EPA-650/2-74-098-Q
August 1975
Environmental Protection Technology Series
VALUATION OF R & D INVESTMENT
ALTERNATIVES FOR SOX AIR POLLUTION
CONTROL PROCESSES,
PART 2
kl V
UJ
O
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EPA-650/2-74-098-0
EVALUATION OF R & D INVESTMENT
ALTERNATIVES FOR SOX AIR POLLUTION
CONTROL PROCESSES,
PART 2
by
S. Caceres, L. Do, N. Gonzalez,
H. A. Kahn, G. K. Mathur, and J. J. O'Donnell
The M. W. Kellogg Company
1300 Three Greenway Plaza East
Houston, Texas 77046
Contract No. 68-02-J308 (Task 23)
ROAP No. 21ADE-010
Program Element No. 1AB013
EPA Task Officer: Gary L. Johnson
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D. C. 20460
August 1975
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EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development.
EPA, and approved for publication. 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.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These series are:
1. ENVIRONMENTAL HEALTH EFFECTS RESEARCH
2. ENVIRONMENTAL PROTECTION TECHNOLOGY
3. ECOLOGICAL RESEARCH
4. ENVIRONMENTAL MONITORING
5. SOCIOECONOMIC ENVIRONMENTAL STUDIES
6. SCIENTIFIC AND TECHNICAL ASSESSMENT REPORTS
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/2-74-098-a
ii
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TABLE OF CONTENTS
PAGE NO.
1. Introduction 1
2. Summary and Conclusion 5
2.1 SO Emission Sources 5
2.2 Coit of Stack Gas Scrubbing 6
2.2.1 Utility Plants 6
2.2.2 Industrial Boiler Plants 6
2.2.3 Sulfuric Acid Plants 7
2.2.4 Sulfur (Claus) plants 8
2.3 Cost of Fuel Conversion 8
2.3.1 Substitute Natural Gas 8
2.3.2 Intermediate Btu Gas 8
2.3.3 Low Btu Gas 9
2.3.4 Solvent Refined Coal 9
3. Desulfurization Processes 10
3.1 Flue Gas Desulfurization 10
3.2 Substitute Natural Gas H
3.3 Solvent Refined Coal 12
4. SO Emission Sources 17
Jt
4.1 Utility Plants 17
4.1.1 Upgraded Data Base for Utility Plants 17
4.1.2 FPC Form 67 and the Creating of the
Upgraded Data Base 17
4.1.3 Steps in Creating the Data Base 18
4.1.4 Assumptions for Data Extractions and
Data Validation 19
4.1.5 Methods to Improve the Data Base 20
4.1.6 Effect of the size of the Data Base on
Cost 21
4.2 Industrial Boilers 22
4.2.1 Original Data Base From NEDS 22
4.2.2 Data Extraction Step 22
4.2.3 Data Validation Step 24
4.3 Sulfuric Acid Plants 26
4.4 Sulfur (Claus} Plants 29
5. The General Cost Model 43
5.1 Introduction 43
5.2 Review of the Utility Financing Method 43
5.3 Discounted Cash Flow Method 46
111
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Table of Contents (Contd.)
PAGE NO.
Cost of Stack Gas Scrubbing 51
6.1 Utility Plants 51
6.1.1 Comparison of Cost Analysis as Applied
to Different Data Bases 51
6.1.2 Scrubbing Cost Analysis Using Upgraded
Data Base 52
6.2 Sulfuric Acid Plants 56
6.2.1 Process Appraised 56
6.2.2 Variation of Equipment Costs and Plant
Size 58
6.2.3 Cost Model 60
6.2.4 Total Plant Investment and Total Capital
Required 71
6.2.5 Operating Costs 71
6.2.6 Effect of Various Parameters on Costs 73
6.2.7 Wellman-Lord Model Applied to Existing
Sulfuric Acid Plants 74
6.3 Industrial Boilers 76
6.3.1 Conventional Scrubbing Systems 76
6.3.2 Packaged Scrubbing System 79
6.4 Wellman/Allied Model Applied to Claus Plants 83
6.4.1 Equipment Costs 85
6.4.2 Raw Materials and Utilities 87
6.4.3 Credits 87
6.4.4 Reference Size 88
Cost of Fuel Conversion 143
7.1 Costs of Mine-Mouth Coal 143
7.2 Costs of Mine-Mouth SNG 144
7.3 Cost Model for Production of Intermediate
Btu Gas 146
7.3.1 Electric Power and High Pressure Steam
Requirements for the Intermediate Btu Gas
Plant 146
7.3.2 Major Equipment Costs, E 146
7.3.3 Total Capital Requirement and Net Annual
Operating Cost 150
7.3.4 Annual Raw Material Requirements 150
7.4 Cost Model for Production of Low Btu Gas 152
7.4.1 Electric Power ard High Pressure Steam
Requirements for the Low Btu Gas Plant 152
IV
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Table of Contents (Contd.)
7.4.2 Major Equipment Costs, E
7.4.3 Total Capital Requirement and Net Annual
Operating Cost
7.4.4 Annual Raw Material Requirements
7.5 Cost of Mine-Mouth SRC
8. References
9. Appendices
FPC Form 67
Appendix A.
Appendix B.
Appendix C.
Appendix D.
Appendix E.
Appendix F.
Appendix G.
Appendix H.
Appendix I.
Appendix J.
PAGE NO,
152
156
156
158
171
173
173
NEDS Data Input Form for Industrial Plants 187
The General Model
Derivation of Equation for Total Annual
Production Cost-Discounted Cash Flow
Method
Stack Gas Scrubbing Cost Models for
Utility Plants-Summary
Packaged Limestone Scrubbing System
for 50 MM Btu/hour Boiler
Sample Calculation of Cost of SNG and
SRC
189
211
218
225
235
Sample Calculation of Cost of Intermediate
Btu Gas 243
Sample Calculation of Cost of Low Btu Gas 246
Nomenclature 249
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LIST 0? TABLES
TABLE NO. DESCRIPTION PAGE NO
4.1
4.2
4.3
t.4
4.5
4.6
4.7
4.8
5.1
5.2
6.1
6.2
6.3
Summary of Errors Related to the Reduced
Data Base
Summary of Errors $ Edits Made to the
Uparaded Utilitv Data Base
Uograded Utilitv Data Base
Unoraded ntilitv Data Rase (Validated)
Upgraded Industrial Boiler Data Rase
Summary of Errors Related to the "JEDS Tnnut
File
Upgraded Industrial Boiler Data Base (Validated)
Summary of Errors & Edits Made to the Ungraded
Industrial Boiler Data Base
General Cost Model - Summary of Equations -
Utilitv Financing Method
General Cost Model - Summary of Ecruations -
Discounted Cash Flow Method
Stack Has Scrubbing Cost Analvsis - ^uel
Allocated to Boilers
Stack ^as Scrubbing <"ost Analvsis -
Actual Plant nata
EPA Stack Gas Scrubbing Cost Analvsis System
31
32
33
34
35
36
37
38
49
50
89
90
- Summary of Costs Bv States - Wet Limestone
Process Apnlied to Utility "lants 91
6.4 FPA Stack Has Scrubbing Cost Analvsis System
- Summary of Costs By States - Wellman/Allied
Process Applied to utility ^lants 92
6.5 Summarv of Stack Pas Scrubbing Costs By States
- Wellman-Lord Process Applied to Sulfuric
Acid Plants
VI
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LIST OF TABLES (CONT'D.)
TABLE NO. DESCRIPTION PAGE NO.
6.6 Equipment Cost Equations For Wet Limestone
Process Applied to Small Industrial Boilers 94
6.7 Equipment Cost Eauations For Wellman/Mlied
Process Applied to Small Industrial Boilers 95
6.8 Wet Limestone Process and Cost Model For
Industrial Boilers - Summary of Equations 96
6.9 Wellman/Allied Process and Cost Model For
Industrial Boilers - Summary of Equations 98
6.10 Summary of Stack Gas Scrubbing Costs By
States - Wet Limestone Process Applied to
Industrial Boiler Plants 101
6.11 Summary of Stack Gas Scrubbing Costs By
States - Wellman/Allied Process Applied to
Industrial Boiler Plants 102
6.12 Cost Summary For Packaged and Field Erected Wet
Limestone Scrubbing Unit (50 MMBTU/HR Industrial
Boiler) 103
7.1 Mine-Mouth Cost of Coal, SNG, and SRC 159
VI1
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LIST OF FIGURES
FIGURE NO. TITLE PAGE NO,
3.1 Wet Limestone Process Flowsheet 13
3.2 Wellman/Allied Process Flowsheet 14
3.3 Lurgi SNG Process Flow Diagram 15
3.4 Solvent Refined Coal Process Flow Diagram 16
4.1 Tail Gas Flow Rates From Existing
Sulfuric Acid Plants 39
4.2 Sulfur Dioxide Emissions From Existing
Sulfuric Acid Plants 40
4.3 Acid Mist Emissions From Existing Sul-
furic Acid Plants 41
4.4 Glaus Plant Emissions 42
6.1 Average Total Capital Requirement For
Installing Stack Gas Scrubbing in
Existing Power Plants (MM$) 104
6.2 Average Total Capital Requirement For
Installing Stack Gas Scrubbing in
Existing Power Plants ($/KW) 105
6.3 Average Annual Production Cost of Stack
Gas Scrubbing in Existing Power Plants 106
6.4 Incremental Operating Cost of Stack Gas
Scrubbing in Existina Power Plants 107
6.5 Maximum Total Capital Requirement For
Installing Stack Gas Scrubbing in
Existing Power Plants ($/KW) 108
6.6 Maximum Incremental Operating Cost of
Stack Gas Scrubbing in Existing Power
Plants (nills/KWH) 109
6.7 Cumulative Total Capital Requirement For
Installing Stack Gas Scrubbing in Existing
Power Plants (Summation in Order of In-
creasing $/KW) 110
vi 11
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LIST OF FIGURES (CONT'D)
FIGURE NO. TITLE PAGE NO,
6.8 Cumulative Total Capital Requirement For
Installing Stack Gas Scrubbing in
Existing Power Plants (Summation in Order
of Decreasing Plant Size) 111
6.9 Cumulative Annual Production Cost of Stack
Gas Scrubbing in Existing Power Plants
(Summation in Order of Increasing mills/
KWH) 112
6.10 Cumulative Annual Production Cost of
Installing Stack Gas Scrubbing in
Existing Power Plants (Summation in Order
of Decreasing Plant Power Production) 113
6.11 Cumulative Total Capital Requirement For
Reducing Sulfur Emissions From Existing
Power Plants 114
6.12 Cumulative Annual Production Cost of Re-
ducing Sulfur Emissions From Existing
Power Plants. 115
6.13 Effect of Acid Concentration on Sulfuric
Acid Price 116
6.14 Effect of Plant Parameters on Total Capital
Requirement - Wellman-Lord Process Applied
To Sulfuric Acid Plants 117
6.15 Effect of Plant Parameters on Production
Cost-I - Wellman-Lord Process Applied to
Sulfuric Acid Plants 118
6.16 Effect of Plant Parameters on Production Cost-
II - Wellman-Lord Process Applied to Sul-
furic Acid Plants 119
6.17 Average Total Capital Requirement For In-
stalling Wellman-Lord Stack Gas Scrubbing
in Existing Sulfuric Acid Plants (MM$) 120
6.18 Average Total Capital Requirement for In-
stalling Wellman-Lord Stack Gas Scrubbing in
Existing Sulfuric Acid Plants ($/Ton of
Annual 100% Acid Capacity) 121
IX
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LIST OF FIGURES (CONT'D)
FIGURE NO. TITLE PAGE NO.
6.19 Incremental Operating Cost of Wellman-
Lord Stack Gas Scrubbing in Existing
Sulfuric Acid Plants " 122
6.20 Maximum Total Capital Requirement For
Installing Wellman-Lord Stack Gas Scrub-
bing in Existing Sulfuric Acid Plants
($/Ton of Annual 100% Acid Capacity) 123
6.21 Maximum Incremental Operating Cost of
Wellman-Lord Stack Gas Scrubbing in
Existing Sulfuric Acid Plants ($/Ton of
100% Acid) 124
6.22 Cumulative Total Capital Requirement For
Installing Wellman-Lord Stack Gas Scrub-
bing in Existing Sulfuric Acid Plants
(Summation in Order of Increasing $/Ton of
Acid 125
6.23 Cumulative Annual Production Cost of Well-
man-Lord Stack Gas Scrubbing in Existing
Sulfuric Acid Plants 126
6.24 Cumulative Total Capital Requirement For
Reducing Sulfur Emissions From Existing
Sulfuric Acid Plants - Wellman-Lord Process 127
6.25 Cumulative Annual Production Cost of Re-
ducing Sulfur Emissions From Existing
Sulfuric Acid Plants - Wellman-Lord Process I28
6.26 Average Total Capital Requirement For In-
stalling Stack Gas Scrubbing in Existing
Industrial Boiler Plants (MM$) 129
6.27 Average Total Capital Requirement For In-
stalling Stack Gas Scrubbing in Existing In-
dustrial Boiler Plants ($/MM Btu/Yr) 130
6.28 Average Annual Production Cost of Stack Gas
Scrubbing in Existing Industrial Boiler
Plants 131
6.29 Incremental Operating Cost of Stack Gas
Scrubbing in Existing Industrial Boiler Plants 132
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LIST OF FIGURES (CONT'D)
FIGURE NO. TITLE PAGE NO.
6.30 Maximum Total Capital Requirement For
Installing Stack Gas Scrubbing in
Existing Industrial Boiler Plants
($/MM/YR) 133
6.31 Maximum Incremental Operating Cost of
Stack Gas Scrubbing in Existing Indus-
trial Boiler Plants ($/MM Btu) 134
6.32 Cumulative Total Capital Requirement For
Installing Stack Gas Scrubbing in Existing
Industrial Boiler Plants (Summation in
Order of Increasing $/MM Btu/YR) 135
6.33 Cumulative Total Capital Requirement For
Installing Stack Gas Scrubbing in Existing
Industrial Boiler Plants (Summation in
Order of Decreasing Plant Size) 136
6.34 Cumulative Annual Production Cost of Stack
Gas Scrubbing in Existing Industrial Boiler
Plants (Summation in Order of Increasing
$/MM Btu) 137
6.35 Cumulative Annual Production Cost of Stack
Gas Scrubbing In Existing Industrial Boiler
Plants (Summation in Order of Decreasing
Plant Production) 138
6.36 Cumulative Total Capital Requirement For
Reducing Sulfur Emissions From Existing In-
dustrial Boiler Plants 139
6.37 Cumulative Annual Production Cost of Re-
ducing Sulfur Emissions From Existing Indus-
trial Boiler Plants 140
6.38 Packaged Limestone System For 50 MM Btu/fiR
Industrial Boiler - Overall Plot Plan 141
6.39 Packaged Limestone System For 50 MM Btu/HR
Industrial Boiler - Arrangement of Scrubbing
Section 142
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LIST OF FIGURES (CONT'D)
FIGURE NO. TITLE PAGE NO,
7.1 Mine-Mouth Cost of Coal ($/Ton) 160
7.2 Cost of Production of SNG ($/MM Btu) 161
7.3 Intermediate Btu Gas Process Flow Diagram 162
7.4 Effect of Carbon Content of Coal on Inter-
mediate Btu Gas Capital Cost 163
7.5 Effect of Carbon Content of Coal on Inter-
mediate Btu Gas Production Cost 164
7.6 Effect of Location Factor on Intermediate
Btu Gas Production Cost 165
7.7 Low Btu Gas Process Flow Diagram 166
7.8 Effect of Carbon Content of Coal on Low
Btu Gas Capital Cost 167
7.9 Effect of Carbon Content of Coal on Low
Btu Gas Production Cost 168
7.10 Effect of Location Factor on Low Btu Gas
Production Cost 169
7.11 Cost of Production of SRC ($/MM Btu) 170
xn
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1. INTRODUCTION
The work reported herein represents Part 2 "of a two part
study which investigated the technical and economic aspects
of a variety of technologies that could be used for the
control of sulfur oxides from existing stationary sources.
The study was done for the Office of Research & Development,
Environmental Protection Agency, under Task 23, Contract
No. 68-02-1308. Primarily, the work was intended to provide
EPA with sufficient cost information to be helpful in de-
termining effective, meaningful, and reasonable sulfur
oxide control regulations for stationary sources. As an
additional objective, it was also intended to provide guide-
line information to EPA for allocating its annual development
budget.
Part 1 consisted of an investigation of the major sulfur
oxide pollution sources, and a technical and economic
assessment of various desulfurization techniques applicable
to these sources. Specifically, the following source groups
were studied:
1) Utility plants
2) Industrial boilers
3) Sulfuric acid plants
4) Sulfur (Claus) plants
5) Nonferrous smelters
Available information on each source group was reviewed and
plants were characterized according to emission levels,
plant capacity, type of fuel or feed, age, load factor, and
geographical distribution. Statistical distributions were
generated illustrating the variation of different plant
parameters over the plant population for each source group.
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Distributions of actual sulfur oxide emissions were also
determined for each group. The sources, thus characterized,
formed the basis for the investigation of desulfurization
techniques.
Control technologies studied included the following:
1) Flue gas desulfurization
2) Fuel conversion processes
3) New power plant designs
The wet limestone process and the Wellman-Lord/Allied Chemical
combined process were selected as being representative of
throwaway and regenerable processes, respectively, for flue
gas desulfurization. Fuel conversion processes studied in-
cluded a process to convert coal to substitute natural gas
via Lurgi gasification, and a process for solvent refined
coal. In the area of new power plant designs, both a com-
bined cycle plant, using Lurgi low Btu gas, and a pressurized,
fluidized bed combustor were investigated.
Each process was reviewed for technical merit and feasibility,
and process models were developed. These models basically
set the processing sequence, process design, and process
variables. Cost models were then developed which relate the
important process variables to capital and operating costs.
After establishing the cost models, the cost of installing
flue gas desulfurization systems for existing utility plants
was investigated. Additionally, costs of substitute natural
gas and solvent refined coal were investigated and compared.
The results of the previous work are reported in "Evaluation
of R&D Investment Alternatives For S02 Air Pollution Control
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Processes - Part I" (EPA-650/2-74-098). The reader is re-
ferred to that report for detailed information.
Part 2 of this study is an extension of the work of Part 1.
It consists of three prime areas of investigation:
1) a re-investigation of plant and emissions data to obtain
new or enlarged data bases.
2) Determination of flue gas desulfurization costs, based
on the revised data bases.
3) Extension of the work on fuel conversion to include ad-
ditional processes, and further cost comparisons of the
different technologies.
New data on utility boilers, consisting of a tape containing
Federal Power Commission (FPC) Form 67 information, were
obtained from EPA. This information was edited and validated
to obtain a new data base for use in estimating flue gas de-
sulfurization costs. Additionally, a NEDS (National Emissions
Data System) tape, containing information on industrial
boilers, was also obtained from EPA. These data, after
editing and validating, formed the data base for the flue gas
desulfurization cost analysis of industrial boilers. The
sulfur (Glaus) plant data base was upgraded with NEDS infor-
mation to include, where available, the number of reaction
stages in each plant. The sulfuric acid data base was also ex-
panded to include gas flows and SO levels for each plant.
a
Using the revised data bases discussed above, flue gas de-
sulfurization costs were determined and summarized for exist-
ing utility plants, industrial boilers, and sulfuric acid
plants. Both scrubbing systems were included in the cost
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analysis for utility plants and industrial boilers. For the
latter, this required some revisions to the cost models, due
to the small size of many of the industrial boilers. Costs
were also developed for a "packaged" wet limestone scrubbing
system applied to a small industrial boiler to determine
whether maximized shop fabrication would significantly lower
costs for these small units.
Scrubbing costs were determined for acid plants, using a
modified form of the Wellman/Allied cost model adapted
specifically for application to acid plants. This cost
model was also reviewed to determine what changes were nec-
essary to adapt it to Claus plant applications.
The substitute natural gas (SNG) model developed in Part 1
of this study served as a basis for two new cost models:
intermediate Btu gas, and low Btu gas. Costs were determined
for SNG, low Btu gas, and solvent refined coal based on
actual coal prices in different parts of the country.
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2. SUMMARY AND CONCLUSIONS
2.1 SO Emission Sources
Ji
Input data obtained from EPA on utility boilers (Federal
Power Commission Form 67 for 1971) contains information
on 205 utilities, 689 plants, and 2798 boilers. After
checking the raw data, it was found that 418 plants, con-
taining 1555 boilers, required no editing. The final
data base, selected for cost analysis of flue gas desul-
furization, includes 417 plants. Although this is a smaller
data base than used in Part 1 of this study (881 plants),
it should be more reliable since it is based on actual
plant data.
The National Emission Data System tape for industrial
boilers contains information on 5685 plants having a
total of 12,047 boilers. About 72% of the plants and
84% of the boilers are exclusively fired by either coal,
oil, or gas. It was found that only 3991 plants and 4562
boilers had no major errors in the raw data. Only 3866
plants and 4106 boilers required no editing at all.
SO emmisions were estimated for all sulfuric acid plants
Xi
in the data file from Part 1 and incorporated into the
file. It was found that sulfuric acid mist constitutes
an important part of the total emissions from an acid
plant, being as high as 40% of the total emissions. This
is significant from the point of view of designing a tail
gas desulfurization unit, since acid mist particles tend
to be small, stable, persistent, and difficult to remove.
The data file for Claus plants was upgraded to include
the number of catalytic stages for each plant. Since
emissions can be estimated on the basis of feed composi-
tion (H-S concentration) and number of stages, future
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inclusion of feed composition in the data base is
highly desirable. At present, no such information is
available. For plants having 1-3 catalytic stages and
H2S feed concentrations of 15-90 mole %, emissions
have been estimated to be 0.79-0.39 tons S02/long ton
of sulfur.
2.2 Cost of Stack Gas Scrubbing
2.2.1 Utility Plants
Little difference was found for scrubbing costs between
the wet limestone process and the Wellman/Allied system.
For existing utility plants, capital costs averaged from
about $200/KW for plants of 40 MW size to approximately
$40/KW for 3000 MW plants. Operating costs for these
plant sizes ranged from 10 mills/KWH for the smaller
plant to 2 mills/KWH for the large plant.
Based on the total plant capacity included for cost analysis
approximately 80% of the capacity could be controlled
for less than $100/KW. About 90% of the power production
from these plants could be controlled at costs of under
6 mills/KWH. An 80% reduction in sulfur emissions could
be achieved at a total capital cost of approximately
2500 MM$and a total operating cost of 500 MM$/year.
Beyond 80%, costs increase sharply for further emission
reductions.
2.2.2 Industrial Boiler Plants
Of the total of 4385 industrial boiler plants considered
for cost analysis, only 829, or 19%, require control.
For existing plants, capital costs averaged about $0.8/
MM Btu/year (based on total annual capacity) for plants
in the size range of 10,000 MM Btu/hour to$2.4/MM Btu/year
6
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for plants of 100 MM Btu/hour capacity. Operating
costs averaged from $0.2/MM Btu for 3000 MM Btu/hour
plants to $1.8/MM Btu for plants having capacities
of 100 MM Btu/hour. For plants with capacities under
100 MM Btu/hour, both capital and operating costs in-
crease sharply with decreasing plant size.
Based on the number of plants requiring control, about
95% of the industrial boiler plant capacity could be
controlled for capital costs of less than $3.0/MM Btu/
year. 95% of the total plant production could be con-
trolled at operating costs under S1.5/MM Btu.
The cost of a packaged limestone scrubbing system for a
50 MM Btu/hour boiler was estimated to be about $8/MM Btu/
year. Operating costs are more than $3/MM Btu. These
costs are lower (by about 20%) than those estimated for
a normal field-erected installation for small boilers,
but the exact magnitude of the cost savings is uncertain,
due to the accuracy of the estimating techniques employed.
2.2.3 Sulfuric Acid Plants
For existing sulfuric acid plants, tail gas scrubbing
capital costs averaged from $58/ton of annual acid capacity
(100% acid) for plant capacities of 10 M tons/year to about
$10/ton of annual acid capacity for 1800 M ton/year plants.
The corresponding operating costs are §17/ton of acid for
the smaller plant and $4/ton of acid for the larger plant.
About 90% of the total sulfuric acid plant capacity could
be controlled for capital costs of less than $30/ton of
annual capacity, while the same percentage of total produc-
tion could be controlled for operating costs of under $9/ton
of acid. Control of more than 90% of the total plant
capacity or production causes a substantial increase in costs.
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2.2.4 Sulfur (Glaus) Plants
A review of the Wellman/Allied model showed that a number
of changes should be made in order to apply it to treat-
ment of tail gas from a Claus plant. A major change is
that the Allied section of the system is no longer needed
since the recovered SO- from the Wellman-Lord section
could be recycled directly as feed to the Claus unit.
Additionally, since the incinerated tail gas (After cooling)
is saturated with water vapor and contains no fly ash,
no prescrubbing section is needed. The higher SO^ con-
centrations in the tail gas, relative to typical concen-
trations in boiler flue gas, would also suggest a re-design
of the absorber to a more conventional, and perhaps less
expensive, configuration.
2.3 Cost of Fuel Conversion
2.3.1 Substitute Natural Gas
Based on reported coal prices, the cost of SNG has been
estimated to vary from a low of $1.14/MM Btu to a high
of $2.67/MM Btu. These costs correspond to mine-mouth
coal prices of $1.90/ton and $25.61/ton. SNG production
costs tend to be the highest in eastern states and the
lowest in Rocky Mountain states, primarily due to the
difference in coal prices.
2.3.2 Intermediate Btu Gas
The process and cost model for an imediate Btu gas plant
is based on the SNG model from Part 1 and corresponds to
9
a plant capacity of 125 x 10 Btu/day. The model predicts
total capital requirements for the plant to be about
150-170MM$. Intermediate Btu gas production costs vary
from $1.17-1.65/MM Btu, depending on coal costs ($8-12/ton),
coal analysis, and plant location.
8
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2.3.3 Low Btu Gas
The process and cost model for a low Btu gas plant is
also based on the SNG model from Part 1 and also is sized
for 125 MM Btu/day. Total capital requirements are
predicted to be 120-130MM$. Production costs are estimated
at $1.00-1.45/MM Btu, depending upon coal costs ($8-12/ton),
coal analysis, and plant location.
2.3.4 Solvent Refined Coal
Based on estimated mine-mouth coal prices of $1.90-15.05/
ton, production costs for solvent refined coal have been
estimated at $0.64-1.31/MM Btu. For equivalent fuel
(coal) prices, SRC costs are about 55-60% of the cost
of SNG. As with SNG, the most significant cost variable
is the cost of coal.
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3. DESULFURIZATION PROCESSES
A variety of desulfurization processes were investigated in
Part 1 of this study , and these form the basis of much of the
work reported here. In order to acquaint the reader who is
unfamiliar with Part 1, a brief review and description is
provided for each process.
3.] Flue Gas Desulfurization
Two flue gas desulfurization processes were investigated:
the wet limestone process and the WeiIman-Lord/Allied Chemical
process. These were chosen as being representative of the
throwaway and regenerable scrubbing processes, respectively,
and because they are the most commercially advanced of the
flue gas desulfurization technologies.
The wet limestone process, illustrated in Figure 3.1, is
based on the Catalytic, Inc. design ( 3 ) with some process
modifications made by Kellogg. Flue gas is contacted with
a recirculating limestone slurry in a dual scrubbing system,
consisting of a venturi followed by a turbulent contact
absorber (TCA), to cool and saturate the gas and to remove
sulfur oxides. The gas passes through a water-washed en-
trainment separator, is heated in a direct-fired reheater
to establish buoyancy, and finally compressed before dis-
charge to the stack. Make-up limestone is ground and
slurried before being added to the scrubbing system. Waste
solids from the scrubbing systems are sent to a settling
pond for disposal.
Figure 3.2 shows the process flow sheet for the Wellman/Allied
system. The design is based on the demonstration plant now
under construction at the D.H. Mitchell plant of the Northern
10
-------
Indiana Public Service Company, with some process mod-
ifications made by Kellogg. Flue gas is cooled and
saturated in a prescrubber after which it is contacted
with a sodium sulfite solution for SO- removal. The
clean gas is reheated and recompressed prior to dis-
charge to the atmosphere. SO- is regenerated from the
spent solution from the absorber by evaporation/crystal-
lization of the liquor. The SO- is purified by conden-
sation of water and steam stripping of the condensate after
which it is converted to elemental sulfur via reaction with
natural gas in the Allied Chemical section of the process.
A purge system is necessary to remove and process oxidation
products, while a make-up system replenishes sodium values
lost in the purge stream.
3.2 Substitute Natural Gas
The model developed for substitute natural gas (SNG) is based
on Lurgi pressure gasification of coal with steam and oxygen.
The actual designed was obtained from information in the
literature ( 5 ) and Kellogg sources ( 9 ).
The process flow sheet is shown in Figure 3.3. Coal from
storage is crushed and classified, with the sized material
being sent directly to the gasifiers. Fines produced from
grinding are sent either to a boiler (equipped with a stack
gas scrubbing unit), which provides process steam and power
requirements, or to a fines agglomeration unit, from which
the agglomerated coal is fed bo the gasifiers. In the gas-
ifiers, coal is reacted with steam and oxygen. The latter
is supplied by an on-site oxygen plant. Raw gas from gas-
ification undergoes shift reaction to adjust the H-/CO ratio,
followed by cooling prior to the purification step. Phenols
and tars condensed by gas cooling are recovered in a Pheno-
11
-------
solvan unit and recycled as fuel to the boiler. Purification
consists of removal of most of the C02 and virtually all of the
H0S. H0S from purification is sent to a Glaus plant for con-
£• t*
version to elemental sulfur. The purified gas is methanated
over a nickel catalyst, after which final C02 removal is
effected to upgrade the gas to pipeline quality. The product
gas is then compressed for delivery to the pipeline.
3.3 Solvent Refined Coal
The solvent refined coal process, illustrated in Figure 3.4,
is based on a Stearns-Roger report for the Pittsburg and
Midway Coal Mining Company, (17,18), with some process mod-
ifications made by Kellogg. After crushing and grinding,
the raw coal is sent to flash dryers where the moisture is re-
moved. The dried coal is dissolved in a solvent (anthracene)
in the presence of hydrogen, which is supplied by reforming
recycled light oil. Dissolution of the coal involves both
hydrogenation and depolymerization reactions. Ash is re-
moved from the dissolved coal by filtration after which it is
dried, to recover residual solvent, and sent to storage.
Solvent and light oils are recovered and purified through
flash separation and distillation. Solvent is recycled to
the dissolving section while the light oil, after sulfur re-
moval and recovery, is used both as feed to the hydrogen plant
and as fuel to a boiler which supplies process steam and
power requirements. The major by-product of the purification
step is cresylic acid. Finally, the liquefied coal is solid-
ified and transferred to storage. Alternately, the coal could
be kept in a liquefied state, but this requires keeping it hot.
12
-------
FIGURE 3.1
WET LIMESTONE PROCESS FLOWSHEET
NA TRAINS
NA TRAINS
FLUE GAS
TOTAL FLOW TO ALL TRAINS Gp ACFM
SULFUR FLOW Sf M LB/HR
3-STAGE
TCA
SECTION I
TRAINS
1.
T*
D
G
EMERGENCY
AMMONIA
INJECTION
SYSTEM
AGITATOF
»ND PUMP
SECTION II
SECTION III
-------
FIGURE 3.2
WELLMAN/ALLIED PROCESS FLOWSHEET
AREA
FLUE GAS
REHEAT
FLUE GAS
H2O-
FLUE GAS
COMPRESSION
FLUE GAS
TO STACK
AREA III
1
MAKE-UP
SYSTEM
PRESCRUBBING
AND
SO2 REMOVAL
SULFITE'SOL'N
EVAPORATION
AND
CRYSTALLIZATION
FLY ASH I
SLURRY '
AREA I -ABSORBER
AREA II SO2 REGENERATION
AREA III PURGE/MAKE UP
AREA IV - SO2 REDUCTION
| AREA III
VENT GAS
TO ABSORBER
SO2 PURIFICATION
(CONDENSATION/
STRIPPING)
CONDENSATE
| ARI
AREA IV
PURGE SYSTEM
(CRYSTALLIZATION
AND DRYING)
T
AREA II
1
S02
r
NATURAL
GAS
S02
REDUCTION
TAIL GAS I
TO ABSORBER I
PURGE
SOLIDS
SULFUR
-------
FIGURE 3.3
LURGI SNG PROCESS FLOW DIAGRAM
RAW
COAL
FEED
70%
COAL
PREPARATION
AND
GRINDING
30%
FINE
AGGLOMERATION
*
STEAM &
POWER
GENERATION
11
SULFUR
REMOVAL &
RECOVERY
10
CLEAN STACK GAS
SULFUR BY-PRODUCT
LURGI
GASIFIERS
AIR
SHIFT
CONVERSION
& COOLING
OXYGEN
PLANT
J I
PURIFICATION
COj + H2S
REMOVAL
METHANATION
SNG
COMPRESSION
SNG TO
. PIPELINE
TARS, PHENOLS ETC
PHENOL
SOLVAN
UNIT
FUEL TO STEAM
& POWER GENERATION
OTHER
OFFSITE
12
-------
FIGURE 3.4
SOLVENT REFINED COAL PROCESS FLOW DIAGRAM
USED WITH
PLANT
STEAM
& POWER
GENERATION
FUEL GAS & OIL
HYDROGEN
PLANT
RAW
COAL '
FEED
COAL
HANDLING
& GRINDING
LIGHT OIL
SLURRY
PREHEAT
DISSOLVER
RECYCLED
HYDROGEN
GAS
SULFUR
REMOVAL &
RECOVERY
ASH
FILTERING
DRYING
SULFUR
, BY-PRODUCT
SOLVENT
AND LIGHT
OIL RECOVERY
OTHER
OFFSITES
PRODUCT
SOLIDIFICATION
SRC
CRESYLIC ACID
BY-PRODUCT
-------
4. 50^ EMISSION SOURCES
4.1 Utility Plants
4.1.1 Upgraded Data Base for Utility Plants.
The cost statistics generated in Part 1 of this study
used as its data base:
1. Actual data on the majority of the plants and
2. Data obtained by replacing erroneous or missing
values with new values based on statistical distri-
butions derived from the total boiler population. For
example, incorrect boiler heat rates were replaced using
a correlation, based on data for all boilers, between
heat rate and boiler size. Appropriate substitutions
were also made for other boiler parameters where neces-
sary.
The major revisions that were made were with regard to
the allocation of plant fuel to the individual boilers
within each plant. The various assumptions with regard
to the actual data base used in Part 1 are discussed in
that report, in Part 2, costs for installing wet lime-
stone and Wellman-Lord/Allied Chemical scrubbing on ex-
isting utility boiler plants were rerun and summarized
using data available on FPC Form 67 for the year 1971.
The magnetic tape containing data from Form 67 was
supplied by EPA to Kellogg.
4.1.2 FPC Form 67 and the Creating of the Upgraded
Data Base
FPC Form 67 is a questionnaire filed by the steam
electric generating power plants with the Federal Power
Commission and a copy of this form is included in
17
-------
Appendix A. These forms are edited and processed for
each, year and the data are available on a magnetic tape.
The tape supplied to Kellogg contained nearly 340,000
unique records.
The data base for 1971 contains data on:
205 utilities
689 plants
2798 boilers
The utilities and plants in the FPC Form 67 have been
identified by a 6 and 4 digit numeric code respectively.
As far as is known, there is no equivalence between the
plant and utility codes as given in the FPC Form 67 and
the identification codes in the data base used in Part
1 of this study. Table 4.1 shows the summary or errors
related to the entire data base extracted from the FPC
67 data. Since a definite means to establish equivalence
between the two data bases was not available, it was
decided that the data base be solely extracted from the
data supplied by EPA (FPC Form 67 for the year 1971).
4.1.3 Steps in Creating the Data Base
The creation of the data base was accomplished through
the following steps:
1. Data Reduction - The data that were not needed by
the cost analysis programs were dropped.
2. Data Extraction - All available data required for
the cost analysis of stack gas scrubbing were extracted.
Table 4.1.3 illustrates the data extracted for each plant.
18
-------
3. Data Validation - In a number of plants data were
missing for one or more boilers. The data base was
validated by using suitable codes to indicate what
data were available or missing for each plant and its
individual boilers. These codes were used as the basis
to either process the plant for cost analysis or ex-
clude it. Table 4.4 shows the transformation to the
data of an individual plant and its boilers to include
the data validation codes.
4.1.4 Assumptions for Data Extraction & Data Validation
Certain basic assumptions had to be made in order to
create the required data base. These include:
1. The data supplied on the FPC tape were already
edited for proper sequence and were reported strictly
as required by the questionnaire.
