EPA-450/3-75-047
April 1975
COMPARISON OF FLUE GAS
DESULFURIZATION,
COAL LIQUEFACTION,
AND COAL GASIFICATION
FOR USE AT COAL-FIRED
POWER PLANTS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Water Programs
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
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EPA-450/3-75-047
COMPARISON OF FLUE GAS
DESULFURIZATION,
COAL LIQUEFACTION,
AND COAL GASIFICATION
FOR USE AT COAL-FIRED
POWER PLANTS
by
The M. W. Kellogg Company
1300 Three Greenway Plaza East
Houston, Texas 77046
Contract No. 68-02-1308
EPA Project Officer: William L. Polglase
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
Office of Air and Waste Management
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
April 1975
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This report is issued by the Environmental Protection Agency to report
technical data of interest to a limited number of readers. Copies are
available free of charge to Federal employees, current contractors and
grantees, and nonprofit organizations - as supplies permit - from the
Air Pollution Technical Information Center, Environmental Protection
Agency, Research Triangle Park, North Carolina 27711; or, for a fee,
from the National Technical Information Service, 5285 Port Royal Road,
Springfield, Virginia 22161.
This report was furnished to the Environmental Protection Agency by
The M. W. Kellogg Company, Houston, Texas 77046, in fulfillment of
Contract No. 68-02-1308. The contents oi this report are reproduced
herein as received from The M. W. Kellogg Company. The opinions,
findings, and conclusions expressed are those of the author and not
necessarily those of the Environmental Protection Agency. Mention of
company or product names is not to be considered as an endorsement
by the Environmental Protection Agency.
Publication No. EPA-450/3-75-047
11
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TABLE OF CONTENTS
PAGE NO.
List of Tables vi
List of Figures viii
1. Introduction 1
2. Summary and Conclusions 3
2.1 500 MW Existing Plant (60% Load Factor) 4
2.2 1000 MW New Plant (80% Load Factor) 5
3. Bases For Comparison of Desulfurization Technologies 7
4. Flue Gas Desulfurization 9
4.1 Process Description 9
4.1.1 Wet Limestone 9
4.1.2 Wellman-Lord/Allied 11
4.1.3 Cat-Ox 12
4.1.4 Utility and Energy Consumption 13
4.2 Process Complexity 13
4.2.1 Wet Limestone and Cat-Ox i3
4.2.2 Wellman-Lord/Allied 15
4.3 Flexibility of Processes 16
4.4 Status of Technology 17
4.4.1 Application in Japan 17
4.4.2 Application in the U. S. 19
4.4.3 Operational Problems in the U.S. 19
4.4.4 Vendor Capacity 26
4.5 Environmental Effects 27
4.5.1 Wet Limestone 27
4.5.2 Wellman-Lord/Allied and Cat-Ox 31
4.6 Installation 33
4.6.1 Installation Time 33
4.6.2 .Space Requirements 35
4.6.3 Retrofitting Problems 37
4.6.4 Time Out of Service For Retrofitting 38
111
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TABLE OF CONTENTS (Cont'd.)
PAGE NO,
Solvent Refined Coal 55
5.1 Process Description 55
5.1.1 Section 1 - Coal Handling and Grinding 56
5.1.2 Section 2 - Slurry Preheat and Dissolvers 57
5.1.3 Section 3 - Ash Filtering and Drying 57
5.1.4 Section 4 - Solvent, Light Oil, and Cresylic
Acid Recovery 58
5.1.5 Section 5 - Product Solidification 59
5.1.6 Section 6 - Hydrogen Plant 59
5.1.7 Section 7 - Sulfur Removal and Recovery 59
5.1.8 Section 8 - Steam and Power Generation 60
5.1.9 Section 9 - Other Offsites 60
5.1.10 Energy Balance 61
5.2 Complexity 62
5.3 Flexibility 64
5.4 Status of Technology 65
5.4.1 Description of Present Status 65
5.4.2 Areas of Uncertainty 66
5.5 Environmental Effects 69
5.6 Installation 72
Low Btu Gas 75
6.1 Process Description 75
6.2 Complexity 78
6.3 Flexibility 79
6.4 Status of Demonstrated Technology 80
6.5 Environmental Effects 81
6.6 Installation 82
Economic Comparison of Processes 88
7.1 Basis for Costs 88
7.2 Energy Conversion Efficiency 90
7.3 Manpower Requirements 91
7.4 Economics of Each Process 92
IV
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TABLE OF CONTENTS (Cont'd.)
