costs indicated in
each of the tables (46-50) correspond to the equip-
ment described. The size-cost scale factors are typical
values indicated in the literature; where more than
one scale factor is indicated, the factor from the
latest cost reference is used for scaling from the base
to other equipment sizes. Accuracy of the various
cost sources is projected below (see pp. 157-165).
Source of data Accuracy, % variance
Vendor data
Previous purchases, escalated
Publications
+20,-10
+10.-10
+30, -20
2. Total capital investment requirements-base case and
existing case process equipment and installation
79
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analysis For illustrative purposes, the process
equipment and installation analysis for Ihc base case
and existing case of each of the live processes are
shown in tables 3544. These display tables show
summarized area-by-area equipment costs along with
installation expense including costs for piping, duct-
work, concrete, excavation and site preparation,
structures, electrical equipment, instrumentation,
painting, buildings, land, and construction facilities.
Installation expenses are estimated individually based
on detailed layout drawings, itemized material take
offs and projected erection labor requirements and
arc itemized separately and displayed according to
the material and labor component of each, where
applicable. The subtotal direct investment is defined
as the sum of the above costs for each area.
To .the subtotal direct investment is added the
indirect costs for the project, which include engi-
neering design and supervision, construction field
expense, and contractor fees and contingency.
Each of these indirects is estimated as a percentage
of the direct investment as specified in the power
plant, process design, and economic premises (see
table 10). The subtotal fixed investment is defined as
the sum of the subtotal direct investment and the
indirects.
In keeping with the FPC accounting practice,
allowances are included for startup and modifications
and interest during construction at 8% per year as
discussed previously. These allowances are estimated
as a percentage of the subtotal fixed investment and
added to the subtotal fixed investment to obtain the
total capital investment.
3. Summary of estimated fixed investment -area-by-area
investment cost breakdown for each of the 16 case
variations studied-•- In addition to the more detailed
base case and existing case total capital investment
breakdown tables which are presented in the text, a
summary of estimated fixed investment is presented
in Appendix B for each of the projected case
variations. Examples can be seen in Appendix- tables
B-l, B-4, B-7, etc. The method used for projecting
these estimates is discussed in the following
paragraphs.
Excluding construction facilities for each area, the
base case direct cost shown in tables 35, 37, 39, 41,
43 are broken into the material and labor com-
ponents and adjusted as necessary to retlect required
modifications in process design for the case varia-
tions. For example, indirect steam reheat investment
costs arc replaced with direct oil-fired reheat invest-
ment costs for existing coal-fired and all oil-fired
units requiring stack gas reheat, and investment costs
for an additional scrubbing bed are included for
limestone scrubbing systems which do not utilize a
particulale scrubber (existing coal-fired units and new
and existing oil-fired units). Modifications are
included in the amount of ductwork provided for all
existing units.
The labor portion of the area investments for
existing units is estimated by multiplying the pro-
jected labor requirements for a new unit of equiva-
lent design by a retrofit difficulty factor of 1.25. This
factor corresponds to an assumed labor efficiency of
80% for retrofit installations. The adjusted subtotal
area investment is then scaled exponentially
according to the relative throughput, using a
weighted average scaling exponent calculated from
the base case investment breakdown. Flue gas
processing areas are scaled on the basis of relative gas
throughput whereas byproduct processing areas are
scaled on the basis of relative sulfur throughput.
Table 25 shows the relative quantities of gas and
sulfur which must be processed for each of the case
variations, in comparison to the base case quantities.
Once these area investments are scaled and construc-
tion facilities are reincorporated into the estimate,
the subtotal direct, subtotal fixed, and total capital
investment are determined by the same procedure
described above for the base case investment.
Table 25. Relative Quantities of Gas
and Sulfur to be Processed in Comparison
with the Base Case Quantities
Case
Coal-fired power unit
90% S02 removal
200 MW N 3.5% S
200 MW E 3.5% S
500MWE3.5%S
500 MW N 2.0% S
500MWN3.5%S
500 MW N 5.0% S
1,OOOMWE3.5%S
I,OOOMWN3.5%S
80% SO2 removal
500MWN3.5%S
, Oil-fired power unit
90%SO2 removal
200 MW N 2.5% S
500 MWN 1.0% S
500 MW N 2.5% S
500 MW N 4.0% S
500 MW E 2.5% S
1 ,000 MW N 2.5% S
Relative throughput rate, %
Gas
40.89
42.22
102.22
100.00
. 100.00
100.00
200.0G
193.33
100.00
34.44
84.23
84.23
84.23
86.00
162.89
Sulfur removed
40.89
42.22
102.22
57.14
iOO.OO
142.86
200.00
i93.33
88. 8l)
21.81
21.33
53.33
85.33
54.52
103. SO
80
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As mi illustralion of the use of this method, the
direct cost for the raw material handling area for the
limestone slurry process from table 35 is $419,000,
of which $198,000 is material costs, and $221,000 is
labor. Assuming a retrofit difficulty factor of 1.25,
the total area investment for an existing unit of
similar capacity is $198,000 plus 1.25 ($221,000), or
$474,000. Using a weighted average scaling exponent
of 0.65 for the limestone process raw material
handling area and a relative limestone throughput
rate of 42.22% for a 200-MW existing power unit, as
indicated in table 25, the projected raw material
handling area costs for this unit is $271,000 as shown
in Appendix table B-4.
4. Total capital investment requirements--tabular invest-
ment results of the 16 case variations- For each of
the live processes, a summary table is presented in
(he text giving (lie projected total capital investment
requirements for Ihe case variations, expressed as
total $ and $/kW as illustrated in tables 27-31.
Operating Costs
Annual and lifetime operating costs for each process are
presented on a regulated economics basis. The basic premise
of regulated economics provides that the power company
will be permitted to charge electricity customers suffi-
ciently to earn up to a prescribed return on the base
investment. Since electrical power producers rarely
compete with each other in a given geographical area,
regulation of power rates is necessary to prohibit unreason-
able profits, but at the same time assure an adequate return
on investment sufficient to attract capital for expansion to
meet growing demand. In the United States, regulation is
usually the responsibility of state or local agencies with the
FPC responsible for setting guidelines for accounting
procedures and for rates on interstate transactions (14).
If a power company provides all or a portion of the
investment for pollution abatement facilities, its investment
will almost certainly be merged with the total power plant
investment as is presently done with dust removal equip-
ment and, therefore, increase the "rate base" on which the
utility is allowed to earn at the rate set by the regulatory
commission. Thus, a return on equity or profit must be
included in any process evaluation under regulated eco-
nomics; it is the "cost of investment money" as any other
operating cost item such as fuel or labor.
The regulated "cost of investment money" is added to
operating costs as part of the capital charges applied (see
"Power Plant, Process Design, and Economic Premises").
In the projection of annual operating costs, capital
charges are applied as average annual costs as defined in the
economic premises. In Ihe lifetime operating cost projec-
tions, however, declining balance capital charges based on
the undepreciated investment are applied, similar to the
actual method used in regulated industry. The methods for
presenting annual and lifetime operating costs for the five
processes are discussed below.
Annual Operating Cost
Annual operating costs are estimated under regulated
economics assuming an overall cost of money of 10%. The
operating life of the S02 control facilities is designed to be
the same as the remaining life of the power plant. All
tabulated results and operating cost tables correspond to
mid-1975 costs, an annual operation of 7,000 hours, and
straight line depreciation over the estimated power plant
life. Operating costs for disposal of fly ash are not included
in the annual operating cost estimates nor is product
revenue reflected. To provide visibility of the results, the
projected annual operating costs are presented in three
manners. The method of projecting each of these operating
cost estimates follows.
1. Detailed area-by-area base case and existing case
operating cost breakdown analyses—For illustrative
purposes, base case and existing case operating cost
estimates for the five processes are presented in tables
59-68. Each of the operating cost estimates are
subdivided by operating area function and projected
according to the direct and indirect cost components.
Included as direct costs are: delivered raw materials,
operating labor and supervision, utilities, main-
tenance, and analyses. The indirect costs include
capital charges, and plant and administrative
overhead.
Direct costs-The raw material costs given in the
power plant, process design, and economic premises
are projected 1975 delivered costs to a Chicago
power plant location, and labor costs are projected
1975 midwestern rates. The projected costs of
utilities to the process depend on quantity, source,
and accounting practice. The values used are fully
allocated costs, as if purchased from an inde-
pendent source with full capital recovery provided
for. As quantities increase, the unit cost of utili-
ties is decreased to show some economy of scale.
For those cases where a heat credit is taken for
export of steam or heated boiler feed water to
the power unit system, the value of the credit is
based only on the equivalent fuel cost. For
existing power units, it is assumed that steam is
not available from the power plant.
The quantities of raw materials and utilities
required for each process, except for electricity, are
shown on the material balance for the base case
process design. Electricity requirements are projected
from required motor horsepower or known
81
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equivalent kilowatt usage as defined in the base case
equipment description.
Operating labor and supervision for each process is
estimated considering the amount of process equip-
ment in each area and the difficulty of'operation.
Analysis labor estimates are based on the quantities
of materials which must be analyzed to maintain
quality control. Maintenance is estimated as a percent
of the subtotal direct investment, as shown in table
13. The maintenance percentages projected for each
of the five processes are based on individual estimates
of maintenance requirements for the various
processing steps from pilot plants and systems
already in operation.
Indirect costs-The capital charges included in the
indirect operating costs are applied as average capital
charges, including depreciation, interim replacements,
insurance, cost of capital and taxes, and considering
the remaining life of the power plant. Plant overhead
is estimated as 20% of the subtotal conversion costs,
•which includes the projected costs for labor, utilities,
maintenance, and analyses. Administrative overhead
is estimated as 10% of operating labor for the
throwaway processes. For the product-producing
processes, administrative and marketing overhead is
estimated individually for each process on the basis
of an estimated relative difficulty in marketing the
various products.
The detailed operating cost breakdown tables
(59-68) are presented in the text in a modular fashion
so that all of the direct or indirect cost components
are shown, according to the processing area to which
they are attributed. The equivalent total unit
operating cost is expressed as dollars per ton coal
burned, mills per kilowatthour, cents per million Btu
heat input, and dollars per ton sulfur removed. The
distribution of direct and indirect operating costs is
given, expressed as a percent of the total annual
operating cost.
2. Total projected average annual operating cost --
Summary tables showing the projected breakdown of
the average annual operating cost are presented in
Appendix B for 16 case variations studied on each
process. Examples can be seen in Appendix tables
B-2, B-5, B-8, etc. These tables summarize the overall
process costs and present equivalent unit operating
costs expressed as dollars per ton coal or barrel oil
burned, mills per kilowatthour, cents per million Btu
heat input, and dollars per ton sulfur removed. The
distribution of operating cost components are given,
expressed as a percent of the total annual operating
cost. Working capital requirements for each of the 16
case variations arc calculated based on the projected
annual operating cost breakdown and shown on the
operating cost tables presented in the appendix for
each process. For the present study, working capital
is defined as the total of 3 weeks of raw material
costs, 7 weeks of direct operating costs, and 7 weeks
of overhead costs as discussed on page 29.
Raw materials and utilities for the case variations
are scaled from the requirements indicated on the
detailed base case and existing case operating cost
breakdown analyses (tables 59-68). Utilities such as
humidification water, reheat energy, and electricity
for the fan are scaled proportional to the relative gas
rate for the many case variations; whereas, raw
materials and utilities such as absorbent, and elec-
tricity for the sulfur processing areas, are scaled
proportional to the relative sulfur rate for the various
cases. Annual costs for raw materials and utilities are
then calculated by applying the unit costs to the
annual usage rates.
3. Tabular summary of projected annual operating
costs—For the 16 case variations given in the text a
tabular summary of projected annual operating costs
is given for each process, as illustrated in tables
51-55, with projected costs expressed in total dollars
and-equivalent unit costs.
Lifetime Operating Cost
Because of the typical declining load of most power
units over their life, lifetime operating costs are better
measures of the overall process costs than are annual
operating costs. Since annual operating costs vary each year
as the rate base declines due to depreciation "write off
(the cost of money and income taxes are applied to
undepreciated portion of investment) and with any changes
in on-stream time of the power unit, it is desirable to have a
year-to-year tabulation of annual operating costs and
cumulative lifetime operating costs for any given case. For
the most meaningful comparison which recognizes the time
value of money, the declining annual operating costs for
each process over the life of the plant should be discounted
at the cost of money (10% for this study) to the initial year
of operation. The total of these costs can be compared
directly or can be converted to equivalent unit costs for
comparison with the premium expected for low-sulfur
fuels.
For each of the 16 case variations of the five processes
evaluated, lifetime economics are projected corresponding
to the declining operating profile established earlier.
Examples can be seen in the lifetime cost projections given
in Appendix tables B-3, B-6, B-9, etc. Year-by-year
operating costs included in the lifetime cost projections are
calculated by computer in the same manner as annual
operating costs, with the exception that capital charges are
based on the declining undepreciated investment. Since the
82
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regulated rate of investment profitability is included in the
year-by-year projections of operating costs, any revenue
received from sale of byproducts can be applied toward
reducing these yearly costs. Therefore, the net increase or
decrease in the cost of power to the consumer for each year
of the power plant life is defined as the corresponding
operating cost less the revenue resulting from sale of
byproduct. For the limestone and lime processes which do
not produce a salable product, the net annual increase or
decrease in cost of power is equal to the total operating
cost. For the other processes, however, the net annual
increase or decrease in cost of power is less than the total
operating cost by an amount equal to the revenue from the
sale of byproduct acid or sulfur. Results of the lifetime
economic projections are presented in the following two
fashions:
1. Computer printouts of the detailed year-by-year cash
flow analyses are given in Appendix B for each of the
16 case variations for each process. Examples can be
seen in Appendix tables B-3, B-6, H-9, etc.
2. Tables 70-74 giving the summarized results are
presented in the text.
In each presentation, the lifetime economic results are
given for each process as both cumulative actual and
cumulative discounted costs (discounted at the cost of
money to the initial year). The results are also given as the
lifetime average increase or decrease and the levelized
increase or decrease in unit operating cost expressed as
dollars per ton coal or barrels of oil burned, mills per
killowatthour, cents per million Btu heat input, and dollars
per ton sulfur removed. As the name implies, the lifetime
average increase or decrease in unit operating cost is simply
an average unit operating cost obtained by dividing the
lifetime operating cost by the lifetime number of units,
such as tons of coal burned. Levelized unit operating costs
are obtained by dividing the discounted process costs over
the life of the power unit by the discounted number of
units. They are the more significant costs because they
include the effect of time on both money, and units of
measure.
SENSITIVITY ANALYSES
Since many components of the investment and operating
cost estimates can vary, the sensitivity of operating cost
results to variations in several of the key economic
parameters is evaluated. Table 26 identifies the parameters
which are varied and the range of values which is studied.
Each range is selected corresponding to deviations in design
or costs which can be encountered. As an illustration,
investment variations ranging from 70% to 130% of the
projected investment are selected to indicate the effect of
inaccuracies on overall orocess costs. Limestone and lime
price variations illustrate the effect of rural or metropolitan
plant location and corresponding low and high cost
limestone or lime on overall process costs. Other variations
such as antioxidant utilization and MgO or catalyst losses
are selected to show the effect of design and operating
variations of particular processes on projected costs. The
effects of these variations on the projected annual and
lifetime operating costs are presented in figures 51-67 and
75-93 of the results.
RESULTS
Capital Investment
Summaries of the case variations for each process are
shown in Appendix B, and tabulated totals are presented
below in tables 27 through 31.
For the comparisons to be fully understood, a review of
the premises should be undertaken parallel to careful
examination of the results. Overall, the fixed investment
costs for four of the processes are relatively close with lime
slurry investment requirements lowest for new coal-fired
units and limestone slurry investment lowest for new
oil-fired and existing coal-fired units. These results depend
heavily on the predefined number and types of scrubbers
specified for the various duties. The limestone, magnesia,
and sodium processes require only one scrubber stage for
S02 removal, whereas the lime process requires two. When
particulate removal is not required, the lime process suffers
in comparison to the other processes. Selection of scrubber
types other than Venturis for the lime process might
eliminate thfs disparity.
As can be seen from the display tabulations, the
investment requirements for the five process cases cover a
wide range. The projected total investments for the
limestone slurry process range from $8,263,000 ($41.3/kW)
for a new 200-MW, 2.5% S oil-fired unit to $37,725,000
($37.7/kW) for a new 1,000-MW, 3.5% S coal-fired unit;
investments for the lime slurry process range from
$9,482,000 ($47.4/kW) for a new 200-MW, 2.5% S oil-fired
unit to $38,133,000 ($38.1/kW) for an existing 1,000-MW,
3.5% S coal-fired unit.
With some important exceptions, the investment require-
ments of the product-producing processes are generally
greater than those of either the limestone or lime throw-
away processes. Investments for the magnesia slurry -
regeneration process, however, are very competitive with
lime and limestone, ranging from $8,861,000 ($44.3/kW)
for a new 200-MW, 2.5% S oil-fired unit to $38,865,000
($38.9/kW) for a new 1,000-MW, 3.5% S coal-fired unit;
those for the sodium solution - S02 reduction process range
from $10,324,000 ($51.6/kW) for a new 200-MW, 2.5% S
oil-fired unit to $47,721,000 ($47.7/kW) for an existing
83
-------
Table 26. Sensitivity Variations Studied in the Economic Cost Projections
Item
Investment
Years remaining
life
On-stream time
Process
Five processes
Limestone slurry process
(existing unit)
Five processes
Annual operating cost
Range of
Base value variations
7, 000.hr/yr 0-7,000
Lifetime operating
Base value
100% of projected
investment
200 MW-20 yr
500andl,OOOMW-25yr
Declining on-stream
profile (see table 3)
cost
Range of variations
70%-130%
15, 20, 25 yr
Constant on-stream
time, 5, 000 and
7,000 hr/yr over
life of plant
Labor costs
Cost of money
Raw material price
consumption
Waste disposal
High-low
projection
Product revenue
Magnesis slurry -
regeneration process
Limestone slurry process
and sodium solution -
SO? reduction process
100% of estimated
labor requirement
100%-200%
Annual escalation rate,
0%/yr
0%-7.5%
Five processes
e- Limestone slurry process
lime slurry process
Magnesia slurry -
regeneration process
Sodium solution - S02
reduction process
Catalytic oxidation
processes
Limestone slurry process
Limestone slurry process
Magnesia slurry -
regeneration process
Sodium solution - S02
reduction process
Catalytic oxidation
process
Average capital charges, \2%-24%
14.9% of total investment
Limestone price, S4/ton S2-S8
Lime price, S20.50-S26.00/ ton $1 8-S34
depending on plant size
MgO losses, 1 .8%/cycle 1 .8%-20%
Antioxidant utilization, 0%-100%
design rate
Catalyst losses, 10%-60%
10%/yr
Waste disposal cost, S2-S8
$4/ton of wet solids
— —
_ _
— _
_ _
Cost of investment
money, 10%
—
—
-
.
—
—
-
Raw material cost,
$4/ton
Waste disposal cost,
$4/ton of wet solids
Sulfuric acid
revenue, $8/ton
Sulfur revenue,
S25/short ton
Sulfuric acid
revenue, $6/ton
8%-12%
—
—
-
—
—
—
S2-S8
up to $8
SO-S32
S15-S40
SO-S30
-------
Table 27. Limestone Slurry Process
Total Capital Investment Summary3 _ ___
Case Investment
Coal-fired power uiut _ $ $/kW
90% S02 removal; on-site solids disposal
200MWN3.5%S 30 yr 13.031,000 65.2
200 MW E 3.5% S 20 yr 11,344,000 56.7
500MWE3.5%S 25 yr 23,088,000 46.2
500MWN2.0%S 30 yr 22,600,000 45.2
500MWN3.5%S.30yr
25,163,000 50.3
500 MW N 5.0% S 30 yr 27,343,000 54.7
!,OOOMWE3.5%S 25 yr 35,133,000 35.1
1,000 MWN 3.5%S 30 yr 37,725,000 37.7
80% S02 removal; on-site solids disposal
500 MW N 3.5% S 30 yr 24,267,000 48.5
907" S02 removal; off-site solids disposal
500MWN3.5%S 30 yr 20,532,000 41.1
90% S02 removal; on-site solids disposal
(existing unit requiring parliculatc
scrubber)
500 MW E 3.5% S 25 yr 29,996,000 60.0
jOjUfiredjJOwer unit
90% S02 removal; on-site solids disposal
200 MW N 2.5% S 30 yr
500 MW N 1.0% S 30 yr
500MWN2.5%S 30 yr
500MWN4.0%S 30 yr
500MWE2.5%S 25 yr
! ,000 MW N 2.5% S 30 yr
"Stack B;IS reheat to 175°l;.
On-site disposal pond located I mile from power plant.
Midwesl plant location represents project beginning mid-1972,
ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay
incentive not considered.
8,263,000 41.3
12,935,000 25.9
15,473,000
17,481,000
18,657,000
23,384,000
30.9
35.0
37.3
23.4
Table 28. Lime Slurry Process
Total Capital Investment Summary3
Investment
Case
Coal-fired power unit
$/kW
90% S02 removal; on-site solids disposal
200MWN3.5%S 30 yr
200 MW E 3.5% S 20 yr
500MWE3.5%S 25 yr
500MWN2.0%S 30 yr
500MWN3.5%S 30 yr
500MWN5.0%S 30 yr
1,OOOMWE3.5%S 25 yr
1,OOOMWN3.5%S 30 yr
80% S02 removal; on-site solids disposal
500 MWN 3.5%S 30 yr
90% SOj removal; off-site solids disposal
500MWN3.5%S 30 yr
90% S02 removal; on-site solids disposal
(existing unit requiring particulate
scrubber)
500 MW E 3.5% S 25 yr
Oil-fired power unit
90% S02 removal; on-site solids disposal
200MWN2.5%S 30 yr
500 MWN 1.0% S 30 yr
500MWN2.5%S 30 yr
500 MWN 4.0%S 30yr
500 MW E 2.5% S 25 yr
1,000 MWN 2.5% S 30 yr
11,749,000 58.7
13,036,000 65.2
26,027,000 52.1
20,232,000 40.5
22,422,000 44.8
24,272,000 48.5
38,133,000 38.1
32,765,000 32.8
21,586,000 43.2
18,323,000 36.6
26,090,000 52.2
9,482,000 47.4
15,961,000 31.9
18,148,000 36.3
19,861,000 39.7
21,817,000 43.6
26,341,000 26.3
"Stack gas reheat to 175°K
On-site disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972,
ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay
incentive not considered.
i,000-MW, 3.5% S coal-fired unit. For the catalytic
oxidation process, the projected investments range from
$13,()()»>,000 ($(«5.3/kW) for a new 200-MW, 2.5% S
oil-fired unil to $69,889,000 ($69.9/kW) for a new
1,000-MW, 3.5%S coal-fired unil.
The summari/.ed investment results for the five processes
are shown in figures 33 through 37 which indicate the
effect of power unit size, and sulfur content of fuel on the
total fixed investment for units of different fuel type and
status (new or existing). Again caution should be exercised
in comparing results for new and existing coal-tired units,
since existing coal-fired units are assumed to be already
equipped with 98.7% efficient electrostatic precipilators for
collecting fly ash. The effects of similar variations on unit
investment ($/kW) are given in figures 38 through 41.
Another point of interest is the difference in investment
requirements of the various processes for 80% versus 90%
S02 removal. For each of the processes excluding catalytic
oxidation, investment and operating cost projections for
80% S02 removal are given, for comparison with the 90%
S02 removal base case projection. For the catalytic
oxidation process, it is reported to be difficult and
impractical to limit S02 removal to 80%, since it is too
difficult to design the converters for only 80% efficient
conversion of S02 to SO3. Therefore, an 80% S02 removal
case is not evaluated for the catalytic oxidation process.
Table 32 gives a comparison of the investment requirements
for the other four processes.
An important consideration for existing power units is
the assumption for this study that these units are already
85
-------
Table 29. Magnesia Slurry - Regeneration Process
Total Capital Investment Summary3
Case Investment
Coal-fired power unit
90% S02 removal
200 MWN 3.5%S 30yr
200MWE3.5%S 20 yr
500MWE3.5%S 25 yr
500 MWN 2.0% S 30 yr
500 MW N 3.5% S 30 yr
500 MWN 5.0% S 30 yr
1,OOOMWE3.5%S 25 yr
1,000 MWN 3.5% S 30 yr
80%S02 removal
Table 30. Sodium Solution - S02 Reduction Process
Total Capital Investment Summary3
500 MW N 3.5% S 30 yr
90% S02 removal
(existing unit requiring particulate
scrubber)
500MWE3.5%S 25 yr
power unit
90% SO2 removal
200MWN2.5%S 30 yr
500 MWN 1.0% S 30 yr
500 MW N 2.5% S 30 yr
500 MWN 4.0% S 30 yr
500MWE2.5%S 25 yr
1 ,000 MWN 2.5% S 30 yr
$
14,139,000 70.7
14,372,000 71.9
26,026,000 52.1
22,958,000 45.9
26,406,000 52.8
29,355,000 58.7
38,717,000 38.7
38,865,000 38.9
25,568,000 51.1
32,213,000 64.4
8,861,000 44.3
12,695,000 25.4
16,080,000 32.2
18,765,000 37.5
20,376,000 40.8
23,656,000 23.7
"Stack gas reheat to 175°F.
Midwest plant location represents project beginning mid-1972,
ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay
incentive not considered.
Case
Coal-fired power unit
90% S02 removal
200 MWN 3.5% S 30 yr
200MWE3.5%S 20 yr
500MWE3.5%S 25 yr
500 MWN 2.0% S 30yr
500MWN 3.5%S 30yr
500MWN5.0%S 30 yr
1,OOOMWE3.5%S 25 yr
1,000 MWN 3.5% S 30 yr
80% S02 removal
500 MW N 3.5% S 30 yr
90%S02 removal
(existing unit requiring particulate
scrubber)
500MWE3.5%S 25 yr
Oil-fired power .unit.,..
90%S02 removal
200 MW N 2.5% S 30 yr
500MWN1.0%S 30 yr
500 MW N 2.5% S 30 yr
500MWN4.0%S 30yr
500MWE2.5%S 25 yr
l,OOOMWN2.5%S30yr
Investment
$/kW
16,198,000 81.0
17,149,000 85.7
31,208,000 62.4
26,706,000 53.4
30,491,000 61.0
33,709,000 67.4
47,721,000 47.7
45,832,000 45.8
29,127,000 58.3
37,957,000 75.9
10,324,000 51.6
15,198,000 30.4
18,949,000 37.9
21,893,000 43.8
24,445,000 48.9
28,765,000 28.8
aStack gas reheat to 175*F.
Midwest plant location represents project beginning mid-1972,
ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay
incentive not considered.
capable of meeting EPA particulate emission standards.
Since some units may not yet be equipped with electro-
static precipitators to maintain these emission levels, the
costs for an existing unit requiring installation of particu-
!ate control facilities are also projected. Table 33 gives a
comparison of the investment requirement for existing
units requiring the additional facilities with those which are
already capable of meeting the EPA particulate emission
standard.
The most noticeable effect which may be seen from this
table is the very small difference ,in the lime process
investment for the two variations considered. Since a
two-stage scrubbing system is provided for the lime process
regardless of the particulate removal requirements, this
result is inherent with the S02 removal equipment specified
for this'process.
The comparison between investment requirements for
limestone and lime slurry processes designed for off-site and
on-site waste solids disposal is shown in table 34. Invest-
ments for off-site disposal are approximately 18% lower
than corresponding on-site disposal investments, primarily
because of the savings in the cost of a waste disposal pond.
Detailed base case and existing case area equipment and
installation breakdowns which give component costs for the
five processes are shown in tables 35 through 44. In
comparing the base case area equipment and installation
breakdowns for the five processes, the predominant cost
areas can be readily identified. Table 45 shows the
contribution of the major cost areas to the total capital
investment for each of the five processes. However, it
should again be noted that process differences and the total
projected investment must be given careful consideration in
comparing the results. For the limestone and lime slurry
processes, the particulate removal, S02 absorption and
waste disposal areas require the greatest investment. The
predominant cost areas of the magnesia slurry-
86
-------
Table 31. Catalytic Oxidation Process
Total Capital Jnvestmenj^ummary3
Case Investment
Coal-fired power unit $ $/kW
90%S()2 removal
200 MWN 3.5% S 30 yr 19,537,00097.7
200MWE3.5%S 20 yr 17,735,000 88.7
500 MW E 3.5% S 25 yr 37,907,000 75.8
. 500 MW N 2.0% S 30 yr 42,520,000 85.0
500 MW N 3.5% S 30 yr . 42,736.000 85.5
500 MWN 5.0% S 30 yr . 42,928.000 85»
1,000 MWK3.5%S 25 yr 62,913,000 6.1.1)
1,000 MWN 3.5%S 30 yr 69,889.000 <,<><>
0% S()2 removal
200 MWN 2.5% S 30 yr
500 MW N 1.0% S 30 yr
500 MWN 2.5% S 30 yr
500 MW N 4.0% S 30 yr
500 MW E 2.5% S 25 yr
1,000 MW N 2.5% S 30 yr
43,810,000 87.0
13,069,000 65.3
28,067,000 5(..l
28,277,000 56.()
28,449,000 5(>.9
32,824,000 65.6
46.356,000 46.4
aMidwest plant location represents project beginning mid-1972,
ending mid-1975. Average cost basis for scaling mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay
incentive not considered.
Table 32. Comparison of Investment
Requirements for SOj Removal
___P£°cesses_At 90% and 80% SO2 Removal
Investment
Projected total savings
capital investment resulting from
requirements, $ design for );0%
500 MW new 3.5% S S02 removal
coal-fired units compared
90%SO2 80%S(K to')0%
Process removal _ removal $ %
LimesTonVslurry 25,163,000 24,267,000 896,000 3.6
Lime slurry 22,422,000 21,586,000 836,000 3.7
Magnesia slurry -
regeneration 26,406,000 25,568,000 838,000 3.2
Sodium solution -
SO2 reduction 30,4<> 1,000 29,127,000 I,3o4,000 4.5
regeneration process are the parliculate removal and SO2
absorption areas and the sulfuric acid processing area. For
the sodium solution - SO2 reduction process, the pre-
Table 33. Investment Requirements for SOj Removal
Installations on Existing Power Units Requiring
Additional Facilities for Removal
_ of Part'u:u!ates Comparison with Standard3
Projected total capital
investment requirements, $
500 MW, existing 3.5% S
coal-fired units
Requiring Difference in
additional projected
particulate investment
removal requirements
Process facilities Standard11 $ _%_
I.Milestone silirry :.l>,996.000 23,088,6o6 6,908,000 29.9
Lime slurry 26,090,000 26,027,000 63,000 0.2
Magnesia slurry -
regeneration 32,213,000 26,026,000 6,187,000 23.8
Sodium solution -
S()2 reduction 37,957,000 31,208,000 6,749,000 21.6
Catalytic
oxidation 43,816.000 37,907,000 5,909.000 15.6
"Standard case assumes that the existing electrostatic precipitator is
adequate for existing units.
Table 34. Comparison of Investment Requirements for
Limestone and Lime S02 Removal Processes Designed for
On-site and Off-site Waste Solids Disposal
Process
On-site
waste
solids
disposal
Off-site
waste
solids
disposal
Difference in
projected
investment
requirements
$0i.
to
Limestone slurry 25,163,000 20,532,0004,631,000 18.4
Lime slurry 22,422,000 18,323,000 4,099,000 18.3
dominant cost areas are the particulate removal, S0a
absorption, the S02 regeneration, and reduction areas. In
the catalytic oxidation process, the particulate removal,
S02 conversion, and sulfuric acid processing sections are
the predominant cost areas.
In making an overall comparison of processes based on
total investment, it should be noted that only the net
difference in investment costs is seen. The difference in
investment requirements between processes or between new
and existing units can best be analyzed by looking at
specific areas as shown in the base case and existing case
summarized area equipment and installation breakdowns
(tables 35-44). As an illustration using tables 35 and 36 for
the limestone slurry process, a comparison of the overall
investment indicates that costs for an existing power unit
are less than for a new unit ($23,088,000 vs. $25,163,000).
Comparison of the area costs, however, show similar areas
to generally be more expensive for existing units than for
new units. For example, direct investment costs for the
87
-------
X
oc
Table 35. Limestone Slurry Process
Total Capital Investment Requirements
Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Raw
materials
handling
Direct Coat
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation,
railroads, roads, and pond
Structural
Material
Labor
Electrical
Material
Labor
Instrument*
Material
Labor
Paint and miscellaneous
Material
Labor
Build inp
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Coin
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal Tued investment
Allowance (at startup and modifications
Interest during construction
Total capital investment
Percent of total capital investment
103
29
1
1
15
8
14
81
_
11
10
39
S3
8
4
1
5
_
_
6
_
419
38
46
21
42
566
45
45
656
2.6
Ferd
preparation
379
57
14
28
6
6
7
38
-
_
-
58
92
49
25
1
6
65
67
1
_
899
81
99
45
90
1,214
97
97
1,408
5.6
Particulatc
scrubbing
1,126
114
102
95
733
582
12
48
_
84
38
61
73
77
38
3
15
-
_
2
_
3,203
288
352
160
320
4323
346.
346
5,015
19.9
SO,
scrubbing
2.254
335
341
313
377
418
24
81
-.
85
41
101
112
162
81
3
15
-
_
2
_
4,745
427
522
137
474
6,405
513
513
7,431
29.5
Reheat
410
80
11
20
-
-
_
_
-
_
_
1
1
21
11
_
1
_
_
_
_
556
50
61
28
56
751
60
60
871
3.5
Fans
285
34
_
_
146
S3
4
21
-
_
_
133
• 155
15
7
_
1
-
_
_
_
854
77
94
43
85
1,153
92
92
1,337
5.3
Solids
disposal Utilities
60
3
86
78
-
-
1
5
3.028
_
2
50
184
11
5
2
13
-
_
395
_
3,923
353
432
1%
392
5,296
424
424
6,144
24.4
-
-
6
11
_
-
_
-
-
_
_
10
10
16
8
3
3
-
_
_
_
67
6
8
3
7
91
7
7
105
0.4
Construction
facilities
Services 5%
107
25
-
_
-•
-
_
-
339
_
-
_
_
_
_
_
_
113
40
14
_
638
57
70
32
64
861
69
69
9*9
4.0
-
-
-
-
-
-
_
-
-
_
_
_
-
_
_
_
-
-
-
_
765
765
69
84
38
77
1,033
82
82
1,197
4.8
Percent of
direct
Total investment
4,724
677
561
546
1,277
1,067
62
274
3.367
180
91
453
710
359
179
13
59
178
107
420
765
16,069
1,446
1,768
803
1,607
21,693
1,735
1,735
25,163
29.4
4.2
3.5
3.4
7.9
6.6
0.4
1.7
21.0
1.1
0.6
2.8
4.4
2.2
1.1
0.1
0.4
1.1
0.7
2.6
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
Percent of
total capital
investment
18.8
2.7
2.2
2.2
5.1
4.2
0.3
1.1
13.4
0.7
0.4
1.8
2.8
1.4
0.7
0.1
0.2
0.7
0.4
1.7
3.0
63.9
5.7
7.0
3.2
6.4
86.2
6.9
6.9
100.0
"Basis:
500-MW new coal-fired power unit, 3.5% S in fuel; 90% SOj removal; on-stle solids disposal.
Stack gas reheat to 175 F by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table 36. Limestone Slurry Process
Total Capital Investment Requirements
Existing Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Direct Com
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and rapports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation.
raOfoads, roads, and pond
Structural
Material
Labor
Electrical
Material
Labor -
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Coia
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest ™**ing constrt'cuoo
Total capital investment
Percent of total capital investment
Raw
materials
handling
105
37
1
1
IS
10
14
103
-
11
13
40
105
8
5
1
7
_
_
6
-
482
49
63
34
53
681
54
54
789
3.4
Construction
Feed
preparation
390
72
14
36
6
8
7
48
-
-
_
59
117
50
32
1
8
66
85
• 1
-
1,000
100
130
70
110
1,410
113
113
1,636
7.1
SOj
scrubbing
2,510
426
353
403
363
387
24
103
-
86
52
102
142
165
103
3
19
—
_
2
-
5,243
524
682
367
577
7,393
592
592
8477
37.1
Reheat
186
23
9
27
_
_
_
1
—
_
_
8
18
35
16
—
_
-
_
-
—
323
32
42
22
36
455
36
36
527
2.3
Fans
450
84
-
-
388
386
7
39
-
-
_
135
196
15
9
-
1
-
_
-
—
1.710
171
272
120
188
2,411
193
193
2,797
12.1
Solids
disposal
67
4
87
99
-
_
1
6
2,734
_
3
51
233
11
6
2
16
_
_
291
_
3,611
361
469
253
397
5,091
407
407
5,905
25.6
Utilities
31
57
12
19
-
_
1
7
46
_
_
52
67
20
12
4
7
_
_
-
-
335
34
44
23
37
473
38
38
549
2.4
Services
108
32
-
-
-
_
_
_
422
_
_
_
-
- .
_
_
_
114
50
14
_
740
74
96
52
81
1,043
83
83
1,209
5.2
facilities
5%
-
_
-
-
-
_
-
_
-
-
_
_
-
-
_
-
_
_
_
-
672
672
67
87
47
74
947
76
76
1,099
4.8
Total
3,847
735
476
585
772
791
54
307
3,202
97
68
447
878
304
183
11
58
ISO
135
314
672
14,116
1,412
1335
988
1453
19,904
1492
1492
23X«8
Percent of
direct
investment
27.2
5.2
3.4
4.1
5.5
5.6
0.4
2.2
22.7
0.7
0.5
3.2
6.2
2.1
1.3
0.1
0.4
1.3
0.9
2.2
4.8
100.0
10.0
13.0
7.0
11.0
141.0
11.3
11.3
163.6
Percent of
total capital
investment
16.7
3.2
2.1
2.5
3.3
3.4
0.2
1.3
13.9
0.4
0.3
1.9
3.8
1.3
0.8
0.1
0.2
0.8
0.6
1.4
2.9
61.1
6.1
8.0
4.3
6.7
86.2
6.9
6.9
100.0
00
>Basb:
500-MW existing coal-fired power unit, 3.5% S in fuel; 90% SOj removal; cm-site sotidi disposal.
Stark gas reheat to 175 F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash exclude*.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
vO
o
Table 37. Lime Slurry Process
Total Capital Investment Requirements
Base Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Raw
materials F--d
handling preparation
Direct Coin
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and tuppotU
Material
Labor
Concrete foundations
Material
Labor
Excavation site preparation
raflroadf. roads, and pond
Structural.
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Coin
Engineering design and supervision
Construction field expense
Contractor, fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction
Trial capital investment
Percent of total capital investment
•Basis:
3SO
50
-
-
9
$
10
46
-
30
45
96
IDS
24
12
1
7
_
_
1
-
795
72
87
40
79
1,073
86
86
1.245
5.5
145
14
10
10
2
1
3
12
-
_
_
41
47
66
33
_
3
_
_
_
-
387
35
43
19
39
523
42
42
607
2.7
500-MW new coal-tired power unit, 3.5% S in fuel; 90% SO, i
Particulate-
SOj
scrubbing
1,016
380
363
338
785
644
12
47
_
84
39
48
55
119
60
3
23
„
_
1
_
4,017
361
442
201
402
5.423
434
434
6,291
28.1
SOj
scrubbing
1,076
380
363
341
175
196
13
47
-
84
39
89
101
148
74
3
23
_
_
1
-
3,153
284
347
158
315
4,257
340
340
4,937
22.0
Reheat
410
80
7
12
-
-
_
_
_
_
_
1
1
21
10
_
_
_
_
_
_
542
49
60
27
54
732
58
58
848
3.8
Fans
285
34
-
_
153
54
4
21
_
_
_
88
100
18
9
_
1
_
_
_
_
767
69
84
38
77
1,035
83
83
1,201
5.4
Solids
disposal Utilities
11
2
80
92
-
-
_
1
2,686
_
2
60
68
7
3
1
5
_
„
338
3456
302
369
168
336
4,531
362
362
5,255
23.4
_
_
6
11
-
-
_
_
_
_
_
10
10
16
8
3
3
_
_
_
-
67
6
7
3
7
90
7
7
104
0.5
Construction
Services facilities
82
25
-
-
-
-
_
_
278
_
_
_
-
-
_
_
113
40
14
-
552
50
61
28
55
746
60
60
866
3.8
-
-
-
-
-
_
_
_
—
_
_
_
-
_
-
_
_
_
_
_
682
682
61
75
34
68
920
74
74
1,068
4.8
Percent of
direct
Total investment
3,375
965
829
804
UM
900
42
174
2,964
198
125
433
491
419
209
11
65
113
40
355
682
14318
U89
1,575
716
1,432
19,330
1446
1.546
22,422
23.6
6.7
5.8
5.6
7.8
6.3
0.3
1.2
20.7
1.4
0.9
3.0
3.4
2.9
1.5
0.1
0.4
0.8
0.3
2.5
4.8
100.0
9.0
11.0
S.O
10.0
135.0
10.8
10.8
156.6
Percent of
total capital
investment
15.0
4.3
3.7
3.6
S.O
4.0
0.2
0.8
13.2
0.9
0.6
1.9
2.2
1.9
0.9
0.1
0.3
0.5
0.2
1.6
3.0
63.9
5.7
7.0
3.2
6.4
86.2
6.9
6.9
100.0
removal: on-iite solids disposal.
Stack gas reheat to 175 F by indirect steam reheat
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, eadins mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table 38. Lime Slurry Process
Total Capital Investment Requirements
Existing Case2 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Raw
materials
handling
Direct Can
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation.
railroads, roads, and pond
Structural
Material
Laboi
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Cost!
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction
Total capital investment
Parent of total capital investment
.155
64
-
-
9
6
10
58
-
31
57
98
138
24
15
1
9
_
_
1
_
876
88
114
61
96
1,235
99
99
1.433
5.5
Feed
prep nation
160
18
10
13
2
1
3
15
-
-
-
42
59
67
42
_
4
-
_
-
_
436
44
57
31
48
616
49
49
714
2.7
First
stage SOj
scrubbing
1.029
481
368
428
951
753
12
60
-
85
49
49
70
121
76
3
29
-
-
1
-
4465
456
593
320
502
6,436
515
515
7,466
28.7
Second
stage SOj
scrubbing
1,090
481
368
432
347
377
13
60
•
85
49
90
128
150
94
3
29
-
_
1
_
3,797
380
494
266
418
5,355
428
428
6411
23.9
Reheat
173
21
8
25
-
-
-
1
-
-
-
8
18
35
16
_
_
_
_
_
_
305
30
40
21
34
430
34
34
498
1.9
Fans
455
88
-
-
127
181
7
39
-
-
-
89
127
18
11
-
1
-
-
-
_
1,143
114
149
80
126
1,612
129
129
1,870
7.2
Calcium
solids
disposal
11
3
81
116
_
-
-
1
2,420
-
3
61
86
7
4
1
6
_
_
249
_
3,049
305
396
213
335
4,298
344
344
4,986
19.1
Utilities
31
57
12
19
-
-
1
7
46
-
-
52
67
20
12
4
7
_
_
_
_
335
33
44
24
37
473
38
38
549
2.1
Construction Percent of
facilities direct
Services 5% Total investment
83
32
-
-
-
-
-
-
356
-
-
_
-
-
-
-
-
114
50
14
_
649
65
84
45
71
914
73
73
1,060
4.1
3.387
1,245
847
1,033
1,436
1,318
46
241
2,822
201
158
489
693
442
270
12
85
114
50
266
758 758
758 15,913
76 1,591
98 2,069
53 1,114
83 1.750
1,068 22,437
86 1,795
86 1,795
1,240 26,027
4.8
21.3
7.8
5.3
6.5
9.0
8.3
0.3
1.5
17.7
1.3
1.0
3.1
4.3
2.8
1.7
0.1
04
0.7
0.3
1.7
4.8
100.0
10.0
13.0
7.0
11.0
141.0
11.3
11.3
163.6
Percent of
total capital
investment
13.0
4.8
3.2
4.0
5.5
5.1
0.2
0.9
10.8
0.8
0.6
1.9
2.7
1.7
1.0
0.1
0.3
0.4
0.2
1.0
2.9
61.1
6.1
8.0
4.3
6.7
86.2
6.9
6.9
100.0
•Basis:
500-MW existing coal-fired power unit, 34% S in fuel; 90% SOj removal; on-site solids disposal.
Stack gas reheat to 175 F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location repiesents project beginnrng nuJ-1972. ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spired.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table 39. Magnesia Slurry - Regeneration Process
Tb'tal Capital Investment Requirements
Base Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Raw
materials
handling
Direct Costs
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation,
railroads, and roads
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Costs
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction
Total capital investment
Percent of total capital investment
92
15
-
1
-
1
6
4
2
25
28
10
5
-
3
-
-
-
-
192
21
21
10
19
263
26
21
310
1.2
Feed
preparation
102
6
15
13
5
2
1
6
_
-
25
37
15
7
1
3
-
_
_
-
238
26
26
12
24
326
33
26
385
14
Paniculate
scrubbing
1,071
375
206.
188
787
644
15
57
_
84
41
91
175
136
68
3
24
_
_
1
_
3,966
436
436
198
396
5,432
543
434
6,409
24.3
SO,
scrubbing
976
361
200
186
177
1%
|!
41
-
84
38
51
57
124
62
3
24
_
_
1
-
2492
285
285
130
259
3451
355
284
4,190
15.9
Reheat
373
78
11
20
_
-
_
-
_
_
_
1
1
16
8
_
1
_
_
_
-
509
56
56
25
51
697
70
56
823
3.1
Slurry
Fans processing
235
30
-
-
153
54
4
19
-
_
_
101
115
20
10
_
_
_
_
_
-
741
81
81
37
74
1,014
102
81
1,197
4.5
297
68
60
58
2
1
3
12
_
3
1
47
75
53
26
_
3
_
_
2
-
711
78
78
36
71
974
97
78
1,149
4.3
Cake MgSOa
drying calcination
592
177
1
1
28
26
6
29
_
7
4
32
36
17
8
1
6
_
_
1
-
972
107
107
49
97
1,332
133
107
1472
5.9
680
209
3
6
14
6
6
27
_
6
9
31
44
38
19
1
8
_
_
1
-
1,108
122
122
55
111
1418
152
121
1,791
6.8
Sulfuric
acid
production
785
262
230
234
378
461
38
175
-
78
35
91
144
138 •-
71
9
65
-
_
3
• -
3.197
352
352
160
320
4,381
438
350
5,169
19.6
Acid
storage &
snipping
128
3
12
30
_
-
7
35
14
2
14
6
15
9
3
_
_
_
_
_
-
278
31
31
14
28
382
38
31
451
1.7
Utilities
80
5
8
24
-
-
3
28
6
2
14
26
30
16
8
8
11
-
..
_
-
269
30
30
13
27
369
37
30
436
1.6
Construction Percent of
facilities direct
Services 5% Total investment
98
29
-
-
_
-
-
-
399
-
_
_
_
_
_
_
_
180
63
14
-
783
86
86
39
78
1,072
107
86
1,265
4.8
-
-
-
-
_
-
-
-
_
_
_
_
-
_
-
_
_
-
_
_
778
778
86
86
39
78
1,067
107
85
1,259
4.8
5,509
1,618
746
761
1,544
1,390
95
435
419
270
158
527
757
592
295
26
148
180
63
23
778
16,334
1,797
1,797
817
1,633
22,378
2,238
1,790
26,406
33.7
9.9
4.5
4.6
9.5
84
0.6
2.7
2.6
1.7
1.0
3.2
4.6
3.6
1.8
0.2
0.9
1.1
0.4
0.1
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
Percent of
total capital
investment
20.9
6.1
2.8
2.9
5.8
5.3
0.4
1.6
1.6
1.0
0.6
2.0
2.9
2.2
1.1
0.1
0.6
0.7
0.2
0.1
2.9
61.8
6.8
6.8
3.1
6.2
84.7
8.5
6.8
100.0
"Basis:
500-MWnewcoal-riredj)owerumt,34*Siafiiel;90%SOj removal; 15.8tons/la 1CO%H2SO,,.
Stack gas reheat to 175 F by indirect steam reheat
Midwest plant location represents project beginning nud-1972, ending mid-197S. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spired.
Fly ash slurry neutralized before disposal; closed loop water uiiluat»n for 1st stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table 40. Magnesia Slurry - Regeneration Process
Total Capital Investment Requirements
Existing Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Direct Costs
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation.
railroads, and roads
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
labor
Land
Construction facilities
Subtotal direct investment
Indirect Costi
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction
Total capital investment
Percent of total capital investment
Raw
materials
handling
93
19
-
1
-
_
1
8
-
4
3
25
36
10
6
_
4
-
-
-
-
210
25
27
15
23
300
30
24
354
1.4
Feed
preparation
113
8
15
16
5
3
1
8
-
-
-
25
47
15
9
1
4
-
-
-
-
270
32
35
19
30
386
39
31
456
1.8
S02
scrubbing
990
457
203
236
1,133
891
11
52
-
85
48
52
72
126
79
3
30
-
-
1
-
4,469
536
581
313
492
6491
639
511
7,541
29.0
Reheat
173
21
8
25
-
-
_
1
-
-
-
8
18
35
16
_
_
-
-
-
-
305
37
40
21
34
437
44
35
516
2.0
Fans
433
56
-
-
128
181
5
27
-
-
_
103
146
20
13
_
_
-
-
-
-
1,112
133
145
78
122
1,590
159
127
1,876
7.2
Slurry
processing
306
87
61
74
2
1
3
15
-
3
1
48
95
54
33
_
4
-
-
2
-
789
%
103
55
87
1,130
113
90
1,333
5.1
Cake
drying
606
225
1
1
29
33
6
37
-
7
5
32
46
17
10
1
8
-
-
1
_
1,065
128
138
74
117
1,522
152
122
1,796
6.9
MgSO3
calcination
694
265
3
g
14
8
6
34
-
6
11
31
56
39
24
1
10
-
-
1
1,211
145
157
85
133
1.731
173
138
2,042
7.8
Sulfuric
acid
production
796
332
233
297
383
584
39
222
-
79
44
92
183
140
90
9
82
-
-
3
_
3.608
433
469
253
397
5,160
516
413
6.089
23.4
Acid
storage &
shipping
149
4
12
38
-
-
7
44
17
2
18
6
19
9
4
_
_
-
-
-
-
329
40
43
23
36
471
47
38
556
2.1
Construction
Utilities
130
9
10
33
-
-
4
SO
10
3
25
57
70
16
10
10
17
-
-
-
-
454
54
59
32
50
649
65
52
766
2.9
Services
99
36
-
-
-
-
-
-
456
_
-
-
-
-
_
-
_
182
80
14
_
867
104
113
61
95
1,240
124
99
1,463
5.6
facilities
5% Total
4,582
1,519
546
729
1,694
1,701
83
498
483
189
155
479
788
481
294
25
159
182
80
22
734 734
734 15,423
88 1,851
95 2,005
51 1,080
81 1,697
1,049 22,056
105 2,206
84 1,764
1,238 26.026
4.8
Percent of
direct
investment
29.7
9.9
3.6
4.7
11.0
11.0
0.5
3.2
3.2
1.2
1.0
3.1
5.1
3.1
1.9
0.2
1.0
1.2
0.5
0.1
4.8
100.0
12.0
13.0
7.0
.11.0
143.0
14.3
11.4
168.7
Percent of
total capital
investment
17.6
5.9
2.1
2.8
6.5
6.5
0.3
1.9
1.9
0.7
0.6
1.9
3.0
1.9
1.1
0.1
0.6
0.7
0.3
0.1
2.8
59.3
7.1
7.7
4.1
6.5
84.7
8.5
6.8.
100.0
vfl
a Basis:
500-MW existing coal-frgal power unit, 3.5% S in fuel, 90% SOj removal; 16.1 tons/hr 100% H2SO4.
Stack gas reheat to 175 F by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Avenge cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
' f :stment requirements for removal and disposal of fly ash excluded.
Construction u'tn,. ^..~*>«es with accompanying overtime pay incentive not considered.
-------
Table 41. Sodium Solution - SO2 Reduction Process
Total Capital Investment Requirements
Base Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Raw materials
handling & Paniculate
preparation scrubbing
Direct Costs
Equipment
Material
Labor
Piping and insulation
Material
labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation.
railroads, and roads
Structural
Material
Labor
Electrical
Material
Labor
Instrumertts
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Costs
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications'
Interest during construction
Total capita! investment
Percent of total capital investment
90
19
2
5
-
-
1
6
-
5
3
25
47
13
7
_
2
_
-
-
225
25
25
11
22
30J
31
23
364
1.2
1,071
375
208
194
726
574
15
57
-
84
41
88
167
145
73
3
24
-
_
1
_
3,846
423
423
192
385
5,269
527
422
6,218
20.4
S02
scrubbing
2.183
709
146
135
238
264
11
41
-
84
38
67
160
110
55
3
24
-
_
1
_
4,269
470
470
214
427
5,850
584
468
6,902
22.6
Reheat
410
80
11
20
_
-
_
-
_
_
_
1
1
10
5
_
1
. _
_
..
_
539
59
59
27
54
738
74
59
871
2.9
Purge
Fans treatment
285
34
-
-
157
59
4
21
-
_
_
157
149
15
7
_
1
-
-.
_
_
889
98
98
44
89
1,218
122
97
1,437
4.7
749
133
63
61
54
73
15
64
_
27
13
65
91
37
18
1
g
_
_
1
_
1,473
162
162
74
147
2,018
202
161
2,381
7.8
S02
regeneration
1,628
145
104
119
6
10
14
67
-
92
42
106
160
131
65
3
23
_
_
2
_
2,717
299
299
136
272
3,723
372
298
4393
14.4
SO,
reduction
1,870
846
2
5
55
90
_
-
-
_
-
30
21
_
_
_
_
_
_
2
_
2,921
321
321
146
292
4,001
400
320
4,721
15.5
Sulfur
storage &
shipping
103
2
6
11
-
-
4
16
13
2
14
16
23
. 9
4
_
1
_
_
3
_
227
25
25
11
23
311
31
25
367
1.2
Utilities
-
-
58
45
-
_
_
-
_
_
_
12
17
17
8
14
24
_
_
_
-
195
21
21
10
19
266
27
21
314
1.0
Construction Percent of
facilities direct
Services 5% Total investment
98
29
-
-
-
-
_
_
278
„
_
_
_
„
_
__
_
180
63
14
_
662
73
73
33
66
907
91
73
1,071
3.5
-
-
-
§
-
-
_
-
_
_
_
_
_
_
_
_
_
_
898
898
99
99
45
90
1,231
123
98
1,452
4.8
8,487
2,372
£00
595
1,236
1,070
64
272
291
294
151
567
836
487
242
24
108
180
63
24
898
18,861
2,075
2,075
943
1,886
25,840
2,584
2,067
30,491
44.9
12.6
3.2
3.2
6.6
5.7
0.3
1.4
1.5
1.6
0.8
3.0
4.4
2.6
1.3
0.1
0.6
1.0
0.3
0.1
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
Percent of
total capital
investment
27.8
7.8
2.0
2.0
4.0
3.5
0.2
0.9
1.0
0.9
0.5
1.8
2.7
1.6
0.8
0.1
0.4
0.6
0.2
0.1
2.9
61.8
6.8
6.8
3.1
6.2
84.7
8.5
6.8
100.0
500-MW new ccaJ-fired^ower unit, 3.5% S in fuel; 90% SOj removal; 4,7 tons/hr S produced.
Stack gas reheat to 175 F by indirect Beam reheat.
Midwest plant location repraeim project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process stotage; only pumps are spared.
F!y ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table 42. Sodium Solution - SO2 Reduction Process
Total Capital Investment Requirements
Existing Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Raw materials
handling 4 SO2
preparation scrubbing
Direct Costs
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and upports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation,
railroads, and roads
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buudsngs
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Cottt
Engineering design and supervision
Construction field expense
Con tnttor tees
Conliinfrm y
Subtotal fixed investment
Allowance for startup and modifications
Intend during construction
Total capital investment
Pet-cent of total capital investment
92
24
2
6
-
-
1
8
—
5
3
25
60
14
9
—
2
-
_
_
-
251
30
33
17
28
359
36
29
424
1.4
2,218
902
149
171
1,046
766
11
52
-
85
48
69
204
111
70
3
31
_
_
2
_
5,938
712
772
416
653
8,491
849
679
10,019
32.1
Reheat
173
21
8
25
—
-
_
1
-
_
_
8
18
35
16
—
_
-
_
-
305
37
40
21
34
437
44
35
516
1.6
Purge
Fans treatment
462
62
_
_
127
181
5
29
—
_
_
159
188
15
9
_
I
-
_
_
-
1,238
149
161
87
136
1,771
177
142
2,090
6.7
730
198
59
65
55
92
15
81
—
28
16
66
115
38
23
1
10
—
—
1
-
1,593
191
207
111
175
2,277
228
182
2,687
8.6
SO]
regeneration
1,928
293
106
151
6
13
14
85
-
94
53
108
203
133
83
3
29
-
_
2
_
3^04
396
429
231
363
4,723
472
378
5,573
17.9
SO,
reduction
1,892
1,070
2
7
55
115
_
_
-
_
_
30
27
_
_
_
-
_
_
2
_
3400
384
416
224
352
4^76
458
366
5,400
17.3
Sulfur
storage &
snipping
120
2
6
14
—
-
4
20
17
2
18
16
29
9
6
—
1
-
_
3
_
267
32
35
19
29
382
38
30
450
1.4
Utilities
98
184
59
50
—
—
3
21
107
_
_
59
79
23
14
16
39
—
_
_
-
752
90
98
53
83
1,076
108
86
U70
4.1
Construction Percent of
facilities direct
Services 5% Total investment
99
37
-
-
—
-
_
_
354
_
_
-
-
_
_
-
-
182
80
14
-
766
92
99
54
84
1,095
109
88
1,292
4.1
-
-
-
-
-
-
-
-
-
_
_
-
-
—
—
-
—
—
_
_
881
881
106
114
62
97
1,260
126
101
1,487
4.8
7,812
2,793
391
489
1,289
1,167
53
297
478
214
138
540
923
378
230
23
113
182
80
24
881
18.495
2,219
2,404
1,295
2,034
26,447
2,645
2,116
31,208
42.3
15.2
2.1
2.6
7.0
6.3
0.3
1.6
2.6
1.2
0.7
2.9
5.0
2.0
1.2
0.1
0.6
1.0
0.4
0.1
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
Percent of
total capital
investment
25.0
8.9
1.3
1.6
4.1
3.7
0.2
1.0
1.5
0.7
0.4
1.7
3.0
1.2
0.7
0.1
0.4
0.6
0.3
0.1
2.8
59.3
7.1
7.7
4.1
6.5
84.7
8.5
6.8
100.0
'Basis:
500-MW existing coal-fired power unit, 3.5% S in fuel; 90% SOj removal; 4.8 torn/hi S produced.
Stack gas reheat to 175°F by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis foe scaling, mid-1974.
Mminmrn in process storage; only pomps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fry ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
OS
Table 43. Catalytic Oxidation Process
Total Capital Investment Requirements
Base Case2 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Startup
bypass
ducts
Direct Costs
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation.
railroads, and roads
Structural
Material
Labor
Electrical
Material
Labor
Instruments
Material
Labor
Faint and miscellaneous
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Costs
Engineering design and supervision
Construction field expense
Coatnctor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
LErteresl during construction
Total capital investment excluding catalyst
Catalyst
Total capital investment
Percent of total capital investment
-
-
-
.-
350
97
_
-
-
_
_
15
20
6
3
-
-
-
.-
_
-
491
54
54
25
49
673
67
54
794
-
794
1.9
Paniculate
removal
4,469
3,126
-
_
585
319
_
-
-
_
_
64
129
28
14
-
-
_
2
_
8,736
961
961
437
874
11,969
1,197
9S7
14,123
-
14,123
33.0
SO,
conversion
671
556
-
1
465
197
.
4
17
_
56
43
23
42
42
21
1
5
-
_
1
_
2,145
236
236
107
214
2,938
294
235
3,467
1,728
5,195
12.2
Heat
recovery
(31)
(25)
121
166
42<
384
4
15
_
_
_
78
193
85
43
2
14
_
-
1
_
1,475
162
162
74
147
2,020
202
162
2,384
_
2,384
5.6
H,S04
absorption
Fans cooling
316
43
-
-
302
229
5
24
-
_
_
203
265
16
8
_
1
-
_
_
-
1,412
155
155
71
141
1,934
193
155
2,282
_
2,282
5.3
5,659
760
275
259
684
513
27
124
-
23
5
77
149
233
117
1
9
_
_
2
_
8,917
981
981
445
£32
12,216
1.222
977
14,415
_
14,415
33.7
Acid
storage &
shipping
68
101
13
31
-
-
11
48
19
2
14
30
43
18
9
_
_
-
_
2
_
409
45
45
20
41
560
56
45
661
_
661
1.5
Utilities
-
-
2
5
-
_
_
_
_
_
_
10
10
16
8
3
3
_
_
_
_
57
6
6
3
6
78
8
6
92
-
92
0.2
Construction Percent
facilities of direct
Services S% Total investment
36
9
-
-
-
-
_
-
278
_
_
_
_
_
-
_
-
132
50
13
-
518
57
,57
26
52
710
71
57
838
-
838
2.0
-
-
-
-
-
-.
_
-
-
_
_
„
-
_
_
_
-
_
_
_
1.208
1,208
133
133
60
121
1,655
165
132
1,952
-
1,952
4.6
11,188
4,570
411
462
2,811
1,739
51
228
297
81
62
500
851
444
223
7
32
132
50
21
1,208
25,368
2,790
2,790
1,268
2,537
34,753
3,475
2,780
41,008
1,728
42,736
44.1
18.0
1.6
1.8
11.1
6.9
0.2
0.9
1.2
0.3
0.2
2.0
3.4
1.7
0.9
0.0
0.1
0.5
0.2
0.1
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
6.8
168.5
Percent of
total capital
investment
26.3
10.7
1.0
1.1
6.6
4.1
0.1
0.5
0.7
0.2
0.1
1.2
2.0
1.0
015
0.0
0.1
0.3
0.1
0.0
2.8
59.4
6.5
6.5
3.0
5.9
81.3
8.2
6.5
96.0
4.0
100.0
"Basis:
500-MW new coal-fired power unit, 3.5% S in fuel; 90% SO2 removal; 15.7 tons/hr 100% HjSO4.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table 44. Catalytic Oxidation Process
Total Capital investment Requirements
Existing Case3 Summary—Process Equipment and Installation Analysis
(Thousands of Dollars)
Startup
Direct Costs
Equipment
Material
Labor
Piping and insulation
Material
Labor
Ductwork, chutes, and supports
Material
Labor
Concrete foundations
Material
Labor
Excavation, site preparation,
railroads, and roads
Structural
Material
Labor
Fiectrical
Material
Labor
Instruments
Material
Labor
Paint and miscellaneous
Material
Labor
Buildings
Material
Labor
Land
Construction facilities
Subtotal direct investment
Indirect Com
Engineering design and supervision
Construction Field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modification
Interest during construction
Total capital investment excluding catalyst
Catalyst
Total capital investment
Percent of total capital investment
bypass
ducts
-
-
-
-
179
74
-
-
-
-
_
15
26
6
4
_
_
-
-
-
-
304
36
39
21
33
433
43
35
511
-
511
1.4
ParticuUte
removal
1,471
1,553
-
-
483
475
_
-
-
_
-
65
164
29
18
-
-
-
-
2
-
4,260
511
554
298
469
6,092
609
487
7.188
-
7,188
19.0
S02
conversion
683
708
-
1
136
164
4
22
-
57
54
23
53
43
27
1
6
-
-
1
-
1,983
238
258
139
218
2,836
284
227
3,347
1,766
5,113
13 .5
Reheat
1,894
160
244
293
-
-
23
26
-
-
_
172
199
133
97
8
8
-
-
1
-
3^58
391
424
228
358
4,659
466
373
5,498
-
5,498
14.5
Fans
688
98
-
-
305
413
9
53
-
_
_
206
334
16
10
-
1
-
-
-
-
2.133
256
277
149
235
3,050
305
244
3,599
-
3499
9.5
H,SO«
absorption
& cooling
4.247
857
176
214
308
273
24
141
-
24
6
61
148
214
134
1
10
-
-
2
-
6,840
821
889
479
753
9,782
978
782
11,542
-
11,542
30.5
Acid
storage &
shipping
69
128
13
39
-
_
11
61
22
3
18
31
55
18
11
-
-
-
-
2
-
481
58
62
34
53
688
69
55
812
-
812
2.1
Construction
Utilities
65
122
13
15
-
-
2
14
79
-
_
73
95
22
13
4
10
-
-
-
-
527
63
68
37
58
753
75
60
888
-
888
2.3
Services
36
11
-
_
_
-
-,
-
356
_
_
_
_
_
-
_
_
133
63
14
-
613
74
80
43
67
877
88
70
1,035
-
1,035
2.7
facilities
5%
-
-
-
_
-
-
_
-
-
_
-
_
-
_
-
-
_
-
-
-
1,020
1,020
122
133
71
112
1,458
146
117
1,721
-
1,721
4.5
Total
9,153
3,637
446
562
1,4)1
1,399
73
317
457
84
78
646
1,074
481
314
14
35
133
63
22
1.020
21,419
2,570
2,784
1,499
2,356
30,628
3,063
2,450
36,141
1,766
37,907
_
Percent
of direct
investment
42.7
17.0
2.1
2.6
6.6
6.5
0.3
1.5
2.1
0.4
0.4
3.0
5.0
2.2
1.5
0.1
0.2
0.6
0.3
0.1
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
8.3
177.0
_
Percent of
total capital
investment
24.1
9.6
1.2
1.5
3.7
3.7
0.2
0.8
1.2
0.2
0.2
1.7
2.8
1.3
0.8
0.0
0.1
0.4
0.2
0.1
2.7
56.5
6.8
7.3
4.0
6.2
80.8
8.1
6.4
95.3
4.7
_
100.0
"Bias
\O
500-MW existing coal-fired power unit, 3.5% S in fuel; 90% SOj removal; 16.0 tons/hr 100% H2SO4.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Avenge cost basis for scaling, mid-1974.
Only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Area
Particulate removal
S02 conversion
S02 absorption
Waste disposal
Sulfuric acid processing
SOj regeneration
SOj reduction
Table 45. Investment Distribution for Major Cost
Areas Base CMC Total Capital Investment3
^lrihutioin)rbase^cascJptajcapiUil investment, % ___
Limestone Ume sluny Magnesia slurry - Sodium solution - Catalytic
slurry process process regeneration process S02 reduction process oxidation process
19.9
-
29.5
24.4
-
28.1
-
22.0
23.4
-
24.3
—
15.9
—
19.6
20.4
—
22.6
_
—
33.0
12.2
33.7
14.4
15.5
Subtotal, %
Total capital
investment, M $
73.8
25,163
73.5
22,422
59.8
26,406
72.9
30,491
78.9
42,736
aMajor cost areas are defined as those which account for more than 10% of the total capital investment.
so
20
Limestone slurry process • X
Lime slurry process • A
Magnesia slurry - regeneration proceu • 0
Sodium solution • SO] reduction process
Catalytic oxidation process - "
3.5% S In coat
90% SO] removal
I
I
I
•B
8«o
•20
200
400 600 800
Power unit lit*, MW
1,000
Limestone slurry proem • X
Lime slurry process • A
Magnesia ilurry - regeneration process • 0
Sodium tolution • SO, reduction proem • 0
Catalytic oxidation prootn • o
3.6* Sin coal
80% SOi removal
Powor unit size, MW
Figure 33. All processes. Effect of power unit size
on total capital investment: new coal-fired units
Figure 35. All processes. Effect of power unit size
on total capital investment: existing coal-fired units
20
! I I
Limaitona ykirry procen • X
Lima tiurry proceu "
Maonnia ilurry . raganaration procan • 0
Sodium Klution • SO] reduction proom • o
Catalytic oxidatfoo proceu • n
2.6% S in oil
90% SO, removal
.80
'80
!40
200
400 600 800
Power unit ilia, MW
1,000
Figure 34. All processes. Effect of power unit size
on total capital investment: new oil-fired units
I T I
Limestone slurry process • X
Lima slurry process • "
Magneela ilurry • regeneration promt • 0
Sodium solution - SO] reduction process •
Catalytic oxidation proceei • »
80% SO, removal
Sulfur in «nl,%
Figure 36. All processes. Effect of
sulfur content of coal on total capital
investment: new 500-IV1W coal-fired units
-------
560
:«0
T
T
Limestone slurry process • X
Lime slurry process ^
Mngnwia Blurry regeneration process • O
Sodium wiliition SO] reduction procftM
(^ilttlylii. uf HlnttOM pr SO, reduction protest • 0
~ Ciulytlc oxidation orocess • "
Iso
2.6% S in oil
90% SO, removel
Sullur in oil, %
Figure 37. All processes. Effect of
sulfur content of oil on total capital
investment: new 500-MW oil-fired units
Power unit size, MW
Figure 39. All processes. Effect of
power unit size on unit investment cost,
dollars per kilowatt: new oil-fired units
100
BSO
I
Limestone slurry process • X
Lime slurry process *
Magnesia slurry • regeneration process • 0
Sodium solution SO, reduction process
Catalytic oxidation proceu - n
3.5% S in coal
90% SO, removal
I I i
100
a 75
25
200
400
800 800
Power unit size, MW
1,000
Figure 38. All processes. Effect of
power unit size on unit investment cost,
dollars per kilowatt: new coal-fired units
I
I
Lirmtone slurry process X
Lirra slurry process A
Megnetie slurry • regeneration process • 0
Sodium solution SO, reduction process o
Catalytic oxidation process n
90% SO, removel
1
J_
Sulfur In coil, X
Figure 40. All processes. Effect of sulfur
content of coal on unit investment cost,
dollars per kilowatt: new 500-MW coal-fired units
I I !
Limestone slurry process X
Ltme slurry proceu A
Magnesia slurry • regeneration process 0
Sodium solution SO, r*duction process •
Catalytic oxidation process • :i
90% SO, removal
99
Sulfur In oil, %
Figure 41. Ali processes. Effect of sulfur
content of oil on unit investment cost,
dollars per kilowatt: new 500-MW oil-fired units
-------
SO 2 scrubbing area are projected as $4,745,000 for a new
unit in comparison lo $5,243,000 lor an existing unit, and
ina (.-menial I'an cosls lor a new unit are projected as
$854,000 in conipaiison to supplemental I'an r)costs of
$1,710,000 for an existing unit. Certain areas are less
expensive for existing units, however. The omission of a
particulate scrubber for existing units saves approximately
$3,203,000 (since particulate emission regulations are
assumed already met) and direct investment costs for an
oil-fired reheat system on an existing unit ($323,000) are
lower than corresponding costs for an indirect steam reheat
system for a new unit ($556,000). The overall difference in
costs between new and existing units for the various
processes is mainly attributed to differences in ductwork,
particulate removal requirements, the use of direct oil-fired
reheat as opposed to indirect steam reheat, and the assumed
25% higher installation labor costs for existing units as
compared to new units.
The required investment for existing power units
utilizing the limestone and lime slurry processes varies with
operating profile and remaining life of the power plant, due
to corresponding variations in the quantities of waste solids
to be disposed. In comparison, however, investment
requirements for the recovery processes do not vary with
plant age. Figure 42 shows the effect of power unit size and
years remaining life on the projected total capital invest-
ment required for the limestone slurry process applied to
existing power units. The relationship for the lime slurry
process is similar.
Base case equipment lists indicating size/scale factors
and the sources of the equipment cost data for each of the
five processes are presented in tables 46 through 50.
JaoU
.£2C _
5
I
1
5.5% S m coal
90% SO] removal
2Syr>
I
I
I
Figure 42. Limestone slurry process. Effect
of years remaining life on total capital
investment: existing coal-fired units
Annual Operating Cost
Projected annual operating costs under regulated eco-
nomics for the five processes are presented using the three
methods discussed earlier. Summary tables giving the
projected annual operating cost for the base case and 16
variations for each process are given in Appendix B and
tabular summaries of the projected annual operating cost
and equivalent unit operating costs are given in tables 51
through 55. In order that direct comparisons can be made,
credits for recovery products have not been included; these
will be applied in determining lifetime operating costs in a
later sect ion.
Generally, the operating costs for the limestone slurry
process are the lowest of the five processes and those for
the sodium solution - S02 reduction process are the
highest. However, some very important exceptions are
emphasized in plots of the results. Figures 43 through 50
show the effects of power unit size, fuel type, and sulfur
content of fuel on annual and unit operating costs. As the
projections show, the ranking of operating costs for the five
processes depends to a small degree on the size of the plant
but to a larger degree on the sulfur content of fuel. For new
500-MW power units utilizing 1.0% sulfur oil, the projected
annual operating costs for the catalytic oxidation process
rank among the highest of the five processes (figure 50),
however, for oil-fired units utilizing high-sulfur oil (>4.0%)
the projected annual operating costs for the Cat-Ox process
are the lowest. The slight decrease in annual operating cost
for the Cat-Ox process with increasing sulfur content of
fuel oil is the result of a greater amount of heat recovered
for the high sulfur installations in conjunction with the
'higher unit cost for recovered heat assumed for oil-fired
units.
Several special cases, are shown in the total average
annual operating cost summaries:
80% S02 removal
Particulate removal for existing unit
Off-site solids disposal
Additional information on the treatment of these cases
is provided in tables 56 through 58.
Table 56 shows the effect of designing for 80% S02
removal instead of the assumed standard of 90% on annual
operating costs for the limestone slurry process, lime slurry
process, magnesia slurry - regeneration process and the
sodium solution - S07 reduction process. Designing for 80%
S02 removal instead of 90% would result in a savings of
only 3,6% to 6.6% of the projected annual operating cost.
Results of an evaluation of the annual operating costs
for existing units requiring additional facilities for removal
of particulates but excluding costs for ash disposal are given
in table 57. The standard case assumes that existing
electrostatic precipitators are adequate for existing plants.
Since the lime slurry process is designed with a two-stage
100
-------
Table 46. Limestone Slurry Process Equipment List and Cost
Area I Material Handling
Si/c cost
sriilr I'ltrlor
No. Desnljijion factor ^source
Hasr
cost
llase cost
source
Projected" 1574"
Date equipment cost
of cost _each total
1. Unloading 1
hopper No. 1
2. Limestone 1
feeder No. 1
(vibrating)
3. Conveyor |
(belt) No. 1
4. Conveyor 1
(belt) No. 2
5. Hoppers 3
under pile
6. Limestone 3
feeder No. 2
(vibrating)
7. Conveyor 1
(belt) No. 3
8. Tunnel 2
sump pump
9. Elevator 1
No. !
10. Bin 1
1 1 . Car shiikoi 1
12. Dust 1
collecting
system No. 1
1 3. Dust 1
collecting
system No. 2
14. Mag filler 1
system
Capacity "4 IIs; 8'-
4" side 2 '-4 "bot-
tom, 3 deep, carbon
steel
210 tons/hr, 42"
wide x 5 'long pan,
2'/2 hp vibrator included
carbon steel
210 tons/hr, 250ft/
min,24"belt, 10'
long, 2'/2 hp motor
included, carbon
steel
210 tons/hr, 250ft/
min,24' belt, 172'
long, 20 hp motor
included, carbon
steel
„; . it . I . II
7 -4 top, 1 -4
bottom, 3 'deep.
carbon steel
!00 tons/hr, 18"
wide x S'/i' long pan,
1 hp vibrator included,
carbon steel
250 ft/min, 18" belt,
135' long, 3 hp motor
included, carbon
steel
5 gpm. 10' head.
V> hp motor included.
carbon steel.
neoprene lining
100 tons/hr <«' 85 Ib/
ft3, 16" x 8"x8'/2''
bucket, 235 ft/min,
15 hp motor included,
carbon stee!
5,OOOff\3/8"
carbon steel plate,
plus structural steel
Railroad trackside
vibrator
2.000 ct'm inertial
separator, XQ cyclone.
2 dust hoppers, fan.
and drive
6,000cfm inertial
separator, XQ cyclone,
2 dust hoppers, fan,
and drive
14,000 elm. automatic
fabric dust collectors.
bag support, shaker sys-
tem, isolation damper.
external shakoi motor
;;nd drive, dus, hoppei ,
fan and motor for bag
filter system (Vi in feed
preparation area)
0.68 Chem. Engr. 3-24-69
Guthrie
0.58 Chcm. Engr. 3-24-69
Guthrie
,
0.81 Fund, of Cost Engr.
1964
0.65 Chem. Engr. 3-24-69
Guthrie
0.81 Fund, of Cost Engr.
1964
0.65 Chem. Engr. 3-24-69
Guthrie
0.68 Chem. Engr. 3-24-69
Guthrie
0.58 Chem. Engr. 3-24-69
Guthrie
0.65 Chem. Engr. 3-24-69
Guthrie
0.81 Fund, of Cost Engr.
1964
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
0.83 Chem. Engr. 3-24-69
.Guthrie
0.68 Chem. Engr. 3-24-69
Guthrie
0.80 Chem. Kngr. 3-24-69
Guthrie
0.80 Chcm. Engr. 3-24-69
Guthrie
0.68 Chem, Lngr. 3-24-61)
Gulhrie
1,700 Catalytic 1973
Inc.
•v<6
2,691 Richardson Engr. 1971
Services
1,887 TVA work 1964
order D05C30
8,948 TVA work 1962
order D05P353
1,300 Chem. Engr.- 1969
3-24-69, Guthrie
1,550 Richardson Engr. 1973
Services
11, 250 Chem. Engr.- 1969
3-24-69, Guthrie
560 Catalytic 1973
Inc.
8,765 TVA work 1964
order D05C30
12,650 TVA work 1964
order D05C30
4,866 TVA work 1965
order D05C30
2,392 Richardson Engr. 1973
Services
4,724 Richardson Engr. 1973
Services
7,926 Richa-dson Engr. 1973
Services
2,000 2,000
3,300 3,300
2,900 2,900
13,700 13,700
1,700 5,100
1,700 5,100
14,800 14,800
600 1,200
13,300 13,300
19,200 19,200
6,600 6,600
2,600 2,600
5,100 5,100
8,500 8,500
Subtotal
103,400
-------
Table 46. Limestone Slurry Process (Cont.)
l-'cod Picpariillon
1.
2.
3.
4.
5.
6.
7.
8.
I
Item
Bin discharge
feeder
Weigh feeder
Gyratory
crusher
Elevator
No. 2
Wet ball
mill
Mills
product
tank
Lining
Agitator,
mills
product
tank
Pumps, mills
product tank
No.
2
2
2
2
2
2
1
1
2
Si/.c cost
Sl'tllf
Description factor
12W tons/hr, 10"
widex 2'/2 long pan,
vibrator included,
carbon steel
12'/2 tons/hr, 18"
belt, 14 long, l'/2
hp motor included,
carbon steel
1 2'A tons/hr, 0 x 1 V4
to % , 25 hp motor
included
1 2% lons/hr, 85 lb/
ft3, 235ft/min, 24'
it n * iH
ctrs,6 x4 x4'//
bucket, I hp motor
included
300 tons/day; 8'dia
x 12' long, from %"
to 200 mesh
450 hp motors for
ball mill
1 ,920 gal, 8' diam-
eter x 5' high,
vertical with open
top, carbon steel
Neoprene lining for
mill product tank
1 hp, neoprene
coated
96 gpm, 58' head,
centrifugal, with
variable speed drive
0.58
0.65
1.20
0.65
0.65
1.07
0.52
0.50
0.26
Factor
source
Chem. Kngr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Kngr. 3-24-69
Guthrie
Chem. Kngr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Fund, of Cost Engr.
1964
Fund, of Cost Engr.
1964
Chem. Kngr. 3-24-69
Gulhrie
Fund, of Cost Engr.
1964
Depends on gpm and head
Base
cost
500
7,216
10,455
1,760
99,245
13,100
2,120
1.400
1,026
2,060
requirements resulting in changes
Base cost
source
Richardson Engr.
Services
Catalytic
Inc.
Denver Equip.
Co.
Chem. Engr.-
3-24-69, Guthrie
Denver Equip.
Co.
Westinghouse
GATX
GATX
Mixing Equip.
Co., Inc.
Denver Equip.
Co.
Date
of cost
1973
1972
1973
1969
1973
1973
1971
1971
1971
1973
Project ed"
equipment
each
600
8,200
1 1 ,300
2,400
108,150
14,200
2,500
800
1,200
2,200
(971-
cost
total
1,200
16,400
22,600
4,800
216,300
28,400
2,500
800
1,200
4,400
of motor and impeller sizes
and 3 hp motor, carbon
9.
10.
1
1.
12.
13.
14.
Slurry feed
tank
Lining
Agitator,
slurry
feed
tank
Pumps, slurry
feed tank
Dust
collecting
system
Hoist
Bag filler
sysli'in
1
1
2
1
1
1
steel, neoprene lining
46,080 gal, 6,160ft3,
17 -4 diameter x 27'
high, vertical with open
top, (4) 1 '-5 "wide
baffles, carbon steel
%" neoprene lining
lOhp, neoprene
coated
96 gpm, 58' head.
centrifugal, with
variable speed drive
and 3 hp motor, carbon
steel, neoprene lined
8,000 elm, inertial
separator, XQ
cyclone, 2 dust hoppers
fan and drive
5 ton electric
14,000 cfm, automatic
fabric dust collectors.
0.68
0.50
0.46
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Fund, of Cost Engr.
1964
Depends on gpm and head
16,000
14,000
4,717
. 2,060
requirements resulting in
GATX
GATX
Mixing Equip.
Co., Inc.
Denver Equip.
Cp.
1971
1971
1971
1973
19,200
17,000
5,600
2,200
19,200
17,000
5,600
4,400
changes of motor and
impeller size
0.80
t
0.81
0.68
Chem. Engr. 3-24-69
Guthrie
Popper, H.
Chem. Kngr. 3-24-69
Gulhrie . ,
5,894
17,570
1,926
Richardson Engr.
Services
Richardson Engr.
Services
Richardson Engr,
Services
1973
1973
1973
6,400
19,000
8,500
6,400
19,000
8,500
bag support, shaker system,
isolation damper, external
shaker motor and drive,
dust hopper, motor and
fan for bag filter system
0/2 in materials handling
area)
Subtotal
378,700
-------
Area 3- Participate Scrubbing
Table 46. Limestone Slurry Process (Cont.)
Item
l.Tank,
particulate
scrubber,
effluent
hold
Lining
2. Agitator,
effluent
hold tank
3. Pumps,
recycle
slurry
4. Venturi
scrubber
5. Venturi &
MBA sump
Size-cost
scale Factor
No. Description factor source
4 25^00 gal, 3,435 ft3,
13 diameter x 26'
high, open top, (4)
1 ' wide baffles,
carbon steel
Vi" neoprene lining
4 5 hp, neoprene
coated
6 4,900 gpm, 144'
head, centrifugal,
belt drive, 300 hp
motor included, carbon
steel, neoprene lining
4 With variable throat,
36' long x 5 'wide x
20 'high, convey ing
section & throat
carpenter 20, remainder
Vt" carbon steel with
neoprene lining
4 28' long x 41' wide
x 13' high, >/4"
carbon steel, neoprene
lining (Vi in SO2
scrubbing area)
0.68 Chem. Engr. 3-24-69
Guthrie
0.26 Fund, of Cost Engr.
1964
0.50 Chem. Engr. 3-24-69
_ Guthrie . . .
Depends on gpm and head
requirements resulting in
changes of motor and
impeller size
0.60 Universal Oil
Products
0.68 Chem. Engr. 3-24-69
Guthrie
Base Base cost
cost scurce
13,500 GATX
10,000 GATX
3,400 Mixing Equip.
Co.
13,440 Denver Equip.
Co.
133,000 Universal Oil
Products
49,500 Universal Oil
Products
Projected 1974
Date equipment cost
of cost each total
1971 16,300 65,200
1971 12,000 48,000
1971 4,000 16,000
1973 14,500 87,000
1971 150,000 600,000
1971 57,500 230,000
6. Soot
blowers
Subtotal
20
1.00 TVA
3,500 Widows Creek- 1971 4,000 80,000
TVA
1,126,200
103
-------
Table 46. Limestone Slurry Process (Cont.)
Area 4 SO2 Scrubbing
Item
No. Description
Sfise-eoiF
scale
factor
Factor
source
Bate Base coit
cost source
254,500 Universal Oil
T55Ie Projected—T574~"
of equipment cost
cost each total
300,0001,200,000
1. TCA scrubber 4
S02 absorber, mo-
bile bed, with
demister, 41' long x 13
wide x 41' high;%"
carbon steel with
neoprene lining,
316 S.S. grids, high
density poly, spheres,
FRP spray headers,
chevron vane mist
eliminators
0.80
Universal Oil
Products
Products
2. Venturi & 4
MBA sump
3. Tank, 4
absorber
effluent
hold
Lining
4. Agitator, SO2 4
absorber
hold tank
S. Pumps, SO2 10
absorber
recycle
slurry
6. Pumps, 2
makeup
water
7. Soot 40
blowers
Subtotal
28' long x 41'
wide x 13' high ,%"
carbon steel, neoprene
lining (% in paniculate
scrubbing area)
240,000 gal, 32,088
ft3 40' diameter x
26' high, open top,
field erected,
carbon steel
Vt" neoprene lining
50 hp, neoprene
coated
11,500 gpm, 105'
head, centrifugal,
neoprene lined, belt
drive, 500 hp motor
included
1,240 gpm, 150'
head, vertical
multistage turbine,
100 hp motor
included
0.68 Chem. Engr. 3-24-69
Guthrie
0.68 Chem. Engr. 3-24-«9
Guthrie
0.50 Chem. Engr. 3-24-69
Guthrie
Depends on gpm and head
requirements resulting in
changes of motor and
impeller size
Depends on gpm and head
requirements resulting in
changes of motor and
impeller size
1.00 TV A
49,500 Universal Oil
Products
38,327 GATX
32,000 GATX
12,245 Catalytic
Inc.
23,000 Allen, Sherman,
Hoff
2,369 Richardson Engr.
Services
3,500 Widows Creek-
TVA
1971 57,500
1972 45,100
1972 38,600
1973 13,250
1971 27,100
1973 2,600
1971 4,000
2
230,000
180,400
154,400
53,000
271,000
5,200
160,000
,254,000
Area 5 -Reheat
Size-cost
Item No.
l.Gas 4
reheater
2. Soot 20
blowers
Subtotal
Description
tube type. 2,028 ft*
1 3,900 lb,'/j of
tubes made of inconel
625 and remaining V4
made of cor-ten
scale Factor
factor source
0.80 Chem. Engr. 3-24-69
Guthrie
1.00 TV A
Base Base cost
cost source
70,000 Widows Creek -
TVA
3,500 Widows Creek -
TVA
Date Projected
of equipment
cost each
1971 82,500
1971 4,000
1974
cost
total
330,000
80,000
410,000
104
-------
Table 46. Limestone Slurry Process (Cont.)
Area 6-Gas Handling
Item
l.Fan
Subtotal
No. Description
4 41"l,200rpm,
2,905 bhp, 3,250 hp
motor included with
insulation. (Cost is
difference between
41 and 15 fan.
Remainder is
allocated to boiler.)
Size-cost
scale Factor
factor source
0.68 Chem. Engr. 3-24-69
Guthrie
Base
cost
59,710
Base cost
source
Widows Creek -
TVA
Date
of
cost
1971
Projected
equipment
each
71,150
1974
cost
total
284,600
284,600
Area 7 -Solids Disposal
Item
l.Pond feed
tank
No. Description
1 63,000 gal, field
erected, 8,423 ft3,
Size-cost
scale Factor
factor source
0.68 Chem. Engr. 3-24-69
Guthrie
Base
cost
20,000
Base cost
source
GATX
Date
of
cost
1971
Projected
equipment
each
24,000
1974
cost
total
24,000
21' diameter x 26' high,
vertical with open top,
Lining
2. Agitator
3. Pumps, pond
feed tank3
4. Pumps,
recycle pond
water3
Subtotal
carbon steel, 1 - 8
x 26 'baffles
'•/*" neoprene lining
1 7V4 hp, neoprene
coated
4 l,128gpm@75'
head, neoprene
lined with 50 hp
motor
2 1 , 000 gpm @ 150'
head, multistage
turbine, cast iron
bowl, stainless steel
impellers, with 75
hp motor
aCost for this equipment prorated for fly ash
Area 8-Utilities
Note: There is no
0.50 Chem. Engr. 3-24-69
0.47 Fund of Cost Engr. 1964
Depends on gpm and head
requirements resulting in
changes of motor and
impeller size
Depends on gpm and head
requirements resulting in
changes of motor and
impeller size
removal.
16,120
4,717
1,850
1,100
GATX
Mixing Equip.
Co., Inc.
Denver Equip.
Co.
Richardson Engr.
Services
1971
1971
1973
1973
19,000
5,400
2,225
1,450
19,000
5,400
8,900
2,900
60,200
process equipment in this area.
Area 9-Services
Item
1. Pay loader
2. Plant
vehicles
3. Maint. &
instrument
shop-
equipment
4. Service
building-
equipment
5. Stores-
equipment
Subtotal
No. Description
1 Gasoline type,
2yd3
- (allocation)
- Office, machine
tools, and
machine shop
equipment
- Equipment for lab.,
locker room, motor
control room,
restrooms
- Office equipment,
shelving, etc.
Size-cost
scale Factor
factor source
_ _
_ _
Base
cost
21,000
10,000
22,400
Base cost
source
Chem. Engr.-
3-24-69, Guthrie
Chem. Engr.-
3-24-69, Guthrie
29,700 Chem. Engr.-
_ _
9,000
3-24-69, Guthrie
Chem. Engr.-
3-24-69, Guthrie
Date
of
cost
1969
1974
1969
1969
1969
Projected
equipment
each
24,800
26,400
35,000
10,600
1974
cost
total
24,800
10,000
26,400
35,000
10,600
106,800
-------
Table 47. Lime Slurry Process Equipment List and Cost
Area 1 -Raw Material Handling
Item No.
Description
Size-cost
scale
factor
Factor
source
Base
cost
Projected 1974
Base cost Date equipment cost
source of cost each total
1. Convey or 1
(belt) No. I
2. Conveyor 1
(belt) No. 2
3. Storage bin, 4
lime
4. Feeder,
discharge
5. Conveyor 1
elevator
6. Process bin, 1
lime
7. Feeder, bin 2
discharge
8. Bin vibrators 16
9. Bin vibrators 8
Subtotal
Enclosed, 69.3 tons/
hr, 18" belt, 800'
long, 250ft/min, 58'
rise with 15 hp motor
0.65
0.65
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Enclosed, 69.3 tons/
hr, 18" belt, 39'
long, with 3 trippers,
250 ft/min, with 7V4
hp motor
11,820ft3, 325 tons 0.68 Chem. Engr. 3-24-69
field erected, 29'/i x
Il'xSOtt', column
height 22', with
ladders, C/S
Rotary air lock type,
46.2 tons/hr, 18"
diameter by 18 long,
16 rpm
Redler Z type, 103'
long, 46.2 tons/hr
5 hp motor
3,360ft3, ll'x
4'/i', C/S
Rotary air lock type,
n " J • , t\ "
9 diameter by 9
long, carbon steel
National Air
Vibrator Co., BH-5
National Air
Vibrator Co., BH-4
Guthrie
0.58 Chem. Lngr. 3-24-69
Guthrie
0.65 Chem. Engr. 3-24-69
Guthrie
0.65 Chem. Engr. 3-24-69
Guthrie
0.58 Chem. Engr. 3-24-69
Guthrie
30,300 TVA
47,800 TVA
43,765 Rex Chain Belt,
Inc.
3,100 Richardson Engr.
Services
11,300 TVA work
order DO5N71
23,400 Rex Chain Belt,
Inc.
1.400 Richardson Engr.
Services
290 National
Vibrator Co.
190 National
Vibrator Co.
1973 32,800 32,800
1973 51,700 51,700
1973 50,000 200,000
1973 3,300 13,200
1964 17,200 17,200
1973 25,300 25,300
1973 1,500 3,000
1973 300 4,800
1973 200 1,600
349,600
106
-------
Table 47. Lime Slurry Process (Cont.)
Area 2 -Feed Preparation
Hem
1 . Conveyor
(screw)
2. Slaker,
lime
3. Pumps, slaker
product
4. Slurry feed
tank
5. Agitator,
slurry feed
tank
6. Pumps, slurry
feed tank
Subtotal
No. Description
2 5.8tons/hr,9"
diameter feeder
screw, 1 2 diame-
ter conveyor, 12'
long, 20 rpm, with
1 hp motor
2 ll,5501b/hr, 20 'x
5Vi x 9 , neoprene
3 185 gpm, 35' head
centrifugal, with
5 hp motor,
neoprene lined
1 177,600 gal, 23,743
ft3, 31 'diameter
by 32 high vertical
cylinder, open top,
carbon steel, field
erected
Neoprene lining
1 IS hp, neoprene
coated
2 3 70 gpm, 20 'head,
centrifugal, with
5 hp motor,
neoprene lined*
T?i/.e-cosi
scale !• actor Base
factor source cost
0.80 Chem. Engr. 3-24-69 2,200
Guthrie
0.57 Dixie-Cahaba 14,000
lined
Depends on gpm and head 2,200
requirements resulting in
changes of motor and impeller
sizes
0.68 Chem. Engr. 3-24-69 35,000
Guthiie
0.50 Chem. Engr. 3-24-69 7,750
Guthrie
Depends on gpm and head 2,060
requirements resulting in
changes of motor and impeller
sizes
Base cost
source
Chem. Engr.-
3-24-69, Guthrie
Dixie-Cahaba
Denver Equip.
Co.
GATX
Catalytic, Inc.
Denver Equip.
Co.
Projected 1974
Date equipment cost
of cost each total
1969 2,900 3,800
1973 15,100 30.200
1973 2,400 7,200
1971 48,700 48,700
39,900 39,900
1973 8,400 8,400
1973 2,200 4,400
144,600
Area 3 -Paniculate Scrubbing
Item
i.Particulate-
SO2 scrubber
2. Pumps,
participate
scrubber
recycle
slurry
3. Pumps,
makeup
water
4. Soot
blowers
Subtotal
No. Description
4 Variable throat
venturi, 28 diame-
ter x 54 K 'high,
Chevron Vane mist
eliminators
Neoprene lining
10 6,500 gpm, 110'
head, centrifugal,
neoprene lined with
belt drive, guard
and 350 hp motor
2 663 gpm, 150' head
vertical multistage
turbine, with 50
hp motor ('/i in SO2
scrubbing area)
20
Size-cost
scale Factor Base
factor source cost
0.60 Chemico 125,000
Depends on gpm and head 16,188
requirements resulting in
changes of motor and impeller
sizes
Depends on gpm and head 1,250
requirements resulting in
changes of motor and impeller
si/.es
1.0 TV A 3,500
Base cost
source
Chemico
Allen, Sherman,
Hoff
Richardson Engr.
Services
Widows Crcek-
TVA
Projected 1974
Date equipment cost
of cost each total
1971 165,100 660,400
20,900 83,600
1971 19,100 191.000
1973 700 1,400
1971 4.000 80,000
1,016,400
107
-------
Table 48. MagnesiiPSIurry - Regeneration Process Equipment List and Cost
Area 1-Raw Material Handling
Item
I.Cokc
receiving
hopper
i
2. Coke
conveyor
3. Coke
storage
silo
4. Makeup
MgO storage
silo '
5. Pneumatic
conveying
system
6. Sump pump
No. Description
"~l 8'TrSide,27-4'"r
hoi torn, 3 deep,
with load bearing
grizzly and vibrator,
carbon steel
1 Redier Z type, 5fi'
long, 15 tons/hr,
25 hp motor
1 15 ' diameter x 20.5 '
high with 7. 5 'cone
bottom, 4, 132 ft3
volume, with slide
gate for vibrating
hopper, carbon sleel
1 1 8' diameter x 2?'
high with 9 ' cone
bottom, 7,634 ft3
volume, 3/8 carbon
steel plate, vibrating
hopper
Size-cost
scale Factor
factor source
0.68 Chem. l;.ngr. 3-24-69
Guthrie
0.65 Chem. Engr. 3-24-69
Guthrie
0.90 Chem. Engr. 3-24-69
Guthrie
0.90 Chem. Engr. 3-24-69
Guthrie
1 Complete with blower, 0.60 Chem. Engr. 3-24-69
air, heater, cyclone
receiver, receiver
filter and pump
1 5 gpm, 10 head,
carbon steel,
Guthrie
Depends on gpm and head
requirements resulting in changes
Base Base cost
cost source
2,400 Catalytic Inc.
7,359 TVA work
order D05N71
TVA work
order D05C30
TVA work
order D05C30
36,900 Fuller Co.
560 Catalytic, Inc.
Projected 1974
Date equipment cost
of cost each total
1973 2,600 2,600
1964 11,200 11,200
1965 8,500 8,500
1965 13,000 13,000
1965 55,600 55,600
1973 600 600
% hp motor included of motor and impeller sizes
Subtotal
91,500
Area'2-Feed Preparatio"
Item
1. Weigh'
feeder,
makeup MgO
2. Vibrating
feeder,
makeup MgO
3. Conveyor-
elevator,
Mgo
4. Weigh
feeder.
recycle MgO
5. Vibrating
feeder,
recycle MgO
6. MgO
slurry ing
tank
Lining
7. Agitnlor
8. Mgo
slurry pumps
Subtotal
No. Description
1 300 Ib/hr, carbon
steel
1 300 Ib/hr, carbon
steel, Jeffery
2 DTH
1 Redler Z type, 70'
long, 8'/z tons/hr,
5 hp motor
1 8.3 lons/hr carbon
sleel
1 8.3 tons/hr carbon
steel
1 23 in diameter by
34 'high, 14,126ft3
105 ,672 gal field
erected
Neoprenc lining for
MgO slimy ing lank
1 20 hp, hi'oprcnc
coaled
2 263 gpm, 10-20 hp
included centrifugal.
carbon steel,
neoprene lined
•///J
Size-cost
scale Factor
factor source
0.65 Chem. Kngr. 3-24-69
(conveyor) Guthrie
0,58 Chem. Engr. 3-24-69
Guthrie
0.65 Chem. Engr. 3-24-69
Guthrie
0.65 Chem. Engr. 3-24-69
(conveyor) Guthrie
0.58 Chem. Engr. 3-24-69
Guthrie
0.68 Chem. Engr. 3-24-69
Guthrie
0.50 Chem. Engr. 3-24-69
0.47 Fund, of Cost Engr.
1964
Depends'on gpm and head
requirements resulting in changes
of motor and impeller sizes
Base Base cost
cost source
4,500 TVA
500 Richardson- Engr.
Services, for a
Jeffery 2 DTH
7,700 TVA work
order D05N71
7,216 Merrick
500 Richardson Engr.
Services, for a
Jeffery 2 DTH
28,100 GATX
23,000 GATX
7.750 Catalytic, Inc.
2,500 Denver Equip.
Co.
Projected 1974
Date equipment cost
of cost each total
1971 5,300 5,300
1973 500 500
1964 11,700 11,700
1972 8,200 8,200
1973 500 500
1971 33,700 33,700
1971 27.900 27,900
1973 8,400 8,400
1973 2,700 5,400
101,600
-------
Table 48. Magnesia Slurry • Regeneration Process (Cont.)
Area 3 Particulale Scrubbing
Size-cost
1.
Item
Paniculate
scrubbers
No.
4
Description
Venturi, 28 'diame-
ter, 48Vi 'high with
scale Factor
factor source
Base
cost
0.60 Chemico 125,000
Base cost
source
Chemico
Date
of cost
1971
Projected
equipment
each
162,100
1974
cost
total
648,400
variable throat, includes
2.
3.
4.
5.
6.
7.
8.
Surge tanks
Agitators,
surge tank
Recycle
pumps
Underflow
pumps to
pond
Soot
blowers
Pumps,
makeup
water
Neutralization
system
Subtotal
4
4
6
6
20
2
mist eliminator
Neoprene lining
40,600 gal, carbon
steel, 24'
diameter, 12' high
Neoprene lining
20 hp, neoprene
coated
4,740 gpm, 130'
head, neoprene lined,
300 hp motor
1 13 gpm, 55 psi.
neoprene lined,
7'/2 hp motor
880 gpm, 150 '
head, vertical.
multistage turbine
with 50 hp motor
0.68 Chem. Engr. 3-24-69
Guthrie
0.50 Mixing Equip. Co.
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
1 .00 TVA
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
15,950
13,275
10,450
4,717
13,440
2.060
3,500
1,290
Chicago Bridge
and Iron
GATX
Mixing Equip.
Co.
Denver Equip.
Co.
Denver Equip.
Co.
Widows Creek-
TVA
Richardson Engr.
Services
1970
1971
1971
1973
1973
1971
1973
1 (Allocation)
18,800
15,400
12,700
5,500
14,500
2,200
4,000
1,400
30,000
1
75,200
61,600
50,800
22,000
87,000
13,200
80,000
2,800
30,000
,071,000
Area 4- SO2 Scrubbing
Size-cost
1.
2.
3.
Item
SO2
absorbers
Pumps,
recycle
Soot
blowers
Subtotal
No.
