FF3 ff% A
IF IPli
B&i J^
TVA
U.S. Environmental
Protection Agency
Off ice of Research
and Development
Tennessee
Valley
Authority
Industrial Environmental Research
Laboratory
Research Triangle Park, NC 277 1 1
Office of Agricultural and
Chemical Development
Muscle Shoals, AL 35660
EPA-600/7-78
April 1978
TVAY-122
070
POTENTIAL ABATEMENT
PRODUCTION AND MARKETING
OF BYPRODUCT SULFURIC ACID
IN THE U.S.
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide'range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-070
April 1978
POTENTIAL ABATEMENT PRODUCTION
AND MARKETING OF BYPRODUCT
SULFURIC ACID IN THE U.S.
by
J.I. Bucy, R.L. Torstrick, W.L. Anders,
J.L. Nevins, and P.A. Corrigan
Tennessee Valley Authority
Office of Agricultural and Chemical Development
National Fertilizer Development Center
Muscle Shoals, Alabama 35660
EPA Interagency Agreement D8-E721-BJ (TV-41967A)
Program Element No. EHE624A
EPA Project Officer: Charles J. Chatlynne
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, N.C. 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
-------
ABSTRACT
Air quality regulations require control of sulfur oxides emissions from
power boilers. Recovery of sulfur in useful form would avoid waste disposal
and conserve natural sulfur and natural gas used to mine sulfur. Market-
ability of byproducts is an uncertainty. This U.S. Environmental Protection
Agency-sponsored study was conducted by the Tennessee Valley Authority to
evaluate market potential for sulfur and sulfuric acid byproducts. A cost
model was developed to estimate the least-cost compliance method from three
alternatives: (1) selecting a clean fuel strategy, (2) selecting a limestone-
throwaway scrubbing technology, or (3) selecting a sulfuric acid or sulfur-
producing scrubbing technology. For plants where production of byproducts
was the economic choice, a market simulation model was used to evaluate dis-
tribution of byproducts in competition with existing markets. Significant
amounts of sulfuric acid could be produced from sulfur oxides in power plant
flue gas and sold in competitive markets.
This report was submitted by the Tennessee Valley Authority, Office of
Agricultural and Chemical Development, in fulfillment of Energy Accomplish-
ment Plan 80 BBJ under terms of Interagency Agreement EPA-IAG D8-E721 with
the Environmental Protection Agency. Work was completed as of June 1977.
ii
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CONTENTS
Abstract .............................. ii
Figures .............................. vi
Tables ...............................
Abbreviations, Glossary, and General Conversion Factors ...... X
Executive Summary ......................... XV
Introduction ............................ 1
Objectives of Phase III Study .................. 2
Phase I Model .......................... 3
The Expanded Model ........................ 3
Program and Scope ........................ 6
Elemental S and H2S04 Industry ................... 7
Domestic Consumption of S .................... 7
Organization of Frasch S Production, Distribution, and Handling . 10
S Price History ......................... 12
S Reserves ............................ 15
Impact of Environmental Regulations on S Production ....... 15
Frasch S Production ...................... 15
Recovered S Production ..................... 16
Byproduct ^864 Production at Smelters ............. 16
H£S04 Production in S-Burning Acid Plants ........... 16
Domestic Consumption of ^SO^ .................. 17
End Use Analysis of S and ^SO^ in Fertilizer Production ...... 19
Phosphate Fertilizer Market ................... 19
Phosphate Consumption Patterns ................. 20
Phosphate Production and Trade Patterns ............ 22
Future Supply Patterns ..................... 24
Implications for the S Market ................. 26
Analysis of the Potential Demand for Abatement Byproduct ^804 ... 29
The Existing S-Burning Acid Plants in the U.S ........... 29
The Impact of Abatement Acid ................... 32
Production Costs for H2S04 .................... 32
The Demand Curve for Abatement Acid ............... 33
Analysis of the Potential Supply of Byproduct ^864 from Smelters . 37
End Uses for Byproduct Acid ................... 37
1978 Production Potential ................... 37
111
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SC>2 Emission Regulations and Applications 45
SIP I'.'.'.'.'.!! 45
Federal NSPS 45
Trends in Establishing SIP 46
Emission Control Regulations for Fossil-Fired Power Generators . . 46
Units of the Regulation 46
Application of the Regulations 47
Emission Compliance Alternatives 48
Characteristics of the Power Utility Industry 49
Fossil Fuels 49
Historical Consumption and Characteristics 50
Projected 1978 Consumption and Characteristics 51
Power Plant Characteristics 53
Plant Location 53
Plant Size 53
Boiler Characteristics 61
Boiler Size 61
Boiler Capacity Factors 63
Boiler Heat Rates 66
Scrubbing Cost Generator 69
Procedure for Utilizing FPC Data to Estimate Compliance Status . . 69
FPC Form 67 Data Projections 69
Compliance Test 70
Compliance Status of Power Plants 72
Development of the Scrubbing Cost Generator 72
Background 72
Investment Scaling Procedure 74
Revenue Requirement Scaling Procedure 76
Output of the Scrubbing Cost Generator 80
Supply Curve for Abatement Acid 82
Abatement Byproduct Acid Distribution-Transportation System 85
Standard Point Location Code 85
Distribution Cost Generation 85
Market Simulation Model Theory 91
Economic Theory 91
Multidimensional Equilibrium Model 93
Results and Analysis 95
Plants Out of Compliance in 1978 95
ACFL 95
Results and Analysis of Byproduct Smelter Acid Market 97
Results and Analysis of Power Plant Abatement Acid Market 97
Scrubbing Cost Generator Prescreen 97
Compliance Strategies Selected by Power Plants in Model Runs . . 99
Operating Profile for Power Plants Associated with Compliance
Strategies Proposed for 1978 106
IV
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Results and Analysis of Demand Points for Abatement Byproduct Acid . 108
Best Candidates for Purchasing Abatement Byproduct Acid 108
Supplementary Analysis 112
Summary of S02 Emissions Control Strategies to Meet Compliance . . 112
Clean Fuel Demand Curve 112
Power Plant Supply Curve Based on Incremental Cost for Production
of Abatement Acid 115
Transportation Cost Analysis 115
Impact of Barge Transportation 115
Sensitivity of the S Price 120
Other Uses of the Model 121
Investment Costs 121
Operating Costs 121
Change in Regulations 123
Evaluation of Other Abatement Products 123
Use of Transportation Model 123
Social Cost Consideration 124
Conclusions 126
Recommendations 129
References 131
Appendices
A Basic System Flow Diagram 133
B A Mathematical Statement of Model 139
C The End-Use Input Requirements for S and H2S04 143
D Frasch S Production 145
E S Storage Terminal Operation 151
F Production, Storage, and Retrofit of Emission Controls to
H2S04 Plants Using Elemental S 155
G Demand Schedule for H2S04 Plants 169
H Byproduct 1^504 Production from Smelter Gases Including
Estimates of Retrofit Tail Gas Cleanup and Limestone
Neutralization 173
I ^SO^ Transportation Rates from Western Smelters to Eastern
Terminals 181
J Projection of Steam Plant Data Base, 1978 183
K Variable Cost of Limestone and Sludge Disposal 189
L Specific Supply Points for Sale of Byproduct Smelter Acid ... 193
M Scrubbing Versus Clean Fuel When ACFL is $0.70/MBtu
Heat Input 199
N Feedstock Analysis for S-Burning H2S04 Plants in Model Runs. . . 203
0 Size and Ownership of S-Burning Acid Plants 221
P Acid Plants Out of Compliance, Retrofit Cost, and Candidates
for Purchase of Byproduct Acid 225
Q Power Plants and Acid Plants Affected by a Reduction of
$20/Ton in S Price 227
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FIGURES
Number Page
S-l Flow diagram for major system design requirements xxi
S-2 The supply cost curve for abatement acid xxiii
S-3 Abatement byproduct H2S04 demand curve (Eastern States) . . . xxv
S-4 Flow diagram of freight rate generation model xxvi
S-5 Geographic distribution of assumed supply and demand for
western and Canadian acid in zero ACFL model run xxxii
1 Flow diagram for major system design requirements 5
2 Geographic distribution of S terminals 13
3 U.S. phosphate supply - demand outlook 27
4 Geographic distribution of S-burning acid plants (1978) ... 30
5 Amortized value of maintenance and capital outlays for new
H2S04 plants (assuming 11% interest and 5% compound
maintenance) 34
6 Abatement byproduct l^SO^ demand curve (Eastern States) ... 36
7 Geographic distribution of smelter byproduct acid plants in
37 Eastern States and 11 Western States 39
8 Abatement byproduct 1^504 demand curve (Western States) ... 41
9 Geographic distribution of assumed supply and demand for
western and Canadian acid in zero ACFL model run 42
10 Trends in the consumption of coal, oil, and gas from 1969-78 . 52
11 Location of coal-fired steam-electric power plants (1978) . . 55
12 Location of oil-fired steam-electric power plants (1978) ... 56
13 Location of gas-fired steam-electric power plants (1978) ... 57
14 Location of steam-electric power plants capable of utilizing
a combination of fossil fuels 58
15 General layout of a power plant designed with an FGD system . 60
16 Average boiler capacity factors as a function of boiler age . 64
17 Geographic distribution of 187 power plants projected out of
compliance (1978) 73
18 The supply cost curve for abatement acid OA
19 Geographic identification of standard point location codes
(SPLC) 86
20 Flow diagram of freight rate generation model gy
21 Railroad rate territories ' gg
22 Four basic commodity column tariffs for H2S04 rail shipments ! 90
23 Conceptual demand curve for H2S04 and supply curve for
abatement production ^2
24 Geographic distribution of the seven best power plant
candidates for production and marketing of abatement HnSOA . 1Q4
VI
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FIGURES (continued)
Number Page
25 Geographic distribution of S-burning acid plants (1978) . . . 109
26 Clean fuel demand curve - all plants (1978) ......... 114
27 Abatement acid supply curve for $0.35 ACFL model run ..... 116
28 Abatement acid supply curve for $0.50 ACFL model run ..... 117
29 Abatement acid supply curve for $0.70 ACFL model run ..... 118
30 Conceptual demand curve for I^SO^ and supply curve for
abatement production .................... 125
vii
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TABLES
Number Fag
S-l U.S. Consumption of S in All Forms by End Use XXVi
S-2 Projected 1978 Fossil Fuel Consumption Rates and
Characteristics XXVi
S-3 Comparison of Projected 1978 Regional Fossil Fuel Consumption
with Historical 1973 Consumption
S-4 Power Plant Operating Characteristics Projected for 1978 . . . XXIX
S-5 Summary of Model Results for Smelters and Power Plant Sales
to Acid Plant Demand Points XXXiii
1 U.S. Sulfur Consumption Patterns 1974-74 8
2 Apparent Consumption of S in the U.S 9
3 U.S. Sulfur Demand Forecast 10
4 Time-Price Relationship for S 14
5 U.S. H2S04 Market Statistics 18
6 U.S. Consumption of S in All Forms by End Use 19
7 U.S. Phosphate Consumption 21
8 Average Phosphate Fertilizer Application Rates for Major Crops
in the U.S 22
9 U.S. Production of l^PO^ and Phosphate Fertilizers 23
10 U.S. Phosphate Fertilizer Exports 25
11 U.S. Sulfur-Burning H2S04 Plant Capacity (1978) 31
12 Major Parameters in Model 35
13 Incremental I^jSO^ Production for Eastern and Western
Smelters 1976-1978 40
14 Units for Expressing State S02 Emission Regulations 47
15 Consumption Pattern of Fossil Fuels in the U.S., 1969-73 ... 50
16 Historical Fossil Fuel Characteristics for the Period
1969-73 51
17 Projected 1978 Fossil Fuel Consumption Rates and
Characteristics 53
18 Comparison of Projected 1978 Regional Fossil Fuel Consumption
with Historical 1973 Consumption 54
19 Conventional Fossil-Fueled Steam-Electric Generating Plants,
Total and Average Capacities, Net Generation and Capacity
Factors for the Total Power Industry, 1938-73 59
20 Fifteen Largest Steam-Electric Plants in the U.S. in 1973 . . 62
21 Trends in Boiler Size, 1959-73 61
22 Distribution of Boilers by Age and Capacity Factor - All
Boilers 63
viii
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TABLES (continued)
Number
23 Distribution of Boilers by Age and Capacity Factor -
Boilers Out of Compliance 65
24 Distribution of Boilers by Size and Capacity Factor -
All Boilers 65
25 Distribution of Boilers by Size and Capacity Factor -
Boilers Out of Compliance 66
26 National Average Heat Rates for Fossil-Fueled Steam-Electric
Plants - Total Electric Power Industry, 1938-73 67
27 Indirect Investment and Allowance Factors 75
28 Projected 1978 Unit Costs for Raw Materials, Labor and
Utilities 78
29 Estimated Maintenance Rates for Alternative FGD Process .... 77
30 Annual Capital Charges for Power Industry Financing 79
31 Sample Output of Scrubbing Cost Generator 81
32 Reclassification of Base Points 88
33 Power Plant Operating Characteristics Projected for 1978 ... 96
34 Byproduct Smelter Acid Distribution in Model Runs 98
35 Eight Power Plants Scrubbing, Producing, and Marketing Acid in
$0.35 ACFL Run 100
36 Twenty-Four Power Plants Scrubbing, Producing, and Marketing
Acid in $0.50 ACFL Run 101
37 Two Power Plants Scrubbing, Producing, and Marketing Acid in
$0.50 ACFL Run, But Also Using Clean Fuel 102
38 Twenty-Nine Power Plants Scrubbing, Producing, and Marketing
Acid in $0.70 ACFL Run 103
39 Summary of Model Results for Smelters and Power Plant Sales to
Acid Plant Demand Points 105
40 Operating Characteristics of Power Plant Candidates for Use
of Scrubbing Technology 107
41 Acid Plants Buying Abatement Acid in Model Runs Ill
42 1978 Strategies Selected for Reducing Emissions 113
43 Cost Reduction by Barge Shipment 119
44 Effect of $20 Reduction in S Price on Supply and Demand for
Byproduct Acid 122
45 Total Cost of Acid Production for Model Runs 126
IX
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ABBREVIATIONS, GLOSSARY, AND GENERAL CONVERSION FACTORS
ABBREVIATIONS
ACFL
BOM
CDS
CENTRE
EDS
EPA
FGD
FIPS
FPC
Ga
ka
Ma
MES
NEDS
NRBT
NSPS
PEDCo
SIP
SPLC
SRI
TVA
Alternative clean fuel level
U.S. Bureau of Mines
Compliance Data System
Centre Mark Company
Energy Data System
U.S. Environmental Protection Agency
Flue gas desulfurization
Federal Information Processing Standard
Federal Power Commission
Billion (109)
Thousand (103)
Million (106)
Mutually exclusive set
National Emissions Data System
National Rate Basis Tariff
New Source Performance Standards
PEDCo-Environmental Specialists, Inc.
State Implementation Plan
Standard Point Location Code
Stanford Research Institute
Tennessee Valley Authority
a. Although British units are used in this report,
the International System of Units (SI) symbols
are used in transition to the metric system.
x
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GLOSSARY
Alternative clean fuel level: The value assigned to premium price for fuel
that will meet the sulfur oxide emission standard.
Avoidable costs: An estimation of the production costs over the long-term
planning horizon that could be avoided by closing an existing acid
plant assuming abatement acid would be available in amounts equal to
the plant production capacity (330 days/yr). Salvage value of the
plant is assumed to be equal to the salvage cost.
Capacity factor: Throughout this study capacity factor is defined and
calculated as the ratio of the annual quantity of heat consumed in the
boiler in comparison to the quantity that would have been consumed if
the boiler operated at rated capacity (full load) for the entire year
(8760 hr). For steam electric boilers, this definition is equal to
capacity factors calculated in terms of either steam or electricity
generation.
Centre Mark Company: Source of geographic information on locations in the U.S.,
including latitudes, longitudes, county data, and various other infor-
mation related to over 100,000 locations.
Commodity column tariff: Tariff publishing Docket 28300 commodity rates
which are exceptions to the class rates.
Competitive equilibrium solution: Represented by the long-run break-even
market condition which comes at a critical price where identical firms
just cover their full competitive costs. At a lower long-run price,
firms would leave the industry until prices return to the critical
equilibrium level; at higher long-run price, new firms would enter
the industry replicating what existing firms are doing and thereby
force market price back down to the long-run equilibrium price where
all competitive costs are just covered.
The long-run competitive equilibrium for sulfur and sulfuric acid
market conditions in this study is simulated by minimizing the total
cost of both the sulfuric acid and power plant industries , subject to
the condition that the acid production demand is still met either from
traditional sulfur sources or from a partial substitution of abatement
sulfuric acid.
Compliance Data System: A data base containing compliance information and
status for all emission sources in the U.S. as they relate to clean
air requirements.
xi
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Consumer surplus: On the assumption that the marginal utility of money
remains constant, consumers surplus represents the gain to those
consumers who would be willing to pay more than the market price for
a particular good.
Docket 28300: A general investigation by the Interstate Commerce Commission
of the reasonableness of class rates in the U.S. (except in the mountain
Pacific and transcontinental territories) that resulted in the class
rates and tariffs in use today.
Energy Data System: A data base containing fuel quality and consumption data,
plant design and operating data, emission regulations, compliance infor-
mation, future megawatt capacities, and air quality data.
Form 67: Federal Power Commission form used to report annual steam-electric
plant and water quality control data.
Frasch process: A process developed by Herman Frasch for mining underground
sulfur deposits by pumping large quantities of superheated water into
the formation through pipes and pumping the melted sulfur to the surface
where it is either shipped or stored as a liquid or solid.
Limestone slurry scrubbing: A process for removing sulfur oxides from flue
gases by scrubbing the gases in a tower with a limestone slurry. The
resulting slurry of calcium sulfites, sulfates, unreacted limestone,
etc., is sent to a disposal pond where the solids settle out with no
further treatment.
Magnesia slurry scrubbing: A regenerative process for the removal of sulfur
oxides from flue gases by scrubbing the gases in a tower with a magnesium
oxide slurry. The magnesium sulfite formed in the slurry is removed and
thermally decomposed into magnesium oxide and a stream of concentrated
sulfur dioxide gases. The regenerated magnesium oxide is returned to the
scrubbing tower and the concentrated sulfur dioxide stream is fed to a
conventional contact sulfuric acid plant for the production of commercial
(98%) sulfuric acid. This process is called magnesia (MgO) slurry
scrubbing in the text.
Market demand: Amount of goods that buyers are ready to buy at each specified
price in a given market at a given time (also called demand schedule).
Demand for abatement acid in this study is simulated as though all con-
sumption occurred at sulfuric acid plants producing at 330 days/yr.
Market supply: Amount of goods that sellers are ready to sell at each speci-
fied price in a given market at a given time (also called a supply
schedule).
Supply of I^SO^ in this study represents either production at each of
the commercial acid plants or purchases from any power plant capable of
producing abatement acid or sulfur.
Xii
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Mutually exclusive set number: A number used in the transportation subsystem
to derive shipping costs between two points.
National Emissions Data System: A computer-based EPA emission inventory system
for storing and retrieving estimates of the criteria pollutants from
both point and area sources.
National Rate Basis Tariff: Tariff containing alphabetical lists of all rail
stations with rate basis applicable.
Net social gain: Monetary measure of the social benefit enjoyed from
recycling abatement byproduct sulfuric acid into productive use. It
is the combination of consumer and producer surplus.
Optimum useful life: Identified in this study as the minimum point on the
long-run average total cost curve for an acid plant. At this point
the added capital cost savings enjoyed by increasing useful life one
year equals the added maintenance saving from shortening useful life
one year.
PEDCo-Environmental Specialists, Inc.: The company that gathers information
under contract to EPA on FGD by direct interviews with and surveys of
utilities in the U.S.
Producer surplus: The difference between the market price at which a producer
sells and the respective lower supply prices at which he would be willing
to offer lesser amounts of a particular product.
Product differentiation: Any difference, real or imaginary, between two or more
very similar goods or services that may result in preference for one
over the other without regard to price.
Scrubbing cost screen: Designed in the study as an economic screen to select
the most efficient power plant boilers in terms of unit cost of abatement
production of 100% H2S04 equivalent. Equivalent 100% H2S04 in any flue
gas desulfurization process is the amount of 100% H2S04 which could have
been produced from the sulfur values in abatement byproducts, such as,
calcium sulfite, calcium sulfate throwaway sludge, or elemental sulfur.
Standard Point Location Code: A transportation-oriented 6-digit number
prescribed by the National Motor Freight Association under the
guidance of the SPLC policy committee. It is used as a logistical
linkage between all possible shipping origins and destinations for
truck and/or rail.
Wellman Lord/Allied Process: A regenerative process for the removal of
sulfur oxides from flue gases by scrubbing the gases in a tower with
a solution of sodium sulfite. The sodium bisulfite formed is thermally
decomposed (in a separate vessel) to sodium sulfite and sulfur dioxide
gas. The regenerated sodium sulfite is returned to the scrubbing
tower and the sulfur dioxide gas is reduced with natural gas to form
molten elemental sulfur.
xlii
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GENERAL CONVERSION FACTORS
EPA policy is to express all measurements in Agency documents in
metric units. Values in this report are given in British units for the
convenience of engineers and other scientists accustomed to using the
British system. The following conversion factors may be used to provide
metric equivalents.
Conversion Factors for Metric Equivalents of British Units
British
Metric
ac
bbl
Btu
ft3
gal
Ib
lb/ft3
Ib/hr
ton
ton,
long
ton/hr
acre
barrels of oil
British thermal unit
cubic feet
gallons
pounds
pounds per cubic foot
pounds per hour
•a
tons (short)
n
tons (long)
tons per hour
0.405
158.97
252
0.02832
3.785
0.4536
16.02
0.126
0.90718
1.016
0.252
hectare
liters
cubic meters
liters
kilograms
kilograms per cubic
meter
grams per second
metric tons
metric tons
kilograms per second
ha
1
3
m
1
kg
kg/m
g/sec
t
t
kg/sec
a. All tons are expressed in short tons in this report except sulfur which
is expressed in long tons.
xiv
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POTENTIAL ABATEMENT PRODUCTION AND MARKETING
OF BYPRODUCT SULFURIC ACID IN THE UNITED STATES
EXECUTIVE SUMMARY
INTRODUCTION
Emission control regulations for the electric power industry require
utilities to either burn fuel with a low enough sulfur (S) content to meet
the standard or to remove a portion of the S before, during, or after com-
bustion. Coal is the predominant fuel for power boilers and its use will
increase. Utilities generally prefer use of complying coal when it is the
economic choice compared to other alternatives for control. However, complying
fuel is not always available near the areas of high electricity demand.
Technology for removal of S from coal prior to or during combustion is being
developed but will not make a substantial contribution to control in the next
decade. The primary alternative to use of fuel that meets the emission
requirement is removing sulfur oxides (SOX) from the flue gas produced when
the coal is burned in the boiler. Use of flue gas desulfurization (FGD)
technology currently accounts for only a minor portion of the control required,
but its use is growing as a result of limited alternatives to meet compliance
schedules. Most applications are based on lime and limestone scrubbing.
These methods produce high volumes of waste solids for utilization or ultimate
disposal. Technology for recovery of S in useful form is being developed
that will provide an alternative to production of waste solids. Recovery of
S from flue gas would conserve natural S reserves and reduce the requirement
for energy used in mining S. One of the major uncertainties associated with
this approach is the marketability of recovered S byproducts.
In this study sponsored by the U.S. Environmental Protection Agency (EPA),
the Tennessee Valley Authority (TVA) has evaluated the potential markets for
S and sulfuric acid (^SO^) that could be economically produced by the power
industry as compared to use of clean fuel or limestone scrubbing. A market
simulation model was developed to evaluate distribution of byproducts from
smelters as well as power plants in competition with the existing markets
based on an assumed S price of $60/long ton in 1978. This value of S is
representative of projected costs of production. Recovery of S from gas and
oil was not included in the study although delivered price of S reflects
this competition.
CONCLUSIONS
A greater portion of future supply of S will have to come from other than
natural sources. Beyond the year 2000, the demand will exceed the supply of
natural S (1). Recovery of S byproducts from coal combustion could make a
substantial contribution to the additional supply.
xv
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The entire U.S. electric utility industry was characterized from Federal
Power Commission (FPC) data (2) with respect to plant age, fuel type, capacity,
load factors, and SOX emission rates for the operating year 1978. Out of a
total of 3382 boilers located at 800 power stations, 833 boilers at 187 sta-
tions were projected to be out of compliance with current applicable emission
regulations. The total SOX emissions from these 187 plants are equivalent to
17.5 Mtons (M = 1 million) of I^SC^; total H2SC>4 consumption in the U.S. was
estimated to be 32.2 Mtons in 1978. Therefore the total market is about
twice the potential byproduct production.
For the plants estimated to be out of compliance, limestone scrubbing is
generally the least-cost scrubbing method when credit for byproduct sales is
not included but when credit is applied, production of byproducts becomes
competitive; of the alternatives considered in this study, production of
H2S04 was less expensive than production of S. An alternative to use of
scrubbing was provided by comparing the cost of scrubbing with selected
values of premium cost of complying fuel. The values were selected to
determine the effect on potential volume of abatement products.
When the clean fuel premium was set at $0.70/MBtu, the mix of least-
cost compliance methods was:
Purchase complying fuel 71 plants
Use limestone scrubbing 87 plants
Produce byproduct acid 29 plants
The amount of acid produced and marketed totaled approximately 6 Mtons; an
additional 5 Mtons could have been produced at a lower cost than the alterna-
tive compliance method selected but could not be sold in competition with
acid produced from elemental S priced at $60/ton. The simulation model was
designed to allow the nonferrous smelter industry to compete with the utility
industry for byproduct markets. The total byproduct acid supplied from both
industries was 7.11 Mtons or 22% of the total H2S04 market; however, some
of the plants that are good candidates for recovery may be implementing other
compliance plans. The control of sulfur dioxide (S02) emissions in the
utility industry through use of recovery technology could contribute 56% of
the estimated total reduction needed for the industry to be in compliance.
Further use of recovery technology will depend primarily on substantial
increases in elemental S prices which are difficult to predict. Reduction
in the cost of control technology would also increase the potential for
increased production of byproducts, but the costs are not likely to improve
significantly. Reduction in transportation costs is a more realistic
possibility for improving economics of marketing byproduct acid. Higher
levels of clean fuel premium would not affect the results since the acid
supply at the maximum value studied exceeded the demand.
The development of data bases and programs for use of the model to
predict byproduct market potential resulted in capability to perform other
highly relevant calculations.
The scrubber cost generator may be used to estimate the investment and
operating costs of alternative scrubbing systems for all existing and planned
xv i
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power plants. In this study, costs were estimated for limestone, magnesium
oxide (MgO) , and Wellman-Lord/Allied scrubbing systems for all plants projected
to be out of compliance in 1978, For use in the study, relativity of costs
was the primary interest. However, the input cost data could be refined to
reflect special design considerations for specific plants to improve the
accuracy of estimates for planning and analyses.
The procedure for evaluating compliance status based on applicable stan-
dards and FPC projection of fuel characteristics will be useful in estimating
the effect of changing emission standards on the cost of compliance. The study
reported here was based on the State Implementation Plans (SIP) regulations
that were in effect as of June 1976.
The transportation model that was developed to distribute byproduct acid
from supply points to areas of use is a sophisticated program that has poten-
tial for extensive use. The model calculates actual, rate-base mileage between
any two points on the established railway network. For this study, tariffs
were incorporated for t^SO^ movements. Available tariffs for any other commodity
could be incorporated to calculate actual transportation costs between any
two points .
An important finding was that while long-run competitive equilibrium solu-
tions predict what may happen in competitive markets they do not identify net
social gain. The savings to both industries at the $0.70/MBtu clean fuel
premium run resulting from absorption of abatement byproduct acid in the
existing market amounted to $122,877,000 or $16.20/ton of acid utilized.
METHODOLOGY
The objective of the overall marketing model is to simulate long-run com-
petitive equilibrium market conditions for S and H2S04 in the U.S. as might
be impacted by production of abatement acid or S. To simulate these conditions,
the cost to both the H2S04 and the power plant industries is minimized subject
to the condition that acid demand is met either from traditional S sources or
from substitution of abatement
Analysis of the model addresses three choices for the steam plants that
are not meeting the current SIP standards. These include (1) selecting a
clean fuel strategy, (2) selecting a limestone-throwaway scrubbing technology,
or (3) selecting an H2S04 (MgO)- or S- (Wellman-Lord/Allied) producing scrub-
bing technology. Costs for production of S by the Wellman-Lord/Allied process
were higher in all cases studied than production of ^SO^. Projected savings
in distribution costs for S compared to H2S04 did not offset the incremental
production costs. Costs for use of the Wellman-Lord/Allied technology will
be more clearly defined during the current full-scale demonstration, partially
funded by EPA, at the Mitchell Station of the Northern Indiana Public Service
Company. Revised information will be included in the model. The incentive for
production of S is high because it is a safe, noncorrosive, convenient material
to handle, and can be easily stockpiled for long periods of time at relatively
low cost. Moreover, fluctuations in market demand could be met with less impact
to both the producer and consumer. It is likely that a mix of marketable by-
products will ultimately provide the least-cost compliance with S02 regulations
in the utility industry. Technology for production of S should be fully devel-
oped so that the choice is available and so that accurate information Is avail-
able for cost comparisons with other methods of control.
xvii
-------
The optimal solution predicts not only which acid producer would buy and
which steam plant would sell t^SO^, but also which steam plant would sell to
which acid plants. Any variations to this optimal solution would increase
the total cost to both industries.
A flow diagram of the major system design requirements is outlined in
Figure S-l. The major data bases feed the market simulation model through
cost generation models as follows:
1. Emission control requirements for SOX were determined for each power
plant boiler, stack, or plant projected to operate in 1978 using the
FPC data (Form 67), June 1976 SIP, and New Source Performance
Standards (NSPS).
2. The scrubbing cost generator was developed to provide unit production
costs for byproduct I^SO^, elemental S, and limestone-throwaway sludge
including potential production quantities for each power plant boiler.
It was designed as an economic screen to select the most efficient
boiler combinations for meeting compliance on the basis of cents/MBtu
heat input for each scrubbing system considered. The results of this
screen provide the lowest cost method for compliance with given scrub-
bing technology. This information is fed to the market simulation
model to identify both the relative efficiency as well as unique loca-
tion advantages for all power plant boilers producing abatement acid
in competition with byproduct smelter acid producers in the existing
market. The marketing model then estimates long-run competitive
equilibrium solutions based on realistic outputs of abatement by-
products by identifying major candidates for abatement byproduct
production and consumption versus a limestone-throwaway strategy and/
or the alternative of using a clean fuel.
3. The acid production cost generator encompasses the elemental S
producers, the S-burning H2S04 producers, and the byproduct H2SC>4
producers associated with smelter operations. These data bases were
developed from the TVA computerized data base on worldwide manu-
facturers of fertilizer and related products. This information
supplemented by references from other sources provided the necessary
inputs to the acid production cost generator to provide unit avoidable
production costs for each t^SO^ plant projected to operate in 1978.
4. Transportation and distribution options were calculated by the trans-
portation cost generator for H2S04 and elemental S for all possible
transfer combinations between the S producers, the electric utilities,
smelter plants, and H^SC^ plants considered in this study.
Compliance Test
The SC>2 emission and compliance model uses the projected annual fuel
consumption and characteristics data to calculate the annual quantity of S
that is emitted from each boiler and plant. For each plant, allowable
emissions are calculated based on NSPS for new boilers or the applicable SIP
for existing boilers taking into account heating value and S content of the
xviii
-------
BYPRODUCT MARKETING MODEL
BASIC SYSTEM
SUPPLY
DATA BASE
TRANSPORTATION
DATA BASE
DEMAND
DATA BASE
POWER PLANTS,
REGULATIONS,
COST ESTIMATES
TARIFFS
RAIL MILEAGE
BARGE MILEAGE
ACID
PLANTS
SCRUBBING
COST
GENERATOR
TRANSPORTATION
COST
GENERATOR
ACID PRODUCTION
COST
GENERATOR
MARKET SIMULATION
LINEAR
PROGRAMMING
MODEL
/
\
n
EQUILIBRIUM
SOLUTION
RESULTS
v;
Figure S-l. Flow diagram for major system design requirements.
xix
-------
fuel. Excess emissions expressed as tons of S which must be removed are
estimated as the difference between the calculated actual and allowable values.
The compliance test selects the applicable level of SIP as (1) an entire
plant, (2) an individual boiler, or (3) an individual stack. In all cases
where scrubbers could be used, they are designed for an S02 removal efficiency
of 90%. However, the actual level of removal efficiency will depend on
better definition of performance during sustained full-scale operation when
coal is the fuel. The amount of gas scrubbed is based on increments of
standard-size scrubbers.
Scrubber Cost Generator
In all cases the S02 control strategy is selected on the basis of mini-
mum cost for compliance. The data generated in the scrubbing cost model are
used to calculate the scrubbing cost of a limestone-throwaway system versus
a salable byproduct for each of the 833 boilers or combinations of boilers
identified in this study that will be out of compliance with emission control
regulations in 1978 (based on 1976 regulations). The cost is expressed as
cents/MBtu for direct comparison with the clean fuel alternative. The
alternative clean fuel level (ACFL) represents the premium that can be paid
for complying fuel in lieu of using an FGD system.
The model also calculates cost differential between scrubbing with a
limestone-throwaway system and scrubbing with MgO to produce H2S04. This
accommodates identifying the incremental cost difference of the two systems
for all boilers or the combinations of boilers included in the model. This
incremental cost becomes input to the marketing model which is designed to
determine potential for production and marketing of abatement I^SO^ at various
power plant locations. The comparative FGD costs for each power plant con-
sidered in the study can be used to generate a supply curve for the produc-
tion of abatement I^SO^. The supply curve for abatement acid is presented
graphically in Figure S-2. This curve is estimated by ranking power plant
boiler combinations from lowest to highest cost for producing abatement H2S04
as a function of accumulated supply quantities.
Acid Cost Generator
H2S04 plants are widely scattered throughout the industrial sector of
the U.S.; acid has been traditionally produced by S-burning plants in captive
use near the point of consumption. In this study it was assumed that the
H2S04 market can be simulated as though all consumption occurs at the H2S04
plants and that acid-producing firms will close these plants and buy abate-
ment acid if it can be delivered at costs equal to or below their avoidable
cost of production. This assumption ignores some of the market entry
barriers but provides the basis for an economic assessment. Avoidable cost
is an estimation of the production costs that could be avoided by closing an
existing acid plant assuming abatement byproduct acid would be available in
amounts equal to the plant production capacity (330 days/yr). To develop
the required inputs to the model on the demand side, it was necessary to
identify the acid plants that burn elemental S for the production of H2S04
and calculate the avoidable costs of production at each plant.
xx.
-------
PQ
S
0.5 -
8
10
12
14
CUMULATIVE S REMOVAL, MTONS OF
Figure S-2. The supply cost curve for abatement acid.
xxi
-------
The avoidable costs (theoretical) were calculated at each of the 90 acid
plant locations considered in the study. Costs of manufacture based on data
generated indicated that most of the acid production costs range from $25.00-
$45.00 depending on plant location, size, and age; the March 1976 price for
H2S04 (100% H2S04 f.o.b.) was $44.95/ton. A summation of capacity of acid
plants versus avoidable cost of production is shown in Figure S-3. The re-
sulting plot defines the demand curve for abatement acid. The demand curve
is estimated by ranking all acid plants from highest to lowest cost and accumu-
lating demand quantities to show acid cost as a function of acid plant
capacity. At a very high cost of alternative supply, only a few acid pro-
ducers could justify buying rather than producing H2S04- As supply cost of
abatement acid declines, more acid producers would become potential customers.
At low supply costs all but the largest, most modern acid plants located near
S supplies could be shut down. The important implication for the present
study is that small quantities of abatement acid could be marketed at high
value but as the supply increases the value declines.
Transportation Cost Generator
To assess representative competitive costs, a market system analysis
must generate accurate S freight rates from the Frasch S sources to the acid
plants and l^SO^ freight rates from all power plants and/or smelters to all
H2S04 plants.
The linkage used in the study between the S-H2SC>4 and power plant data
bases and the rate generation system is a Standard Point Location Code (SPLC).
A flow diagram of the freight rate generation system used in this model is
shown in Figure S-4. This shows that an SPLC for a power plant origin and
one for H2S04 plant destination are input to the National Rate Base Tariff
(NRBT). This tariff determines for rail rate purposes the basing points for
the origin and destination. Output are two sets of codes used to define
mileage and tariff rates between the byproduct shipping origin and destination
points.
It is important to identify not only the mileage but also the tariff
number. A slight error in mileage is not nearly as critical as knowing which
tariff applies. Four tariffs were found in published H2S04 rates. Rates for
eight other tariffs were generated by the TVA Navigation and Regional
Economics Branch (Division of Navigation Development and Regional Studies)
from these using sound traffic legal arguments similar to the negotiation
process that would ensue should large acid movements become a reality.
RESULTS OF ANALYSES
S and H?S04 Industry
The U.S. Bureau of Mines (BOM) (3) reports the production of S in all
forms in 1976 at 10.9 Mlong tons. Elemental S was produced by 69 companies
at 182 plants in 32 states with 10 of the largest companies owning 57 plants
and accounting for 75% of the output. The production was concentrated in
Texas and Louisiana accounting for 68% of the total output. The Frasch S was
produced in these two states at 12 mines, 5 of the largest mines accounting
xxii
-------
100
80
§
H
8
PM
60
40
20
I
I
I
5 10 15 20 25 30
CUMULATIVE ANNUAL CAPACITY, MTONS OF 100% H2S04
Figure S-3, Abatement byproduct H-SO, demand curve (Eastern States).
35
-------
SPLC,—I
I—SPLC2
NRBT
I-C
JT
INDEX, INDEX2
*
DOCKET
28300
I
RATE BASE MILEAGE
RATE
SEARCH
MINIMUM
RATE
MES,
M
TARIFF
GENERATOR
I
TARIFF NUMBER
Figure S-4. Flow diagram of freight rate generation model.
xxiv
-------
for 82% of the total Frasch output and 48% of the total production of S in
all forms. Long-range prediction of S demand in millions of tons is shown
below.
Forecast
1976 1980 1985 1990
Fertilizer 6.4 7.5 9.3 11.0
Industrial 4.5 5.3 6.0 6.8
Total 10.9 12.8 15.3 17.8
Frasch S production is a mining operation. Wells are sunk into S-bearing
strata, S is melted by hot water injected into the strata, and the molten S
is pumped out. The molten S is pumped from the well to either heated tanks
for storage as a liquid or to vats where it cools and solidifies. About 75%
of the total mining costs of Frasch S is variable, such as the cost of
natural gas to heat water, water treatment, labor, and operating supplies.
The cost of hot water to melt the S is by far the most important cost and
will differ drastically from mine to mine as water requirements and fuel cost
differ. In an analysis prepared for this study the cost of natural gas was
varied from $0.20-$3.00/kft-* (k = 1 thousand) with an intermediate value of
$1.00/kft3. Water requirements or water rate varied from 1600 gal/ton of S
produced to 9000 gal/ton of S. The results of this study indicated that the
lowest capital investment and operating costs are associated with mines
having low water rates and that cost increases markedly with increasing
natural gas costs. For operation where the major variables are constant,
i.e., water rate and natural gas cost, the usual economies of size prevail.
Most of the S consumed in the U.S. is used to produce 1*2^04. Over two-
thirds of the H2S04 is used in the manufacture of fertilizers. A breakdown
of the estimated consumption of S in all forms by end use is presented in
Table S-l.
Characteristics of Power Plants
In 1973 utilities were requested by FPC to project fuel consumption and
characteristics for 1978. The majority of utilities provided FPC with these
projections. For the utilities which did not project this information, fuel
consumption and characteristics reported for 1973 were used. Based on the
updated projections, Table S-2 shows the consumption rates and characteristics
of fossil fuels projected to be utilized during 1978. For plants which use
multiple fuels and did not project their 1978 consumption, a method for
projecting distribution of fuel type was developed.
A comparison of the total projected 1978 coal, fuel oil, and gas con-
sumption with the historical 1973 fuel consumption by region is shown in
Table S-3. The projections indicate a general increase in the consumption
of coal and oil, but a slight decrease in the consumption of gas. The
regional increases or decreases are primarily influenced by fuel availability
and price. In reviewing the data, it must be remembered that a significant
xxv
-------
TABLE S-l. U.S. CONSUMPTION OF S
IN ALL FORMS BY END USE
(klong tons S equiv)
H2S04
Fertilizer acid
H3P04
Normal superphosphates
(NH/,)2S04 and other
Total fertilizer acid
Industrial acid
Total H2S04
Non-acid
Total in all forms
1974
4,945
405
685
6,035
3,715
9,750
1,250
11,000
1975
5,410
290
670
6,370
3,080
9,450
1,200
10,650
1976
5,560
230
610
6,400
3,285
9,685
1,215
10,900
TABLE S-2. PROJECTED 1978 FOSSIL FUEL CONSUMPTION
RATES AND CHARACTERISTICS
Plants out
All plants of compliance
Coal
Total consumption
ktonsa 475,600 226,800
GBtub 10,408,300 5,125,000
Heating value, Btu/lb 10,943 11,300
S content, % by wt 2.12 2.81
Equivalent S02 content, Ib S02/MBtuc 3.87 4.97
Oil
Total consumption
kbbl 620,200 110,200
GBtu 3,827,400 686,900
Heating value, Btu/gal 146,924 148,454
S content 0.99 1.42
Equivalent S02 content, Ib S02/MBtu 1.08 1.54
Gas
Total consumption
Mft3 2,556,000 108,200
GBCu 3 2,602,200 117,000
Heating value, Btu/ft 1,018 1,081
a. k = one thousand.
b. G = one billion.
c. M = one million.
XXVI
-------
TABLE S-3. COMPARISON OF PROJECTED 1978 REGIONAL FOSSIL
FUEL CONSUMPTION WITH HISTORICAL 1973 CONSUMPTION
Geographic Coal, Oil, Gas,
region3 ktons kbbl Mf t^
Historical 1973 consumption
New England 1,080 82,930 6,070
Middle Atlantic 46,990 144,690 64,730
East North Central 135,960 23,340 105,590
West North Central 31,620 3,440 352,820
South Atlantic 75,860 141,380 202,660
East South Central 63,060 6,510 73,750
West South Central 4,730 20,850 1,957,070
Mountain 23,930 8,990 207,630
Pacific 3,740 76,970 451,220
U.S. total 386,970 509,100 3,421,540
Projected 1978 consumption
U.S. total 475,570 620,250 2,556,020
a. The states included in each geographic region are:
New England - Connecticut, Maine, Massachusetts, New
Hampshire, Rhode Island, Vermont; Middle Atlantic -
New Jersey, New York, Pennsylvania; East North Central -
Illinois, Indiana, Michigan, Ohio, Wisconsin; West
North Central - Iowa, Kansas, Minnesota, Missouri,
Nebraska, North Dakota, South Dakota; South Atlantic -
Delaware, District of Columbia, Florida, Georgia,
Maryland, North Carolina, South Carolina, Virginia,
West Virginia; East South Central - Alabama, Kentucky,
Mississippi, Tennessee; West South Central - Arkansas, -
Louisiana, Oklahoma, Texas; Mountain - Arizona,
Colorado, Idaho, Montana, Nevada, New Mexico, Utah,
Wyoming; Pacific - California, Oregon, Washington.
b. Regional consumption data not available.
xxvii
-------
amount of new generating capacity between 1973 and 1978 is from nuclear units.
The data shown include the effect of projected decreases in fossil fuel utili-
zation as a result of new nuclear units coming online as well as changes in
fossil fuel consumption resulting from decreases in fuel availability of
increases in cost.
The operating characteristics of all 800 U.S. power plants projected to
be in operation in 1978 are outlined in Table S-4. Also included in this
table are the characteristics of the plants projected to operate out of com-
pliance in 1978. As the data in the table indicate, 187 power plants out of
a total of 800 were calculated to be out of compliance. It should be noted
that many of the plants estimated to be out of compliance are likely imple-
menting compliance plans that are different from those selected for this
study. Even though plants out of compliance make up only 32% of the total
population with respect to capacity, they burn about 50% of the total coal;
only 20% of the total oil, and only 5% of the total gas. Plants out of
compliance have a 30% higher S content in the coal burned and a 43% higher S
content in the oil burned than the overall nationwide average. The average
boiler size for plants out of compliance was about 30% greater than the
average for all plants. The age range of boilers, the range of boiler sizes,
and boiler capacity factor for plants out of compliance were not significantly
different from the industrywide values.
Byproduct Acid from Smelters
The 14 smelters located in the 11 Western States were analyzed separately
from the 14 smelters in the 37 Eastern States of the U.S. The model assumes
that existing S-burning acid plants and byproduct acid plants associated with
smelter operations were operating at an equilibrium position in the 1975
market year. The model then addresses the incremental acid that is projected
to be produced at both existing and new smelter locations in 1978. The 1978
incremental production estimated for the Western States amounted to 849,000
tons of acid. The analysis for smelters located in the Eastern States
amounted to 811,000 tons of acid.
Part of the acid produced by western smelters was distributed in the
East. This surplus western acid was marketed in the simulation model through
transshipment terminals supplied by unit trains. The terminal locations
included Chicago, Illinois; St. Louis, Missouri; Memphis, Tennessee; Baton
Rouge, Louisiana; and Houston, Texas. Two additional transshipment terminals
were added in the model at Buffalo, New York, and Detroit, Michigan, in order
to analyze the marketing of 200,000 tons of byproduct acid from smelters in
Canada. This concept is presented graphically in Figure S-5.
Byproduct Acid from Power Plants
The clean fuel alternative is defined as the incremental additional
price for fuel that will meet the applicable S02 emission regulation. The
ACFL selected for the model runs ($0.00, $0.35, $0.50, and $0.70/MBtu) were
chosen to show the effect on potential volume of abatement acid. For some
power plants with multiple boiler installations a mix of alternative methods
XXV111
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TABLE S-4. POWER PLANT OPERATING CHARACTERISTICS PROJECTED FOR 1978
No. of power plants
No. of boilers
Total capacity, MW
Total fuel
Coal, ktons
Coal, GBtu 1
Oil, kbbl
Oil, GBtu
Gas, Mft3
Gas, GBtu
Average S content of coal, %
Average S content of oil, %
Emissions, equivalent tons H2S04
Total emitted
Required abatement
Average capacity factor, %
Average boiler generating capacity, MW
Age of boilers, %
0-5
6-10
11-15
16-30
>30
Size of boilers, %
<200
200-500
501-1000
>1000
Capacity factor of boilers, %
<20
, 20-40
41-60
>60
1978
all
U.S. plants
800
3,382
411,000
475,600
10,408,300
620,300
3,827,400
2,556,000
2,602,200
2.12
0.99
29,552,100
9,912,600
31.87
122
5
8
8
42
37
82
11.7
6
0.3
40
20
23
17
1978
plants
out of
compliance
187
833
132,600
226,800
5,125,100
110,200
686,900
108,200
v 167,000
2.81
1.42
17,562,300
9,912,600
35.12
159
10
10
6
42
32
75
15
9
1
35
17
29
19
xxix
-------
X
X
X
• DEMAND POINT
A TRANSSHIPMENT TERMINAL
O ORIGIN OF BYPRODUCT
SMELTER ACID
Figure S-5. Geographic distribution of assumed supply and demand for western and
Canadian acid in zero ACFL model run.
-------
produce the least-cost compliance strategy. A summary of the distribution
of compliance strategies selected by the model for each ACFL model run is
listed as follows:
ACFL, cents/MBtu
Compliance strategy 0 35 50 70
Plants using clean fuel only 187 168 113 71
Plants using only limestone scrubbing 0 7 41 77
Plants using limestone scrubbers and
clean fuel 0 4 7 10
Plants using MgO scrubbing only 0 8 24 29
Plants using MgO scrubbing and clean
fuel 0 0 2 0
Total power plants 187 187 187 187
The potential production and marketing of abatement acid for power
plants that produced acid in each of the model runs are outlined as follows:
ACFL, cents/MBtu
0 35 50 7JD
No. of plants 0 8 26 29
Thousands of tons
marketed 0 2,554 5,108 5,595
Power plants that were the best candidates for production of byproduct
acid were generally larger, newer plants with high load factors. The dis-
tinctive characteristics were (1) most boilers <10 yr old, (2) average size
about 600 MW (<15% smaller than 200 MW), and (3) the average capacity factor
about 60%. The average load factor for potential acid-producing plants was
more than three times as high as the average for all plants considered.
A summary of the compliance strategies developed from the model runs
for controlling excess emissions projected for 1978 is outlined in the
following tabulation:
Strategies Selected for Reducing Emissions
(Reductions expressed as equiv ktons of
ACFL,
cents/MBtu
0
35
50
70
00
By using
clean fuel
9,912
7,993
3,123
700
Total by
scrubbing
0
2,885
9,503
12,583
13,598
By MgO
scrubbing
0
2,554
5,108
5,595
-
By limestone
scrubbing
0
330
4,395
6,988
-
Total
reduction
9,912
10,878
12,627
13,284
13,598
xxxi
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Equilibrium Solution
A summary of model results for smelter and power plant sales to acid
plant demand points for all model runs is outlined in Table S-5. These
results show the potential quantity of power plant acid in relation to the
total market. At the $0.70/MBtu ACFL, the potential for production of acid
(abatement capacity) at a cost below the alternative clean fuel premium fuel
cost exceeded the market demand (sales) for the acid by 5 Mtons. The plants
that would not be able to market the acid used limestone scrubbing even though
production of acid would have been less costly if markets were available.