PAGE NO,
7.4.1 Flue Gas Desulfurization 92
7.4.2 Economics of SRC 92
7.4.3 Economics of Low Btu Gas 94
7.5 Cost Comparison 98
8. References 121
9. Appendix 125
v
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LIST OF FIGURES
FIGURE NO. DESCRIPTION PAGE NO,
4.1
4.2
4.3
4.4
4.5
5.1
5.2
6.1
6.2
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.9
Wet Limestone Process Flowsheet
Wellman/Allied Process Flowsheet
Cat-Ox Process Flowsheet
Flue Gas Desulfurization in Japan
Total Flue Gas Desulfurization by U.S.
Utilities
Solvent Refined Coal Process Flow Diagram
Coal Liquefaction Project Schedule
Lurgi Low B.t.u. Gas Process
Flowsheet
Coal Gasification Project Schedule
Wet Limestone Operating Costs (FGD)
Wellman/Allied Operating Costs (FGD)
Cat-Ox Operating Costs (FGD)
Total Production Cost vs. Load Factor (FGD)
Total Production Cost vs. Coal Cost (SRC)
Total Production Cost vs. Load Factor (SRC)
Total Production Cost vs. Coal Cost (low
Btu gas)
Total Production Cost vs. Load Factor (Low
Btu gas)
Total Annual Cost vs. Coal Cost for
Existing 500 MW
50
51
52
53
54
73
74
86
87
111
112
113
114
115
116
117
118
119
7.10 Total Annual Cost vs. Coal Cost for New
1000 MW 120
VI
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List of Tables
Table No. Description Page Ho.
3.1 Power Plant Parameters 8
4.1 Annual Utility Consumption
by FGD Processes 39
4.2 Annual Energy Consumption
by FGD Processes 40
4.3 Major Equipment Areas for
500 MW New FGD System 41
4.4 Flue Gas Desulfurization
in Japan 42
4.5 Total Flue Gas Desulfurization
Figures for Japan 43
4.6 Flue Gas Desulfurization Units
on Stream by 1974 on U.S.
Utilities 44
4.7 Planned Flue Gas Desulfurization
Units on U.S. Utilities (1975-
1980) 45
4.8 Status of United States Utilities
Flue Gas Desulfurization Units 46
4.9 Will County No. 1 Flue Gas
Desulfurization Availability 47
4.10 Characteristics of Sludge from
Wet Limestone Units 48
4.11 Sludge Disposal on U.S. Utilities 49
6.1 Material Balance for low Btu Gas
Process 83
6.2 Annual Utilities - Low Btu Gas Plants 84
6.3 Coal Gasification Processes for
Production of Low Btu Gas 85
7.1 Unit Prices Used in Cost Comparisons 99
7.2 Process Energy Conversion Efficiency 100
7.3 Process Manpower Requirements 101
7.4 Economics of Wet Limestone Scrubbing 102
7.5 Economics of Wellman-Lord/Allied
Scrubbing 103
7.6 Economics of Cat-Ox Scrubbing 104
7.7 Economics-SRC-New 1000 MW 105
7.8 Economics-SRC-New 1000/4000 MW
System 106
vn
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List of Tables
Table No. Description Page No.
7.9 Economics-SRC-Existing 500 MW 107
7.10 Economics-SRC-Existing 500/2000
MW System 108
7.11 Economics-Low Btu Gas-Existing
500 MW 109
7.12 Economics-Low Btu Gas-New 1000
MW 110
Vlll
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1. INTRODUCTION
The work reported herein is a comparison of three differ-
ent desulfurization techniques:
1) flue gas desulfurization
2) solvent refined coal
3) coal gasification to produce low Btu gas
The study was performed for the Environmental Protection
Agency under Task 34, Contract No. 68-02-1308.