2. All data had been checked for magnitude errors and
corrected where necessary.
3. All footnotes and comments about any data were
ignored.
In order to improve the data base created from the raw
input, data for individual plants and boilers were
checked and validated. It must be pointed out that no
statistical distributions were used to supply missing
data either for plants or boilers. However, the follow-
ing assumptions were made to validate the data base:
1. Whenever a boiler load factor was missing it was
replaced by 67%.
19
-------
2. Whenever the gas flow rate for a boiler within a
plant was missing it was replaced using the average flow
rate per unit capacity of the other boilers in the same
plant as a basis.
3. If heating values for the fuels were missing they
were replaced by standard values.
In a large number of plants (see Summary of Errors and
Edits,Table 4.2) there were errors in the data that
would result in an erroneous cost for flue gas desulfur-
ization. For example, in certain plants the fuel con-
sumption of a boiler was missing or the boiler size was
not given. The Summary of Errors and Edits (Table 4.2)
indicates exactly the quality of the data available from
the data file used for this part of the study. It must
be pointed out that a plant or a boiler could have more
than one type of error.
For generating the various costs and cost curves only
417 utility plants have been included. This amounts to
about 61% of the data available in the raw data base
received from EPA. Additionally, utilities which do
not use fuels from other states or do not transmit power
to other states are not within the jurisdiction of the
FPC and their data are not available on FPC Form 67.
By contrast, the number of plants considered in Part 1
of this study was 881.
4.1.5 Methods to Improve the Data Base
In order to upgrade and complete the data base created
by using the FPC Form 67 it is necessary that all miss-
ing data be gathered and added to the data base. There
20
-------
are a number of utility plants which do not report to
the FPC but must be accounted for in estimating the
costs of the flue gas desulfurization. Following are
some of the ways that could be used to get a more re-
liable data base:
a) Using the data extraction and validation system
developed by Kellogg as part of this study, generate
individual plant data reports (Table 4.4) and with
this as the basis gather or correct all missing or in-
valid data by contacting individual utility companies.
b) Use other data sources on utility plants. These
sources have been discussed in Part 1 of this study.
4.1.6 Effect of the Size of the Data Base On Cost
The objective of this study was to obtain certain cost
statistics for applying stack gas scrubbing for the
removal of SO- emissions from existing power plants in
the U.S. In order to generate average costs and obtain
a relationship between the plant size and investment,
for example, a good sample of the utility plants
throughout the country is required. The 417 plants
^
which have formed the basis of the cost statistics is
a reliable data base, containing actual data reported
by the different utilities. However, if total invest-
ment or operating cost (for the U.S. or a particular
state) are desired, then the figures reported here
obviously will be unrealistic , since a large number of
power plants have not been included in the study. Sec-
tion 6.1 of this report discusses how each of the costs
are affected by the amount of data considered.
21
-------
4.2 Industrial Boilers
Industrial boilers in the United States constitute a major
source of sulfur dioxide emissions and contributed approx-
imately 13% of the total U.S. sulfur emissions in 1971.
4.2.1 Original Data Base From NEDS
Industrial boiler data were provided by EPA from NEDS
(National Emissions Data System) on a magnetic tape.
The tape received includes data for each individual
plant and its boilers. The typical NEDS data input form
is shown in Appendix B. Data for each plant include
name, state, and county location with each individual
boiler in the plant described by its capacity, emissions,
flow rate and type of fuel burned.
The preliminary analysis of the data base received show-
ed that 5685 plants are included which total 12,047
boilers. This gives an average of 2 boilers per plant,
ranging from a minimum of 1 per plant to a maximum of
45.
4.2.2 Data Extraction Step
The data received were rearranged and stored on a tape.
Computer programs have been used to extract boiler data,
and a special subroutine was written to use the individ-
ual boiler data and arrive at the overall plant data.
Individual boiler sizes are summed to give the plant
size. Fuel consumption is calculated for each boiler
and the total amount of fuel burned in the plant is
determined. The sulfur emission from each boiler is
calculated and the value obtained is compared to the
22
-------
value reported on NEDS data file tape.
Each boiler in a plant could burn more than one fuel.
The types of fuel burned are determined by an 8-digit
SCC number (Source Classification Code). A subroutine
converts the SCC number to type of fuel used. The
following fuels could be burned: coalr oil, gas, coke,
wood, LPG, bagasse, and some nonclassified fuels. Boil-
er load factors are also calculated. In many cases
important boiler data were not available from the NEDS
data file and a subroutine was written to check and
print out which ones were missing. (The correction for
the missing data will be discussed in the next section.)
Each plant, as well as each boiler, is assigned an error
code which is used later in order to determine if a
plant should be bypassed or not in the cost model.
The summary of the data extraction step gives the
following fuel burning data breakdown:
1) For Plants
Number in Percent of total
each category population
Plants burning only coal, 4316 72
oil or gas
Plants burning only fuels 1026 17
other than coal, oil or
gas
Plants burning all types 669 11
of fuel
2) For Boilers
Boilers burning only coal, 9088 84
oil or gas
23
-------
Number in Percent of total
each category population
Boilers burning only 679 6
fuels other than coal,
oil or gas
Boilers burning all types 1085 10
of fuel
A sample of the extracted plant and boiler data is shown
in Table 4.5. The summary of errors related to plants
and boilers is shown in Table 4.6.
4.2.3 Data Validation Step
The following corrections have been made for missing
data values.
Corrections to Individual Plant Data
A plant is bypassed for the cost analysis program:
1) When its capacity is missing.
2) When the total fuel consumption is not available.
3) When there are zero boilers indicated for the plant.
4) When the plant has no boiler flow rates given.
5) When all boiler sizes are missing.
When the cost analysis program is applied, a choice can
be made to bypass or include plants which use fuels
other than coal, oil and gas.
Corrections to Individual Boiler Data
1} When the flow rate is missing for an individual
boiler in a plant, the boiler flow rate is obtained
by prorating from the available flow rates of the
other boilers in that particular plant.
24
-------
2) When the boiler load factor is zero, it is replaced
by a value of 0.5.
3) When the boiler load factor is greater than 1.1
(probably due to some erroneous data), it is re-
placed by a load factor of 0.5.
A sample of the validated plant and boiler data report
is shown in Table 4.7. The summary of the data validation
step which gives the plant and boiler errors breakdown
is shown in Table 4.8.
25
-------
4.3 Sulfuric Acid Plants
Atmospheric emissions from sulfuric acid plants vary, both
in quantity and composition, depending upon the process,
the mode of operation, and the condition of the plant.
The quantitative information on sulfur emissions from the
various types of plants has been obtained from the report
"Engineering Analysis of Emissions Control Technology for
Sulfuric Acid Manufacturing Processes" prepared by Chemico
(4 ), and has been classified as follows:
1) Chamber Acid Plants
Tail gas flow rate 130,000 SCF/ton of 100% acid
S02 0.02 tons S/ton of 100% acid
Acid Mist: 0.002 tons S/ton of 100% acid
2) Sulfur Burning Contact Plants (3 Conversion Stages)
Tail gas flow rate 92,000 SCF/ton of 100% acid
S02 0.02 tons S/ton of 100% acid
Acid mist:
- 99% acid product 0.002 tons S/ton of 100% acid
- Oleum product 0.005 tons S/ton of 100% acid
3) Sulfur Burning Contact Plants (4 Conversion Stages)
Tail gas flow rate 90,000 SCF/ton of 100% acid
S02 0.012 tons S/ton of 100% acid
Acid mist:
- 99% acid product 0.002 tons S/ton of 100% acid
- Oleum product 0.005 tons S/ton of 100% acid
4) Wet Gas Contact Plants (3 Conversion Stages)
26
-------
Tail gas flow rate
Sulfur Emission
tons S/ton of 100% acid
Raw Material SCF/ton 100% acid as SO
H2S 100,000
Pyrites 109,000
Acid sludge 109,000
Copper converter
gas 192,000
Roaster gas 145,000
5\ Wet Gas Contact Plants C4 Conversion Stages)
as SO,,
0.018
0.018
0.018
0.027
0.018
99%
0.002
0.002
0.003
0.004
0.003
as Mist
Acid Oleum
0.006
0.006
0.007
0.011
0.008
Sulfur Emission
tons S/ton of 100% acid
Raw Material SCF/ton 100% acid as SO
H2S 99,000
Pyrites 108,000
Acid sludge 117,500
Copper converter
gas 184,000
Roaster gas 143,000
These values were used to determine the sulfur emissions for
all (251) plants contained in the sulfuric acid plant data
file developed in Part 1 of this study. The emission sta-
tistics are summarized in Fig. 4.1, 4.2, and 4.3.
Sulfuric acid mist constitutes an important fraction (9% to
40%) of the total sulfur emission from acid plants. It con-
as S00
0.012
0.012
0.012
0.018
0.012
99%
0.002
0.002
0.003
0.004
0.003
as Mist
Acid Oleum
0.005
0.006
0.006
0.010
0.008
27
-------
sists of small drops (1 to 5 microns in diameter) of sul-
furic acid, usually over 90% concentration, formed in the
vapor phase from water vapor and SO.,. Once formed, it
is extremely stable and it is not readily separated or re-
moved from the gas. A most persistent form of this mist
is produced in most oleum plants. The important fact from
a pollution standpoint is that this mist consists of much
finer particles (0.2 to 3.0 microns) than those present in
the normal mist produced in plants where oleum is not a
product. For plants producing 98% acid, about 30% by
weight of the particles are smaller than 2 microns.
28
-------
4.4 Sulfur (Glaus) Plants
The unrecovered sulfur appears in the Glaus plant tail gas
principally as H-S, elemental sulfur, and SO. with lesser
amounts of other sulfur compounds. Incineration of the
tail gas is the method most often used to convert the unre-
covered sulfur almost entirely to sulfur oxides.
The acid gas feed composition, number of catalytic stages,
sulfur emission, and tail gas treatment, if any, are seldom
published for U.S. plants. Therefore, there are no corre-
lations available to determine the actual emissions from a
plant, given its characteristics. Limited quantitative in-
formation can be obtained from the report "Characterization
of Claus Plant Emissions" ( 19) which gives the amount of
S02 released (as incinerator stack gas sulfur dioxide
equivalents) as a function of the number of catalytic stages
and the acid gas feed concentration as follows:
Number of Mole percent H2S Stack gas SO2
Catalytic stages in acid gas feed s.tons SC^/l.ton of S product
1 90 0.39
2 15 0.25
2 50 0.17
2 90 0.14
3 90 0.07
These values are plotted in Fig. 4.4 .
The above mentioned report also gives a list of the plants
that are operating in the U.S. and provides estimates of
their emissions by assuming that:
a) The typical Claus plant has two catalytic stages.
29
-------
b) The Glaus sulfur production averages 60 percent of the
rated plant capacity.
c) The Glaus sulfur recovery averages 90 percent.
A data file on Glaus plants was obtained from this in-
formation during Part 1 of this study. This file
has now been upgraded to include the number of catalytic
stages for some plants by cross-referencing the infor-
mation with that contained in the NEDS file on Glaus plants.
30
-------
TABLE 4.1
OF ERRORS RBUgEP TO THE REDUCED DATA BASE
FRROR
TYPE/NUMBER
ERROR DESCRIPTION
NUMBER
OF ERRORS
ACTION
TAKEN
PLANT ERRORS
1
2
3
4
5
6
T
S
BOTLER ERRORS
ANNUAL TOTAL FUEL CONSUMPTION FOR A PLANT IS MISSING
SULFUR * FOR COAL NOT GIVEN
SULFUR I FOR OIL NOT GIVEN
AVERAGE HEATING VALUE OF FUEL NOT GIVEN
PLANT STATE IS NOT GIVEN
PLANT CAPACITY IS NOT GIVEN
4OCR NUMBER IS NOT GIVEN
PLANT HAS ZERO NUMBER OF BOILERS REPORTED
9
10
11
12
13
1*
15
16
PAGE ERRORS
17
IB
ANNUAL TOTAL FUEL CONSUMPTION FOP A BOILER MISSING
TOTAL HOURS OF OPERATION FOR BOILER MISSING
BOILER CAPACITY FACTOR IS HISSING
BOILER NUMBER IS NOT IN SEQUENCE - NO BOILER DATA ON NEXT BOILER
BOILER SIZE IS NOT GIVEN
THE SULFUR EMISSION COMPUTED BY PGM C SUPPLIED BY UTILITY NOT IN TOLERANCE *
FLUE GAS FLOW RATE IS MISSING FOR A GIVEN LOAD
NO ANNUAL Oft MONTHLY FUEL CONSUMPTION GIVEN FOR THE BOILER
COLUMNS OF PAGE NOT HATCHED
STATE CODE IS GREATER THAN 51 OR EQUAL TO 40
19
1
3
4
0
0
0
16
731
107
Jll
O
620
1493
2583
732
0
54
MV
MA
MA
NV
NA
NA
NA
BP
MV
ZE
ZE
NA
it
NA
ZE
BP
BP
NA
RECORD' ERRORS
23
24 "
FORM AT IDENTIFICATION IS IN CONFLICT WITH TYPE OF DATA ON RECORD
ILLEGAL CHARACTER IN DATA FILED
BR
BR
LEGEND OF ACTIONS TAKEN
**•*»«****«******•*****
NA NO ACTION TAKEN
ZE ZERO VALUE ASSUMED
MV MCNTHLY DATA USED TO OBTAIN ANNUAL VALUE
MA MONTHLY DATA USED TO OBTAIN AVERAGE VALUE
BP PAGE BYPASSED
BR RECORD BYPASSED
TOLERANCE-10.00 OF EACH OTHER
-------
TABLE 4.2
SUMMARY OP ERRORS I. EPIT MADE TO THE UPGRADED -UTILITY DATA BASE
T» V«LI?ITY
CCDE
EXPLANATION Of P4T4 VALIDITY CCDE
NUMBER IN
CODE
ACTION
TAKEN
ccrrs CCP PLANTS
NC FD1TING REQUIRED FOR PLANT CiTA
PLANT CAPACITY IS NOT GIVEN
«NNUAL TCTAL FUEL CCNSUMPTICN NOT GIVEK
PLANT HAS ZERO NUMBER OF PQILERS REPORTED
NC GAS FLOW RATE GIVEN FOR ANY BOILER
HEATING VALUES HISSING FCR FUEL
CAPACITY FOR ALL BOILERS IN A PLANT IS HISSING
PLANTS WITH MAJTR ERRORS IN BCILER DATA
PLANTS
NA
BP
BP
BP
BP
SB
BP
BP
FOR BCILERS
BOILERS
NO EDIMNG REQUIRED FOR BCIIER DATA
LLAD FACTOR MISSING REPLACED BY PLANT AVE CR 67 %
BCILER SIZE IS MISSING
GAS FLOW RATE IS MISSING REPLACED BY PRORATING
NC GAS FLOW IS AVAILABLE FOR ANY BOILER
FUEL CONSUMPTION FOR A BOILER is MISSING
34
253
200
0
748
NA
SB
BP
SB
BP
BP
LECENO OF ACTICNS TAKEN
Kt - NO ACTICN TAKEN
PP - BYPASS FOR COST ANALYSIS
SB - SUBSTITLTF STANCARD VALUES
NCIE
41**
TtE DATA VALIDITY CODE EXPLANATIONS GIVEN IN THIS SUMMARY ARE THE SAME AS THOSE
APPEAPINC CM INDIVIDUAL PLANT t CCST ANALYSIS REPORTS
-------
I'ABLR 4. T
UPGRADED UTILITY DATA BASE
STATE :
*****
UTIL ITY NAME:
»*•*•*•*****
FPC UTILITY CODE;
****************
COUNTY :
******
PLANT NAME ADDRESS:
***•»•**••*•***•••
STATE CODE : 1
COUNTY CODE : 97
AOCR CODE : 5
LOCATION FACTOR : 0.0
***************
FPC PLANT CODE:
**************
PLANT DATA SUMMARY
******************
ANNUAL FUEL CCNSUMPTION PLANT SIZE!MM)=1770.80 HEATING VALUE OF:
COALIMTONS/YRI •= 2321.50 > SULFUR IN COAL= 2.61 COAL IBTUSLB) = 12008.00
OIL (MBBL/VRI = 159.90 I SULFUR IN OIL = 0.50 OIL IBTU/LBI -136000.00
CAS (MCF/VRI = 0.0 GAS (BTU/CFI - 0.0
NUMBEP OF BOILERS:
*****••••••••***•
BOILER DATA SUMMARY
** 4** **************
BOILER BOILER FUEL CONSUMED
NUMBER SIZE COAL GIL GAS
I MM I MT/YR HBBL/VR MHCF
AMT OF S HRS.
EMITTED OF CAPACITY
CALC. REPORT OPN. FACTOR
IMT/VR) I
FLUE GAS FLOW RATE
LOAD
100* 75* SOS
ACFH
DESULFUR14ATION
EQUIPMENT OPG.
DATA
EFF HRS OF
% SERVICE
153.1 325.
153.1 299.
272.0 522.
403.8 680.
788.8 312.
4. O. 8.503 8.306
10. 0. 7.B95 7.662
15. 0. 13.745 13.360
26. 0. 17.970 17.423
35. 0. 8.430 8.007
7403
7753
7432
6882
1402
63.00
56.00
57.00
52.00
13.00
0.
716000.
639000.
826090.
1800000.
0.
440000.
462000.
579008.
1400000.
0.
294000.
325000.
394eae.
1000000.
0.0
0.0
0.0
0.0
0.0
a
o
o
0
o
-------
TABL3 4.4
UPGRADED UTILITY DATA. BASE (VALIDATED)
3T«TE CODE I 1
QIUNTV CODE I «7
40CR CODE I S
JMLT" GitR CO. PLAVT •J.ME *30^£SS|CHJCK
f»« iilTiirv ;03FlnOu508 EPA JUL"* COOEt FPC
*
'^SMT Tftl A JALT^r TV £}}F - 0
CJJ-Lf MD-wS/Y*) « 121.60 X SJL*U3 IM CT4L= 2.13 C3*L C3TU/LWJ
TIL (^^^L^1"* = 1."* * SJLpU' 1^ 311 B <»i50 DIL (BTJ/LB)
3*5 (Mcr/y?) . SSDO.DA G4S (9TJ/CF)
9-TLE* •flLE* FUEL CT^SJ'tEO ETTFEO 3F CAPACITY
s J»:»B« *I;E cruL DIU s»s CALC. BEB^RT O»N. FACTOR
1 16.0 "2. 1. 1720. 0«99i O.B69 73Q4 95.00
2 «•..! «0. I. 1690. O.»ll* 0.9P7 7?82 S«.00
J u*,,l L*«T CODElOaOO EPA PLAM
LOCATION FACTOR i 1.20
r CODEl
MJXRER OF BOILERS! 1
•t
B 120U7.00
BI ifrooa.oo
• 1051.00
FLUE 6*3 FLO" RATE
LJAD
100X 75X SOX
ACFM
170000. 162000. 158000.
170000. 1(12000. 15*000.
182000. 180000. 17AOOO.
OESULFURIZATION
FQUIDMEMT OP6.
DATA
EFF HR9 OF
X SERVICE
0.0 0
0.0 0
0.0 0
DATA
VALIDJT
CODE •
0
0
0
F3»
^F THIS C3DE "EFiS TO Sl'-HARr 3F
-------
.r; t . 5
UPGRADED INDUSTRIAL
n PVTA BR5T:
*** INDUSTRIAL BOILERS DATA EXTRACTION SUPSYSTE" «=ROM
ENVIRONMENTAL PROTECT1CN AGtNCY
*4*******4******»**»**44***44****
NEDS INPUT DATA bASE ***
STATE CCDE:
PLANT NO:
PLANT CATA
FU=L CATA:
1
1 PLANT nAMt:
SUGARY PL&XT
?U£L TYPE A,l
* COAL
OIL
GAS
CCKE
HOUD 1
LPG
BAGASSF
UNCLASS
COUNTY CHDE: 540
AOCR CODE: 2
SIZE: 2C3 HCBTU/HB NO.BCILERS:
GU,,T 0JK,,T
0 MMBTU/YR
116760 MlhTL/YR
0 KMBTLVYG
0 MMBTL/YR
74O970 MNBTU/YH
0 MMBTU/YR
0 PMBTU/YP
0 HMBTD/YR
HEATING VALUE
0 MHBTU/T
140 CMBTU/MG
0 CHBTU/MHCF
0 KKB^U/T
10 Cr«BTU/T
0 MMBTU/NG
0 CCBTU/T
0 HHBTU/T
PLANT IP:
3 TOTAL
UTM ZONE: Ib
PLANT ERROR
YEAR: 72
CODE: 6
FUEL BURNT: 1857730 MMBTU/YR
PERCENT SULFUR
0.0
0.20
O.O
4444*44*44 4* 444*««*
BOILER
NUMUFR
1
2
3
PCINT SIC IPP FLOW R. TEMP.
10
1 2421
2 2421
3 24^1
ACF1 F
0 4 19 5J 55O
0 tl953 550
0 00
BOILEP
SIZE
t>MBTU/HR
63
63
77
BOILER
LOAD
1.06
1.06
1.02
SC2 EMISSIONS (T/YR1
CALCULATED REP3*TEO
7 1OO
7 100
0 103
BCILER
ERROP
CODE
6
6
3
-------
TABLE 4.6
CP.'. 'f:ixsTF :ti eniLEhS STACK GAS scfcuoflirtG DATA EXTRACTION SUBSYSTEM
OF cR'iOtS FcLCTED TC THE NEDS INPUT DATA FILF
»»»««*•»»*»*****«*****»*»**»****»*»****»***»**»****»****
EI-ROR DESCRIPTION NUMBER OF
IVPf /NUMBER ERRORS
FLAM EPFCFS
i PLANT HAS NC KAJC» ERRCAS 3991
2 X SULFUR FOP COAL MISSING 14
3 X SULFUk FOR OIL MISSING 49
<. X SULFUR FOR CCKF HISSING 0
5 AVERAGE HEATING VALUE OF FLEL IS NOT GIVEN 0
6 PL AM tSES OTHEF FUEL THAN COAL CIL OP GAS 615
7 PL AM CAPACITY ADDS UP TO ZERO 711
E PLANT HAi ZFRC NUMBER OF BCILEK REPORTED o
9 ANNUAL TUTAL FUEL CONSUMPTION FOR A PLANT IS NCT GIVEN 305
RCILEP EfrPCRS
I dCILEft HAS NO MAJOP ERRORS REPORTED 4562
2 BCILER FUEL OPERATING KATE IS NOT GIVEN 1O4
3 BOILER FLCw RATE IS NOT GIVEN 4134
4 BCILER LSES NCN STANDARD FUEL 336
5 BOILER SIZE IS NOT GIVEN 1574
t SULFUR EMISSIONS CALCULATED AND REPORTED ARE NOTIN TOLERANCE 1337
7 THEPE ARE MORE THAN ONE T«0-C«ROS PER BCILER 0
-------
4.7
P| 1FJ|
UPGRADED lUPUSTfilAL BOILER DATA BASE (VALIDATED)
•.* TMOI'STRIAL HrillERS DATA EXTRACTION SUBSYSTEM FHU1 NEDS INPUT DATA BASE •••
f NVIBQMHF-MTAL PROTECTION AGFNCV
*•••*•••»*»*»•*•••••*«••«•••••*••
i COUNTY ronft 500 AQCP CODEI 2 UTH ZONEI 16 VEAR.I 72
PLANT M£-fi PLANT tor PLANT ERRU* COOEI 6
PLANT VALIDATION CODCl 6
T PLA* t Oil a SUMPiPv PLAMT Sf ZFl
I (UK ntrti FUEL TITPF iMniiMT RUBNT
1 COAL
i OTL
GAS
C.IKE
WO01
LPG
RAT.AS3F
BOfLFH DitA SUMMARY
t wntLFR pRINT STC tPP FI.O" R.
I MJMBfU in »CFM
I
t t t ?Uf\ n 22950
r ? 2 ?«?! n 27050
r 3 1 2«?t n 2*i«Sn
201 MMBTU/HR NO.BOILF.RSi S
HEATING VALUE
0 MHPTU/T
100 HMBTU/xs
Q MMBTU/MNCF
0 HMRTU/T
10 MHBTU/T
0 HI4BTU/HG
P HMHTU/T
TE^P. BOILER BOILER
F SIZE LOAD
MMRTU/HR
550 61 1.06
559 (,) 1.06
0 TT 1.02
TOTAL FUEL RURNTl
PERCENT SULFUR
o.o
0.20
0.0
SO; EH1S3IONS(T/VR)
CALCULATED REPORTED
T 100
T 100
0 103
1SSTTJO MHBTU/YR
BOILER. BOILER
ERR01 VALID.
CODE CODE
fc 6
6 6
I a
Tf THf. SUMARY » T TMI- EM> FOR
CODE
-------
TABLE 4.8
EPA STACK CAS SCRUBBING DATA VALIDATION SUR8Y3TE1 FOR INDUSTRIAL BOILERS ***
SllHMtPV nr ERRORS H EDITS "tnf Tn UPGRADED DATA BASE
ft***************************************************
EXPLANATION OF OATA VAI IOITY CODF NUMBER OF ACTION in
WALIDM» cnf>E BE TAKEN
PLANTS
******
i NO FOTMMB is REQUIRED 3866 NA
5 "EATING VALUE T8 MISSING 0 SB
ft PLANT USES OTHER FIJFLS TMAN (HAL OIL OR GAS fclS NA
7 PLAMT CAPACITY Anns UP Tn ZERO Tit BP
P PLANT HAS ZERO NU«RFR rip HPUE"8 REPORTED 0 BP
o ANNUAL FUEL CONSUMPTION FOR A PLANT IS NOT GIVEN JOS BP
to PLANT TO BYPASS WITH MAJOR ERRORS 11*1 BP
BOILERS
*******
i *o FDITINC is REOUTRED MO* NA
2 nniLER LOAD IS ZERO AND REPLACED BY 0.5 Z5IO SB
3 BOILER LOAD IS GREATER THAN t.l AND REPLACED BY 0.5 95U SB
U r,AS FLOW RATE IS HISSING Sll) SB
5 ontLE" SIZE IS NOT GIVFN 0 gp
h SO? EMISSIONS CALCULATED AND REPORTED ARE NOT IN TOLERANCt 1337 NA
N«INO ACTION TAKEN
PP|RT PASS
SBlSUHSTTTUTE
-------
80
70
FIGURE 4.1
TAIL GAS FLOW RATES FROM
EXISTING SULFURIC ACID PLANTS
w
EH
Q
H
u
H
D
S
D
w
OS
U
ffl
60
50
40
30
20
10
LttU
n-p m
50 100 150 200 250
TAIL GAS FLOW RATE, M SCFM
300
39
-------
90
FIGURE 4.2
SULFUR DIOXIDE EMISSIONS FROM
EXISTING SULFURIC ACID PLANTS
80 .
(Note: In addition to those
shown, there is 1 plant in
the range of 4000-5000 Ibs
of sulfur per hour)
70
60 .
50 -
40 .
30 .
20 •
10
J-l
400
800
1200
1600
2000
2400
2800
S02 EMISSION (AS SULFUR), BOUNDS PER HOUR
40
-------
(0
H
PL,
Q
H
U
s
D
b
m
155
70 A
60 .
50
40
30
20 -
10 -
FIGURE 4.3
ACID MIST EMISSIONS FROM
EXISTING SULFURIC ACID PLANTS
0 200 400 600 800 1000 1200
ACID MIST EMISSION (AS SULFUR), POUNDS PER HOUR
41
-------
fIGURE 4.4
CLAUS PLANT EMISSIONS
0.6TT
0.5(
3
H
CO *•»
CO tl
O
U
u
8
en
, . 6,0. 3tf
EH H O
CO D
o a
05 W O
O EH
H H
a! H Jo.2
W X X.
a o 01
H H O
U Q co
a
H K CO
D Zft 1
CO
.1 STAGE
2 stages
O 3 stages
15
50
90
MOLE PERCENT H2S IN ACID GAS FEED
42
-------
5. THE GENERAL COST MODEL
5.1 Introduction
In Fart 1 of this study, a general cost model was developed
to provide a standard format for estimating process eco-
nomics. The purpose was to allow economic comparisons
between processes to be made on a consistent basis by
ensuring that all estimates include the same cost items.
The general cost model developed in Part 1 of this study
uses a utility-type financing method and is based on a
procedure recommended in the literature (20). Fundamen-
tally, the model assumes no time value for money. That
is, for estimating the economics of desulfurization pro-
cesses, such items as interest on debt and return on
investment can be related to capital costs by simple
percentages which remain constant from year to year.
This method allows a simple, straight-forward calculation
of process operating costs.
For Part 2 of this study, the model was reviewed to
determine what changes should be made when applying it
to the industrial sector. The revised model differs from
the utility financing method primarily in that it uses
the discounted cash flow method, which takes into recount
the time value of money. It is essentially based on a
procedure recommended in the literature (20), with some
minor modifications. The revised model has been used
for estimating the economics of flue gas desulfurization
processes applied to sulfuric acid plants, sulfur (claus)
plants, and industrial boilers.
5.2 Review of the Utility Financing Method
The general cost model from Part 1 of this study has been
43
-------
excerpted in its entirety and is included in Appendix C
for reference. A brief review will be given here to in-
troduce the reader to the model.
The general cost model consists of two parts: A capital
cost model and an operating cost model. The capital
cost model is a factored estimate. Where complete cost
data are lacking for a particular process, the model allows
factoring from equipment costs (E) to total capital required
(TCR). Of course, where more complete process cost esti-
mates are available, the model is used merely as a check-
list to ensure inclusion of all appropriate cost items.
Thus, the model can be "entered" at any level, depending
upon the stage of development of process economics. The
operating cost model needs, as minimal input, an estimate
of process capital costs, operating labor requirements,
and consumption of raw materials, utilities, chemicals,
catalysts, etc. The total annual production cost (TAG)
can then be calculated on the basis of these variables.
If equipment costs (E) for a process are known, or can
be estimated, the total capital required (TCR) for construc-
tion of the plant can be calculated from the model.
Construction labor costs (L) and other material costs
(M), such as piping, electical, instrumentation, etc.,
are estimated as percentages of equipment costs. The
model permits variations in construction labor costs
with geographical area to be estimated via a location
factor (F). Engineering costs are factored from total
direct material costs (E+M). The bare cost (BARC) of
the plant, defined as the sum of equipment costs, other
material costs, construction costs, and engineering, can
thus be estimated from equipment costs only. Of course,
if the process economics have been developed further than
equipment costs, the "factors" derived from the process
cost estimate can be substituted for the "typical" factors
used in the model.
44
-------
To the base cost is added taxes and insurance, contractor's
overheads and profit, and contingency (CONTIN). Each
of these is estimated as a percentage of the base cost,
and the sum of all items represents the total plant
investment (TPI). In order to obtain the total capital
required (TCR), start-up costs (STC), working capital
(WKC), and interest during construction (IDC) are added
to the total plant investment. The first two items
are estimated as a function of process operating costs,
and can simply be related to the total number of opera-
tors (TO), the hourly rate for operators (CO), the
annual cost of raw materials and utilities less by-
product credits (ANR), and the annual credit for by-
products (ACRED). Interest during construction is
a function of total plant investment, and is also related
to the total engineering and construction time.
The operating cost model is similarly constructed.
The total net operating cost (AOC) is defined as the sum
of annual costs of raw materials and utilities less by-
product credits (ANR), operating labor and supervision
(AOL), maintenance labor and supervision (AML), plant
supplies and replacements (APS), administration and over-
heads (AOH), and local taxes and insurance (ATI). Raw
material and utilities costs, credits, and operating
labor requirements are, of course, different for each
process and must be known before operating costs can be
estimated. The remaining terms can all be expressed
as a function of total plant investment or total operating
labor costs.
In order to obtain the total annual production cost (TAC),
capital charges must be added to the total net operating
cost. Depreciation (ACR) is determined using the straight
45
-------
line method over the plant life, based on the total capital
required less the working capital. Interest or debt and
return on equity (AIC) are calculated by assuming a
debt-to-equity ratio, an interest rate (Debt), and a
net rate of return (Equity) . Federal income taxes (AFT)'
are determined using an assumed tax rate of 48%. The
resultant equation for total annual production cost
can be simplified and expressed as a function of only a
few variables: total plant investment, operating labor
requirements, and raw material and utility costs.
The important equations for the utility financing method
of the general cost model are summarized in Table 5.1.
For a complete definition of the terms shown in the
table, the reader is referred to Appendix J.
5.3 Discounted Cash Flow Method
The discounted cash flow method of the general cost model
was developed for industrial applications of control
processes, and in this report is used only for stack
gas scrubbing economics. It also consists of two parts:
a capital, cost model and an operating cost model. The
essential difference between the discounted cash flow
method and the utility financing method is the way in
which capital charges are determined.
Through total plant investment (TPI), the capital cost
model is constructed as described in the previous section.
In order to obtain the total capital required (TCR),
working capital (WKC) and return on investment during
construction are added to the total plant investment.
Working capital is related to operating costs, as before.
The term, return on investment during construction,
replaces interest during construction used in the utility
46
-------
financing method. This arises from the assumption of
a 1UO% equity position for project financing in the dis-
counted cash flow method. It should be noted that start-
up costs are not treated as capitalized costs, and there-
fore are not included in the total capital required. Start-
up costs are assumed to be an initial operating expense.
The total net operating cost (AOC) is calculated in an
identical manner to that described in the preceding
section. To this must be added the capital charges to
yield the total annual production cost (TAG). The fol-
lowing procedures have been used to apply the discounted
cash flow method to the general cost model:
1. Net operating costs are determined for each year.
Start-up costs are included as an initial operating
expense.
2. An accelerated depreciation schedule (Sum-of-the-
years digits) is used. Depreciation is taken over
the plant life, based on the total plant investment.
3. A federal tax rate of 48% has been assumed.
4. Cash flows are determined for each year of the
project life. These values are then discounted,
using the desired net rate of return on investment.
This yields the discounted cash flows for each year
of the project life.
5. A constant yearly production cost is calculated which
gives the desired discounted cash flow rate of return
on investment over the project life. This cost, then,
includes both capital recovery and return on invest-
ment.
The important cost equations for the discounted cash flow
method are summarized in Table 5.2. The general equation
47
-------
tor total annual production cost (TAG) shows it to be
a function of the total capital required (TCR), start-
up costs (STC), working capital (WKC), total plant
invesment (TPI), net annual operating costs (AOC),
plant life (1), and the rate of return on investment
(r). For stack gas scrubbing units, the equation can
be greatly simplified, as shown in the table. A complete
derivation of the equations for total annual production
cost is given in Appendix D.
48
-------
TABLE 5.1
GENERAL COST MODEL
SUMMARY OF EQUATIONS
UTILITY FINANCING METHOD
CAPITAL COST MODEL
BARC = 1.15 (E + M) + 1.43 L'F
TPI =1.12 (1.0-1- CONTIN) BARC
TCR = TPI + STC + WKC + IDC
For stack gas scrubbing units,
TCR =1.15 TPI +1.8 TO-CO (1.0 + F) + 0.4 (ANR + ACRED)
For other units,*
TCR =1.21 TPI + 0.8 TO'CO (1.0 + F) + 0.4 (ANR + ACRED)
OPERATING COST MODEL
AOC * ANR + AOL + AML + APS -I- AOH + ATI
= 0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR
TAG = AOC + ACR + AIC + AFT
For stack gas scrubbing units,
TAG = 0.237 TPI + 2.1 TO'CO (1.0 + F) + 1.04 ANR + 0.042
ACRED
For other units,*
TAG = 0.225 TPI + 2.1 TO'CO (1.0 + F) + 1.04 ANR + 0.039
ACRED
*SNG, SRC, low Btu gas, intermediate Btu gas
49
-------
TABLE 5.2
GENERAL COST MODEL
SUMMARY OF EQUATIONS
DISCOUNTED CASH FLOW METHOD
CAPITAL COST MODEL
BARC =1.15 (E + M) + 1.43 L-F
TPI =1.12 (1.0 + CONTIN) BARC
TCR = TPI + WKC + IDC
For stack gas scrubbing units,
TCR + 1.15 TPI + 0.4 TO-CO (1.0 + F) + 0.20 (ANR + ACRED)
OPERATING COST MODEL
AOC = ANR + AOL + AML + APS + AOH + ATI
= 0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR
r (1+r) ,[TCR + STC _ WKC _ 0>4g Tpl „ 2
OTBT l (1+r) I -1J L1V-K °^ (l+r) A - "-1*0 iri ^Jm+TT
£ + 1 -n , ,
For stack gas scrubbing units,
_ TCR + STC -0.239 WKC - 0.291 TPI
- 3.955
= 0.298 TPI + 2.18 TO-CO (1.0 + F) + 1.09 ANR + 0.09
ACRED
50
-------
6. COST OF STACK GAS SCRUBBING
6.1 Utility Plants
6.1.1 Comparision of Cost Analysis as Applied to
Different Data Bases
Part 1 of this study investigated the cost of retro-
fitting stack gas scrubbing units to existing utilities.