At the $0.35/MBtu level, essentially all of the acid that could be produced
economically compared to purchase of complying fuel was sold. The small
differential in sales between the $0.50 and $0.70/MBtu level of ACFL indicates
that the market for byproduct acid from power plants was nearly saturated at
5 Mtons, or approximately 15% of the total market. Further substitution of
byproduct acid in the existing market would depend on substantial increase in
the price of S; $60 was assumed for the study.
Distribution of Acid Markets
Distribution of acid for the 90 acid plants considered in each model run
is outlined as follows:
ACFL, cents/MBtu
0 35 50 70
Producing from S 58 42 30 28
Buying from smelters only 21 11 1 5
Buying from steam plants only 0 22 41 41
Producing from S and buying
from smelters 11 6 2 1
Producing from S and buying
from steam plants 0232
Producing from S and buying
from smelters and steam
plants 0001
Buying from smelters and
steam plants 0 7 13 12
Total acid plants 90 90 90 90
Four significant factors that affect the purchase of abatement acid by
current producers of H2S04 in this study are listed as follows:
1. Size
2. Age
3. Compliance with clean air standards
4. Location
Abatement acid produced in the model run from the utility industry at
the $0.70/MBtu clean fuel premium was distributed to 56 different demand
points in 23 states. The current supply that was replaced by byproduct acid
xxxii
-------
TABLE S-5. SUMMARY OF MODEL RESULTS FOR SMELTERS AND
POWER PLANT SALES TO ACID PLANT DEMAND POINTS
(ktons of
ACFL, cents /MBtu
Eastern smelters
Capacity
Sales
Demand points
Western smelters
Capacity
Sales
Demand points
Canadian acid
Capacity
Sales
Demand points
Total smelter acid capacity
Sales
Demand
Mixed demand points
Steam plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur to 1^504 plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur only
0
818
818
15
738
738
15
200
200
4
1,756
1,756
32a
11
-
-
-
-
32,237
30,481
69a
11
58
35
818
818
13
738
738
8
200
200
4
1,756
1,756
24a
13
2,635
2,554
31a
9
32,237
27,926
50a
8
42
50
818
818
12
738
594
3
200
200
2
1,756
1,612
16a
15
8,497
5,108
57a
16
32,237
25,516
35a
5
30
70
818
818
14
738
498
3
200
200
3
1,756
1,516
19a
13
10,758
5,595
56a
14
32,237
25,126
31a
4
28
a. Steam plants and eastern and western smelters can supply a common
demand point.
XXX111
-------
was generally from smaller, older plants remotely located from the elemental
S production points on the Gulf Coast. The larger, more efficient plants
generally can produce acid at costs lower than the delivered cost of abate-
ment byproducts; however, there are exceptions. Savings in transportation
cost because of location advantage can offset production cost differential.
Sensitivity Analyses
One of the key inputs in the analysis of the potential market for abate-
ment byproduct acid is the price of elemental S. All the results of this
study are based on S price of $60/long ton f.o.b. Port Sulphur. A $20.00
decrease in the unit price of S lowers the avoidable cost of production for
H2S04 at each respective acid plant by $6.11/ton of acid produced. This
price structure would reduce the quantity of both byproduct smelter acid as
well as the abatement acid from power plants that can be marketed in the
model.
The model assumed distribution of byproduct acid by rail shipment.
Since several of the potential producers are located on navigable waterways,
barge transportation could be used. As an example of possible savings on
shipment costs, estimates were made for barge shipments of selected produc-
tion totaling 700,000 tons. The cost differential between rail and barge
transportation totaled $725,000 or about $l/ton of acid. This potential
savings is 11% of the average transport cost. Because barge rates are
normally negotiated, rates were not available for inclusion in the trans-
portation model. An in-depth analysis will be required before realistic
conclusions can be made.
RECOMMENDATION
Information on current compliance programs for existing power plants
and for additional planned capacity was not available during the period of
this study. The results of the work show that the potential for use of
recovery technology is good and the initial follow-on work should focus on
plants where compliance alternatives are still flexible. A survey of com-
pliance plans should be carried out and the option of producing byproduct
acid should be evaluated by incorporating specific information on those
plants into the program data base. This evaluation would be particularly
helpful in the planning process for future coal-fired power plants or for
those that may be required to convert from gas or oil to coal.
XXXIV
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INTRODUCTION
Air quality regulations require many fossil fuel-fired power plants to
meet emission limitations on sulfur oxides (SOX) formed when sulfur (S) in
the fuel is burned. The current alternatives are use of low-S fuel that
meets the emission regulation or use of flue gas desulfurization (FGD)
technology to remove SOX after the fuel is burned. Other technology to
convert high-S fuels to clean gas or liquids is being developed but is not
yet ready for use.
The electric utility industry would generally prefer use of complying
fuel if it is the economic choice. However, coal supplies that meet the
emission regulations are in short supply in the eastern part of the country
where a major portion of the power is produced. Much of the coal in the
Western States is sufficiently low in S to meet the present New Source
Performance Standards (NSPS), but limitations on mining and transportation
facilities reduce the potential of this fuel supply for use in the industrial
East. Moreover, proposed changes to the regulations could prevent use of
coal from regions outside the area of use.
FGD technology is still in the development stage, but several power
companies have installed FGD systems to comply with the regulations while
burning high-S fuel. Most of the processes are based on scrubbing with lime
or limestone and produce sludge that must be discarded in storage ponds.
This practice commits large land areas to nonproductive use. Technology for
recovery of S in useful form is also under development. These processes will
provide an alternative to processes producing waste solids and will allow
conservation of natural S reserves. An effective method for evaluating
market potential of recovered products and for identifying the most likely
mix of compliance strategies is needed to provide guidance to the utility
industry in selecting from alternative systems.
In order to provide perspective on the potential use of recovery
technology, the U.S. Environmental Protection Agency (EPA) contracted with
the Tennessee Valley Authority (TVA) to carry out a series of studies to
develop a method for comparison of FGD systems to evaluate market potential
for abatement products, and to characterize and identify power plants that
are the most likely candidates for producing useful products.
Phase I was completed in December 1973 using the TVA power system as a
single utility example of theoretical production and distribution of abate-
ment sulfuric acid (H2S04). A computerized production-transportation model
-------
was developed and although the study was hypothetical, it provided consider-
able insight as to the impact that abatement H2S04 could have on the existing
market. Results of the study were published (4).
Phase II involved a preliminary market study of the potential use of
calcium sulfate (CaS04) sludge by the wallboard fabrication industry to derive
cost data for comparison of throwaway alternatives. This study was conducted
early in 1974 (5).
Phase III, the subject of this report, is an expansion of the Phase I
study. A TVA interim report, S-469, was prepared as part of this phase to
include analysis of abatement production of elemental S as well as H2S04 (6).
However, the cost of abating elemental S with current technology was such
that it could not normally compete in the market with abatement H2S04-
Possibly future technology will provide a more competitive scrubbing system.
The final report of Phase III addresses the potential production and market-
ing of abatement H2SC>4 by the utility industry in the 48 contiguous states
of the U.S. in competition with byproduct acid produced in the smelter
industry.
As presently planned future work will focus on an expanded study of
CaS04 sludge utilization for wallboard, potential use of abatement
S byproducts in the fertilizer industry [S, H2S04, (Nlfy^SO^J, and will
evaluate alternative strategies for optimum technology mix considering
product markets [S, H2S04, (Ntfy^SC^, phosphate fertilizers, wallboard, etc.],
process cost differentials, and clean fuel alternatives.
OBJECTIVES OF PHASE III STUDY
The objectives for this third phase of study are outlined as follows:
Using the analysis techniques, data research, and basic computer model
derived for Phase I, the expanded investigation was conducted to (1)
determine the quantities of byproduct t^SC^ or elemental S which could be
produced by air pollution abatement installations at power plants, (2) define
the most economical market distribution-transportation system including
storage costs, (3) determine competitive costs of H2S04 producers using
elemental S as raw material; costs of acid plant pollution control included,
(4) determine competitive costs of elemental S production, (5) predict as a
function of the above the possible net sales revenue for marketing
strategies covering the existing acid market, the existing elemental S
market, and the growth markets for these commodities, and (6) recommend the
most practical byproduct for specific power plant installations based on
results of the above tasks.
The purpose of these objectives is to provide general and practical
information concerning the potential for abatement byproducts in the current
production, distribution, and use of S and H2S04 in the U.S. Also, the
computer model of Phase I was enlarged to cover the expanded power plant
data base and programed to reflect pollution restrictions dictated by
-------
State Implementation Plans (SIP) and NSPS. The model was designed for
multiproduct capability and relatively easy modification as the data bases
change. A further criterion is system transferability to other potential
users through the use of standard computer languages, commercial time
sharing, and remote batch national computer networks, although it should be
noted that the system that has been built is a highly complex system of
programs and data bases requiring advanced and very specialized skills.
PHASE I MODEL
The Phase I model was a traditional transportation model solved with a
linear programing algorithm. Transportation costs were calculated by a rate
specialist for each possible transport combination. Cost of the abatement
acid at the steam plant was assumed to be zero. The solution to the model
minimized the cost of marketing abatement acid as well as the average total
production cost for the H2S04 industry. The model assumed that the acid
plant would close down and buy abatement acid if the acid could be delivered
equal to or below the avoidable cost of production.
THE EXPANDED MODEL
The 1972 Federal Power Commission (FPC) Form 67 data file contained
information that could be correlated with variables used in the detailed
cost estimates of the five leading FGD processes prepared by TVA in
January 1975 (EPA 600/2-75-006) (7). The availability of these data
provided the basis for development of a cost screen designed to identify the
most promising power plant boiler candidates for abatement byproduct
production. The 1973 FPC Form 67 data available in 1976, contained 5- and
10-yr projections of proposed new power plant installations. SIP and NSPS
standards for air pollution control effective in June 1976 identified
allowable emissions for each power plant in the U.S. A rail transportation
rate generation model developed by TVA was modified to calculate accurate
transportation rates for elemental S and H2S04 for all origins and destina-
tions in the rail rate territories located east of the transcontinental
territory.
A systems model was designed to combine data inputs needed to assess the
nationwide market potential of abatement byproducts. Three major data bases—
(1) H2S04 producers, (2) transportation-distribution options, and (3) power
plant data (FPC, SIP, and TVA cost estimates)—supply information to feed a
market simulation model through three cost generation models. All data were
projected to 1978 values. The three cost generation models include (1)
the transportation cost generator, (2) the scrubbing cost generator, and
(3) the H2S04 production cost generator. The transportation cost generator
provides transportation, distribution, and storage options to calculate least-
cost shipping modes considering rail, barge,or truck combinations for S-H2S04
from Port Sulphur, Louisiana, to all acid plants and between all combinations
-------
of power plants, smelters, and acid plants considered in the study. The second
model, the scrubbing cost generator, was designed to provide a method for pro-
jecting comparative costs for installing FGD systems on power plants projected
to be out of compliance in 1978. It is used as an economic screen to select
the most efficient boilers in terms of unit cost of abatement production. The
third model is used to calculate the avoidable cost of production for each S-
burning H2SC>4 plant included in the study. Avoidable cost is an estimation of
the production cost that could be avoided by closing an existing acid plant
with the assumption that abatement byproduct acid would be available in
amounts equal to the plant production capacity (330 days/yr).
Analysis of the model addresses three choices for the steam plants that
are projected to operate out of compliance in 1978. This includes (1) select-
ing a clean fuel strategy, (2) selecting a limestone-throwaway scrubbing
technology, or (3) selecting an H2S04-producing scrubbing technology.
Concepts include the consideration of nonferrous smelters byproduct acid
in the final solution; central regeneration facilities for one or more boiler
combinations of scrubbing at power plant sites for recovery processes; the
estimated cost of limestone delivered to each potential power plant scrubbing
site (this required development of data for all limestone sources in the U.S.);
actual emission regulation codes and values; limiting the potential acid market
to users of elemental S; distinguishing between scrubbing cost estimates for
new plants versus retrofitting old plants; site specific location adjustments;
the addition of western power plants, acid plants, and smelters; and addition
of geographic data required by the transportation system in the market simula-
tion model. The new data sources considered in addition to the previous phase
include EPA Energy Data Systems (EDS), Compliance Data Systems (CDS), the
monthly report from PEDCo-Environmental Specialists, Inc., Stanford Research
Institute (SRI), U.S. Bureau of Mines (BOM), National Emission Data Systems
(NEDS), Centre Mark Company (CENTRE) geographic and transportation data, and
several FPC publications and reports.
The expanded model allows for significantly better estimates of long-run
competitive equilibrium solutions since they are based upon more realistic
economic premises and outputs of abatement byproducts than the Phase I work.
A basic flow diagram of major system design requirements is shown in
Figure 1. A more detailed flow diagram of the model is presented in Appendix
A. It is assumed that the I^SO^ market can be simulated as though all con-
sumption occurred at H2S04 plants, and that acid-producing firms would close
these plants and buy abatement acid if acid prices were below their projected
long-run H2S04 production cost. Long-run competitive equilibrium market
conditions can be simulated by minimizing the cost to both the H2SC»4 and power
industries. Power plants are assumed free to produce or not to produce S or
H2S04 and to sell to any H2S04 plant in competition with other power plants.
Likewise, H2S04 plants are assumed free to continue buying S from traditional
sources or from power plants, and free to buy acid in lieu of production
subject to competition in their respective industries. Product differentia-
tion is not assumed significant. Problems of stable, guaranteed abatement
supplies are ignored, but probably are solvable. Rail transportation
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BYPRODUCT MARKETING MODEL
BASIC SYSTEM
SUPPLY
DATA BASE
POWER PLANTS,
REGULATIONS,
COST ESTIMATES
SCRUBBING
COST
GENERATOR
TRANSPORTATION
DATA BASE
TARIFFS
RAIL MILEAGE
BARGE MILEAGE
TRANSPORTATION
COST
GENERATOR
DEMAND
DATA BASE
ACID
PLANTS
ACID PRODUCTION
COST
GENERATOR
MARKET SIMULATION
LINEAR
PROGRAMMING
MODEL
/
\
EQUILIBRIUM
SOLUTION
RESULTS
A
vy
Figure 1. Flow diagram for major system design requirements.
5
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cost is assumed adequate for simulating competitive market conditions. Some
preliminary work was done using barge-truck strategies to determine possible
impact on the equilibrium solution, but in-depth analysis will be required
before any realistic conclusions can be made.
PROGRAM AND SCOPE
The computer model design is directed towards identifying major candi-
dates for abatement byproduct production and consumption. From a data bank
maintained at the TVA National Fertilizer Development Center, design and oper-
ating inputs were cataloged in the computer for existing U.S. contact and
chamber t^SO^ plants. Capital and operating costs for mining S by the Frasch
process, transporting and storage of S, manufacturing acid by the contact
process, storage of acid, and controlling acid plant tail gas emission were
calculated to determine competitive costs of S and acid production.
Development of an accurate transportation data base for computing
shipping costs for S and acid contributed in a major way to the value of the
study since shipping cost is a significant and essential element in the price.
Power plant design and operating data provided in the FPC Form 67 data
base were used to characterize key design and operation parameters of all
power plants in the U.S. For this effort, only boilers burning coal or oil
are of interest. Parameters such as fuel type, S in fuel, heat rate, fuel
consumed, on-stream time, age of boiler, etc., are vital. Possible output
of byproducts was calculated for each power plant, given the level of S02
control designated by June 1976 SIP standards. For boilers where scrubbing
was needed, 90% removal efficiency was assumed. However, scrubbing was used
only on the number of boilers necessary to bring the plant into compliance.
The most likely candidates for use of recovery compared to low-S fuel or
limestone scrubbing were identified. A mathematical statement of the model
is presented in Appendix B.
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ELEMENTAL S AND H2S04 INDUSTRY
S is one of the most important industrial raw materials. It is used
principally in the form of I^SO^ at some stage in the production of virtually
everything we eat, wear, or use. It is referred to as the workhorse of the
chemical industry. Its consumption is an indicator of the state of the
economy of an individual nation or of the world. Unfortunately, however, in
most uses S ends up as a residual of the production process. Recycling this
residual back into productive use is a major problem facing the chemical
industry.
DOMESTIC CONSUMPTION OF S
S enters into the production of many products in varying amounts, for
example,from 18.090 tons of S or S equivalent per ton of uranium 235 (U-235)
0.0003 ton/ton of phenol-formaldehyde plastic molding compound. The amount
of S and the equivalent l^SO^ consumed per ton of various manufactured
products is shown in Appendix C.
The demand for S or 1^804 is derived from the demand for the products
outlined in Table 1. In most instances it is used in fixed proportions with
other inputs in the production process. For this reason demand is inelastic
in the short run but tends to become more elastic in the long run because
there are very few unique uses for S. The demand is subject to only modest
seasonal fluctuations. Because of the pervasive use of S throughout the
industrial sector of the economy there has been a historically strong corre-
lation between the demand for S and the index of industrial production. That
is, the demand is responsive to cyclical fluctuations in business conditions
and expands when industrial production rises.
In 1974 55% of all domestic S consumption was used in the manufacture
of fertilizers. The balance of 45% was used in the production of the follow-
ing products: plastic and synthetic products, 6%; paper products, 3%; paints,
4%; nonferrous metal production, 5%; explosives, 3%; petroleum refining, 2%;
iron and steel production, 1%; and other uses, 21%. Each of the various uses
included in the latter category used <1% of the S demand (8) .
The distribution trends for the apparent consumption of S, by source,
1970-76, is outlined in Table 2. The distribution in 1976 mainly from
domestic sources is listed as follows:
Frasch S 43%
Recovered elemental S 29%
S in other forms 8%
Imports of Frasch and
recovered elemental S 16%
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TABLE 1. U.S. S CONSUMPTION PATTERNS 1964-743
(klong tons S)
Agriculture (fertilizers)
Plastic and synthetic products
Paper products
Paints
Nonferrous metal production (Cu-U)
Explosives
Petroleum refining
Iron and steel production
Other
U.S. primary demand
1964
3,090
500
415
505
235
215
155
330
1,810
7,255
1965
3,610
555
430
510
265
230
165
295
1,921
7,981
1966
4,425
555
440
520
310
260
190
275
2,170
9,145
1967
4,735
495
400
505
260
265
195
220
2,176
9,251
1968
4,470
550
390
490
300
250
180
170
2,272
9,072
1969
4,465
570
365
445
370
260
190
125
2,379
9,169
1970
4,680
495
350
420
390
255
195
120
2.322
9,227
1971
4,800
515
320
380
410
255
200
105
2,188
9,173
1972
5,210
540
340
390
430
260
220
110
2,354
9,854
1973
5,520
580
370
420
500
280
230
110
2,224
10,234
1974
5,980
610
390
440
560
290
240
110
2,260
10,880
a. Sulfur. U.S. Bureau of Mines reprint from Bulletin 667, 1975, p. 15.
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TABLE 2. APPARENT CONSUMPTION OF S IN THE U.S.
(klong tons)
1970 1971 1972 1973 1974 1975 1976
Frasch
Shipments 6,504 6,738 7,613 7,438 7,898 6,077 5,860
Imports 539 449 269 302 954 967 731
Exports 1.433 1.536 1.852 1.776 2.601 1.295 1.198
Total 5,610 5,651 6,030 5,964 6,251 5,749 5,393
Recovered
Shipments 1,471 1,582 1,927 2,451 2,547 2,902 3,146
Imports 998 850 869 920 1,196 930 996
Exports from the Virgin Islands - - ^ - 62^ 57 72_
Total 2,469 2,432 2,796 3,371 3,681 3,775 4,070
Pyrites
Shipments 339 316 283 212 162 237 286
Imports5 130 130 50 - - - -
Total 469 446 333 212 162 237 286
Byproduct sulfuric acid 537 518 546 600 654 767 942
Other forms0 142 126 149 88 7£ 75 77_
Total all forms 9,227 9,173 9,854 10,235 10,818 10,603 10,768
a. Sulfur, U.S. Bureau of Mines reprint from Bulletin 667, 1975, p. 15.
b. Estimate.
c. Includes consumption of hydrogen sulfide and liquid sulfur dioxide.
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Three distinct trends in domestic consumption of S by sources are indicated
in Table 2. Domestic Frasch S has steadily declined while domestic_recovered
S has steadily risen. BOM predicts that these two trends will continue.
Although imports have become an increasingly important source of S for
domestic consumption, they are expected to remain stable or even decline over
the long range.
The basic reason for these trends relates to the pervasive drive for
pollution control. The Frasch industry formerly enjoyed a dominant role in
the S market throughout the U.S. However, since 1960 recovered S and byproduct
H9SOA sectors have progressively obtained control of the markets in the
Western and Central States as well as a gradual penetration of the markets in
the Southern States. Canadian imports of recovered S are largely confined to
the northern tier of states, whereas Mexican imports of Frasch S are limited
to the Florida and east coast markets. As a result the Frasch industry has
gradually constricted its marketing to the Southern and Eastern States and
the inland waterway system with the export trade holding at a level of 1-2
Mtons.
Long-term projections of S demand in the U.S. are shown in Table 3 (9).
ORGANIZATION OF FRASCH S PRODUCTION, DISTRIBUTION, AND HANDLING
BOM reports the production of S in all forms in 1976 at 10.707 Mlong
tons (5); elemental S was produced by 69 companies at 182 plants in 32 states.
Ten of the largest companies own 57 plants and account for 75% of the output.
The production was concentrated in Texas and Louisiana accounting for 68% of
the total output. The Frasch S was produced in these two states at 12 mines.
TABLE 3. U.S. S DEMAND FORECAST
(Mlong tons)
Forecast
1976 1980 1985 1990
Fertilizer 6.4 7.5 9.3 11.0
Industrial 4.5 5.3 6.0 6.8
Total 10.9 12.8 15.3 17.8
10
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The mines are owned by the following companies:
Company No. of mines State
Freeport Minerals 3 Louisiana
Texas Gulf 5 Texas
Texas Gulf ! Louisiana
Duval 1 Texas
Jefferson Lake Sulfur 1 Texas
Farmland Industries Corporation
(purchased from Atlantic
Richfield Corporation 11-76) 1 Texas
Five of the largest mines account for 82% total Frasch output and 48%
of the total production of S in all forms (8).
Frasch S production is a mining operation. Wells are sunk into S-bearing
strata, S is melted by hot water injected into the strata, and the molten S
is pumped out. The molten S is pumped from the well to either heated tanks
for storage as a liquid or to vats where it cools and solidifies.
About 75% of the total mining costs of Frasch S is variable, such as
the cost of natural gas to heat water, water treatment, labor, ana operating
supplies (10). The cost of hot water to melt the S is by far the most
important cost and will differ drastically from mine to mine as water require-
ments and fuel cost differ. In an analysis prepared for this study the cost
of natural gas was varied from $0.20-$3.00/ kf t-* with an intermediate value
of $1.00/kft3 (6). Water requirements or water rate varied from 1600 gal/ton
of S produced to 9000 gal/ton of S. Results of the cost calculations
(in terms of third quarter, 1974 dollars) are presented in Appendix D,
Tables 1-3.
These results indicate that the lowest capital investment and operating
costs are associated with mines having low water rates and that cost increases
markedly with increasing natural gas costs. For operation where the major
variables are constant, i.e., water rate and natural gas cost, the usual
economies of size prevail.
The development of a S dome can be compared to the punching of pins in
a pin cushion. Each well punched into a S dome formation has an expected
life of 1-2 yr. At any time the S mine can have several wells operating in
parallel. The number of wells depends primarily on the short-run market
demand. As the mining process for a given dome reaches the mature stage,
operating costs increase at an increasing rate due to the increased water and
energy requirements. This incremental increase causes the supply price of
S to rise to a point where it is no longer economical to continue mining the
S dome.
Most molten S is shipped in liquid form by water from the mines or
transshipment terminals on the Texas and Louisiana Gulf Coast to the marketing
terminals. The basing point for the Gulf Coast market is Port Sulphur.
11
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Marketing terminals are strategically located either on the inland waterway
system or along the east coast adjacent to ports served by deepwater vessels.
From the marketing terminal, molten S is transported by barge, truck, or rail
directly to the point of consumption at a S-burning acid plant. A map of the
relative locations for S terminals is presented in Figure 2. March 1975 trans
port rates were used in this study. Rates were projected to 1978 with an
inflation factor of 1.15.
Cost data were estimated for S-marketing terminals serving H2S04 plants
in eastern U.S. (11, 12). The data obtained are presented in Appendix E in
terms of third quarter, 1974 dollars. As expected, increasing the size of
the terminals decreases the unit operating costs. Terminals that handle only
molten S have lower costs than terminals which reship both solid and liquid
S. Storage requirements added, on the average, $2.47/ton to the cost of S
on the inland waterway system and $1.20 at deepwater terminals in Florida
and the east coast. These data were used in the program to calculate the
production cost of l^SO^ for this study.
The delivered cost of S to each acid plant in the model is based on
$60/long ton for S f.o.b. Port Sulphur plus transportation from Port Sulphur
through marketing terminals by either truck or rail to the acid plant, which-
ever is lower cost. The least-cost mode for transporting S was extended to
cover a relative comparison of rail transportation from Port Sulphur versus
water transport — terminal throughput — truck or rail to the acid plant. This
least-cost mode was selected in all cases for S delivered to a given acid
plant.
Most of the large t^SO^ users own and operate captively their acid
production plants. Such plants are located in close proximity to the major
markets for the prime product (chemicals) or close to the raw material inputs
used in the production process (fertilizers) . Although many companies that
produce l^SO^ are industrial giants, there is very little opportunity for
concentration in the acid market because of the pervasive use of H2SC>4 in the
many sectors of the industrial economy. That is, no single acid producer
uses enough S to exercise significant control over the S market. A breakdown
of the top 20 largest producers of H2S04 is presented in the analysis section
of this report.
S PRICE HISTORY
The average annual price f.o.b. mine or S plant in dollars per long ton for
Frasch and recovered S reported to BOM from 1954-76 are presented in Table 4.
It is noted that the cyclical fluctuation in business activity in the
domestic economy during the 1958 and 1961 recessions did not affect S prices.
This situation prevailed over several decades prior to 1965 due to the
existence of ample Frasch stocks under the control of a few major producers.
This was followed by a period of short supply coupled with the rapid growth
of the fertilizer industry which resulted in abnormally high prices in 1967
and most of 1968 when an oversupply developed. The oversupply caused a
general collapse of the S market lasting through most of 1973. Then prices
12
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LIQUID SULFUR TERMINAL
INLAND WATERWAY
9'DEPTH OR MORE
6'-9'DEPTH
— — UNDER CONSTRUCTION
I—ft TENNESSEE-CUMBERLAND RIVER CANAL
Figure 2. Geographic distribution of S terminals.
13
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TABLE 4. TIME-PRICE RELATIONSHIP FOR Sa
(Frasch and recovered S f.o.b. mine/plant)
Average annual price, dollars per long ton
Year
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974,
1975b
1976° (first quarter)
a. Sulfur, U.S. Bureau
p. 16.
b. Preliminary.
c. Estimate.
Actual prices
26.65
27.94
26.49
24.41
23,82
23.46
23,13
23.12
21.75
19.99
20.19
22.47
25.77
32.64
40.12
27.05
23.14
17.47
17.03
17.84
28.88
46.50
55.00
of Mines reprint
Constant 1973 dollars
45.87
47.44
43.50
38.62
36.76
35.60
34.57
34.10
31.70
28.76
28.64
31.30
34.92
42.83
50.59
32.55
26.42
19.07
17.98
17.84
28.18
38.72
43.55
from Bulletin 667, 1975,
14
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rose to an average of $51.19/ton f.o.b. mine/plant in 1976 followed by an
apparent stabilizing trend. The average price for recovered S during this
same period was $13.50/ton lower f.o.b. plant, as compared to Frasch S price.
S is normally sold under long-term contracts direct to industrial con-
sumers and priced on a delivered basis at regional terminals. The regional
terminal prices vary with location. Export prices are determined independent
of domestic prices. The f.o.b. or f.a.s. gulf port prices published in the
Chemical Marketing Reporter and other journals reflect spot purchases.
Generally the quoted prices for spot and contract sales are the same, but
with no formal commodity exchange for S it is difficult to determine the
exact S price at any given point in time. The current published price in
the Chemical Marketing Reporter is $65/long ton f.o.b. gulf ports. The price
assumed for this study is $60/long ton f.o.b. Port Sulphur.
S RESERVES
G. H. K. Pearse recently completed a study on the long-run S supply for
North America (1). He projects the long-run supply price gradually increas-
ing from $10-$40/ton f.o.b. mine in 1970 dollars (about $50 in 1974). The
resulting S supply price increase will encourage the relatively inefficient
Frasch and native S mines to become producers over time. He projects that
the current S reserves in the U.S. from conventional sources (Frasch process,
native ore, petroleum, natural gas, sulfide ores, and pyrite) in the amount
of 290 Mtons will be mined out at current production rates, about 12 Mtons/yr,
by 2000- During the same period it is estimated that 110 Mtons of S will
become available from oil shales and coal gas, giving a total cumulative
production of 400 Mtons. The cumulative demand in the U.S. is estimated to
be 550 Mtons by 2000, leaving a deficit of 150 Mtons of S (513.95 Mtons
of H2S04).
BOM estimates the U.S. reserves at 230 Mtons (8). This includes reserves
of primary S deposits of the elemental, pyrite, and sulfate types. Such
reserves are defined as S that is recoverable at present price levels using
current technology.
They have also defined "other identified S resources" as S potentially
recoverable from identified deposits at all price levels by full utilization
of current technology. The domestic reserves identified in this classifica-
tion amount to 400 Mtons. No attempt is made in the latter estimate to
associate the estimated supply price with specific reserve sources. A study
in this area is needed.
IMPACT OF ENVIRONMENTAL REGULATIONS ON S PRODUCTION
Frasch S Production
There are relatively few environmental problems associated with the
Frasch sector of the industry. The major centers of production are located
in remote undeveloped areas and the molten S product which is produced and
15
-------
distributed directly to the consumer poses no environmental problem. However,
the small portion of elemental S that is stored and distributed in the solid
form (referred to as vatted S) does cause a dust problem. Special handling
techniques have been developed to overcome the dust hazard. It is estimated
that 95% of the elemental S distributed to S-burning acid plants is handled
in the liquid form.
Recovered S Production
The growth in the recovery of S from natural gas since the mid-1950 's
has been one of the most significant trends in the S market. The principal
sources of recovered S are the hydrogen sulfide (l^S) contaminants in sour
natural gas and the organic S compounds contained in crude oil. Recovery is
mainly in the elemental form. Its production has been stimulated by the
increasing demand for low-S fuel as an air pollution control measure.
Recovered elemental S accounted for 29% of the total domestic production of
S in all forms in 1976 (3) . It was produced by 51 companies in 137 plants
in 27 states. The five largest recovered elemental S producers were Chevron
USA Inc., Exxon Company USA, Getty Oil Company, Shell Oil Company, and
Standard Oil Company of Indiana. Together their 41 plants accounted for 53%
of the recovered elemental S production in 1976. Future recovery of S from
natural gas is likely to decline as gas supplies drop.
Byproduct H7SOA Production at Smelters
In the smelting of nonferrous sulfide ores, primarily copper (Cu) , lead
(Pb), and zinc (Zn) , the S is converted into sulfur dioxide (S02) which can
be recovered from stack gases in the form of ^504. The acid is referred to
as byproduct H^SO^. In practice only the more highly concentrated portion of
the smelter gases are used to produce t^SO^. Because of the remote location
of most nonferrous metal smelters the pollution control laws allow inter-
mittent controls for the lean streams of the S02 in the stack gases.
The S contained in byproduct I^SO^ produced at Cu, Pb, and Zn smelters
during 1976 amounted to 9% of the total domestic production of S in all forms.
This represented a 23% increase in output as compared to 1975. It was pro-
duced by 13 companies at 24 plants in 13 states. The five largest producers
of byproduct t^SO, were American Smelting and Refining Company, Magma Copper
Company, Kennecott Copper Corporation, Phelps Dodge Corporation, and St. Joe
Minerals Corporation. Together their 14 plants produced 71% of the output
during 1976 (3).
H2S04 Production in S-Burning Acid Plants
All H2S04 plants, particularly the older ones, have problems in con-
trolling the amount of pollutants in their tail gases required by air pollu-
tion control laws. The SIP standards in most states require the conversion
efficiency of S to H2S04 to be equal to or >99.7% efficient. This
means that a major portion of the existing plants must add a retrofit
tail gas cleaning system in order to comply with the air pollution control
laws. A detailed discussion on the retrofit alternatives for H2S04 plants
is outlined in Appendix F.
16
-------
DOMESTIC CONSUMPTION OF H2S04
In 1974, 90% of the S consumed in the U.S. was either converted to HoSO/
or produced directly in this form. H2SOA is considered to be the most
important of the mineral acids. In 1974 H2S04 was produced at 150 plants in
42 states (13).
H2SO^ is produced by burning S or S-bearing materials to form S02. The
S02 is oxidized by air in the presence of a catalyst to form S03. The 803
is then passed through an adsorption tower where it is absorbed in recircu-
lating concentrated acid. This process produces concentrated acid of high
purity; compact plants of high capacity are feasible.
Sources of S or S02 for the manufacture of H2SO. include (1) elemental
S, (2) pyrites, (3) gypsum, (4) petroleum products, (5) smelter off-gases,
and (6) waste gases from burning fossil fuels. In 1975 a brimstone-based
acid accounted for 91% of the total H2SO^ production, followed by non-
ferrous smelter gases at 7% and all other raw material sources at 2%.
H2S04 capacity and production have grown slowly. In 1967
capacity was 36.93 Mtons. The average growth rate has been approximately
3.5% annually; and, by 1975, capacity had grown to 48.18 Mtons. Based on
current announcements of new plants, H2S04 capacity by 1980 should be approxi-
mately 51.0 Mtons.
In 1967, U.S. production of H2S04 from all sources was 28.8 Mtons,
representing an average operating rate of 78% of capacity (13) . In the
following 7 yr, a general improvement in operating rates for H2S04 plants
took place, reaching a peak of almost 90% of capacity during the phosphate
fertilizer shortage of 1973-74. In 1975, with the addition of almost 10
Mtons of additional capacity the average operating rate for the industry
dropped to only 67% of capacity. Production of H2S04 from all sources was
in excess of 32.3 Mtons.
Almost all plants in the U.S. today are contact plants. Chamber plants,
which are being phased out, now comprise only 0.2% of total plant capacity
compared to 3.5% in 1967.
The use of spent H2S04, the second most common process, has decreased
over the past 8 yr from a high of 20.5% of capacity in 1967 to 17.4% in 1975.
It is expected that use of spent H2S04 will drop to 16.5% of capacity by 1980.
Production from smelter operations has been increasing. In 1967, the
percent of total capacity for plants associated with the smelters was only
8.5. By 1975, it had grown to 12.3% and is expected to continue to a high
of 14.7% by 1980. The availability of this acid for fertilizer use, however,
may be limited because of its use in the Southwest for leaching Cu and U
ores. Table 5 lists the capacity, production, and operating rates for H2S04
in the U.S. for the years 1967-80 (14).
17
-------
TABLE 5. U.S. H2S04 MARKET STATISTICS
(Mtons of material)
Product
1967
1970
1973
1974
1975
1976
1977
1978
1979
1980
Total Sulfuric Acid
Capacity
Production
Operating rate, %
36.93 36.71 39.22 38.69 48.18
28.82 29.53 31.95 34.18 32.37
(78.0) (80.4) (80.0) (88.3) (67.2)
48.54 49.72 50.41 50.89 51.01
Smelter Sulfuric Acid
Capacity
Total capacity, %
Production
Operating rate, %
Spent Sulfuric Acid
Capacity
Total capacity, %
Production
Chamber Process Plants
Capacity
Total capacity, %
Production
Operating rate, %
Sulfur- Burning Contact Plants
Capacity
Total capacity, %
3.14
(8.5)
1.25
(39.7)
7.56
(20.5)
1.08
1.28
(3.5)
0.84
(66.0)
24.94
(67.5)
3.39
(9.2)
1.84
(54.1)
7.58
(20.6)
1.27
0.67
(1.8)
0.32
(48.2)
25.08
(68.3)
3.81
(9.7)
2.05
(54.0)
8.60
(21.9)
1.56
0.30
(0.8)
0.11
(35.4)
26.51
(67.6)
4.14
(10.7)
2.24
(54.1)
8.32
(21.5)
0.75
0.14
(0.4)
0.13
(93.0)
26.09
(67.4)
5.97
(12.3)
2.63,
(44.0)
8.40
(17.4)
0.95
0.12
(0.2)
0.10
(83.9)
33.70
(70.0)
6
(13
8
(17
0
(0
33
(68
.67
•7)
.41
.3)
.07
•1)
.39
.8)
6.82
(13.7)
8.41
(16.9)
0.07
(0.1)
34.42
(69.2)
7.38
(14.6)
8.41
(16.7)
0.07
(0.1)
34.55
(68.5)
7.38
(14.5)
8.41
(16.5)
0.07
(0.1)
35.03
(68.8)
7.50
(14.7)
8.41
(16.5)
0.07
(0.1)
35.03
(68.7)
a. Refortified acid only.
-------
END USE ANALYSIS OF S AND H2S04 IN FERTILIZER PRODUCTION
PHOSPHATE FERTILIZER MARKET
While S and H2S04 have many uses, it is estimated that about two-thirds
of the total U.S. consumption of S in all fortnr, is used in the fertilizer
industry (15). The balance of consumption was for a variety of uses in
essentially every sector of the domestic manufacturing industry. In 1976
preliminary data indicate that 6.4 Mtons of S was used in the production of
fertilizer (Table 6). Ninety percent of the total went to the production
of phosphoric acid (H3P04) and normal superphosphate. Thus, any analysis of
the future of the S and H2S04 market must consider the prospects of the phos-
phate fertilizer market. The following is a review of the production and use
patterns that have taken place in the U.S. phosphate fertilizer market in the
past few years and a discussion of the future U.S. outlook for the phosphate
industry.
TABLE 6. U. S. CONSUMPTION OF S IN ALL FORMS BY END USE
(klong tons S equiv)
1974 1975 1976
H2S04
Fertilizer acid
H3P04 4,945 5,410 5,560
Normal superphosphates 405 290 230
SO, and other 685 670 610
^ ' • ' ~ T --• ••
Total fertilizer acid 6,035 6,370 6,400
Industrial acid 3,715 3,080 3,285
Total H2S04 9,750 9,450 9,685
Nonacid 1,250 1.200 1.215
Total in all forms 11,000 10,650 10,900
19
-------
Phosphate Consumption Patterns
Between 1945 and 1974, the U.S. phosphate fertilizer market has averaged
an annual growth rate of almost 4.5%/yr (16). Over this period, the market
has been characterized by several major cyclical movements; however, market
growth has exhibited a stable upward movement. In recent years, there has
been an indication that phosphate use by farmers has begun to level off
(Table 7) . Soil test results have shown an accumulation of phosphorus (P)
in the soil in some areas, and application rates on the nation's major crops
appear to be approaching optimum levels under today's cropping practices
and management.
In 1975 phosphate fertilizer use declined by more than 10%. Analysts
generally agree that this decline was caused by an imbalance in the input and
output price structure faced by the farmer during the year. In relation to
the prices received by the farmer for his crops, fertilizer price levels
were too high; and the farmer curtailed fertilizer use. With an improvement
in the benefit to cost ratio for the farmer in 1976, phosphate fertilizer use
recovered the lost demand of the 1975 season and exceeded its previous highs
by almost 200,000 tons of P2C>5 (17). While this recovery was significant,
it left in doubt the question of the future growth pattern for the phosphate
market.
Some indication of the future growth in phosphate fertilizer demand can
be found by looking at the recent history of average rates of application on
the four major crops grown in the U.S. (Table 8) (18). Cotton producers,
for example, have not changed phosphate application levels since 1964,
responding only to changing market conditions as determined by cotton prices.
Until last year, when phosphate application rates reached all time highs,
corn had shown the same pattern. With application rates and the percentage
of the planted acreage receiving phosphates appearing to be relatively con-
stant, acreage planted becomes the key factor in forecasting the future
demand for phosphate fertilizers in the U.S. In recent years, planted
acreage has been at an all time high as government policy has been geared to
stimulating maximum farm production. High levels of exports of farm products
at very favorable prices in response to food shortages in many parts of the
world have played an important part in the farm picture in the past few years.
But this situation has been changing rapidly. Grain-producing countries
have had good weather conditions, are reporting bumper crops, and are actively
seeking export markets. In addition, some of the major importing nations
are also in the midst of harvesting a record crop production and establishing
buffer stocks as a future hedge against poor crop years. These factors make
forecasting the future national agricultural policy difficult and clouds the
outlook for the short-term phosphate fertilizer market.
Projections of phosphate fertilizer use in 1980 which were made prior to
the 1976 recovery indicate a range between 5 and 6 Mtons of P205 (19).
Including the 1976 recovery projections of 1980, demand has varied from 5.5-
6.3 Mtons P205, centering around 5.8 M (20). If phosphate use falls within
these suggested ranges, the average annual growth rate for the next few years
will remain below the long-term average for the industry.
20
-------
TABLE 7. U.S. PHOSPHATE CONSUMPTION
(Tons of
Fiscal
year
1955
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
Total
P205
consumption
2,283,660
2,572,348
2,645,085
2,807,039
3,072,873
3,377,841
3,512,207
3,897,132
4,304,688
4,453,330
4,665,569
4,573,750
4,803,443
4,863,738
5,085,162
5,098,626
4,510,979
5,215,246
P205
in
mixtures
1,821,087
2,033,316
2,069,425
2,219,444
2,473,599
2,704,985
2,816,056
3,110,784
3,502,897
3,579,140
3,724,237
3,709,062
3,943,372
3,997,280
4,237,591
4,271,429
3,717,825
4,422,380
Direct application materials
Superphosphates
291,406
287,335
303,256
313,860
318,415
382,287
403,403
506,351
517,470
566,120
656,713
608,338
610,969
620,059
576,580
576,497
566,953
564,667
Ammonium
phosphates
84,617
171,329
188,398
204,768
205,457
215,604
204,401
220,908
223,761
227,288
207,448
183,688
178,878
174,277
201,423
193,000
175,899
228,199
Total
462,573
539,032
575,660
587,595
599,274
672,856
696,151
786,348
801,791
874,190
941,332
864,697
860,071
866,458
847,571
827,197
793,154
792,866
Diammonium
phosphates
113
35,278
63,482
110,074
177,487
244,271
302,088
417,821
451,452
608,296
723,786
726,486
814,938
883,795
1,073,198
1,051,416
1,038,091
1,486,950
-------
TABLE 8. AVERAGE PHOSPHATE FERTILIZER APPLICATION RATES
FOR MAJOR CROPS IN THE U.S.
(Lb/acre)
Year Corn Cotton Soybeans Wheat
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
33
40
49
51
57
56
63
54
57
54
54
50
60
30
32
32
30
31
31
27
27
30
32
31
21
28
3
5
9
9
9
11
10
10
13
13
11
10
12
12
12
13
16
15
15
15
15
16
17
18
15
19
Phosphate Production and Trade Patterns
The phosphate fertilizer market is made up of several different types
of products that have different S requirements. These can be classified as
normal superphosphate, concentrated superphosphate, ammonium phosphates,
liquid mixtures, and granular mixed fertilizers. Depending upon the grade
of phosphate rock used, S requirements for the production of normal super-
phosphate range from 0.60-0.65 ton of S per ton of P205, concentrated super-
phosphate from 0.65-0.70, and wet-process H3P04 from 0.90-0.95 (21). The
P205 content of ammonium phosphates and most fertilizer mixtures is derived
from wet-process H3P04- Because of the wide range of S requirements, the
future phosphate product mix is an important factor in determining the out-
look for the S and ^SO^ market.
Production of wet-process H^PO^ and the major phosphate fertilizer
materials in the U.S. is shown in Table 9 (22). Between 1960 and 1976,
HoPO/ production increased from 1.3 Mtons of ?2®5 to almost 7 Mtons. During
the same period, normal superphosphate production has steadily declined and
today is <400,000 tons of P205- Concentrated superphosphate production has
remained relatively constant between 1.0 and 1.5 Mtons.
The significant change in the U.S. phosphate fertilizer market has been
the rapid shift from low-analysis materials to a market based almost entirely
on the production of wet-process H3P04. In addition to the ammonium phosphate
grades, there has also been a significant gain in the liquid mixed ferti-
lizer market which is based primarily on wet-process superphosphoric acid.
22
-------
ISJ
LO
TABLE 9. U.S. PRODUCTION OF H3P04 AND PHOSPHATE FERTILIZERS
(ktons of
Year
1955
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
1974
1975
1976
Wet-process
phosphoric
acid
775,000
1,325,000
1,409,000
1,577,000
1,957,000
2,275,000
2,896,000
3,596,000
3,993,000
4,152,000
4,328,000
4,642,000
5,016,000
5,775,000
5,919,000
6,186,000
6,889,000
6,938,000
Multinutrient materials
Superphosphate
Normal
1,558
1,270
1,247
1,213
1,227
1,206
1,113
1,138
1,184
914
807
670
626
677
620
698
484
388
Concentrated
707
986
1,024
960
1,113
1,225
1,466
1,696
1,481
1,389
1,354
1,474
1,513
1,659
1,693
1,719
1,649
1,595
Ammonium
phosphates
_
269
370
536
-
-
1,081
1,376
1,747
1,633
1,844
2,092
2,395
2,577
2,919
2,654
3,044
3,633
Other
__
131
102
113
-
-
172
239
284
215
288
361
468
570
347
296
218
232
Total
8
400
472
649
891
1,034
1,253
1,615
2,031
1,848
2,132
2,453
2,863
3,147
3,266
2,950
3,262
3,865
Total
2,273
2,656
2,743
2,822
3,231
3,465
3,832
4,449
4,696
4,151
4,293
4,597
4,992
5,483
5,578
5,367
5,395
5,848
-------
H3P04 use in the production of granular complete mixed fertilizers also
remains as a significant part of the phosphate fertilizer picture.
The Canadian phosphate market is very similar to the U.S. with the
exception that normal and concentrated superphosphate play a much smaller
role in the total supply picture. Most of the phosphate production in
Canada is made up of the various grades of monophosphate and diammonium
phosphate materials.
Exports of phosphate materials to the world market now play an important
role in the supply situation for the U.S. It is estimated that over 20% of
the total U.S. production of finished phosphate fertilizer materials now
enters world markets. Up to now the ammonium phosphates and concentrated
superphosphate have been the primary products in the export market. However,
in the past several years there has been a growing trend for other countries
to establish phosphate product production facilities based on the importation
of ^PO^. The U.S. has a key position in this market and is exporting sub-
stantially higher amounts of ^PO^ than it has in previous years. Product
exports are shown in Table 10 (23).
When product production levels are related to trade tonnages, the impact
of the shift to HoPO^-based materials is apparent. Concentrated super-
phosphate production has leveled off while trade levels have increased. Thus,
the available supply for the U.S. market for this product has been on the
decline along with supply of normal superphosphate. Ammonium phosphate
production has been expanded to the point of satisfying the domestic market
and allowing large gains in the export sector. Ammonium phosphates now
account for over 60% of all U.S. phosphate production entering the export
market.
Future Supply Patterns
The last .large-scale expansion of phosphate production facilities took
place from 1973 to 1975. At that time, the total wet-process l^PO^ capacity
went from 6.4 Mtons to 8.6 Mtons P205- With the final completion of this
expansion program early in 1977, the U.S. 1^04 capacity stood at just over
9.0 Mtons. There have been no expansions of Canadian capacity which now
contributes over 900,000 tons of P2C>5 to the North American total (24).
Between now and 1980, there are no new capacity expansions anticipated.
Several possible projects have been in the planning stage for some time but
cannot be included in the tabulation at this time. Should any of these units
be built, U.S. capacity will exceed 10 Mtons of ?2®5-
Over the last 15 yr, the number of normal superphosphate plants has
shown a steady decline. At one time, they numbered over 200 units scattered
over the country, but today they number only in the forties and are located
primarily in the southeastern U.S. Faced with rising costs on all fronts,
many of these plants have been converted to ammoniation-granulation facili-
ties which use H^PO, as the primary phosphate source. It is expected that
normal superphosphate production will continue to decline. However, it will
be a somewhat slower rate than has been experienced in the past few years.
24
-------
TABLE 10. U.S. PHOSPHATE FERTILIZER EXPORTS
(ktons of P205)
Superphosphate Ammonium Phosphoric Total all
Year Normal Triple phosphates acid materials
1955 57 60 38 - 155
1960 31 144 46 - 221
1961 30 174 34 - 238
1962 26 228 53 - 307
1963 18 270 81 - 369
1964 39 276 159 - 474
1965 17 233 140 - 390
1966 18 294 338 - 650
1967 15 291 556 - 862
1968 19 533 556 - 1,108
1969 6 361 413 - 780
1970 8 325 448 19 800
1971 2 321 597 57 977
1972 12 393 799 22 1,263
1973 3 409 983 40 1,473
1974 6 488 876 33 1,451
1975 6 494 1,181 169 1,882
1976 2 589 1,242 216 2,049
25
-------
It is doubtful that this product will disappear completely from the phosphate
picture; however, its market share will remain quite small in the years ahead.
Very little in the way of capacity additions for concentrated super-
phosphate are expected. This product's market share will probably decline;
however, it is expected that production levels will remain relatively con-
stant over the next few years. Concentrated superphosphate will remain a
popular export product for those countries that have domestic nitrogen (N)
supplies and do not wish to import N in the form of ammonium phosphates.
The future supply outlook for the U.S. phosphate industry is shown in
Figure 3. Total demand for phosphate materials including that entering the
export market should be approaching 8 Mtons of ?2^5- Tne potential supply
that can be made available to the fertilizer industry if plants are operated
at their historical average operating rate of 87% of capacity, and assuming
the continued decline in normal superphosphate production, will balance with
this level of demand by the end of the decade. Between now and 1980, however,
it can be expected that the industry will operate at somewhat reduced levels
moving to higher or lower levels as dictated both by domestic demand and the
demands of the export market.