In order to meet sulfur oxide emissions standards, com-
bustion sources which normally burn high sulfur fuels can be
controlled by removing sulfur in one of three ways:
1) prior to combustion
2) during combustion
3) after combustion
Coal gasification and solvent refined coal represent two
methods of pre-combustion sulfur control, while flue gas
desulfurization is, of course, a post-combustion control
method. Although there are a variety of processes under
development which remove sulfur during combustion, none
were included in this study.
The overall objective of this task was to make a
technical and economic comparison of flue gas desulfurization,
solvent refined coal, and coal gasification (low Btu gas).
It was a basic premise of this task to confine the study to
an investigation of these processes as applied to conventional
steam-electric power plants. Therefore, low Btu gas for use
as fuel in a combined steam and gas turbine cycle was not
considered. The latter is a promising technology for base-load
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plants in the future. However, widespread commercialization
is dependent upon successful gas turbine development to allow
the turbines to operate at temperatures high enough to achieve
better cycle efficiencies than can be obtained in a conventional
power plant.
Three flue gas desulfurization systems were included as
being representative of the field. These are:
1) the wet limestone (or lime) process
2) the Wellman-Lord/Allied Chemical process
3) the Cat-Ox (Monsanto) process
The solvent refined coal process is based on the Pittsburg
and Midway Coal Mining Company flow sheet, while low Btu gas
is based on Lurgi pressure gasification.
Each process or technology was reviewed to obtain the
following information:
1) process complexity
2) process flexibility
3) status of technology
4) environmental effects
5) installation difficulties
6) energy conversion efficiency
7) manpower requirements
8) economics
The results of this study have been quantified where possible
and comparisons between the different technologies have been
made based on the available information.
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2. SUMMARY AND CONCLUSIONS
This study evaluates flue gas desulfurization, solvent
refined coal, and low Btu gas as applied to two different
conventional power plants. The first is an existing 500 MW
plant operating at 60% load factor, and the second is a new
1000 MW plant operating at 80% load factor. Sulfur recovery
efficiencies of 90% have been used for the flue gas desulfur-
ization processes and low Btu gas, giving an overall SO~
emmission rate of about 0.6 Ibs SO2/MMBtu. For solvent
refined coal (SRC), it has been assumed that the SRC can
typically be desulfurized to about 1.0% sulfur. This would
produce an S0» emmission rate from the power plant of
£.*
approximately 1.2 Ibs SO /MM Btu. The combined emmissions
from the power plant and the SRC plant would be slightly higher.
Of necessity, flue gas desulfurization units and low Btu
gas plants must be sized in relation to the power plants which
they serve. However, some flexibility in size is possible
with solvent refined coal plants. Since the product is easily
stored and shipped, these plants need not be integrated with
a single power plant, but could serve several power plants
within an area. For this study, two different size solvent
refined coal plants have been considered. The first is sized
to produce fuel corresponding to the power plant fuel consump-
tion. The second is assumed to be four times this size. These
plants are identified in subsequent tables according to the
equivalent power production from the solvent refined coal
product. Thus a 500/500 unit would correspond to a 500 MW
power plant being served by a 500 MW (equivalent power) solvent
refined coal plant. A 1000/4000 unit would represent a 1000 MW
power plant receiving fuel from a 4000 MW (equivalent power)
solvent refined coal plant.
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The total production costs summarized here are the total
operating costs for each process. These include all direct
and indirect costs plus depreciation, interest on debt, return
on equity, taxes and insurance. Additionally, the cost of
coal has been included for each process. This permits a direct
comparison to be made between flue gas desulfurization and
the other control methods. Costs are shown in cents per
million Btu of heat input to the boiler.