4
6
20
Description
Venturi absorber
28 'in diameter
by48'/j'high.
mist eliminator
Neoprene lining
6,320 gpm, 100 '
head with 300 hp
motor, neoprene lined
scale Factor
factor source
Base
cost
0.60 Chemico 150,000
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
1 .00 TVA
15,913
3,500
Base cost
source
Chemico
Allen, Sherman.
Hoff
Widows Creek -
TVA
Date
of cost
1971
1971
1971
Projected
equipment
each
176,900
18,800
18.800
4,000
1974
cost
total
707,600
75,200
112,800
80,000
975,600
Area 5 -Reheal
Size-cost
1
2.
Hem
. Uehcater
Soul
blowers
Subtotal
No.
4
20
Description
Steam, tube type,
1,658ft2, V4 of
tubes made of Incoloy
825, other Vi made
of cor-ten
scale factor
factor source
0.80 Chem. Engr. 3-24-69
Guthrie
1.00 TVA
Base-
cost
70,000
3.500
liase cost
source
Widows Creek-
TVA
Widows Creek-
TV A
Date
of cost
1971
1971
Projected
equipment
each
73,200
4.000
1974
cost
total
292,800
80,000
372.800
-------
Table 48. Magnwla Slurry • Regeneration Process (Cont.)
Area 6 (ins Mundling__
Item No. Description
Size-cost Projected 1974
scale Factor Bate Base cost Date equipment cost
factor source coat source of cost each total
1. Fan
4 39 , 1,190 rpm,
No. 1,035 AF, 3,000
hp motor included
(cost is difference
between 38' and
15 fan, remainder
allocated to boiler)
Insulation for fans
0.68 Chem. Engr. 3-24-69
Guthrie
49,200 Widows Creek- 1971 58,000 232,000
TVA
625 TVA
Subtotal
1973 675 2,700
234,700
Area 7 -Slurry Processing
Item
1. Screens
2. Liquor tank
3. Liquor
pumps
4. Conversion
tank
5. Agitator
6. Steam
coil
7. Pumps
conversion
tank
8. Centrifuges
9. Conveyors,
screw-
horizontal
10. Conveyors,
screw-
vertical
1 1 . Comicnsale
lank
12. Condensate
pump
Subtotal
Size-cost
scale Factor
No. Description factor
4 Wet screens, hous-
ing 4 long, 5 wide,
8 high, DSM screens
1 5, 000 gal, 9 'diame-
ter, lOVa' high,
neoprene lined
2 1 ,440 gpm, 75 '
head with 50 hp
motor, neoprene lined
1 6, 300 gal, 12' diame-
ter, lYi high, stainless
. steel, field
fabricated
1 20 hp, stainless
steel
1 1,200 ft2 area,
stainless steel
2 340 gpm, 55 'head, 10
hp, neoprene lined
2 Parallel 36 "x 72"
solid bowl with 200
hp motors, S/S
1 33.2 tons/hr, 16"
screw, 60 rpm, with
5 hp motor, 20 ft.
long, stainless steel
1 33.2 tons/hr 16"
screw, 60 rpm, with
5 hp motor, 40 ft
long, stainless steel
1 100 gal, carbon
steel
1 25 gpm, 200 psig with
5 hp motor, carbon
steel
0.58 TVA
-
0.30 Chem. Engr. 3-24-69
Guthrie
Depends on gpm and head
. requirements resulting in changes
of motor and impeller sizes
0.66 Fund, of Cost Engr.
1964
0.50 Chem. Engr. 3-24-69
0.51 Fund, of Cost Engr.
1964
0.32 Chem. Engr. 3-24-69
Guthrie
Depends ongpm and head
requirements resulting in changes
of motor and impeller sizes
Base Base cost Date
cost source of cost
4,500 Don-Oliver 1971
8,140 Chem. Engr.- 1969
3-24-69, Guthrie
3,500 Denver Equip, 1973
Co.
19,200 Chem. Engr.- 1969
3-24-69, Guthrie
4,700 Mixing Equip. 1970
Co.
2,000 Chem. Engr.- 1968
3-24-69, Guthrie
2,500 Denver Equip. 1973
Co.
0.73 Chem. Engr. 3-24-«9 86,667 Bird Machine 1971
Guthrie
0.60 (Diameter)
Chem. Engr. 3-24-69
0.77 (Length and diameter)
Fund, of Cost Engr.
1964
0.60 (Diameter)
Chem. Engr. 3-24-69
0.77 (Length and diameter)
Fund, of cost Engr.
1964
0.82 Fund of Cost Engr.
^^it-
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
Co.
3,600 Chem. Engr.- 1969
3-24-69, Guthrie
6,000 Chem. Engr.- 1969
3-24-69, Guthrie
185 TVA 1973
460 Richardson Engr. 1973
Services
Projected 1974
equipment cost
each total
5,300 21,200
10,700 10,700
3,800 7,600
26,100 26,100
5,900 5,900
2,700 2,700
2,700 5,400
102,200 204,400
4,700 4,700
7,900 7,900
200 200
500 500
297,300
112
-------
Table 48. Magnesia Slurry • Regeneration Process (Cont.)
Area 8-Cake Drying
Item
1. Fluid bed
dryer
No.
1
Description
18' diameter by 40 '
high single-stage,
Size-cost
scale
factor
0.60
Factor
source
Dorr-Oliver 1972
Base
cost
350,000
Base cost
source
Dorr-Oliver
Date
of cost
1971
Projected
equipment
each
412,700
1974
cost
total
412,700
2. Dust
collector
3. Fan I.D.
4. Conveyor-
elevator
refractory-lined
carbon steel dryer
with (a) 10 diame-
ter x 16 long, oil-
fired, horizontal,
refractory-lined,
carbon steel combus-
tion chamber, (b) 250-
hp blower, and (c)
refractory-lined, car-
bon steel cyclone with
a conical bottom
1 Fabric dust collector. 0.68
12' 5 "wide by 45 V
long by 2l' 31 high,
44,400 Ib, 57,900 acfm
Dustex model No.
DW-14-60
1 250 hp 0.68
I Redler Z type, 122' ' 0.65
long, 19.6 tons/hr,
25 hp
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
84,800 American Preciiionl971
Industries, Inc.,
Dustex Division
100,000 100,000
19,300 Chem.Engr.-
3-24-69, Guthrie
13,400 TVAwork
order D05N71
1968 26,600 26,600
1964 20,400 20,400
5. MgSO3
storage
silo with
vibrating
hopper
Subtotal
Silo 26 diameter x
43'high, with 13'
cone bottom, 25,489
ft3 volume, 4,794
ft surface area,
3/8' carbon steel
plate
0.90 Chem. Engr. 3-24-69
Guthrie
19,800 TVA work
order D05C30
1965 32,200 32,200
591,900
113
-------
Table 48. Magnesia Slurry - Regeneration Process (Cont.)
Area 9- MgSO3 Calcination
Item
l.Coke
weigh
feeder
2. Vibrating
feeder
3. Conveyor-
elevator
MgO feeder
to fluid
bed cal-
ciner
4. Fluid
bed
calciner
5. Conveyor
elevator
Z-type
calciner
to recycle
MgO
6. MgO recycle
storage
silo
7. Vibrating
feeder
8. Dust
collector
9. Weigh
feeder
10. Waste heat
boiler
1 1 . Conveyor-
elevator dust
collector
to conveyor
elevator to
fluid bed
calciner
Subtotal
Size-cost
scale
No. -/Description factor
1 2181b/hr, 2hp 0.65
(conveyor)
1 218 Ib/hr, 1 hp 0.58
1 Redler Z type, 84' 0.65
long, 20 tons/hr,
25 hp
1 16' diameter x 38' high 0.60
3 stage with cyclone,
carbon steel refrac-
tory-lined with a
400 hp blower and
a refractory-lined
carbon steel cyclone
with a conical bottom
1 Redler Z type, 8?' 0.65
long, 8Vi tons/hr,
15 hp
1 26 ' diameter x 3 1' 0.90
high with 13 cone
bottom, 18,950ft3
volume, 3,814ft2
surface area, 3/£
carbon steel plate
1 39,400 Ib or 19.8 0.58
tons/hr, 2 hp
1 Fabric dust collector 0.68
12-5" wide 33' 8"
longx 21 '3" high.
33,200 Ib, 40,000 ACTM
Dustcx DW- 14-44
1 19.8 tons/hr, 2 lip 0.65
(conveyor)
1 System with 22" 0.67
diameter x 20 long
heat exchanger 840ft2,
30 diameter x 20
long feed water
tank 16,000 Ib/hr
1 Redler Z type 38' 0.65
long, 294 Ib/hr,
2.5 hp
Factor
source
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Dorr-Oliver 1972
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Kngr. 3-24-69
Guthrie
TVA
Chem. Engr. 3-24-69
Guthrie
Base Base cost
cost source
4,500 TVA
500 Richardson Engr.
for a 2 DTH
9,200 TVA work
order D05N71
418,000 Dorr-Oliver
9,600 TVA work
order D05N71
16,400 TVA work
order D05C30
1,550 Richardson Engr.
for a 3 DM
60,800 American Preci-
sion Industries,
Inc., Dustex
Division
7,200 Merrick
24,800 TVA
4,200 TVA work
order DOS N71
Projected 1974
Date equipment cost
of cost each total
1971 5,300 5,300
1973 500 500
1964 14,000 14,000
1971 492,800 492,800
1964 14,500 14,500
1965 26,700 26,700
1973 1,700 1,700
1971 71,700 71,700
1972 8,200 8,200
37,900 37,900
1964 6,400 6,400
679.700
114
-------
Table 48. Magnesia Slurry • Regeneration Process (Cont.)
AMM It) ')8% Suliiiiic Add Production
1.
llcm
Coin pie Ic
H2S04 unit
Subtotal
Area 1 1 -Acid
Item
No. Description
Size-cost
scale
factor
1 Complete 98% sulfuric 0.70
acid system
Storage and Shipping
No. Description
Size-cost
scale
factor
Factor
source
Dorr-Oliver
Factor
source
Base
cost
642,100
Base
cost
Base cost
source
Dorr-Oliver
and Chemico
Base cost
source
Date
of cost
1971
Date
of cost
Projected
equipment
each
785.300
Projected
Equipment
each
1974
cost
total
785,300
785,300
1974
cost
total
1. Sulfuric acid 3 500,000 gal carbon 0.63 Chem. Engr. 3-24-69 36,400 TV A work
storage tanks steel tanks Guthrie order D05C66
1972 41,400 124,100
2. Pumps
Subtotal
2 400 gpm, with 40 Depends on gpm and head
hp motor, carbon requirements resulting in changes
steel of motor and impeller sizes
1,900 Richardson Engr. 1973
Services
2,000 4,000
128,100
Area 12-Utilities
Item
1. Oil heaters
2. Coil heaters
3. Tank,
storage
No.
2
2
1
Description
Coil heaters for
tanks, C/S
Fuel oil storage
tank, 660,000 gal
field erected, C/S
painting included
Size-cost
scale
factor
0.85
0.32
0.63
Factor Base Base cost
source cost source
Chem. Engr. 3-24-69 TVA
Guthrie
Chem. Engr. 3-24-69 TVA
Guthrie
Chem. Engr. 3-24-69 35,500 GATX
Gutluie
Date
of cost
1973
1973
1971
Projected
equipment
each
1,000
1,500
42,600
1974
cost
total
2,000
3,000
42,600
4. Tank, 2
holding
5. Pumps, feed 2
6. Pumps, 2
transfer
Subtotal
Holding lank 24,000 0.30 Chem. Engr. 3-24-69 11,750
gal, field erected, C/S Guthrie
GATX
Catalytic, Inc.
Depends on gpm and head 750
requirements resulting in changes
of motor and impeller sizes
Depends on gpm and head 1,400 Catalytic, Inc.
requirements resulting in changes
of motor and impeller sizes
1971 14,100 28,200
1973 800 1,600
1973 1,500 3,000
80,400
Area 13 -Services
1.
2.
3.
4.
Item No.
Plant
vehicles
Shop
equipment
Service
building
equipment
Stores
equipment
Subtotal
Description
(Allocation)
Office, machine
tools, machine
shop equipment
Equipment for lab,
locker room, motor
control room, resl-
rooms
Office equipment,
shelving, etc.
Size-cost'
scale Factor Base Base cost
factor source cost source
15,000
26,000 Chem. Engr. 3-24-69
Guthrie
34,300 Chem. Engr. 3-24-69
Guthrie
10,300 Chem. Engr. 3-24-69
Guthrie
Date Projected 1974
of equipment cost
cost each total
1974 - 15,000
1971 - 30,600
1971 - 40,400
1971 - 12,100
98.100
115
-------
Table 49. Sodium Solution • SOj Reduction Process Equipment List and Cost
Aieu_T -Makeup Handling »nd
Item
1. Pneumatic
convey-
ing sys-
tem
2. Storage
bin,
soda ash
3. Vibrating
feeder
4. Weigh
feeder
S. Mixing
tank
6. Agitator
7. Antioxi-
dant
feeder
8. Bin
vibrator
9. Pump,
mixing
tank
Subtotal
Size-cost
scale Factor
No. Description factor source
1 Complete with blower, 0.60 Chem. Engr.,3-24-69
air heater, cyclone Guthrie
receiver, receiver (composite)
filter and pump
1 12 'diameter x 36' 0.90 Chem. Engr. 3-24-69
high with cone bottom, Guthrie
4, 500 cu ft, carbon
steel
1 34 cu ft/hr, 1.32 0.80 Chem. Engr. 3-24-69
tons/hr Guthrie
1 1.32 tons/hr, with 0.65 Chem. Engr. 3-24-69
discharge chute (conveyor) Guthrie
1 12' in diameter by 0.30 Chem. Engr. 3-24-69
14 'high, .11, 800 gal Guthrie
with 4-1 ' wide x 14'
long baffles, carbon
steel, with flake-
line lining-ceilcote
1 3 hp, neoprene 0.50 Chem. Engr. 3-24-69
coated 0.21 Fund, of Cost Engr.
1964
1 45 Ib/hr with chute 0.65 Chem. Engr. 3-24-69
(conveyor) Guthrie
2 Syntron model
RV-44-B
'I 25 gpm, 75'head, Depends on gpm and head
horizontal centrifu- requirements resulting in changes
gal, with 1 hp motor of motor and impeller sizes
Base Base cost
cost source
36,900 Fuller Co.
6,800 TVA work
order D05C30
500 Richardson Engr.
Services
6,000 Vibra Screw,
Inc.
7,800 GATX
1,400 TVA
1,800 Vibra Screw,
Inc.
768 Syntron.FMC
Corp,
800 TVA
Date
of
cost
1965
1965
1973
1973
1971
1970
1973
1973
1970
Projected
equipment
each
55,600
10,200
500
6,400
10,200
1,800
1,900
850
1,000
1974
cost
total
55,600
10,200
500
6,400
10,200
1,800
1,900
1,700
2,000
90,300
116
-------
Table 49. Sodium Solution • SOa Reduction Process (Cont.)
Areu 2 Purliculute Scrubbing
Item
1. Particu-
late
scrub-
bers
2. Surge
tanks
3. Agitator,
surge
tank
4. Recycle
pumps
5. Underflow
pumps to
pond
6. Neutrali-
zation
system
7. Soot
blowers
8. Pumps,
make up
water
Subtotal
Size-coit
icalc Factor
No. Description factor source
4 Venturi, 28' dia-
meter, 48Vi' high with
variable throat, in-
cludes mist elimina-
tor
Neoprene lining for
above
4 40,600 gal carbon
steel, 24' diameter
12' high
Neoprene lining for
above
4 20 hp, neoprene
coated
6 4,740 gpm, 130' head
neoprene lined, 300
hp motor
6 113 gpm, 55 psi,
neoprene lined,
7Vi hp motor
. 1 (Allocation)
20
2 880 gpm, ISO 'head,
verticle, multi-
stage turbine with
SO hp motor
0.60 Chemico
0.68 Chem. Engr. 3-24-69
Guthrie
0.50 Mixing Equipment
Co.
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
1.00 TVA
Depends on gpnvand head
requirements resulting in changes
of motor and impeller sizes
Date Projected
Base Base cost of equipment
cost source cost each
125,000 Chemico 19-71
13,275 Chicago Bridge 1970
and Iron
10,450 GATX 1971
4,717 Mixing Equip- 1971
ment Co.
13,440 Denver Equip- 1973
ment Co.
2,060 Denver Equip- 1973
ment Co.
3,500 Widows Creek- 1971
TVA
1,290 Richardson Engr. 1973
Services
162,100
18,800
15,400
12,700
5,500
14,500
2,200
' 30,000
4,000
1,400
1974
cost
total
648,400
75,200
61.600
50,800
22,000
87,000
13,200
30,000
80,000
2,800
1,071,000
117
-------
Table 49. Sodium Solution- S02 Reduction Process (Cont.)
Area3-SO2 Absorption
Item No. Description
1. S02 4 31 'diameter, 60'
absorber high, carbon steel
with S/S internals,
fleximesh mist
eliminator with
fiberglass lining
Neoprene lining for
above
Size-cost
scale Factor
factor source
0.80 Fund, of Cost Engr.
1964
V
./
Date
Base Base cost of
cost source cost
480,000 Koch Engr. Co. 1973
1973
Projected 1974
equipment cost
each total
519,350 2.077,400
13,525 54,100
2. Recycle
pumps
Subtotal
16
1.000gpm60 head
with 35 hp motor,
centrifugal, neo-
prene lined
Depends on gpm and head
requirements resulting in change
of motor and impeller sizes
2,895 Denver Equip.
Co.
1973 3,132 50,100
2,181,600
Area 4-Reheat
Item
No.
Description
Size-cost
scale
factor
Factor
source
Base
cost
Base cost
source
Date Projected
of equipment
cost each
1974
cost
total
1. Reheater
2. Soot
blowers
Subtotal
Steam, tube type,
1,752 sq ft, '/2
tubes inconel 625,
'/2 tubes cor-ten
20
0.80 Chem. Engr. 3-24-69
Guthrie
1.00 TVA
70,000 Widows Creek- 1971 82,500 330,000
TVA
3,500 Widows Creek- 1971 4,000 80,000
TVA
410,000
Area 5-Flue Gas Handling (Fans and Ducts)
Item
1. Fan
Subtotal
No.
4
Description
41.5", 1,200 rpm,
3,500 hp motor in-
Size-cost
scale
factor
0.68
Factor
source
Chem. Engr. 3-24-69
Guthrie
Base
cost
59,700
Base cost
source
Widows Creek -
TVA
Date
of
cost
1971
Projected
equipment
each
70,400
1974
cost
total
281,600
cluded (cost is dif-
ference between 41.5 '
and 15 fan, re-
mainder allocated to
boiler)
Insulation for fans
700 TVA
1973
750
3,000
284,600
118
-------
Table 49. Sodium Solution • SO3 Recluc tion Process (Cont.)
Ami d I'll if/,1' Tn'iilim'iil
Si/i'-riMl
scule Factor
_No. IK'Scriplion _lai'L<>L_ _ source
Mem
I. Refriger-
ation system
2. Pumps,
etheylene
glycol
3. Tank,
etheylene
glycol
4. Tank,
chiller-
crystallizer
5. Pumps,
chiller-
crystallizer
6. Feed cooler
7. Centrifuge
8. Tank,
centra te
9. Pumps,
centtatc
10. Belt convey-
or, centri-
fuge and re-
cycle to
dryer
11. Dryer,
rotary
12. Belt convey-
or, dryer lo
elevator
I 3. Uuckct
elevator
14. Weigh I'mliT,
recycle bin
Iliise lln.se cost
cost source
Dule Projected
of equipment
cost each
1974
cost
total
I 500 tons 0.72
2 2,607 gpm, 125'head
horizontal, centrif-
ugal, with 200 hp
motor
1 lo'diameter, 15' 0.30
high with top 8,813
gal., insulated
Insulation for above
1 12'diameter, 18' 0.65
high, VA" S/S plate,
insulated
Insulation for above
2 350 gpm, 50' head
horizontal, centrif-
ugal, ncopronc lined,
with 10 hp motor
1 1,529 ft2, shell 0.65
and tube, 316 S/S
1 36"diameter, 96" 0.73
solid bowl, 316 S/S
with 300 hp drive
1 5'diameter, 8'high 0.30
960 gal,closed lop,
S/S
2 350 gpm, 75'head,
hori/ontal, centrif-
ugal, neoprene lined
with 15 hp motor
1 18" belt, 14'long, 0.65
50 tons/hr, 100 0.23
ft/min with 1 hp
motor
I 12'diameter, 60' 0.45
long, with 175 hp 0.92
motor
I 18" belt, 14'long, 0.65
50 tons/hr 100 ft/min
with 1 hp enclosed
motor
I 4'/ high, 50 tons/hr, 0.83
I O"X(-"N ft'//'
bucket, 2(.0 fl/min
with 7.5 lip motor
I .M» Ions/hi, 100 0.65
fl/min, 18 belt, (conveyor)
Fund, of Cost Engr.
1964
49,700 Trane
Depends on gpm and head 6,306 Richardson Engr.
requirements resulting in changes of Services
motor and impeller sizes
Chem. Kngr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
7,000 Chem. Engr.-
3-24-69, Guthrie
120,000 Platecoil Co.
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
3,000 Denver Equip.
Co.
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
Chem. Engr. 3-24-69
Fund, of Cost Engr.
1964
45,000 Chem. Engr.-
3-24-69, Guthrie
108.400 Bird Machine
Co.
6,400 Chem. Engr.-
3-24-69, Guthrie
3,500 Denver Equip-
ment Co.
1,850 TVA
1973 53,800
1973 6,800
1969 9,800
500
1973 129,800
500
1973 3,250
1969 47,500
1971 130,000
1969 8,800
1973 3,800
1973 2,000
S 3,800
13,600
9,800
500
129,800
500
6,500
47,500
130,000
8,800
7,600
2,000
Chem. Engr. 3-24-69-
Fund of Cost Engr.
1964
Chem. Engr. 3-24-69
Fund of Cost Engr.
1964
Chem. Engr. 3-24-69
Guihrie
Chem. Eng:. 3-24-69
Guthrie
120,000 TVA
2,300 TVA
4,100 TVA
7,400 TVA
1971 141,500 141,500
1973 2,500
1964 6,200
1973 8,000
2,500
6,200
8,000
5 long, with
motor
hp
119
-------
Table 49. Sodium Solution- Sty Reduction Process (Cont.)
Item
15. Bin, recycle
16. Feeder,
vibrating
17. Conveyor,
recycle
18. Dust
collector
No. Description -'
1 100 ft3, C/S
closed'top
1 30 tons/hr
Size-cost
scale Factor
factor source
0.68
0.65
Chem. Engr. 3-2449
Guthrie
Chem. Engr. 3-24-69
Date
Base Base cost of
cost source cost
1,850 TVA 1973
1,850 TVA 1973
Projected 1974
equipment cost
each total
2,000 ""• 2,000
2,000 2,000
(conveyor) Guthrie
1 18" belt, 30
tons/hr, 95* long,
enclosed with 1 hp
motor'
1 Fabric dust collec-
tor 12-5 " wide,
45'-8" long, 2l'-3"
high, 44,400 Ib,
0.65
0.50
0.68
Chem. Engr. 3-24-69
Fund, of Cost Engr.
1964
Chem. Engr. 3-24-69
Guthrie
4,600 TVA 1973
84,800 American Preci- 1971
sion Industries
Inc. , Dustex
Division
5,000 5,000
100,000 100,000
57,900 acfm, Dustex
19. Fan, dust
collector
20. Steam/air
heater
21. Dust con-
veyor
No. 1
22. Dust con-
veyor
No. 2
23. Belt con-
veyor,
storage
bin load-
ing
24. Bin,
storage .
and load-
ing
25. Bin vi-
brator
26. Agitator,
chiller-
crystal-
lizer
Subtotal
model DW-14-60
1 Fan for above
250 hp
1 Air heater, finned
tube, 735 ft2
insulated, without
motor fan, C/S
1 14" belt, 2 tons/hr,
45 'long, covered,
with 1 hp motor
1 14" belt, 2 tons/hr,
30 'long, covered,
with 1 hp motor
1 14" belt, 2 tons/hr,
68 'long, enclosed,
with 3 hp motor
1 20 1 wide, 40' high,
10 'deep, with cone
bottom, 8,000 ft3,
carbon steel
4 Syntron model
RV-44-B'
1 5 hp, neoprene '
coated '
0.68
0.80
0.65
0.50 ;
0.65
0.23
0.65
0.23
0.90
0.50
0.46
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-69
Guthrie
Fund, of Cost Engr.
1964
Chem. Engr. 3-24-69
Guthrie
Fund, of Cost Engr.
1964
Chem. Engr. 3-24-69
Guthrie
Fund, of Cost Engr.
1964
Chem. Engr. 3-24-69
Guthrie
Chem. Engr. 3-24-^9
Fund, of Cost Engr.
1964
*
19,300 Chem. Engr.- 1968
3-24-69, Guthrie
5,800 Chem. Engr.- 1969
3-24-69, Guthrie
4,600 TVA 1973
3,700 TVA 1973
2,775 TVA 1973
12,200 TVA 1965
768 Syntron, FMC 1973
Corp.
1,550 TVA 1970
26,600 26,600
8,500 8,500
5,000 5,000
4,000 4,000
3,000 3,000
18,400 18,400
850 3,400
1,550 2,000
748,500
120
-------
Table 49. Sodium Solution - SO2 Reduction Process (Cont.)
Area 7-50; Regeneration
1
2.
Hem
. Surge tank
Pump,
surge tank
No. Description
1 36' diameter, 38'
high, 278,400 gal,
carbon steel
Lining for above
2 600 gpm, 125 'head
horizontal centrif-
ugal with 40 hp
Size-cost
scale Factor
factor source
0.68 Chem. Engr. 3-24-69
Guthrie
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
Base
cost
41,100
3,400
Base cost
source
GATX
Denver Equip.
Co.
Date Projected
of equipment
cost each
1972 48,000
35,100
1973 3,700
1974
cost
total
48,000
35,100
7,400
motor, neoprene lined
•3.
i!
4.
5.
6.
7.
8.
9.
10.
11
Evaporator-
crystal-
lizer sys-
tem (com-
plete)
Stripper
Dissolving
tank
Agitator,
dissolving
tank
, Pumps, dis-
solving
tank
Compressor
Condensatc
tank
, Condensate
pumps
. Dcsuper-
heater
Subtotal
2 Shell and tube heat-
er, evaporator-crys-
tallizer, pumps-evap.
circulation, primary
condensers
2 2 '-8 "diameter, 16'
high, 316 stainless
steel
2 36 'diameter, 20'
high, 152,280 gal,
carbon steel, resin
lined
Lining for above
2 1 0 hp, neoprene
coated
2 600 gpm, 100' head,
horizontal, centrif-
ugal; neoprene lined
2 1 ,268 scfm with 250
hp drive
1 lO'diameter, 16'
long, horizontal,
9,408 gal, insulated
carbon steel
Insulation for above
2 600 gpm, 125 'head,
horizontal, centrif-
ugal, with 30 hp
motor
1 250,000 Ib/hr, with
pressure reducing
station
0.70 Chem. Engr. 3-24-69
Guthrie
0.79 Fund, of Cost Engr.
1964
0.68 Chem. Engr. 3-24-69
Guthrie
0.46 Chem. Engr. 3-24-69
Guthrie
0.50 Fund, of Cost Engr.
1964
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
0.90 Fund, of Cost Engr.
1964
0.30 Chem. Engr. 3-24-69
Guthrie
Depends on gpm and head
requirements resulting in changes
of motor and impeller sizes
0.65 Chem. Engr. 3-24-69
Guthrie
600,000
9,600
21,000
4,717
3,400
42,260
6,000
1,575
5,100
Goslin
TVA
GATX
Mixing Equip.
Co.
Denver Equip.
Co.
Turbo-netics
Chem. Engr.-
3-24-69, Guthrie
Richard; son Engr.
Services
Copes-Vulcan
Inc.
Area 8-SOi Reduction
\~
Item
SO j reduc-
tion (mil
Subtotal
No. Description
1 Complete unit
Size-cost
scale Factor
factor source
0.55 Allied Chemical 1
Base
cost
,728,000
Base cost
source
Allied Chemical
1973 649,200
1973 10,400
1972 23,850
23,150
1971 5,500
1973 3,700
1974 43,950
1969 8,300
500
1973 1,700
1974 5,300
Date Projected
of equipment
cost each
1973 1,869,700
1,298,400
20,800
47,700
46,300
11,000
7.4C")
87,900
8,300
500
3,400
5,300
1,627,500
1974
cost
total
1,869,700
1,869,700
121
-------
Table 49. Sodium Solution • S02 Reduction Process (Coin.)
Area 9-Sulfur Storage and Shipping
Item
1. Tanks, sulfur
storage
No. Description
1 43' diameter, 4l'
high, 467, 109 gal.
carbon steel, closed
top
Size-cost
scale Factor
factor source
0.68 Chem. Engr. 3-24-69
Guthrie
Date Projected 1974
Base Base cost of equipment cost
cost source cost
45,000 Chem. Engr.- 1969
3-2449, Guthrie
each total
64,800 64,800
2. Pumps, sulfur 4
3. Sulfur re-
ceiving pit
Subtotal
Insulation for above
125 gpm, 100' head,
high temp., steam
traced and insulated,
with 10 tip motor
10 wide, 10 long,
10'deep, with cover
304 S.S.
Insulation for above
Depends on gpm and head 1,850 TVA
requirements resulting in changes
of motor and impeller sizes
0.90 Chem. Engr. 3-24-69 1,600 TVA
Guthrie
1973
10,000
2,000
2,400
10,000
8,000
1973 17,600 17,600
2,400
102,800
Area 10-Utilities
Note: There is no process equipment in this area
Area 11 -Services
1.
2.
3.
4.
Item
Plant
vehicles
Main, and in-
strument
shop equip-
ment
Service
building
equipment
Stores equip-
ment
Subtotal
Size-cost
scale Factor
No. Description factor source
(Allocation)
Office, machine tools
and machine shop
equipment
- Equipment for lab, - -
locker room, motor
control room, rest-
rooms
- Office equipment, -
shelving, etc.
Base
cost
15,000
26,000
34,300
10,300
Base cost
source
-
Chem. Engr.-
3-24-69, Guthrie
Chem. Engr.-
3-2A-69, Guthrie
Chem. Engr.-
3-24-69, Guthrie
Date
of
cost
1974
1971
1971
1971
Projected
equipment
each
-
30,600
40,400
12,100
1974
cost
total
15,000
30,600
40,400
12,100
98,100
122
-------
Table 50. Catalytic Oxidation Process Equipment List and Cost
Aira I Slinlii|i bypass duels
Note: There is no process equipment in this urea.
Area 2- Flue gas cleaning
Item No.
1. Precipitator 4
Subtotal
Size-cost
scale Factor
Description factor source
Double compartment 0.75 Chem. Engr. 3-24-69
high temp., 99.9% ef- Outline
ficiency precipita-
tor75'highby 100'
wide by 50 deep
625,000 acfm at
890 °F and 8" H20
Date Projected 1974
Base Base cost of equipment cost
cost source cost each total
1,032,500 TVA 1973 1,117,165 4,468,700
4,468,700
Area 3--SO2 Conversion
Item No.
1. Converter 4
2. Unloading 1
conveyor
3. Catalyst 1
elevator
4. Catalyst 1
sifter
5. Hopper, fly 1
ash collection
6. Catalyst 1
storage
bin
7. Catalyst 1
loading
conveyor
Subtotal
Size-cost
scale Factor
Description factor source
Converter 50' high 0.90 TVA
by 33 wide by
36 long, plate
work, screens, insu-
lation, catalyst
discharge, gates,
platforms, paint,
etc. , carbon steel
55.2 tons/hr, 20" 0.65 Chem. Engr. 3-24-69
belt, 250 fpm, 350' Guthvie
long with 5 hp
motor totally
enclosed
Bucket elevator 90' 0.83 Chem. Engr. 3-24-69
high with 18"x g" Guthrie
x II 3/4 "buckets
and 10 hp motor
Catalyst sifter 0.55 TVA
4 wide by 10 long
single deck screen
with 3 hp motor
Hopper 8 'diameter 0.68 Chem. Engr. 3-24-69
by 16' high with 8' Guthrie
cone, 938 ft3 with
closed top, carbon
steel
Hin, 18' diameter by 0.68 Chem. Engr. 3-24-69
25 'high with is'
cone, 7,634 ft3
with closed top,
carbon steel
Belt conveyor 260' 0.65 Chem. Engr. 3-24-69
with tripper, 20" Guthrie
belt and 25 hp motor
enclosed
Date Projected 1974
Base Base cost of equipment cost
cost source cost each total
118,200 Stanford Re- 1970 146,800 587,200
search Insti-
tute, Monsanto
11,120 TVA 1973 12,000 12,000
18,200 Chem. Engr.- 1969 24,000 24,000
3-24-69, Guthrie
3,000 Stanford Re- 1970 3,700 3,700
search Insti-
tute, Monsanto
3,700 TVA 1973 4,000 4,000
8,800 TVA 1973 9,500 9,500
28,120 TVA 1973 30,400 30,400
670,800
123
-------
Table SO. Catalytic Oxidation Process (Cont.)
Area 4-Heat Recovery
Item
1. Econo-
mizer
2. Air
heater
3. Steam/air
heater
4. Fluid/air
heater
5. Conden-
sate
heater
6. Surge
tank
7. Pump
recirculating
Subtotal
§ize-cost
scale Factor
No. Description factor source
4 Economizer 6.9' wide 0.80 TVA
by 33.5' high by
8.4 long, finned
tube gas to water
heat exchanger
4 Air heater 6.6' high 0.80 Chem. Engr. 3-24-69
by 24.4' wide by 26.6* Guthrie
long, 115,600 ft2, gas to
air heat exchanger (as com-
pared to 158,400 ft2 each re-
quired for normal power plant
operation- credit for power
plant is assumed for uniform
comparison with other processes.)
4 Air heater 14.4 ' 0.80 Chem. Engr. 3-24-69
high by 30.2' wide Guthrie
by 2.22' long, fin-
ned tube steam to
air heater, 9;260 ft2
area
4 Air heater 14.4' 0.80 Chem. Engr. 3-24-69
high by 30.2' wide Guthrie
by 8.86' long, fin-
ned tube liquid to
air heat exchanger
81,730ft2 area
4 4,034 ft2 carbon 0.65 Chem. Engr. 3-24-69
steel shell and tube Guthrie
water to condensate
heat exchanger
2 Cooling water surge 0.30 Chem. Engr. 3-24-69
tank-No. 2 acid Guthrie
cooler, vertical
cylinder, 8,136 gal.,
carbon steel open top
6 Condensate heater Depends on gpm and head
tank pump and drive, requirements resulting in changes
1 ,356 gpm @ 162 of motor and impeller sizes
head, centrifugal
with lOOhp motor
Base Base cost
cost source
64,600 Colbert unit
No. 5 -TVA
6,000 Chem. Engr.-
3-24-69, Guthrie
30,000 Chem. Engr.-
3<24-«9, Guthrie
23,000 Chem.Engr.-
3-24-69, Guthrie
6,300 Chem.Engr.-
3-2449, Guthrie
3,275 Richardson Engr.
Services
Date Projected 1974
of equipment cost
cost each total
N/C
1960 (102,700) (410,800)
1969 8,800 35,200
1969 43,400 173,600
1969 33,200 132,800
1969 8,700 17,400
1973 3,500 21,000
(30,800)
Area 5- Fans
Item
I. F. D. Fan
2. 1. D. Fan
Subtotal
Size-cost
scale Factor
No. Description factor source
4 16.5", 270,000 cfm 0.68 Chem. Engr. 3-24-69
with 1,000 hp motor Guthrie
4 46", 393,000 cfm 0.68 Chem. Engr. 3-24-69
with 3,750 hp motor Guthrie
(cost is difference
between 46" and 15 "
fan, remainder al-
located to boiler)
Base Base cost
cost source
66,900 Widows Creek -
TVA
Date Projected 1974
of equipment cost
cost each total
N/C
1971 78,875 315,500
315,500
124
-------
Table 50. Catalytic Oxidation Process (Cont.)
Area 6 -Sulfuric Add Absorption and Cooling
Item
1. Absorber
and mist
elimi-
nator
2. Pumps ,
acid
circulation
3. No. 1
circula-
tion
acid
cooler
4. Tank,
coolant
surge
5. Pumps,
coolant
reciiculation
6. No. 2
circula-
tion
acid
cooler
7. Product
acid
cooler
8. Tank, in-
termit-
tent
wash
9. Pumps,
intermittent
wash
Subtotal
Size-cost
scale Factor Base
No. Description factor source cost
2 Vertical, cylindri-
cal, brick-lined,
packed with Brink
fiber demister
10 65 psig, 90S.5 gpm,
with 60 hp motor
8 Acid to fluid heat
exchanger, impervi-
ous graphite tubes,
12,200ft2, carbon
steel shell
Insulation for above
2 Cooling solution
surge tank, vertical
cylinder, 7,506 gal,
carbon steel
6 85 psig, 1,251 gpm,
with 125 hp motor
4 Acid to water heat
exchanger, impervi-
ous graphite tubes,
8,070 ft2, carbon
steel shell
2 Shell and tube acid
to water heat ex-
changer, impervious
graphite tubes, 165
ft , carbon steel
shell
1 8, 000 gal, 10' dia-
meter by 13.5 'high
carbon steel, open top
2 800 gpm ,100' head
with 40 hp motor
0.90 TVA 1,538,500
Depends on gpm and head 3 ,4 1 7
requirements resulting in changes
of motor and impeller sizes
0.65 Chem. Engr. 3-24-69 133,000
Guthrie
0.30 Chem. Engr. 3-24-69 6,000
Guthrie
Depends on gpm and head 3,893
requirements resulting in changes
of motor and impeller sizes
0.65 Chem. Engr. 3-24-^9 95,000
Guthrie
0.65 Chem. Engr. 3-24-69 4,500
Guthrie
0.30 Chem. Engr. 3-24-69 6,200
Guthrie
Depends on gpm and head 2,400
requirements resulting in changes
of motor and impeller sizes
Date
Base cost of
source cost
Monsanto 1970
Richardson Engr. 1973
Services
Karbate 1971
Chem. Engr.- 1968
3.-24-69, Guthrie
Richardson Engr. 1973
Services
Karbate 1971
Karbate 1971
Chem. Engr.- 1968
3-24-69, Guthrie
Richardson Engr. 1973
Services
Projected 1974
equipment cost
each total
1,910,850 31)1,700
3,700 37,000
156,800 1,254,400
3,000 24,000
8,300 16,600
4,200 25,200
114,000 456,000
5,300 • 10,600
8,500 8,500
2,600 5,200
5,659,200
125
-------
Table SO. Catalytic Oxidation Process (Cunt.)
Area 7 Acid Storage andjihjgping_
Item
1. Product
acid
storage
tank
2. Acid
loading
pumps
Subtotal
Size-cost
scale Factor Base
No. Description factor source cost
4 50 'diameter by 35'
high vertical cylin-
der, 500,000 gal
carbon steel
2 400 gpm pumps, with
40 hp motor
0.68 Chem. Engr. 3-24-69 14,200
Guthrie
Depends on gpm and head 1,893
requirements resulting in changes
of motor and impeller sizes
Date Projected 1974
Base cost of equipment cost
source cost each total
TVAwork 1972
order D05C66
Richardson Engr. 1973
Services
16,100 64,400
2,000 4,000
68,400
Area 8-Utilities
Note: There is no process equipment in this area.
Area 9-Services
1.
2.
Item No.
Vehicles
Shop build-
Description
(Allocation)
Maintenance and
Size-tost
scale
factor
-
-
1'actor
source
-
-
Base
cost
10,000
26,400
Base cost
source
-
-
Date
of
cost
1974
1974
Projected
equipment
each
-
-
1974
cost
total
10,000
26,400
ing equip-
ment
Subtotal
instrumentation
shop equipment
(allocation)
36,400
126
-------
Table 51. Limestone Slurry Process
Total Average Annual Operating Costs Summary3
Case
Coal-fired unit
Years
remaining
life
Total annual
operating
cost, $
Dollars/ton
(bbl)ofcoal
(oil) burned
Mills/
kWh
Cents/
million Btu
heat input
Dollars/
ton sulfur
removed
90% SOj removal; on-site solids disposal
200 MWN 3.5% S 30 3,921,500 7.31 2.80 30.45 267.31
200MWE3.5%S 20 3,867,100 6.98 2.76 29.08 255.25
500MWE3.5%S 25 7,892,600 5.88 2.26 24.51 215.17
500 MW N 2.0% S 30 6,774,700 5.16 1.94 21.51 330.47
500 MW N 3.5% S 30 7,702.700 5.87 2.20 24.45 214.68
500 MWN 5.0% S 30 8,522,200 6.49 2.43 27.05 166.25
1,OOQMWE3.5%S 25 12,752,900 4.86 1.82 20.24 177:72
I,OOOMWN3.5%S 30 11,874,100 4.68 1.70 19.50 171.17
80% SOj removal; on-sitc solids disposal
500 MWN 3.5%S 30 7,378,000 5.62 2.11 23.42 231.36
90% S02 removal; off-site solids disposal
500 MWN 3.5% S 30 8,376,500 6.38 2.39 26.59 233.46
90% SOj removal; on-site solids disposal
(existing unit requiring particulate
scrubber)
500MWE3.5%S 25 9,573,400 7.14 2.74 29.73 261.00
Oil-fired power unit
90% SOz removal; on-site solids disposal
200 MW N 2.5% S
500 MWN 1.0% S
500 MW N 2.5% S
500 MW N 4.0% S
500 MW E 2.5% S
1,OOP MWN 2.5% S
aStack gas reheat to 175° V.
Power unit on-stream time, 7,000 lir/yr.
Midwest plant location, 1975 operating costs.
Investment and operating cost for disposal of fly ash excluded.
Limestone raw material cost, $4/lon.
Trucking and off-site costs for calcium solids disposal, $4/ton.
30
30
30
30
25
30
2,842,000
4,732,500
5,564,400
6,281,800
6,587,300
8,987,400
1.38
0.94
1.11
1.25
1.28
0.92
2.03
1.35
1.59
1.79
1.88
1.28
22.07
15.02
17.66
19.94
20.46
14.76
362.96
618.63
290.87
205.15
336.77
242.97
127
-------
Table 52. Lime Slurry Process
Total Average Annual Operating Costs Summary3
Case
Coal-fired power unit
90% S02 removal; on-site solids disposal
200 MW N 3.5% S
200 MW E 3.5% S
500 MW E 3.5% S
500 MW N 2.0% S
500 MW N 3.5% S
500 MW N 5.0% S
1,OOOMWE3.5%S
1,000
-------
Table 53. Magnesia Slurry - Regeneration Process
Total Average Annual Operating Costs Summary8
Case
Coal-fired power unit
90% S02 removal
200MWN3.5%S
200MWE3.5%S
500 MW E 3.5% S
500 MW N 2,0% S
500 MW N 3.5% S
500MWN5.0%S
1,OOOMWE3.5%S
1,OOOMWN3.5%S
80% SO2 removal
500MWN3.5%S
90% S02 removal
(existing unit requiring particulate
scrubber)
500MWE3.5%S
Oil-fired power unit
90% S02 removal
200 MW N 2.5% S
500MWN1.0%S
500 MW N 2.5% S
500 MW N 4.0% S
500 MW E 2.5% S
1,OOOMWN2.5%S
Years Total annual
remaining operating
life cost, $
30
20
25
30
30
30
25
30
30
25
30
30
30
30
25
30
4,776,800
5,091,200
9;607,900
7,523,400
9,210,800
10,768,500
15,481,900
14,347,000
8,789,700
11,227,300
3,204,400
4,633,100
6,092,700
7,393,500
7,308,700
9,715,900
Dollars/ton
100%
H2S04
105.68
109.25
85.10
119.23
83.43
68.24
70.09
67.20
89.51
99.44
132.96
196.32
103.44
78.49
121.41
85.30
Dollars/ton Cents/
(bbl)ofcoal Mills/ million Btu
(oil) burned kWh heat input
8.90
9.19
7.16
5.73
7.02
8.20
5.90
5.65
6.70
8.37
1.56
0.92
1.21
1.47
1.42
1.00
3.41
3.64
2.75
2.15
2.63
3.08
2.21
2.05
2.51
3.21
2.29
1.32
1.74
2.11
2.09
139
37.09
38.28
29.84
23.88
29.24
34.19
24.57
23.56
27.90
34.87
24.88
14.71
19.34
23.47
22.70
15.95
Dollars/
ton sulfur
removed
323.85
334.29
260.66
365.04
255.43
209.02
214.64
205.78
274.16
304.59
407.17
602.48
316.83
240.28
371.75
261.32
"Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Investment and operating cost for disposal of fly ash excluded.
129
-------
Case
('<>aNlredjH>wer_unj(
90% SO2 removal
200MWN3.5%S
200MWE3.5%S
500MWE3.5%S
500 MW N 2.0% S
500 MW N 3.5% S
500MWN5.0%S
1,OOOMWE3.5%S
1,OOOMWN3.5%S
80%S02 removal
500MWN3.5%S
90%S02 removal
(existing unit requiring particulate
scrubber)
500MWE3.5%S
Table 54. Sodium Solution • SOj Reduction Process
Total Average Annual Operating Costs Summary1
Years Toliil annual Dollars/ton Dollars/ton
remaining operating product (bbl)ofcoal
Iije costj!_ sulfur (oil) burned
30
25
Dollars/
Mills/ million Blu ton sulfur
kWh heal input removed
30
20
25
30
30
30
25
30
5,971,700
7,377,700
14,658,000
9,101,700
11,601,500
13,983,300
25,118,500
18,391,300
446.65
534.62
438.60
487.24
354.79
299.36
384.13
290.96
11.13
13.31
10.92
6.93
8.84
10.65
9.57
7.25
4.27
5.27
4.19
2.60
3.31
4.00
3.59
2.63
46.36
55.47
45.52
28.89
36.83
44.39
39.87
30.20
407.07
486.98
399.62
443.99
323.34
272.79
350.03
265.12
10,834,300 372.83
16,389,200 490.40
8.25
12.22
3.10 34.39 339.74
4.68 50.90
Oil-fired power unit
90%SO2 removal
200 MW N 2.5% S
500 MW N 1.0% S
500MWN2.5%S
500 MW N 4.0% S
500 MW E 2.5% S
!.OPJLMW.N2,5%_S
aStack gas reheat to ITS^K
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.'
Investment and operating cost for disposal of fly ash excluded.
446.82
30
30
30
30
25
30
4,269,200
5,854,700
8,305,100
10,640,500
10,261,600
13,686,200
598.77
839.99
476.21
381.38
575.85
406.00
2.07
1.16
1.65
2.11
1.99
1.41
3.05
1.67
2.37
3.04
2.93
1.96
. 33.15
18.59
26.37
33.78
31.87
22.47
545.24
765.32
434.14
347.50
524.62
370.00
5.10
T
T
T
Limestone slurry process - X
Lime slurry process • "
Magnesia slurry • regeneration process - O
Sodium solution S02 reduction process • 0
Catalytic oxidation process • "
3.5% S in coal
90% SO) removal
7,000 hr annual operation
T
T
I
I
I
I
I
200
600
Pnvnr unit li/«. MW
800
1,000
Figure 43. All processes. Effect of power
unit size on total average annual operating cost:
new coal-fired units under regulated economics
20
I'
I I \
Limestone slurry process • X
Lime slurry process- /*
Magnesia slurry regeneration proem • 0
Sodium solution - SOi reduction procest •
Catalytic oxidation process • o
2.6% S in oil
00% SO, removal
7.000 hr annual operation
I
_L
_L
600
Powtr unit llrt, MW
800
1,000
Figure 44. All processes. Effect of power
unit size on total average annual operating cost:
new oil-fired units under regulated economics
130
-------
Table 55. Catalytic Oxidation Process
Total Average Annual Operating Costs Summary3
Case
,. _ CoaUfiredj?q_weruiiiit_
9% SO 2 removal
200MWN3.5%S
200 MW E 3.5% S
500MW'E3.5%S
500 MW N 2.0% S
500 MWN 3.5%S
500 MWN 5.0%S
I.OOOMW !• 3.5%S
1,000 MWN 3.5%S
')()% SO2 removal
(existing unit wilhoul existing
particulute collection facilities)
500MWE3.5%S
Oil-fired power unit
90% SO 2 removal
200 MW N 2.5% S
500 MW N 1.0% S
500 MW N 2.5% S
500 MW N 4.0% S
500 MW E 2.5% S
1,000 MWN 2.5% S
aPowet unit on-streum time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Investment and operating cost for disposal of fly ash excluded.
Years
remaining
life
30
20
25
30
30
30
25
30
Total annual
operating
cost, $
4,232,700
5,849,400
12,399,600
8,801,200
8,873,900
8,940,500
2 1 ,460,800
13,957,600
Dollars/ton
100%
H2S04
94.27
126.06
110.41
140.15
80.75
56.95
<>7.64
65.71
Dollars/ton
(bbl)ofcoal
(oil) burned
7.89
10.55
9.24
6.71
6.76
6.81
8.18
5.50
Mills/
kWh
3.02
4.18
3.54
2.51
2.54
2.55
3.07
1.99
Cents/
million Btu
heat input
32.86
43.98
38.51
27.94
28.17
28.38
34.06
22.92
Dollars/
ton sulfur
removed
288.53
386.10
338.05
429.33
247.32
174.41
299.06
201.21
25
13,598,300 121.09
10.14
3.89
42.23
370.73
30
30
30
30
25
30
2,750,100
5,743,600
5,677,500
5,565,100
11,126,100
8,911,900
114.59
245.45
96.89
59.33
185.74
78.66
1.34
1.14
1.13
1.11
2.16
0.92
1.96
1.64
1.62
1.59
3.18
1.27
21.35
18.23
18.02
17.67
34.55
14.63
351.23
750.80
296.79
181.75
568.82
240.93
Table 57. Average Annual Operating Cost for S02
Removal Installations on Existing Power Units
Requiring Additional Facilities for Removal
of Particulates-Comparison with Standard
Table 56. Comparison of Average Annual
Operating Costs for SO2 Removal
Processes at 90% and 80% SO2 Removal
Projected total Annual
average annual operating cost
operating cost, $ savings resulting
500 MW, from design
new 3. 5% S for80%S02
coal-fired units removal corn-
Process
Limestone slurry
Lime slurry
Magnesia slurry -
rcgcncrution
Sodium solution -
SOj reduction
90% S02
removal
7,702,700
8,101,900
<>,: 10,800
11,601,500
80% S02
removal
7,378,000
7,806.900
8,789,700
10,834,300
pared to 90%
$
324,700
295,000
421,100
767,200
%
4.2
3.6
4.6
6.6
Process
Projected average
annual operating cost, $
500 MW,
existing 3.5% S
coal-fired units
Requiring
additional
particulate
removal
facilities Standard3
Difference in
projected
annual
operating,
cost
$ %
Limestone slurry 9,573,400 7,892,6001,680,80021.3
Lime slurry 9,728,300 9,612,400 115,900 1.2
Magnesia slurry -
regeneration 11,227,300 9,607,900 1,619,400 16.9
Sodium solution -
S02 reduction 16,389,200 14,164,500 2,224,7(0 15.7
Catalytic
oxidation 13.598,300 12,399.600 1.198.700 9.7
"Standard case assumes that the existing electrostatic pteupitator is
adequate for existing units.
131
-------
Table 58. Comparison of Average Annual Operating Costs
for Limestone and Lime SO2 Removal Processes Using
_On-site and_pffjsite Waste Solids Disposal
Annual
operating cost
Projected total average savings resulting
annual operating cost, $ from design
500 MW, new 3.5% S for on-site as
coal-fired units opposed to
Off-site On-site off-site disposal
Process disposal disposal $ %
Limestone slurry
Lime slurry
8,376,500
8,641.000
7,702,700
8,101,900
673,800
539,100
8.0
6.2
= 16
Limestone slurry proctss • X
Lime Ilurry proem - A
Magrwtis Hurry • regeneration proem • O
Sodium solution • SO, reduction proem - 0
Catalytic oxidation procan • °
3.5% S In coal
90% SO, removal
7,000 hr annual operation
// ^
JL
200
400
_L
600
Power unit size. MW
_L
800
1.000
Figure 45. All processes. Effect of power
unit size on total average annual operating cost:
existing coal-fired units under regulated economics
I I I
Limestone slurry proce» X
Lime slurry procett - A
M*gn«i* slurry • regeneration process 0
Sodium solution • SO, reduction process • 0
Catalytic oxidation process "
3.5% S in coal
90% SO, removal
7,000 hr annual operation
0
I
800 '
a
600 •g
600
Power unit site, MW
1.000
Figure 46. All processes. Effect of power
unit size on average unit operating cost:
new coal-fired units under regulated economics
I I I
Limestone slurry process • X
Lime •Jurry proceti • A
Magnesia (lurry regeneration procew • 0
Sodkim solution • SO] reduction protest • 0
Catalytic oxidation process • o
2,5% S In oil
00% SO, removit
7,000 hr annual operation
I
I
400
800
Power unit sire, MW
800
1.000
Figure 47. All processes. Effect of power
unit size on average unit operating cost:
new oil-fired units under regulated economics
I I 1
Llmastona durry process • X
Lima Ilurry proem • A
Magnesia iiurry * regeneration proeass - 0
, Sodium soi»tlon • SO, induction proem • o
Catalytic OKEdatlon process • °
3.6* Sin coal
90% SO] ramoval
7,000 hr annual operation
I
I
I
200
600 800 1,000
Power unit site, MW
Figure 48. All processes. Effect of power unit
size on average unit operating cost: existing
coal-fired units under regulated economics
BOO
400 -8
20 —
I-15
I I I
Limestone Hurry proem • X
Lime slurry process • A
Magnesia slurry • regeneration process • 0
Sodium solution • SO, reduction process - o
Catalytic oxidation procett • n
8m SO, removal
7,000 hr annual operation
T
• to —
I
I
I
Sulfur In coal, %
Figure 49. All processes. Effect of sulfur content
of coal on total average annual operating cost: new
500-MW coal-fired units under regulated economics.
-------
I I I
Llmeitone tlurry proem • X
Llmt ilurry proctts - A
Magnetia ilurry • regeneration proem • O
Sodium wlution • SO] reduction procen •
• Catalytic oxidation proctn • a
00% S0j removal
7,000 hr annual operation
I
I
I
I
012346
Sulfur In oil, %
Figure 50. All processes. Effect of sulfur content
of oil on total average annual operating cost: new
500-MW oil-fired units under regulated economics
scrubbing system for removal of S02, very little additional
investment (see table 33) and operating cost are required to
provide for removal of particulates.
The comparison between on-site and off-site waste
disposal for the limestone and lime scrubbing processes is
shown in table 58. Annual operating costs for off-site as
compared to on-site disposal are 8.0% higher for the
limestone slurry process, and 6.2% higher for the lime
slurry process.
Detailed area-by-area base case (new and existing)
operating cost breakdown analyses are shown in tables 59
through 68. In comparing the detailed operating cost
breakdown analyses for the five processes, it can be seen
that capital charges account for the greatest percentage of
the projected operating costs for each of the five processes.
The ranking of other major cost items vary depending upon
the process. Table 69 shows the four major operating cost
components of each process and the corresponding percent
distribution of total annual operating cost attributed to
each component for the base case installation. It can be
seen that the costs of maintenance and energy are generally
next to capital charges in magnitude.
In addition to the evaluation of effect of variables
included in the case variations, the impact of changes of
other selected parameters on annual operating cost was
determined by sensitivity analyses. Different parameters
were selected for the various processes because they do not
apply uniformly.
Figures 51 and 52 show the effect of variations in annual
on-stream time and sulfur content of fuel on total average
annual operating costs for the limestone and sodium
processes. Although not shown, projected costs for the lime
and magnesia slurry processes fall in between those shown
for the limestone and sodium processes. The effect of
variations in annual on-stream time and sulfur content of
fuel on total average annual operating costs for coal-fired
power units utilizing the catalytic oxidation process are
shown in figure 53. The small effect of variations In sulfur
content of fuel for the Cat-Ox process is again obvious.
The effect of variations in average capital charges on the
average annual operating cost for new 500-MW, 3.5% S
coal-fired power units utilizing the limestone slurry process,
the magnesia slurry - regeneration process, and the catalytic
oxidation process are shown in figures 54 through 56.
Similar results are observed for the lime and sodium
processes. From these results it is obvious that the effect of
varying capital charges is most pronounced on the Cat-Ox
process, which requires the greatest investment.
Tables 59 through 68 presented earlier show that base
case labor costs make up a larger percentage of the total
projected operating costs for the magnesia slurry - regenera-
tion process (3.40%) than for the other processes
(0.71%-3.21%). Since the accuracy of labor projections may
be questioned, it is worthwhile to show the effect of
variations in labor requirements on annual operating costs.
As an illustration, figure 57 shows the effect of doubling
the estimated operating labor requirement of the magnesia
slurry - regeneration process on the total annual operating
cost. As suggested by the detailed operating cost distribu-
tion analysis, however, the effect of this variation is rather
small.
The effect of variations in projected maintenance costs
on annual operating cost is shown in figure 58 for the
magnesia slurry - regeneration process. Although similar
variations in maintenance projections for the other
processes result in different ranges of costs, the general
effect is similar.
Figures 59 and 60 show the sensitivity of annual
operating costs to variations in energy cost for the sodium
solution - S02 reduction and the catalytic oxidation
processes. These processes are the most and the least
sensitive to variations in energy costs, respectively, of the
five processes evaluated.
It should be noted that the steam required for the
SOa regeneration area in the sodium process (see table
65) could be reduced approximately 45% by utilizing
double effect evaporators. ' Such a reduction would
lower the overall process steam requirements approxi-
mately 33%, equivalent to a reduction in overall
energy requirements of about 18%. Figure 61 shows
the effect of variations in steam costs or utilization on
annual operating cost for this process. Neglecting the
difference in investment requirements for installing
double effect evaporators, the total annual operating
cost for the sodium solution - SOj reduction process
might be reduced about 5%-6%.
133
-------
Table 59. Limestone Slurry Process
Total Average Annual Operating Costs
Base Case3 Summary—Area Contribution Analysis
Raw
materials
Direct ctpitai investment, $
Total capital uvestmenu $
Direct costs
Delivered caw material
Limestone
Annual quantity, tons
Anmtalcost, J
Sab total raw material cost
CoWGfBOB CQSll
Opexatn.« teboi and sDperrakm
Annal qoantity. maa-hr
Annual cost, $
Utilities
Steam
Annual quantity, M Ib
Annual cost, S
frocess water
AB&ual quantity. M pi
Annual cost, t
Electricity
Annual quantity, kWh
Annual cost, $
Maintenance (labor and material)
Percent of dstct mvestncDt
Annual cost, J
Analyses
Aasnal qtKttity, hr
Aajttal con, t
Snfatotil conversion coats
Subtotal dinct costs
/w0n.if costs
Avenge capital charges at 14.9*
oi capital mvcstncot
Overhead
flant, 2O% of conversion cosU
Adninistntrfe, 10% of
optratiaf labor
Subtotal indirect costs
Total annual operating con
Peiicirt of total aanual opentiflg cost
Eqnivalml total unit operating co«
Total
16.069,000
25.163.000
Unit cost. S
4.00/100
84K>/naa-hr
0.70/M Ib
0.08/Mtal
0.010/kWh
12.00/hr
Doom/ton
codburaed
5.87
Kaw
materials
175,000
700,000
700,000
1420
lt.200
18.200
71(400
3,600
34>00
721300
937
Mnu/kWh
2.20
handling
419.000
656.000
4.170
33,400
390,000
3.900
6
25,000
62300
62300
97,700
12400
3300
113400
1754(00
2.28
Ceiitt/l
Feed
preparation
899,000
1.408.000
6,470
51,700
5,150.000
51400
g
71.000
174.2OO
174JOO
2094(00
344WO
5^00
2494WO
4M4WO
540
BHOB D
Particiilate
scrubbing
3^03,000
5.016.000
4300
39.2OO
6.4404)00
64,400
10
320,000
760
9.100
432.700
432.700
747.400
86400
3300
(374(00
U 70400
164*
<*an/te»
SO,
scrabbtng
4,74:. 000
7.430.000
4,900
39,200
174,700
144WO
22430,000
225300
11
522,000
1.140
13.700
814.200
814.200
1,1074)00
162400
3300
U734WO
lvMC4WO
27.11
Reheat
556 4WO
871.000
1.250
10.000
4924*0
34S4WO
8
44400
399400
399400
129 4MO
79300
i4W>
210.TOO
»I*JOO
7.92
Fans
854,000
1337.000
1JSO
104)00
43,080,000
430,800
8
68.000
508,800
5084(00
199JOO
1014(00
14100
3024)00
tiojao
10JJ
Calcium
lOtidl Construction
disposal Utilities Services facilities
3,923,000 67,000 638,000 765,000
6.143.000 105.000 999.000 1.198.000
3.340
26.700
754WO
6.000
700.000 230.000 220,000
7,000 2,300 2.200
6
235,000
3(0
4,600
279300 2300 2400
279,300 2300 2,200
915,300 15.600 148,900 17(400
55.900 500 400
2.700
973.900 U.100 14*300 17(400
1453,200 1MOO 151400 17(400
M.27 0.24 1.97 2.32
Total Total
annual annual
quantities doUan
175.000
7004)00
7004)00
264(0
210400
492,800
345,000
250300
20,000
78.740.000
787,400
8
1485400
3.800
454>00
2*93,700
3393,700
3,749300
538,700
21,000
43094WO
7,702,700
Percent of
total annual
operating cost
9.09
9.09
2.73
4.48
0.26
K>.22
16.69
049
34.97
44.06
48.68
6.99
0.27
55.94
100.00
Bra bent inpvt mUetitmont
24.45
H4M
500-MW new coat-rind BOWWMB*. 3.5% Sin Sad; 90* SOj removal; on-me tobll ApoiaL
Remaining life of power ptrat, 30 yr.
Cod burned. 1312400 lomt/yi. 9,000 Btu/kWh.
Slack pa reheat to 175°F.
Power unit on-ttieam time, 74)00 to/ft.
MlihMU pbmt location. 1975 optntfec colts.
Sulfui remoted, 35 JSO taat/rr, «olidi dupooj, 206,000 toiu/yr cilciam »bdj inctadinj only hydnte water.
Investment and operating coct for disposal of fly ash excluded.
-------
Table 60. Limestone Slurry Process
Total Average Annual Operating Costs
Existing Case3 Summary—Area Contribution Analysis
Direct capital investment, S
Total capital investment, I
Direct Coat
Delivered raw material
Limestone
Annual quantity, tons
Annual cost, S
Subtotal raw material cost
Conversion costs
Operating labor and supervision
Annual quantity, man-hr
Annual cost, $
Utilities
Fuel oil (No. 6)
Annual quantity, gal
Annual cost, $
Process water
Annual quantity, M gal
Annual cost, \
Electricity
Annual quantity, kWh
Annual cost, S
Maintenance (labor and supervision)
Percent of direct investment
Annual cost, $
Analyses
Annual quantity, hr
Annual cost, $
Subtotal conversion costs
Subtotal direct costs
Indirect Coitt
Average capital charges at 1 5.3%
of capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of
operating labor
Subtotal indirect com
Total annual operating con
Percent of total annual operating cost
Equivalent total unit operating cost
Total
14,116,000
23.088,000
Unit Cost, t
4.00/ton
8.00/man-hi
0.23/gal
0.08/M gal
O.OlO/kWh
12.00/hr
Dollars/ ton
coal burned
5.88
Raw
materials
178,900
715,600
715,600
1,520
18,200
18,200
733,800
3*00
3400
737,400
9.34
Raw
materials
handling
482,000
789,000
4,380
35,000
400,000
4,000
6
29,000
68,000
61,000
120.700
13.600
3,500
137,800
205300
2.61
Feed
preparation
1,000,000
1,636,000
6,680
53.400
5460,000
52,600
8
80.000
186,000
186,000
150300
37.200
5300
292.800
478,800
6.07
SOj
scrubbing
5,243,000
8,577,000
8,760
70,100
178,600
14300
23,030.000
230300
12
640300
1,900
22300
977.800
977,800
1,312300
195*00
7,000
1414,900
2,492.700
31.51
Calcium Total Total Percent of
solids Construction armoal annual total annual
Reheat
323.000
527,000
1,460
11,700
4,160,000
956,800
Fans
1,710.000
2,797,000
1,460
11.700
20,000 35330,000
200
g
26,000
994,700
994,700
80.600
19S.MO
1,200
28O.700
1,275,400
l«.tt
358,300
8
137.000
507,000
507,000
427.900
101.400
1.200
530.500
1,037.500
13.15
disposal Utilities Services
3,611,000 335,000 740,000
5,905,000 549,000 1,209,000
3,540
28300
77300
6400
710,000 240,000 230,000
7,100 2,400 2,300
6
217,000
380
4*00
263400 2,400 2,300
263400 2,400 2.300
903400 84,000 185.000
52.600 500 500
2300
951,900 84.500 185 ,500
1422.100 MJOO 117300
IS.4I 1.10 2.31
facilities quantities dollars operating cost
672,000
1.099.000
178500
715,600
715,600
26480
210.200
4,160,000
956,800
255.900
20400
65,720,000
657,200
8
1.129,300
3300
45*00
3,019*00
3.735,200
168.200 3432400
603,900
21,000
168,200 4.157,400
164400 7,892*00
2.13
9.07
9.07
2.66
12.12
0.26
833
14.31
0.58
38.26
47.33
44.75
7AS
0.27
52*7
100.00
Cents/mitton DoBan/ton
Mitts/kWh
2.26
Btu heat tnpat sulfur rawed
24 Jl
2IS.I7
aBuis:
500-MW existing coal-fired power unit, 3.5% S in fuel; 90% SO, removal; on-site sobb dixpocal.
Remaining life of power plant, 25 yr.
Coal burned, 1,341,700 tons/yi, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 197S operating costs.
Sulfur removed. 36,680 tocu/yi, solids disposal, 210,600 tons/yr caJcium solids including only hydrate water.
Investment and operating cost for removal and disposal of fly ash excluded-
-------
ON
Table 61. Lime Slurry Process
Total Average Annual Operating Costs
Base Case3 Summary—Area Contribution Analysis
Direct capital investment, S
Total capital investment, $
Direct Cortl
Delivered raw material
Lime
Annual quantity, tons
Annual cost, S
Subtotal raw mtt*m1 cost
Operating labor and supervision
Amai quantity, man -hi
Annual cost, t
Utilities
Steam
Annual quantity, M Ib
Annual cost, $
Process watei
Annual quantity, M gal
Annual cost, S
Electricity
Annual quantity, kWn
Annual cost, $
Maintenance (labor and material)
Percent of direct investment
Annual cost,}
Analyses
Annual quantity, hf
Annual cos!, $
Sub toll! conversion costs
Subtotal direct costs
Average capital chargei «l 14.9%
of capital snvesaxot
Overhead
Plant, 20* of co*ven»o» costs
Administrative. 10% of
operating labor
Subtotal indirect euro
Total unnat opentmg cost
Percent of total anaul opentmf cost
Raw
materials
Total handling
14318,000 795,000
22.422,000 1,245.000
(Uw
Unit cost, S materials
22.00/ton
81,200
1,786.400
1,786,400
8.00,'raan-hi
2.290
18.400
0.70/M ft
0.08/Mgal
0.010/kWh
220.000
2,200
6
48,000
12.00/hr
760
9,100
9,100 68,600
1,795400 68*09
185400
1,800 13,700
1300
1,800 201,100
1,7*7300 269,700
22.19 3.33
Feed
preparation
387,000
607,000
4,390
35,100
340,000
3,400
8
31.000
69400
69400
90.400
13,900
3400
107300
177,300
2.19
Particuiate-
SO,
scrubbing
4,017,000
6.291,000
4300
39,200
86400
6300
14,790,000
147300
11
442.000
760
9.100
645,100
645,100
937,400
129,000
3300
1,070300
1.715,400
21.17
SO,
i Drubbing
3.153,000
4,937,000
4.900
39.200
86400
6300
14,790,000
147,900
10
315,000
1,140
13,700
522,700
522,700
735*00
104*00
3300
844,100
1366,800
16J7
Reheat
542.000
848,000
1,250
10,000
490,000
343.000
8
44,000
397,000
397.000
126,400
79,400
1,000
206*00
603^00
7.45
Fans
767,000
1,201,000
1.250
10,000
43,080,000
430,800
8
62,000
502300
502*00
179,000
100*00
1,000
2SO*90
7I3.400
9*7
Calcium
solids
disposal
3,356,000
5,255,000
3340
26,700
68300
5*00
430,000
4300
6
203.400
380
4*00
244*00
244*00
753,000
48,900
2,700
114*00
1.079.200
IJJ2
Construction
Utilities Services facilities
67,000 552.000 682,000
104,000 866,000 1,068,000
230,000 220,000
2300 2,200
2300 2,200
2300 2,200
15400 129,000 159,100
500 400
14,000 I29.40C 159,100
U300 131*00 159,100
0.23 1*2 1.96
Total Total
annual annual
quantities dollars
81400
1,786,400
1,786,400
22320
178,600
490,000
343,000
241300
19,400
74,100,000
741,000
8
1,145,400
3,040
36400
2,463300
4,250,300
3340300
492,800
17300
3 ,85 5,600
8,101300
Percent of
total annual
operating cost
22.05
22.05
2.20
4.23
0.24
9.15
14.14
0.45
30.41
52.46
41.24
6J*
0-Z2
4744
100.00
DoUm/ton Cems/mauon Dollni/ioa
coil burned lUb/kWh BU heat input sulfiu rammd
Equivalent total unit operatiug cost
6.17 2.31 25.72
225.81
•Basis:
500-MW new coal-fired power unit, 3.5% S in fuel; 90% SO., removal; on-lite solids disposal.
Remaining life of power plant, 30 yr.
Coal burned, 1312400 tons/yr, 9,000 Btu/kWh.
Stack sa« reheat to 175 F.
Midwest plant location, 1975 operaiinf costs.
Sulfur removed, 35.880 tons/yr; solids disposal. 174,700 tons/yr calcium wlids mctuduij only hydrate water.
investment and operating cost for disposal oJ fly ath excluded.
-------
Table 62. Lime Slurry Process
Total Average Annual Operating Costs
Existing Case3 Annual Operating Cost Summary—Area Contribution Analysis
Direct capital investment, 3
Total capital investment, I
Direct Com
Delivered raw material
Lime
Annual quantity, tons
Annual cost, S
Subtotal raw material cost
Conversion costs
Operating labor and supervision
Annual quantity, matvor
Annual cost, $
Utilities
Fad oi (No. 6)
Annual quantity, gal
Annual cost, $
Process water
Annual quantity, M gal
Annual cost, S
Electricity
Annual quantity. kWh
Annual cost, S
Maintenance (labor and material)
Percent of direct investment
Annual cost, t
Analyses
Annual quantity, hr
Annual cost, t
Subtotal conversaoo costs
Subtotal direct costs
Average capital charges at 15.3%
of capital investment
Overhead
Plant, 2O% of conversion costs
Administrative. 10% of
operating tabor
Subtotal indirect costs
Total antttal operatsBg cost
Percent of total msul optntaif cost
Equivalent total unit opculing cost
Total
15,913,000
26,027,000
Raw
Unit cost, $ materials
22.00/ton
83,000
1,826,000
1,826,000
8.00/man-hr
0.23/gal
0.08/Mgal
0.010/kWh
12.00/hr
760
9,100
9,100
1.835,100
1.800
1JOO
1 ,836.900
19.11
DoHan/toa
coal burned Mffls/kWh
7.16 2.75
Raw
materials
Feed
handling preparation
876,000
1,433,000
2490
18,400
220,000
2,200
6
53,000
73,600
73,600
219400
14,700
1,900
235300
309,400
3.22
Cents/mulion
Btii hat input
29.85
436.000
714,000
4490
35,100
350,000
3400
8
35,000
73,600
73,600
109,200
14,700
3400
127.400
201 MO
2.09
First
state SO,
scrubbing
4465,000
7.466 MO
4,900
39400
88,450
7.100
15,120,000
151400
11
502,000
760
9,100
708*00
708*00
1,142400
141.700
3^00
1487.900
1.996400
20.T7
Second
stage SO,
scrubbing
3.797,000
6411,000
4,900
39400
88.450
7,100
15.120,000
151400
10
380,000
1,140
13,700
591400
591400
950400
118400
3.900
1X172.400
1^63jMO
1741
Reheat
305 MO
498 MO
1450
10,000
4,236 MO
974,300
20,000
200
8
25.000
1.009400
1,009400
76400
202 MO
1,000
279400
1.2*8.700
1341
Fans
1.143MO
1.870,000
1450
10.000
•
35470,000
355,700
8
92.000
457,700
457,700
2(6.100
91400
IMO
371,600
(3*400
(.TO
Calcium
sonds
disposal Utilities Services
3,049,000 335,000 649,000
4,986,000 549,000 1,060.000
3440
26,700
70,400
5,600
440.000 240,000 230,000
4,400 2,400 2400
6
186,000
380
4,600
227400 2,400 7400
227.300 2,400 2400
762.900 84,000 162400
45400 500 $00
2.700
(11,100 (4400 162,700
1X131,400 86,900 165MO
10JO 0.90 1.72
Total Total
Construction ««wt«f anmiTl
facilities quantities dollars
758.000
1.240,000
83,000
1326,000
1,826 MO
22420
178*00
4436,000
974400
247400
19,800
67410,000
673,100
8
1473MO
3,040
36400
3,155400
4,981,300
1(9.700 3.9(2.100
631,100
17^00
189.700 4*31.100
1(9.700 9*12.400
1.97
Percent of
total mnutl
operating cost
19M
19.00
1J6
10.14
0.21
7M
1343
048
32.82
5142
41.42
647
0.19
41.1 g
100.00
Dollars/ton
sulfur renoTBi
262.06
500-UW aistint coatfsred power unit, 3.5% S • f»el; 90S SO, removal; on-site solids dispoaL
Remasnint fife of power plant, 25 yr.
Coal burned, 1441,700 tons/yr. 9400 Bta/kWh.
Slack gas reheat to 175°F.
Power unit oo-streajn time, 7,000 hr/yr.
Midwest plant location, 1975 operating; costs.
Sulfur removed, 36*80 lons/yr; solids disposal, 178*00 tons/yr calcium solids mdudinf only hydrate water.
Investment and operating cost for removal and disposal of fly ash occluded.
-------
U)
oc
T.able hi Magnesia Siurrv - regeneration Process
Iota! Average Annual Operating Costs
Base Case3 Summary— Area Contribution Analysis
Dstecl capital investmenl. S
Total capital ttncstnent. S
DmetCottt
Delivered raw sulertall
Lunedftstafe neutralization j
Annual quantity, tons
Annual cost. S
atacnenom oxide (98%)
Annual quantity, tons
Annual cost,!
Cote
Annual quantity, tou
Annual cost. S
Catalyst
Annual quantity, bten
Arotul cost, S
Subtotal raw Materials costs
Conversion costs
Openttttj labor aarf supervnaoo
Annaal quantity, maafhi
Anaalcost,t
UtaWes
Fuel oi (No. 6)
Anmal oaastutiei. pi
Annual cost, S
5tot>a
Annual Quantities. M Ib
Ansnssl cost, S
Aaavsal quantity, UM Btu
Ansuelcost,S
rtocess water
AMV.V quaanity. M pi
Annual cost, 1
Eltctncaty
Aaa.aal.ianOly.ltWh
AaMaloM,>
Iliialiaia I (labor rJd saeleoal)
fwmt of direct investment
AasMasI cost, S
Analyse.
AautnalcaoaMity. to
Alenal cost, f
Subtotal coBvenson cost*
Subtotal direct coats
Arente capita) cstsrps « 149%
«fca.»til»v=«aa,l
Owmead
riant, 20% afcouvuSKlil costs
Adaatanatnlivc and aaartetrflK.
IKc/uMfetakiu costs
Subtotal indarect costs
Total anansal ooantaac cost
Percent of total axnaul ooerauni cost
Eaativaieiit total unit operMmf cost
i
Tola! 1
16434,000
26,406,000
Raw
f art coal, t materials
26.00/too
134
3.500
155.00'lon
1.086
168.300
15.00/lon
11.400
1.800
3,000
186,200
8.00;man-hi
0.23/tal
0.70/Ulb
•040/MMBRi
0.04/Mpl
0.010.1 Wh
114XVnr
425
5,100
5,100
191.300
14100
600
1400
192.900
24»
DeOsn/ton OoBan/ton
lOOSHiSO, coal burned
83.43 7.02
Raw
natenals Feed
^anduni prepantioo
192.000
310,000
1.440
11400
970,000
9.700
5
9400
30.800
30.800
46,200
6400
3,400
55.100
8(400
0.94
UffllAWk
238.000
385000
3.720
29.800
260.000
2400
6
14JOO
46.700
46,700
57,400
9JOO
5,100
71.800
118400
149
Con*.
Ptracuasle
3 H6.0QO
6412000
4450
35400
184JOO
7.400
74004)00
76.000
10
396400
760
9JOO
524.700
524.700
955,400
105.009
57.700
1.111,100
1442JOO
I7A5
SO,
vrrabbmi Reriett
2492,000 5094)00
4.190,000 323,000
4.450 100
35.600 6.400
4404)00
3C84XJO
23.700
MO
6J40.000
63409
10 8
259400 40JOO
1.140
13.700
3734)00 355,200
3734100 355400
(24JOO 122400
74400 71400
41.000 39.100
739.900 232JOO
U1I.900 5U4XK
1X01 6.38
Fans
74LOOO
Slurry
piocesoi
711 000
4.1984100 1,149 000
»80
6.400
37.5-10,000
379400
i
59.400
444 JOO
444,900
178400
194)00
48,900
S'U.W
7*1 JOB
847
3.720
29.800
89400
41.400*
24504M
2*400
7
494tX>
435
5.200
159,700
159.700
171409
31.900
17400
220.709
380.400
4.13
Sulfuric Acid Total Total
Cue MtSO, acid storage ft Construction annual annual
drvmt calcination production ihippinc Utibtm Servicei facuities quantities doHsrt
972.000 I1lp81000
1471,000 1.791,000
3.840 3440
30.700 30.700
1.558,000 2.7984XX)
588,300 643400
1014X»
(60400)°
2jt504»0 24304X10
2S400 26.300
8 1
77400 11,700
1475 1475
15400 15300
740400 744,000
740400 744.000
234.100 266500
141,100 14MOO
81400 81400
463.700 497400
1404300 1441400
13.07 1348
3.197,000
5,168,000
94BO
77,400
13994900
50.000
84604XXI
85400
4
127.900
2450
30400
401400
401400
7704KX)
80300
44400
894409
1496,000
14417
278300
450rOOO
2,460
19.700
2604)00
2400
4
11400
640
7.700
41400
41400
67.100
8400
4400
79400
1214100
1.31
269.000 '*!4WO
7TJ4500
•etcent ot
[Ota! annual
operating
con
435,000 l.:t64K» 1.2584)00
760,000 2504MO
7400 2400
3
8.100
15.700 2400
15.700 2400
644tX> 188400
3400 500
1.700 300
69400 189,400
15300 191.900
0.93 2.08
134
3400
1.086
161300
763
11.400
1400
3.000
1K400
39400
313.600
5356,000
1431,900
529400
356.400°
1014)00
(60.000)
2407400
11300
714)60,000
710400
7
' 1.143,400
8400
102,000
3.885,600 "
4,071,800
187,400 3.9344iX>
777.100
'27,400
187.400 i.m.ooo
187,400 9410JOO
2.03
0.04
1.83
012
0.03
2.02
3.40
13.39
3.87
(0.66)
0.96
7.71
12.41
1.11
42.19"
44.21
42.71-
8.44
444
55.79
100.00
isKo. Oonan/lo>
Bn> newt aatm saUhr moved
243 29.24
255.43
•fiaots:
500-MW new coiMlKd powes unit. 3-SI S in fuel; 90* SO, removal: 110400 tosaVn 100% H,3O,
teueu,, Ufc of powei plant, 30 yi
Coal oumed, 1J12400 lona/yt. 9.000 BtuftWh
Stack (aaretleat to 175 T
Power unit oiMUeani taose, 7.000 hr/yr
Midwest ptant keotion, 1975 opetaonsj oosu
Sutfn reraond. 364)60 toni/yt
lancstnent and opentug con for disposal of fly ash excluded.
"Steam fenented in the cakming u*t waste heat bo&et is aaseoed at a unit value of S040/MX &ta or S0.54A1 A.
-------
Table 64. Magnesia Slurry - Regeneration Process
Total Average Annual Operating Costs
Existing Case3 Summary—Area Contribution Analysis
Direct capital investment, $
Total capital investment. $
Otrvci Com
Delivered raw materials
Matnenira oxidr (98%)
Annual quantity, tons
Annual cost S
Coke
Annual quantity, tons
Annual cost. S
Catalyst
Annual quantity, bten
Annual cost, $
Subtotal raw nutenalx costs
ConverskM costs
Openunt labor and supcrvawn
Annual quantity, raan-tu
Annual cost. S
Ultimo
Fueled (No 6f
Annual quantity , pi
Annual cost, I
Hat credit
Annual quantity. MM Btu
Annual cost, S
Process watet
Annual quantity, M gal
Annual cost, S
fkctricity
Annual quantity, kWh
Annual cost, S
Maintenance (labor and material)
Percent of direct investment
Annul cost. S
Analyses
Annual quantity, hr
Annual cost, S
Subtotal conversion costs
Subtotal direct costs
Average capftal charfa at 15.3*
of capital Kivestmenl
Overhead
Plant, 20% of conversion costs
Adnumtntrve and marketing.
1 1 % Of COKveriKM COItS
Subtotal indvert com
Total wuMal opernnf coat
rVrcrat of tout annul operadas con
Total
15. 4 23,000
22,056.000
Unit cost*. J
ISS.OO/to«
15.00/ton
1.65 Alter
LOO/nan-hr
0.23/eal
-0.60/MM Bto
0 04/M pi
0.010/kWh
12.00/hi
Raw
mate rub
handbrw
210.000
354.000
Raw
materials
1 110
172.100
780
11.700
1.840
3.000
146,800
1420
12.200
990.000
9.900
5
11.000
425
5.100
5.100 33.106
191.900 33.100
54.200
1.000 6.6OO
600 3.600
1.600 64.400
193400 97.500
2.01 101
DottarVtoB. Dottm/tott
100%HiSO« coalbuioed MiUi/kWh
Equivalent total unit operating cost
K 10
7 16 2.75
Feed SOi
preparation scrubbing
270.000 4.469,000
456,000 7.541,000
3.800 8.180
30,400 65,400
213.100
8400
260.000 6400.000
2400 65.000
6 12
17.000 525*00
1.900
22300
50.000 687.100
50.000 687.300
69300 1.153300
10,000 137400
5400 75400
85.300 1.366300
135.300 2.054.100
1.41 2139
Reheat
305.000
516.000
880
7,000
3.685,000
847.600
20.000
200
8
25.000
8T9.MO
879 3OO
78.900
176,000
96.8OO
351.700
1.231400
I2J2
Fans
1.112.000
1.876.000
880
7,000
21.110.000
211.100
8
89,000
507,166
307.100
287,000
61.400
33JOO
382.200
689.300
7.17
Slurry
processing
789.000
1.333.000
3,800
30.400
2.710.000
27.100
7
56.000
435
5,200
IIJ.700
1U.700
204.000
23.700
13.100
240.800
359400
3.74
Cake McSO,
dryint calcination
1.065,000 1.211.000
1,796,000 2.042.000
3.950 3520
31.400 31.400
2*14,000 2,861,000
601.200 658.000
20300
(12400)
2.910.000 2.690.000
29.100 26300
8 8
86,000 97,000
1.275 1.275
15.300 15.300
7t>3,0oo 816.160
763.000 816.100
274.800 312.400
152.600 163.200
83.900 (9300
511.300 545.400
1.274.300 1.3(1400
1326 1431
Sulfunc
acid
production
3.608.000
6.089.000
9.760
78.100
2.043.000
81.700
8.750.000
87400
4
145400
2450
30*00
422.900
422.900
931*00
84 MO
4*400
1.062.700
1.415,600
15 47
Acid
storage &
shipping Utilities Services
329.000 454,000 867.000
556,000 766.000 1.463.000
2440
20.300
260,000 780.000 250.000
2,600 7300 . 2400
4 3
14.000 14.000
640
7.700
44.600 JliM 2400
44*OO 21300 2400
85.100 117.200 223300
1.900 4.400 500
4.900 2,400 300
98.NO 1 24.000 224.600
143400 145300 227.100
149 142 236
Total
Construction annual
facilities quantities
734.000
1.238.000
1.110
780
1.840
39.200
9.160,000
20.800
2.256.100
47.230,000
7
8400
189.400
189.400
189.400
1.97
Total Percent of
annual total annuaj
dollars operating ;ost
172.100 1.79
11.700 012
3,000 003
186.800 1.94
313.600 3.26
2.106.800 2193
(12400) (0.13)
90.200 0*4
472.300 4.92
1.079.600 11.24
102,000 1 06
4,li2.UUU 43.22 *"
4.338.800 4516
3.982.000 41 45
830.400 8.64
456.700 4 75
5.269.100 5484
9.607.900
lOGOC
Cents/mason Dotkn/to*
Btu beat MENU wtfn:
rmaewed
29.84 26066
asa
SOO-MW ouint coal-iired power unit 3 51 S in f jd WT SO, rcmonl. 112.900 KxiVyr 100% H,SO«
Renuanmc life of power plant, 25 y:
Coal burned. 1341.700 toos/yi, 9.2lfT> Btu nWh
Suck gas reheat to 175°F
Power unit orrareaa tune. 7.000 r.r*vi
Midwesl piknt location. 1975 bperaQnf c->sti
Sulfu: removed. 36.660 tons,'yr.
Inve'Irrteii! and ->peTaluig cost for rm.oi^act >:>£u\j: ot fly ash otclitdea
Ul
SO
-------
Table 65. Sodium Solution - SO2 Reduction Process
Total Average Annual Operating Costs
Base Case2 Summary—Area Contribution Analysis
Total
Direct capital wtcoaatt. S 11.861.000
Total caenai arastaaea!. S 30,491400
Dmct Coat
r-ll— ..1 n- manrali <» •040/Ual In
Aeaaaalcocl.!
AaaaaaltjaaaaitMlial
AaaaaicoO,>
Qecofciej 0.010ftWB
AaeaHl fnatily. kVk
it.- fci-.-,— OafewMal i i • n
tacan of dinet a»aaa>aat
A^J1"*''
AaHalajaaaOr.ta
AMMfccMt. S
Safcantali IIMIIHIIII cota
SaMaol to«cs oaB
AvnaaB capital ckava at 14.9%
Chrtea?'"™""'0''
n..i Trni.CM.i..iaiiiinji
A taa»a« nil i aaa awta.it. 11*
Sab«otai aaaaact coats
Tooi»«i«TOTn^c-.
hto-a-le*! —itTCMta.^
Dc4to/toa
praalaaaatfii
Fi|aiialia]> total aaK uyaaliai coo 354.79
Raw taaHriak
preparatioa
Raw
aalatali
134
3400
9300
413400
317.100
634 JOO
12,000
1.133.300
i
440
7,700
7,700
1.141400
-
1400
900
2,400
1,143,400
t4«
IXAxt/loB
U4
•talc
S004IW nc. coaMkW iioa>ar aio, 34» S m hal; 90% SO) not
225.000
364.000
3455
24.400
8JOO
200
450400
4400
S
11300
40,400
40,400
54,200
>,100
4.400
66.700
107,100
on
itib/m
3.31
rattieoaiB
3444400 '
SO,
Knbboai Reheat
U69.000 539400
6J18400 6.902,000 871.000
4«5
37.000
169.700
3.400
7,170400
71.700
10
385400
760
9,100
506 JOO
506 job
924400
101,200
55,700
1483,400
14(9400
13.70
CntaMak
BntMalbv
3643
4>24 970
3V400 7400
420400
294400
2430400
32300
7 8
298JOO 43,100
l,MO
: 13.700
31 UW 3*4.900
371300 144,900
1428.400 129.800
74,200 69400
40400 37.900
1. 143,400 236,700
1414400 S81400
1344 541
n Ddaao/tcai
32334
Fan
K9.000
1.431 000
9TO
7400
43/09400
434400
8
71.100
513400
513.100
214,100
103400
54.400
373JOO
8MJOO
744
teat SO,
oeataeat rafenentioB
1.413400
2381.000
9.735
77300
142400
100,000
326300
4400
4400400
65400
6
88.400
2400
24400
361400
361400
354400
72,400
3*400
467400
828400
7.15
2.717400
4393,000
9,735
77400
1475400
1,102400
9.448400
189400
11,700400
117400
4
108.700
1J70
1SJOO
1410300
1410300
654400
322.100
177000
1,153400
2.744,100
2343
SO,
nducdoa
2321,000
4.721,000
9.7J5
77300
509400
509400
82.700
(4»400)b
2470400
20.700
4
116400
2,750
33.000
10*300
708300
703,400
141.700
77^00
923400
1431300
1444
Sotfai Total Total Percent of
nonce 4 Conttroctwn tnnaal Mnual total aamul
diippiaf Utibtiet Serrket facilitks o^antitiei dodan opentiaf con
227400 195400 662.000
198,000
367400 314.000 1471.000 1.452,000
3450
24300
21400
113006
170400 230400 250.000
1.700 2300 2400
4
9,100
600
7.200
54400 2300 7.400
54400 2,300 2400
54,700 46400 159400
10400 500 500
6400 300 300
71400 47400 140.400
125,700 49,900 141300
\M 0.4] 1.40
134
3400
9300
483400
317.100
634400
1.133300
44400
372400
509400
509400
2,158400
1408.400"
82,700
(49400)"
9353,400
199,100
74,190400
741300
6
1,131.700
9,160
109300
4422300
5456400
216300 4443400
904400
4J7400
216JOO 5345300
216300 11401400
146
0.03
4.17
5.47
0.10
9.77
3.21
4.39
13.00
(0.43)
1.72
4.39
9.75
0.95
38.98
48.75
39.16
7.80
4.29
51.25
10040
nal: 32.700 tcuftn iaUn
,
life al pom (tat, 30 n.
Coal Iwwt, 1J12400 u»«/rt. »400 KuM*.
F.
Salto nmumA. 354*0 uufri.
I. iilmi*im4t>tmamict*!ti.
°Sl»«l HMraM • Ote SO, «
-------
Table 66. Sodium Solution - SO2 Reduction Process
Total Average Annual Operating Costs
Existing Casea Summary—Area Contribution Analysis
Raw materials
Dinct capital irmstnunt, S
Total ' "i"!*! tuiuuncnt, (
UrectCota
Dearered raw matenah
Soda ash
Animal qnutity, toes
Annul cost,!
Antioxidant
Annul quantity, ft
Armudcott, S
Catalyn
Annud cost. J
Subtotal raw materials cost
Cuuiusno costs
Operatinf labor and sapemnon
Annul quantity, man-hr
Annul cost,!
Utilities
Fad oB (No. 6)
Annd quantity, pi
Annul cost,!
Nsnudps
Aaud quality, mcf
Annual cost, t
Rest credit
Annual quantity, MM BID
Amndcost,S
Process wster
Aaaod quantity, M pi
Annul cos!,}
Electricity
Annad quntity, kWh
Amrad cost, i
Mamaaance Oabot and material)
Pstceat of direct investment
An«nulco«,5
AasJyaes
Anaul quntity, hr
Annual con, t
Svbtotd conversion costs
Subtotal direct com
/isdfcecrCom
Arerafe capital charts at IS J*
ofcapadianstaKat
Oiiianiil
Plaat, 20% of coavfctsioa costs
AdsftWsfratlre and narketiaf
SaMotd indirect costs
Totd anaad operating cost
Percent of told annul openttnf cost
Eqetraleat told unit operatiaf cost
Totd
18,495,000
31,208,000
Raw
Umt cost, ( msterak
52.00/ton
9300
494,000
2.00/tt
324.100
648JOO
12300
1,154300
8.00/man^u
0.23/pl
1.00/SKf
•0*0/MMBtn
0.02/Mpl
0.010/kWb
12.00/to
640
7,700
7.700
1.162JOO
1300
600
2.100
1.164300
7.94
DoBars/ton DoBats/toa
prodnct mlfur cod banej
438.60 1552
haadonf A
preparation
151,000
424 ,000
3.175
25,400
9,100
200
460 ,000
4*00
5
13,000
43,200
43^00
64300
1*00
3300
76300
120.000
032
SO,
5338,000
10.019.000
8395
67,200
173*00
3300
2,210,000
22300
9
535 WO
1300
22300
651300
651300
1333300
130300
50.700
1.7133OO
2365 yao
16.14
Reheat
305,000
516WO
\fm
8300
4JXW4XX)
92OOOO
20 WO
200
I
2JWT
954 WO
954 WO
783OO
190300
74300
344 WO
1^98 WO
834
Fans
1.238.000
2,090 WO
1J»5
8300
27, 130 WO
271300
1
103.000
383,100
383,100
319,800
76*00
29300
426330
809.400
532
Purge
treatment
1393,000
2*87 WO
9,855
78,800
623,000
143300
64300
(38*00)
333300
6,700
6*40.000
66,400
6
100.000
2,000
24 WO
380*00
380,600
411,100
76,100
29,700
516,900
897300
6.12
SO,
regeneration
3.304,000
5373,000
c
i
C-
9355
78,800
12344 WO
2,977,100
"j
c. t.
9.658^00
193,100
11360.000
119*00
C. !.
5
168WO
.''
'U70
15JOO
3351300
3351 .WO
•'•t
852,700
710.400
276300
13393OO
5391,700
.4.7.
Sulftu
SO, rtorafe*
ndactioa sbjppaif
3JOOWO 267,000
5,400,000 450WO
^
9,855 3,175
78300 25,400
520300
520300
2,110,000 170,000
21,100 1,700
,"
4 4
130 WO 11.700
2.750 600
33,000 7JOO
783,700 4*WO
783,700 46WO
I26JOO 68300
15*300 9300
• 61,100 3*00
1XM4.100 81*00
1327300 127*00
12.47 037
Utilities Serrices
752,000 766,000
1470,000 1492,000
240,000 150.000
2.400 2300
3
24,000
26,400 2300
26,400 2300
194300 197,700
5300 500
2,100 200
201,700 191,400
228,100 200500
136 1.37
Total Total
Construction annud annual
facilities quantities doUan
881,000
1,487,000
9300
494,000
324,100
648^00
12300
1,154300
46300
372WO
17367WO
4,040,400
520300
520300
64300
(38*00)
10.174.4W
203300
51.260.0W
512*00
6
1,109.700
9.160
109300
6,830300
7384300
227300 4,774300
1366,100
532300
227300 6*73400
227300 14.658WO
135
Percent of
total annul
operating cost
3J7
4.42
0.0*
737
2-54
2736
333
(046)
139
330
737
0.75
46*0
54.47
3238
932
3*3
4533
100.00
Oata/antaoa Dotes/ton
MgsftWh
Babotltepot
Sttttnr natovsd ^
555^
5004IW exista* -c-iMinid ponrts «*. 33* S in fir*90* SO, nsnonl; 33,420 tos«/yi saHto
Ronsinis, life of powa ptus t* r:
Cod borned, 1341,700 toas/yt, 9^00 Bto/kWh.
Stack fssrehest to 175°F.
Powef unit o»stnsm time, 7/MO hr/yi.
Midwest pbnt locmtian, 1975 opentinf costs.
SBtfai naurrtd, 36*80 tans/yi.
lanstmcat and openttag cost for disposal of Uy adi exckded.
-------
-fk
to
Table 67. Catalytic Oxidation Process
Total Average Annual Operating Costs
Base Case3 Summary—Area Contribution Analysis
Direct capital investment, S
Total capital investment, $
Direct Com
Delivered law material
Catalyst
Annual quantity, liter
Annual cost, $
Subtotal raw material costs
Conversion costs
Operating labor and supervision
Annual quantity, man-hr
Annual cost, $
Utilities
Steam
Annual quantity, M Ib
Annual cost, J
Heat credit
Annual quantity, MM Bru
Annual cost, $
Process water
Annual quantity, M gal
Annual cost, $
Electricity
Annual quantity, kWh
Annual cost, t
Maintenance (labor and material)
Percent of direct investment
Annual cost, S
Analyses
Annual quantity, hr
Annual cost, $
Subtotal conversion costs
Subtotal direct costs
IndJrtct Cotti
Average capital charges at 14.9%
of capital investment
Ovefncad
Plant, 20% of conversion costs
Admmisrntive and marketing
Subtotal indirect costs
Total annual operating cost
Percent of total annual operating cost
Equivalent total cnit operating cost
Total
25.368.000
42.736.000
Unit cost, $
1.65/liter
8.00/man-hr
0.70/M Ib
-0.60/MM Btu
0.08/M gal
0.010/kWh
12.00/hr
Dollars/ton
100% H2SO4
80.75
Startup
bypass Paniculate
ducts removal
491.000 8.736.000
794.000 14.123.000
Raw
materials
104,700
172.800
172,800
440
3400
27,420,000
274,200
3
264400
541300
172,800 541300
118300 2,104400
108,400
136,100
118,300 2348300
172300 118400 23904600
1.95 1J3 32.57
SOj
conversion
2.145.000
5.195.000
2,930
23400
270,000
2,700
6
128,700
154,900
154,900
774,100
31,000
33400
838,600
993400
11.20
Heat
recovery
1.475.000
2.384.000
440
3400
179,000
125300
987,000
(S9WOO)
3,470,000
34,700
3
44.300
(384,400)
(384,400)
355,200
(76500)
(96400)
181300
(202,6 00)
(2.28)
Fans
1.412.000
2482,000
440
3,500
52340,000
528,400
8
113,000
644,900
644,900
340,000
129,000
161,900
630,900
1,275,800
14.38
H2SO«
absorption
& cooling
8,917,000
14,415,000
440
3400
312,000
25,000
5,750,000
57400
5
448,200
3,200
38,400
572,600
572,600
2,147,800
114400
177,700
2,440,000
3,012,600
33.94
Acid
storage & Construction
shipping Utilities Services facilities
409.000 57.TKX) 518.000 1.208.000
661.000 92,000 838.000 1,952,000
3,200
25,600
260,000 230.000 200,000
2,600 2300 2,000
4
16,400
800
9,600
54,200 2300 2,000
54,200 2,300 2,000
98400 13,700 124,900 290,900
10,800 500 400
13,600 600 500
122,900 14,800 125300 290,900
177,100 17,100 127300 290.900
2.00 0.19 1.44 3.28
Total Total
annual annual
quantities dollars
104,700
172,800
172,800
7,890
63,100
179,000
125300
987,000
(592,200)
312,000
25,000
90,440,000
904,400
4
1,014,700
4.000
48,000
1488,300
1,761,100
6,367,700
• 317,700
427,400
7,112,800
8,873,900
Percent of
total annual
operating cost
1.95
S.95
0.71
1.41
(6.67)
0.28
10.19
11.44
044
17.90
1935
71.75
348
431
80.15
100.00
Doflan/toB Cents/million Dollars/ton
coal burned Kuls/kWh Btu heat input sulfur removed
6.76 2.54 28.17
247.32
'Basis:
500-MW new coal-fired power unit, 3.5% S in fuel; 90% SOj removal; 109,900 tons/yr 100% H2SO«
Remaining life of power plant, 30 yr.
Coal burned, 1312400 tons/yr;9,000 Btu/kWh.
Power unit on-ttream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Sulfur removed, 35,880 tons/yt
Investment and operating cost for disposal of fly ash excluded.