Implications for the S Market
From the above discussion it can be concluded that the S industry should
not expect the phosphate fertilizer market to absorb any large-scale
"increase" in the production of H2S04 in the next few years. The shift to
t^PO^ with its higher S requirement is almost complete so the changing product
mix of the phosphate industry will have a relatively minor impact on the S
market.
S demand by the phosphate industry should be variable over the next few
years as operating rates change according to the demands of the export market.
Between 1975 and 1980, however, estimates show that total S demand by the
fertilizer industry should increase by about 1 Mtons. The industrial sector
of the market is estimated to grow by 1.2 Mtons during the same period.
26
-------
10
O
w
o.
u_
O
to
O
(O
z
o
POTENTIAL FERTILIZER
SUPPLY AT 87%
OPERATING RATE
PHOSPHATE FERTILIZER
DEMAND INCLUDING
NET EXPORTS
1974
1975
1976
1977
1978
1979
1980
1981
Figure 3. U.S. phosphate supply - demand outlook.
27
-------
ANALYSIS OF THE POTENTIAL DEMAND FOR ABATEMENT BYPRODUCT
In this study, it was assumed that the H2S04 market can be simulated as
though all consumption occurs at the H2S04 plants and that acid-producing
firms will close these plants and buy abatement acid if it can be delivered
equal to or below their avoidable cost of production. Avoidable cost is an
estimation of the production cost that could be avoided by closing an existing
acid plant assuming abatement byproduct acid would be available in amounts
equal to the plant production capacity (330 days/yr). To develop the required
inputs to the model on the demand side, it was necessary to identify all
potential acid producers and their avoidable costs of production. The acid
plants selected include only those plants that burn elemental S as feedstock
for the production of H2S04.
The sludge acid plants are excluded from the analysis because of their
unique operating procedure. That is, they receive sludge acid or weak acids
which are decomposed to produce pure S02 used as feedstock to an acid plant.
The sludge acid feedstock is usually supplemented with elemental S in order
to efficiently produce a concentrated commercial- grade acid.
Sludge acid plants could use a regenerable product loaded with S02 from
an FGD system by regenerating the absorbent onsite. However, this action
would require considerable modification of the existing acid plant facilities.
It was not included in the study.
THE EXISTING S-BURNING ACID PLANTS IN THE U.S.
TVA's computerized file of worldwide manufacturers of fertilizer and
related products contains a list of 104 plants producing ^804 by burning
elemental S. Total annual production capacity exceeds 35 Mtons. Fourteen of
these plants are located in the 11 Western States with a production capacity
of 3.04 Mtons (3). This group was analyzed separately because of the unique
characteristics of the market in these states coupled with the difficulties
encountered in modeling the transportation rates in the transcontinental
freight zone. This is discussed further in the section dealing with the
marketing of byproduct acid produced by smelters.
The acid plants located in the 37 Eastern States were considered as a
potential market for abatement byproduct acid. This includes 90 S-burning
H2S04 plants with an annual production capacity of 32.237 Mtons based on
330 days' operation/yr. The geographic distribution of these plants by states
is outlined in Figure 4 and Table 11 (14).
29
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SULFUR-BURNING ACID PLANTS
• FRASCH SULFUR
o RECOVERED SULFUR
Figure 4. Geographic distribution of S-burning acid plants (1978).
-------
TABLE 11. U.S. S-BURNING H2S04 PLANT CAPACITY (1978)a
(ktons - 330 days/yr)
State
Alabama
Arkansas
Florida
Georgia
Iowa
Illinois
Indiana
Kansas
Louisiana
Massachusetts
Maryland
Maine
Michigan
Total East
State
California
Colorado
Idaho
New Mexico
Total West
Total Contiguous
Number of plants
4
2
20
3
1
6
1
1
6
1
1
1
2
37 States
Number of plants
6
1
2
1
11 States
States 48
Annual
capacity
342
205
16,189
365
98
985
56
105
4,965
120
350
75
60
Annual
capacity
1,271
55
1,310
141
State
Missouri
Mississippi
North Carolina
New Jersey
New York
Ohio
Oklahoma
Pennsylvania
South Carolina
Tennessee
Texas
Virginia
West Virginia
State
Nevada
Washington
Wyoming
Number of Plants
2
1
6
9
1
5
1
1
1
1
4
8
1
90
Number of plants
1
1
2
14
104
Annual
capaci ty
553
1,220
2,026
1,720
6
665
110
75
42
132
806
832
135
32,237
Annual
capacity
140
15
110
3,042
35,279
a. Projected 1978
31
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THE IMPACT OF ABATEMENT ACID
H2S04 plants are widely scattered throughout the U.S. chiefly because of
the low-bulk value of the acid, difficulties in handling the acid in the bulk,
and subsequent high cost of shipment as compared to handling elemental S.
Therefore, acid has been traditionally produced by S-burning plants in captive
use near the point of consumption. However, many existing plants are old and
will soon need replacing. Some will likely shut down in 1978 because
compliance with pollution control regulations will not be economical. This
group should be receptive to the opportunity to buy abatement acid in lieu of
building a new acid plant.
Many power plants enjoy a unique location advantage for supplying abate-
ment acid in the existing market. This is especially true for acid plants
located in the more remote areas from traditional S supplies. The most orderly
way to incorporate abatement acid would be to replace the capacity of relative-
ly high-cost S-burning H2S04 plants. These are generally remotely located
from S sources. The producer is given the opportunity to close his plant down
and buy abatement acid if it results in a saving. The more efficient plants
would continue to produce.
PRODUCTION COSTS FOR H2S04
The expenses that could be saved or avoided by shutting down existing
acid producers were estimated. Such expenses are delineated below:
Raw material S
Utilities Electric power
Cooling water
Processed water
Boiler-feed water
Operating expenses Labor
Supervision
Capital costs Amortized costs for maintenance of
existing facilities and amortized
costs of new capital investment at
end of useful plant life
In the Phase I study a computer program was developed using these inputs
to calculate contact H2S04 production costs. Details of this program are
given in the report on Phase I. For existing plants, the initial capital
expenditures are handled as a "sunken investment" and, therefore, do not enter
directly into the firm's decision to discontinue present production and buy
abatement ^504. Only avoidable costs are considered in making this decision.
Annual costs are calculated in perpetuity using the discounted cash flow
analysis method. The outlay streams are then amortized or averaged over all
years in the firm's planning horizon. The cost streams are composed of:
32
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1. Constant annual expenditures for S, utilities, and operating expenses
2. Periodic expenditures for new replacement plants
3. Maintenance of existing facilities which is assumed to grow at a
compound rate
The impact of inflation is not included in the analysis. These cost streams
for a new plant are presented in Figure 5.
The optimum useful life is identified as the minimum point on the average
total cost curve. At this point the added capital cost savings that result
from increasing useful life 1 yr equals the added maintenance saving from
shortening useful life 1 yr. The average capital charge of 19.3%, identified
in Figure 5, covers a range from 23-36 yr. Random effects, such as abrupt
physical, economical, technological, or environmental changes, play the
dominant role during this period with regard to the timing of plant replacement
or shutdown.
H2S04 plants built prior to 1960 were assumed to average 95.5% conversion
of S to acid. Plants built between 1960 and 1975 were assumed more efficient
with 97% conversion. These efficiencies, however, are not representative of
plants that must operate after 1975 since emission limitations will require an
efficiency of at least 99.7%. For the potential growth market, it was
necessary to consider tail gas cleanup at a 99.7% efficiency level for new
plants (double absorption). Capital and operating cost estimates for acid
plant tail gas cleaning systems for existing plants are outlined in Appendix F.
These costs, of course, must be added to the avoidable costs of existing plants.
THE DEMAND CURVE FOR ABATEMENT ACID
The avoidable costs (theoretical) are calculated at each respective acid
plant location considered in the study. The major variables used in the acid
plant cost generation program are outlined in Table 12 along with example
values. Costs of manufacture based on data generated here indicate that most
of the acid production costs range from $25-$45 depending on plant location,
size, and age; the March 1976 price for H2S04 (100% H2S04 f.o.b.) was $44.95/ton
(25). Cost estimates projected for each specific acid plant are outlined as
a demand schedule in Appendix G. A summation of capacity of acid plants
versus avoidable cost of production is shown in Figure 6. The resulting plot
defines the demand curve for abatement acid.
The demand curve is estimated by ranking all acid plants from highest to
lowest cost and accumulating demand quantities to show acid cost as a function
of acid plant capacity. At a very high cost of alternative supply only a few
acid producers could justify buying rather than producing t^SO^. These plants
tend to be old, low-volume producers far from S supplies. As supply cost of
abatement acid declines, more acid producers would become potential customers.
At low supply costs all but the largest, most modern acid plants located near
S supplies could be shut down. The important implication for the present study
is that small quantities of abatement acid could be marketed at high value but
as the supply increases the value declines.
33
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20
T
TOTAL"
\
OPTIMAL
USEFUL LIFE
15
o
o
-i
j*
a
o
10
CAPITAL-
MAINTENANCE
o
a:
UJ
o.
I
10
20 30 40
USEFUL LIFE .YEARS
50
60
Figure 5. Amortized value of maintenance and capital
outlays for new I^SO^ plants (assuming 11%
interest and 5% compound maintenance).
34
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TABLE 12. MAJOR PARAMETERS IN MODEL
No.
Description of variable
Example
value
1 Tons of S/ton H2S04 (before 1960) 0.3053
2 Tons of S/ton H2S04 (after 1960) 0.3006
3 Year of technology change 1960
4 H2S04 plant investment ($/ton/yr) 27.285
5 Capacity for this plant (ktons/yr) 247.5
6 Scale factor for determining investment for
other sized plants 0.734054
7 Fixed conversion cost/ton ($/ton) 0.47
8 Fixed annual conversion cost ($/yr) 116.620
9 Taxes and insurance rate 0.015
10 Time preference rate for money 0.11
11 Compound maintenance rate 0.05
12 Economic useful life (yr) 34
13 Percent H2S04 concentration 98
14 Port Sulphur price ($/ton S) 53.57
15 Steam plant H2S04 price ($/ton H2S04) 0
16 Proportion of 330 tons/day capacity estimate 1
17 Number of years considered 1
18 Year considered 1978
19 Unit cost inflation factor over 1973 1.93
20 Transportation cost inflation over 1975 1.15
21 Retrofit cost for compliance 4.41
35
-------
o
H
W
U
PL,
00
80
60
40
20
1
I
1
I
10 15 20 25
CUMULATIVE ANNUAL CAPACITY, MTONS OF 100%
30
35
Figure 6. Abatement byproduct 1^804 demand curve (Eastern States)
-------
ANALYSIS OF THE POTENTIAL SUPPLY OF BYPRODUCT H2S04 FROM SMELTERS
S contained in byproduct acid at Cu, Pb, and Zn smelters amounted to 9%
of the total domestic production of S in all forms in 1976. It represents
the third most important source of S in the S industry as shown in Table 2.
The byproduct acid market is a well-developed market and it has been in
operation a number of years. The recent increases in production outlined in
Tables 5 and 6 are a direct result of the existing environmental regulations
that require more stringent control of emissions.
New source performance standards for H2S04 plants limit the quantity of
S02 that may be emitted to 4 Ib S02/ton of H2S04. Proposed standards for
primary Cu, Zn, and Pb smelters limit the emission concentration of S02 to
<0.065% by vol requiring the removal of approximately 90% of the emitted
S02- Although state regulations for existing t^SO^ plants and smelters are
in most cases less stringent than the NSPS, there are cases where the state
regulation is equal to NSPS.
END USES FOR BYPRODUCT ACID
Approximately 5% of the domestic S consumption is used for leaching of
Cu and U ores with l^SO^. In the Cu industry it is used for the extraction
of the metal occurring in deposits, mine dumps, and wastes when Cu content
is too low to justify concentration with conventional flotation techniques.
It is also used for the recovery of Cu from ores containing Cu carbonate and
silicate minerals that cannot be treated efficiently by flotation processes.
Smelter acid is also used as a reagent for the recovery of U from ores. The
surplus of the byproduct smelter acid goes into the same market identified
in Table 1 for acid produced from elemental S. A number of the captive use
^2^4 plants which closed down in the last decade are presently using by-
product acid from smelters. The most popular end use is for fertilizer
production.
1978 PRODUCTION POTENTIAL
To evaluate the potential production of abatement acid from power plants
in the existing S market, the marketing model must be designed to accommodate
the byproduct acid from smelters. They are already established in the acid
market.
The present technology assumes that the production of byproduct
to control S02 emissions in smelter operations represents the best available
technology. Since the law requires S02 control, the smelter operator is
37
-------
faced with the option of either marketing the surplus acid that cannot be
used in leaching operations or neutralizing the acid to form a waste product
that is acceptable to the environment. This means that a cost equivalent to
the cost of neutralizing the acid could theoretically be invested in marketing
the acid. A discussion including cost estimates for byproduct l^SO^ produc-
tion from smelter gases including estimates of retrofit tail gas cleanup and
limestone neutralization is presented in Appendix H. In the model it is_
assumed that the value of the byproduct acid is zero at the plant site.
Using a 1975 base period, it was assumed that existing S-burning acid
plants and byproduct acid plants operating at smelter locations were operating
at an equilibrium position in the market place. The incremental acid that
is projected to be produced at both existing and new smelter locations in
1978 is assumed to be in direct competition with abatement acid that could be
produced by a steam plant at a given location.
The 14 smelters located in the 11 Western States were analyzed separately
from the 14 smelters in the 37 Eastern States of the U.S. Each smelter that
was identified as being out of compliance by the EPA compliance data system
in September 1976 was assumed to be equipped with control equipment by 1978
that increased capacity by 16% compared to 1975. Plants in compliance were
assumed to increase their capacity factor by 10% in 1978 and new plants are
assumed to operate at 60% capacity (100% = 330 days/yr). The geographic
location of the plants considered in this analysis are outlined in Figure 7.
The 1978 incremental production estimated for the Western States amounted to
849,000 tons I^SO^. The analysis for the smelters located in the Eastern
States amounted to 811,000 tons of acid. This analysis is presented in
Table 13.
The avoidable costs of production were calculated for each of the 14
acid plants located in the 11 Western States. This analysis assumed the use
of recovered S from western Canada at $25/ton f.o.b. Calgary, Alberta, Canada,
delivered by rail to each acid plant considered. The results of these
calculations are presented in graphic form in Figure 8 as a demand curve for
abatement acid for the Western States. The interpretation of this demand
curve is similar to the demand curve presented in Figure 6. Assuming a zero
value for the smelter acid only one smelter location at Hayden, Arizona,
could deliver byproduct acid equal to or below the avoidable cost of produc-
tion at an acid plant located at Helm, California. This accommodated the
marketing of 111,000 tons of byproduct smelter acid in the Western States.
This left a balance of 738,000 tons to be marketed in the Eastern States.
The strategy for marketing the western surplus smelter acid in the
eastern market involves the use of transshipment terminals supplied by unit
trains. Rail rates for unit train shipments are shown in Appendix I. The
value of the acid at the transshipment terminal was assumed to be equal to
the rail rate plus $1.5G/ton terminal handling charge. The terminal locations
selected were: Chicago, Illinois; St. Louis, Missouri; Memphis, Tennessee;
Baton Rouge, Louisiana; and Houston, Texas. Two additional transshipment
terminals were added in the model at Buffalo, New York, and Detroit, Michigan,
in order to analyze the marketing of 200,000 tons of byproduct acid from
smelters in Canada. This concept is presented graphically in Figure 9. The
storage cost analysis is presented in Appendix F.
38
-------
X \
A NONFERROUS SMELTER
Figure 7. Geographic distribution of smelter byproduct acid plants
in 37 Eastern States and 11 Western States.
-------
TABLE 13. INCREMENTAL H2SOA PRODUCTION FOR EASTERN AND WESTERN SMELTERS
1976-1978
Existing
Capacity,
State ktons
Missouri
Tennessee
Pennsylvania
Iowa
Oklahoma
Texas
Ohio
Total
1978 increased
production factor
1978 increased
production
Total 1978 increased
production estimate
Arizona
New Mexico
Montana
Idaho
Utah
Washington
Total
1978 increased
production factor
1978 increased
production
Total 1978 increased
production estimate
760
1,250
579
100
91
286
20
3,086
2,284
780
330
250
600
50
4,294
In
compliance
190
-
-
-
91
160
20
461
0.10
46
2,284
-
-
-
-
-
2,284
0.10
228
Out of
compliance New
90 480
1,250
500 79
100
- -
126
1,840 785
0.16 0.60
294 471
811
200 580
230 100
250
600
50
1,330 680
0.16 0.60
213 408
849
40
-------
-tA>-
500 1000 1500 2000 2500 3000 3500
CUMULATIVE ANNUAL CAPACITY, 1000 TONS 100% H2S04
Figure 8. Abatement byproduct I^SO^ demand curve
(Western States).
41
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• DEMAND POINT
A TRANSSHIPMENT TERMINAL
O ORIGIN OF BYPRODUCT
SMELTER ACID
Figure 9. Geographic distribution of assumed supply and demand for western
and Canadian acid in zero ACFL model run.
-------
In the marketing model, the seven transshipment terminals (listed above)
are handled as simulated smelter-producing locations that can compete in the
market with the 14 eastern smelters and the 187 power plants that are candi-
dates for production of t^SO^. The results of the model runs are presented
in a later section.
43
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S02 EMISSION REGULATIONS AND APPLICATIONS
With the passage of the Clean Air Act Amendments of 1970, EPA was given
the responsibility and authority to regulate and control air pollution in the
U.S. and its territories. Among other responsibilities, the Clean Air Act
required EPA to put into effect National Ambient Air Quality Standards (NAAQS)
for pollutants which adversely affect public health and welfare, including
S02, nitrogen dioxide (N02), particulate matter, carbon monoxide (CO), hydro-
carbons, and photochemical oxidants.
SIP
The Clean Air Act required each state to adopt and submit to EPA an
acceptable plan for attaining, maintaining, and enforcing NAAQS in all regions
of the state. These SIP prescribed emission limiting regulations, timetables
for compliance with the limitations, and measures required to ensure attain-
ment of the standards. Unacceptable plans were returned to the states for
revision or, in some cases, substitute regulations were established by EPA.
While the primary responsibility for enforcing SIP regulations rests with the
individual states, EPA is responsible for assuring that all implementation
plan requirements are fulfilled. As a result, EPA provides technical and
legal assistance to the states in enforcing SIP regulations. If any state
fails to enforce its implementation plan regulations, the Federal Government
may take legal actions against the noncomplying sources.
Following initial approval of most SIP in 1972, many states began
submitting to EPA revisions to their implementation plan, many of which alter
the emission limitations. Usually, these revisions are based on additional
air quality measurement data or on a more detailed technical analysis of air
pollution control strategies. When approved by EPA, these revisions become a
part of the implementation plan.
FEDERAL NSPS
In addition to the SIP limitations, emissions from certain sources are
restricted further by NSPS.
The purpose of these standards is to prevent the occurrences of new air
pollution problems, encourage improvements in emission control technology, and
provide a mechanism for controlling pollutants which EPA suspects are hazardous,
but for which insufficient information is available to regulate under other
provisions of the Act.
45
-------
The standards are applicable to newly constructed facilities, new
equipment additions to existing facilities, and existing equipment which is
modified in such a way that an increase of pollutant emissions occurs. NSPS
is in most cases more stringent than SIP.
TRENDS IN ESTABLISHING SIP
Over the past few years, much attention has been focused on emission
regulations for SOX since these regulations impact the supply of fuel,
particularly coal, which can be burned to produce electrical energy.
While U.S. supplies of coal are plentiful, some of this coal is too high in
S content to be burned in compliance with State and Federal regulations for
S02 without the use of emission reduction systems, which, in some cases, are
either costly or impractical. As a result, many states have been reevaluating
their S02 regulations to ensure that scarce low-S fuels are being required
only in areas where they are needed to protect public health. In some cases,
states have revised their S emission regulations to allow the burning of higher
S fuels in less polluted areas where they can be burned without violating
ambient air quality standards.
EMISSION CONTROL REGULATIONS FOR FOSSIL-FIRED POWER GENERATORS
Units of the Regulation
NSPS contains distinct regulations which limit the emission of particu-
lates and S02 from individual fossil-fired boilers as shown below:
Allowable emission,
Ib/MBtu heat input
Coal-fired unit Oil-fired unit
Particulate matter 0.1 0.1
S02 1.2 0.8
This regulation is applicable to boilers for which construction or
modification was begun after August 17, 1971.
In contrast to NSPS regulations, there are variations in (1) the units of
measure in which SIP regulations for existing plants are expressed, (2) the
equipment (boiler, stack, or entire plant) to which the regulations apply, and
(3) the value of the regulation. Table 14 shows the units in which SIP
regulations are expressed.
Some states control all emission sources equally, while other states
prescribe different emission limits for sources according to the fuel used,
the geographic location, the size of the source, or the type of source (e.g.,
power plant or other combustion units).
46
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TABLE 14. UNITS FOR EXPRESSING STATE S02 EMISSION REGULATIONS (26)
1. % S for all fuels
2. % S for each fuel
3. Lb S02/MBtu for all fuels
4. Lb S02/MBtu for each fuel
5. Lb S/MBtu for all fuels
6. Lb S/MBtu for each fuel
7. Ppm S02 in exhaust gas
8. Impact on ambient air quality in ppm
9. Lb S02/hr
The most common regulation for controlling S02 emissions is by either
limiting the amount of S or S02 emitted per unit heat input (Ib S/MBtu, Ib
S02/MBtu) or limiting the S content of the fuel (% S). However, other S02
regulations limit S02 emission concentrations expressed as parts of SC>2 per
million parts of volume of stack gas (ppm SC^) or limit the amount of S02
emitted per hour (Ib S02/hr). Some states or regions specify ambient air
quality regulations only (i.e., no specific emission limit for a source).
Other methods of limiting S02 emissions which appear in the SIP include re-
quiring a percent control of input S (% control) and requiring applica-
tion of "latest reasonably available control technology" or "new proven
technologies."
Some of the above-mentioned methods for regulating SC>2 control the
emissions of SOX more directly than do others, and each method has different
implications regarding fuels that can be legally burned.
A detailed discussion of the effect of different applications of the SIP
regulations on degree of S02 removal is included in State Implementation
Plan Emission Regulations for Sulfur Oxides; Fuel Combustion (EPA-450/2-76-
002, March 1976)(267!~
Application of the Regulations
Besides the various units of measure used regulations also vary as to the
equipment upon which the emission limit is enforced. Twenty-five states or
territories enforce their regulations on a boiler basis, 13 on a stack basis,
and 18 on a total plant basis (all boilers collectively). In considering
compliance with a regulation, this information determines whether a source is
allowed to average its emission over all boilers (or stacks) or if each
boiler (or stack) must comply with the regulation.
About one-third of the states regulate specific fuel types. These
regulations usually control oil-fired sources more strictly than coal-fired
sources since, in general, oil contains less S and has a higher heat content
than does coal. But, in some cases, the S restriction for coal is more
stringent than the restriction for oil to prohibit the use of coal without
flue gas cleaning equipment.
47
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About half of the states have specific S02 regulations for various
geographic areas within the state. These geographic areas might be specified
as cities, counties, Federal Air Quality Control Regions (AQCR), Standard
Metropolitan Statistical Areas (SMSA), or some locally defined geographic
region. In some areas, including Arizona, New Mexico, and Puerto Rico,
regulations have been promulgated which apply to specific plants.
In about one-third of the states, the size of the source determines
whether or not the source must comply with an S02 emission limitation and if
so, the stringency of the limitation. In most cases, source size is defined
by the heat input rate measured in MBtu/hr. Other methods of defining source
size include Ib steam/hr generated and emission potential in tons S02/yr
emitted. In some states, emission limit is determined by the heat input range
under which a source falls. In these states, larger sources usually are
controlled more stringently than smaller sources.
Over half of the states use more than one of the parameters discussed
above in their regulations. In addition, about 35% of the states have
separate regulations for new sources and about 10% have regulations for
existing sources that become more stringent over time.
In a few states, the limits on emissions or fuel quality are specified as
maximum values averaged over a given time period. Most regulations, however,
state that emissions or S content shall not exceed a maximum value. This
phraseology implies that instantaneous compliance with the limit is required.
EMISSION COMPLIANCE ALTERNATIVES
Several methods for reducing S02 emissions for compliance with State or
Federal emission regulations are considered in this study. Alternative
strategies considered for power plants include:
Use of low-S coal
Limestone scrubbing with ponding of sludge
Magnesia (MgO) scrubbing with H2S04 production
It is assumed that H2S04 plants and smelters which are out of compliance
will reduce their emission by producing
The major objectives of this study are to determine the potential for
production of byproduct H2S04, in meeting S02 emission regulations and the
impact of their recovery and sale on S-I^SO^ industry supply-distribution
characteristics. In all cases, the S02 control strategy is selected on the
basis of minimum costs for compliance.
48
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CHARACTERISTICS OF THE POWER UTILITY INDUSTRY
In the power industry, either fossil or nuclear fuel is supplied to a
boiler and the heat energy of the fuel is used to generate steam. The steam
generated in the boilers is fed to steam turbines which drive generators for
producing electricity. Fossil fuel is a general term which refers to either
coal, oil, or natural gas. Most coal and oil contain S that is emitted as
S02 in the stack gas when the fuel is burned. Natural gas may contain some
S, but in relatively small amounts. Nuclear fuels do not contain S and are
not consumed in the same manner as fossil fuels; therefore, their use does
not result in the emission of S02- In presenting characteristics of the power
industry below, emphasis is placed on fossil-fired plants which use coal, oil,
or natural gas to generate steam.
Detailed information related to the characteristics of the steam-
electric utility industry is found in Steam-Electric Plant Construction Cost
and Annual Production Expenses (FPC S-250) (27) and Steam-Electric Plant
Air and Water Quality Control Data (FPC S-253) (2). Key information given
in these publications is included below to characterize the utility industry.
FOSSIL FUELS
During the decade prior to 1967, approximately 66% of the total annual
fossil-fueled power generation was by coal, about 26% by natural gas, and
the remaining 8% by residual oil. During the second half of the past decade,
when restrictions on the importation of residual oil were removed on the
east coast, foreign residual oil began to compete favorably with other fuels.
Electric utilities, particularly those near deepwater ports, started to
convert from coal to oil and to build new oil-fired units. This process was
accelerated with the setting forth of strict S02 emission control regulations.
With the growing shortage in the supply of natural gas, the use of desulfu-
rized or naturally low-S oil offered the most viable solution to the S02
pollution problem along the entire east coast.
A large proportion of the oil used by electric utilities, particularly
along the eastern seaboard, is of foreign origin. In the 1965-72 period,
approximately 398 coal-fired generating units were converted to the use of
oil. Economic considerations dictated the conversions initially. More
recently, however, the paramount reason for converting to oil has been the
requirement to meet strict S emission regulations which the utilities were
unable to do using coal. Most of the conversions took place on the east
coast at plants with easy access to ocean and river barge transport of lower
priced, desulfurized, or naturally low-S imported residual oil. The Arab
49
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oil embargo in late 1973 was instrumental in effecting arbitrary and sudden
huge price increases in the world price of oil. In a relatively short period
of time, the economic advantage of using imported oil versus coal as a fuel
for electric power generation reversed. In early 1974 a number of utilities
on the east coast reported 42 oil-burning plants of their systems capacities
as having capability of conversion from oil to coal. A few of these plants
have been converted to coal, with conversion by the others contingent upon
coal availability. Due to current uncertainties in the long-range oil supply
picture, and the increasing amounts of nuclear generation becoming available
to electric utilities, oil's role in electric generation will probably decline
in the future.
Historical Consumption and Characteristics
The historical consumption pattern of coal, natural gas, and oil in the
U.S. from 1969 through 1973 based on FPC Form 67 data is shown in Table 15.
Historical characteristics of coal, oil, and gas for the corresponding period
are given in Table 16. The data indicate that the average heating value of
coal, fuel oil, and gas has declined slightly during this period. The data
also show a slight decline in the average S content of coal and a significant
decline in the average S content of oil. The lower heating values of coal
and fuel oil appear to be at the expense of using fuels with lower S contents.
The average ash content of coal during the same period increased from approxi-
mately 12.5 to 13.3%.
TABLE 15. CONSUMPTION PATTERN OF FOSSIL FUELS
IN THE U.S., 1969-73 (2)
Total Btu, 10
15
of total Btu
Year
Coal
Oil
Gas
Total Coal Oil
Gas
1969
1970
1971
1972
1973
7.065
7.098
7.244
7.794
8.583
1.577
2.008
2.328
2.816
3.270
3.429
3.820
3.841
3.811
3.517
12.071
12.926
13.413
14.421
15.370
58.5
54.9
54.0
53.9
55.8
13.1
15.5
17.4
19.6
21.3
28.4
29.6
28.6
26.5
22.9
50
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TABLE 16. HISTORICAL FOSSIL FUEL CHARACTERISTICS FOR THE PERIOD 1969-73 (2)
Year
1969 1970 1971 1972 1973
Coal
Average heating value,
Btu/lb 11,628 11,276 11,169 11,176 11,090
Average S content, % by wt 2.59 2.58 2.47 2.39 2.32
Equivalent S02 content,
Ib S02/MBtu 4.46 4.58 4.42 4.28 4.27
Average ash content, % by wt 12.53 13.72 13.85 13.41 13.29
Fuel Oil
Average heating value,
Btu/gal 148,727 147,991 147,017 146,285 145,772
Average S content, % by wt 1.68 1.52 1.28 1.07 0.98
Equivalent S02 content,
Ib S02/MBtu 1.80 1.64 1.40 1.18 1.08
Gas
Average heating value,
Btu/ft3 1,033 1,031 1,030 1,028 1,028
Projected 1978 Consumption and Characteristics
In 1973 utilities were also requested by FPC to project fuel consumption
and characteristics for 1978. The majority of utilities provided FPC with
these projections. For the utilities which did not^project this information,
fuel consumption and characteristics were assumed to be the same as that
reported for 1973. Based on the updated projections, Table 17 shows the con-
sumption rates and characteristics of fossil fuels projected to be utilized
during 1978. For plants which use multiple fuels and did not project their
1978 consumption, the method for projecting fuel is discussed in Appendix J.
A comparison of the total projected 1978 coal, fuel oil, and gas con-
sumption with the historical 1973 fuel consumption by region is shown in
Table 18. Figure 10 shows the overall trend in fossil fuel consumption from
1969 through 1978. The projections indicate a general increase in the con-
sumption of coal and oil, but a slight decrease in the consumption of gas.
The regional increases or decreases are primarily influenced by fuel avail-
ability and price. In reviewing the data, it must be remembered that a
significant amount of new generating capacity between 1973 and 1978 is from
nuclear units. The data shown include the effect of projected decreases in
fossil fuel utilization as a result of new nuclear units coming online as well
as changes in fossil fuel consumption resulting from decreases in fuel avail-
ability or increases in cost.
51
-------
16.0
14.0
12.0
TOTAL,
in
O 10.0
x
t/i
= 8.0
CD
COAL
6.0
4.0
GAS
2.0
OIL
I
I
1969 1970
I97i
YEAR
1972 1973 1978
Figure 10. Trends in the consumption of coal,
oil, and gas from 1969-78.
52
-------
TABLE 17. PROJECTED 1978 FOSSIL FUEL CONSUMPTION RATES AND CHARACTERISTICS
All plants
Plants out
of compliance
Coal
Total consumption
ktons
GBtu
Heating value, Btu/lb
S content, % by wt
Equivalent S02 content, Ib S02/MBtu
Oil
Total consumption
kbbl
GBtu
Heating value, Btu/gal
S content, % by wt
Equivalent S02 content, Ib S02/MBtu
Gas
Total consumption
Mft3
GBtu
Heating value, Btu/ft3
475,570
10,408,290
10,943
2.12
3.87
620,247
3,827,427
146,924
0.99
1.08
2,556,021
2,602,232
1,018
226,780
5,125,075
11,300
2.81
4.97
110,167
686,900
148,454
1.42
1.54
108,239
116,968
1,081
POWER PLANT CHARACTERISTICS
Plant Location
The location of major coal-, oil-, and gas-fired power plants based on
1973 FPC data is shown in Figures 11 through 13 respectively. Figure 14
shows the location of plants which use multiple fuel mixes for the same
period. The data show coal-fired plants to be scattered from the east to
the west coast. The highest concentration of coal-fired plants is in the
Midwest. Oil-fired power plants are most predominant along the east and west
coasts and the lower Mississippi Valley; however, they are also found at
other scattered locations in the Midwestern States. Gas-fired plants are
predominant near the Louisiana and Texas Gulf Coast and adjacent states, but
like oil-fired plants, are also found at other locations. At the end of 1973,
plants with facilities for using multiple fuels were widely scattered.
Plant Size
Historical data for conventional fossil-fueled steam-electric generating
plants for the total power industry are shown in Table 19. An analysis of
these data indicates that total fossil-fueled power generation has generally
doubled every 10 yr. New plants are constructed to (1) provide additional
capacity for the increasing electrical demand and (2) provide replacement
capacity for older less-efficient plants which are being retired. The total
53
-------
TABLE 18. COMPARISON OF PROJECTED 1978 REGIONAL FOSSIL
FUEL CONSUMPTION WITH HISTORICAL 1973 CONSUMPTION
Geographic Coal, Oil, Gas,
regiona ktons kbbl Mft3
Historical 1973 consumption (2)
New England 1,080 82,930 6,070
Middle Atlantic 44,990 144,690 64,730
East North Central 135,960 23,340 105,590
West North Central 31,620 3,440 352,820
South Atlantic 75,860 141,380 202,660
East South Central 63,060 6,510 73,750
West South Central 4,730 20,850 1,957,070
Mountain 23,930 8,990 207,630
Pacific 3,740 76,970 451,220
U.S. total 386,970 509,100 3,421,540
Projected 1978 consumption
U.S. total 475,570 620,250 2,556,020
a. The states included in each geographic region are:
New England - Connecticut, Maine, Massachusetts, New
Hampshire, Rhode Island, Vermont; Middle Atlantic -
New Jersey, New York, Pennsylvania; East North Central -
Illinois, Indiana, Michigan, Ohio, Wisconsin; West
North Central - Iowa, Kansas, Minnesota, Missouri,
Nebraska, North Dakota, South Dakota; South Atlantic -
Delaware, District of Columbia, Florida, Georgia,
Maryland, North Carolina, South Carolina, Virginia,
West Virginia; East South Central - Alabama, Kentucky,
Mississippi, Tennessee; West South Central - Arkansas,
Louisiana, Oklahoma, Texas; Mountain - Arizona,
Colorado, Idaho, Montana, Nevada, New Mexico, Utah,
Wyoming; Pacific - California, Oregon, Washington.
b. Regional consumption data not available.
54
-------
Ul
Ul
• Coal users
Figure 11. Location of coal-fired steam-electric power plants (1978)
-------
D Oil users
Figure 12. Location of oil-fired steam-electric power plants (1978)
-------
Gas users
Figure 13. Location of gas-fired steam-electric power plants (1978).
-------
00
Combination users
Figure 14. Location of steam-electric power plants capable of
utilizing a combination of fossil fuels.
-------
installed steam-electric generating capacity from fossil-fueled plants
increased from 26,000 MW in 1938 to over 318,000 MW in 1973. During the same
period, average plant size in megawatts increased from 22 to 322. The total
number of plants varies annually as new plants are built and old plants are
retired. At the end of 1973, there were 219 fossil-fueled plants 500 MW in
size or larger.
TABLE 19. CONVENTIONAL FOSSIL-FUELED STEAM-ELECTRIC GENERATING
PLANTS, TOTAL AND AVERAGE CAPACITIES, NET GENERATION AND CAPACITY FACTORS
FOR THE TOTAL POWER INDUSTRY, 1938-73a'b (27)
1938 1947 1957 1967 1971 1972 1973
Number of
plants 1,165 1,045 1,039 971 985 979 988
Installed
capacity, MW 26,066 36,035 99,500 210,237 275,593 294,049 318,357
Average plant
size, MW 22 35 96 217 280 300 322
Net generation,
GkWh 68.4 174.5 497.2 974.1 1,282.2 1,378.3 1,459.2
Approximate
average annual
plant factor, % 35 55 57 53 53 54 52
*
a. Excludes Puerto Rico.
b. Excludes nuclear, geothermal, gas turbine, and internal combustion plants.
Most power plants consist of a number of separate units which are capable
of producing power independently of the other units within the plant. Each
unit generally includes a separate boiler for generating steam, a separate
turbine and generator for producing electricity, and separate flue gas han-
dling facilities. Although some plants have common flue gas stacks for
multiple boilers, most boilers are designed with separate stacks. Modular
units allow for servicing and maintenance without significantly affecting the
output of the overall plant and allows for the addition of new generating
capacity without intefering with the operation of the existing facilities.
A diagram showing the general layout of a plant, including facilities
for S02 control, is shown in Figure 15. This diagram illustrates the relation-
ships between plant, boilers, and stacks, and facilities for controlling S02
emissions.
59
-------
ON
O
« f
• '
cQ*±jv
UNIT 4
BOILER
1 1 1 1 r
*
L P. STEAM
i UNIT
BOILER
GO&-
UNIT 2
^ rFMrrfATHR TIIRPIMT — E- AM
i
L.P. STEAM
*
L P STEAM
ST£
*
L.P STEAM
:AM
GO^
AM
BOILER
UNIT 1
BOILER
co&
COAL
fc /A?R\
^^PREHEAT
_ /ATfiN _,
^^PREHEAT
fh\R\
PREHEAT
_^/^TRN_
PREHEAT
^./A?R\_
PREHEAT
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PREHEAT
, /A?R\
PREHEAT
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PREHEAT
-*
— »
-»
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-*
i
-»
ESP
PP
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ESP
ESP
ESP
ESP
PP
FAN
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PP
FAN
PP
FAN
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GAS ' ' *"
S
FAN
V
^GAS TO STACKX"
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s
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GAS TO /^
STACK V
S.
FAN
SCRUBBER
t
~l
SCRUBBER!— •»•
t
SCRUBBER
1
SCRUBBER
1
SCRUBBER
t
SCRUBBER
t
SCRUBBER
1
c ppi
—+
»
JBBERJ — *
SULFUR,
SCRUBBER, SUALrF,UDRIC
SLURRY OR WASTE
DISPOSAL
FACILITIES
BYPRODUCT
RAW MATERIAL
FACILITIES
Figure 15. General layout of a power plant designed with an FGD system.
-------
BOILER CHARACTERISTICS
Boiler Size
As an illustration of the size relationship between plants and boilers,
Table 20 identifies the total plant size in megawatts and the number of
separate units for the 15 largest steam-electric plants in the U.S. based on
1973 FPC data. These plants range in size from 1872-2933 MW. For comparison,
individual boiler sizes at these plants range from 69-1300 MW.
TABLE 20. FIFTEEN LARGEST STEAM-ELECTRIC PLANTS IN THE
U.S. IN 1973a (27)
Plant name
MW
Unit
Utility
Amos
Paradise
Labadie
Monroe
Sammis
Robinson, P.H.
Four Corners
Moss Landing
Alamitos
Pittsburg
Marshall
Widows Creek
Nine Mile
Point
St. Clair
Keystone
a. Coal-fired
2,933
2,558
2,482
2,462
2,456
2,315
2,270
2,175
2,121
2,029
2,000
1,978
1,917
1,905
1,872
except as
3
3
4
3
7
4
5
7
6
7
4
8
5
7
2
noted,
b . Based on maximum generator
Appalachian Power Company
Tennessee Valley Authority
Union Electric Company
Detroit Edison Company
Ohio Edison Company
Houston Lighting and Power
Company
Arizona Public Service
Company
Pacific Gas and Electric
Company
Southern California Edison
Company
Pacific Gas and Electric
Company
Duke Power Company
Tennessee Valley Authority
Louisiana Power and Light
Company
Detroit Edison Company
Pennsylvania Power and
Light Company
ratings.
61
-------
The average size of larger boilers (>300 MW) placed in service has gener-
ally increased over the years. Table 21 shows the number of units, corres-
ponding total megawatts, and the average unit size in megawatts for units
placed in service during the period 1959-73.
TABLE 21. TRENDS IN BOILER SIZE, 1959-73 (27)
Fossil-fueled units, 300 MW and larger
No. units
placed in Total Average unit
Year service MW size, MW
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
5
8
9
7
10
10
17
20a
26
22
26
25
29
32
35
1,800
2,525
3,180
2,525
4,500
3,625
7,740
8,424
13,245
12,274
14,249
14,413
17,575
18,753
21,843
360
317
353
361
450
362
455
421
509
558
548
577
606
586
624
Total 281
146,671
522
a.
Seven of these units were actually
installed in prior years and were
rerated in 1966.
For comparison with the size ranges given above, the average boiler size
considering all boilers projected to be operational in 1978 is' 122 MW and the
average boiler size for plants which are projected to be out of compliance
in 1978 is 159 MW. In contrast, the largest commercial boilers presently in
operation or under construction are 1300-MW units.
62
-------
Boiler Capacity Factors
The data given in Table 19 indicate that average annual capacity factors
for power plants ranged from approximately 52-57% of rated capacity for the
period 1947-73. In contrast, however, capacity factors for individual boilers
within a plant vary considerably. As new units are added, load factors for
the older units are generally decreased and the newer, more efficient units
are operated at higher capacity factors. However, delays in construction of
new generating capacity often require older plants to operate at higher than
normal capacity factors. Based on historical FPC data for 1969-73, the
average annual capacity factors for all boilers as a function of boiler age
were determined and are shown in Figure 16. The data indicate a gradual
increase in capacity factors from approximately 50 to 65% during the first
10 yr of operation followed by a relatively constant profile for approxi-
mately 5-7 yr and a gradually declining operating profile over the remaining
life of the plant. Boilers >20 yr old generally operate at annual capacity
factors <50%. A breakdown of the projected 1978 distribution of all boilers
by age and capacity factor is shown in Table 22. Table 23 shows the distri-
bution for these boilers projected to be out of compliance.
TABLE 22. DISTRIBUTION OF BOILERS BY AGE AND CAPACITY FACTOR - ALL BOILERS
Number of boilers and (% of total number of boilers)
Boiler capacity factor
Boiler
age, yr
0-5
6-10
11-15
16-30
>30
Total
28
30
20
265
1,009
1,352
<20%
( 0.8%)
( 0.9%)
( 0.6%)
( 7.9%)
(29.8%)
(40.0%)
20-40%
26
34
45
410
154
669
( 0.8%)
( 1.0%)
( 1.3%)
(12.1%)
( 4.6%)
(19.8%)
41-60%
84
92
73
465
61
775
( 2
( 2
( 2
(13
( 1
(22
.5%)
.7%)
.2%)
.7%)
.8%)
.9%)
40
127
120
274
25
586
>60%
( 1.2%)
( 3.8%)
( 3.5%)
( 8.1%)
( 0.7%)
(17.3%)
Total
178
283
258
1,414
1,249
3,382
( 5.3%)
( 8.4%)
( 7.6%)
(41.8%)
(36.9%)
( 100%)
Boiler capacity factors also vary as a function of boiler size. Larger
boilers are often operated as base load plants while the older, generally
smaller and less-efficient boilers are operated to provide peaking capacity.
Table 24 shows a breakdown of the projected 1978 distribution of all boilers
by size and capacity factor. Table 25 shows the distribution for these
boilers projected to be out of compliance.
Capacity factors are also a function of fuel type; however, plant design
is the primary consideration which affects the consumption-distribution
pattern. For plants which are capable of burning alternate fuels, the utili-
zation trend changes as a function of fuel availability and costs.
63
X
-------
80
ALL BOILERS AVERAGE CAPACITY FACTOR vs. BOILER AGE-
BASED ON 1969-1973 FPC DATA
50+I.5A 65 92-
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0 10 20 30 40 50 60 7
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tr
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20
BOILER AGE-YEARS
Figure 16. Average boiler capacity factors as a function
of boiler age.
64
-------
TABLE 23. DISTRIBUTION OF BOILERS BY AGE AND CAPACITY FACTOR -
BOILERS OUT OF COMPLIANCE
Boiler
age, yr
0-5
6-10
11-15
16-30
>30
Total
Number
of boilers and (% of total number of boilers)
Boiler capacity factor
5
9
4
56
216
290
<20%
( 0.6%)
( 1.1%)
( 0.5%)
( 6.7%)
(25.9%)
(34.8%)
20-40%
8
5
5
90
38
146
( 1.0%)
( 0.6%)
( 0.6%)
(10.8%)
( 4.6%)
(17.6%)
41-60%
49
26
16
135
13
239
( 5
( 3
( 1
(16
( 1
(28
.9%)
.1%)
.9%)
.2%)
.6%)
.7%)
19
45
26
66
2
158
>60%
( 2.3%)
( 5.4%)
( 3.1%)
( 7.9%)
( 0.2%)
(18.9%)
Total
81
85
51
347
269
833
( 9.8%)
(10.2%)
( 6.1%)
(41.6%)
(32.3%)
( 100%)
TABLE 24. DISTRIBUTION OF BOILERS BY SIZE AND CAPACITY FACTOR -
ALL BOILERS
Boiler
size, MW
Number of boilers and (% of total number of boilers)
Boiler capacity factor
<20%
20-40%
41-60%
>60%
Total
<200
200-500
501-1000
>1000
1,270 (37.6%)
53 ( 1.6%)
29 ( 0.8%)
0 ( 0.0%)
601 (17.8%)
45 ( 1.3%)
21 ( 0.6%)
2 ( 0.1%)
510 (15.1%)
180 ( 5.3%)
79 ( 2.3%)
6 ( 0.2%)
390 (11.5%)
120 ( 3.5%)
76 ( 2.3%)
0 ( 0.0%)
2,771 (82.0%)
398 (11.7%)
205 ( 6.1%)
8 ( 0.2%)
Total 1,352 (40.0%) 669 (19.8%) 775 (22.9%) 586 (17.3%) 3,382 ( 100%)
65
-------
TABLE 25. DISTRIBUTION OF BOILERS BY SIZE AND CAPACITY FACTOR -
BOILERS OUT OF COMPLIANCE
Boiler
size, MW
Number of boilers and (% of total number of boilers)
Boiler capacity factor
<20%
20-40%
41-60%
>60%
Total
<200
200-500
501-1000
>1000
283 (34.0%)
7 ( 0.8%)
0 ( 0.0%)
0 ( 0.0%)
129 (15.5%)
12 ( 1.4%)
5 ( 0.6%)
0 ( 0.0%)
129 (15.5%)
69 ( 8.3%)
36 ( 4.3%)
5 ( 0.6%)
87 (10.4%)
38 ( 4.6%)
33 ( 4.0%)
0 ( 0.0%)
628 (75.4%)
126 (15.1%)
74 ( 8.9%)
5 ( 0.6%)
Total 290 (34.8%) 146 (17.5%) 239 (28.7%) 158 (19.0%) 833 ( 100%)
Boiler Heat Rates
Because heating values of fossil fuels vary over a wide range, the thermal
efficiency of fossil fuel steam-electric power plants is generally expressed
in terms of heat rate. Heat rate is defined as the'total Btu of heat required
to generate 1 kWh of electricity for delivery to the transmission system.
These data are reported annually to FPC at the utility, plant, and boiler level.
Table 26 shows historical national average heat rates for fossil-fueled power
plants from 1938-73. This table also shows the thermal efficiency for con-
verting heat energy into electricity, which is calculated by dividing the
thermal equivalent of 1 kWh (3413 Btu) by the heat rate. As shown, national
average heat rates have declined from a high of 16,500 Btu/kWh in 1938 to about
10,400 Btu/kWh in 1972-73.
According to the FPC data, there were 14 units in 1973 with heat rates of
<9000 Btu/kWh compared with 18 units in 1972. The most efficient single unit
had a heat rate of 8714 Btu/kWh in 1973. Corresponding to 1973, there was a
total of 41 plants with overall heat rates of <9,500 Btu/kWh, and 124 plants
with heat rates under 10,000 Btu/kWh. These totals account for 19 and 45% of
the total electrical generation respectively. The most efficient single plant
had an average heat rate of 8818 Btu/kWh. Based on projections to 1978, plant
heat rates range from 8,818 to >30,000 Btu/kWh.
The most efficient heat rate at the company level was reported as 9524
Btu/kWh. In 1973 there was a total of 16 utilities with heat rates <10,000
Btu/kWh.
66
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TABLE 26. NATIONAL AVERAGE HEAT RATES FOR FOSSIL-FUELED STEAM-
ELECTRIC PLANTS - TOTAL ELECTRIC POWER INDUSTRY, 1938-73 (27)
Year
1938
1948
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
Btu/net
kWh
16,500
15,738
13,361
12,889
12,180
11,699
11,456
11,365
11,085
10,970
10,760
10,650
Thermal
efficiency,3
%
20.68
21.69
25.54
26.48
28.02
29.17
29.79
30.03
30.79
31.11
31.72
32.05
Year
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
Btu/net
kWh
10,558
10,482
10,462
10,453
10,415
10,432
10,398
10,447
10,494
10,478
10,379
10,389
Thermal
efficiency,3
%
32.33
32.56
32.62
32.65
32.77
32.72
32.82
32.67
32.52
32.57
32.88
32.85
a. Based on 3,413 Btu as the energy equivalent of 1 kWh.
67
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SCRUBBING COST GENERATOR
Each utility is required by law to report annually plant, boiler, and
fuel characteristics for their steam-electric generators on FPC Form 67. A
file containing FPC Form 67 data for the period 1969-73 was supplied to TVA
along with utility projections, where available, of similar data for 1978 for
use in the byproduct marketing study. The data were primarily for use in
projecting S02 emissions at power plants for determining the compliance status
of power plants with State and Federal S0£ emission regulations and the market
potential for S and 8(2804 abatement production at plants which are out of
compliance.