2.1 500 MW Existing Plant (60% Load Factor)
Total Production Costs - C/MM Btu
Flue Gas Desulfurization
Solvent Refine'd Low Btu
Coal (SRC) Gas
Coal Cost Wet
S/T
5
10
15
Limestone
57
78
98
Wellman-Lord
/Allied
63
83
104
Cat-Ox
67
88
108
500/500
117
145
174
500/2000
80
108
137
108
143
177
Flue gas desulfurization appears to be superior to the use of
SRC or low Btu gasification. The wet limestone process seems
to be the least costly scrubbing process followed by the Wellman-
Lord/Allied process and the Cat-Ox process respectively.
Use of SRC (sized to produce fuel for a 500 MW power plant)
or low Btu gas is not competitive with stack gas scrubbing.
The use of a large (2000 MW) SRC system improves economics
for the process considerably. Fuel costs are about 37C/MM Btu
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lower when the size is increased by a factor of four. However,
costs are still somewhat higher than flue gas desulfurization
costs. A substantial increase in by-product credit (cresylic
acid) would be necessary to enable this process to be competitive
with stack gas scrubbing.
As the load factor decreases, the unit operating cost for
all processes increases. The increase in cost is much greater
for SRC and low Btu gas than for flue gas desulfurization
thereby reinforcing the previous conclusions.
Total Production Costs - C/MM Btu*
Flue Gas Desulfurization Solvent Refined Coal Low Btu Gas
Wet Wellman-
Load Factor Limestone Lord/Allied Cat-Ox 500/500 500/2000
143
188
* Coal at $10/T
2.2 1000 MW New Plant (80% Load Factor)
Total Production Costs - C/MM Btu
Coal Cost:
$/T
5
10
15
Flue gas desulfurization remains somewhat superior to the use of
SRC (sized for 1000 MW) or coal gasification.
60%
45%
78
87
83
95
88
105
145
177
108
128
Flue Gas
Wet
Limestone
44
65
86
Desulfurization
Wellman-Lord
/Allied
49
70
90
Cat-Ox
52
73
93
Solvent Re
1000/1000
80
109
137
fined Coal
1000/4000
53
82
110
Low Btu Gas
74
108
143
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The use of a large SRC plant (4000 MW system) improves economics
for the process considerably. Costs are about 27C/MM Btu less
than for a 1000 MW SRC plant.
When coal costs are low (about $5/T), the 4000 MW SRC process
is competitive with flue gas desulfurization. With coal at
$10/T, the 4000 MW SRC process appears to be somewhat more
costly than flue gas desulfurization. However, an increase
in by-product credit may be realized which could make SRC
competitive with flue gas desulfurization.
At a coal price of $5/T, coal gasification costs about
20C/MM Btu more than the 4000 MW SRC process. As coal prices
increase, the spread becomes greater due to lower efficiency
of the gasification process. The increase in cost is about
1.3C/MM Btu for each $ 1/T of coal price increase.
Integration of coal gasification into a combined cycle power
plant (utilizing gas turbines and steam turbines) would appear
to be more desirable than its use as feed preparation for a
conventional power plant.
As the load factor decreases, the unit operating cost for
all processes increases as shown by the following table:
Costs - C/MM Btu*
Flue Gas Desulfurization Solvent Refined^ Coal Low Btu Gas
Wet Wellman-
Load Factor Limestone Lord/Allied Cat-Ox 1000/1000 1000/4000
108
120
* Coal at $10/T
80%
60%
65
70
70
76
73
83
109
128
82
92
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3. BASES FOR COMPARISON OF DESULFURIZATION TECHNOLOGIES
In this study, an attempt has been made to compare
different desulfurization technologies and processes as
applied to conventional steam-electric power plants. The
processes included in the study are:
1) the wet limestone process > flue
2) the Wellman-Lord/Allied Chemical Process > gas
3) the Cat-Ox Process J desulfurization
4) solvent refined coal
5) Lurgi coal gasification to produce low
Btu gas
Conventional H2S removal systems are included in the gasification
and solvent refined coal processes, a Benfield system for
the former and an amine system for the latter. Sulfur is
recovered in 2-stage Glaus plants. No Glaus tail gas treat-
ment facilities are included. An overall sulfur recovery of
90% has been used for flue gas desulfurization processes and
low Btu gas, giving an overall S0~ emission rate of about
£*
0.6 Ibs. SOp/MM Btu. For the solvent refined coal process,
the product can typically be desulfurized to about 1.0% sulfur.