However, as pointed out in section 4.1.1 of this report
the same costs had to be re-estimated and summarized
using an upgraded data base. This new data base is
smaller but more reliable than the original one. The
costs obtained using this data base are much more re-
liable and realistic. The control strategy applied in
both cases is the same, viz., the control is applied to
the individual boilers in decreasing order of their
sulfur emissions. This means that if a plant is emit-
ting sulfur above the allowable emission level (assumed
to be 1.2 Ibs of S02/MMBtu), then control is applied to
the largest sulfur-emitting boiler. If this does not
reduce emissions below the allowable level, then the
boiler emitting the second largest amount of sulfur is
controlled. This scheme is continued until plant emis-
sions are below the allowable level.
In Part 1 of this study, after the data base was edited
for missing values and magnitude errors the fuel demand
for the boilers was calculated, using the boiler load
factor and boiler heat rate. Since only the overall
plant fuel consumption was known (by types and amounts),
the fuel within a plant had to be allocated to the vari-
ous boilers. Allocation was done in the order of coal,
oil and gas, starting with the largest boiler and work-
51
-------
ing toward the smallest boiler. In most cases the
largest boiler became the largest emitter of sulfur. In
reality this may not be true. Tables 6.1 and 6.2 give
the capital costs and operating costs for an identical
plant in the following two cases:
Table 6.1 - Using fuel allocation as described above.
Table 6.2 - Using actual plant data.
Since the stack gas scrubbing costs for each individual
plant are different, it can be expected that the costs
on a national and state basis will be different using
different data bases. For a comparison of any specific
cost, the figures should be compared with costs in Part
1 of this study.
6.1.2 Scrubbing Cost Analysis Using Upgraded Data Base
The figures and tables in this section present the re-
sults obtained by applying the cost models for the two
different scrubbing processes, viz., the wet limestone
process and the Wellman/Allied system. The cost models,
unit costs for raw materials, location factors, etc.
used in this study are identical to those used in Part 1
of this study (The cost models are summarized in Ap-
pendix E). The allowable plant emission level has been
assumed to be 1.2 Ibs. S02/MMBtu, consistent with Part 1.
Only plants requiring control are included in the cost
analysis.
Table 6.3 and Table 6.4 give a breakdown of costs for
each state for the two processes. It must be noted that
the costs are based on a limited number of plants only.
Hence, the entries under columns titled total capacity,
total production, total capital required and total oper-
52
-------
ating costs are likely to be under-estimated. These
figures are only from the plants requiring controls on
at least 1 boiler of the plant. Of the 417 plants con-
sidered for cost analysis 256 of them required control
on at least 1 boiler. This represents 55% of the plants
considered. The variation in operating costs between
two identical plants in different states results from
different location factors.
Figure 6.1 represents the average total capital required
for installing wet limestone and Wellman/Allied stack
gas scrubbing units in existing utilities of different
sizes. The graph shows that the variation between the
costs of the two scrubbing processes is small.
Figure 6.2 represents the relationship between the plant
size and the total capital requirement, in $/KW, for the
two processes. It can be seen that with an increase in
the size of the plant the capital requirement drops.
Costs vary from about $40/KW to almost $200/KW for plants
in the range of 3000 to 40 MW.
Figure 6.3 illustrates the average annual cost of pro-
duction (MM$/year) for installing stack gas scrubbing in
existing power plants. There is no significant differ-
ence in costs between the two processes.
Figure 6.4 shows the relationship of the plant size to
the incremental operating cost (mills/KWh). This cost
ranges from 4 mills/KWh to 2 mills/KWh for plants be-
tween 400 MW to 2000. This graph suggests that for
small plants, it would probably be more economical to
switch from stack gas scrubbing to burning clean fuel
for controlling S02 emissions.
53
-------
Figure 6.5 illustrates how the maximum total capital
requirement, in $/KW , for installing stack gas scrub-
bing varies with the percent of U.S. utility plant
capacity under control. 80% of the total plant capacity
could be controlled at costs of $100/KW or less. Apply-
ing controls to the remaining 20% of plant capacity,
which includes essentially the smaller plants, would
result in excessively high costs, as much as $700/KW.
If only the first 20% of the plant capacity was control-
led the capital requirement for stack gas scrubbing is
of the magnitude of $40/KW or less.
Figure 6.6 presents the maximum total cost of production,
in mills/KWH, for installing stack gas scrubbing as a
function of the percent of total plant production con-
trolled. This graph can be interpreted in a similar
manner to figure 6.5. It would become increasingly un-
economical to apply stack gas scrubbing as a means of
controlling SO- emissions to approximately the last 10%
total plant production.
Figure 6.7 shows the cumulative total capital require-
ment, in MM$, versus the % of plant capacity under con-
trol. While interpreting this graph, one must be aware
that the absolute cost (total capital required) for con-
trolling 10% of the total US power plant capacity is not
$700 MM but much higher. This is, as was explained
earlier in 4.1, due to only a limited number of plants
being included in the data base. However, since the
sample does include a large number of plants from all
over the US, scaling of absolute cost figures may be
reasonable. Figure 6.8 illustrates the relationship
between the same quantities except that the basis of
cumulating the costs is different for the two graphs.
The two graphs show that if stack gas scrubbing was used
54
-------
to control the entire power capacity, the total capital
cost would be the same. However, when only a certain
percentage, say 50%, of the entire plant capacity is to
be controlled, it would be more economical to install
stack gas scrubbing on the basis of increasing TCR ($/KW)
rather than on the basis of the decreasing plant size.
Figures 6.9 and 6.10 illustrate the relationship between
the cumulative total cost of production, in MM$/Yr, and
the % of the total plant production controlled. The
operating cost is lower for controlling a certain % of
the plant production if controls are applied on the basis
of increasing operating costs (mills/KWH). For example,
to control 60% of the total plant production, the cum-
ulative operating cost is $920 MM/year when controls are
applied on the basis of the summation in order of in-
creasing TAG, while the cost for controlling on the
basis of decreasing plant production is $1200 MM/year.
The total cost figures are based only on the limited
number of plants considered.
55
-------
6.2 Sulfuric Acid Plants
6.2.1 Process Appraisal
Of the two flue gas desulfurizatlon processes investi-
gated in this study, only the regenerable process (Well-
man/Allied) has been included for application to sulfuric
acid plants. The basis for the process and cost models
is the design for the demonstration plant under constru-
ction at the D. H. Mitchell plant of the Northern Indi-
ana Public Service company (NIPSCO). This design com-
bines the Wellman-Lord SO recovery process and the
2
Allied Chemical SO- reduction process to produce elemen-
tal sulfur as an end product.
The model for sulfuric acid plants has been developed
following the same procedure used in the report on
Part 1 of this study, where the Wellman/Allied process
and cost models for utility boilers were developed. A
review and evaluation of the NIPSCO design was present-
ed in that report and several process changes were made.
While most of these changes were adopted for the present
model, additional modifications were introduced because
of the difference in the stack gas emissions from sul-
furic acid plants and utility boilers.
As discussed in section 4.3, sulfuric acid mist con-
stitutes an important fraction of the total sulfur emis-
sion from acid plants. In order to prevent the formation
of sulfate in the scrubbing system, sulfuric acid mist
has to be removed from the acid plant tail gas before
it enters the absorber. The results presented in the
report "Engineering Analysis of Emissions Control Tech-
nology for Sulfuric Acid Manufacturing Processes" pre-
pared by Chemico ( 4 ) have been used to determine the
56
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most effective method for acid mist removal. It was
found that electrostatic precipitators and fiber mist
eliminators are the only devices capable of reducing the
acid mist concentration to less than the EPA New Source
Performance Standard of 0.15 pounds per ton of acid. Of
these two alternatives, fiber mist eliminators repre-
sent a lower investment and were therefore adopted for
the design.
Acid mist eliminators become more expensive as their
efficiency is improved. On the other hand, the formation
of sodium sulfate is increased by the amount of acid
mist that goes into the absorber. This in turn increases
the make-up chemical cost and the cost of purge treat-
ment. Therefore, it is important to point out that
studies should be made in order to determine an economi-
cally optimum balance between the amount of acid mist
that is removed in the eliminator and in the absorber.
However, this would require additional information on
acid mist particle size distributions and studies of
acid mist removal in the absorber.
In the absence of this information, a high efficiency
type mist eliminator was incorporated into the model
in order to make it applicable to all acid plants. This
type of design will collect particles greater than 3
microns in size with essentially 100% efficiency and all
remaining particles with 99.5% efficiency. The recovered
sulfuric acid can then be returned to the acid plant.
The tail gas discharge from acid plants does not contain
any fly ash. In view of this fact, all equipment related
to fly ash removal has been either modified or elimi*
nated from the design. The prescrubbing section of the
absorber tower has been reduced and modified to serve
57
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the only purpose of saturating the incoming qas with
water vapor. The absorber surge tank and fly ash
filter system were eliminated while the evaporator feed
tank was enlarged to provide enough surge capacity.
The Allied process for sulfur recovery has not been in-
cluded in the model since the recovered sulfur dioxide
can be directly recycled to the converter in the acid
plant.
In accordance with the model for utility boilers, the
absorber was designed for an overall SO- removal ef-
ficiency of 95% and all the pieces of equipment have
been sized for 100% load factor.
6.2.2 Variation of Equipment Costs and Plant Size
The flue gas discharge from utility boilers is much
greater than that from sulfuric acid plants, i.e., at
full capacity, the largest acid plant discharges 288
M SCFM of tail gas, comparable to the flow from an
80 megawatt utility boiler. In order to avoid large
extrapolations from the reference size plant used in
the previous model, it was necessary to investigate
and determine cost correlations for small size equip-
ment. As a result of this study, the exponents re-
lating cost to size for different types of equipment
are generally different from those used in the model
for utility boilers.
Cost proportional to
Tower shells (including lining) (ACFM)
0.9
Tower internals (ACFM)
.0.1 - 0.5
Centrifugal pumps UJUKJ
Tanks and drums (volume)
58
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Cost proportional to
Agitators (BHP)0*5
08 — 09
Fans, blowers, and compressors (BHP) '
Direct fired heater (duty) *
0.9
Ductwork and dampers (ACFM)
Heat exchangers (surface) * " *
Forced circulation evaporators Q ,
(complete system) (duty) '
0 8
Storage silos and bins (volume)
Pressure vessels (volume) *
0 9
Pressure vessel internals (ACFM) *
Miscellaneous solids handling n B
equipment (flow)u
-------
sulfuric acid plants, it was not necessary to use mul-
tiple trains since the plant capacities involved are
well below the maximum train sizes determined in the
model for utility boilers.
A reference plant size to be used in the model was
chosen to handle a tail gas flow of 20,000 ACFM (@170°F,
14.7 psia), a sulfur rate (as SO-) of 350 pounds per
hour (Ibs/hr), and a sulfur rate (as acid mist) of -50
Ibs/hr. These figures were obtained by averaging the
highest and lowest emissions from existing acid plants
in order to make the scale-up and scale-down factors
comparable in magnitude.
The following factors were determined in order to scale-
down from the adjusted NIPSCO design to the reference
plant size:
Scale-down factor
For the gas flow 0.0536
For the sulfur (from S02) rate 0.1452
6.2.3 Cost Model
1. Equipment Costs
Equipment costs have been calculated for the different
areas of the reference plant and are as follows:
60
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1) The Absorber Area
Cost of Reference
Size Train Cost
M$ (end of 73) Relationship
a) Mist eliminator elements
b) Mist eliminator tank
c) Sulfuric acid pumps
d) Absorber shell and lining
e) Absorber internals
f) Prescrubber circulation
pumps, quench pumps, and
absorber circulation pumps
g) Induction Fan
h) Reheater, ductwork, dampers
i) Fuel oil system
j) Evaporator feed tank,
agitator, and pumps
Total equipment cost for
absorber area, EA =
32.5
18.6
1.1
41.4
22.7
GP1-0
GP0-5
SM0'1
GP°-6
OP0'9
8.3
12.6
35.4
25.8
15.1
213.5 M $
GP
GP
GP
GP
0.4
0.9
0.8
0.5
.0.5
In general, for a plant with a total gas flow of GP M
ACFM, a sulfur rate from S02 of S Ibs/hr, and a sulfur
rate from acid mist of SM Ibs/hr, the total equipment
cost for the absorber area is:
EA
0.4
,0.8
0'5
GP0-6
41.4(f)
.0.9
35.
+ 15. 1C S )
3T3T
°'5
1.1 ()"
M $
Note that the last term is insignificant and can there-
fore be neglected.
61
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2) The SO Regeneration Area
2
Cost of Reference
Size Train
M$ (end of 73)
a) Tanks, agitators, and
heat exchangers 55.1
b) Pumps 3.9
c) Condensate stripper shell
and evaporator system 62.6
d) Compressor and condensate
stripper internals 10.8
Total equipment cost for
the S02 regeneration area, ES = 132.4
Cost
Relationship
s°'5
S°'3
S0.7
S0.8
M $
In general, for a plant handling a sulfur (from S02)
rate of S Ibs/hr, the total equipment cost for the S02
regeneration area is:
0.3
0.5
0.7
ES =
+ 55,
0.8
+ 62. 6
M $
3) The Purge/Make-up Area
a) Pumps and fans
b) Tanks and agitators
c) Plate exchangers and dryer
d) Crystallizer centrifuge,
evaporation system, and
refrigeration unit
Cost of Reference
Size Train, M $
(end of 73)
14.5
14.6
42.3
36.6
Cost
Relationshio
S0.3
S°'5
,,0.4
,0.7
62
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e) Bins and miscellaneous g^g
solids handling equipment 10.9 S
Total equipment cost for
the purge/make-up area, EP = 118.9 M $
In general, for a plant handling a sulfur (from S02)
rate of S Ibs/hr, the total equipment cost for the purge/
make-up area is:
c 0.3 <, 0.4 s 0.5
0.7 0.8
4) Retrofit Factor
A retrofit factor, RF, has to be introduced to reflect
the difficulty of installation and increased costs of gas
related equipment for a retrofit installation. This
factor will not apply to other areas since these are as-
sumed to be locatable anywhere on the plant site. In
the absence of detailed information on sulfuric acid plant
lay-outs, this factor has been assumed to be equal to the
higher retrofit factors used in the model for utility
boilers. This assumption arises from the small plant
capacities and older installations.
The total equipment costs for the Wellman-lord system
can then be summarized as follows:
rp 0.4 Gp 0.5 Gp 0.6
EA = RF [8.3(§|) + 44.4(f|) + 41. 4(^) +
__ 0.8 rt, 0.9 rp
" + 35. 4 eg) + 35.3C§§) + 32. 5 C§f) 1 +
15- K) M $
63
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c 0.3 Q 0.5 0.7
ES= 3.9(^1 + SS.Kjfj) + 62.6(^1
c 0.8
c 0.3 0.4 0 0.5
EP = 14.51^) + 42-3(3Sff> + 14-6
c 0.7 _ 0.8
\ •}£ £ t & \ t 1 A ft / *5 \
2. Other Material Cost and Labor Costs
The same factors used in the cost model for utility
boilers have been used to relate the costs of labor and
other materials to the major equipment costs. These
relations are shown below, where E represents the major
equipment cost, L the labor cost, and M the cost of
other materials. The subscripts A, S, and P refer to
the absorber area, the S02 regeneration area, and the
purge/make-up area respectively. Labor costs are based
on the Gulf Coast area. Field materials include only
piping, instruments, electrical, insulation, painting,
concrete, and structural steel.
LA = 0.224 EA MA = 0.429 EA
LS = 0.310 Eg Mg = 0.742 ES
Lp = 0.623 Ep Mp = 0.827 Ep
3. Raw Materials and Utilities Costs
1) Sodium Carbonate
The amount of sodium carbonate used to replenish the
sodium values lost by oxidation of the scrubbing solution
is directly proportional to the sulfur (from SO ) rate,
5. The consumption of sodium carbonate can be scaled
64
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directly from the NIPSCO design where 0.265 tons/hr are
required. Since the scale-down factor on the sulfur
rate is 0.1452, the sodium carbonate make-up for the
reference plant at 100% load factor is:
Consumption = x 0.1452 x 8760 = 0.337 M tons/yr
In general, the annual cost of sodium carbonate, AS, for
a sulfuric acid plant having a load factor of LF is:
AS = 0.337(3!^) • CS * LF
where CS is the purchase price of sodium carbonate in
$/ton
2) Power
The power consumption shown for the NIPSCO design has
been adjusted to reflect the process and equipment
changes described in Part 1. The adjusted power require
ment for the NIPSCO design is 3134 KW of which 2467 KW
are proportional to the gas flow rate and 667 KW are
proportional to the sulfur rate (from SO,) .
The annual power consumption of the reference plant at
100% load factor is:
Consumption = 2.467 x 0.0536 x 8760 (proportional to GP)
+ 0.667 x 0.1452 x 8760 (proportional to S)
= 1.160 M KWH/yr + 850 KWH/yr
The annual power cost, AE, is:
AE = I1-«* + 0'85- CE • LF M $/yr
65
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where CE is the purchase (or transfer) price of electri
city in mills/KWH.
3) Steam
The steam consumption for the adjusted NIPSCO design is
52.7 M Ibs/hr and is proportional to the sulfur rate.
For the reference plant at 100% load factor, the steam
consumption is:
Consumption = ~ x 0.1452 x 8760 = 67 MM Ibs/yr
The annual cost of steam, AH, is:
AH = 67 (-) CH • LF M $/yr
where CH is the purchase (or transfer) price of steam in
$/Mlbs.
4) Cooling Water
The total cooling water requirement for the modified
NIPSCO design is 3.3 M GPM, of which 0.19 M GPM is pro-
portional to the gas flow and 3.11 M GPM is proportional
to the sulfur rate. Cooling water required for the re-
ference plant at 100% load factor is:
Consumption = 0.19 x 0.0536 x 60 x 8760 (proportional to GP)
+ 3.11 x 0.1452 x 60 x 8760 (proportional to S)
= 5350 M gal/yr + 237000 M gal/yr
The annual cost of cooling water, ACW, is:
ACW = t5.4(£.) + 237 (-)] CCW ' LF M $/yr
66
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where CCW is the cost of cooling water in $/M gal.
5} Process Water
For the NIPSCO design, the use of process water is 10 GPM
and is proportional to the sulfur rate. Its consumption
for the reference plant at 100% load factor is:
Consumption = ^ x 0.1452 x 60 x 8760 = 760 M gal/yr
The annual cost of process water, AW, is:
AW = 0.76(3!^) CW • LF M ?/yr
where CW is the cost of process water in $/M gal.
6) Fuel Oil
As described in the model for utility boilers, the
NIPSCO design was modified to include direct reheating
of the flue gas. The consumption of fuel oil for this
purpose was established to be 254,000 MM Btu/yr. For
the reference plant at 100% load factor, the fuel oil
consumption is:
Consumption = 254,000 x 0.0536 = 13,600 MM Btu/yr
The cost of fuel oil, AF, is:
AF = 13.6(|J) CF • LF M $/yr
where CF is the purchase price of fuel oil in $/MM Btu.
67
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7) Credits
The process will produce three materials: sulfuric acid,
sulfur dioxide, and a dry purge solids stream consisting
of sodium sulfite, sodium sulfate, and sodium thiosulfate.
Sulfuric acid and sulfur dioxide would normally be return-
ed to the acid plant and can therefore be listed as credits.
The purge material may have positive or negative value
depending upon whether or not it can be sold. If it is
not sold, a waste disposal cost would be incurred. The
cost treatment of the purge solids can be handled by
insertion of a positive or negative unit value in the
model .
a) Sulfuric Acid
Sulfuric acid particles are collected in the mist elim-
inator elements. The liquid drains to the bottom of the
tank and can then be recycled to the acid plant or sold
directly as a" product.
The reference plant has a sulfur flow (from acid mist) of
50 Ibs/hr. At 99.6% overall acid mist removal efficiency,
the amount of 100% sulfuric acid recovered in one year at
100% load factor is:
Production = 50 x 0.996 x [ x - = 670 tons/yr
The sulfuric acid credit, ASA, is then given by:
ASA = <> VSA ' LF M
where VSA is the value of sulfuric acid in $/ton of acid
of concentration CONG.
68
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The value of the recovered su If uric acid depends on its
concentration. The average concentration of the acid
mist droplets varies with the concentration of the acid
being produced in the acid plant. For the concentration
range in consideration, the following linear correlation
was determined:
CONG = 0.455 CONC^ + 0.545
(for 0.75 <_ CONC- <_ 1)
where CONG, is the concentration of the acid being pro-
duced in the acid plant, and CONG is the average con-
centration of the acid mist particles.
The value of sulfuric acid, VSA, is given in terms of
its concentration, CONG, by:
VSA = 50 CONG - 31 $/ton of acid
(for 0.9 <_ CONG <_ 1)
These two relations can be combined into one to give
the sulfuric acid value in terms of the concentration of
the acid plant product (see Figure 6.13):
VSA = 22.75 CONG - 3.75 $/ton of acid
(for 0.75 <_ CONG <_ 1)
The credit value of the recovered S02, VSD, can be
established in terms of the equivalent amount of sulfuric
acid that can be produced from it:
VSD ° x x VSA {1-FR) s/ton of acid
69
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where FR represents the operating costs in the acid plant
as a fraction of the sulfuric acid value, VSA.
b) Sulfur Dioxide
The S0_ production for the modified NIPSCO design is
4430 Ibs/hr, and is proportional to the sulfur rate
(from S0_). For the reference plant at 100% load
factor:
Production = 4430 x 0.1452 x |^- = 2820 tons/yr
The S02 credit, ASD, is:
ASD = 2.82(3!^) VSD • LF M $/yr
where VSD is the credit value of S02 in $/ton.
Using the previous relation, the S02 credit, ASD, can
be obtained in terms of VSA as:
ASD = ^~- (^Ifl-) VSA (1-FR) • LF $/ton of acid
c) Purge Solids
The NIPSCO design shows a purge solids production rate
of 0.35 tons/hr which is proportional to the sulfur rate.
The purge solids flow for the reference plant at 100%
load factor is:
Production = 0.35 x 0.1452 x 8760 = 450 tons/yr
The purge solids credit (or debit), APS, is:
APS = 0.45 Utrr) VPS • LF M $/yr
70
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where VPS is the unit value of the purge solids in
$/ton. If the purge solids are listed as a credit (debit),
VPS would be positive (negative).
The total cost of raw materials and utilities less credits,
ANR, is:
ANR=AS+AE+AH+ACW+AW+AF-ASA-ASD-APS M $/yr
6.2.4 Total Plant Investment and Total Capital Required
The bare cost of the control plant (BARC), total plant
investment (TPI), and total capital required (TCR) for
the Wellman-Lord system can be calculated from the ap-
propriate equations in the General Cost Model.
BARC = 1.15 (E + M) + 1.43 L • F M $
TPI = 1.12 (1.0 + CONTIN) • BARC M $
TCR = 1.135 TPI +0.2 (AOC + CRED) M $
where E = EA + ES + EP M $
L = LA + LS + LP M $
M = MA + MS + MP M$
6.2.5 Operating Costs
The total net annual operating cost (AOC) is given by
the following equation from the General Cost Model:
AOC = 0.078 TPI + 2.0 TO • CO (1.0 + F) + ANR M $/yr
71
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where TO = total number of shift operators
CO = hourly rate for an operator ($/hr)
For a 200 MW utility plant, the Wellman-Lord system re-
quires 16 operators (4 per shift) . In the model for
utility boilers it was assumed that, for plants less
than 200 MW, the number of operators was directly pro-
portional to the plant size. Since the reference
control plant used in this model handles a gas flow
which is approximately equivalent to that from a 6 MW
boiler, the number of operators required for the re-
ference plant is:
ref. = 16 2W = °'48
If it is further assumed that, for other plant sizes, the
number of operators is directly proportional to the
total gas flow, then,
TO = 0.48
The total annual production cost, TAG, can then be cal
culated from the appropriate equation in section 5 as:
vir - STC + TCR - 0.239 WKC - 0.291 TPI . _„
TAG -- - - + AOC
where the working capital (WKC) and start-up costs (STC)
are given by:
WKC =0.2 (AOC + CRED)
STC =0.2 (AOC + CRED)
72
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6.2.6 Effect of Various Parameters on Costs
In Figures 6.14 to 6.16 typical costs which were cal-
culated from the model have been plotted to illustrate
the effects of different variables on costs. These
plots are not for actual, existing plants, but have
been included merely to illustrate typical cost vari-
ations predicted by the model. Although the figures are
self-explanatory, some of the more significant conclusions
should be noted.
Figure 6.14 shows that plant capacity has a large effect
on the total capital requirement. Small plants are far
more expensive to control than large ones. On an equiv-
alent basis ($/ton of 100% acid annual plant capacity),
a plant having an annual capacity of 2,000 M tons of
100% acid can be controlled for 15% to 18% of the cost
required for a 10 M ton/yr plant.
Figures 6.15 and 6.16 show that plant capacity has a
similar effect on operating costs. While a new 10 M
ton/yr plant (Gulf Coast location) can be controlled at
a cost ranging from 10 $/ton to 17 $/ton, a plant 200
times larger could be controlled for 1.8 $/ton to 3.2
$/ton.
Figures 6.14 and 6.15 also indicate how the costs vary
with the amount of sulfur (from S02) in the gas. The
values that were used (S.,=24 and S.=54) represent the
minimum and maximum encountered in existing acid plants
(refer to Section 4.3). Increasing the S0_ emissions
from 24 to 54 pounds of sulfur per ton of 100% acid can
increase the total capital requirement of the control unit
by as much as 35%, and increase the operating costs of the
control unit by as much as 50%.
73
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The amount of acid mist in the gas does not have a
noticeable effect on the total capital requirement be-
cause the mist eliminators are designed based on the
total gas flow from the sulfuric acid plant. Since the
recovered sulfuric acid is claimed as a credit, the acid
mist content of the gas has a positive effect on pro-
duction costs. As seen in Figure 6.16, increasing the
acid mist emissions from 4 to 22 pounds of sulfur per
ton of 100% acid may reduce the costs by as much as 23%.
The same figures also show the effect of the gas dis-
charge on costs. For a 2000 M tons/yr plant, the total
capital requirement could increase by 47% and the pro-
duction cost by 58% when the amount of gas discharged
increases from 92 to 192 M ACF per ton of 100% acid
produced.
The influence of load factor on operating costs was
not investigated because, on the average, most sulfuric
acid plants operate at 95% of capacity, with only minor
deviations from this figure. The effects of retrofit
and location factors on costs are similar to those in-
dicated in Part 1 of this study.
6.2.7 Wellman-Lord Model Applied to Existing Sulfuric
Acid Plants
The Wellman-Lord stack gas scrubbing model has been
applied to all the salfuric acid plants contained in the
data file mentioned in Section 4.3. A breakdown of
costs, capacities and production for each state is pre-
sented in Table 6.5. The results of the analysis are
presented graphically in Figures 6.17 to 6.25.
74
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Figure 6.17 shows the total capital required for instal-
ling the stack gas scrubbing system in existing sulfuric
acid plants of various sizes. Figure 6.18 presents the
total capital requirement expressed in $/ton of 100%
annual acid capacity. This cost increases gradually
with decreasing plant capacity from 2,000 to 100 M tons
of 100% acid/yr, but rises sharply below 100 M tons/yr.
Figure 6.19 shows the estimated incremental production
cost ($/ton of acid) for installing the Wellman-Lord
system in existing sulfuric acid plants. The incremental
cost varies from about 8.5 $/ton to 6.1 $/ton for plant
sizes of 100 to 2,000 M tons/yr. Below 100 M tons/yr,
the incremental cost rises sharply with decreasing
size.
The cumulative plant capacity (as percent of total
capacity) is plotted against the maximum capital require-
ment in Figure 6.20. This plot shows that 90% of the
total sulfuric acid capacity could be controlled at costs
below 28 $/ton of annual acid capacity, while the total
U.S. capacity could be controlled at costs of 74 $/ton
of annual acid capacity or less. A similar graph for
the maximum annual production cost is shown in Figure
6.21.
The cumulative total capital requirement (in MM$) and
production cost (in MM $/yr) are plotted against percent
of total capacity controlled in Figures 6.22 and 6.23
respectively. Similarly, the cumulative costs versus
the reduction in sulfur emissions (as percent of total
U.S. emissions from sulfuric acid plants) are shown in
Figures 6.24 and 6.25
75
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6.3 Industrial Boilers
6.3.1 Conventional Scrubbing System
In Part 1 of this study an investigation was made to de-
termine the costs of fitting stack gas scrubbing pro-
cesses to coal and oil fired industrial boilers in the
U.S. With slight modifications, the cost models de-
veloped for utility boilers were used for this purpose.
However, the costs predicted for small size industrial
boilers (less than 100 MMBtu/hr) were found to be very
high, mainly because these boilers represent a large
extrapolation of the models from the type of application
for which they were initially developed.
In this phase of the study, the cost models for utility
boilers have been re-examined for application to small
utility boilers. New reference sizes were determined
for which equipment costs have been obtained from the
correlations developed for the cost model for sulfuric
acid plants (Section 6.2) and from price quotations for
shop fabricated scrubbing units (Section 6.3.2).
The reference size control plants were chosen to handle
a flue gas flow of 20,000 ACFM and a sulfur rate of 170
Ibs/hr. This is approximately equivalent to the dis-
charge from a 6 MW utility boiler.
The equipment cost equations derived for this reference
size are presented in Table 6.6 and Table 6.7 for the
wet limestone and Wellman/Allied systems respectively.
These equations were found to be applicable for gas flow
rates not greater than 110,000 ACFM and sulfur flow rates
up to 1,000 Ibs/hr. The cost models for utility boilers
76
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can then be applied beyond these points Cfor a detailed
explanation of these equations refer to Sections 5 and
6 in Part I of this study). Tables 6.8 and 6.9 give a
summary of the combined cost models for both processes.
These equations were implemented for computer application
and were used to determine the costs for installing wet
limestone and Wellman/Allied scrubbing on existing in-
dustrial boilers on a plant basis for all plants greater
than 5 MW equivalent size. The control procedure that
was used is the same as that for utility boilers, viz.,
controls are applied to individual boilers in a plant
(in order of decreasing sulfur emissions) until the over-
all plant emission falls below the allowable level C1.2
Ibs of S02/MMBtu).
After the data base was edited as discussed in section
4.2.3, it was found that among 4385 plants considered
for cost analysis, only 829 plants required control.
This represents about 19% of the plants considered.
Table 6.10 and 6.11 give the breakdown of costs for each
state for both Wellman/Allied and wet limestone process-
es.
Figures 6.26 and 6.27 represent graphically the average
total capital requirement for installing Wellman/Allied
and wet limestone stack gas scrubbing units in exist-
ing industrial boiler plants. Only plants requiring
control are included in these cost curves. These graphs
show that the wet limestone process is somewhat less
expensive, although at a plant size less than 50 MMBtu/hr,
there is no distinct difference between the two processes.
Figures 6.28 and 6.29 represent the variation in average
77
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annual production cost for both processes. The cost
in $/MMBtu decreases with increasing plant size.
Figure 6.30 represents the maximum total capital require-
ment, in $/MMBtu/yr, versus the cumulative plant capacity
expressed as a percentage of the total capacity of con-
trolled plants. This curve shows the cost of control-
ling any given percentage of the total US plant capacity.
Figure 6.31 shows the same type of relationship between
the maximum total production cost, in $/MMBtu, and the
cumulative plant capacity of controlled plants, ex-
pressed in %.
Figure 6.32 shows the cumulative total capital require-
ment, in MM$, versus the cumulative plant capacity of
controlled plants, expressed in %. Only one curve was
drawn since there was no difference in the cost between
the two processes. The summation wa.s ma,de- in. order of
increasing TCR ($/MMBtu/yr). Figure 6.33 is a similar
plot except that the summation was made in order of de-
creasing plant size.
Figures 6.34 and 6.35 show the cumulative production
cost, in MM$/yr, versus the cumulative plant production,
expressed as % of the total US controlled plants. The
summation in the first curve was made in order of in-
creasing TAG ($/MMBtu) and the second one in order of
decreasing plant production.
Figures 6.36 and 6.37 show the reduction in sulfur em-
ission, expressed in %, versus the cumulative total
capital requirement, in MM$, and the cumulative pro-
duction cost, in MM$/yr.
78
-------
6.3.2 Packaged Scrubbing System
1. Objective
The objective of this phase of the study was to develop
a cost estimate for shop fabrication and packaging of
a scrubber unit as a possible investment alternative
to reduce capital expense and make scrubbing more
economically practical. The scrubbing system selected
is the wet limestone scrubbing system to serve a 50
MMBtu/hr coal fired boiler (single boiler plant). This
size boiler was selected on the basis of the minimum
size referred to in the EPA task description.
"Packaged system" refers to a scrubbing system which
consists of several preassembled units. It differs
from a normal installation in the sense that field
erection cost is minimized. The major equipment is
combined into sections at the shop and arrives at the
job site in single units as opposed to having each
separate piece of equipment installed in the field.
Ideally, a skid-mounted unit for the entire scrubbing
system would represent the minimum field erection cost,
but this proved to be impractical due to the equipment
sizes and shipping dimensions allowed.
As an alternate to a skid-mounted system some of the
major equipment pieces can be combined as packaged
sections. Two sections have been assembled as follows.
1) The venturi and TCA scrubbers are mounted on the
scrubber sump at the shop and shipped as a unit. All
lining, required instrumentation and internal piping
79
-------
is completed at the shop.
2) The gas reheater and entrainment separator are shop
assembled as a packaged section, including the ductwork
and transition pieces.
This ductwork consists of sections from the TCA scrub-
ber to the entrainment separator, from the entrainment
separator to the reheater and a short section from the
reheater.
The rest of the equipment is shop fabricated, including
lining where required.
2. Basis of Design
The limestone slurry scrubbing system was designed to
be part of a steam generating plant having a single
50 MMBtu/hr coal-fired boiler.
Fuel to Boiler - The boiler will be fueled with
4200 Ibs/hr of coal with a sulfur content of 3.5
weight percent and an ash content of 14.5 weight per-
cent.
Gas to Scrubbing System - Gas entering the scrubbing
system is 18,000 ACFM @ 300°F and atmospheric pressure
(12,300 SCFM) with an S02 rate of 300 Ibs/hr and a
solids rate of 500 Ibs/hr (4.74 gr solids/SCFM).
Process - The limestone scrubbing system is based on
the Catalytic design (3).
Equipment - A detailed description of the equipment
is given in Appendix F.
80
-------
Figure 6.38 - Shows the location of all the equipment.
The settling pond has been assumed to be onsite but
located in a remote section of the plant.
Figure 6.39 - Shows the plan view, side view and
elevation for the equipment included in the scrubbing
section. Over all dimensions are 52 ft wide by 69 ft
long with an elevation of 74 ft.
3. Costs
All equipment prices included in the "packaged unit"
were obtained from individual manufacturers and quoted
as "budget price".
Basis for Cost Estimate
1) The plant will be constructed in the Midwest area
where Cincinnati construction labor rates apply.
2) The venturi and TCA scrubbers will be mounted on
the scrubber sump at the shop and shipped as a unit.
All lining, required instrumentation and internal
piping will be completed at the shop.
3) All vessels that require lining will be completely
shop assembled.
4) The gas reheater and entrainment separator will be
shop assembled as a unit, including the ductwork and
transition pieces. The ductwork consists of the duct
from the TCA scrubber, duct to and from entrainment
separator, duct to and from the gas reheater.
5) All ductwork will be lined at the shop.
81
-------
6) The ductwork from the boiler to the venturi scrub-
ber is shipped as a single piece.
7) The effluent gas duct, from the gas reheater duct
to the I.D. fan, is shipped in two sections due to
shipping length limitations.
8) All pumps are base mounted.
9) Tank agitators will be shipped fully assembled and
ready to be mounted on top of the corresponding tanks.
10) The belt conveyor will be shipped in four sections
due to shipping length limitations.
Comparison With Field Erected Unit
The costs of a packaged versus field erected wet limestone
scrubbing unit for a 50 MM Btu/hour boiler are summarized in
Table 6.12. The total capital required, TCR, for a packaged
unit was estimated to be $3493M (about $8/MM Btu/year) compared
to S4364M (about $10/MM Btu/year) for a field erected unit, a
potential savings of 20%. However, in view of the 20-25%
accuracy of the wet limestone cost model, which was used to
generate costs for the field erected unit, the only conclusion
that can be drawn from the cost comparison is that a packaged
system appears to offer some potential for reducing capital costs,
but the magnitude of the cost savings is uncertain.