TVA developed a procedure for using the Form 67 data in conjunction with
applicable S02 emission regulations to (1) project the compliance status of
individual plants and the quantity of S which must be recovered to meet SC>2
emission regulations for those plants out of compliance, (2) estimate costs
for removing the required amount of S02 from the gas to meet compliance
requirements by three alternative scrubbing processes, and (3) compare the
costs for scrubbing including credit from sale of byproducts with alternative
costs for complying with the regulation by the use of low-S coal. The overall
comparison is used to assist in selecting the minimum cost compliance alter-
native. Discussions of the data required for input to the scrubbing cost
generator and the method for developing the model are given below.
PROCEDURE FOR UTILIZING FPC DATA TO ESTIMATE COMPLIANCE STATUS
FPC Form 67 Data Projections
The projected 1978 FPC Form 67 data which serve as input to both the SC>2
emission and compliance model and the scrubber cost generator include a number
of key data items which were reported to FPC at the plant level only. In the
compliance tests and the scrubber cost generator the majority of the calcula-
tions are begun at the boiler level; therefore, it was necessary to project
much of the plant level data to the boiler level for input to these models.
Plant level data available from either 1978 projections or historical 1969-73
data updated with more current information from FPC include plant capacity in
megawatts, overall projected plant capacity factor, fuel consumption breakdown
as coal, oil, and gas, plant heat rate in Btu/kWh, heating values of coal, oil,
and gas, and S contents of coal and oil. At the boiler level, the following
data are available from similar sources: boiler startup year, boiler capacity
in megawatts, and design combustion air rates to the boiler at full load
expressed in sft3/min. Fuel is allocated from the plant level to the boiler
level from either utility projections for 1978 or historical 1969-73 consump-
tion. For the cases in which utilities projected plant level data, the data
69
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were generally used as projected. For the other cases where historical plant
data were used projections at the boiler level were adjusted in accordance
with the historical boiler age-capacity factor relationship which was described
earlier. In all cases, data projections and adjustments at the boiler level
are allowed to override the plant level data. Details of the methods for
allocating fuel from the plant to the boiler level may be found in Appendix J.
The projections of fuel consumptions are reported in terms of GBtu/yr for each
fuel at each boiler for convenience in comparing the relative fuel distribution,
and individual boiler capacity factors (annual) are calculated.
Since individual boiler heat rates are not included in the FPC data file,
the overall plant heat rates were assumed to be applicable for each boiler in
the plant. Reported air rates to the boiler are compared with calculated air
rates as a check of the data file. If reported air rates differ from calcu-
lated rates by >25%, calculated air rates are allowed to override the reported
rates.
The FPC data file is used by the compliance test model to project SC>2
emissions for each boiler and plant for comparison with allowable emissions.
The compliance test procedure is discussed below.
Compliance Test
The S02 emission and compliance model uses the projected annual fuel
consumption and characteristics data to calculate the annual quantity of S
which is emitted for each boiler and plant. For each plant, allowable
emissions are calculated based on NSPS for new boilers or the applicable SIP
in effect for AQCR in which the plant is located for existing boilers in
conjunction with the heating value and S content of the fuel. Excess emissions
expressed as tons S which must be removed per year are then estimated as the
difference between the calculated and allowable emissions. In the test for
compliance, the plant is considered to be in compliance with the regulation if
actual emissions are less than allowable emissions, or do not exceed allowable
emissions by >10%. This allowance factor is applied to adjust for round off
differences in converting SIP from the various units of expression to the
equivalent single unit of expression (Ib S02/MBtu) for simplification in
testing for compliance.
The compliance procedure tests the level of application of the SIP to
determine the procedure for complying with the regulation. Levels of appli-
cation are specified as either (1) an entire plant, (2) an individual boiler,
or (3) an individual stack. In all cases where scrubbers are required, they
are assumed to be designed for an SC>2 removal efficiency of 90%. However, the
actual performance level needs to be more clearly defined in sustained full-
scale operation when high-S coal is burned. The 90% level results in over-
compliance for many plants, particularly those which have SIP which apply at
the boiler level.
Compliance Procedure for Meeting Plant Level SIP
When the regulation applies to an entire plant, the model determines the
number of boilers which must be scrubbed, ordered from lowest to highest cost,
to reduce overall plant emission to comply with the regulation. The FPC data
70
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for these plants and specific boilers are used as input to the scrubbing cost
generator for projecting costs.
Compliance Procedure for Meeting Boiler Level SIP—
When SIP are applied at the boiler level, the compliance test procedure
determines compliance status for individual boilers similar to the method for
determining compliance status at the plant level and specifies the boilers
which exceed allowable emissions. The FPC data for these plants and specific
boilers are then used as input to the scrubbing cost generator and for projecting
costs similar to the plant level SIP compliance procedure. A hypothetical
example is given below to illustrate the difference in SC>2 emission reductions
when the two procedures are applied to the same plant. Assume that a plant
made up of four equal-size boilers operating at equal capacity factors has a
total annual S emission rate of 120,000 tons/yr and an allowable emission of
60,000 tons/yr. Excess emissions for this plant calculated by difference are
equal to 60,000 tons/yr. The total S emission rate per boiler is about
30,000 tons/yr. If scrubbers capable of removing 90% of the S to the boiler
were installed on each boiler, the net reduction in emissions for each boiler
would be 0.90 x 30,000 or 27,000 tons/yr. If the S02 emission regulation was
a plant level regulation, the reduction in emissions could be achieved by
installing scrubbers on three of the four boilers. (Excess emissions = 60,000
tons/yr; reduction in emissions for three boilers = 3 x 27,000 or 81,000 tons/
yr, which is greater than the quantity of excess emissions.) If the same
hypothetical plant had boiler level rather than plant level SIP, the fourth
boiler would not be in compliance, even though the total emissions for the
plant were less than the allowable emissions. Therefore, all four boilers
would require scrubbers if the regulation was on a boiler basis.
Compliance Procedure for Meeting Stack Level SIP—
Power plants are designed with a wide variety of boiler-stack config-
urations. Therefore, the application of stack level regulations has different
implications as far as the procedure for complying with the regulation. If,
for example, the plant is designed with multiple boilers, but with a single
stack, the procedure for meeting the regulation is similar to the procedure
for complying with plant level regulations. If the plant is designed with
separate stacks for each individual boiler, the procedure for meeting the
regulations is similar to the procedure for complying with boiler level SIP.
Most power plants fit into one of the above two categories. However, there
are a number of plants which have multiple boilers which feed to more than one
stack. In many cases, the FPC data for these plants do not include sufficient
information to determine the specific association between stacks and boilers.
Therefore it is not possible for these plants to use a compliance test to
determine status of individual stacks. Because of this problem, and with the
concurrence of EPA, all stack level SIP are used similar to boiler level SIP
when the association between boilers and stacks cannot be determined.
The final output of the scrubbing cost generator is an identification of
all boilers at each plant that must be scrubbed to meet the S02 emission
regulation.
71
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Compliance Status of Power Plants
Based on the projected data, it is estimated that a total of 187 plants
will be out of compliance with either NSPS (new plants) or SIP (existing
plants) in 1978. It should be noted that many of the plants shown as out of
compliance are likely on a compliance schedule with technology that may be
different from that projected. Of these, a total of 69 plants is out of
compliance based on plant level SIP and 118 based on boiler level SIP. A map
showing the location of these plants is shown in Figure 17. Boiler sizes for
plants out of compliance range from as low as 5 to 1150 MW, whereas plant
sizes range from 38 to 2558 MW. Boiler ages for these plants range from zero
(new plants) to 60 yr old. The total annual quantity of emissions from these
plants is equivalent to 5,734,629 tons of S per year, compared to an allowable
emission rate of 3,236,764 tons/yr. Based on these projections, an average
overall S02 removal efficiency of 44% would be required to bring these plants
into compliance.
The method for using the output of the compliance tests to project costs
for meeting the regulation by FGD is discussed below.
DEVELOPMENT OF THE SCRUBBING COST GENERATOR
The purpose of the scrubber cost generator is to provide a simplified,
consistent method for projecting comparative costs for installing FGD systems
on the power plants projected to be out of compliance with the regulation.
Because of the limited amount of information available for input to the model,
the projections are to be treated as general rather than specific in evalua-
tion of the results.
The FPC data projections to 1978 and the output of the compliance test
models are inputs to the model. The basis for its development and other
relevant information concerning its use are discussed below.
Background
TVA in conjunction with EPA published a report entitled Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes (EPA 600/2-75-006;
NTIS PB 242 541, January 1975) (7) which projects the economics of S02 control
by two throwaway processes (limestone and lime slurry scrubbing) and three
recovery processes (magnesia slurry-regeneration, Wellman Lord/Allied, and
catalytic oxidation). As mentioned, the limestone, magnesia, and Wellman
Lord/Allied are the primary FGD alternatives considered in the current study.
The detailed "base" investment and operating cost projections given in the
above report for these processes, and the method illustrated for scaling costs,
were coded into a computer model to allow for projection of economics for these
processes at other capacities based on using the 1978 FPC data projections
discussed above.
The "base" data incorporated into the program correspond to scrubbing
processes designed for 500-MW boilers, both new and existing, which burn 3.5%
S coal (dry basis). They are assumed to emit 92% of the S in the coal overhead
72
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« < 70$/MBTU (SCRUBBING COST)
A>70$/MBTU (SCRUBBING COST)
Figure 17. Geographic distribution of 187 power plants projected out of compliance (1978)
-------
as S02, and are designed to remove 90% of the S02- The processes were
modified from the initial study to exclude the costs for particulate removal.
Investment Scaling Procedure
Direct Investment Scaling—
A method was established for using the FPC Form 67 data and the compliance
test data to project the investment and unit revenue requirements for each
power plant out of compliance. Quantities of air and S rates to the boiler
for the base case are included in the data base.
Similar data are projected for each boiler which is determined from the
compliance test to be out of compliance. Relative capacities are calculated
to allow for scaling costs. Flue gas processing equipment and costs are
estimated assuming that each boiler must be designed with separate, independ-
ent equipment. Absorbent preparation and effluent processing areas, however,
are designed with common facilities at the plant level to process the combined
quantities of absorbent and effluent from all of the boilers. This "common
facility" concept minimizes the investment requirements because designing for
installation of single large units rather than multiple small units results in
an economy of scale.
The FPC Form 67 data base does not contain data specifying flue gas rates
from the boiler to allow for scaling of the gas processing equipment (scrubbers,
fans, reheaters, and duct). Therefore, costs for these areas are scaled on the
basis of air rates to the boiler. Emission rates of S for each boiler are
available from the compliance tests and are totaled for each boiler which
requires S(>2 control; the total quantity is then used in scaling S processing
costs.
The general form of the equations for scaling costs for (1) the flue gas
processing areas and (2) the absorbent preparation and effluent processing
areas are shown below:
Bl
(1) Flue gas processing Base flue gas
area cost for _ processing
individual area cost
boiler (I)
Design air rate to boiler (I)
Design air rate to base boiler
Where Bl = scaling exponent for the gas processing equipment whose
costs are being scaled.
Total flue gas processing area costs for the plant are equal to the sum of the
flue gas processing area costs for each boiler which requires scrubbers.
B2
(2) Absorbent prepara- Base absorbent
tion and effluent preparation and
processing area = effluent pro-
common facilities cessing area
cost (entire plant) cost
Total annual S throughput for
all boilers which require
scrubbers
Total annual S throughput for
the base plant
Where B2 = scaling exponent for the S processing equipment whose
costs are being scaled.
74
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Since the absorbent preparation and effluent processing areas are
designed utilizing common facilities for the total throughput, these calcu-
lated costs do not need to be summed boiler by boiler.
The total direct investment is calculated as the sum of the total flue
gas processing area and the common facilities costs.
Indirect Investment Costs—
Indirect investment costs are estimated as a percentage of the direct
costs similar to the method used in the initial study. For simplification in
developing the model, the indirect cost factors do not vary with plant or
boiler size. Table 27 shows the indirect cost factors which are used in
projecting total investment requirements for each of the three processes as a
function of plant status (new or existing unit).
TABLE 27. INDIRECT INVESTMENT AND ALLOWANCE FACTORS (7)
Indirect Investment Factors
Engineering design and supervision
Construction field expense
Contractor fees
Contingency
Total indirects
Indirect investment and allowance factors
as a percent of direct capital investment
Limestone Magnesia and Wellman
process Lord/Allied gfocesses
New Existing
9
11
5
10
35
10
13
7
Ij.
41
Hew Existing
11
11
5
10
37
12
13
7
11
43
Allowance Factors
Startup and modifications
Interest during construction
Total allowances
8
_8
16
8
JJ
16
10
_8
18
10
_8
18
75
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Investment Adjustment Factors —
The data base was created to allow the input of other factors for ad-
justing process investment. A process premise factor is an allowable input to
adjust the projected process investment for any of the four processes. The
adjustment is applied uniformly for all plants. It allows the relativity of
process investments to be varied from that reported in the initial study to
reflect updated technology and costs and is applied separate from cost indices.
For the current study, process premise factors for the limestone, sodium, and
gypsum processes are input as 1.2, whereas the factor for the magnesia process
is input as 1.3. These values adjust the relativity of the costs to conform
with recent vendor cost data.
The data base also allows for the use of site-specific factors which can
be used for any process and any plant to adjust the investment to take into
account special design provisions which were not considered in the initial
study. Factors were incorporated for some of the TVA plants to reflect the
effect of a common plenum which would require fewer scrubbers, and to adjust
for higher projected capacity factors in comparison with projected FPC factors.
Two additional factors which may be input to the program to impact
process investment include (1) a retrofit difficulty factor (developed by
PEDCo) and (2) a location factor. Each of these factors is applied specifi-
cally to all processes at a given location. The retrofit difficulty factor
adjusts the projected investment equally for all processes at a given location
to account for site-specific variations in design and layout which would
affect costs for installation of each process alternative equally. Location
factors are applied in the same manner to account for site-specific differences
in construction costs which are related to plant location and terrain.
The FPC data file does not contain information specifying the number of
flue gas ducts on existing boilers. Since the number of required scrubbing
trains is a function of the number of ducts, power plants with gas flow
rates of <700,000 sft3/min were arbitrarily assumed to be designed with two
ducts, whereas plants with larger flow rates were assumed to be designed with
four ducts.
Revenue Requirement Scaling Procedure
Direct Costs —
Annual quantities of raw materials and utilities required for each
processing area (i.e., absorbent preparation, scrubbing, reheat, S02 processing,
etc.) are identified and are scaled from the "base" data proportional to the
relative gas ratio or the relative S throughput ratio similar to the method
for scaling investments. Labor and analyses requirements are scaled propor-
tional to the relative gas or S throughput ratio raised to a fractional
exponential power.
f«n P as.humidif ica<:ion water, reheat, and electricity for the
and'uMliMe Pr°P°rtional to the relative gas rate, whereas raw materials
and utilities, such as absorbent and electricity for the S-processing areas
are scaled proportional to the relative S rate. Annual cos
Annual costs for raw materals
76
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and utilities are then calculated by applying the unit costs to the annual
usage rates.
Projected unit costs for raw materials and utilities for 1978 are shown
in Table 28 with the exception of limestone and sludge disposal. A program
with the supporting data base was developed for calculating the delivered cost
of limestone to each power plant considered in the study. Details are out-
lined in Appendix X.
Maintenance is estimated as a percent of the subtotal direct investment
at the rates indicated in Table 29. Conversion operating costs are defined as
the sum of utility, labor, maintenance, and analyses costs. Direct costs are
defined as the sum of raw material plus conversion costs.
TABLE 29. ESTIMATED MAINTENANCE RATES FOR ALTERNATIVE FGD PROCESS (7)
Maintenance rate,
Process % of direct investment
Limestone 8
Magnesia 7
Wellman-Lord/Allied 6
Indirect Costs—
The capital charges included in the indirect operating costs are applied
as average capital charges, including depreciation, interim replacements,
insurance, and cost of capital and taxes. Depreciation is straight line over
the remaining life of the plant (based on an assumed useful life of 30 yr).
The capital charge allocation for interim replacements varies as a function of
the remaining life of the plant. For a new plant it is allocated as 0.67% of
the total investment, but declines to zero for plants with <20 yr of remaining
life. Insurance is allocated as 0.50% of total investment for all plants.
The overall breakdown of capital charges included in the cost projections is
shown in Table 30 (7).
For each process, plant overhead is estimated as 20% of conversion costs,
and administrative overhead as 10% of operating labor. Administrative over-
heads in the initial study (7) were calculated on a different basis for
processes producing a salable byproduct as compared to sludge producing
processes to take into account the costs for marketing the byproducts. For
this study, however, the byproduct prices are assumed to be net prices after
marketing expenses have been deducted; therefore, administrative overheads
are calculated by the same procedure for all processes.
Subtotal indirect costs are defined as the total of capital charges, and
plant and administrative overheads. Total annual revenue requirements are
defined as the total of direct plus indirect costs.
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TABLE 28. PROJECTED 1978 UNIT COSTS FOR RAW MATERIALS, LABOR, AND UTILITIES
Unit cost, $
Raw Materials
Limestone
Lime
Mag ne s ium ox id e
Coke
Vanadium pentoxide catalyst
Sodium carbonate
Antioxidant (sodium process-scrubbing)
Sulfuric acid
Variable3
42.00/ton
215.00/ton
28.00/ton
2.20/1
78.00/ton
2.75/lb
54.00/ton
Labor
Operating labor
Analyses
10.00/hr
15.00/hr
Utilities
Fuel oil, No. 6
Natural gas
Steam (500 psig)
Process water
Electricity
Heat credit
Water treatment
Sludge transportation fee
(offsite disposal variation)
0.35/gal
2.50/kft3
1.40/klb
0.06/kgal
0.027/kWh
1.15/MBtu
1.20/kgal
1.00/tona
a. See details in Appendix K.
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TABLE 30. ANNUAL CAPITAL CHARGES FOR POWER INDUSTRY FINANCING (7)
Depreciation, straight line (based on
years remaining life of power unit)
Interim replacements (equipment
having less than 30-yr life)
Insurance
Total rate applied to
original investment
As percentage of
original investment
Years remaining life
30 25 20
3.33 4.00 5.00
0.67 0.40
0.50 0.50 0.50
4.50 4.90 5.50
Cost of capital (capital structure
assumed to be 50% debt and 50% equity)
Bonds at 8% interest
Equity at 12% return to stockholder
Taxes
Federal (50% of gross return or
same as return on equity)
State (national average for states
in relation to Federal rates)
Total rate applied to
depreciation base
As percentage
of outstanding
depreciation basec
4.00
6.00
6.00
4.80
20.80b
Original investment yet to be recovered or "written off."
Applied on an average basis, the total annual percentage of original
fixed investment for a plant with 30 yr remaining life would be
4.5% + 1/2(20.80%) = 14.90%.
a.
b.
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Output of the Scrubbing Cost Generator
The overall output of the scrubbing cost generator includes the following
information for each of the three scrubbing alternatives considered:
1. Plant investment
$
$/kW
2. First-year costs excluding byproduct revenue
$
Mills/kWh
Cents/MBtu
3. Byproduct
Production rate, tons/yr
Equivalent cost, $/ton
4. Incremental process cost in comparison to limestone scrubbing
$
$/ton of byproduct
An example output is shown in Table 31.
The data generated in the scrubbing cost model are used to calculate the
scrubbing costs of a throwaway system versus a salable byproduct for each of
the 833 boilers identified in this study as operating out of compliance with
pollution control laws in 1978.
The scrubbing costs for fossil fuel power generation are expressed in
cents/MBtu for convenience in comparing them with clean fuel alternatives.
Use of low-S fuel is also a realistic alternative to FGD which must be
considered for meeting compliance regulations. The alternative clean fuel
level (ACFL) represents the amount of premium that one can pay for fuel that
is low enough in S to meet compliance in lieu of scrubbing with an FGD system.
The model also calculates the cost differential between scrubbing with a
limestone throwaway system versus MgO-acid producing system. This comparison
is based on the quivalent of 100% H2S04 for both systems. This accommodates
identifying the incremental cost difference of the two systems for all boilers
or combinations of boilers included in the model.
The lowest cost scrubbing system is limestone scrubbing at all plants in
the model except for a unique type of plant, that is, a large (500-MW) new
plant burning a low-S fuel such as oil and yet is exceeding SIP regulations.
MgO-acid scrubbing in this instance is lower in cost as compared to limestone
scrubbing. Such plants were handled in the model with a zero incremental cost
in lieu of using the negative cost.
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TABLE 31. SAMPLE OUTPUT OF SCRUBBING COST GENERATOR
Plant code: 000000-0000
PLANT NAME: X
Compliance costs from 1978 projections
Capacity factor, %
Coal
Oil
Gas
S content, %
Coal
Oil
Total capacity, MW (12 boilers)
Total scrubbed, MW (5 boilers)
Process
Investments
$
$/kW
First year costs (byproduct
revenues excluded)
$
Mills/kWh
Cents/MBtu
Byproduct
Tons/yr
Cost, $/ton
Incremental costs in compari-
son to limestone process
$
$/ton
56.5
2.5
0.1
3.2
1.5
1,275
1,109
Limestone
Magnesia
Wellman-Lord/
Allied
80
45
,152,545
72.3
,078,254
6.82
65.7
Sludge
426,094
105.8
0
0
95,996,739
86.6
52,957,830
8.02
77.2
H2S04
228,181
232.1
7,879,576
35
104,861,270
94.6
67,973,845
10.29
99.1
S
68,399
993.8
22,895,591
335
81
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Costs for production of S by the Wellman-Lord/Allied process were higher
in all cases studied than production of H2S04. Projected savings in distri-
bution costs for S compared to H2S04 did not offset the incremental production
costs. Costs for use of the Wellman-Lord/Allied technology will be more
clearly defined during the current full-scale demonstration, partially funded
by EPA, at the Mitchell Station of the Northern Indiana Public Service Company.
Revised information will be included in the model. Also, EPA is currently
sponsoring work with ESEERCO (Empire State Electric Energy Research Corporation)
and Niagara Mohawk to develop the Atomics International process for producing
S from SC-2 in stack gas. This technology and other work involving use of
solid reductants could lead to lower costs for production of S as an alter-
native to producing H2S04.
Several factors that are difficult to incorporate into a generalized
economic model could have a significant influence on the choice of byproducts.
The incentive for production of S is high because it is a safe, noncorrosive,
convenient material to handle, and can be easily stockpiled for long periods
of time at relatively low cost. Because of the latter advantage, S could be
incorporated more easily into the existing market. Moreover, fluctuations
in market demand could be met with less impact to both the producer and con-
sumer. S also has the advantage of being more economical to ship than acid,
especially for long distances.
In the computer program used for the marketing study, the model assumes
that acid plants that could be supplied with byproduct acid at a lower cost
than their own production costs (including cost of raw material S) would shut
down and purchase byproduct acid to sell to their customers. This would
involve a strong commitment to use of the byproduct because personnel to man
the acid plant could not be kept on standby nor would a guaranteed supply of
S be available on short notice. The acid distributor would very likely prefer
to purchase byproduct S (at a lower price than natural S) to supplement or
replace his traditional supply. Also, H2S04 plants normally generate steam
from burning S for use in other plant operations. It would be necessary to
replace this available energy with an alternate supply requiring the burning
of additional coal or fuel oil. Facilities for replacement steam production
could cost more than the savings from purchase of byproduct acid. S would
be favored over acid as a byproduct in those power plant locations where an
existing S terminal is already in operation. There are a number of such
terminals on the East Coast. The facilities required for handling molten S
would be of little value in handling acid. Also, S would be the preferred
byproduct in extremely cold climates. The freezing point of acid varies with
concentration, but 98% acid will freeze at about 40°F. Long-term storage of
acid would be much more expensive and difficult under these conditions.
Another situation when S would be favored is for power plants in the Western
States where the limited acid market is controlled by smelters. Shipping S
to the eastern market would be more economical than acid.
It is likely that a mix of marketable byproducts will ultimately provide
the least-cost compliance with S02 regulations in the utility industry.
Technology for production of S should be fully developed so that the choice
is available and so that accurate information is available for cost comparisons
with other methods of control.
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The cost information from the scrubbing cost model becomes input to the
marketing model which is designed to determine the potential for the pro-
duction and marketing of byproduct l^SO^ at the various power plant locations.
The data can also be used to generate a supply curve for the production of
abatement
Supply Curve for Abatement Acid
A demand curve for abatement acid was presented in Figure 6. For
illustrative purposes it is useful to consider the supply curve that would be
traced out by different levels of a uniform f.o.b. steam plant supply cost
for 1^504. This ignores steam plant location relative to acid plants. Such
a curve can be estimated by ranking power plant boilers from lowest to highest
cost for producing H2S04 and accumulating supply quantities shown in Figure 18.
The range of supply costs is much greater than those for demand. While about
9 Mtons of acid is available at an infinite price, supplies greater than
about 8 Mtons is unreasonable.
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1.5
1.0
crt
O
U
H
M
0.5
8
10
12
14
CUMULATIVE S REMOVAL, MTONS OF HnSO,
Figure 18. The supply cost curve for abatement acid.
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ABATEMENT BYPRODUCT ACID DISTRIBUTION-TRANSPORTATION SYSTEM
To assess representative competitive costs, this market system analysis
must generate accurate S freight rates from the Frasch S sources to the acid
plants and 1^804 freight rates from all power plants to all 1^504 plants.
This represents more than 300,000 possible rates which is a prohibitive
manual task. Also, the overall market study series calls for a possible
expansion to evaluate CaS04 for wallboard, ammonium sulfate {(1^4)2804], and
several other fertilizer classifications; therefore, the task becomes
increasingly demanding.
STANDARD POINT LOCATION CODE
The logistical linkage between the H2S04 and power plant data bases and
the rate generation system is the Standard Point Location Code (SPLC). This
is a transportation-oriented, six-digit number prescribed by the National
Motor Freight Traffic Association under the guidance of the SPLC Policy
Committee. The system is similar to U.S. mail zip codes. Figure 19 shows
location areas to the first two-digit level. The first digit indicates a
region relating to major traditional traffic associations. The first two
digits uniquely identify a state or a portion thereof. As more digits are
added, smaller nested areal units are identified. The third digit gives a
cluster of counties, the fourth digit a county, the fifth digit a cluster of
points within a county, and the sixth digit identifies all rail and truck
specific points.
DISTRIBUTION COST GENERATION
A logic flow diagram of the freight rate generation system used in this
model is shown in Figure 20. It shows that an SPLC for a power plant origin
and one for an H2S04 plant destination are input to the National Rate Basis
Tariff 1-C (NRBT 1-C). This tariff determines for rail rate purposes the
basing points for the origin and destination. While there are about 60,000
rail points, there are only 2,632 basing points east of the Rocky Mountains.
Outputs from the NRBT 1-C block in Figure 20 are two sets of codes used
to define mileage and tariff rates between the byproduct shipping origin and
destination points. One set—Index 1 and Index 2—is used to determine the
appropriate rate base mileage to be applied. The two index values are
pointers to a 3.5 M record triangular mileage file compiled from 12 tariffs
resulting from the landmark 1945 Interstate Commerce Commission hearing
entitled "Docket 28300." (Short line rail mileage published in the twelve
"28300 Class Tariffs" by all railroads operating east of the transcontinental
85
-------
00
Figure 19. Geographic identification of Standard Point Location Codes (SPLC),
-------
SPLC,—,
|—SPLC2
NRBT I-C
I
INDEX
__*
INDEX.
i
DOCKET
28300
I
RATE BASE MILEAGE
RATE
SEARCH
MINIMUM
RATE
MES,
i
MES;
TARIFF
GENERATOR
I
TARIFF NUMBER
Figure 20. Flow diagram of freight rate generation model.
87
-------
territory outlined in Figure 21). The file includes rail (and some truck)
tariff mileage for shipments within and between five major freight associations
shown in Figure 21. Output from the Docket 28300 block of Figure 20 is a rate
base number that can be thought of as a type of mileage.
The second group of codes output from the NRBT 1-C define the mutually
exclusive set (MES) numbers for the origin and destination points and serve
as input to the Tariff Rate Generator block to choose the appropriate tariff.
Figure 21 shows the location of the nine rate territories (MES Nos.) east of
the Rockies. Identification of the nine territories is necessary due to over-
lapping application of the five major freight rate territories. The remaining
10 MES numbers as shown in Table 32 are those base points which by virtue of
unique circumstances or borderline applications necessitates separate listing.
The result is a total of 19 MES numbers for basing points in the Docket 28300
tariffs. Given the MES for both the origin and destination it can be deter-
mined in which tariff(s) these points can be found, which is output from the
Tariff Generator block in Figure 20.
TABLE 32. RECLASSIFICATION OF BASE POINTS
10
10
11
12
12
12
13
13
13
13
13
13
14
14
KY
KY
KY
DC
VA
WV
VA
VA
VA
VA
VA
VA
VA
VA
Lexington
Winchester
Chilesburg
Washington
Norfolk
Charleston
Alberta (S)
Altavista (S)
Burkeville (S)
Lynchburg (S)
Petersburg (S)
Suffolk (S)
Bristol
Norton
14
14
15
15
16
16
17
18
19
19
19
19
19
19
VA
TN
SC
SC
NC
TN
IL
NY
IN
IN
IN
IN
IN
WV
St. Paul
Bristol
Anderson Quarry
Rion
Bunn
Brownsville
Sparta
Pulaski
Cannelton
Corydon
Ferdinand
Huntingburg
Marengo
Olcott
The importance of knowing not only the mileage but also the tarrif
number is illustrated in Figure 22. Shown are l^SO^ rail rates within four
major freight associations as a function of rate base numbers. A slight
error in mileage is not nearly as critical as knowing which tariff applies.
Also these are the only published 1^804 rates. Rates for the other eight
tariffs were generated by the TVA Navigation and Regional Economics Branch
(Division of Navigation Development and Regional Studies) from those using
sound traffic legal arguments similar to the negotiation process that would
ensue should large acid movements become a reality. In Figure 20 rate base
and tariff numbers are input to the Rate Search block and the minimum rate
is output for use in the transportation cost model.
88
-------
oo
WESTERN TRUNK
TERRITORY
GENERAL FREIGHT TR
"•COMMITTEE
I t
I ,"•...
TRANS-CONTINENTAL
TERRITORY
SOUTHWESTERN
TERRITORY
SWL 5
#8 SWL-SFA
Figure 21. Railroad rate territories.
-------
26 i—
24 -
22
20
18
16
14
o
tr
12
CO
O
*x
-co-
10
•'" /WTL-2000J /
/ /' '
// A
:' / /SW-2004-l
E-2009-H / /' /
SFA-351-0
-4
-/
200 400 600 800 1000 1200 I40O 1600 1800
DISTANCE
Figure 22. Four basic commodity column tariffs for
H2S04 rail shipments.
90
-------
MARKET SIMULATION MODEL THEORY
Objective of the overall marketing model is to simulate long-run com-
petitive equilibrium S and H2S04 market conditions in the U.S. as might be
impacted by recovery of byproducts from S02 control in the power industry.
To simulate these conditions, total cost of both the H2S04 and power industries
is minimized subject tc the condition that acid production (demand) is still
met, either from traditional S sources or from substitution of abatement
The model is similar to the classic transportation model of linear pro-
graming where demands represent H2S04 plant customers and supplies represent
either production at each of the commercial acid plants or purchases from
any power plant boiler capable of producing acid. Incurred (transfer) costs
represent either H2S04 production cost using Port Sulphur S in the first case
or boiler scrubbing cost plus transportation cost to the respective acid
plants in the second case. A mathematical statement of the model is outlined
in Appendix B.
ECONOMIC THEORY
Through the use of several simplifying assumptions, the complex process
taking place in the model can be conceptualized in terms of classical supply
and demand curves.
If spatial considerations could be ignored, the demand (price) curve in
Figure 6 and the supply (cost) curve in Figure 18 could be plotted on the
same graph as in Figure 23; where they intersect would represent supply-
demand equilibrium.
It was explained earlier, and summarized in Figure 6, that from the
H2S04 plant data base and the long-run average acid production cost generator,
all commercial acid producers can be ranked in terms of a demand curve. A
conceptual f.o.b. power plant acid demand curve DDT is shown in Figure 23.
At high abatement supply price levels, only the smallest, oldest, most
remotely located acid plants would be interested in curtailing production
and buying abatement acid. As supply price declines, more acid producers
buy until even the largest, newest plants located near S supply sources
become candidates.
Likewise, as explained earlier and summarized in Figure 18 boilers can
be ranked in terms of a supply (cost) curve, f.o.b. each power plant such as
SS' in Figure 23. The intersection of such a supply curve wxth the conceptual
91
-------
t
u
<
0.
o
Ul
o
o:
o.
USE
MCLEAN FUEL
CONTINUE PRODUCTION
QUANTITY OF SULFURIC ACID
Figure 23. Conceptual demand curve for l^SO^ and supply
curve for abatement production.
92
-------
demand in Figure 23 would represent an equilibrium position at point Q. The
price F represents the alternative of buying complying fuel.
From the demand curve DD1 , H2S04 producers above equilibrium price P
would find it profitable to buy acid from steam plants rather than continuing
production. Those less than price P would find it more profitable to con-
tinue production.
From the supply curve SS1, boilers below price P would find it feasible
to use a scrubbing strategy that produces H2S04, while those above price P
but less than price F would profit from using a scrubbing strategy that
produces and disposes calcium (Ca) sludge. Those above price F would find it
more profitable to use a clean fuels strategy in lieu of scrubbing, assuming
that such clean fuel is available.
Multidimensional Equilibrium Model
While the preceding simplified economic description presents the essence
of the economic model, a more elaborate spatial equilibrium model is required
for realistic analysis. The problem is that the lowest acid cost boiler
could be close to or far from the highest cost commercial acid plant. It
therefore is necessary to trace a demand curve for a single source (location)
of supply. This could be done for every supply point, but would be of no
analytical significance unless there was only one supply point being con-
sidered. As soon as more than one supply point is considered, competition
develops for demand points. Hence, while traditional supply-demand concepts
are helpful in exploring the basic underlying economic structure of flue gas
marketing alternatives, a much more elaborate multidimensional equilibrium
model is required before analytical conclusion can be drawn.
The model implicitly ranks potential acid buyers as described earlier
under the demand for abatement acid except that every potential abatement
acid producer is given his own view of the market with reference to his
specific location. As the model is being solved this view is dynamically
changed to reflect the bidding away of markets by other potential abatement
producers. The decision-making process might be viewed in two stages (1)
the utility manager is bidding for markets at a given price and (2) based on
results of the bidding decides if production of acid is the least-cost
alternative. The results of this bidding process, of course, interacts with
his abatement strategy decision. The task of simulating this process from
the viewpoint of 104 acid producers and 833 steam plant boilers can be
solved with modern computers and linear programing techniques. The solution
reveals not only which acid producers would buy and which power plants would
sell H2S04, but also which power plants would sell to which acid plants. The
mix of abatement strategies and marketing patterns resulting in the lowest
possible cost to the combined industries (society) is said to be optimal.
Such a solution simulates the result of long-run competitive equilibrium
solutions. Any variation to this optimal solution would increase the total
cost to both industries .
The model is designed to place alternative strat e?ies/°^C°^"°^fves
emissions in perspective for each power plant in relation to the alternatives
93
-------
available to all other power plants. The model addresses only those plants
that are projected to be out of compliance in 1978. The strategies considered
include (1) the use of clean fuel, (2) scrubbing with limestone to produce a
throwaway sludge, and (3) scrubbing with MgO to produce J^SO^ as a marketable
product. It is obvious that the lower the cost of clean fuel the less justi-
fication utilities would have to use FGD. However, clean fuel is more
expensive than traditional fuel supplies. The premium cost for complying
fuel is assumed to be the limit on the net cost of scrubbing. That is, as
the premium for clean fuel increases the more the utility industry can pay
for FGD systems.
If scrubbing is the least-cost option the model chooses between the use
of limestone scrubbing technology or the production of abatement acid; costs
for production of S by the Wellman-Lord/Allied process were higher in all
cases studied than production of 112804. If the incremental cost of scrubbing
with MgO to produce I^SO^ compared with limestone scrubbing can be recovered
by marketing t^SO^ in the existing market then the power plant would choose
the acid-producing strategy.
The model considers total cost of both the H2S04 and power industries
and chooses the set of alternatives that minimize the total cost. t^SO^
producers are given a choice of continuing production or buying acid from any
steam plant.
94
-------
RESULTS AND ANALYSIS
PLANTS OUT OF COMPLIANCE IN 1978
The operating characteristics of all 800 U.S. power plants projected to
be in operation in 1978 are outlined in Table 33. Also included in this table
are the characteristics of the plants projected to operate out of compliance
in 1978.
As the data in the table indicate, 187 power plants out of a total of 800
were calculated to be out of compliance. It should be noted that many of the
plants estimated to be out of compliance are likely on compliance scheduled
that are different from those selected for this study. Even though plants out
of compliance make up only 32% of the total population with respect to capacity,
they burn about 50% of the total coal; only 20% of the total oil and only 5%
of the total gas. Plants out of compliance have a 30% higher S content in the
coal burned and a 43% higher S content in the oil burned than the overall
nationwide average. The average boiler size for plants out of compliance was
about 30% greater than the average for all plants. The age range of boilers,
the range of boiler sizes, and boiler capacity factor for plants out of
compliance were not significantly different from the industrywide values.
ACFL
The ACFL is defined as the premium price for fuel that will meet the
applicable S02 emission regulation. Determination of the actual premium paid
for complying fuel in the utility industry is beyond the scope of this study.
Also, the availability of complying fuel was not considered. The ACFL selected
for the model runs ($0.35, $0.50, and $0.70/MBtu) were chosen to show the
effect on potential volume of abatement acid. However, the range covered
should be representative of most actual situations. Extreme values were used
to demonstrate that at low premium price, scrubbing is not competitive while
at high premium values, FGD is the economic choice. The results of these
calculations for all plants estimated to be out of compliance in 1978 are
shown in the following tabulation:
Reduction in Emissions
Clean fuel
premium,
cents /MB tu
Clea
ktons S
n fuel Scrubbing
Annual
Clean fuel
cost, $
Scrubbing
25 4 440 - 1,172,406,000
' eg 4 342 159,200,000 2,323,553,000
_9 ^440 - 2,866,244,000
95
-------
TABLE 33. POWER PLANT OPERATING CHARACTERISTICS PROJECTED FOR 1978
1978
1978 plants
all out of
U.S. plants compliance
No. of power plants 800 187
No. of boilers 3,382 833
Total capacity, MW 411,000 132,600
Total fuel
Coal, ktons 475,600 226,800
Coal," GBtu 10,408,300 5,125,100
Oil, kbbl 620,300 110,200
Oil, GBtu 3,827,400 686,900
Gas, Mft3 2,556,000 108,200
Gas, GBtu 2,602,200 167,000
Average S content of coal, % 2.12 2.81
Average S content of oil, % 0.99 1.42
Emissions, equivalent tons H2S04
Total emitted 29,552,100 17,562,300
Required abatement 9,912,600 9,912,600
Average capacity factor, % 31.87 35.12
Average boiler generating capacity, MW 122 159
Age of boilers, %
0-5 5 10
6-10 8 10
11-15 8 6
16-30 42 42
>30 37 32
Size of boilers, %
<200 82 75
200-500 H.7 15
501-1000 'fe 9
XLOOO 0.3 1
Capacity factor of boilers, %
<20 40 35
20-40 20 17
41-60 23 29
>60 17 19
96
-------
Based on the inputs used to calculate scrubbing costs in this studv -he
above tabulation indicates that at $0.25/MBtu ACFL no scrubbers won]^ be'used
Clean fuel would be the logical strategy for controlling emissions! V'cl^n'
fuel cost is >$1.50/MBtu heat input, very little clean fuel would be used and
scrubbing would be the strategy for controlling the ma-jor portion of S02
emissions. The scrubbing costs are based on the least-cost method without
credit for byproduct sales which is normally limestone scrubbing.
The total costs shown illustrate that if clean fuel were available at
$0.25/MBtu premium, annual cost of compliance would be $1.17G (G = 1 billion)
while at a premium of $1.50 compliance would be mainly by scrubbing at a cost
of nearly $2.5G.
RESULTS AND ANALYSIS OF BYPRODUCT SMELTER ACID MARKET
The first model run was made at a zero ACFL so that all power plants
chose a clean fuel strategy leaving only the smelters participating in the
market. As was expected, the smelter acid was fully integrated into the acid
market projected for 1978. When the clean fuel premium for the utility in-
dustry was set at the $0.35/MBtu ACFL level, eight power plants produced and
sold acid in competition with the smelters. The distribution changed slightly,
but the total smelter capacity, 1,756,000 tons, was moved into the market.
When the ACFL was increased further to $0.50/MBtu and $0.70/MBtu, competition
from power plant acid reduced the amount of byproduct acid that can be sold by
the western smelters. The results of all the runs on smelter acid distribution
are summarized in Table 34. At the $0.50/MBtu level, power plant acid replaced
20% of the western smelter acid and at the $0.70/MBtu level, over 70% of the
market for western smelter acid was lost to acid produced by power plants.
Because of their close proximity to the industrial areas of the U.S., all of
the eastern and Canadian smelter acid was sold in competition with the power
plant acid at all levels of clean fuel premium. The analysis of model runs
indicates that the location of the western smelters with respect to
the H2S04 market places them at a disadvantage in competition with power
plants located in vicinity of the industrial sector of the Eastern U.S. If
the power plants develop such markets, the western smelter would have to
equalize the price in order to compete. The only other option available to
the western smelter would be to neutralize any excess byproduct acid that
cannot be used for leaching of low-grade feedstock.
The supply points identified with the sale of byproduct smelter acid in
each of the model runs are outlined in Appendix L.
RESULTS AND ANALYSIS OF POWER PLANT ABATEMENT ACID MARKET
Scrubbing Cost Generator Prescreen
The scrubbing cost generator was used to identify scrubbing candidates
for all 187 power plants operating out of compliance at each of the three
selected values of ACFL. The results are tabulated as follows:
97
-------
TABLE 34. BYPRODUCT SMELTER ACID DISTRIBUTION IN MODEL RUNS
(ktons)
Eastern smelters
Direct sales
Total Eastern
Canadian smelters
Via Buffalo terminal
Via District terminal
Total Canadian
ACFL, cents/MBtu
35 50
70
818 818 818 811
818 818 818 818
165 165 200 200
35 35 -
200 200 200 200
Western smelters
State Terminal
Arizona
Houston
New Mexico Chicago
Baton Rouge
St. Louis
Houston
Utah
Montana
Memphis
St. Louis
St. Louis
Memphis
Total Western
Total byproduct smelter
acid
118
304
76
96
46
98
738
118
304
76
96
46
98
738
118
155
50
166
9
96
594
118
81
199
1,756 1,756 1,612 1,217
98
-------
ACFL. cervts/Mgtti
35 50 '
Plants with scrubbing
costs lower than ACFL 19 74 116
Plants with scrubbing
costs higher than ACFL 168 113 71
All power plants with an FGD acid-producing potential of <66,000 tons/yr
were excluded from the acid-producing candidates because acid plants with a
lower production capacity would be too small to be competitive. Such plants
were given the choice of choosing a limestone or a clean fuel strategy in the
model.
For some power plants with multiple boiler installations, a mix of
alternative methods produced the least-cost compliance strategy. The results
of the prescreen are outlined in the following tabulation:
Total U.S. (187 plants)
ACFL. cents/MBtu
Prescreen 35 50 70
1. All clean fuel 168 113 71
2. All limestone scrubbers 6 25 48
3. Mixed limestone scrubbers
and clean fuel 438
4. Potential MgO-acid scrubbers 9 40 58
5. Potential MgO-acid scrubbers
and clean fuel 0 6_ 2_
187 187 187
Compliance Strategies Selected by Power Plants in Model Runs
The market simulation model was run to determine which of the potential
acid-producing power plants would be viable candidates for marketing abate-
ment acid in competition with byproduct acid from smelters. A summary of the
distribution of strategies at the ACFL is shown in the following tabulation:
ACFL. cents/MBtu
1.
2.
3.
4.
5.
Compliance strategy
All clean fuel
All limestone scrubbers
Mixed limestone scrubbers
and clean fuel
MgO-acid scrubbers
Mixed MgO-acid scrubbers
and clean fuel
35
168
7
4
8
0
187
50
113
41
7
24
2
187
70
71
77
10
29
0
187
99
-------
Many of the potential acid-producing plants identified in the scrubber
cost generator prescreen run used limestone scrubbing in the long-term
equilibrium model solution. The switch from recovery to a throwaway method
resulted from the increased transportation costs at the higher abatement acid
production levels. The potential production and marketing of abatement acid
for the power plants that selected MgO-acid scrubbing strategy in each of the
model runs is outlined as follows:
ACFL. cents/MBtu
35
50
70
Potential production and 2,554 5,108 5,595
marketing acid, ktons
A listing of the specific power plants that chose the acid scrubbing
strategy in each of the three alternative clean fuel model runs is outlined in
Tables 35-38. The tables include plant number, location, megawatts, Btu
scrubbed, and tons of acid produced.
TABLE 35. EIGHT POWER PLANTS SCRUBBING, PRODUCING,
AND MARKETING ACID IN $0.35 ACFL RUN
Plant No.
1395000250
3800000800
4510000100
4740000300
4770003000
4770004100
4815000400
4820001800
Total
Average
Location
North Carolina
Pennsylvania
Alabama
Florida
Kentucky
Tennessee
Ohio
Michigan
MW
2,286
1,600
910
1,136
2,558
2,550
1,831
2,462
15,443
1,930
Btu
scrubbed
99,526,110
100,763,230
54,170,170
71,443,680
121,162,120
12,853,680
132,159,990
141,227,650
733,357,630
91,669,703
Tons of
acid
105,209
241,426
68,824
250,963
628,358
572,320
254,335
433,206
2,554,641
319,330
A geographic distribution of the 187 power plants included in the model
runs is outlined in Figure 17. This figure also identifies the plants that
chose a clean fuel strategy in the $0.70/MBtu ACFL model run as well as the
plants that chose a scrubbing strategy. In the latter group of 116 plants,
29 produced and marketed acid, and 81 used a clean fuel strategy. A tabula-
tion of estimated scrubbing and clean fuel use in compliance strategies is
presented in Appendix M.
100
-------
TABLE 36. TWENTY-FOUR POWER PLANTS SCRUBBING, PRODUCING, AND
MARKETING ACID IN $0.50 ACFL RUN
Plant No,
070Q000.550
0785000500
0790000100
1115001300
1395000250
1655000300
1790002550
1790002800
2455000250
2730000600
3795000350
3800000800
4045000900
4510001000
4530000850
4740000300
4770Q03000
4770004100
4815000400
4820001800
5125000650
5125000700
5250001400
5540000250
Total
Average
Location
New York
Illinois
Illinois
Illinois
North Carolina
Florida
Georgia
Georgia
Kentucky
New York
Pennsylvania
Pennsylvania
Indiana
Alabama
Texas
Florida
Kentucky
Tennessee
Ohio
Michigan
Missouri
Missouri
Virginia
Missouri
MW
1,200
590
602
1,271
2,286
964
1,792
1,820
1,011
1,511
650
1,600
1,062
910
634
1,136
2,558
2,660
1,831
2,462
1,150
1,100
845
527
32,172
1,341
Btu
scrubbed
50,142,240
23,955,530
29,939,960
66,538,760
99,576,110
50,383,440
72,759,860
88,005,410
56,196,800
80,571,790
27,815,880
100,763,230
59,604,720
54,170,170
25,742,050
71,443,680
121,163,120
128,536,880
132,159,990
141,227,620
47,372,990
51,037,800
42,656,150
20,774,340
1,642,528,550
68,436,690
Tons of
acid
75,016
77,549
96,692
281,208
105,209
192,742
253,367
255,939
148,978
126,735
72,342
241,426
147,606
68,824
95,195
250,963
628,358
572,320
254,335
433,206
67,997
176,480
68,606
108,149
4,799,242
199,968
101
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TABLE 37. TWO POWER PLANTS SCRUBBING, PRODUCING, AND MARKETING ACID
IN $0.50 ACFL RUN, BUT ALSO USING CLEAN FUEL
Plant No.
3455000400
4805000200
Total
Total
Location
Indiana
Ohio
($0.50 run)
MW
660
1,263
1,923
34,095
Btu
scrubbed
34,148,090
47,675,290
81,823,380
1,724,351,930
Btu using
clean fuel
4,731,910
3,061,600
Tons of
acid
132,291
177,166
309,457
5,108,699
Production and sale of byproduct acid was the least-cost compliance
strategy at all levels of clean fuel premium for seven of the power plants.
This indicates that the combination of production costs and proximity to
markets makes these plants the most stable candidates for use of recovery
technology. They are presented graphically in Figure 24 and listed as follows:
Plant No.
1395000250
3800000800
4510000100
4740000300
4770003000
4770004100
4815000400
Location
North Carolina
Pennsylvania
Alabama
Florida
Kentucky
Tennessee
Ohio
Incremental
cost, $/ton acida
0.00
4.09
0.42
16.72
15.18
10.01
7.02
Tons of
acid
105,209
241,426
68,824
250,963
628,358
572,320
254,335
Total
2,121,435
a. Additional unit cost of producing abatement acid as
compared to limestone scrubbing.
However, at least two of these plants plan to use compliance methods that were
not included as alternatives in the study.
A summary of model results for smelter and power plant sales to acid
plant demand points for all model runs is outlined in Table 39. These results
show the potential quantity of power plant acid in relation to the total
market. At the $0.70/MBtu ACFL, the potential for production of acid (abate-
ment capacity) at a cost below the ACFL premium fuel cost exceeded the market
demand (sales) for the acid by 5 Mtons. All acid produced was marketed, but
only the lowest cost producers could compete with existing supplies; the
remainder used limestone scrubbing. At the $0.35/MBtu level, essentially all
of the acid that could be produced economically compared to purchase of
complying fuel was sold. The small differential in sales between the $0.50
102
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TABLE 38. TWENTY-NINE POWER PLANTS SCRUBBING, PRODUCING, AND
MARKETING ACID IN $0.70 ACFL RUN
Plant No.