This produces an S02 emission rate of about 1.2 Ibs. S02/MM Btu
from the power plant, but the overall emissions from the
solvent refined coal plant plus the power plant would be slightly
higher.
Process descriptions and the bases for process designs are
given in subsequent sections of this report.
In order to make quantitative comparisons between processes,
basic power plant parameters have been established to define
the reference plants. These parameters are shown in Table 3.1.
Since all control processes depend on the use of coal as fuel
or feed, coal data are also listed in the table.
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Table 3.1
POWER PLANT PARAMETERS
Power Plant Size
500 MW
1000 MW
Number of boilers 2
Size of each boiler, MW 250
Age of plant, years 10
Heat rate, BTU/KWH* 9,500
Load factor, % 60
Electrostatic precipitator yes
Electrostatic precipitator
efficiency, % 98.7
Minimum gas temperature
at stack, °F 175
Coal (fuel or feed)
HHV (as rec'd.), BTU/LB 12,000
% sulfur 3.5
% ash 12
% moisture 5
4
250
new plant
8,700
80
yes
98.7
175
12,000
3.5
12
5
No boiler de-rating used for case of low Btu gas fired boiler
8
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4. FLUE GAS DESULFURIZATION
4.1 Process Descriptions
4.1.1 Wet Limestone
Generally speaking a wet limestone process can be divided
into three areas:
Limestone receiving and preparation
Particulate and sulfur dioxide removal
Sludge treating and disposal
Figure 4.1 is a block flow diagram of the wet limestone
system.
Limestone arrives as a coarsely ground material, and
is conveyed by belt to a storage pile. It then proceeds
to a wet ball mill, which produces a limestone slurry that
is stored in a slurry feed tank.
The slurry then goes to an SO absorber effluent tank,
from which it is circulated to the SO absorber. Overflow
from the absorber effluent tank proceeds tc a particulate
scrubber. Overflow from this tank is pumped to the sludge
disposal pond.
The flue gas first enters a venturi scrubber, where it
is sprayed with high velocity limestone slurry. The quenched
gas exists from the venturi throat into a sump, where a
reduction in gas velocity causes the slurry droplets to fall
out.
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The particle-free gas then flows upward in the SO-
absorber, where it contacts countercurrently the limestone
slurry. The overall reaction occuring in the absorber
is:
CaCO + S00 -> CaSO + CO,
J ^ J 4
Slurry droplets that carry over with the gas are collected
on the demister vanes.
The scrubbed gas then enters the reheater, where its
temperature is raised to about 175°F. An induced draft fan
boosts the pressure of the gas before it enters the stack.
The sludge produced in the process is either pumped
directly to a settling pond, or it receives some kind of
treatment such as clarification or chemical fixation. Ul-
timate disposal may be ponding or use as landfill. (20,Pp21-25)
A wet lime process is quite similar to the wet limestone
process. Some minor differences do exist, such as the elimina-
tion of the grinding step in the lime process. This results
in a slightly lower capital investment, and an energy savings.
Lime has a higher activity than limestone, so less feed is
required, and some energy can be saved in the slurry circulation,
On the other hand, lime is several times more costly than lime-
stone, thus offsetting these advantages. Overall, the process
designs and costs for lime and limestone systems are very
similar.
10
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4.1.2 Wellman-Lord/Allied
The Wellman-Lord/Allied process involves removal of the
S0? by contacting the flue gas with a sodium sulfite-bisulfite
solution. The absorber consists of valve trays, each equipped
with a separate scrubbing loop. A prescrubbing section removes
fly ash and S0_. Figure 4.2 illustrates the process.
When the flue gas contacts the sodium sulfite-bisulfite
solution, the following reactions occur:
2NaHSO_
1/2
A certain amount of unregenerable salts are formed in
the system, and a purge stream is required to control the
level of these salts.