-------
Table 68. Catalytic Oxidation Process
Total Average Annual Operating Costs
Existing Case3 Summary—Area Contribution Analysis
Direct capital investment, $
Total capital investment, $
Direct Costt
Delivered raw material
Catalyst
Annual quantity, liters
Annual cost, $
Subtotal raw material costs
Conversion costs
Operating labor and supervision
Annual quantity, man-hi
Annual cost, $
Utilities
Fuel oil (No. 2)
Annual quantity, gal
Annual cost, S
Process water
Annual quantity, M gal
Annual cost, $
Electricity
Annual quantity. kWh
Annual cost, $
Maintenance (labor and material)
Percent of direct investment
Annual cost, $
Analyses
Annual quantity, hi
Annual cost, $
Subtotal conversion costs
Subtotal direct costs
Indirect Costt
Average capital charges at 15.3%
of capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketiag
Subtotal indirect costs
Total annual operating cost
Percent of total annual operating cost
Equivalent total unit operating cost
Total
21.419.000
37,907,000
Unit cost. J
1.65/nter
8.00/min-hr
0.30/gal
0.02/M gal
0.010/kWh
12.00/hr
DoOats/ton
100%H}SO4
110.41
Startup
bypass Paniculate
ducts removal
304.000 4.260.000
511,000 7,188,000
Raw
materials
107,000
176,600
176,600
440
3400
3400,000
35.000
2
85,200
123,700
176,600 123,700
78300 1,099,800
24,700
11,100
78,300 1,135,600
176,600 78,300 1,259,300
1.43 0.63 10.16
SO,
conversion
1.983.000
5,113,000
2,930
23400
270,000
2,700
6
116,000
142,200
142,200
782300
28,400
11,200
821,900
964,100
7.78
DoDars/ton Cents/minion
Reheat
3.258.000
5,498,000
440
3400
10.330,000
3,099,000
140,000
1,400
6
195400
3,299.400
3,299,400
841.200
659,900
296,200
1,797300
5,096,700
41.10
Dollars/ ton
Fans
2.133.000
3499,000
440
3400
66,800,000
668,000
8
170,600
842,100
842,100
550,600
168.400
75,400
794,600
1,636,700
13.20
H,S04
absorption
& cooling
6.840.000
11442,000
440
3400
7,961.000
159,200
3,180,000
31,800
4
270,300
3,200
38,400
503,200
503,200
1,765.900
100,700
57,100
1323,700
2,426300
1947
Acid
storage &
shipping Utilities
481,000 527.000
812,000 888,000
3,200
25.600
260,000 240,000
2,600 2,400
4
19,200
800
9,600
57,000 2,400
57,000 2,400
124,200 135,800
11.400 500
5,100 200
140,700 136400
197,700 138,900
149 1.12
Total Total
Construction annual annual
Services facilities quantities dollars
613,000 1.020.000
1,035,000 1.721,000
107.000
176,600
176,600
7,890
63,100
10.330,000
3,099,000
7361,000
159,200
210,000 74,600,000
2,100 746,000
4
856,800
4,000
48,000
2,100 4,972,100
2,100 5,148,700
158,400 263,300 5,799,800
400 994,400
200 456,700
159,000 263,300 7,250,900
161,100 263,300 12399,600
1.30 2.12
Percent of
total annual
operating con
1.42
1.42
041
24.99
1.28
6.02
6.91
0.39
40.10
4142
46.78
8.02
3.68
58.48
100.00
coal burned Mills/kWh Btu heat input sulfur removed
9.24 3.54 3841
338.05
•Ban*-
500-MW existing coal-fired power unit. 3.5% S in fuel; 90% SO2 removal; 112,300 tons/yr 100% HjSO4.
Remaining life of power plant, 25 yr.
Coal burned, 1,341.700 tons/yr; 9,200 Btu/kWh.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Sulfur removed, 36,680 toos/yr.
Investment and operating cost fot disposal of fly ash excluded.
-------
Process
^-- _ . _ _ .. ,,_ _______
Major operating cost components (percent of total annual operating cost)
I 2 3 4
Limestone slurry
Lime slurry
Magnesia slurry - regeneration
Sodium solution • S02 reduction
Catalytic oxidation
Capital charges
(48.68)
Capital charges
(41.24)
Capital charges
(42.71)
Capital charges
(39.16)
Capital charges
(71.75)
Maintenance
(16.69)
Lime
(22.05)
Fuel oil
(13.39)
Steam
(13.00)
Maintenance
(11.44)
Electricity
(10.22)
Maintenance
(14.14)
Maintenance
(12.41)
Maintenance
(9.75)
Electricity
(10.19)
Limestone
(9.09)
Electricity
(9.15)
Plant overhead
(8.44)
Plant overhead
(7.80)
Administrative and
marketing overhead
1,500
8,000
3,000 4,500
Annual on-stream time, hr
Figure 51. Limestone slurry process. Effect of annual
on-stream time on total average annual operating
cost: new coal-fired units under regulated economics
7,500
1,500
6,000
3,000 4,500
Annual on-stream time, hr
Figure 52. Sodium solution - SO2 reduction
process. Effect of annual on-stream time on
total average annual operating cost: new
coal-fired units under regulated economics
7,500
1,600
6,000
3,000 4,500
Annual on-itream time, hr
Figure 53. Catalytic oxidation process.
Effect of annual on-stream time on total
average annual operating cost: new
coal-fired units under regulated economics
7,500
I*,-
3.5% Sin coal
90% SO, removal
7,000 hr annual oparation
capital charaas animated as % of totat capita) invattmant
400 800 800
Povwr unit liia, MW
1,000
Figure 54. Limestone slurry process. Effect
of variations in capital charges on total
average annual operating cost: new
coal-fired units under regulated economics
-------
I-
•8
«f1B
BlO
I I
35% S in coal
90% SO, removal
7.000 hr annual operation
— Average capital charges estimated ti % of total capital InvMtrmnt
I
200
400 600 800
Powar unit size, MW
1,000
Figure 55. Magnesia slurry - regeneration
process. Effect of variations in capital
charges on total average annual operating cost:
new coal-fired units under regulated economics
I I I I
3.8% S In coal
90% SO) ramoval
7,000 hr annual operation
— Labor colt varlad from projected valun by tha % Indicated
200
400
800
Powar unit tin, MW
800
1,000
Figure 57. Magnesia slurry - regeneration
process. Effect of variations in labor cost
on total average annual operating cost: new
coal-fired units under regulated economics
20 —
10 —
I I \
3.5% S in coal
90% SO, removal
7,000 hr annual operation
Average capital charge* animated as %
of total capital investment
J_
_L
_L
200
400 600 800
Powar unit size, MW
1.000
12%
Figure 56. Catalytic oxidation process.
Effect of variations in capital charges
on total average annual operating cost:
new coal-fired units under regulated economics
I I I I
3.9% S in coal
90% SO, removal
7,000 hr annual operation
— Maintenance cost varied from base values by the % indicated
I
I
I
I
I
20C
400
800
Power unit site, MW
800
1,000
Figure 58. Magnesia slurry - regeneration
process. Effect of variations'in maintenance
cost on total average annual operating cost:
new coal-fired units under regulated economics
145
-------
I-
I I I
3.5% S in coal
90% SO, removal
7,000 hr annual operation
Energy cott varied from bait value* by
the % indicated
I
200
400 800 800
Power unit ilze, MW
1,000
Figure 59. Sodium solution - SO2 reduction
process. Effect of variations in energy cost
on total average annual operating cost: new
coal-fired units under regulated economics
= 20
I I
3.5% S in coal
90% SO] removal
7,000 hr annual operation
— Steam con varied from batt values by the % indicated
E
I
200
400
600
Powtf unit till. MW
800
1,000
Figure 61. Sodium solution - S02 reduction
process. Effect of variations in steam cost
on total average annual operating cost: new
coal-fired units under regulated economics
i-
I.
«'0
— Energy cost varied from base values by the % indicated
I 1
35% S in coal
90% SOj removal
7,000 hr annual operation
I
T
I
I
I
T
I
400 600
Power unit lite, MW
800
1,000
Figure 60. Catalytic oxidation process.
Effect of variations in energy cost on
total average annual operating cost: new
coal-fired units under regulated economics
10
3.5% S in coal
90% SO] removal
7,000 hr ennui! operation
I
T
I
I
200
400
600
Powar unit tl», MW
800
1,000
Figure 62. Limestone slurry process.
Effect of variations in limestone price
on total average annual operating cost: new
coal-fired units under regulated economics
The sensitivity of the limestone and lime slurry
process annual operating costs to variations in raw
material price, and solid disposal method and costs are
indicated in figures 62 through 64. As can be seen in the
tabulated results, presented in table 58, operating costs for
limestone and lime scrubbing processes utilizing off-site
disposal are higher than those for processes utilizing
low-cost on-site disposal. A wide range of overall costs
could be encountered.
Figure 65 indicates the sensitivity of projected annual
operating costs of the magnesia slurry - regeneration process
to magnesia losses encountered during drying, regeneration
and cycling of the absorbent.
The effect of antioxidant utilization on the annual
operating cost of the sodium scrubbing- S02 redaction to
S process, corresponding to new 3.5% S coal-fired units is
shown in figure 66. This figure compares the operating
costs for sodium systems designed for no antioxidant
146
-------
520
I,
T
T
3 b% S HI iml
00% SO, innnval
/,000 hi annual operation
I
400
JIB/ton
I
600
Povwr unit siie, MW
800
1,000
Figure 63. Lime slurry process. Effect
of variations in lime price on total
average annual operating cost: new
coal-fired units under regulated economics
f
I
I'o
I I T I
3,6% S In coal
80% SO, removal
7.000 hr annual operation
— Variation! In MjO loiaai axpramd ai % of throuahput
0.8%
I
200
400 . 600
Powtr unit liza, MW
800
1,000
Figure 65. Magnesia slurry - regeneration
process. Effect of variations in MgO losses
on total average annual operating cost: new
coal-fired units under regulated economics
5
&
I.
I I 1
3.5% S in coal
90% SO, removal
7.000 hr annual operation
600
Power unit lize, MW
1.000
Figure 64. Limestone slurry process. Effect
of variations in limestone price and in disposal
method on total average annual operating cost:
new coal-fired units under regulated economics
I-
•s
I'
[
I I
3.5% S In coal
90% SO] rtmoval
7,000 hr annual operation
400
800
Power unit lite, MW
800
1,000
Figure 66. Sodium solution - SO3 reduction
process. Effect of antioxidant use on
total average annual operating cost: new
coal-fired units under regulated economics
utilization with costs for systems designed for the amount
recommended by the process developer, considering the
overall relationship between antioxidant utilization, sulfite
oxidation, and makeup sodium carbonate requirements.
Figure 67 shows the effect of catalyst losses on the
annual operating cost for the catalytic oxidation process.
The lower curve, indicating 10% catalyst losses per year,
corresponds to the expected costs for new coal-fired power
units which have 99.9% efficient electrostatic precipitators.
(outlet fly ash loading of 0.005 gr/scf), and require cleaning
of the catalyst only four times per year. If, however, the
electrostatic precipitators are not capable of operating at
the high efficiency desired, additional cleanings would be
required. The middle and upper curves indicate the effect
of additional cleanings and corresponding catalyst losses on
the projected annual operating costs.
147
-------
-15
I I
3.5% S in coal
90% SO] removal
7,000 hr annual operation
10 —
24 clnninp/yr, 60% km
r, 10% Urn
• 12 ctMnings/yr, 30% lott
J_
_L
I
200
400 600
Powtr unit lire. MW
Figure 67. Catalytic oxidation process. Effect
of variations in number of cleanings (and resulting
catalyst loss) on total average annual operating
cost: new coal-fired units under regulated economics
81.
-I
IH
1
J 200
90*. SU,
Limeitorw slurry proctu X
Ltmf slurry proem •"•
Mugimil* slurry • regeneration pioccsi O
Sodium solution SO reduction proems
CiUlytic oxidation pmceu «
I
I
600
Power uml itit, MW
800
1.000
Figure 68. All processes. Effect of power unit
size on cumulative present worth of total increase
or decrease in cost of power to consumers:
new coal-fired units under regulated economics
Lifetime Operating Cost
Along with the investment and annual operating cost
summary tables given in Appendix B, computer projections
of the detailed year-to-year operating cost and sales revenue
analyses for the base case and 16 variations for each of the
five processes arc presented. These projections are prepared
on a regulated economics basis as discussed in the pro-
cedure and correspond to the 30-year declining operating
profile of the unit established in the power plant
premises. Annual capital charges are based on the
£0
III
sl° °
"•S
60
•51150
P
o S
Linrwitorw slurry process X
Lime tlurry process • <*•
Magnesia slurry • regeneration process • 0
Sodium solution • SO, reduction process
Catalytic oxidation process • <>
?.5% 5 in oil
90% SO, (cmovdl
L-
1
600 800
fowtt .mil lira. MW
_J
t.ooo
Figure 69. All processes. Effect of power unit
size on cumulative present worth of total increase
or decrease in cost of power to consumers:
new oil-fired units under regulated economics
undepreciated investment. The overall net increase or
decrease in cost of power is shown for each year,
considering the declining annual operating cost and the net
sales revenue resulting from sale of marketable byproducts.
Lifetime costs, both total and discounted (at the regulated
cost of money- 10% for this study) are displayed, and
equivalent unit operating cost are shown. Summarized
results of the lifetime operating cost projections for the five
processes are presented in tables 70 through 74. Table 75
shows the cumulative lifetime credits, both actual and
discounted, for the magnesia, sodium, and Cat-Ox processes
which are included in the lifetime cost projections.
The total discounted lifetime operating costs for the five
processes are presented graphically in figures 68 and 69 for
new coal- and oil-fired power units. The effect of power
unit size on equivalent levelized unit operating costs for
new coal- and oil-fired power units are presented in figures
70 and 71. These unit cost results show trends somewhat
similar to those given in the annual operating cost
estimates; however*the magnitude of the costs are higher.
These higher costs are the result of the declining operating
profile of-the power plant. In comparison with the ranking
of average annual unit operating costs given earlier, the
relative lifetime costs may be shifted slightly since product
revenue is reflected where applicable and since declining
balance capital charges in conjunction with discounted
process costs tend to penalize processes requiring a high
capital investment.
The effect of power unit size on levelized unit operating
costs for existing coal-fired power units is given in figure
72.
Figures 73 and 74 show the effect of sulfur content of
fuel on levelized unit operating costs for new 500-MW coal-
148
-------
Table 70. Limestone Slurry Process
Actual and Discounted Cumulative Total and Unit Increase (Decrease)
in Cost of Power over the Life of the Power Unit3
Case
Coal-fued power unit
90% SO2 removal; on-site solids disposal
200 MWN 3.5% S 30 yr
200 MW E 3.5% S 20 yr
500 MWE 3.5% S 25 yr
500 MW N 2.0% S 30 yr
500 MW N 3.5% S 30 yr
500 MW N 5.0% S 30 yr
1,000 MWE 3.5% S 25 yr
1,000 MWN 3.5% S 30 yr
80% SO 2 removal; on-site solids disposal
500 MW N 3.5% S 30 yr
Cumulative
actual net
increase
(decrease)
in cost
of power, $
99,119,400
57,203,400
153,722,200
170,746,900
193,110,500
212,604,300
242,836,600
294,508,400
185,360,800
Lifetime average increase (decrease)
in unit operating cost
Dollars/ton
(bbl) of
coal (oil)
burned
10.14
12.57
8.67
7.14
8.08
8.89
7.00
6.37
7.75
Cents/
million
Mills/
kWh
3.89
4.97
3.32
2.68
3.03
3.33
2.63
2.31
2.91
Btu
heat
input
42
52
36
29
33
37
29
26
32
.25
.36
.13
.76
.66
.06
.17
.55
.31
Dollars/
ton of
sulfur
removed
371.23
461.32
316.95
457.15
295.50
•227.63
255.89
232.91
319.31
Cumulative
present worth
net increase
(decrease)
in cost of
power,b $
40,142,800
29,067,800
70,550,000
69,314,200
78,439,900
86,426,800
111,985,400
120,015,500
75,259,300
Levelized increase '(decrease) in
unit operating costc
Dollars/ton
(bbl) of
coal (oil)
burned
9.54
11.94
8.07
6.74
7.63
8.40
6.55
6.03
7.32
Mills/
kWh
3.66
4.73
3.09
2.53
2.86
3.15
2.45
2.19
2.74
Cents/
million
Btu heat
input
39.76
49.76
33.61
28.07
31.77
35.01
27.27
25.14
30.48
Dollars/
ton of
sulfur
removed
348.76
437.77
295.06
431.33
278.85
214.99
239.29
220.62
301.04
90% SOj removal; off-site solids disposal
500 MW N 3.5% S 30 yr 195,872,700 8.19 3.07 34.14 299.73 80,426,200 7.82 2.93 32.57 285.91
90% SO2 removal; on-site solids disposal
(existing unit requiring particulate scrubber)
500 MWE 3.5%S 25 yr 190,383,800 10.74 4.12 44.74 392.54 87,143,300 9.96 3.82 41.52 364.46
Oil-fired power unit
90% SOj removal; on-site solids disposal
200 MW N 2.5% S
500 MWN 1.0% S
500 MWN 2.5% S
500 MW N 4.0% S
500 MW E 2.5% S
1,000 MW N 2.5% S
30 yr
30 yr
30 yr
30 yr
25 yr
30 yr
69,607,000
113,517,500
133,973,500
151,255,000
126,916,800
212,367,000
1.86
1.24
1.46
1.65
1.87
1.20
2.73
1.78
2.10
2.37
2.74
1.67
29.67
19.79
23.35
26.36
29.83
19.15
488.47
813.75
384.43
271.07
490.03
315.32
28,281,000
46,404,800
54,743,900
61,808,400
58,358,800
87,171,700
1.75
1.18
1.39
1.57
1.74
1.14
2.58
1.69
2.00
2.25
2.56
1,59
28.01
18.80
22.17
25.03
27.81
18.26
462.11
770.84
365.45
257.64
457.00
300.70
aBasis:
Stack gas reheat to 175°F.
Over previously defined power unit operating profile. 30 yr life;
Midwest plant location, 1975 operating costs.
Investment an i operating cost for disposal of fly ash excluded.
Limestone raw material, cost, $4/ton.
Trucking and off-site costs for calcium solids disposal, $4/ton.
Constant labor cost assumed over life of project.
"Discounted at 10% to initial year.
c£ouivalent to discounted process cost over life of power units.
7,000 hr-lOyr, 5,000 hr-5 yr, 3,500 hr-5 yr, 1,500 hr-10 yr.
-------
Table 71. Lime Slurry Process
Actual and Discounted Cumulative Total and Unit Increase (Decrease)
in Cost of Power over the Life of the Power Unit3
Case
Coal-fired power unit
90% SO2 removal; on-site solids disposal
200 MWN 3.5^- S 30 yr
200 MW E 3 .5~c S 20 yr
500 MW E 3.5" S 25 yr
500 MW N 2.0^ S 30 yr
500 MWN 3.5~c S 30 vr
500 MW N 5.0-- S 30 yr
1,000 MW E 3.5~c S 25 yr
1,000 MWN 3.5^ S 30 yr
80% SO2 removal: on-site solids disposal
500 MW N 3.5"c S 30 yr
Cumulative
actual net
increase
(decrease)
in cost
of power, -S
100.776.300
68,615,500
182,422,100
168-.298.800
194.580,100
217.913.400
282,501.000
296.557,800
187,497,300
Lifetime average increase (decrease)
in unit operating cost
Dollars/ton
(bbl) of
coal (oil)
burned
10.31
15.08
10.29
7.04
8.14
9.12
8.14
6.42
7.84
Mills/
kWh
3.95
5.97
3.94
2.64
3.05
3.42
3.05
2.33
2.94
Cents/
million
Btuheat
• input
42.96
62.81
42.87
29.33
33.91
37.98
33.93
26.73
32.68
Dollars/
ton of
sulfur
removed
377.44
553.35
376.13
450.60
297.75
233.31
297.68
234.53
322.99
Cumulative
present worth
net increase
(decrease)
in cost of
h f
power. S
41,112.500
34.979.000
84.117.600
68.709.000
79.593.300
89.293.900
130,977.300
121.789.900
76.687.900
Levelized increase (decrease) in
unit operating costc
Dollars-' ton
(bbli of
coal i oil.'
burned '
9.-'
14.37
9.62
6.66
~.~4
S.68
7.66
6.12
".45
Mills.
kWh
3.75
5.69
: 69
. 2.50
2.90
' 25
2.87
2.22
2. SO
Cents/
million
Btu heat
incut
40.72
59.88
40.08
27.83
32.24
36.17
31,90
25.51
31.06
Dollars/
ton of
. sulfur
removed
357.19
526.79
351.81
427.56
282.95
222.12
279.87
223.88
306.75
90% SO2 removal; off-site solids disposal
500 MW N 3.515 S 30 yr 195,982,800 8.20 3.07 34.16 299.90 80,903.300
90% SOj removal; on-site solids disposal
(existing unit requiring paniculate scrubber)
500 MWE 3.5
-------
Table 72. Magnesia Slurry- Regeneration Process
Actual and Discounted Cumulative Total and Unit Increase (Decrease)
in Cost of Power over the Life of the Power Unit3
Case
Coal-fired power unit
90% SOj removal
200MWN3.5%S 30 yr
200 MW E 3.5% S 20 yr
500MWE3.5%S 25 yr
500 MW N 2.0% S 30 yr
500MWN3.5%S 30 yr
500MWN5.0%S 30 yr
1,000 MWE 3.5% S 25 yr
1,OOOMWN3.5%S 30 yr
80% SO2 removal
500MWN3.5%S 30 yr
90% SOj removal (existing unit
requiring partjculate scrubber)
500MWE3.5%S 25 yr
Oil-fired power unit
90% SO2 removal
200MWN2.5%S 30 yr
500MWN1.0%S 30 yr
500MWN2.5%S 30 yr
500MWN4.0%S 30 yr
500MWE2.5%S 25 yr
1,000 MW N 2.5% S 30 yr
Cumulative
actual net
increase E
(decrease)
in cost
of power, $
110,802,200
71.1M.500
170,821,300
176,0*1,200
207,239,000
235,017,500
262,956,000
310,696,300
199,642,700
205,075,200
74,295,900
108,158,200
136,607400
160,718,300
133,978,500
209,805300
Lifetime average increase (decrease)
in unit operating cost
)ollars/ton
(bbl) of
coal (oil) Mills/
bumed kWh
11.34
15.64
9.64
7.37
8.67
9.83
7.58
6.72
8.35
11.57
1.98
1.18
1.49
1.75
1.97
1.18
4.35
6.19
3.69
2.76
3.25
3.69
2.84
2.44
3.13
4.43
2.91
1.70
2.14
2.52
2.90
1.65
Cents/
million
Btuheat
input
47.23
65.16
40.15
30.69
36.12
40.96
31.59
28.01
34.80
48.20
31.67
18.85
23.81
28.01
31.49
18.91
Dollars/
ton of
sulfur
removed
412.67
567.22
350.76
469.55
315.43
250.55
275.7S
244.74
341.56
421.10
517.74
775.33
390.87
286.49
516.29
309.45
Cumulative
present worth
Levelized increase (decrease) in
unit operating costc
net increase Dollars/ton
(decrease) (bbl) of
in cost of coal (oil) Mills/
power,b $ burned kWh
44,860,300
36,106,200
78,292,200
71,503,600
84,249,500
95,621,900
121,156,200
126,808,000
81,119,800
93,875,800
30,089,900
44,030,300
55,673,400
65,572,800
61,393,300
85,962,400
10.66
14.84
8.95
6.95
8.19
9.30
7.08
6.38
7.89
10.73
1.87
1.12
1.41
1.66
1.83
1.13
4.09
5.87
3.43
2.61
3.07
3.49
2.66
2.31
2.96
4.12
2.74
1.61
2.03
2.39
2.69
1.57
Cents/
million
Btuheat
input
44.44
61.81
37.30
28.96
34.12
38.73
29.50
26.57
32.86
44.73
29.81
17.83
22.55
26.56
29.25
18.01
Dollars/
ton of
sulfur
removed
389.07
538.90
325.81
443.02
2f7.81
236.86
257.72
232.12
322.54
390.66
486.89
731.40
370.17
271.64
479.26
294.80
aBasis:
Stack gas reheat to 175°F.
Over previously defined power unit operating profile. 30 yr life; 7,000 hr-10 yr, 5,000 hi-5 yr, 3,500 hr-5 yr, 1,500-10 yr.
Midwest plant location, 1975 operating costs.
Investment and operating cost for disposal of fly ash excluded.
Revenue, $8/ton, 100%H2SO4.
Constant labor cost assumed over life of project.
"Discounted at 10% to initial year.
cEquivalent to discounted process cost over life of power units.
-------
to
Table 73. Sodium Solution -SO2 Reduction Process
Actual and Discounted Cumulative Total and Unit Increase (Decrease)
in Cost of Power over the Life of the Power Unit3
Case
Coal-fired power unit
90% SO2 removal
200 MW N 3.5% S 30 yr
200 MW E 3.5% S 20 yr
500 MWE 3.5^5 25 yr
500 MW N 2.0% S 30 yr
500 MW N 3.55? S 30 yr
500 MW N 5.0S S 30 yr
1,OOOMWE3.5%S 25 yr
1,000 MWN 3.5^ S 30 yr
80% SO2 removal
500 MWN 3.5% S 30 yr
90% SOj removal (existing unit requiring
particulate scrubber)
500MWE3.5%S 25 yr
Oil-fired power unit
90% SOj removal
200 MW N 2.5% S 30 yr
500 MWN 1.0% S 30 yr
500 MWN 2.5% S 30 yr
500 MWN 4.0% S 30 yr
500MWE2.5%S 25 yr
l.OOOMWN 2.5% S 30 yr
Cumulative
actual net
increase L
(decrease)
in cost
of power, S
135,200,000
95,051,600
245,102,700
210,050,100
255,114,300
296,905,800
402,645,600
390,806,900
240,560,300
281,830,300
95,903,600
134,582,300
180,606,100
222,853,600
178,718,300
286,613,900
Lifetime average increase (decrease)
in unit operating cost
)ollars/ton
(bbl) of
coal (oil) Mills/
burned kWh
13.83
20.88
13.82
8.79
10.67
12.42
11.61
8.46
10.06
15.90
2.56
1.47
1.97
2.43
2.63
1.62
5.30
8.27
5.30
3.29
4.00
4.66
4.35
3.07
3.77
6.09
3.76
2.11
2.83
3.50
3.86
2.25
Cents/
million
Btu heat
input
57.63
87.00
57.60
36.61
44.46
51.75
48.37
35.23
41.93
66.24
40.88
23.46
31.48
38.84
42.00
25.84
Dollars/
ton of
sulfur
removed
506.37
766.55
505.37
562.38
390.38
317.89
424.28
309.06
414.40
581.09
673.01
964.75
518.24
399.38
690.03
425.56
Cumulative
present worth
Levelized increase (decrease) in
unit operating costc
net increase Dollars/ton
(decrease) fbbl) of
in cost of coal (oil) Mills/
power, $ burned kWh
55.045,000
48,568,300
113,985,500
85,604,900
104,292,300
121,660,300
188,464.400
160,375,200
98,245,000
130,713,900
39,147,900
55,025,400
74,204,600
91,887,900
82,852,700
118,705,700
13.09
19.96
13.03
8.32
10.14
11.83
11.01
8.06
9.55
14.95
2.43
1.39
1.88
2.33
2.47
1.56
5.02
7.90
5.00
3.12
3.80
4.43
4.13
2.92
3.58
5.73
3.57
2.01
2.70
3.35
3.63
2.16
Cents/
million
Btu heat
input
54.53
83.14
54.31
34.67
42.24
49.28
45.90
33.60
39.79
62.28
38.78
22.29
30.06
37.22
39.48
24.87
Dollars/
ton of
sulfur
removed
478.24
731.45
476.73
532.70
370.75
302.64
402.70
294.81
392.98
546.69
639.67
914.04
495.36
383.03
648.81
409.47
aBasis:
Stack gas reheat to 175°F.
Over previously defined power unit operating profile. 30 yr life; 7,000 hr-10 yr, 5,000 hr-5 yr, 3,500 hr-5 yr, 1,500 hr-10 yr.
Midwest plant location, 1975 operating cost.
Investment and operating cost for disposal of fly ash excluded.
Revenue, $25/ton, sulfur; $20/ton, Na2SO4.
Constant labor cost assumed over life of project.
"Discounted at 10% to initial year.
"•Equivalent to discounted process cost over life of power units.
-------
Table 74. Catalytic Oxidation Process
Actual and Discounted Cumulative Total and Unit Increase (Decrease)
in Cost of Power over the Life of the Power Unit3
Case
Coal-fired power unit
90% SO2 removal
200 MW N 3.5% S 30 yr
200 MW E 3.5% S 20 yr
500MWE3.5%S 25 yr
500 MW N 2.0% S 30 yr
500 MWN 3.5% S 30 yr
500 MWN 5.0% S 30 yr
1,OOOMV/E3.5%S 25 yr
1,000 MWN 3.5% S 30 yr
90% SO? removal (existing unit without
existing particulate collection facilities)
500 MW E 3.5% S 25 yr
Oil-fired power unit
90% SOz removal
200 MW N 2.5% S 30 yr
500 MWN 1.0% S 30 yr
500 MW N 2.5% S 30 yr
500 MW N 4.0% S 30 yr
500 MW E 2.5% S 25 yr
1, 000 MWN 2.5% S 30 yr
Cumulative
actual net
Lifetime average increase (decrease)
in unit operating cost
increase Dollars/ton
(decrease) (bbl) of
in cost coal (oil) Mills/
of power, S burned kWh
111,370,000
83,064,800
231,056,400
237,377,500
234,219,400
239,951,400
390,958,500
367,669,100
258,758,900
73,836,300
157,587,800
153,253,600
148,200,000
208,160,100
241,054,000
11.39
18.25
13.03
9.93
9.80
9.66
11.27
7.96
14.60
1.97
1.72
1.67
1.62
3.06
1.36
4.37
7.22
5.00
3.72
3.67
3.62
4.23
2.88
5.59
2.90
2.47
2.40
2.32
.4.50
'l.89
Cents/
million
Btu heat
input
47.47
76.03
54.30
41.37
40.82
40.25
46.96
33.15
60.81
31.47
27.47
26.71
25.83
48.92
21.73
Dollars/
ton of
sulfur
removed
417.12
669.88
476.40
635.55
358.41
247.27
411.97
290.76
533.52
518.15
1,129.66
439.75
265.59
803.71
357.91
Cumulative
present worth
Levelized increase (decrease) in
unit operating costc
net increase Dollars/ton
(decrease) (bbl) of
in cost of coal (oil) Mills/
power,*5 S burned kWh
44,823,500
42,423,000
106,607,800
95,780,300
94,320,900
92,805,300
181,012,700
148,117,600
119,124,800
29,653,800
63,574,000
61,591,500
59,249,500
96,305,200
96,899,300
10.66
17.43
12.19
9.31
9.17
9.02
10.58
7.45
13.62
1.84
1.61
1.56
1.50
2.87
1.27
4.08
6.90
4.67
3.49
3.44
3.38
3.97
2.70
5.22
2.70
2.32
2.25
2.16
4.22
1.77
Cents/
million
Btu heat
input
44.40
72.62
50.79
38.79
38.20
37.59
44.08
31.03
56.76
29.37
25.75
24.95
24.00
45.89
20.30
Dollars/
ton of
sulfur
removed
389.43
638.90
445.87
596.02
335.30
230.86
386.78
272.28
498.22
484.54
1,056.05
411.16
246.98
754.15
334.25
aBasis:
Over previously defined power unit life, 30 yr life; 7,000-hr-10 yr, 5,000 hr-5 yr, 3,500 hi-5 yr, 1,500 hr-10 yr.
Midwest plant location, 1975 operating costs not escalated.
Investment and operating cost for disposal of fly ash excluded.
Revenue, $6/ton, 100% H2SO4.
Constant labor cost assumed over life of project.
"Discounted at 10% to initial year.
cEquivalent to discounted process cost over life of power units.
-------
Table 75. Lifetime Byproduct Production and Credit
Case
Magnesia slurry - regeneration process
Lifetime
Years production Net revenue,
remaining short tons, $/short ton Cumulative revenue
Coal-fired power unit life 100%H2O4 100%H,SOA Actual $
90% SO2 removal
200MWN3.5%S
200 MW E 3.5% S
500 MW E 3.5% S
500 MW N 2.0% S
500MWN3.5%S
500 MW N 5.0% S
1,OOOMWE3.5%S
1,OOOMWN3.5%S
80% SO2 removal
500MWN3.5%S
90% SO2 removal
(fly ash removed by particulate
scrubber)
500 MW E 3.5% S
90% SO2 removal
(without existing electrostatic
precipitator)
500MWE3.5%S
Oil-fired power unit
90% SO2 removal
200 MW N 2.5% S
500 MW N 1 .0% S
500 MW N 2.5% S
500 MW N 4.0% S
500 MW E 2.5% S
1,OOOMWN2.5%S
30
20
25
30
30
30
25
30
30
25
25
30
30
30
30
25
30
823,000
383,000
1/92,000
1,149,000
2,011,500
2,874,000
2,918,500
3,889,500
1 ,788,000
1,492,000
-
439,500
430,500
1,072,500
1,716,000
795,500
2,074,500
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
-
8.00
8.00
8.00
8.00
8.00
8.00
6,588,000
3,064,000
11,936,000
9,192,000
16,092,000
22,992,000
23,348,000
31,116,000
14,304,000
11,936,000
-
3,516,000
3,444,000
8,580,000
13,728,000
6,364,000
16,596,000
Sodium solution -
Lifetime
production, Net revenue,
short tons $/short ton
Discounted $ Sulfuf Na^SO* Sulfur
2,834,500
1,638,100
5,886,900
3,956,400
6,923,300
9,894,300
11,517,900
13,388,000
6,156,700
5,887,000
-
1,511,600
1,480,600
3,693,100
5,906,900
3,139,100
7,142,000
244,500 96,500 25.00
114,000 45,000 25.00
442,000 175,000 25.00
340,000 135,000 25.00
595,000 237,000 25.00
851,000 339,000 25.00
864,000 344,000 25.00
1,151,000 457,500 25.00
529,500 211,500 25.00
442,000 175,000 25.00
-
129,500 51,000 25.00
127,500 51,000 25.00
317,000 126,500 25.00
508,500 202,000 25.00
235,000 93,500 25.00
614,000 244,500 25.00
Na,SO4
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
-
20.00
20.00
20.00
20.00
20.00
20.00
SC<2 reduction process
Cumulative revenue
Actual $
8 042,500
3,750,000
14,550,000
11,200,000
19,627,500
28,055,000
28,480,000
37,925,000
17,467,500
14,550,000
-
4,257;500
4,207,500
10,455,000
16,752,500
7,745,000
20,240,000
Discounted $
3,458,900
2,001,600
7,177 500
4,821,600
8,446,300
12,069,700
14,047,200
16,320,200
7,519,700
7,177,500
-
1,831,800
1,810,600
4,496,500
7,206,300
3,824,000
8,707 100
Catalytic oxidation process
Lifetime
production, Net revenue,
short tons, S/short ton Cumulative revenue
100% H,SO4 100% HiSO4 Actual
817,500
380,500
1,484,500
1,144,500
2,002,500
2,859,000
2,904,500
3,868,500
-
-
1,484,500
436,500
426,000
1,068,000
1,708,500
791,000
2,064,000
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
-
-
6.00
6.00
6.00
6.00
6.00
6.00
6.00
4,905,000
2,283,000
8,907,000
6,867,000
12,01.5,000
17,154,000
17,427,000
23,211,000
-
-
8,907,000
2,619,000
2,556,000
6,408,000
10,251,000
4,746.000
12,384,000
Discounted $
2,111,400
1.221,200
4,392,300
2,953,900
5,168,900
7,382,800
8,595,800
9,988,500
-
-
4,392,400
1,128,100
1.100,200
2,756,400
4,411,200
2,342,100
5,328,400
-------
I immtixwi ttuiry proctlt X
I urm »tuny untunj .<
MnuiiHtii) flurry rftgeoftrallun proem 0
SiMlium tulunon SO, reduction proceii
Cmlylic oxidation process <>
_L
16.5
600 KO
Power unit slit, MW
Figure 70. All processes. Effect of power
unit size on levelized unit operating cost:
new coal-fired units under regulated economics
5800
§600 —
1200
T
Limestone ilurry process X
Lime slurry process • A
Magnesia slurry - regeneration procew 0
Sodium solution - SO, reduction £roc*H • 0
Catalytic oxidation proce« • °
200
_L
400
J.
600
Power unit li/t, MW
_L
Figure 71. All processes. Effect of power
unit size on levelized unit operating cost:
new oil-fired units under regulated economics
800
200
LlmMtoiw ilurry proem X
Lime ilurry prooatl *
Magneiii ilurry • regeneration proem 0
Sodium lolutlon • SOj reduction proceN •
Catalytic oxidation proctu • "
200
400 600
Power unit tii», MW
800
22.0
16.5
5.5
1,000
Figure 72. All processes. Effect of power unit
size on levelized unit operating cost: existing
coal-fired units under regulated economics
S10
f
1.
1 I I
Limestone tlurry proceu • X
Lime slurry process • "
Magnesia slurry regeneration process • 0
Sodium solution SO, reduction process •
Catalytic oxidation process - "
90% SO, removal
I
JL
1
3 4
Sulfur in coal, %
4.50
3.75 a
8
3.00 •
2.25
Figure 73. All processes. Effect of sulfur content
of coal on levelized unit operating cost: new 500-MW
coaJ-fired units under regulated economics
and oil-fired power units. In comparison with the annual
operating costs given earlier, the relative ranking is shifted.
For the catalytic oxidation process these costs decrease
with increasing sulfur content of fuel for both coal- and
oil-fired power units, whereas, for all other processes, these
costs increase.
Table 76 shows the effect of designing for 80% SO2
removal instead of the assumed standard of 90% on
cumulative lifetime discounted process costs for the lime-
stone, lime, magnesia, and sodium processes. Designing for
80% S02 removal in comparison to 90% results in a lifetime
savings of only 3.6% to 5.8% of the projected costs
corresponding to 90% S02 removal.
Given in table 77 is a comparison of the lifetime
operating costs for existing units requiring additional
facilities for removal of particulates with the standard case
which assumes that existing electrostatic precipitators on
existing units are adequate. The effect is similar to that
shown for the investment and annual operating costs;
additional costs for particulate removal are the least for the
lime slurry process because only minor modifications in
design and operation are required.
155
-------
Table 76. Comparison of Cumulative Lifetime Discounted Process
_c.°jLts for S02 Removal Processes at 90% and 80% S02 Removal
Cumulative lifetime discounted
process cost, $
500MW,new3.5%S
coal-fired units
Cumulative lifetime
discounted cost savings
resulting from design
for 80% S02 removal
Process
Limestone slurry
lime slurry
Magnesia slurry - regeneration
Sodium solution - S02 reduction
90%SQ2
removal
78,439,900
79,593,300
84,249,500
104,292,300
80% S02
removal
75,259,300
76,687,900
81,119,800
98,245,000
compared to 90%
$
3,180,600
2,905,400
3,129,700
6,047,300
%
4.1
3.6
3.7
5.8
Table 77. Cumulative Lifetime Discounted Process Costs for S02 Removal Installations on Existing
Power Units Requiring Additional Facilities for Removal of Particulates-Comparison with Standard3
Cumulative discounted process
cost, $
500-MW existing 3.5% S
coal-fired units Difference in projected
Requiring additional cumulative lifetime dis-
particulate removal counted process costs
Process
Limestone slurry
Lime slurry
Magnesia slurry - regeneration
Sodium solution - S02 reduction
Catalytic oxidation
facilities
87,143,300
84,924,200
93,875,800
130,713,900
119,124,800
Standard3
70,550,000
84,117,600
78,292,200
113,985,500
106,607,800
$
16,593,300
806,600
15,533,600
16,728,400
12,517,000
%
23.5
1.0
19.9
14.7
11.7
Standard case assumes that the existing electrostatic precipitator is adequate for existing units.
,2.5
I I T
Limestone slurry process > X
Lime slurry process • A
Magnesia slurry • regeneration process • 0
Sodium solution • SO] reduction proces* • 0
—Catalytic oxidation process • "
90% SO, removal
1.0
I
I
3.5
3.0 E
2.5 f
2.0,
1.5
1.0
2 3
Sulfur in oil, %
Figure 74. All processes. Effect of sulfur content
of oil on levelized unit operating cost: new 500-MW
oil-fired units under regulated economics
The comparison between cumulative lifetime discounted
process costs for the limestone and lime processes cor-
responding to off-site and on-site waste solids disposal
shown in table 78 indicates that the cumulative discounted
costs for off-site waste solids disposal are only 1.6% to 2.5%
greater than for the on-site disposal variations. This result is
somewhat surprising in comparison with the 6.2% to 8.0%
higher annual operating costs projected for off-site disposal
variations. Obviously, the effect of declining on-stream time
compiled with the off-site disposal fee per ton of wet solids
narrows the difference.
The sensitivity of lifetime operating costs to parameter
changes not readily visible in the results of the case
variations are discussed below.
The effect of declining remaining life of a power unit on
levelized unit operating costs for the limestone slurry
process is shown in figure 75.
Figure 76 shows the overall range of discounted process
costs which could be expected for the limestone slurry
process over the life of the power unit when both high and
low price limestone and on-site and off-site disposal
variations are considered simultaneously. In comparing the
results, it should be remembered that the majority of the
1S6
-------
Table 78. Comparison of Cumulative Lifetime Discounted
Process Cost for Limestone and Lime SO?
Removal Processes Utilizing On-site and
Off-site Waste Solids Disjx>saJ_
Process
Limestone
slurry
lime slurry
Cumulative discounted
process cost, $
500-MW,new3.5%S
coal-fired units
Off-site -On-site
80,426,200 78,439,900
80,903,300 79,593,300
Cumulative
discounted
lifetime savings
resulting from
design for
on-site as
opposed to
off-site waste
solids disposal
$ %
\ ,986,300 2.5
1,310,000 1.6
case variations of limestone and lime slurry processes
correspond to power units which utilize an on-site pond for
waste disposal. If, for a given power plant, land is not
available, alternate methods of disposal would need to be
used.
Figures 77 through 81 show the sensitivity of lifetime
levelized unit operating costs to variations in total capital
investment for the five processes. These relationships can be
used for projecting the range of levelized unit operating
costs which may be encountered as a result of possible
inaccuracies in the projected investment, or with variations
in project scope.
The effects of variations in product revenue on levelized
unit operating costs for the magnesia and sodium scrubbing
processes, and the catalytic oxidation process are given in
figures 82 through 87. The revenues are varied from what is
considered to be a minimum price in a saturated market up
to the current list price. It can be seen that the sensitivity
of levelized unit operating costs to variations in product
revenue is greater for the sulfuric acid than the sulfur
processes. This is an important point when the weight
relationship between sulfur and sulfuric acid is considered;
1 ton of sulfur is equivalent to approximately 3 tons of
sulfuric acid.
Figure 88 shows the effect of annual labor cost
escalation on the cumulative lifetime discounted costs of
the limestone and sodium scrubbing processes (a) without
labor escalation and (b) with labor cost escalation rates of
7.5% per year over the life of the power unit. The
relationship shows that there is an increase of about
7%-10% in the projected lifetime operating costs with
escalation included.
The effect of variations in the cost of money on
levelized unit operating costs for the five processes are
presented in figures 89 through 93. The relative variations
,20
.
\
Is
3.5% S in coal
80% SO, rimovil
— On tin WMM Klldi dlipoul
15-vL
200
400 BOO
Povwr unit tin, MW
800
1,000
Figure 75. Limestone slurry process. Effect of years
remaining life on levelized unit operating cost:
existing coal-fired units under regulated economics
1*1
*
|l|
*iS
«
!
I I
3.6* S in col
00% SO, rimovi!
MO
Povwr unit tilt. MW
800
Figure 76. Limestone slurry process. Effect
of variation in limestone price and in disposal
method on cumulative present worth of total
increase or decrease in cost of power to consumers:
new coal-fired units under regulated economics
are obviously the greatest for the processes which require
the greatest capital investment.
ACCURACY OF RESULTS
When the results of a comprehensive cost evaluation are
widely distributed, questions regarding estimate accuracy
are almost always raised. For SO2 processes, such questions
are especially relevant since many previous process cost
estimates have been inconsistent.
157
-------
1
1,6
I
3,5% S In coil
aOK SO, rtmovil
_ Invntmtnt wild from bra vitun by thi % Indteind
500
400.1
"
! !
300
200 1
-j
100
Po»
600 800
r unit f>», MW
1,000
Figure 77. Limestone slurry process. Effect of
variations in investment on levelized unit operating
cost: new coal-fired units under regulated economics
,20
115
.
3.6%Sinco«l
90% SO,
Invntmtnt vtrlwl from but vilutt by thi % Indicitid
200
400 600
Povwr unit llw, MW
BOO
400
300?
9
200 "I
100
1,000
Figure 78. Lime slurry process. Effect of variations
in investment on levelized unit operating cost:
new coal-fired units under regulated economics
,20
3.6* S In cot!
90*50, rimovtl
~ lnvtilm.ru viritd from biH vllu«l by lh« % Indiciud
600 *
§
400 |
300,
200 i
too
400 600 800
Povwr unit iin, MW
1,000
Figure 79. Magnesia slurry - regeneration
process. Effect of variations in investment
on levelized unit operating cost: new
coal-fired units under regulated economics
3.5%Slncoil
am SO, rtmmit
ImMtrmnt virlfd from DIM vilun by th» % indicated
_L
200
400
600 800
f>ov»r unit tin, MW
£
600|
"
100
Figure 80. Sodium solution - S02 reduction
process. Effect of variations in investment
on levelized unit operating cost: new
coal-fired units under regulated economics
T
3.6S S in coil
90S SO, r«mov«l.
Invntmint v.riM from bm v«iun by thi % indiutid
I
I
400 «00 800
Powtr unit tin, MW
1.000
-f
"I
400 |
300 |
200 i
100
Figure 81. Catalytic oxidation process. Effect of
variations in investment on levelized unit operating
cost: new coal-fired units under regulated economics
810
3.6* Sin coil
90K SOi rimovll
$ 0/ton.
'* B/ton
WSA
'$32/nn.
I
600 800
Poiwr unit lln. MW
460
400 »
350 f
300 .f
2 BO S
200 |
ISO'S
.3
1001
1.000
Figure 82. Magnesia slurry - regeneration
process. Effect of variations in sulf uric
acid revenue on levelized unit operating cost:
new coal-fired units under regulated economics
-------
2.5% S in oil
90% SO] rwnoval
I
I
400 800 800
Pomr unit tin. MW
1,000
Figure 83. Magnesia slurry - regeneration
process. Effect of variations in sulfuric acid
revenue on levelized unit operating cost:
new oil-fired units under regulated economics
BOO
400
200
2.5% S in oil
90%SOj removal
_ Sulfur expremd in thort tons
600 800
r unit Itzt, MW
1.000
Figure 85. Sodium solution • S02 reduction
process. Effect of variations in sulfur
revenue on levelized unit operating cost: new
oil-fired units under regulated economics
700 £
600 °>
K>of
400 =
120
1
S15
i
I
1,0
1
S
1
3.6S S in co.1
90% SO, removil
Sulfur ixpreiwd in thort toni
200
400
600 800
Power unit size, MW
Figure 84. Sodium solution • S02 reduction
process. Effect of variations in sulfur
revenue on levelized unit operating cost:
new coal-fired units under regulated economics
BOO K
S
.?
400 S
3001
1
200|
100
400 800 800
Powar unit tizt, MW
1,000
Figure 86. Catalytic oxidation process.
Effect of variations in sulfuric acid.revenue
on levelized unit operating cost: new
coal-fired units under regulated economics
159
-------
2.5% S in oil
90% SO, removal
I
I
I
600 800
Power unit llza, MW
Figure 87. Catalytic oxidation process.
Effect of variations in sulfuric acid
revenue on levelized unit operating cost:
new oil-fired units under regulated economics
I20
I
1,5
3.5* S In coal
90% SO] removal
_ flagulattd cost of capital applitd it indicated
8%
I
JOO
400
600
Powtr unit tilt, MW
800
1,000
Figure 89. Limestone slurry process.
Effect of variations in cost of money
on levelized unit operating cost: new
coal-fired units under regulated economics
Limtitone flurry prown • X
Sodium solution • SO, refaction procra -c
«00
PDVXI unit tin, MW
Figure 88. Limestone slurry and sodium
solution - S02 reduction processes.
Effect of annual labor cost escalation
on cumulative present worth of total increase
or decrease in cost of power to consumers:
new coal-fired units under regulated economics
Regulated con of capital applied n indicated
600
Power unit iln, MW
BOO
1.000
Figure 90. Lime slurry process. Effect of variations
in cost of money on levelized unit operating
cost: new coal-fired units under regulated economics
160
-------
T,
t 6
3.5% S in coal
90% SO, removal
Regulated cost of capital applied n Indicated
xxxxx
600 800
Puwer unit tire. MW
1,000
Figure 91. Magnesia slurry - regeneration
process. Effect of variations in cost of
money on levelized unit operating cost: new
coal-fired units under regulated economics
,20
3.5% S in cool
90% SO, romoval
Regulated cost of capital applied as indicated
—tt%
I
J_
I
600
r unit size, MW
800
.1.000
Figure 92. Sodium solution • SO2 reduction
process. Effect of variations in cost of
money on levelized unit operating cost:
new coal-fired units under regulated economics
Several full-scale stack gas SO2 removal projects are now
under way and as costs for these become available,
comparisons with the results of this study are to be
expected. In many cases, however, such efforts will be
misleading if care is not taken to make sure the scope of
work is directly comparable. For instance, the base case
(500-MW, 3.5% S new coal-fired unit) capital investment
for limestone slurry scrubbing derived in this study is
$S0.3/kW; however, as can be seen in table 79, with some
j 20
3.6% S In ccxl
90% SO, removal
_ Regulated con of capital applied H Indicated
_L
200
_L
400 600
Power unit size, MW
1.000
Figure 93. Catalytic oxidation process.
Effect of variations in cost of money
on levelized unit operating cost: new
coal-fired units under regulated economics
changes in scope, the cost could rise to $113.0/kW or
higher depending on a variety of inputs.
The actual costs of installing and operating several
large-scale systems will be the best measure of accuracy of
these projections and, even then, the effects of further
process development and inflation will have to be
examined. However, considering the current status of
process technologies, the estimates in this study should be
more accurate than any previously published.
Recognition should be given to the factors having the
greatest degree of uncertainty on the costs of these systems.
Until demonstrated performance is obtained, there are
numerous areas of concern in all the processes; however,
deviations in the following factors are expected to have the
largest impact.
Investment
Mist elimination in slurry scrubbing processes.
System reliability (need for redundancy)-all processes.
Materials of construction-all processes.
Solids disposal system in limestone and lime processes.
Operating Cost
Raw material and solids disposal cost for limestone and
lime processes.
Recycle MgO losses in magnesia process.
Process maintenance-all systems.
Catalyst cleaning and losses in Cat-Ox process.
Oxidation losses in sodium scrubbing process.
Energy costs-all systems.
161
-------
Table 79. Limestone Slurry Process
Investment wjth ModifiedLfrojeciMScope
Investment,
S/kW
Base investment-limestone slurry process.
(including fly ash removal but not disposal)
500-MW new coal-fired unit burning coal with
3.5% S, 12% ash, 90% SO^ removal, 30-year
life, 127,500 hours operation, on-site solids
disposal, proven system, only pumps spared,
no bypass ducts, experienced design and
construction team, no overtime, 3-year
program, 5% per year escalation, mid-1974
cost basis for scaling
Overtime to accelerate project or cover
local demand requirements (50% of
construction labor requirements)
Research and development costs for first
of a kind process technology (as allowed
by FPC accounting practice)
Power generation capital for lost capacity
(normally covered by appropriate
operating costs for power used in
process)
Reliability provisions with added
redundancy of scrubbers, other equipment,
ducts and dampers, instrumentation for
' changeover (assumes no permission to
run power plant without meeting S02
removal emission standards at all times)
Additional bypass ducts and dampers
Retrofit difficulty-moderate, space
, available beyond stack, less than three
shutdowns required for tie-ins, field
I fabrication feasible
Fly ash pond including closed-loop
provisions
500-ft stack added to project cost
Air quality monitoring system, 2-15
mile radius, 10 stations
Cost escalation of 10%/year instead of 5%
Possible delay of up to 2 years in
equipment and material deliveries (1977
completion instead of 1975)
Total
50.30
3.20
5.00
4.50
6.00
2.00
10.00
5.50
6.00
0.70
4.80
15.00
113.00
Sales value of acid, sulfur, and sodium sulfate.
Investment changes caused by process uncertainties
would normally be covered by the estimate contingency
and modifications after startup since the magnitude of
these components reflect process definition. With the
premise that the designs in this study are proven, not first
of a kind, only nominal provisions for contingency (10% of
direct cost) and modifications after startup (10.8% of direct
cost) are included in the base estimates. However, further
refinement will likely evolve during continued process
development. Therefore, projections of total capital invest-
ment variance based on the present "state of the art" and
the data available to TVA are given below for the base case
of each process.
% variance from base
total capital investment
due to data
availability and process
Process development status
Limestone slurry +15, -5
Lime slurry +15, -5
Magnesia slurry - regeneration +20, -10
Sodium solution • SO^ reduction +25,-10
Catalytic oxidation +15, -5
For the time and money spent to prepare the investment
estimates and the state of process development, qualified
texts (4, 23, 33, 34) on the cost estimation indicate these
estimates should have an accuracy range of+25% to 30% to
-10% to -15%. To give the reviewer better perspective on
the reliability of these factors, an analysis of accuracy was
made on the base case investment for each process. In
preparing this analysis, additional projections of possible
variances in the major estimate components were necessary.
The following variances from the base case are considered
to be reflective of information utilized.
Component
Variance, %
Directs
Process equipment
Vendor data
Previous purchases, escalated
Publications
Materials
Construction labor
Site preparation
Land
Construction facilities
Indirects
Engineering, design, and supervision
Construction field expense
Contractors fees
Contingency
Allowance for startup
+20,-10
+10,-10
+30, -20
+20,-15
+25,-15
+ 100,-25
+200, -70
+60, 40
+50,-20
+50, -20
+50,-20
Depends on
process definition
Depends on
process definition
For a 3-year project, interest during construction could
be expected to vary from 6% to 10% of total fixed
investment.
162
-------
Using H'ow inpiils, calculated projections of maximum
und minimum invustmenl which rcllccl accumulation of
individual component deviations for each process are shown
in tables 80 through 84. The cumulative variances are
obviously too large because not all factors will vary in the
same direction and to the extreme values. Therefore, an
educated judgment was used to select the most likely values
for ranges in investment accuracy for each process. These
are stated in table 85.
Because the estimates for cuse variations are fac-
tored, their accuracy must be considered us less than
the base case. Since the accuracy of operating cost
results would depend largely on those for investment,
and because almost every unit of operating cost is a
variable, estimates of operating cost accuracy arc nol
projected. The effects of variations in the primary
operating cost factors are shown in the sensitivity
analyses previously presented.
Table 80. Limestone Slurry Process- Investment Estimate Accuracy Analysis
Investment, $
_ _ Component Minimum Ifrasc case'1
Direct costs
Maximum
Process equipment
Materials
Construction labor
Silc prepaiation
Land
Construction facilities
Subtotal direct investment
Indiiecl costs
.linginecring design and supeivision
Construction Held expense
Conlracloi fees
Contingency
Subtotal llxed investment
Allowance for startup and modifications
Interest dining construction
Total capital investment
Percent of variance
a50()-MW new coal-tired powe> unit, 3.5% S in fuel; 90%
Table 81 . Lime Slurry
Component
Direct costs
Process equipment
Materials
Construction labor
Site preparation
Land
Construction facilities
Subtotal direct investment
Indirect costs
linginecring design and supervision
Construction Held expense
Contractor fees
Contingency
Subtotal llxed investment
Allowance for startup and modifications
Interest during construction
Total capital investment
Percent of variance
4,237,000
2,621,000
3,154,000
2.525,000
1 26,000
4 5') ,000
13.122.000
1,157,000
1.414,000
642,000
1,607.000
17,942,000
477,000
1,077,000
10,406,000
-22.5
4.724,000
3,083.000
3,710,000
3,367.000
420,000
765.000
16,06') ,000
1,446,000
1,768,000
803.000
1,607,000
21,603,000
1,735,000
1,735,000
25,163,000
0
5,571,000
3.700,000
4,638,000
6.734,000
• 1.260.000
1.224,000
23,127.000
2,160,000
2,652,000
1,205,000
3,494,000
32,647,000
3,622,000
3,265,000
30,534,000
+57.1
SOj temoval;on-site solids disposal.
Process-Investment Estimate
Minimum
3,029,000
2,694,000
3,207,000
2,223,000
107,000
409,000
11,669,000
1 ,03 1 .000
1 ,260.000
573,000
1,432,000
15,965,000
425,000
958,000
17,348,000
-22.6
Accuracy Analysis
Investment, $
Base cdsea
3,375,000
3,169,000
3,773,000
2,064,000
355,000
682,000
14,318,000
1,280,000
1,575.000
716,000
1,432,000
19,330,000
1,546,000
1,546,000
22,422,000
0
Maximum
3,962,000
3,803,000
4,717,000
. 5,928,000
1,065,000
1 ,09 1 ,000
20,566,000
1,034,000
2,363.000
1.074,000
3,1.14,000
29,051,000
3,228,000
2,905,000
35,184,000
+56.9
a500-MW new coal-fired power unit, 3.5% S in fuel; 90% SOj removal; on-site solids disposal
Vo3
-------
Table 82. Magnesia Slurry_- Regeneration Process-Investment Estimate Accuracy Analysis
Investment, $
Component
Direct costs
Process equipment
Materials
Construction labor
Site preparation
Land
Construction facilities
Subtotal direct investment
Indirect costs
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction
Total capital investment
Percent of variance
a500-MW new coal-fired power unit, 3.5% S in fuel
Table 83. Sodium Solution -
Component
Direct costs
Process equipment
Materials
Construction labor
Site preparation
Land
Construction facilities
Subtotal direct investment
Indirect costs
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
i Subtotal fixed investment
Allowance for startup and modifications
Interest during construction
Total capital investment
Percent of variance
"500-MW new coal-fired power unit, 3.5% S in fuel;
Minimum
4,940,000
3,383,000
4,781,000
314,000
7,000
467,000
13,892,000
1,438,000
1,438,000
654,000
1,633,000
19,055,000
0
1,143,000
20,198,000
-23.5
; 90% SO2 removal; 15.8 tons/hr 100% H2SO
Base case8
5,509,000
3,980,000
5,625,000
419,000
23,000
778,000
16,334,000
1,797,000
1,797,000
817,000
1,633,000
22,378,000
2,238,000
1,790,000
26,406,000
0
4-
Maximum
6,517,000
4,776,000
7,031,000
838,000
69,000
1,245,000
20,476,000
2,696,000
2,696,000
1,226,000
4,274,000
31,368,000
4,879,000
3,137,000
39,384,000
+49.1
SO2 Reduction Process- Investment Estimate Accuracy Analysis
Minimum
7,610,000
2,934,000
4,853,000
218,000
7,000
539,000
16,161,000
1,660,000
1 ,660,000
754,000
1,886,000
22,121,000
0
1,327,000
23.448,000
-23.1
90% SO2 removal; 4.7 tons/hr S produced.
Investment^
Base case3
8,487,000
3,452,000
5,709,000
291,000
24,000
898,000
18,861,000
2,075,000
2,075,000
943,000
1,886,000
25,840,000
2,584,000
2,067,000
30,491,000
0
Maximum
10,105,000
4,142,000
7,136,000
582,000
72,000
1,437,000
23,474,000
3,113,000
3,113,000
1,415,000
5,697,000
36,812,000
6,395,000
3,681,000
46,888,000
+53.8
164
-------
Table 84. Catalytic Oxidation Process-Investment Estimate Accuracy Analysis
Component
Direct costs
Process equipment
Materials
Construction labor
Site preparation
Land
Construction facilities
Subtotal direct investment
Indirect costs
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowancfe for startup and modifications
Interest during construction
Total capital investment
excluding catalyst
Catalyst
Total capital investment
Percent of variance
Minimum
10,025,000
3,771,000
6,984,000
223,000
6,000
725,000
21,734,000
2,232,000
2,232,000
1,014,000
2,537,000
29,749,000
1,338,000
1,785,000
32,872,000
1,555,000
34,427,000
-19.4
Investment, $
Base case3
11,188,000
4,437,000
8,217,000
297,000
21,000
1,208,000
25,368,000
2,790,000
2,790,000
1,268,000
2,537,000
34,753,000
3,475,000
2,780,000
41,008,000
1,728,000
42,736,000
0
Maximum
13,468,000
5,324,000
10,271,000
594,000
63,000
1,933,000
31 ,653,000
4,185,000
4,185,000
1 ,902,000
5,742,000
47,667,000
6,680,000
4,767,000
59,114,000
2,074,000
61,188,000
+43.2
a500-MW new coal-fired power unit, 3.5% S in fuel; 90% SO2 removal; 15.7 tons/hr 100% H2SO4.
Table 85. Projected Overall Investment Estimate Accuracy
Based on Available Data and Depth of Investigation
Process % range
Limestone slurry
Lime slurry
Magnesia slurry - regeneration
Sodium solution - regeneration
Catalytic oxidation (Cat-Ox)
+20 to -5
+20 to-10
+25 to-15
+25 to-10
+20 to -10
165
-------
Conclusions
From the multitude of data generated in this study, a
large number of conclusions can be derived. The most
important ones are listed below.
INVESTMENT
1. For new coal-fired systems, the lime scrubbing
process has the lowest investment and catalytic oxi-
dation has the highest (figure 33). The limestone
and magnesia processes are less expensive than the
lime process on oil-fired units (figure 34) because
lime process definition specifies two stages of
ventuii scrubbing for S02 removal in comparison to
one SOj scrubbing stage for the limestone and
magnesia processes. Limestone investment is slightly
lower than magnesia investment for both 3.5% S
coal-fired units and 2.5% S oil-fired units. Costs for
all four wet scrubbing processes range within 22%
to 36% of each other depending upon the fuel.
2. As sulfur content of fuel varies, the relative invest-
ment ranking of the wet scrubbing processes
changes; lime is still lowest for coal-fired units
(figure 36), but for oil-fired units (figure 37), lime-
stone or magnesia investments are the lowest.
Although these investments are very close through-
out the range of sulfur values, magnesia investment
is slightly lower for the low-sulfur oil, and lime-
stone investment is slightly lower for the medium-
and high-sulfur oils.
3. The Cat-Ox process has the poorest investment economy
of scale (unit size) of all five systems (figures 33 and
34); however, for sulfur variations, Cat-Ox has the best
scale factor (figures 36 and 37). A reheat (existing)
Cat-Ox system requiring full particulate removal facili-
ties to 0.005 gr/scf was found to be only 2.5% higher
than a new integrated unit (table 31).
4. Plant age is an important factor only in the limestone
and lime processes (figure 42) where pond size depends
on remaining plant life; older (less remaining life) units
should use limestone or lime processes.
5. Removal of only 80% of the S02 (which would
meet emission standards for 3.5% S coal-fired units)
instead of 90% decreases investment by only 3% to
5% (table 33).
OPERATING COST
1. For new 3.5% S coal-fired power units under the
premises used, the limestone process has the lowest
annual operating cost and sodium the highest (figure
43). For 2.5% S oil-fired units, limestone and Cat-Ox
operating costs are very competitive, ranking the
lowest of the five processes and sodium the highest
(figure 44). Lifetime operating costs are lowest for the
limestone slurry process for coal-fired power units, and
sodium Jhe highest (figure 70). However, the magnesia
process is competitive with limestone and lime
operating costs for the larger size units. For new 2.5%
S oil-fired units, lifetime limestone operating costs are
lowest for 200- and 500-MW units, whereas, magnesia
process operating cost is lowest for 1,000-MW units
(figure 71).
2. As sulfur content of fuel varies, the relative operating
costs for all five systems change. However, the most
dramatic change is reflected in the lifetime operating
cost for the Cat-Ox process. The Cat-Ox process
lifetime operating c'ost is the highest of the five
processes for low sulfur oil-fired units, whereas, for
high sulfur oils it improves in rank and becomes the
lowest (figure 74). This is one of the most interesting
results of the study. The heat credit for Cat-Ox
becomes quite significant at high sulfur levels. Con-
sidering the overall range of sulfur contents for both
coal- and oil-fired units, situations exist for which
lifetime operating costs for four of the five processes
are lowest in rank (figures 73 and 74).
3. Raw material costs for the lime and sodium processes
are highest of the five processes, whereas, those for the
magnesia and Cat-Ox processes are lowest (tables
59-68).
4. Sodium scrubbing has the highest total labor cost and
Cat-Ox the lowest; however, labor is one of the
smallest components (l%-3% of total annual operating
cost) for all five processes (tables 59-68).
5. Energy costs are significant for all systems; applications
of sodium scrubbing on existing units require the
greatest amount of energy (35% of total operating
cost). The magnesia process is also energy intensive; the
Cat-Ox system uses the lowest amount (5%) (tables
59-68).
166
-------
6. Although expense for antioxidant (sodium system) is
high, it is justified lo keep sulfate formation down and
save NajCO.i makeup (figure 66).
7. Maintenance is quile significant ranging from 7% of (he
total annual operating cost for (he Cat-Ox reheat
process (existing unit) to 17% for the limestone slurry
process (new unit) (tables 59-68).
8. Capital charges are the largest individual component of
operating cost for all five processes (tables 59-68). For
new Cat-Ox systems, base case capital charges are 72%
of the total annual operating costs. For the other
processes, base case capital charges are in the range of
39% to 50%. A change in depreciation rate or cost of
money will obviously affect Cat-Ox the most.
9. For high operating on-stream times, on-site solids
disposal is less expensive than off-site (table 58),
however, the reverse may be true for low operating
times.
10. Only about 4% to 6% of total operating cost is saved
when 80% S02 removal is provided instead of 90%
(table 76).
11. A Cat-Ox process on an existing plant has a 40%
greater annual operating cost than on a new system
(table 55). This is caused by the high energy required
for stack gas reheat from 310° to 890°F prior to
conversion of S02 to S03.
12. As would be expected the scrubbing steps of each
process are the highest cost operations (tables 59-68).
13. For the energy intensive processes, oil-fired systems are
at a disadvantage because of the high cost of fuel oil
relative to coal ($1.53/MM Btu compared to S0.54/MM
Btu).
14. Because 3 tons of sulfuric acid can be made from
approximately 1 ton of sulfur, every dollar increase in
net sales revenue for acid would require an equivalent
$3 increase in value of sulfur to obtain the same reve-
nue. Current prices of sulfuric acid in small quantities
can be as high as $35/ton; however, the best sulfur
prices would probably be less than $50/ton. If in the
sodium scrubbing process, an acid plant were substi-
tuted for a sulfur production unit, approximately
$335,000 a year operating cost could be saved; how-
ever, this is only 3% of the total operating cost. Sale of
byproducts at the values assumed in the study would
reduce the base case lifetime operating cost 7.2% for
the magnesia, 7.1% for the sodium, and 4.9% for the
Cat-Ox process (tables B-l 17, B-165, and B-213).
15. Because of product revenues, the relative ranking of
the magnesia scrubbing process on oil-fired units
improves under lifetime operating costs until it is the
lowest cost system above 800-MW size (figure 71).
16. Labor cost escalation (7.5% per year) over a 30-year
process life would add about 7% to 10% to total
process cost (figure 88).
17. Regardless of which process is utilized, the increase in
the cost of power to consumers for the base case is
projected to range from 2.86 to 3.80 mills/kWh. For all
case variations, projected costs could range from 1.57
to 7.90 mills/kWh (tables 70-74).
18. Because the relative rankings of these five processes are
so variable, and the results so close, this evaluation will
need to be updated as process definitions stabilize,
improvements are developed, and economic conditions
change.
167
-------
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1973.
13. Farmer, M. H. "Long Range Sulfur Supply Demand
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16. Federal Power Commission. "Statistics of Privately
Owned Electric Utilities in the United States, 1971 "
Washington, D.C. 20402: Superintendent of
Documents, U.S. Government Printing Office FPC
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17. Federal Power Commission. "Steam-Electric Construc-
tion Cost and Annual Production Expenses." Twenty-
fourth Annual Supplement-1971. Washington, D.C.
20402: Superintendent of Documents, U.S.
Government Printing Office, February 1973.
18. Gittinger, L. B. "Sulphur • Outlook for Producers Best
in Several Years." Eng. Mining J., Vol. 174, March
1973, pp. 152-154.
19. Grant, Eugene L. and W. Grant Ireson. Principles of
Engineering Economy. Ronald Press Company, New
York, 1964.
20. Guthrie, K. M. "Capital Cost Estimating." Chemical
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114-142.
21. Hewson, G. W., S. L. Pearce, A. Pollitt, and R. L. Rees.
Soc. Chem. Ind. (London), Chem. Eng. Group, Proc.
25, 1933, pp. 67-99.
22. Hunter, William D., Jr. "Application of S02 Reduction
in Stack Gas Desulfurization Systems." New Orleans,
Louisiana: EPA Flue Gas Desulfurization Symposium,
1973.
23. Jelen, F. C. Cost and Optimization Engineering.
McGraw-Hill Book Company, New York, 1970, pp.
302-303.
168
-------
24. Johnslone, H. F., H. J. Read, and H. C. Blankmeyer.
"Recovery of S02 frofn Waste Gases. Equilibrium
Vapor Pressures Over Suifite-Bisulfite Solutions." Ind.
Eng. Oiem.,Vol.30,No. 1, 1938, pp. 101-109.
25. M. W. Kellogg Company. "Evaluation of S02 - Control
Processes." Springfield, Virginia 22151: National
Technical Information. Service. (PB 204-711), 1971.
26. M. W. Kellogg Company. "Evaluation of the Control-
lability of Power Plants Having a Significant Impact on
Air Quality Standards." Springfield, Virginia 22151:
National Technical Informal ion Service, l')74.
27. Koehlei, George R. "Operational Performance of the
Chemico Basic Magnesium Oxide System at the Boston
Edison Company." New Orleans, Louisiana: I;,I'A Hue
Gas Dcsulfuri/ation Symposium, l()73.
28. McGlamery, G. G., R. L. Torslrick, J. P. Simpson, and
J. F. Phillips, Jr. "Conceptual Design and Cost Study,
Sulfur Oxide Removal From Power Plant Stack Gas -
Magnesia Scrubbing - Regeneration: Production of
Concentrated Sulfuric Acid." Springfield, Virginia
22151: National Technical Information Service. (PB
222-509), 1973.
29. McGlamery, G. G., D. A. Waitzman, J. L. Nevins, and
G. A. Slappey. "Marketing Sulfuric Acid From Sulfur
Dioxide Abatement Sources, Phase I - The TVA
Hypothesis." Chicago, Illinois: Electrical World
Conference, 1973.
30. Manderson, M. C. "World Sulfur Outlook Into the Late
1970's." Chicago, Illinois: 160th American Chemical
Society National Meeting, 1970.
31. Miller, W. E. "The Cat-Ox Project at Illinois Power."
New Orleans, Louisiana: EPA Flue Gas Desulfurization
Symposium, 1973.
32. Pearson, J. L., G. Nonhebel, and P.H.N. Ulander, ./.
Inst. Fuel, Vol. VIII, No. 39, February 1935, pp.
119-156.
33. Perry, John II. Chemical Engineers' Handbook, Fourth
Edition, McGraw-Hill Book Company, New York,
1963.
34. Peters, Max Stone and Klaus D. Timmerhaus. Plant
Design and Economics for Chemical Engineers.
McGraw-Hill Book Company, New York, 1968.
35. "Pilot Plant Absorbs Sulfur in Station Stack
Gases." Electrical World, Vol. 1(>8, October 9,
1967, pp. 29-30.
36. Platou, J. S. "Elemental Sulfur- Problems and Oppor-
tunities." Chicago, Illinois: Electrical World
Conference, 1973.
37. Plumley, A. L., 0. D. Whiddon, F. W. Shutko, and J.
Jonakin. "Removal of S02 and Dust From Stack
Gases." Paper presented at American Power
Conference, Chicago, Illinois, April 25-27, 1967.
38. Pollock, W. A., J. P: Tomany, and G. Frieling. Mech.
/;>ȣ., Vol. K'), No. H, August l%7, pp. 21-25.
39. Popper, Herbert. Modern Cost Engineering Techniques.
McGraw-Hill Book Company, New York, 1970.
40. Raben, I. A. "Status of Technology of Commercially
Offered Lime and Limestone Flue Gas Desulfurization
Systems." New Orleans, Louisiana: EPA Flue Gas
Desulfurization Symposium, 1973.
41. Radian Corporation. "Evaluation of Lime/Limestone
Sludge Disposal Options." Prepared for Environmental
Protection Agency, Research Triangle Park, N.C.,
1973.
42. Rees, R. L. ./. Inst. Fuel. Vol. XXV, No. 148, March
1953, pp. 350-357,
43. Rochellc, Gary T. "Economics of Flue Gas Desulfuriza-
tion." New Orleans, Louisiana: EPA Flue Gas
Desulfuri/.ation Symposium, 1973.
44. Rossoff, J. (Aerospace Corporation, El Segundo,
California). Private communication.
45. Sakanishi, Jim and Robert H. Quig. "One Year's
Performance and Operability of the Chemico/Mitsui
Carbide Sludge (Lime) Additive S02 Scrubbing System
at Ohmula No. 1." New Orleans, Louisiana: EPA Flue
Gas Desulfurization Symposium, 1973.
46. Schmidt, Paul Frank. Fuel Oil Manual, Third Edition.
Industrial Press, Inc., New York, 1969.
47. Schneider, Raymond T. and Christopher B. Earl.
"Application of the Wellman-Lord SOi Recovery
Process to Stack Gas Desulfurization." New Orleans,
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1973.
48. Sensenbaugh, J. D. "Formation and Control of Oxides
of Nitrogen in Combustion Processes." Combustion
Engineering Inc., Windsor, Conn. (PA.C.ce. 16.5.66) ,
49. Slack, A. V. Sulfur Dioxide Removal From Waste
Gases. Park Ridge, New Jersey: Noyes Dati
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"Economic Factors in Recovery of Sulfur Dioxide
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From Power Plant Stack Gas - Ammonia S< rubbing:
169
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field, Virginia 22151: National Technical Information
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170
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APPENDIX A
GENERAL CONVERSION FACTORS
EPA policy is to express all measurements in Agency documents in metric units. Values in this report are given in British
units for the convenience of engineers and other scientists accustomed to using the British system, The following conversion
factors may be used to provide metric equivalents.
.ac
bbl
Btu
°F
ft
ft2
ft3
ft/min
ft3/min
gal
gpm
gr
gr/ft3
hp
in
Ib
lb/ft3
Ib/hr
mi
rpm
scfm
ton
ton, long
ton/hr
British
Multiply
acre
barrels of oil
British Thermal Unit
degrees Fahrenheit-32
feet
square feet
cubic feet
feet per minute
cubic feet per minute
gallons
gallons per minute
grains (troy)
grains per cubic foot
horsepower
inches
pounds
pounds per cubic foot
pounds per hour
miles
revolutions per minute
standard cubic feet
per minute (32° F)
tons (short)3
tons (long)3
tons per hour
By
0.405
158.97
252
0.5555
30.48
0.0929
0.02832
0.508
0.000472
3.785
0.06308
0.0648
2.288
0.7457
2.54
0.4536
16.02
0.126
1609.
0.1047
1.695
0.90718
1.016
0.252
Metric
To obtain
hectare
liters
gram-calories
degrees Centigrade
centimeters
square meters
cubic meters
centimeters per second
cubic meters per second
liters
liters per second
grams
grams per cubic meters
kilowatts
centimeters
kilograms
kilograms per cubic meter
grams per second
meters
radians per second
normal cubic meters
per hour (0°C)
metric tons
metric tons
kilograms per second
ha
1
g-cal
°C
cm
m2
m3
cm/sec
m3 /sec
1
I/sec
g
g/m3
kW
cm
kg
Kg/m3
g/sec
m
rad/sec
Nm3/hr
t
t
kg/sec
aAH tons, including tons of sulfur, are expressed in short tons in this report.
171
-------
APPENDIX B
COST TABLES
Table B-1. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(200-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Paniculate scrubbers and inlet ducts (2 scrubbers
including common feed plenum, effluent hold tanks,
agitators, and pumps)
Sulfur dioxide scrubbers and ducts (2 scrubbers including
mist eliminators, effluent hold tanks, agitators,
pumps, and exhaust gas ducts to inlet of fan)
Stack gas reheat (2 indirect steam reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal pumps,
pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
234,000
472,000
1,381,000
2,048,000
243,000
377,000
2,275,000
46,000
2.9
5.9
17.4
25.9
3.1
4.8
28.8
0.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
458,000
377,000
7,911,000
870,000
1,028,000
554,000
870,000
11,233,000
899,000
899,000
13,031,000
5.8
4.8
100.0
11.0
13.0
7.0
11.0
142.0
11.4
11.4
164.8
"Basis:
Stuck gas reheat to I 75 F by indirect steam reheat.
Disposal pond lueulcd 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for sealing, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal ot"fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
172
-------
Table B-2. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MWnew coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-site solids disposal)
Direct Costs
Delivered raw material
Limestone
Subtotal
Annual quantity
71.6M tons
Total annual
Unit cost, $ cost, $
4.00/ton 286,400
286,400
Percent of
total annual
operating cost
7.30
7.30
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .09 x 7,911,000
Analyses
Subtotal conversion costs
Subtotal direct costs
17,520 man-hr
201,500 M Ib
102,300Mgal
32,180,000 kWh
8.00/man-hr
0.80/M Ib
0.08/M gal
0.011/kWh
140,200
161,200
8,200
354,000
712,000
24,000
1,399,600
1,686,000
3.58
4.11
0.21
9.03
18.15
0.61
35.69
42.99
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
1,941,600
a Basis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $13,031,000;subtotal direct investment, $7,911,000.
Working capital, $283,000.
Investment and operating cost for disposal of tly ash excluded.
49.51
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 7.31
279,900
14,000
2,235,500
3,921,500
Cents/million
Mills/kWh Btu heat input
2.80 30.45
7.14
0.36
57.01
100.00
Dollars/ton
sulfur removed
267.31
173
-------
Table B-3
L1HESTCKE SLURRY PROCESS, 200 Hit. NEW CG»L FIRED POWER UNIT, 3.5* S IN FUEL, 90* SD2 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: » 13031000
TOTAL
SULFUH et-PRQDUCT OP. COST
REMOVED
YEARS ANNUAL
AFTtR OPERA-
PCWIR TIUN,
UNIT K«-HR/
START KK
1 7000
2 7COO
3 7COO
4 7COO
s_ iliac _
6 7000
7 7000
8 70CC
9 7COO
_\ ^ 3tlLkl
11 5COC
12 5000
13 5000
li 5000
_1S 5£iQC -
16 3500
17 3500
18 3500
19 3500
POKER UNIT
Hf AT
REQUIREMENT
MILLIL'M BTU
/YEAR
12«tfOOOO
12860000
12efcCOUC
122BOCOO
i P h E L; "i n **)
12EtOOOL'
128ROCOO
128fcOOCO
12 1SOO J7fcnnr,n nsnrri
26 1500
27 1500
2£ 1500
29 1500
27600CO
2760000
2760000
2760000
115000
115000
115000
115000
-JO 1500 23tCOOJ. 0.15UGO
BY
POLLUTION
CCNTKOL
PROCESS,
TOSS/YEAR
14700
14TOC
14700
14700
l&ZOC
14700
14700
14700
14700
_ 147gn
10500
1050C
10500
10500
i ns n n
7300
7300
7300
73 OC
za ao.
31 OC
3100
' 3100
3100
3.i.aa.
3100
3100
3100
3100
3J.OO.
TOT 127500 i346CCOCO 9775000 267000
LIFEUHE AVERAGE INCREASE (DECREASE) IN UhlT OPERATING COST
DOLLARS PER TON OF CLAL BURNED
HILLS PER KILOWATT-HCWR
CENTS PER BILLION BTU HEAT IMPUT
DOLLARS PER TON OF SLLFUR RF10VED
PROCESS CCST DISCGUIiTED AT 10.0* TO INITIAL YEAR, DOLLARS
LEVEL1ZED INCREASE (DirCR EASE J l.K UNIT OPEJJAT1HG COS
DOLLARS PER TCK OF CCAL BURNED
MILLS PER K1LOWA1T-HCUR
CENTS PER MILLION BTt HEAT IMPUT
DOLLARS PER TON OF SULFUR RE10VED
RATE,
:tiUIVALENT
TONS/YEAR
WASTE
SOLIDS
84200
84200
84200
84200
84200
84200
P4200
84200
60200
60200
60200
60200
42100
42100
42100
42100
4?JQQ
18000
18000
18COO
18000
IfOOO
18000
18000
18000
1BCQQ
1533500
G COST
RS
EQUIVALENT TO
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE, REGULATED TUTAL INCREASE NET INCREASE
t/TON ROI FOR NET (DECREASE) (DECREASE)
POWER SALES IN COST OF IN COST OF
WASTE COMPANY, REVENUE, POWER, POWER,
SOLIDS */YEAR S/YEAR * t
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
o.n
0.0
0.0
• o.o
0.0
o.n _
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
O-O
DISCOUNTED
5277200
5186900
5096500
5006200
4825500
4735100
4644800
4554400
3919600
3829200
3738900
3648500
3106100
3015600
2925400
2835100
2115700
2025400
1935000
1844700
1664000
1573600
1483300
1392900
99119400
10.14
3.89
42.25
371.23
40142800
PROCESS COST OVER
9.54
3.66
39.76
348.76
0
0
0
0
o
0
0
0
0
n
0
0
0
0
Q
0
0
0
0
fl_
0
0
0
0
n
0
0
0
0
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
5277200
5186900
5096500
5006200
441^800
4825500
4735100
4644800
4554400
3919600
3829200
3738900
3648500
aSSfiZQQ
31061CO
3015800
2925400
2835100
22A.4JQO _
2115700
2025400
1935000
1844700
1254300- -
1664000
1573600
1483300
1392900
99,119,400
10.14
3.89
42.25
371.23
40142,800
POWER UNIT
9.54
3.66
39.76
348.76
5277200
10464100
15560600
205668CO
. ..254112*00
303081CO
35043200
39688000
44242400
52626100
56455300
60194200
63842700
6.2400300
70507000
735228GO
76448200
79263300
84143700
86169100
BB104100
89948800
aO.2O3.lOO
933*7100
9*940700
96424000
97816900
99119400
-------
Table B-4. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(200-MW existing coal-fired power unit, 3.5% S in fuel;
90% S02 removal; on-site solids disposal)
Percent of subtotal
Investment. $ direct investment
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins) 271,000 4.1
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps) 528,000 8.0
Sulfur dioxide scrubbers and ducts (2 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between outlet of supplemental fan and stack
gas plenum) 2,278,000 34.5
Stack gas reheat (2 direct oil-fired reheaters) 142,000 2.1
Fans (2 fans including ducts and dampers between tie-in
to existing ducts and inlet to supplemental fan) 757,000 11.5
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps) 1,554,000 23.5
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant) 229,000 3.4
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees •
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
534,000
315,000
6,608,000
793,000
991,000
595,000
793,000
9,780,000
782,000
782,000
11,344,000
8.1
4.8
100.0
12.0
15.0
9.0
12.0
148.0
11.8
11.8
171.6
"Basis:
Stack gas reheat to 175 °F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps arc spared.
Remaining life of power unit, 20 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
175
-------
Table 8-5. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW existing coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-stte solids disposal)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .09 x 6,608,000
Analyses
Subtotal conversion costs
Subtotal direct costs
73.9 M tons
17,520 man-hr
1,720,000 gal
105,700 M gal
27,140,000 kWh
4.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.011/kWh
295,600
295,600
140,200
395,600
8,500
298,500
594,700
24.000
1,461,500
1,757,100
Percent of
total annual
operating cost
7.64
7.64
3.63
10.23
0.22
7.72
15'.38
0.62
37.80
45.44
Indirect Costs
Average capital charges at 15.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 6.98
1 ,803,700
292,300
14,000
2,110,000
3,867,100
Cents/million
Mills/kWh Btu heat input
2.76 29.08
46.64
7.56
0.36
54.56
100.00
Dollars/ton
sulfur removed
255.25
"Basis:
Remaining life of power plant, 20 yr.
Coal jurned, 554,200 tons/yr, 9,500 Btu/kWh
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $11,344,000; subtotal direct investment, $6,608,000.
Working capital, $294,900.
Investment and operating cost for removal and disposal of fly ash excluded.
176
-------
Table B-6
LIMESTONE SLURRY PROCESS. 200 MW. EXISTING COAL FIRED POWER UNIT. 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
11344000
YEARS ANNUAL
AFTER CPERA-
P&I.ER T10S,
UMT KW-hR/
STAR.T Kk
1
2
3
S
6
7
8
11 50QO
1 2 5COO
13 5COC
14 50CO
_L5. 5.a&a
16 35&0
17 3500
18 3500
19 3500
2 Q 3 5 Q C
21 1500
22 1500
23 1500
24 1500
SULFUK
REMOVED
POWER UNIT PUWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CCMSUMPT ION . CONTROL
MILLION ETU TONS COAI PROCESS,
/YEAR /YEAR TONS/YEAR
95COOOC 395800 10800
95CCOOC 395800 10300
95CCOCO 395800 10800
95C-COCG 395PCO 1&800
*5*'"'aOO i^^flCO 1Q8.QO
6650000 277100 7600
66SOOOO 277103 7iOO
665C300 277100 7600
66500CC 277100 7600
665.COPO 277100 7kQQ
2850000 118700 3200
28500CO 118700 3200
285..000 116700 3200
2650003 116700 3200
-25 -15.QD ?8Lti(H.n ii«7oo _ -*2on
26 1500
27 1500
28 1500
29 1500
10 ison
TOT 57500
LIFETIME
PROCESS CtST
LFVCLHED
285GOCO 116700 3200
2850000 118700 3200
2850000 116700 3200
285CCOG 118700 3200
28YOOCQ. 11870.0 3.2BQ
1C92500CO 4551500 124000
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
62100
62100
62100
621CO
f±2 1 no
43500
43500
43500
43500
43SOO
18600
16600
18600
18600
__. 1B6QQ
18600
18600
18600
10600
1R600
714000
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
$/TON
WASTE
SOLIDS
0.0
c.o
0.0
c.o
n.n
0.0
0.0
0.0
0.0
n.o
0.0
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
n.n
RO! FOR
POWER
COMPANY,
WYEAR
4554600
4436600
4318600
4200600
6QP y fcfi 0
3577100
3459100
3341100
3223100
TOTAL
NET
SALES
REVENUE,
$/YEAR
0
0
0
0
fl_
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
4554600
4436600
4318600
4200600
40.4260.0-
3577100
3459100
3341100
3223100
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
t
4554600
8991200
13309800
1751C400
2 1 **<) 3QOO
25170100
28629200
31970300
35193400
3105200 n 3lO5?QQ ^«?<>KAnn
2421400
2303400
21C5400
2067400
„ , ._ i«Jt
-------
Table B-7. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW existing coal-fired power unit, 3.5% S in fuel;
90% SO} removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between outlet of supplemental fan and
stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in
to existing duct and inlet to supplemental fan)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
482,000
1,000,000
5,243,000
323,000
1,710,000
3,611,000
335,000
3.4
7.1
37.1
2.3
12.1
25.6
2.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
740,000
672,000
14,116,000
1,412,000
1,835,000
988,000
1 ,553,000
19,904,000
1,592,000
1,592,000
23,088,000
5.2
4.8
100.0
10.0
13.0
7.0
11.0
141.0
11.3
11.3
163.6
aBasis: 0
Stack gas reheat to 175 F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
178
-------
Table B-8. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-site solids disposal)
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
178.9 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 14,116,000
Analyses
Subtotal conversion costs
Subtotal direct costs
26,280 man-hr
4,160,000 gal
255,900 M gal
65,720,000 kWh
4.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.010/kWh
715,600
715,600
210,200
956,800
20,500
657,200
1,129,300
45.600
3,019,600
3,735,200
Percent of
total annual
operating costs
9.07
9.07
2.66
12.12
0.26
8.33
14.31
0.58
38.26
47.33
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 5.88
3,532,500
603,900
21,000
4,157,400
7,892,600
Cents/million
Mills/kWh Btu heat input
2.26 24.51
44.75
7.65
0.27
52.67
100.00
Dollars/ton
sulfur removed
215.17
"Basis:
Remaining life of power plant, 25 yr.
Coal burned, 1,341,700otons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°I''.
Power unit on-strcam time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $23,088.000; subtotal direct investment, $14,116,000.
Working capital. $628,200.
Investment and operating cost Tor removal and disposal of fly ash excluded.
179
-------
00
o
Table B-9
LIMESTONE SLURRY PRCCESS, 500 MW. EXlSTIlsG COAL FIRED POWER UNIT, 3.5« S IN FUEL, 90* 502 REMOVAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT:
23088003
YEARS ANNUAL PCKER UNIT
AFTER OPERA- HEAT
PQrfER TICN, REQUIREMENT,
UNIT Kh-KR/ KILLIPN ETU
START K« /YEAR
SULFUR BY-PRODUCT
REMOVED RATE,
POWH* UNIT BY EQUIVALENT
FUEL POLLUTION TONS/YEAR
CONSUMPTION, CONTROL
TONS COAL PROCESS, WASTE
/YEAR TONS/YEAR SOLIDS
NET REVENUE,
I/TON
WASTE
SLLIDS
1
2
3
i;
fe
7
Id
11
12.
16
17
lo
19
7CCC
70CO
7COO
7COO
2C.O.D. _
5CCO
5000
5COO
5COO
_iaac. -
3500
35CC
35CO
35CO
3SOC
21 1500
22 15CO
23 1500
24 1500
-2.5 _liDC . ..
26 1500
27 1500
2t 1500
29 1500
_3.a 15QQ
322C0003
322CCOCO
322COCOO
322CCOC3
^2200000
<:30CCOOO
23000000
23000000
230COOCO
I610COOO
leiocooc
161G03CO
161000CO
69COOCO
69COOOO
69COOOO
69CCOCO
69CCOOO
t9GOCOO
69COOOG
6900000
1341700
1341700
1341700
1341700
13417QO
958300
958300
958300
958300
670800
670800
670830
670800
67QftQfi
287500
287500
2P7500
267500
1 ft 7? 00
2S7500
2b7500
28750C
267500
36700
36700
36700
36700
2620C
26200
26200
26200
18300
18300
18300
16300
7900
7900
7900
7900
79np
7900
7900
7900
7900
210.0.
210600
210600
210600
210600
150400
150400
150400
150400
105300
105300
105300
105300
45100
45100
45100
45100
45100
45100
45100
45100
0.0
0.0
0.0
0.0
o.n
0.0
0.0
0.0
0.0
0 ,0
0.0
0.0
0.0
0.0
nTn
0.0
0.0
0.0
0.0
Q-O
0.0
0.0
0.0
0.0
o.n
POWER
SALES
COMPANY, REVENUE, POWER,
IN COST OF IN COST OF
POWER,
»/Y£AR
S/YEAR
TOT 92500 4255COOCC 17729000 485300 2782500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TCN OF CuAL BURNED
MILLi PER KILDWATT-HuUR
CEMS PER MILLION BTti HEAT 1MPUT
DliLLttRS PER TCN UF SLLFUR REMOVED
PROCESS COST DISCOUNTED AT 10.01 TO INITIAL YEAR, COLLARS
IfcVELlZEO INCREASE (DECREASE* IK UNIT OPERATING COST EtUlVALEKT TO DISCOUNTED PROCESS COST OVER LIFE OF POWER UNIT
DOLLARS PER TON OF ClAL EURfcED 8.C7 0.0 8.07
MILLS PER KILtiWATT-HlUR 3.09 0.0 3.09
CENTS PE* MILLION BTU HEAT INPUT 33.61 0.0 33.61
UGLLARS PER TON OF JLLFUR RE10VED 295.06 0.0 295.O6
10293700
10101600
9909500
9717400
_ 452,540.0
8262700
8070600
7878500
7666400
6465800
6273700
6081600
5689600
0
0
0
0
Q_.
0
0
0
0
0
0
0
0
0
n
4301800 0
4109700 0
3917600 0
37255CO 0
3533*00 0_
3341300 0
3149300 0
2957200 0
2765100 0
2,52300.0 -Q_
153722200 0
8.67 C.O
3.32 0.0
36.13 0.0
316.95 C.O
70550000 . 0
1C293700
10101600
9909500
9717400
8262700
8070600
7878500
768640C
646580Q
6273700
6081600
5889600
.. _ .-5697500
4301800
4109700
3917600
3725500
3341300
3149300
2957200
2765100
2S73000
153,722,200
8.67
3.32
36.13
316.95
70,550/100
10293700
2039S300
30304800
40022200
57810300
65680900
73759400
81445800
—EAStO-iao
95405900
101679600
107761200
113650800
123650100
127759800
131677400
135402900
142277600
145426930
148384100
151149200
-------
Table B-10. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 2.0% S in fuel;
90% SOi removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, effluent hold tanks,
agitators, pumps, and exhaust gas ducts to inlet of
fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal pumps,
pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment. $
Percent of subtotal
direct investment
291,000
601,000
3,203,000
4,745,000
556,000
854,000
2,789,000
67,000
2.0
4.2
22.2
32.9
3.8
5.9
19.3
0.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
638,000
687,000
14,431,000
1,299,000
1,587,000
722,000
1,443,000
19,482,000
1,559,000
1,559,000
22,600,000
4.4
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheat to 175 !•'by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
181
-------
Table B-11. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 2.0% S in fuel;
90% SOi removal; on-site solids disposal)
Direct Costs
Deliveied r;iw material
Limestone
Subtotal raw mntisiial
Annual quantity
Unit cost, $
Total annual
cost, $
100.0 M tons
4.00/t on
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 14,431,000
Analyses
Subtotal conversion costs
Subtotal direct costs
21 ,(»80 man-hr
492,800 M Ib
217,900 M gal
76,060,000 kWh
8.00/man-hr
0.70/M Ib
0.08/M gal
0.010/kWh
400,000
400,000
173,400
345,000
17,400
760,600
1,154,500
40,800
2,491,700
2,891,700
Percent of
total annual
operating cost
5.90
5.90
2.56
5.09
0.26
11.23
17.04
0.60
36.78
42.68
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit. operating cost 5.16
3,367,400
498,300
17,300
3,883,000
6,774,700
Cents/million
Mills/kWh fitu heat input
1.94 21.51
49.70
7.36
0.26
57.32
100.00
Dollars/ton
sulfur removed
330.47
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Blu/kWh
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating cqsts.
Total capital investment, $22,600,000; subtotal direct investment, $14,431,000.
Working capital, $481,800. .
Investment and operating cosl for disposal of fly ash excluded.
182
-------
TableB-12
LIMESTONE SLURRY PRICES', SCO H*. NEW CPfL FIRED POWEk UNIT, 2.0% S IN FUEL, 90* 502 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
22600000
YtAFS ANNUAL
AFTER CPEkA-
PGxER TUN,
UMT Kii-hR/
START K»
1
2
3
6
7
c
9
11
13
14
16
17
le
19
_2a
22
23
26
27
23
29
_3Q
70CO
7CCC
7COO
7000
2C.CC
7CCC
7COO
7CCO
70CC
5COC
5tOC
5CCO
500C
3500
3500
3500
3500
150C
1500
1500
1500
1500
150C
1500
1500
1400
TUT 127500
LIFETIME
PBOlESS COST
PrWER UMT PQWEf. UNIT
HE*T FUEL
f EtUUL^ENT, CONSUMPTION,
KILL 1C'. ETU TUNS CLAL
/YE-* /YEAR
315C C-OCO
315rC3CiO
315i.COC3
315UCCC
315COOCO
315, jGi.0
315CC300
iiSCOOCO
2250*01,0
225COOCC
2251.COOC
1575JOCO
IS 750000
157LJJOO
6751000
6750CC3
6750000
675J3CO
67S30C j
675GOCO
675000C
1312500
131 25 JO
13125CO
13125CO
131250C
13125i?
1312500
13125JC
937503
S37500
937500-
937500
656200
b56200
656200
t562CO
2R1203
2T;1200
2K1200
2bl200
2B1200
231210
251200
25120C
SULFUR bY-PRUDUCT
REMOVED RATE,
bY EQUIVALENT
POLLUTION TONS/YEAR
CONTiiDL
PRUCESS, WASTE
TONS/YEAR SCLIDS
20500
20530
20530
2050C
20500
20500
20500
2050C
14600
14600
14600
14600
10300
10300
10300
103 30
4400
4400
4400
*4 00
4tkQQ
4400
4430
4400
4430
57375CCOC' 23S05530 373500
AVtKAGF INCkbASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILUWATT-H_UR
CEkTS PER KILLIGN 611. HEAT INPUT
DOLLARS PER TON OF SLLFUR REHOVEO
aiSCliUhTEl AT 10.0% TO INITIAL YEAR, DOLLARS
1-17700
1177CO
117700
117700
1177CO
117700
117700
117700
641CO
S41CO
84100
841CO
^4100
56900
56900
58900
58900
25200
25200
25200
25200
. .. .252CQ . ,
25200
25200
25200
25200
2144000
COST
TOTAL
OP. COST
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE, REGULATED TOTAL INCREASE NET INCREASE
S/TON ROI FOR NET (DECREASE) (DECREASE)
POWER SALES IN COST OF IN COST OF
WASTE COMPANY, REVENUE, POWER, POWER.
SCLIDS i/YEAfc S/YEAR S *
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
c.o
0.0
0.0
0.0
0-Q
0.0
0.0
0.0
0.0
0.0
c.o
0.0
0.0
0.0
9125800
8969100
8812400
8655700
B4941QO
8342400
8185700
8029000
7872300
6757600
6600900
64443CO
6287600
5339900
5183200
5026500
4869600
3623700
3467000
3310300
3153600
2840200
26S3600
2526900
2370200
170746900
7.14
2.68
29.76
457.15
69314200
0
0
0
0
n
9125800
8969100
8812400
8655700
«4991 JO
0 8342400
0 8185700
0 8029000
0 7872300
0 7715600
0
0
0
0
0
0
0
0
0
o
0
0
0
0
0
0
0
0
0
n
0
0.0
0.0
0.0
0.0
0
6757600
6600900
6444300
62676CO
5339900
5183200
5026500
4669800
3623700
3467000
3310300
3153600
299*90"
2840200
2683600
2526900
2370200
170,746,900
7.14
2.68
29.76
457.15
69,31VOO
9125800
18094900
26907300
35563000
52404500
60590200
686192CO
76491500
64^071 so
9C9647CO
97565603
1040C9900
110297500
121768300
126951500
131978000
136847800
1451647CG
148651700
151962000
155115600
160952700
163636300
166163200
16*533400
LEVELIZED 1NCPEASE (DECREASE) IN UNIT OPERATING CIST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF POWER UNIT
DOLLARS PER TLN iif CLAL BURNED 6.74 0.0 6.74
MILLS PER KlLOWATT-HfUR 2.53 0.0 2.53
CEKTS PER MLLIC'N BTL HEAT INPUT 28.07 0.0 28.07
DOLLARS PER TuN Of SLLFUR REMOVED 431.33 0.0 431.33
00
-------
Table B-13. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% S0j removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, effluent hold tanks,
agitators, pumps, and exhaust gas ducts to inlet
of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal pumps,
pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
419,000
899,000
3,203,000
4,745,000
556,000
854,000
3,923,000
67,000
2.6
5.6
19.9
29.5
3.5
5.3
24.4
0.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
638,000
765,000
16,069,000
1 ,446,000
1,768,000
803,000
1,607,000
21,693,000
1,735,000
1,735,000
25,163,000
4.0
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheat to 175 F by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
184
-------
Table B-14. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% SO 2 removal; on-site solids disposal)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
175.0 M tons
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 16,069,000
Analyses
Subtotal conversion costs
*
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
26,280 man-hr
492,800 M Ib
250,300 M gal
78,740,000 kWh
4.00/ton
8.00/man-hr
0.70/M Ib
0.08/M gal
0.010/kWh
700,000
700,000
210,200
345,000
20,000
787,400
1,285,500
45,600
2,693,700
3,393,700
3,749,300
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, l,312,500otons/yr, 9,000 Btu/kWh.
Slack gas reheat to 175°1\
Power unit on-strcam time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $25,163,000; subtotal direct investment, $16,069,000.
Working capital, $572,600.
Investment and operating cost I'or disposal of fly ash excluded.
Percent of
total annual
operating cost
9.09
9.09
2.73
4.48
0.26
10.22
16.69
0.59
34.97
44.06
48.68
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 5.87
538,700
21,000
4,309,000
7,702,700
Cents/million
Mills/kWh Btu heat input
2.20 24.45
6.99
0.27
55.94
100.00
Dollars/ton
sulfur removed
214.68
185
-------
TableB-15
LIMESTONE SLURRY PROCESS, 500 HW . NEtt COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT- * 25163000
YEARS ANNUAL
AFTtR OPERA-
POWER T1UN.
UNIT KW-HR/
START KK
1 7000
2 7000
3 7CCO
4 7000
*> innn
6 7000
7 7000
3 7000
9 7000
10 7000
11 5000
12 5000
13 5000
14 5000
1? 5PQP
16 3500
17 3500
It 3500
19 3500
20. 3^QP
21 1500
22 1500
23 1500
24 1500
SULFUR BY-PRODUCT
REMOVED RATE,
PCWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TCNS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION ETU TONS COAL PROCESS,
/YEAR /YEAR TCNS/YEAR
315COCOO 131250C 35900
315CGOOO 1312500 35900
31SCOOGO 1312500 35900
3150COCO 1312500 35900
315QQQOG. 1312.5QQ 3^900
31500000 1312500 35900
31500000 131250C 35900
31500000 1312500 35900
315COOOO 1312500 35900
^isfioncjo i ^i i ? i o n ^ 5 9 n n
22500000 937500 2560C
225COOCC 937500 25600
22500000 937500 25600
2250COCO 937500 25600
ppejonono *>^"7Sftfi 2*»f» oo
157500CO 656200 17900
15750000 656200 17900
15750000 656200 17900
15750000 656200 17900
i575riQQn fc5&2Cfl 179QO
6750000 261200 7700
6750000 2812CO 7700
6750000 281200 7700
6750000 2aI200 7700
WASTE
SOLIDS
206000
206000
206000
206000
?n*iftflft
206000
206000
206000
206000
2n«.oon
147100
147100
147100
147100
i & 11 on
103000
103000
103000
103COO
103000
44100
44100
44100
44100
2S l^QO tisnofia ?&i2no TIQO. &6ino
26 1500
27 1500
2B 1500
29 1500
•*n 1500,
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
6750000 281200 7700
6750000 281200 7700
67500CO 261200 7700
6750000 28I20C 7700
tn75iQQOQ 2H1?00 7^0.^
573750000 23*05500 653500
44100
44100
44100
44100
&&lfifi
3751500
TOTAL
DP. COST
INCLUDING NET ANN.UM. CUMULATIVE
NET REVENUE, REGULATED TOTAL INCREASE NET INCREASE
»/TQN ROI FOR NET (DECREASE) (DECREASE)
POWER SALES IN COST OF IN COST OF
WASTE
SOLIDS
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
O-O
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
O-O
0.0
0.0
0.0
0.0
OnO
0.0
0.0
0.0
0.0
d.G
COMPANY, REVENUE,
»/YEAR S/YEAR
10320500
10146000
9971600
9797100
"QUi^^fcflO
9448200
9273700
9099200
8924700
8750300
7640900
7466400
7292000
7117500
£>94t3QCQ
6029900
5855500
5681000
55C6500
5337100
4074300
3899800
3725400
3550900
1^TiiL(\{\
3201900
3027500
2*53000
2*78500
?tf)&lflG
193110500
0
0
0
0
O
0
0
0
0
Q
0
0
0
0
0
0
0
0
0
fj
0
0
0
0
n
0
0
0
0
p
0
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CPAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SILFUR REMOVED .