0700000550
0785000100
0785000500
0790000100
1000000050
1095000200
1115001300
1395000250
1655000300
1790002550
1790002800
2455000250
2730000600
3795000350
3800000800
3840000500
4045000900
4510000100
4530000850
4740000300
4770001900
4770002100
4770003000
4770004100
4815000400
5125000650
5125000700
5250001400
5540000250
Total
Average
Location
New York
Illinois
Illinois
Illinois
Texas
Ohio
Illinois
North Carolina
Florida
Georgia
Georgia
Kentucky
New York
Pennsylvania
Pennsylvania
Pennsylvania
Indiana
Alabama
Texas
Florida
Tennessee
Tennessee
Kentucky
Tennessee
Ohio
Missouri
Missouri
Virginia
Missouri
MW
1,200
616
590
602
836
1,255
1,271
2,286
964
1,792
1,820
1,011
1,511
650
1,600
940
1,062
910
634
1,136
1,482
1,723
2,558
2,660
1,831
1,150
1,100
845
527
36,562
1,261
Btu
scrubbed
50,142,240
24,933,140
23,955,530
29,939,960
33,943,780
63,971,180
66,538,760
99,576,110
50,383,440
72,759,860
88,005,410
56,196,800
80,571,790
27,815,880
100,763,230
31,096,200
59,604,720
54,170,170
25,742,050
71,443,680
72,402,030
85,504,880
121,163,120
128,536,880
132,159,990
47,372,990
51,037,800
42,646,150
20,774,340
1,813,152,110
62,522,486
Tons of
acid
75,016
126,448
77,549
96,692
125,523
379,768
281,208
105,209
192,742
253,367
255,939
148,978
126,735
72,342
241,426
72,786
147,606
68,824
95,195
250,963
301,246
223,146
628,358
572,320
254,335
67,997
176,480
68,606
108,149
5,594,953
192,929
103
-------
Figure 24. Geographic distribution of the seven best power plant candidates
for production and marketing of abatement t^SO^.
-------
TABLE 39. SUMMARY OF MODEL RESULTS FOR SMELTERS AND
POWER PLANT SALES TO ACID PLANT DEMAND POINTS
(ktons of H2S04)
ACFL, cents/MBtu
Eastern smelters
Capacity
Sales
Demand points
Western smelters
Capacity
Sales
Demand points
Canadian acid
Capacity
Sales
Demand points
Total smelter acid capacity
Sales
Demand
Mixed demand points
Steam plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur to 1^804 plants
Capacity
Sales
Demand points
Mixed demand points
Port Sulphur only
0
818
818
15
738
738
15
200
200
4
1,756
1,756
32*
11
-
-
-
-
32,237
30,481
69a
11
58
35
818
818
13
738
738
8
200
200
4
1,756
1,756
24a
13
2,635
2,554
31a
9
32,237
27,926
50a
8
42
50
818
818
12
738
594
3
200
200
2
1,756
1,612
16a
15
8,497
5,108
57a
16
32,237
25,516
35a
5
30
70
818
818
14
738
498
3
200
200
3
1,756
1,516
19a
13
10,758
5,595
56a
14
32,237
25,126
31a
4
28
a. Steam plants and eastern and western smelters can supply a common
demand point.
105
-------
and $0.70/MBtu level of ACFL indicates that the market for byproduct acid
from power plants was nearly saturated at 5 Mtons, or approximately 15% of the
total market. Further substitution of byproduct acid in the existing market
would depend on substantial increase in the price of S; $60 was assumed for
the study.
An analysis of the distribution of byproduct acid is presented in the
following section.
Operating Profile for Power Plants Associated with Compliance Strategies
Proposed for 1978
A summary of the operating characteristics of the plants that are candi-
dates for use of scrubbing and for production of abatement acid are outlined
in Table 40.
In general, plants with a high scrubbing cost (and therefore good candi-
dates for buying clean fuel) had small, old boilers with a low capacity factor,
and burned fuel with a higher than average S content. Plants with low-to-
average scrubbing costs tended to have the opposite characteristics, i.e.,
large, newer boilers with a higher capacity factor, and a lower S content fuel
than the average burned by plants out of compliance.
Power plants that were the best candidates for production of acid were
generally bigger, newer, and had a much higher capacity factor than scrubbing
candidates in general. The best candidates had boilers more than three times
as large as the average plant out of compliance. The following statements are
generally true of the best candidates for acid scrubbing systems: (1) they
burn coal; (2) the boilers have an average capacity factor of >60%; (3) the
average boiler size is >600 MW (<15% of the boilers are smaller than 200 MW);
and (4) they have very few old boilers (almost none >30 yr old), and most of
their boilers are <10 yr old.
Two other factors not shown directly in Table 40 also have a significant
impact in determining the best acid-producing candidates. Location is
critical, since even though the economics of scrubbing to produce acid may be
favorable, high transportation costs can offset the advantage of production
cost. The emission standard promulgated for a given plant is important; unless
large quantities of S02 removal are required (implying very low allowable
emissions, very high emission levels, or a combination of both), scrubbing to
produce acid is not usually the most economical method.
Changes in ACFL are more significant for scrubbing candidates that produce
acid than for scrubbing candidates in general since market distribution is
impacted as more and more plants are considered for acid scrubbing. Location
factors are responsible for changing the mix as additional candidates are
brought into the solution. For example, seven of the eight power plants
producing acid in the $0.35 ACFL run yielded demand points to relatively
higher cost plants in the $0.50 ACFL run. A further change in distribution
?at«nr™r!™Tlted ln the $°'7° ACFL run' 16 °f 24 P°wer Plants Producing acid
in ?0.50 ACFL run yielded demand points to other plants even though all other
characteristics were economically superior.
106
-------
TABLE 40. OPERATING CHARACTERISTICS OF POWER PLANT CANDIDATES FOR USE OF SCRUBBING TECHNOLOGY
Scrubbing cost, <:/MBtu
No. of power plants
No. of boilers
Total capacity, MW
Total fuel
Coal, ktons
Coal, GBtu
Oil, kbbl
Oil, GBtu
Gas, Mft3
Gas, GBtu
Average S content of coal, %
Average S content of oil, %
Average capacity factor, %
Average boiler generating capacity, MW
Age of boilers, %
0-5
6-10
11-15
16-30
>30
Size of boilers, %
<200
200-500
501-1000
>1000
Capacity factor of boilers, %
<20
20-40
41-60
>60
<35
19
69
25,642
54,688
1,242,134
33,246
204,605
10,173
14,685
2.12
0.85
57.64
372
22
20
14
26
18
46
19
28
7
15
.4
29
52
<50
74
290
84,716
171,365
3,888,782
79,600
494,105
14,976
20,303
2.63
1.33
49.33
292
17
17
9
35
22
52
24
22
2
20
3
39
38
<70
116
457
109,518
213,613
4,825,282
96,193
598,090
28,274
34,482
2.78
1.36
46.83
240
15
14
7
45
19
60
24
15
1
17
12
41
30
>70
71
376
23,081
13,167
299,793
13,974
88,810
79,965
82,486
2.87
1.50
20.90
61
3
6
5
38
48
97
4
1
0
57
24
14
5
Acid-producing plants at ACFL,
C/MBtu
35
8
27
17,581
42,242
975,606
0
0
0
0
2.46
N/A
65.61
647
41
26
7
22
4
11
26
44
19
4
0
30
66
50
26
101
40,383
84,231
1,912,380
22,118
137,750
3,213
3,270
2.68
1.71
43.00
400
32
21
5
15
27
38
21
36
5
28
2
41
29
70
29
106
43,259
89,712
2,007,277
23,022
143,263
463
520
2.85
1.74
49.33
408
31
20
6
31
12
33
31
31
5
12
5
58
25
-------
RESULTS AND ANALYSIS OF DEMAND POINTS FOR ABATEMENT BYPRODUCT ACID
The demand analysis involves a detailed review of the 1978 acid plant
operating profile assumed in this study. Each acid plant (90 total) has three
alternative strategies for obtaining supplies: (1) buying elemental S from
Port Sulphur via a marketing terminal and converting to H2S04, (2) buying
byproduct acid from a smelter, and (3) buying abatement acid from a steam
plant. The model assumes that the acid plant will close down in the second
and third strategies and buy abatement byproduct acid if it can be delivered
equal to or below the avoidable cost of production in the existing plant. The
feedstock analysis for the 90 acid plants considered is outlined as follows:
Feedstock Analysis for 90 Acid Plants
ACFL, cents/MBtu
0 35 50 70
Buying Port Sulphur only 58 42 30 28
Buying from smelters only 21 11 1 5
Buying from steam plants
only 0 22 41 41
Buying from Port Sulphur
and smelters 11 6 2 1
Buying from Port Sulphur
and steam plants 0232
Buying from Port Sulphur
and smelters and steam
plants 0001
Buying from smelters and
steam plants 0 7 13 12
Total acid plants 90 90 90 90
The specific plants associated with each purchase option identified in the
model run in accordance with the above tabulation are outlined in Appendix N,
Tables 1-12. The geographic distribution of acid plants buying elemental S
only versus plants purchasing abatement byproduct acid is presented in Figure
25.
Best Candidates for Purchasing Abatement Byproduct Acid
Four significant factors that affect the purchase of abatement acid by
current producers of H2S04 in this study are listed as follows: (1) size,
(2) age, (3) compliance with clean air standards, and (4) location. The first
three factors are reflected in the avoidable cost of production. The location
factor relates to transport cost.
Acid plants considered in the study range in size from 6,000 tons/yr to
2,260,000 tons/yr. Size is a critical factor in the solution results. No
plant larger than 500,000 tons/yr (28 plants) was a potential buyer of abate-
ment acid, while all plants <75,000 tons/yr (24 plants) were potential buyers
of abatement acid in the model solutions (see Appendix 0, Table 1).
108
-------
SULFUR-BURNING ACID PLANTS
• ELEMENTAL SULFUR ONLY
POTENTIAL BYPRODUCT DEMAND
POINTS
Figure 25. Geographic distribution of S-burning acid plants (1978).
-------
Size and age parameters are somewhat related since technological advance-
ments in 1960 made it feasible to build much larger t^SC^-producing facilities
(6000 ton/day units). Most of the larger plants are located on the Gulf
Coast in close proximity to the S supplies. Acid plants built after 1960 have
an average production of 1680 tons/day and represent 49% of the total number
of plants in the study; they represent 76% of the total production capacity of
all plants. About one third of the abatement byproduct acid in the $0.70
ACFL model run was delivered to these plants and replaced only 10% of their
total production capacity. A listing of the ownership of plants by size is
outlined in Appendix 0; plants that purchase acid in the model run are shown.
The older plants built prior to 1960 include 46 plants with 24% of the
total production capacity for all plants. The average size is 520 tons/day.
These plants use 67% of the abatement byproduct acid in the $0.70 ACFL model
run which replaces 64% of their total production capacity.
Appendix P presents a listing of the 20 acid plants which are projected
to operate out of compliance with clean air standards in 1978. The plants
that are purchasing abatement acid in the model runs are identified in Table
P-l. As the ACFL is raised an increasing number of these plants buy abate-
ment acid because the economic incentive for producing acid at power plants
increases and production from more favorable locations is available. Only 30%
are purchasing abatement acid at the zero ACFL where only smelter acid is
marketed.
An analysis of the size of firm associated with production capacity is
shown in Appendix 0. There are 42 firms with 90 S-burning acid plants with
production capacity of 32,227,000 tons/yr. The 15 largest firms have 48 acid
plants (54% of all plants) equal to 80% of the total production capacity of
all plants. These plants buy 48% of the abatement byproduct acid in the $0.70
ACFL run, but it replaces only 13% of their production capacity.
The 27 small firms have 42 acid plants equal to 20% of total production
capacity of all plants. They buy 52% of abatement byproduct acid which
replaces 64% of their production capacity.
Table 41 identifies acid plants that purchase abatement byproduct acid in
more than one of the model runs at given ACFL. Most of such plants are older,
smaller, and generally more remotely located from the Gulf Coast supplies of S
as compared to the total population, but there are exceptions. Unique
location advantage for across-the-fence operation can preempt other factors.
In the model runs, all the acid produced by a specific power plant was
sold, but the supply did not exactly equal the demand at the points of use.
Therefore, the incremental demand was met through production of acid from S.
This incremental amount represents an additional quantity of byproduct acid
that could be sold at the values calculated in the model. Specific power
plants and smelters that could supply this additional demand if production
could be increased (higher load factor or higher S coal), were identified and
are listed in Tables 13-16 of Appendix N. A summation of the additional
amounts at each level of clean fuel premium is as follows:
110
-------
TABLE 41. ACID PLANTS BUYING ABATEMENT ACID IN MODEL RUNS
ONE ACID PLANT BOUGHT BYPRODUCT ACID IN THE SMELTERS ONLY RUN .\NT> IX THE 50e
AND 70C ACFL POWER PLANT RUNS. DID NOT BUY BYPRODUCT ACID IN THE 35c RUN.
Avoidable
production
cost,
S/ton
C_0_mEany_ Location Capacity Year _ of_ncid
Desoto KS 105,000 1940 40.29
No.
114 U.S. Industrial Chem
17 ACID PLANTS BUYING ACID AT $.35, $.50, AND $.70 BUT NOT IN SMELTERS ONLY
RUN
10
13
20
28
33
46
48
49
50
61
70
96
102
109
116
119
120
Allied Chemical
Allied Chemical
American Cynamid
Army Ammunition Plant
Borden Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
W. R. Grace
LJ & M LaPlace
Royster Company
Stauffer Chemicals
Swift Chemicals
USS Agri-Chem
Weaver Fertilizer
Acme (Wright) Fertili
Nitro
Front Royal
Hamilton
Radford
Norfolk
Richmond
North Bend
Deepwater
Cleveland
Charleston
Edison
Mulberry
LeMoyne
Norfolk
Navassa
Norfolk
Acme
WV
VA
OH
VA
VA
VA
OH
NJ
OH
SC
NJ
FL
AL
VA
NC
VA
NC
135,000
160,000
95,000
212,000
80,000
90,000
175,000
125,000
200,000
42,000
75,000
325,000
250,000
35,000
70,000
35,000
48,000
1940
1945
1967
1940
1937
1946
1956
1937
1937
1937
1967
1967
1957
1946
1967
1967
1968
38.03
35.94
36.76
35.95
38.06
37.27
42.41
36.21
43.25
42.51
34.40
35.60
35.06
44.28
38.72
44.55
36.22
12 ACID PLANTS BUYING BYPRODUCT ACID AT $.50 AND $.70 BUT NOT AT $.35
11 Allied Chemical
40 Cities Service
53 Essex Chemical
56 Gardinier
62 W. R. Grace
74 Mobil Oil
77 Monsanto Company
83 Occidental Ag Chem
114 U.S. Industrial Chem
131 U.S. Industrial Chem
134 E. I. Dupont
136 USS Agri Chem
Hopewell
Augusta
Newark
Tampa
Bar tow
Depue
El Dorado
Plainview
Desoto
Tuscola
Linden
Wilmington
VA
GA
NJ
FL
FL
IL
AR
TX
KS
IL
NJ
NC
200,000
125,000
180,000
450,000
320,000
420,000
100 , 000
100,000
105,000
170,000
325,000
70,000
1965
1967
1956
1937
1960
1967
1960
1963
1940
1975
1937
1968
35.50
32.51
33.20
34.17
33.81
31.19
35.03
36.84
40.29
32.12
32.78
33.94
2 ACID PLANTS BUYING BYPRODUCT ACID AT $.70 BUT NOT AT $.35 OR $.50
18 American Cynamid
86 Olin Corporation
Savannah GA 216,000 1967
Baltimore MD 350,000 1941
29.80
32.48
111
-------
Additional Byproduct Acid Production and Sales to Acid Plants
Without Changing the Optimal Solutions in Each Model Run
Cents/MBtu Tons
0 1,283,000
35 706,565
50 668,623
70 632,282
The model could be refined to incorporate those additional quantities, but
the impact on validity of conclusions drawn from the study does not justify the
significant added cost. The capability to identify the supply points and
potential quantities as was done in the study is adequate.
SUPPLEMENTARY ANALYSIS
Summary of S02 Emissions Control Strategies to Meet Compliance
Table 42 summarizes the reduction in S02 emissions by each compliance
strategy for all of the 187 power plants that were projected to be out of
compliance in 1978. S02 control by clean fuel strategy accounts only for the
reduction required by SIP standards. Use of scrubbing technology reduces the
emissions further than that required by the regulations because the removal
efficiency and amount of gas treated cannot be practically matched with the
standard. A constant removal efficiency was assumed and gas volume was based
on increments of standardized-size scrubber modules. The column labeled
"excess removed by scrubbing" shows the total amount for both limestone and
MgO scrubbing.
Clean Fuel Demand Curve
The use of clean fuel as an alternative to scrubbing can be presented
graphically in the form of a demand curve. This demand curve is estimated by
plotting limestone scrubbing cost for all power plant boilers or combinations
of boilers from highest to lowest cost versus the reduction in emission
accumulated as shown in Figure 26. Scrubbing cost is presented in cents/MBtu
and is the maximum premium that can be paid for complying fuel.
At the upper end of the curve there are a few small power plants that only
exceed SIP requirements by a small amount yet the law requires compliance by
either an FGD system or the use of clean fuel. In this instance the power
plant can pay a very high premium for clean fuel as an alternative to scrubbing.
In the flat part of the curve the economies to scale associated with large
scrubber systems or large power plants burning medium- to high-S coal reduces
the unit cost of scrubbing to the point that a relatively lower premium can be
paid for clean fuel as an alternative to scrubbing. As the cost of clean fuel
112
-------
TABLE 42. 1978 STRATEGIES SELECTED FOR REDUCING EMISSIONS
(ktons/yr
ACFL,
cents/MBtu
OO
70
50
35
0
Total
by scrubbing
13,598
12,583
9,503
2,885
0
Amount
required
by SIP
9,912
9,211
6,788
1,919
0
By MgO
scrubbing
-
5,595
5,108
2,554
0
By limestone
scrubbing
-
6,988
4,394
330
0
By using
clean fuel
-
700
3,123
7,993
9,912
Total
reduction
-
13,284
12,627
10,878
9,912
Excess
removed
by scrubbing
-
3,371
2,714
965
0
-------
1234
REDUCTION IN SULFUR EMISSIONS, TONS xlO6
Figure 26. Clean fuel demand curve - all plants (1978).
114
-------
is reduced the more clean fuel is used in lieu of scrubbing. No scrubbin
would occur <$0.25/MBtu heat input based on the costs of technology used in
this study.
Power Plant Supply Curve Based on Incremental Cost for Production of
Abatement Acid
The incremental cost of production for power plants producing acid as
compared to limestone scrubbing in each of the ACFL model runs can be presented
in graphic form as a supply curve by plotting incremental cost from lowest to
highest versus the accumulating acid production for each increment. This is
presented in Figures 27, 28, and 29. The incremental cost represents the net
revenue required to justify production of acid. The average of the incremental
cost is calculated at $ll/ton for the $0.35 ACFL, $10.65/ton for the $0.50
ACFL, and $10.97/ton for the $0.70 ACFL.
Transportation Cost Analysis
The transportation cost analysis is outlined in the following tabulation:
ktons of H2S04
ACFL, Power U.S. Canadian Transport
cents/MBtu plants smelters smelters Total cost, $ $/ton
0
35
50
70
2,623
5,370
6,069
1,556
1,556
1,412
1,312
200
200
200
200
1,756
4,379
6,982
7,585
13,513
41,311
64,371
72,919
7.70
9.43
9.22
9.61
The data show that as the volume of acid increases the total costs of
transportation increases proportionately. The fairly constant unit cost of
transportation results from change in distribution pattern as additional
producers supply demand points with location advantages so that total costs
are minimized. This is illustrated by the fact that the demand points changed
for 16 out of 24 power plants in the $0.70/MBtu ACFL run as compared to the
$0.50/MBtu run, and only two additional demand points were needed for the five
additional power plant supply points.
Impact of Barge Transportation
Barge transport was utilized in the model to handle deliveries of molten
S from Gulf Coast to marketing terminals where truck or rail transport was
used to reach acid plants, but only rail transportation was used to distribute
abatement acid. Numerous power plants are located on navigable waterways.
Barge transport would be a viable option for shipping byproduct acid from these
plants. Barge transportation of acid could be included in the model. However,
rates are not standard and a major effort would be required to estimate
negotiated rates for all points.
115
-------
30
20
in
o
u
z
u
Z
UJ
DC
u
z
10
0.5 1.0 1.5 2.0 2.5
TONS OF SULFURIC ACID PRODUCED x I06
3.0
Figure 27. Abatement acid supply curve for $0.35 ACFL model run.
116
-------
z
o
I-
•N.
-w-
(O
o
o
z
Ul
z
Ul
cc
o
2468
TONS OF SULFURIC ACID PRODUCED x I06
10
Figure 28. Abatement acid supply curve for $0.50 ACFL model run.
11?
-------
80
o 60
-w-
O
0 40
UJ
2
UJ
K
S2 20
I
I
I
2 4 6 8 10
TONS OF SULFURIC ACID PRODUCED x 106
12
Figure 29. Abatement acid supply curve for $0.70 ACFL model run.
118
-------
An estimate of potential savings by barge shipments was prepared for three
candidates for MgO-acid scrubbing that are located on the inland waterway
system.
Rail and Barge Shipments from Power Plants to 42 Acid Plants
on the Inland Waterway System
FPC No.
4770003000
4770004100
4815000400
Location
Kentucky
Tennessee
Ohio
Tons shipped
628,358
572,320
254,355
Rate/ton
Average
Highest
Lowest
Average
Highest
Lowest
Average
Highest
Lowest
Rail, $
19.22
30.28
10.20
19.58
32.05
10.20
26.43
47.09
11.09
Barge, $
16.63
32.93
8.64
16.06
32.03
7.89
19.84
39.37
7.39
The potential savings for utilizing barge shipment in three model runs,
$0.35, $0.50, and $0.70/MBtu ACFL,are presented in Table 43.
The net reduction in transport cost resulting from barge transport for
each of the model runs is listed as follows:
ACFL, cents/MBtu
35 50 70
Reduced cost, $ 483,101 644,931 725,308
However, these results do not necessarily represent optimal solution of a
linear programing model, even for the three plants selected. If the model were
actually run with the barge transport option the optimum production and distri-
bution of abatement acid could change significantly. The only conclusion that
can be made in the absence of such a model run is that transportation costs
would be lower. Therefore, the potential savings to both industries would be
greater as compared to model solutions presented in this study.
Sensitivity of the S Price
One of the key inputs in the analysis of the potential market for abate-
ment byproduct acid is the price of elemental S. All of the results of this
study are based on S price of $60/ton f.o.b. Port Sulphur. A $20-00 dejreaw
the price of S lowers the avoidable cost of production for H2S04 at each
respective acid plant by $6.11/ton of acid produced. This ^£™wll as
structure would reduce the quantity of both byproduct smelter acid as well
119
-------
TABLE 43. COST REDUCTION BY BARGE SHIPMENT
FPC
number
Location At 35C/M ACFL
2. 4770003000 Kentucky
10 Allied Chemicals
3. 4770004100 Tennessee
16 American Cyanamid
4. 4815000400 Ohio
10 Allied Chemical
52 Eastman Kodak
Reduction
by barge
3.70/ton
0.26/ton
Tons
97,330
6,000
Reduced
cost
3.03/ton 37,670 114,140.00
0.28/ton 26,000 7,280.00
360,111.00
1,560.00
At 50C/M ACFL
2. 4770003000 Kentucky
96 Royster
3. 4770004100 Tennessee
126 American Cyanamid
4. 4815000400 Ohio
10 Allied Chemical
0.26/ton 134,350 34,931.00
2.21/ton 50,000 110,500.00
3.70/ton 135,000 499,500.00
At 70C/M ACFL
2. 4770003000 Kentucky
62 W. R. Grace
96 Royster
3. 4770004100 Tennessee
96 Royster
4. 4815000400 Ohio
10 Allied Chemical
0.26/ton
0.26/ton
239,600
141,250
62,296.00
36,725.00
0.69/ton 183,750 126,787.00
3.70/ton 135,000 499,500.00
120
-------
the abatement acid from power plants that can be marketed in fh«
estimate of the extent of reduction is shown in Table 44 TK moaei- An
plants and acid plants affected are presented in Appendii Q Spe°ltlc power
The estimates were based on manual calculations rather than a m i
model run because the $40 S price is arbitrary and was Selected onlv 7
the effect of price. The above analysis shows that the quantity of £°,
byproduct acid that could be sold in the existing m£^ u e edt
a significant amount. reauced
OTHER USES OF THE MODEL
The development of data bases and programs for use of the model to predict
byproduct market potential resulted in capability to perform other highly
relevant calculations.
Investment Costs
The scrubber cost generator may be used to estimate the investment of
alternative scrubbing systems for all existing and planned power plants. In
this study, costs were estimated for limestone, MgO, and Wellman-Lord/Allied
scrubbing systems for all plants projected to be out of compliance in 1978.
For use in the study, relativity of investment costs was the primary interest.
However, the input cost data could be refined to reflect special design
considerations for specific plants to improve the accuracy of estimates not
only for the plants included in this study but for the total current and
future population. This capability would be particularly helpful in evaluating
conversion from gas or oil to coal. Moreover, the alternative methods for
compliance could be expanded to include other scrubbing systems, coal cleaning,
production of clean fuels from coal, or other advanced technology for use of
coal.
An example of use of the model to estimate investment costs is shown
below in the cumulative total capital required for limestone scrubbing for the
187 plants considered in the study.
ACFL, Investment
cents/MBtu for scrubbing, $
oo 6,937,543,000
70 5,501,613,000
50 4,058,091,000
35 1,079,165,000
Operating Costs
The scrubber cost generator can also be used to estimate operating costs
with the same degree of flexibility as discussed in the investment cost
description. For this study, only the first year operating costs were
estimated for the three scrubbing methods at each plant out of compliance. If
121
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TABLE 44. EFFECT OF $20 REDUCTION IN S PRICE
ON SUPPLY AND DEMAND FOR BYPRODUCT ACID
Reductions
At 35C clean
Supply: 2
4
Demand : 6
At 50c clean
Supply : 6
2
Demand : 10
At 70c clean
Supply: 8
2
Demand: 10
fuel alternative
power plants
smelters
acid plants
fuel alternatives
power plants
smelters
acid plants
fuel level
power plants
smelters
acid plants
Tons of acid
246,311
437,000
Total 683,000
683,000
639,722
498,000
Total 1,137,722
1,137,722
939,163
417,000
Total 1,356,163
1,356,163
122
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the projected load factors over the life of the power plants were available
the lifetime operating costs could be developed. This information is necessarv
to estimate revenue requirements from present worth costs to cover the
additional cost of operation, including amortization of investment. A major
revision of the model would be required to estimate revenue requirements
However, a program in Fortran language is available from another study.
The estimated total first year operating costs for use of limestone
scrubbing and clean fuel at the 187 plants defined earlier is as follows:
ACFL,
cents /MI
oo
70
50
35
Operating cost, $
5tu Scrubbing
2,886,245,000
2,037,721,000
1,513,241,000
406,877,000
Clean fuel
0
267,351,000
636,280,000
1,225,907,000
Total
2,886,245,000
2,305,072,000
2,149,521,000
1,632,784,000
Use of clean fuel at some of the plants compared to scrubbing at all
plants results in savings to the utility industry of:
ACFL,
cents/MBtu Savings, $
70 561,172,000
50 716,723,000
35 1,233,461,000
Change in Regulations
The procedure for evaluating compliance status based on applicable
standards and FPC projection of fuel characteristics may be used to estimate
the effect of changing emission standards on the cost of compliance. This
study was based on the SIP regulations that were in effect as of June 1976.
The program would be useful in evaluating the cost use benefit of alternative
standards, provided that valid information could be developed for projecting
costs for these processes at various S02 removal efficiencies. Also,
information is needed on economic effect of various emission rates.
Evaluation of Other Abatement Products
The model can be modified to include byproducts other than S and H2S04
and to evaluate potential for restructuring end use markets to take into
account location advantages.
Use of Transportation Model
The transportation model that was developed to distribute byproduct acid
from supply points to areas of use is a sophisticated program that *as
potential for extensive use. The model calculates actual rate-base mileage
123
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between any two points on the established railway network. For this study,
tariffs were incorporated for 1^804 movements. Available tariffs for any other
commodity could be incorporated to calculate actual transportation costs
between any two points. The model can be used to estimate cost of rail ship-
ments for any of the materials that may be needed in compliance programs
including coal, raw materials for scrubbing systems, byproducts for disposal
or use, clean fuels derived from coal, and equipment. Usefulness of the model
in other areas of the industrial community is obvious.
Truck and barge transportation costs are not as easily defined as rail
shipments but meaningful approximation could be developed to extend the
capability of the model. A significant amount of work would be necessary.
Social Cost Consideration
An important conceptual use of the marketing model is shown in Figure 30.
This figure is the classical presentation of economic benefit to consumers of
a product (consumer surplus) and the benefit to the producer (producer surplus).
The use of the term surplus indicates that the action represented results in a
reduction in resources required to match the supply with the demand. The
combined economic benefit is defined as net social gain. The area under the
demand curve DD' out to supply quantity Q (DRQS) is the total gain to consumers
(acid plants) from the purchase of Q tons of l^SO^. (It should be recognized
that marketers cannot give preferential treatment to certain customers because
of antitrust laws; therefore, in the optimum solution, all customers pay the
same price for abatement acid.) Consumers pay a total of P $/ton for Q tons
that results in a total cost represented by the rectangle (PSQR). Similarly
this same total revenue pays for producing acid at the power plants where the
total cost for production is the area (RSQ) below the supply curve SS' out to
supply quantity Q. Consumer surplus is the indicated area (DPR). Producer
surplus is the area below P and above the supply curve as indicated (PRS). At
equilibrium the most marginal consumer and producer neither gain nor lose, but
all others in the solution have an economic advantage; net social gain is the
total savings by both. Methodology used in this study does not address
division of net social gain between producer and consumer. It is assumed this
will be determined in the market place.
The above theory can be related to results of the study. The linear
programing model summarized the least-cost solutions associated with each
model run. The results are outlined in Table 45 entitled "Total Cost of Acid
Production for Model Runs." The reduction in total cost of acid is the net
social gain that results from productive use of abatement byproduct acid in
the existing market. Distribution of the savings between the utility industry
and the acid industry will depend on negotiations between the two.
124
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0
o
o
a:
(O
UL
O
Ul
O
QL
Q.
CONSUMER SURPLUS
PRODUCER
SURPLUS '
QUANTITY OF SULFURIC ACID
Figure 30. Conceptual demand curve for I^S
curve for abatement production.
and supply
125
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TABLE 45. TOTAL COST OF ACID PRODUCTION FOR MODEL RUNS
ACFL, cents/MBtu
Acid industry cost, $ 35 50 70
Acid from S 965,377,000 965,377,000 965,377,000
Byproduct acid + acid
from S 885,043,000 846,421,000 842,500,000
Reduction in cost of acid 80,335,000 118,956,000 122,887,000
Tons of acid utilized
Total from steam plants
Total from smelters
$/ton saving
4,379,000
2,623,000
1,756,000
18.34
6,982,000
5,370,000
1,612,000
17.04
7,585,000
6,069,000
1,516,000
16.20
CONCLUSIONS
The overall objective of the study, to identify potential markets for
abatement byproducts from electric utility FGD systems,was accomplished. In
the conduct of the study, a large volume of useful data was assembled and
procedures were developed for use of the information in the market studies and
in related work.
The entire U.S. electric utility industry was characterized from FPC data
with respect to fuel type, capacity, load factors, and SQ2 emission rates.
Out of a total of 3,382 generating units at 800 power stations, 833 boilers at
187 power stations were projected to be out of compliance with current appli-
cable emissions regulations in 1978. The total S02 emissions from these 187
plants was equivalent to 17.5 Mtons of 1^304; total H2S04 consumption in the
U.S. was estimated to be 32.2 Mtons in 1978. Therefore, the total market is
nearly twice the potential byproduct production.
A market simulation model was developed to estimate:
1. Potential quantity of byproduct resulting from recovery being the
least-cost compliance method
2. Quantity of byproduct could be sold in a competitive market
environment
3. Best power plant candidates for production
4. Most likely consumption points
Through use of a scrubber cost generating model, it was determined that lime-
stone scrubbing is generally the least-cost scrubbing method when credit for
byproduct sales is not included and when credit is applied, production of
126
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byproducts becomes competitive. Costs for production of S bv rh<> n IT
Allied process were higher in all cases studied than production of J so"
Projected savings in distribution costs for S compared to H,SO, did not^h-
set the incremental production costs. Costs for use of the Wellman-Lon'/AH- A
technology will be more clearly defined during the current full-scale d
stration, partially funded by EPA, at the Mitchell Station of the Northern""
Indiana Public Service Company. Revised information will be included in the
model. Also, EPA is currently sponsoring work with ESEERCO and Niagara Mohawk
to develop the Atomics International process for producing S from SO? in stack
gas. This technology and other work involving use of solid reductants could
lead to lower costs for production of S as an alternative to producing H2SOA
Several factors that are difficult to incorporate into a generalized economic
model could have a significant influence on the choice of byproducts. The
incentive for production of S is high because it is a safe, noncorrosive,
convenient material to handle, and can be easily stockpiled for long periods
of time at relatively low cost. Because of the latter advantage, S could be
incorporated more easily into the existing market. Moreover, fluctuations
in market demand could be met with less impact to both the producer and con-
sumer. It is likely that a mix of marketable byproducts will ultimately
provide the least cost compliance with S02 regulations in the utility
industry. Technology for production of S should be fully developed so that
the choice is available and so that accurate information is available for
cost comparisons with other methods of control.
An alternative to use of scrubbing was provided by comparing the cost
of scrubbing with selected values of premium cost of complying fuel. When
the clean fuel premium was set at $0.70/MBtu, the mix of least-cost compliance
methods was:
Purchase complying fuel 71 plants
Use limestone scrubbing 87 plants
Produce byproduct acid 29 plants
The amount of acid produced and marketed totaled approximately 5.6 Mtons; an
additional 5 Mtons could have been produced at a lower cost than the alter-
native compliance method selected but could not be sold in competition with
acid produced from elemental S priced at $60/ton. The simulation model was
designed to allow the nonferrous smelter industry to compete with the utility
industry for byproduct markets. The total byproduct acid supplied from both
industries was 7.11 Mtons or 22% of the total ^804 market.
Power plants that were the best candidates for production of byproduct
acid were generally bigger, newer plants with high load factors. The dis-
tinctive characteristics were:
1. Most boilers <10 yr old
2. Average size about 600 MW (<15% smaller than 200 MW)
3. Average capacity factor about 60%
The average load factor for potential acid-producing plants was more than
three times as high as the average of all plants considered.
When the clean fuel premium was set at $0.50 /MBtu .the amount of acid
supplied by the utility industry was reduced to 5A Mtons ^ acid
elemental S was reduced from $60 to S40/ton, tne amount uj yv
could be sold to replace production from existing conventional sources was
reduced from 5.6 to 4.2 Mtons.
127
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Abatement acid produced in the model run from the utility industry at the
$0.70/MBtu clean fuel premium was distributed to 55 different demand points in
23 states. The current supply that was replaced by byproduct acid was
generally from smaller, older plants remotely located from the elemental S
production points. The larger, more efficient plants generally can produce acid
at costs lower than the delivered cost of abatement byproducts. However, there
are exceptions. Savings in transportation cost because of location advantage
can offset production cost differential.
The model assumed distribution of byproduct acid by rail shipment. Several
of the potential producers are located on navigable waterways and could use
barge transportation. As an example of possible savings on shipment costs,
estimates were made for barge shipments of selected production totaling 700,000
tons. The cost differential between rail and barge transportation totaled
$725,000 or about $l/ton of acid. This potential savings is 11% of the average
transport cost.
The results of the study show that a significant amount of byproduct acid
produced by the utility industry could be incorporated in an orderly manner
into existing ^804 markets. The control of S02 emissions in the utility
industry through use of recovery technology could contribute 56% of the
estimated total reduction needed for the industry to be in compliance. Further
use of recovery technology will depend primarily on substantial increases in
elemental S prices which are difficult to predict. Reduction in the cost of
control technology would also increase the potential for increased production
of byproducts, but the costs are not likely to improve significantly. The
costs may be understated in this study because a 1975 basis (escalated to 1978)
was used for the investment and operating cost estimates. Reduction in
transportation costs is a more realistic possibility for improving economics of
marketing byproduct acid. Higher levels of clean fuel premium would not affect
the results since the acid supply at the maximum value studied exceeded the
demand. It should be emphasized that some of the plants that are good
candidates for use of recovery technology may be implementing other compliance
plans.
The development of data bases and programs for use of the model to predict
byproduct market potential resulted in capability to perform other highly
relevant calculations.
The scrubber cost generator may be used to estimate the investment of
alternative scrubbing systems for all existing and planned power plants. In
this study, costs were estimated for limestone, MgO, and sodium sulfite
scrubbing systems for all plants projected to be out of compliance in 1978.
For use in the study, relativity of investment costs was the primary interest.
However, the input cost data could be refined to reflect special design
considerations for specific plants to improve the accuracy of estimates not
only for the plants included in this study but for the total current and
future population. This capability would be particularly helpful in evaluating
conversion from gas or oil to coal. Moreover, the alternative methods for
compliance could be expanded to include other scrubbing systems, coal cleaning,
production of clean fuels from coal, or other advanced technology for use of
coal.
128
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The scrubber cost generator can also be used to estimate operating
with the same degree of flexibility as discussed in the investment cost
description. For this study, only the first year operating costs were
for the three scrubbing methods at each plant out of compliance if the
projected load factors over the life of the power plants were available the
lifetime operating costs could be developed. This information is necessary to
estimate revenue requirements from present worth costs to cover the additional
cost of operation, including amortization of investment. A major revision of
the model would be required to estimate revenue requirements.
The procedure for evaluating compliance status based on applicable
standards and FPC projection of fuel characteristics may be used to estimate
the effect of changing emission standards on the cost of compliance. This
study was based on the SIP regulations that were in effect as of June 1976.
The program would be useful in evaluating the cost to benefit ratio of alternative
standards, provided that valid information could be developed for projecting
costs for these processes at various S02 removal efficiencies. Also, in-
formation is needed on economic effect of various emission rates.
The model can be modified to include byproducts other than S and H2S04
and to evaluate potential for restructuring end use markets to take into
account location advantages.
The transportation model that was developed to distribute byproduct acid
from supply points to areas of use is a sophisticated program that has potential
for extensive use. The model calculates actual, legal mileage between any two
points on the established railway network. For this study, tariffs were
incorporated for H2SOA movements. Available tariffs for any other commodity
could be incorporated to calculate actual transportation costs between any two
points. The model can be used to estimate cost of rail shipments for any of
the materials that may be needed in compliance programs including coal, raw
materials for scrubbing systems, byproducts for disposal or use, clean fuels
derived from coal, and equipment. Usefulness of the model in other areas of
the industrial community is obvious.
An important finding was that while long-run competitive equilibrium
solutions predict what may happen in competitive markets they do not identify
net social gain. The linear programing model solutions present a running
account of minimum cost solutions associated with each model run for both
industries. The savings to both industries at the $0.70/MBtu clean fuel
premium run resulting from absorption of abatement byproduct acid in the
existing market amounted to $122,877,000 or $l6.20/ton of acid utilized.
RECOMMENDATIONS
Information on current compliance programs for existing power plants and
for additional planned capacity was not available during the period of this
study. The results of the work show that the potential for use of «covery
technology is good and the initial follow-on work should focus ™J%£»
where compliance alternatives are still flexible. A survey of =«P^J w
Plans should be carried out and the option of producing byproduct acid should
129
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be evaluated by incorporating specific information on those plants into the
program data base. This evaluation would be particularly helpful in the
planning process for future coal-fired power plants or for those that may be
required to convert from gas or oil to coal.
In order for the program to remain meaningful, the data bases will have
to be updated periodically. The period should be keyed to the annual FPC
report on the utility industry. Investment and operating cost data on
alternative FGD technology should be refined to permit more accurate estimation
of emission control cost for specific plants and for the overall power industry.
Use of the simulation models and the associated data bases is presently
limited to TVA personnel familiar with the complex program. The program is
being documented and included along with procedures in a users manual that,
as a minimum, will define the capability of the system. If the demand for
use of any part of the program justifies the expense, the files can be
maintained online so that qualified users can access the system through time-
sharing facilities.
An extension of the program is planned, subject to availability of funds,
to evaluate effect of product end use pattern on market potential for by-
products. For example, availability of byproduct H2S04 in the Midwest could
favor production of fertilizer materials near the point of use rather than
near the location of traditional raw materials.
130
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REFERENCES
1. Pearse, G. H. K. Sulphur-Economics and New Uses. Presented at the
Canadian Sulfur Symposium, May 30-June 1, 1974. Industrial Mineral
Section, Minerals and Metals Division, Energy Mines and Resources
Canada, Ottawa, Ontario. '
2. Federal Power Commission. Steam-Electric Plant Air and Water Quality
Control Data, for the year ended December 31, 1973, based on FPC Form
No. 67, FPC S-253, January 1976. 184 pp.
3. U.S. Department of Interior, Bureau of Mines. Sulfur in 1976. Mineral
Industry Surveys, June 13, 1977. 17 pp.
4. Waitzman, D. A., J. L. Nevins, and G. A. Slappey. Marketing H2S04 from
S02 Abatement Sources — The TVA Hypothesis. (TVA Bull. Y-71; EPA-650/2-
73-051), NTIS PB 231 671, December 1973. 100 pp.
5. Corrigan, P. A. Preliminary Feasibility Study of Calcium- Sulfur Sludge
Utilization in the Wallboard Industry. TVA report S-466 (prepared for
EPA), June 21, 1974. 66 pp.
6. Bucy, J. I., J. L. Nevins, P. A. Corrigan, and A. G. Melicks. The
Potential Abatement Production and Marketing of Byproduct Elemental
Sulfur and Sulfuric Acid in the United States. TVA report S-469 (pre-
pared for EPA), March 1976. 100 pp.
7. McGlamery, G. G. , et al. Detailed Cost Estimates for Advanced Effluent
Desulfurization Processes. (TVA Bull. Y-90; EPA-600/2-75-006) , NTIS PB
242 541/1WP, January 1975. 418 pp.
8. U.S. Department of Interior, Bureau of Mines. Sulfur. A Chapter from
Mineral Facts and Problems, 1975 Edition. Preprint from Bull. 667. 22 pp.
9. Nelson, C. P. A Look at Sulphur - Today and Tomorrow. Paper presented at
Chemical Market Research Association Meeting, New York, March 1977.
10. Hazelton, Jared E. Economics of the Sulfur Industry. Resources for the
Future, Inc., Washington, D.C., 1970.
11. Horseman, M. N. J. World Sulphur Supply and Demand, 1960-1980. Document
ID/76. United Nations, New York, 1973. 165 pp.
12. Hicks, G. C., et al. Technical and Economic Evaluation of
Intermediates for Use by Developing Countries. TVA Bull. Y-3 (prepared
for AID), 1970. 54 pp.
13. U.S. Department of Commerce, Bureau of the Census. Sulfuric Acid - 1976.
Series M28A(76)-14, Supplement 1, June 1977.
Current Industrial Reports. Series M28A(76)
7 pp.
131
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14. Harre, E. A. Records of the Economics Market Research Section, Division
of Agricultural Development, Tennessee Valley Authority, Muscle Shoals,
Alabama. TVA World Fertilizer Production Capacities (from Computer Data
File), 1975.
15. Eckert, G. F., Jr. Sulphur-Brimstone Demand Quickened in '76. Eng.
Mining J., 178(3):118-120, 122, March 1977.
16. Harre, E. A. The Supply Outlook for Phosphate Fertilizers. TVA Bull.
Y-96. In: Proceedings of the TVA Fertilizer Conference, Louisville,
Kentucky, July 29-31, 1975. pp. 36-44.
17. U.S. Department of Agriculture, Crop Reporting Board of the Statistical
Reporting Service. Commercial Fertilizers, Final Consumption for Year
Ended June 30, 1976. SpCr 7(77), April 1977. 30 pp.
18. U.S. Department of Agriculture, Statistical Reporting Service. Fertilizer
Used on Selected Crops in Selected States, 1971. February 9, 1972. 4 pp.
19. Harre, E. A. What's Ahead in Fertilizer Supply-Demand. TVA Bull. Y-106.
In: Proceedings of the TVA Fertilizer Conference, Cincinnati, Ohio,
July 27-28, 1976. p. 18.
20. Williams, G. G., J. R. Douglas, and E. A. Harre. Fertilizer Oversupply—
Not for Long. In: Proceedings of the 10th Hawaii Fertilizer Conference,
Honolulu, April 25, 1977. Cooperative Extension Service, University of
Hawaii (Misc. publication No. 146).
21. Bixby, D. W. Sulfur Requirements of the Phosphate Fertilizer Industry.
The Role of Phosphorus in Agriculture, Soil Science Society of America,
Madison, Wisconsin, 1978. (In press)
22. U.S. Department of Commerce, Bureau of the Census. Inorganic Fertilizer
Materials and Related Products - December 1976. Current Industrial
Reports. Series M28B(76)-12, February 1977. 6 pp.
23. U.S. Department of Commerce, Bureau of the Census. U.S. Exports:
Schedule B Commodity by Country. Report No. FT 410/December 1976.
April 1977. 603 pp.
24. Harre, E. A., M. N. Goodson, and J. D. Bridges. Fertilizer Trends - 1976.
TVA Bull. Y-lll. Tennessee Valley Authority, Muscle Shoals, Alabama,
March 1977. 43 pp.
25. Chemical Marketing Reporter, 207(13):40, March 31, 1975.
26. Crenshaw, J. D., et al. State Implementation Plan Emission Regulations
for Sulfur Oxides: Fuel Combustion. (EPA-450/2-76-002) NTIS PB 251 174,
March 1976. 74 pp.
27. Federal Power Commission. Steam-Electric Plant Construction Cost and
Annual Production Expenses. Twenty-Sixth Annual Supplement-1973, FPC
S-250. 185 pp.
132
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APPENDIX A
BASIC SYSTEM FLOW DIAGRAM
CONTENTS
Figures Page
w -S£
A-l Flow diagram for major system design requirements 134
A-2 Supply subsystem 135
A-3 Transportation subsystem 136
A-4 Demand subsystem 137
i ^ft
A-5 Linear programing model subsystem •L->0
133
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BYPRODUCT MARKETING MODEL
BASIC SYSTEM
SUPPLY
DATA BASE
POWER PLANTS,
REGULATIONS,
COST ESTIMATES
TRANSPORTATION
DATA BASE
TARIFFS
RAIL MILEAGE
BARGE MILEAGE
DEMAND
DATA BASE
ACID
PLANTS
SCRUBBING
COST
GENERATOR
TRANSPORTATION
COST
GENERATOR
ACID PRODUCTION
COST
GENERATOR
MARKET SIMULATION
LINEAR
PROGRAMMING
MODEL
EQUILIBRIUM
SOLUTION
RESULTS
Figure A-l. Flow diagram for major system design requirements.
134
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FPC
NEW PLANT
PROJECTIONS
FOR
1978
FPC
FORM 67
DESIGN
DATA
EPA
ENERGY
DATA
SYSTEMS
DATA BASE
OPERATIONAL
COMPLIANCE
DATA
SYSTEMS
DATA
BASE
SUPPLY
SUBSYSTEM
DATA
BASE
GEOGRAPHIC
U.S. BUREAU
OF MINES
SPECIAL REPORT
PEDCO
REPORTS
ENGINEERING
COST
ESTIMATES
COST FACTORS
AND PARAMETERS
ALL SUPPLY
DATA PROJECTED
TO
1978
INTERACTIVE
TERMINAL
INQUIRIES
AND
ANALYSIS
SCRUBBING
COST
GENERATOR
Figure A-2. Supply subsystem.
135
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DOCKET
28300
CENTRE
GEOGRAPHIC
DATA
SUPPLY
POINTS
TRANSPORTATION
DATA BASE
BARGE
TRANSPORTATION
DATA
DEMAND
POINTS
INTERACTIVE
TERMINAL
INQUIRIES
AND
ANALYSIS
TRANSPORTATION
COST
GENERATOR
TRUCK POINTS
LATITUDES
LONGITUDES
STANDARD POINT
LOCATOR CODES
PIPS CODES
INLAND WATERWAY
RATES
DEEP WATER RATES
FOR COASTAL
LOCATIONS
TERMINALS ON
WATERWAYS
Figure A-3. Transportation subsystem.
136
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TVA
WORLDWIDE
FERTILIZER
RELATED
DATA
BASE
COMPLIANCE
DATA
SYSTEMS
DATA
BASE
CENTRE
GEOGRAPHIC
DATA
SULFUR
TRANSPORTATION
DATA
DEMAND
SUBSYSTEM
DATA
BASE
SULFUR
TERMINALS
STANFORD
RESEARCH
INSTITUTE
REPORTS
PRODUCTION
COST FACTORS
AND PARAMETERS
INTERACTIVE
TERMINAL
INQUIRIES
AND
ANALYSIS
NATIONAL
EMISSIONS
DATA
SYSTEMS
DATA
BASE
DEMAND DATA
PROJECTED TO
1978
ACID PRODUCTION
COST
GENERATOR
Figure A-4. Demand subsystem.