Sodium sulfite is regenerated in an evaporator by thermal
decomposition of the bisulfite:
2NaHS03 -»• Na2SO3 + S02 + H20
Additional sulfite is generated by reacting make-
up sodium hydroxide in this reaction:
NaOH + NaHSO., •+• Na-SO~ + H^O
11
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The sulfite crystals are slurried by the addition of
condensate from the wet SO- gas purification section following
the bisulfite thermal decomposition step.
The compressed S02 product gas goes to the reduction
area where it is first mixed with natural gas. The preheated
mixture flows to a reduction unit which produces S, H?S,
CO- and H^O. After cooling the gas enters a claus unit, where
most of the H S and remaining S0_ is converted to elemental
sulfur. A coalescer removes the droplets of sulfur, and the
tail gas is burned with natural gas, then routed to the scrubber
system. (12,pp 131-134)
The conversion of sulfur dioxide to elemental sulfur was
chosen for this study because sulfur is usually the most desirable
product. Other routes are available, such as conversion to
sulfuric acid. This type of plant would perhaps cost less,
but the product is not as easy to handle and store as the solid
sulfur.
4.1.3 Cat-Ox
Cat-Ox removes SO by oxidation over a vanadium catalyst
^
to S0_, then absorption of the SO to produce 80% sulfuric
acid. The process is illustrated in Figure 4.3.
The use of the catalyst requires a very efficient electro-
static precipitator to prevent clogging. Existing units also
require a reheater so that the gas enters the converter
at about 890°F. New units should have the converter upstream
of the economizer and air preheater, thus avoiding a reheater.
12
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The particle free gas enters the converter, where the
SO- in the flue gas is oxidized to SO.. After the economizer
and air preheater in a new unit, or cooling water heat ex-
changer in an existing unit, the SO ..-rich gas contacts a
circulating stream of sulfuric acid, which absorbs the SO.,
and water vapor. A very efficient mist eliminator removes
entrained acid droplets.
The effluent acid is cooled further, part of it goes
to product storage tanks, and part of it returns to the absorp-
tion circuit. (12,pp 149-150)
4.1.4 Utility and Energy Consumption
Tables 4.1 and 4.2 compare the utility requirements and
energy consumption of the three flue gas desulfurization
processes. Figures for the wet limestone and Wellman-Lord/
Allied process are from M. W. Kellogg cost models (3, pp 88-91,
pp 116-121), while those for the Cat-Ox process are derived
from a TVA report (14 p 276).
4.2 Process Complexity
Stack gas scrubbing processes provide relatively simple meth-
ods of desulfurization. Table 4.3 lists the major pieces
of equipment involved in the three systems.
4.2.1 Wet Limestone and Cat-Ox
In terms of process complexity, wet limestone and
Cat-Ox are fairly equal, the following points being considered:
13
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Particulate removal in the wet limestone process is less a
concern than in the Cat-Ox process, because the electrostatic
precipitator already present in the existing 500 MW plant
is adequate for wet limestone particulate control. Cat-Ox
requires an additional high-efficiency precipitator to
further reduce the particulates level.
SO- removal is also somewhat simpler in the wet limestone
process, as it is done in one step, rather than the two
required in the Cat-Ox process.
Raw material receiving and handling is quite a bit simpler
in the Cat-Ox process.
Both processes require special attention given to the mist
eliminators. The wet limestone process must provide for
adequate washing of the demister to reduce plugging, while
Cat-Ox needs a very efficient demister to eliminate a sulfuric
acid plume.
Both processes must contend with a product of some sort;
wet limestone must dispose of its by-product sludge, while
Cat-Ox must store and sell its sulfuric acid product.
14
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4.2.2 Wellman-Lord/Allied
Of the three flue gas desulfurization processes under
consideration, Wellman-Lord/Allied is the most complicated.
A rather elaborate circulation system is associated with the
SO absorber. Liquid from each tray is removed, then reintrc
duced at a point above its respective tray.
Generation of the elemental sulfur product is somewhat
involved. The steps required to generate the product are
evaporation, SO_ purification, SO? reduction, and finally
product storage.
In addition to the elemental sulfur product generated, there
is a by-product recovered from the purge stream. This
consists of sodium sulfate and a small quantity of thionates.