Operating costs are about $3.20/MM Btu for a packaged
unit compared to $3.90/MM Btu for a field erected unit. This
difference is related to capital charges.
82
-------
6.4 Wellman/Allied Model Applied to Glaus Plants
The Wellman/Allied process and cost model presented in Part 1
has been re-examined in order to determine what modifications
would be necessary to make it applicable to Glaus sulfur
recovery plants.
Information on the tail gas discharge from Glaus plants has
been obtained from the report "Characterization of Glaus
Plants Emissions" prepared by Process Research, Inc. ( 19)
It should be pointed out that the main body of this report
gives the sulfur dioxide flow rate as a function of the
number of catalytic stages and the amount of hydrogen
sulfide in the gas feed. This information is insufficient
to completely characterize the emissions. However, the
Appendix of the report contains some data provided by com-
panies that are operating Glaus plants.
The available information indicated that, after incineration,
the tail gas from Glaus plants is at a temperature that
ranges from 850°F to 1,300°F and normally contains from 1.0%
to 1.6% Cby volume) of S02. These figures have been com-
pared with available figures in the NEDS Glaus plant file,
and seem to be representative. As a result of incineration
and the Glaus process itself, the gas also contains large
amounts (25% to 33%) of water vapor.
The temperature of the flue gas is much too high to be fed
directly into the absorber. A small sized boiler can be
designed to utilize part of this heat to generate steam and
cool the hot gas down to about 300°F. It is estimated that
this boiler could provide from 80% to 90% of the steam re-
quired by the evaporator system in the S0_ recovery section.
This can be claimed as a credit.
83
-------
A water cooled heat exchanger can then be used to further
reduce the temnerature of the gas to the operating tempera-
ture in the absorber. At this point the gas will be satu-
rated with water vapor and some water will have condensed.
The gas can enter the absorber after the condensate is re-
moved .
The cost model developed for utility boilers is based on the
design for the demonstration plant being installed at the
D.H. Mitchell plant of the Northern Indiana Public Service
Company (NIPSCO). This design includes quench pumps and a
prescrubbing section in the absorber where the gas is scrub-
bed by recirculating water to remove the flyash. The gas
becomes saturated with water vapor and its temperature is
reduced in this same process. These sections can therefore
be effectively eliminated in the present case since the
tail gas from Glaus plants does not contain any flyash and
is already saturated with water vapor after going through
the cooling process described above.
The NIPSCO absorber is designed to handle a gas that contains
approximately 0.2% SO-. Perforated trays without downcomers
are used for this purpose. The liquid is recirculated to
each tray in order to maintain an effective licnaid level.
The gas from Glaus plants will enter the absorber with an
S02 concentration ranging from 1.2 to 1.8% by volume. Under
these conditions, the liquid (sodium sulfite solution} flow
rate is greater and a higher bisulfite concentration can be
obtained as a product. A normal perforated tray tower de-
sign appears to be feasible and more economical because the
circulating pumps can then be eliminated and the costs re-
duced. This cost reduction will he partly off-set by- the
increased cost of the tower internals. The rest of the
equipment in the plant (shown as proportional to the sulfur
rate in the model for utility boilers) will then have to be
84
-------
scaled to provide enough caoacity to handle the higher liquid
rate and bisulfite concentration. For similar gas flows, it
is estimated that this equipment has to he 4 to 6 times
larger than the corresponding equipment used in the process
for utility boilers.
Equipment such as the flyash filter and the absorber surge
tank and pump can be eliminated from the design since they
are related to flyash removal. The liquid from the absorb-
er can be fed directly into the evaporator feed tank, which
will have to be enlarged to provide enough surge capacity.
The Allied section for sulfur recovery need not be included
in the model since the recovered sulfur dioxide can be
directly recycled as a feed to the Claus plant.
The tail gas discharge rate from Claus plants is much less
than the flue gas flow from most utility boilers. There-
fore, a smaller reference size plant should be used as a
basis for the cost model. Only single trains apoear to be
necessary for each process section. The cost correlations
for small size equipment developed for the model for sul-
furic acid plants would then be applicable.
Finally, it is important to point out that further studies
are required to fully characterize the emissions from Claus
plants. A cost model can only be applied to existing plants
if the tail gas flow rate, composition and temperature can
be predicted from plant characteristics such as production
capacity, number of catalytic stages, and feed gas compo-
sition.
6.4.1 Equipment Costs
For application to Claus plants, the Wellman/Allied
85
-------
process and cost model for utility boilers will have to
be modified as follows:
1) Absorber Area
The following equipment can be eliminated from this
area:
a} Quench pumps
bl Prescrubber section of the absorotion tower, in-
cluding lining and internals
c) Prescrubber circulation pumps
d} Absorber internals
e) Absorber circulation pumps
These costs will then be replaced by:
a) Cooling system, which will include:
- Boiler
- Steam drum
- Heat exchanger
- Separating drum
- Booster fan
- Pumps
b) Modified tower internals (new tray designl
2] SO £ Regeneration Area
Equipment that can be deleted from this section:
a) Flyash filter
b) Absorber surge tank, agitator, and pump
86
-------
Other eauipment costs in this area need to be adjusted
to reflect the increase in capacity due to the higher
liquid and sulfur flow rates. In the absence of the
absorber surge tank, the evaporator feed tank has to
be enlarged to provide enough surge capacity.
3) Purge/Make-up Area
Equipment costs in this area are proportional to the
sulfur flow rate and, as before, need to be adjusted
for the higher flow rates.
4) Reduction Area
This area can be eliminated from the model since the
sulfur dioxide would be recycled to the Glaus plant.
6.4.2 Raw Materials and Utilities
The consumption of raw materials and utilities will
have to be modified according to the process and
equipment indicated above.
6.4.3 Credits
1) Since the Allied section can be excluded from the
model, the sulfur credit has to be eliminated and
replaced by a sulfur dioxide credit.
2) The purge solids credit (debit) will have to be
modified according to the new process.
3) The steam produced in the boiler can also be list-
ed as a credit.
87
-------
6.4.4 Reference Size
A smaller (more representative! reference size olant
is recommended to be used as a basis for the modified
cost model. Statistics on existing Glaus plants in-
dicate that a multitrain system will not be necessarv.
88
-------
TABLE P.I
STACK GAS SCRUBBING COST ANALYSIS
FUEL ALLOCATED TO BOrLERS
PLANT NO 1 OF UTILITY — 2
PLANT SI/E— 1771 MEGAWATTS
NO. OF BOILERS 5
BOILER FUEL CONSUMPTION £ SULFUR EMISSION DATA
I UNCONTROLLED)
THE BOILERS ARE ARRANGED IN ORDER OF DECREASING SULFUR EMISSIONS AND
THIS IS THE ORDER IN WHICH THE CONTROLS ARE APPLIED
STATE ALABAMA
BOILER SIZE
MEGAWATTS!
FUEL BURNED
IMMMBTU)
SULFUR EMISSION
IMTON/VEAR)
SULFUR EMISSION
I TON/YR/HEGAWATT)
7B9
404
272
153
153
32025.23
UB06.73
5802.39
1159.20
1159.20
34.65
12.77
6.28
1.25
1.25
43.92
31.62
23.08
8.20
8.20
NO. OF
BOILERS
CONTROLLED
FUEL CONSUMPTION,SULFUR EMISSION t CONTROL COST DATA
METHOD OF CONTROL—WELLNAN-LORD PROCESSFRACT ION OF S02 REMOVED— 0.95
* PLANT CAP
(CONTROLLED)
% PLANT FUEL
BURNED BY
CONTROLLED
BOILERS
TOT CAP REO
(CUMMULATIVE)
MM» S/KM
T A C
MILS/ C/HHBTU */TON
KMH. SULFUR
REMOVED
SULFUR REMOVED
NTONS/YEAR
OVERALL PLANT
S02 EMISSION
LBS/MMBTU
0.0
44.55
67.36
0.0
61.64
84.37
0.0
43.835
64.896
0.0
55.56
54.40
0.0
3.31
3.51
0.0 0.0
36.77 357.71
39.02 379.63
0.0
32.92
45.05
4.33
1.79
O.S6
-------
TABLE 6.?.
STACK GAS SCRUBBP1G COST ANALYSE
ACTUAL PLJtfTE DATA,
*****************************************************************************************
PLANT HC. - 1 OF UTILITY NO. - 1 UTILITY NAME-
PLflNT NAME C ACDRESS-
********************
UTMLITV CODE - PLANT CODfc-
************* 4*********
PLANT SIZE - ITTCMEGAWAITS NUMBFK OF BOILERS- 5
STATE -ALABAMA
STATE CODE: I
AOCR CODE: 5
COUNTY CODE: 9T
DATA VALIDITY CODE - 0 *
PCILE" FUEL CONSUMPTION £ SULFUR EMISSION CAT/1
(UNCONTROLLED)
THF BOILERS ARE ARRANGED IN OFOER OF DECREASING SULFUR EMISSIONS AND
THIS IS THE PRDER IN WHICH ThE CONTROLS ARE APPLIED
BCILER SIZE
(MEGAWATTS)
FUEL BURNED
(MMPBTU)
SULFUR EMISSION
IHTON/YEAR1
SULFUR EMISSION
I TCN/YR/MECANATTI
403
272
153
788
153
17831.76
13412.33
8009.7-3
9510.35
7783.63
17.97
13.75
8.50
8.43
7.89
50.53
55.57
10.70
51.60
FUEL CONSUMPTION,SULFUR EMISSION £ CCNTPOL COST DATA
METHOD Of CONTROL—WELLMAN-LORD PHOCESSFRACTION OF S02 REMOVED— 0.95
NO. OF
BOILERS
CONTROLLED
X PLANT CAP
(CONTROLLED)
t PLANT FUEL
BURNED BY
CCNTROLLED
BOILERS
TOT CAP REO
(CUMMULATIVEI
MM* S/KW
T A C
MILS/ C/MMBTU »/TON
KWH. SULFUP
REMOVED
SULFUP REMOVED
MTONS/VEAR
OVERALL PLANT
SOZ EMISSION
LBS/MMBTU
0.0
22.77
38.14
46.78
91.30
0.0
31.53
55.25
69.42
86.24
0.0
21.509
34.004
42.?54
77.<-S9
0.0
!>3.37
50.38
51.03
48.06
0.0
3.25
2.94
2.87
3.93
0.0
33.49
30.04
29.56
39.83
0.0
349.78
311.53
303.66
420.24
0.0
17.07
30.13
38.21
46.22
4.00
2.79
1.87
1.30
0.73
CODE EXPLANATION
**«* »*»****«*«*
0 DATA IS SUFFICIENT FOR COST ANALYSIS
3 OR MORE CATA INSUFFICIENT FOR CCST ANALYSIS
-------
TABLE 6.3
EPA STACK. GAS SCRUBBING
COST ANALYSIS SYSTEM
SUMMARY OF COSTS BY STATES - MET LIMESTOHE' PROCESS APPLIED TO UTILITY SLANTS
SIAIE
ALABAMA
ALASKA
AHIIUNA
ANKANSAS
CALIFUNNIA
CULlMADu
CONNECT ICUI
DELAnARL
O.C.
FLUNIOA
CEQNbIA
HAH«II
IDAHU
ILLINOIS
INDIANA
IU«A
KANSAS
KENIUCKY
LOUISIANA
HAlNt
MARYLAND
MASSALHUStTI
MICHIGAN
M1NNESUIA
MISSISSIPPI
MISSOURI
MUM ANA
NEBRASKA
NEVADA
NEH HAMfSHIM
NEM JtRSfT
NEH MEXICU
NEH YUNK
N. CAMULINA
NURIM DAMJFA
OH ID
UKLAHUMA
OHEGON
PENNSYLVANIA
RHODE ISLAND
S. IAKULINA
SUUIM DAKU1A
TENNESSEE
TEXAS
UIAH
VERnONl
VIKCINIA
MASHINGIUN
N. VIRGINIA
N1SCUNSIN
nrOnlNG
1U1AL
CAPACITY
MM
7607.00
0.0
0.0
179.00
0.0
O.U
1683.00
766.00
0.0
6009.00
5433.00
0.0
0.0
6047.00
4456.00
1458.00
400.00
8773.00
0.0
214.00
3474. uo
2753.00
roi9.oo
1737.00
420.00
5975. UO
2^2.00
lOIb.OO
0.0
6J7.UO
osi.ou
0.0
40*9.00
*762.00
741.00
12003.00
O.U
0.0
12604.00
165. 00
2390. UO
123.00
S966.00
593.00
0.0
30.00
3932. 00
0.0
bSbb.uU
U275.00
4S6.00
IUIAL
fRUDUCI IUN
MUM
360t)7lob.OO
0.0
0.0
777158.75
0.0
0.0
8337606.00
4440371.00
0.0
43739168.00
454S1616.00
0.0
0.0
27371968.00
28709888.00
8071845.00
1036026. UO
4b792848.00
0.0
1382090.00
18288288.00
16809168.00
41924352.00
8843770.00
1199496.00
28305808.00
1013373.94
4889986.00
0.0
3747792.00
3755322.00
0.0
22308896.00
37882304.00
5204/9!>. 00
69599520.00
0.0
0.0
68063568.00
1228589.00
12558511.00
238096.50
30643872.00
3480433.00
0.0
122201.88
21635312.00
0.0
39629112.00
22343008.00
4S71041.0V
TulAL
TCH
MS
346857.31
0.0
0.0
10752.10
0.0
0.0
186444.75
38111.90
0.0
427309.00
370480.81
0.0
0.0
442036.00
522809.69
163310.13
12372.90
652009.06
0.0
20150.60
156157.81
170085.88
510134.69
158897.44
5092.20
365739.94
20132.20
43455.59
0.0
38784.70
38081.30
0.0
47179U.J3
163317.69
57204.39
10933/8.00
0.0
0.0
904659. 08
40252.40
71644.88
15498.10
369853.81
29144.80
0.0
6556.20
246351.81
0.0
461189.56
504948.31
25156.90
AVERAGE
1CH
»/KM
45.60
0.0
0.0
60.07
0.0
O.U
110.77
49.75
0.0
53.35
69.47
0.0
0.0
73.34
117.33
112.01
30.93
74.32
0.0
94.16
44.95
61.78
72.68
91.48
23.15
61.21
90.69
42.61
0.0
60.68
56.32
0.0
116.23
28.34
76.69
91.09
0.0
0.0
71.78
2i|3.95
29.98
126.00
62.08
49.15
0.0
218.54
62.65
0.0
70.32
118.12
55.17
TUTAL
1AC
M»
91791.36
0.0
0.0
2724.40
0.0
0.0
46101.29
9904.30
0.0
119470.00
94U62.81
0.0
C.O
116319. 3B
1388/1.13
41391.18
3127.90
172134.56
0.0
6092. 60
43434.19
50692.29
134866.06
40209.29
1375.60
96741.13
5003.20
10580.39
0.0
10743.30
9693.50
0.0
123916.50
44218.39
15594.79
486764.06
0.0
0.0
236439.06
9543. '60
16744.119
3591. 50
97230.13
7753.40
0.0
1466.00
7U660.be
U.D
123514.68
127449.31
6265.70
AVENAGE
IAC
nlLS/KNHM
4.50
0.0
0.0
3.51
0.0
0.0
5,/7
2.23
0.0
2.73
3./0
0.0
0.0
4. 25
4.04
5.13
2.18
3.76
0.0
4.41
2.37
3.02
3.22
4.S5
1.15
3.42
4.94
2.16
0.0
2.86
4.63
0.0
5.55
1.17
3.00
a. 12
0.0
0.0
3.47
/.77
1.49
15.08
3.17
2.43
0.0
12.00
3.27
0.0
3.12
5.70
2.44
-------
TABLE f.A
EPA STACK r,AS SdRI'SSTHr,
SUMMAfl*
SIA It
ALAbAMA
ALA in A
AHI^UNA
AMKANSAS
CAL1FUHNIA
CULUKAUU
CUNNtUICUl
DELAHAkb
D.C.
FLUKIUA
GEUHG1A
HAHA11
IUAHU
ILLINOIS
INDIANA
IU«A
KANSA4
KENIULKY
LOUISIANA
MAINE
MANYLAND
MASSACMUStl 1
MICHIGAN
MIMNESOI A
MISSISSIPPI
MISSOURI
MUNI ANA
NE6KASKA
NEVADA
NE« MAMPSH1H
MEN JtSStY
NED HEXICU
NE" YUNK
N. CAROLINA
NURIW OAMJ^A
OHIU
UMLAHUHA
OHEGON
PENNSYLVANIA
HHCOE ISLAND
S. CAKULINA
SUUIM OAMJTA
ItNNtSStE
TEXAS
UIAH
VERHUNI
VIKUINIA
HASHINGIQN
H, ViHGINIA
NJSLUNSIN
WYOMING
COST ANM.VRIS SVSTEM
DJ? COSTS BY STATES - '.SEIJJlAN/MiLIED PROCESS APPLIED TO I1TILI11": PLANTS
lot AL
CAPACITY
Hh
76U7.00
U.O
0.0
179. UO
0.0
U.O
1683.00
766. OU
O.U
0009.00
5333.00
0.0
0.0
602/.00
4456. UO
1458.00
40U.OO
0773.00
0.0
214.00
3474. OU
2753.00
7019.00
1737.00
220.00
5975.00
222.00
1015.00
O.U
637.00
653.00
0.0
4059.00
5762.00
744. UU
12003.00
O.U
0.0
12604.00
165.00
2390.00
123. UU
5956. OU
593. OU
0.0
30.00
3932. UU
O.U
6558.00
4275. OU
456. OU
IUIAL
PRUUUC 1 IUN
MHh
3o607l6b.OO
O.U
0.0
777158.75
U.O
U.U
8337606.00
4440371. UO
O.U
4373916B.OO
25451bl6.UU
O.U
O.U
27371960.00
20709866.00
0071845.00
1436026.00
4579204B.OO
U.U
I36209U.UO
16266280,00
16809166.00
41924352.00
0643770.00
1199296.00
28305008.00
1013373.94
0869986.00
0.0
3747792.00
3755322.00
O.U
22306896.00
37882304. UO
5204795. UO
69599520.00
U.U
O.U
68063568. UO
1228589. UO
12558511.00
236096. SO
3U643872.00
3460433. UO
O.U
122t!Ul.Ba
21635312. 00
O.U
39629312. UO
22343006. OU
2571041.00
lUlAL
TCK
MS
377910.30
0.0
0.0
12256.80
0.0
0.0
164236.63
38782.89
0.0
551221.56
314146.60
0.0
0.0
487773.31
473795.30
146620.38
12618.90
637193.69
0.0
20664.70
164922.38
255161.63
461100.19
143132.19
6940.60
398335.00
18153.70
34430.80
0.0
396U5.8Q
36129.50
0.0
500604.19
146131.63
S3880.ttO
1013465.06
0.0
0.0
820913.94
40164.80
69£73.06
19352.59
327630.56
20116.30
0.0
6137.60
372461.31
0.0
4202U9.13
396965.69
21006.60
AVEHAGE
ICM
»/KM
49.66
0.0
O.U
60.47
O.U
U.U
109.47
50.63
U.O
60.03
50,91
0.0
0.0
6U.93
106,33
100.56
31.55
72.63
0.0
97,59
47,47
92.68
65.69
62,40
31,55
66,67
61.77
33.92
0.0
62.18
55.33
0.0
123,33
25.36
72.43
04.43
0.0
0,0
65.13
243.42
26.96
157.34
54.49
33.92
0.0
204.59
94,73
U.O
65.30
92.86
46.07
IUIAL
TAG
M»
103346.94
0.0
U.O
3286. *VU
O.U
0.0
49492.59
10591. bU
' 0.0
157666,63
819UI.44
0,0
0.0
133006.31
132243.25
38456.48
3352.50
175340.19
0.0
6436.10
46165.29
76924.19
127906.06
37727,59
1947.30
109446.44
4821.60
6606.00
0,0
11423.70
9907,20
"o;o
130872.38
41432,29
I54tt6.su
276649.31
0.0
0.0
224098,94
10216.10
16993.79
4605,70
9U013.31
5696,90
0.0
1432.20
10b946.1V
0,0
120300.38
105239. 19
53V4.40
AVbNAGt
IAC
MILb/KHHN
2.62
0.0
0.0
4.23
U.O
U.U
b.94
2.39
u.o
3.61
3.22
0.0
U.O
.86
.61
.76
.33
.63
.0
.66
.53
.58
.05
.27
.62
3.87
6.76
1.60
0.0"
3.05
2.64
0.0
6.22
1.09
2.96
4.00
0.0
O.U
3.29
0.32
1.5l
19.34
2.44
1.64
U.O
11.72
4.94
U.O
3.U4
4.71
2.10
-------
•TOUR
STATE
ALABAMA
ALASKA
ARIZONA
ARKANSAS
CALIFORNIA
COLORADO
CONNECTICUT
DELAWARE
FLORIDA
GEORGIA
HAWAII
IDAHO
ILLINOIS
INDIANA
IOWA
KANSAS
KENTUCKY
LOUISIANA
MAINE
MARYLAND
MASSACHUSETTS
MICHIGAN
MINNESOTA
MISSISSIPPI
MISSOURI
MONTANA
NEBRASKA
NEVADA
HEU HAKPSH1RE
NEW JERSEY
NEW MEXICO
NEW TORK
NORTH CAROLINA
NORTH DAKOTA
OHIO
OKLAHOMA
OREGON
PENNSYLVANIA
RHODE ISLAND
SOUTH CAROLINA
SOUTH DAKOTA
TENNESSEE
TEXAS
UTAH
VERMONT
VIRGINIA
WASHINGTON
WEST VIRGINIA
WISCONSIN
WYOMING
D C
PLANT TYPE
1
2
3
4
5
SUMMARY OF STACK GAS SCRUBBING COSTS BY STATES
WELUUN-IARD PROCESS APPLIED TO SULFUKTC
TOTAL CAPITAL
REQUIREMENT
(Mt)
10,950
17.099
9.069
50,662
3.228
7.330
147.475
20,617
1,272
17,590
53,599
17,921
10,993
6,512
5,809
59,018
18,658
1,308
8.553
2,924
5,783
14,983
4,157
3,707
49,762
5,467
4,467
20,643
19,866
5,441
24,160
877
7,058
19,470
72,960
17,190
18,854
4.549
3,058
3,443
3.337
35,995
270.982
199,466
188,054
86.319
TOTAL ANNUAL
PRODUCTION COST
(M$/YR)
3,004
4,858
2,565
14,378
8B7
2,089
43.257
5.734
350
5.092
15.252
5,027
3.173
1,850
1.624
17,332
5,209
631
2,377
832
1,677
4,227
1,199
1 ,067
14,072
1 ,547
1 ,249
6,050
5,597
1,544
6,810
238
1,928
5,705
20,779
5,019
5,252
1 ,269
878
942
930
9,881
76,999
58.351
53.675
24.593
TOTAL CAPACITY
K TONS OF lOOt
ACID PER YEAR
337 8
636 8
432.9
2,209.7
116 1
426 3
9,421 0
641 8
127 9
858 5
2,619.0
720 0
624.8
248 9
264.6
4,215 0
746 6
219 0
313 6
150 7
277 0
651 2
315.4
297.8
2.352 1
192 7
208 0
1,292 5
766 5
196 2
929 1
200 0
137 5
1,153 0
3,915 4
613 2
661 9
124 4
184 0
109.5
113.9
733 1
12,257 4
13,896.0
8,008.7
4,292.8
ACID PLANTS
TOTAL PRODUCTION
M TONS OF I00(
ACID PER YEAR
326 8
605.5
415 3
2,108 6
107.6
407 6
9,923 4
612 1
120 0
820 8
2,493 1
672 0
599 5
236 8
?54 0
4,018 8
713.9
210 0
301 2
144 0
263.6
625 8
302 4
278 4
2.261 4
185 3
202.0
1.233 2
727 6
177 6
897 6
196 3
129 S
1,111 0
3,756.5
578. 9
630 9
115.2
168 0
10S.O
109 4
691 2
11,638.8
13,180 0
7,627 5
4,105 9
AVERAGE
TCR
(S/TON/YR)
32.41
26.85
20 95
22 93
27 81
20 08
15.65
32 12
31 58
20 49
20.47
24.86
17 69
26 16
21 95
14 00
24 99
21 08
27 27
25 29
20 87
23 01
26 36
26 45
21 16
28 37
21 47
15 97
25 92
27 73
26 00
50 08
51 32
16 89
18 63
28 03
28 49
36 57
21 82
31 45
29 30
49 10
22 11
14 35
23.48
20 11
AVERAGE
TAC
(J/TON)
9 19
8 02
6 18
6 82
8 25
5 97
4 90
9 37
9 13
6 20
6 12
7 48
5.29
7 81
6 39
4 31
7 30
C 01
7 89
7 53
6 36
6 75
8.06
8 55
6 22
8 35
6 18
4 91
7 69
8 69
7 59
14 61
14.88
5 14
5 53
8 67
8 32
11 02
6.77
8 97
8 50
14 30
6 62
4 43
7 04
5 99
93
-------
TABLE 6.6
EQUIPMENT COST EQUATIONS FOR WET LIMESTONE
PROCESS APPLIED TO SMALL INDUSTRIAL BOILERS
NA rT- 0.6 CT- 0.8
EC = I RBi [ 130 (§^) + 14.1 (f£i) J
+ 17.9 RP ()°'5 + 15.8 ()0'4 M$
S °'3 s 0.5
ES = 29.6 (-) + 17.4 (-) M$
p = 258 ()- M$
GP < 110 M ACFM
S £ 1000 Ibs/hr
Note; See Appendix J for Explanation of Symbols
94
-------
TABLE 6.7
EQUIPMENT COST EQUATIONS FOR WELLMAN/ALLIED
PROCESS APPLIED TO SMALL INDUSTRIAL BOILERS
NAT GT- 0.5 GTi °-6
EA = E RBj. [ 15.2 (i) + 46.1
- + 39.3 ()- ]
25.8 RP () + 20-7 () ' + 14-7 IF () ' MS
c 0.6 c O-7 c °-8
ES = 42.1 (T^-) + 39.6 (^J + 9.5 (y^r) M$
q 0.5 R °-8
EP = 54.7 (^r) + 28.2 (~) M$
ER = 51 (m) +26.6
GP i 110 M ACFM
S i 1000 Ibs/hr
Note: See Appendix J for Explanation of Symbols
95
-------
TABLE 6.8
WET LIMESTONE PROCESS AND COST MODEL
FOR INDUSTRIAL BOILERS
SUMMARY OF EQUATIONS
If GTi £ 110 M ACFM:
ECli = RBi [ 130 11Q M ACFM:
0-5
RT- '- PT. «.
i = *Bi C 1041 (ffj) + 408 (gj) ] NA M$
where GT
NA
then, for the plant, EC1 = E ECli M$
i=l
If GP S 110 M ACFM:
EC2 = 17.9 RP <§|)°'5 M$
If Gp > 110 M ACFM:
GP °-5
EC2 = 238 RP {^gj-J M$
If S s. 1000 Ibs/hr:
S 0.4
EC3 =15.8 (.) M$
ES = 29.6 (j)' + 17.4 (p)' M$
P » 258 (f^)0'6 M$
If S > 1000 Ibs/hr:
SF 0.5
EC3 = 201 () M$
op 0 9
ES = 1680 (1) ' M$
96
-------
= 5000
S
TABLE 6.8 (CONTINUED)
qp. T.p 0.9
where SF =
For the plant:
M$
EC
E
L
M
AL
AA
AW
AF
AE
ANR
BARC
TPI
AOC
WKC
STC
TCR
Tar
= EC1 + EC2 + EC3
= EC + ES
= 0.39 EC + 0.18 ES
= 0.82 EC + 0.09 ES
= 600 CL-LF (H)
= 0.43 CA (|^)
= 230 CW-LF [ ( Gj- ) + (§1) ]
= 1,800 CF-LF (^Ifl-g-)
= CE-LF [ 213 (33^0') + 35 (||o ]
=AL+AA+AW+AF+AE
= 1.15 (E + M) + (P + 1.43 L) F
= 1.12 (1.0 + CONTIN) BARC
= 0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR
=0.2 AOC
=0.2 AOC
= 1.135 TPI + WKC
STC + TCR -0.239 WKC -0.291 TPI
M$
M$
M$
M$
M$/yr
M$/yr
M$/yr
M?/yr
M$/yr
M$/yr
M$
M$
M$/yr
M$
M$
M$
MS/vr
97
-------
TABLE 6.9
WELLMAN/ALLIED PROCESS AND COST MODEL
FOR INDUSTRIAL BOILERS
SUMMARY OF EQUATIONS
If GT.^ < 110 M ACFM:
om. 0.5 Rm. 0.6 rjT • 0 .8
i = RBi [ 15.2 &•) + 46.1 (Sit) + 40.0 -GT"u-°
r"T> . 0.9
39.3 (i) ] M$
If GT^ > 110 M ACFM:
f^m . I PT1 • '
i [ 726 (j.) +639 (-) ] NAT M$
GP
where GT =
NAT
then, for the plant, EAl = EEAli M$
i
If GP < 110 M ACFM:
GP 0.5
EA2 = 25.8 RP {-) M$
If GP > 110 M ACFM:
GP °-5
EA2 = 119 RP (33^-) M$
If S < 1000 Ibs/hr:
S °-5 S °-6
EA3 =20.7 () + 14.7 IF (T~) M$
ES = 42.1 ()' + 39.6 ()' + 9'5 ()' M$
c 0.5 q 0 8
EP = 54.7 ( + 28.2 {J m° M$
q 0.7 c 0.8
ER = 51.0 () + 26.2 (-) M$
If S > 1000 Ibs/hr:
98
-------
TABLE 6.9 (CONTINUED)
'
EA3 = [ 133 (^ ' + 127 IF (^ ' ] N7
c-j 0 5 Q7 0.6 q7 0.9
ES = [ 209 (£1) + 618 (^y) + 157 (^-) ] N7
CQQ 0 5 c;?R 0.6 cog 0.7
EP = t 525 £ff) + 380 (S^f) + 86 <^f|)
+ 306 (^||) ' + 519 (£j|) ' ] N28
CF 0.5 SF 0.6 SF 0-9
ER = 998 (||) + 287 (||) + 683 (|^)
f, S S
where S7 1Q(io N? , fa^» 1000 N28 , =>r IQQ$
For the plant:
EA = EA1 + EA2 + EA3
E = EA + ES + EP + ER
L = 0.224 EA + 0.310 ES + 0.433 EP + 0.623 ER
M = 0.429 EA + 0.742 ES + 0.827 EP + 0.772 ER
AL =28.2 CS-LF (||)
cp
AN = 1460 CN-LF (||-)
GP
AFA = 1.24 CFA-LF-IF (y^)
AE = [ 154 (jjjffi) + 79 (||-) ] CE-LF
AH = 5430 CH-LF (||)
PD ctP
ACW = [ 856 (^Q) + 19,900 (|^) ] CCW-LF
AW = 64 (||-) CW-LF
AF = 1,800 (^iL-) CF-LF
M$
M$
M$
M$
M$
M$
M$
M$
M$/yr
M$/yr
M$/yr
M$/yr
M$/yr
M$/yr
M$/yr
M$/yr
99
-------
TABLE 6.9 (CONTINUED)
op
ASC =95.4 (||-) VSC-LF M$/yr
op
APS =37.3 (|^-) VPS-LF M$/yr
ANR = AS + AN + AFA + AE + AH + ACW + AW + AF - ASC -
APS M$/yr
BARC = 1.15 (E + M) + 1.43 L-F M$
TPI = 1.12 (1.0 + CONTIN) BARC M$
AOC = 0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR M$/yr
CRED = ASC + APS M$/yr
WKC =0.2 (AOC + CRED) M$
STC =0.2 {AOC + CRED) M$
TCR = 1.135 TPI + WKC M$
TAG = STC + TCR -0.239 WKC -0.291 TPI + AQC M$/yr
*5 • y 0 D
Note; See Appendix J for Explanation of Symbols
100
-------
TADLK e.in
SUHMARY O" STACK GAS SCRUBBI!!': COSTS By STATES
WET LIMESTONE PPOCESS APPLIED TO INDUSTRIAL BOIL"!" PLAMTS
NU.
SIAIt
LAHAL1IV
(MMBlU/HKJ
ALABAMA
ALASKA
AKIIUNA
AKKANbAil
LALUUkNlA
LUL'lKAU'J
LUNNEC1 1CUI
UtLAnAKL
HUKlUA
bLUKl.lA
HAxAll
IDAMU
1LL1NU1S
INDIANA
1(J»A
KANbAb
KtNIULKlf
UUUlblAN*
MAINE
MAKTLANU
nA!>»ALnJit 1 1
MICMlbAN
Mibalablffi
HlSbUUKl
MUNI ANA
NtVAUA
Nt» MAMPbHIH
Nt« JtKbL»
NLH MtXlLU
Ntrt YUhK
N. LAHULINA
NIIKIM UAKUlA
UH]U
UK LA MUM A
IJMLbUN
PtNNblfL VAN1A
KMUUt IbLANU
b. LANUL1NA
bLIUIH UAKUIA
Ih.NNtbbtt
lt«Ai>
Ul AH
Vt KMUNI
V 1 Nlj 1 Ml A
n A&nINU 1 UN
ft. VIHU-IMA
-IbLUNSIN
U. L.
b
u
U
U
1
i.
1
3
V
1 1
\d
o
u
ou
e,
u
1
u.
u.
u.
bU.
180.
108.
U.
7U/3.
11UU.
U.
u.
u.
U.
lb3U!.
5 J »
u.
33tt!
HHUUULIlUN
(nnblu/Hx)
bVdt>.
U.
U.
U.
bul
bu.
ILK
I AL
139.
U.
11 /6«.
Ib343.
U.
U.
U.
1 1 IdS.
3Db3.
U.
341.
0.
U.
0.
0.
81 10.
0.
U.
lbM7.
lObO.
B.
b7«B.
0.
Bl IB.
1^07.
U.
b/Bbi.
U.
U.
u.
lUVb.
lUlub.
U.
UU71 1.
u.
V!:.
u.
IKUbB.
U.
U.
blllu.
Bl'aiO.
33B03.
U.
13b3c!.
1003.
u.
u.
lOilB.
1813.
U.
U.
3b/3/.
1/ou.
lbUb3/.
U.
U.
Ilb3»
U.«S
U.U
1 m£0
U^bi
IAL
i»/MMB 1 U J
U.«0
U.U
0.0
U.U
I.o3
1 .BB
U.3B
U.lb
U.U
U.3b
0.1V
U.3b
U.U
0.80
U./l
U. /b
U.U
u. n
U.U
u.b/
U.U
1 .
-------
•"ABLE f. 11
SUMMARY OP STACK. GAS SCRUBBING COSTS BY STATES
NELLMAIVALLIED PROCESS APPLIED TO INDUSTRIAL BOILER
ALABAMA
ALAbKA
LAL^UNN 1 A
LULIJWAUO
LljNNtLIlLUl
UtLAKAHb
f-LUHJUA
MA VIA 1 1
1UAMU
ILLINOIS
1MU1ANA
1UMA
IVANSAb
IStMULM
LUUiSlAMA
MAINt
MAKTLANU
MAbSALMUStI I
HlLhlbAN
MlNNtSUIA
MSSUUhl
MUNI ANA
NtVADA
Nbw
Nt»
Nt«
N. IAHUL1NA
NUKIH UAMITA
UnlU
UKLArlUHA
UKtUUN
HfcNNS>LVANJA
KMUUb ISLANU
S. LAHULlNA
bUUlM liAKIIlA
ItNNtbbtL
ILXAb
Ul AH
VtMMUNI
VIKblNlA
KASHINI.IUN
•.. ViKblMA
•1SLUNSIN
* TUNING
U. L.
NL . UK
CLAM &
u
u
0
1
i
1
1
0
1 1
12
b
u
eU
°9
V
I f
u
*J
B9
be!
4<>
u
b
2
u
u
22
u
u
ub
u
u
11
IB
1
It!
u
2
/
u
5b
1
LAH4L1 1 T
IMMrttU/MH)
u.
u.
u.
bU.
IbU.
1UB.
1091.
u.
/U/l.
b3/0.