137
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I SUPPLY
DATA AND
COSTS
TRANSPORTATION
DATA AND
COSTS
DEMAND
DATA AND
COSTS
INTERACTIVE
TERMINAL
INQUIRIES
AND
ANALYSIS
LINEAR PROGRAMMING MODEL
ru
REPORTS OF
LINEAR
PROGRAMMING
SOLUTIONS
AND RESULTS
LINEAR PROGRAMMING
SOLUTIONS AND RESULTS
FOR COMPUTER ANALYSIS
Figure A-5. Linear programming model subsystem.
138
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APPENDIX B
A MATHEMATICAL STATEMENT OF MODEL
139
-------
APPENDIX B
A MATHEMATICAL STATEMENT OF MODEL
CURRENT MATHEMATICAL MODEL
Demand Sector
i = 1, 2, . . . , n demand point numbers
C^ = Avoidable cost at demand point i per ton of byproduct
D^ = The quantity of byproduct which demand point i would purchase
at price C^ or less
Utility Sector
j = 1, 2, . . . , m utility supply point numbers
CB. = Average cost per ton of byproduct for producing at utility
supply point j to meet SIP compliance
CL-: = Average cost in cents/MBtu of producing and disposing of
limestone slurry at utility j to meet SIP compliance
CF.: = Average cost in cents/MBtu of using the best clean fuel
alternative to bring utility j into compliance with SIP
BTU. = The number of Btu input that would have to be scrubbed or
cleaned to bring utility into compliance with SIP
s.: = Tons of byproduct produced per Btu input that would have to
be scrubbed to bring utility j into compliance with SIP
CA-: = Average cost per ton of byproduct for the best alternative
to byproduct production and marketing
= Sj * MIN (CLj, CFj), if out of compliance
= 0, if within compliance
S.: = Tons of byproduct produced to bring utility j into
compliance with SIP
= Sj * BTUj (j = 1, 2, . . . , m)
140
-------
Society
J. = Cost per ton of byproduct incurred by either the demand or
supply sector in transferring a. unit of byproduct from
utility j to demand point i
j-
= Tons of byproduct transferred from utility j to demand point i
fj_ = Tons of byproduct used by demand point i from current source
of supply
TSC = Total social cost or total cost of implementing the
Clean Air Act to both the utility and demand sectors.
m
ZCA.S. 4- MIN J
3 1 (x j
j = 1 1J
Z cixi«
m
n
i = 1
+ ^ V* (CB.-CA. + T. .)
L, L, 3 j ij
j = 1 i = 1
subject to:
m
X
j = 1
n
Xij ^ Sj
i = 1
X. . > 0
—
= L 2, . . ., ro)
(i = 0, 1, 2, . . . , n)
(j = 1, 2, . . . , m)
141
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APPENDIX C
THE END-USE INPUT REQUIREMENTS FOR S AND H2S04
CONTENTS
Table Page
C-l Tons of Elemental S or Equivalent l^SO^ Required in
Manufacture of One Ton of Indicated Product .......... 144
143
-------
TABLE C-l. TONS OF ELEMENTAL S OR EQUIVALENT H2S04 REQUIRED IN
MANUFACTURE OF ONE TON OF INDICATED PRODUCT
Short
Tons of Sulfur
or Equivalent Equivalent
Sulfur Per Ton Tons
Product of Producta of
Fertilizers
Diammonium phosphate (DAP) 18-46-0 Grade 0.443b 1.355
Granular triple superphosphate (GTSP) 0-46-0 grade 0.311b 0.951
P205 in 547. ?2°5 wet phosphoric acid 0.943b 2.885
Wet phosphoric acid (547« P205) 0.509b 1.557
Granulated ammonium polyphosphate (CAPP) 12-57-0 0.538b 1.646
Normal superphosphate (NSP) 0-20-0 grade 0.121 0.370
Liquid fertilizer 11-37-0 grade 0.646b 1.976
Sulfuric acid, 100% 0.338C 1.000
Synthetic fiber intermediates
Hydrogen cyanide (Modacrylic fiber) 0.081 0.248
Caprolactan (Nylon 6 fiber) 1.019d 3.117
Acetate rayon (fibers, photographic film, etc.) 0.034 0.104
Synthetic rubber (SBR) 0.005 0.015
Vulcanized synthetic rubber (SBR) 0.012 0.037
Carbon disulfide (fibers, cellophane, other chemicals) 0.936 2.863
Paper pulp 0.109 0.333
Indigo dye 0.297 0.909
Pheno-fonnaldehyde plastic moulding compound 0.0003 0.001
Phenol by sulfonation (plastics) 0.441 1.349
Explosives
Nitrocellulose 0.169 0.517
Black powder 0.100 0.306
Nitroglycerine 0.014 0.043
Lithopone paint pigment 0.105 0.321
Leather tanning
Vegetable tan 0.007 0.021
Chrome tan 0.076 0.232
Bordeau mixture (4-4-50) (fungicide) 0.002 0.006
Treflan (10070) (Herbicide) 0.420 1.285
Alum, 177o A^OS (water treatment chemical) 0.150 0.459
Sodium dichromate (tanning, dyeing, paint pigments, etc) 0.142 0.434
Uranium 235 18.090 55.341
Sodium sulfate (1007o) 0.226e 0.691
Ammonium sulfate (1007°) 0.243f 0.743
All values are from Shreve, R.N. Chemical Process Industries 3rd Edition,
McGraw-Hill Book Company, New York, 1967, unless otherwise noted.
Unpublished TVA data.
cAverage of several published values.
dAnon. Chemical Week, June 26, 1974, p. 41.
eAssuming direct neutralization of sulfuric acid with sodium hydroxide
with no losses.
^Assuming direct neutralization of sulfuric acid with ammonium hydroxide
with no losses.
144
-------
APPENDIX D
FRASCH S PRODUCTION
CONTENTS
Tables ' Page
D-l Frasch S Production - Effect of Natural Gas Cost on
Production Cost of Frasch S for Various Plant Heating
Water Capacities 148
D-2 Frasch S Production - Effect of Plant Heating Water
Capacity on Total Capital Investment 149
D-3 Frasch S Production - Effect of Natural Gas Cost on
Operating Cost for Various Water Rates 150
145
-------
APPENDIX D
FRASCH S PRODUCTION
TECHNOLOGY
Wells which vary in depth from 200-2000 ft are sunk into a S dome using
a method similar to that of sinking oil wells. The most economical way to
get S out of the dome formation is to melt it and pump it out. This involves
the use of superheated water at 330°F which is pumped into the dome.
The well consists of three concentric pipes and a casing. Inside the
casing an 8-in. pipe is sunk through the cap rock over the dome to the bottom
of the S deposit. Its lower end is perforated. A 4-in. pipe is lowered to
within a short distance of the bottom. Last and innermost is a 1-in. pipe
for compressed air reaching more than halfway to the bottom of the well. The
superheated water is forced down the space between the 8- and 4-in. pipes and
out into the S-bearing formation where it melts the S. The molten S collects
at the bottom of the well where the pressure of the water forces it part of
the way up the 4-in. pipe. The compressed air from the 1-in. pipe aerates
and lightens the liquid S so that it will rise the rest of the way to the
surface.
Once on the surface the hot, yellow S is pumped to a relay station for
air removal and then either to heated tanks for storage in liquid form or to
vats where it cools and solidifies. At this point, it is ready for marketing.
ECONOMICS
The primary information source for S mining economics is Jared E.
Hazleton's The Economics of the Sulfur Industry, published by Resources for
the Future, The John Hopkins Press, Baltimore and London, 1970. Investment
costs given by Hazleton were updated to the third quarter of 1974 and mid-
1978, as were the costs of labor, supervision, and utilities. The costs
given exclude loading, royalties, and severance taxes. They also exclude all
costs of exploration and development. They do include the drilling of new
production wells since, on the average, one well will only produce for
approximately 1 yr and will mine S from about 1/2 acre of a S dome.
The cost of mining Frasch S is very dependent upon the hot water rate
associated with each mine, where the water rate is defined as the number of
gallons required to produce 1 ton of S. The water rate varies drastically
frcm mine to mine because, of the widely divergent geological nature of S-
containing salt domes (mines). Since the water is usually heated with
natural gas, mining costs are very sensitive to the price of natural gas.
146
-------
Within the framework of the third quarter 1974 estimates, the cost of natural
gas was varied from $0.20-$3.00/kft3 with an intermediate value of $1.00/kft3.
The $0.20/f t3 rate is typical of existing contracts for old gas, the $1.00
rate is about that presently being paid under more recent contracts, and the
$3.00 figure is a projected rate. For the mid-1978 estimates, the cost of
natural gas was pegged at $2.50/kft3.
DISCUSSION OF RESULTS
Using a constant water per ton of S rate of 1,600 gal, total heating
water rates were varied for S production rates of 218,750, 875,000, and
1,750,000 long tons (LT)/yr. Costs were also estimated for a production rate
of 350,000 LT/yr of S at a water rate of 4,000 gal of water per ton S, and
a production rate of 155,400 LT/yr of S at a water rate of 9,000 gal of water
per ton of S with a constant total heating water rate of 4 Mgal/day for both
cases. It is felt that these ranges adequately represent the various Frasch
S mining operations in the U.S. now and in the foreseeable future.
From the data in Table D-l, it can be seen that for mines with identical
water rates (1600 gal/LT) the unit operating cost for the third quarter of
1974 for mining Frasch S decreases with increased mining rates and, of course,
plant size. At a natural gas price of $1.00/kft^, the unit cost decreases
from $18.19/LT at a production rate of 218,750 LT/yr to $11.47/LT at a produc-
tion rate of 1,750,000 LT/yr. Similar reductions are shown for mid-1978 costs.
The marked sensitivity of operating costs to the price of natural gas is also
shown in Table D-l.
The effect of plant heating water capacity and plant capacity upon total
capital investment is shown in Table D-2, where the investment required per
long ton per year decreases from $24.69 at a production rate of 218,750 LT/yr
to $14.81 at a production rate of 1,750,000 LT/yr for third quarter 1974 costs.
In Table D-3 the effect of water rate and price of natural gas on cost
of production for a mine having a capacity of 4 Mgal of water per day is
given. These data show that as the water rate increases from 1600 to 9000
gal/LT at a natural gas cost of $1.00/kft3, the operating cost for the third
quarter of 1974 increases from $12.71 to $71.57/LT. Similar increases are
shown for mid-1978 costs.
147
-------
TABLE D-l. FRASCH S PRODUCTION -
EFFECT OF NATURAL GAS COST ON PRODUCTION COST OF
FRASCH S FOR VARIOUS PLANT HEATING WATER CAPACITIES
(Water rate: 1600 gal/LT S)
S production Plant capacity, Operating cost,
rate, LT/yr gal of water/day $/LT of S
Third Quarter 1974 Costs
Natural Gas Cost: $0.20/kft3
218,750
875,000
1,750,000
1,000,000
4,000,000
8,000,000
13.68
8.25
7.05
Natural Gas Cost: $1.00/kft3
218,750
875,000
1,750,000
1,000,000
4,000,000
8,000,000
18.19
12.71
11.47
Natural Gas Cost; $3.00/kft3
218,750
875,000
1,750,000
1,000,000
4,000,000
8,000,000
29.45
23.86
22.51
Mid-1978 Costs
Natural Gas Cost: $2.50/kft3
218,750
875,000
1,750,000
1,000,000
4,000,000
8,000,000
30.04
23.07
21.42
148
-------
TABLE D-2. FRASCH S PRODUCTION -
EFFECT OF PLANT HEATING WATER CAPACITY ON TOTAL CAPITAL INVESTMENT
(Water rate: 1600 gal/LT S)
S production Plant capacity, Total capital Capital invest-
rate, LT/yr gal of water/day investment, $ ment, $/LT/yr
Third Quarter 1974 Costs
218,750 1,000,000 5,400,000 24.69
875,000 4,000,000 16,992,000 19.42
1,750,000 8,000,000 25,920,000 14.81
Mid-1978 Costs
218,750 1,000,000 6,939,000 31.72
875,000 4,000,000 21,835,000 24.95
1,750,000 8,000,000 33,307,000 19.03
149
-------
TABLE D-3. FRASCH S PRODUCTION -
EFFECT OF NATURAL GAS COST ON OPERATING COST
FOR VARIOUS WATER RATES
(Plant heating water capacity: 4 Mgal/day)
Water rate, S production Operating cost,
gal/LT rate, LT/yr $/LT
Third Quarter 1974 Costs
Natural Gas Cost: $0.20/kft3
1,600
4,000
9,000
875,000
350,000
155,400
1,500
4,000
9,000
875,000
350,000
155,400
8.25
20.64
46.44
Natural Gas Cost: $1.00/kft3
12.71
31.82
71.57
Natural Gas Cost: $3.00/kft3
1,600
4,000
9,000
875,000
350,000
155,400
23.86
59.76
134.41
Mid-1978 Costs
Natural Gas Cost: $2.50/kft3
1,600
4,000
9,000
875,000
350,000
155,400
23.07
57.78
129.97
150
-------
APPENDIX E
S STORAGE TERMINAL OPERATION
CONTENTS
Table Page
E-l S Storage Terminal Operation - Effect of Throughput
Capabilities on Total Capital Investment and Operating
Costs 154
151
-------
APPENDIX E
S STORAGE TERMINAL OPERATION
TECHNOLOGY
The liquid S from the mines is pumped through insulated and steam-heated
carbon steel pipe lines directly to terminals where it is stored either as
a liquid in insulated and heated welded carbon steel tanks or to outdoor vats
where it is cooled and solidified. Steam coils at pressures between 35 and
70 psig are used to maintain the molten S in the tanks at temperatures between
260 and 270°F (126-133°C). From the marketing terminal, the molten S is
transported by barge, truck, or rail directly to the point of consumption in
insulated vessels.
The solid S in the vats is broken out by modified bulldozers or power
shovels. If it is to be reshipped as a solid, it is moved by conveyor belts
to conventional road, rail, or water carriers. This method of reclaiming
solid S generates considerable S dust which not only represents a monetary
loss but has an adverse effect upon the environment. For this and other
reasons such as contamination of the solid S during handling and shipping in
dirty equipment, most S shipments are now made in the molten state. The dust
problem may be minimized somewhat by processing the molten S into solid slates
or prills for stockpiling and reclaiming. However, in the present study the
cost of shipping solid S is based on reclamation from vats as described above.
ECONOMICS
The primary information source is World Sulfur Supply and Demand, 1960-
1980 published in New York by the United Nations Industrial Development
Organization, Vienna. Much valuable information was also obtained from
"Technical and Economic Evaluation of Fertilizer Intermediates for use by
Developing Countries" prepared for the Agency for International Development
by TVA (TVA Bulletin Y-3).
Investment costs given in the above publications were updated to the
third quarter of 1974 and mid-1978 as were the costs of labor, supervision,
and utilities. In all cases the annual throughput was taken as four times
the primary storage capacity. Costs were estimated for primary storage
capacities of 20,000, 40,000, and 60,000 LT, giving annual throughputs of
80,000, 160,000, and 240,000 LT respectively. Costs were estimated for
terminals receiving solid S and redelivering 60% of the S as a liquid and
terminals receiving all S in the liquid form and redelivering as the liquid.
Solid S storage capital costs include site preparation, foundations, and cost
of handling facilities such as conveyors. Liquid S storage costs include
tanks (excluding piling), all onsite lines, valves, meters, etc., but not
delivery or discharge lines beyond battery limits. Tank capacities and hence
costs are based on standard units 40 ft high with varying diameters.
152
-------
Except for the terminal with a throughput of 240,000 LT/yr (60% of the
S delivered as a liquid), one melter of the appropriate size was considered
the most economical. In the 240,000 LT/yr terminal, two melters were
assumed. All terminals receiving solid S were assumed to reship 60% of the
throughput as liquid.
For those terminals receiving and delivering molten S only, the terminal
with the annual throughput of 80,000 LT/yr was assumed to have two storage
tanks holding 10,000 LT each; the terminal with the throughput of 160,000 LT
was assumed to have two tanks holding 20,000 LT each; the terminal with a
throughput of 240,000 LT was assumed to have two tanks holding 30,000 LT each.
DISCUSSION OF RESULTS
As shown in Table E-l, increasing the size of the terminals decreases the
unit storage costs. For those terminals which receive solid S and redeliver
60% of the S in the molten form, the estimated costs as of the third quarter
of 1974 are $4.67/LT for a terminal with an annual throughput of 80,000 LT,
$3.71/LT for a throughput of 160,000 LT, and $3.26/LT for a throughput of
240,000 LT. Capital costs in dollars per long ton per year are $9.00, $7.20,
and $6.87 respectively.
The terminals which handle only molten S have even lower costs, resulting
primarily from the elimination of the labor- and maintenance-intensive solid
S handling operation. For these terminals the estimated costs, as of the
third quarter of 1974, are $4.14/LT for an annual throughput of 80,000 LT;
$2.85/LT for a throughput of 160,000 LT, and $2.47/LT for a throughput of
240,000 LT.
Greater throughput rates, up to eight times the primary storage capacity,
are possible in S terminal operations. These greater throughput rates would
significantly decrease unit operating and capital costs.
153
-------
TABLE E-l. S STORAGE TERMINAL OPERATION -
EFFECT OF THROUGHPUT CAPABILITIES ON TOTAL CAPITAL
INVESTMENT AND OPERATING COSTS
Throughtput, Total capital Capital investment, Operating cost,
LT/yr investment, $ $/LT/yr $/LT of S
Third Quarter 1974 Costs
Terminals Receiving Solid S and Redelivering 60% Liquid
80,000 720,000 9.00 4.67
160,000 1,151,700 7.20 3.71
240,000 1,648,390 6.87 3.26
Terminals Receiving and Redelivering All Liquid
80,000 647,840 8.10 4.14
160,000 820,600 5.13 2.85
240,000 928,568 3.87 2.47
Mid-1978 Costs
Terminals Receiving Solid S and Redelivering 60% Liquid
80,000 925,200 11.57 6.36
160,000 1,479,900 9.25 5.11
240,000 2,118,200 8.83 4.56
Terminals Receiving and Redelivering All Liquid
80,000 832,500 10.41 5.90
160,000 1,054,500 6.59 4.26
240,000 1,193,200 4.97 3.78
154
-------
APPENDIX F
PRODUCTION, STORAGE, AND RETROFIT OF EMISSION CONTROLS
TO H2S04 PLANTS USING ELEMENTAL S
CONTENTS
Tables Page
F-l H2S(>4 Production from Elemental S - Effect of Acid Plant
Capacity on Total Capital Investment and Operating Costs
for Single Contact-Single Absorption (SC-SA) and Dual
Contact-Dual Absorption (DC-DA) l^SO^ Plants ........ 158
F-2 H2S(>4 Storage Terminal Operation - Effect of Throughput
Capabilities on Total Capital Investment and Operating
Costs ........................... 161
F-3 Retrofit of Emission Controls to H SO^ Plants Using
Elemental S - Effect of Acid Plant Capacity on the Total
Capital Investment for Emission Control Systems ...... 165
F-4 Retrofit of Emission Controls to H2S04 Plants Using
Elemental S - Effect of Acid Plant Capacity on the
Operating Costs of Emission Control Systems ........ 166
155
-------
APPENDIX F
PRODUCTION, STORAGE, AND RETROFIT OF EMISSION CONTROLS
TO H2S04 PLANTS USING ELEMENTAL S
H2SC>4 PRODUCTION FROM ELEMENTAL S
Technology
Basically H2S04 is produced by burning S or S-bearing materials to form
S02- The S02 is oxidized by air in the presence of a catalyst to form sulfur
trioxide (803) which combines with water vapor to form 112804.
The various sources of S02 for manufacture of H2S04 include (1) elemental
S, (2) pyrites [sulfide ores of iron (Fe), Cu, Pb, or Zn], (3) t^S from sour
gas or petroleum, (4) S-bearing ores of volcanic origin, (5) waste gases from
metallurgical refining operations, and (6) waste gases from combustion of
S-containing fuels. This study is concerned only with the production of acid
from elemental S. In addition to the S02 source alternatives listed above,
there are also alternate methods of conversion of S02 to 803.
There are two principal processes for conversion of S02 to the trioxide
form: the chamber and the contact processes. The older chamber process which
was introduced in the 18th century uses nitrogen oxides (NOX) as the oxygen-
carrying catalyst for the conversion of S02 to 803. The reactions which
produce the 803 and H2S04 take place either in huge lead chambers or packed
towers.
The modern contact process facilitates conversion of S02 to 803 by use
of a metal or metal-oxide catalyst. The 803 is then passed through an absorp-
tion tower where it is absorbed in recirculating concentrated acid. The major
advantages of the contact process are that concentrated acid of high purity
can be produced directly and compact plants of high capacity are feasible.
Plants of 1000 ton/day capacity are now rather commonplace and plants having
capacities of 2000 tons/day and above have recently been constructed. Very
few of the old chamber process plants are still in operation in the U.S. and
the vast majority of plants use the more efficient contact process. For this
reason, the present study is confined to ^804 produced by the contact process.
Contact H2S04 plants built prior to 1960 average 95.5% conversion of
elemental S to ^804. Plants built after 1960 are more efficient with 97%
conversion. However, neither of these classes of plant can meet present
emission standards which require a conversion efficiency of 99.7%.
Those existing contact plants which fail to meet emission standards are
of the single contact-single absorption type; i.e., the gas stream containing
the 802 fr°m the S burner is passed through a converter where, in contact with
156
-------
the catalyst, the SC>2 is oxidized to 803 and the oxidized gases are passed
through an absorber where most of the 803 is removed to form acid. However,
the tail gas leaving the absorber contains too much unconverted S02 to meet
emission standards, One method of solving this problem is to pass the gases
from the absorber through a second converter and a second absorber. This
second conversion and absorption results in an overall conversion efficiency
of 99.7% or greater, thus meeting emission standards. Existing single contact-
single absorption plants can be retrofitted with an additional converter-
absorber system to enable them to meet emission standards. Other systems are
also available for this purpose and will be discussed in another section of
this report. Virtually all new H^SO^ plants are built with two converter-
absorber systems in series in order to meet emission standards; these are
called dual contact-dual absorption plants. Cost data for both types of
plants have been developed.
Economics
Monsanto Enviro-Chem Systems, Inc., The Ralph M. Parsons Company, and
Davy Powergas, Inc., were the primary sources of capital cost data and utility
and labor requirements for both the single contact-single absorption and the
dual contact-dual absorption plants. Other valuable information was obtained
from Chemical Process Industries by R. Norris Shreve, McGraw-Hill Book
Company; The Economics of Su~l:furic Acid Production prepared for the Agency
for International Development by TVA (TVA Bulletin"Y-28); The Fertilizer
Manual published by the United Nations Industrial Development Organization,
New York; and The Manufacture of Sulfuric Acid edited by Werner W. Duecker
and James R. West, Reinhold Publishing Corporation, New York.
Investment costs from the above sources were calculated for the third
quarter of 1974 and mid-1978, as were the costs of labor, supervision, and
utilities. The cost of S was excluded from the estimates because of its
variability. Credit for byproduct steam was included. Investment costs
include capital costs for 30 days' storage of acid and S for each plant size
investigated.
Costs for single contact-single absorption plants having capacities of
50, 100, 250, 750, and 1500 tons/day of 100% H2S04 were estimated as well as
costs for dual contact-dual absorption plants having capacities of 100, 250,
750, and 1500 tons/day. Costs for dual contact-dual absorption plants of
50 ton/day capacity were not estimated as it is doubtful if plants of such
small capacity will ever be built. All plants were assumed to operate 330
days/yr.
Discussion of Results
As with most chemical plants there is a decided unit cost advantage with
increasing capacity. Although this cost advantage is substantial at all
levels of capacity explored, it decreases with increasing size of the acid
plant as shown in Table F-l.
157
-------
TABLE F-l. H2S04 PRODUCTION FROM ELEMENTAL S -
EFFECT OF ACID PLANT CAPACITY ON TOTAL CAPITAL INVESTMENT AND OPERATING
COSTS FOR SINGLE CONTACT-SINGLE ABSORPTION (SC-SA)
AND DUAL CONTACT-DUAL ABSORPTION (DC-DA) H2S04 PLANTS
Acid plant
capacity,
tons of 100%
H?SOA/day
Third
1,
Quarter
50
100
250
750
500
Total capital
investment, $
SC-SA
DC-DA
Capital investment,
$/ton
of 100% H?SOA/yr
SC-SA
DC-DA
Operating cost,
$/tona
of 100% H2SO£
SC-SA
DC-DA
1974 Costs
2,737
3,220
4,913
9,494
14,600
,000
,000
,800
,500
,800
—
3,942,000
6,443,000
11,211,000
18,088,000
165.
97.
5£.
38.
29.
88
58
56
36
50
119
78
45
36
-
.45
.10
.30
.54
41.
23.
12.
7.
4.
06
13
92
10
85
-
26.35
15.44
7.33
5.00
Mid-1978 Costs
1,
50
100
250
750
500
3,517
4,138
6,314
12,200
18,762
,000
,000
,000
,000
,000
-
5,065,000
8,279,000
14,406,000
23,243,000
213.
125.
76.
49.
37.
15
39
53
29
90
153
100
58
46
—
.48
.35
.21
.96
51.
29.
16.
8.
5.
96
11
10
68
80
—
33.26
19.16
8.76
5-76
a. Does not include the cost of S.
158
-------
For example, for single contact-single absorption plants built in the
third quarter of 1974, the capital investment required in terms of dollars
per ton of 100% t^SO/^/yr is $165.88 for a 50 ton/day plant and $29,50 for a
1500 ton/day plant, while the unit capital investment for a 750 ton/day plant
is $38.36, only $8.86/ton of acid per day greater than that for the 1500 ton/
day plant. First year operating costs (excluding S) for single contact-single
absorption plants built in the third quarter of 1974 are $41.06/ton of 100%
H2S04 for a 50 ton/day plant and $4.85/ton for a 1500 ton/day plant, while
the operating cost for a 750 ton/day plant is $7.10/ton, a difference of only
$2.25/ton greater than that for the 1500 ton/day plant. These trends can
also be seen in the data for dual contact-dual absorption plants.
The data given above also show that dual contact-dual absorption plants
are more costly to build and generally more costly to operate even though
they have a somewhat higher S recovery efficiency than single contact-single
absorption plants (an exception will be discussed below). For example, the
capital investment required in terms of dollars per ton of 100% K^SO^/yr for
100 ton/day planes built in the third quarter of 1974 is $97.58 for a single
contact-single absorption plant and $119.45 for a dual contact-dual absorption
plant. First year operating costs (excluding S) for a 100 ton/day plant
built in the third quarter of 1974 are $23.13/ton of 100% H2SC>4 for a single
contact-single absorption plant and $26.35/ton for a dual contact-dual
absorption plant, while the operating costs for 1500 ton/day plants are $4.85/
ton for a single contact-single absorption plant and $5.00/ton for a dual
contact-dual absorption plant.
The major factor contributing to the decreasing difference in operating
costs between single contact-single absorption and dual contact-dual absorption
plants with increasing size is the greater thermal efficiency of the larger
dual contact-dual absorption plants. The higher thermal efficiency of these
plants results in the production of more byproduct steam for which an operating
cost credit can be taken. This proportionately larger byproduct steam genera-
tion credit, coupled with the relatively higher credit value for this commodity
in mid-1978 as contrasted with the projected values of the other utilities,
actually results in a slightly lower operating cost for a 1500 ton/day dual
contact-dual absorption plant than the same sized single contact-single
absorption plant in mid-1978, i.e., $5.76/ton for the dual contact-dual
absorption plant versus $5.80/ton for the single contact-single absorption
plant. The operating costs before steam credits are taken are $8.52/ton and
$7.90/ton respectively. However, since single contact-single absorption
plants will not be built in mid-1978 unless emission standards for H2S04
plants are greatly relaxed, this comparison between the two types of plants
is of academic interest only.
159
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H2SO, STORAGE TERMINAL OPERATION
Technology
Concentrated (93-98%) H2S04 is usually stored in carbon steel vessels
with an expected life of about 25 yr. Carbon steel is suitable because a
protective sulfate film formed on the steel surfaces inhibits corrosion.
However, this film can be eroded where flow velocities are excessive. Hence,
tank nozzles, pipe lines, valves, and pumps must be properly sized if carbon
steel is used. If flow velocities are excessive, stainless steel is recom-
mended for pipe lines, etc. Plastic-lined material may also be used. Plastic
pipe by itself is not recommended as it may be easily broken by a falling
object or some other shock.
H2S04 tanks are usually designed for no additional pressure above the
weight of the acid. Steel plates 3/8 in. thick are usually used in tank con-
struction, with the joints welded both inside and out.
All storage tanks are above ground on concrete piers or saddles so spaced
and of such a height that leaks may be detected by visual inspection of the
bottom sections of the tanks. Each tank is equipped with a vent to allow air
to move in and out of the tank as the rcid level changes, or as breathing
takes place because of temperature changes. The vent or breather is equipped
with a drying agent such as silica gel, which is inert to acid fumes, in
order to prevent dilution of the acid (dilute acids are more corrosive) with
the moisture in the air and to prevent interface corrosion of the tank wall.
exhibits an unusual freezing point curve. The freezing point of
93% H2S04 is minus 30°F and the freezing point of 98% ^804 is 35°F. There-
fore, suitable precautions must be taken when storing acids of different
strengths at various temperatures.
Economics
The concept of shipping ^804 from the point of manufacture to a storage
terminal for transshipment to the consumer instead of direct shipment from
the producer to the consumer is relatively new. Hence, not much data exists
on costs of operating such a terminal. Data in the study Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes by G. G. McGlamery,
et al. (EPA-600/2-75-006 or PB-242 541/1WP, January 1975) was used to estimate
operating costs for H2S04 terminals. These costs were based on the use of
carbon steel storage tanks on concrete piers surrounded by an earthen dike,
carbon steel acid pumps, valves and piping, and a railroad car loading dock.
Costs were estimated for three sizes of terminals having primary storage
capacities of 4,680, 11,376, and 21,960 tons of 100% H2S04 and yearly through-
put rates of 45,300, 110,400, and 213,500 tons of 100% H2S04 respectively.
These annual throughput rates are about 10 times the primary storage capacity.
Costs were estimated for the third quarter of 1974 and mid-1978.
IhO
-------
Discussion of Results
The data in Table F-2 show that the economies of scale prevail—the
larger the storage capacity the lower the unit investment and operating costs.
For example, a terminal with a throughput of 45,200 tons/yr of 100% H^SO^ has
a unit investment cost in the third quarter of 1974 of $5.97,/ton of 100%
H2S04/yr and a total operating cost of $1.68/ton of 100% H^SO^ The corre-
sponding figures for a terminal with a throughput of 213,500 tons of 100%
H2SO^/yr are $3.37 and $0.77 respectively. The mid-1978 costs show the same
trend.
TABLE F-2. H2S04 STORAGE TERMINAL OPERATION ~
EFFECT OF THROUGHPUT CAPABILITIES ON
TOTAL CAPITAL INVESTMENT AND OPERATING COSTS
Total Capital
Throughtput, capital investment, Operating
tons 100% investment, $/ton 100% cost, $/ton
100% H?SOA
Third Quarter 1974 Costs
45,200 270,000 5.97 1.68
110,400 475,000 4.30 1.05
213,500 720,000 3.37 0.77
Mid-1978 Costs
45,200 347,000 7.68 2.18
110,400 610,000 5.53 1.38
213,500 925,200 4.33 1.02
161
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RETROFIT OF EMISSION CONTROLS TO H2S04 PLANTS USING ELEMENTAL S
Technology
As mentioned in the preceding section, most existing I^SO^ plants are
contact plants of the single contact-single absorption type which have 95-97%
S conversion efficiencies. Since a minimum of 99.7% S conversion efficiency
is required to meet present emission standards for new and modified plants,'
these existing single contact-single absorption plants must be retrofitted
with some system which will enable them to meet these standards. There are
four major methods for doing this.
1. Adding another converter-absorber system (dual contact-
dual absorption)
2. Scrubbing the stack gas with a sodium sulfite-bisulfite
solution (Wellman-Lord process)
3. Scrubbing the stack gas with an ammonium sulfite-bisulfite
solution (NH3 absorption process)
4. Adsorbing the contaminants in the stack gas on molecular
sieves (Purasiv S process)
In the dual contact-dual absorption system, the tail gas from the
absorber of the existing acid plant is passed through a booster blower to
provide the pressure necessary to force the gas through the remaining
additional equipment. The tail gas must then be heated before passing
through the additional converter where most of the unreacted S02 in the tail
gas is converted to SOo. Heating of the gas can be done either by bleeding
in a portion of the hot gases from the S furnace or employing a separate
fuel-fired heater. The fuel-fired heater is generally used for retrofit
because of smaller capital costs and less downtime for tie-in of the abate-
ment system to the acid plant. An air heater is included in the fuel-firing
system to minimize fuel consumption. The. gas from the converter is passed
through an additional absorber where the SOo is removed to form more acid.
The tail gases from this second absorber, after passing through a mist elimi-
nator, can be vented to the atmosphere without exceeding emission limitations.
A mist eliminator is also added to the absorber of the existing plant to
protect the booster blower and heat exchangers from corrosion by acid carry-
over from the absorber.
In the Wellman-Lord process the tail gas from the acid plant is scrubbed
in an absorber with a regenerable sodium sulfite-bisulfite solution. The
resulting solution is thermally regenerated in an evaporator-crystallizer and
the S02 driven off is returned to the drying tower in the acid plant. The
slurry from the regenerator is redissolved in water from the condenser on
the evaporator-crystallizer and returned to the absorber. The small portion
of the sodium sulfite which is oxidized to sulfate is removed in a purge
stream along with a small amount of sodium thiosulfate which forms in the
process.
162
-------
The NH3 absorption process consists of scrubbing the SC>2 in the tail
gases from the existing acid plant in a solution of ammonium sulf ite-bisulf ite
and discharging the scrubbed gases to the atmosphere through a high-efficiency
particulate collector (such as a Brink mist eliminator) in order to remove
the extremely fine particles of ammonium sulf ite-bisulf ite from the gas
stream. The scrubbing solution from the absorber-scrubber is acidified with
H2SC-4 and the resulting ammonium sulf ate [(NH^^SO^ ] solution is air stripped
to remove S02 which is returned to the drying tower of the I^SO^ plant. The
resulting (NH^^SO^ solution can be used in a diammonium phosphate process or
processed in a separate crystallization operation.
The Purasiv S process uses beds of molecular sieves to remove the SC>2
from the tail gas of the existing acid plant. The tail gas is passed through
one of two parallel beds of molecular sieves. While one adsorbent bed is
treating the gases, the other is being regenerated with hot air. The regene-
rated S02~air stream is returned to the drying tower of the acid plant where
it substitutes for the dilution air usually drawn into the tower. Bed switch-
ing is accomplished without any interruption in flow or removal of SC^ from
the tail gas stream. The cleaned gas is vented to the atmosphere.
Economics
Capital and operating costs for the dual contact-dual absorption system
were obtained from The Ralph M. Parsons Company, Monsanto Enviro-Chem, Inc.,
and Davy Powergas, Inc. Costs from these sources were essentially the same
and were averaged for use in the estimates. The capital costs include all
of the equipment mentioned in the section on technology plus the necessary
valves, piping, foundations, engineering costs, contractor fees, etc.
The Wellman-Lord process is proprietary and the source of information
concerning the process was Davy Powergas. Neither credit for possible sales
of the sodium sulfate byproduct nor disposal costs if the product is not
marketable is included in the cost estimates.
The source of information concerning the NH3 absorption process was also
Davy Powergas. In the cost estimates, no credit was taken for the byproduct
(NH^SO^. The estimates include costs of the absorber, stripper, mist
eliminator, pumps, piping, foundation, engineering costs, etc., but do not
include any equipment for crystallization of the
The Purasiv S process which uses beds of molecular sieves to remove the
SC>2 from the acid plant tail gas is the property of the Union Carbide
Corporation and all cost information was obtained from them. The estimates
include the cost of the parallel bed system, the furnace for heating the
regeneration air, fans, ducts, foundations, engineering costs, etc., as well
as an expansion of an existing substation, a cooling water tower, and fuel
oil storage. Because of the specialized nature of the adsorbent, a service
contract for its renewal is included in the estimate rather than outright
purchase of new adsorbent and reprocessing of spent material.
163
-------
Since all four methods of abating the emissions from H2S04 plant stack
gases result in an increased recovery of S, a credit is given in the cost
estimates for the equivalent S recovered.
Cost estimates were prepared for each of the four methods for con-
trolling emissions from existing single contact-single absorption H2SC-4
plants having capacities of 50, 100, 250, 750, and 1500 tons of 100% H2S04/
day and operating 330 days/yr. Costs were calculated for the third quarter
of 1974 and for mid-1978.
Discussion of Results
The data in Table F-3 show that of the four retrofit systems evaluated,
the NH3 absorption scheme is the least capital intensive, varying from $21.70/
ton of 100% H2S04/yr for a 50 ton/day plant tc $3.96 for a 1500 ton/day plant
for the third quarter of 1974. The Wellman-Lord system is somewhat more
capital intensive with corresponding costs of $27.12 and $4.81. The two most
capital intensive systems are the dual contact-dual absorption system with
costs of $33.61/ton of 100% H2S04/yr for a 50 ton/day plant and $6.91 for a
1500 ton/day plant, and the molecular sieve scheme, with values of $44.06
and $7.27 respectively. The mid-1978 costs exhibit the same trend.
However, the data in Table F-4 show that there is considerable variation
in overall operating costs,depending upon plant size and the retrofit system
used. The lowest average cost for the third quarter of 1974 for all plant
sizes evaluated is that for the dual absorption system, $4.36/ton of 100%
H2SC>4, followed by the molecular sieves at $4.96, the NH3 absorption system
at $5.05fand the Wellman-Lord scheme at $5.78. The same trend is exhibited
by the data for mid-1978.
The situation changes when comparisons are made on individual plant
sizes. The third quarter of 1974 data indicate that the dual absorption and
molecular sieves schemes are cheaper to operate for 50 and 100 ton/day plants,
with costs of $7.49 and $5.17/ton of 100% H2SC>4, respectively, for the dual
absorption system and $9.16 and $6.12 for the molecular sieve scheme; the
corresponding figures for the NH3 absorption scheme are $10.55 and $6.35,
while for the Wellman-Lord system they are $11.79 and $7.22. For the 250
ton/day plants, the dual absorption and NH3 absorption systems are the least
expensive to operate with almost identical third quarter 1974 costs of $3.87
and $3.89/ton of 100% H2S04 respectively; the corresponding costs for the
molecular sieves and Wellman-Lord systems are $4.43 and $4.55. The cheapest
operating costs for the 750 and 1500 ton/day plants are associated with the
NH3 absorption system, with costs of $2.50 and $1.98 respectively. The
operating costs for the other systems for the 750 ton/day plants are almost
identical, varying from $2.96 to $2.99/ton of 100% H2S04; for the 1500 ton/day
plants the operating costs of the other systems vary from $2.14 for the
molecular sieves scheme to $2.36 for the Wellman-Lord system.
The mid-1978 operating costs also vary widely between plant sizes and
abatement systems, with roughly the same trends as the third quarter 1974
costs.
1C, 4
-------
TABLE F-3. RETROFIT OF EMISSION CONTROLS TO H2SO^ PLANTS USING ELEMENTAL S -
EFFECT OF ACID PLANT CAPACITY ON THE TOTAL CAPITAL INVESTMENT FOR EMISSION CONTROL SYSTEMS
Acid plant
capacity,
tons
of 100%
H2S04/day
Retrofit system
Dual contact-dual absorption
Total
capital
investment, $
Investment,
$/ton 100%
H2S04/yr
Wellman-Lord
Total
capital
investment, $
Investment,
$/ton 100%
H2S04/yr
Ammonia absorption
Total
capital
investment , $
Investment,
$/ton 100%
H2S
-------
TABLE F-4. RETROFIT OF EMISSION CONTROLS TO H2S04 PLANTS USING
ELEMENTAL S - EFFECT OF ACID PLANT CAPACITY ON
THE OPERATING COSTS OF EMISSION CONTROL SYSTEMS
Acid plant
capacity,
tons of .100%
H2SOi/day a
Operating cost,
Dual
bsorption
Wellman-
Lord
Third Quarter 1974 Costs
50
100
250
750
1,500
Average
Mid-1978 Costs
50
100
250
750
1,500
Average
7.49
5.17
3.87
2.96
2.30
4.36
10.40
7.41
5.74
4.53
3.68
6.35
11.79
7.22
4.55
2.99
2.36
5.78
15.50
9.72
6.36
4.38
3.58
7.91
$/ton 100% 1
NH3
absorption
10.55
6.35
3.89
2.50
1.98
5.05
14.11
8.81
5.71
3.95
3.28
7.17
*2S04
Molecular
sieves
9.16
6.12
4.43
2.97
2.14
4.96
12.54
8.62
6.43
4.59
3.44
7.12
166
-------
In actual application the NH^ scrubbing system would probably have a
distinct advantage over the others if the byproduct (NH^nSO/ could be
utilized, such as would be the case for a captive acid plant located in a
fertilizer complex. If no credit can be taken for the (NH^^SCU, then the
decision as to which system to use becomes largely dependent upon individual
acid plant factors such as location, space available for retrofit, etc.
167
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APPENDIX G
DEMAND SCHEDULE FOR H2S04 PLANTS
CONTENTS
Tables Page
G-l Demand Schedule for H2S04 - Eastern Acid Plants 170
G-2 Demand Schedule for H2S04 -Western Acid Plants 172
169
-------
TABLE G-1. DEMAND SCHEDULE FOR
- EASTERN ACID PLANTS
Annual Avoidable
capacity, cost of
ktons production,
6.00
17.00
52.00
67.00
87.00
152.00
176.00
201.00
266.00
306.00
436.00
468.00
524.00
564.00
599.00
634.00
739.00
789.00
989.00
1,031.00
1,206.00
1,232.00
1,342.00
1,452.00
1,502.00
1,607.00
1,705.00
1,780.00
1,835.00
1,910.00
1,980.00
2,015.00
2,147.00
2,233.00
2,313.00
2,411.00
2,546.00
2,666.00
2,756.00
2,856.00
2,951.00
2,999.00
90.47
66.35
57.91
56.44
51.70
50.35
49.51
46.96
46.19
45.66
45.58
45.25
44.82
44.70
44.55
44.28
44.27
44.08
43.25
42.51
42.41
41.19
40.50
40.44
40.31
40.29
39.68
39.36
39.15
38.91
38.72
38.62
38.42
38.12
38.06
38.05
38.03
37.68
37.27
36.84
36.76
36.22
$ Plant name
Eastman Kodak
Home Guano Company
Detroit Chemical Co.
Kerr-McGee
Royster Company
Minn Min and Smelt
Columbia Nitrogen
American Cyanamid
American Cyanamid
Swift Chem Company
Allied Chemical Corp
Swift Chem Co.
Marion Manufacturing
Borden Chemical
Weaver Fertilizer
Swift Chem Co.
Olin Corporation
American Cyanamid
E. I. Dupont De Nem
W. R. Grace and Co,
E. I. Dupont De Nem
American Cyanamid
E. I. Dupont De Nem
Pennsalt Chemicals
American Cyanamid
U.S. Industrial Chem
W. R. Grace and Co.
Delta Chemical
Reichhold Chemicals
E. I. Dupont De Nem
USS Agri-Chem
Cities Service Oil
Army Ammunition Pit
El Paso Products
Borden Chemical
U.S. Industrial Chem
Allied Chemical Corp
Stauffer Chemical Co.
E. I. Dupont De Nem
Occidental Ag Chera
American Cyanamid
Acme (Wright) Pert Co.
Location
Rochester
Do than
Detroit
Cottondale
Norfolk
Copley
Moultrie
Kalamazoo
Bound Brook
Calumet City
Cleveland
Wilmington
Indianapolis
Streator
Norfolk
Norfolk
N. Little Rock
Joliet
Cleveland
Charleston
North Bend
Mobile
Gibbstown
Tulsa
Fortier
Desoto
Joplin
Searsport
Tuscaloosa
Cornwells Hts.
Navassa
Monmouth Jet
Tyner
El Paso
Norfolk
Dubuque
Nitro
Ft. Worth
Richmond
Plainview
Hamilton
Acme
NY
AL
MI
FL
VA
OH
GA
MI
NJ
IL
OH
NC
IN
IL
VA
VA
AR
IL
OH
SC
OH
AL
NJ
OK
LA
KS
MO
ME
AL
PA
NC
NJ
TN
TX
VA
IA
WV
TX
VA
TX
OH
NC
(continued)
170
v
-------
TABLE G-l (continued)
Annual Avoidable
capacity. cost of
ktons production,
3,124.00
3,336.00
3,496.00
3,821.00
4,021.00
4,271.00
4,371.00
4,446.00
4,896.00
5,161.00
5,231.00
5,551.00
5,731.00
6,056.00
6,276.00
6,401.00
6,881.00
7,231.00
7,351.00
7,521.00
7,970.00
8,853.00
9,413.00
9,833.00
10,288.00
11,568.00
11,968.00
12,468.00
13,825.00
14,070.00
14,286.00
14,816.00
15,096.00
16,146.00
17,346.00
17,886.00
18,376.00
18,901.00
20,121.00
20,621.00
22,271.00
23,497.00
24,687-00
25,347.00
26,897.00
28,097.00
30,257.00
32,237.00
36.21
35.95
35.94
35.60
35,50
35.06
35.03
34.40
34.17
34.04
33.94
33.81
33.20
32.78
32.73
32.51
32.49
32.48
32.30
32.12
31.76
31.72
31.41
31.19
31.12
30.96
30.88
30.30
30.30
29.82
29.80
29.75
29.12
28.56
28.45
27.92
27.60
27.53
27.27
27.26
26.87
26.50
26.35
26.21
25.85
25.64
25.23
25.19
$ Plant name
E. I. Dupont De Nem
Army Ammunition Pit
Allied Chemical Corp
Royster Company
Allied Chemical Corp
Stauffer Chemical Co.
Monsanto Company
LJ + M LaPlace Cde
Gardinier
Monsanto Company
USS Agri-Chem
W. R. Grace and Co.
Essex Chemical Co.
E. I. Dupont De Nem
Swift Chem Co.
Cities Service Oil
W. R. Grace and Co.
Olin Corporation
Monsanto Company
U.S. Industrial Chem
Texasgulf Inc.
Gardinier
NL Industries Inc.
Mobil Oil
NL Industries Inc.
W. R. Grace and Co.
Engelhardt McConser
Olin Corporation
Texasgulf Inc.
American Cyanamid
American Cyanamid
American Cyanamid
USS Agri-Chem
Gardinier
Agrico Chem-Williams
USS Agri-Chem
Borden Chemical
Beker Industries
Miss Chem Corp.
Allied Chemical Corp.
Occidental Ag Chem
Farmland Industries
CF Industries Inc.
CF Industries Inc.
CF Industries Inc.
Agrico Chem-Williams
Freeport Minerals
International Miner
Location
Deepwater
Radford
Front Royal
Mulberry
Hop ewe 11
LeMoyne
El Dorado
Edison
Tampa
E. St. Louis
Wilmington
Bartow
Newark
Linden
Agrico la
Augusta
Bartow
Baltimore
Everett
Tuscola
Lee Creek
Tampa
Sayreville
Depue
St. Louis
Bartow
Nichols
Pasadena
Lee Creek
Warner (Linden)
Savannah
Fortier
Bartow
Tampa
Donaldsonville
Ft. Meade
Pt. Manatee
Taft
Pascagoula
Geismar
White Springs
Pierce
Bonnie
Bonnie
Plant City
Pierce
Uncle Sam
Bonnie
NJ
VA
VA
FL
VA
AL
AR
NJ
FL
IL
NC
FL
NJ
NJ
FL
GA
FL
MD
MA
IL
NC
FL
NJ
IL
MO
FL
FL
TX
NC
NJ
GA
LA
FL
FL
LA
FL
FL
LA
MS
LA
FL
FL
FL
FL
FL
FL
LA
FL
171
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TABLE G-2. DEMAND SCHEDULE FOR
- WESTERN ACID PLANTS
Annual
capacity,
ktons
Avoidable
cost of
production, $
15.00
156.00
191.00
246.00
312.00
452.00
527.00
667.00
867.00
1,092.00
1,467.00
1,732.00
2,392.00
3,042.00
43.72
37.61
34.29
33.83
31.95
30.43
30.00
29.33
29.31
27.35
26.97
26.45
21.26
20.53
Plant name
Location
Georgia Pacific
Kerr-McGee
Phelps Dodge
Union Carbide Corp.
Valley Nitrogen Prod.
Allied Chemical Corp.
Phelps Dodge
Anaconda Company
Allied Chemical Corp.
Occidental Ag Chem
Valley Nitrogen Prod.
Valley Nitrogen Prod.
Beker Industries
J. R. Simplot Co.
Bellingham WA
Grants NM
Jeffrey City WY
Uravan CO
Bena CA
Pittsburg CA
Riverton WY
Yerington NV
Richmond CA
Lathrop CA
Helm CA
Helm CA
Conda ID
Pocatello ID
172
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APPENDIX H
BYPRODUCT H2SC>4 PRODUCTION FROM SMELTER GASES INCLUDING ESTIMATES OF
RETROFIT TAIL GAS CLEANUP AND LIMESTONE NEUTRALIZATION
CONTENTS
Tables Page
H-l H^SO, Production from Smelter Gas - Effect of Acid Plant
Capacity on Total Capital Investment at Various S02
Levels in Smelter Gas 176
H-2 H2S04 Production from Smelter Gas - Effect of Acid Plant
Capacity on Operating Cost at Various S02 Levels in
Smelter Gas 176
H-3 Retrofit of Emission Controls to ^804 Plants Using
Smelter Gas - Dual Contact-Dual Absorption System -
Effect of Acid Plant Capacity on Total Capital
Investment at Various S(>2 Levels in Smelter Gas 178
H-4 Limestone Neutralization of H2SC>4 - Effect of System
Capacity on Total Capital Investment and Operating Cost . . . 180
173
-------
APPENDIX H
BYPRODUCT H2S04 PRODUCTION FROM SMELTER GASES INCLUDING ESTIMATES OF
RETROFIT TAIL GAS CLEANUP AND LIMESTONE NEUTRALIZATION
H2S04 PRODUCTION FROM SMELTER GAS
Technology
As in an elemental S-burning acid plant, the S02 in the smelter gases is
oxidized to 503 by the contact process to produce 1^504. While the SC>2 gas
stream to the converter in an elemental S acid plant is clean and requires
little if any cleanup to protect the catalyst in the converter, the gases from
smelter plants are dirty and require extensive treatment to remove dust and
fume. Most of the dust and fume are removed in dry cyclones and bag filters.