Additional process steps are required in the treatment of the
purge stream.
15
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4.3 Flexibility of Processes
Application of S02 emissions control to the utility
industry presents some potential problems due to the nature
of the industry. The sizes of the power plants are quite
varied. Operation is not a steady affair, with periodic
shutdowns occuring from time to time. Flue gas desulfuri-
zation appears well suited to these conditions.
Stack gas scrubbing technology can be applied to the
wide range of capacities that exists in the utility industry.
In Japan existing and planned flue gas desulfurization units
applied to utility boilers range from 30 to 500 MW. In
the United States units due on-stream by the end of 1974 range
from 32 to 820 MW.
Application of flue gas desulfurization to large power
plants requires the use of multiple scrubbing trains. For
example, the power plants considered in this study use
four identical scrubbing trains on the 500 MW plant, and eight
identical trains on the 1000 MW plant. The concept of
identical trains is most evident in the Cat-Ox process, where
$/KW total capital requirement is only about 10 percent higher
in a 500 MW unit than a 1000 MW unit. In the wet limestone
and Wellman-Allied, doubling the plant size results in about
a 30 percent reduction in $/KW total capital requirement. (See
section 7.4.1)
Flue gas desulfurization operation follows that of the
boiler: when the boiler is down, so is the desulfurization
unit. This presents no problems in operating these units,
as simple start-up and shut-down accompany the relative
process simplicity of flue gas desulfurization. The danger
of contamination of the Cat-Ox catalyst by fly ash exists
during start-up, so the units are equipped with a start-up
by-pass duct, allowing the operation to stablize before actual
desulfurization begins. Routine maintenance and cleaning of the
systems can be scheduled during boiler down time.
16
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4.4 Status of Technology
Flue gas desulfurization is a commercially proven method
of controlling S0_ emissions. The successful commercial
applications of flue gas desulfurization can be separated
into eight basic classes (23, p80):
Lime or limestone slurry scrubbing
Sodium sulfite scrubbing with thermal regeneration
Dual media system using dilute sulfuric acid for scrubbing
Double alkali systems
Magnesium oxide
Copper oxide acceptor
Activated Carbon
Once through soda ash solution system
4.4.1 Applications in Japan
Most of the successful commercial installations are
located in Japan, where units have been performing adequately
for two years or longer, with availabilities of over 95 percent,
S02 removal efficiencies up to 95 percent have been achieved.
Inspired by these successes the Japanese industry has moved
ahead vigorously with flue gas desulfurization. The technology
has been successfully applied to boiler stack gas, Glaus sulfur-
plant tail gas, sulfuric acid-plant tail gas, copper smelting
tail gas, and iron ore sintering tail gas. (23, pp79-80)
Tables 4.4 and 4.5, and Figure 4.4 show the progress of
flue gas desulfurization in Japan. These points are worthy of
note (19, pp4,7,10):
17
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There are seventeen wet limestone scrubbing facilities
with capacities greater than 20 MW operating in Japan, or
scheduled for completion by 1974. Many of the plants attain
S0_ removal levels of 90 percent. The Mitsubishi-Jecco
process is commonly used for oil-fired boilers, iron-ore
sintering plants, etc., while the Chemico Mitsui and Mitsui
Miike processes are used for coal-fired boilers. In addition
fourteen lime or limestone processes are to be installed
during 1975 and 1976.
Twenty-'two double-alkali facilities in units of 20 MW or
larger are now operating in Japan or scheduled for completion
by the end of 1974, with six other units due onstream by
the end of 1975. Seven of the processes use wet absorbents:
Nippon Kokan, ammonium sulfite; Chiyoda, sulfuric acid;
Kurechi-Kawasaki, Showa Denko, Showa Denko-Ebara, and
Tsukishima, sodium sulfite; Kurabo Engineering, sodium
sulfate; and Dowa mining, aluminum sulfate. The Hitachi-
Tokyo Electric process uses a dry absorbent, activated carbon.
The Wellman-Lord process is currently being used in twelve
Japanese locations.with sizes of 20 MW or larger. Two
additional units are scheduled for completion in 1975.