1*
U.U
U.bb
2.UU
1.11
U.Ob
U.U
1 .Id
U.7I
i AL
li/nno luj
U.lb
U.U
U.U
U.U
O.Vi
«!.U3
u.ll
u.u
0.49
u.b3
1.9 /
U.U
o.9«;
U.bb
U.U
0.9b
U.U
U.bl
U.U
l.l/
i.uu
1 .09
U.U
u. /b
U./3
U.U
U.U
1./2
-------
TABLE 6.12
COST SUMMARY FOR PACKAGED AND FIELD ERECTED
WET LIMESTONE SCRUBBING UNIT
(50 MM Btu/hr Industrial Boiler)
Total Capital Required
TCR,MS
Major Equipment
Chemical Process
Solid Handling
Field Labor
Chemical Process
Solid Handling
Other Materials
Chemical Process
Solid Handling
Settling Pond
M
° Bare Cost of Plant
Plant Investment
Interest During
Construction
Working Capital
Total Capital Required
Total Capital Required**
5/MM Btu/yr.
Syn ool
EC
ES
E
LC
LS
L
MC
MS
M
P
BARC
TPI
IDC
WKC
TCR
(End of
Field
Erected
781
173
9TT
640
16
656
305
31
3~3T
500
3350
3752
507
105
4364
9.96
74)
Packaged
Unit
402
113
5T5
280
66
346
233
114
347
500
2679
3000
405
88
3493
7.97
Total Annual Production Cost
TAG, M$/yr.
Raw Materials and Utilities*
Limestone
Ammonia
Process Water
Fuel Oil
Electricity
Number of Operators
Operating Labor & Superv.
Main. Labor & Superv.
Plant Supplies & Replmts .
Admin. & Overhead
Direct & Indirect Cost
Local Taxes and Ins.
Net Annual Opr. Cost
Start-up Cost
Depreciation, Return on
Investment, Federal Tax
Total Annual Production Cost
Total Annual Production Cost
Symbol
AL
AA
AW
AF
AE
ANR
TO
AOL
AML
APS
AOH
ATI
AOC
STC
(End of
Field
Erected
15.5
.2
.6
15.7
3.0
5
118
68
75
130
426
101
527
105
743
TAG 1375
74)
Packaged
Unit
15.5
.2
.6
15.7
3.0
35
5
118
54
60
120
387
54
441
88
592
1121
* Based on a load factor of 80%
** Based on a yearly capacity of 50x8760=430,000 MM Btu/yr.
$/MM Btu
3.94
3.21
-------
300
200
100
I? 80
W 60
3 40
w
K
20 ••
10 ..
^ 8
I 6
w
4 --
2 -.
FIGURE 6.1
AVERAGE TOTAL CAPITAL REQUIREMENT FOR
INSTALLING STACK GAS SCRUBBING IN
EXISTING POWER PLANTS
(MM$)
WET LIMESTONE
WELLMAN-LORD/ALLIED
H 1—h
-t-
10 20 40 60 100 200 400 4600 1000
PLANT SIZE, MW
2000 4000
104
-------
FIGURE 6.2
AVERAGE TOTAL CAPITAL REQUIREMENT FOR
INSTALLING STACK GAS SCRUBBING IN
EXISTING POWER PLANTS
($/KW)
EH
£
W
H
8
EH
H
o
o
EH
W
O
W
200 -r
100
80
GO ••
40 ..
20 ..
I 1 1 1—I 1 h
10 20 40 60 100 200 400 600
PLANT SIZE, MT-'
H 1—I-
H
1000
2000 3000
105
-------
FIGURE 6.3
AVERAGE ANNUAL PRODUCTION COST OF STACK
GAS SCRUBBING IN EXISTING POWER PLANTS
60
40
20 ..
O
U
2 10
O
H 8
U
§ 6
c
cu ,
!3
25
W
W
2 ..
WELL-'IAN-LORD/ALLIED
WET LIMESTONE
•4-
H—h
-t-
10 20 40 60 100 200
PLANT SIZE, MW
400 600 1000
2000
106
-------
O
U
W
P,
O
E-t
?s
w
*^<
1^-*
W
«
u
4 --
2 -•
10
FIGURE 6.4
INCREMENTAL OPERATING COST OF STACK GAS
SCRUBBING IN EXISTING POWER PLANTS
.WELLMAN-LORD/ALLIED
WET LIMESTONE
'20
-H-
40 60
H 1—H
-\ 1—I-
4-
100
200
400 600 1000
2000
4000
PLANT SIZE, MW
107
-------
FIGURE 6.5
MAXIMUM TOTAL CAPITAL REQUIREMENT FOR INSTALLING
STACK GAS SCRUBBING IN EXISTING POWER PLANTS
($/KW)
1000 T
P r' *"!
o ..• U
60:; -•
400
H
D
a
E-i
H
o
.-I
§
H
200
100 ..
40 -.
20 --
10
Capacity summed in order
of increasing $/KW
WET LIHEHTONE
WET LIMESTONE
WELLMAN-LORD/ALLIED
20
-t-
-1-
H
40 60 80 100
% OF PLANT CAPACITY UNDER CONTROL
108
-------
6.6
u
s
«
u
23
MAXIMUM If.CREMfNTAL OP I.: RATING COST Or STACK
GAS SCRUBBING Ui EXISTING POWER PLANTS
(MILLS/KWH)
40 _
3 20
LC
O
u 10
-3 --
2 --
Note: Production summed in ordor
of increasing Hills/KWH
WELLMA:J-LORD/ALI.I:T»
100
O/ TOTAL I'LANT rO\":R PRODUCTION CONTROLLED
109
-------
10,000 -,-
90,10 -
8010 -
13
H
W
ft
O
U
>
H
u
FIGURE 6.7
CUMULATIVE TOTAL CAPITAL REQUIREMENT
•'OR INSTALLING STACK GAS SCRUBBING IN
EXISTING POWER PLAIiTS
(SUMMATION IN ORDER OF INCREASING $/KW)
7000 .
£000 -
WELLHAN-LORD/ALLIED
WET LIMESTONE
H 5000
6
4UOO ''
3000
£000 - '
1000 --
20 40 60 80 100
% OF PLANT CAPACITY UNDER CONTROL
110
-------
FIGURE 6.8
CUMULATIVE TOTAL.CAPITAL REQUIREMENT FOR INSTALLING
STACK ;;A:' rCIUiBBING IN EXISTING POWER PLANTS
(SU.'IMATION IN ORDER 01" DECREASING PLANT SIZE)
10,000 _.
9000
8000 --
EH
2
W
g 7000
D
O
w
EH
H
u
EH
O
EH
W
•>
M
EH
6000 --
5000 --
4000 --
8 3000
2000 --
1000 "
.:-:ET LIMESTONE
WELLMAN-LO?.D/ALLIED.'
4-
40 CO 80 100
% OF I'LANT CAPACITY UNDER CONTROL
111
-------
CO-
5
10
O
U
2!
O
u
§
0,
D
2
1
W
FIGURE 6.9
CUMULATIVE ANNUAL PRODUCTION COST OF
STACK GAS SCRUBBING IN
EXISTING POWER PLANTS
(SUMMATION IN ORDER OF INCREASING MILLS/KWH)
3000 -T-
2000
M 1000
i
D
U
WELLMAN-LORD/ALLIED
.WET LIMESTONE
H
20 40 60 80 100
% OF TOTAL POWER PRODUCTION UNDER CONTROL
112
-------
[• IGURi: i). LO
CUMULATIVE ANNUAL PRODUCTION COST OF
STACK GAS SCRUBBING IN
EXISTING POWER PLANTS
(fiUWATTVJ IN ORDER OF DF.CRCAS ' NG PLANT POWER PRODUCTION)
(X
JH
X
O
U
M
EH
U
•J
Q
§
z
w
M
H
3
D
1000 "
Wf'LJ.MAU-LORiy ALLIED
WET LIMESTONE
0 20 40 60 80 100
P6 OF TOTAL POWER PRODUCTION UNDER CONTROL
113
-------
FIGUPF. 6.J.1
CUMULATIVE TOTSX CAPITAL REQUIREMENT FOR REDUCIIIG
SULFUR EMISSIONS FROM EXISTING POWER PLANTS
10,000
9000
8000
7000
Vi-
(X
<
u
s
MOTR: Summation in order of
increasing TCR(S)/Ton of
sulfur removed
6000
D 5000
C
4000
£ 3000
% 2000
1000
WET LIMESTONE
20
40 SO 8Q 100
% REDUCTION IN SULFUR EMISSIONS
114
-------
FIGURE fi.l,?
CUMULATI\7E ANNUAL PRODUCTION COST OF REDUCING
SULFUR EMISSIONS FROM EXISTING POSTER PLANTS
3000
to-
1
O
CJ
§
H
E-i
O
D
P
§
P;
S3
H
1000
NOTE: Sur-jnation in order of
5.ncre?.sinq TAC($)
of sulfur removed
T«TET LIMESTONE
20 40 60 80 100
% REDUCTION IN SULFUR EMISSIONS
115
-------
FIGURE O.L3
EFFECT OF ACID CONCENTRATION
ON SULFURIC ACID PRICE
7.
EH
\
in-
W
U
M
a
a
M
U
u
75 .80 .813 .90 .95
SUU-'URIC ACID CONCENTRATION (PLANT PRODUCT)
WEIQHT FRACTION
U
3
O
O
a
P.
116
-------
FIGURE 6.14
or PLAI:T PARAMETERS CM TOTAL CAPITAL REQUIREMENT
'\TI3LLMAN-LORD PROCESS APPLIED "TO SOLFCTRIC ACID'PLANTS
50 -r
50
BASTS OF CALCULATION
LOCATION FACTOR = 1
RrTROFIT FACTOR = 1
20 50 100 200
PLA::T CAPACITY, K TO::S oi' 100% ACID PFP V:~AP
500
1000
2000
G = GAG DISCHARGE, VAZI1 PrR TO" : 3V 103ft ACID PRODUCED
Sl= S02 co:-TTl::Ilr
J- CULFUR) , LB^ . PEP TO1I Or 100% ACID PRODUCED
-------
FIGURE 6.15
EFFECT OF PLANT PARAMETERS ON PPODUCTION COSTS—I
WELLMAN-LORD PROCESS APPLIED TO SULFURIC ACID PLANTS
00
20
10
Q
W
U
§
O
eu
E-
w Q
O M
u u
2
O *>
U »4
3
§fe
£!
to-
3A3IS OF CALCULATION
LOCATION FACTO3 = 1
RETROFIT FACTOR = 1
= 14
8 •
6 -•
4
3
2 ..
NOMENCLATURE
G = GAS DISCHARGE, MACF PER TON OF 100% ACID PRODUCED
Sx= SOn CONTENT (AS SULFUR), LBS. PER TON OF 100% ACID PRODUCED
S2= MIST CO.-ITENT (AS SULFUR), LBS. PER TON OF 100% ACID PRODUCED
G = 1D2
20 50 100 200
PLANT CAPACITY, M TON'S OF 100% ACID PER YEAR
500
1000
2000
-------
-FIGURE 6.16
EIFFCT OF PLA\'T PARAMETERS ON PRODUCTION COSTS - II
UELKIA-.-LORD J'ROCLSS APPLIED TO SULPURIC ACID PLANTS
BASIS OF CALCULA-T^:i
LOCATION FACTO^ = 1
RETROFIT FACTOR = 1
20 ...
w
O
g
EH CM
CO
O Q
U M
M <*>
H O
U O
10
20
G = GA" DISCHARGE, MACF PER TON OF 100% ACID PRODUCED
Sl= °°2 COHTEKT
-------
FIGURE 6.17
AVERAGE TOTAL CAPITAL REQUIREMENT FOR
INSTALLING WELLMAN-LORD STACK GAS SCRUBBING
IN EXISTING SULFURIC ACID PLANTS
(MM$)
20 ,-
10 - -
Z
W
B
u
cu
<
u
El
o
u
u
10
100
PLANT CAPACITY,
M TONS OF 100% ACID PER YEAR
1000
120
-------
FIGURE 6.18
AVERSE TOTAL CAPITAL REQUIREMENT FOR INSTALLING
WELLMAN-LORD STACK GAS SCRUBBING IN EXISTING StJLFURIC ACID PLANTS
of JVNNUAI, loos ACID CAPACITY)
so --
o
40- --
10
30 . -
20 -
10 •-
-4-
4-
4-
10
20 50 100 200 500
PLANT CAPACITY, M TONS OF 100% ACID PER YEAR
1000
2000
-------
(A
O
u
o o
Z M
M CJ
W O
(Xi O
O .H
EIGURE 6.19
INCREMENTAL OPERATING COST OF WELLMAN-LORD STACK
GAS SCRUBBING IN EXISTING SULFURIC ACID PLANTS
10 20 50 100 200
PLANT CAPACITY, M TONS OF 100% ACID PER YEAR
500
1000
2000
-------
2 H
W U
H U
a
O Q
H H
S u
frH O
H O
<
tt
i ^
FIGURE 6.20
MAXIMUM TOTAL CAPITAL REQUIREMENT FOR
INSTALLING WELLMAN-LORD STACK GAS SCRUBBING
IN EXISTING SULFURIC ACID PLANTS
($/TON OF ANNUAL 100% ACID CAPACITY)
80
70
60
50
40
30
20
10
0
0
4-
10 20 30 40 50 60 70 80 90
% OF PLANT CAPACITY UNDER CONTROL
100
123
-------
FIGURE 6.21
MAXIMUM INCREMENTAL OPERATING COST OF WELLMAN-LORD
STACK GAS SCRUBBING IN EXISTING SULFURIC ACID PLANTS
Q
H
dP
O
o
z
8
O
U
2
H
21 ,-
20 - -
($/TON OF 100% ACID)
Note: Production
summed in ofder
of increasing
$/ton of acid.
4-
0 10 20 30 40 50 60 70 80 90 100
% OF TOTAL PLANT PRODUCTION CONTROLLED
124
-------
FIGURE 6.22
CUMULATIVE TOTAL CAPITAL REQUIREMENT FOR
INSTALLING WELLMAN-LORD STACK GAS SCRUBBING IN
EXISTING SULFURIC ACID PLANTS
800 T-
700 -
600 •-
IE 500 ' -
EH
Z
W
T,
§ 400 •-
D
O
g
H
8!
u
8
H
>
H
§
D
U
300 •-
200 -
100
0 10 20 30 40 50 60 70 80 90 100
% OF PLAIJT CAPACITY UNDER CONTROL
125
-------
W
§
H
EH
U
g
§
W
M
§
D
U
FIGURE 6.23
CUMULATIVE ANNUAL PRODUCTION COST OF
HELLMAN-LORD STACK GAS SCRUBBING
IN EXISTING SULFURIC ACID PLANTS
220 r
210
200
J.90
180
170
160
150
140
130
120
110
100
90
80
70
60
50
40
30
20
1ft
4-
+
•4 1 1-
-I
0 10 20 30 40 50 60 70 80 90 100
% OF TOTAL PLANT PRODUCTION UNDER CONTROL
126
-------
FIGURE 6.24
CUMULATIVE TOTAL CAPITAL REQUIREMENT FOR REDUCING
SULFUR EMISSIONS FROM EXISTING SULFURIC
ACID PLANTS-WELLMAN-LORD PROCESS
EH
z
D
O
g
H
EH
O
EH
W
1
800 -r-
700 •-
600 •-
500 •-
400 .-
300 --
200 •-
100 '-
Summation in order of
increasing TCR(S)/ton
per year of sulfur
removed
-I \-
4-
•4-
-I
0 10 20 30 40 50 60 70 80 90 100
% REDUCTION IN SULFUR EMISSIONS
127
-------
FIGURE 6.25
CUMULATIVE ANNUAL PRODUCTION COST OF REDUCING SULFUR
EMISSIONS FROM EXISTING SULFURIC ACID PLANTS —
WELLMAN-LORD PROCESS
220 i-
w
O
O
i
H
u
g
§
ft
g
H
H
§
D
U
Summation in order of
increasing TAC($)/ton
of sulfur removed
i—i—i—i
10 20 30 40 50 60 70 80 90 100
% REDUCTION IN SULFUR EMISSIONS
128
-------
w
200 -r
160
80
60 --
40 ..
!Z
W
S
H
D
O
3
2
fH
H
U
jjj
o
^
w
20
10
8
6
4
2 ..
40
FIGURE 6.26
AVERAGE TOTAL CAPITAL REQUIREMENT
FOR INSTALLING STACK GAS SCRUBBING
IN EXISTING INDUSTRIAL BOILER PLANTS
(MM$)
-J 1—I-
4-
-4-
H—^—I
60
100
200
400 600 1000 2000
4000
10,000
PLANT CAPACITY, MMBTU/HR
129
-------
U)
o
OS
>«
3
z§
£
4.8 -r
4.4
1.0
3.6
3.2
M 2.8
D
O
* 2.4
I
£ 2.0
1.6
1.2
0.8
0.4
40
60
FIGURE 6.27
AVERAGE TOTAL CAPITAL REQUIREMENT
FOR INSTALLING STACK GAS SCRUBBING
IN EXISTING INDUSTRIAL BOILER PLANTS
($/MMBTU/YR)
WELLMAN/ALLIED
WET LIMESTONE
-I h
4-
H h
100
200 400 600 1000
PLANT CAPACITY, MMBTU/HR
2000
•4-
H h
4000
10,000
-------
FIGURE 6.28
AVERAGE ANNUAL PRODUCTION COST OF STACK
GAS SCRUBBING IN EXISTING INDUSTRIAL BOILER PLANTS
rt
x
H
to
O
U
53
O
U
D
Q
2
a.
D
2
W
*i
30 ^
20 ..
10
8
6 --
4 ..
2 ..
1
0.8
0.6
0.4
9.2
H-
40 60
h
100 200 400 600 1000 2000
PLANT CAPACITY, MMBTU/HR
4000
10,000
131
-------
FIGURE 6.29
INCREMENTAL OPERATING COST OF STACK GAS
SCRUBBING IN EXISTING INDBSTRIAL BOILER PLANTS
WELLMAN/ALLIED
60
100
200 400 600 1000
PLANT CAPACITY, MMBTU/HR
2000
H 1
4000 6000
-------
u>
u>
D
§
H
D
I
H
a
8 ^_
7 --
6 - -
5 - -
4 - -
FIGURE 6.30
MAXIMUM TOTAL CAPITAL REQUIREMENT FOR INSTALLING
STACK GAS SCRUBBING IN EXISTING INDUSTRIAL BOILER PT.
($/MMBTU/YR)
NOTE: Capacity summed in order of
increasing $/MMBTU/YR
W^TLLMAN/ALLIED
WET LIMESTONE
10
20
30 40 50 60
% OF PLANT CAPACITY UNDER CONTROL
70
80
100
-------
FIGURE 6.31
ui
O
u
2;
M
I
u
IX
O
u
2
r
D
X
CO ,
40
?0 . .
10
8
4 '
2 ..
1
0.8
o. 6
0.4 -.
0.2 - -
0.1
MAXIMUM INCREMENTAL OPERATING COST OF
STACK GAS SCRUBBING TN EXISTING TN-
nUSTRIAL BOILER PLANTS
($/MMBTU)
NOTE: Production summed in order
of increasing $/MMBTU
WET LIMESTONE
20 40 60 80
% OF TOTAL PLANT PRODUCTION UNDER CONTROL
134
100
-------
FIGURE 6.32
CUMULATIVE TOTAL CAPITAL REQUIREMENT FOR INSTALLING
STACK GAS SCRUBBING IN EXISTING INDUSTRIAL BOILER PLANTS
(SUMMATION IN ORDER OF INCREASING $/M.MBTU/YR)
3800 -,-
WET LIMESTONE
20
40 fiO 80 100
% OF PLANT CAPACITY UJIDEP CONTROL
135
-------
FIGURE f..33
CUMULATIVE TOTAL CJU>ITAL REQUIREMENT FOR
INSTALLING STACK GAS SCRUBBING TN
EXISTING INDUSTRIAL BOILER PLANTS
(SUW1ATION IN ORDER OF DfCREASING PLANT SIZE)
4000 _^
3600 --
3200 --
2800 --
2400 ..
2000 --
1600 --
1200 ..
ROO --
400 --
WELLMAN/ALLIED
WET LIMESTONE
±
±
20 40 £0 $0
% OF PLANT CAPACITY UNDER CONTROL
136
-------
FIGURE 6.34
CUMULATIVE ANNUAL PRODUCTION COST OF STACK GAS
SCRUBBING IN EXISTING INDUSTRIAL BOILER PLANTS
(SUMMATION IN ORDER OF INCREASING $/MMBTU)
PC
I
o
u
§
u
8
D
12
H
>
H
u
1000 --
?oo ..
800
700 --
600 - -
500 _.
400
3T1 - -
200
100 --
20 40 60 '"0 100
OF TOTAL PLANT P^PUCTION U?TDF.R CONTROL
137
-------
FIGURE 6.35
CUMULATIVE ANNUAL PRODUCTION COST OF STACK GAS
SCRUBBING IN EXISTING INDUSTRIAL BOILER PLANTS
(SUMMATION IN ORDER OF DECRHSING PLANT PRODUCTION)
1100 __
1000 ..
900 .-
800 --
700 --
600 —
500 --
400 . .
300
200 . .
T<7ET LIMESTONE
H
20 40 60 80 100
% OF TOTAL PLANT PRODUCTION UNDER CONTROL
138
-------
j3 0.36
CUMULATIVE TOTAL CAPITAL RF.OUIREMENT FOR r
SULFUP EMISSIONS FRO'' EXISTTIfi PTDnSTT'IAL BOILED PLANTS
o
h!
8-
u
d
£
M
fr-
1T7TF: rUTnmation in order of
.increasing TC^CS) /'"On oer
of
-------
FIGBBE 6.37
CUMULATIVE ANNUAL PRODUCTION COST OF REDUCING
SULFUR EMISSIONS FROM EXISTING INDUSTRIAL BOILER PLANTS
1100 T
1000 "
900 --
800 ..
(A
8
H
E-.
U
Q
S
i
D
U
700 --
600 ..
500 --
400 _.
300 --
200 ..
100 --
WET LIMESTONE
Summation in order of increasing
TAGCSI/Ton o? sulfur removed
f
20 40 60 flO 100
% REDUCTION IN SULFUR EMISSIONS
140
-------
FIGURE B.3C
PACKAGED LIMESTONE SYSTEM FOR 50 MMBTO/KR INDUSTRIAL BOILER
OVERALL PLOT PLAN
160-
-\
LIMESTOHE STORAGE PILE
NOTE; SEE APPENDIX f FOR
EQUIPMENT DBSCRTPTIOS
LIMESTONE HANDLING AMD SLgRRg PTEPABATIXOT SECTION
106-L
101-V
105-F
o Q
o
0 fl i«-f
^f*' 104-P
0
D
DDo
106-L
101-F
1Q1-E
102-L
oa oo
Oo
^ 117-P
ion-B
10B-F
107-P
OUILET
GAS
DUCT
O
OO-F
100-E
INLET
GAS
DUCT
113-.T
108'
SCRUBBING SECTION
-------
FIGURE 6.31
PACXATCD LIMES-XCIIT SYSTEM FOR 50 MMBTU/HR IMOOSTRIAL BO HER
ARRANGEMENT OF SCRUBSDIR SECTION
69'
108-F
OUTLET GAS DUCT
o
107-F
1Q1-F
n
52'
100-F
O 5
110-F
O
100-B
INLET GAS DUCT {
113-J
7X
,
fti
C
H
1
101-E
n FI
PLfltl
VIEW
100-E
102-F
NOTE: SEE APPENDIX F FOR
EQUIPMENT DESCRIPTION
m-* PI n n
101-E
7
74'
109-F
n n
ELEVATION
SIDE VIEW
-------
7. COST OF FUEL CONVERSION
7.1 Costs of Mine Mouth Coal
Coal costs have been determined on the basis of sulfur con-
tent of coal. Average sulfur content of coal has been deter-
mined from coal analyses for various coals in a state 0.4).
Coal cost based on this average sulfur content has been
compared with the average purchase price of coal in a state
(6 ). The two costs matched closely in all cases with the
exception of the states of Illinois and West Virginia. Thus,
it is generally justified to conclude that the coal mined
was consumed within the state. If it is assumed that trans-
portation charges within a state are relativelv small com-
pared to the coal cost, it is reasonable to infer that the
average purchase price in a state approximates the mine-
mouth cost of coal.
The average price paid for all purchases in the year 1973 for
coal mined in Alabama was $12.80/ton. The average sulfur
content of coal in Alabama was determined to be 1.5% (14).
For coal with a sulfur content from 1.5 to 2%, the price-
paid was $12.9I/ton. Therefore, a coal having a sulfur con-
tent of 1.5 - 2% was chosen as representative and an aver-
age price of $12.80/ton was used as the mine-mouth price.
There was similar agreement in prices in the case of all
states other than the ones described below.
In Illinois, 70% of the coal purchased contained over 2%
sulfur and about 24% of the coal had less than 0.5% sulfur.
As there are no known deposits of low sulfur coal in Illinois,
it is evident that the coal was imported from out of state
sources. In this case, the coal cost has been taken as the
average cost for coal containing more than 2% sulfur. There
143
-------
is substantial deviation between the average price of coal
and the price based on sulfur content in the rase of West
Virginia. The purchase price of coal in the 2-3% sulfur
range has been used for calculation of SNG and SPC costs in
that state.
Based on the average sulfur content, coal costs for different
coal producing states have been obtained from published
sources C6 1 and are presented in Table No. 7.1.
144
-------
7.2 Costs of Mine-Ttouth SNG
The cost of production of SNG varies from $1.14/TPlRt:u in
Texas to $2.67/MMBtu in Virginia,corresponding to coal costs
of $1.90/ton and S25.61/ton respectively The cost of pro-
duction of SNG is the highest in several eastern states
(Ohio, Pennsylvania, Virginia and West Virginia), ranging
from $2.00/MMBtu to $2.70/RMBtu. This is due to higher coal
and labor costs. The cost of SNG production in several
western states (Colorado, Montana, New Mexico and Wyoming)
is low due to the availability of inexpensive coal, and
ranges from $1.25/MMBtu to ftl.60/MMBtu. Costs in some mid-
western (Illinois, Indiana and Missouri) and southern
(Alabama, Kentucky and Tennessee) states would represent
costs closer to the average cost and varv from S1.65/MMBtu
to $1.95/MMBtu.
The cost of producing SNG was found to be the lowest in
Texas due to availability of the least expensive coal and
to lower labor costs. Virginia coal is the most expensive
and results in the highest SNG cost.
The procedure to evaluate total annual cost of production
is shown in the General Cost Model in appendix r. A sample
calculation of the cost of SNG is given in appendix G.
145
-------
7.3 Cost Model for Production of Intermediate Btu ftas
q
The model represents a plant producing 125 x 10' Rtu/day
of intermediate Btu gas having a higher heating value of
323 Btu/SCF (dry).
7.3.1 Electric Power and High Pressure Steam Require-
ments for the Intermediate Btu Gas Plant
1. In this model all drivers are powered by electri-
city. The total power requirement for the plant is
about 63 MW.
2. Steam generated during waste heat recovery produces
about 18 MW power.
3. Intermediate Btu gas, after sulfur removal, is ex-
panded in two stages to produce about 45 MW cower, f^as
is re-heated by hot crude gas in between the expansion
stages.
4. Steam reauired for process units is produced partly
during the cooling of. crude gas from the gasifier, and
partly in the Glaus plant.
5. About 10% of the 550 psig steam required for gas-
ification is generated in the gasifier jacket and the
remainder is obtained by burning tar and tar oils in
a boiler.
7.3.2 Major Equipment Costs, E
The intermediate Btu gas plant has been divided into the
following 10 sections.
146
-------
Section Solid Handling
Number Chemical Processing (C) Unit
1 S Coal Preparation and Handling
2 S Fines Agglomeration
3 S Coal Gasification
4 C Gas Cooling
5 C Gas Purification by Benfield
Process
6 C Oxygen Plant
7 C The Phenosolvan Unit
8 C Sulfur Recovery - Claus Plant
9 C The Utility Plant
10 C Other Offsites
Equipment costs have been develooed using published
data and in-house information (5,9). Costs are for end
of 1973 and for a U.S. Gulf Coast location. Section No. 1,
2, 3, 6, 7 and 9 are similar to SNG plant and are described
in detail in Part 1 of this study.
Section 1 - Coal Preparation and Handling
Raw coal from storage is crushed and classified in this
section. No variations in E have been determined, with
the coal type.
El = 1250 M s
Section 2 - Fines Agglomeration
Coal flow to the fines agalomeration unit decreases as
the carbon content of coal increases.
E2 = 2560-50 (PCARB-65) M $
147
-------
Section 3 - Coa^- Gasification
The number of gasifiers required depends on the cmantity
of the coal feed, the slagging properties of the coal
and the reactivity of the coal.
E3 = 6410 + 70 CPCARB-65) M S
Section 4 - Gas Cooling
The crude gas from the gasifier is cooled before sending
it to the gas purification unit. No significant vari-
ations in cost could be determined with the carbon con-
tent.
E4 = 800 M $
Section 5 - Gas Purification by the Ben'field Process
This unit selectively removes H2S from the gas. H^S
is removed to the extent of meeting emission standards.
Gas purification is not required for low sulfur coals.
The increase in cost with increase in sulfur content
of coal is not significant.
E5 = 1400 M $
Section 6 - Oxygen Plant
The oxygen requirements for the gasifier increase with
increasing carbon content of the coal.
E6 = 4960 + 80 (PCARB-65) M $
148
-------
Section 7 - The Phenosolvan Unit
This unit handles all the gas liouor which has been
condensed. Here, the main objective is to recover
nhenol and tars.
E7 = 920 M $
Section 8 - Sulfur Recovery in Claus Plant
Here H2S removed during gas purification is converted
to elemental sulfur. It has been assumed that 80% of
the sulfur in coal is recovered as elemental sulfur.
There is an increase in cost as the sulfur content of
coal increases. The sulfur recovery plant is not re-
quired for low sulfur coals.
E8 = 280 (TDAFC • PSULFl°*6 + 90 PSUL*1 - 200 M S
where PSULF is the nercentage sulfur in coal on a dry
ash free basis.
Section 9 - The Utility Plant
The utility plant supplies power and generates steam for
the qasifiers. The boiler plant increases in size as
the carbon content of coal increases. The rest of the
unit has been assumed to be independent of the coal
type and has a major equipment cost of 4600 M$.
E9 = 7500 + 60 (PCARB-65) M S
Section 10 - Other Offsites
This includes storage facilities, service systems, elec-
149
-------
trical distribution, sewers and waste disposal, site
^reparation, plant huildinas and mobile equipment.
E10 = 5500 M $
7.3.3 Total Capital Requirement and Net Annual Operating Cost
The Total Plant Investment has been derived from the
cost of major equioment. "he Total Canital Require-
ment and the Net .Annual Production Tost are calculated
using the procedures of the General Cost Model, which
is fully explained in Appendix C.
7.3.4 Annual Raw Material Requirements
The total dry ash free coal requirement (TDAFC) of a
125
bv:
125 x 109 Btu/day intermediate Btu gas plant is qiven
TDAFC = 0.651 - 0.0067 (PCARB-65) million Ib/hr
9
The total "as received coal" requirement of a 125 x 10"
Btu/day intermediate Btu gas plant is given by:
TCOAL = 100 TDAFC/ QOQ.-PH2.0-PASH.) million Ib/hr
where PH20 and PASH are the moisture and ash contents
of coal respectively.
The annual cost of raw materials less by product credits
is given by:
ANR = ACOAL + ACHEM - ASULF
150
-------
The annual cost of catalysts and chemicals, ACHF.M, is
assumed constant at 400 J1$.
The annual cost of the coal feed to the plant, ACOAL,
is given by:
ACOAL =12 CCOAL'TCOAL-SD
where CCOAL is the unit cost of coal as received at the
site in i?/ton and SD is the number of days the plant is
on stream per year.
The credit per year for the sale of sulfur, ASUL^, is
given by:
ASULF =0.1 CSULF-TDAFC-PSULF-SD Mfi/yr.
where CSULF is the unit credit for sulfur in S/ton.
It has been assumed that 80% of the sulfur in the coal
feed to the plant is recovered.
The total number of shift operators for the intermediate
Btu gas plant can be assumed to be 150.
An example is provided in appendix H to illustrate cost
calculations from the model.
Figures 7.4 and 7.5 illustrate the effects of change
in carbon and sulfur content of coal on the car>ital
and production costs. Figure 7.6 shows the effect of
location factor on the costs of production.
151
-------
7.4 Cost Model for Production of Low Btu Gas
g
This model represents a plant producing 125 x 10 Btu/day
of low Btu eras havinq a higher heating value of 196 Btu/SC^
(dry).
7.4.1 Electric Power and High Pressure Steam Require-
ment^for the Low Bfru Gas Plant
1. In this model all drivers are powered by electricity.
The total power requirement for the plant is about 16 MW.
2. Low Btu gas after sulfur removal is expanded in two
stages to produce about 62 MW power. Purified low Btu gas
is re-heated by hot crude gas between expansion stages.
3. Steam required for the coal gasifiers is produced by
burning tar and tar oils in a boiler. About 25% of the
gasifier steam is generated in the gasifier jacket.
4. Steam required for process units is obtained from
the tar fired boiler and from the Glaus plant.
5. About 46 MW net power is available from the plant.
7.4.2 Major Equipment Costs, E
The low Btu gas plant has been divided into the following
10 units:
Section Solid Handlinq (S)
Number Chemical Handling (C) Unit
1 S Coal Preparation and Handlinq
2 S T'ines Agglomeration
3 S Coal Gasification
152
-------
Section Solid Handling CS1
Number Chenical Handling CCI Unit
4 C Gas Cooling
5 C Gas Purification bv Benfield Process
6 C Air Compression
7 C The Phenosolvan Unit
8 C Sulfur Recovery Claus Plant
9 C The Utility Plant
10 C Other Offsites
g
The major equipment costs for a 125 x 10 Btu/day low
Btu gas plant are:
Section 1 - Coal Preparation and Handling
Raw coal from storage is crushed and classified in this
section. No variations in E have been determined with
the coal type.
El = 1300 M S
Section 2 - Fines Agglomeration
The coal flow to the fines agglomeration unit decreases
as the carbon content of coal increases.
E2 = 2640 - 50 (PCARB-651 M $
Section 3 - Coal Gasification
The number of gasifiers required depends on the quantity
of the coal feed, the slagging properties of the coal and
the reactivity of the coal.
E3 = 6900 + 80 (PCARB-65J M $
153
-------
Section 4 - ftas Cooling
The crude gas from gasifier is cooled before gas purifi-
cation in the Benfield system. There is no change in
cost with variation in the carbon content of the coal.
E4 =700 M $
Section 5 - Gas Purification by the Denfield Process
This unit removes H2S selectively from the gas to the
extent of meeting the allowable emission standards. Gas
purification is not required for the gas produced from
low sulfur coal. The increase in cost is not signifi-
cant as the sulfur content of the coal increases.
E5 = 1780 M $
Section 6 - The Phenosolvan Unit
This unit handles all the gas liquor which has condensed.
Here, the main objective is to recover uhenol and tars.
No significant cost variations could be determined in
general terms.
E6 =950 M $
Section 7 - Sulfur Recovery by Claus" Flant
H-S removed during the purification of gas by the Benfield
process is converted to elemental sulfur. It has been
assumed that 80% of the sulfur in coal is recovered as
elemental sulfur. There is an increase in the equip-
ment cost as the sulfur content of coal increases. How-
ever, for low sulfur coals the sulfur recovery plant is
154
-------
not required.
E7 = 290 (TDAFC-PSULF)0'6 + 100 PSUL* - 210 MS
where PSULF is percentage of sulfur in dry ash free coal.
Section 8 - The Utility Plant
The utility plant supplies power and steam to the plant.
Power is generated by expansion of the purified gas in
two stages. Steam is raised in a tar-fired boiler.
The boiler plant increases in size as the carbon content
of coal increases. The rest of the unit is assumed to
be independent of the coal type and has a manor equip-
ment cost of 3600 M$.
E8 = 5640 + 50 (PCARB-65) M $
Section 9 - Air Compressors
In this section air required for gasification is com-
pressed to 320 psig. There is a slight increase in
cost as the carbon content of coal increases.
E9 = 850 + 20 (PCARB-65) M S
Section 10 - Other Offsites
This includes storage facilities, service systems,
electrical distribution, sewers and waste disposal, site
preparation, plant buildings, and mobile equipment.
E10 = 6000 M $
155
-------
7.4.3 Total Capital Requirement and Net Operating Cost
This model conforms exactly to the format in the General
Cost Model, which is fully explained in Appendix C. The
Total Plant Investment has been derived from the cost of
major equipment. The Total Capital Requirement and ^he
Net Annual Production Cost are calculated using the nro-
cedures of the General Cost Model.