DISCOUNTED AT 10.0% TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE! IN UNIT OPERATING COST
DOLLARS PER TON OF CtAL BURNEO
MILLS PER K1LQWATT-HCUR
CEKTS PER MILLION BTt MEAT IHPUT
DOLLARS PER TUN Of SULFUR RENOVED
EQUIVALENT TO
DISCOUNTED
8.08
3.03
33.66
295.50
78*39900
PROCESS COST OVER
7.63
2.86
31 .77
278.85
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
POWER,
*
10320500
10146000
9971600
9797100
9672600
9448200
9273700
9099200
8924700
R75Q3QQ
7640900
7466400
7292000
7117500
^'S 4:3000
6029900
5855500
5681000
5506500
5337100
4074300
3899800
3725400
3550900
3^7ChfcOQ
3201900
3027500
2853000
2678500
7.SQ41PQ ,
193/110,500
8.08
3.03
33.66
295.50
78439,900
POWER UNIT
7.63
2.86
31.77
278.85
POWER,
i
10320500
20466500
30438100
40235200
£<)£*» 7 ft on
S9306000
68579700
77678900
86603600
*J*»3S3^QQ
102994800
110461200
117753200
124670700
131B131OO
137843600
143699100
149380100
154886600
1 ^Q21fl^O.O
164293000
168192800
171918200
175469100
1 7 Afl4|<>l}Qf)
182047400
185074900
187927900
190606400
19311O5OO
-------
Table B-16. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 5.0% S in fuel;
90% SO-i removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, effluent hold tanks, agitators,
pumps, and exhaust gas ducts to inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps)
Utilities (instrument air generatioh and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
528,000
1,162,000
3,203,000
4,745,000
556,000
854,000
4,876,000
67,000
3.0
6.7
18.3
27.2
3.2
4.9
27.9
0.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
638,000
831 ,000
17,460,000
1,571,000
1,921,000
873,000
1,746,000
23,571,000
1,886,000
1,886,000
27,343,000
3.6
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheat to I75°F by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
187
-------
Table B-17. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 5.0% S in fuel;
90% SOi removal; on-site solids disposal)
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
250.0 M tons
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 17,460,000
Analyses
Subtotal conversion costs
Subtotal direct costs
28,360 man-hr
492,800 M Ib
282,700 M gal
81,400,000 kWh
4.00/ton
8.00/man-hr
0.70/M Ib
0.08/M gal
0.010/kWh
1,000,000
1,000,000
226,900
345,000
22,600
814,000
1,396,800
49,200
2,854,500
3,854,500
Percent of
total annual
operating cost
11.73
11.73
2.66
4.05
0.27
9.55
16.39
0.58
33.50
45.23
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 6.49
4,074,100
570,900
22,700
4,667,700
8,522,200
Cents/million
Mills/kWh Btu heat input
2.43 27.05
47.80
6.70
0.27
54.77
100.00
Dollars/ton
sulfur removed
166.25
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $27,343,000; subtotal direct investment, $17,460,000.
Working capital, $656,500.
Investment and operating cost for disposal of fly ash excluded.
188
-------
Table B-18
LIMESTONE SLURRY FRLCESS, soc
. New COAL FIRED POWER UNIT, s.ot s IN FUEL, 90* soz REMOVAL, REGULATED co. ECONOMICS
FIXED INVESTMENT: * 27343000
YEARS ANNUAL
AFTER OPERA-
POWER TIUN,
UNIT KH-HR/
START KM
1 7COO
2 7000
3 7000
4 7000
5. 700P
6
7
S
9
11
12
13
14
16
17
18
19
-20.
21
22
23
24
_25
26
27
28
29
_3fl
TOT
PRO
7000
7000
7000
7000
2CQ.Q
5COO
SuOO
5000
5COO
5.60.0.
3500
3500
3500
3500
3.5.CO.
1500
1500
1500
1500
J5QQ
1500
1500
1500
1500
127500
LIFETIME
CESS COST
PLhER UNIT PUWCR UNIT
HEAT FUEL
REOUIkfcHENT, CONSUMPTION
KILLICN BTU TONS COAL
/YEAR /YEAR
315COOCO
315COOCG
3151,0000
31500000
3.15.CUQO.U _
31500000
315000CO
315CCOOO
3151'UOOO
3-151-QIitll
225COOOO
22500000
2250GOCO
225CCOCO
15750000
1575000C
15750000
15750000
15.25.ilC.CO.
t7500CC
6750CCO
t75COOO
675COCO
fc.2iQO.Cil
6750000
675COCU
675COOO
6750000
1312500
1312500
1312500
1312500
1312500
1312500
1312500
1312500
i 31 2son
937500
937500
937500
93750C
(56200
656200
656200
656200
2&1230
281200
281203
281200
2E12ilO_
281200
281200
231200
281200
jni^no
TOTAL
SULFUR BY-PRODUCT OP. COST
REKUVED RATE, INCLUDING
BY EQUIVALENT NET REVENUE, REGULATED TOTAL
POLLUTION TONS/YEAR t/TON ROI FOR NET
, CONTROL POWER SALES
PROCESS, WASTE WASTE COMPANY, REVENUE,
TONS/YEAR SCLIDS SOLIDS */YEAR J/YEAR
•51300 294300
51300 294300
5130C 2943CO
51300 294300
_ 513QQ P943DQ
51300
51330
51300
51300
5J.3.Q.O.
36600
36500
36600
36600
34,6 QQ-
25600
25600
25600
25600
716.00
11300
11000
11000
11000
iiaao
11900
11300
11000
11330
unnn
573750000 23905500 93430P
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF CCAL BURNED
MILLS PEK KILOWATT-HLUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REHOVED
DISCOUNTED AT 10.0% TO INITIAL YEAR, DOLLARS
294300
294300
294300
294300
210200
210200
210200
210200
147100
147100
147100
147100
1471QO
63100
63100
63100
631CO
Minn
63100
63100
63100
63100
5360500
COST
0.0
0.0
0.0
0.0
p-fl
0.
0.
0.
0.
__O-
0.
0.
0.
0.
0
0
0
0
n
0
0
0
0
n
0.0
0.0
0.0
0.0
Q.n
0.
0.
0.
0.
0.
0.
0.
0.
0
0
0
0
n
0
0
0
0
o
11366700
11177200
10987600
10798000
lO'-oa'-oo
10418900
10229300
10039700
9850200
96.60600
8411000
8221500
8031900
7842300
26,5220.0.
6627900
6438300
6248700
6059200
4459500
4269900
4060400
3890800
31C12D.O
3511700
3322100
3132500
2943000
212604300
6.89 0.
3.33 0.
37.06 0.
227.63 0.
86426600
0 O 0 O C
0
0
0
0
n
0
0
0
0
Q
0
0
0
0
Q _
0
0
0
0
_fl
0
0
0
0
Q
0
0
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
11366700
11177200
10987600
10798000
-10600500
10418900
10229300
10039700
9850200
96^0600
8411000
8221500
8031900
7842300
6627900
6436300
6248700
6059200
4459500
4269900
4080400
3890600
33Q12QQ.,_
3511700
3322100
3132500
2943000
2253AQQ
213604,300
8.89
3.33
37.06
227.63
66,426,800
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
i
11366700
22543900
33531500
443295CO
_ -54S3a0.00
65356900
75586200
85625900
95476100
10513.6700
113547700
121769200
129801100
137643400
14.5.2S61QO
151924000
156362300
164611000
170670200
-_i2&5asaao
180999300
165269200
189349600
193240400
., 1969.41600
200453300
203775400
206907900
209850900
. .21260.4.300
LEVEL1ZEO INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF POWER UNIT
DOLLARS PER TON OF CCAL BURNED 6.40 0.0 8.40
MILLS PER K1LOWATT-HCUR 3.15 0.0 3.15
CENTS PER MILLION BTC HEAT INPUT 35.01 0.0 35.01
DOLLARS PER TON OF SULFUR REMOVED 214.99 0.0 214.99
-------
Table B-19. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(1,000-MW existing coal-fired power unit, 3.5% S in fuel;
90% SO 2 removal; on-site solids disposal)
Limestone receiving and storage.(hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Sulfur dioxide scrubbers and inlet ducts (4 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between outlet of supplemental fan and
stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in
to existing duct and inlet to supplemental fan)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from th6 power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
745,000
1,621,000
8,530,000
559,000
2,611,000
5,440,000
448,000
3:4
7.4
38.9
2.5
11.9
24.8
2.0
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
948,000
1,045,000
21,947,000
1,975,000
2,634,000
1,536,000
2,195,000
30,287,000
2,423,000
2,423,000
35,133,000
4.3
4.8
100.0
9.0
12.0
7.0
10.0
138.0
11.0
11.0
160.0 .
aBasls:
Stack gas rclical (o 175 I by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant locution represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
190
-------
Table B-20. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics2
(1,000-MW existing coal-fired power unit, 3.5% S in fuel;
90% S02 removal; on-site solids disposal)
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
350.0 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6}
Process water
Electricity
Maintenance
Labor and material, .07 x 21,947,000
Analyses
Subtotal conversion costs
Subtotal direct costs
35,040man-hr
8,130,000 gal
500,600 M gal
128,570,000 kWh
4.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.009/kWh
1,400,000
1,400,000
280,300
1,869,900
40,1)00
1,157,100
1,536,300
74,400
4,958,000
6,358,000
Percent of
total annual
operating cost
10.98
10.98
2.20
14.67
0.31
9.07
12.05
0.58
38.88
49.86
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
5,375,300
aBasis:
Remaining life of power plant, 25 yr.
Coal burned, 2,625,000 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 lir/yr.
Midwest plant locution, 1975 operating costs.
Total capital investment, $35,1 33,000; subtotal direct investment, $21,947,000.
Working capital, $1,073,900.
Investment and operating cost for disposal of fly ash excluded.
42.14
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 4.86
991,600
28,000
6,394,900
12,752,900
Cents/million
Mills/kWh Btu heat input
1.82 20.24
7.78
0.22
50.14
100.00
Dollars/ton
sulfur removed
177.72
191
-------
Table B-21
LIMESTONE SLURRY PROCESS, 1000 HW. EXISTING COAL FIRED POKER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: » 35133000
YEARS ANNUAL
AFTER OPERA-
POWER T10N,
UNIT KW-HR/
START KW
1
2
3
•5
6 7CCO
7 700C
« 7000
9 7000
ID 70GQ
11 5GCO
12 5000
13 5COO
14 5COO
_1S 5QQC .
16 3500
17 3500
18 3500
19 3500
SULFUR
REMOVED
POWER UNIT PuhER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TQNS COAL PROCESS,
/YEAR /YFAR TONS/YEAR
630COOOO 2625000 71800
630COOOO 2625000 71B 00
63000DOO 2625000 71BOO
630COOOO 2625000 71800
630uOOCQ 2 f: 2 SQ Q Q 7 2 & D T
4501COOO 1675000 51300
45000000 U750GO 51300
4500COI--0 lt75COC 5130C
45000000 1675COO 5130C
450CQCDQ _. ItTSOQO SHOO
315COOCO 1312500 35900
315COOOO 13125CO 35900
315000CO 1312500 35900
315COOGO 1312500 35900
2Q 3SQQ 315DGDQD 131J5GD 3VJOO
21 1500
ZZ 15CO
23 1500
24 15CO
2"j 15DD
26 1500
27 1500
28 1500
29 1500
30 J5QO
TOT 92500
LIFETIME
PROCESS CDST
LEVELIIED
135000C3 562500 15400
135COOOO 562503 15400
135COOOO 562500 15400
13500000 562500 15400
issfjOQCQ *»fc,25fin 154 on
13500010 562500 15400
13500000 562500 15400
135GOOOU 562500 15400
135COOCO 5625CO 15400
.135&QQQU 5625.00 15&QQ
BY-PRODUCT
RATE.
EQUIVALENT
TPNS/YEAR
WASTE
SOLIDS
412000
412000
412000
412000
612000
294300
294300
294300
294300
29.4100
206000
206000
206000
206000
2060QQ
88300
88300
88300
88300
HH^^Q
88300
88300
88300
88300
Jlfi^Q ft
TOTAL
OP. COST
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE, REGULATED TOTAL INCREASE NET INCREASE
WTON ROI FOR NET {DECREASE) (DECREASE)
POWER SALES IN COST OF IN COST OF
HASTE COMPANY, REVENUE, POWER, . POWER.
SOLIDS */YEAR S/YEAR $ »
0.0
0.0
0.0
c.o
0-0
0.0
0.0
0.0
c.o
Q.O
c.o
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
o. o
0.0
0.0
0.0
0.0
o.o
B325COOOC 34637500 949000 5444500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER MLQW ATT -h LAIR
CENTS PER MILLION BTC HEAT IMPUT
DOLLARS PfcR TON OF SLLFUR REMOVED
DISCOUNTED AT 10.0% TO INITIAL YEA*. DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING CUST
DOLLARS PER TUN OF CCAL BURNED
KILLS PER KILOMATT-HCUR
CENTS PER MILLION BTL' HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
DISCOUNTED
16406800
16114500
15822200
15529900
0
0
0
0
16406800
16114500
15822200
15529900
!S217ftOn o i«i?37«.on
13074700
12782300
1249COOO
12197700
.1 1 QP SAO n
10165000
9872700
9580400
9288100
B9«>i8nn
6652700
6360400
6068100
5775800
"k& It 1*»fl ft
5191200
4198900
4606600
4314300
&n?2finn
242836600
7.00 0.
2.63 0.
29.17 0.
255.89 0.
111985400
PROCESS COST OVER LIFE
6.55 0.
2.45 0.
27.27 C.
239.29 0.
0
0
0
0
0
0
0
0
0
n
0
0
0
0
o
0
0
0
0
n
0
0
0
0
0
0
OF
0
0
0
0
13074700
12782300
1249COOO
12197700
1 19,05400
10165000
9872700
9580400
9288100
89.9580(1
6652703
6360400
6068100
5775800
^£.JI "%** OQ
5191200
4898900
4606600
4314300
4.Q22J1DQ
242^36^00
7.00
2.63
29. 17
255.89
111985,400
POWER UNIT
6.55
2.45
27.27
239.29
16406800
32521300
48343500
63873400
7911 1000
92185700
104968000
117458000
129655700
141S&1 1OO
151726100
161598800
171179200
180467300
1A94&31QO
196115800
202476200
208544300
214320100
2 1991^600
224994800
229893700
234500300
238814600
26216.36. $00
-------
Table B-22. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(1,000-MW new coal-fired power unit, 3.5% S in fuel;
90% SO 2 removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, effluent hold tanks, agitators,
pumps, and exhaust gas ducts to inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process
steam, water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment $
Percent of subtotal
direct investment
643,000
1,445,000
4,756,000
7,616,000
942,000
1,294,000
5,865,000
89,000
2.6
5.9
19.3
30.9
3.8
5.2
23.8
0.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
8T4,000
1,173,000
24,637,000
1,971,000
2,464,000
1,232,000
2,217,000
32,521,000
2,602,000
2,602,000
37,725,000
3.3
4.8
1DO.O
8.0
10.0
5.0
9.0
132.0
10.6
10.6
153.2
"Basis:
Stack gas reheat to 175 F by indirect steam reheat.
Disposal pond located I mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
193
-------
Table B-23. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics2
(1,000-MWnew coal-fired power unit, 3.5% S in fuel;
90% S0t removal; on-site solids disposal)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
338.4 M tons
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .07 x 24,637,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
35,040 man-hr
952,700 M Ib
484,000 M gal
152,220,000 kWh
4.00/ton
8.00/man-hr
0.60/M Ib
0.08/M gal
0.009/kWh
1,353,600
1,353,600
280,300
571,600
38,700
1,370,000
1,724,600
74,400
4,059,600
5,413,200
5,621,000
Percent of
total annual
operating cost
Remaining life of powet plant, 30 yr.
Coal burned, 2,537.500 tons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $37,725,000; subtotal direct investment, $24,637,000.
Working capital, $919,900.
Investment and operating cost for disposal of fly ash excluded.
11.40
11.40
2.36
4.81
0.33
11.54
14^52
0.63
34.19
45.59
47.33
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 4.68
811,900
28,000
6,460,900
11374,100
Cents/million
Mills/kWh Btu heat input
1.70 19.50
6.84
0.24
54.41
100.00
Dollars/ton
sulfur removed
171.17
194
-------
Table B-24
LIMESTONE SLURRY PROCESS, 1COO HW. NEW CLAL FIRED POWER UNIT, 3.5* S IN FUEL, 90*
FIXED INVESTMENT: $ 37725000
SULFUR BY-PRODUCT
REMOVED RATE,
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7COO
2 7000
3 7000
* 7000
S 7QQQ
6 7000
7 7000
8 7000
9 7000
1 0 ?CQQ
11 5000
12 5000
13 5000
14 5COO
1 5 5000
16 3500
17 3500
18 3500
19 3500
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS,
/YEAR /YEAR TONS/YEAR
6C9000CO 2537500 69*00
60900000 2537500 69*00
60900000 2537500 69*00
60900000 2537500 69*00
609Ct}Q@0 2S3750Q 6SkQO
609000CO 2537500 69*00
6090COCO 2537500 69*00
609000CO 2537500 69*00
609COOOO 2537500 69*00
6Q9CQQCQ 2 53 2SGQ 69fc QQ
4350COCO 1M2500 49600
4350COOC 1612500 49600
43500000 1C12500 4960C
4350000C 1812500 49600
435.LCQCD 1U12^QP 49600
30450000 1268700 34700
30450000 126fc7CO 34730
3045GOCO 1268700 34700
30450000 1268700 34700
?o 3500 3C4caoon i?fcH7on ?&7on
21 1500
22 1500
23 1500
24 1500
3*. l*Ofl
26 1500
27 1500
28 1500
29 1500
*n tunp
TOT 127500
LIFETIME
PROCESS COST
LEVEL1ZEO
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
J705QOC/Q _. S.fcVJ'Jn . 14«00 ,,
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
13050000 5^» 370^ 149QQ
11092500OO 4621800C 1264500
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
398300
398300
398300
398300
39 A^nn
3983CO
398300
398300
398300
?QA ^no
284500
284500
284500
284500
?8A*OO
199100
199100
199100
199100
19.9100 .^
85300
85300
85300
85300
• cinn
•5300
•5300
•5900
•5300
gCfAA
7254000
SU2 REMOVAL, REGULATED CO. ECONOMICS
TOTAL
OP. COST
INCLUDING NET ANNUAL
NET REVENUE, REGULATED
S/TON
WASTE
SPLID5
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
fl.O
0.0
0.0
0.0
0.0
fl_ A
ROI FOR
POWER
COMPANY,
(/YEAR
15798800
15537200
15275700
*5C14100
1475.7f.nO
14491000
14229400
13967900
13706300
1444*800
11657400
11395800
11134300
10872700
1061 1?QQ
9155000
8893400
8631900
8370300
ft i Ofiiton
6123000
5861*00
5599900
5338300
Cfl7tf«JlflA
4815200
4553600
4292100
4030500
17AQOOO
294508400
TOTAL
NET
SALES
REVENUE,
S/YEAR
0
0
0
0
o
0
0
0
0
n
0
0
0
0
o
0
0
0
0
o
0
0
0
0
o
0
0
0
0
o
0
CUMULATIVE
INCREASE NET INCREASE
(DECREASE)
IN COST DF
POWER,
*
15798800
15537200
15275700
1501*100
1 £ 75,?|»QQ
14491000
14229400
13967900
13706300
13444800
11657400
11395800
11134300
108727.00
-10.6112011 .
9155000
8B934CO
8631900
8370300
BlOMftOQ
6123000
58*1400
5599900
5338300
Cf)7JLA Aft
4*15200
4553600
4292100
4030500
^7&QOOf)
294508AOO
(DECREASE)
IN COST OF
POWER,
S
15798800
31336000
46611700
61625800
Itt ^TBfcOO
90869400
105098800
119066700
132773000
14fc?178OO
157875200
169271000
180405300
191278000
20 JIB. 8.92OO
211044200
219937600
228569500
236939800
2&% Q4B&QO
251171600
257033000
262632900
267971200
271£)fc0>QQQ
277863200
282416800
286708900
290739400
24450840.0
AVERAGE INCREASE (DECREASE I IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER HILLIUN BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
DISCOUNTED
6.37
2.31
26.55
232.91
120015500
0.0
0.0
0.0
0.0
0
PROCESS COST OVER LIFE OF
6.03
2.19
25.1*
220.62
0.0
0.0
0.0
0.0
6.37
2.31
26.55
232.91
120015/500
POWER UNIT
6.03
2.19
25.14
220.62
-------
Table B-25. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
80% SO j removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, effluent hold tanks,
agitators, pumps, and exhaust gas ducts to inlet
of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal pumps,
pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
419,000
899,000
3,203,000
4,351,000
556,000
797,000
3,827,000
67,000
2.7
5.8
20.7
28.1
3.6
5.1
24.7
0.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
638,000
738,000
15,495,000
1 ,395,000
1,704,000
775,000
1,550,000
20,919,000
1,674,000
1,674,000
24,267,000
4.1
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheat to 175 F by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal ot" fly ash excluded.
Conslruction labor shortages with accompanying overtime pay incentive not considered.
196
-------
Table B-26. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(5QO-MW new coal-fired power unit, 3.5% S in fuel;
80% SOi removal; on-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
175.0 M tons
4.00/ton 700,000
700,000
Percent of
total annual
operating cost
9.48
9.48
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 15,495,000
Analyses
Subtotal conversion costs
Subtotal direct costs
26,280 man-hr
492,800 M Ib
248,600 M gal
67,380,000 kWh
8.00/man-hr
0.70/M Ib
0.08/gal
0.010/kWh
210,200
345,000
19,900
673,800
1,239,600
45,600
2,534,100
3,234,100
2.85
4.68
0.27
9.13
16.80
0.62
34.35
43.83
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
3,616,100
"Basis:
Remaining life of power plant, 30 yr.
Coal burned. 1,312,500Qtons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175° !•'.
Power unit nn-slrcain lime, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $24,267,000; subtotal direct investment, $15,495,000.
Working capital, $546,800.
Investment and operating cost for disposal of tly ash excluded.
49.02
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 5.62
506,800
21,000
4,143,900
7,378,000
Cents/million
Mills/kWh Btu heat input
2.1 1 23.42
6.87
0.28
56.17
100.00
Dollars/ton
sulfur removed
231.36
197
-------
Table B-27
LIHfSTC'.t SLURRY PROCESS, SOU HK. NEW COAL FIRED POkER UNIT, 3.54 S IN FUEL. 80% SD2 REMOVAL, REGULATED CD. ECONOMICS
FIXED INVESTMENT: » 24269000
TGTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING
YEARS ANNUAL
AFTER GPERA-
POMER TION,
UNIT Kfc-HR/
START Kk
1
2
3
4
^
6
7
8
9
in
11
1 2
13
14
IS
16
17
18
19
?n
21
22
23
24
f\
26
27
23
29
30
TliT
1000
7000
7000
7CUO
70QO
7000
7COO
700C
7COO
7000
5000
5000
5000
5000
_5Qna_
3500
3500
3500
3500
^•sno
1500
1500
1500
15CO
15PP
1500
150C
1500
1500
t SOI"!
127500
LIFETIME
PROCESS COST
LEVELUED
PCWER UNIT POWER UNIT 6Y EQUIVALENT
HEAT FUEL POLLUTION TCNS/YEAR
RECUI&EMEKT, CUNSUHPTIDN, CONTROL
MILLION BTU TONS COAL PROCESS, WASTE
/YE*R /YEAR TONS/YEAR SOLIDS
315COOOO 1312500 31900
315COOOC 1312500 31900
315COOOO 1312500 31900
31500000 1312500 31900
ajsnpooo i>i?5Sn ._ 319(41
315COCCO 1312500 31900
315COOCO 13125CO 31900
3150COCO 1312500 3190C
315000CO 1312500 31900
^l^O^Orfi 1 - 1 7*100 ^ 1 9 Qfl
22500000 937500 228 00
225COOCO 937500 22800
225000CC 937500 22300
225000CO 937500 22800
p?sonnon SITSPQ 228 QO.
15750000 o5620U 15900
15750000 b562CO 15900
15750300 t562CO 15900
1575COCC 656200 15900
i575f)Ofto fi"5f»?GC i *»i nn
6750000 261200 6800
675COCO 261200 6800
675COOO 2E1200 6900
6750000 261200 6800
(>7SQOG3 ?fll?pn frUOO
6750000 281200 MOC
67500CO 2S1200 6800
67500CO 281200 6800
6750000 281200 6800
675DQCO Zfll'f-f feSUD
5737500CO 23905500 580500
AVERAGE INCREASE (DECREASE! IN UNIT OPERATING
DOLLARS PER TON OF CLAL BURNED
KILLS PER KILOWATT-HfUR
CENTS PER MILLION BTL HEAT 1HPUT
DOLLARS PER TON DF SULFUR RtMOVtO
DISCOUNTED AT 10. Ct TO INITIAL YEAR, COLLARS
183100
183100
183100
183100
1E31OO_
183100
163100
183100
183100
1831 QQ
130600
130800
130600
130800
^t3Q8QQ
91600
91600
91600
91600
Q 1 fcQO
39200
39200
39200
39200
^o^nfl
3*200
3*200
3*200
3*200
^•2OQ
3335000
COST
INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF CCAL BURNED
MILLS PEK KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON DF SULFUR REHOVEO
NET REVENUE, REGULATED TOTAL
i/TON ROI FOR MET
POWER SALES
WASTE COMPANY, REVENUE,
SOLIDS
0.0
0.0
0.0
0.0
o.n
0.0
0.0
0.0
0.0
n.o
0.0
0.0
0.0
0.0
P,,Q
0.0
0.0
c.o
0.0
0 t)
0.0
0.0
c.o
0.0
O O
0.0
0.0
0.0
0.0
O O
DISCOUNTED
»/YEAR I/YEAR
9902900
9734600
9566300
9398000
o? 2980Q
9061500
8893200
8724900
8556700
ft^fi A&ftfi
7334300
7166100
6997800
6829500
fklvJ'i 1 ?fifl
5792100
5623800
5455500
5287300
5ll<»000
3921000
3752700
3584500
3416200
^2&1QOf)
3079700
2911400
2743100
2574800
^^A|L|LA A
185360800
7.75
2.91
32.31
319.31
75259300
PROCESS COST OVER
7.32
2.74
30.48
301.04
0
0
0
0
0
0
0
0
0
r>
0
0
0
0
a
0
0
0
0
o
0
0
0
0
a
0
0
0
0
o
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
INCREASE NET INCREASE
{DECREASE! (DECREASE)
IN COST OF IN COST OF
POWER, POWER.
f
9902900
9734600
9566300
9398000
9.229aDO_ .
9061500
8893200
8724900
8556700
fi^ft &6 DO
7334300
7166100
6997800
6329500
&6.6JL2QQ
5792100
5623800
5455500
5287300
•ill Qnnn
3921000
3752700
3584500
3416200
37679QP
3079700
2911400
2743100
2574800
2±(ltltlt\{\
185,360,800
7.75
2.91
32.31
319.31
75,259,300
POWER UNIT
7.32
2.74
30.48
301.04
S
9902900
19637500
29203800
38601800
47K31 6Q/O
56893100
65786300
74511200
83067900
-------
Table B-28. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% SO?, removal; off-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Paniculate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, effluent hold tanks,
agitators, pumps, and exhaust gas ducts to inlet
of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (off-site disposal facilities
including feed tank, agitator, pumps, thickener,
drum filters, and cake loading silo)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
419,000
899,000
3,203,000
4,745,000
556,000
854,000
1,106,000
67,000
3.2
6.9
24.4
36.2
4.2
6.5
8.4
0.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
638,000
624,000
13,111,000
1,180,000
1,442,000
656,000
1,311,000
17,700,000
1,416,000
1,416,000
20,532,000
4.9
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
"Basis:
Stack gas reheat to 175°F by indirect steam reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
199
-------
Table B-29. Limestone Slurry Process
Tout Average Annual Operating Costs-Regulated Utility Economics3
(5'00-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; off-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Li mestone 1 75.0 M tons
Subtotal raw material
Conversion costs
Operating labor and
supervision 26,280 man-hr
Utilities
Steam 492,800 M Ib
Process water 224,300 M gal
Electricity 78,920,000 kWh
Maintenance
Labor and materials, .08 x 1 3,1 1 1 ,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost excluding trucking
and off -site disposal of calcium solids
Annual cost for trucking and off -site
disposal of calcium solids at $4/ton
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 6.38
4.00/ton 700,000
700,000
8.00/man-hr 210,200
0.70/M Ib 345,000
0.08/Mgal 17,900
0.010/kWh 789,200
1,048,900
45,600
2,456.800
3,156,800
3,059,300
491,400
21,000
3,571,700
6,728,500
1,648,000
8,376,500
Cents/million
Mills/kWh Btu heat input
2.39 26.59
Percent of
total annual
operating cost
8.36
8.36
2.51
4.12
0.21
9.42
12.53
0.54
29.33
37.69
36.52
5.87
0.25
42.64
80.33
19.67
100.00
Dollars/ton
sulfur removed
233.46
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
Slack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $20,532,000; subtotal direct investment, $ 13,111,000.
Solids disposed, 206,000 tons/yr calcium solids including hydrate water.
206.000 tons/yr associated water
412,000 tons/yr
Working capital, $534,300.
Investment and operating cost for disposal of fly ash excluded.
200
-------
Table B-30
LIMESTONE SLURRY PROCESS, 500 M*. NEW CQ«L FIRED POWER UNIT, 3.5* S IN FUEL, 90t 502 REMOVAL.
FIXED INVESTMENT:
20532000
YEARS ANNUAL
AFTER GPERA-
POWER T1DN,
UNIT KK-HR/
START KM
1 7COO
2 7000
3 7COO
4 7COC
t 7QGC.
6 7000
7 7COO
8 70CO
9 7000
IQ ZGQQ
11 5000
12 5000
13 5COO
14 5COO
16 3500
17 3500
18 3500
19 3500
PChfcR UMT
HEAT
REOUIREMFNT,
M1LLICK ETU
/YEAR
315COOCO
315000CO
315COOCO
315COOCO
315COijDCl
3150COCO
3150COCO
31500000
3150COCO
315LQODO.
225COOCO
2250COOO
225COOCC
225COOCO
157500CO
1575000C
15750000
15750000
PuhER UNIT
FUEL
CCNSUNPTION,
TliNS CCAL
/YEAR
1312500
13125^0
1312500
1312503
i "^i ps^n
U12500
1312500
1312500
13125CO
1^1 ?^ m
937500
937500
937500
9375CO
656203
656200
656200
6562CC
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
35900
35900
35900
35900
359. ao.
35900
35900
35900
35900
''WOO
25600
25600
25600
2560C
17900
17900
17900
17900
_2Q 3.5-O.a 15.250.fl££ 6562CC Iliac.
21 1500
22 1500
23 1500
24 1500
_2S 15il0_
26 1500
27 1500
28 1500
29 1500
_3.0 1500.
6750000
67500CO
675COOO
6750000
6.2scoaa
6750000
6750000
6750000
6750000
_62SOQLO_.
2cl200
2612CO
281203
281200
ytkl f f\f\
281200
2B1200
281200
281200
281200
7700
770C
7700
7700
IZflQ.
7700
7700
7700
7700
7700
TOT 127500 S7375000C 23905500 653500
LIFETIME AVERAGE INCREASE (DECREASE! IN UNIT OPERA
DOLLARS PER TON OF COAL BURNED
HILLS PER KILOHATT-HtUR
CENTS PER MILLION BTlt HEAT INPUT
DOLLARS PER TON OF SU.FUR REHOVfcO
PROCESS COST DISCOUNTED AT 10.Ot TO INITIAL YEAR. DOLLARS
LEVELIZEO INCREASE (DECREASEI IN UNIT OPERATING COS
DOLLARS PER TUN OF CCAL 6URNEO
KILLS PER KILGWATT-HCUR
CENTS PER MILLION BTL HEAT INPUT
DOLLARS PER TON OF SULFUR REKOVED
BY-PHDDUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
412000
412000
412000
412000
4120.00
412000
412000
412000
412000
412000.
294300
294300
294300
294300
PQ43QQ
206GOO
206000
206000
206000
2C6.aao
88300
88300
88300
88300
H&3CLQ
88300
88300
88300
88300
&83QQ
7504500
ING COST
.ARS
' EQUIVALENT TO
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON
WASTE
SOLIDS
0.0
0.0
0.0
0.0
Q*Q
0.0
0.0
0.0
c.o
£1^.0
0.0
0.0
0.0
0.0
Q-.Q
0.0
.0.0
0.0
0.0
a~a
0.0
0.0
0.0
0.0
o.n
0.0
0.0
0.0
0.0
O-ft
DISCOUNTED
ROI FDR
POWER
TOTAL
NET
SALES
COMPANY. REVENUE,
»/YEAR J/YEAR
10512500
10370100
10227700
10065400
9.943.QQQ
9800700
9658300
9516000
9373600
Q2.il 3OQ
7735000
7592600
745C300
7307900
71 ASbOfl
5976300
5834000
5691600
5549300
56.0690.0—
37B5100
3642700
3500300
3358000
•»y 1 SffrGQ
3073300
2930900
2788600
2646200
>SO^QOO
195872700
8.19
3.07
34.14
299.73
80426200
PROCESS COST OVER
7.82
2.93
32.57
285.91
•o
0
0
0
c
0
0
0
0
o
0
0
0
0
n
0
0
0
0
o
0
0
0
0
f)
0
0
0
0
a
0
c.o
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
(DECREASE!
IN COST GF
POWER,
S
10512500
10370100
10227700
10085400
3943000- _
9800700
9658300
9516000
9373600
9234300
7735000
7592600
7450300
7307900
716S6QQ
5976300
5834000
5691600
5549300
5.&0&9D.O.
3785100
3642700
3500300
3358000
^91 •h&DQ
3073900
2930900
2788600
2646200
?«03«na
195.872,700
8.19
3.07
34.14
299.73
80426200
POWER UNIT
7.82
2.93
32.57
285.91
(DECREASE!
IN COST OF
POWER,
*
10512500
20882600
31110300
41195700
SI 138700
60939400
70597700
80113700
89487300
OR "71 ft Aftft
106453600
114046200
121496500
128804400
— iis9iaoao
141946300
147780300
153471900
159021200
L6.442.BJ.aO
168213200
171855900
175356200
178714200
111 lQ?9fiOO
185003100
187934000
190722600
193368800
... 19SH7?7DO
-------
Table B-31. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW existing coal-fired power unit, 3.5% S in fuel;
90% S02 removal; on-site solids disposal; paniculate
scrubber required for fly ash removal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, and all ductwork between outlet
of supplemental fan and particulate scrubber)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, effluent hold tanks,
agitators, pumps, and exhaust gas ducts between
S02 scrubber and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between
tie-in to existing duct and inlet of supplemental
fan)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
482,000
1,000,000
3,977,000
5,260,000
323,000
1,738,000
3,611,000
335,000
2.6
5.4
21.7
28.7
1.8
9.5
19.7
1.8
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
740,000
873,000
18,339,000
1,834,000
2,384,000
1,284,000
2,017,000
25,858,000
2,069,000
2,069,000
29,996,000
4.0
4.8
100.0
10.0
13.0
7.0
11.0
141.0
11.3
11.3
163.6
"Basis:
Stiick gas reheat to 175°I-' by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
202
-------
Table B-32. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing coal-fired power unit, 3.5% S in fuel; 90% S02 removal;
on-site solids disposal; paniculate scrubber required for fly ash removal}
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
178.9 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 18,339,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
26,280 man-hr
4,160,000 gal
255,900 M gal
83,930,000 kWh
4.00/ton
8.00/man-hr
715,600
715,600
210,200
4,589,400
aBasis:
Remaining life of power plant, 25 yr.
Coal burned, l,341,700otons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $29,996,000; subtotal direct investment, $18,339,000.
Working capital, $712,200.
Investment and operating cost for disposal of fly ash excluded.
Percent of
total annual
operating cost
7.48
7.48
2.20
0.23/gal
0.08/M gal
0.010/kWh
956,800
20,500
839,300
1,467,100
45,600
3,539,500
4,255,100
9.99
0.21
8.77
15.32
0.48
36.97
44.45
47.94
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 7.14
707,900
21,000
5,318,300
9,573,400
Cents/million
Mills/kWh Btu heat input
2.74 29.73
7.39
0.22
55.55
100.00
Dollars/ton
sulfur removed
261.00
203
-------
to
o
Table B-33
LIMESTONE SLURRY PROCESS, 500 M*. EXISTING COAL FIRED POWER UNIT, 3.5* s IN FUEL, 90* $02 REMOVAL, FLYASH REMOVED BY PART. SCRUB.
FIXED INVESTMENT: * 29996000
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWER T10N, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS,
START KW /YEAR /YEAR TONS/YEAR
1
2
3
S , _
6 7000 322COOOO 1341700 36700
7 7000 32200000 1341700 36700
8 7000 32200000 1341700 36700
9 7000 3Z2COOOO 1341700 36700
ID 7QQQ ^^PflOQflQ 1^61700 ^fcTOfi
11 5000 23000000 958300 26200
12 5COO 23000000 958300 26200
13 5COO 230000CO 958300 26200
14 5000 2300COOO 958300 26200
is snnn '100QQQQ «?MDO ?*,?nn
16 3500 16100000 670800 18300
17 3500 16100000 670800 18300
18 3500 16100000 670800 18300
19 3500 161COOOO 670800 18300
^Q 35CO l^lQOfiijQ fr70*QQ ^fi^on
21 1500 6900000 267500 7900
22 15CO 690000G 287500 7900
23 1500 6900000 267500 7900
24 15CO 69COOOC 287500 7900
25 1500 1*^00000 ?&75DQ 1T9.QQ
26 1500 69GOOOO 287500 7900
27 1500 69COOOO 287500 7900
28 1500 6900000 287500 7900
29 1500 6900000 237500 7900
«3iQ 1 5QQ 69GQQQO ^K "^** ^ 0 *" ^ "
TOT 92500 42S5000GO 17729000 485000
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
210600
210600
210600
210600
2\ OfeflQ
150400
150400
150400
150400
1 «; o^.OD
105300
105300
105300
105300
\d^'*nn
45100
45100
45100
45100
&51QQ
45100
45100
45100
45100
t<;inn
2782500
TOTAL
QP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON
WASTE
SOLIDS
0.0
0.0
0.0
0.0
n.o
0.0
0.0
0.0
0.0
n.o
0.0
0.0
0.0
0.0
o.n
0.0
0.0
0.0
0.0
n.o
0.0
0.0
0.0
0.0
n.o
ROI FOR
POWER
COMPANY,
S/YEAR
12693000
12443400
12193900
11944300
ltf.O4.7np
10238100
9988500
9739000
94B9400
Q^^QAnn
8043300
7793700
7544200
7294600
VCA.^ i on
5422900
5173300
4923800
4674200
6424. 7QQ
4175100
3925500
3676000
3426400
^1 74*^00
190383800
TOTAL
NET
SALES
REVENUE,
S/YEAR
0
0
0
0
n
0
0
0
0
n
0
0
0
0
0
0
0
0
0
0
0
0
0
0
I)
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
12693000
12443400
12193900
11944300
11&Q6IQO
10238100
9988500
9739000
9489400
Qj>"V>HQfl
8043300
7793700
7544200
7294600
704511)0
5422900
5173300
4923800
4674200
4474700
4175100
3925500
3676000
3426400
^1 TfkQfin
1903838CO
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
- S
12693000
25136400
37330300
49274600
Afi Qtfk Q ^ ft fl
71207400
81195900
90934900
100424300
i n*tti\A,&. i nn
117707400
125501100
133045300
140339900
i £*v^tft •» Ann
152807900
157981200
1*2905000
167579200
1 T^OQ^Qnft
176179000
180104500
183760500
1*7206900
i *KJ n i B no
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10. C* TO INITIAL VEAt, DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SU.FUR REMOVED
EQUIVALENT
TO DISCOUNTED
10.74
4.12
44.74
392.54
87143300
0.0
0.0
c.o
0.0
0
PROCESS COST OVER LIFE OF
9.96
3.82
41.52
364 .46
0.0
0.0
0.0
0.0
10.74
4.12
44.74
392.54
87143300
POWER UNIT
9.96
3.82
41.52
364.46
-------
Table B-34. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(20Q-MWnew oil-fired power unit, 2.5% Sin fuel;
90% 502 removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Sulfur dioxide scrubbers and ducts (2 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between common feed plenum and inlet of
fan)
Stack gas reheat (2 direct oil-fired reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal pumps,
pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
157,000
300,000
1,827,000
110,000
256,000
1,550,000
126,000
3.1
6.0
36.4
2.2
5.1
30.9
2.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
451,000
239,000
5,016,000
552,000
652,000
351,000
552,000
7,123,000
570,000
570,000
8,263,000
9.0
4.8
100.0
11.0
13.0
7.0
11.0
142.0
11.4
11.4
164.8
aBasis:
Stack gas reheat to 175°F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
205
-------
Table B-35. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW new oil-fired power unit, 2.5% S in fuel;
90% S0t removal; on-site solids disposal)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .09 x 5,016,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
38.2 M tons
17,520 man-hr
900,000 gal
76,700 M gal
20,160,000 kWh
4.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.019/kWh
152,800
152,800
140,200
207,000
6,100
383,000
451,400
15,600
1,203,300
1,356,100
Percent of
total annual
operating cost
Remaining life of power plant, 30 yr.
Oil burned, 2,058,200 bbl/yr, 9,200 Btu/kWh.
Stack gas reheat to 175 °F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $8,263,000; subtotal direct investment, $5,016,000.
Working capital, $225,600.
5.38
5.38
4.93
7.28
0.21
13.48
15.89
0.5S
42.34
47.72
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 1 .38
1,231,200
240,700
14,000
1,485,900
2,842,000
Cents/million
Mills/kWh Btu heat input
2.03 22.07
43.32
8.47
0.49
52.28
100.00
Dollars/ton
sulfur removed
362.96
206
-------
Table B-36
LIHE5TCNE SLURRY PKCCESS, 200 M». NEx HIL FIRED POWER UNIT, 2.5* S IN FUEL, 90% S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: * 8263000
TOTAL
SULFUR BY-PRODUCT OP. CCST
REMOVED RATE,
YEARS ANNUAL POWER UNIT FUKER UMT BY EQUIVALENT
AFTEF OPEkA- HEtT FUEL POLLUTION TCNS/YtAR
PCWER TICN, RLCUIREHEM , CONSUMPTION, CONTROL
UMT K»-HR/ IMLLIIN ETU BARRELS OIL PROCESS, WASTE
START KW /YEAR /YEAR TONS/YEAR SOLIDS
1 7COO 12P6.0CC 2C5E23C 7300
2 70CO 12PfcOOCj 2056200 7800
3 "730C 12KcCCOC 2C5B200 7800
4 7000 1281-0000 2058200 7800
5 200.0 IZStOQCiu £f!5n?Cr) L ., 7100 ....
6 700C 12(JfcCOCC 2C58200 7800
7 7000 12?eOOCu 2058200 7800
a 7000 1288COCO 2C58200 7800
9 7000 128600CC 2056200 7800
11 5000 92COOUr, 1470100 5600
12 5000 92CGOIC' 1470100 5600
13 5000 92COOCO 1470100 5600
14 5000 92COCCC 1470100 5600
_15 5COQ S2CQOCH . 1470,1 QQ. , _ .... ...SfttQO. ,.
16 350C 644QOCC 1029100 3900
17 3500 64400CO 102910C 3900
18 3500 64400CO 1029100 3900
19 3500 6440000 1C29100 3900
_2.Q 3.5QQ h44000D 1C291Q9 3.9QD ....
21 15CO 27600CO 441000 1700
22 1500 2760000 441000 1700
23 1500 2760000 441000 1700
24 1500 2760000 441000 1700
_25 1500 276QODC- . 44innc i7nn
26 1500 2760000 441000 1700
27 1500 2760CCO 441000 1700
28 1500 27tOOOO 441000 1700
29 1500 27600CO 441000 1700
•^n 15QC 276LQGQ .441000 1700
44900
44900
44900
44900
...44900.
44900
44900
44900
44900
449.0Q
32100
32100
32100
32100
22500
22500
2250D
22500
9600
9600
9600
9600
9600
9600
9600
9600
96QH
TOT 127500 2346COOOO 37488000 142500 818000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT -HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10. C* TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST ECUIVALENT TO
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTL HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE, REGULATED TOTAL INCREASE NET INCREASE
I/TON ROI FOR NET (DECREASE) {DECREASE!
POWER SALES IN COST OF IN COST OF
WASTE COMPANY, REVENUE, POWER, POWER,
SOLIDS */YEAR S/YEAR S i
0.0
0.0
0.0
0.0
. . .. o-n
0.0
0.0
0.0
c.o
0-0
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Q.O
0.0
0.0
0.0
0.0
n.,n
DISCOUNTED
3701600
3644300
35B7000
3529800
1477SOO
3415200
3357900
3300600
3243300
2748300
2691000
2633700
2576400
25J910Q-
2161300
2104000
2046700
1989400
1434400
1377200
1319900
1262600
1148000
1090700
1093500
976200
64607000
1.86 0.
2.73 0.
29.67 0.
488.47 0.
28281000
PROCESS COST OVER LIFE
1.75 0.
2.58 0.
28.01 0.
462.11 0.
0
0
0
0
0
0
0
0
0
o
0
0
0
0
n
0
0
0
0
p
0
0
0
0
n
3 O O O O
0
0
0
0
0
0
OF
0
0
0
0
3701600
3644300
3587000
3529800
3422SDD
3415200
3357900
3300600
3243300
2748300
2691000
2633700
2576400
2161300
2104000
2046700
1989400
1434400
1377200
1319900
1262600
1205300
1146000
1090700
1033500
976200
_S1A2QQ. .
69,607,000
1.86
2.73
29.67
488.47
28^81000
POWER UNIT
1.75
2.58
28.01
462.11
3701600
7345900
10932900
14462700
L3S1352D.O
21350400
24708300
28008900
31252200
37186600
39877600
42511300
45087700
49768100
51872100
53918800
55908200
59274700
60651900
61971800
63234400
65587700
66678400
67711900
68688100
tatfilQQO
to
o
-------
Table B-37. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 1.0% S in fuel;
90% SOi removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
154,000
296,000
4,240,000
252,000
582,000
1,530,000
185,000
1.9
3.6
51.3
3.1
7.0
18.5
2.2
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
628,000
393,000
8,260,000
743,000
909,000
413,000
826,000
11,151,000
892,000
892,000
12,935,000
7.6
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheut to 175 °F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
208
-------
Table 8-38. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics2
(500-MW new oil-fired power unit, 1.0% Sin fuel;
90% SOi removal; on-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
37.4 M tons
4.00/ton 149,600
149,600
Percent of
total annual
operating cost
3.16
3.16
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 8,260,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
17,520 man-hr
2,200,000 gal
163,300 M gal
47,290,000 kWh
8.00/man-hr
140,200
1,927,300
aBa$is:
Remaining life of power plant, 30 yr.
Oil burned, 5,033,600 tjbl/yr. 9.000 Btu/kWh.
Stack gas reheat to 175 V.
. Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 197S operating costs.
Total capital investment, $ 12,935,000; subtotal direct investment, $8,260,000.
Working capital, $386,200.
2.96
0.23/gal
0.08/M gal
0.018/kWh
506,000
13,100
851,200
660,800
30,000
2,201,300
2,350,900
10.69
0.28
18.00
13.96
0.63
46.52
49.68
40.72
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 0.94
440,300
14,000
2,381,600
4,732,500
Cents/million
Mills/kWh Btu heat input
1.35 15.02
9.30
0.30
50.32
100.00
Dollars/ton
sulfur removed
618.63
209
-------
to
Table B-39
LIMESTONE SLURRY PROCESS. SCO MM. NEW, OIL FIRED POWER UNIT. l.Ot 5 IN FUEL, 90t 502 REMOVAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 12935000
SULFUR
REMOVED
YEARS ANNUAL POhER UNIT PCWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
PUkcR TION, ReCUUEHENT, CONSUMPTION, CONTROL
UNIT Kk-HR/ MILLION BTU BARRELS OIL PROCESS,
START KH /YEAR /YEAR TONS/YEAR
1
2
3
a
&
7
11
13
_Li
lo
17
It
1"
^l
22
23
24
27
it
29
-3.J1
70CO
7COC
7TOO
7COO
2CCQ.
7LOO
7000
7CCC
7C.CO
5 COO
5COC
50CC
5COO
iUCQ
3^00
3500
3500
3JCO
150C
1500
liOC
1500
1500
1500
1500
15CO
. ISQIi
31500000
315COOOO
315CUOCO
31500000
315COOOC
315COOCO
315COOOO
315000PC
21SCQO.CO
22500000
225GOCOO
22500000
22500000
725CQOCC
15750COC
15750COO
15750000
157500GC
6750000
6750000
675: 000
6750000
__ ...67.&QQQC.
6750000
6750000
675 COOO
6750000
5C33600
5033600
5C33600
51336CO
5033600
5033600
5033600
5C33600
35*5400
3595400
3595*00
35954UO
2516800
2516BGJ
2516800
251680C
1078600
1078600
1078600
1076600
1078600
1078600
107*600
1076600
7700
7700
7700
7700
7700
7700
7700
7700
27.0.0..
5500
5500
5500
5500
«!50.n
3800
3800
3800
3900
1600
1600
1600
1600
16 QQ
1600
1600
1600
1600
TOT 127500 57375COCO 516fc3000 139500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT DPEfcAl
DOLLARS PER BARREL OF GIL SUKNED
MILLS PER KILLWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF StLFUR REMOVED
PRDCcSS CLST DISCOUNTED AT 10.Ot TC INITIAL YEAR, 001
LfcVtLIZtD INCREASE (DECREASE) IN UNIT OPERATING C05
DOLLARS PER BARREL UF OIL BU1NEG
MILLS PER KI LOW ATT-HCUR
CENTS PER MILLION BTL. HEAT IVPUT
DOLLARS PER TON OF SULFUR REMOVED
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
43900
43900
43900
43900
to39.r>0
43900
, 43900
43900
43900
41900
31400
31400
31400
31400
M4QQ
22000
22000
22000
22000
220nn
9400
9400
9400
9400
9&Q& HO ft
35123700
40663700
46114100
51474800
«»?7innn _5-6.24.5.an.O
4485200
4395500
4305800
4216100
61231000
65626500
69932300
74148400
4.1264QQ n &i.?&6Dri 7fi?7&fino
3494500
3404800
3315200
3225500
31^400
2270300
2180600
2090900
2001200
1 A| * Cft A
1*21*00
1732200
1642500
1552BOO
i&AYin A.
113517500
1.24
1.78
19.79
813.75
46404800
0
0
0
0
0
0
0
0
n
.0
0
0
0
0
0.0
0.0
0.0
0.0
0
PROCESS COST OVER LIFE DF
1.18
1.69
18.80
770.84
c.o
0.0
0.0
0.0
3494500
3404800
3315200
3225500
at a t a QO
2270300
2180600
2090900
2001200
I Ql 1 SO.Q
1821800
1732200
1642500
1552800
i A A^t QQ
113,517,500
1.24
1.78
19.79
813.75
46404,800
POWER UNIT
1. 18
1.69
18.80
770.84
81769300
85174100
88489300
91714800
^tfrflfiAfrOO
97120900
99301500
101392400
103393600
1 O*» 1O ^ 1 AO
107126900
106859100
110501600
112054400
1 1 3S1 7SQO
-------
Table U-40. Limestone Slurry Process
Summary of Estimated Fixed Investment4
(50U-M W new oil-fired power unit, 2.5% S in fuel;
90% SO-i removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal pumps,
pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
279,000
572,000
4,240,000
252,000
582,000
2,672,000
185,000
2.8
5.8
42.9
2.5
5.9
27.0
1.9
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
628,000
471,000
9,881,000
889,000
1,087,000
494,000
988,000
13,339,000
1,067,000
1,067,000
15,473,000
6.4
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
"Basis:
Stack gas reheat to 175°!'' by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
211
-------
Table B-4T. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
(500-MW new oil-fired power unit, 2.5% S in fuel;
90% S0t removal; on-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
93.4 M tons 4.00/ton 373,600
373,600
Percent of
total annual
operating cost
6.71
6.71
Conversion
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 9,881,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
19,600 man-hr
2,200,000 gal
187,500 M gal
49,280,000 kWh
8.00/man-hr
0.23/gal
0.08/M gal
0.018/kWh
156,800
506,000
15,000
887,000
790,500
36,000
2,391,300
2,764,900
aBasis:
Remaining life of power plant, 30 yr.
Oil burned, 5,033,600 bbl/yi, 9,000 Btu/kWh
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $15,473,000; subtotal direct investment, $9,881,000.
Working capital, $460,300.
2.82
9.09
0.27
15.94
14.21
0.6S
42.98
49.69
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 1.11
2,305,500
478,300
15,700
2,799,500
5,564,400
Cents/million
M i I Is/kWh Btu heat i nput
. 1.59 17.66
41.43
8.60
0.28
50.31
100.00
Dollars/ton
sulfur removed
290.87
212
-------
Table B-42
LIMESTONE SLURRY PROCESS, 500 H*. NEW, OIL FIRED POKER UNIT, 2.5* S IN FUEL, 90* 502 REHOVAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT:
15473000
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KW-HR/ MILLION BTU BARRELS DIL PROCESS.
START KW /YEAR /YEAR TONS/YEAR
1
2
3
4
s
6
7
8
9
in
11
12
13
14
is
16
17
18
19
21
22
23
24
_2i_
26
27
28
29
3Q
7000
7000
7000
7000
7000
7000
7000
7000
7000
7nnn
5000
5000
5000
5000
•;nnn
3500
3500
3500
3500
1500
1500
1500
1500
1500
1500
1500
1500
1500
31500000
315COOCO
31500000
31500000
_3isoa0aa_-
31500000
31500000
31500000
315COOOO
115CQQOQ
22500000
22500000
22500000
22500000
_225DQDHO_
15750000
1575COOO
15750000
15750000
6750000
6750000
6750000
6750000
.6750000
6750000
675000C
6750000
6750000
5033600
5C33600
5033600
5033600
5033600
5033600
5033600
5033600,
3595400
3595400
3595400
3595400
2516800
2516800
2516800
2516800
1078600
1078600
1078600
1078600
lG7ftf,OQ
1078600
1078600
1078600
1078600
i07af.no
19100
19100
19100
19100
l«l DC.
19100
19100
19100
19100
ISIOD-
13700
13700
13700
13700
9600
9600
9600
9600
4100
4100
4100
4100
4100
4100
4100
4100
41 DO
TOT 127500 573750000 91683000
LIFETIME AVERAGE INCREASE {DECREASEI
348500
UNIT OPERA
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TOM Of SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0% TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COS
DOLLARS PER BARREL OF OIL BURNED
HILLS PER KUDWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
109900
109900
109900
109900
IMaOQ-
109900
109900
109900
109900
inoQno
78500
78500
78500
78500
7SSOO
54900
54900
54900
549CO
_5420fl-
23500
23500
23500
23500
?*«;rm
23SOO
23500
23500
23SOO
zasnn
2001000
INC COST
.ARS
i EQUIVALENT
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
$/TON
WASTE
SOLIDS
0.0
0.0
0.0
o.b
0^0
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
n.o
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
o.o
TO DISCOUNTED
ROI FOR
POWER
COMPANY,
S/VEAR
7174100
7066800
6959500
6852200
f 7*490.0
6637700
6530400
6423100
6315800
fcpnusnn
5294400
5187100
5079800
4972600
486S3QO
4129100
4021800
3914500
3807200
V^99«»nn
2691700
2584400
2477100
2369800
_226^5J}Q _
2155200
2047900
1940700
1833400
i7?«.ioo
133973500
1.46
2.10
23.35
384.43
54743900
TOTAL
NET
SALES
REVENUE,
t/YEAR
0
0
0
0
n
0
0
0
c
o
0
0
0
0
n
0
0
0
0
0
0
0
0
0
n
0
0
0
0
ft
0
0.0
0.0
0.0
0.0
0
PROCESS COST OVER LIFE OF
1.39
2.00
22.17
365.45
0.0
0.0
0.0
0.0
NET ANNUAL
CUMULATIVE
INCREASE' NET INCREASE
(DECREASE)
IN COST OF
POWER,
*
7174100
7066800
69S9500
6852200
*,744<)no
6637700
6530400
6423100
6315800
6?a85OO
5294400
5187100
5079800
4972600
4865100
4129100
4021800
3914500
3807200
^6<»9900
2691700
2584400
2477100
2369800
^?fc?SOO
2155200
2047900
1940700
1833400
1 77*100
133,973,500
1.46
2.10
23.35
384.43
54,743,900
POWER UNIT
1.39
2.00
22.17
365.45
(DECREASEI
IN COST OF
POWER,
S
7174100
14240900
21200400
28052600
•46797 snn
41435200
47965600
54388700
60704500
<.&4i innn
72207400
77394500
82474300
87446900
q?4t??nn
96441300
100463100
104377600
108184800
11 in*47nn
114576400
117160800
119637900
122007700
i?4?7Q?nn
126425400
128473300
130414000
132247400
1^3«7?^na
N>
-------
Table B-43. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 4.0% S in fuel;
90% S0
-------
Table 8-44. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
(500-MW new oil-fired power unit, 4.0% S in fuel;
90% SO?, removal; on-site solids disposal)
Annual quantity
Unit cost, $
149.4 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 11,162,000
Analyses
Subtotal conversion costs
Subtotal direct costs
21,680 man-hr
2,200,000 gal
211,700 M gal
51,270,000 kWh
4.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.018/kWh
Total annual
cost, $
597,600
597,600
173,400
506,000
16,900
922,900
893,000
39,600
2,551,800
3,149,400
Percent of
total annual
operating cost
9.51
9.51
2.76
8.06
0.27
14.69
14.22
0.63
40.63
50.14
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 1.25
2,604,700
510,400
17,300
3,132,400
6,281,800
Cents/million
Mills/kWh Btu heat input
1.79 19.94
41.45
8.13
0.28
49.86
100.00
Dollars/ton
sulfur removed
205.15
aBasis:
Remaining life of power plant, 30 yr.
Oil burned, 5,033,600 bbl/yr, 9,000 Btu/kWh.
Stack gas reheat to 175° F.
Power.unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $17,481,000; subtotal direct investment, $11,162,000.
Working capital, $529,500.
215
-------
to
Table B-45
LIMESTONE SLURRY PROCESS, 500 UK. NEti. OIL FIRED POKER UNIT, 4.0* S IN FUEL, 90* S02 REHOVAL, RECULATED CD. ECONOMICS
FIXED INVESTMENT: s 17481000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KH-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 1000
6 7000
7 7COC
8 7000
9 7000
i Q 2UQO-
11 5000
12 5000
13 5000
14 5000
^ ^ SAQQ.
16 3500
17 3500
18 3500
19 3500
?Q 3.5jQQ
21 1500
22 1500
23 1500
24 1500
31 IfPO
26 1500
27 1500
28 1500
29 1500
30 ^ SQQ
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CCNTROL
MILLION BTU BARRELS OIL PROCESS,
/YEAR /YEAR TONS/YEAR
31500000 5033600 30600
31500000 5033600 30600
31500000 5033600 30600
315000CO 5033600 30600
31SDOQOO 5C3*ftna in*, on
31500000 5033600 30600
315000CO 5C33600 30600
31500000 5033600 30600
31500000 5C33600 30600
3l5flQQOQ *>01^4.Qf* ^Q&ftQ
22500000 3595400 21900
22500000 3595400 21900
22500000 3595400 21900
225000CO 3595400 21900
?2*i 00000 H5*?S^Ofl 2 19 Qfl
15750000 2516800 15300
15750000 2516800 15300
15750000 2516800 15300
15750000 2516890 15300
I *5 TiQfiofi ?<^i jkflnn m^i on
6750000 1078600 6600
6750000 1C78600 6600
6750000 1078600 6600
6750000 1078600 6600
<>7«iQOOP )n7fifcan iff,nn
6750000 1078600 6600
675COOO 1078600 6600
6750000 1078600 6600
6750000 1078600 6600
I*35CQOQ»_ i £} *tn Ann &&on
573750000 91683000 558000
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
HASTE
SOLIDS
175800
175800
175800
175800
125&QO
175800
175800
175800
175800
i 75gnn
125600
125600
125600
125600
t 2*V#*ftfl
87900
87900
87900
67900
RTQnfl
37700
37700
37700
37700
^77Qf)
37700
37700
37700
37700
ITFTfifl
3202500
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
*/TON
HASTE
SOLIDS
0.0
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
fl-0
0.0
0.0
0.0
0.0
0-n
0.0
0.0
0.0
0.0
P-P
0.0
0.0
0.0
0.0
(j-n
0.0
0.0
0.0
0.0
O.IJ
ROI FOR
POUER
COMPANY ,
S/YEAR
8100300
7979100
7857900
7736700
T**15**QO
7494300
7373100
7251900
7130700
7f}OQ5flO
5977600
5856400
5735200
5614000
OQO
108886600
113427000
117846200
122144200
i ?t\i2 1 ono
129359800
132277400
135073800
137749000
140*301000
142735800
145047400
147237800
149307000
i s i ?•» "in no
-------
Table B-46. Limestone Slurry Process
Summary of Estimated Fixed Investment9
(500-MW existing oil-fired power unit, 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between outlet of supplemental fans and
stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between
tie-in to existing duct and inlet to supplemental
fan)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water_return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
Investment. $
Percent of subtotal
direct investment
320,000
636,000
4.636.000
270,000
1.533,000
2,463,000
311,000
2.8
5.6
40.6
2.4
13.4
21.6
2.7
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
694,000
543,000
11,406,000
1,141,000
1,483,000
798,000
1,255,000
16,083,000
1,287,000
1,287,000
18,657,000
6.1
4.8
100.0
10.0
13.0
7.0
11.0
141.0
11.3
11.3
163.6
"Basis:
Stack gas reheat to 175 °F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Construction labor shortages with accompanying overtime pay incentive not considered.
217
-------
Table B-47. Limestone Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing oil-fired power unit. 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
95.4 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 11,406,000
Analyses
Subtotal conversion costs
Subtotal direct costs
19,600 man-hr
3,040,000 gal
191,500Mgal
53,320,000 kWh
4.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.018/kWh
381,600
381,600
156,800
699,200
15,300
959,800
912,500
36.000
2,779,600
3,161,200
Percent of
total annual
operating cost
5.79
5.79
2.38
10.61
0.23
14.58
13.85
0.55
42.20
47.99
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
2,854,500
aBasis:
Remaining life of power plant, 25 yr.
Oil burned, 5,145,400 bbl/yr, 9,200 Btu/kWh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $18,657,000; subtotal direct investment, $11,406,000.
Working capital, $524,500.
43.33
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 1 .28
555,900
15,700
3,426,100
6,587,300
Cents/million
Mills/kWh Btu heat input
1.88 20.46
8.44
0.24
52.01
100.00
Dollars/ton
sulfur removed
336.77
218
-------
Table
LIMESTONE SLURRY PRCCESS, 5CC! Mh. EXISTING OIL FIRED PUWfcR UNIT, 2.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CD. ECONOMICS
FIXED INVESTMENT:
18657000
SULFUR
REMOVED
YEARS ANNUAL PuViER UNIT PGWtR UNIT bY
AFTER CPtfA- HEAT FUEL POLLUTION
PU«ER TION, REQUIREMENT, CONSUMPTION, CCNTR3L
UMT K«-hR/ MLLICA PTU BARRELS OIL PROCESS,
START K* /YEAR /YEAR TCKS/YEAR
1
2
3
c
6 700C 322CUOCO 51*5*00 1*600
7 7CCC 322COCCG 51*5*00 1960C
i 7CCC 322COOOO 51*5*00 19600
9 7000 322COOCO 51*5*00 19600
ia 7cno 3p?nccfii( 51*5*00 i9spo
11 5CCC iSOCOOCO 3675300 1*000
12 5COC 230COOGO 3675300 1*300
13 5000 i30COOOO 3675300 1*300
1* 5000 23000000 36753CO 1*300
1 c 5 C Q 0 ^30r3DCQ 3 & 2 S 3 Q 0 • 1 4 Q 0 G
16 3500 16100000 2572700 9800
17 350C 161CCOOO 2572700 9900
18 3500 161COOOO 2572700 9800
19 3500 16100000 2572700 980C
?0 ^00 ifeicqoOO P57?7QD _: _. _ aaoc
21 15GO 690COOO 1102600 *20C
22 1500 69COOOO 1102600 4200
23 1500 69000GO 1102600 4200
2* 1500 6900000 1102600 *200
?«; ispo - 69COPPO .110.260.0 ., i?on . _
26 15CO 6900000 1102600 *200
27 1500 69GOOLO 11026CO *200
28 1500 6900000 1102600 4200
29 1500 69000CO 1102600 *200
10 , I'JQG .690001)0 11C26.G0 . .<«?QO .....
TOT 92500 42550CODO 67993000 259000
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
1123CO
112300
112300
112300
1123. OO.
60200
60200
B0200
80200
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
I/TON
HASTE
SOLIDS
0.0
0.0
C.O
0.0
0,0
0.0
0.0
0.0
0.0
ROI FOR
POWER
TOTAL
NET
SALES
COMPANY, REVENUE,
t/YEAR
8527700
8372*00
6217200
8062000
790^700
682*200
6669000
6513700
6358500
ar,?ori • fi.G /.pn^^nn
56100
56100
56100
56100
SftlpO
24100
24100
24100
24100
24 1QQ
2*100
2*100
24100
24100
261 QO
1484COO
C.O
0.0
0.0
0.0
n.Q
0.0
0.0
0.0
0.0
O-O
0.0
0.0
0.0
0.0
n.o
5326200
5170900
5015700
4860500
67Q52QQ
3516900
3361700
3206400
3C51200
2ftQ&nnn
2740700
2585500
2430300
2275100
tl , ?H«»np
12*916800
S/YEAR
0
0
0
0
fi
0
0
0
0
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
8527700
8372*00
8217200
8062000
"7 jQfc 2QQ
682*200
6669000
6513700
6358500
(DECREASE)
IN COST OF
POWER,
»
8527700
16900100
25117300
33179300
£ i OB Anon
47910200
54579200
61092900
67451400
n fe?n-*-»nn 7^*,5*-»nn
0
0
0
0
n
0
0
0
0
o
0
0
0
0
n
0
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER PARREL OF. OIL BURNED
MILLS PER K1LGHATT-HCUR
CENTS PER MILLION 8TL HEAT INPUT
DOLLARS PER TUN OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0% TO INITIAL YEAR, DOLLARS
LEVELIZEU INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL DF OIL BURNED
KP.IS PER KILDWATT-HCUR
*° CENTS Ptk KILHUN BTL HEAT INPUT
\0 DOLLARS PER TUN OF bcL?'Jp BFHOVED
EQUIVALENT
TO DISCOUNTED
1.87
2.74
29.83
490.03
58358800
PROCESS COST OVER
1.74
2.56
27.81
457.00
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
5326200
5170900
5015700
*660500
6 70*? GO
3516900
3361700
3206400
3051200
?8«4POO
2740700
2585500
2430300
2275100
?1 198.00
126,916,800
1.87
2.74
29.83
490.03
58,358x800
POWER UNIT
1.74
2.56
27.81
457.00
78980900
84151800
89167500
94028000
*J8"7^1 ^ OO
102250100
105611800
108818200
111869400
1 147*. stnn
117506100
120091600
122521900
124797000
124916ftQn
-------
Table B-49. Limestone Slurry Process
Summary of Estimated Fixed Investment3
(1,000-MW new oil-fired power unit, 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Limestone receiving and storage (hoppers, feeders,
conveyors, elevators, and bins)
Feed preparation (feeders, crushers, elevators,
ball mills, tanks, and pumps)
Sulfur dioxide scrubbers and inlet ducts (4 scrubbers
including common feed plenum, mist eliminators,
effluent hold tanks, agitators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including feed tank, agitator, slurry disposal
pumps, pond, liner, and pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
428,000
919,000
6,836,000
435,000
881,000
3,998,000
246,000
2.8
6.0
44.8
2.8
5.8
26.2
1.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
801,000
727,000
15,271,000
1,222,000
1,527,000
764,000
1,374,000
20,158.000
1,613,000
1,613,000
23,384,000
5.2
4.8
100.0
8.0
10.0
5.0
9.0
132.0
10.6
10.6
153.2
"Basis:
Stack gas reheat to 175°F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
220
-------
Table B-50. Limestone Slurry Process
Total Average Annual Operating Costs Regulated Utility Economics3
(1,000-MW new oil-fired power unit. 2.5% S in fuel;
90% SO} removal; on-site solids disposal)
Direct Costs
Delivered raw material
Limestone
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
180.5 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .07 x 15,271,000
Analyses
Subtotal conversion costs
Subtotal direct costs
25,840 man-hr
4,250,000 gal
362,500 M gal
95,300,000 kWh
4.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.017/kWh
722,000
722,000
206,700
977,500
29,000
1,620,100
1,069,000
64,800
3,967,100
4,689,100
Percent of
total annual
operating cost
8.03
8.03
2.30
10.88
0.32
18.03
11.89
0.72
44.14
52.17
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
3,484,200
a Basis:
Remaining life of power plant, 30 yr.
Oil burned, 9,731,500 bbl/yr, 8,700 Btu/kWh
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $23,384,000; subtotal direct investment, $15,271,000.
Working capital, $782,500.
38.77
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 0.92
793,400
20,700
4,298,300
8,987,400
Cents/million
Mills/kWh Btu heat input
1.28 14.76
8.83
0.23
47.83
100.00
Dollars/ton
sulfur removed
242.97
221
-------
K>
(O
Table B-51
LIMESTONE SLURRY PRCCE5S. 1CCC KM. hEM OIL FIRED POWER UNIT, 2.5* S IN FUEL, 90% S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: »
2 33-84000
YEARS ANNUAL
AFTER OPERA-
POWER TICN,
UNIT KW-HR/
START KW
1
2
3
4
7000
7000
7COO
700C
POWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION
M1LLICN FTU BARRELS OIL
/YEAR
6G9C&QCO
6C9COOCO
609COOGO
fc09CCOOO
/YEAR
97il50C
97315 JC
9731500
9731500
5. 7QDQ fcO<3f,r,O"G 97315Cn
6
7
8
•j
in
11
12
13
14
1 S
16
17
13
19
?0
21
22
23
24
?•=,
26
27
28
29
30
TCT
7COO
700C
7CCC
7COC
T'^'CO
5CCO
5COO
5COO
5000
iCCQ
3500
3500
3500
3500
3iQ£t
1500
1500
1500
1500
15.0.0.
1500
1500
15CO
1500
X5.0G.
127500
LIFETIME
6C9COOCO
609COOOO
6C9CCGCC
6C9COOCO
b.C.9C "'2. or<
435GOOCC,
435CCOOG
435CCO'.C
435COOOC
A^ c P n :jC.c
3C4E03CO
3C4500CO
304f.C3C(J
304500CO
304S ,QOIi
13050COO
13050000
13050UCO
1305000C
9731500
97315CO
9731500
9731500
• SJ3 15.CQ
6S51100
695110C.
e95 iioc
6S511GU
t^SJ-'l^Il
4£6580C
Ue 658 00
4S65800
4t65800
£t h f\ *i P H O
2C853CO
2085300
2&t5300
2CB5300
SULFUR BY-PRODUCT
REMOVED RATE,
&Y EQUIVALENT
POLLUTION TONS/YEAR
, CONTROL
PROCESS, WASTE
TONS/YEAR SOLIDS
37000
37000
37000
37300
1730"
3703Q
37300
37D3C
3730C
171 an __
26400
26400
2640C
264 DC
Pfi<* flf'
1650C
16500
1H500
IfcSOO
_. liiifl
7900
7900
7930
7900
21 2400
212400
212400
212400
J •J p£ QQ
212400
212400
212400
212400
? 124. G.Q
151700
I517C3
1517CO
151703
1^1 "7fiO
106203
1C6200
1C6200
106200
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED TOTAL
*/TON R01 FOR NET
POWER SALES
WASTE COHPANY, REVENUE,
SOLIDS
0
0
0
0
0
0
0
0
c
p
0
0
c
0
Q
0
0
0
0
. 0
.0
.0
.0
• fl
.0
.0
.0
.0
.n
.0
.0
.0
.0 '
Q
.0
.0
.0
.0
S/YEAR »/YEAR
11420200
1125bCOO
11095900
10933800
10771*00
' 10609500
10447400
10285200
10123100
££ f^Q i>2pn fi.n sfitsflnn o
45500
45500
45500
45500
13Q5GJIiG prn^-^nn 7ann tssnn
13050000
13050JCO
1305COCO
1305COCO
^^05^ ^Olx
1U925000U
AVERAGE INCREASE
DOLLARS
20853&0
20&5300
2C85300
2C85300
2 C & 5. 3 C.u
177252500
(DECREASE
PER BARREL
7900
7900.
7900
7900
29 CKi
673500
1 IN UNIT OPERATING
DF OIL BURS ED
45500
45SOO
45500
45500
. .fcSSQQ
3668500
COST
0
0
0
0
fl
0
0
0
0
0
.0
.0
.0
.0
,0
.0
.0
.0
.0
- fl
MILLS PEP KILGWATT-HLUR
CENTS PER MILLION
PROCESS COST
LEVELUEfc
DGLLAX5
DISCOUNTED AT
PER TuN UF
8TL HEAT INPUT
SLLFUR REKOVED
13.0% TO INITIAL YEAR, DOLLARS
INCREASE (OFCREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS
PER BARREL
MILL i PER K ILOhATT
CEi.TS PER MILLION
UOLLhRS
PER TUN OF
OF OIL BU*«ED
-riCUR
BTb HEAT INPUT
JLLFUR fcEHUVED
DISCOUNTED
41546CO
3992400
3830300
3668100
1SD6QCQ
3343900
3181700
3019600
2857500
26S5.3UQ
212367000
1.20
1 .67
. 19.15
315.32
87171700
PROCESS COST OVER
1 .14
1 .59
18.26
30C.70
•3
0
0
0
£
0
0
0
0
._ _ a .
0
c.o
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
&.0
0.0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE!
IN COST OF IN COST OF
POWER, POWER,
S
1 1420200
11258000
11095900
10933800
1 0 32J.& 00
1C6C9500
10447400
102R5200
1C123100
996C90Q
8393600
8231500
8069300
7907200
774^1 pr,
6497300
6335200
6173100
•6010900
«;s4aBOO
4154600
3992400
3630300
3668100
35Q6QOQ , , -
3343900
3181700
3019600
2857500
^69.5300
212,367,000
1.20
1.67
19. 15
315.32
87,171,700
POWER UNIT
1. 14
1.59
18.26
300.70
*
11420200
22678200
33774100
44707900
SSfrjf 95QO
66089000
76536400
86821600
96944700
.inA3D.56fl.O
115299200
123530700
131600000
139507200
i A ~f j>e j*3QO
153749600
160084BOO
166257900
172268800
1T&H76QQ
182272200
186264600
190094900
193763000
1 922690QQ
200612900
203794600
206B14200
209671700
21 ?^*S7QQQ
-------
Table B-52. Lime Slurry Process
Summary of Estimated Fixed Investment3
(200-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-site solids disposal)
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
Particulate - sulfur dioxide scrubbers and inlet ducts (2
scrubbers including common feed plenum and pumps)
Sulfur dioxide scrubbers and ducts (2 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (2 indirect steam reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Perc.ent of subtotal
direct investment
440,000
220,000
1,783,000
1,394,000
228,000
338,000
1,947,000
47,000
6.2
3.1
25.0
19.5
3.2
4.7
27.3
0.7
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
396,000
340,000
7,133,000
785,000
927,000
499,000
785,000
10,129,000
810,000
810,000
11,749,000
5.5
4.8
100.0
11.0
13.0
7.0
11.0
142.0
11.4
11.4
164.8
"Basis:
Stack gas reheat to 175 !•' by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
223
-------
Table B-53. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-site solids disposal)
Annual quantity
Unit cost,$
Total annual
cost, $
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .09 x 7,133,000
Analyses
Subtotal conversion costs
Subtotal direct costs
33.2 M tons
14,880 man-hr
200,400 M Ib
99,000 M gal
30,310,000 kWh
26.00/ton
8.00/man-hr
0.80/M Ib
0.08/Mgal
0.011/kWh
863.200
863,200
119,000
160,300
7,900
333,400
642,000
19,200
1,281,800
2,145,000
Percent of
total annual
operating cost
20.73
20.73
2.86
3.85
0.19
8.01
15.41
0.46
30.78
51.51
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned Mills/kWh
Equivalent unit operating cost 7.76 2.97
1 ,750,600
256,400
11,900
2,018,900
4,163,900
Cents/million
Btu heat input
32.33
42.04
6.16
0.29
48.49
100.0
Dollars/ton
sulfur removed
283.84
aUasis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $11,749,000;subtotal direct investment, $7,133,000.
Working capital, $374,700.
Investment and operating cost for disposal of fly ash excluded.
224
-------
Table B-54
LIMf SLURRY PRCCtSS, 2CC HK . NEh COAL FIRED POWEK UNIT, 3.5* S IN FUEL, 90* SD2 REMOVAL, REGULATED CD. ECONOMIC...
FIXED INVESTMENTS
117490QO
SULFUR BY-PRODUCT
REMOVED RATE,
YEARS ANNUAL PLKER I'UT POSER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TICiN, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KH-hR/ HILLIC'v ETU TiJNS COAL PROCESS, WASTE
START KW /Y£*^ /YEAR TONS/YEAR SDLIDS
1 7000 128cOOCC 536700 14700
2 70CO 128t.?00 536700 14700
3 7000 li£i.:u: 536700 14700
4 7COC 12?EOOCO 536700 14700
5 70QC 128*0000 S3*>700 ... ,.14700
6 7000 12°.600Co 536700 14700
7 7COO 12iHivOO 536700 14700
8 7000 IZ^eCOCO 536700 14700
9 7COO 12otC,aCC 5367CO 14700
10 7DOP l?aoOQQO 536.70C 14300
11 5000 92CGCCC 363300 10500
12 5000 92COCOO 383300 10500
13 5000 92COOCO 383300 10500
14 5000 9210000 ^83300 10500
15 5.QDQ 92C''QrQ £ 33QQ 10.5.D.3
16 3500 6440GGJ 268300 7300
17 350C 6440000 268300 7300
18 3500 64400CO 266300 7300
19 3500 64400GO 266300 7300
pn ^*>nn A&^fionn xvR^no i^nn
21 1500 27600CO 115000 3100
22 1500 2760000 115000 3100
23 1500 2760000 115000 3100
24 1500 276COCO 115000 3100
pc 1 5O C 2"2t* uOnQ 1 t *iftflO "% 1 ftft
26 1500 2760000 115000 3100
27 1500 2760000 115000 3100
28 1500 276000C 115000 3100
29 1500 2760000 115000 3100
33 . ..1500 276.QGCQ. . nsr^n VQn
TOT 127500 2346COOCO 9775000 267000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
COLLARS PER TCN OF CCAL BURNED
HILLS PER K1LOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
71400
71400
71400
71400
214OQ
71400
71400
71400
71400
7i&na
51000
51000
51000
51000
5J.OQQ .
35700
35700
35700
35700
^•\"ion
15300
15300
15300
15300
1 *»"^03
15300
15300
15900
15300
tt^oo
1300500
COST
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTli HEAT INPUT
to DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED TOTAL
t/TON ROI FOR NET
POWER SALES
WASTE COMPANY, REVENUE,
SOLIDS S/YEAR WEAR
0.0
0.0
0.0
0.0
e.f)
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
n.n
DISCOUNTED
5386200
53C4700
5223300
5141800
^n&n&nn
4978900
4897500
4816000
4734600
£&5^ inn
3981900
3900400
3619000
3737500
3f>^6? PQ
3112900
3031400
2950000
2868500
27A71QQ
2040000
1958600
1877100
1795700
1 71£2Of)
1632800
1551300
1469900
13*8400
uninnn
10077*300
10.31 0.
3.95 0.
42.96 0.
377.44 C.
41112500
PROCESS COST OVER LIFE
9.77 0.
3.75 0.
40.72 0.
357.19 0.
0
0
0
0
n
0
0
0
0
q
0
0
0
0
n
0
0
0
0
fl
0
0
0
0
n
0
0
0
0
0
0
0
0
0
0
0
OF
0
0
0
0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE! (DECREASE!
IN COST OF IN COST OF
POWER, POWER,
$
5386200
5304700
5223300
5141800
5060400
4976900
4897500
4816000
4734600
4653100
3981900
3900400
3819000
3737500
36*f»l Op
3112900
3031400
2950000
2868500
?iRi i on
2040000
1958600
1877100
1795700
1 T\ &?OO
1632800
1551300
1469900
1388400
iiainnn
100776300
10.31
3.95
42.96
377.44
41112500
POWER UNIT
9.77
3.75
40.72
357.19
*
5386200
10690900
15914200
21056000
7f.l 14.&QO
31095300
35992800
40808*00
45543400
SO 196SQQ
54178400
58078800
61897800
65635300
647914.OO
72404300
75435700
78385700
81254200
fl^n^i *%nn
86081300
8*039900
89917000
91712700
4 Tfc i> i» Q no
95059700
96*11000
98060900
99469300
A 0,07,763.00
-------
Table B-55. Lime Slurry Process
Summary of Estimated Fixed Investment3
- (200-MW existing coal-fired power unit, 3.5% S in fuel;
90% S02 removal; on-site solids disposal]
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and ducts (2
scrubbers including common feed plenum, pumps, and
all ductwork between outlet of supplemental fans
and the scrubbers)
Second stage sulfur dioxide scrubbers and ducts (2 scrubbers
including mist eliminators, pumps, and all ductwork
between scrubbers and stack gas plenum)
Stack gas reheat (2 direct oil-fired reheaters)
Fans (2 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
- pond water return pumps)
'utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
"Basis:
489,000
250,000
2,041,000
1,691,000
129,000
506,000
1,425,000
233,000
6.4
3.3
26.9
22.3
1.7
6.6
18.8
3.1
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
468,000
362,000
7,594,000
911,000
1,139,000
683,000
911,000
11,238,000
899,000
899,000
13,036,000
6.1
4.8
100.0
12.0
15.0
9.0
12.0
148.0
11.8
11.8
171.6
Slack gas reheat to 175 1; by direct oil-fired reheat.
Disposal pond located I mile from power plant.
Midwest plant localion represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage;only pumps are spared.
Remaining life of power unit, 20 yr.
investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
226
-------
Table B-56. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics9
(200-MW existing coal-fired power unit, 3.5% S in fuel;
90% SO* removal; on-site solids disposal)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .09 x 7,594,000
Analyses
Subtotal conversion costs
Subtotal direct costs
34.3 M tons
26.00/ton
14,880 man-hr
1,750,000 gal
102,200 M gal
27,780,000 kWh
8.00/man-hr
0.23/gal
0.08/M gal
0.011/kWh
891,800
891,800
119,000
402,500
8,200
305,600
683,500
19.200
1,538,000
2,429,800
Percent of
total annual.
operating cost
18.49
18.49
2.47
8.35
0.17
6.34
14.17
0.40
31.90
50.39
Indirect Costs
Average capital charges at 1 5.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 8.70
2,072,700
307,600
11,900
2,392,200
4,822,000
Cents/million
Mills/kWh Btu heat input
3.44 36.26
42.98
6.38
0.25
49.61
100.00
Dollars/ton
sulfur removed
318.28
"Basis:
Remaining life of power plant, 20 yr.
Coal burned, 554,200 tons/yr, 9,500 Btu/k\Vh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $13,03(>.000;svibtolal direct Investment, $7,594,000.
Working capital, $421,500.
Investment and operating cost for removal and disposal of tly ash excluded.
227
-------
N)
to
CO
Table B-57
LIME SLURRY PROCESS, 2CC MW . EXISTIi.G CCAL FIRED POWER UNIT, 3.5* S IH FUEL, 9C* SO? REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT:
13036000
YEARS ANNUAL
AFTER OPERA-
PQrfER TICN,
UNIT KW-HR/
START KW
1
2
3
4
6
7
9
11 5COO
12 5000
13 5000
14 50CO
_15 5C.QO.
16 3500
17 3500
18 35CO
19 3500
?q 3_5fl.D_
21 1500
22 1500
23 1500
24 15GO
-25. _ 15J1Q
26 1500
27 1500
28 1500
29 1500
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CUNSUMPTION, CONTRUL
K1LLIC.N faTU TONS CCAL PROCESS,
/YEAR /YEAR TONS/YEAR
•
9500CO^ 3<*580C 1C800
95000CO 395800 10800
95COOCC 395600 10ROO
95CCOOO 3558CC 10800
o 5 r n 3 f j o ^s 9 5 & G n lOPOf)
6650000 £77100 7600
6650903 2771CO 7600
665C3CO 2771CC 7600
665CCCC 277100 7600
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
52700
52700
52700
52700
c p 5CQ
36900
36VCO
36900
36900
NET REVENUE,
t/TON
WASTE
SOLIDS
0.0
0.0
0.0
0.0
o.n
0.0
0.0
0.0
c.o
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POkER
COMPANY,
i/YEAR
5496900
5361300
S225700
5090200
4954602
4288400
4-152600
4017300
38817CO
TOTAL
NET
SALES
REVENUE ,
i/YEAR
0
0
0
0
Q_
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
S
5496900
5361300
5225700
5090200
, 6554600
4288400
4152800
40.17300
3881700
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
t
5496900
10858200
16033900
21174100
? &1 ^ft JDO
30417100
34569900
38587200
42468900
£x6.£GQOX. t 7 7 1 t_ '~i 26.UQ 36.HG.3 0~^Q 3-Z&6..LC.Q Q 3..2&6-LQJQ. A6>.2-l_5JlflQ
28500CG 118700 3200
2850000 116700 3200
2850000 Ilo700 3200
285000C 118700 3200
2B.CL2Q£ 11&7Q1 3.2Q.Q
2R5CUOO 116700 3200
28500C& 118700 3200
2850000 llb70C 3200
2«50000 . 11S7CC- 3200
.;30 . 15QQ JsR^nnn IIHTOO i?rif>
TOT 57500
LIFETIME
PROCESS COST
LEVELIZED
1C92500CC 45515CC 124000
iseoo
15600
15BOO
15600
1580.0.
15bOO
15800
15800
15600
J "580.0 , ..
606000
c.o
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
fl A
2850IOC
2714600
2579000
2443400
?'P3*OQ
2172300
2036700
1901100
1765500
jfcinoon
68615500
0
0
0
0
D
0
0
0
0
o
0
2850100
2714600
2579000
2443400
y ^Q Jfl OO
2172300
2036700
1901100
176-5500
1 fc^fifiOG
68615500
49065100
51779700
54358700
56802100
COfQttOAft
61282200
63318900
65220000
669(5500
Aft&i *5i5po
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KHQWATT-HtUR
CENTS PER MILLION BTt HEAT INPUT
DOLLARS PER ICN OF SULFUR REMOVED
DISCOUNTED AT 10.0% TC INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN'UMT OPERATING COST
OCLLtRS PER TDK OF CCAL BURNED
MILLS Pbk KUOWATT-HCUR
CENTS PFR MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR R'EMOVED
EQUIVALENT TO
15.08
5.97
62.81
553.35
34979000
0.0
0.0
0.0
. 0.0
0
DISCOUNTED PROCESS COST OVER LIFE OF
14.37
5.69
59.88
526.79
0.0
0.0
0.0
0.0
15.08
5.97
62.81
553.35
34979000
POWER UNIT
14.37
5.69
59.88
526.79
-------
Table B-S8. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-M W existing coal-fired power unit, 3.5% S in fuel;
90% 502 removal; on-site solids disposal)
Investment, $
Percent'of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and ducts (4
scrubbers including common feed plenum, pumps, and
all ductwork between outlet of supplemental fans
and the scrubbers)
Second stage sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and all ductwork
between scrubbers and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
876,000
436,000
4,565,000
3,797,000
305,000
1,143,000
3,049,000
335,000
5.5
2.7
28.7
23.9
1.9
7.2
19.1
2.1
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
649,000
758,000
15,913,000
1,591,000
2,069,000
1,114,000
1,750,000
22,437,000
1 ,795,000
1,795,000
26,027,000
4.1
4.8
100.0
10.0
13.0
7.0
11.0
141.0
11.3
11.3
163.6
"Basis:
Stack gas reheat to 175 F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
229
-------
Table B-59. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-M W existing coal-fired power unit, 3.5% S in fuel;
90% SO
-------
Table B-60
LIMF SLURRY PROCESS, SCO *W. EXISTING CO«L FIREU PQ.ER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT: i 26027000
TOTAL
SULFUR BY-PRODUCT OP. COST
YEARS ANNUAL
AFTER OPERA-
POMER Tir.N,
UNIT KW-HR/
START KW
1
2
3
6 7COO
7 7000
8 70CO
9 7COO
REMOVED RATE,
PtjWEF UNIT Pbfci-R UNIT BY ECU1VALENT
HEAT FUEL POLLUTION TONS/YEAR
RCOUlRcPENT, COSSOHPTIDN, CONTROL
fILLICN FTU TONS CCAL PROCESS, WASTE
/YEAR /YEAR TONS/YEAR SOLIDS
322COOCO 1341700 36700
•322CCDOO 1341700 36700
?22C.COCO 1341700 36700
222COCCC, 13417CO - 36700
178600
17E600
178600
178600
INCLUDING
NET REVENUE, REGULATED TOTAL
t/TON RC1 FDR NET
POWER SALES
WASTE COMPANY, REVENUE.
SOLIDS i/YEAR »/YE*R
0.0
0.0
0.0
0.0
12319200
12102700
11886100
116696CO
0
0
0
0
_IQ _JG!JD ^?p('-nrr. 1-^1700 ?fc7nn i76fccn n.n ntsinnn n
11 5 COO
12 5000
13 5000
14 5COO
IS 5uQQ
16 350C
17 3500
18 3500
19 35CO
2Q 3JJO.Q.
21 1500
22 1500
23 1500
24 1500
p cj j *»QQ
26 1500
27 1500
28 1500
29 1500
230CCOCO 958300 26200
230COOOC 958300 26230
23CCCOOO 9583CO 26200
2300C3C3 958300 26200
? "5 P ! L f1 ( • ^ *f *i fi ^ m ? & P L) P
161COOCC: 67G800 16300
U-1G090C 670800 18300
UICCOCG 670RCO 16300
161UCCOO 670800 U300
i&lCOfPC A7n^0ii |f< ^00
6900000 ^ 1 QO
147312900
152080100
156630800
160964900
i Asnfl ? tftfio
168983500
172668000
176135900
179387300
1 R.?62i? 1 0^
-------
Table B-61. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 2.0% S in fuel;
90% SOi removal; on-site solids disposal)
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
Participate - sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
Investment, $
Percent of subtotal
direct investment
549,000
272,000
4,017,000
3,153,000
542,000
767,000
2,386,000
67,000
4.2
2.1
31.1
24.4
4.2
5.9
18.5
0.5
ilkways)
IS
n rate)
552,000
615,000
12,920,000
1,163,000
1,421,000
646,000
1,292,000
17,442,000
1,395,000
1,395,000
20,232,000
4.3
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
Slack gas reheat to I75"F hy indirect steam reheul.
Disposal pond located I mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table B-62. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 2.0% S in fuel;
90% SO-i removal; on-site solids disposal)
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
46.4 M tons
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 12,920,000
Analyses
Subtotal conversion costs
Subtotal direct costs
18,410 man-hr
490,000 M Ib
212,400 M gal
73,670,000 kWh
24.00/ton
8.00/man-hr
0.70/M Ib
0.08/M gal
0.010/kWh
1,113,600
1,113,600
147,300
343,000
17,000
736,700
1,033,500
32,800
2,310,200
3,423,800
Percent of
total annual
operating cost
16.10
16.10
2.13
4.96
0.25
10.65
14.95
0.47
33.41
49.51
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 5.27
3,014,600
462,000
14,700
3,491,300
6,915,100
Cents/million
Mills/kWh Btu heat input
1.98 21.95
43.60
6.68
0.21
50.49
100.00
Dollars/ton
sulfur removed
337.32
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,50CMons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $20,232,000; subtotal direct investment, $12,920,000.
Working capital, $589,300.
Investment and operating cost for disposal of fly ash excluded.
233
-------
Table B-63
LIME SLURRY PROCESS, SCO MW. NEW COAL FIRED POWER UNIT, 2.0* S IN FUEL. 90* S02 REMOVAL. REGULATED CO. ECONOMICS.
FIXED INVESTMENT: $
20232000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT K*-HR/
START KW
1
2
3
t.
7COO
7COO
7000
7000
SULFUR BY-PRODUCT
REMOVED RATE,
PDKER UNIT PQWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
RtUUIREMENT, CONSUMPTION, CONTROL
MILLION PTt' TONS COAL PROCESS, WASTE
/YEAk
315COOCO
315000CO
315COOCO
315COOCO
5 7nno ^i*Lnnr.r.
b
7
a
9
in
11
12
13
14
1"i
16
17
16
19
?t\
21
22
23
24
7000
7COO
7COO
7000
700"
5000
5000
5000
5000
5CQQ-
3500
3500
3500
3500
35CO_
1500
1500
1500
1500
315COOCD
315Ct,-DOO
315COOCO
31500000
315i,U3IiQ
225CCOGG
225COOC&
225CCiDOO
225COOOO
p 2 *»cr»nf fi
15750000
157500GO
15150000
15750000
-15250002
67JC30C
6750000
675GOCD
67*0000
/YEAR
1312500
1312500
1312500
1312500
1112500
1312500
1312500
1312500
1312500
i ^i p'ion
937500
937500
937500
S37500
O -> "7^QQ
656200
656200
656200
656200
6.5.6.200.
2812CO
281200
281200
281200
TCNS/YEAR SOLIDS
20500
20500
20500
20500
2C £QQ
20500
20500
20500
20500
2fl ^n ft
14600
1460U
14600
14600
I U feO 1
1C300
10300
10300
10300
1 Q ^ T 0
4400
4400
4400
4400
_25 i*nn fc74n;inn lounn t*t.nn
26
27
28
29
1500
1500
1500
1500
6750000
6750000
675C300
67500CL
281200
281200
281200
«!tl200
3.0...... .. 15Q.O. - 6JSjmfln_ .. _ 2fil2JVO_
TOT
127500
LIFETIME
5737500CO
AVERAGE INCREASE
DOLLARS
23W5500
(DECREASE
PER TON Of
4400
4400
4430
4400
44QQ
373500
) IN UNIT OPERATING
CCAL BURNED
99800
99800
99800
99600
99f,QQ
99800
99800
99800
99800
99800
71300
71300
71300
71300
7.13QQ
49900
49900
49900
49900
499QQ
21400
21400
21400
21400
2IfcflQ
21400
21400
21400
21400
» ItQQ
1818000
COST
TOTAL
OP. COST
INCLUDING MET ANNUAL CUMULATIVE
NET REVENUE. REGULATED TOTAL INCREASE NET INCREASE
WTON ROI FOR NET (DECREASE) (DECREASE)
POWER SALES IN COST OF IN COST OF
WASTE COMPANY, REVENUE. POWER, POWER,
SOLIDS
0.
0.
0.
0.
0-
0.
0.
0.
0.
n.
0.
0.
0.
0.
ft
0.
0.
0.
0.
0.
0.
0.
0.
fl-
0
0
0
0
n
0
0
0
3
n
0
0
0
0
n
0
0
0
0
n
0
0
0
0
n
P.O
0.
0
c.o
0.0
O-
n
MILLS PER KILGWATT-HCUR
CEKTS PER HILLIDN
PROCESS COST
LEVELIZED
DOLLARS
C1SCGUKTEC AT
PER TON OF
PTU HEAT INPUT
SLLFUR REMOVED
1C. OS TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN' UNIT OPERATING COST EQUIVALENT TO
DOLLARS
PER TON CF
CCAL BURNED
DISCOUNTED
MILLS PER KILOWATT-HCUR
CEMS PER H1LLIGK
DOLLARS
PER TUN UF
BTL HEAT INPUT
SLLFUR REMOVED
t/YEAR I/YEAR %
9019900
8879600
8739300
8599000
£458800
8318500
8178200
B0379CO
7897700
77S74HO
6655300
6515000
6374800
6234500
&ti<}& ?no
5203200
5C63000
4922700
4782400
4&4^inn
3423SOO
3283500
3143200
3002900
^'h2?QQ
2722400
25*2100
2441800
2301600
2 JL613QO
166298800
T.04
2.64
29.33
450.60
68709000
PROCESS COST OVER
6.68
2.50
27.83
427.56
0
0
0
0
0
0
0
0
0
0
0
0
0
0
n
0
0
0
0
n
0
0
0
0
0
0
0
0
0
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
c.o
0.0
9019900
8879600
8739300
8599000
fi&58.&QQ
8318500
8178200
8037900
7897700
7757400
6655300
6515000
6374800
6234500
tAQApQn
5203200
5063000
4922700
4782400
4662100
3423800
3283500
3143200
3002900
3li 6.27.00
2722400
2582100
2441800
2301600
5 1 fci 3[OC|
168298800
7.04
2.64
29.33
450.60
68709000
POWER UNIT
6.68
2.50
27.83
427.56
*
9019900
17899SOO
26638800
35237800
4h?4tS660Q
52015100
60193300
68231200
76128900
B ^fift&^QD
90541600
97056600
103431400
109665900
X 1 S?60 * 00
120963300
126026300
130949000
135731400
}^O37^5OQ
143797300
147080800
150224000
153226900
1 ^&QR96QQ
158812000
161394100
163835900
166137500
_Ltfi2SiBAOO
-------
Table 8-64. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% 502 removal; on-site solids disposal)
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
Participate - sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
795,000
387,000
4,017,000
3,153,000
542,000
767,000
3,356,000
67,000
5.5
2.7
28.1
22.0
3.8
5.4
23.4
0.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
*
Total capital investment
552,000
682,000
14,318,000
1,289,000
1,575,000
716,000
1,432,000
19,330,000
1 ,546,000
1,546,000
22,422,000
3.8
4.8
'(00.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheat to 17S°F by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, e'nding mid-1975. Average cost basis for scding, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
235
-------
Table B-65. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-site solids disposal)
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
81.2 M tons
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 14,318,000
Analyses
Subtotal conversion costs
Subtotal direct costs
22,320 man-hr
490,000 M Ib
241,900 M gal
74,100,OOOkWh
22.00/ton
8.00/man-hr
0.70/M Ib
0.08/M gal
0.010/kWh
1^,786,400
1,786,400
178,600
343,000
19,400
741,000
1,145,400
36,500
2,463,900
4,250,300
Percent of
total annual
operating cost
22.05
22.05
2.20
4.23
0.24
9.15
14.14
0.45
30.41
52.46
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 6.17
3,340,900
492,800
17,900
3,851,600
8,101,900
Cents/million
Mills/kWh Btu heat input
2.31 25.72
41.24
6.08
0.22
47.54
100.00
Dollars/ton
sulfur removed
225.81
"Basis:
Remaining life of power plain, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $22,422,000; subtotal direct invesiment, $14,318,000.
Working capital, $744,000.
Investment and operating cost for disposal of fly ash excluded.