At this point the gas is discharged to the atmosphere if S02 removal is not
necessary.
If the SC>2 is to be recovered in an acid plant, the remaining dust and
fume must be removed, usually in a wet scrubber. In the scrubber the small
amount of 503 formed during the smelting process -reacts with the water to form
a weak solution of H2S04- Some of the acid formed leaves the scrubber as a
mist and must be removed in an electrostatic precipitator (ESP). The weak
acid from the scrubber and precipitator is contaminated with dust and is
discarded. The cleaned gases, having been passed through a wet scrubber, are
saturated with water vapor. Part of this water must be removed so that the
ratio of water:S02 in the gas does not exceed that required to produce
concentrated acid (100% H2S04 has a water:S02 mol ratio of 1). The excess
water is removed by cooling the gas directly by contact with product acid or
indirectly in a water-cooled heat exchanger, or both. The cleaned and cooled
gases are now ready for conversion of the S02 to H2S04 in a conventional
contact plant.
Economics
Smelter gas acid plants are more expensive to build and operate than S-
burning plants, primarily because the smelter off-gases must be thoroughly
cleaned before processing in the acid plant. Another factor is the varying
S02 content of the several gas streams from a smelter, ranging from <1% from
reverberatory copper smelting furnaces to about 15% from fluid-bed roasters.
For technical and economic reasons, the S02 content of the gases fed to a
contact acid plant is limited to the range of about 4-12%. The higher limit
is imposed by the fact that the S02~bearing gases to the converter of a
contact acid plant must contain sufficient oxygen to oxidize the S02 to SO^.
Also, as the S02 content of the gases increases, the amount of heat released
by the oxidation of S02 to S03 in the converter increases and the resulting
higher temperature may damage the catalyst. The lower limit is imposed by
economic considerations. Concentrations of S02 lower than 4% in the feed gas
are technically feasible but uneconomic because to accommodate the larger gas
174
-------
flows necessary to maintain a reasonable production rate, the size of the
equipment, and thus its cost, become prohibitive. Some of the gas streams
from a smelter may be blended to give a composition suitable for feeding to an
acid plant, but even so, some of the dilute SC>2 gases are vented to the at-
mosphere after particulate removal when S02 emission standards permit.
The above considerations make it desirable to have cost data for several
sizes of smelter acid plants, each receiving feed gases of varying S02
content. Hence, cost estimates were prepared for smelter acid plants having
capacities of 250, 750, and 1500 tons of 100% H2S04/day, operating 330 days/yr,
and processing gases containg 4, 8, and 12% S02- Costs were calculated as of
the third quarter of 1974 and mid-1978.
The capital and operating cost data were obtained primarily from System
Study for Control of Emissions - Primary Nonferrous Smelting Industry by
Arthur G. McKee and Company, San Francisco, California, June 1969- The
capital investments for these plants include, in addition to the acid plant
itself, only the gas cleaning and cooling equipment required to protect the
catalyst in the acid plant converter; the cost of the preliminary gas-cleaning
equipment required to meet particulate emission standards is a necessary cost
for processing those gas streams which are to be vented to the atmosphere
without S02 removal, and thus, is not considered as an expense chargeable to
S02 recovery.
Since most of the existing smelter acid plants are of the single contact-
single absorption type, this technology was used in preparing the cost
estimates. Costs for retrofitting these plants to meet acid plant emission
standards will be found in the appendix of this report.
Discussion of Results
The data in Table H-l indicate that unit capital investment decreases
both with increased acid plant size and with increased concentration of S02 in
the feed gases. The unit capital cost in $/ton of 100% H2S04/yr for the third
quarter of 1974 decreases from $106.19 for a 250 ton/day plant receiving gases
containing 4% S02 to $68.82 for a 1500 ton/day plant also receiving 4% S02
gases. Similar trends occur for plants processing 8 and 12% S02 gases. The
unit capital cost decreases from the $106.19 figure mentioned above for a
250 ton/day plant being fed gases containing 4% S02 to $61.05/ton of 100%
for the same sized plant processing 12% S02 gases.
Operating costs in $/ton of 100% H2S04 also decrease with increasing size
of acid plants and increasing concentration of S02 in the feed gases as shown
in Table H-2. The operating cost for a 250 ton/day plant processing 4% S02
gases is $24.79/ton of 100% H2S04 for third quarter 1974 costs, while the
operating cost for a 1500 ton/day plant, also processing 4% S02 gases, is
$14.38. When the concentration of S02 in the feed gases is increased to 12%,
the operating cost for the 250 ton/day plant processing 4% S02 gases decreases
from the $24.79 figure to $14.44 for the same sized plant processing 12% S02
gases. The trends illustrated above also apply to the mid-1978 data.
175
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TABLE H-l. H2SC>4 PRODUCTION FROM SMELTER GAS -
EFFECT OF ACID PLANT CAPACITY ON TOTAL CAPITAL INVESTMENT
AT VARIOUS S02 LEVELS IN SMELTER GAS
Acid plant
capacity,
tons of 100%
H2S04/day
Third Quarter
250
750
1,500
Mid-1978 Costs
250
750
1,500
Capital investment,
Total capital investment, $ $/ton 100% H2S04/yr
4% S02 8% S02 12% S02 4% S02 8% S02 12%
1974 Costs
8,760,960 5,513,230 5,036,900 106.19 66.82 61
19,891,100 12,460,300 11,791,700 80.37 50.34 47
34,065,850 21,119,390 19,281,110 68.82 42.67 38
11,258,000 7,084,500 6,472,400 136.46 85.87 78
25,560,000 16,011,500 15,152,300 103.27 64.69 61
43,774,600 27,138,400 24,776,200 88.43 54.83 50
S02
.05
.64
.95
.45
.22
.05
TABLE H-2. H2S04 PRODUCTION FROM SMELTER GAS -
EFFECT OF ACID PLANT CAPACITY ON OPERATING COST AT
VARIOUS S02 LEVELS IN SMELTER GAS
Acid
plant capacity, Operating cost,
tons of 100% $/ton 100% H2S04
H2S04/day 4% S02 &% S02 12% S02
Third Quarter 1974 Costs
250 8.34 3.87 2.38
750 6.45 2.96 1.80
1,500 5.06 2.30 1.38
Mid-1978 Costs
250 12.37 5.74 3.54
750 9.76 4.53 2.76
1,500 8.08 3.68 2.22
176
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RETROFIT OF EMISSION CONTROLS TO H2S04 PLANTS USING SMELTER GAS
Technology
Smelter gas H2S04 plants can be retrofitted for control of tail gas
emissions using the technology previously discussed in this report in the
section on retrofitting elemental S-burning plants. The information developed
in that section of the report showed that, for all the acid plant sizes in-
vestigated, the dual contact-dual absorption alternative had the lowest
overall average operating cost. For this reason only the dual contact-dual
absorption system was evaluated for use on smelter gas acid plants.
Economics
In S~burning acid plants the gas to the. converter contains about 8% S02-
Since retrofitting costs have been developed for such plants in a prior section
of this report, these developed capital costs are used directly as the capital
costs for retrofitting smelter gas acid plants also being fed gases containing
8% S02- The capital costs for smelter gas (or other) acid plants are directly
proportioned to gas flow, For a given acid production rate gas flow translates
inversely to SO;; content. Hence the capital costs for smelter gas acid plants
being fed gas streams containing 4% and 12% SCb were calculated from the costs
of acid plants being fed 8% S02 using appropriate scaling factors.
Costs for retrofitting smelter gas acid plants with dual contact-dual
absorption systems having capacities of 250s 750, and 1500 tons of 100% K2S04/
day and being fed gases containing 4%s 8%s and 12% S02 were estimated for the
third quarter of 1974 and mid-1978.
Discussion of Results
The data in Table H-3 show the same trend in unit capital costs for
retrofitting smelter gas acid plants with dual contact-dual absorption systems
as the data for capital costs of the smelter gas acid plants themselves. The
unit capital investment required decreases as the size of the plant and the
concentration of S02 in the feed gases increases. For example, the unit
capital investment in the third quarter of 1974 for a 250 ton/day plant
receiving gases containing 8% S02 is $13.87/ton of 100% H2S04 produced/yr
while a 1500 ton/day plant requires only $6.91. The third quarter 1974 unit
investment cost for a 250 ton/day plant is $28.94/ton of 100% acid/yr when
the feed gas contains 4% S02 while the corresponding cost when the feed gas
contains 12% S02 is $8.45.
Operating costs show the same trend. In the third quarter of 1974, the
operating costs for a 250 ton/day plant processing gases containing 8% S02 is
$3.87/ton of 100% 1^804 while the corresponding cost for a 1500 ton/day plant
is $2.30. When a 250 ton/day plant processes gases containing 4% S02, the
operating cost is $8.34/ton of 100% H2S04 while the cost of processing gases
177
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containing 12% S02 is $2.38. These trends for both unit capital and operating
costs are also reflected in the mid-1978 costs.
TABLE H-3. RETROFIT OF EMISSION CONTROLS TO H2S04 PLANTS
USING SMELTER GAS - DUAL CONTACT-DUAL ABSORPTION SYSTEM -
EFFECT OF ACID PLANT CAPACITY ON TOTAL CAPITAL
INVESTMENT AT VARIOUS S02 LEVELS IN SMELTER GAS
Acid
plant capacity, Capital investment,
tons of 100% Total capital investment, $ $/ton 100%
H?S04/day _ 4% S02 _ 8% SO? _ 12% SO? 4% S09 8% SO? 12% SO?
Third Quarter 1974 Costs
250 2,387,530 1,144,000 729,900 28.94 13.87 8.45
750 5,296,800 2,538,000 1,619,240 21.40 10.25 6.54
1,500 7,133,400 3,418,000 2,180,700 14.41 6.91 4.41
Mid-1978 Costs
250
750
1,500
3,068,000
6,663,400
9,166,400
1,470,000
3,261,300
4,392,100
937,900
2,080,700
2,802,200
37.19
26.92
18.52
17.82
13.18
8.87
11.37
8.41
5.66
LIMESTONE NEUTRALIZATION OF H2S04
Technology
At the present time no detailed information is available concerning large-
scale neutralization of H2S04. Therefore, the information given in this report
is based on a conceptual design and cost study presented in Neutralization of
Abatement Derived Sulfuric Acid prepared for EPA by Process Research, Inc.,
EPA Report No. EPA-R2-73-187. In this conceptual design, the H2S04 is
neutralized with a slurry of ground limestone. The resulting gypsum is
disposed of by ponding.
The ground limestone is slurried with the overflow from the gypsum pond.
The slurry is pumped to a neutralization tank where the acid is added. The
gases evolved (mostly C02) are vented to the atmosphere through the limestone
slurry tank to trap any 803 vapor which might be liberated by the heat
generated during the neutralization step. The neutralized slurry is pumped to
the gypsum settling pond where the remaining heat of reaction is dissipated by
the evaporation of water from the pond. The overflow from the pond is
collected in a sump where makeup water is added to compensate for that lost in
evaporation and for that occluded or combined in the gypsum sludge. The amount
178
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of makeup water required will be reduced in proportion to the rainfall collected
by the pond. The strength of the acid neutralized will also affect the water
balance, In this study, 93% H2SC>4 is neutralized. However, except in the
wettest regions of the U.S., such as the Gulf Coast, the amount of water lost
from the circuit by evaporation and by retention in the gypsum sludge will
exceed the amount added by rainfall, ranking the use of makeup water necessary.
This may occur during the dry season in the arid regions of the West where the
neutralization of smelter acid may become important because of the Jack of
markets for the abatement acid. However, in this study, it is assumed that
neither will makeup water be required, nor will disposal of surplus water be
necessary.
The gypsum pond dikes are constructed of soil excavated from the interior
area. The bottoms of the ponds and the inside slopes of the dikes are covered
with a 6-in. layer composed of selected excavation materials into which
bentonite has been mixed. Another 4- to 6-in. layer of excavated material is
placed on top of the bentonite-treated layer. The outside faces and tops of
the dikes are finished with a layer of topsoil. The pond overflow is collected
in a structure located opposite the slurry inlet and includes an adjustable
weir gate and a sump containing a pump, The pond or ponds are all 20 ft deep,
No acid storage facilities are included, in the system since the acid storage
associated with the acid plants is assumed to be adequate.
Economics
The conceptual design used in this report is essentially the same as the
one appearing in the previously mentioned report Neutralization of Abatement
Derived Sulfuric Acid. The Process Research report assumed the initial
purchase of land for 10 annual gypsum ponds and the construction of only one
annual pond; however, a single 30-yr pond concept was used in this report.
Investment and operating costs were calculated for neutralization
facilities having dally capacities of 250, 750, and 1500 tons/day of 100%
H2S04 and operating 330 days/yr. The 1500 ton/day unit was assumed to have
two neutralization tanks and dual ball mills for grinding the limestone; the
other units have a single neutralization tank and one ball mill. Costs were
calculated for the third quarter of 1974 and mid-1978.
Discussion of Results
The data in Table H~4 indicate that, as might ba expected, the economies
of size are present in this operation; that is, as the size of the .facility
increases, both the unit investment and operating cost decrease. For a
neutralizing system treating 250 tons/day of 100% H2S04, the unit investment
cost in the third quarter of 1974 is $84.74/ton of 100% H2S04/yr and the
operating cost is $25.13/tori of 100% H2S04 neutralized, while for a 1500
ton/day installation the comparable figures are $38.52 and $12.95. The costs
for mid-1978 show a similar trend.
Since the gypsum pond accounts for about 80% of the capital investment,
both the investment costs and the operating costs will be reduced considerably
179
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when a neutralization plant is built for an acid plant which has only 10- or
15-yr life expectancy and is not scheduled for replacement.
TABLE H-4. LIMESTONE NEUTRALIZATION OF H2S04 -
EFFECT OF SYSTEM CAPACITY ON TOTAL CAPITAL
INVESTMENT AND OPERATING COST
System capacity, Total Capital investment, Operating
tons of 100% H2S04 capital $/ton 100% cost, $/ton
neutralized/day investment, $ H?SO^/yr 100% H?SO&
Third Quarter 1974 Costs
250 6,991,300 84.74 25.13
750 13,029,200 52.64 16.60
1,500 19,067,100 38.52 12.95
Mid-1978 Costs
250 8,983,800 108.89 34.28
750 16,742,500 67.65 23.21
1,500 24,501,200 49.50 18.40
180
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APPENDIX I
H2S04 TRANSPORTATION RATES FROM WESTERN SMELTERS
TO EASTERN TERMINALS
CONTENTS
Table Ia8e
1-1 Unit Train H2S04 Rates, $/Ton 182
181
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TABLE 1-1. UNIT TRAIN H2S04 RATES, $/TONa
Co
ho
Point of origin
Hay den
AZ
21.80
24.42
24.42
24.42
19.60
-
-
Hurley
MM
16.79
18.86
18.86
18.86
13.36
-
-
Separ
NM
16.79
18.86
18.86
18.86
13.36
-
-
Kellogg
ID
22.05
22.95
22.95
41.85
41.85
-
-
Anaconda
MT
19.00
19.40
19.40
35.65
33.15
-
-
Garfield
UT Canada
18.75
17.85
17.85
30.50
26.50
5.45
6.85
Eastern terminals
Location
Chicago
St. Louis
Memphis
Baton Rouge
Houston
Buffalo
Detroit
IL
MO
TN
LA
TX
NY
MI
a. A terminal handling charge of $1.50/ton will be added at each terminal.
-------
APPENDIX J
PROJECTION OF STEAM PLANT DATA BASE, 1978
183
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APPENDIX J
PROJECTION OF STEAM PLANT DATA BASE, 1978
FPC Form 67 was the basic data source used in developing the steam plant
data base and converting the information into a form useful for calculation of
scrubbing cost by any of the processes considered. Projections for 1978 made
by the utilities were taken as accurate projections of power demand in 1978
for each plant.
Many of the projections made by the industry and reported to FPC were
plant level projections. To calculate scrubbing cost it was necessary to
convert plant level data to boiler level. Specific data requirements neces-
sary to calculate costs included boiler age, air rate, heat rate, boiler size,
and fuel type, quantity, Btu content, and S content.
Boiler age and size were given for each plant. For new plants boiler age
was obtained from other FPC reports.
Fuel Projections
The FPC data from Form 67 only reported megawatts to be generated and
fuel consumption at the plant level. For purposes of cost estimation it was
necessary to convert plant level projections to boiler level projections of
fuel use by type and amount. Normally Btu content and S content of fuels to
be used were given. When no values were given, the following standard values
were assumed: S content of fuel, coal 3.5%, oil 2.5%, gas 0%; Btu content of
fuel, coal 12,000 Btu/lb, oil 149,000 Btu/gal, and gas 1,000 Btu/ft3. In
some cases plant projections for 1978 were not made. The following briefly
describes the methods and procedures followed to develop fuel projections to
be used in the steam plant data base.
In some cases boilers were listed as existing that apparently were no
longer in service except possibly on a standby basis. That is, the sum of
reported boiler capacity exceeded reported plant capacity. Recognizing that
scrubbing facilities would not be installed on these unused boilers, they were
dropped from consideration. The procedure for dropping was to eliminate any
boiler >30 yr old that had a capacity equal to or less than the difference
between boiler capacity and plant capacity when boiler capacity was greater
than plant capacity. After this algorithm was completed, all remaining
boilers were considered candidates for scrubbing.
Boilers are used at <100% of capacity, depending on a number of factors
including power demand. Projections made by the utilities were assumed to
184
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reflect power demand in 1978. Boiler age is the most general determinant of
using the boiler or its capacity factor. The projected boiler capacity factor
was used as the key factor in allocating fuel input requirements to individual
boilers. The capacity factor used was based on historical (1969-73) capacity
factor versus age of reported boiler operation. That relationship is shown i\
Figure 16. It represents the average capacity factor of each boiler for the
5-yr period (about 15,000 observations). This relationship was used to
predict boiler capacity factor as a function of age. The data indicated a
startup period lasting for about 10 yr. During this period, the relationship
was assumed linear and positive of the type y - a + bx, BoiJers ^rnns
on stream in 1978 are assumed to operate at a capacity factor of 50%,
Operation is assumed to increase at an annual rate of 1.5% through 10 yr of
age. Between ages 10 and 15, operation is assumed constant At a 65% capacity
factor, After age 15, the capacity factor is assumed to decline linearly at
an annual rate of 1,8%/yr to a minimum of 2% at 50 yr by the equation
y = a + bx.
Once boiler capacity (given from FPC) and its capacity factor were
established it was then possible to calculate megawatts to be generated by
each boiler and to calculate Btu of heat input required. This calculation
was based on the given or the assumed plant heat rate.
At this point, t«ro algorithms were used. If a plant had projected its
own megawatt production and fuel level, the projection by the utility was
assumed correct. If fuel requirements at the boiler level, based on calcu-
lated capacity factors, were less than plant level projections of megawatts to
be generated by the plant, each boiler capacity factor was adjusted upward
by a constant percentage. If fuel requirements exceeded plant megawatt
projections, then boiler capacity factors were adjusted downward by a constant
percentage. If a 30-yr-old or older boiler existed and plant megawatt could
be generated by existing newer boilers at the calculated capacity factor, the
capacity factor of the old boiler was reduced to zero. (No fuel was allocated
to those boilers.)
When the utility did not project megawatts to be generated and/or fuel
use in 1978, each boiler was assumed to operate at the calculated capacity
factor based on boiler age. Megawatts to be generated and fuel requirements
were calculated accordingly.
Completion of the above steps provided an estimate of total Btu heat
input requirements to meet projected 1978 power demands. Btu requirements
were, at the same time, projected to each individual boiler to be used in
generating electricity in 1978. The next step was to calculate fuel type and
amount to meet projected Btu requirements.
Plant Level Fuel Type, 1978
When plant level projections of fuel requirements were made, fuel type
and Btu content were also given and usually S content of each fuel was also
given. Five separate cases were identified requiring slightly different
procedures to project fuel type and amount. In all cases, amount of fuel is
a function of Btu content of the fuel and Btu heat input requirements.
185
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Case 1
This case covers all plants that reported 1973 data and that projected
fuel on Form 67. When the plant level projections for 1978 were made on
Form 67, they were assumed to be correct in all cases except when the
quantities of fuel projected would cause the plant to exceed megawatt capacity.
Where fuel quantities would cause the plant to exceed the reported capacity,
fuel quantities were reduced proportionally to operate the plant at 80% of
reported capacity. There were 625 plants in this category. In this and all
other cases projected megawatts to be generated were used as the factor to
check against and adjust to if fuel projections and megawatts to be generated
did not match.
Case 2
This case covers all plants existing in 1973 that reported plant level
fuel consumption in 1973, but did not project megawatts to be generated or
fuel quantities in 1978, and did not project an increase of >100 MW of
capacity between 1973 and 1978. The historical capacity factor profile
presented earlier is used to calculate megawatts to be generated and Btu heat
input requirements. The proportion of the total projected Btu requirements
to be met from each fuel source is assumed to be the same as used in 1973.
There were 107 plants included in this category.
Case 3
This is the same as Case 2 above except that it considers plants where
capacity has increased by >100 MW between 1973 and 1978. Fuel consumption in
1978 on the capacity existing in 1973 is calculated the same as in Case 1
above. Additional fuel consumption for the new increased capacity will be
based on the projected capacity factor as in Case 2, and the fuel type will
be determined as follows: If the plant burned oil in 1973, but no coal, the
additional fuel will be oil; otherwise, the additional fuel will be coal.
There were seven plants included in this category.
Case 4
This case covers all new plants coming online after 1973 that did not
report 1973 data, and did not project megawatts or fuel consumption for 1978.
They are projected to burn coal and to operate at the projected capacity
factor based on the historical data. There were 43 plants included in this
category.
Case 5
This case covers all new plants (coming online after 1973) that did
project megawatts to be generated and fuel consumption for 1978. This is the
same as Case 1, but a separate case number was used to allow identification
of new plants. There were 18 plants included in this category.
186
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Once these calculations were completed, Btu input requirements per
boiler had been established. The remaining problem was to determine what fuel
type each boiler will use when the plant projects more than one fuel type. It
will be recalled that when fuel type was not projected, only coal or oil was
projected as a fuel source and in no case were fuel sources mixed. Oil was
projected only if the plant had never burned coal in any boiler from 1969-73.
Where projections of mixed fuel sources were made, an algorithm was developed
to allocate all projected gas consumption first. Gas was first projected
to the largest exclusive gas boiler. If that did not take up ill gas then
remaining, gas was allocated to boilers that had historically used gas until
projected consumption was met. Oil was allocated next in the same fashion as
gas. First to largest exclusive oil boiler, and so on, until ail projected
oil was consumed. Coal was allocated last as above to the largest exclusive
coal boilers and as needed to fill any remaining need for Stu heat input re-
quirements at any boiler. The steam plant data base is complete at this
point.
Historical and projected 1978 fuel usage by type is shown in the following
tabulation:
Actual Fuel Use byJType (1969-73) and Projected_
Use by Type (19781
Coal, Oil, Gas,
Year ktons k (42-gal) bbl Mft?
1969 30,379 252,654 3,319,330
1970 314,749 323,291 3,704,726
1971 324,271 377,030 3,728,747
1972 348,694 458,390 3,707,278
187
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APPENDIX K
VARIABLE COST OF LIMESTONE AND SLUDGE DISPOSAL
189
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APPENDIX K
VARIABLE COST OF LIMESTONE AND SLUDGE DISPOSAL
The delivered cost of limestone is a major input cost item and is subject
to wide variation due to availability and f.o.b. cost of limestone. A 1972
study (Availability of Limestones and Dolomites - Task No. 1 Final Report,
by J. J. O'Donnell and A. G. Sliger of the M. W. Kellogg Company) estimated
delivered cost of high-Ca limestone in 1972 to 37 selected power plants, most
of which were located in the eastern half of the U.S. Delivered costs ranged
from $1.95-$13.00/ton. Delivered costs were under $4/ton to half the plants
and all but three in the study could have been supplied at under $6/ton.
Previous TVA studies had assumed limestone cost at $4/ton to each utility.
Because of the variability in cost found in the Kellogg study previously
mentioned, a limestone data base was developed to use in this and other
studies. This data base provides for the calculation of delivered cost of
limestone to each utility from the nearest limestone quarry. The f.o.b. price
used is the state average price in 1975 inflated by 10% to reflect 1978 costs.
Dolomite sources are excluded from the data base. According to information
developed, delivered costs of limestone in 1978 will range from $2.07-$11.23/
ton. All but 50 plants in the U.S. can be supplied at a delivered cost of
<$6/ton in 1978.
The data do not assure that limestone is of the quality required for use
in scrubbing. Further, there is no assurance that sufficient quantities exist
at producing locations to meet long-term utility needs.
The limestone data base was developed from information provided
specifically for use in this study by BOM.
A few existing plants do not have adequate land available for onsite
disposal of throwaway Ca solids from the slurry process. When this was
the case, offsite disposal charges were added. Land cost was assumed the
same. Some cost areas were different between onsite and offsite disposal
but in sum total investment was approximately equal. Miles to disposal area
were added into the cost model and transportation costs were calculated.
Costs were based on a charge of $l/ton for distances up to 3 mi and then
charges were assumed to decline linearly to a minimum of $0.20/ton mi for
distances up to 20 mi.
190
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The calculated delivered costs of limestone are shown in the following
tabulation for selected power plants.
Plant No.
0700000550
0785000100
0785000500
0790000100
1000000050
1095000200
1115001300
1395000250
1655000300
1790002550
1790002800
2455000250
2730000600
3795000350
3800000800
3840000500
4045000900
4510000100
4530000850
4740000300
4770001900
4770002100
4770003000
4770004100
4815000400
5125000650
5125000700
5250001400
5540000250
Plant name
Rose ton
Cof feen
Newton
Edwards
Deely
Conesville
Power ton
Belews Creek
Crystal River
Wans ley
Bowen
Ghent
Northport
Homer City
Martins Creek
Eddystone
Cayuga
Gas ton
Harrington
Big Bend
Johns onvi lie
Kingston
Paradise
Cumberland
Stuart
Rush Island
Sioux
Yorktown
Columbia
Mine
MW price, $/ton
1,200
616
590
602
836
1,255
1,271
2,286
964
1,792
1,820
1,011
1,511
650
1,600
940
1,062
910
634
1,136
1,482
1,723
2,558
2,660
1,831
1,150
1,100
845
527
2.66
2.37
2.37
2.37
2.21
2.41
2.37
2.44
2.06
2.67
2.67
2.22
8.24
2.62
2.62
2.62
2.22
2.39
1.90
2.06
2.35
2.24
2.35
2.35
2.41
2.37
2.37
2.44
1.91
Transport
cost, $/ton
1.61
1.15
1.61
2.07
1.15
1,61
1.61
2.30
1.61
2.07
1.15
1.15
2.30
1.61
1.15
1.61
2.07
1.15
2.07
2.07
2.30
2.07
1.15
2.07
1.61
1.61
1.61
3.45
1.15
Delivered
cost, $/ton
4.27
3.52
3.98
4.44
3.36
4.02
3.98
4.44
3.67
4.74
3.82
3.37
10.54
4.23
3.77
4.23
4.29
3.54
3.97
4.13
4.65
4.31
3.50
4.42
4.02
3.98
3.98
5.89
3.06
191
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APPENDIX L
SPECIFIC SUPPLY POINTS FOR SALE OF BYPRODUCT SMELTER ACID
CONTENTS
Tables Page
K-l Fourteen Western Smelters . , , . 194
K-2 Eastern Smelters Selling Byproduct Acid in $0.00/MBtu
and $0.35/MBtu ACFL Runs 195
K-3 Smelters Selling Byproduct Acid in $0.50/MBtu ACFL Run . . 196
K-4 Smelters Selling Byproduct Acid in $0.70/MBtu ACFL Run • • 197
193
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TABLE L-l FOURTEEN WESTERN SMELTERS
No.
065
150
151
152
153
154
155
156
157
158
159
160
175
182
Company
Gulf Resources
Phelps Dodge
Kennecott Copper
American Smelting (ASARCO)
Phelps Dodge
Magma Copper Company
Hecla Mining Company
Inspiration Con Corp
Anaconda Company
Kennecott Copper
Kennecott Copper
American Smelting (ASARCO)
Anaconda Company
Phelps Dodge
Total
Location
Kellogg
Morenci
Hayden
Hayden
Ajo
San Manual
Casa Grande
Inspiration
Anaconda
Hurley
Gar field
Tacoma
Anaconda
Hidalgo Co.
ID
AZ
AZ
AZ
AZ
AZ
AZ
AZ
MT
NM
UT
WA
MT
NM
Capacity
250,000
600,000
250,000
260,000
100,000
525,000
89,000
460,000
230,000
200,000
600,000
50,000
100,000
580,000
4,294,000
194
-------
TABLE L-2. EASTERN SMELTERS SELLING BYPRODUCT ACID
IN $0.00 AND $0.35/MBTU ACFL RUNS
' • • ~— — ~ — , __
Company
New Jersey Zinc Company
St. Joe Minerals
American Smelting (Asarco)
American Metal (Amax)
Amax Lead Company
Engelhard-Nat ' 1 Zinc
St. Joe Minerals
Cities Service Oil
American Smelting (Asarco)
American Metal (Amax)
American Smelting (Asarco)
Armco Steel
Climax Molybdenum
Climax Molybdenum
Location
Palmerton
Herculaneum
Corpus Christi
Monsanto
Salem (Buick)
Bartlesville
Josephtown
Copperhill
El Paso
Monsanto
Corpus Christi
Middle ton
Langeloth
Ft. Madison
PA
MO
TX
IL
MO
OK
PA
TO
TX
IL
TX
OH
PA
IA
Total (14 Eastern Smelters)
Average
Tons sold
26,000
14,000
7,000
12,000
7,000
9,000
54,000
200,000
16,000
288,000
76,000
2,000
47,000
60,000
818,000
58,428
CANADIAN SMELTERS
Terminal Tons sold
Buffalo
Detroit
165,000
35,000
Total 200,000
WESTERN SMELTERS
State Terminal Tons soia
Arizona
New Mexico
Utah
Montana
Houston
Chicago
Baton Rouge
Memphis
St . Louis
Memphis
118,000
304,000
76,000
96,000
46,000
98,000
Total
738,000
TOTAL SMELTER ACID
East
West
Canada
818,000
738,000
200,000
Total 1,756,000
195
-------
TABLE L-3. SMELTERS SELLING BYPRODUCT ACID
IN $0.50/MBTU ACFL RUN
"
Company
New Jersey Zinc
St. Joe Minerals
American Smelting (Asarco)
American Metal (Amax)
Amax Lead Company
Engelhard-Nat ' 1 Zinc
St. Joe Minerals
Cities Service Oil
American Smelting (Asarco)
American Metal (Amax)
American Smelting (Asarco)
Armco Steel
Climax Molybdenum
Climax Molybdenum
Location
Palmerton
Herculaneum
Corpus Christ!
Monsanto
Salem (Buick)
Bartlesville
Josephtown
Copperhill
El Paso
Monsanto
Corpus Christi
Middleton
Langeloth
Ft. Madison
PA
MO
TX
IL
MO
OK
PA
TN
TX
IL
TX
OH
PA
IA
Total (14 Eastern Smelters)
Average
Tons sold
26,000
14,000
7,000
12,000
7,000
9,000
54,000
200,000
16,000
288,000
76,000
2,000
47,000
60,000
818,000
58,428
CANADIAN SMELTERS
Terminal Tons sold
Buffalo 200,000
Detroit 0
Total
200,000
WESTERN SMELTERS
State
Total
Terminal
Tons sold
Arizona
New Mexico
Utah
Montana
Houston
Chicago
St. Louis
Baton Rouge
Houston
St. Louis
118,000
155,000
166,000
50,000
9,000
96,000
0
594,000
TOTAL SMELTER ACID
East 818,000
West 594,000
Canada 200,000
Total 1,612,000
196
-------
TABLE L-4. SMELTERS SELLING BYPRODUCT ACID
_IN_$0. 70/MBTU ACFL RUN
Company
New Jersey Zinc
St. Joe Minerals
American Smelting (Asarco)
American Metal (Amax)
Amax Lead Company
Engelhardt-Nat'l Zinc
St. Joe Minerals
Cities Service Oil
American Smelting (Asarco)
American Metal (Amax)
American Smelting (Asarco)
Armco Steel
Climax Molybdenum
Climax Molybdenum
Location
Palmer ton
Herculaneum
Corpus Christi
Monsanto
Salem (Buick)
Bartlesville
Josephtown
Copperhill
El Paso
Monsanto
Corpus Christi
Middleton
Langeloth
Ft. Madison
PA
MO
TX
IL
MO
OK
PA
TN
TX
IL
TX
OH
PA
IA
Total (14 Eastern Smelters)
Average
Tons sold
26,000
14,000
7,000
12,000
7,000
9,000
54,000
200,000
16,000
288,000
76,000
2,000
47,000
60,000
818,000
58,428
CANADIAN SMELTERS
Terminal Tons sold
Buffalo
Detroit
200,000
0
200,000
WESTERN SMELTERS
State
Terminal
Tons sold
Arizona Houston
New Mexico Chicago
Utah
Montana
Total
118,000
81,000
0
0
199,000
TOTAL SMELTER ACID
East
West
Canada
818,000
199,000
200,000
Total 1,217,000
197
-------
APPENDIX M
SCRUBBING VERSUS CLEAN FUEL WHEN A.CFL IS
$0.70/MBTU HEAT INPUT
CONTENTS
Tables Page
L-l Estimated Compliance Strategies for the Thirty-Seven Eastern
States 200
L-2 Estimated Compliance Strategies for the Western States .... 201
199
-------
TABLE M-l. ESTIMATED COMPLIANCE STRATEGIES FOR THE
THIRTY-SEVEN EASTERN STATES SCRUBBING VERSUS CLEAN FUEL
WHEN ACFL IS $0.70/MBTU HEAT INPUT
Scrubbed
(-70c) Clean fuel (>70
-------
TABLE M-2. ESTIMATED COMPLIANCE STRATEGIES FOR THE WESTERN STATES
SCRUBBING VERSUS CLEAN FUEL WHEN ACFL IS $0.70/MBTU HEAT INPUT
State
AZ
CA
NV
NM
WA
WY
Total
East
& West
Scrubbed
No. of
plants
0
0
2
0
0
1
3
116a 4
(<$0.70)
Abatement
capacity ,
ktons
STT c n
07 ^>U^
14,794 45,314
15,708 48,114
30,502 93,413
,108,963 12,583,699
Clean
No. of
plants
2
1
1
1
1
0
6
81a
fuel (>$0.70)
Abatement
capacity,
ktons
S H7
4,443 13
317
307
70
26
5,163 15
228,849 700
,609
971
940
214
80
,812
,850
a. Ten plants are scrubbing and using clean fuel.
201
-------
APPENDIX N
FEEDSTOCK ANALYSIS FOR S-BURNING ISO PLANTS IN MODEL RUNS
CONTENTS
Tables Page
N-I Acid Plants Buying Abatement Byproduct Acid in $0.00/MBtu
ACFL Model Run ......... . ............. . 205
N-2 Acid Plants Buying Abatement Byproduct Acid in $0.35/MBtu
ACFL Model Run . . ..................... . 206
N-3 Acid Plants Buying Abatement Byproduct Acid in $0.50/MBtu
ACFL Model Run ......... . . .......... ... 207
N-4 Acid Plants Buying Abatement Byproduct Acid in $0.70/MBtu
ACFL Model Run .... .............. ...... 208
N-5 Acid Plants Buying Abatement Byproduct Acid and Frasch S
in $0.00/MBtu ACFL Model Run ....... , . . . ...... 209
N-6 Acid Plants Buying Abatement Byproduct Acid and Frasch S
in $0.35/MBtu ACFL Model Run .... ........ ..... 210
N-7 Acid Plants Buying Abatement Byproduct Acid and Frasch S
in $0.50/MBtu ACFL Model Run ............... . . 211
N-8 Acid Plants Buying Abatement Byproduct Acid and Frasch S
in $0.70/MBtu ACFL Model Run ................. 212
N-9 Fifty-Eight Acid Plants Buying Frasch S Only in $0.00/MBtu
ACFL Model Run ........................ 213
N-10 Forty-Two Acid Plants Buying Frasch S Only in $0.35/MBtu
ACFL Model Run ........................ 214
N-ll Thirty Acid Plants Buying Frasch S Only in $0.50/MBtu
ACFL Model Run ........................ 215
N-12 Twenty-Eight Acid Plants Buying Frasch S Only in $0.70/MBtu
ACFL Model Run ........................ 216
(continued)
203
-------
APPENDIX N (continued)
CONTENTS
Tables Page
N-13 Set I - $0.00/MBtu ACFL Model Run 217
N-14 Set II - $0.35/MBtu ACFL Model Run . 218
N-15 Set III - $0.50/MBtu ACFL Model Run 219
N-16 Set IV - $0.70/MBtu ACFL Model Run 220
204
-------
TABLE N-l. ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID
IN $0.00/MBTU ACFL MODEL RUN
• —
«
15
16
17
19
27
32
44
51
52
60
68
72
75
79
85
88
91
95
98
104
107
108
113
114
126
128
130
132
133
135
137
138
Company
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition
Borden Chemical
Detroit Chemical
E. I. Dupont
Eastman Kodak
W. R. Grace
Kerr-McGee
Minn Mine & Smelt
Monsanto Company
NL Industries
Olisi Corporation
Olin Corporation
Pennsalt Chemicals
Reichhold Chemical
Royster Company
Stauffer Chera
Swift Chemicals
Swift Chemicals
US Industrial
US Industrial
American Cyanamid
Home Guano Co
Columbia Nitrogen
Marion Mfg
E. I. Dupont
Cities Service
Allied Chemical
El Paso Products
TOTAL
Location
Bound Brook
Mobile
Joliet
Ka lama? oo
Tyner
Streator
Detroit
Cornwell Hghts
Rochester
Joplin
Cottondale
Copley
E. St. Louis
St. Louis
N. Little Rock
Pasadena
Tulsa
Tuscaloosa
Norfolk
Ft. Worth
Calumet City
Wilmington
Dubuque
Desoto
Fortier
Do than
Moultrie
Indianapolis
Gibbstown
Monmouth Jet
Cleveland
El Paso
i
NJ
AL
IL
MI
TN
IL
MI
PA
NY
MO
FL
OH
IL
MO
AR
TX
OK
AL
VA
TX
IL
NC
IA
KS
LA
AL
GA
IN
NJ
NJ
OH
TX
3
Average size
Average size
Capacity
65,000
26,000
50,000
25,000
132,000
40,000
35,000
75,000
6,000
98,000
15,000
65,000
265,000
455,000
105,000
500,000
110,000
55,000
20,000
120,000
40,000
32,000
98,000
105,000
50,000
11,000
24,000
56,000
110,000
35,000
130,000
86,000
,039,000
TPY
TPD
Year
1945
1967
1937
1967
1941
1951
1937
1941
1930
1954
1950
1942
1937
1958
1947
1946
1937
1957
1937
1925
1942
1942
1940
1940
1967
1937
1947
1947
1957
1971
1909
1967
94,968
286
Steam
plants Smelters
65,000
26,000
50,000
25,000
132,000
40,000
35,000
65,000
6,000
7,000
15,000
65,000
265,000
95,000
105,000
118,000
9,000
55,000
20,000
83,000
40,000
32,000
93,000
60,000
50,000
11,000
24,000
56,000
20,000
35,000
38,000
16,000
1,756,000
Port
Sulphur
0
0
0
0
0
0
0
10,000
0
91,000
0
0
0
360,000
0
382,000
101,000
0
0
37,000
0
0
5,000
45,000
0
0
0
0
90,000
0
92,000
70,000
1,283,000
Avoidable
production
cost
46.19
41.19
44.08
46.96
38.42
44.70
57.91
38.91
90.47
39.68
56.44
50.35
34.04
31.12
44.27
30.30
40.44
39.15
51.70
37.68
45.66
45.25
38.05
40.29
40.31
66.35
49.31
44.82
40.52
38.62
45.58
38.12
Average year
1946
205
-------
TABLE N-2. ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID
IN $0.35/MBTU ACFL MODEL RUN
. . - . • — '
//
10
13
15
16
17
19
20
27
28
32
33
44
46
48
49
50
51
52
60
61
68
70
72
75
79
85
88
91
95
96
98
102
104
107
108
109
113
116
119
120
126
128
130
132
133
135
137
138
Company
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition
Army Ammunition
Borden Chemical
Borden Chemical
Detroit Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
Eastman Kodak
W. R. Grace
W. R. Grace
Kerr-McGee
LJ & M LaPlace
Minn Mine & Smelt
Monsanto
NL Industries
Olin Corporation
Olin Corporation
Pennsalt Chemicals
Relchhold Chemical
Royster Company
Royster Company
Stauffer Chemicals
Stauffer Chemicals
Swift Chem Co
Swift Chem Co
Swift Chem Co
US Industrial
USS Agri-Chem
Weaver Fertilizer
Acme (Wright)
Fertilizer
American Cyanamid
Home Guano
Columbia Nitrogen
Marion
Manufacturing
E. I. Dupont
Cities Service
Allied Chemical
El Paso Products
TOTAL
Location
Nitro
Front Royal
Bound Brook
Mobile
Joliet
Kalamazoo
Hamilton
Tyner
Radford
Streator
Norfolk
Detroit
Richmond
North Bend
Deepwater
Cleveland
Cornwell Hts
Rochester
Joplin
Charleston
Cottondale
Edison
Copley
E.St. Louis
St. Louis
Little Rock
Pasadena
Tulsa
Tuscaloosa
Mulberry
Norfolk
LeMoyne
Fort Worth
Calumet Cty
Wilmington
Norfolk
Dubuque
Navassa
Norfolk
Acme
Fortier
Do than
Moultrie
Indianapolis
Gibbstown
Monmouth Jet
Cleveland
El Paso
Capacity
WV
VA
NJ
AL
IL
MI
OH
TO
VA
IL
VA
MI
VA
OH
NJ
OH
PA
NY
MO
SC
FL
NJ
OH
IL
MO
AR
TX
OK
AL
FL
VA
AL
TX
IL
NC
VA
IA
NC
VA
NC
LA
AL
GA
IN
NJ
NJ
OH
TX
135
160
65
26
50
25
95
132
212
40
80
35
90
175
125
200
75
6
98
42
15
75
65
265
455
105
500
110
55
325
20
250
120
40
32
35
98
70
35
48
50
11
24
56
110
35
130
86
5,086
Average
Average
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
TPY
TPD
Average Year
Year
1940
1945
1945
1967
1937
1967
1967
1941
1940
1951
1937
1937
1946
1956
1937
1937
1941
1930
1954
1937
1950
1967
1942
1937
1958
1947
1946
1937
1957
1967
1937
1957
1925
1942
1944
1946
1940
1967
1967
1968
1967
1937
1947
1947
1957
1971
1909
1967
2,
105,958
321
1948
Steam
plants
135,000
107,837
0
26,000
0
0
95,000
132,000
78,000
0
80,000
35,000
90,000
175,000
99,000
200,000
32,426
6,000
91,000
0
15,000
0
11,000
0
0
105,000
0
101,000
55,000
250,963
20,000
250,000
0
0
32,000
35,000
0
70,000
35,000
3,209
0
11,000
0
56 , 000
110,000
0
81,000
0
623,435
Avoidable
Port production
Smelters
65
50
25
134
40
26
42
7
42
57
54
265
455
127
9
83
40
60
50
24
35
49
16
1,756
0
0
,000
0
,000
,000
0
0
,000
,000
0
0
0
0
,000
0
,574
0
,000
,000
0
,426
,000
,000
,000
0
,000
,000
0
0
0
0
,000
,000
0
0
,000
0
0
0
,000
0
,000
0
0
,000
,000
,000
,000
Sulphur
0
52,163
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
17,574
0
0
0
0
373,000
0
0
74,037
0
0
37,000
0
0
0
38,000
0
0
44,791
0
0
0
0
0
0
0
70.000
706,565
cost
38.03
35.94
46.19
41.19
44.08
46.96
36.76
38.42
35.95
44.70
38.06
57.91
37.27
42.41
36.21
43.25
38.91
90.47
39.68
42.51
56.44
34.40
50.35
34.04
31.12
44.27
30.30
40.44
39.15
35.60
51.70
35.06
37.68
45.66
45.25
44.28
38.05
38.72
44.55
36.22
40.31
66.35
49.51
44.82
40.50
38.62
45.58
38.12
206
-------
TABLE N-3. AC1.D PLANTS BUYING ABATEMENT BYPRODUCT ACID
IN $0.50/MBTU ACFL MODEL RUN
Steam
#
10
11
13
15
16
17
19
20
27
28
32
33
40
44
46
48
49
50
51
52
53
56
60
61
62
68
70
72
74
75
77
79
83
85
88
91
95
96
98
102
104
107
108
109
113
114
116
119
120
126
128
130
131
132
133
134
135
136
137
138
Company
Allied Chemical
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition
Army Ammunition
Borden Chemical
Borden Chemical
Cities Service
Detroit Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
Eastman Kodak
Essex Chemical
Gardinier
W. R. Grace
W. R. Grace
W. R. Grace
Kerr-Mc.Gee
LJ & M LaPlace
Minn Mine & Smelt
Mobil Oil
Monsanto Co
Monsanto Co
NL Industries
Occidental Ag Chem
Olin Corporation
Olin Corporation
Fennsalt Chemicals
Reichhold Chemical
Royster Company
Royster Company
Stauffer Chemical
Stauffer Chemical
Swift Chemicals
Swift Chemicals
Swift Chemicals
US Industrial
US Industrial
USS Agri-Chem
Weaver Fertilizer
Acme (Wright)
Fertilizer Co
American Cyanamid
Home Guano Co
Columbia Nitrogen
US Industrial Chem
Marion
Manufacturing
E. I. Dupont
E. I. Dupont
Cities Service Oil
USS Agri-Chem
Allied Chemicals
El Paso Products
TOTAL
Location
Nitro
Hopewell
Front Royal
Bound Brook
Mobile
Joliec
Kalamazoo
Hamilton
Tyner
Radford
Streator
Norfolk
Augusta
Detroit
Richmond
North Bend
Deepwater
Cleveland
Cornwell Hts
Rochester
Newark
Tampa
Joplin
Charleston
Bartow
Cottondale
Edison
Copley
Depue
E. St. Louis
El Dorado
St. Louis
Plainview
N. Little Rk
Pasadena
Tulsa
Tuscaloosa
Mulberry
Norfolk
LeMoyne
Fort Worth
Calumet Cty
Wilmington
Norfolk
Dubuque
Desoto
Navaasa
Norfolk
Acme
For tier
Dothan
Moultrie
Tuscola
Indianapolis
Gibbstown
Linden
Monmouth Jet
Wilmintgon
Cleveland
El Paso
WV
VA
VA
NJ
AL
IL
MI
OK
TN
VA
IL
VA
GA
MI
VA
OH
NJ
OH
PA
NY
NJ
FL
MO
SC
FL
FL
NJ
OH
IL
IL
AR
MO
TX
AR
TX
OK
AL
FL
VA
AL
TX
IL
KC
VA
IA
KS
NC
VA
NC
LA
AL
GA
IL
IN
NJ
NJ
NJ
NC
OH
TX
Average
Average
Capacity
135,000
200,000
160,000
65,000
26,000
50,000
25,000
95,000
132,000
212,000
40,000
80,000
125,000
35,000
90,000
175,000
125,000
200,000
75,000
6,000
180,000
450,000
98,000
42.000
320,000
15,000
75,000
65,000
420,000
265,000
100,000
455,000
100,000
105,000
500,000
110,000
55,000
325,000
20,000
250,000
120,000
40,000
32,000
35,000
98,000
105,000
70,000
35,000
48,000
50,000
11,000
24,000
170,000
56,000
110,000
325,000
35,000
70,000
130,000
86,000
7,651,000
TPY 127
TPD
Average Year
Year
1940
1965
1945
1945
1967
1937
1967
1967
1941
1940
1951
1937
1967
1937
1946
1956
1937
1937
1941
1930
1956
1937
1954
1937
1960
1950
1950
1942
1967
1937
1960
1958
1963
1947
1946
1937
1957
1967
1937
1957
1925
1942
1944
1946
1940
1940
1967
1967
1968
1967
1937
1947
1975
1947
1957
1937
1971
1968
1909
1967
,516
386
1950
Plants
135
200
160
65
26
50
25
95
132
12
40
80
125
35
90
175
99
198
75
6
28
450
91
42
6
15
26
420
145
100
176
95
92
101
55
325
20
250
37
40
32
35
98
45
70
35
48
50
11
24
170
56
110
46
35
70
94
5,370
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,265
,000
,000
,000
,431
,000
,735
0
,000
,546
,000
,480
,195
,974
0
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,000
,751
,000
,000
,000
0
,377
Smelters
200
26
2
151
7
48
65
119
278
12
498
9
83
60
36
16
1,612
0
0
0
0
0
0
0
0
0
,000
0
0
0
0
0
0
,000
,000
0
G
,735
0
,000
0
0
0
,265
,000
0
,454
0
,520
0
,026
,000
,000
0
0
0
0
,000
0
0
0
0
,000
0
0
0
0
0
0
0
0
0
0
0
0
,000
,000
,000
Port
Sulphur
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
313,569
0
0
0
0
0
0
0
4,805
0
2,000
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
278,249
0
0
0
70,000
668,623
Avoidable
production
cost
38.03
35.50
35.94
46.19
41.19
44.08
46.96
36.76
38.42
35.95
44.70
38.06
32.51
57.91
37.27
42.41
36.21
43.25
38.91
90.47
33.20
34.17
39.68
42.51
33.81
56.44
34.40
50.35
31.19
34.04
35.03
31.12
36.84
44.27
30 . 30
40.44
39.15
35.60
51.70
35.06
37.68
45.66
45.25
44.28
38.05
40.29
38.72
44.55
36.22
40.31
66.35
49.51
32.12
44.82
40.50
32.78
38.62
33.94
45.58
38.12
207
-------
TABLE N-4. ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID
IN $0.70/MBTU ACFL MODEL RUN
. — . . . , , • • "
tl_
10
11
13
15
16
17
18
19
20
27
28
32
33
40
44
46
48
49
50
51
52
53
56
60
61
62
68
70
72
74
75
77
79
83
85
86
88
91
95
96
98
102
104
107
108
109
113
114
116
119
120
126
128
130
131
132
133
134
135
136
137
138
Company
Allied Chemical
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
American Cyanamid
Array Ammunitions
Army Ammunitions
Borden Chemical
Borden Chemical
Cities Service
Detroit Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E, I. Dupont
E. I. Dupont
Eastman Kodak
Essex Chem Co
Gardinier
W. R. Grace
W. R. Grace
W. R. Grace
Kerr-McGee
LJ & M LaPlace
Minn Mine & Smelt
Mobil Oil
Monsanto
Monsanto
NL Industries
Occidental Ag Chem
Olin Corporation
Olin Corporation
Olin Corporation
Pennsalt Chemical
Reichhold Chemical
Royster Company
Royster Company
Stauffer Chemical
Stauffer Chemical
Swift Chem Co
Swift Chem Co
Swift Chem Co
US Industrial
US Industrial
USS Agri Chem
Weaver Fertilizer
Acme (Wright)
Fertilizer Co
American Cyanamid
Home Guano Co
Columbia Nitrogen
US Industrial
Marion
Manufacturing
E. I. Dupont
E. I. Dupont
Cities Service
USS Agri Chem
Allied Chem
El Paso Products
TOTAL
Location
Nitro
Hopewell
Front Royal
Bound Brook
Mobile
Joliet
Savannah
Kalamazoo
Hamilton
Tyner
Radford
Streator
Norfolk
Augusta
Detroit
Richmond
North Bend
Deepwater
Cleveland
Cornwell Hts
Rochester
Newark
Tampa
Joplin
Charleston
Bartow
Cottondale
Edison
Copley
Depue
E. St. Louis
El Dorado
St. Louis
Plainview
N. Little Rck
Baltimore
Pasadena
Tulsa
Tuscaloosa
Mulberry
Norfolk
LeMoyne
Fort Worth
Calumet Cty
Wilmington
Norfolk
Dubuque
Desoto
Navassa
Norfolk
Acme
Fortier
Do than
Moultrle
Tuscola
Indianapolis
Gibbstown
Linden
Monmouth Jet
Wilmington
Cleveland
El Paso
WV
VA
VA
NJ
AL
IL
GA
MI
OH
TN
VA
IL
VA
GA
MI
VA
OH
NJ
OH
PA
NY
NJ
FL
MO
SC
FL
FL
NJ
OH
IL
IL
AR
MO
TX
AR
MD
TX
OK
AL
FL
VA
AL
TX
IL
NC
VA
IA
KS
NC
VA
NC
LA
AL
GA
IL
IN
NJ
NJ
NJ
NC
OH
TX
Capacity
135,000
200,000
160,000
65,000
26,000
50,000
216,000
25,000
95,000
132,000
212,000
40,000
80,000
125,000
35,000
90,000
175,000
125,000
200,000
75,000
6,000
180,000
450,000
98,000
42,000
320,000
15,000
75,000
65,000
420,000
265,000
100,000
455,000
100 , 000
105,000
350,000
500,000
110,000
55,000
325,000
20,000
250,000
120,000
40,000
32,000
35,000
98,000
105,000
70,000
35,000
48,000
50,000
11,000
24,000
170,000
56,000
110,000
325,000
35,000
70,000
130,000
86,000
8,217,000
Average
Average
Average
Year
1940
1965
1945
1945
1967
1937
1967
1967
1967
1941
1940
1951
1937
1967
1937
1946
1956
1937
1937
1941
1930
1956
1937
1954
1937
1960
1950
1967
1942
1967
1937
1960
1958
1963
1947
1941
1946
1937
1957
1967
1937
1957
1925
1942
1944
1946
1940
1940
1967
1967
1968
1967
1937
1947
1975
1947
1957
1937
1971
1968
1909
1967
TPY
TPD
year
Steam
plants
135,000
200,000
59,000
65,000
26,000
9,000
216,000
25,000
95,000
132,000
212,000
40,000
80,000
125,000
35,000
90,000
173,000
99,000
200,000
75,000
6,000
75,016
450,000
91,000
42,000
320,000
15,000
56,947
65,000
420,000
0
100,000
420,000
95,195
105,000
35,037
0
87,000
55,000
325,000
20,000
250,000
120,000
0
0
35,000
98,000
45,000
20,000
35,000
0
50,000
11,000
24,000
170,000
56,000
110,000
0
35,000
0
130,000
5,523
6,068,718
132,532
401
1950
Avoidable
Port production
Smelters
101
41
2
26
104
7
18
265
35
500
23
40
32
60
50
48
76
70
16
1,516
0
0
,000
0
0
,000
0
0
0
0
0
0
0
0
0
0
,000
,000
0
0
0
,984
0
,000
0
0
0
,053
0
0
,000
0
,000
0
0
0
,000
,000
0
0
0
0
0
,000
,000
0
0
,000
,000
0
,000
0
0
0
0
0
0
,963
0
,000
0
,000
,000
Sulphur
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
4,805
0
314,963
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
248,037
0
0
0
64,477
632,282
cost
38.