7.4.4 Annual Raw Material Requirements
The total dry ash free coal requirement (TDAFC} of a
Q
125 x 10 Btu/day low Btu gas plant is:
TDAFC = 0.683 - 0.0071 (PCARB-651 million Ib/hr.
9
The total "as received coal" reauirement of a 125 x 10
Btu/day low Btu gas plant is given by:
TCOAL = 100 TDAFC/(inO-PH20-PASH.) million Ib/hr.
where PH7.0 and PASH are the moisture and ash contents of
coal respectively.
The annual cost of raw materials less by product credits
is given by:
ANR = ACOAL + ACHEM - ASULF - APOWER.
The annual cost of raw materials and chemicals, ACHEM, is
assumed constant at 420 M$.
The annual cost of the coal feed to the plant, ACOAL, is
156
-------
given by:
ACOAL =12 CCOAL-TCOAL'SP M$/vr.
where CCOAL is the unit cost of coal as received at the
site in $/ton and SH is the number of days the plant is
on stream per year.
The credit per year for the sale of sulfur, ASULF, is
given by:
ASULF = 0.1 CSULF'TDAFOPSULF-SD M$/yr
where CSULF is the unit credit for sulfur in $/ton. It
has been assumed that 80% of the sulfur in the coal feed
to the plant is recovered.
APOWER is the annual credit for power available for sale
and is given by:
APOWER = 1.1 x CPOWER x SD MS
where CPOWER is the cost of power in mills/KWH.
The total number of shift operators for the low Btu gas
plant can be assumed to be 150.
An example is provided in apnendix I to illustrate cost
calculations from the model.
Figures 7.8 and 7.9 illustrate the effects of change in
carbon and sulfur content of coal on the capital and
production costs. Figure 7.10 shows the effect of lo-
cation factor on the cost of production.
157
-------
7.5 Cost of Minfe-Mouth. SRC
Costs have been calculated based on the following assumptions:
1. 80% of the coal is converted to SRC on a Btu basis.
9
2. The amount of cresvlic acid produced from a 250 x 10
Btu/day SRC plant is constant at 170 Tons/day.
3. 40% of the sulfur present in the coal is recovered as by-
product sulfur.
SRC costs have not been determined for the states of-Colorado,
Montana, New Mexico, Virginia and Wyoming. Most of the coal
mined in these states contains less than 1% sulfur and it is
more practical to burn these low sulfur coals in existing coal
fired boilers. On the basis of cost oer MMBtu, SRC costs are
55-60% of SNG costs. SRC costs for various locations are
plotted on the map (Fig. 7.11) and tabulated in Table 7.1.
The procedure to evaluate total annual cost of production of
SRC is shown in the General Cost Model in appendix C. A
sample calculation of the cost of SRC is given in appendix G.
158
-------
Table 7.1
Mine-Mouth Cost of Coal, SNG, and SRC
State
Alabama
Colorado
Illinois
Indiana
Kentucky
Missouri
Montana
New Mexico
North Dakota
Ohio
Pennsylvania
Tennessee
Texas
Virginia
West Virginia
Wyoming
Coal, $/ton
12.80
7.21
8.64
8.49
11.49
7.66
3.73
3.36
2.26
14.43
15.05
9.18
1.90
25.61
11.48
3.30
SNG, $/MM BTU
1.87
1.58
1.85
1.97
1.88
1.81
1.43
1.29
1.29
2.22
2.21
1.69
1.15
2.69
2.03
1.27
SRC, $/MM BTU
1.11
-
1.06
1.15
1.10
1.00
-
-
0.73
1.31
1.31
0.96
0.64
-
1.18
-
159
-------
FIGURE 7.1
MINE-MOUTH COST OF COAL
( S /' ton )
-------
FIGURE 7.2
COST OF PRODUCTION OF SNG
($/MM Btu)
-------
FIGURE 7.3
INTERMEDIATE BTU GAS PROCESS FLOW DIAGRAM
m
to
GAS
COOLING
HEAT
RECOVERY^
SULFUR
»- 125 X 10 BTU/DAY
INTERMEDIATE BTU
GAS
-------
FIGURE 7.4
EFFECT OF CARBON CONTENT OF COAL ON
INTERMEDIATE BTU GAS CAPITAL COST
170 T
160 -.
150
•OT-
130 _.
O
U
120 _.
110 _.
% SULFUR DAFB
6%
COST, $
COAL COST
% SULFUR DAFB
6%
4%
2%
0%
65
70 75
% CARBON DAFB
SO
85
TOT.Mi CAPITAL
REQUIRED
TOTAL PLANT
INVESTMENT
163
-------
W
O
U
H
EH
U
D
C
FIGURE 7.5
EFFECT OF CARBON CONTENT OF COAL ON INTERMEDIATE
BTU «AS PRODUCTION COST
1.6 -
1.5 .
1.4 -
1.3 -.
1.2
1.1
60
COAL COST
S/TON 12
% SULFUR DAFB
6%
2%
COAL COST
S/TOJI 8
% SULFUR DAFB
6%
65
70
75
80
% CARBON DAFB
164
-------
FIGURE 7.6
EFFECT OF LOCATION FACTOR ON INTERMEDIATE BfU -
PRODUCTION COST
BITUMINOUS COAL: CAR30H
SULFUR
ASH
R4% DAFB
2% DATS
7%
6%
M
8
§
H
fri
B
0
1.6 ..
1.5 -
1.4 _:
1.3 -,
1.2 .
1.1 ..
COAL COST, $/TON
12
1 0 1.2 1.4 1.6 1.8
LOCATION FACTOR
2'.0
165
-------
FIGURE 7.7
LOW BTU GAS PROCESS FLOW DIAGRAM
a\
125 x 10 BTU/DAY
BTU GAS
-------
F. 7.R
EFFECT OF CARBON CONTENT OF COAL ON LOW BTU
CAPITAL COS"1
130 _.
121 __
110 ._
100 - -
E-.
ui
8
90 --
COAL COST, $/TOII
1?.
6%
2%
6%
TOTAL CAPITAL
WJTJIRED
6%
4%
2%
TOTAL PLANT
70
75
80
n^FB
R5
167
-------
I
M-
g
H
FIGURE 7.9
EFFECT OF CARBON CONTHBT O*1 COAL ON
I/DW BTU GAS PRODUCTION COST
1.6 _
1.5 _.
$12/TOM
1.4 _.
% SULFUR P^FB
t*
8%
1.2 _.
COM. COST
$8/TON
1.1 -•
€%
0%
65
75
% CARBON DAFB
168
-------
*ir-urr, 7. in
EFFECT OF LOCATION
-------
-J
o
FIGURE 7.11
COST OF PRODUCTION OF SRC
($/MM Btu)
-------
8. REFERENCES
1. Brink, Jr., J. A., Burggrabe, W. F., and Greenwell,
L. E., "Mist Eliminators for Sulfuric Acid Plants",
Chemical Engineering Progress, Vol. 64, No. 11, pg.
82, November, 1968.
2. Brink, Jr., J. A., Burggrabe, U. F., and Rauscher, J. A.,
"Fiber Mist Eliminators for Higher Velocities", Chemical
Engineering Progress, Vol. 60, No. 11, pg. 68, Novem-
ber, 1964.
3. Catalytic, Incorporated, "A Process Cost Estimate for
Limestone Slurry Scrubbing of Flue Gas", Parts I and II,
prepared for the Office of Research and Monitoring,
U.S. Environmental Protection Agency, Contract No.
68-02-0241, January, 1973.
4. Chemical Construction Corporation, "Engineering Analysis
of Emissions Control Technology for Sulfuric Acid
Manufacturing Processes", prepared for Division of
Process Control Engineering, National Air Pollution
Control Administration, Contract No. CPA 22-69-81,
March, 1970.
5. El Paso Natural Gas Company, "Application to the Federal
Power Commission for Burham Coal Gasification Complex
in New Mexico", November 7/1972.
6. Federal Power Commission News, February, 1974.
7. Guthrie, K. M., "Data and Techniques for Preliminary
Capital Cost Estimating", Chemical Engineering, Vol.
76, No. 6, pg. 114, March, 1969.
8. Holland, F. A. Watson, F. A., and Wilkinson, J. K.,
"Capital Costs and Depreciation", Chemical Engineering,
Vol. 80, No. 17, July 23, 1973.
9. M. W. Kellogg Company, "Engineering Evaluation of a
Process to Produce 250 Billion Btu/Day Pipeline Quality
Gas'", June, 1972. (Confidential)
10. M. W. Kellogg Company,• -"Evaluation of R&D Investment
Alternatives for SO Air Pollution Control Processes,
Part 1", prepared for the Office of Research and Develop-
ment, U.S. Environmental Protection Agency, Contract
No. 68-02-1308, September, 1974.
11. Liebson, I., and Trischman, Jr., C.A., "When and How to
Apply Discounted Cash Flow and Present Worth", Chemical
Engineering, Vol. 78, No. 28, pg. 97, December 13, 1971.
171
-------
8. REFERENCES
12. Lurgi Minerololtechnik Grub'H, "The Lurgi Process -
the Route to S.N.G. From Coal", presented at the Fourth
Synthetic Pipeline Gas Symposium, Chicago, October 30, 1972,
13. National Coal Association, "Steam-Electric Plant Factors/
1972 Edition" December, 1972.
14. Nielson, G.F. (edit.),"1972 Keystone Coal Industry
Manual" McGraw-Hill, New York, 1972.
15. Perry, R.H., Chilton, C.H., and Kirkpajtrick, S.D. (edit.),
"Chemical Engineers' Handbook", 4tH Edit., McGraw-Hill,
New York, 1963.
16. Peters M.S., and Timmerhaus, K.D., "Plant Design and
Economics for Chemical Engineers", McGraw-Hill New York,
1968.
17. Pittsburgh and Midway Coal Mining Company, "Development of
a Process for P-roducing an Ashless, Low-Sulfur Fuel From
Coal", prepared for the Office of Coal Research, Contract
No. 14-01-0001-496, November, 1969.
18. Pittsburgh and Midway Coal Mining Company, "Economic
Evaluation of a Process to Produce Ashless, Low-Sulfur
Fuel from Coal", prepared for the Office of Coal
Research, Contract No. 14-01-0001-496, 1969.
19. Process Research Incorporated, "Characterization of
Glaus Plant Emissions", prepared for the Office of
Research and Monitoring, U.S. Environmental Protection
Agency, Contract No. 68-02-0242, April, 1973.
20. Synthetic Gas-Coal Task Force, "Final Report - The Supply -
Technical Advisory Ta^k Force - Synthetic Gas-Coal",
prepared for the Supply-Technical Advisory Committee,
National Gas Survey, Federal Power Commission, April,
1973.
21. U. S. Bureau of Mines Bulletin No. 643, 1967.
22. U. S. Bureau of Mines Report of Investigation No. 6086,
1962.
23. U. S. Bureau of Mines Report of Investigation No. 6461,
1964.
24. U. S. Bureau of Mines Report of Investigation No. 6622,
1965.
25. U. S. Bureau of Mines Report of Investigation No. 7104,
1968.
26. U. S. Bureau of Mines Report of Investigation No. 7219,
1969.
172
-------
APPENDIX A
FPC FORM 67
173
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
COMPANY NAME
COMPANY - PLANT CODE
PLANT CAPACITY - MU
PLANT NAME
STATE
COUNTY
REPORT FOR YEAR ENDED
DECEMBER 31, 19 ^_^_
POST OFFICE AND ZIP CODE
Schedule A - Fuel Quality
SECTION 1 • Plant Fuel Consumption Data
QUALITY REPORTED ON | J
(Check one) : [ )
B) ••• "As burned11 basis
R) ... "As received" basis
Report percent sulfur, ash, and moisture figures as weighted averages for the month to the nearest 0.1 percent (based on weight of fuel consumed). Report fuel
quality and Btu values on "as burned" basis) if quality is only available on "as received" basis, it may be so reported. If fuel represents a blend of two or
more types of coal or oil with distinctly different qualities, this should be described in a footnote.
o
u
z
_J
01
02
OJ
04
O'j
06
07
OS
09
10
11
12
.»
MONTH
(•)
JAN.
FEB.
MAR.
APR.
MAY
JUNE
JULY
AUG.
SEP.
OCT.
NOV.
DEC.
YEAR
COAL
CONSUMPTION
1000 Tona
(b)
BTU
per Pound
(c)
AVG. *
SULFUR
(d)
AVG. t
ASH
(.)
AVG. «
MOISTURE
(f)
0 1 L
CONSUMPTION
1000 Bbls
(9)
BTU
per Gal.
00
AVG. t
SULFUR
(i)
GAS
CONSUMPT 1 ON
1000 Mcf.
(j)
BTU
per eu. ft.
00
CHECK FOR
FOOTNOTE-
(1)
All footnotes should b* shown on page 12.
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
COMPANY NAME
PLANT NAME
COMPANY - PLANT CCOE
REPORT FOR YEAR
DECEMBER Jl,
E."DED
19
Schedule A - Fuel Quality (Cont'd)
Section 2 - Plant Fuel Source Data
o
z
LU
_J
14
15
16
17
18
19
20
21
22
(a)
SOURCE 1
SOURCE 2
SOURCE }
SOURCr 4
SOURCE 5
50URCC f.
SOURCE 7
SOURCE 8
ALL OTHER
COAL
SOURCE
(BUREAU OF MINES
COAL DISTRICTS)-
(b)
QUANTITY
1000 Tons
(c)
O'L
SOURCE
SUPPLIER **
(
-------
S'iEAiM-ELLCTlUC PLANT AIR AND WATER QUALITY CONTROL DATA
PART i - AIR QUALITY CONTROL DATA
I.A'ii
PLANT NAME
H,a,flP.\HY - PLAt.' CC3E
REPORT FOR TAR ENDED
DECEMBER 31, 19
SCHEDULE B - OPERATIONAL DATA
A separate sheet (including Sections 1 and 2) should be prepared for each plant boiler.
01
Section 1 - Fuel Consumption at Boiler No.
LJ 0
\i =
_I
02
°?
04
OS
0&
07
OB
OS
10
11
1.'
11
14
15
MOUTH
(«J
JAIiljiRT
FErSl ARY
MARCH
APRIL
V,»Y
JU'.'f
JULY
-•jauip
"rrrTE'^EH
jtr-'ifR
•.cvr- ;s
OrCF.'5tR
TOTAL yi'AT
COAL UCPO Tor.s)
(•)
OIL UOOQ Bbls)
(c)
GAS
(1000 Mcfl
(
17
1$
11
20
ont mucus nominal fi
ess thai, full out ov
Qf . fc£ lo^-^
er 75^ load ... 2
During Period
of 3, stem
M
No-loid hoi standby
No-load cold staridb
Other (explain in f
UEEKCAYS
Average for
consecutive four
hours of highest
output
(Code only)
(b)
WINTER riA< tEEK
r.Li'Ts H«I< »FCK
LC.EST PO.'ER
r^Rf') ..TFK
Average 'or
consei.utive four
hours of lowest
output
(Cod« only)
{c}
oclnote, pg. 12]
lines It, il and 18; Acual
Code
. . -'.'iir-' ;•> risri:';- :..RH-J VFAU;
Average fcr
consecutive four
hours of lowest CHrCK F£|R
output FOOIHOIE^
(Code only)
(e) to r-idr-ijht Sunda/.
FPC Forn 67
Sheet Rev (6-70)
176
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
•COMPANY NAME
ANT NAME
COMPANY - PLANT CODE
REPORT FOR YEAR ENDED
DECEMBER 51, 19
SCHEDULE B - OPERATIONAL DATA (Cont'd)
Section 3 - Flue Gas Cleaning Equipment
BOILER NO.
BOILER NO.
BOILER NO.
BOILER NO.
CHECK FOR
FOOTNOTE
21
BOILER NUMBER
MECHANICAL SEPARATORS:
TESTED EFFICIENCY
DATE OF TEST (YEAR/MONTH/DAY) ..
ESTIMATED EFFICIENCY AT ANNUAL
OPERATING FACTOR (If no test
during year)
ELECTROSTATIC OR COMBINATION
ME CHAN 1CAl-
ELECTRICAL PRECIPITATORS;
TYPE (Code »E" for Electrostatic,
25 or "C" for Combination)
TOTAL HOURS FOR THE YEAR DURING
WHICH ALL ELECTRICAL BUS SEC-
TIONS ARE ENERGIZED At.'O WHILE
'6 BOILER IS OPERATING •
TESTED EFFICIENCY
28 DATE OF TEST (YEAR/',!ONTh/DAY)
STATE NUMBER OF HOURS DURING YEAR
WHEN PRECIPITATOR IS NOT FULLY
OPERATIONAL WHILE BOILER IS
?9 OPERATING
ESTIMATED EFFICIENCY DURING
PERIODS WHEN BOILER IS OPERATING
BUT WHEN PRECIPITATOR IS NOT
JO FULLY OPERATIONAL
ESTIMATED EFFICIENCY AT ANNUAL
OPERATING FACTOR ( If no test
during year) *
DESULFURIZATION SYSTEM: ••»
J2 HOURS OF SERVICE DURING YEAR •.,
53 TESTED EFFICIENCY
34 DATE OF TEST (YEAR/MOl.'TH/DAY) ...
ESTIMATED EFFICIENCY AT ANNUAL
OPERATING FACTOR (if no test
J5 during year)'
OTHE" FLUE GAS CLEANING
TYPE (rtxplain :n foot.-.ote)
36 HOURS IN SERVICE DURING YtAn"
• Explain in footnote unusual operatii] conditions
" All footnotes snould be shown on page 12.
••• When operational
FPC Form 67
n,.,/ (6-70)
177
Sheet
-------
'iu. I:LECY;MC PLANT A1U AND WATI-'R QUALITY CONTROL DATA
IVU-.T I - AH QUALITY CONTROL DATA
(•oi" >a - 11 v i com
ran'1•;'( -~i
hLFORT FOR YFAR LWOi'P
DECEMBER 51, 19
SCHEr.ULi-: C - DiGi»^,;.l of Products Collected from Combustion Cycle at Plant
J
Cl
AMOlil.l
(a)
PnITIVi:> JM'IJ (lOGO Ions)
Linrsio-n
(b)
DOLOMITE
(r)
OTHER "
(d)
CHI U FOR
FOUTKliir
(«) -
o
i j
_j
0?
"03
01
c'7
06
07
03
PKOMJCT
(-)
HYAfll
ri"T10;.' ASM
ILL/LiUI GIJLfUil
SULIURIC AC 10 »»»• «
SULIUR D10n liOHO1' AbH (IF SOI D INI 1 RWINGLFC)
oALLb Oi Sli:r.J'< ANO SULFUR CHODUCTS
0'iiiR Rtvrnirs me;.1 AIR QJALMY CONTROL DURATIONS (SPECIFY IN
rrv-rr.O'f )
Tor,.i ev-rnor ui,T L/LIS R^rrur i HP" AIR QJMITY CONTROL
OilKAllCi'S (lllT/.L OF LH,"S 15 1 IIWUCH 19)
}/ All footnblcs sliuulc be ^.lidwn on page ]
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
COMPANY NAME
PLANT NAME
COMPANY - PLANT CODE
REPORT FOR YEAR ENDED
DECEMBER 31, 19.
SCHEDULE E - Equipment (Design Parameters)
PLEASC. CIRCLE TW APPROPRIATE IJUV.BER;
(l) Regular Plant Report
(2) Placed in Operation during year
(3) Altered during year
(4) Not previously reported
(5) Amended report
Section 1 - Boiler Data
(a)
BOILER NO.
(b)
BOILER NO.
(c)
BOILER NO.
(d)
BOILtR NO.
(e)
CHECK FOR
BOHER NUMRER(S)
01
02 SERVED BY STACK NUMBER
03 RELATED TO GENEHATOR NUMBER
Oi DOILFR MANUFACTURER (Code as shown below)
05 YEAR BOILER PLACED IN SERVICE
ASSOCIATED TURBO-GENERATING CAPACITY
06 (Megawatts)
MAXIMUM CONTINUOUS STEAM CAPACITY
07 (Thousand pounds/hour)
DESIGN FUEL CONSUMPTION! 100)i RATING
08 COAL (Tons/hour)
09 RESIDUAL OIL (Barrels/hour)
GAS (Thousand cubic feet/hour)
PERCENT BOILER EFFICIENCY
11 AT 100? LOAD
L2 AT 75* LOAD
AT 50* LOAD
AIR FLOW AT 1001 LOAD
TOTAL AIR, STANDARD CUBIC FEET/MINUTE
14 (incl. Excess Air)
PERCEHT EXCESS AIR USED
WET OR DRY BOTTOM - (Code as "Wet" or
16 "Dry")(For Coal only)
FLYASH RE INJECT I ON - (Code
17 "Yes" or "No")
TYPE OF FIRING (Code as
18 shown below)'*"
* BOILER MANUFACTURERS:
BAW - The Babcock & Wilcox Co.
CE - Combustion Engineering, Inc.
ERIG - Erie City Iron Works
FW - Foster Wheeler Corp.
RILY - Riley Stoker Corp.
VOGT - Henry Vogt Machine Co., Inc.
OTHE - Other (Specify in footnote)
•• All footnotes should be shown on page 12.
••» TYPE OF FIRING (where applicable, use
more than one code):
PCFR - Pulverized Coal: Front Firing
PCOP - Pulverized Coal: Opposed Firing
PCTA - Pulverized Coal: Tangential Firing
CYCL - Cyclone
SPRE - Spreader Stoker
OSTO - Other Stoker
FLUI - Flu idized Bed
RFRO - Residual Oil: Front Firing
ROPP - Residual Oil: Opposed Firing
RTAN - Residual Oil: Tangential Firing
GFRO - Gas: Front Firing
GOPP - Gas: Opposed Firing
GTAN - Gas! Tangential Firing
OTHE - Other (Specify in footnote)
179
Sheet
FPC Form 67
Rev (6-70)
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
CO.MPM1Y NflVE
LAN1 NAME
ACT - PLAHI CODE
REPORT FOR YEAR ENDED
DECEMBER 51, 19
SCHEDULE E - Equipment (Design Parameters) - Continued
Section 2 - Flue Gas Cleaning Equipment Data
BOILER NO.
BOILER NO.
(e)
BOILER NO.
BOILER NO.
CHECK FOR
FOOTNOTE
BOILER NUMbrRS (Enter same Boiler- Numbers as
indicated on page 9i line 01)
FLl'E GAS CLEANING EQUIPMENT
HEC^NICAL COLLECTORS
19 TYPE (Code as shown oelov)*
20 DESIGN EFHCIEHCY (Percent)
21 MASS EMISSION RATE (Pounds per hour}** ...
22 YEAR PLACED II: SERVICE
2} IHSTALLFO COS1 (Thousands of dollars)***..
24 MANUFACTURER (Code as shown below)•••• ...
ELECTROSTATIC AiiO COi'BI,'IATIQH
MEUIANICAL-ELECTRICAL PRFCIPITATORS
25 TYPE (Code as "E" or "C")
26 DESIGN EFFICIENCY (Percent)
2? MASS EMISSIOU RATE (Pounds per hour)** ...
28 YEAR PLACED IN SERVICE
29 INSTALLED COST (Thousands of dollars)***..
MANUFACTURER (Code as shown below)**** ...
DESULFURIZA1ION SYSTEM
31 TYPE (indicate by footnote)
}2 DESIGN EFFICIENCY (Percent) ,
33 MASS EMISSION RATE (Pounds per hour)**
34 YEAR PLACED IN SERVICE
35 INSTALLED COST (Thousands of dollars)*** .,
36 MANUFACTURER (Specify in footnote) ,
OTHER FLUE GAS CLEAN IHG EQUIPMENT
37 TYPE (indicate by footnote)
38 DESIGN EFFICIENCY (Percent)
39 MASS CM I SSI Oil RATE (Pounds per hour)** ...,
40 YEAR PLACCD IN SERVICE
41 INSTALLED COST (Thousands of dollars)***..,
42 MANUFACTURER (Specify in footnote)
I/All footnotes should be shown on page 12.
* Mechanical Collectors - Type (if more than one type is used in a senesi indicate all applicable codes and
explmn in footnote).
GRAV - Gravitational or baffled chamber
SCTA - Single cyclone-Conventional reverse flow,
tangential inlet
SCAX - Single cyclone-Conventional reverse flow,
axial inlet
MCTA - Multiple cyclones-Conventional reverse
flow; tangential inlet.
HCAX - Multiple cyclones-Conventional reverse
flow; axial inlet
*• Pounds per hour = Crams/Actual Cu.Ft./ X /Actual Cu.Fl.Vol./Hr./
7000/Grains/Pound
*•* Sec Instruction 12, page 8.
*«<• flue Gas Cleaning Equipment Manufacturers (See page 11 for Codes)
FTC Forn. 6?
Rev (6-70)
CYCL - Straight-through-flow cyclones
IMPE - Impeller collector
VENT t Wet collector: Ventun
WETC - Wet Collector: Other (Specify in footnote)
BAGH - Baghouse (Fabric Collector)
OTHE - Other (Specify in footnote)
180
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART I - AIR QUALITY CONTROL DATA
I'L.V.I KAMI
LUHI'AIIY - I'LAIII
KLI'UIU MIX YLAK INUIU
in (i win it ;i,
SCHEDULE E - Equipment (Design Parameters) - Continued
Section1 3 - Stack Data
tu
_i '
4J
44
4',
4(.
56
ri7
(ai
blACK IIUMI'l KG
INSTALLED COSI (Thousand;, ot do] !.n ..) ( 1 nslrucl ion
12, pag«. 8)
SIACK III 1 GUT (Feet .itiuve Gr mind llcv.itiun)
II'SIDL UIAKITIR OF FLUE AT Till' (inches)
nui I.AS HATE (CURIL FD I/MINUTI )
AT 100* LOAD
AT Itf I.OAU
AT Wf LOAD
ixn CAS iiMi'iRAiunr (oicunr, rAKiiiiu n )
AT lOOt LOAD
AT 75« LOAD
AT 50/, LOAD
IXIT GAS VIIOCITY (Fl IT/il COIID]
AT 100/ LOAU
AT 75* IOAO
AT SOI LOAU
DISTANCE TO NEXT STACK, JEMCR TO CEXII R
(FEET)-'
ORIENTATION OF 1 INI OF STACKS - DtGRHES CLOCK-
WISE FROM TRUP MOUTH*'
L1ALK
NUMUER
(b)
S1ACK
NUMBEK
(c)
SIALK
MUMHLH
f,0
STACK
nuvnrR
M
CIIFCK FOH
FOOTtlOTf
(0
Ail footnote:; ijiould be bhown on pacjc 12.
Show position uf sucks by slack number lo correspond wilh the identification in line 4J. Enter true north on
the diagram.
Stacks Orientation Diagram:
FLUE GAS CLTAHIIIC EQUIP. MANUFACTURERS (Sec pg. 10]
AAFC - American Air Filler Cii., lnc«
AM5T - America.! SUrd.ird, Inc.
liriC - Oclto PuMution Conuol Corp.
BUF.L - Bucll liujincoring Co.^ inc.
UUCO - The Duco.i Co., Inc.
FIKL - Fis(.hei -Klustcrm(in, Inc.
FULL - Fuller Co., Orato Producis
KIRK - KirP A lilum Wnnu f aclur i ng Lo.
KOPP - Konpers Co., Inc.
PPCI - Precipilair Pollution Control, Inc.
FAOA - Precipitation Associates of America, Inc.
PLVR - Pulven/ing Machinery Division
COTT - Research-Co Ilrell, Inc.
SVRS - Scversk/ Electrunalom Corp.
UOI' - HOP Air Corrcclion Division
TORI - The ToriI Corp.
WEST - Western Precipitation Division
WIIEE - Wheclabralor Corp.
ZURN - Zu.n Industries, Inc.
OTHE - Other (Specify in footnote)
181
FPC Form 67
Rev (6-70J
-------
COY" „> I.A!..
STEAM- iSJ.KC'irtiC VLAKT All-; AND WA'JVil QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL, DATA
_ ___ (Apphf-ab'e to No P! car and Fossil Fu_e_lcd fj\ earn- HK-ctric Planer.)
"~ ----- - hil-OHT
NA"F
FIAMT GA.V.GITY - :.!..
STATt
COUNTY
OU YEAn LMjfD
DECIMBLH Jl, 19 __
COVPAilf - "LAHT CObl
POST orncr MID ZIP CODE
SCHEDULE A - OPERATIOMAL DATA
Section 1 - Average Annual Cooling Water Use of Plant - CFS
Li'
'.! •
— O
. 1 .-
0!
02
05
(a)
AV'.Hiiiu HAIL OF \.\ riiOHt,;.L nio,,1 'ATE;; ,;';OY DURING YEAR
.".F.:. cr °'\IF Oh FiiSiiiArtji re in'iit1 r-';i^ nu'iii.o YTAR
AV.Hir I'rfTC 0." I'BK^'Jl1" ICI! Ult'.t"-, i'f..K
fb)
CHECK FOB
FOOTHOTf *
fc)
Section 2 - Maximum Water Temperatures and Average Stream Flows
Durinii Montlir. of \Vmtcr and Summer System Peak Power Loads
WHITER PFAK LPAD VONTH **
o
2£
UJ
2
_J
04
MAXIfUB TCMPCRATUSt
°F
AT
DIVERSION'
fa)
«T
OUThALL
(b)
I'OKIMLY AVFRAGE
•!.('.• i1. RICFIVING
'..'AITR BCOV, CIS
(c)
SUMMFR PEAK LOAD MOUTH »•
MAXIMUM TFUPfRATURE
OF
AT
DIVLRIilON
(d)
AT
OUTFALL
f.)
MONTHLY AVrRACr
FLCU IN RLCCIVING
WATER BODY, CFS
(f)
ci >.-:.< '3'.
FOOTI.'OrE ' |
(9)
. _clion 3 - Amount of Chemicals used During the Year
•jj
z .
— o
_J Z
05
06
(a)
COOLING '..'ATER
BOILER UATFR
M'.KLIIP
PHOSPHATE
LDS.
(b)
CAUSTIC
SODA IBS.
(c)
HYDRAZII1E
GAIS.
(d)
LIME
LDS.
(»)
4LUM.
LSS.
(0
CHLORIHt
LES.
(q)
OTHER
(h)
CHECK FOR
FOOTNOTf •
(<}
SCHEDULE D - OPERATION AND MAINTENANCE EXPENSES, $1, OOP
Section 1 - Cooling Water Operation at Plant
a
i: •
_ o
.j n
07
ns
(.)
AUilML OPERATION AND WMNFEN'AKCF EXPENSES
•M.MUAL nOTT 01 CIU-ICAL ADDITIVES
(b)
CHUCK FOR
FOOTNOTE *
(c)
Section 2 - Boiler Water MiJuup and Boiler Blowdown Treatment
UJ
— t
— l-L-
05
(V
(.-.)
ACI.'UAL Cf'rRATICH A IIP MAIMTCIJANCE 1 XPCt.'SFS
;.:."U«i cosi OF Ci.r- IUL tODniv:11.
(b)
CHECK (PR
FOOT.\'"1f •
(c)
* III footnotes rniuld Lc sKoun on pog? ?0.
*• Sf.fr i fj monlli.
TfC for-* fi
fVv (n-70)
182
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL DATA
AMY NAME
PLANT NAME
COMPANY - PLANT CODE
REPORT FOR YEAR ENDED
DECEMBER 31, 19_
SCHEDULE C - WATER USE AUTHORITY AND LIMITING CRITERIA
UJ
z .
3 2
01
02
03
04
UJ
z •
— 0
_J Z
O1)
06
I
|08
(-)
ISSUING AUTHORITIES OF LICENSES OR PERMITS: COUNTY, STATE, FEDERAL,
OR OTHER. LIST AND DESCRIBE AUTHORITIES IN FOOTNOTE.
FREQUENCY OF TEMPERATURE MONITORING OF COOLING WATER EFFLUENT I
CONTINUOUSLY (c), HOURLY (H), DAILY (0), OR OTHER (0).
FOOTNOTE AND EXPLAIN IF OTHER.
DISTANCE MIXING ZONE EXTENDS DOWNSTREAM. FT.
DISTANCE MIXING ZONE EXTENDS FROM SHORE, FT.
(a)
MAXIMUM ALLOWABLE TEMPERATURE RISE OF COOLING WATER (°F)
AT OUTFALL TO RECEIVING WATER BODY
AT LIMITS OF DEFINED MIXING ZONE
MAXIMUM ALLOWABLE TEMPERATURE OF COOLING WATER (°F)
AT OUTFALL TO RECEIVING WATER BODY
AT LIMITS OF DEFINED MIXING ZONE
(b)
SUMMER
(b)
WINTER
(c)
CHECK FOR
FOOTNOTE •
(c)
CHECK FOR
FOOTNOTE *
(d)
SCHEDULE D - COOLING FACILITIES
SECTION 1 - GENERAL DESIGN DATA
UJ
Z .
— G
_J Z
09
10
11
12
13
14
(a)
GENERATING UNIT IDENTIFICATION NUMBER
RATED GENERATING CAPACITY, MW
TYPE COOLING: ONCE-THROUGH, FRESH (OTFJ:
ONCE-THROUGH, SALINE (OTS): COOLING POND
(CP): WET COOLING TOWER (WCT): DRY
COOLING TOWER (OCT): COMBINATION (CB).
FOOTNOTE AND EXPLAIN COMBINATIONS.
YEAR COOLING FACILITIES INSTALLED
DESI3NED TEMPERATURE RISE ACROSS THE
CONDENSER, of
DESIGNED RATE OF FLOW THROUGH THE CONDENSER,
CFS
(b)
(c)
(<0
(e)
CHECK FOR
FOOTNOTE *
(f)
• ALL FOOTNOTES SHOULD BE SHOWN ON PAGE 20.
FPC Form 67
Rev (6-70)
183
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL DATA
COMPANY NAME
PLANT NAME
COMPANY - PLANT CODE
REPORT FOR YEAR ENDED
DECEMBER 31, 19_
SCHEDULE D - COOLING FACILITIES - Continued
ei
z
z
_j
l^
16
17
18
iy
20
21
22
23
24
25
SECTION 2 - ONCE THROUGH COOLING
(a)
DESIGNED RATE OF WITHDRAWL AT FULL LOAD, CFS
INTAKE LOCATIONS: I/
DIRECTION FROM CENTER OF PLANT, DEGREES
DISTANCE FROM CENTER OF PLANT, FT.
DISTANCE FROM SHORE, FT.
AVERAGE DISTANCE BELOW WATER SURFACE, FT.
OUTFALL LOCATIONS: I/
DIRECTION FROM CENTER OF PLANT, DEGREES
DISTANCE FROM CENTER OF PLANT, FT.
DISTANCE FROM SHORE, FT.
AVERAGE DISTANCE 3ELOW WATER SURFACE, FT.
ARE DIFFUSERS USED? FOOTNOTE AND DESCRIBE
IF "YES."
INSTALLED COSTS, $1,000 **
(b)
( = )
Ml
(e)
ChECK F0% '
FOOTNOTE'
(f)
c5
z
UJ
z
_J
26
27
28
SECTION 3 - COOLING PONDS
(a)
TOTAL SURFACE AREA, ACRES
TOTAL VOLUME, ACRE-FEET
INSTALLED COSTS, ,$1,000 *•
. (b)
(c)
M
(e)
CHECK FOR
FOOTNOTE *
(0
d
•z.
LU
•SE.
_J
29
30
31
32
33
3*
SECTION 4 - COOLING TOWERS
(a)
TYPE DRAFT-MECHANICAL (M), NATURAL (N)
LENGTH, IF APPLICABLE, FEET
WIDTH OR DIAMETER AT BASE, FEET
HEIGHT, FEET
WATPR COOLING RANGE, °F
INSTALLED COSTS, $1,000 **
(b)
(c)
M
(e)
CHECK FOR
FOOTNOTE •
(f)
I/ ALTHOUGH NOT REQUIRED, A SKETCH SHOWING THE LAYOUT OF THE COOLING SYSTEM IS DESIRABLE.
* ALL FOOTNOTES SHOULD BE SHOWN ON PAGE 20.
** See instruction 3, Schedule D, page 15.
184
FPC Form 67
Rev (6-70)
-------
STEAM-ELECTRIC PLANT AIR AND WATER QUALITY CONTROL DATA
PART II - WATER QUALITY CONTROL DATA
COMPANY NAME
PLANT NAME
COMPANY - PLANT CODE
REPORT FOR YEAR ENDED
DECEMBER 31, 19_
SCHEDULE E - COOLING WATER SUPPLY
SECTION 1 - ONCE THROUGH COOLING
o
z
UJ
z
_J
01
02
03
SOURCE(S)
OF
WATER
(a)
7-DAY, 10 YEAR
DEPENDABLE FLOW
CFS
(b)
AVERAGE
FLOW
CFS
(c)
GENERATING UNITS
SERVED
NO
(d)
NO
(e)
NO
(0
NO
(g)
CHECK FOR
FOOTNOTE *
(h)
FOOTNOTE AND EXPLAIN ANY DISCHARGE INTO A DIFFERENT BODY OF WATER, AND WHEN DISCHARGE IS OTHER THAN
DOWNSTREAM FROM WATER INTAKE LOCATION.