236
-------
Table B-66
L1HE SLURRY PROCESS, 500 MW. NEW COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90% 502 REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT:
22422000
YEARS ANNUAL
AFTER CPERA-
POriER T1CN,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7COO
4 7COC
c 2000
6 7CCO
7 7000
8 7CCO
9 7COO
1Q 7CQQ
11 5000
12 5COO
13 :-GOO
14 5000
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
FEOUIfcEHENT, CONSUMPTION, CONTROL
M1LLICN ETU TUNS COAL PROCESS,
/YEAR /YEAR TONS/YEAR
31SCOQOO 1312500 35900
315CCOOO 1312500 35900
315LUOCO 1312500 35900
315CCOCO 1312500 35900
31SOuQ°J 1312.5.&Q 3SSQQ
315GOOOO 1212500 35900
315CGUUO 1312500 35900
315CJOCO 1312500 35900
3150COOO 1312500 35900
315CGOO& 13125G3 359,0,0
225COOCS 937500 25600
225COJCO 937500 256JO
22500000 937500 25600
225CC3CO 937500 25600
BY-PRODUCT
RATE*
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
174700
1747CO
174700
174700
1 747CO
174700
174700
174700
174700
1 74700
124800
124800
124800
124800
15 ^ 5000 ppsi.nnnn q-*7snn j*.t,nn i?tftnn
16 3500
17 3500
18 3500
19 3500
;p «ao
21 1500
22 1500
23 1500
24 1500
2.5, 15,00,
26 1500
27 IbOO
28 1500
29 1500
_aa i5£o._
K>| I £7500
LIFETIME
PROCESS COST
LEVELIZED
to
OJ
-J
15750000 656200 17900
1575000C 656200 17900
15750000 656200 17900
?5750000 6562CO 17900
15?5QO£,G . ^5.620° n«no _
67500CO 281200 7700
6750000 281200 7700
6750000 281200 7700
6750000 281200 7700
6,7.5.00.00. 2fil2QO ^700
6750000 281200 7700
6750000 281200 7700
6750000 281200 7700
6750000 281200 7700
67^^000 ?fil?QQ 7700
5737500UO 23905*00 653500
87300
87300
87300
87300
fil^OO
37400
37400
37400
37400
37400
37400
37400
37400
37400
17 A no
3181500
TOTAL
OP. COST
INCLUDING
NET REVENUE. REGULATED
S/TON
WASTE
SOLIDS
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
O-o
0.0
0.0
0.0
0.0
Q-Q
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
n.a
R01 FOR
POWER
COMPANY,
I/YEAR
10434500
10279000
10123600
9968100
4ft.l?*>QQ
9657200
9501700
9346300
9190800
9Q3.53QO
7691300
7535800
7380400
7224900
7n#»Q£QQ
5989700
58342CO
5678800
5523300
S^AIQOO
3893100
3737600
3582200
3426700
^271 V)D
3115800
2960300
2104900
2649400
2^^400,0
194580100
TOTAL
NET
SALES
REVENUE,
i/YEAR
0
0
0
0
[1
0
0
0
0
D
0
0
0
0
n
0
0
0
0
0
0
0
0
0
0
0
0
0
n
0
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
IDECREASE)
IN COST OF
POWER.
$
10434500
10279000
10123600
9968100
9. 8 12600
9657200
9501700
9346300
9190800
5035300
7691300
7535800
7380400
7224900
7069600
5989700
5834200
5678800
5523300
*t "%fc*7Q OO
3893100
3737600
3582200
3426700
^2713.00
3115800
2960300
2804900
2649400
P£44f]f)Q
1V4580100
(DECREASE)
IN COST OF
PObER.
V
104345CO
20713500
30837100
4C805200
5061 780^
60275000
69776700
79123000
88313800
9 7 ^^ q i oo
105040400
112576200
119956600
127181500
i 3 & 2 *> 0 90 ^
140240600
146074800
151753600
157276900
1 4*26&4-f|OG
166537900
170275500
173857700
177284400
i an5557QO
183671500
186631800
189436700
192086100
1 Q45MD 1QG
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTt HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
DISCOUNTED
8.14
3.05
33.91
297.75
79593300
PROCESS COST OVER
7.74
2.90
32.24
282.95
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
8.14
3.05
33.91
2^7.75
79593300
POWER UNIT
7.74
2.90
32.24
282.95
-------
Table B-67. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 5.0% S in fuel;
90% SO-i removal; on-site solids disposal)
Percent of subtotal
Investment, $ direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators) 1,006,000 6.5
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps) 485,000 3.1
Particulate - sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps) 4,017,000 25.9
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans) 3,153,000 20.3
Stack gas reheat (4 indirect steam reheaters) 542,000 3.5
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum) 767,000 5.0
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps) 4,172,000 28.9
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant) 67,000 0.4
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
552,000
738,000
15,499,000
1,395,000
1,705,000
775,000
1,550,000
20,924,000
1,674,000
1,674,000
24,272,000
3.6
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
"Basis:
Stack gas reheat to I75°l? by indirect sjeani reheat.
Disposal pond located I mile, from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis tor scaling, mid-1974.
Minimum in process storage; only pumps arc spared.
Investment requirements for disposal of fly iish excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
238
-------
Table B-68. Lime Slurry Process
Total Average Annual Operating Costs Regulated Utility Economics'1
(500-MW new coal-fired power unit, 5.0% S in fuel;
90% SOi removal; on-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime 1 1 6.0 M tons
Subtotal raw material
Conversion costs
Operating labor and
supervision 24,090 man-hr
Utilities
Steam 490,000 M Ib
Process water 271 ,400 M gal
Electricity 74,520,000 kWh
Maintenance
Labor and material, .08 x 15,499,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 6.99
21.00/ton 2,436,000
2,436,000
8.00/man-hr 192,700
0.70/M Ib 343,000
0.08/Mgal 21,700
0.010/kWh 745,200
1,239,900
39,400
2,581,900
5,017,900
3,616,500
516,400
19,300
4,152,200
9,170,100
Cents/million
Mills/kWh Btu heat input
2.62 29.11
Percent of
total annual
operating cost
26.56
26.56
2.10
3.74
0.24
8.13
13.52
0.43
28.16
54.72
39.44
5.63
0.21
45.28
100.00
Dollars/ton
sulfur removed
178.89
"Basis:
Remaining life of power plant, 30 yr.
Coal liurned. 1,312,SO(Hons/yr, 9.000 Htu/kWh.
Stack gas reheat to I7S°I;.
Power unit on-slream time, 7,000 lir/yr.
Miilwesl plant location, l')75 operating costs.
Total capital investment, $24,272,000; subtotal direct investment, $15,499.000.
Working capital, $888,100.
Investment and operating cost for disposal of tly ash excluded.
-------
Table B-69
LIHE SLURRY PROCESS, 500 MW. NEW COAL FIRED POWER UNIT, 5.0* S IN FUEL, 90% SQ2 REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT: $ 24272000
YEARS ANNUAL
AFTER OPERA-
POWER TICS,
UNIT KW-HR/
START KW
1 7000
2 7COO
3 7COO
4 7COC
5. 2Q.QQ.
6 7000
7 7000
8 7COO
9 7000
1 'i TOfiO
11 5COO
12 btiOO
13 ' 5000
14 5CQC
!•> "iGQO
16 3500
17 3500
IS 3500
19 3500
_£Q 35.UD
21 1500
22 1500
23 1500
24 1500
POWER UNIT
HEAT
RECUIREMEM,
MILLIL'N frTU
/YE*»
315CCOCO
315COQC3
315S.U3CO
31500CCU
^ 1 *i ° fj Cl f i f
315CCOCO
3150COCO
315COOCC
31500000
— 315LL:OCQ
2<|i2i,'OOC
2250COO&
2i5CCOC-0
225CO'JOO
.? p *i r fi fi r P
1575UOCO
1575COC3
1575:000
1 5 7 i- (j 0 f1 D
1S.25U "^£11
67SCOC:
675CGOO
675 TQCC/
67500CO
PQWIR UNIT
FUEL
SULFUR
REMOVED
BY
POLLUTION
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
TOTAL
OP. COST
INCLUDING
NET'REVENUE, REGULATED
t/TOH
CUNSUMPTION, CONTROL
TONS COAL
/YEAR
1312500
1312500
131250C
131250C
13.12.5J10.
1312500
1312500
1312500
1312500
1 "* 1 }*•! Of
937500
937500
93750D
9375CC
*j "^ 7 *i 0 TJ
656200
656200
456200
156220
£5.6.2.^0.
2cl2CO
2812':t
2 J120C
2612CO
PROCESS,
TONS/YEAR
51300
51300
51300
51300
*\ 1 "3Ofl
51300
51300
51300
51300
51 3Qfi
36603
36603
3frtOO
36fcOO
"^ f t* Q r>
25600
25600
25600
25600
2. 5. L Q 0
11003
11030
11000
11000
_i\ 1500 fc7S:,r,rri >hl?fr.5 11 mi
26 1500
27 150C
28 1500
29 1500
^0 15QQ
TUT 127500
LIFETIME
675COOJ
675COCO
6750300
6750000
1 75 /.^r r,
5737500CO
2612GO-
281200
2H200
2812 DC
2,^^2-Ql
23^05500
AVERAGE INCREASE (DECREASE
t/OLLARS PER TON UF
MILLS
CENTS
11000
11030
11COO
11COO
11000
934COO
WASTE
SOLIDS
249500
249500
249500
249500
?t* QSfl ft
249500
249500
249500
249500
P495fin
178200
176200
17B200
178200
i T n2t\(\
124800
124800
124800
124cOO
124BQCI
53500
53500
53500
53500
535QQ
53500
53500
53500
53500
*» Tinn
4545000
HASTE
SOLIDS
0.0
0.0
0.0
0.0
0-0
0.0
c.o
0.0
0.0
Ci D
0.0
0.0
0.0
0.0
Q-,0
0.0
0.0
0.0
0.0
0~*.Q
0.0
0.0
0.0
0.0
Q O
0.0
0.0
0.0
c.o
OiQ
ROI FOR
PCWER
COMPANY,
*/YEAR
11695300
11527000
11356700
11190400
HO?"CO
10853600
10685500
10517200
10348900
i m fi fi i%f) o
8611400
8443200
8274900
8106600
7*j"^i> "^nn
66E3700
6515400
t-347100
6178800
6DJC500
4299700
4131400
3963100
3794600
Ifc 2f»^(lf\
3458300
3290000
3121700
2953400
7?A*h 1 flfl
217913400
NET ANNUAL CUMULATIVE
TOTAL
NET
SALES
REVENUE,
I/YEAR
0
' 0
0
0
o
0
0
0
0
o
0
0
0
0
D
0
0
0
0
0
0
0
0
0
o
0
0
0
0
0
INCREASE NET INCREASE
(DECREASE)
IN COST OF
POWER,
*
11695300
11527000
11358700
11190400
(DECREASE)
IK COST OF
POWER.
t
11695300
23222300
34581000
45771400
11Q221QQ s*7»^50n
10853800
10685500
10517200
10348900
67647300
78332800
88850000
99198900
_lQlflQfcQQ i fl9^79 son
86114QO
8443200
8274900
6106600
79383QQ
6683700
6515400
6347100
6178800
£010-5 QQ _
4299700
4131400
3963100
3794800
^fc?J»*»OO
3458300
3290000
3121700
2953400
?"785 100
2179)3400
117990900
126434100
134709000
142615600
1 S H7S "?
-------
Table B-70. Lime Slurry Process
Summary of Estimated Fixed Investment3
(],000-MW existing coal-fired power unit, 3.5% S in fuel;
90% SO} removal; on-site solids disposal)
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and ducts (4
scrubbers including common feed plenum, pumps, and
all ductwork between outlet of supplemental fans
and the scrubbers)
Second stage sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and all ductwork
between scrubbers and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
1,364,000
666,000
6,782,000
5,720,000
543,000
1,746,000
4,593,000
442,000
5.7
2.8
28.5
24.0
2.3
7.3
19.3
1.8
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
831 ,000
1,134,000
23,821,000
2,144,000
2,859,000
1,667,000
2,382,000
32,873,000
2,630,000
2,630,000
38,133,000
3.5
4.8
100.0
9.0
12.0
7.0
10.0
138.0
11.0
11.0
160.0
"Basis:
Stack gas reheat to 175°I; by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with :iccompanying overtime pay incentive not considered.
241
-------
Table B-71. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW existinglval-fired power unit, 3,5% S in fuel;
90% S0t removal; on-site solids disposal)
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
162.4 M tons 20.50/ton
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .07 x 23,821,000
Analyses
Subtotal conversion costs
Subtotal direct costs
29,760 man-hr
8,288,000 gal
483,900 M gal
131,680,OOOkWh
8.00/man-hr
0.23/gal
0.08/M gal
0.009/kWh
3.329,200
3,329,200
238,100
1,906,200
38,700
1,185,100
1,667,500
59,500
5,095,100
8,424,300
Percent of
total annual
operating cost
21.76
21.76
1.56
12.45
0.25
7.75
10.90
0.39
33.30
55.06
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
labor
Dollars/ton
coal burned
5.83
5,834,300
1,019,000
23,800
6377,100
15,301,400
Cents/million
Mills/kWh Btu heat input
2.19 24.29
38.12
6.66
0.16
44.94
100.00
Dollars/ton
sulfur removed
213.23
aBasis:
Remaining life of power plant, 25 yr.
Coal burned, 2.625,000 tons/yr. 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $38,133,000; subtotal direct investment, $23,821.000.
Working capital, $1,466,500.
Investment and operating cost for removal and disposal of fly ash excluded.
242
-------
Table B-72
LIME SLURRY PRCCESS, 1000 MW. EXISTING CCAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* 502 REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT: » 38133000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING NET ANNUAL CUMULATIVE
YEARS ANM/AL POWER UNIT PUWFR UNIT BY EQUIVALENT NET REVENUE, REGULATED TOTAL INCREASE NET INCREASE
AFTER OPERA- HEAT FUEL POLLUTION TLNS/YEAR I/TON RDI FOR NET (DECREASE) (DECREASE)
POrfER T1LN, RCGUIREHEHT, CONSUMPTION, CPNTRGL POWER SALES IN COST OF IN COST OF
UNIT K«-hR/ "ItLIL.'i BTU TONS COAL PROCESS, WASTE WASTE COMPANY, REVENUE, POWER, POWER,
START K. /YEAk /YEAR TONS/YEAR SOLIDS SOLIDS i/YEAR t/YEAR » S
1
2
3
4
6
7
8
9
in
11
12
13
14
1 S
16
17
18
19
7000
7COO
7000
7CCC
7QOC
5000
5000
5CCO
5000
5CQ£_
3500
3500
35CC
3500
tSCOGOCC 2625000 71800
630GOOCU 2625COO 71800
6300COCO 2t.25000 71800
630COOCO 2625000 71800
&3.QCGGC3 2^25,000 7.1&3Q
45CGOOOO 1K75000 51300
45000000 U75COC 51300
45000000 1<:75000 51300
450COOCO 1B75000 51300
&5.QC33CQ J^i7^0^0 5X3Q9.
31SCCUCO 1312500 35900
315COOOO 1312500 35900
315COOOG 1312500 35900
315CCOOO 1312500 35900
3*9400
349400
349400
349400
3ft9fcQQ
249500
249500
249500
249500
2&SSQO
174700
174700
174700
174700
2Q ?5DO 3i^nnarn i*i?snn -»^«tn i7^ino
21
22
23
24
?«i
26
27
2a
29
10
TOT
150C
1500
15CO
15CG
1 500
1500
15GO
150C
1500
i.5£Q
92500
LIFETIME
PROCESS COST
LEVELIZED
13500000 562500 15400
135000GO 562500 15400
1350COCO 562500 15400
135COCOC 562500 15400
135.0CQCQ lib2'?QO. 15*QQ
135COOCO 562500 15400
135CCOCC 562500 15400
135COOOG 5625GO 15400
13500000 562500 15400
13.5CQ3QL 5fa25Qfl 15*00
B325COOCO 3*687500 9*9000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOUARS PER TON OF COAL BURNED
MILLS PER KILDKATY-HCUR
LENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
74900
74900
74900
749CO
'49.00
74900
74900
74900
74900
76QOO
4617000
COST
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF CCAL BURNED
KILLS PER KILUWATT-HIUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SLLFUR REMOVED
0.0
0.0
0.0
c.o
pTn
0.0
0.0
0.0
0.0
Q-O
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
n.o
0.0
0.0
0.0
0.0
0.0
DISCOUNTED
19267300
18950000
18632700
18315500
J7998200
15222500
1*905200
1*587900
1*270700
1 3.95^4.00
117**900
11*27700
11110*00
10793200
i ft& "7*r*jfio
7512200
7195000
6877700
6560*00
fr243.^Qfl
5925900
5608700
5291*00
497*100
&.fk56.9Qn
282501000
8.14 0.
3.05 0.
33.93 0.
297.68 0.
130977300
PROCESS COST OVER LIFE
7 . 66 0 .
2.87 0.
31.90 0.
279.87 0.
0
0
0
0
n
0
0
0
0
n
0
0
0
0
D
0
0
0
0
o
0
0
0
0
n
0
0
0
0
0
0
OF
0
0
0
0
19267300
16950000
18632700
18315500
1 7338,200.
15222500
1*905200
1*587900
1*270700
1 3953* oo
117*4900
11427700
11110400
10793200
104,75900
7512200
7195000
6877700
6560400
19267300
38217300
56850000
75165500
9^X6*3700
108386200
123291*00
137879300
152150000
i 6_61Q34CO
177848300
189276000
200386400
211179600
2? 1 1K^ *i %flO
229167700
236362700
2*32*0*00
2*9800800
62*3200 256044000
5925900
5608700
5291*00
*97*100
£&5&Qnp
282501000
8.1*
3.05
33.93
297.68
130977300
POWER UNIT
7.66
2.87
31.90
279.87
261969900
267578600
272870000
2778*4100
2B25D1000
-------
Table B-73. Lime Slurry Process
Summary of Estimated Fixed Investment2
(1,000-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; on-site solids disposal)
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
Particulate - sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
1,228,000
586,000
5,925,000
4,713,000
955,000
1,161,000
5,018,000
88,000
5.7
2.7
27.7
22.0
4.5
5.4
23.5
0.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
704,000
1,019,000
21,397,000
1,712,000
2,140,000
1 ,070,000
1,926,000
28,245,000
2,260,000
2,260,000
32,765,000
3.3
4.8
100.0
8.0
10.0
5.0
9.0
132.0
10.6
10.6
153.2
aBasis:
Stack gas reheat to 175°F by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
244
-------
Table B-74. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MWnew coal-fired power unit, 3.5% Sin fuel;
90% S02 removal; on-site solids disposal)
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
157.0 M tons
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .07 x 21,397,000
Analyses
Subtotal conversion costs
Subtotal direct costs
29,760 man-hr
947,300 M Ib
467,700 M gal
143,280,000 kWh
20.50/ton
8.00/man-hr
0.60/M Ib
0.08/M gal
0.009/kWh
3,218,500
3,218,500
238,100
568,400
37,400
1,289,500
1,497,800
59,500
3,690,700
6,909,200
Percent of
total annual
operating cost
25.64
25.64
1.90
4.53
0.30
10.27
11.93
0.47
29.40
55.04
indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
4,882,000
738,100
23,800
5,643,900
12,553,100
38.89
5.88
0.19
44.96
100.00
Dollars/ton
coal burned
4.95
Mills/kWh
Cents/million
Btu heat input
1.79
Egui^alentpunjtjjp_eratinjj cost
"Basis:
KcmainiiiK life of power plant, 30 yr.
Coal humed, 2,537,500olous/yr, 8.700 Btu/kWh.
Stuck gas reheat to I 75°I1'.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $32,765,000; subtotal direct investment, $21,397,000.
Working capital. $1,218,300.
Investment and operating cost for disposal of tly ash excluded.
20.61
Dollars/ton
sulfur removed
180.96
245
-------
to
Table B-75
LIME SLURRY PROCESS, 1COO P*. NEW COAL FIRED POKER UNIT, 3.5* S IN FUEL, 90* SO2 REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT:
32765000
YEARS ANNUAL
AFTER OPERA-
POWER TIGN,
UNIT Kti-HR/
START KN
1
2
3
4
7000
70CO
7000
7000
PGfcER UNIT PQWtR UNIT
HEAT FUEL
REOUIfcfcKENT, CONSUMPTION,
KILLICK BTL' TONS COAL
/YEAR
6C9 '_•'.;•- CC;
fcO?C,Ci»,0
tCVCCOCu
fcC9Gj3CC
/YEAR
2537500
2537500
2537500
2537500
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCE'SS,
TONS/YEAR
6V400
69400
69400
69400
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
riASTE
SOLIDS
3377CO
337700
337700
337700
.5 70QO fcC9CC^L~ .?^7=n3 ftqum . . 3377LQ
6
7
8
9
i Q
11
12
13
14
\ r
16
17
18
19
_za
i2
?3
24
7COC
7000
7000
7000
jfCOf)
5COC
5000
5000
5000
5GQC
3500
3500
3500
3500
35on
15CC
1500
1500
1500
60«i;cotc
609C03CC,
6C9CCOCC
6C9CCDOO
6 Cf9 f r CCQ
435C=,OC3
435C9CCG
435COOCO
435 C J-JU'O
A a c r fi^f/i
3C45tOrC
3C'.5GOC'C-
3045 OOfG
3C45C.OCC
13 L4* ' fr r
ISOtiJGOO
130503CO
1305G-3fO
1305QDOO
2537500
2537500
2537500
2537500
2.5.3.25.^1}—
Ibl2500
1612500
16125CO
1812500
It1 1 2 *s Q Q
1266700
1268703
12b8700
126t700
* "• i. HTQT1
?437UO
543700
5437CO
5437CO
69400
69400
69400
69400
tOi^jQ
4V600
49600
49600
49600
AC fvno
34700
34700
34700
34730
•a A 3f* Q
14900
14900
14900
14900
337700
3377CO
337700
337700
33 Jj? 00
2412CP
2412CO
241200
2^1200
-2412QQ
168VCO
168900
168900
168900
I t C 0 JQ Q
72400
72400
72400
72400
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED TOTAL
*/TON ROI FOR NET
POWER SALES
HASTE COMPANY, REVEtVUE,
SCLIDS
0.0
0.0
0.0
G.O
£UQ
C.O
C.O
0.0
C.O
0.0
G.O
G.O
C.O
0-0
0.0
C.O
0.0
c.o
f. n
0.0
0.0
c.o
0.0
t/YEAR */YEAR
15961600
15734600
15507500
15280300
i5H 5.310.0.-
14825900
14596800
14371600
14144400
X3i^l ?Z£ Q
1172370C
11496600
11269400
11C42200
in p i *»nno
9C7GOOO
8842300
66! 5600
838B400
ft i f»i ?fi n
5796100 "
5566900
5341700
5114500
0
0
0
0
_ _ Q
0
0
0
0
o
0
0
0
0
0
0
0
0
0
o
0
0
0
0
,_25 i«,nn i^"'r:jp;i si^ino i<.i>nn 7?tnn n.n t«R7tnn n
27
28
29
3iQ
TOT
1500
1500
1500
1500
JL5iQ£l
127500
1305COOO
I3C500CO
1305C3CO
1305S300
i 3 u c u~^C 0
1109250000
LIFETIKE AVEKAC-E INCREASE
DOLLARS
543700
543700
543700
543700
t f. ^1Q(>
462160CO
(DECREASE )
PER TDK HF C
14900
14900
14900
14900
1 fe^f 0 fl
1264500
IH UNIT CPERAT
CAL BURNED
72400
72400
72400
72400
"^^fcQft
6151500
ING COST
0.0
0.0
0.0
0.0
Q.Q
KILLS PER KlLLhATT-HCUR
CEKTS PER MILLIUN BTU HfAT SNPUT
PROCESS COST
LEVELJZEu
DOLLARS
D1SCCUMEC AT
PER TUK b'F SULFUR REMOVED
10.0% Tti IF, I
INCREASE (DECREASE! IK UHn
DuLLBRS
PER Ttf< OF C
MLLS PEH KILLWTT-it
TIAL YEAR, DOLLARS
DPfcfcATING COST EQUIVALENT TU
iAL tURNEO
iUR
DISCOUNTED
CcMS,. PER HJLLI.JK BTL HEAT INPUT
t'ULLARS
PER TON DF S
CLFUK REKOVEO
4660200
4433000
4205800
3978600
>-te i ^LOQ
296557800
6.42
2.33
26.73
234.53
121789900
PROCESS COST OVER
6.12
2.22
25.51
223.88
0
0
0
0
Q
0
0.0
0.0
0.0
0.0
0
LIFE DF
0.0
0.0
c.o
0.0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE!
!N COST OF IN COST CF
PGbiER, POWER.
i
15961800
15734600
15507500
152S0300
JL5QI53. \ CO
1482590C
14598800
143716CO
14144400
«X 33JL jf 2&Q
117237GO
11496600
11269400
11042200
10815PQO
9070000
8842800
8615600
8388400
& 1 fc 1 2fifi
5796100
5568900
5341700
5114500
48IO4D.Q
4660200
4433000
42058CO
3978600
^TMSOP
296557800
6.42
2.33
26.73
234.53
1217899CO
POWER UNIT
6.12
2.22
25.51
223.88
$
15961600
31696400
47203900
62484200
77S37100
92363200
106962000
121333600
1354780CO
1 ^93^ 5 .?C£I
161118900
172615500
183884900
194927100
20574210.0
214812100
223654900
232270500
2406589GO
OABft->fj IjQft
2546162CO
26Q185100
265526800
270641300
P?**11*? II "7QO
28C168900
2S4621900
288827700
292806300
>Q#v*5^"7*nn
-------
Table B-76. Lime Slurry Process
Summary of Estimated Fixed Investment9
(500-MW new coal-fired power unit, 3.5% S in fuel;
80% SOi removal; on-site solids disposal)
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
Particulate - sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
795,000
387,000
4,017,000
2,812,00
542,000
718,000
3,238,000
67,000
5.8
2.8
29.1
20.4
3.9
5.2
23.5
0.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
552,000
656,000
13,784,000
1,241,000
1,516,000
689,000
1,378,000
18,608,000
1,489,000
1,489,000
21,586,000
4.0
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
"Basis:
Stack gas reheat to 175°F by indirect steam reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-197^. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
247
-------
Table B-77. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 3.5% S in fuel;
80% SO* removal; on-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime
Subtotal raw material
8 1. 2 M tons
22.00/ton 1,786,400
1 ,786,400
Percent of
total annual
operating cost
22.88
22.88
Conversion costs
Operating labor and
supervision
Utilities
Steam
Process water
Electricity
Maintenance
Labor and material, .08 x 13,784,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
22,320 man-hr
490,000 M Ib
239,400 M ga!
64,190,000 kWh
8.00/man-hr
0.70/M Ib
0.08/M gal
0.010/kWh
178,600
343,000
19,200
641,900
1,102,700
36,500
2,321,900
4,108,300
3,216,300
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500otons/yr, 9,000 Btu/kWh.
Stack gas reheat to 17S°K
Power unit on-stream lime, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $21,586,000; subtotal direct investment, $13,784,000.
Working capital, $721,000.
Investment and operating cost for disposal of fly ash excluded.
2.29
4.39
0.25
8.22
14.12
0.47
29.74
52.62
41.20
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 5.95
464,400
17,900
3,698,600
7,806,900
Cents/million
Mills/kWh Btu heat input
2,23 24.78
5.95
0.23
47.38
100.00
Dollars/ton
sulfur removed
244.81
248
-------
Table B-78
LIXt SLUfckY PkCChiS, 5CC ?W . .'.LI- COAL Fl^ED POWER UMT, 3.5* S IN FUEL, 80* SG2 REMCVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT:
215E6003
TDTAL
YtAfcS ANNUAL FL hEK UNIT
AFTi-* ijPf*4- HEAT
POV.ER TILS, R Ei-U'lf-FHENT,
UNIT Krf-hR/ MLLII\ bTU
STAk
1
2
3
/,
5
6
7
6
9
10
1J
1 '{
1 i
14
] ^
16
17
IB
19
7 T
21
22
23
24
?S
2b
27
28
29
3Q
T KR
7CCC
7C.OC
7COC
7CuC
7 • r p
7CCO
7COC
7. .".CO
7-:c:
7 -\Qp
5000
5-OOC
5COC
5^iJO
c nno
3500
3500
3500
?50C
" * QG
1530
15CO
1500
1500
1 C. QQ
1500
1500
1500
1500
. __15QC
/Yf ;s
ili( JCCu
:- 1 5 C C 0 J C'
-J 1 5 C u 0 0 J
3 I 5 r 0 0 C "
i i t r .• • r r
3 150 00 CO
3if ooecc
31MOOC :
:-i5C'.oco
^ * t f r Q r ri
.251COCC.
2i5C.COCO
225C j JCO
^^^(..?.^ :
• -> t f / •. n r ,a
1575C-GOO
1575 1/ J'jC
1575:000
1&75000C
1 c 7 c "'iCO
675JJCC
675uOOC
67500CO
6750000
ft 7 *» "3DD
675COOO
6750000
67f 03CO
67500CO
62S£lJGa
S'JLFUR BY-PRODUCT OP. COST
REPQVtD RATE, INCLUDING
fuHik UNIT bY EOUIVALENT NET REVENUE, REGULATED
FUEL PULLUTIUN TCNS/YEAR J/TON ROI FOR
CI;\SUKPT I >N , CGNTRt'L POWER
TLNS t;:AL PKLCE5S, WASTE WASTE COMPANY,
/Yt,U TOMS/YEAR
i;ia5'^
1^125 '-'0
I': 1250'.'
: .• it ? -j
i "^ i ? c ^ '"*
li!25C;
13125 ,J
1 i 1 2 •> 0 C-
13125JO
1 "2 1 ^ r 1 **
'.-375'C
•• i 7 5 C 0
S3750C
' 37500
S ^ 7*i L. li
t562-?.J
156200
456200
t>56200
t r t •) Q *•
2I«120'j
2E1200
2S1200
221200
> * j p r> Q
i>=1200
2'iliOO
281200
2H1200
2L12QO
31900
31900
31900
31900
31 o ^ j
31900
3 1900
3190 )
31SOO
•Z 1 OQQ
22bOO
22eOO
?2600
22530
72 h D T
15900
15900
15VOO
15900
issoa
61?00
6800
6800
6600
6600
6POO
6F.30
6P.OO
6800
hKon
SULIDS SDLIDS S/YEAR
155300
155300
1553CO
155300
I'lS^OQ
155300
1553CO
155300
155300
I'iS^QO
110900
110903
110900
110900
1109 00
77600
77600
77600
77600
776.QT
33300
33300
33300
33300
33.300. r
33300
33300
33300
33300
,1*300.
0.0
0.0
0.0
O.G
a^a.
0.0
o.o
0.0
c.o
fi A
0.0
0.0
0.0
0.0
C. Q
0.0
0.0
G.O
0.0
r,.n
0.0
0.0
0.0
0.0
0^.0.
0.0
0.0
0.0
0.0
a.n
10052600
99C2900
9753300
9603600
94">&nnn
9304300
9154700
90C5000
8855300
870^700
7410900
7261300
7111600
6962COO
681 PlOn
5771800
5622200
5472500
5322900
S1732QQ
3752000
3602300
3452700
3303000
^ i c^^nn
9003700
2*54000
2704400
2554700
^^nsioo
TOTAL
NET
SALES
REVENUE ,
4/YEAR
0
0
0
0
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
100526CO
9902900
9753300
9603600
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
10052600
19955500
29708800
39312400
9304300
9154700
9005000
8855300
7410900
72613CO
7111600
6962000
££12300-
58070700
67225400
76230400
H5085700
93251&00
101202300
108463600
115575200
122537200
0
0
0
0
Q
0
0
G
0
n
0
0
0
0
5771800
5622200
5472500
5322900
3752000
3602300
3452700
3303000
31»3Qn
3003700
2854000
2704400
2554700
P405100
135121300
140743500
146216000
151538900
160464100
164066400
167519100
170822100
)7^<>T«;<.nn
176979100
179833100
182537500
185092200
V01 127500 573750CIO 239C5500 580500 2*28500
LIFETIME AVLtAGE INCfccASE (UtCkkASt) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BUKhED
MILLS PEK KILOWATT-HLUR
CENTS PER MILLION BTU HEAT INPUT
DuLLARS PER TON GF SLLFUR REMOVED
PROCtSS COST DISCOUNTED AT 10.C* TO INITIAL YEAR, DOLLARS
187497300
7.*4
2.94
32.68
322.99
76687900
0.0
0.0
0.0
0.0
vO
LEVtLIZEO INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER TCS OF CIAL BURNED 7.45 0.0
HILLS PER KILCWATT-HLUR 2.80 0.0
CbKIS PER MILLION BTU HEAT INPUT 31.06 0.0
DOLLARS PtR TON UF SLLFUR REMOVED 306.75 0.0
187497300
7.84
2.94
32.68
322.99
76687900
POWER UNIT
7.45
2.80
31.06
306.75
-------
Table B-79. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% S02 removal; off-site solids disposal)
Percent of subtotal
Investment, $ direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators) 795,000 6.8
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps) 387,000 3.3
Particulate - sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps) 4,017,000 34.3
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans) 3,153,000 26.9
Stack gas reheat (4 indirect steam reheaters) 542,000 4.6
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum) 767,000 6.6
Calcium solids disposal (off-site disposal facilities
including feed tank, agitator, pumps, thickener,
drum filters, and cake loading silo) 863,000 7.4
Utilities (instrument air generation and supply system,
plus distribution systems for obtaining process steam,
water, and electricity from the power plant) 67,000 0.6
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
552,000
557,000
1 1 ,700,000
1,053,000
1,287,000
585,000
1,170,000
15,795,000
1,264,000
1,264,000
18,323,000
4.7
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
"Basis:
Stack gas reheat to I75°l'' by indirect steam reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
250
-------
Table B-80. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% S0 1 removal; off-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime 81. 2 M tons
Subtotal raw material
Conversion costs
Operating labor and
supervision 22,320 man-hr
Utilities
Steam 490,000 M Ib
Process water 220,900 M gal
Electricity 74,570,000 kWh
Maintenance
Labor and material, .08 x 1 1 ,700,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost excluding trucking
and off -site disposal of calcium solids
Annual cost for trucking and off -site
disposal of calcium solids at $4/ton
Total annual operating cost
Dollars/ton
coal burned
Equivalent unit operating cost 6.58
22.00/ton 1,786,400
1 ,786,400
8.00/man-hr 178,600
0.70/M Ib 343,000
0.08/Mgal 17,700
0.010/kWh 745,700
936,000
36,500
2,257,500
4,043,900
2,730,100
451,500
17,900
3,199,500
7,243,400
1,397,600
8,641,000
Cents/million
Mills/kWh Btu heat input
2.47 27.43
Percent 6f
total annual
operating cost
20.67
20.67
2.07
3.97
0.20
8.63
10.84
0.42
26.13
46.80
31.59
5.23
0.21
37.03
33.83
16.17
100.00
Dollars/ton
sulfur removed
240.83
afiasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $)H.32.UH)0; subtotal direct investment, $11,700,000.
Working capital, $710,600.
Solids disposed, 174.700 lons/yi calcium solids including hydrate water.
174.700 tons/yi associated water.
349,400 lons/yr
Investment and operating cost lor disposal of fly ash excluded.
251
-------
Table B-81
LIME SLURRY PROCESS, 5CC UK. KEk CCAL FIPED POWER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL-
FIXED INVESTKENTS S
18323000
YEARS
AFTER
POWER
UNIT
START
1
2
3
4
5
6
7
8
9
10
11
It
13
14
ANNUAL
OPERA-
TION,
Kk-hR/
Kb
7000
7000
7000
7000
7 £0Q
7COO
7000
7000
7000
3000
5COO
5000
5000
5COO
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLUN BTU TONS COAL PROCESS, WASTE
/YEAR
315CCOCG
31500000
315CC300
315CCOOO
315CUuL0
3150COCO
315COOOC
315COOCC
31500000
315QOCQ.Q
225COOCO
225CCOOO
225GOOCO
225COOOO
/YEAR
13125C3
Iil2500
1312500
1312500
1312SJIO.
1312500
1312503
131250C
1312503
13125QQ
937530
937500
937500
S37500
TONS/YE-AR SOLIDS
35900
35900
35900
35900
35 9.QQ
35900
35900
35900
35900
35. 9 0 3
25600
25603
25603
25600
349400
349400
349400
349400
.341401
349400
349400
349400
349400
349&QO
249600
249600
249600
249600
is soon ppsocinn «j*7«;r,ri 7^t,n.T ?^9»,OQ
16
17
18
19
-20-
22
23
24
-25.
26
27
28
29
_*a
TOT
3500
350C
3500
3500
_ 35.00,
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500.
127500
15750000
15.75COCO
I57500CO
157C.OC,00
J5750CPC
6750000
6750000
6750000
6750000
656200
t!>620C
65C29G
656200
fcSAPOO
2ol200
281200
261200
281200
17900
17900
17900
17900
17SDP
7700
7703
7700
7700
174700
174700
174700
174700
174700
74900
74900
74900
74900
TOTAL
OP. COST
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE. REGULATED TOTAL INCREASE NET INCREASE
I/TON ROI FOR NET (DECREASEI (DECREASE)
POWER SALES IN COST OF IN COST QF
WASTE COMPANY, REVENUE, POWER, POWER,
SOLIDS
0.
0.
0.
0.
G.
0.
0.
c.
0.
c.
0.
0.
c.
0.
0
0
0
0
n
0
0
0
0
n
0
0
0
0
»/YEAR »/VEAR
10547300
1042C200
10293200
101661CO
10039. 100
9912100
9785000
9658000
9530900
94Q39Q.O.
7733800
7606800
7479700
7352700
0
0
0
0
_0_
0
0
0
0
Q
0
0
0
0
*
10547300
10420200
10293200
10166100
lQO.131.aO.
9912100
9785000
9658000
9530900
S4.^3SO.O,
7733800
7606800
7479700
7352700
f),o TJjsfcnn n 7j?Sfcno
0.
0.
0.
0.
0-
0.
0.
0.
0.
0
0
0
0
n
0
0
0
0
f*?1* Lnflk J fc 1 Pflft TJC\C\ "T^Qfll O_fl
675COOO
67500UC
67500CC
6750000
1 7S'^QCQ
573750000
LIFETIME AVERAGE INCREASE
DOLLARS
2f 1200
2tl200
2*1200
281200
?« i ? r G
23VC5500
(DECREASE
PER TON OF
7700
7700
7700
7700
Tinn
653500
I IN UNIT OPERATINC
CCAL BURNED
74900
74900
74900
74900
IfcSQQ
6364500
COST
0.
0.
0.
0
0
0
0.0
fl
{)
HILLS PER KILLWATT-HCUR
CENTS PER HILLICN
PROCESS CDST
LEVELUED
DOLLARS
DISCOUNTED AT
PER TON C.F
BTU HEAT INPUT
SUFUR REMOVED
10.0% TC INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS
PER TON DF
CLAL BURNED
DISCOUNTED
MILLS PER KILDWATT-HL'UR
CEKTS PER HILLICN
3QLLARS
PER TON OF
BTt HEAT INPUT
SLLFUR REMOVED
5913500
5786400
5659400
5532300
.... , „ .,5405300
3624900
3497800
3370800
3243700
. . --„ 3116700.. .,,..
2989600
2862600
2735500
2608500
?&.fii&nn
195?«2800
8.20 0.
3.07 0.
34.16 0.
299.90 0.
80903300
PROCESS COST OVER LIFE
7.86 0.
2.95 0.
32.77 0.
287.61 C.
0
0
0
0
0
0
0,
0
0
_o
0
0
0
0
0
0
0
0
0
0
OF
0
0
0
0
5913500
5786400
5659400
5532300
5 A QCri QfJ
3624900
3497800
3370800
3243700
31X6JOO -
2989600
2862600
2735500
2608500
5A O 1 A QQ
195982800
8.20
3.07
34.16
299.90
80903300
POWER UNIT
7.66
2.95
32.77
287.61
*
10547300
20967500
31260700
41426800
S 1&65.9QQ
61378000
71163000
80821000
90351900
99.75. 5.&QQ
1074-89600
115096400
122576100
129928800
1 ?71*&AOO
143067900
148854300
154513700
160046000
X&5&5 1.300
169076200
172574000
i 75944 800
179188500
1 ft > 4Q *i ^ QO
185294600
188157400
190892900
193501400
i**5S&2ROQ
-------
Table B-82. Lime Slurry Process
Summary of Estimated Fixed Investment2
(500-MW existing coal-fired power unit, 3.5% S in fuel; 90% S02 removal;
on-site solids disposal; paniculate scrubber required for fly ash removal)
Percent of subtotal
Investment, $ direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
Particulate • sulfur dioxide scrubbers and ducts (4
scrubbers including common feed plenum, pumps, and
all ductwork between outlet of supplemental fans
and the scrubbers)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and all ductwork
between scrubbers and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
876,000
436,000
4,565,000
3,797,000
305,000
1,179,000
3,049,000
335,000
5.5
2.7
28.6
23.8
1.9
7.4
19.1
2.1
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
649,000
760,000
15,951,000
1 ,595,000
2,074,000
1,117,000
1,755,000
22,492,000
1,799,000
1,799,000
26,090,000
4.1
4.8
100.0
10.0
13.0
7.0
11.0
141.C
11.3
11.3
163.6
aBasis:
Stack gas reheat to 175°F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
253
-------
Table B-83. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing coal-fired power unit, 3.5% Sin fuel; 90% SO^ removal;
on-site solids disposal; paniculate scrubber required for fly ash removal)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Lime
Subtotal raw material
83.0 M tons 22.00/ton
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 15,951,000
Analyses
Subtotal conversion costs
Subtotal direct costs
22,320 man-hr
4,236,000 gal
247,300 M gal
75,850,000 kWh
8.00/man-hr
0.23/gal
0.08/M gal
0.010/kWh
1,826,000
1,826,000
178,600
974,300
19,800
758,500
1,276,100
36,500
3.243,800
5,069,800
Percent of
total annual
operating cost
18.77
18.77
1.84
10.02
0.20
7.80
13.10
0.38
33.34
52.11
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
3,991,800
"Basis:
Remaining life of power plant, 25 yr.
Coal burned, l,341,700otons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs..
Total capital investment, $26,090,000; subtotal direct investment, $15,951,000.
Working capital, $877,600.
investment and operating cost for disposal of fly ash excluded.
41.04
Plant, 20% of conversion costs
Administrative, 10% of operating
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
labor
Dollars/ton
coal burned
7.25
648,800
17,900
4,658,500
9,728,300
Cents/million
Mills/kWh Btu heat input
2.78 30.21
6.67
0.18
47.89
100.00
Dollars/ton
sulfur removed
265.22
254
-------
Table B-84
LIKE SLURRY PROCESS, 500 MW. EXISTING COOL FIRED POWER UNIT, 3.5* S IN FUEL. 90* S02 REMOVAL, FLYASH REMOVED BY PART. SCRUB.
FIXED INVESTMENTS t
26090000
SULFUR
REMOVED
YEARS ANKUAL PLWER UNIT PUWCR UNIT BY
AFTER OPERA- HEAT FUEL PCLLUTIJN
PG.eR TKN, PEtUlREHENT, U.'WSUMPT 1QK , CONTROL
UNIT KK-HR/ M1LLICN BTU TGNS COAL PROCESS,
START KW /YEAR /YcAR TONS/YEAR
1
2
3
5
6 7000 322CUOCO 1341700 36700
7 7COO 322COOOU 134170C 36700
3 7COO 322CDOCO 1341700 367CJ
9 7CCO 322CCJCO 1341700 36700
in 7CQQ 322CQCOQ X3A17QU 3&7QQ
11 5COC 230COOCL' 958300 26200
12 5COO 230C0300 958300 26*00
13 5CCO 23000000 958300 26200
14 SCOO 230COOCO 958300 26200
1 "i SC11Q P3QPOQOO fiSfi^QO 2fc^ftfl
16 3500 16100000 67080C 18300
17 3500 16100000 670800 18300
18 3500 161COOOO 670800 18300
19 3500 161COOCO 670800 id 300
?n 3500 IfclOjOOQ fc7QHOp is^nn
21 1500 69COOOO 287500 7900
22 1500 6900000 287500 7900
23 1500 6900000 287500 7900
24 1500 69000CO 297500 7.900
'5 15QQ fe9DCOCQ .-, ?87SOO J9QQ
26 1500 6900000 287500 7900
27 1500 6900000 287500 7900
28 1500 6900000 287500 1900
29 1500 6900000 287500 7900
•a ft i •; A n f» Q P O O.C1 f) PftTSQQ 1 Q O f)
TD1 92500 425500000 -77^SOOO 485000
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
178600
178600
178600
176600
17^6^0
127500
127500
127500
127500
1 p"7^OO
89300
89300
89300
89300
8930P,
38300
38300
38300
38300
38300
38300
38300
38300
^H^Ofl
2360000
NET REVENUE,
*/TON
HASTE
SOLIDS
0.0
0.0
0.0
0.0
n.n
0.0
0.0
0.0
0.0
0-°,.
0.0
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
o.o
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
*/YEAR
12441600
12224600
12007500
11790400
1 Ir^ 7^^fio
9905100
9688000
9470900
9253900
SQ3fiAfln
7695200
7478200
7261100
7044000
&A?'?noo
5015600
4798500
4581500
4364400
414710"
3930200
3713200
3496100
3279000
in&2Qf)G
184065400
TOTAL
NET
SALES
REVENUE,
»/YEAK
0
0
0
0
o
0
0
0
0
o_
0
0
0
0
™ O
0
0
0
0
0
0
0
0
0
o
0
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
(DECREASE)
IN COST CF
POWER,
t
12441600
12224600
12007500
11790400
115733QO- ..
9905100
9688000
9470900
9253900
J 9.036BQQ-..
7695200
7478200
7261100
7044000
^B270QP
5015600
4798500
4581500
4364400
_.,, 41473QO
3930200
3713200
3496100
3279000
3062000
164085400
(DECREASE!
IN COST OF
POWER,
S
12441600
24666200
36673700
48464100
&nn^7&no
69942500
79630500
89101400
98355300
i o 739? 1QO
115087300
122565500
129826600
136870600
14369260.0
148713200
153511700
158093200
162457600
14«ffc4;iQ69nO
170535100
174248300
177744400
181023400
] ft&Ofl ^4OO
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR* DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER K1LOHATT-HU)R
CENTS PER MILLION BTt HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
10.38
3.98
43.26
379.56
84924200
0.0
0.0
0.0
0.0
0
DISCOUNTED PROCESS COST OVER LIFE OF
9.71
3.72
40.46
355.18
0.0
0.0
0.0
0.0
10.38
3.98
43.26
379.56
84924200
POWER UNIT
9.71
3.72
40.46
355.lt
(SI
VI
-------
Table B-85. Lime Slurry Process
Summary of Estimated Fixed Investment'1
(200-MW new oil-fired power unit, 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and inlet ducts (2
scrubbers including common feed plenum and pumps)
Second stage sulfur dioxide scrubbers and ducts (2 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (2 direct oil-fired reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
291,000
148,000
1,611,000
1,255,000
103,000
227,000
1,326,000
129,000
5.1
2.6
28.0
21.8
1.8
3.9
23.0
2.2
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
393,000
274,000
5,757,000
633,000
748,000
403,000
633,000
8,174,000
654,000
654,000
9,482,000
6.8
4.8
100.0
11.0
13.0
7.0
11.0
142.0
11.4
11.4
164.8
aBasis:
Stack gas reheat to 17S°F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975 • Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared:
Construction labor shortages with accompanying overtime pay incentive not considered.
256
-------
Table B-86. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics9
•>'" (200-MW new oil-fired power unit, 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime
Subtotal raw material
1 7. 7 M tons
26.00/ton 460,200
460,200
Percent of
total annual
operating cost
13.48
13.48
Conversion costs
Operating labor and
supervision
Utilities "
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .09 x 5,757,000
Analyses *
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
14,880 man-hr
873,000 gal
74,600 M gal
21,970,000 kWh
8.00/man-hr
0.23/gal
0.08/M gal
0.019/kWh
119,000
200,800
6,000
417,400
518,100
12,500
1,273,800
1,734,000
1,412,800
aBasis:
Remaining life of power plant, 30 yr.
Oil burned, 2,058,200 bbl/yr, 9,200 Btu/kWh.
Stack gas wheat to 175°F.
Power uml on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $9,482,000; subtotal direct investment, $5,757,000.
Working capital, $295,900.
3.49
5.88
0.18
12.23
15.17
0.37
37.32
50.80
41.39
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 1 .66
254,800
11,900
1 ,679,500
3,413,500
Cents/miliion
Mills/kWh Btu heat input
2.44 26.50
7.46
0.35
49.20
100.00
Dollars/ton
sulfur removed
435.95
257
-------
to
in
OO
Table B-87
LINE SLURRY PROCESS. 200 MW. NEW OIL FIRED POWER UNIT, 2.5* S IN FUEL. 90* S02 REMOVAL, RECULATED CO. ECONOMICS.
FIXED INVESTMENT:
9402000
YEARS ANNUAL
AFTER OPERA-
POWER T10N.
UNIT KM-HR/
START KW
1 7000
2 7000
3 7COO
4 7000
5 l&fiG
6 7COO
7 7000
8 7000
9 7000
1Q. _ , 7000.
11 5000
12 5000
13 5000
14 50.00
1 5 SQQD
16 3500
17 3500
18 3500
19 3500
in 3.5PO
21 1500
22 1500
23 1500
24 1500
2 *5 1 *»fifl
26 1500
27 1500
28 1500
29 1500
_iQ ISOO,-
TOT 127500
LIFETIME
PROCESS COST
LEVELIZEu
SULFUR
REMOVED
PCWER UNIT POWER UNIT 6Y
HEAT FUEL POLLUTION
REQUIREMENT. CONSUMPTION. CONTROL
MILLION BTU CARRUS OIL PROCESS.
/VEAk /YMR TONS/YEAR
12880000 2158200 7800
12880300 2C56209 7800
12P50000 2C582CO 7800
12880000 20?82CG 7803
i^fifc liQGn ^i;*i*i>Ct^i ^ An *\
12880000 2058200 7600
12880300 2058209 7800
128803CO 2058200 7800
12380000 2C5B2CO 7eOO
t y ft c. ft rjfjfi 2Ii^fi? 00 JfiDQ
92COOOO 14701CO 5600
92COOCO 14701SC 5630
92CCOCO 1470103 5b30
92COOOO 1470100 5603
o? f ijJDn lfc2Q109 5&Q3
64400CC lo2QO
2544700
2479000
2413200
2347500
^y tt \ tf\o
1664900
1599100
1533400
1467600
i&ni«nn
1336100
1270400
1204600
1136900
TOTAL
NET
SALES
REVENUE.
S/VLAR
0
0
0
0
0
0
0
0
0
Q
0
0
0
0
o_
0
0
0
0
0
0
0
0
. , , n
0
0
0
0
NET ANNUAL
CUMULATIVE
INCREASE NET INCREASE
(DECREASE)
IN COST OF
POWER,
*
4400000
4334200
4268500
4202700
_ -6122000
4071200
4005500
3939700
3674000
31°?? 00
3255200
3169400
3123700
3057900
79.9.22QQ ,
2544700
2479030
2413200
2347500
?28! 100
1664900
1599100
1533403
1467603
14.Q19QQ
13361CO
1270400
1204603
1136900
(DECREASEI
IN COST OF
POWER,
*
4400000
8734200
13002700
17205400
9\ %£9&flA
25413600
29419100
93356600
37232600
A J f)& 1 QOQ
44296200
47465600
50609300
53667200
5665940"
59204100
61683100
64096300
66443600
68725.500
70390400
71989500
73522900
74990500
74»'3Q26QO
77728500
78998900
80203500
81342400
,10231QO, o im»inn n>&i««oo
82415500
0
62415500
AVERAGE 1NUFASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL UF GIL 5URNED
MILLS PER RILCWATT-rtCUR
CEMi PER MILLION Bit HEAT INPUT
DOLLARS PER TON OF SU.FUR kEMDVEO
DISCOUMED AT 13.0% TO INITIAL YE Ilk, DOLLARS
INCREASE (DECREASE) IK UNIT OPERATING COST
OULARS PER BARREL LF GIL BURNED
HILLS PER KILOkATT-HtUR
CENTS PER MILLION BTL HEAT INPUT
DOLLARS PER TCN OF SLLFUR REMUVEO
EQUIVALtNT TO DISCOUNTED
2.20
3.23
35.13
578.35
33612500
0.0
0.0
0.0
0.0
0
PROCESS COST OVER LIFE OF
2.08
3.06
33.30
549.22
0.0
0.0
0.0
0.0
2.20
3.23
35.13
578.35
33612500
POWER UNIT
2.08
3.06
33.30
549. 2Z
-------
Table B-88. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 1.0% S in fuel;
90% S02 removal; on-site solids disposal)
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Second stage sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fan)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
287,000
146,000
3.631,000
2,841,000
245,000
515,000
1,309,000
186,000
2.8
1.4
35.6
27.9
2.4
5.1
12.8
1.8
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
547,000
485,000
10,192,000
917,000
1,121,000
510,000
1,019,000
13,759,000
1,101,000
1,101,000
15,961,000
5.4
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
"Basis:
Stack pas reheat to 175 !•' by direct oil-fired reheat.
Disposal pond located I mile from power plant.
Midwest plant locution represents project beginning mid-1972. ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
259
-------
Table B-89. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
Direct Costs
Delivered raw material
Lime
Subtotal raw material
(500-MW new oil-fired power unit, 1.0% S in fuel;
90% SOi removal; on-site solids disposal)
Annual quantity
Unit cost, $
Total annual
cost, $
17.3M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 10,192,000
Analyses
Subtotal conversion costs
Subtotal direct costs
14,880 man-hr
2,134,000 gal
160,500 M gal
53,440,000 kWh
26.00/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.018/kWh
449,800
449,800
119,000
490,800
12,800
961,900
815,400
24,000
2,423,900
2,873,700
Percent of
total annual
operating cost
7.82
7.82
2.07
8.54
0.22
16.74
14.18
0.42
42.17
49.99
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit opeiating cost 1.14
2,378,200
484,800
11,900
2,874,900
5.748,600
Cents/million
Mills/kWh Btu heat input
1.64 18.25
41.37
8.43
0.21
50.01
100.00
Dollars/ton
sulfur removed
751.45
"Basis:
Remaining IHV of power plant, 30 yr.
Oil burned. 5,033,600 bbl/yr, 9,000 Btu/kWh.
Stack gas reheat to 17S°F.
Power unit on-streani time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $ 15,961,000; sublotaldirecl investment. $10.192,000.
Working capital, $479,700.
260
-------
Table B-90
LIME SLURRY PRCCtSS, SCO MN . Nti. UIL FIRED PIWER UNIT, 1.0* S IN FUEL, 90* 502 REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT:
15961000
SULFUR
REMOVED
YEARS AN.'.UAl PI'WER UNIT PUH LR UNIT bY
AFTER CPERA- HEAT FUEL PtJLLUTIJN
PUrfER TILN, REtUIRCHFNT, CONSUMPTION, CCNTSOL
UNIT Kh-HR/ fILLJL\ BTU BARRELS P!L PROCESS,
START K« /YEik /Yb4k TENS/YEAR
1 7CCC :U5Ci.vKC 5-.3360J 7700
2 7C-OC MSOGOCC 5L336CC 7700
i 7C3C 315!.uOC" 5C336?C 7700
<• 700C MSrOTCC 5C336jj 7700
•i 7LQC ilS(,i.5Cf. ,,..5.L:ifcOC _.__27QQ u-
b 7COC SISCjOl'C 51J36GO 7700
7 7000 SlsrODfU 5033600 7730
b 7CCO 315CCJCO 5033600 7700
9 7CGC 315CL'OCC 5C336CO 7700
13 7GCC 315LjOQO 5C3360.C* 27QQ
11 51,00 i25rOOGC 3595400 5500
12 50CO 225COOPO 3595400 5500
13 500C 225CCCCC 35954CO 5500
14 50CO 225tCOf.Q 3595400 5500
15 5000 ^25tjJ^O 35954A\lu,_^ , .. 5.5.QC
16 3500 1575COCC 2516POO 3800
17 3500 157FCDCG 2516600 3800
18 350C 1575JCCO 2516800 3SOO
19 3500 1575COCO 2516EDC 3600
^0 . 3'.CQ. . . . . 15.75C!jOQ_ , .251feaCCl 3630 -
i\ 15CO 675COCO l':-7660a 1600
22 1500 67500CC 1C7B600 1600
23 1500 4750000 1078600 ItOO
24 liOO 675COC.C 10736CO 1600
, ir- 1500 - . , ..b75.OQ.Lil . 1L7P.6QQ-- 1600
26 150C 675COOO 1C76600 1600
27 15CC 675tOtC 107t600 IfcOO
2B 15CO 675COOO 107S600 1603
29 1500 67500GO 1078600 1600
-3Q 150C 625CQCu_ 1C.2S6QC „ 1600
TOT 1275CC S7375000C ^1683000 139500
BK-PRDDUCT
RATE,
EQUIVALENT
TLNS/YEAR
WASTE
SCLIDS
37300
37300
37300
37300
3,3300-
37300
37300
37300
37300
3230Q
26600
26600
26600
26600
' ?Afkflfi
18600
18600
18600
18600
1860.0.-
8000
6000
8000
8000
flfinn
8000
8000
8000
8000
Anno
679000
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
i/TON F.LJI FOR
WASTE
SOLIDS
0.0
c.o
0.0
0.0
0.0
0.0
0.0
0.0
p.o
0.0
0.0
0.0
0.0
0-0
0.0
0.0
0.0
0.0
o.n
0.0
0.0
0.0
0.0
o.o
0.0
0.0
c.o
0.0
o a
POWER
COMPANY,
»/YEAR
7409000
7298300
7187700
7077000
&S66.4QQ
6855700
6745100
6634400
6523700
6413 1QQ
5460500
5349900
5239200
5128600
50119.QC
4252300
4141700
4031000
3920400
TOTAL
NET
SALES
REVENUE,
»/YEAR
0
0
0
0
0
0
0
0
p
0
0
0
0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE!
IN COST OF IN COST OF
POWER,
*
7409000
7298300
7187700
7077000
6S6.&&OQ.
6855700
6745100
6634400
6523700
fcAiaiflfl
5460500
5349900
5239200
5128600
^0. SO1790O
0
0
0
0
4252300
4141700
4031COO
3920400
POWER.
$
7409000
14707300
21895000
28972000
3.SS384QO
42794100
49539200
56173600
62697300
6S1..1Q4QO
74570900
79920800
85160000
9C288600
£5306.500
99558800
103700500
107731500
111651900
*«n• 129fcOQ
130391000
132491900
134482200
136361800
19ft 1 3QIQQ
LiFETlnE tVtkAGE INCREASE (DtCRTASE) IN UNIT OPERATING LOST
ULLARS PER BARREL UF OIL BURNED
MILLS PER KILOWATT -HtUR
CENTS PFR MILLION BTU HEAT INPUT
DOLLARS PtR TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TC INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DkCREASE) IN UNIT OPERATING COST
DOLLARS PER bARREL OF OIL- BURUED
HILLS PER KILOVATT-HCUR
CEKTS PER MILLION BTU HEAT INPUT
£ OOLLAR5 PER TON OF SIL.FUR REMOVED
EQUIVALENT TO
DISCOUNTED
1.51
2.17
24.08
990.18
56505800
PROCESS COST OVER
1.43
2.06
22.89
938.63
0.0
0.0
0.0
0.0
0
LIFE OF
o.c
0.0
0.0
0.0
1.51
2.17
24.08
990.18
56505800
POWER UNIT
1.43
2.06
22.89
938.63
-------
Table B-91. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Second stage sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
525,000
260,000
3,631,000
2,841,000
245,000
515,000
2,286,000
186,000
4.5
2.3
31.3
24.5
2.1
4.5
19.7
1.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
547,000
552,000
11,588,000
1,043,000
1,275,000
579,000
1,159,000
15,644,000
1,252,000
1,252,000
18,148,000
4.7
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheat to 175 !•' by direct oil-fired reheat.
Disposal pond located t mile Iron) power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975 Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
262
-------
'I able B-92. Lime Slurry Process
Tot.il Average Annual Operating Costs Regulated Utility Economics'1
(500-MWnew oil-fired power unit, 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
Percent of
total annual
operating cost
43.3 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 11,588,000
Analyses
Subtotal conversion costs
Subtotal direct costs
16,650 man-hr
2,134,000 gal
182,500 M gal
53,760,000 kWh
24.50/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.018/kWh
1,060,900
1,060,900
133,200
490,800
14,600
967,700
927,000
28,800
2,562,100
3,623,000
15.48
15.48
1.94
7.16
0.21
14.12
13.54
0.42
37.39
52.87
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 1 .36
2,704,100
512,400
13,300
3,229,800
6,852,800
Cents/million
Mills/kWh Btu heat input
1.96 21.75
39.46
7.48
0.19
47.13
100.00
Dollars/ton
sulfur removed
358.22
"Basis:
Remaining life of power plant, 30 yr.
Oil burned, 5,033,600 bbl/y:, 9,000 Btu/kWh.
Slack gas reheat lo 175°!'.
Power unit on-slrcmn time, 7,000 lir/yr.
Miilwesl plant locution, 1975 operating costs.
Tola! capital investment. $1 K.I4K.OOO; subtotal direr! investment, $11,5KK,()00.
Working capital, $6I'),700.
263
-------
to
Table B-93
LINE SLURRY PROCESSt 500 KM. NEK OIL FIRED POWER UNIT, 2.5* S IN FUEL* »0* S02 REMOVAL* REGULATED CO. ECONOMICS.
FIXED INVESTMENTS » 1*14*000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE* INCLUDING
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1
2
3
4
«;
6
7
8
9
-Ifi.
11
12
13
-15
16
17
le
19
-20.
21
22
23
24
-25
26
27
28
29
-10,
TOT
PRO
7COO
7000
7000
7COO
7PPD
7000
7000
7000
7000
5000
5COO
5000
5QOO
5000
POWER UNIT PGW£R UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION ?.TU BARRELS OIL PROCESS, WASTE
/YEAR /YEAR TONS/YEAR SOLIDS'
315COOOO
315CC-OCO
315000CO
31500000
315CUOCO
315CUOCO
3150000C
3150COOO
225COOCO
22500000
22500000
22500000
TZSLQUCQ
3500 15750000
3500 I5750CCO
3500 15'75COCO
3500 157500CO
„ ,.^35QQ .1^_j575CUOC .
1500 67bCO(,'j
1500 6750003
1500 675C300
1500 6750000
.,___150C_ fc750i»r:ft
1500
1500
1500
1500
- -15QQ-
127500
LIFETIME
CESS COST
LEVELIZED
6750000
6750000
675COOO
67500CO
5033600
50336CO
5033600
5033600
5033600
S0336GO
50336CO
5033600
3595400
3595400
3595400
3595400
2516GCO
2516*00
2516800
2516800
2S168QC..
1C7860C
1U786CO
1078600
1078600
1078603
1078600
1078600
1C78609
m.fc«xHO_
19100
19100
19100
19100
19100
19100
19100
l^inn
13730
13700
13700
13700
9600
9600
9630
9600
.9600 .
4100
4100
4100
4103
4103
4100
4100
4100
Aiaa
93200
93200
93200
93200
93200
93200
93200
93200
Qf'OO
66500
66500
66500
66500
46600
46600
46600
46600
20000
20000
20000
20000
20000
20000
20000
20000
2COOH.
57375COOO 91683000 348500 1697500
AVEfcACE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
HIILS PER KILdWATT-HLUR
CENTS PER MILLION BTU HEAT INPUT
HOLLARS PER TON 3F SUFUR REMOVED
DISCOUNTED AT 10.0% TD INITIAL YEAR, DOLLARS
INCREASE (Of CREASE) IN UNIT OPERATING CUST EQUIVALENT
DOLLARS PER SARREL OF OIL BURNED
HILLS PER KUOWATT-HLUR
CEKTS PEK MILLION BT L HEAT INPUT
DOLLARS PER T3N HF SLLFUR RFKOVEO
NET REVENUE. REGULATED TOTAL
S/TON ROI FOR NET
POKER SALES
HASTE COMPANY, REVENUE.
SOLIDS t/VEAR »/YEAR
0.
0.
0.
0.
O-
0.
0.
0.
0.
n.
0.
0.
0.
0.
n.
0.
0.
0.
0.
0-
0.
0.
0.
0.
0
0
0
0
0
0
0
0
0
0
0
0
o
0
0
0
6
n
0
0
0
0
0.0
0.0
0.0
0.0
n n
TO DISCOUNTED
8740700
6614900
8489000
8363200
8111600
7985800
7859900
7734100
7AHH3DO
6434500
6308700
6182900
6057000
4992500
4866700
474C900
4615000
3210900
3085100
2959300
2*33400
2707600
25*1*00
2456000
2330200
2204300
162810600
1.78
2.55
28.38
467.18
66727200
PROCESS COST OVER
1.69
2.43
27.03
445.44
0
0
0
0
0
0
0
0
0
0
0
0
0
o
0
0
0
0
0
0
0
0
0
0
0
0
Q
0
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
INCREASE NET INCREASE
IDECREASEI (DECREASE I
IN COST OF IN COST OF
POKER* POWER.
* S
8740700
8614900
8489000
8363200
A2326Q0. _
8111600
7985800
7859900
7734100
2608300 _
6434500
6308700
6182900
6057000
4992500
4866700
4740900
4615000
&&&S2QQ .
3210900
3085100
2959300
2833400
2581800
2456000
2330200
2204300
162810600
1.78
2.55
28.38
467.18
66727200
POWER UNIT
1.69
2.43
27.03
445.44
8740700
17355600
25844600
34207800
50556800
58542600
66402500
74136600
01746900
8*179400
94488100
100671000
106728000
117651700
122518400
127259300
131874300
139574400
142659500
145618800
148452200
153741600
156197600
158527800
160732100
_JL&2fiXQ6QO
-------
Table B-94. Lime Slurry Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 4.0% S in fuel;
90% SO* removal; on-site solids disposal)
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Second stage sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including (lurry disposal pumps, pond, liner, and
pond wattr return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
716,000
350,000
3,631,000
2,841,000
245,000
515,000
3,048,000
186,000
5.6
2.8
28.6
22.4
1.9
4.1
24.0
1.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
547,000
604,000
12,683,000
1,141,000
1.395,000
634,000
1,268,000
17,121,000
1,370,000
1,370,000
19,861,000
4.3
4.8
100.0
9.0
11.0
5.0
10.0
135.0
10.8
10.8
156.6
aBasis:
Stack gas reheat to 175 F by direct oil-fired reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
265
-------
Table B-95. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
Direct Costs
Delivered raw material
Lime
Subtotal raw material
(500-M W new oil-fired power unit. 4.0% S in fuel;
90% SOi removal; on-site solids disposal)
Annual quantity
Unit cost, $
Total annual
cost, $
69.3 M tons
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 12,683,000
Analyses
Subtotal conversion costs
Subtotal direct costs
18,410 man-hr
2,134,000 gal
204,600 M gal
54,080,000 kWh
22.50/ton
8.00/man-hr
0.23/gal
0.08/M gal
0.018/kWh
1.559.300
1.559,300
147,300
490,800
16,400
973,400
1,014,600
31,700
2,674.200
4,233,500
Percent of
total annual
operating cost
20.14
20.14
1.90
6.34
0.21
12.58
13.10
0.41
34.54
54.68
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
2,959,300
aBasis:
Remaining life of power plant, 30 yr.
Oil burned, 5,033,600 bbl/yr, 9,000 Btu/kWh.
Stack gas reheat to 17S°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment. $ 19,861,000;subtotal direct investment. $12.683,000.
Working capital, $733,800.
38.22
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 1.54
534,800
14,700
3,508,800
7,742,300
Cents/million
Mills/kWh Btu heat input
2.21 24.58
6.91
0.19
45.32
"00.00
Dollars/ton
sulfur removed
252.85
266
-------
Table B-96
L1MF SLUkkY PRGCtSS, 5K MV. . KE» LIL FlhED PL'WER UNIT, 4.0% 5 IN FUEL, 9Gt SC2 REMOVAL, RE&ULATFD CO. ECONOMICS.
FIXED INVESTMENT:
YCAPS ANNUAL
AFTfck OPERA-
PO»ER TILN,
UMT Kn-HR/
START KW
PjhEA UNIT
HEM
Piiht<< U'ilT
FUEL
M I L L 11 f»
/YcA5
ETu bARRtLS 6IL
SULFUR
REMUVkD
ev
POLLUTION
CO MR I'L
PROCESS,
TOKS/YtAR
BY-PRUPUCT
RATE,
EQUIVALENT
TUNS/YEAR
WASTE
SCLIDS
19661COO
NET REVENUE,
J/TON
WASTE
SULIDS
TOTAL
OP. COST
INCLUDING
RfGULATEU
RM FOR
POWER
COMPANY,
»/YFAk
TOTAL
NET
SALES
REVENUE,
I/YEAR
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POh'Ek,
*
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POKER,
$
1 1
12
13
14
-15.-
16
17
16
19
_2Q-
21
22
23
24
-25-
26
27
26
29
-30.
7COO
7000
7CGO
7CUC
2CaO-
7CCO
7CO&
7CCO
7CCO
2CCC.
5COO
5COC
5COC
5000
_5CQQ-
350C
350C
3500
3500
3SQQ.
l&OO
1500
150C
15CO
1500.
1500
1500
1500
1500
315: .OC j
31?CoOr3
315: ::io
51 3?6CC
5.-J360J
5'. i36C;
JU600
306DO
30bOO
3C600
14°100
149100
149100
149100
315COOCO
315COCCJ
315^:300
2250001-0
?25,oOCO
<; 2 5 0 u J C L
5C336CO
35954C/C
31V5430
359540:>
35954C:
30600
30600
3&600
30600
IQaQQ.
21900
21900
2190D
21930
140100
149100
1491CO
149100
106500
106500
1065CO
106500
C .0
0.0
O.P
C.O
0.0
0.0
0.0
3.0
C.O
0.0
0.0
0.0
960fi5CC
9670800
95331CO
939540C
-S125J2CQ
912COOC
8982300
E6446CO
b7C69CO
7215500
7C7780G
6940100
0802400
1575001 P
15751; UC>
157!.;OOC
15750003
25168UC
25166DO
25168CO
15300
15300
15300
15300
67500CO
675C.OOU
6750COO
1C7860C*
1U7B6JO
!C7bbOO
1078600
6600
6600
6600
6600
74500
74500
74503
74500
24500.-
31«CO
31900
31900
31900
0.0
0.0
0.0
0.0
-O-
0.0
0.0
0.0
0.0
5585500
5447900
5310200
5172500
356640C
3428700
3291000
3153300
675CCCU
675UOOO
67EOOCO
6750000
1078600
107b600
1073600
1C79600
6600
6600
6600
6600
31900
31900
31900
31900
0.0
0.0
0.0
0.0
E.ft
2877900
2740200
2602500
2*6*800
(j
0
_a
o
o
o
o
.0
0
0
0
0
.0
0
0
0
0
-fl
0
0
0
0
_fl
0
0
0
0
I.
98C8500
9670800
9533100
9395400
9120000
8962300
8844600
8706900
£569200-
7215500
7077800
6940100
68C2400
9808500
19479300
29012400
38407800
____ 4266.55^0
56765500
6 5767 8 CO
7*612400
83319300
5565500
5447900
5310200
5172500
991C40CO
106181800
1131219CO
119924300
___ 126.5*9300
1321745CO
137622*00
1*2932600
148105100
3566*00
3*28700
3291000
3153300
2877900
27*3200
2602500
2*6*800
2127100-
156706300
160135000
163*26000
166579300
__ 16.8551430.0
172*72800
175213000
177815500
180280300
TOT 127500 572750CW/0 91683000 556000 2V15000
LIFETIME AVERAGE INCRIASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL GF OIL BURNED
MILLS PER KILUWATT-HCUK
CENTS PER MILLION BTU HEAT INPUT
UULLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCDUKTEl! AT IO.C.% TO INITIAL YEAR, DOLLARS
182607400
1.99
2.86
31.83
327.25
74929500
182607*00
LEVELUED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER
DOLLARS PER SAKREL OF OIL BURNED
MILLS PER K1LUKATT-HLUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON UF SUFUR REMOVED
1.90
2.73
30.35
312.34
0.0
0.0
0.0
0.0
0
LIFE OF
0.0
0.0
0.0
0.0
1.99
2.86
31.83
327.25
7*929500
POWER UNIT
1.90
2.73
30.35
312.3*
-------
Table B-97. Lime Slurry Process
Summary of Estimated Fixed Investment9
(500-MW existing oil-fired power unit, 2.5% S in fuel;
90% S02 removal; on-site solids disposal)
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and ducts (4
scrubbers including common feed plenum, pumps, and
all ductwork between outlet of supplemental fans
and the scrubbers)
Second stage sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and all ductwork
between scrubbers and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
579.000
293,000
4.123,000
3,419,000
263,000
1,025,000
2,080,000
312,000
4.3
2.2
30.9
25.6
2.0
7.7
15.6
2.3
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
609,000
635,000
13,338,000
1,334,000
1,734,000
934,000
1,467,000
18,807,000
1,505,000
1,505,000
21,817,000
4.6
4.8
100.0
10.0
13.0
7.0
11.0
141.0
11.3
11.3
163.6
aBasis:
Stack gas reheat to 175 F by direct oil-rued reheat.
Disposal pond located 1 mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Avetige cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Construction labor shortages with accompanying overtime pay incentive not considered.
268
-------
Table B-98. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(50Q-M W existing oil-fired power unit, 2.5% S in fuel;
90% SO2 removal; on-site solids disposal)
Direct Costs
Delivered raw material
Lime
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
44.3 M tons 24.50/ton
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .08 x 13,338,000
Analyses
Subtotal conversion costs
Subtotal direct costs
16,650 man-hr
3,100,000 gal
186,300 M gal
56,320,000 kWh
8.00/man-hr
0.23/gal
0.08/M gal
0.018/kWh
1,085,400
1,085,400
133,200
713,000
14,900
1,013,800
1,067,000
28,800
2,970,700
4,056,100
Percent of
total annual
operating cost
13.56
13.56
1.66
8.91
0.19
12.67
13.34
0.36
37.13
50.69
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/bbl
oil burned
Mills/kWh
3,338,000
594,100
13,300
3,945,400
8,001,500
Cents/million
Btu heat input
1.56
2.29
24.85
41.72
7.42
0.17
49.31
100.0
Dollars/ton
sulfur removed
409.07
aBasis:
Remaining life of power plunt. 25 yr.
Oil burned, 5,145,400 bbl/yr, 9,200 Btu/kWh.
Stuck gas reheat to 175°K
Power unit on-stream time, 7,000 hr/yr. ^
Midwest plant location, 1975 operating costs.
Total capital investment, $21,817,000; subtotal direct investment, $13,338,000.
Working capital, $690,400.
269
-------
•s
Table B-99
LIME SLURRY PROCESS, 500 MW . EXISTING OIL FIRED POWER UNIT, 2.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CD. ECONOMICS.
FIXED INVESTMENTS ft
21817030
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWfcR UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWER TICK, RETIREMENT, CONSUMPTION, CONTROL
UNIT Kti-hR/ MILLION BTU BARRELS OIL PROCESS,
START KM /YEAR /YCAR TONS/YEAR
1
2
3
4
5 -
6 700C 322C.C30C 51454CD 19600
7 7000 322CJOOO 51454CO 19600
8 7000 322COOCO 5145400 19600
9 7000 322COOOO 5145400 19600
ir> .3000 ^- 32ZCCQCL .,5 145400 .. ^,.^19600 ,
11 5000 233CCOCO 3675300 14000
12 5COO 230COCOO 3675300 14030
13 5000 230COOCO 3675300 14000
14 StOO 2300COCO 3t75300 14000
15 50QQ 23GC3Qliv> 3* 75^0 XfeCQQ - .
16 3500 161COOCO 2572700 9800
17 35CC 161C02CO 2572700 9*03
18 3500 1610UOCT 2572700 9600
19 3500 161C30CC 2572700 9800
_2Q 35.QQ 1&.1QQ3D'" 25.227QQ aflCkU
21 1500 6900300 1102600 4200
22 1500 6900000 1102600 4200
23 1500 69CJOOO 1102600 4200
24 1500 69COCC(< 1102600 4200
21 15.00 . &9LCQCQ _ .110260(2 -, — , 4200
26 150C 69COOCO 1102630 4200
27 1500 6900000 1102600 4200
28 1500 69COOOO 1102603 4200
29 1500 69COOCO 1)02600 420.0
_3Q...^ 1SQQ , 69PQ3CO - - - _, itp?fcfin J _,- J.,di20Q..,.I,..
Wl 92500 425500000 67993000 259000
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
WASTE
SOLIDS
95200
95200
95200
95200
._. S520.Q
68000
.68000
68000
68COO
ft POOQ
47600
47600
^47600
^47600
ii 36.QQ
20400
20400
20400
20400
>ft^fifl
20400
20400
20400
20400
>ft&fin
i?!>8CO&
TOTAL
OP. COST
INCLUDING NET ANNUAL CUMULATIVE
NET REVENUE, REGULATED TOTAL INCREASE NET INCREASE
i/TON ROI FOR NET {DECREASE) (DECREASE)
POWER SALES IN COST OF IN COST OF
WASTE
SOLIDS
0.0
3.0
0.0
0.0
ft n
0.0
c.o
0.0
c.o
._._.. -Q-Q .
0.0
0.0
0.0
0.0
f,-Q
0.0
0.0
0.0
0.0
0-Q
o.c
0.0
0.0
0.0
fliO
COMPANY, REVENUE,
ft/YEAR t/YEAR
10270500
1C089000
9907500
9726000
9*44400
8185000
8003500
7822000
764050C
zfcs&aao
6364100
6182600
6001100
5819600
„ - ^56.38000- Jlr . Lr-
4160400
3978900
3797400
3615800
5f%A"^ftfl
3252800
3071300
2H9600
2708200
L. . 2S26700
152088300
0
0
0
0
_Q
0
0
0
0
POWER,
ft
10270500
10089000
9907500
9726000
OCA^A QQ
8IB5000
8003500
7822000
7640500
POWER.
ft
10270500
20359500
30267000
39993000
&S&^2&00
57722400
65725900
73547900
81188400
0 54*fc«nn «BA47inn
0
0
0
0
_Q
0
0
0
0
Q
0
0
0
0
0
6364100
6182600
60C1100
5819600
_ S63AQ.OQ_ ...
4160400
3978900
3797400
3615800
363&30k2
3252800
3071300
2889800
2708200
252620Q
152088300
95011400
101194000
107195100
113014700
.11&6&22QO
122813100
126792000
130589400
1342C5200
,137638500
140892300
143963600
146853400
149561600
1S2QB&3UO
LIFETIME AVERAGE 1NCRFAJF (DECREASE) IN UNIT UP ER AT INC COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILCWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
UOLLAKS PER TON UF SULFUR REHUVtD
PROCESS COST DISCOUNTED AT 10. Gt TO INITIAL YCAR* DuLLtRS
LEVELIZED INCREASE IDtCkfcASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF GIL BURNED
MILLS PfcR KILOW(TT-HIUR
CENTS PEP MILLION BTL HEAT INPUT
bGLLA*S PER TON iif SULFUR. REPOVFD
EQUIVALENT TO
DISCOUNTED
2.24 0.
3.29 C.
35.74 0.
587.21 0.
70126200
PROCESS COST OVER LIFE
2.09 0.
3.07 0.
33.41 0.
549.15 0.
0
0
0
0
0
OF
0
0
0
0
2.24
3.29
35.74
587.21
70126200
POWER UNIT
2.09
3.07
33.41
549.15
-------
l.ible B-IOO. Lime Slurry Process
Summary of Estimated Fixed Investment3
(1,000-M W new oil-fired power unit, 2.5% S in fuel;
90% SOi removal; on-site solids disposal)
Investment, $
Percent of subtotal
direct investment
Lime receiving and storage (bins, feeders, conveyors,
and elevators)
Feed preparation (conveyors, slakers, tanks, agitators,
and pumps)
First stage sulfur dioxide scrubbers and inlet ducts (4
scrubbers including common feed plenum and pumps)
Second stage sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust gas
ducts to inlet of fans)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Calcium solids disposal (on-site disposal facilities
including slurry disposal pumps, pond, liner, and
pond water return pumps)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from the power plant)
Service facilities (buildings, shops, stores, site
811,000
394,000
5,358,000
4,247,000
431,000
780,000
3,420,000
244,000
4.7
2.3
31.1
24.7
2.5
4.5
19.9
1.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
699,000
819,000
17,203,000
1,376,000
1,720,000
860,000
1,548,000
22,707,000
1,817,000
1,817,000
26,341,000
4.1
4.8
100.0
8.0
10.0
5.0
9.0
132.0
10.6
10.6
153.2
"Basis:
Stuck gas reheat to 175 !•' by direct oil-fired reheat.
Disposal pond located I mile from power plant.
Midwest plant location represents project beginning mid-1972, ending mid-1975 Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
271
-------
Table B-101. Lime Slurry Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW new oil-fired power unit. 2.5% S in fuel;
90% S0j removal; on-site solids disposal)
Annual quantity
Unit cost, $
Total annual
cost. $
Direct Costs
Delivered raw material
Lime
Subtotal raw material
83.7 M tons 22.00/ton
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Process water
Electricity
Maintenance
Labor and material, .07 x 17,203,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
21,950 man-hr
4,128,000 gal
352,900 M gal
103,940,000 kWh
8.00/man-hr
0.23/gal
0.08/M gal
0.017/kWh
1341,400
1,841,400
175.600
949,400
28,200
1,767,000
1,204.200
51,800
4.176,200
6,017,600
aBasis:
Remaining life of power plant, 30 yr.
Oil burned, 9,731,500 bbl/yr, 8,700 Btu/kWh.
Slack gas reheat to 175°I-'.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant locution, 1975 operating costs.
Total capital investment, $26,341,000; subtotal direct investment, $17,203,000.
Working capital, $ 1,031,100.
Percent of
total annual
operating cost
17.05
17.05
1.63
8.79
0.26
16.37
11.16
0.48
38.69
55.74
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative, 10% of operating labor
Subtotal indirect costs
Total annual operating cost
Dollars/bbl
oil burned
Equivalent unit operating cost 1.11
3,924,800
835,200
17,600
4,777,600
10,795,200
Cents/million
Mills/kWh Btu heat input
1.54 17.73
36.36
7.74
0.16
44.26
100.00
Dollars/ton
sulfur removed
291.84
272
-------
Table B-102
LINE 5LUF.KY PROCESS, HOC Hk. NE» Pit FIRED POWER UNIT, 2.5* S IN FUEL, VO* S32 REMOVAL, REGULATED CO. ECONOMICS.
FIXED INVESTMENT:
26341COO
to
-j
U)
YEARS ANNUAL
AFTEB QPERA-
PDWER TUN,
UNIT K»-nR/
START K,.
1 7C.DO
2 7C&0
3 7COC
4 7CCO
5 2LLH
6 7COC
7 7CCO
8 7CCO
9 7i.CC
10 7f.f.P
11 5GDO
12 5CCO
13 SCCC
14 5 CCO
15. . SLGO
16 35CC
17 3500
18 3500
19 3500
_2Q 3S30
21 1530
22 1500
23 1500
24 1500
25 15.UQ
26 1500
27 1500
28 1500
29 15CO
10 I«OQ
TOT 127500
LIFETIME
PROCESS COST
LEVELI2ED
SULFUR
REMOVED
PC-VER UNIT fClhtR U.\1T BY
HEAT FUEL POLLUTION
RtfcUlhErtENT, CONSUMPTION. CONTRUL
MLLICN PTU BAhftELS PTL PROCESS,
/YEtK /YEAR TONS/YEAR
*-09CCCOu 9731500 37000
6091000C 97315C-? 37CCO
6091't'COr. 9731500 37030
609COOC-0 97315C.J 37000
b09LC: £3 32315-J'^ 33LQQ
fc09CCOCC 97315CO 37000
6C9CCCOC 97315, -J 37000
609'.ODOO 9731519 37COO
6C9UCJCJ 97?1500 370Jo
tpqi'iPrtp0, 97^1^*0 T7TTT
i.35COOCO 695110J 26400
435CCOOO 6951100 26400
A35CJOCO 6951100 26400
435000CO 69511CC 2640C
<-3^"D3f..T ^551100, fttt^O ^ ^
3045COOD 4J658CO 16500
JC450000 4e65BCO 16500
3C45000C 4*65600 13500
3C4EOOOO 41,6580'J 16503
3C^» r^QLQ ^H^'iflfifi Ifl^rtT
13050000 2085300 7900
13050000 2C8530C 7900
13050000 2CP5300 7900
1305U300 2C85300 7900
•13.253UCC 2U£S2CD 7S3Q
13050000 2085300 7900
13050000 2C85300 7900
13050000 2015300 7900
13050000 2C05300 7900
130SQGCQ _2C8S3JO "">00
1109250000 177252500 673500
BY-PRODUCT
RATE,
EQUIVALENT
TDNS/Yf AR
WASTE
SOLIDS
IfrOlGO
IbOlOO
180100
1B0100
-liQlQfl.
160100
IfsOlOO
160100
180100
i tn i no
128600
128600
126600
128600
IZ&fiOQ
90000
9COOO
90000
90000
-90QQQ
38600
38600
36600
38600
3860.0
38600
38600
38600
38603
^jt^hftn
3280000
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
t/TON ROI FOR
POWER
WASTE
iOLlOS
0.0
0.0
0.0
0.0
COMPANY,
S/YEAR
13535500
13352900
13170300
12987700
0,0 ipsninon
0.0
0.0
0.0
0.0
Q.Q ^
0.0
C.O
0.0
0.0
. ., - o . a
0.0
0.0
G.O
0.0
(KO
0.0
0.0
0.0
0.0
o.o
0.0
0.0
0.0
0.0
n.n
12622400
12439800
12257200
12074500
118919QQ
9925000
9742400
9559700
9377100
9194*00
7639200
7456500
7273900
7091300
TOTAL
NET
SALES
REVENUE,
I/YEAR
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IK COST OF IN COST OF
POWER,
*
13535500
13352900
13170300
12987700
j.2fiQ5QQO
12622400
12439800
12257200
12074500
POWER,
$
13535500
26888400
40058700
53046400
&S851&D.O
78473800
90913600
103170800
115245300
11891900 l?7H7?00
9925000
9742400
95597CO
9377100
(^ 1 gtc Qfj
7639200
7456500
7273900
7091300
137062200
146804600
156364300
165741400
1749?590f>
162575100
190031600
197305500
204396800
fc«Ofi7QO o fcQAA7nn ;uin*snn
4805400
462280C
4440200
4257600
^fi7coon
3(92300
3709700
3527100
3344500
%i At Ann
251141900
0
0
0
0
n
0
0
0
0
0
0
4805400
4622800
4440200
4257600
4Q2SQQO
3892300
3709700
3527100
3344500
^t i A i Ann
251141900
216110900
220733700
225173900
229431500
233504 500
237398SOO
241108500
244635600
247980100
2*i 1 1 4tl Qflfl
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF. OIL BURNED
RILLS HER KILCKATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON UF SULFUR REMOVbO
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
HILLS PEK KILUWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON CF SULFUR REMOVED
EQUIVALENT TO
DISCOUNTED
1.42
1.97
22.64
372.89
103411900
PROCESS COST OVER
1.36
1.88
21.66
356.72
0.0
0.0
0.0
0.0
0
LIFE OF
C.O
0.0
0.0
0.0
1.42
1.97
22.64
372.89
103411900
POWER UNIT
1.36
1.88
21.66
356.72
-------
Table B-103. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment2
(200-MW new coal-fired power unit, 3.5% S in fuel;
90% SO2 removal; 6.5 tons/hr IOO%HtSO4)
Investment, $
Percent of subtotal
direct investment
274
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (2 scrubbers including
common feed plenum, effluent hold tanks, agitators, pumps,
and fly ash neutralization facilities)
Sulfur dioxide scrubbers and ducts (2 scrubbers
including mist eliminators, pumps, and exhaust
gas ducts to inlet of fan)
Stack gas reheat (2 indirect steam reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2 S04 )
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
"Basis:
Stark gas rchcul lo 175 !•' hy indirect sloani reheat.
Midwest plant location represents projects beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Hy ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
105,000
134,000
1,761,000
1,143,000
214,000
327,000
384,000
553,000
643,000
1,787,000
151,000
166,000
1.3
1.6
21.2
13.7
2.6
3.9
4.6
6.6
7.7
21.5
1.8
2.0
557,000
396,000
8,321,000
1,082,000
1,082,000
582,000
915,000
11,982,000
1,198,000
959,000
14,139,000
6.7
4.8
100.0
13.0
13.0
7.0
11.0
144.0
14.4
11.5
189.9
-------
Table B-104. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs—Regulated Utility Economics3
(200-MWnew coal-fired power unit, 3.5% S in fuel;
90% SOT. removal; 45,200 tons/yr 100% HIS04)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw material
Lime (1st stage neutralization)
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Steam
Heat credit
Process water
Electricity
Maintenance
55
448
312
736
30,440
2,190,000
180,000
8,300
902,700
tons 26.00/ton
tons 155.00/ton
tons 15.00/ton
liters 1.65/liter
man-hr 8.00/man-hr
gal 0.23/gal
M Ib 0.80/M Ib
MM Btu -0.60/MM Btu
M gal O.Oe/M gal
29,050,000 kWh 0.01 1/kWh
Labor and material, .08 x 8,321 ,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
100%H2SO4
105.68
Dollars/ton
coal burned Mills/kWh
8.90 3.41
1,400
69,400
4,700
1,200
76,700
243,500
503,700
144,000
(5,000)
54,200
319,600
665,700
54,000
1,979,700
2,056,400
2,106,700
395,900
217,800
2,720,400
4,776,800
Cents/million
Btu heat input
37.09
0.03
1.45
0.10
0.03
1.61
5.10
10.54
3.01
(0.10)
1.13
6.69
13.94
1.13
41.44
43.05
44.10
8.29
4.56
56.95
100.00
Dollars/ton
sulfur removed
323.85
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°!'.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, l')75 operating costs.
Total capital investment. $l4,l39.000:sul>tolal direct investment, $8.321,000.
Working capital. $363,900.
Investment and operating cost for disposal of lly usli excluded.
275
-------
Table B-105
MAGNESIA SLURRY-REGENERATION PROCESS. 20C MW NEW COAL FIRED POWER UNIT, 3.5* S IN FUEL, 9Ct S02 REMOVAL, REGULATED CO ECQN.
FIXED INVESTMENTS $ 14139000
YEARS ANNUAL POWER UNIT
AFTER OPERA- HEAT
POWER TION, EQUIREMENT,
UNIT KW-HR/ MILLION BTU
START KW /YEAR
1
2
3
4
6
7
8
9
-10.-
11
13
-IS.
16
17
18
19
-2LO-
21
22
23
24
-25.
26
27
28
29
7000
7000
7000
7000
2000
7000
7000
7000
7000
zaoa
5000 '
5000
5000
5.000
. - SOQO., .
3500
3500
3500
3500
35.00.
1500
1500
1500
1500
. -15QO.
1500
1500
1500
1500
12880000
12880000
12880000
12880000
I2£flflUQQ_-
12880000
12880000
12880000
12880000
12B&QQQQ
9200000
9200000
9200000
9200000
6440000
6440000
6440000
6440000
fc&faOQnn
2760000
2760000
2760000
2760000
-2260000.-.
2760000
2760000
274000C
27600CO
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT BY EQUIVALENT
FUEL POLLUTION TONS/YEAR
CONSUMPTION. CONTROL
TONS COAL PROCESS, 100*
/YEAR TONS/YEAR H2S04
536700
536700
536700
536700
536700
536700
536700
5367CO
383300
383300
383300
383300
268300
268300
268300
268300
115000
115000
115000
115000
115000
115000
115000
115000
115002- —
14700
14700
14700
14700
14700
14700
14700
14700
IfclQQ
10500
10500
10500
10500
10500.
7400
7400
7400
7400
3200
3200
3200
3200
_.. . . 3200. . _
3200
3200
3200
3200
45200
45200
45200
45200
.„ 452QQ.
45200
45200
45200
45200
32300
32300
32300
32300
323QG
22600
22600
22600
22600
9700
9700
9700
9700
97OO
9700
9700
9700
9700
NET REVENUE,
i/TON
100*
H2S04
8.00
8.00
8.00
8.00
a... DO
8.00
8.00
8.00
8.00
a 00
8.00
8.00
8.00
8.00
a.oo. .
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
*/YEAR
NET ANNUAL CUMULATIVE
TOTAL INCREASE NET INCREASE
NET (DECREASE) (DECREASE)
SALES IN COST OF IN COST OF
REVENUE, POWER, POKER,
i/YEAR $ $
6247700 361600
6149700 361600
6051700 361600
5953600 361600
5fl556QQ. . 36MOQ
575760C 361600
5659500 361600
5561500 361600
5463500 361600
53654DQ . *fcl«.on
4636100
4538100
4440000
4342000
42A&aoa
8.00 3647600
8.00 3549500
8.00 3451500
8.00 3353500
B.GQ ,, 3?55400
8.00
8.00
8.00
8.00
__ « ^^ 8 » QO. . .
8.00
8.00
8.00
8.00
.2427800
2329800
2231700
2133700
1937700
1839600
1741600
1643600
258400
258400
258400
258400
2SBA.QO.
180800
180800
180800
180800
77600
77600
77600
77600
._ Z2&QO
77600
77600
77600
77600
5886100
5788100
5690100
5592000
5396000
5297900
5199900
5101900
4377700
4279700
41816CO
4083600
3SB56QO
5886100
11674200
173643CO
22956300
33846300
39144200
44344100
49446000
58827500
631C7200
67288800
71372400
7S«ftnnn
3466800 78824800
3368700 82193500
327C7CO 854642&0
3172700 88636900
_3Q2AiQQ 912115UO
2350200 94061700
2252200 96313900
2154100 98468000
2056100 1005241CO
1860100
1762000
1664000
1566000
104342300
106104300
107768300
109334300
llfl£Q22CO
TOT 127500 2346COOOO 9775000 268500 S23SOO
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILOWATT-HCUR
CENTS PER MILLION BTl; HEAT 1NPU1
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0% TO INITIAL YEAR, DOLLARS
117390200 6588000
12.01
4.60
50.04
437.21
47694800
0.67
0.25
2.81
24.54
2834500
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER TON OF CCAL BURNED 11.34 0.68
KILLS PER KILDWATT-HCUR 4.35 0.26
CENTS PER MILLION BTt HEAT INPUT 47.24 2.80
DOLLARS PER TON OF StLFUR REMOVED 413.66 24.59
110802200
11.34
4.35
47.23
412.67
44B6C300
POWER UNIT
10.66
4.09
44.44
389.07
-------
Table B 106. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment9
(200-M W existing coal-fired power unit. 3.5% S in fuel;
90% SOi removal; 6.7 tons/hr 100% HrfO*)
Investment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (2 scrubbers including
common feed plenum, mist eliminators, pumps, and all ductwork
between outlet of supplemental fan and stack gas plenum)
Stack gas reheat (2 direct oil-fired reheaters)
Fans (2 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H7 SO4)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
116,000
153,000
1,983.000
129,000
493,000
429,000
610,000
706.000
2,032,000
180,000
282,000
1.4
1.9
24.4
1.6
6.1
5.3
7.5
8.7
25.0
2.2
3.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
620,000
387,000
8,120,000
1,137,000
1,218,000
731,000
974,000
12,180,000
1,218,000
974,000
14,372,000
7.6
4.8
100.0
14.0
15.0
9.0
12.0
150.0
15.0
!2.0
177.0
aBasis:
Slack gas reheat to I75°r by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-i975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps arc spared.
Remaining life of power unit, 20 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
277
-------
Table 8-107. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW existing coal-fired power unit, 3.5% S in fuel;
90% SO* removal; 46,600 tons/yr 100% #2S04 ;
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw material
Magnesium oxide (98%) 463 tons 155 .00 Aon
Coke 322 tons 15. 007 ton
Catalyst 760 liters 1.65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 30,440 rr.an-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 3,783,000 gal 0.23/gal
Heat credit 8,600 MM Btu -0.60/MM Btu
Process water 931 ,400 M gal 0.06/M gal
Electricity 19,500 ,000 kWh 0.011/kWh
Maintenance
Labor and material, .08 x 8,120,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 5.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
Equivalent unit operating cost 109.25 9.19 3.64
71,800
4,800
1,300
77,900
243,500
870,100
(5,000)
55,900
214,500
649,600
54,000
2,082,600
2,160,500
2,285,100
416,500
229,100
2,930,700
5,091,200
Cents/million
Btu heat input
38.28
1.41
0.09
0.03
1.53
4.78
17.10
(0.10)
1.10
4.21
12.76
1.06
40.91
42.44
44.88
8.18
4.50
57.56
100.00
Dollars/ton
sulfur removed
334.29
aBasis:
Remaining life of power plant, 20 yr.
Coal burned, 554,200 tons/yr. 9,500 Blu/kWh.
Stack gas reheat to 175°K
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $14,372,000; subtotal direct investment, $8,120,000.
Working capital, $382,200.
Investment and operating cost for removal and disposal of fly ash excluded.
278
-------
Table B-108
MAGNESIA SLURRY-REGENERATION PROCESS, 20C MW EXISTING COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* 302 fcEMOVAL, REGULATED CO ECON.
FIXED INVESTMENT:
14372000
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWER TION. REQUIREMENT, CONSUMPTION, CONTROL
UNIT Kk-HR/ MILLION BTU TONS COAL PROCESS,
START KW /YEAR /YEAR TONS/YEAR
1
2
3
4
6
7
8
9
11 5000 95COOOO 395800 10900
12 5COO 9500000 395800 10900
13 5000 9500000 395800 10900
14 5000 9500000 395800 10900
IS - 50QQ 95.0QQOQ , J^jftna . -10.9.0.0
16 3500 6650000 277100 7600
17 3500 6650000 277100 7600
IS 3500 6650000 277100 7600
19 3500 4650000 277100 7600
20 3SQQ 66*QQQQ ?77Ifin 7&QO
21 1500 2850000 118700 3300
22 1500 2850000 118700 3300
23 1500 2850000 118700 3300
24 1500 2850000 J18700 3300
_2*» 15.0.Q 2ASQQQO ll£?QQ 33.0.0
26 1500 2850000 118700 3300
27 1500 2850000 1187CO 3300
28 1500 2850000 118700 3300
29 1500 2850000 118700 3300
3.0. 15.00 7BS.OQOQ .118703- .. 33.QQ
TOT ',7500 109250000 4551500 125500
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
100*
H2S04
33300
33300
33300
33300
^^^Ofl
23300
23300
23300
23300
23300
10000
10000
10000
10000
loaao.
10000
10000
10000
10000
10QOQ
383000
NET REVENUE,
S/TON
100*
H2S04
8.00
8.00
$.00
8.00
ft -0.0
.00
.00
.00
.00
• 00
.00
.00
.00
.00
.00
.30
.00
.oc
.00
TOTAL
OP. COST
INCLUDING
REGULATED TOTAL
RC1 FOR NET
POWER SALES
COMPANY, REVENUE,
$/YEAR »/YEAR
5913400 266400
5763900 266400
5614400 266400
5465000 266400
5315500 26fc&QC
4637400 186400
4488000 186400
4338500 186400
4189000 186400
&034600 1B64QD
3121200 80000
2971700 80000
2822300 80000
2672800 8COOO
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
*
5647000
5497500
5348000
51986.00
§ ftiQ 1 CD
4451000
4301600
4152100
4002600
3A532QQ
3041200
2891700
2742300
2592800
25233QO .. «OCQOr ^t43-»nn
2373800 80COO
2224400 80000
2074900 80000
1925400 80000
2293800
2144400
1994900
1845400
lOO |77«,qnn noaoo Jt^QOO.
76250500 3064000 71186500
CUMULATIVE
NET INCREASE
(DECREASE I
IN COST OF
POWER,
*
5647000
11144500
16492500
2 1691 ICO
?<* 7t n?t *"}
31191200
3549280C
39644900
4364 7 5'. 0
&25LL2tD
50541900
534336.0
56175900
58766700
61212D2C
63505800
65650200
67645100
6949 C5 CO
7.118.6,50.0
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
LEVEL1ZED INCREASE (DECREASE I IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
HILLS PER KUDWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
EQUIVALENT TO
16.31 0.67
6.46 U.27
67.96 2.80
591.64 24.42
37744300 1636100
DISCOUNTED PROCESS COST OVER LIFE OF
15.51 0.67
6.14 0.27
64.61 2.80
563.35 24.45
15.64
6.19
65.16
567.22
36106200
POWER UNIT
14.84
5. 87
61. 81
538.90
-------
Table B-109. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(500-M W existing coal-fired power unit, 3.5% S in fuel;
^ removal; /ft./ tonx/hr 100% 11
Investment, $
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
common feed plenum, mist eliminators, pumps, and all ductwork
between outlet of supplemental fan and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgSO.i storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulf uric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2S04 )
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Coristruction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
210,000
270,000
4,469,000
305,000
1,112,000
789,000
1,065,000
1,211,000
3,608,000
329,000
454,000
867,000
734,000
15,423,000
1,851,000
2,005,000
1,080,000
1,697,000
22,056,000
2,206,000
1.764,000
26,026,000
Percent of subtotal
direct investment
1.4
1.7
29.0
2.0
7.2
5.1
6.9
7.9
23.4
2.1
2.9
5.6
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
"Basis:
Stuck gas reheat to 175 !•' l>v iliriTl oil-l'ired reheat.