35.
35.
46.
41.
44.
29.
46.
36.
38.
35.
44.
38.
32.
57.
37.
42.
36.
43.
38.
90.
33.
34.
39.
42.
33.
56.
34.
50.
31.
34.
35.
31.
36.
44.
32.
30.
40.
39.
35.
51.
35.
37.
45.
45.
44.
38.
40.
38.
44.
36.
40.
66.
49.
32.
44.
40.
32.
38.
33.
45.
38.
03
50
94
19
19
08
80
96
76
42
95
70
06
51
91
27
41
21
25
91
47
20
17
68
51
81
44
40
35
19
04
03
12
84
27
48
30
44
15
60
70
06
68
66
25
28
05
29
72
55
22
31
35
51
12
82
50
78
62
94
58
12
208
-------
TABLE N-5. ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID AND FRASCH S
IN $0.00/MBTU ACFL MODEL RUN
Number
51
60
79
88
91
104
113
114
133
137
138
Acid plant
E. I. Dupont DeNeiaours
W. R, Grace
N. L. Industries
Olin Corporation
Permsalt Chemical
Stauffer Chemicals
U.S. Industrial Chemical
U.S. Industrial Chemical
E. I. Dupont DeNemours
Allied Chera Corporation
El Paso Products
Smelter Location
Canada-Buffalo
Amax Lead Company Salem (Buick) , Mo
St. Joe Minerals Herculaneum, Mo
American Metal (Amax)
Arizona-Houston
Engelhard-National Zinc Bartlesville, Ok
American Smelt (Asarco) Corpus Christi, Tx
New Mexico-Chicago
Climax Molybdenum Ft. Madison, la
New Jersey Zinc Co. Palmerton, Pa
Armco Steel
Climax Molybdenum Langeloth, Pa
Amer Smelt (Asarco) El Paso, Tx
Acid demand balance
Addition
acid
demand
tons/yr
10,000
91,000
360,000
382,000
101,000
37,000
5,000
45,000
90,000
92,000
70,000
1,283,000
209
-------
TABLE N-6. ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID AND FRASCH S
IN $0.35/MBTU ACFL MODEL RUN
Number
70
88
104
113
138
Number
13
96
120
Acid plant Smelter
LJ & M Canada-Buffalo
Olin Corporation Arizona; New Mexico-
Houston
Stauffer Chemical American Smelt (Asarco)
U.S. Industrial Chemical Climax Molybdenum
El Paso American Smelt (Asarco)
Company Steam plant
Allied Chemical Paradise
Royster Company Big Bend
Acme (Wright) Fert Belews Creek
Location
Canada
Arizona; New Mexico
Corpus Christi, Tx
Fort Madison, la
El Paso, Tx
Subtotal
Number
6 4770003000
5 4740000300
1 1395000250
Subtotal
Additional
acid
demand
tons/yr
17,574
373,000
37,000
38,000
70,000
535,574
Additional
acid demand
tons/yr
52,163
74,037
44,791
170,991
Acid demand balance 706,565
210
-------
TABLE N-7. ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID AND FRASCH S
IN $0.50/MBTU ACFL MODEL RUN
. _
Number Acid plant
88 Olin Corporation
138 El Paso Products
Number Company
62 W. R. Grace
83 Occidental Ag. Chem
134 E. I. Dupont DeNemours
Smelter
Arizona; New Mexico-
Houston
Asarco
Steam plant
Crystal River
Wansley
Harrington
Roseton
Additional
acid demand
Location tons/yr
Arizona ;New Mexico 2,000
El Paso 70,000
Subtotal 72,000
Additional
acid demand
Number tons/yr
14 1655000300 313,569
15 1790002550
29 4530000850 4,805
3 7000000550 278,249
Subtotal 596,623
Acid demand balance 668,623
211
-------
TABLE N-8. ACID PLANTS BUYING ABATEMENT BYPRODUCT ACID AND FRASCH S
IN $0.70/MBTU ACFL MODEL RUN
Number
134
138
Number
83
86
Company Buying Smelter
E. I. Dupont DeNemours Canada-Buffalo
El Paso Products Asarco
Company Buying Steam plant
Occidental Ag Chem Harrington
Olin Corporation Homer City
Additional
acid demand
Smelter Location tons/yr
Canada 248,037
El Paso 64,477
Subtotal 312,514
Additional
acid demand
Number tons/yr
41 4530000850 4,805
34 3795000350 314,963
Subtotal 319,768
Acid demand balance 632,282
212
-------
TABLE N-9. FIFTY-EIGHT ACID PLANTS BUYING FRASCH S ONLY
IN $0,00/MBTU ACFL MODEL RUN
—
Avoidable
production
#
1
2
7
10
11
13
18
20
21
28
31
33
34
36
37
38
40
43
46
48
49
50
53
54
55
56
57
58
61
62
63
66
67
70
73
74
76
77
83
84
86
96
102
109
110
111
115
116
117
119
120
127
129
131
134
136
142
176
Company
Agrico Chem-Williams
Agrico Chem-Williams
Allied Chemical
Allied Chemical
A3 lied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
American Cyanamid
Army Ammunition Pit
Beker Industries
Borden Chemical
Borden Chemical
CF Industries
CF Industries
CF Industries
Cities Service
Delta Chemical
E. I. Dupont
E. I. Dupont
E. I. Dupont
E. I. Dupont
Essex Chemical
Farmland industries
Freeport Minerals
Gardinier
Gardinier
Gardinier
W. E. Grace
W. R. Grace
W. R. Grace
International Miner
W. R. Grace
LJ & M LaFlace
Miss Chem Corporation
Kcbii Oil
Monsanto
Monsanto
Occidental Ag Chen
Occidental Ag Chem
Olin Corporation
Royster Company
Stauffer Chemicals
Swift Chemicals
Swift Chemicals
Texas gulf Inc.
USS Agri Chem
USS Agri Chem
USS Agri Chem
Weaver Fertilizer
Acme (Wright) Pert Co
ML Industries
Englehardt McConser
US Industrial Chem
E. I. Dupont
USS Agri Chem
American Cyanamid
Texas gulf Inc.
TOTAL
Location
Pierce
Donaldsville
Geismar
Nitro
Hopewell
Front Royal
Savannah
Hamilton
Linden
Radford
Taft
Norfolk
Port Manatee
Plant City
Bonnie
Bonnie
Augusta
Searsport
Richmond
North Bend
Deepwater
Cleveland
Newark
Pierce
Uncle Sam
Tampa
Tampa
Tampa
Charleston
Bar tow
Bar tow
Bonnie
Bartow
Edison
Pascagoula
Dupue
Everett
El Dorado
Plainview
White Springs
Baltimore
Mulberry
LeMoyne
Norfolk
Agricola
Lee Creek
Bartow
Navassa
Ft. Meade
Norfolk
Acme
Sayreville
Nichols
Tuscola
Linden
Wilmington
Fortier
Lee Creek
Average TPY 503
Average TPD 1
Average year
FL
LA
LA
WV
VA
VA
GA
OH
NJ
VA
LA
VA
FL
FL
FL
FL
GA
ME
VA
OH
NJ
OH
NJ
FL
LA
FL
FL
FL
SC
FL
FL
FL
FL
NJ
MS
IL
MA
AR
TX
FL
MD
FL
AL
VA
FL
NC
FL
NC
FL
VA
NC
NJ
FL
IL
NJ
NC
LA
NC
,414
,525
1961
Capacity
1,200,000
1,200,000
500,000
135,000
200,000
160,000
216.000
95,000
245,000
212,000
525,000
80,000
490,000
1,550,000
1,190,000
660,000
125,000
75,000
90,000
175,000
125,000
200,000
180,000
1,226,000
2,160,000
450,000
1,050,000
883,000
42,000
320,000
480,000
1,980,000
1,280,000
75,000
1,220,000
420,000
120,000
100,000
100,000
1,650,000
350,000
325,000
250,000
35,000
220,000
1,357,000
280,000
70,000
540,000
35,000
48,000
560,000
400,000
170,000
325,000
70,000
530,000
449,000
29,198,000
Year
1975
1975
1968
1940
1965
1945
1967
1967
1970
1940
1965
1937
1967
1967
1967
1976
1967
1942
1946
1956
1937
1937
1956
1965
1969
1937
1974
1977
1937
1960
1960
1975
1977
1967
1958
1967
1969
1960
1963
1967
1941
1976
1957
1946
1976
1966
1964
1976
1963
1976
1968
1937
1945
1975
1937
1968
1978
1976
cost
25.64
28.45
27.26
38.03
35.50
35.94
29.80
36.76
29.82
35.95
27.53
38.06
27.60
25.85
26.35
26.21
32.51
39.36
37.27
42.41
36.21
43.25
33.20
26,50
25.23
34.17
28.26
31.72
42.41
33.81
32.49
25.19
30.96
34.40
27.27
31.19
32.30
35.03
36.84
26.87
32.48
35.60
35.06
44.28
32.73
30.30
29.12
38.72
27.92
44.55
36.22
31.41
30.88
32.12
32.78
33.94
29.75
31.76
213
-------
TABLE N-10. FORTY-TWO ACID PLANTS BUYING FRASCH S ONLY
IN $0.35/MBTU ACFL MODEL RUN
ft
I
2
7
11
18
21
31
34
36
37
38
40
43
53
54
55
56
57
58
62
63
66
67
73
74
76
77
83
84
86
110
111
114
115
117
127
129
131
134
136
142
176
Company
Agrico Chem-Williams
Agrico Chem-Williams
Allied Chemical
Allied Chemical
American Cyanamid
American Cyanamid
Beker Industries
Borden Chemical
CF Industries
CF Industries
CF Industries
Cities Service
Delta Chemicals
Essex Chemicals
Farmland Industries
Freeport Minerals
Gardinier
Gardihier
Gardinier
W. R. Grace
W. R. Grace
International Miner
W. R. Grace
Miss Chen Corporation
Mobil Oil
Monsanto
Monsanto
Occidental Ag Chem
Occidental Ag Chem
01 In Corporation
Swift Chemicals
Texas gulf Inc.
US Industrial Chem
USS Agri Chem
USS Agri Chem
NL Industries
Englehardt McConser
US Industrial Chem
E. I. Dupont
USS Agri Chem
American Cynamid
Texas gulf Inc.
TOTAL
Locat ion
Pierce
Donaldsville
Geismar
Hopewell
Savannah
Linden
Taft
Port Manatee
Plant City
Bonnie
Bonnie
Augusta
Searsport
Newark
Pierce
Uncle Sam
Tampa
Tampa
Tampa
Bartow
Bartow
Bonnie
Bartow
Pascagoula
Dupue
Everett
£1 Dorado
Plainview
White Springs
Baltimore
Agricola
Lee Creek
Desoto
Bartow
Ft. Meade
Sayreville
Nichols
Tuscola
Linden
Wilmington
Fortier
Lee Creek
FL
LA
LA
VA
GA
NJ
LA
FL
FL
FL
FL
GA
ME
NJ
FL
LA
FL
FL
FL
FL
FL
FL
FL
MS
IL
MA
AR
TX
FL
MD
FL
NC
KS
FL
FL
NJ
FL
IL
NJ
NC
LA
NC
Capacity
1,200,000
1,200,000
500,000
200,000
216,000
245,000
525,000
490,000
1,550,000
1,190,000
660,000
125,000
75,000
180,000
1,226,000
2,160,000
450,000
1,050,000
883,000
320,000
480,000
1,980,000
1,280,000
1,220,000
420,000
120,000
100,000
100,000
1,650,000
350,000
220,000
1,357,000
105,000
280,000
540,000
560,000
400,000
170,000
325,000
70,000
530,000
449.000
27,151,000
Year
1975
1975
1968
1965
1967
1970
1965
1967
1967
1967
1976
1967
1942
1956
1965
1969
1937
1974
1977
1960
1960
1975
1977
1958
1967
1969
1960
1963
1967
1941
1976
1966
1940
1964
1963
1937
1945
1975
1937
1968
1978
1976
Avoidable
production
cost
25.64
28.45
27.26
35.30
29.80
29.82
27.53
27.60
25.85
26.35
26.21
32.51
39.36
33.20
26.50
25.23
34.17
28.26
31.72
33.81
32.49
25.19
30.96
27.27
31.19
32.30
35.03
36.84
26.87
32.48
32.73
30.30
29.12
27.92
31.41
30.88
32.12
32.78
33.94
29.75
31.76
Average TPY 646,452
Average TPD 1,958
Average year
1964
214
-------
TABLE N-ll. THIRTY ACID PLANTS BUYING FRASCH S ONLY
IN $0.50/MBTU ACPL MODEL RUN
-- • - — --- - - - — —
J_
I
2
7
18
21
31
34
36
37
38
43
54
55
57
58
63
66
67
73
76
84
86
110
111
115
117
127
129
142
176
Company
Agrico Chem Williams
Agrico Chem Williams
Allied Chemical
American Cyanamid
American Cyanamid
Beker Industries
Borden Chemicals
CF Industries
CF Industries
CF Industries
Delta Chemicals
Farmland Industries
Freeport Minerals
Gardinier
Gardinier
W. R. Grace
International Miner
W. R. Grace
Miss Chem Corporation
Monsanto
Occidental Ag Chem
Olin Corporation
Swift Chemicals
Texasgulf Inc.
USS Agri Chem
USS Agri Chem
NL Industries
Englehardt McConser
American Cyanamid
Texasgulf Inc.
TOTAL
Location
Pierce
Donaldsville
Geismar
Savannah
Linden
Taft
Port Manatee
Plant City
Bonnie
Bonnie
Searsport
Pierce
Uncle Sam
Tampa
Tampa
Bar tow
Bonnie
Bartow
Pascagoula
Everett
White Springs
Baltimore
Agricola
Lee Creek
Bartow
Ft . Meade
Sayreville
Nichols
Fortier
Lee Creek
FL
LA
LA
GA
NJ
LA
FL
FL
FL
FL
ME
FL
LA
FL
FL
FL
FL
FL
MS
MA
FL
MD
FL
NC
FL
FL
NJ
FL
LA
NC
Capacity
1,200,000
1,200,000
500,000
216,000
245,000
525,000
490,000
1,550,000
1,190,000
660,000
75,000
1,226,000
2,160,000
1,050,000
883,000
480,000
1,980,000
1,280,000
1,220,000
120,000
1,650,000
350,000
220,000
1,357,000
280,000
540,000
560,000
400,000
530,000
449,000
24,586,000
Year
1975
1975
1968
1967
1970
1965
1967
1967
1967
1976
1942
1965
1969
1974
1977
1960
1975
1977
1958
1969
1967
1941
1976
1966
1964
1963
1937
1945
1978
1976
Avoidable
production
cost
25.64
28.45
27.26
29.80
29.82
27.53
27.60
25.85
26,35
26.21
39.36
26.50
25.23
34.17
31.72
32.49
25.19
30.96
27.27
32.30
26.87
32.48
32.73
30.30
29.12
27.92
31.41
30.88
29.75
31.76
Average TPY 819,533
Average TPD 2,483
Average year 1966
215
-------
TABLE N-12. TWENTY-EIGHT ACID PLANTS BUYING FRASCH S ONLY
IN $0.70/MBTU ACFL MODEL RUN
//
1
2
7
21
31
34
36
37
38
43
54
55
57
58
63
66
67
73
76
84
110
111
115
117
127
129
142
176
Company
Agri Chem Williams
Agri Chem Williams
Allied Chemical
American Cyanamid
Beker Industries
Borden Chemicals
CF Industries
CF Industries
CF Industries
Delta Chemicals
Farmland Industries
Freeport Minerals
Gardinier
Gardinier
W. R. Grace
International Miner
W. R. Grace
Miss. Chem Corporation
Monsanto
Occidental Ag Chem
Swift Chemicals
Texasgulf Inc.
USS Agri Chem
USS Agri Chem
ML Industries
Englehardt McConser
American Cyanamid
Texasgulf Inc
TOTAL
Location
Pierce
Donaldsville
Geismar
Linden
Taft
Port Manatee
Plant City
Bonnie
Bonnie
Searsport
Pierce
Uncle Sam
Tampa
Tampa
Bartow
Bonnie
Bartow
Pascagoula
Everett
White Springs
Agricola
Lee Creek
Bartow
Ft. Meade
Sayreville
Nichols
Fortier
Lee Creek
FL
LA
LA
NJ
LA
FL
FL
FL
FL
ME
FL
LA
FL
FL
FL
FL
FL
MS
MA
FL
FL
NC
FL
FL
NJ
FL
LA
NC
Capacity
1,200,000
1,200,000
500,000
245,000
525,000
490,000
1,550,000
1,190,000
660,000
75,000
1,226,000
2,160,000
1,050,000
883,000
480,000
1,980,000
1,280,000
1,220,000
120,000
1,650,000
220,000
1,357,000
280,000
540,000
560,000
400,000
530,000
449,000
24,020,000
Year
1975
1975
1968
1970
1965
1967
1967
1967
1976
1942
1965
1969
1974
1977
1960
1975
1977
1958
1969
1967
1976
1966
1964
1963
1937
1945
1978
1976
Avoidable
production
cost
25.64
28.45
27.26
29.82
27.53
27.60
25.85
26.35
26.21
39.36
26.50
25.23
28.26
31.72
32.49
25.19
30.96
27.27
35.03
26.87
32.73
30.30
29.12
27-92
31.41
30.88
29.75
31.76
Average TPY 857,857
Average TPD 2,599
Average year
1967
216
-------
TABLE N-13. SET 1 - $0.00/MBTU ACFL MODEL RUN
ff Name
51 E. I. Dupont
60 W. R. Grace
79 NL Industries
88 Olin Corporation
91 Pennsalt Chem
104 Stauffer Chem
113 US Industrial Chem
114 US Industrial Chem
133 E. I. Dupont
137 Allied Chem Corp
138 El Paso Products
TOTALS
"
lependent on abatement byproduct acid supplies
Location
Cornwell Hts.
Joplin
St. Louis
Pasadena
Tulsa
Ft. Worth
Dubuque
Desoto
Gibbstown
Cleveland
El Paso
PA
MO
MO
TX
OK
TX
IA
KS
NJ
OH
TX
Demand
75
98
455
500
110
120
98
105
110
130
86
1,887
Port
Sulphur
10
91
360
382
101
37
5
45
90
92
70
1,283
Abatement
65
7
95
118
9
83
93
60
20
38
16
604
IB - Supply points not satisfying total demand requirements
Area
Canada
Eastern
Eastern
Eastern
Eastern
West
West
Eastern
Eastern
Eastern
West
Eastern
Eastern
Eastern
Eastern
Eastern
ui J. J_il
-------
TABLE N-14. SET TI - $0.35/MBTU ACFL MODEL RUN
Port
// Name Location Demand Sulphur Abatement
13 Allied Chem Corp
70 LJ & M LaPlace Cde
88 Olin Corporation
96 Royster Co.
104 Stauffer Chem Co.
113 US Industrial Chem
120 Acme (Wright) Pert
138 El Paso Products
TOTALS
>endent on abatement byprod
Location
Front Royal
Edison
Pasadena
Mulberry
Ft. Worth
Dubuque
Acme
El Paso
VA
NJ
TX
FL
TX
IA
NC
TX
Demand
160
75
500
325
120
98
48
86
1,412
52.163
17.574
373.000
74.037
37.000
38.000
44.791
70.000
706.565
107.837
57.426
127.000
250.963
83.000
60.000
3.209
16.000
705.435
IIB - Supply points not satisfying total demand requirements
SMELTERS
Area
Canada
Western
Western
Eastern
Eastern
Eastern
Eastern
Smelter
Amer Smelt (Asarco)
Amer Smelt (Asarco)
Climax Molybdenum
Amer Smelt (Asarco)
Location
Canada
Arizona
New Mexico
Corpus Christi TX
Corpus Christi TX
Ft Madison IA
El Paso TX
Potential
demand
75
500
500
120
120
98
86
Amount
selling
57.426
118.000
9.000
7.000
76.000
60.000
16.000
Demand
balance
17.574
373.000
0.000
37.000
0.000
38.000
70.000
Acid
plant
No
70
88
88
104
104
113
138
TOTALS
879
343.426 535.574
POWER PLANTS
Number
6 4770003000
5 4740000300
1 1395000250
TOTALS
Location
Kentucky
Florida
North Carolina
Potential Amount
demand selling
160
325
48
533
107.837
250.963
3.209
Acid
Demand plant
balance No
52.163
74.037
44.791
13
96
120
362.009 170.991
218
-------
TABLE N-15. SET 111 - $0.50/MBTU ACFL MODEL RUN
IIIA - Acid plants partly dependent on abatement byproduct acid supplies
if
62
83
88
134
138
Name
Location
W. R. Grace & Co.
Occidental Ag Chem
Olin Corporation
E. I. Dupont
El Paso Products
TOTALS
Bartow
Plainview
Pasadena
Linden
El Paso
FL
TX
TX
NJ
TX
Capacity
320
100
500
325
86
1,331
Port
Sulphur
313.569
4.805
2.000
278.249
70.000
Abatement
6.431
95.195
498.000
46.751
16.000
668.623 662.377
IIIB - Supply points not satisfying total demand requirements
SMELTERS
Area
Smelter
Western
Western
Eastern Amer Smelt (Asarco)
TOTALS
Location
Arizona
New Mexico
El Paso TX
Potential
demand
500
500
86
586
Amount
selling
118
380
16
514
Acid
Demand plant
balance No.
2.
0.
70.
72
88
88
138
POWER PLANTS
Number
14 1655000300
15 1790002550
29 4530000850
3 0700000550
TOTALS
Location
Florida
Georgia
Texas
New York
Potential
demand
320
320
100
325
745
Amount
selling
2.101
4.330
95.195
46.751
148.377
Acid
Demand plant
balance No.
0.
313.569
4.805
278.249
596.623
62
62
83
134
219
-------
TABLE N-16. SET LV - $0.70/MBTU ACFL MODEL RUN
IVA - Acid plants partly dependent on abatement byproduct acid supplies
Name
Location
Port
Capacity Sulphur
Abatement
83
86
134
138
Occidental Ag Chem
Olin Corporation
E. I. Dupont
El Paso Products
Plainview
Baltimore
Linden
El Paso
TX
MD
NJ
TX
100
350
325
86
4.805
314.963
248.037
64.477
95.195
35.037
76.963
21.523
TOTALS
861 632.282
228.718
IVB - Supply points not satisfying total demand requirements
SMELTERS
Area
Smelter
Location
Canada
Eastern
Amer Smelt (Asarco)
Canada
El Paso TX
Acid
Potential Amount Demand plant
demand selling balance No.
325
86
411
76.963
16 . 000
92.963
248.037
64.477
312.514
134
138
POWER PLANTS
Number
41 4530000850
34 3795000350
7 1000000050
TOTALS
Location
Texas
Pennsylvania
Texas
Potential
demand
100
350
(86)
Amount
selling
95.195
35.037
5.523
Demand
balance
4.805
314.963
0.000
Acid
plant
No.
83
86
138
450
135.755 319.768
220
-------
APPENDIX 0
SIZE AND OWNERSHIP OF S-BURNING ACID PLANTS
CONTENTS
Tables Page
0-1 S-Burning Acid Plants Ordered by Size of Plant (1978) ..... 222
0-2 S-Burning Acid Plant Capacity by Firm (1978) 224
221
-------
TABLE 0-1. S-BURNING ACID PLANTS ORDERED BY SIZE OF PLANT (1978)
— -..-... . . . _ . — . . . _
No.
55
66
84
36
111
67
54
73
1
2
37
57
58
38
127
117
142
31
7
88
34
63
79
56
176
74
129
86
96
134
62
115
75
102
21
110
18
28
11
50
53
48
131
13
10
27
137
40
49
76
104
91
133
85
114
77
83
60
113
20
46
138
33
43
51
70
136
Company
Freeport Minerals
International Miner
Occidental Ag Chem
C. F. Industries
Texasgulf Inc.
W. R. Grace
Farmland Industries
Miss. Chem Corp
Agri Chem Williams
Agri Chem Williams
C. F. Industries
Gardinier
Gardinier
C. F. Industries
N. L. Industries
USS Agri Chem
American Cyanamid
Beker Industries
Allied Chemical
Olin Corp
Borden Chemicals
W. R. Grace
N. L. Industries
Gardinier
Texasgulf Inc.
Mobil Oil
Englehardt McConserv
Olin Corporation
Royster Company
E. I. Dupont
W. R. Grace
USS Agri Chem
Monsanto
Stauffer Chemical
American Cyanamid
Swift Chemicals
American Cyanamid
Army Ammunitions
Allied Chemical
E. I. Dupont
Essex Chem Co
E. I. Dupont
U.S. Industrial
Allied Chemical
Allied Chemical
Army Ammunitions
Allied Chemical
Cities Service
E. I. Dupont
Monsanto
Stauffer Chemical
Pennsalt Chemical
E. I. Dupont
Olin Corporation
U. S. Industrial
Monsanto
Occidental Ag Chem
W. R. Grace
U. S. Industrial
American Cyanamid
E. I. Dupont
El Paso Products
Borden Chemical
Delta Chemicals
E. I. Dupont
LJ (. M LaPlace
USS Agri Chera
Location
Uncle Sam
Bonnie
White Springs
Bonnie
Lee Creek
Bartou
Pierce
Pascagoula
Pierce
Donaldsville
Bonnie
Tampa
Tampa
Bonnie
Sayrevllle
Ft. Meade
Fortier
Taft
Geismar
Pasadena
Port Manatee
Bartow
St. Louis
Tampa
Lee Creek
Depue
Nichols
Baltimore
Mulberry
Linden
Bartow
Bartow
E. St. Louis
LeMoyne
Linden
Agricola
Savannah
Radford
Hopewell
Cleveland
Newark
North Bend
Tuscola
Front Royal
Nitro
Tyner
Cleveland
Augusta
Deepwater
Everett
Fort Worth
Tulsa
Gibbstown
N. Little Rock
Desoto
El Dorado
Plainview
Joplin
Dubuque
Hamilton
Richmond
El Paso
Norfolk
Searsport
Cornwell Hgts.
Edison
Wilmington
Yr
con-
struc ted
LA
FL
FL
FL
NC
FL
FL
MS
FL
LA
FL
FL
FL
FL
NJ
FL
LA
LA
LA
TX
FL
FL
MO
FL
NC
IL
FL
MD
FL
NJ
FL
FL
IL
AL
NJ
FL
GA
VA
VA
OH
NJ
OH
IL
VA
WV
TN
OH
GA
NJ
MA
TX
OK
NJ
AR
KS
AR
TX
MO
IA
OH
VA
TX
VA
ME
PA
NJ
1969
1975
1967
1967
1966
1977
1965
1958
1975
1975
1967
1974
1977
1976
1937
1963
1978
1965
1968
1946
1967
1960
1958
1937
1976
1967
1945
1941
1967
1937
1960
1964
1937
1957
1970
1976
1967
1940
1965
1937
1956
1956
1975
1945
1940
1941
1909
1967
1937
1969
1925
1937
1957
1947
1940
1960
1963
1954
1940
1967
1947
1967
1937
1942
1941
1967
NC 1968
Capac ity ,
annual
tons
2,160,000
1,980,000
1,650,000
1,550,000
1,357,000
1,280,000
1,226,000
1,220,000
1,200,000
1,200,000
1,190,000
1,050,000
883,000
660,000
560,000
540,000
530,000
525,000
500,000
500,000
490,000
480,000
455,000
450,000
449,000
420,000
400,000
350,000
325,000
325,000
320,000
280,000
265,000
250,000
245,000
220,000
216,000
212,000
200,000
200,000
180,000
175,000
170,000
160,000
135,000
132,000
130,000
125,000
125,000
120,000
120,000
110,000
110,000
105,000
105,000
100,000
100,000
98,000
98,000
95,000
90,000
86,000
80,000
75,000
75,000
75,000
70,000
Capacity
replaced by
abatement acid
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
500,000
0
0
455,000
450,000
0
420,000
0
35,037
325,000
76,963
320,000
0
265,000
250,000
0
0
216,000
212,000
200,000
200,000
180,000
175,000
170,000
160,000
135,000
132,000
130,000
125,000
125,000
0
120,000
110,000
110,000
105,000
105,000
100,000
95,195
98,000
98,000
95,000
90,000
21,523
80,000
0
75,000
75,000
70,000
(continued)
222
-------
TABLE 0-1 (continued)
No.
116
15
72
132
95
17
126
120
61
32
107
44
109
119
135
108
16
19
130
98
68
128
52
Company
USS Agrl Chem
American Cyanamid
Minn. Mine & Smelt
Marion Manufacturing
Reichold Chemical
American Cyanamid
American Cyanamid
Acme (Wright) Fert Co
W. R. Grace
Borden Chemical
Swift Chem Company
Detroit Chemical
Swift Chem Company
Weaver Fertilizer
Cities Service
Swift Chem Company
American Cyanamid
American Cyanamid
Columbia Nitrogen
Royster Company
Kerr-McGee
Home Guano Company
Eastman Kodak
Location
Navassa
Bound Brook
Copley
Indianapolis
Tuscaloosa
Joliet
Fortier
Acme
Charleston
Streator
Calumet City
Detroit
Norfolk
Norfolk
Momnouth Jet
Wilmington
Mobile
Kalamazoo
Moultrie
Norfolk
Cottondale
Do than
Rochester
Year
con-
Capacity,
annual
strutted tons
NC
NJ
OH
IN
AL
IL
LA
NC
SC
IL
IL
MI
VA
VA
NJ
NC
AL
MI
GA
VA
FL
AL
NY
1967
1945
1942
1947
1957
1937
1967
1968
1937
1951
1942
1937
1946
1967
1971
1944
1967
1967
1947
1937
1950
1937
1930
70,000
65,000
65,000
56,000
55,000
50,000
50,000
48,000
42,000
40,000
40,000
35,000
35,000
35,000
35,000
32,000
26,000
25,000
24,000
20,000
15,000
11,000
6,000
Capacity
replaced by
abatement
acid
70,000
65,000
65,000
56,000
55,000
50,000
50,000
48,000
42,000
40,000
40,000
35,000
35,000
35,000
35,000
32,000
26,000
25,000
24,000
20,000
15,000
11,000
6,000
Total
32,237,000 7,584,716
223
-------
TABLE 0-2. S-BURNING ACID PLANT CAPACITY BY FIRM (1978)
Name
C. F. Industries Inc.
Agrico Chem
Gardinier
W. R. Grace
Freeport Mineral
International Miner
Texas gulf Inc.
Occidental Ag
American Cyanamid
Farmland Industries
Miss. Chem Corp
Allied Chem Corp
E. I. Dupont DeNemours
N. L. Industries
USS Agri-Chem
Olin Corp
Borden Chemical
Beker Industries
Monsanto Company
Mobil Oil
Englehardt McConser
U.S. Industrial Chem
Stauffer Chem
Royster Company
Army Ammunition Plant
Swift Chem Co.
Essex Chemical Co.
Cities Service Oil
Pennsalt Chemicals
El Paso Chem
Delta Chemical
LJ & M LaPlace Cde
Minn. Mining & Smelting
Marion Manufacturing
Reichold Chemicals
Acme Fertilizer Company
Detroit Chemical
Weaver Fertilizer
Columbia Nitrogen
Kerr-McGee
Home Guano Co .
Eastman Kodak
Total capacity
[ tons ]
Capacity [ yr ]
3,400,000
2,400,000
2,383,000
2,220,000
2,160,000
1,980,000
1,806,000
1,750,000
1,302,000
1,226,000
1,220,000
1,125,000
1,100,000
1,015,000
960,000
955,000
610,000
525,000
485,000
420,000
Dr 400, 000
373,000
370,000
345,000
344,000
327,000
180,000
160,000
110,000
86,000
75,000
75,000
65,000
56,000
55,000
48,000
35,000
35,000
24,000
15,000
11,000
6,000
32,237,000
Number
of
plants
3
2
3
5
1
1
2
2
9
1
1
5
7
2
4
3
3
1
3
1
1
3
2
2
2
4
1
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Buying abate-
ment acid at
$0.70/MBtu ACFL
0
0
1
3
0
0
0
1
7
0
0
4
7
1
2
3
2
0
2
1
0
3
2
2
2
3
1
2
1
1
0
1
1
1
1
1
1
1
1
1
1
1
Top 5 companies
14 of 90 plants
12,563,000 tons
38.97%
Top 10 companies
29 of 90 plants
20,627,000 tons
63.99%
Top 15 companies
48 of 90 plants
26,047,000 tons
80.79%
Top 20 companies
59 of 90 plants
29,042,000 tons
90.09%
224
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APPENDIX P
ACID PLANTS OUT OF COMPLIANCE, RETROFIT COST, AND
CANDIDATES FOR PURCHASE OF BYPRODUCT ACID
CONTENTS
Table Page
P-l Acid Plants Out of Compliance, Retrofit Cost, and
Candidates for Purchase of Byproduct Acid 226
225
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TABLE P-l. ACID PLANTS OUT OF COMPLIANCE, RETROFIT COST, AND
CANDIDATES FOR PURCHASE OF BYPRODUCT ACID
No.
2
11
15
44
48
50
56
57
58
62
63
67
72
85
96
102
111
133
137
176
Company
Agrico Chem-Williams
Allied Chemical
American Cyanamid
Detroit Chemicals
E. I. Dupont
E. I. Dupont
Gardinier
Gardinier
Gardinier
W. R. Grace
W. R. Grace
W. R. Grace
Minn Mine & Smelting
Olin Corporation
Royster Company
Stauffer Chemicals
Texasgulf Inc.
E. I. Dupont
Allied Chemicals
Texasgulf Inc.
Location
Donaldsville
Hopewell
Bound Brook
Detroit
North Bend
Cleveland
Tampa
Tampa
Tampa
Bartow
Bartow
Bartow
Copley
N. Little Rock
Mulberry
LeMoyne
Lee Creek
Glbbstown
Cleveland
Lee Creek
LA
VA
NJ
MI
OH
OH
FL
FL
FL
FL
FL
FL
OH
AR
FL
AL
NC
NJ
OH
NC
Avoidable
production
cost, $/ton
28.45
35.50
46.19
57.91
42.41
43.25
34.17
28.56
31.72
33.81
32.49
30.96
50.35
44.27
35.60
35.06
30.30
40.50
45.58
31.76
Purchase from
Retrofit smelters
cost, $/ton only
2.80
4.69
6.49 X
7.76 X
4.88
4.69
3.71
2.91
3.06
4.10
3.65
2.75
6.49 X
5.65 X
4.08
4.40
2.70
5.58 Xa
5.32 X*
3.72
Purchase from power plants when ACFL is
50.35/MBtu
X
X
X
X
X
X
Xa
X
X
X
$0.50/MBtu
X
X
X
X
X
X
xa
X
X
X
X
X
X
$0.70/MBtu
X
X
X
X
X
X
X
X
X
X
X
X
X
a. Buying from Port Sulphur in addition to byproduct acid.
-------
APPENDIX Q
POWER PLANTS AND ACID PLANTS AFFECTED BY A REDUCTION
OF $20/TON IN S PRICE
CONTENTS
Tables Page
M-l Effect of S Price Change at $0.35/MBtu ACFL for Power
Plants, Smelters, and Acid Plants 228
M-2 Effect of S Price Change at $0.5Q/MBtu ACFL for Power
Plants, Smelters, and Acid Plants 229
M-3 Effect of S Price Change at $0.70/MBtu ACFL for Power
Plants, Smelters, and Acid Plants
230
227
-------
TABLE Q-1- EFFECT OF S PRICE CHANGE AT $0.35/MBTU ACFL
FOR POWER PLANTS, SMELTERS. AND ACID PLANTS
Two power plants affected by S price change at $t).35/MBtu ACFL
57,79^
188,517
2^6,311
1400000600 Pennsylvania Total tons 80,^09
4770003000 .Kentucky Total tons 628,358
tons affected
tons affected
Four smelters affected by S price change at $0.35/MBtu ACFL
New Mexico
New Mexico
Arizona
Montana
Houston
St. Louis
Houston
St. Louis
Total tons
Total tons
Total tons
Total tons
9,000
166,000
118,000
144,000
tons affected
tons affected
tons affected
tons affected
9,000
166,000
118,000
144,000
437,000
246.311
683,311
Six acid plants affected by S price change at $0.35/MBtu ACFL
13 Allied Chemical Corp
4770003000 Kentucky
33 Borden Chemical
4770003000 Kentucky
48 E. I. Dupont
1^00000600 Pennsylvania
Front Royal, Virginia 29.83
107,837 tons @ 31.73
Norfolk, Virginia 31.95
80,000 tons @ 32.37
North Bend, Ohio 36.30
57,794 tons @ 36.33
60 W. R. Grace
4770003000 Kentucky
Joplin, Missouri
680 tons
33.57
34.13
79
N L Industries inc.
New Mexico - St. Louis
Montana - St. Louis
St. Louis, Missouri 25.01
166,000 tons @ 28.16
144,000 tons @ 28.79
88
Olin Corporation
Arizona - Houston
New Mexico - Houston
Pasadena, Texas
118,000 tons
9,000 tons
24.19
27.56
27.56
683,311
228
-------
TABU; Q-2- EFFECT OF s TRICK CHANGE AT $O.SO/MBTU
ACFL FOR POWER PLANTS, SMELTERS, AND ACID PLANTS
Six power plants affected by S price change
at $0.50/MBtu ACFL
1115001100 Illinois, Total tons 126,788 tons affected 12,054
1655000300 Florida Total tons 192,742 tons affected 2,101
3455000400 Indiana Total tons 132,291 tons affected 42,291
4770003000 Kentucky Total tons 628,358 tons affected 528,297
4770003200 Kentucky Total tons 288,947 tons affected 44,830
5540000250 Missouri Total tons 108,149 tons affected 10,149
639,722
Two smelters affected by S price change
at $0.50/HBtu ACFL
Arizona Houston Total tons 118,000 tons affected 118,000
Mew Mexico Houston Total tons 380,000 tons affected 380,000
498,000
639,722
1,137,722
Ten acid plants affected by S price change
at $0.50/MBtu ACFL
11 Allied Chemical Corp, HopcwelJ., Virginia 29.39
4770003000 Kentucky 156,544 tons @ 31.73
33 Borden Chemical Corp Norfolk, Virginia 31.95
4770003000 Kentucky 80,000 tons I? 32.37
46 E. I. Dupont Richmond, Virginia 31.16
4770003000 Kentucky 90,000 tons @ 31.73
60 W. R. Grace Joplin, Missouri 33.57
4770003000 Kentucky 22,394 tons @ 34.13
62 W. R. Grace Bartow, Florida 27.70
1655000300 Florida 2,101 tons <« 28.55
74 Mobile Oil Depue, Illinois 25.08
1115001100 Illinois 12,054 tons 13 27.59
3455000400 Indiana 42,291 tons @ 25.36
5540000250 Missouri 10,149 tons @ 27.56
88 Olin Corporation Pasadena, Texas 24.19
Arizona Houston 118,000 tons S 27.56
New Mexico Houston 380,000 tons @ 27.56
96 Royster Company Mulberry, Florida 29.49
4770003000 Kentucky 134,359 tons @ 32.96
102 Stauffer Chemical Co LeMoyne, Alabama 28.95
4770003200 Kentucky 44,830 tons @ 30.95
114 U.S. Industrial Chemicals Desota, Kansas 34.18
4770003000 Kentucky 45,000 tons @ 37.83
1,137,722
229
-------
TABLE Q-3. EFFECT OF S PRICE CHANGE AT $0.70/MBTU
ACFL FOR POWER PLANTS, SMELTERS, AND ACID PLANTS
Eight power plants affected by S price change
at $0.70/MBtu ACFL
0785000500 Illinois
1000000050 Texas
1655000300 Florida
Total tons
Total tons
Total tons
3795000350 Pennsylvania Total tons
4520000500 Indiana Total tons
4770001900 Tennessee Total tons
4770003000 Kentucky Total tons
5540000250 Missouri Total t.'.w
77,549
125,523
192,742
72,342
216,721
301,246
628,358
108,149
tons affected 31,951
tons affected 5,523
tons affected 192,742
tons affected
tons affected
tons affected
tons affected
tons affected
35,037
45,000
80,403
538,358
10,149
Two smelters affected by S price change
at $0.70/MBtu ACFL
Arizona Houston
New Mexico Houston
Total tons 118,000
Total tons 299,000
417,000
939,163
1,356,163
tons affected
tons affected
118,000
299,000
Ten acid plants affected by S price change
at $0.70/MBtu ACFL
11
4770003000
33
4770003000
56
1655000300
62
4770001900
4770003000
74
0785000500
5540000250
86
3795000350
88
Arizona
New Mexico
96
4770003000
114
4520000500
138
1000000050
Allied Chemical
Kentucky
Borden Chemical
Kentucky
Gardinier Inc.
Florida
W. R. Grace & Co.
Tennessee
Kentucky
Mobil Oil
Illinois
Missouri
Olin Corporation
Pennsylvania
Olin Corporation
Houston
Houston
Royster Company
Kentucky
U.S. Industrial Chemicals
Indiana
El Paso Products
Texas
1
Hopewell, Virginia
77,508 tons @
Norfolk, Virginia
80,000 tons 13
Tampa, Florida
192,742 tons @
Bartow, Florida
80,403 tons @
239,597 tons @
Depue, Illinois
31,951 tons @
10,149 tons @
Baltimore, Maryland
35,037 tons g
Pasadena, Texas
118,000 tons @
299,000 tons
-------
TECHNICAL REPORT DATA
{Please read Instructions on the reverse be/ore completing)
. REPORT NO.
EPA-600/7-78-07Q
AND SUBTITLE Potential Abatement Production and
Marketing of Byproduct Sulfuric Acid in the U.S.
3. RECIPIENT'S ACCESSION NO.
5. REPORT DATE
April 1978
6. PERFORMING ORGANIZATION CODE
. AUTHOR(S)
J.I. Bucy, R.L.Torstrick, W.L.Anders, J.L. Kevins,
and P.A.Corrigan
8. PERFORMING ORGANIZATION REPORT NO.
TVA Bulletin Y-122
PERFORMING ORGANIZATION NAME AND ADDRESS
Tennessee Valley Authority
Office of Agricultural and Chemical Development
National Fertilizer Development Center
Muscle Shoals. Alabama 35660
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
E PA Interagency Agreement
D8-E721-BJ (TV-41967A)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 7/74 - 6/77
14. SPONSORING AGENCY CODE
EPA/600/13
-,5. SUPPLEMENTARY NOTES JERL-RTP project officer is Charles J. Chatlynne, Mail Drop 61,
919/541-2915.
is. ABSTRACT The report gives resiilts of an evaluation of the market potential for sulfur
and sulfuric acid byproducts of combustion in power plant boilers.(Air quality regu-
lations require control of SOx emissions from power plant boilers. Recovery of
sulfur in useful form would avoid waste disposal and conserve natural sulfur and
natural gas used to mine sulfur,) A cost model was developed to estimate the least-
cost compliance method from three alternatives: selecting a clean fuel strategy,
selecting a limestone-throwaway scrubbing technology, or selecting a sulfuric acid
or sulfur-producing scrubbing technology. For plants where production of byproducts
was the economic choice, a market simulation model was used to evaluate distribu-
tion of byproducts in competition with existing markets. Significant amounts of
sulfuric acid could be produced from SOx in power plant flue gas and sold in com-
petitive markets.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
COSATl Field/Group
Pollution
Sulfuric Acid
Sulfur
Byproducts
Marketing
Sulfur Oxides
Electric Power
Plants
Boilers
Flue Gases
Limestone
Gas Scrubbing
Pollution Control
Stationary Sources
Clean Fuel
13B
07B
14B
05C
10B
13A
2 IB
08G
07A,13H
13. DISTRIBUTION STATEMENT
19. SECURITY CLASS (This Report)
Unclassified
265
Unlimited
20. SECURITY CLASS (This page}
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
231
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