SECTION 2 - COOLING PONDS
d
z
LiJ
Z
_J
04
05
06
07
08
SOURCE(S)
OF
WATER
(a)
7-DAY, 10 YEAR
DEPENDABLE FLOW
CFS
(b)
AVERAGE
FLOW
CFS
(c)
GENERATING UNITS
SERVED
NO
(d)
NO
(e)
NO
(0
NO
(g)
PERIOD OF YEAR POND IS USED FOR COOLING
OTHER USES OF POND
CHECK FOR
FOOTNOTE *
(h)
SECTION 3 - COOLING TOWERS
d
z
UJ
Z
_J
09
10
11
12
1^
TOWER
NO.
(a)
SOURCE(S) OF
MAKEUP WATER
(b)
PERIOD OF YEAR
USED FOR COOLING
(c)
LOCATION OF
BLOWDOWN
DISCHARGE
(d)
GENERATING UNITS
SERVED
NO
(e)
NO
(0
NO
(fl)
NO
(h)
CHECK FOR
FOOTNOTE *
(•)
ALL FOOTNOTES SHOULD BE SHOWN ON PAGE 20.
FPC Form 67
Rev (7-70)
185 Sheet
-------
STEAM-ELF.C.TltiL1 PLANT AlH AND WATFrt QUALITY CONTROL DATA
PAUV U - V.'AT.'IR QUALITi' CONTROL DATA
t
I"'" PL T f~» Yu"Zf- '.'.".ifU
31, I'J
SCHEDULE F - WATER TREATMENT
0!
SECTION 1 - SETTLING POXDS FOR HOILF.R WATER 13LOWDOWN
(•'
, , • • rc.n
, M, r, '.'J
. .A '. V I.'1. • . " 11 V.U
1 n v'.'i'.f • t ".' iM1...
• F : . i>
',«)
I1 -S >tH W.n)
(c)
I.' 1 ••••!"
I1
(«5
.• • '. Ji Li
iCI ILS P-'V.
;o
.•U :U-I3L
4C'v.M CJ.
FT. rfR YR.
(0
i.wi or
W«T i rt :IJ JY
HKimr.j
lll£ U.iC'lArfCE
(9)
> .'. • i-1
err.; • •
(i-i
SECTION 2 - SETTLING PONDS FOR BOTTOM ASH
o
nj
('}
04
, i
1 1
j
or
Hi,
;a)
1 I-1. • r '.C1
',l(. .J "-C'.i
ti.p
i .' i . • 1 1 . r , . i . ,. . i*
PR. v .1 ' v. C: ll ^M'.G
HfiHja 1 i .ik-rs I':H rt;.">)
d> 1 (c)
1
J
'0
rii'.i r'.i.n
in-.-.i i r .r
L -i".'.'m
M
In)
.^'..' ii.niD
..ULIDS °HH
(.)
:r I!'.L oh :_i'ici\::
;-.'i run'iiss »«itR
(b)
OI.-l!iAr>C£
V01.1.M CU.
H. PCS 1h.
(f)
J.AfC OF
VATCR oCOY
KrCEIVII.G
THE DISCHARGE
(3)
AtfOU.'.T PF ASH iRCAlED
TOUS PER YEAR
(e)
Ci"f* FCf!
IColI.OTI •
(h)
fHTK F0.i
F-nOTNOTC •
(d)
SECTION 3 - PROVISIONS FOR PLANT SEWAGE DISPOSAL
-' .."
C'V
.-
rn
],-
(•)
cr;>. irii d'.it. ^I^EFI <„' •;, j'riic '.i.K \:i) SURFAU »-uf<
t'DC^ (r.»). .i< ril'R (On. K^T'-CT17 IF uT'lti: f.O Dl'AIN.
CFHI:!,' is. Me.!,: r., • I;M
.'*)
. • : '•• TWI.I ••• i
,\i r i 11, ;.i
V,V! i' I .''•>' -f.Ci Ul'.d T>r I'l'v. II.:."
BOD
PI 1!
(.0
H
(c)
CO DC
fMH- HAILS
Fl ht
(d)
01 HER
(c)
C'-FCf. fOH
U)
cnr:r FOK
i- '
All ICOniCli: iM.'M » tit S1 - «:. C"J I'AJf 10.
186
FPC
-------
APPENDIX B
NEDS DATA INPUT T'ORM ^OP INDUSTRIAL PLANTS
187
-------
NEDS DATA INPUT FORM FOR INDUSTRIAL PLANTS.
SHU
AQCR
PIUIB
POINT SOURCE
Input Form
Dint ol Ptrsoa
(Wt.
CO
CO
I I I I I I ' I
HUM (ID OuilfD |T««len Fin RiU (N1 •!» II BI Hut II
II 17 1119 N 21122 21
» 34 IS K 17 II 19 4041 42 41U4 45146H7M 49 50 SI 52 53154
C7 U 19170 71172 71 74 75171
twin Quip
Mil
tmri ID< ITU tf
CONTROL EQUIPMENT
PIWII> |SKMlii|| noon
SO, I MO, I »0. I HC
ESTUUTED CONTROL EFFICIENCY (I)
Put I SO, I NO. I HC I CO
35 MD7DI39 40 41 4] 4} 44 45 46 47 41 49 ISO IS IK} U 54
EMISSION ESTIMATE! lloal rim
M.
I ' I I I I I I I I I I I
1 * P 4
CONTROL RECULATIONS
ALLOIARLE EMISSIORS |lm Dun
PvtiuUk I SO,
2Q[2l|22bl|2426|2l|27[2l
' ' ' ' ' I I I I I I I I I I I I I I I I I I I I 1 I I
17 SI 59160 61 El 63
Fal.Fm.il,
MM IliU
OpillllniRlU
Sulhii AK Hill ConUol
. Cailenl •. IDS BTU/ltt
M 27 21 29 10 11 11 H|14|15|M|17pa|19
SI 52 52 94 >5 56 97 SI 53 60 SI 6] II 14 IS M 17 II 69170 71
Figure 4-1. Point source coding form.
-------
APPENDIX C
THE GENERAL MODEL
CExcerpted from
"Evaluation of R&D
Investment Alter-
natives For <5O Air
X
Pollution Control
Processes - Part 1)
189
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4. THE GENERAL MODEL
4.1 The General Process Model
The plants in the models have, as far as possible, been made
self-contained apart from the intake of basic raw feed materials;
i.e., the plant should not be buying natural gas or electricity.
If possible, it should not even be buying desulfurized fuel oil
since supply cannot be assumed. There are obviously exceptions
if the plant is an addition to a larger conventional plant; e.g.,
with stack gas scrubbing for a power plant it would be illogical
not to assume a supply of power. In general, a large plant having
a coal feed will generate its own power, steam and heat requirements
by burning coal and scrubbing the stack gases.
It was not a primary concern to provide special chemical by-products
from any process, but to avoid additional treatment facilities
for impure materials by routing these side streams back to the
plant fuel supply where possible. This approach simplifies the
models and minimizes the effect of credits for special chemical
by-products on the plant costs.
The cost of equipment and raw material, utility and waste product
quantities have all been related to one or more basic process
parameters; e.g., in the stack gas scrubbing models, the basic
process parameters are flue gas flow rate and sulfur content of
the fuel. For a plant producing high quality fuel, the basic
process parameters are product flow rate and properties of the
raw feed materials.
Where possible, equipment costs were related directly to the basic
process parameters. However, the format of some of the estimates
used to develop the models prevented this. In these cases, the
available cost information was carefully examined relative to the
General Cost Model to determine exactly what the costs included.
190
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The equipment costs were extracted from these estimates by using
the relationships between construction labor costs, other material
costs and equipment costs given in the General Cost Model.
Each plant design was examined to fix maximum train sizes for
each group of equipment. It has been assumed that N trains cost
N times the cost of one train. Where a plant is largely made up
of several trains, size variations were only taken in increments
of their size.
For the smaller plants, it was possible to examine the cost of
every item of equipment and assign an exponent of size to give
cost variations. However, for the larger plants, whole sections
have been grouped together. The following is given as a general
guide to the exponents for equipment cost vs. size ( 9,14,21) :
[cost., _ /Size0\n|
n, [CostJ \sTie~J/J
Increasing number of trains of equipment 1.0
Blowers 0.9
Solids grinding equipment 0.8
Steam generation equipment 0.8
Process furnaces and reformers 0.7
Compressors 0.7
Power generation equipment 0.7
Solids handling equipment 0.6
Offsites 0.6
Other process units 0.6
4.2 The General Cost Model
4.2.1 Bases For Costs
All costs in the models are those in existence at the end
of 1973. To update prior cost information used in the con-
struction of the models, an annual inflation multiplication
191
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factor of 1.05 has been used. All costs other than unit
costs for labor, raw materials, etc., are shown in thousands
of dollars (M$).
The direct field construction labor cost, L, and the direct
cost of operating labor, CO, both refer to a Gulf Coast
(Houston) location. For any other location, they are adjusted
through the use of a location factor, F, which is explained
in section 4.3.
Whenever possible in the development of the cost models dis-
cussed in this report, major equipment costs, E, have been
related to plant size variations. The reference values of E
have been taken from actual plant cost estimates when these
were available. Sometimes, however, the cost estimates were
not available in such a detailed breakdown. In such cases,
the relationships developed in the General Cost Model were
used to analyze the cost data. The relationships in the
General Cost Model were developed based on procedures reported
and recommended in the literature ( 9,13) and on Kellogg's
general experience.
4.2.2 Capital Cost Model
Major equipment costs, E, represent the cost of major
equipment delivered to the site, but not located, tied-in
to piping, instruments, etc., or commissioned. It includes
material costs only. Major equipment is defined to include
furnaces, heat exchangers, converters, reactors, towers,
drums and tanks, pumps, compressors, transportation and
conveying equipment, special equipment (filters, centrifuges,
dryers, agitators, grinding equipment, cyclones, etc.), and
major gas ductwork.
Other material costs, M, represent the cost of piping,
electrical, process instrumentation, paint, insulation,
foundations, concrete structures, and structural steel
192
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for equipment support. It does not include such items as
site preparation, steel frame structures, process buildings,
cafeterias, control rooms, shops, offices, etc.
M has been taken as a fixed fraction of E. Whenever possible,
this fraction has been determined from an estimate covering
the particular plant under consideration. This fraction is
often different for each section of the plant, if particular
details were not available, the following relationships have
been assumed ( 9):
Solids handling plant: M = 0.40E
Chemical process plant: M = 0.80E
Direct field construction labor costs, L, are based on Gulf
Coast rates and productivities. Again, L has been taken
as a fixed fraction of E. Wheneve.r possible, it has been
derived from an estimate covering the particular plant under
consideration. This fraction is often different for each
section of the plant. ^f_ particular details were not available,
the following relationships have been assumed (9 ):
Solids handling plant: L = 0.40E
Chemical process plant: L = 0.60E
Indirect costs associated with field labor have been assumed
as follows:
Fringe benefits and payroll burden = 0.12 L
Field administration, supervision
temporary facilities = 0.17 L
Construction equipment and tools = 0.14 L
Total field labor indirect costs = 0.43 L
193
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Home office engineering includes home office construction,
engineering and design/ procurement, client services,
accounting, cost engineering, travel and living expenses,
reproduction and communication. This could range from under
10% to almost 20% of the major equipment and other material
costs. In the model, this has been assumed to be 15% of the
total direct material cost (E + M).
The bare cost of the plant, BARC, is defined as the sum of
equipment costs, other material costs, construction labor
and labor indirects, and home office engineering. For a
Gulf Coast location, it is given by:
BARC =E+M+L+0.43L+0.15 (E+M)
= 1.15 (E+M) + 1.43 L
For any other location, it is given by:
BARC = 1.15 (E + M) + 1.43 L-F
where F is the location factor (see section 4.3).
Taxes and insurance can be 1-4% of the bare cost. In the
model, they have been assumed to be 2%. Contractor's
overheads and profit could depend on several factors, but
are generally in the range of 6-13% of the bare cost. A
value of 10% was chosen for the model.
A contingency has been included in the model and is expressed
as a fraction of the bare cost. It represents the degree
of uncertainty in the process design and the cost estimate.
The contingency, CONTIN, could range from zero for a well-
established process to 0.20 or more for a process still under
development.
194
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The total plant investment, TPI, is defined as the sum of
the bare cost (including contingency), taxes and insurance,
and contractor's overheads and profit. It is therefore
given by:
TPI = (1.0 + CONTIN) BARC + 0.02 (1.0 + CONTIN) BARC
+ 0.10 (1.0 + CONTIN) BARC
= 1.12 (1.0 + CONTIN) BARC
In order to obtain the total capital required for construction
of a particular plant, some additional costs should be added
to the total plant investment. These costs are:
1. Start-up costs
2. Working capital
3. Interest during construction
Start-up costs, STC, have been assumed to be 20% of the total
net annual operating cost, AOC (see section 4.2.3 for
explanation of AOC). Thus:
STC =0.20 AOC
Working capital, WKC, is required for raw materials inventory,
plant materials and supplies, etc. For simplification, it
has also been assumed to be 20% of the total net annual
operating cost, AOC.
Thus:
WKC =0.20 AOC
Interest during construction, IDC, obviously increases with
the length of the construction period which, to some extent,
is a function of the size of the plant. The construction
of plants the size of the stack gas scrubbing units is now
taking about 2-3 years and projects of the magnitude and
195
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complexity of a substitute natural gas plant or a power
station are taking 4-5 years. Two different values for the
interest during construction have therefore been assumed.
The first is intended to be used for stack gas scrubbing
units fitted to existing power plants or for constructions
well under $100 million:
IDC =0.12 TPI
The second is for the larger, more complex plants such as
substitute natural gas, solvent refined coal, and power plants:
IDC =0.18 TPI
The total capital required, TCR, is equal to the sum of the
total plant investment, start-up costs, working capital, and
interest during construction.
Thus:
TCR = TPI + STC + WKC + IDC
For stack gas scrubbing units, this can be reduced to:
TCR = TPI +0.20 AOC +0.20 AOC +0.12 TPI
= 1.12 TPI +0.40 AOC
For the larger plants, this can be reduced to:
TCR = TPI +0.20 AOC + 0.20 AOC +0.18 TPI
=1.18 TPI +0.40 AOC
From section 4.2.3, AOC is calculated from:
AOC = 0.078 TPI +2.0 TO'CO (1.0 + F) + ANR
196
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where TO = total number of shift operators
ANR = Annual cost of raw materials, utilities, and
waste disposal, less by-product credits.
Therefore, for stack gas scrubbing units, the equation for the
total capital required becomes:
TCR = 1.12 TPI + 0.40 [0.078 TPI + 2.0 TO'CO (1.0 + F) + ANR]
- 1.12 TPI + 0.03 TPI + 0.8 TO-CO (1.0 + F) + 0.40 ANR
= 1.15 TPI + 0.8 TO-CO (1.0 + F) + 0.40 ANR
For the larger plants, the equation for the total capital
required becomes:
TCR = 1.18 TPI + 0.40 [0.078TPI + 2.0 TO-CO (1.0 + F) + ANR]
= 1.18 TPI + 0.03 TPI + 0.8 TO-CO (1.0 + F) + 0.4 ANR
= 1.21 TPI + 0.8 TO-CO (1.0 + F) + 0.4 ANR
The buildup of costs to determine the total capital required is
illustrated in Figure 4.1.
4.2.3 Operating Cost Model
The total net annual operating cost, AOC, is the total cost of
operating the plant less the credits from the sale of by-products.
It does not include return of capital, payment of interest on
capital, income tax on equity returns or depreciation. The total
net annual operating cost is made up of the following items:
1. Annual cost of raw materials, utilities, and waste
disposal, less by-product credits
2. Annual cost of operating labor and supervision
3. Annual cost of maintenance labor and supervision
4. Annual cost of plant supplies and replacements
5. Annual cost of administration and overheads
6. Annual cost of local taxes and insurance
197
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The annual cost of raw materials, utilities, and waste disposal,
less by-product credits, ANR, is clearly a function of the
particular process under consideration. It is given by
different relationships for each model.
The total number of operators employed on all shifts, TO,
is different for each process and is either given as an
equation or number for each particular model. It has been
assumed that each operator works 40 hours per week for 50
weeks per year (2000 hours per year) . If CO is the hourly
rate for an operator (Gulf Coast basis) , then the annual
cost of operating labor is given by:
TO -pnoo • ro
Operating labor (Gulf Coast) =
= 2 TO. CO M$/yr
The annual cost of operating labor for any other location
has been assumed to be:
Operating labor = 2 TO- CO (0.5 + 0.5 F)
Supervision was assumed to be 15% of operating labor. Thus,
the total cost of operating labor and supervision, AOL, is
given by:
AOL = 1.15 [2 TO-CO (0.5 + 0.5 F) ]
= 2.3 TO-CO (0.5 + 0.5 F)
The annual cost of maintenance labor has been assumed to be
1.5% of the total plant investment. Maintenance supervision
is 15% of maintenance labor. Therefore, the total annual
cost of maintenance labor and supervision, AML, is:
198
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AML = 1.15 (0.015 TPI)
= 0.018 TPI (rounded up)
Plant supplies and replacements include charts, cleaning
supplies, miscellaneous chemicals, lubricants, paint, and
replacement parts such as gaskets, seals, valves, insulation,
welding materials, packing, balls (grinding), vessel lining
materials, etc. The annual cost of plant supplies and re-
placements, APS, has been assumed to be 2% of the total plant
investment. Thus:
APS = 0.02 TPI
Administration and overheads include salaries and wages
for administrators, secretaries, typists, etc., office
supplies and equipment, medical and safety services, trans-
portation and communications, lighting, janitorial services,
plant protection, payroll overheads, employee benefits, etc.
The annual cost of administration and overheads, AOH, has
been assumed to be 70% of the annual operator, maintenance
labor, and total supervision costs. Thus:
AOH = 0.70 [2.3 TO'CO (0.5 + 0.5F) + 0.018 TPI]
= 1.7 TO.CO (0.5 + 0.5F) + 0.013 TPI (rounded up)
Local taxes and insurance include property taxes, fire and
liability insurance, special hazards insurance, business
interruption insurance, etc. The annual local taxes and
insurance, ATI, have been assumed to be 2.7% of the total
plant investment. Thus:
ATI = 0.027 TPI
The total net annual operating cost, AOC, is therefore given
by:
199
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AOC = ANR + AOL + AML + APS + AOH + ATI
= ANR + 2.3 TO-CO (0.5 + 0.5F) + 0.018 TPI
+ 0.02 TPI + 1.7 TO.CO (0.5 + 0.5F) + 0.013 TPI
+ 0.027 TPI
= 0.078 TPI + 4.0 TO.CO (0.5 + 0.5F) + ANR
= 0.078 TPI + 2.0 TO.CO (1.0 + F) + ANR
In order to obtain the total annual production cost, the
following items must be added to the total net annual
operating cost:
1. depreciation
2. average yearly interest on borrowed capital
3. average yearly net return on equity
4. average yearly income tax
The straight-line method was used to determine depreciation,
based on the total capital required less the working capital,
For stack gas scrubbing units (15 year life) , the annual
depreciation, ACR, is:
ACR = 1/15 (TCR-WKC)
= 0.067 (TCR-0.20 AOC)
For substitute natural gas and solvent refined coal plants
(20 year life), it is given by:
ACR = 0.050 (TCR - 0.20 AOC)
For power plants, both conventional and combined cycle (28
year life), it is:
ACR = 0.036 (TCR - 0.20 AOC)
200
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Interest on debt and return on equity are calculated following
a procedure recommended in the literature (13) and illustrated
in Appendix A. The procedure assumes a fixed debt-to-equity
ratio, an interest rate on debt, and the required net (after
tax) rate of return on equity. Interest on debt and return
on equity are calculated over the plant life, and the yearly
average is expressed as a percentage of the total capital
required (TCR). Assuming a 75%/25% debt-to-equity ratio,
a 9% per year interest rate, and a 15% per year net rate of
return on equity, the annual interest and return, AIC, is
given by:
AIC = 0.054 TCR
Federal income tax is the average yearly income tax over the
plant life, expressed as a percentage of the total capital
required. The calculation of income tax is illustrated in
Appendix A. Based on the assumptions listed in the preceding
paragraph and an assumed tax rate of 48%, the annual federal
income tax, AFT, is given by :
AFT = 0.018 TCR
The total annual production cost, TAG, is given by:
TAG = AOC + ACR + AIC + AFT
For stack gas scrubbing plants, this can be reduced as
follows:
TAG = AOC + 0.067 (TCR - 0.20 AOC) + 0.054 TCR + 0.018 TCR
= AOC + 0.067 TCR - .013 AOC + 0.054 TCR + 0.018 TCR
= 0.139 TCR +0.99 AOC
201
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Substituting for TCR and AOC from preceeding equations:
TAG = 0.139 [1.15 TPI + 0.8 TO-CO (1.0 + F) + 0.40 ANR]
+ 0.99 [0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR]
= 0.237 TPI + 2.1 TO-CO (1.0 + F) + 1.04 ANR
Making the appropriate substitutions, the total annual
production cost for substitute natural gas and solvent
refined coal plants is:
TAG = 0.225 TPI + 2.1 TO'CO (1.0 + F) + 1.04 ANR
For power plants, this equation becomes:
TAG = 0.208 TPI + 2.1 TO-CO (1.0 + F) + 1.04 ANR
The buildup of costs to determine the total annual production
cost is illustrated in Figure 4.2.
4.3 Effect of Location on Plant Cost
The cost models have been developed using U.S. Gulf Coast 1973
costs as a basis. In order to predict plant costs for other
locations, factors have been developed which relate construction
labor costs at various locations to Gulf Coast labor costs. By
multiplying the field labor construction portion of plant cost
by this location factor, the total plant cost is adjusted to
the desired location.
Labor rates for different crafts were obtained from the literature
(10) and escalated to the end of 1973. Using an average craft
mix obtained from in-house information (12), an average construction
labor rate was obtained for each location. Productivity factors
for the various locations, also obtained from in-house data, were
used to create the rate for equal work output. These rates were
202
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then normalized, using Houston (Gulf Coast) as a basis, to yield
relative field labor construction costs.
Table 4.1 lists the relative labor costs determined for twenty
cities. They range from 1.0 for Houston to 2.08 for New York.
Costs are generally highest in the Northeastern quarter of the
country and lowest in the South. These factors are shown on a
map of the U.S. in Figure 4.3.
Table 4.2 lists average location factors for each state. Allowance
has been made in the factor for the importation of temporary labor
to the more remote states. The factors are shown on a map of the
U.S. in Figure 4.4.
Figure 4.5 gives the relationship between major equipment
cost, E, total plant investment, TPI, and location factor, F,
when the contingency, CONTIN, is zero.
203
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TABLE 4 .1
LOCATION FACTORS FOR MAJOR U.S. CITIES
Location
Atlanta
Baltimore
Birmingham
Boston
Chicago
Cincinnati
Cleveland
Dallas
Denver
Detroit
Kansas City
Los Angeles
Minneapolis
New Orleans
New York
Philadelphia
Pittsburgh
St. Louis
San Francisco
Seattle
Location Factor F
1.10
1.41
1.16
1.23
1.52
1.53
1.86
1.07
1.03
1.73
1.37
1.44
1.54
1.16
2.08
1.82
1.52
2.01
1.45
1.21
Houston
1.00
204
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TABLE 4.2
AVERAGE LOCATION FACTORS FOR EACH STATE
State Location Factor
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
D.C.
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
N. Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
S. Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
W. Virginia
Wisconsin
Wyoming
1.2
2.1
1.3
1. 2
1.5
1.2
1.7
1.4
1.4
1.2
1.1
2.0
1.3
1.7
1.6
1.5
1.4
1.5
1.1
1.2
1.4
1.3
1.7
1.5
1.1
1.6
1.3
1.4
1.4
1.2
2.1
1.3
2.1
1.2
1.3
1.6
1.4
1.2
1.6
1.3
1.1
1.3
1.2
1.1
1.2
1.2
1.4
1.2
1.5
1.5
1.3
205
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FIGURE 4.1
RELATIONSHIP BETWEEN CAPITAL COST FACTORS IN THE GENERAL COST MODEL
to
o
a\
MAJOR EQUIPMENT COSTS IE)
OTHER MATERIAL COSTS [Ml
DIRECT FIELD CONSTRUCTION
LABOR COSTS ID
FIELD LABOR INDIRECT COSTS
[FLIC = 043 L)
ENGINEERING FEES
IENGR = OIBIE + MII
FRINGE BENEFITS &
PAYROLL BURDEN
FIELD ADMINISTRATION.
SUPERVISION & TEMPORARY
FACILITIES
CONSTRUCTION EQUIPMENT
& TOOLS
DIRECT PLANT
CONSTRUCTION COSTS
INDIRECT COSTS
OF CONSTRUCTION
TAX & INSURANCE
,TAXI '002 BARC1
BARC PLANT COST
IBARC - 1
(E * M) +
15
43 L)
2
COST OF SITE
WORKING CAPITAL3
[WKC = 020 AOCI
1
CONTRACTOR
OVERHEADS & PROFITS
ICOHP •= 0 10 BARC]
CONTINGENCY 1
(CONTINI
TOTAL PLANT
INVESTMENT (TPII
STARTUP
(STAR -
COSTS
0 20 AOC]
|
INTEREST ON
CONSTRUCTION
CAPITAL
4
TOTAL CAPITAL REQUIREMENT
(TCRI
1 SEE DEFINITION ON PAGE 58
2 COST WOULD NORMALLY BE INCLUDED ONLY IF PURCHASE IS REQUIRED COST IS USUALLY SMALL AND HAS NOT BEEN INCLUDED IN MODEL
3 SEE NOTE 3 OF FIGURE 4 2
4 SEE FIGURE 4 2
-------
FIGURE 4.2
RELATIONSHIP BETWEEN PRODUCTION COST FACTORS IN THE GENERAL COST MODEL
RAW MATERIALS
UTILITIES
CATALYSTS & CHEMICALS
K)
O
WASTE DISPOSAL
BY-PRODUCT CREDIT
COST OF MATERIALS LESS
BY-PRODUCT CREDITS (ANR)
OPERATING LABOR &
SUPERVISION (AOL)
MAINTENANCE LABOR &
MATERIALS [AML - 0018 TPI]
PLANT SUPPLIES &
REPLACEMENTS (APS = 002 TPI]
ADMINISTRATIVE & PLANT
OVERHEADS
[AOH -070 (AOL + AMD)
DEPRECIATION
[ACR = (TCR-WKO/YEARS)
COST OF MONEY
[AIC - 0054 TCR]
FEDERAL INCOME TAX
[AFT = 0018 TCR]
LOCAL TAX & INSURANCE
(ATI - 0.027 TPI]
DIRECT & INDIRECT COST
T COST
FIXED CO!
TOTAL ANNUAL PRODUCTION COST
ITAC]
1 AVERAGE OVER THE PLANT LIFE. ASSUMING 75% DEBT AT 9% INTEREST RATE PER YEAR, AND 25% EQUITY GIVING A NET RETURN OF 15%
2 AVERAGE OVER THE PLANT LIFE. ASSUMING 48% FEDERAL INCOME TAX RATE
3 ANNUAL OPERATING COST IS AOC = ANR + AOL + AML + A»S + AOH + ATI
-------
FIGURE 4.3
LOCATION FACTORS FOR SELECTED CITIES
ro
o
oo
NEW YORK
70S
PHILADELPHIA
1.82
BALTIOMORE
1.41
Hs=r^—^x
v;c-t:3»>^vr. \
fxf /"•> >>
-------
O
vo
FIGURE 4.4
AVERAGE LOCATION FACTORS BY STATE
y//>
S88£
•f,v.-: 1
26
1.50
1.75
.75
1.3
-------
FIGURE 4.5
EFFECT OF LOCATION FACTOR ON TOTAL PLANT INVESTMENT
(CONTINGENCY = 0)
TPI = C • E
SCALE UP
FACTOR C
44 . -
42 - -
40- -
38 . -
36 - -
34 - -
32 - -
30- -
28 - -
26 - -
24 - -
22 ._
20
CHEMICAL
PROCESSING
PLANT
SOLID
HANDLING
PLANT
•\ 1
10 11 12 13 14 15 16 17 18 1.9 2.0
LOCATION FACTOR F
210
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APPENDIX P
DERIVATION OF SQUAT ION FOR TOTAL ANNUAL PRODUCTION COST
DISCOUNTED CASH FLOW METHOD
211
-------
Using the discounter' cash flow method, a constant annual
oroduction cost is calculated which gives the desired dis-
counted rate of return over the proiect life. This oro-
duction cost includes net operating expenses, canital re-
covery, and return on investment. The actual cash flow
would be greater during the early years of a proiect,
gradually diminishing over the li^e of the plant. This
nrovitfes the desired return on investment while maintain-
ing the oroduction cost constant.
In anv year, the cash flow, CF, is given bv the> following
exnression:
CF = denreciation (DEP)
+ net income after taxes (INC)
- capital investment (TCR)
Usina a tax rate of 48%, the net income after taxe? is
52% of the taxable income, TINC. Taxable income is aiven
bv:
TING = total production cost (TAG), which includes
return on investment
- net operating expenses (AOC)
- depreciation (DEP)
Therefore, the net income a^ter taxes is:
INC = O.S2 (TAP - AOC - HEP)
and the exoression for cash flow becomes:
CF = DEP + 0.^2 (TAG - AOC - DE") - TCR
Bv applying a discount factor, DF, to the cash flow,
212
-------
the discounted cash flow, DCF, is obtained. The discount
factor is:
DP =
where r = rate of return, expressed as a fraction
n = year in which discount is being applied.
Thus, the discounted cash flow can be determined by the fol-
lowing equation:
DCF = ()11 [DEP + 0.52 (TAG - AOC - DEP) - TCR]
The discounted cash flow is determined for each year in
terms of known quantities and the only unknown, the total
production cost (TAG) . Setting the sum of all discounted
cash flows over the life of the plant equal to zero provides
the equation for calculating the total production cost.
Year 0
The total capital requirement, TCR, is treated as a capital
cost at start-up completion. Start-up costs, STC, are treat
ed as an expense at start-up completion.
1 0
DCF0 = (~) (-TCR-STC) = -TCR-STC
Year n
An accelerated depreciation schedule (sum-of-the-years-digits
method) has been used. Depreciation is taken over the plant
life, based on the total plant investment, TPI. The depre-
ciation is taken over the plant life, based on the total
plant investment, TPI. The depreciation in year n is given
213
-------
by:
DEP = TPI
n
where a = plant life, years
Substituting this into the general expression for discount
ed cash flow gives, for year n:
DCFn = () [0'48 x 1* TPI + °-52
-------
Setting DCF equal to zero and rearranging terms, the expression becomes:
1
E (_L_)n [0.48 x f)™^ TPI + 0.52 (TAC-AOC)] = TCR + STC -
n=l
Solving for TAG,
£ (^-)n [0.48 x|}Sr] TPI 4- £ (±)n (0.52) (TAC-AOC)
n=l n=l
TCR + STC
0.48 TPI x r S (^-)n U-n+1) + 0.52 (TAC-ADC) I
n=l n=1
TCR + STC
1 l n
0.52(TAC-AOC) Z (^ = TCR + STC +(l+r) - 0.48 TPI x
n=l
__
TOHSTCH- i - 0.48 TPI x ( (t-n-1)
TAG = -
0.52 I
n=l
The summation terra in the denominator is the reciprocal of the uniform
annual series capital recovery factor, which is given by:
* *.
capital recovery factor =
(1+rr -1
215
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Thus,
TAG = — [iii^ ] [TCR+STC- SE£ _ 0.48 TPI x
] + AOC
A 10 percent rate of return has been assumed for all dis-
counted cash flow calculations. Stack gas scrubbing units
have been assumed to have a useful life of 15 years. Using
these values, the equation for TAG can be simplified to:
TAG = 1 [°-10 (] [TCR + STC - „ 0.48 TPI x
U'D (1.10)15 _
16-n ] + AOC =
(15)(16) (1.10)n
TCR+STC-0.239 WKC - 0.291 TPI +
3.955
For stack gas scrubbing units, the following substitutions
can be made:
TCR = TPI + WKC + IDC
WKC =0.20 (AOC + ACRED)
IDC = 0.135 TPI
STC =0.20 (AOC + ACRED)
AOC = 0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR
where IDC = return on investment during construction
ACRED = annual credit for the sale of any by-products
216
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TO = total number of shift operators required
CO = hourly wage of operator, Gulf Coast basis
F = location factor (used to convert labor costs
from a Gulf Coast basis to any other location)
ANR = annual cost of raw materials and utilities, less
by-product credits.
Making these substitutions,
TPI + WKC + IDC + STC - 0.239 WKC - 0.291 TPI AOC
TAC = 3.955
= 0.1793 TPI + 0.1924 WKC + 0.2528 IDC + 0.2528 STC + AOC
= 0.1793 TPI + 0.1924(0.20)(AOC+ACRED) + 0.2528(0.135 TPI)
+ 0.2528(0.20)(AOC+ACRED) + AOC
- 0.213 TPI + 1.09 AOC + 0.09 ACRED
= 0.213 TPI + 1.09 [0.078 TPI + 2.0 TO-COd.O+F) + ANR]
+ 0.09 ACRED
TAC = 0.298 TPI + 2.18 TO.CO(1.0+F) + 1.09 ANR + 0.09 ACRED
217
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APPENDIX E
STACK GAS SCRUBBING COST MODELS FOR UTILITY PLANTS
SUMMARY
218
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COST MODEL FOR THE WET LIMESTONE PROCESS*
Capital Cost Model
In order to estimate capital costs, the wet limestone process
was divided into three sections:
1) Chemical processing equipment
2) Solids handling equipment
3} Settling pond
Based on the Catalytic estimate (3 ), costs were determined
for the pond and all pieces of equipment. These costs were
then related to primary utility plant variables in order to
allow scaling of costs to different size plants.
The following equations summarize the chemical processing
equipment costs, EC, and the solids handling equipment costs,
ES:
EC = 2RB[1041(GT/550)°l5 + 408(GT/550)°'9]
+~238 RP (GP/3300)0'5 + 201 (SF/28)°'5 M $
ES = 1680 (SF/28)0'9 M $
where GP = total gas flow rate into the control unit (MACFM)
GT = gas flow rate to each scrubber train (MACFM)
NA = number of scrubber trains
SF = total sulfur flow rate into the control unit
(M Ibs/hr of sulfur)
RB and RP are retrofit factors which are included to reflect
*For complete description, see section 5. of Part 1 of this
study.
219
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the difficulty and increased cost of retrofitting a control
system in an existing olant, as opposed to a new instal-
lation. The cost of the settling pond, P, was found to
be:
qp TP °'9
P = 5000 C^-—-) M $
where LF = plant load factor (expressed as a fraction)
Other material costs, M, and field labor costs, L, were de-
rived from the Catalytic estimate and expressed as a fraction
of equipment costs. They are summarized as follows:
M = 0.82 EC + 0.09 ES M $
L = 0.39 EC + 0.18 ES M $
The bare cost of the plant, BARC, the total plant investment,
TPI, and the total capital requirement, TCR, are given by the
appropriate equations in the General Cost Model. Note that
since the major portion of the cost of the settling pond is
the labor cost for excavation and construction, this item
has been included with the overall field labor cost. Thus:
BARC = 1.15 (E+M) + (P + 1.43 L) F M $
TPI = 1.12 (1.0 + CONTIN) BARC M $
TCR =1.15 TPI + 0.8 TO-COd+F) +0.4 ANR M $
where F = location factor (used to convert labor costs from
a Gulf Coast basis to any other location)
CONTIN = contingency for the process design and cost
estimate (expressed as a fraction)
TO = total number of shift operators required
CO = hourly wage of operator. Gulf Coast basis (S/hr.)
ANR = cost of raw materials and utilities (M$/yr.)
220
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Operating Cost Model
Raw materials and utilities consumed by the process include
limestone, ammonia, water, fuel oil, and electricity. Process
requirements were derived from the Catalytic estimate and re-
lated to the primary utility plant variables. The cost of
raw materials and utilities, ANR, was determined to be:
ANR = 600 CL-LF (SF/28) + 0.43 CA (SF/28)
+ 230 CWLF [(GP/3300) + (SF/28)]
+ 1800 CF-LF (GP/3300)
+ CE-LF [213 (GP/3300) + 35 (SF/28)] M $/yr,
Unit costs used in the model are:
limestone
ammonia
water
fuel oil
- CL = $4.00/ton
- CA = $50.00/ton
- CW = $0.20/103gal.