Miilwesl plant location represents project beginning mid-1972, ending mid-l97&- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of IIy ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
280
-------
Table B-110. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs—Regulated Utility Economics3
(500-MW existing coal-fired power unit, 3.5% S in fuel;
90% SOt removal; 112,900 tons/yr 100%H2SO4)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium oxide (98%) 1,1 10 tons 155.00/ton
Coke 780 tons 15.00/ton
Catalyst 1 ,840 liters 1 .65/1 iter
Subtotal raw material
Conversion costs
Operating labor and
supervision 39,200 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 9,160,000 gal 0.23/gal
Heat credit 20,800 MM Btu -0.60/MM Btu
Process water 2,256,100 M gal 0.04/M gal
Electricity 47,230,000 kWh 0.010/kWh
Maintenance
Labor and material, .07 x 15,423,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
Equivalent unit operating cost 85.10 7.16 2.75
172,100
11,700
3,000
186,800
313,600
2,106,800
(12,500)
90,200
472,300
1,079,600
102,000
4,152,000
4,338,800
3,982,000
830,400
456,700
5,269,100
9,607,900
Cents/million
Btu heat input
29.84
Percent of
total annual
operating cost
1.79
0.12
0.03
1.94
3.26
21.93
(0.13)
0.94
4.92
11.24
1.06
43.22
45.16
41.45
8.64
4.75
54.84
100.00
Dollars/ton
sulfur removed
260.66
"Basis:
Remaining life of power plant, 25 yr.
Coal burned, 1,341,700otons/yr, 9,200 Btu/kWh.
SUck gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment. $26,026,000; subtotal direct investment, $15,423,000.
Working capital, $768,100.
Investment and operating cost for removal and disposal of fly ash excluded.
281
-------
S)
00
to
Table B-111
MAGNESIA SLURRY-REGENERATION PROCESS, 50C HH EXISTING COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL. REGULATED CO ECON.
FIXED INVESTMENTS i 26026000
YEARS ANNUAL
AFTER OPERA-
POritR TIGN,
UNIT KH-HR/
START Kh
1
2
3
4
-------
Table B-112. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment2
(500-MW new coal-fired power unit. 2.0% S in fuel;
90%S02 removal; 9.0 tons/hr 100%H2SOA)
Investment, $
Percent of subtotal
direct Investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers including
common feed plenum, effluent hold tanks, agitators, pumps,
and fly ash neutralization facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust
gas ducts to inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2S04 )
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
132,000
166,000
3,966,000
2,592,000
509,000
741,000
484,000
684,000
788,000
2,222,000
190,000
269,000
0.9
1.2
27.9
18.3
3.6
5.2
3.4
4.8
5.6
15.6
1.3
1.9
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
783,000
676,000
14,202,000
1,562,000
1,562,000
710,000
1,420,000
19,456,000
1,946,000
1 ,556,000
22,958,000
5.5
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
aBasis: 0
Stack gas reheat to 175 !•' by indirect steam reheat.
Midwest plant location represents projects beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974-
Minimum in process storage; only pumps are spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
283
-------
Table B-113. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics9
(500-MW new coal-fired power unit, 2.0% Sin fuel;
90% SO^ removal; 63,100 tonsjyr 100%HtSO*)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw material
Lime (1st stage neutralization)
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Steam
Heat credit
Process water
Electricity
Maintenance
77 tons 26.00/ton
620 tons 155.00/ton
436 tons 15.00/ton
1,029 liters 1.65/liter
32,520 man-hr 8.00/man-hr
3,061 ,000 gal 0.23/gal
440,000 M Ib 0.70/M Ib-
1 1 ,600 MM Btu -0.60/MM Btu
1, 350,000 M gal 0.05/M gal
63,270,000 kWh 0.010/kWh
Labor and material, .07 x 14,202,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing.
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
119.23 5.73 2.15
2,000
96,100
6,500
1,700
106,300
260,200
704,000
308,000
(7,000)
67,500
632.700
994,100
91,200
3,050,700
3,157,000
3,420,700
610,100
335,600
4,366,400
7,523,400
Cents/million
Btu neat input
23.88
0.03
1.27
0.09
0.02
1.41
3.46
9.36
4.09
(0.09)
0.90
8.41
13.21
1.21
40.55
41.96
45.47
8.11
4.46
58.04
100.00
Dollars/ton
sulfur removed
365.04
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, l,312,50CMons/yr, 9,000 Blu/kWh.
Stack gas reheat to 175° F.
Power unit on-stieam time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $22,958,000;subtotal direct investment. $14,202,000.
Working capital, $558,400.
Investment and operating cost for disposal of fly ash excluded.
284
-------
Table B-114
MAGNESIA SLURRY-REGENERATION PROCESS. 50C HW NEW COAL FIRED POWER UNIT, 2.OX S IN FUEL, 90* S02 REMOVAL, REGULATED CO ECGN.
FIXED INVESTMENT:
22958000
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
PDiER T1DN, REQUIREMENT, CONSUMPTION, CONTROL
UNIT K»-HR/ MILLION BTU TONS COAL PROCESS,
START KW /YEAR /YEAR TONS/YEAR
1 7000 3150COOO 1312500 20600
2 7000 31500000 1312500 20600
3 7COO 31500300 1312500 20600
4 7COO 315COOCO 13125CO 20600
^ 7CQO 315COORQ , nuson ... .20600
6 7000 315COOOO 1312500 20600
7 7COO 315CODOO 1312500 20600
c. 7COO 315COOOO 1312500 20600
9 7000 315CCOOO 131250C 20600
l.T 70CQ 315.CQQOO... 13125.00 ?o*>on
11 500C i25COOOO S37500 1*700
li 5COO 225COOOO 937500 1*700
13 5000 225COOOO 937500 1*700
14 5000 225COOOO 937500 1*700
_L5 5QOQ 2?SCQQOO . 9375QO . 147QQ
16 3500 15750000 656200 10300
17 3500 15750000 656200 10300
18 3500 157500CO 656200 10300
19 3500 157500CO 656200 10300
2(1 3500 157SOOQQ h5fe?r?n 10300
21 1500 67*0000 261200 4400
2? 1500 6750000 261200 4400
23 1500 6750000 281200 4400
24 1500 6750000 281200 4400
26 1500 6750000 281200 4400
27 1500 6750000 261200 4400
28 1500 6750000 281200 4400
29 1500 6750000 281200 4400
^30 J^1500 , 6750000 ,.^?»>'OP -, A40Q ..--
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
loot
H2SO*
63100
63100
63100
63100
6.310Q _
63100
63100
63100
63100
45100
45100
45100
45100
45100 _
31500
31500
31500
31500
31500
13500
13500
13500
13500
13501
13500
13500
13500
13500
t«nn
IDT 12750C 573750000 23905500 375000 1149000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SLLFUR RtKQVtD
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
> DOLLARS PER TON OF SLLFUR REMOVED
TOTAL
OP. COST
INCLUDING NET ANNUAL
NET REVENUE, REGULATED TOTAL INCREASE
I/TON RC1 FOR NET (DECREASE)
POWER SALES IN COST OF
100% COMPANY, REVENUE, POWER,
H2S04 I/YEAR S/YEAR S
8.00
8.00
8.00
8.00
8.00
6.00
8.00
8.00
a^oo.-
8.00
8. CO
8.00
8.00
A^QO
8.00
8.00
8.00
8.00
8^.00.
.00
.00
^00
.00
.00
.00
.00
.00
.00
DISCOUNTED
9912100 50*800
9752900 50*800
9593700 504600
9*3*500 504800
927530P 5Q6.fi.QO
9116200 50*600
8957000 50*800
8797800 50*800
8638600 50*800
B429400 5Q48QQ
7326400 360800
7167300 360800
7CC8100 360800
6848900 360800
5751600 252COC
5592400 252COO
5433300 252COO
5274100 252000
5J.1430Q 252COQ
3627200 136000
3668000 108000
3508900 108COO
3349700 10800U
519.05QQ 1Q8COO
3031300 106000
2872100 108000
2712900 108000
2553800 106000
,. >>«4*>nn IO«OOQ
9*07300
92*8100
9088900
8929700
8611*00
8*52200
8293000
8133800
jai&tao.
6965603
6806500
664730G
6488100
5*99600
53*0*00
5181300
5022100
3719200
3560000
3*00900
32*1700
3082500
2923300
276*100
260*900
2445600
228*600
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
I
9*07300
18655*00
277*4300
36674:09
54055900
625G8100
70601100
78934900
93875100
100681630
107328900
113817000
120145300
125645500
1309659CO
136167200
141189300
149771400
153331400
156732330
15997* 000
16.3QS6.SQO
165979800
1687*3900
1713*8800
17379*600
IJfcQBl^aO
19S7732CO 9192000 176081200
7.75 0.38 7.37
2.91 0.15 2.76
32.29 1.60 30.69
494.06 24.51 469.55
75460000 3956400 71503600
PROCESS COST OVER LIFE OF POWER UNIT
7.34 0.39 6.95
2.75 O.I* 2.61
30.56 1.60 26.96
467.53 2*. 51 443.02
-------
Table B-115. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment9
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% SO^ removal; 15.8 tons/hr 100%H2SOA)
Investment, $
Percent of subtotal
direct investment
286
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers including
common feed plenum, effluent hold tanks, agitators, pumps,
and fly ash neutralization facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust
gas ducts to inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
aBasis:
Stack gas reheat to 175°!-' by indirect steam reheat.
Midwest plant location represents projects beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Fly ash slurry neutralized before disposal: closed loop water utilization for first stage.
Investment requirements tor disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
192,000
238,000
3,966,000
2,592,000
509,000
741,000
711,000
972,000
1,108,000
3,197,000
278,000
269,000
1.2
1.5
24.3
15.9
3.1
4.5
4.3
5.9
6.8
19.6
1.7
1.6
783,000
778,000
16,334,000
1,797,000
1,797,000
817,000
1,633,000
22,378,000
2,238,000
1,790,000
26,406,000
4.8
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
-------
Table B-116. Magnesia Slurry -Regeneration Process
Tot.il Average Annual Operating Costs -Regulated Utility Economics3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; 110,400 tons/yr 100%HtSO4)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw material
Lime (1st stage neutralization)
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
' Operating labor and
supervision
" Utilities
Fuel oil (No. 6)
Steam
Heat credit
Process water
Electricity
Maintenance
134
1,086
763
1,800
39,200
5,356,000
440,000
tons 26.00/ton
tons 155.00/ton
tons 15.00/ton
liters 1.65/liter
man-hr 8.00/man-hr
gal 0.23/gal
M Ib 0.70/M Ib
20,300 MM Btu -0.60/MM Btu
2,207,500
71,060,000
M gal 0.04/M gal
kWh 0.010/kWh
Labor and material, .07 x 16,334,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
100%H2SO4
83.43
Dollars/ton
coal burned Mills/kWh
7.02 2.63
3,500
168,300
11,400
3,000
186,200
.
313,600
1,231,900
308,000
(12,200)
88,300
710,600
1,143,400
102,000
3,885,600
4,071,800
3,934,500
777,100
427,400
5,139,000
9,210,800
Cents/million
Btu heat input
29.24
0.04
1.83
0.12
0.03
2.02
3.40
13.39
3.34
(0.13)
0.96
7.71
12.41
1.11
42.19
44.21
42.71
8.44
4.64
55.79
100.00
Dollars/ton
sulfur removed
2S5.43
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500otons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $26,406,000; subtotal direct investment, $16,334,000.
Working capital, $721,000.
Investment and operating cost for disposal of fly ash excluded.
287
-------
l-J
00
oo
Table B-117
MAGNESIA SLURRY-REGENERATION PROCESS, 50C HU NEM COAL FIRED POWER UNIT, 3.5X S IN FUEL, 90k S02 REMOVAL, REGULATED CO ECL'N.
FIXED INVESTMENT:
26406000
YEARS ANNUAL
AFTER OPERA-
PGWER riON,
UNIT KW-HR/
START KW
1
2
3
4
5
6
7
8
9
_ia
11
12
13
_li
16
17
IB
19
-2&
21
22
23
24
26
27
28
29
TOT
PRO
7000
7000
7000
7000
10.QQ
7000
7000
7COO
7000
2C.O.&
5COC
5COO
5000
5000
SfiCQ
3500
3500
3500
3500
. 350Q
1500
1500
1500
1500
15QC.-
1500
1500
1500
1500
127500
LIFETIME
CESS COST
LEVELIZED
PCWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION
MILLION BTU TONS COAL
/YEAR /YEAR
31500000 1312500
31500000 1312500
315COOOO 1312500
31500000 1312500
315C.QQDO Hl2sr>fl
31500000 1312500
31500000 1312500
31500000 1312500
315COOOO 1312500
315000fto I'I'SQO
SULFUR BY-PRODUCT
REMOVED RATE,
BY EQUIVALENT
POLLUTION TONS/YEAR
, CONTROL
PROCESS, 100*
TONS/YEAR H2S04
36100
36100
36100
36100
36100
36100
36100
36100
ifcinn
22SOOOCO 937500 25800
22500000 937500 25800
225COOOO 937500 25800
2250COOO 937500 25800
72SGQQCG S375.CD JSaOO
15750000 656200
15750000 656200
15750000 656200
157500CO 656200
6750000 281200
6750000 281200
6750000 281200
6750000 281200
6750000 ?«l?nn
6750000 281200
6750000 281200
6750000 281200
6750000 281200
6250QCC— . ?«i?nn
573750000 23905500
AVERAGE INCREASE (DECREASE
DOLLARS PER TON OF
MILLS PER KILOWATT
CENTS PER MILLION
DOLLARS PER TON OF
DISCOUNTED AT 10.0* TO I
INCREASE (DECREASE) IN UN
DOLLARS PER TON OF
MILLS PER KILOWATT
CENTS PER MILLION
DOLLARS PtR TON OF
18000
18000
18000
18000
7700
7700
7700
7700
27.0.0
7700
7700
7700
7700
110400
110400
110400
110400
11Q4.QQ
110400
110400 .
1104CO
110400
-11Q40.0
78900
78900
78900
78900
55200
55200
55200
55200
23700
23700
23700
23700
23700
23700
23700
23700
657000 20115.00
) IN UNIT OPERATING COST
CCAL BURNED
-HCUR
BTU HEAT INPUT
SILFUR REMOVED
NIT1AL YEAR, DOLLARS
IT OPERATING COST EQUIVALENT TO
CCAL BURNED
-HLUR
BTL HEAT INPUT
SILFUR REMOVED
MET REVENUE*
(/TON
H2S04
a.
8.
8.
8.
8.
8.
8.
8.
00
00
00
00
00
00
00
00
QQ
8.00
8.00
8.00
8.00
........ B -QD
8.
8.
8.
8.
».
•
•
•
.
•
00
00
OG
00
00.
00
00
00
00
QQ
00
00
00
00
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY.
(/YEAR
11957900
11774900
11591800
11408700
11042500
10859500
10676400
10493300
IQ31Q?QQ
NET ANNUAL CUMULATIVE
TOTAL INCREASE NET INCREASE
NET (DECREASE) (DECREASE)
SALES IN COST OF IN COST OF
REVENUE, POWER, POWER,
(/YEAR * S
883200
883200
883200
883200
883200
883200
883200
883200
BB3?nQ
8827600 631200
8644600 631200
8461500 631200
8278400 631200
,_ .BO.S5.3.QQ- fc^uon
6897800
6714700
6531700
6348600
6165500 —
4526300
4343200
4160200
3977100
3294CQO...
3610900
3427800
3244700
3061700
2«3«fcOQ
223331000
9.34
3.50
38.92
339.93
91172800
DISCOUNTED PROCESS COST OVE
8.86
3.32
36.93
322.28
441600
441600
441600
441600
441630
189600
189600
189600
189600
lastojQ
1*9600
189600
189600
189600
__i«96.ao.__
16092000
C.67
0.25
2.80
24.50
6923300
R LIFE OF
0.67
0.25
2.81
24.47
11074700
10891700
10708600
10525500
1015930C
9976300
9793200
9610100
&&22Q.O.O
8196400
8013400
78303CO
7647200
6456200
6273100
609C1CO
5907000
5223400 _
4336700
415360C
39706CO
3787500
342130'.
323820C
305510C
28.72100
«^6fi9COu
20723900C
6.67
3.25
36. 12
315.43
84249500
POWER UMT
8. 19
3.C7
34. 12
297.61
11C74700
21966430
32675'iO
432C05JO
_535423LC
637C2200
736785, C
834717CO
930f 1803
1107C5200
1187186-3
12654B9TO
134 196 1JO
lfc!66.L2LO
1461 H4 .0 '
1543E?5Ju
1604796^0
i e '. 6 : c s ; o
If 8i£*5:0
2016779'C
20455 r :: i
-------
Table B-118. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 5.0% S in fuel;
90% SO-i removal; 22.5 tons/hr 100% //2SO,)
Investment, $
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers including
common feed plenum, effluent hold tanks, agitators, pumps,
and fly ash neutralization facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust
gas ducts to inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgSOj storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of HjSC^)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total_capital inyestment__ _
"Basis:
Slack gas reheat to I7s"l; hy indirect steam reheat.
244,000
299,000
3,966,000
2,592,000
509,000
741,000
910,000
1,218,000
1,378,000
4,031,000
354,000
269,000
783,000
865,000
18,159,000
1,997,000
1,997,000
908,000
1,816,000
24,877,000
2,488,000
1,990,000
29,355,000
Percent of subtotal
direct investment
1.3
1.6
21.8
14.3
2.8
4.1
5.0
6.7
7.6
22.2
2.0
1.5
4.3
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
Midwest plant location represents projects beginning mid-1972. ending mid-1975 Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
I'ly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
289
-------
Table B-119. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 5.0% Sin fuel;
90% S0i removal; 157,800 tons/yr 100%H^S04)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime (1st stage neutralization) 192 tons 26.00/ton
Magnesium oxide (98%) 1,551 tons 155.00/ton
Coke 1,090 tons 15.00/ton
Catalyst 2,571 liters 1.65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 45380 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 7,652,000 gal 0.23/gal
Steam 440,000 M Ib 0.70/M Ib
Heat credit 29,000 MM Btu -0.60/MM Btu
Process water 3,063,900 M gal 0.03/M gal
Electricity 78,850,000 kWh 0.010/kWh
Maintenance
Labor and material, .07 x 18,159,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
Equivalent unit operating cost 68.24 8.20 3.08
5,000
240,400
16,400
4,200
266,000
367,000
1,760,000
308,000
(17,400)
91,900
788,500
1,271,100
109,200
4,678,300
4,944,300
4,373,900
935,700
514,600
5,824,200
10,768,500
Cents/million
Btu heat input
34.19
Percent of
total annual
operating cost
0.05
2.23
0.15
0.04
2.47
3.41
16.35
2.86
(0.16)
0.85
7.32
11.80
1.01
43.44
45.91
40.62
8.69
4.78
54.09
100.00
Dollars/ton
sulfur removed
209.02
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $2').155,000; subtotal direct investment. $18.159,000.
Working capital, $K76,200.
Invest men I and operating cosi for disposal of fly ash excluded.
290
-------
Table B-120
KAGNES1A SLURRY-REGENERATION PROCESS. 50C MW NEW COAL FIRED POWER UNIT, 5.0* S IN FUEL, 90* 502 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENT:
29355000
YEARS
AFTER
POWER
UK IT
START
1
2
3
4
5
6
7
3
9
_10
11
12
13
14
_li _.
16
17
18
19
_2Q
21
22
23
24
?5, r
ANNUAL
OPERA-
TION,
Kh-HR/
KW
7000
7000
7000
7000
— 2UOQ
7000
7000
7000
7000
—2000.
5000
sooo
5000
5000
— 5COO
3500
3500
3500
3500
i50fl
1500
1500
1500
1500
15QO
PCWER UNIT
HEAT
REQUIREMENT,
MULICN BTU
/YEAR
31500000
31500000
315COOOO
31SOOOCO
_315CCQCO~
315COOCC
315COOOO
31500000
31500000
3J.5CQQOU
22500000
225COOOO
22500000
22500000
22500QC0 .
15750000
1575000C
15750000
15750000
1&25Q0C0
6750000
6750000
6750000
6750000
fcicnaoo
•26 1500 6750000
27 1500 6750000
28 1500 6750000
29 1500 6750000
-30 150Q 6250000-..
POWER UNIT
FUEL
CONSUMPTION,
TONS COAL
/YEAR
1312500
1312500
1312500
1312500
1312500
1312500
1312500
1312500
1312500
937500
937500
937500
937500
9^7500
656200
656200
656200
656200
, _ 65.62QQ
281200
281200
281200
281200
281200
281200
281200
281200
7*1200 ,
SULFUR
REMOVED
BY
POLLUTION
CONTROL
PROCESS,
TONS/YEAR
51500
51500
51500
51500
.51500 ,
51500
51500
51500
S1500
51SOQ
36800
36800
36800
36800
36&aO
25800
25800
25800
25800
25800-..
11000
11000
11000
11000
110QQ
11000
11000
11000
11000
11000
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
100*
H2S04
157800
157800
157800
157800
157800
157800
157800
157800
157800
112700
112700
112700
112700
112200
78900
78900
78900
78900
„ _ 2BSQQ
33800
33800
33800
33800
33*00
33800
33800
33*00
NET REVENUE
$/TON
100*
H2S04
8.00
8.00
8.00
8.00
^^00
8.00
8.00
8.00
8.00
4*00 —
8.00
8.00
8.00
8.00
4*00 —
8.00
a. oo
8.00
a. 00
a. *oo
a. oo
8.00
a. oo
a. oo
l.po
a. oo
a. oo
*.oo
*.oo
t.oo
TOTAL
OP. COST
INCLUDING
, REGULATED
ROI FOR
POWER
COMPANY,
$/YEAR
13822400
13618900
13415400
13211900
13008300
TOTAL
NET
SALES
REVENUE,
*/YEAR
1262400
1262400
1262400
1262400
_ 12(,2<.DD
12804800 1262400
12601300 1262400
12397700 1262400
12194200 1262400
11320200 1262400
10194600 901600
9991000 901600
9787500 901600
9584000 901600
st2aa4QQ aoafcOfl
7937900 631200
7734400 631200
7530900 631200
7327300 631200
5151100
4947600
4744000
4540500
4133400
3929900
3726400
3522900
270400
270400
270400
270400
270400
270400
270400
270400
210400
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN CDST OF
POWER, POWER,
» S
125600CO
12356500
12153000
11949500
— 1124SaOJ
11542400
11338900
11135300
10931800
10224300
9293000
9089400
8885900
8682400
7306700
7103200
6*99700
6696100
-6692600
4880700
4677200
4473600
4270100
3863000
3659500
3456000
3252500
- 304*300
12560000
249165C3
370695CO
490190'.0
723C73i:0
83646200
94781530
105713300
-_LL64416uO
125734600
1348240CO
1437C9900
152392300
168177800
175281000
182180700
188876800
.-135363630
2002501CO
204927300
209400900
213671000
2216006CD
225260100
228716100
231968600
.-23,50125X0
TOT 127500 573750000 23905500 938000 2*74000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER tON OF CCAL BURNED
MILLS PER KllOUATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON Of SU.FUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
25*009500 22992000 235017500
10.79
4.05
44.97
275.06
105516200
0.96
0.36
4.01
24.51
9*94300
LEVELIZED INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER TON OF CCAL BURNED 10.26 0.96
MILLS PER KILOWATT-HCUR 3.85 0.36
CENTS PER MILLION BTU HEAT INPUT 42.74 4.01
DOLLARS PER TON OF SULFUR REMOVED 261.37 24.51
9.83
3.69
40.96
250.55
95621900
POWER UNIT
9.30
3.49
30.73
236.86
-------
Table U-I2I. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment*1
(I.OOO-MW existing coal-fired power unit, 3.5% S in fuel;
Ot removal; 31.6 tons/hr 100% H2SO4j
Investment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
common feed plenum, mist eliminators, pumps, and all ductwork
between outlet of supplemental fan and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgSOj storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
.Sulfuric acid storage (storage and shipping facilities for
30 days production of H2 S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
•'Basis:
Slack pas reheat lo I75°l; by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
329,000
414,000
6,774,000
543,000
1,685,000
1,253,000
1,625,000
1,824,000
5,583,000
519,000
652,000
1.4
1.8
28.9
2.3
7.2
5.3
6.9
7.8
23.8
2.2
2.8
1,119,000
1,116,000
23,436,000
2,578,000
2,812,000
1,641,000
2,344,000
32,811,000
3,281,000
2,625,000
38,717,000
4.8
4.8
100.0
11.0
12.0
7.0
10.0
140.0
14.0
11.2
165.2
292
-------
Table B-122. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW existing coal-fired power unit, 3.5% S in fuel;
90% S02 removal; 220,900 tons/yr 100% H^04)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium oxide (98%) 2, 150 tons 155.00/ton
Coke 1,526 tons 15.00/ton
Catalyst 3,600 liters 1.65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 47,960 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 17,922,000 gal 0.23/gal
Heat credit 40,600 MM Btu -0.60/MM Btu
Process water 4,413,900 M gal 0.03/M gal
Electricity 92,430,000 kWh 0.009/kWh
Maintenance
Labor and material, .06 x 23,436,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
Equivalent unit operating cost 70.09 5.90 2.21
333,300
22,900
5,900
362,100
383,700
4,122,100
(24,400)
132,400
831,900
1 ,406,200
168,000
7,019,900
7,382,000
5,923,700
1 ,404,000
772,200
8,099,900
15,481,900
Cents/million
Btu heat input
24.57
Percent of
total annual
operating cost
2.15
0.15
0.04
2.34
2.48
26.62
(0.16)
0.86
5.37
9.08
1.09
45.34
47.68
38.26
9.07
4.99
52.32
100.00
Dollars/ton
sulfur removed
214.64
"Basis:
Remaining life of power plant, 25 yr.
Coal burned, 2,625,000otons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $38,717,000; subtotal direct investment, $23,436,000.
Working capital, $1,307,600.
Investment and operating cost for removal and disposal of fly ash excluded.
293
-------
Table B-123
MAGNESIA SLURRY-REGENERATION PROCESS, 10 CO HW EXISTING COAL FIRED POKER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENTS $ 38717000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED TOTAL
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR t/TON ROI FOR NET
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL POWER SALES
UNIT KW-HR/ MILLION BTti TONS COAL PROCESS, lOOt 100* COMPANY, REVENUE,
START KW /YEAR /YEAR TONS/YEAR H2S04 H2S04 4/YEAR i/YEAR
1
2
3
4
5
6 7000 63000000 2625000 72100 220900
7 7000 63000000 2625000 72100 220900
8 7000 63000000 2625000 72100 220900
9 7000 63000000 2625000 72100 220900
to 7flno frjnnQQOO ?f,?«nnn T?>nn 22P*0n
11 5000 45000000 1875000 51500 157800
12 5000 45000000 1875000 51500 157800
13 5000 45000000 1875000 51500 157800
14 5000 45000000 1875000 51500 157800
js _, 5QQQ , .45.00.0000 _ JB150DO sison is7*nn
16 3500 31500000 1312500 36100 110400
17 3500 31500000 1312500 36100 110400
18 3500 J1500000 1312500 36100 110400
19 3500 31500000 1312500 36100 110400
.^Q...-3^QO,, ..31500000 I'l'SOO *fciqp 110*00
21 1500 13500000 562500 15500 47300
22 1500 13500000 562500 15500 47300
23 1500 13500000 562500 15500 47300
24 1500 13500000 562500 15500 47300
?s ISQQ I^QCQDO ___, 5^?5nn i«nn „ r.fcJ30Q
26 1500 13500000 562500 15500 47300
27 1500 13500000 562500 15500 47300
28 1500 13500000 562500 15500 47300
29 1500 13500000 562500 15500 47300
30. 15DO -.13500000. , 562500 ISfOO t 47*00,
.00
.00
.00
.00
.00
.00
.00
.00
UflO—
.00
.00
.00
.00
. nr>
.00
.00
.00
.00
-ftft
.00
.00
.00
.00
TOT 92500 B325COOOO 34687500 953500 2918500
LIFETIME AVERAGE INCREASE (DECREASE! IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTti HEAT INPUT
DOLLARS PER TON OF SCLFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
LEVELUED INCREASE (OECREASEI IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILOWATT-HCUR
CENTS PER MILLION BTl HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
19508500 1767200
19186400 1767200
18864300 1767200
18542100 1767200
m?>nnnn 17^7^00
15422200 1262400
15100100 1262400
14777900 1262400
14455800 1262400
11906200 883200
11584100 883200
11262000 883200
10939900 883200
lQ4L77nO M12QO
7627900 378400
7305800 378400
6983600 378400
4661500 378400
fcl19fcOO ?7f(4Pn
6017200 378400
5695100 378400
5373000 378400
5050900 378400
4728700 a7a4aq
286304000 23348000
8.25 0.67
3.10 0.26
34.39 2.80
300.27 24.49
132674100 11517900
PROCESS COST OVER LIFE OF
7.75 0.67
2.91 0.25
32.31 2.81
282.23 24.51
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE 1
IN COST OF IN COST OF
POWER, POWER,
* *
17741300 17741300
17419200 35160500
17097100 52257600
16774900 69032500
_ •IfcAW.BQQ. , T854BS3QQ
14159800 9964SIOO
13837700 113482800
13515500 126998300
13193400 140191700
1.2AZ13PO 15.3063000
11023000 164086000
10700900 174786900
10378800 185165700
10056700 195222400
323ASOQ 2A4A54SaO
724950C 2122C6400
6927400 219133800
6605200 225739000
6283100 232022130
SSAiOOQ 233383100
5638800 243621900
5316700 248938630
4994600 2539332CO
46-72500 2586057CO
r ..635Q3QQ 2629.54000
2629560CO
7.58
2.84
31.59
275.78
121156200
POWER UNIT
7.08
2.66
29.50
257.72
-------
Table B-124. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment9
(1,000-MW new coal-fired power unit, 3.5% S in fuel;
90%SOi removal; 30.5 tons/hr 100%HiSO^)
Investment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurry ing tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers including
common feed plenum, effluent hold tanks, agitators, pumps,
and fly ash neutralization facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust
gas ducts to inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgSOj storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2SO4)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
299,000
363,000
5,850,000
3,901,000
897,000
1,115,000
1,121,000
1,474,000
1,657,000
4,907,000
435,000
384,000
1.2
1.5
23.8
15.9
3.6
4.5
4.5
6.0
6.7
20.0
1.8
1.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
1,006,000
1,170,000
24,579,000
2,458,000
2,458,000
1,229,000
2,212,000
32,936,000
3,294,000
2,635,000
38,865,000
4.1
4.8
100.0
10.0
10.0
5.0
9.0
134.0
13.4
10.7
158.1
aBasis:
Stack gas reheat to 175 F by indirect steam reheat.
Midwest plant location represents projects beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
295
-------
Table B-125. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW new coal-fired power unit, 3.5% S in fuel;
90% S0t removal; 2 13, 500 tons/yr 100% H2SO4 )
»
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime (1st stage neutralization) 259 tons 26.00/ton
Magnesium oxide (98%) 2,078 tons 155.00/ton
Coke 1,475 tons 15.00/ton
Catalyst 3,480 liters 1.65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 47,960 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 10,356,000 gal 0.23/gal
Steam 850,000 M Ib 0.60/M Ib
Heat credit 39,300 MM Btu -0.60/MM Btu
Process water 4,267,000 M gal 0.03/M gal
Electricity 137,390,000 kWh 0.009/kWh
Maintenance
Labor and material, .06 x 24,579,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing.
1 1 % of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
Equivalent unit operating cost 67.20 5.65 2.05
6,700
322,100
22,100
5,700
356,600
383,700
2,381,900
510,000
(23,600)
128,000
1,236,500
1,474,700
168,000
6,259,200
6,615,800
5,790,900
1,251,800
688,500
7,731,200
.4,347,000
Cents/million
Btu heat input
23.56
Percent of
total annual
operating cost
0.05
2.25
0.15
0.04
2.49
2.67
16.60
3.55
(0.16)
0.89
8.62
10.28
1.17
43.62
46.11
40.36
8.73
4.80
53.89
100.00
Dollars/ton
sulfur removed
205.78
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 2,537,500 tons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000.hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $38,865,000; subtotal direct investment, $24,579,000.
Working capital, $1,172,400.
Investment and operating cost for disposal of fly ash excluded.
296
-------
Table B-1 26
MAGNESIA SLURRY-REGENERATION PROCESS. 10CO HK NEH COAL FIREO POKER UNIT. 3.5* S IN FUEL. 90* S02 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENT: *
38865000
YEARS ANNUAL
AFTER OPERA-
POWER HON.
UNIT KK-HR/
START KW
1
2
3
t,
__5
b
7
8
9
11
12
13
14
-15
16
17
18
19
_2Q
21
22
23
24
_25
26
27
28
29
-30.
7000
7000
700C
7000
20.0,0.
7000
7000
7000
7000
20QQ
5000
5000
5000
5000
5QQO
3500
3500
3500
3500
1500
1500
1500
1500
15.QQ-
1500
1500
1500
1500
SULFUR
REMOVED
POKER UNIT POKER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT. CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS.
/YEAR /YEAR TONS/YEAR
609COOOO
60900000
60900000
60900000
60900000
60900000
60900000
60900000
toaooflDQ—
43500000
43500000
43500000
43500000
435QflDflfl_
30450000
30450000
30450000
30450000
30450flGfl_
13050000
13050000
13050000
13050000
no^nnnn
13050000
13050000
13050000
13050000
2537500
2537500
2537500
2537500
z5.aj.soQ
2537500
2537500
2537500
2537500
^ ^5^35QO -_-•—
1812500
1812500
1812500
1812500
.1012500..
1268700
1268700
1268700
1268700
1 26&7QQ
543700
543700
543700
543700
54*700
543700
543700
543700
543700
69700
69700
69700
69700
frinno
69700
69700
69700
69700
49800
49800
49800
49800
A9HOQ
34900
34900
34900
34900
14900
14900
14900
14900
,149QQ u
14900
14900
14900
14900
l&QQQ
TOTAL
BY-PRODUCT OP. COST
KATE. INCLUDING
EQUIVALENT NET REVENUE, REGULATED
TONS/YEAR $/TON RO I FOR
POKER
100* 100* COMPANY,
H2S04 K2S04 »/YEAR
213500 i
213500
213500
213500
213500
213500
213500
213500
152500
152500
152500
152500
106800
106800
106800
106800
)Of.40O
45800
45800
45800
45800
45*00
45*00
45*00
45*00
1.00 18390200
.00 18120800
.00 17B51300
.00 17581800
U0Q 1231260.0
.00 17042900
.00 16773400
.00 16504000
.00 16234500
-nn 159.65QQQ
.00 13515700
.00 13246200
.00 12976800
.00 12707300
-0" 124.37BQQ
.00 10483100
.00 10213600
.00 9944100
.00 9674700
.OO 4&OS700
.00 6755700
.00 6486300
.00 6216800
.00 5947300
.00 5408400
.00 SI 39000
.00 4869500
. 00 4600000
-ftO A^QfAQ
NET ANNUAL
TOTAL INCREASE
NET (DECREASE)
SALES IN COST OF
REVENUE, POKER,
*/YEAR *
1708000
1708000
1708000
1708000
1708000
1708000
1708000
1708000
1220000
1220COO
1220000
1220000
854400
854400
854400
854400
— 854400
366400
366400
366400
366400
3A&4PQ
3*6400
366400
9*6400
366400
16682203
16412800
16143300
15873800
-_156Q44Qa
15334900
15065400
14796000
14526500
12295700
12026200
11756800
11487300
—UZliaQQ
9628700
9359200
9089700
8820300
ftSSOBOQ
6389300
6119900
5850400
5580900
5042000
4772600
4503100
4233600
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POKER.
$
16682200
33095000
49238300
65112100
96051400
111116800
125912800
140439300
166992000
179018200
190775000
202262300
__ 213480100
223108800
232468000
241557700
250378000
265318100
271438000
277288400
282869300
_ 2AaJ.aQIQO
293222800
297995400
302498500
306732100
•»infc
-------
Table B-127. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
80% SOT. removal; 14.0 tons/hr 100% //2SO,)
Investment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers including
common feed plenum, effluent hold tanks, agitators, pumps,
and fly ash neutralization facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers
including mist eliminators, pumps, and exhaust
gas ducts to inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of HjSC^)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
192,000
238,000
3,966,000
2,592,000
509,000
706,000
656,000
902,000
1,031,000
2,961,000
257,000
2,69,000
1.2
1.5
25.1
16.4
3.2
4.5
4.1
5.7
6.5
18.7
1.6
1.7
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
783,000
753,000
15,815,000
1 ,740, JOO
1 ,740,000
791,000
1,582,000
21,668,000
2,167,000
1 ,733,000
25,568,000
5.0
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
298
"Basis:
Stack gas reheat to 175°l; by indirect steam reheat.
Midwest plant location represents projects beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps arc spared.
l-ly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
-------
Table B-128. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 3.5% S in fuel;
80%SOt removal; 98,200 tons/yr 100%HtSOA)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw material
Lime (1st stage neutralization)
Magnesium oxide (98%)
Coke
Catalyst
Subtotal raw material
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Steam
• Heat credit
Process water
Electricity
Maintenance
1 34 tons
1,086 tons
678 tons
1 ,600 liters
39,200 man-hr
4,761 ,000 gal
440,000 M Ib
18,000 MM Btu
1, 985,400 M gal
66,640,000 kWh
26.00/ton
155.00/ton
15.00/ton
1.65/liter
8.00/man-hr
0.23/gal
0.70/M Ib
-0.60/MM Btu
0.04/M gal
0.010/kWh
Labor and material, .07 x 15,815,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing.
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
Equivalent unit operating cost
89.51 6.70
2.51
3,500
168,300
10,200
2,600
184,600
313,600
1,095,000
308,000
(10,800)
79,400
666,400
1,107,100
102,000
3,660,700
3,845,300
3,809,600
732,100
402,700
4,944,400
8,789,700
Cents/million
Btu heat input
27.90
0,04
1.91
0.12
0.03
2.10
3.57
12.46
3.50
(0.12)
0.90
7.58
12.60
1.16
41.65
43.75
43.34
8.33
4.58
56.25
100.00
Dollars/ton
sulfur removed
274.16
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500otons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175° V.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 197S operating costs.
Total capital investment, $25,568,000; subtotal direct investment, $15.815,000.
Working capital, $681,000.
Investment and operating cost for disposal of fly ash excluded.
299
-------
Table B-129
MAGNESIA SIURRY-RFC-FNFRAT.'ON PROCESS. 50C MM NEW COAL FIRED POWER UNIT, 3.5* S IN FUEL. 80* SO2 REHOVAL, REGULATED CO ECON.
FIXED INVESTMENT: $
25568000
SULFUR
REMOVED
YEARS ANNUAL POWER UNIT POWER UNIT BY
AFTER OPERA- HEAT FUEL POLLUTION
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KV-HR/ MILLION BTU TONS COAL PROCESS.
START KU /YEAR /YEAR TONS/YEAR
1 7000 31500000 1312500 32100
2 7000 31SCOCOO 1312500 32100
3 7000 315COOOO 1312500 32100
4 7000 31SCCOOO 1312500 32100
5 2CQQ 315COQQQ .1 3125C1Q 32100
6 7000 315CCOOO 1312500 32100
7 7000 31500000 1312500 32100
8 7000 315CCOCO 1312500 32100
9 7000 31500000 1312500 32100
10 7000 31SCDQCQ L3125.QQ 3,21.0.0
11 5000 225COCCO 937500 22900
12 5000 225C&000 937500 22900
13 5000 225000CO 937500 22900
14 5000 225COOOO 937500 22900
' 5- 5.QQQ 2?S.Q!iOPG 937^Q° _ 229QQ
16 3500 15750000 656200 16000
17 3500 15750000 656200 16000
18 3500 15750000 656200 16000
19 3500 15750000 (56200 16000
.20 ,3SQD_ ._ 15.75UQCO .. - 65620.0.. ._ .^^16.300
21 1500 67500CO 281200 6900
22 1500 6750000 281200 6900
23 1500 6750000 281200 6900
24 1500 6750000 281200 6900
25 1500 fc7^OQ£P 2^1200 69,0.0.
26 1500 6750000 t .200 6900
27 1500 6750000 261200 6900
28 1500 6750000 281200 6900
29 1500 67500CO 261200 6900
. -*0 1^00- 6.1503.00 -. -..2112QD 6900
TOT 127500 573750000 23905500 584500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERAT
DOLLARS PER TON OF CCAL BURNED
MILLS PER KUOUATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SU.FUR REMOVED
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
100*
H2S04
98200
98200
98200
98200
9ft ?00
98200
98200
98200
98200
Sfl2QQ_
70100
70100
70100
70100
70100,
49100
49100
49100
49100
. r ,.,4910.0
21000
21000
21000
21000
2 1 QQQ
21000
21000
21000
21000
_ 2100,0 „ .
17&800C
ING COST
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON
100*
H2S04
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
8.00
ROI FOR
POWER
COMPANY,
t/YEAR
11449500
11272300
11095000
10917700
1 0740400
10563200
10385900
10208600
10031300
NET ANNUAL
TOTAL
NET
SALES
REVENUE,
J/YEAR
785600
785600
785600
785600
1fi5fcOO
785600
785600
785600
785600
R.DQ Qustnnn 7ns&nn
8.00
8.00
8.00
6.00
ft, 00
6.00
8.00
.00
.00
DO
.00
.00
.00
.00
. on
.CO
.00
.00
.00
-on
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
LEVELLED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF CCAL BORNEO
MILLS PER KILOHATT-HCUR
CENTS PER MILLION BTL HEAT INPUT
DOLLARS PER TON OF SU.FUR REMOVED
DISCOUNTED
*
8457200
B27990C
8102600
7925300
'TT<OOfl
6617100
6439800
6262500
6065200
s&opQQfl
4358100
4180600
4C03500
3626200
2649000
3471700
3294400
3117100
2939800
27&2feOQ
213946700
8.95
3.36
37.29
366.03
67276500
560800
560800
560800
560800
•kAOfiOO
392800
392800
392800
392800
168000
168000
166000
168COO
16BQCQ
168000
168000
168000
168000
L6&QQQ
14304COO
0.60
0.23
2.49
24.47
6156700
PROCESS COST OVER LIFE OF
6.48
3.18
35.35
347.02
0.59
0.22
2.49
24.48
INCREASE
IDECREASE)
IN COST OF
POKER.
*
10663900
10486700
10309400
10132100
QOC A • QQ
9777600
9600300
9423000
9245700
SQ&8.6QC
7896400
7719100
7541600
7364500
J \ »7 5 QQ
6224300
6047000
5869700
5692400
551.5200
4190100
4012600
3835500
3658200
3.fcfllQ00
3303700
3126400
2949100
2771600
2CQ&A QQ
199642700
6.35
3.13
34.80
341.56
81119800
POWER UNIT
7.89
2.96
32.8*
322.5*
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
1C663930
21150600
3146CDCO
415?21CO
H f i»Af**30 3
6132450C
709248CD
803478SO
895935:0
9ffAb 1 900 '
1C65583:C
1142774CO
1218192GO
1291837CO
13£k32DSuO
142595200
146642200
154511900
16C2C4300
j £521 Q 5QO
1699r96CO
173922400
177757930
181416100
jl£61&2 100
1882COBOO
191327200
194276300
197C48100
i S961kj2 ?f2^
-------
Table B-130. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(500-MW existing coal-fired power unit, 3.5% S in fuel; 90% SO* removal;
15.8 tons/hr 100% //aS04; particulate scrubber required for fly ash removal)
Percent of subtotal
Investment, $ direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers including
common feed plenum, effluent hold tanks, agitators, pumps,
fly ash neutralization facilities and all ductwork between
outlet of supplemental fan and particulate scrubber)
Sulfur dioxide scrubbers and ducts (4 scrubbers including mist
eliminators, pumps, and exhaust gas ducts between
SO? scrubber and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
210,000
270,000
4,716,000
3,172,000
305,000
1,185,000
789,000
1,065,000
1,211,000
3,608,000
329,000
454,000
1.1
1.4
24.7
16.6
1.6
6.2
4.1
5.6
6.4
18.9
1.7
2.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
867,000
909,000
19,090,000
2,291,000
2,482,000
1,336,000
2,100 JOOO
27,299,000
2,730,000
2,184,000
32,213,000
4.5
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
"Basis:
Stack gas reheat to 175 F by indirect steam reheat.
Midwest plant location represents projects beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Fly ash slurry neutrali/ed before disposal; closed loop water utilization for first stage.
Investment requirements tor disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
301
-------
Table B-131. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing coal-fired power unit, 3.5% S In fuel;
90% S0t removal; 112,900 tons/yr 100%HtSO^;
particulate scrubber required for fly ash removal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Lime (1st stage neutralization) 137 tons 26.00/ton
Magnesium oxide (98%) 1,1 10 tons 155.00/ton
Coke 780 tons 15.00/ton
Catalyst 1 ,840 liters 1 .65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 39,200 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 9,160,000 gal 0.23/gal
Heat credit 20,800 MM Btu -0.60/MM Btu
Process water 2,256,100 M gal 0.04/M gal
Electricity 72,640,000 kWh 0.010/kWh
Maintenance
Labor and material, .07 x 19,090,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 5.3%
of total capital investment
Overhead
Plant, 2Q% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%H2S04 coal burned Mills/kWh
Equivalent unit operating cost 99.44 8.37 3.21
3,600
172,100
11,700
3,000
190,400
313,600
2,106^00
(12,500)
90,200
726,400
1,336,300
102,000
4,662,800
4,853,200
4.928,600
932,600
512,900
6,374,100
11,227,300
Cents/million
Btu heat input
34.87
Percent of
total annual
operating cost
0.03
1.54
0.10
0.03
1.70
2.79
18.77
(0.11)
0.80
6.47
11.90
0.91
41.53
43.23
43.89
8.31
4.57
56.77
100.00
Dollars/ton
sulfur removed
304.59
aBasls:
Remaining life of power plant, 25 yr.
Coal burned, 1,34l,700otons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $32,213,000; subtotal direct investment, $19,090,000.
Working capital, $858,900.
Investment and operating cost for disposal of fly ash excluded.
302
-------
Table B-132
MAGNESIA SLURRY-REGENERATION PRCCESS, 50C MW EXIST. COAL FIRED POWER UNIT, 3.5* S, 90* 502 REMOVAL, FLYASH REMOVED BY PART. SCRUB.
FIXED INVESTMENT:
32213COO
s
YEARS ANNUAL
AFTER OPEPA-
POWER TIDN,
UNIT KW-HR/
START KW
I
2
3
t,
5
6
7
6
9
-1C
11
12
13
14
_15
16
17
18
19
7COO
7000
7000
7000
7QOC.
5000
5000
5000
5000
SCQQ
3500
3500
3500
3500
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS, 100*
/YEAR /YEAR TONS/YEAR H2S04
322000CC 1341700 36900
32200000 1341700 36900
322COOOO 1341700 36900
32200000 1341700 36900
i^nnnrsn 1^*1700 3*900
230COOCO 958300 26300
230COOOO 956300 26300
23000000 S58300 26300
23000000 958300 26300
2.3QOQOGQ 95A3QQ 263.00
161COOOO 670800 18400
16100000 670800 18400
161COOOO 670800 18400
16100000 670800 18400
2.Q isnn ikinnnnn &7OHOR I*&OQ
21
22
23
24
_2i_.
26
27
28
29
_aa .
TOT
1500
1500
1500
1500
6903000 287500 7900
6900000 287500 7900
69COOOO 287500 7900
6900000 287500 7900
112900
112900
112900
112900
11?9Qn
80600
80600
80600
80600
fifi4*on
56500
56500
56500
56500
*>65QO
24200
24200
24200
24200
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
(/TON R01 FOR
POWER
1UO* COMPANY,
H2S04 (/YEAR
8.
8.
8.
8.
8 -
8.
8.
8.
8.
«-
8.
8.
8.
8.
00
00
00
00
DO
00
00
00
00
DO
00
00
00
00
14577400
14309400
14041400
13773400
11671900
11403900
11135800
10867800
_ic5saBna_
9112700
8844700
8576700
8308700
8^00 nntmnn
8.
8.
8.
8.
00
00
00
00
1_5QO fc9finono ?tn*nn . IQOO 74200 «.oo
1500
1500
1500
1500
15QQ-
92500
LIFETIME
PROCESS COST
LEVEL1ZED
6900000 287500 7900
69COOOO 287500 7900
6900000 287500 7900
6900000 287500 7900
69.00000 J87SOO .790.0
4255CCOOO 17729000 487000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SLLFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
24200
24200
24200
24200
2£>OO
1492000
COST
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SLLFUR REMOVED
B.
8.
8.
8.
A -
00
00
00
00
no
6030200
5762200
5494200
5226200
NET ANNUAL CUMULATIVE
TOTAL INCREASE NET INCREASE
NET (DECREASE) (DECREASE!
SALES IN COST OF IN COST OF
REVENUE, POWER, POWER,
(/YEAR S $
903200
903200
903200
903200
9032QQ
644800
644800
644800
644800
&&&fi on
452000
452000
452000
452000
65.2000
193600
193600
193600
193600
. _ 4S5A20.Q 19360.0.
4690100
4422100
4154100
388*100
3&lp}Dp
217C11200
12.24
4.69
51.00
445.61
99762800
193600
193600
193600
193600
. . . 19.7600 , ,
11936000
0.67
0.26
2.80
24.51
5887000
DISCOUNTED PROCESS COST OVER LIFE OF
11.41
4.37
47.53
415.16
0.68
0.25
2.80
24.50
13674200
13406200
13138200
12870200
\ 2602200
11027100
10759100
10491000
10223000
9955QOQ
8660700
8392700
8124700
7B56700
136742CO
27080400
4C218600
53086800
-6.5taj.000
76718100
87477200
979682JO
108191200
11B14A2QO
126806900
135199630
143324300
151181000
2588200 i^«7AO7r.n
5836600
5568600
5300600
5032600
626&AQ.Q
4496500
4228500
3960500
3692500
3.6265.QC
205075200
11.57
4.43
48.20
421. 10
93875800
POWER UNIT
10.73
4.12
4*. T3
390.66
164606300
170174900
175475500
1805C810C
J.&5.2.7.2.7.00
189769200
193997700
197958200
201650700
2H5Q2S2DO
-------
Table B-133. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(200-MW new oil-fired power unit, 2.5% S in fuel;
90% SOj removal; 3.4 tons/hr 100%H2SO^)
In vestment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (2 scrubbers including
common feed plenum, mist eliminators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Stack gas reheat (2 direct oil-fired reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit forsulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
69,000
90,000
1,440,000
103,000
208,000
249,000
373,000
438,000
1,189,000
99,000
186,000
1.3
1.7
27.6
2.0
4.0
4.8
7.2
8.4
22.8
1.9
3.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
522,000
248,000
5,214,000
678,000
678,000
365,000
574,000
7,509,000
751 ,000
601 ,000
8,861 ,000
10.0
4.7
100.0
13.0
13.0
7.0
11.0
144.0
14.4
11.5
169.9
aBasis:
Stack gas reheat to 175°l' by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
304
-------
Table 8-13-4. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics1
(2M-MWnvwitil-fireJpnwerur.it, J..VY .V in fuel;
Mf.' SO} removal; -V. 100 lons/yr Hill': //j.SYJ, )
Total annual
Annual quantity Unit cost. S cosl.S
Dire ft Costs
Delivered raw material
Magnesium oxide (98%) 239 tons 155.00/ton
Coke 166 tons 15.00/ton
Catalyst 393 liters 1.C5/liter
Subtotal raw material
Conversion costs
Operating labor and
iupei vision 28,360 man-hr 8.00/man hr
Utilities
Fuel oil (No. 6) 1.988.000 gal 0.23/gal
Heat credit 4,400 MM Btu -1 .60/MM btu
Process water 508,000 M gal 0.08/M gal
Electricity 12.470.000 kWh 0.019/kWh
Maintenance
Labor and material. .08 x 5.214,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annu.il operating cost
Dollars/ton Dollars/bbl
100%H:S04 oil burned Mills/kWh
Equivalent unit operating cost 132.96 1.56 2.29
37,000
2,500
COO
40100
226.900
457.200
(7,000)
40.600
236 900
417.100
36.000
1.407,700
1.447.800
1.320.300
281,500
154,800
1,756,600
3.204,400
Cents/million
Btu heat input
24.88
Percent of
total annual
operatn-gcost
1.15
'0.08
0.02
1.25
7.08
14.27
(0.22)
1.27
7.39
13.02
1.12
43.93
45.18
41.20
8.79
4.83
b4.82
100.00
Dollars/ton
sulfur removed
407.17
Kcinjiniiii! iili1 i. 9.2DO IIiii/k\Vh.
Mail. (!j\ rche.ll lo I75'J|:.
IWer iinil im-slrcum time. 7.01)0 hr/yr.
MttlKett pljnl location. 1975 operating coMs.
Imul > jpil.il investment. $K.K(, 1,000; subloljl din-cl iiueslment. S$.214.000.
Working c.ipilj|. $255.900.
305
-------
Table B-135
MAGNESIA SLURRY-REGENERATION PROCESS, 20C MW NEW OIL FIRED POWER UNIT, 2.5* S IN FUEL, 90* 502 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENTS *
8861000
YEARS ANNUAL
AFTER OPERA-
PQUER TIDN,
UNIT KW-HR/
START KW
1
2
3
4
7000
7000
7000
7000
POWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION
MILLION BTU BARRELS OIL
/YEAR
12880000
12680000
12880000
12880000
/YEAR
2C58200
2058200
2058200
2058200
5 7nnn i?«annno 3n*«>nn
6
7
8
9
to
11
12
13
14
15
16
17
18
19
7000
7000
7000
7000
7.QQQ
5000
5000
5000
5000
soon
3500
3500
3500
3500
12880300
12880000
12880000
12880000
i.2fiBQQQD
9200000
92COOOO
9200000
9200000
2058200
2058200
2058200
2058200
?G%ft?no
1470100
1470100
1470100
1470100
SULFUR BY-PRODUCT
REMOVED RATE,
BY EQUIVALENT
POLLUTION TONS/YEAR
. CONTROL
PROCESS, 100*
TONS/YEAR
7900
7900
7900
7900
2900 -
7900
7900
7900
7900
74OO
5600
5600
5600
5600
H2S04
24100
24100
24100
24100
2&1 OO
24100
24100
24100
24100
2410.Q
17200
17200
17200
17200
TOTAL
OP. COST
INCLUDING NET ANNUAL
NET REVENUE, REGULATED TOTAL INCREASE
»/TON ROI FOR NET (DECREASE!
POWER SALES IN COST OF
lOOt COMPANY. REVENUE, POWER,
H2S04
8
8
8
8
i - ,.- 8
8
8
8
8
a
8
8
8
8
.00
.00
.00
.00
~.oo_
.00
.00
.00
.00
.00
.00
.00
.00
.00
S/VEAR J/YEAR
4126300
4064800
4003400
3942000
192800
192800
192800
192800
»
3933500
3872000
3810600
3749200
CUMULATIVE
NET INCREASE
(DECREASE!
IN COST DF
POWER,
S
3933500
7805500
11616100
15365300
. ,3880500 lojunn i«.n77no isos^nuo
3819100
3757600
3696200
3634700
192800
192800
192800
192800
3626300
3564803
3503400
3441900
1*73300 iQ?ann *3«n5nn
3C68900
3007400
2946000
2884500
137600
137600
137600
137600
2931300
2869800
2808400
2746900
22679300
26244100
29747500
33189400
a&SAaaco
395012'JO
42371000
45179400
47926300
, n 1470100 s*nn n?on a.oo ?fi?tioo i37*.on ?*««;•; r,n sGfciiaoo
6440000
6440000
64400CO
6440000
1029100
1029100
1029100
1029100
^20, -*sftn fcitnnnn in?«inn
21
22
23
24
?-i
2b
27
28
29
1500
1500
1500
1500
_ -1SQO.-
1500
1500
1500
1500
2760000
2760000
2760000
2760000
37t OOOO
2760000
2760000
2760000
2760000
441000
441000
441000
441000
4*6 1 oon
441000
441000
441000
441000
_.3Q i«snn ?7*nooo t^innn
TOT
127500
LIFETIME
234600000
AVERAGE INCREASE
DOLLARS
37488000
3900
3900
3900
3900
3900
1700
1700
1700
1700
I 7QQ
1700
1700
170C
1700
1700
143500
(DECREASE! IN UNIT OPERATING
PER BARREL
OF OIL BURNED
12100
12100
12100
12100
121QQ _
5200
5200
5200
5200
.5200
5200
5200
5200
5200
C2fin
439500
COST
8
.00
.00
.00
.00
-00
.00
.00
.00
.00
2411400
2350000
2288600
2227100
? IfiSTQQ
1590600
1529200
1467700
1406300
96800
96800
96800
96800
96.aQQ .
41600
41600
41600
41600
.nn i3&&«aa 41*00
.00
.00
.00
.00
.00
MILLS PER KILOWATT-HOUR
CENTS PER MILLION
PROCESS COST
LEVELIZED
DOLLARS
DISCOUNTED AT
PER TON OF
BTli HEAT INPUT
SULFUR REMOVED
10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS
PER BARREL
OF OIL BURNED
DISCOUNTED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION
DOLLARS
PER TOM OF
BTt HEAT INPUT
SULFUR REMOVED
1283400
1222000
1160500
1099100
41600
41600
41600
41600
rn,,.-.^ .1037600 4lfcOO
77811900
2.08
3.05
33.17
542 . 24
316015CO
PROCESS COST OVER
1 .96
2.88
31 .30
511.35
3516000
C.10
0.14
1.50
24.50
1511600
2314600
2253200
2191800
2130300
5Qt flonn
I54900C
1487600
1426100
1364700
....13Q33QQ.
1241800
1180400
1118900
1057500
52926400
55179600
57371400
59501700
&1.52 Q.&00
63119600
64607200
66C33300
67398000
_ 68201300
69943100
71123500
72242400
73299900
996DDQ 7fc295SDO
74295900
1.98
2.91
31.67
517.74
30089900
LIFE OF POWER UNIT
0.09
0.14
1.49
24.46
1.87
2.74
29.81
486.89
-------
Table B-136. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment2
(500-MW new oil-fired power unit, 1.0% Sin fuel;
90% S0j removal; 3.4 tons/hr 100%HiSOt)
Investment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
common feed plenum, mist eliminators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils; centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2S04 )
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
68,000
88,000
3,260,000
245,000
471,000
245,000
368,000
432.000
1,170,000
97,000
301,000
0.9
1.1
41.5
3.1
6.0
3.1
4.7
5.5
14.9
1.3
3.8
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
733,000
374,000
7,852,000
864,000
864,000
393,000
785,000
10,758.000
1,076,000
861,000
12,695,000
9.3
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
aBasis:
Stack gas reheat to 175 F by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
307
-------
Table B-137. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new oil-fired power unit, 1.0% S in fuel;
90% S0t removal; 23,600 tons/yr 100% HtS04)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium oxide (98%) 232
Coke 163
Catalyst 394
Subtotal raw material
Conversion costs
Operating labor and
supervision 30,440
Utilities
Fuel oil (No. 6) 3,147,000
Heat credit 4,300
Process water 601 ,800
Electricity 24,710,000
Maintenance
Labor and material, .07 x 7,852,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton
100%HaS04
Equivalent unit operating cost 196.32
tons 155.00/ton 36,000
tons 15.00/ton 2,400
liters 1.66/liter 700
39,100
man-hr 8.00/man-hr 243,500
gal 0.23/gal 723,800
MMBtu -1.60/MMBtu (6,900)
Mgal 0.07/Mgal 42,100
kWh 0.018/kWh 444,800
549,600
66,000
2,062,900
2,102,000
1,891,600
412,606
226,900
2,531,100
4,633,100
Dollars/bbl Cents/million
oil burned Mills/kWh Btu heat input
0.92 1.32 14.71
Percent of
total annual
operating cost
0.77
0.05
0.02
0.84
5.26
15.63
(0.15)
0.91
9.60
11.86
1.42
44.53
45.37
40.82
8.91
4.90
54.63
100.00
Dollars/ton
sulfur removed
602.48
aBasis:
Remaining life of power plant, 30 yr.
Oil burned, 5,033,600 bbl/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit en-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $12,695,000; subtotal direct investment, $7,852,000.
Working capital, $371,300.
308
-------
Table B-138
MAGNESIA SLURRY-KEGENERATION PROCESS, 50C MM NEW OIL FIRED POWER UNIT* 1.0* S IN FUEL. 90X 502 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENT: $
12695000
s
YEARS ANKUAL
AFTER DPERA-
PCHER TION,
UNIT Kk-HR/
START KW
1 7GGO
2 7000
3 7000
4 7000
6 7000
7 7000
8 7000
9 7000
_JLO 2DJ1Q_
11 5000
1? 5000
13 5000
14 5000
IS SQOQ
16 3500
17 3500
13 3500
19 3500
30 «OO
21 1500
22 1500
23 150C
24 1500
_25_ _15flO_
26 1500
27 1500
28 1500
29 1500
_aa is£o_
TQT 127500
LIFETIME
PROCESS COST
LEVELIZED
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED TOTAL
HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR NET
REQUIREMENT, CONSUMPTION, CONTROL POWER SALES
MILLION BTU BARRELS OIL PROCESS, 100* 100* COMPANY, REVENUE,
/YEAR /YEAR TONS/YEAR H2S04 H2S04 S/VEAR »/YEAR
315COOOO 5033600 7700
31SCOOOO 5033600 7700
31500000 5033600 7700
31500300 5033600 7700
315COOOO 5033600 7700
31500900 5033600 7700
315COOOO 5033603 7700
315COOCO 5033600 7700
3isnnpOD ... snm.no 770(1
22500000 3595400 5500
22500000 3595400 5500
225COOOO 3595400 5500
225COOOO 3595400 5500
225.00000 , .1595400 s«fQQ
15750000 2516800 3800
15750000 2516800 3800
15750000 2516800 3800
15750000 2516800 3800
is7«>nnnn ?siAftnn ?non
6750000 1078600 1600
6750300 1078600 1600
6750000 1078600 1600
6750000 1078600 1600
6750900 1078600 1600
6750000 1078600 1600
6753000 1078600 1600
6750000 107*600 1600
23600
23600
23600
23600
23600
23600
23600
23600
16900
16900
16900
16900
11800
11800
11800
11800
5100
5100
5100
5100
s|nn
5100
5100
5100
5100
sinn
.00
.00
.00
.00
UO.O-
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
.00
LJlft.
573750300 91683000 139500 430500
AVERAGE INCREASE (DECREASE! 1M UNIT OPERATING COST
DOLLARS PER BARREL Of OIL BURNED
MILLS PER KILOUATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOUATT-HCUR
CENTS PER. MILLION BTL HEAT INPUT
DOLLARS PER TON OF SLLFUR REMOVED
5953800 188800
5865700 188800
5777700 188800
5689700 188800
56Q17QO 18.8800
5513600 188800
5425600 188800
5337600 188800
5249600 188800
51*150.0- 188800
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE). (DECREASE}
IN COST OF IN COST OF
POUER, POhER,
$ »
5765000
5676900
5588900
5500900
5324800
5236800
5148800
5060800
t«7.?7On
4406100 135200 4270900
4318100 135200 4182900
4230100 135200 4094900
4142000 135200 4006800
4ns400o 135200 Mian no
3443900 94400
3355900 94400
3267800 94400
3179800 94400
^naiitnn qttnn
2249700 40800
2161700 40800
2073700 40800
1985700 4C800
1B976QQ 40*00
1809600 40800
1721600 40800
1633600 40800
1545500 40800
111602200 3444000
1.22 0.04
1.75 0.05
19.45 0.60
800.02 24.69
45510900 1480600
PROCESS COST OVER LIFE OF
1.15 0.03
1.66 0.05
18.43 0.60
756.00 24.60
3349500
3261500
3173400
3085400
__2S92AQO_
2208900
2120900
2032900
1944900
I ft 5 68 QO
1768800
1680800
1592800
1504700
108158200
1.18
1.70
18.85
775.33
44030300
POWER UNIT
1.12
1.61
17.83
731.40
5765000
11441900
170308CO
22531700
33269400
385062CO
436S50CO
487158CO
57959400
62142300
66237200
70244000
-2&1&24&0
77512300
8077380r
83947200
87032600
•nninnnn
92238900
94359830
96392700
98337630
101963200
103644000
105236800
106741500
-------
Table B-139. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment9
(500-MW-new oil-fired power unit, 2.5% S in fuel;
90% SO* removal; 8.4 tons/hr
Investment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feedeis, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide sctubhers and ducts (4 sciubbers including
common feed plenum, mist eliminators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Slack gas leheat (4 tlitect oil fited reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slimy processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
fvlgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power 0lant)
Service facilities (buildings, shops, stores, site
126,000
159,000
3,260,000
245,000
471,000
461,000
655,000
755,000
2,126,000
181,000
301,000
1.3
1.6
32.8
2.4
4.7
4.G
6.6
7.6
21.4
1.8
3.0
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
733,000
474,000
9,947,000
1,094,000
1,094,000
497,000
995,000
13,627,000
1 ,363,000
1,090,000
16,080,000
7.4
4.8
100.0
11.0
11.0
' 5.0
10.0
137.0
13.7
11.0
161.7
a Basis:
Stack gas reheat to 175°F by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
310
-------
Table B-140. Magnesia Slurry -Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics*
(500-MW new oil-fired power unit, 2.5% S in fuel;
90% SO) removal; 58,900 tons/yr 100% H^SO*)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw material
Magnesium oxide (98%) 579 tons 155.00/ton
Coke 407 tons 15.00/ton
Catalyst 960 liters 1.65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 32,520 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 4,861 ,000 gal 0.23/gal
Heat credit 10,800 MM Btu -1 .60/MM Btu
Process water 1,241 ,100 M gal 0.05/M gal
Electricity 30,510,000 kWh 0.018/kWh
Maintenance
Labor and material, .07 x 9,947,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 4.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing.
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
100%H2S04 oil burned Mills/kWh
Equivalent unit operating cost 103.44 1.21 1.74
89,700
6,100
1,600
97,400
260,200
1,118,000
(17,300)
62,100
549,200
696,300
79,200
2,747,700
2,845,100
2,395,900
549,500
302,200
3,247,600
6,092,700
Cents/million
Btu heat input
19.34
1.47
0.10
0.03
1.60
4.27
18.35
(0.28)
1.02
9.01
11.43
1.30
45.10
46.70
39.32
9.02
4.96
53.30
100.00
Dollars/ton
sulfur removed
316.83
*Basis:
Remaining life of power plant, 30 yr.
Oil burned. 5,033,600 bbl/yr, 9,000 Btu/kWh.
Stack gas reheat to 17S°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $16,080,000; subtotal direct investment, $9,947,000.
Working capital, $503,300.
311
-------
Table B-141
MAGNESIA SLURRY-REGENERATION PROCESS. 50C NH NEH OIL FIRED POWEft UNIT, 2.5* S IN FUEL. 90* 502 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENTS t 16080000
YEARS ANNUAL
AFTER OPERA-
POWER T10N.
UNIT KW-HR/
START KW
1 7000
2 7COO
3 7000
4 7000
s ynnn
6 7000
7 7000
8 7000
9 7000
| ft 7Q{1O
11 SOOO
12 5000
13 5000
14 SOOO
1 •£ tftOOO
16 3500
17 3500
18 3500
19 3500
>fi ^Cflfl
21 1500
22 1500
23 1500
24 1500
2 5 1 COO
26 1500
27 1500
28 1500
29 1500
_3fl 15QQ
TOT 127500
LIFETIME
PROCESS COST
LEVEL1ZED
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED
HEAT FUEL POLLUTION TONS/YEAR t/TON ROI FOR
REQUIREMENT, CONSUMPTION, CONTROL POWER
MILLION BTU BARRELS OIL PROCESS, 100* 100* COMPANY,
/YEAR /YEAR TONS/YEAR
31500000 5033600 19200
31500000 5033600 19200
31500000 5033600 19200
31500000 5033600 19200
31500000 5.03^600. 19700
31500000 5033600 192OO
31500000 5033600 19200
31500000 5033600 19200
315COOOO 5033600 19200
•a i *£f*nOfiO COI^&AO 1 Q7OA
225COOOO 3595400 13700
2250COOO 3595400 13700
225COOOO 3595400 13700
22500000 3595400 13700
.?j*soooofi ^*»Q
-------
Table B-142. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 4.0% S in fuel;
90%SOi removal; 13.5 tons/hr 100%HJS04)
Investment. $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, 'and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
common feed plenum, mist eliminators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of Ht S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
173,000
215,000
3,260,000
245,000
471,000
638,000
880,000
1,007,000
2,883,000
249,000
301,000
1.5
1.8
28.1
2.1
4.1
5.5
7.6
8.7
24.8
2.1
2.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
733,000
553.000
11,608,000
1,277,000
1,277,000
580,000
1,161.000
15,903,000
1,590,000
1,272,000
18,765,000
6.3
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
3Basis:
Stack gas reheat to 175°F by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost bisis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
313
-------
Table B-143. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new oil-fired power unit, 4.0% S in fuel;
90% SOi removal; 94,200 tons/yr 100% #2S04)
Annual quantity
Unit cost, $
Percent of
Total annual total annual
cost, $ operating cost
Direct Costs
Delivered raw material
Magnesium oxide (98%) 926
Coke 651
Catalyst 1 ,536
Subtotal raw material
Conversion costs
Operating labor and
supervision 34,600
Utilities
Fuel oil (No. 6) 6,575,000
Heat credit 17,300
Process water 1,880,400
Electricity 36,320,000
Maintenance
Labor and material, .07 x 1 1 ,608,000
Analyses
.Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton
100%H2S04
Equivalent unit operating cost 78.49
tons 155.00/ton 143,500
tons 15.00/ton 9,800
liters 1.65/liter 2,500
155,800
man-hr 8.00/man-hr 276,800
gal 0.23/gal 1,512,300
MM Btu -1 .60/MM Btu (27,700)
M gal 0.04/M gal 75,200
kWh 0.018/kWh 653,800
812,600
87,600
3,390,600
3,546.400
2,796,000
678,100
373,000
3.347.100
7,393,500
Dollars/bbl Cents/million
oil burned Mills/kWh Btu heat input
1.47 2.11 23.47
1.95
0.13
0.03
2.11
3.74
20.46
(0.37)
1.02
8.84
10.99
1.18
45.86
47.97
37.81
9.17
5.05
52.03
100.00
Dollars/ton
sulfur removed
240.28
"Basis:
Remaining life of power plant, 30 yr.
Oil burned, 5,033.600 bbl/yr, 9,000 Btu/kWh.
Slack gas reheat to 175°F.
Power unit on-streum time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $18,765,000; subtotal direct investment, $11,608,000.
Working capital. $627,900.
314
-------
Table B-144
MAGNESIA SLURRY-REGENERATION PROCESS. 50C HW NEW OIL FIRED POWER UNIT, 4.0* S IN FUEL, 90* S02 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENT:
16765000
YEARS ANNUAL
AFTER OPERA-
POriER T10N,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7COO
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
PCWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED
HEAT FUEL POLLUTION TONS/YEAR t/TON ROI FOR
REQUIREMENT, CONSUMPTION, CONTROL POWER
MILLION BTU BARRELS OIL PROCESS, 100* ICO* COMPANY,
/YEAR /YEAR TONS/YEAR
315COOOO 5C33600
315COOOO 5033600
315C3000 5033600
31500000 5033600
5 7£ioo^ 3isconnn 4O13&00
6 7000
7 7000
a 7000
9 7000
_lfl 7CCiQ_
11 5000
12 5000
13 5000
14 5000
31500000 5033600
31500000 5033600
315COOCO 5033600
31500000 5033600
315CQODQ 5033600
225COOCO 35954CO
2250000C 3595400
225COOOO 3595400
225COOOO 3595400
_15 5000 ^Jscoonn i*a«&.nn
16 3500
17 3500
18 3500
19 3500
15750000 2516800
1575000C 2516800
15750000 2516800
15750000 2516800
30800
30800
30800
30800
308. QO
30800
30800
30800
30800
^ofino
22000
22000
220 CO
22000
22000. , -
15400
15400
15400
15400
H2S04 H2S04
94200 8.00
94200 8.00
94200
94200
94?QQ
94200
94200
94200
94200
96200
67300
67300
67300
67300
£T5fiO
47100
47100
47100
47100
20. 3500 15750000 psif,*nn istnn 47100
21 1500
22 1500
23 1500
24 1500
25 15DO
26 1500
27 1500
28 1500
29 1500
10 1S.QC
TOT 127500
LIFETIME
675COOC 1078600
6750000 1078600
6750000 1078600
6750000 1C78600
67SflQoo i flTUfcfl n
6750000 1078600
6750000 1078600
6750000 1078600
6750000 1078600
6250OOO 1O7A6QO
573750000 91683000
6600
6600
6600
6600
ffcOQ
6600
6600
6600
6600
6frOO
561000
AVERAGE INCREASE (DECREASE! IN UNIT OPERATING
DOLLARS PER BARREL QF OIL
MILLS PER K1LOUATT-HUIR
BURNED
20200
20200
20200
20200
PQ2OO
20200
20200
20200
20200
202QQ
.00
.00
-00
.00
.00
.00
.00
-00
.00
.00
.00
.00
fcrtft
.00
.00
.00
.00
-OO
.00
.00
.00
.00
no
.00
.00
.00
.00
. on
1716000
COST
CENTS PER MILLION BTL HEAT INPUT
PROCESS COST
LEVELIZEO
DOLLARS PER TON OF SU.FUR
DISCOUNTED AT 10.0* TO INITIAL
REMOVED
YEAR, DOLLARS
INCREASE (DECREASE 1 IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER BARREL OF OIL
HILLS PER KILOWATT-HOUR
BURNED
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR
REMOVED
»/YEAR
9345700
9215600
9CB5500
8955400
TOTAL
NET
SALES
REVENUE,
»/YEAR
753600
753600
753600
753600
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST UF
POWER, POWER,
S
8592100
8462000
8331900
8201800
S
8592100
170541CO
25386000
33587800
fla?sioo 7«4&oo «O7i7OO 6i<,5<9snn
8695200
8565100
8435000
8304900
ftl 748PQ
6888000
6757900
6627800
6497700
6367600
5340700
5210600
5080500
4950300
4A?O?OO
3415700
3285600
3155500
3025400
^ftQC^fift
2765200
2635100
25C5000
2374900
?>4Aflflfl
174446300
1.90
2.74
30.40
310.96
71479700
7S3600
753600
753600
753600
79416CO
7811500
7681400
7551300
75.3600 74Pi?oo
538400
538400
5384CO
538400
5.3.8400
376800
376800
376800
376800
226 &QQ
161600
161600
161600
161600
IMfQO
161600
141600
161600
161600
161&OO
13728000
0.15
0.22
2.39
24.47
5906900
PROCESS COST OVER LIFE OF
1.81
2.61
28.95
296.10
0.15
0.22
2.39
24.46
6349600
6219500
6089400
5959300
•» R?Q?fln
4963900
4833800
4703700
4573500
4443.4QQ
3254100
3124000
2993900
2863800
2233700- ...
2603600
2473500
2343400
2213300
2QB.3.20Q
160718300
1.7S
2.52
28.01
286.49
65572800
POWER UNIT
1.66
2.39
26.56
271.64
49601100
57412600
65094000
72645300
8.2&665.£0
86416100
92635600
98725000
104684300
1105.135.uO
115477490
120311200
125014900
129588400
134Q3.1BQ3
137265900
1404C9900
143403800
146267600
149001100
1516C49LO
154078400
156421800
158635100
_16fl21fi300
-------
Table B-145. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(500-MW existing oil-fired power unit, 2.5% S in fuel;
90% SO* removal; 8.6 tons/hr 100% HtSO*)
Investment, $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
common feed plenum, mist eliminators, pumps, and all ductwork
between outlet of supplemental fan and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in to
existing duct and inlet to supplemental fan)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulf uric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2 S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
138,000
180,000
4,015,000
263,000
999,000
511,000
716,000
826,000
2,398,000
214,000
429,000
1.1
1.5
33.2
2.2
8.3
4.2
5.9
6.8
19.9
1.8
3.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
812,000
575,000
12,076,000
1.449,000
1,570,000
845,000
1,328,000
17,268,000
1,727,000
1,381,000
20,376,000
6.7
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
"Basis:
Stack gas reheat to 175 P by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Construction labor shortages with accompanying overtime pay incentive not considered.
316
-------
Table B-146. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing oil-fired power unit, 2.5% S in fuel;
90% S0j removal; 60,200 tons/yr 100% HtSOA )
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium oxide (98%) 592 tons 155.00/ton
Coke 41 6 tons 15.00/ton
Catalyst 981 liters 1.65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 32,520 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 5,557,000 gal 0.23/gal
Heat credit 1 1 ,1 00 MM Btu -1 ,60/MM Btu
Process water 1,268,800 M gal 0.05/M gal
Electricity 34,030,000 kWh 0.018/kWh
Maintenance
Labor and material, .07 x 12,076,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 5.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
100%HiS04 oil burned Mills/kWh
Equivalent unit operating cost 121.41 1.42 2.09
91,800
6,200
1,600
99,600
260,200
1,278,100
(17,800)
63,400
612,500
845,300
81,600
3,123,300
3,222,900
3,117,500
624,700
343,600
4,085,800
7,308,700
Cents/million
Btu heat input
22.70
Percent of
total annual
operating cost
1.26
0.08
0.02
1.36
3.56
17.48
(0.24)
0.87
8.38
11.57
1.12
42.74
44.10
42.65
8.55
4.70
55.90
100.00
Dollars/ton
sulfur removed
371.75
"Basis:
Remaining life of power plant, 25 yr.
Oil burned, 5,145,400 Ijbl/yr, 9,200 Btu/kWh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $20,376,000; subtotal direct investment, $12,076,000.
Working capital, $569,900.
317
-------
Table B-147
KA6NE5I* SLURRY-REGENERATION PROCESS. SOX MW EXISTING OIL FIRED POWER UNIT, 2.5* S IN FUEL, 90* 502 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENT* * 20376000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KH-HR/
START KW
1
2
3
4
6 7000
7 7000
8 7000
9 7000
10 7.Q0Q-
11 5000
12 5000
13 5000
14 5000
is SQ00,
16 3500
17 3500
18 3500
19 3500
_2Q 3.50,fl_
21 1500
22 1500
23 1500
24 1500
_25_ 1?QO
26 1500
27 1500
28 1500
29 1500
•*o ison
TOT 92500
LIFETIME
POWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION
MILLION BTU BARRELS OIL
/YEAR /YEAR
322COOOO 5145400
32200000 5145400
322COOOO 5145400
32200000 5145400
*%??finnnn si &s&nn
23000000 3675300
2300000C 3675300
230COOOO 3675300
23000000 3675300
23DPQQOO 1675300
16100000 2572700
16100000 2572700
161COOOO 2572700
16100000 2572700
16100000 2S73TQQ
6900000 1102600
6900000 1102600
6900000 1102600
6900000 1102600
690000Q J'Q?4PO
69COOOO 1102600
6900000 1102600
6900000 1102600
6900000 1102600
fciJOODDD 1 lO9&Aft
4255COOOO 67993000
AVERAGE INCREASE (DECREASE
DOLLARS PER BARREL
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
BY EQUIVALENT NET REVENUE, REGULATED
POLLUTION TONS/YEAR »/TON ROI FOR
, CONTROL
PROCESS,
TONS/YEAR
19700
19700
19700
19700
19700
14000
14000
14000
14000
jtnan
9800
9800
9800
9800
Oft Of!
4200
4200
4200
4200
^>nn
4200
4200
4200
4200
&7DO
259500
1 IN UNIT OPERATING
OF OIL BURNED
POWER
100» 100« COMPANY,
H2S04 H2S04 «/YEAR
60200 . 6.00 9427800
60200 8.00 9258300
60200 8.00 9088800
60200 8.00 8919200
TOTAL
NET
SALES
REVENUE,
t/YEAR
481600
481600
481600
481600
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
1 DECREASE)
IN COST OF
POWER,
S
8946200
8776700
8607200
8437600
(DECREASE)
IN COST OF
POWER,
i
89462CO
17722900
26330100
3*767700
&n2nn A . nn AT&QTQQ &BIISQO R ?f»n i GQ ^^Q^SAQQ
43000 8.00 7541300
43000 8.00 7371800
43000 8.00 72C2300
43000 8.00 7032700
63000
30100
30100
30100
30100
'01 00
12900
12900
12900
12900
1 24OO
12900
12900
12900
12900
1 >*flO
795500
COST
MILLS PER ML OK ATT -HOUR
PROCESS C3ST
LEVELIZED
CENTS PER MILLION
DOLLARS PER TON OF
BTU HEAT INPUT
SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
.no fe&fci^on
.00 5884600
.00 5715100
.00 5545600
.00 5376000
DQ *i.?Cft5QO
.00 3878800
.00 3709300
.00 3539800
.00 3370200
no 42flft7nn
.00 3031200
.00 28*1700
.00 2692200
.00 2522600
oo ?^*i^iOfi
140342500
2.06
3.03
32.98
540.82
64532400
344000
344COO
344COO
344000
34fcOQQ
240800
240800
240800
240800
7197300
7027800
6858300
6688700
6519200
5643800
5474300
5304800
5135200
5023310C
57260900
64119200
70807900
TJ jr» "J llftfi
82970900
88*45200
93750000
98885200
?&a«nn <,9fe5200 __1H1«SQ9OO
103200
103200
103200
103200
1C *?00
103200
103200
103200
103200
invpn
6364000
0.09
0.13
1.49
24.53
3139100
INlxZtJE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS TSK ?*SREL
MILLS PER KILQ»*i<~
CENTS PER MILLION
DOLLARS PER TON OF
OF OIL BURNED
-;:ry»
BTU HEAT lii?«I7
SU.FUR REMOVED
1.92
2.63
30.73
503.77
0.09
0.14
1.50
24.51
3775600
3606100
3436600
3267000
3QQ7Cfif)
2928000
2758500
2589000
2419400
.2.2&9QflO
133978500
1.97
2.90
31.49
516.29
61393300
POWER UK IT
1.83
2.69
29.25
479.26
107626500
111232600
114*69200
117936200
1 >1 Q1^7f)Q
1239*1700
12*720200
1293C9200
131728600
t 4997 A ^fiO
-------
Table B-148. Magnesia Slurry-Regeneration Process
Summary of Estimated Fixed Investment3
(1,000-MW new oil-fired power unit, 2.5% S in fuel;
90% SO^ removal; 16.3 tons/hr 100%HiSOn)
Investment. $
Percent of subtotal
direct investment
Magnesium oxide and coke receiving and storage (pneumatic
conveyor and blower, hoppers, conveyors, elevators, and
storage silos)
Feed preparation (weigh feeders, conveyors, elevators,
slurrying tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
common feed plenum, mist eliminators, pumps, and all
ductwork between common feed plenum and inlet of fan)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fan and stack gas plenum)
Slurry processing (screens, tanks, pumps, agitators and heating
coils, centrifuges, conveyors, and elevators)
Drying (fluid bed dryer, fans, combustion chamber, dust collectors,
conveyors, elevators, and MgS03 storage silo)
Calcining (fluid bed calciner, fans, weigh feeders, conveyors,
elevators, waste heat boiler, dust collectors, and recycle
MgO storage silo)
Sulfuric acid plant (complete contact unit for sulfuric acid
production including dry gas purification system)
Sulfuric acid storage (storage and shipping facilities for
30 days production of H2 S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
196,000
243,000
4,906,000
431,000
708,000
726,000
991,000
1,130,000
3,261,000
284,000
431,000
1.3
1.6
32.8
2.9
4.7
4.8
6.6
7.6
21.8
2.9
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
942,000
712.000
14,961,000
1,496,000
1,496,000
748,000
1,346,000
20.047,000
2.005,000
1,604,000
23,656,000
6.3
_i8_
100.0
10.0
10.0
5.0
9.0
134.0
13.4
10.7
158.1
"Basis:
Stack gas reheat to 175° F by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
319
-------
Table B-149. Magnesia Slurry-Regeneration Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW new oil-fired power unit, 2.5% S in fuel;
90% S0j removal; 1 13,900 tons/yr 100% HtS04 )
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Magnesium oxide (98%) 1,108 tons 155.00/ton
Coke 787 tons 15.00/ton
Catalyst 1 ,856 liters 1 .65/liter
Subtotal raw material
Conversion costs
Operating labor and
supervision 39,200 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 9,399,000 ga! 0.23/gal
Heat credit 20,900 MM Btu -1.60/MM Btu
Process water 2,399,600 M gal 0.04/M gal
Electricity 58,990,000 kWh 0.017/kWh
Maintenance
Labor and material, .06 x 14,961,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing,
1 1% of conversion costs
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
100%H2S04 oil burned Mills/kWh
Equivalent unit operating cost 85.30 1.00 1.39
171,700
11300
3,100
186,600
313,600
2,161,800
(33,400)
96,000
1,002,800
897,700
145,200
4,583,700
4,770,300
3,524,700
916,700
504,200
4,945,600
9,715,900
Cents/million
Btu heat input
15.95
Percent of
total annual
operating cost
1.77
0.12
0.03
1.92
3.23
22.25
(0.34)
0.99
10.32
9.24
1.49
47.18
49.10
36.27
9.44
5.19
50.90
100.00
Dollars/ton
sulfur removed
261.32
Remaining life of power plant, 30 yr.
Oil burned, 9,731.500 bbl/yr. 8,700 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stroam time, 7.000 hr/yr.
Midwest plant location, 197S operating costs.
Total capital investment, $23,656,000; subtotal direct investment, $14,961,000.
Working capital, $844,200.
320
-------
Table B-150
MAGNESIA SLURRY-REGENERATION PROCESS. 10CO MW NEW OIL FIRED POWER UNIT, 2.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO ECON.
FIXED INVESTMENT: $ 23656000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE, INCLUDING
YEARS ANNUAL fOWER UNIT POWER UNIT BY EQUIVALENT HET REVENUE, REGULATED
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR
POWER TICiN. REQUIREMENT. CONSUMPTION, CONTROL POWER
UNIT KW-HR/ MILLION BTU BARRELS OIL PROCESS, 100* 100* COMPANY,
START KW /YEAR /YEAR TONS/YEAR
1 7000 609COOOO 9731500 37200
2 7000 609COOOO 9731500 37200
3 7000 60900000 9731500 37200
4 7COO 6C900000 9731500 37200
5 7000 60.90.nanO 9711500 37200
b 7000 609COOOO 9731500 37200
7 7000 60900000 9731500 37200
8 7000 609COOOO 9731500 37200
9 7000 60900000 9731500 37200
10 7000 60900000 9731500 37?00
11 5000 435COOOO 6951100 26600
12 5000 4350COOO 6951100 26600
13 5COO 43500000 6951100 26600
14 5000 435COOOO 6951100 26600
IS 5QQQ 435OQQCQ ^9^1100 766.00
16 3500 30450000 4865800 18600
17 3500 30450000 4865800 18600
18 3500 30450000 4865800 18600
19 3500 30450000 4865800 18600
20 .3500..,.. 304*0100 4065.800 , ,. i«fcfin
21 1500 13050000 2085300 BOOO
22 1500 13050000 2085300 BOOO
23 1500 13050000 2085300 8000
24 1500 13050000 2085300 BOOO
25 1500 130500.00- _ 20B51QO tOOO
26 1500 13050000 20B5300 BOOO
27 1500 13050000 2085300 BOOO
28 1500 13050000 2085300 BOOO
29 1500 13050000 2CB5300 BOOO
'0 1500 130">nofln *o«*»f»n »nnn
TOT 127500 1109250000 177252500 678000
LIFETIME AVERAGE INCREASE (DECREASE! IN UNIT OPERATING
DOLLARS PER BARREL Of OIL BURNED
HILLS PER KILOHATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
H2S04 H2S04
113900
113900
113900
113900
113900
113900
113900
113900
113900
-113900- (
81400
81400
81400
81400
. A14QQ
56900
56900
56900
56900
5ft90Q
24400
24400
24400
24400
9&Aon
24400
24400
24400
24400
2&AOQ
.00
.00
.00
.00
-00
.00
.00
.00
.00
^oo
.00
.00
.00
.00
uoo_
.00
.00
.00
.00
.no
.00
.00
.00
.00
nOO
.00
.00
.00
.00
_ on
2074500
COST
LEVELIZED INCREASE (DECREASE) I* UNIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER BARREL OF OIL BURNED
HILLS PER KILOWATT-HCUR
CENTS PER MILLION BTL HEAT INPUT
DOLLARS PER TON OF SLLFUR REMOVED
t/YEAR
12176900
12012900
11848900
11684900
1 1*20400
11356900
11192900
11028900
10864900
i mnfl^no
8942700
8778700
8614700
8450600
6894000
6730000
6566000
6402000
•V7 ^iinnn
4349000
41B5000
4021000
3B57000
"9.1000
352B900
3364900
3200900
303*900
2«T7«nn
22*401800
1.2B
1.7B
20.41
333.93
93104400
TOTAL
NET
SALES
REVENUE,
$/VEAR
911200
911200
911200
911200
911200.
911200
911200
911200
911200
_S112QQ
651200
651200
651200
651200
fcm 700
455200
455200
455200
455200
....455200
195200
195200
195200
195200
]«s;f)(i
195200
195200
195200
195200
1952QQ
16596000
0.10
0.13
1.50
24.48
7142000
PROCESS COST OVER LIFE OF
1.22
1.70
19.51
319.29
0.09
0.13
1.50
24.49.
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
t
11265700
11101700
10937700
10773700
...10609700...
10445700
10281700
10117700
9953700
si&saoa
8291500
8127500
7963500
7799400
2625400- —
6436800
6274800
6110800
5946800
c^M PA OQ
4153800
3989800
3825800
3661800
1497BOP
3333700
3169700
3005700
2B41700
•?i6?T jfOO
209605600
1.18
1.65
18.91
309.45
85962400
POWER UNIT
1.13
1.57
18.01
294. BO
$
11265700
22367400
33305100
4407BBOO
54A«V«no
65134200
75415900
85533600
95487300
1 QS?77AftO
113568500
121696000
129659500
137458900
1*5.09* *f">
151533100
157807900
163918700
169865500
t 7 S AaV A "JO O
179802100
183791900
187617700
191279500
144T77300
198111000
201280730
204286400
207128100
2Q9fiQ5'Qft
-------
Table 8-151. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment9
(200-MW new, coal-fired power unit, 3.5% S in fuel;
90% SO-i removal; 1.9 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Participate scrubbers and inlet ducts (2 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, and fly ash neutralization
facilities)
Sulfur dioxide scrubbers and ducts (2 scrubbers including
mist eliminators, pumps, and exhaust gas ducts to
inlet of fan)
Stack gas reheat (2 indirect steam reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystal! izer, feed coolers, centrifuge, rotary dryer,
steam/air heater, fan, dust collectors, feeders,
tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process steam,
water, and electricity from power pjant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
129,000
1,704,000
1,831,000
227,000
392,000
838,000
1,454,000
1,785,000
123,000
125.000
1.4
17.9
19.2
2.4
4.1
8.8
15.2
18.7
1.3
1.3
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
471,000
454,000
9,533,000
1,239,000
1,239,000
667,000
1,049,000
13,727,000
1,373,000
1,098,000
16,198,000
4.9
4.8
100.0
13.0
13.0
7.0
11.0
144.0
14.4
11.5
169.9
aBasis:
Stack gas reheat to 175 by indirect steam reheat. ,
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for seating, mid-1974.
Minimum in process storage; only pumps are spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
322
-------
Table B-152. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MWnew coal-fired power unit, 3.5% S in fuel;
90% S02 removal; 13,370 tons/yr sulfur)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw materials
Lime (1st stage neutralization) 54.8 tons 26.00/ton
Soda ash 3,800 tons 52.00/ton
Antioxidant 130 ,000 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 36,100man-hr 8.00/man-hr
Utilities
Natural gas 208,300 mcf 1.00/mcf
Steam 874,100 M Ib 0.80/M Ib
Heat credit 25,700 MM Btu -0.60/MM Btu
Process water 4,070,000 M gal 0.03/M gal
Electricity 30,320,000 kWh 0.011/kWh
Maintenance
Labor and material, .07 x 9,533,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
Equivalent unit operating cost 446.65 11.13 4.27
1,400
197,600
260,000
4,900
463,900
288,800
208,300
699,300
(15,400)
122,100
333,500
667,300
58,200
2,362,100
2,826,000
2,413,500
472,400
259,800
3,145,700
5,971,700
Cents/million
Btu heat input
46.36
0.02
3.31
4.35
0.08
7.77
4.84
3.49
11.72
(0.26)
2.04
5.58
11.17
0.97
39.55
47.32
40.42
7.91
4.35
52.68
100.00
Dollars/ton
sulfur removed
407.07
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $16,198,000; subtotal direct investment, $9,533,000.
Working capital, $505,800.
Investment and operating cost for disposal of fly ash excluded.
323
-------
Table B-153
SODIUM SOLUTIQN-S02 REDUCTION PROCESS, 200 HH NEW COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT: t i6i9sooo
YEARS ANNUAL
AFTER OPERA-
POMER TION.
UNIT KW-HR/
START KU
1
2
3
ft
5
6
7
8
9
_LQ
11
12
13
14
-OS
16
17
18
19
?n
21
22
23
24
_2S
26
27
28
29
'0
7000
7000
7000
7000
7QOO
7000
7000
7000
7000
7onn
5000
5000
5000
SOOO
50flQ
3500
3500
3500
3500
^500
1500
1500
1500
1500
ison
1500
1500
1500
1500
isnn
TOT 127500
LIFETIME
PROCESS COST
LEVELIZEO
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS, SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
12880000 536700 14700
12680000 536700 14700
12880000 536700 14700
12880000 536700 14700
l^uBcqnn si&7nn i47no
12880000 536700 14700
12S80000 536700 14700
12880000 536700 14700
12380000 536700 14700
I2««nnnn' i^«.7f»n i«.7nn .
9200000 383300 10500
9200000 363300 10500
9200900 383300 10500
9200000 383300 10500
"OOQ09 38330O tnsnn
6440000 268300 7300
6440000 268300 7300
6440000 268300 7300
6440000 268300 7300
&46OnflO 7«83nO 73OQ
2760000 115000 3100
2760000 115000 3100
2760000 115000 3100
27600CO 115000 3100
P7*,nnnn ii«;non 3100
2760000 115000 3100
2760000 115000 3100
2760000 115000 3100
2760000 115090 3100
27&nnnn J!«pnnr> , , a inn
13400
13400
13400
13400
t34nn
13400
13400
13400
13400
l^*.or>
9600
9600
9600
9600
<»<-nn
6700
6700
6700
6700
fcinn
2900
2900
2900
2900
?«OQ
2900
2900
2900
2900
yttaa
5300
5300
5300
5300
*.nn
20.00
20.00
20.00
20.00
?o.nn
20.00
20.00
20.00
20.00
yn.nn
20.00
20.00
20.00
20.00
7ft.no
20.00
20.00
20.00
20.00
pn_nn
20.00
20.00
20.00
20.00
7O.OO
20.00
20.00
20.00
20.00
>n_r»n
7656800
7544500
7432200
7319900
7?a?*An
7095300
6983000
6870700
6758400
&&&&inn
5656600
5544300
5432000
5319700
5?o?&an
4411300
4299000
4186700
4074400
?OA?)QQ
2868.800
2756500
2644200
2531900
?61«fc<>G
2307300
2195000
2082700
1970400
itcsmi-in
143242500
14.65
5.62
61.06
536.49
50503900
DISCOUNTED PROCESS COST OWES
13.91
5.33
57.95
508.29
441000
44-1000
441000
441000
&&ioan
441000
441000
441000
441000
44*000
316000
316000
316000
316000
31600O
221500
221500
221500
221500
>?i^nn
94500
94500
94500
94500
..S*50Q^
94500
94500
94500
94500
o&snn
8042500
0.82
0.32
3.43
30.12
3458900
LIFE OF
0.82
a. 31
3.42
30.05
NET ANNUAL
INCREASE
(DECREASE!
IN COST OF
POWER,
»
7215800
7103500
&991200
6878900
f.->t,f.f.nn
6654300
6542000
6429700
6317400
Ajnniriri
5340600
5228300
5116COO
5003700
4841400
4189300
4077500
3965200
3S5290C
?7&n«.nn
2774300
2662000
2549700
2437400
?T?sifln
2212800
2100500
1988200
1875900
]7&3i.on
135200000
13.83
5.30
57.63
506.37
55045000
?QUER UNIT
13.09
5.02
54.53
478.24
CUMULATIVE
NET INCREASE
(DECREASE 1
IN COST OF
POWER.
t
7215800
14319300
21310500
2 t 18 9400
4iS.OO
72445100
77673400
82789400
87793100
«5?fcH&i;nr> :
96874300
100951800
104917000
108769900
H?*incnn
115284800
117946800
120496SOO
122933900
H2«?«eaoQ
127471*00
129572300
131560500
133436400
ii^nnnon
-------
Table B-154. Sodium Solution-SOj Reduction Process
Summary of Estimated Fixed Investment3
(200-MW existing, coal-fired power unit, 3.5% S in fuel;
90% S0t removal; 2.0 tom/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (2 scrubbers including
mist eliminators, pumps, and all ductwork between outlet
of supplemental fans and stack gas plenum)
Stack gas reheat (2 direct oil-fired reheaters)
Fans (2 fans including ducts and dampers between tie-in
to existing duct and inlet to supplemental fans)
Purge treatment (refrigeration system, chiller -
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors,
elevator, and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
packaged boiler, heaters, condensers, strippers,
compressers, tanks, agitators, and pumps)
Sulfur dioxide reduction unit'
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
145,000
2,569,000
129,000
548,000
913,000
1,780,000
1,967,000
146,000
483,000
1.5
26.5
1.3
5.6
9.4
18.4
20.3
1.5
5.0
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
548,000
461,000
9,689,000
1,356,000
1,453,000
872,000
1,163,000
14,533,000
1,453,000
1,163,000
17,149,000
5.7
4.8
100.0
14.0
15.0
9.0
12.0
150.0
15.0
12.0
177.0
"Basis:
Stack gas reheat to 17S°by direct oil-fired teheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 20 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
325
-------
Table 8-155. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW existing coal-fired power unit, 3.5% S in fuel;
90% S03 removal; 13,800 tons/yr sulfur)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Soda ash 3,900 tons 52. 00 Aon
Antioxidant 1 33,900 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 36,100 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 7,255,000 gal 0.23/gal
Natural gas 215,100mcf 1.00/mcf
Heat credit 26,500 MM Btu -0.60/MM Btu
Process water 4,202,300 M gal 0.03/M gal
Electricity 21,170,000 kWh 0.011/kWh
Maintenance
Labor and material, .07 x 9,689,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
Equivalent unit operating cost 534.62 13.31 5.27
202,800
267,800
5,100
475,700
288,800
1,668,700
215,100
(15,900)
126,100
232,900
678,200
58,200
3,252,100
3.727,800
2,726,700
650,400
272,800
3,649.900
7,377,700
Cents/million
Btu heat input
55.47
Percent of
total annual
operating cost
2.75
3.63
0.07
6.45
3.91
22.62
2.92
(0.22)
1.71
3.16
9.19
0.79
44.08
50.53
36.95
8.82
3.70
49.47
100.00
Dollars/ton
sulfur removed
486.98
aBasis:
Remaining life of power plant, 20 yr.
Coal burned, t554,200 tons/yr, 9,500 Btu/kWh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $17,149,000; subtotal direct investment, $9,689,000.
Working capital, $653,500.
Investment and operating cost for disposal of fly ash excluded.
326
-------
Table B-156
SODIUM SOLUTION-S02 REDUCTION PROCESSt 200 MW EXISTING COAL FIRED POKER UNIT. 3.5* S IN FUEL. 90* S02 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT: *
17149000
SULFUR BY-PRODUCT
REMOVED RATE.
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TION, REQUIREMENT, CONSUMPTION. CONTROL
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS, SODIUM
START KW /YEAR /YEAR TONS/YEAR SULFUR SULFATE
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
*/TON KOI FOR
POWER
SODIUM COMPANY,
SULFUR SULFATE J/YEAR
TOTAL
NET
SALES
REVENUE,
S/YEAK
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
t S
1
2
3
4
5
6
7
9
10
11
12
13
14
5000
5000
5000
5000
950COOO 395800 10800 9900
9500000 395800 10800 9900
9500000 395800 10800 9900
9500000 395800 10800 9900
3900
3900
3900
3900
25.00
25.00
25.00
25.00
20.00
20.00
20.00
20.00
.,15. , loon ocnnnnn losann in ROD 91100 -*«on 71.00 yn.nn
16
17
18
19
21
22
23
24
?5
26
27
28
29
_JO_
TOT S
3500
3500
3500
3500
3SD.Q
1500
1500
1500
1500
1500
1500
1500
1500
1500
1100
7500
LIFETIME
PROCESS
6650000 277100 7600 6900
6650300 277100 7630 6900
6650000 277100 7600 6900
6650000 277100 7600 6900
66SOOOO .. .. ?TMon 7*00 4.900
2850000 118700 3200 3000
2850000 118700 3200 3000
2B500C3 118700 3200 3000
2850000 118700 3200 3000
jftSfinoo 118700 ^POO inno
2850000 118700 3200 3000
2850000 118700 3200 3000
2850000 118700 3200 3000
2850000 118700 3200 3000
jasnnnn IIRTOO *?oo 1000
109250000 4551500 124000 114000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
2700
2700
2700
2700
230.0.
1200
1200
1200
12CO
l?00
1200
1200
1200
1200
1700
45000
25.00
25.00
25.00
25.00
>^ * no
25.00
25.00
25.00
25.00
jt » no
25.00
25.00
25.00
25.00
}** ^ no.
20.00
20.00
20.00
20.00
7O.OO
20.00
20.00
20.00
20.00
?0-00
20.00
20.00
2&.00
20.00
?n.on
COST DISCOUNTED AT 13.3* TO INITIAL YEAR, DOLLARS
LEVELUED
INCREASE (DECREASE) IN UNIT OPERATING COiT EQUIVALENT TO
DOLLARS PER TON OF CCAL BURNED
MILLS ?£R KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
7970300
7791900
7613600
7435200
77S&400
6159700
5981300
5803000
5624600
S&64i'3nO
3974500
3796100
3617800
3439400
t?Jfcl IflQ
3082700
2904300
2726000
2547600
^lAQ^no
9*801600
21.71
8.59
90.44
796.79
50569900
DISCOUNTED PROCESS COST OVER
20.78
8.22
86.57
761.59
325500
325500
325500
325500
^?^5QQ
226500
226500
226500
226500
»fk*fton
99000
99000
99000
99000
oonon
99000
99000
99000
99000
QQonn
3750000
0.83
0.32
3.44
30.24
2001600
LIFE OF
0.82
0.32
3.41
30.14
7644800
7466400
7288100
7109700
691 16OO
5933200
5754800
5576500
5398100
5 ? 1 QJIOft
3875500
3697100
3518800
3340400
31621PO
2983700
2805300
2627000
2448600
?^7fl^QO
95051600
20.88
8.27
87.00
766.55
48568300
POWER UNIT
19.96
7.90
83.14
731.45
7644800
15111200
22399300
29509000
3646 O4DO
42373600
48128400
53704900
59103000
A&%??Afin
68198300
71895400
75414200
78754600
•141670O
84900400
87705700
90332700
92781300
9*50*5 Ilk Of)
to
-J
-------
Table B-157. Sodium Solution—SOj Reduction Process
Summary of Estimated Fixed Investment3
(500-MW existing coal-fired power unit, 3.5% S in fuel;
90% SO2 removal; 4.8 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and all ductwork between outlet
of supplemental fans and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in
to existing duct and inlet to supplemental fans)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors,
elevator, and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
packaged boiler, heaters, condensers, strippers,
compressers, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
251,000
5,938,000
305,000
1,238,000
1,593,000
3,304,000
3,200,000
267,000
752,000
1.4
32.1
1.6
6.7
8.6
17.9
17.3
1.4
4.1
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
766,000
881,000
18,495,000
2,219,000
2,404,000
1,295,000
2,034,000
26,447,000
2,645,000
2,116,000
31,208,000
4.1
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
aBasis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction tabor shortages with accompanying overtime pay incentive not considered.
328
-------
Table B-158. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing coal-fired power unit, 3.5% Sin fuel;
90% SOi removal; 33,420 tons/yr sulfur)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw materials
Soda ash
Antioxidant
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Natural gas
Heat credit
Process water
Electricity
Maintenance
Labor and material, .06 x
Analyses
9,500 tons
324,1 00 Ib
46,500 man-hr
17,567 ,000 gal
520,800 mcf
64,300 MM Btu
10,1 74,400 M gal
5 1,260 ,000 kWh
18,495,000
52.00/ton
2.00/lb
8.00/man-hr
0.23/gal
1.00/mcf
•0.60/MM Btu
0.02/M gal
0.010/kWh
Subtotal conversion costs
494,000
648,200
12,300
1,154,500
372,000
4,040.400
520,800
(38,600)
203,500
512,600
1,109,700
109,900
6,830,300
3.37
4.42
0.08
7.87
2.54
27.56
3.55
(0.26)
1.39
3.50
7.57
0.75
46.60
Subtotal direct costs
7,984300
54.47
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
4,774,800
32.58
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
product sulfur
438.60
Dollars/ton
coal burned
10.92
1,336,100
532,300
6,673,200
14,658,000
Cents/million
Mills/kWh Btu heat input
4.19 45.52
9.32
3.63
45.53
100.00
Dollars/ton
sulfur removed
399.62
"Basis:
Remaining life of power plant, 25 yr.
Coal burned, 1.341,700Q tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $31,208,000; subtotal direct investment, $18,495,000.
Working capital, $1,397,000.
Investment and operating cost for disposal of fly ash excluded.
329
-------
Table B-159
SODIUM SOLUTIQN-S02 REDUCTION PROCESS, SCO MW EXISTING COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90% 502 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT: $
31208000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KU-HR/
START KW
1
2
3
4
6
7
8
9
1 Q
11
12
13
14
15
16
17
18
19
?n
21
22
23
24
J5
26
27
28
29
7000
7000
7000
7000
7OOO
5000
5000
5000
5000
soon
3500
3500
3500
3500
ocnn
1500
1500
1500
1500
-ISJID—
1500
1500
1500
1500
3Q 1SOO
TOT
92500
L1FETIHE
PROCESS COST
LEVtLIZEO
SULFUR BY-PRODUCT
REHOVED RATE.
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TOMS/YEAR
REQUIREMENT, CONSUMPTION. CONTROL
MILLION BTU TONS COAL PROCESS, SODIUM
/YEAR /YEAR TOMS/YEAR SULFUR SULFATE
32200000 1341700 36700
32200000 1341700 36700
32200000 1341700 36700
32200000 1341700 36700
•^jjonnno it*i7fin ^*7no
23000000 958300 26200
23000000 958300 26200
23000000 958300 26200
23000000 958300 26200
p^flOQOfiQ Q*5 A^nn ?*» ?n o
16100000 670800 18300
16100000 670800 18300
16100000 670800 18300
16100000 670800 18300
lAinnnnn &7Qiinn tmnn
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
69000QQ 2ft.75.QQ 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
£.900000 287*00 7*00
425500000 17729000 485000
33400
33400
33400
33400
^3&nn
23900
23900
23900
23900
?^9OD
16700
16700
16700
16700
1*700
7200
7200
7200
7200
7jnn
7200
7200
7200
7200
-Z2C.O
442000
13300
13300
13300
13300
13^00
9500
9500
9500
9500
Q*ifln
6600
6600
6600
6600
6&Q D
2800
2800
2800
2800
TOTAL
OP. COST
. INCLUDING
NET REVENUE, REGULATED
t/TON R01 FOR
POWER
SQDIUH COMPANY,
SULFUR SULFATE »/YEAR
25.00
25.00
25. CO
25.00
js.nn
25.00
25.00
25.00
25.00
7 *» f\r\
25.00
25.00
25.00
25.00
?^^ no
25.00
25.00
25.00
25.00
?8QO J5.no
2800
2800
2800
2800
280O
175000
25.00
25.00
25. CO
25.00
y^ f)0
20
20
20
20
?n
20
20
20
20
20
20
20
20
?fl
20
?o
20
20
70
20
20
20
20
?n
.00
.00
.00
.00
^c.o_
.00
.00
.00
.00
.no
.00
.00
.00
.00
.00
.00
.00
.00
.00
-00
.00
.00
.00
.00
17903700
17644000
17384400
171247CC
1 fifi fa^.10 Q
13989600
137300CO
13470300
13210700
1 2
-------
Table B-160. Sodium Solutlon-SOj Reduction Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 2.0% S in fuel;
90% SOi removal; 2.7 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Participate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, and fly ash neutralization
facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and exhaust gas ducts to
inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
steam/air heater, fan, dust collectors, feeders,
tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process steam,
water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
159,000
3,846,000
4,269,000
539,000
889,000
1,035,000
1,837,000
2,147,000
155,000
195,000
1.0
23.3
25.8
3.3
5.4
6.2
11.1
13.0
0.9
1.2
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
662,000
787,000
16,520,000
1,817,000
1,817.000
826,000
1,652,000
22,632,000
2,263,000
1.811,000
26.706,000
4.0
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
"Basis:
Stack gas reheat to 175 by indirect steam reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Fly-ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
331
-------
Table B-161. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics*
(500-MW new coal-fired power unit, 2.0% Sin fuel;
90% S02 removal; 18,680 tons/yr sulfur)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw materials
Lime (1st stage neutralization) 76.6 tons 26.00/ton
Soda ash 5,300 tons 52.00/ton
Antioxidant 181, 200 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 38,600 man-hr 8.00/man-hr
Utilities
Natural gas 291,100mcf 1.00/mcf
Steam 1,401 ,600 M Ib 0.70/M Ib
Heat credit 35,900 MM Btu -0.60/MM Btu
Process water 5,760,200 M gal 0.02/M gal
Electricity 65,230,000 kWh 0.010/kWh
Maintenance
Labor and material, .06 x 16,520,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
Equivalent unit operating cost 487.24 6.93 2.60
2,000
275,600
362.400
6,900
646,900
308,800
291,100
981,100
(21,500)
115,200
652,300
991,200
98,300
3,416,500
4,063,400
3,979,200
683,300
375,800
5,038,300
9,101,700
Cents/million
Btu heat input
28.89
0.02
3.03
3.98
0.08
7.11
3.39
3.20
10.78
(0.24)
1.27
7.17
10.89
1.08
37.54
44.65
43.71
7.51
4.13
55.35
100.00
Dollars/ton
sulfur removed
443.99
aBasis:
Remaining life of power plant, 30 yt.
Coal burned, l,312,SOCMons/yr,9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $26,706,000; subtotal direct investment, $16,520,000.
Working capital, $726,900.
Investment and operating cost for disposal of fly ash excluded.
332
-------
Table B-162
SODIUM SOLUTION-S02 REDUCTION PROCESS, SCO HW NEW COAL FIRED POWER UNIT. 2.0* S IN FUEL. 90% S02 REMOVAL. REGULATED CO ECON
FIXED INVESTMENT: s 26706000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-KR/
START KW
1
2
3
4
6
7
3
9
10
7000
7000
7000
7000
MOO
7000
7000
7300
7000
7QOO
11 5303
12 5000
13 5000
14 5003
16 3500
17 3500
18 3500
19 3500
_2Jl___150fl_
21 1500
22 1503
21 1590
24 1530
26
27
28
29
JO
1500
1500
1503
1530
1SOO
TOT 127500
LIFETIME
PROCESS COST
LEVELIZE3
POWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION.
MILLION STU TONS COAL
/YEAR /YEAR
315COOOO 1312500
31500000 1312500
31500000 1312500
31500003 1312500
31500000 1J12500
31500900 1312503
31500000 U12503
31503900 1312590
31SQOQOO., . .1312500
22500000 9J7500
225000-30 93T500
22500000 937500
22509000 937500
?.>5030P^ 93TSDO
15750000 65S200
15750090 656203
15750000 656200
15759000 656200
]*7<0000 *f*200
6753000 291200
6753339 281200
6750000 281200
6753030 281200
6750000 231200
6750000 281203
6750000 281200
6753000 2J1290
6750000 2Sl?00 .
SULFUR iY-PROOUCT
REMOVED RATE.
•Y EQUIVALENT
POLLUTION TONS/YEAR
CONTROL
PROCESS, SODIUM
TONS/YEAR SULFUR SULFATE
20500
20500
20500
20500
20500
29503
20530
20500
14600
14600
14600
14600
16. Ann
10300
10300
10300
19100
10 *nn
4400
4430
4403
4400
&4QJ
4400
4400
4430
44OO
18700
18700
19700
19700
18700
18700
18700
18700
18700
13300
13300
13300
13300
n»nn
9300
9300
9300
9300
4003
4000
4000
4000
40QQ
4000
4000
4000
43C3
tnnn
7400
7400
7400
7400
7400
7400
7400
7400
5300
5300
5303
5300
«on
3700
3700
3700
S7O8
170 a
1600
1600
1600
1600
1600
1603
1600
1600
ifcnn
573750300 23905539 373500 340030 135000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
SOL:.**; PER ran OF COAL SURHEO
HILLS PER K1LOWATJ-HCUR
TEXTS PER MILLION 3TU HEAT INPUT
DOLLARS PER TUN 3F SU.FUR REMOVED
DISCOUNTED AT 10. Ot fU INITIAL YEAR, DOLLARS
INCREASE in?CRE*S5) 1H UNI7 OPERATING COST eaUIVftLENT TO
DOLLARS PrR TON OF CCAL BURNED
MILLS PER XILQWATJ-HCUR
CENTS °=R MILLION BTU HEAT INPUT
03LLARS PER TON OF SULFUR REMOVE/
TOTAL
OP. COST
INCLUDING
NET Rfc VENUE, REGULATED
I/TON ROI FOR
POWER
SODIUM COMPANY,
SULFUR SULFATE S/YEAR
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
_25~oa_
25.00
25.00
25.00
25.00
25, 901
25.00
25.00
25.00
25.03
75. QQ ,.
20.00
20.00
20.90
20.00
3fi.no
29.00
20.00
20.00
20.00
20.90
20.00
20.00
20.00
JO^OO
20.00
20.00
20.00
20.00
. ?a.ao_
20.00
20.00
20.30
20.00
jn.no
20.00
20.00
20.00
23.00
30.00
11880000
11694900
11509700
11324600
109S4200
10769100
10583900
10398800
8751300
8566200
8381009
6195800
aQ.10_ZQO_
6832700
6647600
4277200
4489700
4304600
4119400
3934200
3563900
3378700
3193600
3008400
?ft?*1OO
221250100
9.26
3.4?
33.56
592.37
90426500
DISCOUNTED PROCESS COST QV
3.79
3.30
36.53
562.70
TOTAL
NET
SALES
REVENUE,
S/VEAR
615500
615500
615500
615500
615500
615500
615500
615500
438503
438500
438500
438500
tutsan
306500
306500
304900
334500
132000
132000
132000
132000
132000
132000
132000
132000
132000—
11200000
0.47
0.18
1.95
29.99
4821600
ER LIFE OF
0.47
9.18
1.96
30.00
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
t
11264500
11079400
10894200
10709100
10338700
10153600
996S400
9783300
450*1 HO
8312800
8127700
7942500
7757300
717J30Q
6526200
6341100
61559&0
5970708
4357700
4172600
3987400
3S92200
3.617100.
3431900
3246700
3061600
2 S 764 00
26,213.0.0.
210050100
8.79
3.29
36.61
562.38
85604900
POWER UNIT
8.32
3.12
34.67
532.70
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
11264500
22343900
33238 10O
43947200
64809COO
74963400
•4931IOO
94715100
112626000
120753700
128696200
136453500
150551900
15*693 OCO
1791*2900
183335500
1*7322900
191125100
198174100
201420100
204482400
20735BSOO
-------
Table B-163. Sodium Solution-SOj Reduction Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% SOi removal; 4.7 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, and fly ash neutralization
facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and exhaust gas ducts to
inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
steam/air heater, fan, dust collectors, feeders,
tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process steam,
water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
225,000
3,846,000
4,269,000
539,000
889,000
1,473,000
2,717,000
2,921,000
227,000
195.000
1.2
20.4
22.6
2.9
4.7
7.8
14.4
15.5
1.2
1.0
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
662,000
898,000
18,861.000
2,075,000
2,075,000
943,000
1,886,000
25,840,000
2,584,000
2,067.000
30,491,000
3.5
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
"Basis:
Stack gas reheat lo 175°by indirect steam reheat.
Midwest plant locution represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
334
-------
Table B-164. Sodium Solution-SO, Reduction Process
Tout Average Annual Operating Costs-Regulated Utility Economics9
(SOO-MW new coal-fired power unit. 3.5% S In fuel;
90% SOi removal; 32, 700 tont/yr sulfur)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Lime (1st stage neutralization) 134.1 tons 26.00/ton
Soda ash 9,300 tons 52.00/ton
Antioxidant 317,100 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 46,500 man-hr 8.00/man-hr
Utilities
Natural gas 509,500 mcf 1.00/mcf
Steam 2,137,800Mlb 0.70/M Ib
Heat credit 62,900 MM Btu -0.60/MM Btu
Process water 9,953,400 M gal 0.02/M gal
Electricity 74,190,000 kWh 0.010/kWh
Maintenance
Labor and material, .06 x 18361,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
Equivalent unit operating cost 354.79 8.84 3.31
3,500
483,600
634,200
12,000
1,133,300
372,000
509,500
1,496,500
(37.700)
199,100
741,900
1.131.700
109,900
4.522,900
5,656,200
4,543,200
904,600
497,500
5,945,300
11,601,500
Cents/million
Btu heat input
36.83
Percent of
total annual
operating cost
0.03
4.17
5.47
0.10
9.77
3.21
4.39
12.90
(0.33)
1.72
6.39
9.75
0.95
38.98
48.75
39.16
7.80
4.29
51.25
100.00
Dollars/ton
sulfur removed
323.34
Remaining life of power plant, 30 yr.
Coal burned. 1,312,500otons/yr, 9,000 Btu/kWh.
Slack gas reheal to 175°K
Power unit on-strcain time, 7,000 hr/yr.
Midwest plant locution, 1975 operating costs.
Total capital investment, $30,491,000; subtotal direct investment, $18,861,000.
Working capital, $1,015,500.
Investment and operating cost for disposal of fly ash excluded.
335
-------
Table B-165
SODIUM SDLUTION-502 REDUCTION PROCESS, SCO HW NEW COAL FIRED POWER UNIT, 3.5X S IN FUEL, 90* S02 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT: $ 30*91000
TOTAL
SULFUR BY-PRODUCT 3P. COST
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
jn 700°
11 5000
12 5000
13 5000
14 5000
i s sooo
16 3500
17 3500
18 3500
19 3500
_2O 35QQ_
21 1500
22 1500
23 1500
24 1500
?5 1500
26 1500
27 1500
28 1500
29 1500
in i«>nn
TOT 127500
LIFETIME
PROCESS COST
LEVEL1ZED
POWER UNIT POWER UNIT
HEAT FUEL
REOUIRENENT, CONSUMPTION
MILLION BTU TONS CCAL
/YEAR /YEAR
31500000
31500000
31500000
31500000
3,1500300
31500000
31500000
3150COOO
31500000
3ISCOQO9
225CCOOO
225COOOO
2250000D
225C0300
15750000
15750000
1575COCO
15750000
6750000
6750000
6750000
6750000
£7saona
6750000
675COOO
6750000
6750000
1312500
1312500
1312500
1312500
1312500
1312500
1312500
1312500
937500
937500
937500
937500
937500
656200
656200
656200
656200
281200
281200
281200
281200
?R]?00
281200
28UOC
261200
281200
?m?nn
REMOVED RATE,
BY EQUIVALENT
POLLUTION TONS/YEAR
. CONTROL
PROCESS, SODIUM
TONS/YEAR SULFUR SULFATE
35900
35900
35900
35900
35900
35900
35900
35900
iionn
25600
25600
25600
25600
17900
17900
17900
17900
17900
7700
7700
7700
7700
7.7.00
7700
7700
7700
7700
77nn
32700
32700
32700
32700
32700
32700
32700
32700
23400
23400
23400
23400
16300
16300
16300
16300
13000
13000
13000
13000
13000
13000
13000
13000
9300
9300
930C
9300
6500
6500
6500
6500
7000 2800
7000 2800
7000 2800
7000 2800
7nnn 2iOJi_
7000 2800
7000 2800
7000 2800
7000 2800
7nnn ?«nn
573750000 23905500 653500 595500 237000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CcNTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10. Ot TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON' OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
SODIUM COMPANY,
SULFUR SULFATE S/YEAR
25.00
25.00
25. CO
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25. CO
25. OC
25.00
25.00
25.00
25.00
25.00
25. CO
25. CO
25.00
25.00
25.00
25.00
25.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
?o.on
20.00
20.00
20.00
20.00
>n,Qn
20.00
20.00
20.00
20.00
?o.nn
20.00
20.00
20.00
20.00
14773500
14562100
14350700
14139300
13716500
13505100
13293600
13082200
10858800
10647400
10436000
10224600
8410800
8199300
7987900
7776500
5391400
5180000
4968600
4757200
6.s&5,fn.r)
4334300
4122900
3911500
3700100
TOTAL
NET
SALES
REVENUE,
»/YEAR
1077500
1077500
1077500
1077500
tO775OO
1077500
1077500
1077500
1077500
1077*00
771000
771000
771000
771000
771000
537500
537500
537500
537500
231000
231000
231000
231COO
231000
231000
231000
231000
231000
274741800 19627500
11.49 0.82
4.31 0.31
47.89 3.43
420.42 30.04
112738600 8446300
DISCOUNTED PROCESS COST OVER LIFE OF
10.96 0.82
4.11 0.31
45.66 3.42
400.78 30.03
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
t
13696000
13484600
13273200
13061800
12639000
12427600
12216100
12004700
10087800
9876400
9665000
9453600
7873300
7661800
7450400
7239000
5160400
4949COO
4737600
4526200
4103300
3891900
3680500
3469100
12S770.P
255114300
10.67
4.00
44.46
390.38
104292300
POWER UNIT
10.14
3.80
42.24
370.75
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
$
13696000
27180600
40453800
53515600
79005000
91432600
103648700
115653400
137534500
147410900
157075900
166S29SOO
J 75771700
183645000
191306800
198757200
205996200
218184200
223133200
227870800
232397000
240815100
244707000
248387SOO
251856600
-------
Table B-166. Sodium Solution-SOj Reduction Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 5.0% S in fuel;
90% S02 removal; 6.7 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, and fly ash neutralization
facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and exhaust gas ducts to
inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
steam/air heater, fan, dust collectors, feeders,
tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressors,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process steam,
water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
281,000
3,846,000
4,269,000
539,000
889,000
1,844,000
3,489.000
3,555,000
289,000
195,000
1.3
18.4
20.5
2.6
4.3
8.8
16.7
17.1
1.4
0.9
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
662,000
993,000
20,851,000
2,294,000
2,294.000
1,043,000
2.085,000
28,567,000
2,857,000
2,285,000
33,709.000
3.2
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
aBasis:
Stack gas reheat to 175°by indirect steam reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
337
-------
Table B-167. Sodium Solution-S02 Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 5.0% S in fuel;
90%SOj. removal; 46,710 tonsfrr sulfur)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Lime (1st stage neutralization) 191 .5 tons 26.00/ton
Soda ash 13,300 tons 52.00/ton
Antioxidant 453,000 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 54,400 man-hr 8.00/man-hr
Utilities
Natural gas 727,800 mcf 1.00/mcf
Steam 2,874,000 M Ib 0.70/M Ib
Heat credit 89,800 MM Btu -0.60/MM Btu
Process water 14,146,700 M gal 0.02/M gal
Electricity 83,120,000 kWh 0.010/kWh
Maintenance
Labor and material, .06 x 20,851 ,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
Equivalent unit operating cost 299.36 10.65 4.00
5,000
691,600
906,000
17,100
1,619,700
435,200
727,800
2,011^00
(53,900)
282,900
831,200
1.251,100
117,700
5,603,800
7,223,500
5,022,600
1,120,800
616,400
6,759,800
13,983,300
Cents/million
Btu heat input
44.39
Percent of
total annual
operating cost
0.04
4.95
6.47
0.12
11.58
3.11
5.21
14.40
(0.39)
2.02
5.94
8.95
0.84
40.08
51.66
35.91
8.02
4.41
48.34
100.00
Dollars/ton
sulfur removed
272.79
aBasis:
Remaining life of powet plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9.000 Btu/kWh.
Stack gas reheat to 175°F,
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $33,709,000; subtotal direct investment, $20,851,000.
Working capital, $ 1,299,700.
Investment and operating cost for disposal of fly ash excluded.
338
-------
Table B-168
SODIUM S&LUTION-S02 REDUCTION PROCESS, 500 MM NEK COAL FIRED POWER UNIT, 5.0* S IN FUEL. 90* S02 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT: * 33709000
U)
OJ
YEARS ANNUAL
AFTER OPERA-
POWER TICK,
UNIT KU-HR/
START KU
1 7000
2 7000
3 7000
4 7000
<; 7nnn
6 7000
7 7000
8 7000
9 7COO
in 7<>nn
11 5000
12 SOOO
13 5000
14 5000
is snnn
16 3500
17 3500
IS 3500
19 3500
?n ^snn
21 1500
22 1500
23 1500
24 1500
7* »*nn
26 1500
27 1500
28 1500
29 1500
in i son
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR BY-PRODUCT
REMOVED RATE.
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS.
/YEAR /YEAR TONS/YEAR SULFUR
31500000 1312500 51300 44700
31500000 1312500 51300 46700
31500000 1312500 51300 46700
31500000 1312500 51300 46700
iiscnnon iii7*nn m inn &A7On
31500000 1312500 51300 46700
31500000 1312500 51300 46700
31500000 1312500 51300 46700
31500000 1312500 51300 46700
iisnnnnn ^ij7snn sunn 4*?00
22500000 937500 36600 33400
22500000 937500 36600 33400
22500000 937500 36600 33400
22500000 937500 36600 33400
77snnnno oi7snn iA&nn i*&nn
15750000 656200 25600 23400
15750000 656200 25600 23400
15750000 656200 25600 23400
15750000 656200 25600 23400
lS7snnnn fs&7nn ?s&nn 7i&nn
6750000 281200 11000 10000
6750000 281200 11000 10000
6750000 281200 11000 10000
6750000 281200 11000 10000
67SQQOQ 7«i7nn unnn innon
6750000 281200 11000 10000
6750000 281200 11000 10000
6750000 281200 11000 10000
6750000 281200 11000 10000
«.7snnan ?oi?nn unnn innnn
573750000 23905500 934000 851000
SODIUM
SULFATE
18600
18600
18600
18600
""•OO
18600
18600
18600
18600
i*>>on
13300
13300
13300
13300
1*^00
9300
9300
9300
9300
oinn
4000
4000
4000
4000
tQQi)
4000
4000
4000
4000
">00
339000
NET REVENUE.
S/TON
SULFUR
25.00
25.00
25.00
25". 00
7«;rnn
25.00
25.00
25.00
25.00
7S.no
25.00
25.00
25.00
25.00
7S.nn
25.00
25.00
25.00
25.00
7S-ftfl
25.00
25.00
25.00
25.00
7S.nn
25.00
25.00
25.00
25.00
75 .no
SODIUM
SULFATE
20.00
20.00
20.00
20.00
7n_nn
20.00
20.00
20.00
20.00
7n.nn
20.00
20.00
20.00
20.00
?Q.pa
20.00
20.00
20.00
20.00
7o.nn
20.00
20.00
20.00
20.00
7n.no
20.00
20.00
20.00
20.00
7n.nn
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FDR
POWER
COMPANY.
S/VEAR
17490200
17256500
17022800
16789000
i&sssmn
16321600
16087900
15854200
15620500
ism&itnn
12836200
12602500
12368800
12135100
11 am ton
9884200
9650500
9416800
9183100
•«64&an
6216500
5982800
5749100
5515400
C7«i7nn
5048000
4814200
4580500
4346800
Aiman
324960800
TOTAL
NET
SALES
REVENUE.
ft/YEAR
1539500
1539500
1539500
1539500
tsiqsnn
1539500
1539500
1539500
1539500
isi«snn
1101000
1101000
1101000
1101000
iininnn
771000
771000
771000
771000
T7innn
330000
330000
330000
330000
iinnnn
330000
330000
330000
330000
4tnnan
28055000
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POUER,
*
15950700
15717000
15483300
15249500
i snisnnn
14762100
14548400
14314700
14081000
1 -41147100
11735200
11501500
11267800
11034100
innnnioo
9113200
8879500
8645800
8412100
MtiA&ao
5886500
5652800
5419100
5185400
4451700
4718000
4484200
4250500
4016800
17841 no
296905800
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POHER,
S
15950700
31667700
47151000
62400500
77&i*ir>fl
92198400
1067468 OO
121061500
135142500
I4BQ80BOO
160725000
172226500
183494300
194528400
?(}s,v*?fla
214441900
223321400
231967200
240379300
74H5577OO
254444200
260097000
265516100
270701500
77c&si?nn
260371200
284855400
269105900
293122.700
?«&4n«ana
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER K1LOHATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR. DOLLARS
13.59
5.10
56.64
347.92
133730000
INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILQHATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
1.17
0.44
4.89
30.03
12069700
DISCOUNTED PROCESS COST OVER LIFE OF
13.00
4.87
54.16
332.66
1.17
0.44
4.88
30.02
12.42
4.66
51.75
317. 89
121660300
POUER UNIT
11.63
4.43
49.2*
302.64
-------
Table B-169. Sodium Solution-SO, Reduction Process
Summary of Estimated Fixed Investment3
(1,000-MW existing coal-fired power unit, 3.5% 5 in fuel;
9.0% SOt removal; 9.3 tons/hr sulfur}
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and all ductwork between outlet
of supplemental fans and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in
to existing duct and inlet to supplemental fans)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors,
elevator, and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
packaged boiler, heaters, condensers, strippers,
compressers, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur Storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems tor obtaining process water and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
380,000
9,885,000
543,000
1,891,000
2,432,000
5,289,000
4,629,000
421,000
1,052,000
1.3
34.2
1.9
6.6
8.4
18.3
16.0
1.5
3.6
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
989,000
1,376,000
28,887,000
3,178,000
3,466,000
2,022,000
2,889,000
40,442,000
4,044,000
3,235,000
47,721 XXX)
3.4
4.8
100.0
11.0
12.0
7.0
10.0
140.0
14.0
11.2
165.2
"Basis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for removal and disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
340
-------
Table B-170. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MWexisting coal-fired power unit. 3.5% S in fuel;
90% SOi removal; 65,390 tons/yr sulfur)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost,$ operating cost
Direct Costs
Delivered raw materials
Soda ash
Antioxidant
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Natural gas
Heat credit
Process Water
Electricity
Maintenance
18, 600 tons
634,200 Ib
56,900 man-hr
34,370,000 gal
1,019,000mcf
125,700MMBtu
1 9,906,800 M gal
100,310,OOOkWh
52.00/ton
2.00/lb
8.00/man-hr
0.23/gal
1 .00/mcf
-0.60/MM Btu
0.02/M gal
0.009/kWh
Labor and material, .05 x 28,887,000
Analyses
Subtotal conversion costs
967,200
1,268,400
24,000
2,259,600
455,200
7.905,100
1,019,000
(75,400)
398,100
902,800
1,444,400
181,100
12,230,300
3.85
5.05
0.10
9.00
1.81
31.48
4.06
(0.30)
1.58
3.59
5.75
0.72
48.69
Subtotal direct costs
14,489,900
57.69
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
7,301,300
29.06
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
product sulfur
384.13
Dollars/ton
coal burned Mills/kWh
9.57 3.59
2,446,100
881,200
10,628,600
25,118,500
Cents/million
Btu heat input
39.87
9.74
3.51
42.31
100.00
Dollars/ton
sulfur removed
350.03
aBasis:
Remaining life of power plant, 25 yr.
Coal burned, 2,625,000otons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 197S operating costs.
Total capital investment, $47,721,000; subtotal direct investment, $28,887,000.
Working capital, $2,528,800.
Investment and operating cost for disposal of fly ash excluded.
341
-------
U)
*>.
K>
Table B-171
SOD I UK SOLUTIDN-SC2 REDUCTION PROCESS, 1000 NU EXISTING COAL FIRED POWER UNIT, 3.5* S IN FUEL. 90* S02 REMOVAL, REGULATED CO ECON
FIXED INVESTMENTS $ 47721000
YEARS ANNUAL
AFTER OPERA-
POKER TION,
UNIT KU-HR/
START KM
SULFUR BV-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS, SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
TOTAL
OP. COST
INCLUDING
HET REVENUE. REGULATED
*/TO» ROI FOR
POWER
SODIUM COMPANY.
SULFUR SULFATE t/YEAR
TOTAL
NET
SALES
REVENUE,
»/YEAR
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER.
* $
1
2
3
7000
7000
7000
7000
i Q inon
11 SOOO
12 SOOO
13 SOOO
14 SOOO
11 innp
16 3500
17 3500
18 3500
19 3500
?n *^nn
21 1500
22 1500
23 1500
24 1500
?« icon
26 1500
27 1500
28 1500
29 1500
.10 ISOO
63000000 2625000 71BOO 65400
63000000 2625000 71800 65400
63000000 2625000 71BOO 65400
63000000 2625000 71800 65400
6^nanaon ?*.>>;nnr> 71 inn «.«&nn
45000000 1875000 51300 46700
45000000 1875000 51300 46700
45000000 1875000 51300 46700
45000000 1875000 51300 46700
6SQOOOOO f*?*ann «i -»pO H*T00
31500000 1312500 35900 32700
31500000 1312500 35900 32700
31500000 1312500 35900 32700
31500000 1312500 35900 32700
?l ii*.pn
13000
13000
13000
13000
i*nnn
5600
5600
5600
5600
^fcQO
5600
5600
5600
5600
*fcon
TOT 92500 832500000 34687500 949000 864000 344000
LIFETIME AVERAGE INCREASE (DECREASE! IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEA*, DOLLARS
LEVELIZED INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION 8TU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
25.00
25.00
25.00
25.00
>«;.no
25.00
25.00
25.00
25.00
?«:.nn
25.00
25.00
25.00
25.00
:>«; nn
25.00
25.00
25.00
25.00
7nnn
462000
4*2000
462000
462000
4A?nnn
431125600 28480000
12.43 0.82
4.66 0.31
51.79 3.42
454.29 30.01
202511600 14047200
DISCOUNTED PROCESS COST OVER LIFE OF
11.84 0.83
4.44 0.31
49.32 3.42
432.72 30.02
27926500
27529400
27132400
26735400
3kiii\-*(\n
21731000
21334000
20937000
20539900
?ni&?qao
16538700
16141600
15744600
15347*00
i&
-------
Table B-172. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment3
(1,000-MW new coal-fired power unit, 3.5% S in fuel;
90% S0t removal; 9.0 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, and fly ash neutralization
facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and exhaust gas ducts to
inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
steam/air heater, fan, dust collectors, feeders,
tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process steam,
water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
339,000
5,712,000
7,043,000
950,000
1,346,000
2,231,000
4,309,000
4,197,000
355,000
272,000
1.2
19.7
24.3
3.3
4.6
7.7
14.9
14.5
1.2
0.9
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
851,000
1,380,000
28,985,000
2,899,000
2,899,000
1,449,000
2,609,000
38,841,000
3,884,000
3,107,000
45,832,000
2.9
4.8
100.0
10.0
10.0
5.0
9.0
134.0
13.4
10.7
158.1
"Basis:
Stack gas reheat to 17S°by indirect steam reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
343
-------
Table B-173. Sodium Solution—SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1.000-MW new coal-fired power unit, 3.5% S in fuel;
90% S02 removal; 63,210 tons/yr sulfur)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Lime (1st stage neutralization) 259.2 tons 26.00/ton
Soda ash 18,000 tons 52.00/ton
Antioxidant 613,000 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 56,900 man-hr 8.00/man-hr
Utilities
Natural gas 985,000 met 1.00/mcf
Steam 4,133,000 M Ib 0.60/M Ib
Heat credit 121 ,500 MM Btu -0.60/M M Btu
Process water 19,242,900 M gal 0.02/M gal
Electricity 143,400,000 kWh 0.009/kWh
Maintenance
Labor and material, .05 x 28,985,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
Equivalent unit operating cost 290.96 7.25 2.63
6,700
936,000
1,226,000
23,200
2,191,900
455,200
985,000
2,479,800
(72,900)
384,900
1,290,600
1,449,300
181,100
7,153,000
9,344,900
6,829,00
1,430,600
786,800
9,046,400
18,391,300
Cents/million
Btu heat input
30.20
Percent of
total annual
operating cost
0.04
5.09
6.66
0.13
11.92
2.48
5.36
13.48
(0.40)
2.09
7.02
7.88
0.98
38.89
50.81
37.13
7.78
4.28
49.19
100.00
Dollars/ton
sulfur removed
265.12
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 2,537,500 tons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Tolal capital investment, $45,8.12,000; subtotal direct investment, $28,985.000.
Working capital. $1,682,900.
Investment and operating cost for disposal of fly ash excluded.
344
-------
Table B-1 74
SODIUM SOLUTIQN-S02 REDUCTION PROCESS, 1000 HW NEW COAL FIREO POWER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT:
45832000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
s 7noo
6 7000
7 7000
8 7000
9 7000
in 7000
11 5000
12 5000
13 5000
14 5000
POWER UNIT POWER UNIT
HEAT FUEL
REQUIREMENT, CONSUMPTION
MILLION BTU TONS COAL
/YEAR /YEAR
60900000 2537500
60900000 2537500
60900000 2537500
60900000 2537500
fc04QQflOQ 75475OQ
60900300 2537500
60900000 2537500
609000CO 2537500
60900000 2537500
£»Q90nnnn ? •* ""i "i *"» o n
43500000 1612500
43500000 1812500
43500000 1812500
43500000 1812500
SULFUR
REMOVED
BY
POLLUTION
, CONTROL
PROCESS,
TONS/YEAR
69400
69400
69400
69400
*44no
69400
69400
69400
69400
fcQ&nfi
49600
49600
49600
49600
is sono 44500000 ifci7son 44*00
16 3500
17 3500
18 3500
19 3500
70 _ 3.50.0
21 1500
22 1500
23 1500
24 1500
?<> 150O
26 1500
27 1500
28 1500
29 1500
_3H 150O-
TOT 127500
LIFETIME
30450000 1268700
30450000 1268700
30450000 1268700
30450000 1268700
304SOOQQ 1 26&7QQ
13050000 543700
13050000 543700
13050000 543700
13050000 543700
L3Q50aflQ_ 5437QQ
13050000 543700
13050000 543700
13050000 543700
13050000 543700
14050000 5447QO
1109250000 46218000
34700
34700
34700
34700
'"t&vn.f}
14900
14900
14900
14900
14400
14900
14900
14900
14900
14400
1264500
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
SODIUM
SULFUR SULFATE
63200
63200
63200
63200
A47QO
63200
63200
63200
63200
fv^ >nn
45200
45200
45200
45200
4VOO
31600
31600
31600
31600
•31 t;nn
13500
13500
13500
13500
14500
13500
13500
13500
13500
1450O
1151000
25100
25100
25100
25100
751 OO
25100
25100
25100
25100
>•* i nn
17900
17900
17900
17900
| 7QOQ
12600
12600
12600
12600
17*00
5400
5400
5400
5400
540.Q_
5400
5400
5400
5400
5400
45750C
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
»/TOa R01 FOR
POWER
SODIUM COMPANY,
SULFUR
25.00
25. CO
25.00
25.00
75-00
25.00
25.00
25.00
25.00
?*-00
25.00
25.00
25.00
25.00
75.00
25.00
25.00
25.00
25.00
75-00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
^** 00
SULFATE S/YEAR
20
20
20
20
?0
20
20
20
20
70
20
20
20
20
?n
20
20
20
20
*>n
20
20
20
20
_2Q
20
20
20
.00
.00
.00
.00
-00
.00
.00
.00
.00
-on
.00
.00
.00
.00
,nn
.00
.00
.00
.00
-JUL-
.00
.00
.00
.00
-aXO.
.00
.00
.00
20.00
?n
-Oft
23159300
22841500
22523700
22206000
7inan?oo
21570400
21252700
20934900
20617200
70744400
16951600
16633900
16316100
15998400
1 5Af^OftOn
13038300
12720600
12402800
12085000
i i 7&7inn
0214300
7896600
7570000
7261000
ftQ^^^nn
6625500
6307000
5990000
5672200
545A5OO
420731900
TOTAL
NET
SALES
REVENUE,
S/YEAR
2002000
2002000
2082000
2002000
7OB70OO
2002000
2002000
2002000
2002000
?nft ?nnn
148CCOO
1408000
1488COO
1488000
1 4RROOO
1042000
1042000
1042000
1042000
i DA?nnn
445500
445500
445500
445500
AA.'i'inft
445500
445500
445500
445500
A A. I1* ft ft
37925000
NET ANNUAL CUMULATIVE
INCREASE RET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
$
21077300
20759500
20441700
20124000
1 4RO*?OO
19488400
19170700
18852900
18535200
i A y i Tinn
15463600
15145900
14828100
14510400
1 4 192&QO
11996300
11678600
11360800
11043000
in7754OO
7768800
7451100
7133300
6815500
A&QTA QO
6180000
5862300
5544500
5226700
A.ftnQnfifi
390806900
$
21077300
41036000
62270500
82402500
iO77(ift*rnn
121697100
140067000
159720700
170255900
1 QAA*7'"t'"tOfl
211936900
227082800
241910900
256421300
770614400
282610200
294288800
305649600
316692600
q2*74« 1 74OO
335186700
342637800
349771100
356586600
"i & "^ n a & A on
369264400
375126700
380671200
305897900
""tonil fMhQDfl
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TOM OF
COAL BURNED
HILLS PER KILOWATT-HOUR
PROCESS COST
LEVELIZED
CENTS PER HILL I Ofl
DOLLARS PER TON OF
BTU HEAT INPUT
SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF
CCAL BURNED
DISCOUNTED
9.20
3.36
38.65
339.05
176695400
0.82
0.29
3.42
29.99
16320200
PROCESS COST OVER LIFE OF
HILLS PER KILOWATT-HOUR
CENTS PER MILLION
DOLLARS PER TON OF
BTU HEAT INPUT
SULFUR REMOVED
8.88
3.22
37.02
324.81
0.02
0.30
3.42
30.00
8.46
3.07
35.23
309.06
160375200
POWER UNIT
8.06
2.92
33.60
294.81
-------
Table B-175. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
80% SO-i removal; 4.2 tons/hr sulfur)
Soda ash,and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Particu late scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, and fly ash neutralization
facilities)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and exhaust gas ducts to
inlet of fan)
Stack gas reheat (4 indirect steam reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
steam/air heater, fan, dust collectors, feeders,
tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process steam,
water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
209,000
3,846,000
4,059,000
539,000
832,000
1,368,000
2,502,000
2,738,000
209,000
195,000
1.1
21.3
22.5
3.0
4.6
7.6
13.9
15.2
1.2
1.1
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
662,000
858,000
18,017,000
1,982,000
1,982,000
901,000
1,802,00
24,684,000
2,468,000
1,975,000
29,127,000
3.7
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
aB;isis:
Stack gas reheat to 175° by indirect steam reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps arc spared.
Fly ash slurry neutralized before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
346
-------
Table B-176. Sodium Solution-SOj Reductioirjjpcess
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new coal-fired power unit, 3.5% S in fuel;
80% SOi removal; 29,060 tons/yr sulfur)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw materials
Lime (1st stage neutralization)
Soda ash
Antioxidant
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision
Utilities
Natural gas
Steam
Heat credit
Process water
Electricity U ^
Maintenance | [•_
134.1 tons 26.00/ton
8,200 tons 52.00/ton
281, 900 Ib 2.00/lb
46,500 man-hr 8.00/man-hr
452,900mcf 1.00/mcf
1, 946,900 Mlb 0.70/Mlb
55,900 MM Btu -0.60/MM Btu
9,060,200 M gal 0.02/M gal
66,450,000 kWh 0.010/kWh
Labor and material, .06 x 18,017,000
Analyses ( ; i
Subtotal c6nv«sion costs
Subtotal direcffcpsts
* I SI
t ' jtet1
Indirect Cjjfs
Average capital chaNes at 14.9%
of total capital invjjstment
Overhead i
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
372.83 8.25 3.10
3,500
426,400
563,800
10,700
1,004,400
372,000
452,900
1,362,800
(33,500)
181,200
664,500
1,081,000
109,900
4,190,800
5,195,200
4,339,900
838,200
461,000
5,639,100
10,834,300
Cents/million
Btu heat input
34.39
0.03
3.94
5.20
0.10
9.27
3.43
4.18
12.59
(0.31)
1.67
6.13
9.98
1.01
38.68
47.95
40.05
7.74
4.26
52.05
100.00
Dollars/ton
sulfur removed
339.74
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $29,127,000; subtotal direct investment, $18,017,000.
Working capital, $932,200.
Investment and operating cost for disposal of fly ash excluded.
347
-------
00
Table B-177
SODIUM SOLUTION-SD2 REDUCTION PROCESS, SCO HW NEW COAL FIRED POWER UNIT, 3.5* S IN FUEL, 80* 502 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT: » 29127000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1
2
3
4
•i
6
7
8
9
in
11
12
13
14
16
17
18
19
?n
21
22
23
24
?5
7000
7000
7000
7000
innn
7000
7000
7000
7000
7O.cn.
5000
5000
5COO
5000
"jnnn
3500
3500
3500
3500
1500
1500
1500
1500
linn
26 1500
27 1500
28 1500
29 1500
10 15QO
SULFUR BY-PRODUCT
REMOVED RAfE.
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/ YEAR
REQUIREMENT, CONSUMPTION. CONTROL
MILLION BTU TONS COAL PROCESS, SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
31500000 1312500 31900
31500000 1312500 31900
31500000 1312500 31900
315COOOO 1312500 31900
.31500000 . n.«1312SOfl . ^1900
31500000 1312500 31900
31500000 1312500 31900
31500000 1312500 31900
31500000 1312500 31900
22500000 937500 22800
22500000 937500 22800
22500000 937500 22800
22500000 937500 22800
15750000 656200 15900
15750000 656200 15900
15750000 656200 15900
15750000 656200 15900
6750000 281200 6800
6750000 281200 6800
6750000 281200 6800
6750000 281200 6800
6750000 281200 6800
6750000 281200 6800
6750000 281200 6800
6750000 281200 6800
&7SOOGQ ?jti?(}n. Aitnn
29100
29100
29100
29 ICO
29100
29100
29100
29100
>o inn
20800
20800
20800
20800
14500
14500
14500
14500
6200
6200
6200
6200
6200
6200
6200
6200
11600
11600
11600
11600
11600
11600
11660
11600
8300
8300
8300
8300
5800
5800
5800
5800
2500
2500
2500
2500
2500
2500
2500
2500
TOT 127500 573750000 23905530 580500 529500 211500
LIFETIME AVERAGE INCREASE (DECREASE! IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILGHATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED TOTAL
S/TON ROI FCR NET
POWER SALES
SODIUM COMPANY, REVENUE,
SULFUR SUtFATE i/YEAR */YEAR
25.00
25. CO
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
7s.nn
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
?n.nn
20.00
20.00
20.00
20.00
>n.nn
13864500
13662600
13460600
13258700
12854800
12652800
12450900
12248900
10198900
9997000
9795000
9593100
7915300
7713400
7511400
7309500
5102600
4900600
4698700
4496700
4092800
3890900
3688900
3487000
959500
959500
959500
959500
959500
959500
959500
959500
686000
686000
686000
686000
478500
478500
478500
478500
205000
205000
205000
205000
205000
205000
205000
205000
258027800 17467500
10.79 0.73
4.05 0.28
44.97 3.04
444.49 30.09
105764700 7519700
DISCOUNTED PROCESS COST OVER LIFE OF
10.28 0.73
3.86 0.28
42.84 3.05
423.06 30.08
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE! (DECREASE!
IN COST OF IN COST OF
POWER, POWER.
i s
12905000
12703100
12501100
12299200
I7O477OO
11895300
11693300
11491400
11289400
9512900
9311000
9109000
8907100
7436800
7234900
7032900
6831000
AA7«nnn
4897600
4695600
4493700
4291700
3887800
3685900
3483900
3282000
240560300
10.06
3.77
41.93
414.40
98245000
POWER UNIT
9.55
— 3.58
39.79
392.98
12905000
25608100
38109200
50408400
74400900
86094200
97585100
108875000
129475400
138786400
147895400
156802500
172944500
180179400
187212300
194043300
205569900
210265500
214759200
219050900
227028500
230714400
234198300
237480300
-------
Table B-178. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment3
(500-MW existing coal-fired power unit, 3.5% S in fuel; 90% SO* removal;
4.8 tons/hr sulfur, par ticulate scrubber required for fly ash removal)
Percent of subtotal
Investment, $ direct investment
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Particulate scrubbers and inlet ducts (4 scrubbers
including common feed plenum, effluent hold tanks,
agitators, pumps, fly ash neutralization facilities, and
all ductwork between outlet of supplemental fans and
particulate scrubbers)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and exhaust gas ducts between
SO2 scrubbers and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in
to existing duct and inlet to supplemental fans)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
packaged boiler, heaters, condensers, strippers,
compressers, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water and electricity
from power plant)
Service facilities (buildings, shops, stores, site
251,000
4,634,000
5,012,000
305,000
1,340,000
1,593,000
3,304,000
3,200,000
267,000
752,000
1.1
20.6
22.3
1.4
6.0
7.1
14.6
14.2
1.2
3.3
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
766,000
1,071,000
22,495,000
2,699,000
2,924,000
1,575,000
2,474,000
32,167,000
3,217,000
2,573,000
37,957,000
3.4
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
aHasis:
Slack KIIS reheat to 175 by dire el oil-tired reheat.
Midwest plan) locution represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spured.
Remaining life of power unit, 25 yr.
I ly ;ish slurry neutrali/.ed before disposal; closed loop water utilization for first stage.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
349
-------
Table B-179. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(50Q-MW existing coal-fired power unit. 3.5% S in fuel; 90% S0t removal;
33,420 tons/yr sulfur; particulate scrubber required for fly ash removal)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Lime (1st stage neutralization) 137.0 tons 26.00/ton
Soda ash 9,500 tons 52.00/ton
Antioxidant 324,100 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 46,500 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 17,567,000 gal 0.23/gal
Natural gas 520,800 mcf 1.00/mcf
Heat credit 64,300 MM Btu -0.60/MM Btu
Process water 10,174,400 M gal 0.02/M gal
Electricity 79,790,000 kWh 0.010kWh
Maintenance
Labor and material, .06 x 22,495,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 5.3%
ot total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
product sulfur coal burned Mills/kWh
Equivalent unit operating cost 490.40 12.22 4.68
3,600
494,000
648,200
12,300
1,158,100
372,000
4,040,400
520,800
(38,600)
203,500
797,900
1,349,700
109,900
7,355,600
8,513,700
5,807,400
1,471,100
597,000
7,875,500
16,389,200
Cents/million
Btu heat input
50.90
Percent of
total annual
operating cost
0.02
3.01
3.96
0.08
7.07
2.27
24.65
3.18
(0.24)
1.24
4.87
8.24
0.67
44.88
51.95
35.43
8.98
3.64
48.05
100.00
Dollars/ton
sulfur removed
446.82
Remaining life of power plant, 25 yr.
Coal burned, 1,341,700 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 197S operating costs.
Total capital investment, $37,957,000. subtotal direct investment, $22,495,000.
Working capital, $1,491,300.
Investment and operating cost for disposal of fly ash excluded.
350
-------
Table B-1 80
SODIUM SOLUTION-S02 REDUCTION PROCESS, 500 HU EXIST. COAL FIRED POWER UNIT, 3.5* S, 90* S02 REMOVAL. FLYASH BEHOVED BY PART. SCRUB
FIXED INVESTMENT:
37957000
YEARS ANNUAL
AFTER OPERA-
POUER T10N,
UNIT KU-HR/
START KH
SULFUR BY-PRODUCT
REHOVED RATE.
POUER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT. CONSUHPT10U, CONTROL
HILLION BTU TONS COAL PROCESS. SODIUtt
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
TOTAL
OP. COST
INCLUDING
NET DEVEHUEr DEGULATED
*/TOn ROI FOR
POUER
SOOIUR COaPflHY,
SULFUR SULFATE S/YEAft
TOTAL
MET
SALES
REVENUE,
S/YEAR
NET ANNUAL
INCREASE
(DECREASE!
IH COST OF
POUER.
$
CUMULATIVE
NET INCREASE
(DECREASE 1
in COST OF
POMEO,
S
1
2
3
4
,5 ,
6 7000
7 7000
8 7000
9 7000
in ''OOP
11 5000
12 SOOO
13 SOOO
14 SOOO
is soon
16 3500
17 3500
IS 3500
19 3500
?n isnn
21 15DO
22 1500
23 1500
24 1500
?s i«;nn
26 1500
27 1500
20 1500
29 1500
in \ son
32200000 1341700 36700
32200000 1341700 36700
32200000 1341700 36700
32200000 1341700 36700
4??nnf)4in ]4Aj7nn ?*inn
23000000 950300 26200
23000000 950300 26203
23000000 950300 26200
23000000 950300 26200
74oonnnn a>;n?nn ?6?nn
16100000 670800 10300
16100000 670000 10300
16100000 670000 10300
16100000 670000 10300
i^innnnn Ainnnn imflO
6900000 207500 7900
6900000 207500 7900
6900000 207500 7900
6900000 207500 7900
«.onnnnn >m«;nn 7900
6900000 207500 7900
6900000 207500 7900
6900000 207500 7900
6900000 207500 7900
«.onnnnn ymxna lenn
33400
33400
33400
33400
44&nn
23900
23900
23900
23900
?ln.no
20.00
20.00
20.00
20.00
?p.ao
20.00
20.00
20.00
20.00
?n.nn
20.00
20.00
20.00
20.00
yn.nn
20336000
20020900
19705100
19389300
iQDT*snn
15974500
15658700
15342900
15027100
1&71 unn
12262000
11947000
11631200
11315400
fna496pp
7719600
7403800
7007900
6772100
&A^*-4fln
6140500
5824700
5508900
$193100
Am7^nn
1101000
1101000
1101000
1101000
i inioon
707500
707500
707500
707500
7(175AO
549500
549500
549500
549500
VAasnn
236000
236000
236000
236000
?4&onn
236000
236000
236000
236000
?4&nna
296300300 14550000
16.72 0.02
6.41 0.32
69.65 3.41
611.09 30.00
137091400 7177500
DISCOUNTED PROCESS COST OVER LIFE OF
15.77 0.02
6.04 0.31
65.70 3.42
576.71 30.02
19235800
18919900
10604100
18280300
174775nn
15187000
14071200
14555400
14239600
i 4«?4ftnn
11713300
11397500
11001700
10765900
lOASDino
7403600
7167800
6051900
6536100
&??ainn
5904500
5508700
5272900
4957100
46A140O
201030300
15.90
6.09
66.24
501.09
130713900
POUER UNIT
14.95
5.73
62.20
546.69
19235000
30155700
567S9300
75040100
Q?n?frvnfi
100207600
123070000
137634200
151073000
I65TO7&(tn
177510900
100900400
199990100
210756000
7717OA1OO
220609700
235057500
242709400
249245500
7**A«.«nnn
261370300
266959000
272231900
277109000
?nin-*n-*oa
-------
Table B-181. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment9
(200-MW new oil-fired power unit, 2.5% S in fuel;
90% SO3 removal; 1.0 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (2 scrubbers including
mist eliminators, pumps, and all ductwork between
common feed plenum and inlet of fans)
Stack gas reheat (2 direct oil-fired reheaters)
Fans (2 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feedjioolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide .reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems fo. obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
88,000
1,826,000
103,000
261,000
556,000
935,000
1,265,000
81,000
209,000
1.5
30.1
1.7
4.3
9.2
15.4
20.7
1.3
3.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
463,000
289,000
6,076,000
790,000
790,000
425,000
668,000
8,749,000
875,000
700.00
10,324,000
7.6
4.8
100.0
13.0
13.0
7.0
11.0
144.0
14.4
11.5
169.9
"Basis:
Stack gas reheat to 175°by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
352
-------
Table B-182. Sodium Solutlon-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW new oil-fired power unit. 2.5% S in fuel;
90%SQi removal; 7,130 tons/yr sulfur)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Soda ash 2,000 tons 52.00/ton
Antioxidant 69,200 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 33,600 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 1 ,032,000 gal 0.23/gal
Natural gas 111,100mcf 1.00/mcf
Steam 343,500 M I b 1.50/M Ib
Heat credit 13,700 MM Btu -1 .60/MM Btu
Process water 2,170,900 M gal 0.04/M gal
Electricity 13,500,000 kWh 0,019/kWh
Maintenance
Labor and material, .07 x 6,076,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
product sulfur oil burned Mills/kWh
Equivalent unit operating cost 598.77 2.07 3.05
104,000
138,400
2,600
245,000
268,800
237,400
111,100
515,300
(21,900)
86,800
256,500
425,300
38,800
1,918,100
2,163,100
1 ,538,300
383,600
184,200
2,106,100
4,269,200
Cents/million
Btu heat input
33.15
Percent of
total annual
operating cost
2.44
3.24
0.06
5.74
6.30
5.56
2.60
12.07
(0.51)
2.03
6.01
9.96
0.91
44.93
50.67
36.03
8.99
4.31
49.33
100.00
Dollars/ton
sulfur removed
545.24
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 2,058,200 bbl/yr, 9,200 Btu/kWh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 lu/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $10,324,000; subtotal direct investment, $6,076,000.
Working capital, $381,800.
353
-------
Table B-183
SODIUM SOLUTIOH-S02 REDUCTION PROCESS, 200 Mb HEW OIL FIREO POWER UNIT, 2.5* S IN FUEL, 90* SQ2 REMOVAL. REGULATED CO ECON
FIXED INVESTMENT: $ 10324000
YEARS ANNUAL
AFTER OPERA-
POHER TION,
U31T KU-HR/
START Kb
1 7000
2 7000
3 7000
4 7000
S 7OOO
6 7000
7 7000
0 7000
9 7000
in innn
11 5COO
12 5000
13 5000
14 5000
i « snna
16 3500
17 3500
10 3SOO
19 3500
7O 4«nn
21 1500
22 1500
23 1500
24 1500
JS l«:nn
26 1500
27 1500
20 1500
29 1500
4O i snn
TOT 127500
LIFETIME
PROCESS COST
LEVELIZEO
SULFUR BY-PRODUCT
REMOVED RATE,
POUER UNIT POHER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TOWS/YEAR
REQUIREMENT, CONSURPTION. CONTROL
BILLION BTU BARRELS OIL PROCESS, SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
12080000 2058200 7000
12880000 2058200 7800
12880000 2058200 7000
12880000 2058200 7000
i7ftAnnnn >n^a?nn Tnnn
12880000 2058200 7000
12800000 2058200 7000
12000000 2058200 7000
12880000 2058200 7000
i?nnnnnn >n*R3nn Tnnn
9200000 1470100 5600
9200000 1470100 5600
9200000 1470100 5600
9200000 1470100 5600
4?pOnnn 1A7nl(ln **Qn
6440000 1029100 3900
6440000 1029100 3900
6440000 1029100 3900
6440000 1029100 3900
AAAnnnn in?oinn ««nn
2760000 441000 1700
2760000 441000 1700
2760000 441000 1700
2760000 441000 1?OO
?7*nnnn V-lOfin ITOI)
2760000 441000 1700
2760000 441000 1700
2760000 441000 1700
2760000 441000 1700
?7fcoOOO AAinnn iTnn
7100
7100
7100
7100
7100
7100
7100
7100
7100
T\nn
5100
5100
5100
5100
sinn
3600
3600
3600
3600
4AOO
1500
1500
1500
1500
Jfon
1500
1500
1500
1500
icnn
2800
2800
2000
2000
7nnn
2800
2800
2800
2800
>nnn
2000
2000
2000
2000
?onn
1400
1400
1400
1400
IAD ft
600
600
600
600
Ann
600
600
600
600
Ann
234600000 37480000 142500 129500 51000
AVERAGE INCREASE (OECREASEI 13 U3IT OPERATING COST
DOLLARS PER BARREL OF OIL CURDED
HILLS PEO KILOUATT-HOUR
CENTS PER MILLION OTU HEAT INPUT
DOLLARS PER TON OF SULFUR REROVEO
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE! 1(1 OMIT OPERATING COST EQUIVALENT TO
DOLLARS PER BARREL OF OIL BURNED
BILLS PER KILOHATT-HOUR
CENTS PER MILLION BTU HEAT IBPUT
DOLLARS PER TON OF SU.FUR REROVEO
TOTAL
OP. COST
INCLUDING
NET R.E VENUE. REGULATED
s/Toa noi fan
POUER
SpOIUCI COaPAOY,
SULFUO. SULFATE S/VEC3
25.00
25.00
25.00
25.00
>«.nn
25.00
25.00
25.00
25.00
>c.nn
25.00
25.00
25.00
25.00
?*.nn
25.00
25.00
25.00
25.00
9C.nn
25.00
25.00
25.00
25.00
?«.on
25.00
25.00
25.00
25.00
?^.nn
20.00
20.00
20.00
20.00
?n.nn
20.00
20.00
20.00
20.00
>n.nn
20.00
20.00
20.00
20.00
>n.nn
20.00
20.00
20.00
20.00
>n .nn
20.00
20.00
20.00
,20.00
?n.nn
20.00
20.00
20.00
20.00
>n.nn
5343200
5271600
5200000
5I2Q500
«n*A«nn
49B5300
4913000
4042200
4770600
AAQonnn
3949400
3077000
3006200
3734600
•*AAiinn
3064400
2992000
2921300
2049700
?7Tninn
1953300
1881000
1010200
1730600
iAA7nnn
1595500
1523900
1452300
1380000
unoxin
TOTAL
NET
SALES
REVENUE.
8/YEflO
233500
233500
233500
233500
?4?«no
233500
233500
233500
233500
?ii«nn
167500
167500
167500
167500
lAicnn
110000
110000
110000
110000
1 ]nnon
49500
49500
49500
49500
A««nn
49500
49500
49500
49500
AQ^nn
100161100 4257500
2.67 0.11
3.93 0.17
42.69 1.01
702.88 29.87
40979700 1031600
DISCOUNTED PROCESS COST OVER LIFE OF
2.54 0.11
3.73 0.16
40.59 1.81
669.60 29.93
NET ANNUAL CUMULATIVE
INCREASE RET ICCREASE
(OECREASEI {OECREASEI
IC1 COST OF IN COST OF
POUER, POUER,
» S
5109700
5030100
4966500
4095000
An?*AAn
4751000
4600300
4600700
4537100
AAAC^nn
3701900
3710300
3630700
3567100
tAQ^AOn
2946400
2074800
2003300
2731700
>AAninp
1903800
1832300
1760700
1609100
iAi7«;ftn
1546000
1474400
1402800
1331300
I >«iQ7r>fi
95903600
2.56
3.76
40.88
673.01
39147900
POUER UNIT
2.43
3.57
30.78
639.67
5109700
10147000
15114300
20009300
?An-49?an
29504500
34264000
30873500
43410600
Air|7A|nn
51650000
55368300
59007000
62574100
AAnAO7nn
69016100
71890900
74694200
77425900
flnnnAfinn
81989800
83822100
85502000
87271900
nnnttQAno
90435400
91909000
93312600
94643900
o«aO4AOO
-------
Table B-184. Sodium Solution-SO2 Reduction Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 1.0% S in fuel;
90% SOi removal; 1.0 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and all ductwork between
common feed plenum and inlet of fans)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
86,000
4,253,000
245,000
594,000
549,000
921,000
1,250,000
79,000
327,000
0.9
45.3
2.6
6.3
5.8
9.8
13.3
0.8
3.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
650,000
448,000
9,402,000
1,034,000
1,034,000
470,000
940,000
12,880,000
1,288,000
1,030,000
15,198,000
6.9
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.6
11.0
161.6
"Basis:
Stack gas reheat to 175°by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
355
-------
Table B-185. Sodium Solution-SOi Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new oil-fired power unit, 1.0% Sin fuel;
90% SOi removal; 6,970 tons/yr sulfur}
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Soda ash
Antioxidant
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Natural gas
Steam
Heat credit
Process water
Electricity
Maintenance
2,000 tons
67,600 Ib
36,100man-hr
2,329,000 gal
108,700 mcf
335,900 M Ib
1 3,400 MMBtu
2,1 77,500 M gal
26,340,000 kWh
52.00/ton
2.00/lb
8.00/man-hr
0.23/gal
1.00/mcf
1.40/Mlb
-1.60/MMBtu
0.04/M gal
O.OISkWh
Labor and material, .06 x 9,402,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
product sulfur oil burned Mills/kWh
Equivalent unit operating cost
839.99 1.16
1.67
104,000
135,200
2,600
241,800
288,800
535,700
108,700
470,300
(21,400)
87,100
474.100
564,100
71,200
2,578,600
2,820,400
2,264,500
515,700
254,100
3,034,300
5,854,700
Cents/million
Btu heat input
18.59
Percent of
total annual
operating cost
1.78
2.31
0.04
4.13
4.93
9.15
1.86
8.03
(0.37)
1.49
8.10
9.63
1.22
44.04
48.17
38.68
8.81
4.34
51.83
100.00
Dollars/ton
sulfur removed
765.32
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 5,033,600 bbl/yr, 9,000 Btu/kWh.
Stack gas reheat to 17S°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $15,198,000; subtotal direct investment, $9,402,000.
Working capital, $497,200.
35ft
-------
Table B-186
SODIUM SOLUTION-S02 REDUCTION PROCESS, 500 MM NEW OIL FIRED POWER UNIT, 1.0* S IN FUEL, 90* 502 REMOVAL, REGULATED CO ECON
FIXED INVESTMENT:
15198000
u>
en
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1
2
3
4
5.
6
7
8
9
_ia
11
12
13
14
IS
16
17
18
19
7000
7000
7000
7000
^ JOQ Q T-,
7000
7000
7000
7000
7nnn
5000
5000
5000
5000
soon
3500
3500
3500
3500
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION. CONTROL
MILLION BTU BARRELS OIL PROCESS,
BY-PRODUCT
RATE.
EQUIVALENT
TONS/YEAR
SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
31SGOOOO 5033600
31500300 5033600
31500000 5033600
31500000 5033600
^t*iflnftofi •» o ^ ^AA n
31500000 5033600
31500000 5033600
31500000 5033600
31500000 5033600
^i co on no *»fl*4*4i»flft
22500000 3595400
22500000 3595400
22500000 3595400
22500000 3595400
7?^Gonflft ^**^S6f)n
15750000 2516800
15750000 2516800
15750000 2516800
15750000 2516800
7700
7700
7700
7700
27.OO
7700
7700
7700
7700
77OO
5500
5500
5500
5500
5500
3800
3800
3800
3800
PP *5OO 1S7SOOOO 7ClJ*ltOO ^fiOO
21
22
23
24
^^
26
27
28
29
1500
1500
1500
1500
1500-
1500
1500
1500
1500
30 1500
TOT
127500
LIFETIME
6750000 1078600
6750000 1078600
6750000 1078600
6750000 1078600
*»75QQOQ 1079^00
6750000 1078600
6750000 1078600
6750000 1078600
6750000 1078600
*f7«;nnnn 107* Ann
573750000 91683000
1600
1600
1600
1600
1*00
1600
1600
1600
1600
1 AQO
139500
7000
7000
7000
7000
7nnn
7000
7000
7000
7000
TOfJQ
5000
5000
5000
5000
snno
3500
3500
3500
3500
*soo
1500
1500
1500
1500
1*00
1500
1500
1500
1500
icno
127500
2800
2800
2800
2800
?ftfin
2800
2800
2800
2800
7800
2000
2000
2000
2000
7QQO
1400
1400
1400
1400
14OO
600
600
600
600
ton
600
600
600
600
&no
51000
NET REVENUE,
*/TON
SODIUM
SULFUR
25.00
25.00
25.00
25.00*
?*% nn
25.00
25.00
25.00
25.00
>*» fin
25.00
25.00
25.00
25.00
?•» , nn
25.00
25.00
25.00
25.00
7* .OO
25.00
25.00
25.00
25.00
?^.nn
25.00
25.00
25.00
25.00
7^. OO
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
SULFATE S/YEAR
20.00
20.00
20.00
20.00
?o .no
20.00
20.00
20.00
20.00
yfl (if\
20.00
20.00
20.00
20.00
7O.OO
20.00
20.00
20.00
20.00
70.00
20.00
20.00
20.00
20.00
7fl.no
20.00
20.00
20.00
20.00
7O.OO
7435800
7330400
7225000
7119700
7Q1 &*3flfl
6908900
6803500
6698200
6592800
A&.jt7&nn
5480700
5375300
5269900
5164500
50CQ70O
4254900
4149500
4044100
3938800
*A**4OO
2734500
2629200
2523800
2418400
7114OOO
2207700
2102300
1996900
1891500
1 786200
138789800
TOTAL
NET
SALES
REVENUE,
S/YEAR
231000
231000
231000
231000
7*1000
231000
231000
231000
231000
7*1000
165000
165000
165000
165000
i&snoo
115500
115500
115500
115500
11 S5OO
49500
49500
49500
49500
645O0
49500
49500
49500
49500
&Q5OO
4207500
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER.
S
7204800
7099400
6994000
6888700
ATA^^QQ
6677900
6572500
6467200
6361800
A7C&&00
5315700
5210300
5104900
4999500
&AO&7OO
4139400
4034000
3928600
3823300
47 74OO
2685000
2579700
2474300
2368900
77&45QO
2158200
2052800
1947400
1842000
1 73&70O
134582300
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER.
S
7204800
14304 2OO
2129*200
281B69OO
*1&.VTQ .TOO
4164*100
48220440
546*7*00
61049*00
£7iii«.nfwt
72621 TOO
77*32000
82936900
879364OO
9?ft?n4AO
96*70000
101004000
104932600
10*755900
1 1 7&T*AnA
115158800
11773*500
120212*00
1225*1700
1 7&B&5 TOO
127003400
1290S62OO
131003600
132*45600
!*&CA7*fMl
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL
MILLS PER KILOWATT-HOUR
BURNED
CENTS PER MILLION BTU HEAT INPUT
PROCESS COST
LEVEL1ZED
DOLLARS PER TON OF SULFUR
DISCOUNTED AT 10.0* TO INITIAL
REMOVED
YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER BARREL OF OIL
HILLS PER KILOWATT-HOUR
BURNED
1.51
2.18
24.19
994.91
56836000
DISCOUNTED PROCESS COST OVER
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR
REMOVED
1.44
2.07
23.02
944.12
0.04
0.07
0.73
30.16
1810600
LIFE OF
0.05
0.06
0.73
3C.08
1.47
2.11
23.46
964.75
55025400
POWER UNIT
1.39
2.01
22.29
914.04
-------
Table B-187. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 2.5% S in fuel;
90% SO-i removal; 2.5 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and all ductwork between
common feed plenum and inlet of fans)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystal) izer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressors,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
152,000
4,253,000
245,000
594,000
977,000
1,750,000
2,068,000
148,000
327,000
1.3
36.3
2.1
5.1
8.3
14.9
17.6
1.3
2.8
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
650,000
558,000
11,722,000
1,289,000
1,289,000
586,000
1,172,00
16,058,000
1,606,000
1,285,000
18,949,000
5.5
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
"Basis: o
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
358
-------
Table B-188. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economies'
(500-MW new oil-fired power unit. 2.5% S In fuel;
90% 502 removal; 1 7,440 tons/yr sulfur)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Soda ash 5,000 tons 52.00/ton
Antioxidant 169,100 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 38,600 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 2,524,000 gal 0.23/gal
Natural gas 271 ,700 mcf 1 .00/mcf
Steam 839,900 M I b 1.40/Mlb
Heat credit 33,500 MM Btu -1 .60/MM Btu
Process water 5,308,200 M gal 0.02/M gal
Electricity 33,000,000 kWh 0.018/kWh
Maintenance
Labor and material, .06 x 1 1 ,722,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
product sulfur oil burned Mills/kWh
Equivalent unit operating cost 476.21 1.65 2.37
260,000
338,200
6,400
604,600
308,800
580,500
271.700
1.175,900
(53,600)
106,200
594,000
703,300
85,300
3,772.100
4,376,700
2,823,400
754,400
350,600
3,928,400
8,305,100
Cents/million
Btu heat input
26.37
Percent of
total annual
operating cost
3.13
4.07
0.08
7.28
3.72
6.99
3.27
14.16
(0.65)
1.28
7.15
8.47
1.03
45.42
52.70
34.00
9.08
4.22
47.30
100.00
Dollars/ton
sulfur removed
434.14
Remaining life of power plant, 30 yr.
Coal burned, 5,033,600 bbl/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $18,949,000; subtotal direct investment, $11,722,000.
Working capital, $772,800.
359
-------
OJ
O\
O
Table B-189
SODIUM SCLUTIUN-S02 REDUCTION PROCESS. SCO Htt BEU OIL FIRED PQHER UNIT, 2.5* S IN FUEL, 90* S02 OEMOVAL, REGULATED CO ECON
FIXED INVESTHE.NT: » 18949000
TEARS ANNUAL
AFTER OPERA-
POUER Tioa,
001 T KU-HR/
START KH
1 7000
2 7000
3 7000
4 7000
1 700P
6 7000
7 7000
8 7000
9 7000
in 7DOO
11 5000
12 5000
13 5000
14 5000
i s *>000
16 3500
17 3500
18 3500
19 3500
yn • V50n
21 1500
22 1500
23 1500
24 1500
3* i«aa
26 1500
27 1500
20 1500
29 1500
..£Q 150Q..
SULFUD BY-PRODUCT
REMOVED RATE,
POUER UNIT PDUER UttIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREttEHT, CONSUMPTION, CONTROL
NILLIOH DTU BARRELS OIL PROCESS, SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
31500000 5033600 19100 17400
31500000 5033600 19100 17400
31500000 5033600 19100 17400
31500000 5033600 19100 17400
t^snnofia ^n"*00 I'l^O iitno
31500000 5033600 19100 17400
31500000 5033600 19100 17400
31500000 5033600 19100 17400
31500000 5033600 19100 17400
4i«nnnnn sn44&nn iQ)an IT&AA
22500000 3595400 13700 12500
22500000 3595400 13700 12500
22500000 3595400 13700 12500
22500000 3595400 13700 12500
?>«0Annn i*a«^nn jiTnn I'?CAA
15750000 2516800 9600 8700
15750000 2516800 9600 8700
15750000 2516800 9600 8700
15750000 2516800 9600 8700
i«7«npna ?^)*.aan af") fl^O0
6750000 1078600 4100 3700
6750000 1078600 4100 3700
6750000 1078600 4100 3700
6750000 1076600 4100 3700
AT^pnnn jflTKkOo Ajftn 970°
6750000 1078600 4JOO 3700
6750000 1078600 4100 3700
6750000 1078600 4100 3700
6750000 1078600 4100 3700
&7«nana invn^nr, A 100 ivnn
6900
6900
6900
6900
*oon
6900
6900
6900
6900
Aonn
5000
5000
5000
5000
«;nop
3500
3500
3500
3500
4500
1500
1500
1500
1500
ison
1500
1500
1500
1500
i«ao
TOT 127500 573750000 91683000 348500 317000 126500
LIFETIME AVERAGE INCREASE {DECREASE) IB UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
HILLS PER KILOHATT-HOUR
CENTS PER HILLIOH BTO HEAT INPUT
DOLLARS PER TOM OF SULFUR REHOVED
PROCESS COST DISCOUNTED AT 10,0* TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER BARREL OF OIL BURNED
KILLS PER KILOUATT-HOUR
CENTS PER HILLIOH 8TU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
1/T0.1 001 F03
POUER
SODIUn COHPANY,
SULFUR SULFATE S/YEAA
25.00
25.00
25.00
25.00
2*5-0."
25.00
25.00
25.00
25.00
?•> nn
25.00
25.00
25.00
25.00
?«;.nn
25.00
25.00
25.00
25.00
>*.ftn
25.00
25.00
25.00
25.00
ji.nn
25.00
25.00
25.00
25.00
?s.nn
20.00
20.00
20.00
20.00
?n.n.nn
20.00
20.00
20.00
20.00
?f»-0«
20.00
20.00
20.00
20.00
'0-0n
20.00
20.00
20.00
20.00
?n.nn
10276400
10145000
10013600
9882300
innn
7129800
6998400
6067000
6735600
AAOA"*On
5505600
5374200
5242900
5111500
/.onninn
3484600
3353300
3221900
3090500
^ocoinn
2827800
2696400
2565000
2433700
>*n?inn
180606100
1.97
2.83
31.48
518.24
74204600
POUEB UNIT
. 1.88
2.70
30.06
495.36
9703400
19275400
28716000
38025300
<,-ittn*oa
56249700
65164900
73940700
02601100
oii?>tnn
98251900
105250300
112117300
118852900
l2^H«p7?oft
130962000
136337000
141579900
146691400
itiA-ricM)
155156100
158509400
161731300
164821000
^ATTpMQO
170608700
173305100
175870100
178303000
inn*.n«.inn
-------
Table B-190. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 4.0% S in fuel;
90% SOi removal; 4.0 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and all ductwork between
common feed plenum and inlet of fans)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors, elevator,
and binsy
Sulfur dioxide regeneration (evaporator-crystallizers,
heaters, condensers, strippers, compressers,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
204,000
4,253,000
245,000
594,000
1,314,000
2,432,000
2,675,000
204,000
327,000
1.5
31.4
1.8
4.4
9.7
18.0
19.7
1.5
2.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
650,000
645,000
13,543,000
1,490,000
1,490,000
677,000
1,354,000
18,554,000
1,855,000
1,484,000
21,893,000
4.8
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
aBasis:
Stack gas reheat to 175 by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
361
-------
Table B-191. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MWnew oil-fired power unit, 4. 0% S in fuel;
90% SOi removal; 27,900 tons/yr sulfur)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw materials
Soda ash 7, 900 tons 52.00/ton
Antioxidant 270,600 Ib 2.00/lb
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision 41,000man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 2,719,000 gal 0.23/gal
Natural gas 434,800mcf 1.00/mcf
Steam 1 ,343,900 M Ib 1 ,40/M Ib
Heat credit 53,600 MM Btu -1 .60 /MM Btu
Process water 8,439,000 M gal 0.02/M gal
Electricity 39,670,000 kWh 0.018/kWh
Maintenance
Labor and material, .06 x 1 3,543,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
product sulfur oil burned Mills/kWh
Equivalent unit operating cost 381.38 2.11 3.04
410,800
541,200
10,200
962,200
328,000
625,400
434300
1,881,500
(85,800)
168,800
714,100
812,600
94,400
4,973,800
5,936,000
3,262,100
994,800
447,600
4,704,500
10,640,500
Cents/million
Btu heat input
33.78
Percent of
total annual
operating cost
3.86
5.08
0.10
9.04
3.08
5.88
4.09
'17.68
(0.81)
1.59
6.71
7.64
0.89
46.75
55.79
30.65
9.35
4.21
44.21
100.00
Dollars/ton
sulfur removed
347.50
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 5,033,600 bbl/yr, 9,000 Btu/kWh.
S tac k gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $21,893,000; subtotal direct investment, $13,543,000.
Working capital, $1,048,800.
362
-------
Table B-192
SODIUM SOLUT10N-502 REDUCTION PROCESS, SCO MM NEW OIL FIRED POWER UNIT, 4.0* S IN FUEL* 90* SO2 REMOVAL, RFGULATED CO ECON
FIXED INVESTMENT: » 21393000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
s 70°°
6 7COO
7 7COO
8 7COO
9 7000
in 7000
11 5000
12 5000
13 5000
14 5000
_L5 5CCQ-
16 3500
17 3500
18 3500
19 3500
21 1500
22 1500
23 1500
24 1500
?* 1500
26 1500
27 1500
28 1500
29 1500
*n iinn
rOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU BARRELS OIL PROCESS. SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
315COOOO
31500000
315000CO
31500000
iisnnnnn
315GOOOC
315COOOO
31500003
31500000
22500000
22500000
225COOCO
22500000
5033600
5033600
5033600
5033600
5033600
5033600
5033600
5033600
3595400
3595400
3595400
3595400
•4SQ56.0O
157500CO 2516800
15750000 2516800
15750000 2516800
157500CO 2516800
i«7«nooo ?siMinn
6750000
6750000
6750000
6750000
6750000
6750000
6750000
6750000
1078600
1078600
1078600
1078600
1078600
1078600
1078600
1078600
30600
30600
30600
30600
3D ADD
30600
30600
30600
30600
21900
21900
21900
21900
219.00
15300
15300
15300
15300
6600
6600
6600
6600
66OO .
6600
6600
6600
6600
4>fcflO
27900
27900
27900
27900
27900
27900
27900
27900
19900
19900
19900
19900
loonn
14000
14000
14000
14000
14.000
6000
6000
6000
6000
6000
6000
6000
6000
*.ooo
11100
11100
11100
11100
1 linn
11100
11100
11100
11100
iiinn
7900
7900
7900
7900
74OO
5500
5500
5500
5500
2400
2400
2400
2400
2400
2400
2400
2400
7&on
573750000 916(3000 558000 508500 202000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE! IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER BARREL OF OIL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
t/TON ROI FOR
POWER
SODIUM COMPANY,
SULFUR SULFATE */YEAR
25.00
25. CO
25.00
25.00
25.00
25.00
25.00
25.00
7s.no
25.00
25.00
25.00
25.00
25. CO
25.00
25.00
25.00
25.00
25.00
25.00
25. CO
25.00
25.00
25.00
25.00
20.00
20.00
20.00
20.00
70.00
20.00
20.00
20.00
20.00
70. OO
20.00
20.00
20.00
20.00
70.00
20.00
20.00
20.00
20.00
7O OO
20.00
20.00
20.00
20.00
tn.nn
20.00
20.00
20.00
20.00
7O.OO
12918000
12766200
12614400
12462600
12159100
12007300
11855500
11703700
9455300
9303500
9151700
8999900
7206800
7055000
6903200
6751400
4381300
4229500
4077700
3925900
3622300
3470500
3318700
3166900
TOTAL
NET
SALES
REVENUE.
i/YEAR
919500
919500
919500
919500
9IQSOO
919500
919500
919500
919500
655500
655500
655500
655500
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASEI (DECREASE)
rn COST OF IN COST Of
POWER. POWER,
$ *
11998500
11846700
11694900
11543100
11239600
11087800
• 10936000
10784200
8799800
8648000
8496200
8344400
RlQ?fcOO
460000 6746800
460000 6595000
460000 0443200
460000 6291400
t&onoo &t?4«.aa
198000
198000
198000
198000
198000
198000
198000
198000
iQAnnn
239606100 16752500
2.61 0.18
3.76 0.26
41.76 2.92
429.40 30.02
99094200 7206300
DISCOUNTED PROCESS COST OVER LIFE OF
2.51 0.18
3.61 0.26
40.14 2.92
413.06 30.03
4183300
4031500
3879700
3727900
3576100
3424300
3272500
3120700
2968900
'812100. ...
222853600
2.43
3.50
38.84
399.38
91887900
POWER UNIT
2.33
3.35
37.22
383.03
1199(500
23845200
35540100
470832OO
6971*200
80802000
91738000
102522200
121954400
130602400
139098600
147443000
162382400
168977400
175420600
181712000
192034900
196066400
199946100
203674000
210674400
213946900
217067600
220036500
0\
<*>
-------
Table B-193. Sodium Solution-S02 Reduction Process
Summary of Estimated Fixed Investment3
(500-MW existing oil-fired power unit. 2.5% S in fuel;
90% S02 removal; 2.5 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and all ductwork between outlet
of supplemental fans and stack gas plenum)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including ducts and dampers between tie-in
to existing duct and inlet to supplemental fans)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystallizers,
packaged boiler, heaters, condensers, strippers,
compressers, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system,, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
170.000
5,208,000
263,000
1,110,000
1,071,000
2,129,000
2,264,000
174,000
690,000
1.2
35.9
1.8
7.6
7.4
14.7
15.6
1.2
4.8
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
718,000
690,000
14,487,000
1,738,000
1,883,000
1,014,000
1,594,000
20,716,000
2.072,000
1,657,000
24,445,000
5.0
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
aBasis:
Stack gas reheat to 17S°by direct oil-find reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Remaining life of power unit, 25 yr.
Construction labor shortages with accompanying overtime pay incentive not considered.
364
-------
Table B-194. Sodium Solution-SOj Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing oil-fired power unit, 2.5% S in fuel;
90% SOt removal; 17,820 tons/yr sulfur)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw materials
Soda ash
Antioxidant
Catalyst
Subtotal raw materials
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Natural gas
Heat credit
Process water
Electricity
Maintenance
5, 100 tons 52.00/ton
172,900 Ib 2.00/lb
38,600 man-hr 8.00/man-hr
10,1 37 ,000 gal 0.23/gal
277,700mcf 1.00/mcf
34,300 MM Btu -1 .60/MM Btu
5,425,700 M gal 0.02/M gal
36,560,000 kWh 0.018/kWh
Labor and material, .06 x 14,487,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 5.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton Dollars/bbl
product sulfur oil burned Mills/kWh
575.85 1 .99 2.93
265,200
345,800
6,500
617,500
308,800
2,331,500
277,700
(54,900)
108,500
658,100
869,200
88,000
4,586,900
5,204,400
3,740,100
917.400
399,700
5,057,200
10,261,600
Cents/million
Btu heat input
31.87
2.58
3.38
0.06
6.02
3.01
22.72
2.71
(0.54)
1.06
6.41
8.47
0.86
44.70
50.72
36.44
8.94
3.90
49.28
100.00
Dollars/ton
sulfur removed
524.62
"Basis:
Remaining life of power plant, 25 yr.
Coal burned, 5.145,400 bbl/yr, 9.200 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $24,445,000; subtotal direct investment, $14,487,000.
Working capital, $913,500.
365
-------
Table 8-195
SODIUM SOLUTION-S02 REDUCTION PROCESS, 500 MH EXISTING OIL FIRED POWER UNIT, 2.5* S IN HJEL-,-90* SO? REMOVAL, REGULATED CO ECON
FIXED INVESTMENTS * 24445GOO
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POKER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT. CONSUMPTION, CONTROL
MILLION BTU BARRELS OIL PROCESS, SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
TOTAL
DP. COST
INCLUDING
NET REVENUE, REGULATED TOTAL
t/TON ROI FOR NET
POWER SALES
SODIUM COMPANY, REVENUE,
SULFUR SULFATE S/YEAR f/YEAR
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE! (DECREASE)
IN COST OF IN COST OF
POWER. POWER*
» S
1
2
3
4
6 7000
7 7000
8 7000
9 7000
in 7000
11 5000
12 5000
13 5000
14 5000
16 3500
17 3500
18 3500
19 3500
21 1500
22 1500
23 1500
24 1500
;« isoo
26 1500
27 1500
28 ISOO
29 1500
10 \ «no
TOT 92500
LIFETIME
PROCESS COST
LEVELIZED
32200000 5145400 19600 17800
322000CO 5145400 19600 17800
32200000 5145400 19600 17800
3220COOO 5145400 19600 17800
23000000 3675300 14000 12700
23000000 3675300 14000 12700
230COOOO 3675300 14000 12700
23000000 3675300 14000 12700
?iooo.-)na i*.7«;infi 14000 l??oa
161COOOO 2572700 9800 8900
16100000 2572700 9800 0900
16100000 2572700 9800 8900
I610COOO 2572700 9800 0900
6900000 1102600 4200 3(00
6900000 1102600 4200 3800
69000CO 1102600 4200 3800
6900000 1102600 4200 3800
6900000 1102600 4200 3800
6900000 1102600 4200 MOO
6900000 1102600 4200 3800
6900000 1102600 4200 3800
7100
7100
7100
7100
7inn
5100
5100
5100
5100
5100
3500
3500
3500
3500
1500
ISOO
1500
1500
ISOO
1500
1500
1500
tcnn
4255COOOO 67993000 259000 235000 93500
AVERACE INCREASE (DECREASE! . IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOHATT-HCUR
CENTS PER MILLION BTL HEAT INPUT
DOLLARS PER TON OF SU.FUR REMOVED
DISCOUNTED AT 10. Ot TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT TO
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOHATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
25.00
25.00
25.00
25.00
2S.OO
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
25.00
20.00
20.00
20.00
20.00
?n.nn
20.00
20.00
20.00
20.00
70.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.00
20.. 00
20.00
20.00
20.00
jn.no
12603900
12600500
12397100
12193700
HQQO4On
top 10000
9806700
9603300
9399900
7714000
7510700
7307300
7103900
4907700
4704300
4501000
4297600
3890800
3687400
3404000
3280700
•4O774OA
186463300
2.74
4.03
43.82
719.94
86676700
DISCOUNTED PROCESS COST OVER
2.58
3.»0
j - 41.30
678.75
587000
587000
587000
587000
^ inn Op
419500
419500
419500
419500
292500
292500
292500
292500
125000
125000
125000
125000
I2SOOO
125000
125000
125000
7745000
0.11
0.17
1.82
29.91
3824000
LIFE OF
0.11
0.17
1.82
29.94
12216900
12013500
11810100
11606700
9590500
9387200
9183800
8980400
•777000
7421500
7218200
7014800
6811400
&&OMOOO
4782700
4579300
4376000
4172600
3765800
3562400
3359000
3155700
178718300
2.63
3.86
42.00
690.03
82852700
POWER UNIT
2.47
3.63
. 39.48
648.81
12216900
24230400
360405OO
47647200
686410OO
78028200
87212000
96192400
112390900
119609100
126623900
133435300
144826000
149405300
153781300
157953900
165688900
169251 300
172610300
175766000
17471*100
-------
Table B-196. Sodium Solutlon-SOa Reduction Process
Summary of Estimated Fixed Investment*
(1,000-MW new oil-fired power unit, 2.5% S in fuel;
90% S0j removal; 4.8 tons/hr sulfur)
Soda ash and antioxidant receiving, storage, and
preparation (pneumatic conveyor and blower, feeders,
mixing tank, agitator, and pumps)
Sulfur dioxide scrubbers and ducts (4 scrubbers including
mist eliminators, pumps, and all ductwork between
common feed plenum and inlet of fans)
Stack gas reheat (4 direct oil-fired reheaters)
Fans (4 fans including exhaust gas ducts and dampers
between fans and stack gas plenum)
Purge treatment (refrigeration system, chiller-
crystallizer, feed coolers, centrifuge, rotary dryer,
fuel oil combustion facilities, fans, dust collectors,
feeders, tanks, agitators, pumps, conveyors, elevator,
and bins)
Sulfur dioxide regeneration (evaporator-crystalIizers,
heaters, condensers, strippers, compressors,
desuperheater, tanks, agitators, and pumps)
Sulfur dioxide reduction unit
Sulfur storage (storage and shipping facilities for 30
days production of molten sulfur)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process steam, water, and
electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
229,000
7,018,000
431,000
899,000
1,480,000
2,777,000
2,970,000
232,000
455,000
1.3
38.5
2.4
4.9
8.1
15.3
16.3
1.3
2.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment
835,000
866,000
18,192.000
1,819,000
1,819,000
910,000
1,637,000
24,377,000
2,438,000
1,950,000
28,765,000
4.6
4.8
100.0
10.0
10.0
5.0
9.0
134.0
13.4
10.7
158.1
"Basis:
Stack gas reheat to 175 by direct oil-fired reheat.
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average coit basis for scaling, mid-1974.
Minimum in process storage; only pumps are spared.
Construction labor shortages with accompanying overtime pay incentive not considered.
367
-------
Table B-197. Sodium Solution-SOi Reduction Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW new oil-flred power unit, 2.5% S in fuel;
90% SOt removal; 33, 710 tons/yr sulfur)
Percent of
Total annual total annual
Annual quantity Unit cost, $ cost, $ operating cost
Direct Costs
Delivered raw materials
Soda ash
Antioxidant
Catalyst
Subtotal raw materials
9,600 tons 52.00/ton 499,200
326,900 Ib 2.00/lb 653,800
12,400
1,165,400
3.65
4.78
0.09
8.52
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Natural gas
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .05 x 18,192,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
46,500 man-hr
4,881,000 gal
525,300 mcf
1,623,800Mlb
64,800 MM Btu
10,262,100 M gal
63,820,000 kWh
8.00/man-hr
372,000
0.23/gal
1.00/mcf
1.30/Mlb
-1.60/MMBtu
0.02/M gal
0.017/kWh
1,122,600
525,300
2,110,900
(103,700)
205,200
1,084,900
909,600
156,500
6,383,300
7,548,700
4,286,000
2.72
8.20
3.84
15.42
(0.76)
1.50
7.93
6.65
1.14
46.64
55.16
31.31
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
product sulfur
406.00
Dollars/bbl
oil burned
1.41
1,276,700
574,800
6,137.500
13,686,200
Cents/million
Mills/kWh Btu heat input
1.96 22.47
9.33
4.20
44.84
100.00
Dollars/ton
sulfur removed
370.00
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 9,731,500 tons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $28,765,000; subtotal direct investment, $18,192,000.
Working capital, $1,332,600.
368
-------
Table B-198
SODIUM SCLUTION-SC2 REDUCTION PROCESS, 1COO MW NEW OIL FIRED POKER UNIT, 2.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO FCDN
FIXED INVESTMENT:
28765000
YEARS ANNUAL
AFTER OPERA-
POWER TICK,
UNIT Kh-HR/
START KW
1
2
3
4
5_
6
7
8
9
13
11
12
13
14
7000
7000
7000
7000
7.000
7000
7000
7COO
7000
7nnn
5000
5000
5000
5000
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU BARRELS OIL PROCESS,
BY-PRODUCT
RATE,
EQUIVALENT
TONS/YEAR
SODIUM
/YEAR /YEAR TONS/YEAR SULFUR SULFATE
609000CO 9731500
609000CO 9731500
60900003 9731500
6090COOO 9731500
4t04nfiQOO QT^ 1 1QO
60900000 9731500
60900300 9731500
60900000 9731500
60900000 9731500
&OQ.CQQQQ 9711 500
43500000 6951100
43500000 6951130
43500000 6951100
43SOOOCO 6951100
37003
37000
37000
37000
t7onn
37000
37000
37000
37COO
37GQO
26400
26400
26400
26400
33700
33700
33700
33700
•a-^iQA
33700
33700
33700
33700
"M"?flfi
24100
24100
24100
24100
13400
13400
13400
13400
i ^&nn
13400
13400
13400
13400
\ jin Q
9600
9600
9600
9600
_15 *r.nn &i*nnnno A.o*iina 71.400 74.100 «f>oo
16
17
13
19
7O
21
22
23
24
3500
3500
3500
3500
_i5QQ
1500
1500
1500
1500
30450000 4865830
30450000 4865800
30450000 4665800
30450000 4865800
^ntifiiinn &ft&
-------
Table B-199. Caulytic Oxidation Process
Summary of Estimated Fixed Investment3
(200-MW new coal-fired power unit, 3.5% S in fuel;
90% S0t removal; 6.4 tonslhrlOO%HiSO*)
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (2
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (2 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Heat recovery and ducts (2 steam/air heaters and 2
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse end air heaters; investment credit
for uso of smaller air heaters included)
Fans (2 ID fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulf uric acid absorber and coolers (1 absorber
including mist eliminator, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulf uric acid storage (storage and shipping
facilities for 30 days production of H3S04)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process
steam, water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
220,000
3,765,000
907,000
668,000
625,000
3,736,000
222,000
$1,000
2.0
34.0
8.2
6.0
5.6
33.7
2.0
0.4
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
369,000
528,000
11,081,000
1,441,000
1,441,000
776,000
1.219,000
15.958,000
1,596,000
1.277.000
18,831,000
706.000
19.537.000
3.3
4.8
100.0
13.0
13.0
7.0
11.0
144.0
14.4
11.5
169.9
6.4
176.3
aBasis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
370
-------
Table B-200, Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics9
(200-MW new, coal-fired power unit, 3,5% S in fuel;
90% SOj removal; 44,900 tons/yr 100% H2SOA )
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Catalyst 42,800 liters 1.65/liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 6,000 man-hr 8.00/man-hr
Utilities
Steam 73,000 M Ib 0.80/M Ib
Heat credit 403,600 MM Btu -0.60/MM Btu
Process water 128,000 M gal 0.08/M gal
Electricity 36,980,000 kWh 0.011/kWh
Maintenance
Labor and material, .05 x 11,081,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/ton
100%HaS04 coal burned Mills/kWh
Equivalent unit operating cost 94.27 7.89 3.02
70.600
70,600
48,000
58,400
(242,200)
10,200
406,800
554,100
25,800
861,100
931,700
2.911,000
172,200
217,800
3,301,000
4,232,700
Cents/million
Btu heat input
32.86
Percent of
total annual
operating cost
1.67
1.67
1.13
1.38
(5.72)
0.24
9.61
13.09
0.61
20.34
22.01
68.77
4.07
5.15
77.99
100.00
Dollars/ton
sulfur removed
288.53
"Basis:
Remaining life of power plant, 30 yr.
Coal burned, 536,700 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment. $19,5 37,000; subtotal direct investment, $11,081,000.
Working capital, $182,000.
Investment and operating cost for disposal of fly ash excluded.
371
-------
-J
to
Table B-201
CATALYTIC OXIDATION PROCESS, ZOO MM NEW COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
19537000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
— 5_ _30QQ_
6 7000
7 7000
6 7000
9 7000
11 5000
12 5000
13 5000
14 SOOO
_J.S 5000.
16 3500
17 3500
18 3500
19 3500
..20 ,3500
21 1500
22 1500
23 1500
24 1500
j«» f^nn
26 1500
27 1500
28 1500
29 1500
in isfln
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
PCWCR UNIT POWER UNIT BY EQUIVALENT NET REVENUE. REGULATED
HEAT FUEL POLLUTION TONS/YEAR i/TON ROI FOR
REQUIREMENT, CONSUMPTION. CONTROL POWER
MILLION BTU TONS COAL PROCESS, lOOt 100* COMPANY.
/YEAR /YEAR TONS/YEAR H2S04 H2S04 »/YEAR
12880000 536700 14700
12880000 536700 14700
12880000 536700 14700
12880000 536700 14-700
12880000 536700 14700
12880000 536700 14700
12880000 536700 14700
12880000 536700 14700
i?Aannnn *tt,-rnn ii,7nn
9200000 383300 10500
9200000 383300 10500
9200000 383300 10500
9200000 383300 10500
a?nnnnn *»a*nn incnn
6440000 268300 7300
6440000 268300 7300
6440000 266300 7300
6440000 268300 7300
A&6nnno ?A^^nn f^nn
2760000 11 SOOO 3100
2760000 115000 3100
2760000 115000 3100
2760000 115000 3100
2760000 115000 3100
2760000 115000 3100
2760000 115000 3100
2760000 115000 3100
?7&nnnn imnnn 4 inn
44900
44900
44900
44900
ttonn
44900
44900
44900
44900
32100
32100
32100
32100
22400
22400
22400
22400
9600
9600
9600
9600
9600
9600
9600
9690
.00
.00
.00
.00
.no
.00
.00
.00
.00
Tnn
.00
.00
.00
.00
_nn
.00
.00
.00
.00
nn
.00
.00
.00
.00
,nn
.00
.00
.00
.00
.nn
234600000 9775000 267000 817500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASEI IN UMT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
6265100
6129600
5994200
5858700
5587800
5452400
5316900
5181500
4625100
4489700
4354200
4218800
3715600
3580100
3444700
3309200
2682000
2546600
2411100
2275700
2004800
1669300
1733900
1598400
TOTAL
NET
SALES
REVENUE.
»/YEAR
269400
269400
269400
269400
269400
269400
269400
269400
192600
192600
192600
192600
134400
134400
134400
134400
57600
57600
57600
57600
57600
57600
57600
57600
116275000 4905000
11.90 0.51
4.56 0.19
49.56 2.09
435.49 18.37
46934900 2111400
PROCESS COST OVER LIFE OF
11.16 0.50
4.28 0.20
46.49 2.09
407.77 18.34
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER. POWER.
* »
5995700
5860200
5724800
5589300
5318400
5183000
5047500
4912100
4432500
4297100
4161600
4026200
3581200
3445700
3310300
3174800
2624400
2489000
2353500
2218100
1947200
1811700
1676300
1540800
111370000
11.39
4.37
47.47
417.12
44823500
POWER UNIT
10.66
4.08
44.40
389.43
S99S700
11855900
17580700
23170000
33942300
39125300
44172*00
49084900
58294000
62591100
66752700
70778900
78250800
81696500
85006800
88181600
93845400
96334400
98687900
100906000
104935800
106747500
108423800
109964600
|i t-»7nnnn
-------
Table B-202. CaUlytic Oxidation Process
Summary of Estimated Fixed Investment9
(200-MW existing coal-fired power unit, 3.5% S in fuel;
90% SOj removal; 6.6 tom/hr 100% H^SO*)
lnvestment,$
Startup bypass ducts and dampers
Electrostatic precipitators and inlet ducts (2
low temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (2 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Reheat (4 direct oil-fired reheaters and 2 flue
gas heat exchangers)
Fans (2 fans including exhaust gas ducts between
fans and stack gas plenum)
Sulfuric acid absorber and coolers (1 absorber
including mist eliminator, coolers, tanks, pumps,
and ducts and dampers between absorber and fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of HjSO^t)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
137.000
1,849.000
847,000
1,395,000
952,000
2,890,000
264,000
377,000
439,000
458,000
9,608,000
1,345,000
1,441,000
865,000
1.153.000
14,412,000
1,441.000
1,153,000
17,006,000
729.000
17.736.000
Percent of subtotal
direct investment
1.4
19.3
8.8
14.5
9.8
30.2
2.7
3.9
4.6
4.8
100.0
8 Basis:
Midwest plant location represents project beginning mid-1972, ending mid-1975- Average cost basis for scaling, mid-1974.
Only pumps are spared.
Remaining life of power unit, 20 yr.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
373
-------
Table B-203. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW existing, coal-fired power unit, 3.5% S in fuel;.