CF = $0.80/106Btu
electricity - CE =88.00 mills/KWH
The total net annual operating cost, AOC, and the total annual
production cost, TAG, are obtained from the General Cost Model:
AOC = 0.078 TPI + 2.0 TO-CO (1.0+F) + ANR M $/yr.
TAG = 0.237 TPI +2.1 TO-CO (1.0+F) + 1.04 ANR M $/yr.
The total number of shift operators, TO, for the wet lime-
stone process was determined to be eight (two men/shift) for
plant capacities of 200 MW or more. For plants smaller than
200 MW, the cost of operating labor has been assumed to de-
crease linearly with size.
221
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COST MODEL FOR THE WELLMAN/ALLIED PROCESS*
Capital Cost Model
The Wellman/Allied process was divided into four sections:
1) Absorber area
2) S0_ regeneration area
3) Purge/make-up area
4) S02 reduction area (Allied Chemical plant)
Based on the Wellman-Lord and Allied Chemical estimate, costs
were determined for all pieces of equipment and related to
utility plant variables for scaling purposes. The following
equations summarize the equipment costs for the absorber area,
EA, for the S02 regeneration area, ES, for the purge/make-up
area, EP, and for the S02 reduction area, ER:
NA
EA = V RB[726(GT/550)°'5 + 639(GT/550)°*9]n
+ 119.RP(GP/3300)°*5
+ [133(S7/7)°'5 + 127 IF(S7/7)°'6] N7 M $
ES = [209(S7/7)°>5 + 618(S7/7)°-6 -I- 157 (S7/7)0>9] N7 M $
EP = [525(S28/28)°'5 + 380(S28/28)°'6 + 86(S28/28)°*7
+ 306(S28/28)°'8 + 519(S28/28)°'9] N28 M $
ER = 998(SF/28)°'5 + 287(SF/28)°*6 + 683(SF/28)°'9 M $
where S7 = sulfur flow rate per train where the maximum flow
per train is limited to 7000 Ibs/hr. of sulfur
(M Ibs/hr of sulfur)
* For complete description, see section 6. of Part 1 of this
study.
222
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S28 = sulfur flow rate per train where the maximum flow
per train is limited to 28,000 Ibs./hr. of sulfur
(M Ibs./hr. of sulfur)
N7 = number of trains of size S7
N28 = number of trains of size S28
IF = particulate index; = 1 if particulates present, =
0 if particulates absent.
Other material costs, M, and field labor costs, L, were derived
from the estimate and are summarized as follows:
M - 0.429 EA + 0.742 ES + 0.827 EP + 0.772 ER M $
L = 0.224 EA + 0.310 ES + 0.433 EP + 0.623 ER M $
The bare cost, BARC, the total plant investment, TPI, and the
total capital requirement, TCR, are given by equations in the
General Cost Model:
BARC = 1.15 (EH-M) + 1.43 L-F M $
TPI = 1.12 (1.0 + CONTIN) BARC M $
TCR = 1.15 TPI +0.8 TO'CO (1+F) +0.4 ANR M $
Operating Cost Model
Raw materials and utilities consumption of the Wellman/Allied
process include sodium carbonate, natural gas, filter aid,
power (electricity), steam, cooling water, process water, and
fuel oil. Possible credits include sulfur, and a purge solids
stream. Process requirements for raw materials and utilities,
and production of by-products were derived from the Wellman-
Lord and Allied Chemical estimate and related to the utility
plant variables. The cost of raw materials and utilities less
credits, ANR, was found to be:
223
-------
ANR = 28.2 CS-LF(SF/28) + 1460 CN-LF(SF/28)
+ 1.24 CFA-LF-IF(GP/3300)
+ CE-LF [154(GP/3300) + 79(SF/28)]
+ 5430 CH.LF(SF/28)
+ CCW-LF[856(GP/3300) + 19,900(SF/28)]
+ 64(SF/28) CW-LF + 1800 CF-LF(GP/3300)
- 95.4(SF/28)VSC-LF - 37.3(SF/28) VPS-LF
M $/yr.
Unit costs used in the model are:
sodium carbonate - CS
natural gas - CN
filter aid - CFA
electricity - CE
steam - CH
cooling water - CCW
process water - CW
fuel oil - CF
sulfur - VSC
purge solids - VPS
= $40.00/ton
= $0.50/103SCF
= $50.00/ton
8.00 mills/KWH
= $0.50/103lbs.
- $0.02/103gal.
= $0.20/103gal.
= $0.80/MMBtu
= $5.00/long ton
= -$1.00/ton
The total net annual operating cost, AOCf and the total
annual production cost, TAG, are obtained from the General
Cost Model:
AOC = 0.078 + PI + 2.0 TO'CO(1.0+F) + ANR M $/yr.
TAG = 0.237 TPI + 2.1 TO-CO (1.0+F) + 1.04 ANR M $/yr.
The total number of shift operators, TO, for the Wellman/
Allied process was found to be sixteen (four men/shift) for
plant capacities of 200 MW or more. For plants smaller than
200 MW, the cost of operating labor has been assumed to de-
crease linearly with size.
224
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APPENDIX F
PACKAGED LIMESTONE SCRUBBING SYSTEM ^OR 50
225
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Description of Mechanical Equipment
A. Scrubbing System
100-S Venturi Scrubber; Variable throat for constant AP
18,000 ACFM @ 300°F (12,300 SCFM)
198 GPM @ 127°F of 19 wt % limestone slurry
Inlet dust loading =4.74 gr/MSCFM
Outlet dust loading - .021 gr/MSCFM
L/G =11.0 GPM/MSCFM inlet gas
AP = 10" H20
C. S. with platsite 7122 (a plastic coating) and 2 in
Kaocrete
Dimensions: 2l4llwx4'6"lx5'h (UOP)
100-F Venturi Recirculation Tank 5 minutes retention
1192 gal. of 19 % limestone slurry
3/16" C. S., rubber lined, open top
1/4" flat bottom
Dimensions: 6' dia. x 61 h (Smith Industries)
103-L Venturi Recirculating Tank Agitator
For 100-F to maintain solids suspension
Open-type agitator with worm-gear reducer drive mechanism
Speed = 1100 ft/min HP = 5.0
Dimensions: 6'3"dJLa. x 718" h. (Denver)
100-J Venturi Recirculating Pump and Drive
2 at 100% capacity (1 spare)
224 GPM of 19 wt % limestone slurry @ 127°F
Centrifugal, outside, slide type maintenance base,
226
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rubber internals
HP = 15 ea
Size 3" suction, 3" discharge
Dimensions: 3' wx 2'6" 1 x 3' h (Denver)
101-E TCA Scrubber with 3 Beds
13,000 SCFM of gas
Gas Velocity 12.5 ft/sec.
990 GPM @ 127°F of 10 wt % limestone slurry
L/G =55.0 GPM/MSCFM of inlet gas to Venturi
Removal efficiency: 90% of S02 removal using 3.5% sulfur
coal (330 Ibs/hr SO2)
AP = 8" H20
1/4" Corten with Neoprene lining
Dimensions: 5'6"wx5llx40Ih (UOP)
102-F Scrubber Sump 5 minute retention
The Venturi and TCA Scrubber will be mourited on top of the
sump
C.S. with polyester coating and 2" Kaocrete
Dimensions: 10' w x 5' 1 x 40' h (UOP)
101-F TCA Recirculation Tank 5 minute retention
5328 gal. of 10 wt % limestone slurry
3/16" C.S., rubber lines, open top, 1/4" flat bottom
Dimensions: 10' dia. x 10' h (Smith Industries)
101-J TCA Recirculation Pump and Drive
2 at 100% capacity (1 spare)
1050 GPM of 10 wt % limestone slurry @ 127°F
Centrifugal, outside, slide type maintenance base,
rubber internals
HP = 40 ea.
Size: 8" suction 6" discharge
Dimensions: 5Iwx4'lx4'h (Denver)
227
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110-F Liquid Ammonia Storage Tank
30, 15 minute adjustments
160 gal. @ 175°F, 350 psig
Horizontal pressure vessel with a u-tube heating coil
(1/2" d x 4" 1) for heating the ammonia. Nozzles, safety
equipment, 2 elliptical heads
Dimensions: 2'6" w x 4'6" 1 (Wyatt)
110-B Direct Fired Gas Reheater
622,000 BTU/Hr
13,300 SCFM from 127°F to 200°F
Oil burner type using No. 2 fuel oil
Dimensions: 5'wx6' 1 x 2'6" h
(John Zink Co.)
105-J Fuel Oil Pump and Drive
1.0 GPM of No. 2 fuel oil
Vertical, inline
HP = 5.0
Size: 2" suction x 1-1/2" discharge
Dimensions: 6" w x 15" 1 x 30" h
(Ingersoll-Rand)
108-F Fuel Oil Storage Tank
8640 gal. of No. 2 fuel oil
3/16" C.S. Cone Roof, 1/4" flat bottom
Dimensions: 11' dia. x 14' h
(30 day supply)
1Q8-J Fuel Oil Loading Pump
4.0 GPM of No. 2 fuel
Vertical, inline
HP = 5.0
Size 2" suction, 1-1/2" discharge
Dimensions: 6" w x 15" 1 x 30' h
228
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113-J Induced Draft Fan
18,250 ACFM @ 200°F for 30 in. H20 differential pressure
HP = 125
Single inlet, St. S. flanged inlet and outlet connections,
wear strip, split housing, access door, drain connections
Dimensions: 68" w x 44" 1 x 72" h (Buffalo Forge)
Ductwork
142 '3" of square duct 2 '3" x 2 '3"
Inlet Gas Duct to Venturi 42 '6"
Duct from TCA Scrubber 6 '3"
to Entrainment Separator 3'0"
From Reheater to I.D. Fan 5*3"
From Reheater to I.D. Fan 63 '0"
From I.D. Fan to Stack 5'0"
From I.D. Fan to Stack 10 "0"
From I.D. Fan to Stack 2'0"
By-Pass From Inlet to Outlet Duct 5 "3
"
Transition Pieces
From TCA Scrubber to Duct
5'6" x 51 -»• 2'3" 6 '3"
Duct to Entrainment Separator
2'3" x 2'3" ->• 6' x 6' 4'0"
Entrainment Separator to Reheater
6' x 61 -»• 6' x 5" 7'0"
Reheater to Duct
61 x 51 -»• 2'3" x 2'3" 5 '3"
100-G Venturi Damper
for 2 '3" x 2 '3" duct
Opposed blades, multi-louvre with actuator installed in
inlet duct to Venturi (Buffalo Forge)
229
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104-L TCA Recirculating TK Agitator
For 101-F to maintain solids suspension
Open-type agitator with worm-gear reducer drive mechanism
Speed: 900 ft/min. HP = 10.0
Dimension: 10'1" dia. x 12'4" h (Denver)
102-L Horizontal 2 Stage Entrainment Separator
13,000 SCFM at 8 ft/sec.
2
Wash water 5 gm/ft of cross sectional area
The complete unit will include a casing (housing) built"
in collecting tank, spray nozzles, baffles, chevron type
eliminator blades and all internal piping
Dimensions: 6' x 6' x 61 (UOP)
107-F Entrainment Separator Recirculation Tank 5 minute retention
888 GPM of water
3/16" C.S. (coal tar epoxy coated), open top
1/4" flat bottom. A baffle in the tank divides the
chamber into two equal parts.
Dimensions: 6' dia. x 6' h (Smith Industries)
107- 1st Stage Entrainment Separator Recirculation
Pump and Drive
2 @ 100% capacity (1 spare)
178 GPM of water
Vertical, inline
HP = 10
Size: 3" suction x 2" discharge,
Dimensions: 6" w x 17" 1 x 43" h (Ingersoll-Rand)
108-J 2nd Stage Entrainment Separator Recirculation
Pump and Drive
2 @ 100% capacity (1 spare)
160 GPM of water
Vertical, inline
HP - 10
Size: 3" suction, 2" discharge,
Dimensions: 6" w x 17" 1 x 43" h (Ingersoll-Rand)
230
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101-G By-pass Damper
For 2'3 x 2'3" by-pass duct from inlet to outlet duct.
Guillotine type with actuator (Buffalo Forge)
102-G Fan Damper
For 2'3" x 2'3" outlet duct to stack.
Opposed blade, multi louvre with actuator (Buffalo Forge)
103-G Inlet Box Fan Damper
To be installed in the inlet fan box
Box dimension 14 1/4" x 59"
Parallel blade
B. Limestone Handling and Slurry Preparation
Stock-pile 30 day supply
288 tons 3/4" crushed limestone
Dimensions: 38' dia-» 19' Hi
108-L Stock-pile Feeder
2.4 TPH, vibrating feeder. Complete with hopper.
Openings 3' dia and 6" dia. at the bottom.
Dimensions: 3'10" x 3'10", 2'7" deep (Vibranetie)
101-V Limestone Silo Conveyor
Belt conveyor, 18" wide, 145 ft. long.
16 ft. horizontal
129 ft. at 20° for 44• vertical lift.
Capacity 2.4 TPH (Hi-Line)
103-F Limestone Storage Silo (1 day supply)
9.6 tons
Atmospheric pressure and temperature. Two cones.
1/4" shell, 3/8" bottom carbon steel.
231
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104-F Ball Mill Surge Tank
4.5 GPM of 60 wt % limestone slurry.
80°F, atmospheric pressure
3/16" C.S.f coal tar expoxy coated, 1/4" flat bottom.
Dimensions: 3'diam., 3' H
102-J Limestone Slurry Transfer Pump & Drive
2 at 100% capacity
1.5 GPM of limestone slurry
HP = 10
Centrifugal, rubber internals
Size: 1 1/2" suction, 1 1/4" discharge
Dimensions: 2' W, 2'7" L, 2' H
114-J Ball Mill Air Compressor
50 ACFM @ 120 psig
460 volt, single stage.
Dimensions: 2'9", 4'5" long, 5' H
C. Waste Disposal, Settling Pond
109-F Slurry Over-flow Surge Tank
13.0 GPM of 19 wt % limestone slurry @ 80°F
3/10" C.S. coal tar epoxy coated, open top
1/4" flat bottom.
Dimensions: 3' diam., 31 H (Maloney-Crawford)
104-J Slurry Over-flow Transfer Pump & Drive
2 pumps @ 100% capacity (1 spare)
13.8 GPM of 19 wt % limestone slurry @ 127°F rubber internals
HP = 10
Size 1 1/2" suction, 1 1/4" discharge
Dimensions: 2' W, 2'7" L, 21 Hi (Denver)
232
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112-J Tunnel Sump Pump
5GPM
105-F Limestone Slurry Hold Tank (1 day supply)
2160 Gal of 60 wt % limestone slurry
3/16" C. Stl open top, 1/4" flat bottom, rubber lined
Dimensions: 7' dia., 7' H (Smith Industries)
105-L Limestone Slurry Tank Agitator
For 105-F Open type Agitator with axial-flow propeller and
worm-gear reducer drive.
Speed = 900 ft/min, HP = 15
Dimensions: 7'3" dia., 8'10" H.
103-J Limestone Slurry Feed Pump & Drive
2 at 100% capacity (1 spare)
4.1 Gal of limestone slurry.
HP = 10
Centrifugal, rubber internals.
109-L Limestone Weigh Feeder
Two 600 Ibs/hr max., 400 Ibs/hr min.
12" width, 35" length.
Gravimetric feeder with digital controller.
(Merrick)
106-L Ball Mill Wet Grinder
2 mills at 100% capacity
Capacity 9.6 TPH
33 RPM HP = 15
3/4" limestone to a product size of. 70%
minus 200 mesh.
Dimensions: 3' dia., 9'9" long, 6' H (Denver)
233
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106-F Process Water Surge Tank
25.0 GPM of water at 80°F
3/16" C.S. coal tar epoxy coated, open top
1/4" flat bottom.
Dimensions: 3' dia., 3' H. (Maloney-Crawford)
106-J Process Water Pump & Drive
2 @ 100% capacity (1 spare)
38.0 GPM of water
HP = 15
Vertical, in-line
Size 2" suction, 1 1/2" discharge
Dimensions: 8" wide, 17" long 44" H.
111-J Emergency Process Water Pump & Drive
38.0 GPM of water
HP = 15
Vertical, in-line
Size 2" suction, 1 1/2" discharge
Dimensions: 8" wide, 17" long, 44" H.
Settling Pond 15 yrs capacity
2.3 acres, 50' deep
80% service factor
Dimensions: 317' x 317' W x 50' H.
234
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APPENDIX
SAMPLE CALCULATION O^ COST OF SNC- AND SP.C
235
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Total annual cost of production has been related to total plant
investment (TPI). Total plant investment includes bare cost
(including contingency) of the plant, taxes and insurance, and
contractor's overhead and profits. Contingency has been
considered equal to zero. Total annual cost of production is
given by
TAG = 0.225 TPI + 2.1 TO-CO (1 + F) + 1.04 ANR
where
TO = Total number of plant operators
300 for SNG; 200 for SRC
CO = Unit cost of operating labor ($7.00/hr)
F = Location factor
ANR = Annual cost of raw materials, utilities, waste
disposal less by product credit
A summary of procedures to calculate cost of production of SNG
Q
and SRC is as follows for a plant capacity of 250 x 10
Btu/day.
SNG Plant;
Cost of the equipment (E) is related to the caj?5on. and sulfur
content of coal. When the carbon and sulfur content of the
coal do not affect equipment size, fixed costs have been used.
Equipment costs have been divided into the category of solid
handling and chemical processing plant and multiplied by a
fixed multiple (C) to get total plant investment. The value
of C varies from 2.4 to 3.1 for solid handling and 3.3 to 4.2
for a chemical processing nlant for location factors between 1.0
(Gulf Coast) and 2.0.
236
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Equipment costs for an SNG olant are as follows:
1. Coal Preparation and Handling
El = 2100 M$
2. Fine Agglomeration
E2 = 5000 - 100 (PCARB-65) M$
3. Coal Gasification
E3 = 14800 + 160 (PCARB-65) M$
4. Shift Conversion and Gas Cooling
E4 = 4500 M$
5. Gas Purification by the Rectisol Process
E5 = 1300 + 200 PSULF M$
6. Methane Synthesis
E6 = 5500 M$
7. SNG Compression
E7 = 3000 M$
8. Oxygen Plant
E8 = 9700 + 160 (PCARB-65) M$
9. Phenosolvan Unit
E9 = 1800 M$
10. Furnace Stack Gas Scrubbing and Plant Sulfur Recovery
CIO = 1250 PSULF + 1065 (TDAFC-PSULF)°'6 M$
11. Utility Plant
Ell = 13800 + 200 (PCARB-65) M$ -
12. Other Offsites
E12 = 14000 M$
where
PCARB = percent carbon in coal on dry ash free basis
PSULF = percent sulfur in coal on dry ash free basis
TDAFC = total dry ash free coal requirement for a
250 x 109 Btu/day SNG plant
237
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For evaluating Total Plant Investment, sections 1 to 3 fall under
the category of coal handling plant while the remaining sections
are chemical processing plants.
q
The total dry ash free coal requirement for a 250 x 10" Btu/day
SNG plant is given by:
TDAFC = 1.51 - 0.0156 (PCARB-65) million Ib/hr
9
The total as received coal requirement {TCOAL) of a 250 x 10
Btu/day SNG plant is given by:
TCOAL = 100 TDAFC/(100 - PH20 - PASH) million Ib/hr
Annual cost of raw materials, utilities less by product credit
(ANR) is given by:
ANR « ACOAL + ACHEM - ASULF
where, ACOAL is annual cost of coal feed to the plant and
is given by:
ACOAL = I?, x CCOAL - TCOAL • SD M$/yr
ACHEM is annual cost of catalyst and chemicals, assumed constant
at 1600 M$.
ASULF is the annual credit for the sale of sulfur. It is assumed
that 80% of tne sulfur in coal is recovered as by-product
and is given by:
ASULF =0.1 CSULF'TDAFC'PSULF-SD M$/yr.
CCOAL = Unit cost of coal feed to plant in $/ton
CSULF = Unit credit for sulfur in $/ton
SD = Number of days the plant is on stream per year
(330 days)
238
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Example; Coal from Jefferson mine, Walker county in Alabama.
Location Factor = 1.2 (for Alabama)
Coal details: Bituminous PCARB = 83.2; PSULF =1.64
PH20 = 4.1; PASH =4.2
TDAFC = 1.51 - .0156 (83.2-65) = 1.23 million Ib/hr
TCOAL = 100 x 1.23/UOO-4.1-4.2) = 1.34 million Ib/hr
Cost of coal = $12.80/ton
Scale up factor (C) to evaluate total plant investment
C = 2.57 solid handling, section 1 to 3
C = 3.46 chemical processing, section 4 to 12
Section
1
2
3
4
5
6
7
8
9
10
11
12
E, M$
2100
3180
17712
4500
13328
5500
3000
12612
1800
3423
17440
14000
TPI, M$
5397
8173
45520
15570
46115
19030
10380
43638
6228
11842
60342
48440
TPI = 320675 M$
ACOAL = 12 x 12.80 x 1.34 x 330 =
ASULF = 0.1 x 10 x 1.23 x 1.64 x 330
67922 M?
666 M$
ANR = 67922 + 1600 - 666
= 68856 M$
239
-------
TAG = 0.225 TPI +2.1 TO-CO (1 + F) + 1.04 ANR
= 0.225 x 320675 + 2.1 x 300 x 7 x 2.2 + 1.04 x 68856
= $153.464 million
Annual Gas Production =82.5 million MMBtu/year
Cost of Production = 153.464/82.5
= $1.86/MMBtu
SRC Plant;
g
The total plant investment for a plant producing 250 x 10
Btu/day of solvent refined coal is given below
Section Total Plant Investment (TPI)
Number Section Description M$ for F=1.0
1 Coal preparation (solid
handling section) 10,000
2 Preheater/dissolvers 40,000
3 Ash filtration, drying
and disposal 15,000
4 Solvent/light oil/cresylic
acid recovery 30,000
5 Product solidification/
handling and storage 10,000
6 Hydrogen plant 10,000
7 Sulfur removal from fuels
and sulfur recovery 10,000
8 Steam and power generation 10,000
9 Other offsites 30,000
165,000
If F = 2.0, the value of TPI is $215 million.
The annual cost of raw materials, utilities, les-s by-oroduct
credits (ANR) is given by:
ANR = ACOAL + ACHEM - ASULF - ACRES
240
-------
ACOAL is the annual cost of coal feed to the plant in M$.
It is assumed that 80% of heating value in coal is recovered
as SRC.
ACHEM is the annual cost of catalysts and chemicals and is
assumed constant at 500 M$.
ASULF is the annual credit for by product-sulfur. It is
assumed that 40% of the sulfur in coal is recovered as by
product.
ACRES is the annual credit for the sale of cresylic acid.
It is assumed that 170 tons/day of cresylic acid is obtained
as by product and sells for $100/ton.
Example; Coal from Jefferson mine, Walker county in Alabama
Location Factor = 1.2
Total Plant Investment = 175092 M$
Coal Details: Bituminous PCARB = 83.2, PSULF =1.64
PH20 =4.1 , PASH =4.2
HHV = 13590 Btu/lb as received
Unit cost = $12.80/ton
Coal feed - 13590x0*8x2000 - 1150° ^ns/day
By-Products: Sulfur = 11500 x 0.015 x 0.4 = 61 LT/day @ $10/LT
Cresylic Acid = 170 tons/day @ $100/ton
ACOAL = 11500 x 12.80 x 330 = 48576 M$
ASULF = 61 x 10 x 330 = 201 M$
ACRES = 170 x 100 x 330 = 5610 M$
ACHEM = Cost of catalysts and chemicals = 500 M$
241
-------
ANR = 48576 + 500 - 201 - 5610
= 43265 M$
TAG = 0.225 x 175092 + 2.1 x 200 x 7 (1+1.2) + 1.04 x 43265
= $90.86 million/year
g
Annual SRC production = 250 x 10 x 330 Btu
= 82.5 million million Btu
Cost of SRC = $90.86/82.5 MMBtu
- $ 1.10/MMBtu
242
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APPENDIX H
SAMPLE CALCULATION OF COST OP INTERMEDIATE RTU GAS
243
-------
Example;
Location; Alabama F = 1.2
Coal Details; Bituminous PCARB = 83.2%, PSULF = 1.64%
PH20 = 4.1%, PASH =4.2
CCOAL = $12.80/ton
Other Information;
SD = 330 CSULF = $10/ton CO = $7/hour
Derived Information;
C = 2.57 Section 1 to 3
C = 3.46 Section 4 to 10
TDAFC = 0.651 - 0.0067 x (83.2 - 65) = 0.529 million Ib/hr
Section EM$ TPI M$
1
2
3
4
5
6
7
8
9
10
1250
1650
7684
800
1400
6416
920
204
8592
6500
3213
4240
19748
2768
4844
22200
3183
706
29728
22490
113120
TPI = $113.12 million
244
-------
TCOAL = 0.529/0.917 = 0.577 million Ib/hr
ACOAL = 12 x 12.80 x 0.577 x 330 = 29247 M$
ASULF = 0.1 x 10 x .529 x 1.64 x 330 = 286 M$
ANR = 29247 + 400 - 286 = 29361 M$
TCR = 1.21 x 113120 + 0.8 x 150 x 7 (1 + 1.2) + 0.4 x 29361
TCR = $150.5 million
TAG = 0.225 x 113120 + 2.1 x 150 x 7 (1 + 1.2) + 1.04 x 29361
TAG = $60.84 million
AGP = 125 x 109 x 330 = 41.25 million MMBtu/year
The gas cost = 60.84/41.25 = $1.47/MMBtu
245
-------
APPFNDTV I
SAMPLE CALCULATION OF1 COST OF LOW BTU
246
-------
Example;
Location: Alabama F = 1.2
Coal Details: Bituminous PCARB = 83.2%, PSULF = 1.64%
PH20 = 4.1%, PASH =4.2%
CCOAL = $12.80/ton
0 the r In formation;
SD = 330 CSULF = $10/ton CO = $7/hour CPOWER = 8 mils/KWH
Derived Information;
C = 2.57 Section 1 to 3
C = 3.46 Section 4 to 10
TDAFC = 0.683 - .0071 (83.2-65) = 0.554 million Ib/hr
Section
1
2
3
4
5
6
7
8
9
10
EM$
1300
1730
8356
700
1780
950
228
6550
1214
6000
TPI M$
3341
4446
21475
2422
6159
3287
789
22663
4200
20760
89542
TPI = $ 89.542 million
247
-------
TCOAL = 0.554/0.917 = 0.604 million Ib/hr
ACOAL = 12 x 12.80 x 0.604 x 330 = 30616 M$
ASULF = 0.1 x 10 x 0.554 x 330 = 183 M$
ACHEM = 420 M$
APOWER = 1.1 x 8 x 330 = 2904
ANR = 30616 + 420 - 183 - 2904 = 29749 M$
TCR = 1.21 x 89542 + 0.8 x 150 x 7 (1+1.2) + 0.4 x 27949
TCR = $121.4 million
TAG = 0.225 x 89542 + 2.1 x 150 x 7 (1+1.2) + 1.04 x 27949
TAG = 54065 M$
AGP = 125 x 109 x 330 = 41.25 million MMBtu
The gas cost = 54.065/41.25
= $1.3l/MMBtu
248
-------
APPENDIX J
NOMENCLATURE
249
-------
AA Annual cost of ammonia M$/year
ACHEM Annual cost of catalysts and chemicals M$/year
ACOAL Annual cost of coal feed M$/year
ACR Annual depreciation M$/year
ACRED Annual credit for by-products M$/year
ACW Annual cost of cooling water M$/year
AE Annual cost of electricity M$/year
AF Annual cost of fuel oil M$/year
AFT Annual federal income tax M$/year
AH Annual cost of steam M$/year
AIC Annual interest on debt and return M$/year
on capital
AL Annual cost of limestone M$/year
AML Annual cost of maintenance labor and M$/year
supervision
AN Annual cost of natural gas M$/year
ANR Annual cost of raw materials, utilities M$/year
and waste disposal, less by-product cre-
dits
AOC Total net annual operating cost M$/year
AOH Annual cost of administration and M$/year
overheads
AOL Annual cost of operating labor and M$/year
supervision
APOWER Annual credit for power available for M$/year
sale
APS Annual cost of plant supplies and re- M$/year
placement
or
Annual credit for purge solids M$/year
AS Annual cost of sodium carbonate M$/year
ASA Annual credit for recovered sulfuric M$/year
acid
ASC Annual credit for recovered sulfur M$/year
ASD Annual credit for recovered sulfur M$/year
dioxide
ASULF Annual credit for recovered sulfur M$/year
ATI Annual cost of local taxes and insurance M$/year
AW Annual cost of process water M$/year
BARC Bare cost of the control plant M$
250
-------
CA
CCOAL
CCW
CE
CP
CH
CL
CN
CO
CONG
CONTIN
CPOWER
CS
CSULF
CW
E
EA
EA1
EAli
EA2
EA3
EC
EC1
ECli
Purchase price of ammonia
Unit cost of coal, as received
Unit cost of cooling water
Purchase (or transfer) price of
electricity
Purchase price of fuel oil
Purchase (or transfer) price of steam
Purchase price of limestone
Purchase price of natural gas
Unit cost of operating labor
Sulfuric acid mist concentration
Sulfuric acid plant product concentra-
tion
Contingency
Unit cost of power
Purchase price of sodium carbonate
Unit credit for recovered sulfur
Unit cost of process water
Total major equipment cost
Major equipment costs, Wellman/Allied
Total major equipment costs related
to scrubbing train, Wellman/Allied
model for industrial boilers
Major equipment costs related to the
"i" th scrubbing train, Wellman/Allied
model for industrial boilers
$/ton
$/ton
$/M gal
mills/KWH
$/MM Btu
$/M Ibs
$/ton
$/MSCF
$/hour
wt. frac.H-SO.
wt. frac.H_SO,.
mills/KWH
$/ton
$/ton
$/M gal
M$
M$
M$
M$
Major equipment costs related to the M$
total gas flow to control plant, Wellman/
Allied model for industrial boilers
Major equipment costs in the absorber M$
area related to the sulfur flow to the
control plant, Wellman/Allied model
for industrial boilers
Major equipment costs, wet limestone M$
model, chemical processing equipment
Total major equipment costs related M$
to scrubbing trains, wet limestone
model for industrial boilers
Major equipment costs related to the M$
"i"th scrubbing train, wet limestone
model for industrial boilers
251
-------
EC2 Major equipment costs related to total M$
gas flow to control plant, wet limestone
model for industrial boilers
EC3 Major chemical processing equipment M$
costs related to the sulfur flow to the
control plant, wet limestone model
for industrial boilers
EP Major equipment costs, Wellman/Allied M$
model, purge/make-up area
ER Major equipment costs, Wellman/Allied M$
model SCL reduction area
ES Major equipment costs, Wellman/Allied M$
model, S02 regeneration area
or
Major equipment costs, wet limestone M$
model, solids handling equipment
F Location factor
FR Sulfuric acid plant operating costs as
a fraction of sulfuric acid value (VSA)
GP Total gas flow to the control plant MACFM
GTi Gas flow to the "i"th scrubbing train MACFM
IDC Interest during construction M$
or
Return on investment during construction M$
IF Particulate index (=1 if particulates
present in gas to control plant, =0
if partuculates absent)
1 Life of control plant years
L Field labor costs M$
LA Field labor costs, Wellman/Allied model, M$
absorber area
LC Field labor costs, wet limestone model, M$
chemical process equipment
LF Load factor of the emissions source
plant
LP Field labor costs, Wellman/Allied model, M$
purge/make-up area
LR Field labor costs, Wellman/Allied model, M$
SO- reduction area
LS Field labor costs, Wellman/Allied model, M$
SCL regeneration area
or
Field labor costs, wet limestone model, M$
solids handling equipment
252
-------
M Field material costs M$
MA Field material costs, Wellman/Allied M$
model absorber area
MC Field materials costs, wet limestone M$
model, chemical process equipment
MP Field materials costs, Wellman/Allied M$
model, purge/make-up area
MR Field materials costs, Wellman/Allied M§
model, S02 reduction area
MS Field materials costs, Wellman/Allied M$
model, S02 regeneration area
or
Field material costs, wet limestone M$
model, solids handling equipment
NA Number of absorber trains
NAT Number of absorber trains, Wellman/Allied
model for industrial boilers
N7 Number of trains of sulfur-related
equipment in the absorber and SO, regen-
eration areas, Wellman/Allied model
N28 Number of equipment trains in the purge/
make-up area, Wellman/Allied model
P Cost of limestone sludge settling pond M$
PASH Percent ash in coal feed, as received
basis
PCARB Percent carbon in coal feed, dry ash-
free basis
PH20 Percent moisture in coal feed, as received
basis
PSULF Percent sulfur in coal feed, dry ash-
free basis
r Discounted cash flow rate of return on
investment (fraction)
RBi Retrofit difficulty factor for boiler "r"
RF Retrofit difficulty factor for sulfuric
acid plants
RP Retrofit difficulty factor for equipment
in scrubbing section not in parallel trains,
wet limestone and Wellman/Allied models
for utility and industrial boiler plants
S Sulfur flow (From SO,) to the control Ibs/hour
plant, Wellman-Lord model for sulfuric
acid plants
253
-------
SD
SF
SM
STC
S7
828
TAG
TCOAL
TCR
TO
TPI
VPS
VSA
VSC
VSD
WKC
Number of plant operating (stream)
days per year
Total sulfur flow to the control plant
Sulfur flow (from acid mist) to the
control plant, Wellman-Lord model for
sulfuric acid plants
Start-up costs
Total sulfur flow to control plant
per train of sulfur-related equipment
in the absorber and SO, regeneration
areas, Wellman/Allied model
Total sulfur flow to control plant
per train of equipment in the purge/
make-up area, WeiIman/Allied model
Total annual production cost
Total coal feed, as received basis
Total capital required
Total number of shift operators
Total plant investment
Unit value of purge solids
Unit value of sulfuric acid
Unit value of recovered sulfur
Unit value of recovered sulfur dioxide
Working capital
M Ibs/hour
Ibs/hour
M$
M Ibs/hour
M Ibs/hour
M$/year
MM Ibs/hour
M$
M$
$/ton
$/ton
$/long ton
$/ton
M$
254
-------
TECHNICAL REPORT DATA
IPIeafc read luaniciiuns on the re\crse before completing)
REPORT NO
EPA-650/2-74-098-a
3 RECIPIENT'S ACCESSION-NO.
4 TITLE AND SUBTITLE
Evaluation of R&D Investment Alternatives for SOX
Air Pollution Control Processes, Part 2
6. PERFORMING ORGANIZATION CODE
7 AUTHOR(S)
S.Caceres, L.Do, N.Gonzalez, H.A.Kahn,
S.K.Mathur, and J.J.O'Donne 11
8. PERFORMING ORGANIZATION REPORT NO.
) PERFORMING ORGANIZATION NAME AND ADDRESS
Fhe M.W. Kellogg Co.
300 Three Greenway Plaza East
Houston, Texas 77046
10 PROGRAM ELEMENT NO.
1AB013: ROAP 21ADE-010
11. CONTRACT/GRANT NO.
68-02-1308, Task 23
12 SPONSORING AGENCY NAME AND ADDRESS
SPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 3/74 - 12/74
14. SPONSORING AGENCY CODE
15 SUPPLEMENTARY NOTES
is. ABSTRACT
report gives results of an extension of work done in Part 1 of the study,
reported in September 1974. Of the five major sources of sulfur oxide emissions
studied in Part 1, new or enlarged data bases are presented for three: utility plants,
industrial boilers , and sulfuric acid plants. Cost models developed for the wet lime-
stone process and the Wellman/Allied process are applied to these source groups,
and the results summarized. Application of the Wellman/Allied system to Claus
plants is also discussed. Economics are shown for a 'packaged* limestone scrubbing
system for small industrial boilers. Cost models, derived from the model for sub-
stitute natural gas plants developed in Part 1, are included for low-Btu and intermed-
iate -Btu gas plants. Production costs of substitute natural gas, low-Btu gas, and sol-
vent refined coal are presented, based on actual coal prices in the U.S.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Sulfur Oxides
Cost Effectiveness
Boilers
Electric Utilities
Sulfuric Acid
Air Pollution Control
Stationary Sources
Industrial Boilers
Claus Plants
13 B
07B
14A
13A
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
267
20 SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
255
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