90% SO* removal; 46,400 tons/yr 100% HaSO< )
Annual quantity
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
44,200 liters
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 2)
Process water
Electricity
Maintenance
Labor and material, .05 x 9,608,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect-Costs
Average, capital charges at 15.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
6,000 man-hr
4,270,000 gal
3,288,000 M gal
30,830,000 kWh
Unit cost, $
Total annual
cost, $
1.65/liters
8.00/man-hr
0.30/gal
0.03/M gal
0.011/kWh
72,900
72,900
48,000
1,281,000
98,600
339,100
480,400
25,800
2,272,900
2,345,800
2,819,900
454,600
229,100
3,503,600
5,849,400
Percent of
total annual
operating cost
1.24
1.24
0.82
21.90
1.69
5.80
8.21
0.44
38.86
40.10
48.21
7.77
3.92
59.90
100.00
Dollars/ton Dollars/ton Cents/million Dollars/ton
100%H1S04 coal burned Mills/kWh Btu heat input sulfur removed
Equivalent unit operating cost 126.06- 10.65 4.18 43.98 386.10
"Basis:
Remaining life of power plant, 20 yr.
Coal burned, 554,200 tons/yr, 9,500 Btu/kWh.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $17,735,000; subtotal direct investment, $9,608,000.
Working capital, $412,000.
Investment and operating cost for disposal of fly ash excluded.
374
-------
Table B-204
CATALYTIC OXIDATION PROCESS, 200 HW EXISTING COAL FIRED POWER UNIT, 3.5* S IN FUEL. 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 17735000
lo
-J
YEARS ANNUAL
AFTER OPERA-
POWER T10N.
UNIT KW-HR/
START KW
1
2
3
4
5
6
7
8
9
—10
11
12
13
14
-IS
16
17
18
19
-20,
21
22
23
24
2^
26
27
28
29
3Q
TOT
5000
5000
5000
5000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE. REGULATED
HEAT FUEL POLLUTION TONS/YEAR »/TON ROI FOR
REQUIREMENT, CONSUMPTION, CONTROL POWER
MILLION BTU TONS COAL PROCESS, 100* 100* COMPANY,
/YEAR /YEAR TONS/YEAR H2S04 H2SD4 S/YEAR
9500000 395800 10800
9500000 395800 10800
9500000 395800 10800
9500000 395800 10800
33100
33100
33100
33100
,5000 «*nnnnn ^osunn in«nn -*iino
3500
3500
3500
3500
J&S0Q—
~1500
1500
1500
1500
1*00
1500
1500
1500
1500
|*E An
57500
LIFETIME
PROCESS COST
LEVELIZED
6650000 277100 7600
6650000 277100 7600
6650000 277100 7600
6650000 277100 7600
465QOQQ '7^1 Qfl 7"^0
2850000 11*700 3200
2850000 118700 3200
2850000 118700 3200
2850000 118700 3200
3««;nnnn 114700 3200
2850000 11*700 3200
2850000 118700 3200
2850000 116700 3200
2850000 118700 3200
? A5QQOO 1 1 B7(ifl ^?Qn
109250000 4551500 124000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SU.FUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
23200
23200
23200
23200
j ^3flO
9900
9900
9900
9900
99.00
9900
9900
9900
9900
.00
.00
.00
.00
.00
.00
.00
.00
.00
Too
.00
.00
.00
.00
-nh
.00
.00
.00
.00
oonn fc.nn
3*0500
COST
INCREASE (DECREASE) IN UKIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
6901000
6716500
6532100
6347600
ft 1 ^> ^ ^fl 0
5369600
5185200
5000700
4816200
&fk3i linn
359*400
3414000
3229500
3045100
7g4^)^{)^
2676200
2491700
2307300
2122800
i o^ft^nn
•5347800
18.75
7.42
78.12
6*8.29
43644200
PROCESS COST OVER
17.93
7.10
74.71
657.29
TOTAL
NET
SALES
REVENUE,
S/YEAR
198600
198600
198600
198600
i QH*\f)Q
139200
139200
139200
139200
i ^Q?nn
59400
59400
59400
59400
^Q&on
59400
59400
59400
59400
•kQfcflfl
22*3000
0.50
0.20
2.09
18.41
1221200
LIFE OF
0.50
0.20
2.09
18.39
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN CUT OF
POWER. roUER.
* »
6702400
6517900
6333500
6149000
"***^^frOO
5230400
5046000
4861500
4677000
&&O7A.OO
3539000
3354600
3170100
2985700
2*01200
2616800
2432300
2247900
2063400
i HTHQnn
•3064800
18.25
7.22
76.03
669.88
42423000
POWER UNIT
17.43
6.90
72.62
638.90
6702400
1 32203CO
19553*00
25702800
^1 MiTfcQO
36897800
41943*00
46*05300
514*2300
CR%'74b.QOQ
5*513900
62*6*500
6603*600
6*024300
71 B^c^nfi
74442300
76*74600
79122500
•11*5900
AlA&iVAfln
-------
Table B-205. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(500'MW existing coal-fired power unit, 3.5% S In fuel;
90%SOt removal; 16.0 tons/hr 100%/ftSOAj
Startup bypass ducts and dampers
Electrostatic precipitators and inlet ducts (4
low temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Reheat (8 direct oil-fired reheaters and 4 flue
gas heat exchangers)
Fans (4 fans including exhaust gas ducts between fans
and stack gas plenum)
Sulfuricacid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between absorbers and fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of HjS04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
304,000
4,260,000
1,983,000
3,258,000
2,133,000
6,840,000
481,000
527,000
1.4
19.8
9.3
15.2
10.0
31.9
2.2
2.5
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
613,000
1,020,000
21,419,000
2,570,000
2,784,000
1,499,000
2.356.000
30,628,000
3,063,000
2.450.000
36,141,000
1,766.000
37.907.000
2.9
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
8.3
177.0
8Basis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
376
-------
Table B-206. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics2
(500-MW existing, coal-fired power unit, 3.5% S In fuel;
90% S0j removal; 112,300 tons/yr 100% #2S04 ;
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Catalyst 107,000 liters 1.65/liters 176,600
Subtotal raw material 176,600
Percent of
total annual
operating cost
1.42
1.42
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 2)
Process water
Electricity
Maintenance
Labor and material, .04 x 21,419,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
7,890 man-hr
10,330,000 gal
7,961,000 M gal
74,600,000 kWh
8.00/man-hr
0.30/gal
0.02/M gal
0.010/kWh
63,100
3,099,000
159,200
746,000
856,800
48,000
4,972,100
5,148,700
5,799,800
994,400
456,700
7,250,900
12,399,600
0.51
24.99
1.28
6.02
6.91
0.39
40.10
41.52
46.78
8.02
3.68
58.48
100.00
Dollars/ton Dollars/ton Cents/million Dollars/ton
100%H2SO4 coal burned Mills/kWh Btu heat input sulfur removed
Equivalent unit operating cost 110.41 9.24 3.J34 38.51 338.05
aBasis:
Remaining life of power plant, 25 yr.
Coal burned, 1,341,700 tons/yr, 9,200 Btu/kWh.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 197S operating costs.
Total capital investment, $37,907,000; subtotal direct investment, $21,419,000.
Working capital, $898,600.
Investment and operating cost for disposal of fly ash excluded.
377
-------
00
Table B-207
CATALYTIC OXIDATION PROCESS, 500 HH EXISTING COAL FIRED POWER UNIT. 3.5* S IN FUEL. 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 37907000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED XATE. INCLUDING
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL POWER
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS. 100* 100* COMPANY,
START KW /YEAR /YEAR TOMS/YEAR H2S04 H2S04 »/YEAR
1
2
3
4
5.
6
7
e
9
11
12
13
14
_L5
16
17
18
19
-20.
21
22
23
24
-25
26
27
28
29
3.0
7000 32200000 1341700 36700
7000 32200000 1341700 36700
7000 32200000 1341700 36700
7000 32200000 1341700 36700
5000 23000000 958300 26200
5000 23000000 958300 26200
5000 2 300,00 00 958300 26200
5000 23000000 958300 26200
SOQQ ?^ ^oo ooo *?smnn ?^?PO
3500 16100000 670800 18300
3500 16100000 670800 18300
3500 16100000 670800 18300
3500 16100000 670800 18300
1500 6900000 ^ 287500 - 7900
1500 6900000 287500 7900
1500 6900000 287500 7900
1500 6900000 287500 7900
_ __-.15QQ__ j, 6900000 ^ ?ft7cfln ?ghh
1500 6900000 287500 7900
1500 6900000 287500 7900
1500 6900000 287500 7900
1500 6900000 287500 7900
I^QO &Qflnnno .>A7cnn *7onn
112300
112300
112300
112300
80200
80200
80200
80200
an?nn
56200
56200
56200
56200
24100
24100
24100
24100
• • • «
3 O O O O
3OOO O
.00
.00
.00
.00
-fin
• • • .
goooo
o ooo
o oooc
o oooc
. • . . .
24100 6.00
24100 6.00
24100 6.00
24100 6.00
241 QO &-QQ
TOT 92500 425500000 17729000 485000 1484500
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TliN OF COAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
LEVEL JZED INCREASE (DECREASE) IN UfcIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF CGAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
16342000
16026600
15711200
15395800
13003900
12688500
12373100
12057700
10081900
9766500
9451100
9135700
6647900
6332500
6017100
5701700
5070900
4755600
4440200
4124800
TOTAL
NET
SALES
REVENUE,
•/YEAR
673800
673800
673800
673800
& 718 OH
481200
481200
481200
481200
t ft 1700
337200
337200
337200
337200
144600
144600
144600
144600
144600
144600
144600
144600
16& 60 O
239963400 8907000
13.54 0.51
5.19 0.19
56.40 2.10
494.77 18.37
111000100 4392300
PROCESS COST OVER LIFE OF
12.69 0.50
4.87 0.20
52.89 2.10
464.24 18.37
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER. POWER,
$ S
15668200
15352800
15037400
14722000
12522700
12207300
11891900
11576500
H'MIQO
9744700
9429300
9113900
8798500
6503300
6187900
5872500
5557100
4926300
4611000
4295600
3980200
231056400
13.03
5.00
54.30
476.40
106607800
POWER UNIT
12.19
4.67
50.79
445.87
15668200
31021000
46058400
60780400
87709700
99917000
111808900
123385400
144391200
153820500
162934400
171732900
186719300
192907200
198779700
204336800
214504800
219115800
223411400
227391600
-------
Table B-208. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 2.0% S in fuel;
90% S0t removal; 9.0 tons/hr 100%HtS04)
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Heat recovery and ducts (4 steam/air heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller air heaters included)
Fans (4 ID fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulfuric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H2S04)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process
steam, water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
491,000
8,736,000
2,145,000
1,475,000
1,412,000
8.917,000
279,000
57,000
1.9
34.6
8.5
5.8
5.6
35.4.
1.1
0.2
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
518,000
1,202,000
25,232,000
2,776,000
2,776,000
1,262,000
2,523,000
34,569,000
3,457,000
2,766,000
40,792,000
1,728,000
42.520.000
2.1
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
6.8
168.5
aBasis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
379
-------
Table B-209. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics3
~ (500-MW new, coal-fired power unit, 20% S in fuel;
90% SOt removal; 62,800 tons/yr 100% H3 504 ;
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
104,700 liters
Conversion costs
Operating labor and
supervision
Utilities
Stearh
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 25,232,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
7,380 man-hr
179,OOOMIb
813,000 MM Btu
178,000 M gal
87,870,000 kWh
1.65/1 iters
8.00/man-hr
0.70/M Ib
-0.60/MM Btu
0.08/M gal
0.010/kWh
172,800
172,800
59,000
125,300
(487,800)
14,200
878,700
1,009,300
32.400
1,631,100
1,803,900
6,335,500
Percent of
total annual
operating cost
1.97
1.97
0.67
1.42
(5.54)
0.16
9.98
11.47
0.37
18.53
20.50
71.98
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
100%H2S04
140.15
Dollars/ton
coal burned Mills/kWh
6.71 2.51
326,200
335,600
6,997,300
8,801,200
Cents/million
Btu heat input
27.94
3.71
3.81
79.50
100.00
Dollars/ton
sulfur removed
429.33
8Basis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,500 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175 F.
Power unit on-stream time, 7,000 hi/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $42,520,000; subtotal direct investment, $25,232,000.
Working capital, $341,900.
Investment and operating cost for disposal of fly ash excluded.
380
-------
Table B-210
CATALYTIC OXIDATION PROCESS, 500 MM N EH COAL FIRED POHER UNIT. 2.0* S IN FUEL, 90* $02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: * 42520000
00
YEARS ANNUAL
AFTER OPERA-
POUER TIOH.
UNIT KH-HR/
START KU
1
2
3
4
S
6
7
a
9
10
11
12
13
14
7000
7000
7000
7000
,7000
7000
7000
7000
7000
7nnn
5000
5000
5000
5000
SULFUR BY-PRODUCT
REMOVED RATE.
POUER UEIIT POHER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION. CONTROL
MILLION BTU TONS COAL PROCESS. 100*
/YEAR /YEAR TONS/YEAR
31500000 1312500 20500
31500000 1312500 20500
31500000 1312500 20500
31500000 1312500 20500
iicnnnnn m?cnn ?n«nn
31500000 1312500 20500
31500000 1312500 20500
31500000 1312500 20500
31500000 1312500 20500
11 snnnnn 1117500 ?n*nn
22500000 937500 14600
22500000 937500 14600
22500000 937500 14600
22500000 937500 14600
15 5onn ??5onnnn Qi7«nn i/.unn
16
17
18
19
_2Q
21
22
23
24
?"*
26
27
28
29
in
TOT
3500
3500
3500
3500
^5.00
1500
1500
1500
1500
isnn
1500
1500
1500
1500
1500
127500
LIFETIME
PROCESS COST
LEVELIZED
15750000 656200 10300
15750000 656200 10300
15750000 656200 10300
15750000 656200 10300
i575Onnn &5ik?nn fnmn
6750000 201200 4400
6750000 201200 4400
6750000 281200 4400
6750000 281200 4400
ATSftfinn >o i^oo A Ann
6750000 281200 4400
6750000 281200 4400
6750000 201200 4400
6750000 281200 4400
ATinnnn 9 ni >nn A Ann
573750000 23905500 373500
AVERAGE INCREASE IDECREASEI IN UNIT OPERATING
DOLLARS PER TON OF COAL OURCtED
HILLS PER KILOHATT-HOUR
CENTS PER HILLIOn BTU HEAT INPUT
DOLLARS PER T03 OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
H2S04
62800
62000
62000
62000
A^AOO
62000
62000
62000
62000
t*y linn
44900
44900
44900
44900
AAQnn
31400
31400
31400
31400
11 Aflfi
13500
13500
13500
13500
i mnn
13500
13500
13500
13500
i A^nn
1144500
COST
INCREASE (DECREASE) IN UfcIT OPERATING COST EQUIVALENT
DOLLARS PER TON OF COAL OURNED
HILLS PER KILOUATT-HCUR
CENTS PER HILLIOfl BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
»/TON ROI FOR
POUER
100* COMPANY.
H2S04
6.00
6.00
6.00
6.00
*. nn
6.00
6.00
6.00
6.00
&.nn
6.00
6.00
6.00
6.00
*r -00
6.00
6.00
6.00
6.00
«.,nn
6.00
6.00
6.00
6.00
n.nn
6.00
6.00
6.00
6.00
A nn
TO DISCOUNTED
S/YE/S
13224700
12929900
12635100
12340300
1 JUAISflft
11750700
11455900
11161100
10866300
10571 5nn
9729100
9434300
9139500
8844700
o^AQcn n
7813800
7519000
7224200
6929400
AAiA&nn
5671100
5376300
5081500
4786700
&A41 cnn
4197100
3902300
3607500
3312700
in 1700(1
244244500
10.22
3.83
42.57
653.93
98734200
PROCESS COST OVER
9.60
3.60
39.99
614.40
TOTAL
NET
SALES
REVENUE.
>/YEAR
376800
376800
376800
376800
^ TAA O ft
376800
376800
376800
376800
37AAOQ
269400
269400
269400
269400
p AQ&nn
188400
188400
100400
188400
initAnn
81000
01000
81000
81000
ninnn
01000
01000
01000
01000
ninnn
6067000
0.29
0.11
1.20
18.38
2953900
LIFE OF
0.29
0.11
1.20
10.30
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POUER,
S
12847900
12553100
12250300
11963500
i i AAn7nn
11373900
11079100
10704300
10409500
1 Ol Q&7OO
9459700
9164900
8870100
8575300
B?nO5OO
7625400
7330600
7035800
6741000
AA&A?nn
5590100
5295300
5000500
4705700
AAjnonn
4116100
3021300
3526500
3231700
?4fr\QnO
237377500
9.93
3.72
41.37
635.55
95700300
POHER UNIT
9.31
3.49
30.79
596.02
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POUER.
$
12847900
25401000
37659300
49622000
AI 7
-------
Table B-211. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(500-MW new coal-fired power unit, 3.5% S in fuel;
90% SO 2 removal; IS. 7 tons/hr 100% HtS04)
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and eluvators)
Heat recovery and ducts (4 steam/air heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller air heaters included)
Fans (4 ID fans including exhaust gas ducts and
dampers between ID fans and stack gas.plenum)
Sulfuric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H3S04)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process
steam, water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
In vestment, $.
Percent of subtotal
direct investment
491,000
8,736,000
2,145,000
1,475,000
1,412,000
8,917,000
409,000
57,000
1.9
34.4
8.5
5.8
5.6
35.2
1.6
0.2
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
518,000
1,208,000
25,368,000
2,790,000
2,790,000
1,268,000
2,537,000
34,753,000
3,475,000
2,780,000
41,008,000
1,728,000
42,736,000
2.0
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
6.8
168.5
"Basis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortage!! with accompanying overtime pay incentive not considered.
382
-------
Table B-212. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics2
(500-MW new, coal-fired power unit, 3.5% S in fuel;
90% SOi removal; 109,900 tons/yr 100% HI SO*)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
104,700 liters
Conversion costs
Operating labor and
supervision
Utilities
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 25,368,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
7,890 man-hr
179,000 Mlb
987,000 MM Btu
312,000 M gal
90,440,000 kWh
1.65/liters
8.00/man-hr
0.70/M Ib
-0.60/MM Btu
0.08/M gal
0.010/kWh
Total annual operating cost
Equivalent unit operating cost
172,800
172,800
63,100
125,300
(592,200)
25,000
904,400
1,014,700
48,000
1,588,300
1,761,100
6,367,700
317,700
427,400
7,112,800
8,873,900
Percent of
total annual
operating cost
1.95
1.95
0.71
1.41
(6.67)
0.28
10.19
19.85
71.76
3.58
4.82
80.15
100.00
Dollars/ton Dollars/ton Cents/million Dollars/ton
100% HjS04 coal burned Mills/kWh Btu heat input sulfur removed
80.75
6.76
2.54
28.17
247.32
aBasis:
Remaining life of power plant, 30 yr.
Coal burned, 1,312,000 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $42,736,000; subtotal direct investment, $25,368,000.
Working capital, $347.300.
Investment and operating cost for disposal of fly ash excluded.
383
-------
TabteB-213
CATALYTIC OXIDATION PROCESS, 500 NW NEW COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* 502 REMOVAL, REGULATED.CO. ECONOMICS
FIXED INVESTMENT: * 42736000
YEARS ANMUAL
AFTER OPERA-
POWER TION.
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
«> inoo
6 7000
7 7000
8 7000
9 7000
10 7000
11 SOOO
12 SOOO
13 5000
14 5000
is soon
16 3500
17 3500
18 3500
19 3500
?0 i^OQ
21 1500
22 1500
23 1500
24 1500
3* ispo
26 1500
27 ISOO
28 1500
29 1500
in isoo
TOT 127500
LIFETIME
PROCESS COST
LEVELIZEO
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED
HEAT FUEL POLLUTION TONS/YEAR $/TO* ROI FOR
REQUIREMENT, CONSUMPTION, CONTROL " POWER
MILLION BTU TONS COAL PROCESS, 100* 100* COMPANY,
/YEAR /YEAR TONS/YEAR H2S04 H2S04 »/VEAR
31500000 1312500 35900
31500000 1312500 35900
31 SCO 000 1312500 35900
31500000 1312500 35900
^icoooftn t*i?sftq -»«;onn
31500000 1312500 35900
31500000 1312500 3S900
31500000 1312500 35900
31500000 1312500 359*00
^jwinoijf) 1*17*00 -a^gnn
22500000 937500 25600
22500000 937500 25600
22500000 937500 25600
22500000 937500 25600
??«ooooo «*7«oo ?c&oo
1S7SOOOO 656200 17900
15750000 656200 17900
15750000 656200 17900
15750000 656200 17900
l«;7«;nnnn **«.?r)Q 17900
6750000 281200 7700
6750000 281200 7700
6750000 281200 7700
6750000 281200 7700
*,7innnn ?m?n(i 77QO
6750000 281200 T700
6750000 281200 7700
6750000 281200 7,700
6750000 281200 7700
A7SOOOO y»t jnn T»nn
109900
109900
109900
109900
inoQfin
109900
109900
109900
109900
inoonp
78500
78500
78500
78500
7«snn
55000
55000
55000
55000
55Qnn
23600
23600
23600
23600
74AOO
23600
23600
23600
23600
23&OO
.00
.00
.00
.00
r°0
.00
.00
.00
.00
.op
.00
.00
.00
.00
.on
.00
.00
.00
.00
-00
.00
.00
.00
.00
-OO
.00
.00
.00
.00
-Oft
573750000 23905500 653500 2002500
AVERAGE INCREASE IOECREASEI IN UNIT OPERATING COST
DOLLARS PER TON OF COAL BURNED
HILLS PER K1LONATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR. DOLLARS
INCREASE (DECREASE 1 IN UHIT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
13319800
13023500
12727200
12430900
i ;>) q^Afin
11838300
11542000
11245700
10949400
ir>f,«;*inn
9806100
9509800
9213500
8917200
•4»nann
7879700
7583500
7287200
6990900
4«.o&£nn
5720000
5423700
5127400
4831100
*«4*«aa
4238500
3942200
3645900
3349600
4A c-^ inn
TOTAL
NET
SALES
REVENUE,
S/YEAR
659400
659400
659400
659400
A*«inn
659400
659400
659400
659400
Acotnn
471000
471000
471000
471000
&7joaa
330000
330000
330000
330000
4*0000
141600
141600
141600
141600
]4]«.nn
141600
141600
141600
141600
161&OO
246234400 12015000
10.30 0.50
3.86 0.14
42.92 2.10
376.79 18.38
99489800 5168900
PROCESS COST OVER LIFE OF
9.67 0.50
3.63 0.19
40.30 2.10
353.68 18.38
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
S $
12660400
12364100
12067800
11771500
\ I f?^;>nn
11178900
10882600
10586300
10290000
Q<>ai7nn
9335100
9038800
8742500
8446200
• 1&p3^9fln/i
71517900
82400500
92986800
103276600
i i»?Tn*nn
122605600
131644400
140386900
148833100
]ChOB-xopn
164532700
171786200
178743400
185404300
i«i7&a«an
197347300
202629400
207615200
212304700
? i fcfc«790f)
220794800
224595400
228099700
231307700
??^:>iunn
-------
Table B-214. Catalytic Oxidation Process
Summary of Estimated Fixed Investment9
(500-MW new coal-fired power unit, 5.0% S in fuel;
90% SOi removal; 22.4 tons/hr 100% HtS04)
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Heat recovery and ducts (4 steam/air heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller air heaters included)
Fans (4 10 fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulfuric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H2 S04)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process
steam, water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
491,000
8,736,000
2,145,000
1.475,000
1,412,000
8,917.000
521,000
57,000
1.9
34.3
8.4
5.8
5.5
35.1
2.0
0.2
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
518,000
1,214,000
25,486,000
2,803,000
2.803,000
1,274.000
2,549,000
34,915,000
3,492,000
2,793,000
41,200,000
1.728.000
42,928.000
2.0
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
6.8
168.5
aBasis:
Midwest plant location represents project beginning mid-1972,ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
385
-------
Table B-215. Catalytic Oxidation Process
Total Average Annual Operating Costs—Regulated Utility Economics3
(500-MW new, cod-fired power unit, 5.0% S in fuel;
90% S0t removal; 157,000 tons/yr 100%H^S04)
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
Annual quantity
Unit cost, $
Total annual
cost, $
104,700 liters
Conversion costs
Operating labor and
supervision
Utilities
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 25,486,000
Analyses
Subtotal conversion costs
Subtotal direct costs
8,990 man-hr
179,000 M Ib
1,161,000 MM Btu
445,000 M gal
93,010,000 kWh
1.65/liters
8.00/man-hr
0.70/M Ib
•0.60/Mlvl Btu
0.08/M gal
0.010/kWh
172,800
172,800
71,900
125,300
(696,600)
35,600
930,100
1,019,400
61,600
1,547,300
1,720.100
Percent of
total annual
operating cost
1;94
1.94
0.80
1.40
(7.79)
0.40
10.40
11.40
0.69
17.30
19.24
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
6,396,300
309,500
514,600
7,220,400
8.940,500
71.54
3.46
5.76
80.76
100.00
Equivalent unit operating cost 56.95
Dollars/ton Dollars/ton Cents/million Dollars/ton
100%H2SQ4 coal burned Mills/kWh Btu heat input sulfur removed
6.81
2.55
28.38
174.41
Remaining lite of power plant, 30 yr.
Coal burned, 1,312,000 tons/yr, 9,000 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $42,928,000; subtotal direct investment, $25,486,000.
Working capital, $352,500.
Investment and operating cost for disposal of fly ash excluded.
386
-------
TableB-216
CATALYTIC OXIDATION PROCESS, SOO MW NEW COAL FIRED POWER UNIT, 5.0* S IN FUEL, 90* 502 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: S 42928000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED
AFTER OPERA.- HEAT FUEL POLLUTION TONS/YEAR S/TON ROI FOR
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL POWER
UNIT KW-HR/ MILLION BTU TONS COAL PROCESS, 100* 100* COMPANY,
START KM /YEAR /YEAR TONS/YEAR
1 7000 31500000 1312500 51300
2 7000 31500000 1312500 51300
3 7000 31500000 1312500 51300
4 7000 31500000 1312500 51300
S 70 QQ 11SOQQnn i*i?«;nn «;j inn
6 7000 31500000 1312500 51300
7 7000 31500000 1312500 51300
8 7000 31500000 1312500 51300
9 7000 31500000 1312500 51300
AQ 700Q ^ISPQQnn iij'/snn si ?nn
11 5000 22500000 937500 36600
12 5000 22500000 937500 36600
13 5000 22500000 937500 36600
14 5000 22500000 937500 36600
i5 500Q ?? 'SPCQGQ 93L75QQ ^&6PQ
16 3500 15750000 656200 25600
17 3500 15750000 656200 25600
18 3500 15750000 656200 25600
19 3500 15750000 656200 25600
£Q 3SQQ 1 ** 7^ QGQiQ 65&2QQ ?S ftO n
21 1500 6750000 281200 11000
22 1500 6750000 281200 11000
23 1500 6750000 281200 11000
24 1500 6750000 281200 11000
2S 1500..^ ._ 67500.00.- -- ??l2no 1100"
26 1500 6750000 281200 11000
27 1500 6750000 281200 11000
26 1500 6750000 281200 11000
29 1500 6750000 281200 11000
10 1500 67sooo0 24i?OQ 11000 ,T^ .
TOT 127500 573750000 23905500 934000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF COAL BURNED
MILLS PER KILCWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
H2S04 H2S04
157000
157000
157000
157000
1 ^7000
157000
157000
157000
157000
i •» 70. n ft
112100
112100
112100
112100
] 1 'inn
78500
78500
78500
78500
7jmno
33600
33600
33600
33600
^3&no
33600
33600
33600
33*00
^^Afln
.00
.00
.00
.00
.Qfl
.00
.00
.00
.00
.on
.00
.00
.00
.00
. nn
.00
.00
.00
.00
nn
.00
.00
.00
.00
.on
.00
.00
.00
.00
k^on
2*59000
COST
LEVELIZED INCREASE (DECREASE! IN UMT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
t/YEAR
13406500
13108900
12811300
12513600
t?2 IfrQfl fl
11918400
11620800
11323100
11025500
TOTAL
NET
SALES
REVENUE,
»/YEAR
942000
942000
942000
942000
442 OOO
942000
942000
942000
942000
NET ANNUAL
INCREASE
(DECREASE!
IN COST OF
POWER,
*
12464500
12166900
11869300
11571600
1 1 27&OO()
10976400
10678800
10381100
10083500
CUMULATIVE
NET INCREASE
(DECREASE!
IN COST OF
POWER.
S
12464500
24631400
36500700
48072300
c^^AAifln
70322700
8I001SOO
91382600
101466100
1O7279OO 942nOO 97R59OO 1112S2OQO
9878500
9580800
9283200
8985600
ft '& ft 7 on n
7942600
7645000
7347400
7049700
*7*;>tn n
9767400
5469800
5172100
4874500
&S7&4on
4279200
3981600
3634000
3386400
tnn«7nn
672600
672600
672600
672600
&7pf»on
471000
471000
471000
471000
A7i nno
201600
201600
201600
201600
201^00
201600
Z01600
201600
201600
?ni«.nn
248105400 17154000
10.38
3.89
43.24
265.64
100188100
PROCESS COST OVER
9.74
3.65
40.58
249.22
0.72
0.27
2.99
18.37
7382800
LIFE OF
0.72
0.27
2.99
18.36
9205900
8908200
8610600
8313000
flA 7 5-3 r\n
7471600
7174000
6876400
6578700
&2fl] i nq
5565800
5268200
4970500
4672900
4125300
4077600
3780000
3482400
3184800
9AJI71 nn
230951400
9.66
3.62
40.25
247.27
92805300
POWER UNIT
9.02
3.38
37.59
230.86
120457900
129366100
137976700
146289700
i •»^'
-------
Table B-217. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(1,000-MW existing coal-fired power unit, 3.5% S in fuel;
90%SOt removal; 31.4 tons/hr 100%HiSO^)
Startup bypass ducts and dcmpers
Electrostatic precipitators and inlet ducts (4
low temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (8 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Reheat (16 direct oil-fired reheaters and 8 flue
gas heat exchangers)
Fans (4 fans including exhaust gas ducts between fans
and stack gas plenum)
Sulf uric acid absorbers and coolers (4 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between absorbers and fans)
Sulf uric acid storage (storage and shipping
facilities for 30 days production of H}S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
439,000
7,002,000
3,464,000
5,610,000
3,193,000
12,340,000
759,000
680,000
1.2
19.5
9.6
15.6
8.9
34.2
2.1
1.9
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
791,000
1,714,000
35.992,000
3,959,000
4,319,000
2,519,000
3,599,000
50,388,000
5,039,000
4.031.000
59,458,000
3,455,000
62,913,000
2.2
4.8
100.0
11.0
12.0
7.0
10.0
140.0
14.0
11.2
165.2
-8,6
174.8
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Remaining life of power unit, 25 yr.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
388
-------
Table B-218. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics9
(1,000-MW existing coal-fired power unit. 3.5% iS in fuel;
90% S02 removal; 219,800 tons/yr 100%HtS04)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
209,400 liters
10,380 man-hr
20,220,000 gal
15,576,000 M gal
145,970,000 kWh
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 2)
Process water
Electricity
Maintenance
Labor and material, .03 x 35.992,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
1.65/liters
8.00/man-hr
0.30/gal
0.02/M gal
0.009/kWh
345,500
345,500
83,000
6,066,000
311,500
1,313,700
1,079,800
77.200
8,931,200
9.276,700
9,625,700
Percent of
total annual
operating cost
1.61
1.61
0.39
28.27
1.45
6.12
5.03
0.36
41.62
43.23
44.85
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
100%H2S04
97.64
Dollars/ton
coal burned
8.18
1,786,200
772,200
12,184,100
21,460.800
, Cents/million
Mills/kWh Btu heat input
3.07 34.06
8.32
3.60
56.77
100.00
Dollars/ton
sulfur removed
299.06
aBasis:
Remaining life of power plant, 25 yr.
Coal burned, 2,625,000 tons/yr, 9,000 Btu/kWh.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $62,913,000; subtotal direct investment, $35,992,000.
Working capital, $1,613.100.
Investment and operating cost for disposal of fly ash excluded.
389
-------
Table B-219
CATALYTIC OXIDATION PROCESS, 1000 NW EXISTING COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90* 502 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: * 62913000
TOTAL
SULFUR BY-PRODUCT OP* COST
REMOVED RAVE. INCLUDING
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR */TON
POWER TION, REQUIREMENT, CONSUMPTION, CONTROL
UNIT KU-HR/ MILLION BTU TONS COAL PROCESS,
START KW /YEAR /YEAR TONS/YEAR
1
2
3
4
6 7000 63000000 2625000 71800
7 7000 63000000 2625000 71600
8 7000 63000000 2625000 71800
9 7000 63000000 2625000 71800
If) 7nnn f^QQnnhn ?6.?50.00 71800
11 5000 45000000 1875000 51300
12 5000 45000000 1675000 51300
13 5000 45000000 1875000 51300
14 5000 45000000 1675000 51300
is 5000 Asnnnnnn ii7<»nnn sivin
16 3500 31500000 1312500 35900
17 3500 31500000 1312500 35900
18 3500 31500000 1312500 35900
19 3500 31500000 1312500 35900
?0 ^SOQ ?1 "rOOQQQ 1^1 ^*»00 ^5SK)0
21 1500 13500000 562500 15400
22 1500 13500000 562500 15400
23 1500 13500000 562500 15400
24 1500 13500000 562500 15400
_2S 15OQ nsnnnnn «&?cnn 1*4(1 ft
26 1500 13500000 562500 15$00
27 1500 13500000 562500 15400
28 1500 13500000 562500 15400
29 1500 13500000 562500 15400
30 1^00 13SCnnnn i&^nn is&nn
TOT 92500 832500000 34687500 949000
LIFETIME AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER TON OF 'COAL BURNED
HILLS PER KILOUATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
100* 100*
H2S04 H2S04
219800
219800
219800
219800
y\ ounn
157000
157000
157000
157000
l«nr,nn
109900
109900
109900
109900
inoonn
47100
47100
47100
47100
471 (10
47100
47100
47100
47100
.00
.00
.00
.00
T°0
.00
.00
.00
.00
L>00_
.00
.00
.00
.00
_nn
.00
.00
.00
.00
.no
.00
.00
.00
.00
47ioo *.nn
2904500
COST
LEVELIZEO INCREASE (DECREASE) IN UMT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF COAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
RO! FOR
POWER
COMPANY,
* »/YEAR
26003700
27460300
26956800
26433400
5 ROI nnn A
22162100
21638700
21115300
20591800
2QnAft£/) rt
17096100
16572700
16049200
15525600
^ *^nfl ?4fln
11133300
10609900
10086500
9563000
on^QAnn
8516200
7992700
7469300
6945900
«*??tnn
408365500
11.77
4.41
49.06
430.33
189608600
TOTAL
NET
SALES
REVENUE.
S/YEAR
1316600
1318800
1318800
1318600
1^1 Aftnn
942000
942000
942000
942000
Q&^nnn
659400
659400
659400
659400
J*4>Q*Vnf)
282600
282600
282600
282600
y M9&nn
282600
282600
282600
282600
17427000
0.50
0.18
2.10
18.36
6595900
PROCESS COST OVER LIFE OF
11.06
4.16
46.17
405.15
0.50
0.19
2.09
16.37
NET ANNUAL
INCREASE
(DECREASE)
IN COST OF
POWER,
$
26684900
26161500
25638000
25114600
>&^QI ?nn
21220100
20696700
20173300
19649800
1 Q| 5#ifi.flQ
16436700
15913300
15389800
14666400
i A^£^nnn
10850700
10327300
9803900
9280400
8757nnn
8233600
7710100
7186700
6663300
390958500
11.27
4.23
46.96
411.97
181012700
POWER UNIT
10.58
- 3.97
44.08
' 366:78
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST OF
POWER,
$
26684900
52846400
78484400
103599000
i yj^ ]qn?nQ
149410300
170107000
190280300
209930100
3 2 on ci A in n
245493200
2614065QO
276796300
291662700
tn&nn«7nn
316856400
327183700
336987600
346266000
^^<>n?cnnn
363258600
370968700
376155400
364818700
^QQQ5 A^nO
-------
Table B-220. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(1,000-MW new coal-fired power unit, 3.5% S in fuel;
90% S02 removal; 30.3 tons/hr 100%HtS04)
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (8 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Heat recovery and ducts (4 steam/air heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller air heaters included)
Fans (4 10 fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulfuric acid absorbers and coolers (4 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H2S04)
Utilities (instrument air generation and supply system,
and distribution systems for obtaining process
steam, water, and electricity from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
706,000
14,231,000
3,707,000
2,037,000
2,097,000
15,925,000
640,000
74,000
1.7
33.8
8.8
4.8
5.0
37.8
1.5
0.2
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
666,000
2,004,000
42,087,000
4,209,000
4,209,000
2,104,000
3P788,000
56,397,000
5,640,000
4.512.000
66,549,000
3,340,000
69,889,000
1.6
4.8
100.0
10.0
10.0
5.0
9.0
134.0
13.4
10.7
158.1
8.1
166.1
"Basis:
Midwest plant location represents project beginning mid-1972,ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps arc spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
391
-------
Table B-221. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW new coal-fired power unit, 3.5% S in fuel;
90% SOt removal; 212,400 tons/yr 100% HtS04)
Annual quantity
Unit cost, $
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
Total annual
cost, $
202,400 liters
Conversion costs
Operating labor and
supervision
Utilities
Steam
Heat credit
Process water
Electricity
Maintenance
Labor and material, .03 x 42,087,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
10,380 man-hr
346,000 M Ib
1,908,200 MM Btu
603,000 M gal
174,840,000 kWh
1.65/liters
8.00/man-hr
334,000
334,000
83,000
0.60/M Ib
•0.60/MM Btu
0.07/M gal
0.009/kWh
207,600
(1,144,900)
42,200
1,573,600
1,262,600
77,200
2,101,300
2.435,300
10,413,500
Percent of
total annual
operating cost
2.39
2.39
0.59
1.49
(8.20)
0.30
11.28
9.05
0.55
15.06
17.45
74.61
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
100%H,S04
65.71
Dollars/ton
coal burned Mills/kWh
5.50 1.99
420,300
688,500
11,522,300
13,957.600
Cents/million
Btu heat input
22.92
3.01
4.93
82.55
100.00
Dollars/ton
sulfur removed
201.21
aBasis:
Remaining life of power plant, 30 yt.
Coal burned, 2,537,500 tons/yr, 8,700 Btu/kWh.
Stack gas reheat to 175°F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $69,889,000; subtotal direct investment, $42,087,000.
Working capital, $496.400.
Investment and operating cost for disposal of fly ash excluded.
392
-------
Table B-222
CATALYTIC OXIDATION PROCESS. 1000 HW KEW COAL FIRED POWER UNIT, 3.5* S IN FUEL. 90* S02 REMOVAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT: * 69889000
YEARS ANNUAL
AFTER OPERA-
POWER TION.
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
5 7000
6 7000
7 7000
8 7000
9 7000
_1Q _ 300.0.
11 5000
12 5000
13 5000
14 SOOO
.15 . 5.00.0...
16 3500
17 3500
18 3500
19 3500
_2Q 35QO-
21 1500
22 1500
23 1500
24 1500
_2S 15QQ_
26 1500
27 1500
28 1500
29 1500
_30 _15QQ_
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU TONS COAL PROCESS, 100*
/YEAR /YEAR TONS/YEAR H2S04
60900000 2537500 69400
60900000 2537500 69400
60900000 2537500 69400
60900000 2537500 69400
Anonoonn 75-37500 AQtnn
60900000 2537500 69400
60900000 2537500 69400
60900000 2537500 69400
60900000 2537500 69400
6Q.QQQQOQ 2537500 4>Q4nn
43500000 1812500 49600
43500000 1812500 49600
43500000 1812500 49600
43500000 1812500 49600
. . 43500000 iRi?5nn 44*00
30450000 1268700 34700
30450000 1268700 34700
30450000 1268700 34700
30450000 1268700 34700
3O45pnnn i?&«7nn 3&7nn
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
unsnnoQ ... 543700 itonn
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
13050000 543700 14900
HOSQQOQ 54^7f)Q 144OO
1109250000 46218000 1264500
AVERAGE INCREASE (DECREASEI IN UNIT OPERATING
DOLLARS PER TON OF CCAL BURNED
HILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
212400
212400
212400
212400
2124QQ
212400
212400
212400
212400
71 7&nn
151700
151700
151700
151700
1517OO
106200
106200
106200
106200
IO*?OP
45500
45500
45500
45500
455(jn
45500
45500
45500
45500
455nn
3868500
COST
INCREASE (DECREASEI IN UkIT OPERATING COST EQUIVALENT
DOLLARS PER TON OF CCAL BURKED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
S/TON ROI FOR
POWER
100* COMPANY,
H2S04 */YEAR
6.00
6.00
6.00
6.00
A* nn
6.00
6.00
6.00
6.00
fc.OO
6.00
6.00
6.00
6.00
& . nn
6.00
6.00
6.00
6.00
ik _ no
6.00
6.00
6.00
6.00
f. 00
6.00
6.00
6.00
6.00
fc.nn
TO DISCOUNTED
21228300
20743800
20259200
19774600
1474O1OO
18805500
18321000
17836400
17351900
i Afifc-f-^n n
15585200
15100700
14616100
14131600
i ^4700 o
12522300
12037700
11553100
11068600
inmt&nnn
9136100
8651500
8167000
7682400
71 47ROO
6713300
6228700
5744200
5259600
4775100
390880100
8.46
3.07
35.24
309.12
158106100
TOTAL
NET
SALES
REVENUE.
t/YEAR
1274400
1274400
1274400
1274400
17744OO
1274400
1274400
1274400
1274400
1 ? 744 Cl ^
910200
910200
910200
910200
4in7OO
637200
637200
637200
637200
4t^~72nfl
273000
273000
273000
273000
77*000
273000
273000
273000
273000
>*7^nflO
23211000
0.50
0.19
2.09
18.36
9988500
PROCESS COST OVER LIFE OF
7.95
2.88
33.12
290.64
0.50
0.18
2.09
18.37
NET ANNUAL
INCREASE
(DECREASEI
IN COST OF
POWER,
S
19953900
19469400
18984800
18500200
1 RO157OO
17531100
17046600
16562000
16077500
1 55479On
14675000
14190500
13705900
13221400
1 77^/iHOO
11885100
11400500
10915900
10431400
444fcflOn
8863100
8378500
7894000
7409400
A4?4Rnn
6440300
5955700
5471200
4986600
&*>n? T nn
367669100
7.96
2.88
33.15
290.76
148117600
POWER UNIT
7.45
2.70
31.03
272.28
CUMULATIVE
NET INCREASE
(DECREASE)
IN COST Of
POWER,
S
19953900
39423300
58408100
76908300
9&Q2&OQQ
112455100
129501700
146063700
162141200
1 "'"'734100
192409100
206599600
220305500
233526900
74«.7fc17OO
258148800
269549300
280465200
290896600
10084340O
309706500
318085000
325979000
333388400
-340^1 *7nn
346753500
352709200
358180400
363167000
^ftT&fiQ 1 OO
-------
Table B-223. Catalytic Oxidation Process
Summary of Estimated Fixed.Investment3
(500-MW existing coal-fired power unit, 3.5% S in fuel; 90% SO* removal;
16.0 tons/hr 100% H^S04 without existingparticulate collection facilities)
Percent of subtotal
Investment, $ direct investment
Startup bypass ducts and dampers
Electrostatic precipitators and inlet ducts (4
low temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Reheat (8 direct oil-fired reheaters and 4 flue
gas heat exchangers)
Fans (4 fans including exhaust gas ducts between fans
and stack gas plenum)
Sulfuric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between absorbers and fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of HjSCU)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
304,000
7,594,000
1,983,000
3,258,000
2,133,000
6,840,000
481,000
527,000
1.2
30.4
8.0
13.1
8.6
27.4
1.9
2.1
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
613,000
1,187,000
24,920,000
2,990,000
3,240;000
1.744;000
2,741,000
35,635,000
3,564,000
2.851,000
42.050.000
1,766,000
43,816,000
2.5
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
7.1
175.8
"Basis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps arc spared.
Remaining life of power unit, 25 yr.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
394
-------
Table B-224. Catalytic Oxidation Process
Tout Average Annual Operating Costs-Regulated Utility Economics3
\_ '
(500-M W existing coal-fired power unit, 3.5% S in fuel; 90% 502 removal;
J 12,300 tons/yr 100% HjSO* without existing paniculate collection facilities)
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
107,000 liters
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 2)
Process water
Electricity
Maintenance
Labor and material, .04 x 24,920,000
Analyses
Subtotal conversion costs
Subtotal direct costs
7,890 man-hr
10,330,000 gal
7,961,DOOM gal
80,470,000 kWh
1.65/liters
8.00/man-hr
0.30/gal
0.02/M gal
0.010/kWh
176,600
176,600
63,100
3,099,000
159,200
804,700
996,800
48,000
5,170,800
5,347,400
Percent of
total annual
operating cost
1.30
1.30
0.46
22.79
1.17
5.92
7.33
0.35
38.02
39.32
Indirect Costs
Average capital charges at 1 5.3%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton
100%H2S04
Equivalent unit operating cost 1 21 .09
6,703,800
1,034,200
512,900
8,250,900
13,598,300
Dollars/ton Cents/million
coal burned Mills/kWh Btu heat input
10.14 3.89 42.23
49.30
7.61
3.77
60.68
100.00
Dollars/ton
sulfur removed
370.73
aBasis:
Remaining life of power plant, 25 yr.
Coal burned, 1,341,700 tons/yr, 9,200 Btu/kWh.
Stack gas reheat to 175° F.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $43,816,000; subtotal direct investment, $24,920,000.
Working capital, $938,300.
Investment and operating cost for disposal of fly ash excluded.
395
-------
u>
Table B-225
CATALYTIC OXIDATION PROCESS, 500 HW EXISTING COAL FIRED POWER UNIT, 3.5* S IN FUEL, 90% 502 REMOVAL, WITHOUT EXISTING ESP
FIXED INVESTMENT:
43816000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
TOTAL
SULFUR BY-PRODUCT . OP. COST
REMOVED *ATE. INCLUDING
POWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE, REGULATED
HEAT FUEL POLLUTION TONS/TEAR S/TON ROI FOR
REQUIREMENT, CONSUMPTION. CONTROL POWER
MILLION BTU TONS COAL PROCESS, 100* 100* COMPANY,
/YEAR /YEAR TONS/YEAR H2S04 H2SQ4 t/YEAR
TOTAL
NET
SALES
REVENUE,
t/YEAR
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER.
$ t
1
2
3
4
5 -
6 7000 32200000 1341700 3670.0
7 7000 32200000 1341700 36700
8 7000 32200000 1341700 36700
9 7000 32200000 1341700 36700
IP 7QPQ 3??nnnnn HAi7nn 4&?nn
11 5000
12 5000
13 5000
14 5000
,14 500.O
16 3500
17 3500
18 3500
19 3500
20 -._ ^SOQ
21 1500
22 1500
23 1500
24 1500
_2i iSOQ
26 1500
27 1500
28 1500
29 1500
•?o 1*00
TOT 92500
LIFETIME
PROCESS COST
LEVELIZED
23000000 958300 26200
23000000 958300 26200
23000000 958300 26200
23000000 958300 26200
16100000 670800 18300
16100000 670800 18300
16100000 670800 18300
16100000 670800 16300
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
6900000 287500 7900
tSOOPflO 2675QO . 7«nn
112300 <
112300
112300
112300
80200
80200
80200
80200
56200
56200
56200
56200
24100
24100
24100 <
24100
t • t •
3 O O O O
30 O 00
.00
.00
.00
.00
_nn
• § • .
3OOOO
3OOOO
.00
.00
b.OO
i.OO
24100 6.00
24100 6.00
24100 6.00
24100 6.00
425500000 17729000 485000 1484500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILCWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UMT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER TON OF CCAL BURNED
MILLS PER KILOWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
18155100
17790600
17426000
17061500
1 AAOinnn
14506500
14142000
13777400
13412900
11286400
10921900
10557300
10192800
7526600
7162100
6797500
6433000
ASlfcftSnn
5703900
5339400
4974800
4610300
673800
673800
673800
673800
*L7innn
481200
481200
481200
481200
337200
337200
337200
337200
144600
144600
144600
144600
144600
144600
144600
144600
267665900 8907000
15.10 0.50
5.79 0.20
62.91 2.10
551.89 18.37
123517200 4392400
PROCESS COST OVER LIFE OF
14.12 0.50
5.41 0.19
58.85 2.09
516.59 18.37
17481300
17116800
16752200
16387700
14025300
13660800
13296200
12931700
10949200
10584700
10220100
9855600
949 11 OO
7382000
7017500
6652900
6288400
SOP3QOQ
5559300
5194800
4830200
4465700
258758900
14.60
5.59
60.81
533.52
119124800
POWER UNIT
13.62
5.22
56,76
498.22
17481300
34598100
51350300
67738000
97786500
111447300
124743500
137675200
161191600
171776300
181996400
191852000
208725100
215742600
222395500
228683900
240167100
245361900
250192100
254657800
-------
Table B-226. Catalytic Oxidation Process
Summary of Estimated Fixed Investment8
(200-MW new oil-fired power unit, 2.5% S in fuel;
90% SOi removal; 3.4
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (2
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (2 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Heat recovery and ducts (2 direct oil-fired heaters and 2
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller air heaters included)
Fans (2 ID fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulfuric acid absorber and coolers (1 absorber
including mist eliminator, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H2S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
200,000
890,000
787,000
688,000
554,000
3,210,000
145,000
150,000
2.7
12.1
10.7
9:4
7.5
43.8
2.0
2.0
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
367,000
350.000
7,341,000
954,000
954,000
514,000
808.000
10,571,000
1,057,000
846,000
12,474,000
595.000
13,069,000
5.0
4.8
100.0
13.0
13.0
7.0
11.0
144.0
14.4
11.5
169.9
8.1
178.0
aBasis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for sealing, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
397
-------
Table B-227. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(200-MW new oil-fired power unit, 2.5% S in fuel;
90% SOi removal; 24,000 tons/yr 100% //2SQ, )
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Catalyst 36,1 00 liters 1.65/liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 5,810 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 437,000 gal 0.23/gal
Heat credit 288,700 MM Btu -1.60/MMBtu
Process water 68,000 M gal ' 0.08/M gal
Electricity 21,900,000 kWh 0.019/kWh
Maintenance
Labor and material, .05 x 7,341,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
100%H2S04 oil burned Mills/kWh
Equivalent unit operating cost 114.59 1.34 1.96
59,600
59,600
46,500
100,500
(461,900)
5,400
416,100
367,100
16,600
490,300
549,900
1,947.300
98,100
154,800
2,200,200
2,750,100
Cents/million
Btu heat input
21.35
Percent of
total annual
operating cost
2.17
2.17
1.69
3.65
(16.79)
0.20
15.13
13.35
0.60
17.83
20.00
70.80
3.57
5.63
80.00
100.00
Dollars/ton
sulfur removed
351.23
"Basis:
Remaining life of power plant, 30 yr.
Oil burned, 2,058,200 bbl/yr, 9,200 Btu/kWh.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment. $13,069,000; subtotal direct investment, $7,341,000.
Working capital, $111,500.
Investment and operating cost for disposal of fly ash excluded.
398
-------
Table B-228
CATALYTIC OXIDATION PROCESS, 200 HW NEW CIL FIRED POWER UNIT. 2.5* S IN FUEL. 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
13069000
SULFUR BY-PRODUCT
REMOVED RATE.
YEARS ANNUAL POWER UNIT POWER UNIT BY EQUIVALENT
AFTER OPERA- HEAT FUEL POLLUTION TONS/YEAR
POWER TION. REQUIREMENT, CONSUMPTION. CONTROL
UNIT KW-HR/ MILLION BTU BARRELS OIL PROCESS, 100*
START KW /YEAR /YEAR TONS/YEAR HZSO*
1 7000 12880000 2058200 7800
2 7000 12680000 2058200 7800
3 7000 12880000 2058200 7800
4 7000 12880000 2058200 7800
$ 7000 i?Rftnflno 20*f?oo 7*00
6 7000 12880000 2058200 7800
7 7000 12880000 2058200 7800
8 7000 12880000 2058200 7800
9 7000 12880000 2058200 7800
10 70(1(1 I??«0000 ?(l^tfl?00 7 linn
11 5000 9200000 1*70100 5600
12 5000 9200000 1470100 5600
13 5000 9200000 1470100 5600
14 5000 9200000 1470100 5600
15 500Q o?onOnQ 14. 7n inn s«,nn
16 3500 6440000 1029100 3900
17 3500 6440000 1029100 3900
18 3500 6440000 1029100 3900
19 3500 6440000 1029100 3900
j>0 ^*no », 44 00 00 1 0291 00 . ?4Qn
21 1500 2760000 441000 1700
22 1500 2760000 441000 1700
23 1500 2760000 441000 1700
24 1500 2760000 441000 1700
ft 15OO 77*0000 t4ionn J7no
26 1500 2760000 441000 1700
27 1500 2760000 441000 1700
28 1500 2760000 441000 1700
29 1500 2760000 441000 1700
30. 1500 ?7fcnoon 4.4innn 1700
24000
24000
24000
24000
?4onn
24000
24000
24000
24000
24000
17100
17100
17100
17100
i7ion
12000
12000
12000
12000
17000
5100
5100
5100
5100
sloe.
5100
5100
5100
5100
5100
TOT 127500 234600000 37488000 142500 436SOO
LIFETIME AVERAGE INCREASE (DECREASE I IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0* TO INITIAL YEAR, DOLLARS
LEVELIZED INCREASE (DECREASEI IN UKIT OPERATING COST EQUIVALENT
DOLLARS PER BARREL OF OIL BURNED
MILLS PER K1LOWATT-HCUR
CENTS PER MLLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
I/TON ROI FOR
POWER
100* COMPANY.
H2S04 S/YEAR
6.00
6.00
6.00
6.00
fc.oo
6.00
6.00
6.00
6.00
A.nn
6.00
6.00
6.00
6.00
A_nn
6.00
6.00
6.00
6.00
*.-nn
6.00
6.00
6.00
6.00
6,00
6.00
6.00
6.00
6.00
4. no
TO DISCOUNTED
4109700
4019000
3928400
3837800
*747>nn
3656600
3566000
3475400
3384800
*?«t?nn
3040600
2950000
28 59400
2768800
?A7fl?OO
2452800
2362200
2271600
2181000
?OQO4nO
1785900
1695300
1604600
1514000
i4?i4nn
1332800
1242200
1151600
1061000
470400
76455300
2.04
3.00
32.59
536.53
30781900
PROCESS COST OVER
1.91
2.81
30.49
502 .97
TOTAL
NET
SALES
REVENUE,
S/YEAR
144000
144000
144000
144000
i44onn
144000
144000
144000
144000
_14*,QflO_
102600
102600
102600
102600
10?fcOO
72000
72000
72000
72000
7?OOO
30600
30600
30600
30600
•?r*,nn
30600
30600
30600
30600
ao.6£0— .
2619000
0.07
0.10
1.12
18.38
1128100
LIFE OF
0.07
0.11
1.12
18.43
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASEI
IN COST OF IN COST OF
POWER. POWER.
t *
3965700
3875000
3784400
3693800
3fc03?OQ
3512600
3422000
3331400
3240800
^i*n?nn
2938000
2847400
2756800
2666200
?575*>on
2380800
2290200
2199600
2109000
7Q1B4QO
1755300
1664700
1574000
1483400
i -to? iinn
1302200
1211600
1121000
1030400
Q3QAOO
73836300
1.97
2.90
31.47
518.15
29653800
POWER UNIT
1.84
2.70
29.37
484.54
3965700
7840700
11625100
15318900
1 H 4? 71 DO
22434700
2S856700
29188100
32428900
1SS791 nn
38517100
41364500
44121300
46787500
&?•?*. 1100
51743900
54034100
56233700
58342700
6031.1100
62116400
63781100
65355100
66838500
<,a?n inn
69533500
70745100
71866100
72896500
7?ff?AtOO
VO
-------
Table B-229. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 1.0% Sin fuel;
90% S0j removal; 3.3 tom/hr 100% H3SO4)
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and'elevators)
Heat recovery and ducts (4 direct oil-fired heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse; and air heaters; investment credit
for use of smallerair heaters included)
Fans (4 10 fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulfuric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H3S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
447,000
2,069,000
1,860,000
1,517,000
1,249,000
7,668,000
143,000
210,000
2.7
12.6
11.3
9.2
7.6
46.5
0.9
1.3
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
515.000
784,000
16,462,000
1,811,000
1,811,000
823,000
1,646,000
22,553,000
2,255,000
1,804,000
26,612,000
1.455.000
28.067.000
3.1
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
8.8
170.5
"Basis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
400
-------
Table B-230. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics9
(500-MW new oil-fired power unit, 1.0% Sin fuel;
90% SOi removal; 23,400 tons/yr 100% #2 S04//
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Catalyst 88,200 liters 1.65/liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 7,190man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 1 ,068,000 gal 0.23/gal
Heat credit 576,000 MM Btu -1 .60/MM Btu
Process water 67,000 M gal 0.08/M gal
Electricity 51 ,630,000 kWh 0.018/kWh
Maintenance
Labor and material, .04 x 16,462,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 1 4.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
145.500
145,500
57,500
245,600
(921,600)
5,400
929,300
658,500
16,300
991,000
1,136,500
4,182,000
198,200
226,900
4,607,100
5,743,600
Cents/million
100%H2S04 oil burned Mills/kWh Btu heat input
Equivalent unit operating cost 245.45 1.14 1.64
18.23
Percent of
total annual
operating cost
2.53
2.53
1.00
4.28
(16.04)
0.09
16.18
11.47
0.28
17.26
19.79
72.81
3.45
3.96
80.21
100.00
Dollars/ton
sulfur removed
750.80
"Basis:
Remaining life of powet plant, 30 yr.
Oil burned, 5,033,600 bbl/yr, 9,000 Btu/kWh.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital Investment, $28,067,000; subtotal direct investment, $16,462,000.
Working capital, $218,600.
Investment and operating cost for disposal of fly ash excluded.
401
-------
Table B-231
CATALYTIC OXIDATION PROCESS. 500 MW NEW OIL FIRED POWER UNIT. 1.0* S IN FUEL. 90* 502 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 28067000
YEARS ANNUAL
AFTER OPERA-
POWER TION,
UNIT KW-HR/
START KW
1 7000
2 7000
3 7000
4 7000
•; 7non
6 7000
7 7000
8 7000
9 7000
_LQ JODO_
11 5000
12 5000
13 5000
14 5000
ic snno
SULFUR
REMOVED
POWER UNIT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU BARRELS OIL PROCESS.
/YEAR /YEAR TONS/YEAR
31500000 5033600 7700
31500000 5033600 7700
31500000 5033600 7700
31500000 5033600 7700
31500000 5033600 7700
31500000 5033600 7700
31500000 5033600 7700
31500000 5033600 . 7700
iiinnnnn «p*-*&nn i7nn
22500000 3595400 5500
22500000 3595400 5500
22500000 3595400 5500
22500000 3595400 5500
16 3500 15750000 2516800 3800
17 3500 15750000 2516800 3800
18 3500 15750000 2516800 3800
19 3500 15750000 2516800 3800
21 1500
22 1500
23 1500
24 1500
26 1500
27 1500
28 1500
29 1500
_3Q 150.0.
TOT 127500
LIFETIME
PROCESS COST
LEVELIZED
6750000 1078600 1600
6750000 1078600 1600
6750000 1078600 1600
6750000 1078600 1600
6750000 1078600 1600
6750000 1078600 1600
6750000 1078600 1600
6750000 1078600 1600
TOTAL
BY-PRODUCT OP. COST
RATE, INCLUDING
EQUIVALENT NET REVENUE. REGULATED
TONS/YEAR I/TON ROI FOR
POWER
100* 100* COMPANY,
H2S04 H2S04 S/YEAft
23400 6.00
23400 6.00
23400 6.00
23400 6.00
2^&QQ fi.nft
23400 t
23400
23400
23400
16700
16700
16700
16700
11700
11700
11700
11700
11700
5000
5000
5000
5000
snnn
5000
5000
5000
5000
snnn
.00
.00
.00
.00
.on
.00
.00
.00
.00
.....
3 O 0 O 0
3O OO O
.00
.00
.00
.00
.on
.00
.00
.00
.00
OQ
573750000 91683000 139500 426000
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON Of SULFUR REMOVED
DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UMT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILDWATT-HCUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
8663500
8468900
8274300
8079700
7690500
7495900
7301300
7106700
AQi?inn
6379000
6184400
5989800
5795200
s <,nn Ann
5131200
4936600
4742000
4547300
TOTAL
NET
SALES
REVENUE,
S/YEAR
140400
140400
140400
140400
i&n&nn
140400
140400
140400
140400
t&n&nn
100200
100200
100200
100200
70200
70200
70200
70200
70200
3736400 30000
3541800 30000
3347200 30000
3152600 30000
? 9 SB 000, innnn
2763400
2568800
2374200
2179600
30000
30000
30000
30000
innnn
160143600 2556000
1.75 0.03
2.51 0.04
27.91 0.44
1147.98 18.32
64674200 1100200
PROCESS COST OVER LIFE OF
1.64 0.03
2.36 0.04
26.19 0.44
1074.32 18.27
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASEI (DECREASEl
IN COST OF IN COST OF
POWER, POWER.
S »
8523100
8328500
8133900
7939300
7550100
7355500
7160900
6966300
6278800
6084200
5889600
5695000
5061000
48664X10
4671800
4477100
3706400
3511800
3317200
3122600
2733400
2538800
2344200
2149600
157587800
1.72
2.47
27.47
1129.66
63574000
POWER UNIT
1.61
2.32
25.75
1056.05
8523100
16851600
24985500
32924800
48219600
55575100
62736000
69702300
82752800
88837000
94726600
100421600
110983000
1 15849400
120521200
124998300
132987200
136499000
139816200
142938800
148600200
151139000
153483200
155632800
-------
Table B-232. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(500-MW new oil-fired power unit, 2.5% S in fuel;
90% SO* removal; 8.4 tons/hr 100% //jSO,;
Converter and absorber startup bypass ducts.
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Heat recovery and ducts (4 direct oil-fired heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller air heaters included)
Fans (4 ID fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulfuric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H2S04 )
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
Investment, $
447,000
2,069,000
1,860,000
1,517,000
1,249,000
7,668,000
267,000
210,000
515,000
790.000
16,592,000
1,825,000
1,825,000
830,000
1,659,000
22,731,000
2,273,000
1,818,000
26,822,000
1,445,000
28,277,000
Percent of subtotal
direct investment
2.7
12.5
1.1.2
9.1
7.5
46.2
1.6
1.3
3.1
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
8.7
170.4
"Basis:
Midwest plant locution represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
403
-------
Table B-233. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW new oil fired power unit, 2.5% S in fuel;
90% SO2 removal; 58,600 tons/yr 100% HtS04 )
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
88,200 liters
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6),
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 16,592,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
7,380 man-hr
1,068,000 gal
705,900 MM Btu
166,000 M gal
53,550,000 kWh.
1.65/liters
8.00/man-hr
0.23/gal
-1.60/MMBtu
0.08/M gal
0.018/kWh
Total annual operating cost
145,500
145,500
59,000
245,600
(1,129,400)
13,300
963,900
663,700
31,000
847,100
992,600
4,213,300
169,400
.302.200
4,684,900
5,677,500
Percent of
total annual
operating cost
2.S6
2.56
1.04
4.33
(19.90)
0.23
16.98
11.69
0.66
14.92
17.48
74.22
2.98
5.32
82.52
100.00
Equivalent unit operating cost 96.89
Dollars/ton Dollars/bbI Cents/million Dollars/ton
100% H2S04 oil burned. Mills/kWh Btu heat input sulfur removed
1.13
1.62
18.02
296.79
"Basis:
Remaining life of power plant, 30 yr.
Oil burned, 5,033,600 bbl/yr, 9.000 Btu/kWh.
Power unit on-stream time.- 7,000 hr/yr.
Midwest plant location. 1975 operating costs.
Total capital investment, $28.277,000; subtotal direct investment, $16,592,000.
Working capital, $205,500.
Investment and operating cost for disposal of fly ash excluded.
404
-------
Table B-234
CATALYTIC OXIDATION PROCESS, 500 HW NEW CIL F.IRED POWER UNIT. 2.5* S IN FUEL. 90t S02 REMOVAL. REGULATED CO. ECONOMICS
FIXED INVESTMENT: $ 28277000
TOTAL
SULFUR BY-PRODUCT OP. COST
REMOVED RATE. INCLUDING NET ANNUAL
YEARS ANNUAL PCWER UNIT POWER UNIT BY EQUIVALENT NET REVENUE. REGULATED TOTAL INCREASE
AFTER OPERA- MEAT FUEL POLLUTION TONS/YEAR »/TOM ROI FOR NET (DECREASE)
POWER TION, REQUIREMENT, CONSUMPTION CONTROL PCWER SALES IN COST OF
UNIT KW-HR/ MILLION BTU BARRELS OIL PROCESS, 100* 100* COMPANY. REVENUE, POWER,
START KW
1
2
3
4
S
6
7
8
9
7000
7000
7000
7000
7.QOO.
7000
7000
7000
7000
/YEAR /YEAR TONS/YEAR
31500000 5033600
31500000 5033600
31500000 5033600
31500000 5033600
^isnnnnr. SOIItiQO
31500000 5033600
315COOOO 5033600
31500000 5033600
31500000 5033600
in 7nnn iisnnnnn tnitf>nn
11
12
13
14
1 S
16
17
18
19
5000
50CO
5000
5000
5QflO_
3500
3500
3500
3500
?0 3500
21
22
23
24
25
26
27
23
29
30
TOT
1500
1500
1500
1500
15"0
1500
1500
1500
1500
JL&QQ
127500
LIFETIME
22500000 3595400
225000CO 3595400
22500000 3595400
22500000 3595400
22*00000 mo^&nn
15750000 2516800
15750000 2516800
15750000 2516800
15750000 2516800
1 *,•?<; no 00 ?5I6PQO
6750000 1078600
6750000 1078600
6750000 1078600
6750000 1078600
A'lsnnoQ i riTfi&flo
6750000 1078600
6750000 1078600
6750000 1078600
6750000 1078600
67SQQOQ 1Q7&6QQ
573750000 91683000
19100
19100
19100
19100
i Q i nn
19100
19100
19100
19100
19100
13700
13700
13700
13700
11700
9600
9600
9600
9600
460.0
4100
4100
4100
4100
tioo
4100
4100
4100
4100
tinn
348500
AVERAGE INCREASE (DECREASE) IN UNIT OPERATING
DOLLARS PER BARREL OF OIL
MILLS PER KILOWATT-HOUR
BURNED
H2S04 H2S04
58600 6.00
58600 6.00
56600 6.00
58600 6.00
cft^nn A . nn
58600
58600
58600
58600
e; ft AOfl
41900
41900
41900
41900
&i Qnn
29300
29300
29300
29300
29100
12600
12600
12600
12600
i ?*\nn
12600
12600
12600
12600
l_?fkOO
.00
.00
.00
.00
.nn
.00
.00
.00
.00
_nn
.00
.00
.00
.00
.on
.00
.00
.00
.00
.fin
.00
.00
.00
.00
.nn
1068000
COST
CENTS PER MILLION BTU HEAT INPUT
PROCESS COST
LEVELUED
DOLLARS PER TON OF SULFUR
DISCOUNTED AT 10.0* TO INITIAL
REMOVED
YEAR, DOLLARS
INCREASE (DECREASE) IN UMT OPERATING COST EQUIVALENT TO DISCOUNTED
DOLLARS PER BARREL OF OIL
MILLS PER KILClWATT-HCUR
BURNED
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR
REMOVED
»/YEAR
8619200
8423200
8227100
8031000
"7 ft "^ *» nn n
7638900
7442900
7246800
7050700
j*.A**&Tn n
6358800
6162700
5966700
5770600
*»^ ~7&i\n n
5130400
4934300
4738300
4542200
A^&rfiTnn
3759000
3562900
3366900
3170800
?Q7&.Jtfl n
2778700
2582600
2386600
2190500
1 *!*}{* VI Q
159661600
1.74
2.50
27.83
458.14
64347900
PROCESS COST OVER
1.63
2.35
26.06
429.56
S/YEAR
351600
351600
351600
351600
"^ti &fin
351600
351600
351600
351600
i*%\ i\nn
251400
251400
251400
251400
2 "» 1 6 fin
175800
175800
175800
175800
iTsitnn
75600
75600
75600
75600
7*»i»nn
75600
75600
75600
75600
T'ifenn
6408000
0.07
0.10
1.12
18.39
2756400
LIFE OF
0.07
0.10
1.11
18.40
*
8267600
8071600
7*75500
7679400
7 4. (11400
7287300
7091300
6B95200
6699100
t\£fiAi nn
6107400
5911300
5715300
5S19200
55^^?OQ
4954600
4758500
4S62500
4366400
6.1 7n&nfi
36B3400
3487300
3291300
3095200
pft<)<»nn
2703100
2507000
2311000
2114900
i ojnonn
153253600
1.67
2.40
26.71
439.75
61591500
POWER UNIT
1.56
2.25
24.95
411.16
CUMULATIVE
NET INCREASE
{DECREASE)
IN COST OF
POWER.
*
•267600
16339200
24214700
31894100
'^^TTSftO
46664 BOO
53756100
60651300
67350400
^^•ISIVYfl
79960900
85872200
91587500
9710670C
i n 9&>44no
1073B450C
112143000
116705500
1210719OO
i 95?&>inn
12*925700
132413000
135704300
13*799500
1&1A4B7DD
144401 BOO
146908800
149219800
151334700
I «J'^!»*»1*^'|fl
S.
-------
Table B-235. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(5QO-MW new oil-fired power unit, 4.0% S in fuel;
90%SOi removal; 13.4
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Heat recovery and ducts (4 direct oil-fired heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller air heaters included)
Fans (4 ID fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulf uric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulf uric acid storage (storage and shipping
facilities for 30 days production of H2S04)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
Investment, $
Percent of subtotal
direct investment
447,000
2,069,000
1,860,000
1,517,000
1,249,000
7,668,000
367,000
210,000
2.7
12.4
11.1
9.1
7.5
45.8
2.2
1.3
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
515,000
795,000
16,697,000
1,837,000
1,837,000
835,000
1,670,000
22,876,000
2,288,000
1,830,000
26,994,000
1,455,000
28,449,000
3.1
4.8
100.0
11.0
11.0
5.0
10.0
137.0
13.7
11.0
161.7
8.7
170.4
"Basis:
Midwest plant location represents project beginning mid-1972. ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompanying overtime pay incentive not considered.
406
-------
Table B-236. Catalytic Oxidation Process
Total Aver.iRi' Annual Operating Costs -Regulated Utility Economics3
(500-MW iww oil-Jlmt'powcr'uiiit.4. "d%S~infuel;
% ,V02 removal; 93,800 tons/yr JOO%H2SOJ
Direct Costs
Delivered raw material
Catalyst
Subtotal taw material
Annual quantity
Unit cost, $
Total annual
cost, $
88,200 liters
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 6)
Heat credit
Process water
Electricity
Maintenance
Labor and material, .04 x 16,697,000
Analyses
Subtotal conversion costs
Subtotal direct costs
7,890 man-hr
1,068,000 gal
853,800 MM Btu
266,000 M gal
55,460,000 kWh
1.65/liters
8.00/man-hr
0.23/gal
-1.60/MM Btu
0.08/M gal
0.018/kWh
145,500
145,500
63,100
245,600
(1,366,100)
21,300
998,300
667,900
43,000
673,100
818,600
Percent of
total annual
operating cost
2.62
2.62
1.13
4.41
(24.54)
0.38
17.94
12.00
0.77
12.09
14.71
Indirect Costs
Average capital charges ;it 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
4,238,900
134,600
373,000
4,746,500
5,565,100
76.17
2.42
6.70
85.29
100.00
Dollars/ton Dollars/bbl Cents/million Dollars/ton
100%H2S04 oil burned Mills/kWh Btu heat input sulfur removed
59.33
1.11
1.59
Equivalent unit operating cost
"Hasis:
Remaining lilc ul power plant. .Ut yr.
Oil hiirnoil, 5,0X1,600 hbl/yr. 9,000 Btu/kWIi.
Power unit on-stroatn time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $28,449,000; subtotal direct investment, $16,697,000.
Working capital, $186,900.
Investment and operating cost for disposal of tly asli excluded.
17.67
181.75
'407
-------
o
oo
Table B-237
CATALYTIC OXIDATION PROCESS, 50G HW NEW CIL FIRED POWER UNIT, 4.0* S IN FUEL. 90X S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT: * 28449000
YEARS ANNUAL
AFTER GPE*A-
PQWER TICN,
UNIT KK-HR/
START Kk
1 7000
2 7COO
3 7COC
4 70CO
5 3.00.0-
6 7COO
7 7000
8 7000
9 7000
1° 7000
11 5000
12 5000
13 50CO
14 5000
_1S SOOQ-
16 3500
17 3500
18 3500
19 3500
^20 ?snn
21 15CO
22 1SCO
23 15CO
24 1500
_2S 1SDO_
26 1500
27 1500
28 1500
29 1500
-30 15QO_
TOT 127500
LIFETIME
PROCESS COST
LEVEtlZED
SULFUR BY-PRODUCT
REMOVED RATE,
POWER UNIT POWER UNIT BY EQUIVALENT
HEAT FUEL POLLUTION TONS/YEAR
REQUIREMENT, CONSUMPTION, CONTROL
MILLION BTU BARRELS OIL PROCESS, 100*
/YEAR /YEAR TONS/YEAR H2S04
31500000 5033600 30600
31500000 5033600 30600
31500000 5033600 30600
31500000 5033600 30600
31500000 5033600 30600
31500000 5033600 30600
31500000 5033600 30600
31500000 5033600 30600
«1<;r>nnnn 5Q136.PQ . , *«Ann
22500000 3595400 21900
22500000 3595400 21900
22500000 3595400 21900
22500000 3595400 21900
??sopnoo 159J4DO 7i«jnn
15750000 2516800 15300
15750000 2516800 15300
15750000 2516800 15300
15750000 2516800 15300
6750000 1078600 6600
6750000 1078600 6600
6750000 1078600 6600
6750000 1078600 6600
.6750000 10766(30.. . _ - IS 600 „.-.;
6750000 1078600 6600
6750000 1078600 6600
6750000 1078600 6600
6750000 1076600 6600
93800
93800
93800
93800
-S3&OA-
93800
93800
93800
93800
67000
67000
67000
67000
46900
46900
4690C
46900
4.6*00
20100
20100
20100
20100
2QIQ.Q
20100
20100
20100
20100
573750000 91683000 558000 1708500
AVERAGE INCREASE (DECREASE! IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
DISCOUNTED AT 10. 0* TO INITIAL YEAR, DOLLARS
INCREASE (DECREASE) IN UNIT OPERATING COST EQUIVALENT
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HOUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
TOTAL
OP. COST
INCLUDING
MET REVENUE, REGULATED TOTAL
*/TON ROI FOR NET
POWER SALES
lOOt COftPANY, REVENUE,
H2S04 t/YEAR */YEAR
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6 on
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6. CO
6.00
6.00
6.00
fc.no
TO DISCOUNTED
8524800
8327500
8130300
7933100
7538600
7341300
7144100
6946800
...6749W1Q
6308600
6111400
5914100
5716900
5519Wfl
5112900
4915600
4718400
4521200
3779300
3582000
3384800
3187500
2793000
2595800
2398500
2201300
?nn4non
562800
562800
562800
562800
562800
562800
562800
562800
402000
402000
402000
402000
281400
281400
281400
281400
120600
120600
120600
120600
120600
120600
120600
120600
i?n6Ofl
158451000 10251000
1.73 0.11
2.49 0.17
27.62 1.79
283.96 18.37
63660700 44H200
PROCESS COST OVER LIFE OF
1.61 0.11
2.32 0.16
25.78 1.78
265.36 18.38
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
7962000
7764700
7567500
7370300
21Z30.QQ
6975800
6778500
6581300
6384000
<,} flfcnnn
5906600
5709400
5512100
5314900
4831500
4634200
4437000
4239800
3658700
3461400
3264200
3066900
^869700.. .
2672400
2475200
2277900
2080700
148200000
1.62
2.32
25.83
265.59
59249500
POWER UNIT
1.50
2.16
24. OQ
246.98
7962000
15726700
23294200
30664500
44813300
51591800
•58173100
64557100
76650500
82359900
87872000
93186900
103136000
107770200
112207200
116447000
124148200
127609600
130873800
133940700
139482800
141958000
144235900
146316600
-------
Table B-238. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(500-MW existing oil-fired power unit, 2.5% S in fuel;
90%SOi removal;8.6 tons/hr
Startup bypass ducts and dampers
Electrostatic precipitators and inlet ducts (4
low temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (4 converters
including catalyst sifter, hopper, storage bin,
conveyors, and elevators)
Reheat (8 direct oil-fired reheaters and 4 flue
gas heat exchangers)
Fans (4 fans including exhaust gas ducts between fans
and stack gas plenum)
Sulfuric acid absorbers and coolers (2 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between absorbers and fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of H^SO.))
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense •
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
Catalyst
Total capital investment
Investment, $
276,000
3,682,000
1,718,000
2,832,000
1,923,000
5,875,000
314,000
493,000
574,000
884,000
18,571,000
2,229,000
2,414,000
1,300,000
2,043,000
26,557,000
2,656,000
2,125,000
31,338,000
1,486,000
32.824.000
Percent of subtotal
direct investment
1.5
19.8
9.3
15.2
10.3
31.6
1.7
2.7
3.1
4.8
100.0
12.0
13.0
7.0
11.0
143.0
14.3
11.4
168.7
8.0
176.7
"Basis:
Midwest plant location represents project beginning mid-1972, ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Remaining lite of power unit, 25 yr.
Investment requirements for disposal of fly ash excluded.
Construction labor shortages with accompany ing overtime pay incentive not considered.
409
-------
Table B-239. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(500-MW existing oil-fired power unit, 2.5% S in fuel;
90% S0t removal; 59,900 tons/yr 100% H^SO4 )
Annual quantity
Unit cost, $
Total annual
cost, $
Direct Costs
Delivered raw material
Catalyst
Subtotal raw material
90,000 liters
Conversion costs
Operating labor and
supervision
Utilities
Fuel oil (No. 2)
Process water
Electricity
Maintenance
Labor and material, .04 x 18,571,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 15.3%
of total capital investment
Overhead
7,380 man-hr
8,690,000 gal
4,245,000 M gal
61,610,000 kWh
1.65/liters
8.00/man-hr
0.30/gal
0.03/M gal
0.018/kWh
148,500
148,500
59,000
2,607,000
127,400
1,109,000
742,800
31.400
4,676,600
4,825,100
5,022,100
Percent of
total annual
operating cost
1.34
1.34
0.53
23.43
1.14
9.97
6.68
0.28
42.03
43.37
45.13
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Equivalent unit operating cost
Dollars/ton
100%H2S04
185.74
Dollars/bb!
oil burned
2.16
935,300
343,600
6,301,000
11,126,100
Cents/million
Mills/kWh Btu heat input
3.18 34.S5
8.41
3.09
56.63
100.00
Dollars/ton
sulfur removed
568.82
•''Basis:
Remaining life of power plant, 25 yr.
Oil burned. 5,145,400 bbl/yr, 9,200 Btu/kWh.
Power unit on-stream time, 7,000 hr/yr.
Midwest plant location, 1975 operating costs.
Total capital investment, $32,824,000; subtotal direct investment, $18,571,000.
Working capital, $830,300.
Investment and operating cost for disposal of fly ash excluded.
410
-------
Table B-240
CATALYTIC CX.IDATICS PROCESS, 500 MW EXISTING OIL FIRED PDKER UNIT, 2.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO. ECONOMICS
AFTER- 'oPTfvi-
PO"'E« TICN,
UNIT Kii-HR/
ST&OT Kk
1
2
3
^
7
6
9
j Q
11
12
13
14
IS
Ib
17
Id
19
—20,
21
22
23
24
25
2b
27
26
29
3.Q
TOT
7COC
7CCC
7000
7CCC
JCCC.
5000
5COO
500 C
500 C
_ SCOC
3500
3 500
3500
3500
3.5CC.
150C
1500
15CC
1500
1SCC
1500
15CC
1500
150C
-15.00.
92500
LIFETIME
-,„:-:_ FIXED INVESTMENT:- :••*-»<
SULFUR BY-PRODUCT
*?*>?&-'&*---••-"- - •'- " REMOVED RATE,
.-.-•P-ChrR uMT POWER UNIT BY EQUIVALENT
- ' HEAT FUEL POLLUTION TONS/YEAR
REJC IRECENT , CONSUMPTION, CONTROL
M1LLICK BTU BARRELS Oil PROCESS, 100*
/rEic /YEAR TONS/YEAR H2S34
3 2 20COOO
32 20 00 CO
322CCCOj
3220CCCC
•3 p p r r^rf
23COOCOO
2KOCOCC
230CCQOO
230CCOCO
2 ' '"CCQG'"
ItlCOGCO
H 100000
16100000
16100000
It 1C °DOQ
6900000
6900000
6900000
6900000
t g r nn fin
6900000
6900000
6900000
6°COOCO
tor ^ncr
425500000
AVERAGE INCREASE
DOLLARS
5145400
5145400
5145400
5145400
M4^40C
3675300
3675300
3675300
3675300
3 fa 75 3QG
2572700
2572700
2572700
2572700
2«;7;>-7nn
1102600
110260C
110260C
1102600
1 1 OP fefiO
1102600
1102600
1102600
110260C
1 1 DP fcnn
67993000
19600
19600
19600
19600
59900
59900
59900
59900
••- 32824000
TOTAL
OP. COST
INCLUDING
NET REVENUE, REGULATED
i/TON RCI FOR
POWER
100* COMPANY,
H2S04 */YEAR
6.
6.
6.
6.
00
00
00
00
14539800
14266700
13993600
1372C500
TOTAL
NET
SALES
REVENUE,
S/YEAR
359400
359400
359400
359400
L<»*on ^oonn »>.nn 11447400 is«4nn
14000
14000
14000
14000
L*t 00 0
9600
9600
9800
9800
QR3Q
4200
4200
4200
4200
4200
4200
4200
4200
4200
4pnn
259000
(DECREASE) IN UNIT OPERATING
PER BARRE
MILLS PER KILOWAT
CENTS PER MILLION
PROCESS COST
LEVEL1ZED
DOLLARS
DISCOUNTED AT
L OF OIL BURNED
T-HCUR
BTL HEAT INPUT
4280C
42800
42800
42600
4 2 BQ.O
29900
29900
29900
29900
?«J90Q
128CC
12800
12800
12800
I ? BOQ
12800
1280C
12600
12800
128.00-
791000
COST
6.
6.
6.
6.
^
6.
6.
6.
6.
£^
6.
6.
6.
6.
^
6.
6.
6.
6.
*,.
00
00
00
00
nn
00
00
00
00
nn
00
00
00
00
nn
00
00
00
00
nn
PER TON OF SLLFUR REMOVED
10.0* TO
INITIAL YEAR, DOLLARS
INCREASE {DECREASEI IN UMT OPERATING COST EQUIVALENT TO
DOLLARS
PER BARRE
MILLS PER KILOKAT
CENTS PER MILLION
DOLLARS
PER TUN 0
L OF OIL BURNED
T-HCU»
BTL HEAT INPUT
f SLLFUR REMOVED
OISCOUKTED
11537500
11264400
10991300
10718200
LQ^t4 ** T 0 0
8923500
8650300
8377200
8104100
76 3 1 fifl fl
5838500
5565400
5292300
5019200
6 7&tk inn
4473000
4199900
3926800
3653700
•a q BOhfl 0
212906100
3.13
4.60
50.04
822.03
96647300
PROCESS COST OVER
2.94
4.32
47.00
772.49
256800
256800
256800
256800
3 5£fiQ Q
179400
179400
179400
179400
1 "794QO
76800
76800
76800
76800
7fiBOO
76800
76800
76800
76800
268-0.0_
4746000
0.07
0.10
1.12
18.32
2342100
LIFE CF
0.07
0.10
1.11
18.34
NET ANNUAL CU»uLA*I¥E
INCREASE NET INCREASE
(DECREASE) (DECREtSE)
IN COST CF IN CCST 2-
POWER, PO»ER,
t S
14180400
13907300
13634^00
1336110C
1 infiBQQO
11280700
11007600
10734500
10461400
1 0 1 8 83 QQ
8744100
8470900
8197800
7924700
7fiSl 6 OG
5761700
5488600
5215500
4942400
4i>693nn
4396200
4123100
3850000
3576900
^ 30 3ft nn
208160100
3.06
4.50
48.92
803.71
96305200
POWER UNIT
2 .87
4.22
45.89
754.15
1416040:
280877C:
417219::
55:63-:::
&6 i?" t~:
7945:?::
9:4593::
ic 11938::
1116552::
121=*±35ri"
1305876CC
139C585CO
1472563::
155181 :::
1 !i2fi^?(s'ri~
1685943CC
1740629:;
17929840:
18424080:
1 8 HQ 1 P!^r
1933063CC
1974294::
2012794CC
2048563::
? n Hi AD 1 3 G
-------
Table B-241. Catalytic Oxidation Process
Summary of Estimated Fixed Investment3
(1,000-MW new oil-fired power unit, 2.5% S in fuel;.
90% SOt removal; 16.2 tons/hr 100% H2SO4 )
Investment, $
Percent of subtotal
direct investment
642,000
3,370,000
3,216,000
2,097,000
1,856,000
13,696.000
417,000
270,000
2.3
12.2
11.7
Converter and absorber startup bypass ducts
and dampers
Electrostatic precipitators and inlet ducts (4
high temperature electrostatic precipitators including
common feed plenum)
Sulfur dioxide converters and ducts (8 converters
including catalyst sifter, hopper, storage bin,
conveyors, andgelevators)
Heat recovery and ducts (4 direct oil-fired heaters and 4
fluid/air heaters including ducts between economizers
and air heaters, and combustion air ducts and dampers
between powerhouse and air heaters; investment credit
for use of smaller.air heaters included)
Fans (4 ID fans including exhaust gas ducts and
dampers between ID fans and stack gas plenum)
Sulfuric acid absorbers and coolers (4 absorbers
including mist eliminators, coolers, tanks, pumps,
and ducts and dampers between air heaters and
ID fans)
Sulfuric acid storage (storage and shipping
facilities for 30 days production of HjSO4)
Utilities (instrument air generation and supply system,
fuel oil storage and supply system, and distribution
systems for obtaining process water, and electricity
from power plant)
Service facilities (buildings, shops, stores, site
development, roads, railroads, and walkways)
Construction facilities
Subtotal direct investment
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Subtotal fixed investment
Allowance for startup and modifications
Interest during construction (8%/annum rate)
Total capital investment excluding catalyst
C;it;ilyst
Total c.ipiial investment
aliasis
Midwest plant locution represents project beginning mid-1972,ending mid-1975. Average cost basis for scaling, mid-1974.
Only pumps are spared.
Investment ict|iiiicmcnls for disposal ot'tly ash excluded.
(\nisiriiciion labor shortages with accompanying overtime pay incentive not considered.
7.6
6.7
49.8
1.5
1.0
alkways) 662,000
1,311,000
27,537,000
2,754,000
2,754,000
1,377,000
2,478,000
36,900,000
>s 3,690,000
n rate) 2.952.000
catalyst 43,542,000
2,814,000
46,356,000
2.4
4.8
100.0
10.0
10.0
5.0
9.0
134.0
13.4
10.7
158.1
10.2
168.3
4I2
-------
Table B-242. Catalytic Oxidation Process
Total Average Annual Operating Costs-Regulated Utility Economics3
(1,000-MW new oil-fired power unit, 2.5% S in fuel;
90% S02 removal; 113,300 tons/yr 100% HtS04)
Total annual
Annual quantity Unit cost, $ cost, $
Direct Costs
Delivered raw material
Catalyst 170,600 liters 1.65/liters
Subtotal raw material
Conversion costs
Operating labor and
supervision 7,890 man-hr 8.00/man-hr
Utilities
Fuel oil (No. 6) 2,066,000 gal 0.23/gal
Heat credit 1 ,365,000 MM Btu -1 .60/MM Btu
Process water 322,000 M gal 0.08/M gal
Electricity 103,570,000 kWh 0.017/kWh
Maintenance
Labor and material, .03 x 27,537,000
Analyses
Subtotal conversion costs
Subtotal direct costs
Indirect Costs
Average capital charges at 14.9%
of total capital investment
Overhead
Plant, 20% of conversion costs
Administrative and marketing
Subtotal indirect costs
Total annual operating cost
Dollars/ton Dollars/bbl
100%H2S04 oil burned Mills/kWh
Equivalent unit operating cost 78.66 0.92 1.27
281,500
281,500
63,100
475,200
(2,184,000)
25,800
1 ,760,700
826,100
49,100
1,016,000
1,297,500
6,907,000
203,200
504,200
7,614,400
8,911,900
Cents/million
Btu heat input
14.63
Percent of
total annual
operating cost
3.16
3.16
0.71
5.33
(24.51)
0.29
19.76
9.27
0.55
11.40
14.56
77.50
2.28
5.66
85.44
100.00
Dollars/ton
sulfur removed
240.93
"Basis:
Remaining life of power plant, 30 yr.
Oil burned, 9,731,500 bbl/yr, 8,700 Btu/kWh.
Power unil on-stream lime, 7,000 lir/yr.
Midwest plant location, 1975 operating costs.
Tol;il capital investment, $46,356,000; subtotal direct investment, $27,537,000.
Working capital, $286,100.
Investment and operating cost for disposal of fly ash excluded.
413
-------
Table B-243
CATALYTIC OXIDATION PROCESS, 1000 MW KEW OTL FIRED POWER UNIT, 2.5* S IN FUEL, 90* S02 REMOVAL, REGULATED CO. ECONOMICS
FIXED INVESTMENT:
46356000
Y6*fcS ANNUAL
AFT = * CPErA-
Pu.ER T10N,
UMT K*-hR/
STiST KW
1 7COO
I 7CCO
2 7000
4 70CC
5 20.0.0.
6 7000
7 7000
a 7000
9 7000
_1£ 20,00 _
11 5000
12 5000
13 5000
14 5000
-15 _ Sflflfl
16 3500
17 3500
16 3500
19 3500
_2Q 3500
i\ 1500
22 1500
23 1500
24 1500
_2S 1SQO
SULFUR
REMOVED
POWER UMT POWER UNIT BY
HEAT FUEL POLLUTION
REQUIREMENT, CONSUMPTION CONTROL
MILLION BTU BARRELS OIL PROCESS,
/YEAR . /YEAR TONS/YEAR
60900000
60900000
60900000
60900000
6Q9.00QOO
609000CC
60900COC
6090COOO
60900000
43500000
43500000
4350000C,
43500000
30450000
30450000
30450000
304500CO
3045QQGCi
13050000
13050000
13050000
13050000
13.Q5QDQC
9731500
9731500
9731500
9731500
93? 1,500.
9731500
9731500
9731500
9731500
973.1'SQ.Q
6951100
6951100
6951100
6951100
tSSliDQ
4865600
4865POO
4865800
4665800
. 486580(1 . ,.
2085300
2085300
2085300
2085300
..2085300
26 1500 1305000C 2085300
27 1500 130500CO 2085300
26 1500 13050000 2085300
29 1500 13050000 2085300
_3.Q 15.G.Q liCLSdQDIi 20B53QQ--
37000
37000
37000
37000
37000
37000
37000
37000
26400
26400
26400
26400
7fe400
18500
18500
18500
18500
7900
7900
7900
7900
I9QQ
7900
7900
7900
7900
7SOO.
BY-PROOUCT
RATE,
EQUIVALENT NET REVENUE,
TONS/YEAR S/TON
100% 100*
H25D4 H2S04
113300
1133CC
113300
113300
113*00 --
113300
11330C
113300
113300
80900
80900
80900
80900
.. 809QO
56700
56700
56700
56700
24300
24300
24300
24300
24300
24300
24300
24300
,_ 2A3QQ
6.00
6.00
6.00
6.00
6.^00.
6.00
6.00
6.00
6.00
A- no
6.00
6.00
6.00
6.00
fc.no
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
6.00
. . 6..QQ. .,
TOTAL
OP. COST
INCLUDING
REGULATED
ROI FOR
POWER
COMPANY,
S/YEAR
13734500
13413100
13091700
12770300
V244$9fl 0
121275CC
11806100
11484700
1116330C
10105800
9784400
9463000
9141600
.... £?2C2Qp
8156800
7835400
7514000
7192600
6013400
5692000
5370600
5049200
4406400
4085000
3763600
3442200
TOTAL
NET
SALES
REVENUE,
S/YEAR
679800
679800
679800
679800
679800
679800
679800
679800
485400
485400
485400
485400
340200
340200
340200
340200
3.40.2flO_
145800
145800
145800
145800
145800
145800
145800
145800
NET ANNUAL CUMULATIVE
INCREASE NET INCREASE
(DECREASE) (DECREASE)
IN COST OF IN COST OF
POWER, POWER,
$ S
13054700
12733300
12411900
12090500
11447700
11126300
10804900
10483500
. .10162100 .
9620400
9299000
8977600
8656200
7816600
7495200
7173800
6852400
£531000
5867600
5546200
5224800
4903400
4260600
3939200
3617800
3296400
13054700
25788000
36199900
50290400
73507200
84633500
95438400
105921900
125704400
135003400
143981000
152637200
168788600
176283800
183457600
190310000
. 19684 10.Qfl
202708600
208254800
213479600
218383000
-222.265.000
227225600
231164800
234782600
238079000
TOT 127500 1109250000 177252500 673500 2064000
LIFETIME AVERAGE INCREASE (DECREASE! IN UNIT OPERATING COST
DOLLARS PER BARREL OF OIL BURNED
MILLS PER KILOWATT-HDUR
CENTS PER MILLION BTU HEAT INPUT
DOLLARS PER TON OF SULFUR REMOVED
PROCESS COST DISCOUNTED AT 10.0% TO INITIAL YEAR, DOLLARS
253438000 12384000 241054000
1 .43
1.99
22.85
376.30
102227700
0.07
0.10
1.12
18.39
5328400
36
89
LEVELUEO INCREASE (DECREASE) IN UMT OPERATING COST EQUIVALENT TO DISCOUNTED PROCESS COST OVER LIFE OF
DOLLARS PER BARREL OF OIL BURNED 1.34 0.07
MILLS PER K1LOWATT-HCUR 1.86 0.09
CENTS PER MILLION BTU HEAT INPUT 21.42 1.12
DOLLARS PER TON OF SULFUR REMOVED 352.63 16.38
21.73
357.91
96899300
POWER UNIT
1.27
1.77
20.30
334.25
-------
APPENDIX C
LARGE SCALE FLUE GAS DESULFURIZATION UNITS ON U.S. POWER PLANTS,
SEPTEMBER 1973 (COMPLETED, UNDER CONSTRUCTION, AND PLANNED) (11)
Utility company
power station
("oimnon weal tli Edison
Will County No. I
Kansas City Power &
Light, Hawthorn No. 4
Kansas Cily Power &
Light, LaCygnc Station
Ari/.ona Public Service
Cholla Station
Detroit Edison
SI. Clair No. 6
Southern California
Edison (operating
agent) Mohave Station
TVA
Widow's Creek No. 8
Northern States Power
Sherhurne County No. I
Public .Service of
Indiana, Gibson Station
Northern States Power
Sherburne County No. 2
Union Electric Co.
Meramec No. 1
Kansas Power & Light
Lawrence No. 4
Kansas Power & Light
Lawrence No. 5
Kansas City Power &
Light, Hawthorn No. 3
Louisville Gas & Electric
Paddy's Run No. 6
Duqiiesne Light Co.
Phillips Station
Southern California
Edison (operating
agent) Mohave Station
Ohio Edison/Mansfield
Station (2 units)
Montana Power
Colslrip No. 1 & 2
Columbus & Southern
Conesville No. 5 X (>
New or
retrofit
R
R
N
R
R
R
R
N
N
N
R
R
N
R
R
R
R
N
N
N
SizeofKGD
unit (MW)
Process
vendor
Limestone Scrubbing
156 B&W
100
820
115
180
160
550
680
650
680
Lime
140
125
430
100
70
100
160
1650
720
750
CE
B&W
Research
Cottrell
Peabody
Engineering
UOP
TVA
CE
CE
CE
Scrubbing
CE
CE
CE
CE
CE
Chemico
SCE/Stearns-
Roger
Chemico
CEA
Not selected
Fuel and
sulfur content
Coal, 3.5%
Coal, 3.5%
Coal, 5%
Coal, 0-4%- 1.0%
Coal, 3.7%
Coal, 0.5%-0.8%
Coal, 3.7%
Coal, 1%
Coal, 1 .5%
Coal, 1%
Coal, 3%
Coal, 3.5%
Coal. 3.5%
Coal, 3.5%
Coal, 3%
Coal, 2%
Coal, 0.5%-0.8%
Coal. 4.3%
Coal, 0.8%
Status
(start-up date)
Operational
(Feb. 1972)
Operational
(Aug. 1972)
Operational
(June 1973)
Under construction
(Oct. 1973)
Under construction
(Dec. 1973)
Under construction
(March 1974)
Under construction
(Jan. 1977)
Under construction
(May 1976)
Planned
(1976)
Planned
(May 1977)
Abandoned
(Sept. 1968)
Operational
(Dec. 1968)
Operational
(Nov. 1971)
Operational
(Nov. 1972)
Operational
(April 1973)
Under construction
(Nov. 1973)
Under construction
(Dec. 1973)
Under construction
(early 1975)
Under construction
(May 1975)
Planned
(1976)
415
-------
Utility company
power station
Salt River Project
Navajo No. 1
Salt River Project
Navajo No. 2
Arizona Public Service
Four Corners No. 1
Arizona Public Service
Four Corners No. 2
Southern California
Edison (operating
agent) Mohave No. 1 & 2
Arizona Public Service
Four Corners No. 3
Salt River Project
Navajo No. 3
Arizona Public Service
Four Corners No. 4
Arizona Public Service
Four Corners No. 5
Boston Edison
Mystic No. 6
Potomac Electric & Power
Dickerson No. 3
Philadelphia Electric
Eddystonc No. 1
Catalytic Oxidation (Cat-Ox)
Illinois Power Co.
Wood River No. 4
Wellman-Lord
Northern Indiana
Public Service
D. H. Mitchell No. 1 1
Aqueous Sodium Base Scrubbing
Nonrepenerablc
Nevada Power
Reid Gardner No. 1 & 2
Nevada Power
Reid Gardner N. 3
Dry Adsorption
Indiana & Michigan Electric
Tanner's Creek Station
New or
retrofit
N
N
R
R
R
R
N
R
R
R
R
R
R
R
R
R
R
Size olT'CjO Process
unlt(MW) vendor
L/LS Not Selected
750 Not selected
750
175
175
1180
229
750
800
800
"*'
Magnesium
150
100
120
Not selected
Not selected
Not selected
Not selected
Not selected
Not selected
Not selected
Not selected
Oxide Scrubbing
Chemico
Chemico
United
Engineers
Other SOi Control Systems
110 Monsanto
115
250
125
150
Davy Powergas/
Allied Chemical
CEA
CEA
B&W/Esso
Fuel and
sulfur content
Coal, Q.5%-0.8%
Coal, 0.5%-0.8%
Coal, 0.75%
Coal, 0.75%
Coal, 0.5%-0.8%
Coal, 0.75%
Coal, 0.5%-0.8%
Coal, 0.75%
Coal, 0.75%
Oil. 2.5%
Coal, 2%
Coal, 2.5%
Coal, 3.2%
Coal,3,5%
Coal, 0.5%-!. 0%
Coal, 0.5%- 1.0%
Coal
Status
(start-up date)
Construction start,
Nov. 1974 (Mar. 1976)
Construction start,
Oct. 1975 (Oct. 1976)
Construction start,
Oct. 1975 (Oct. 1976)
Construction start,
Nov. 1975 (Dec. 1976)
Planned
(Dec. 1976)
Construction start,
June 1976 (Mar. 1977)
Construction start,
Mar. 1976 (Mar. 1977)
Construction start,
Sept. 1975 (Apr. 1977)
Construction start,
Nov. 1976 (June 1977)
Operational
(April 1972)
Operational
(Sept. 1973)
Under construction
(Dec. 1973)
Operational
(Oct. 1972)
Under construction
(early 1975)
Under construction
(Dec. 1973)
Under construction
(1975)
Under construction
(1974)
416
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Utility company
power station
New or
retrofit
SizeofFGD
unit (MW)
Process
vendor
Fuel and
sulfur content
Status
(start-up date)
Process Not Selected
Public Service of
New Mexico
San Juan No. 2
Potomac Electric & Power
Chalk Point No. 3
Potomac Electric & Power
Chalk Point No. 4
Potomac Electric & Power
Dickerson No. 4
Potomac Electric & Power
Dickerson No. 5
R
N
N
N
N
100
630
630
800
800
Not selected
Not selected
Not selected
Not selected
Not selected
Coal, 0.8%
Oil
Oil
Coal, 2%
Coal, 2%
Planned
(Nov. 1974)
Planned
(1975)
Planned
(1976)
Planned
(1976)
Planned
(1977)
417
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