Applications of the process are to industrial boilers, utility
boilers, and a Claus furnace.
Three units using magnesium oxide scrubbing are to be in
operation by the end of 1974, treating a copper smelter,
a sulfuric acid plant, and a Claus unit.
The Sumitomo Shipbuilding process uses dry activated carbon
to absorb S02 from a utility boiler stack.
Shell's copper oxide process is used on a utility boiler
stack gas.
18
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The Mitsubishi - IFF process uses ammonia scrubbing to control
SO emissions from two Glaus furnaces.
4.4.2 Application in the U.S.
In the United States utility industries, twenty flue
gas desulfurization units are expected to be operating by
the end of 1974, representing a total of 3481 MW. Many
additional units are planned to come onstream before 1980.
Tables 4.6and 4.7and Figure 4.5illustrate the planned progress
of flue gas desulfurization in the U.S. utilities. The
following points are noteworthy: (20,pp49-73)
Fourteen facilities employ lime or limestone scrubbing, the
sizes ranging from 30 to 820 MW. Another twenty-eight
units are planned for completion by 1980.
Two sodium carbonate scrubbing units are installed at present,
with two more units anticipated by 1980.
One magnesium oxide unit is presently installed, and another
is planned for completion before 1980.
One double alkali system was started up in March,
1974.
One Cat-Ox unit is currently installed.
Three Wellman-Lord/Allied units are anticipated before 1980.
4.4.3 Operational Problems in the U.S.
Since the introduction of flue gas desulfurization units
in the U.S., many problems have plagued their operation and
reduced the availability of the units. Most of the chemical
problems have been overcome, however some mechanical difficulties
19
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still exist. Table 4.8 summarizes the operating status of
desulfurization units in the United States. (20, pp8-10)
4.4.3.1 Lawrence Power Station
The Lawrence Power Station of Kansas Power and Light
has flue gas desulfurization units on its oldest unit, No. 4,
and on a unit put into service in 1971, No. 5. Wo. 4 has
a capacity of 115 MW burning natural gas and coal, while
No. 5 is rated at 400 MW burning the two fuels.
Both units were built by Combustion Engineering, who
also designed and installed the scrubbing system: limestone
injection followed by wet scrubbing.
The coal presently burned has a heat content of 12,000
Btu/lb, ash content of 12 percent, and sulfur content of
3.75 percent. Because of the curtailment of strip mining
at the Kansas Coal supply site, the feed is to be switched
to Wyoming coal, with a heating value of 10,000 Btu/lb,
ash content of 10 percent, and sulfur content of 0.4 to 0.8
percent.
When the desulfurization unit on No. 4 began operating
in 1968, many problems arose due to improper chemical control
of the process. The problems included:
Scale buildup in hot gas inlet ducts
Erosion of scrubber walls and corrosion of the scrubber
internals.
Scaling of drain lines, tanks, pumps, marble bed, demister,
and reheater.
20
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Scale accumulation on the I.D. fans
Inadequate SO« removal due to everburning of limestone in the
furnace, and dropout of lime in the scrubber.
After a few months of operation, design had to be
modified in these ways:
Installation of soot blowers at the gas inlet duct and
reheater.
Raising of the demister.
Running overflow liquor from the pots to the pond.
Installation of a large tank and pump to recirculate the
underflow.
These modifications reduced some of the problems with scaling,
as well as improving S0_ removal efficiency.
Other revisions were made in 1970 to further combat the
scaling problems, yet demister problem continued, requiring
manual washing every other night. In 1972, both modules
were modified to use a high solid slurry crystallization
process to control saturation and precipitation in the
scrubbers.
Since the fall of 1973 performance of the units has
improved somewhat. In July and August of 1974 availabilities
of near 100% have been reported. Problems still do exist
in both modules, with the one on No. 5 experiencing difficulty
with poor gas distribution.
21
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Plans are currently underway to convert the unit on No.
5 to tail end wet lime or limestone scrubbing only. Plans for
No. 4 include installation of an electrostatic precipitator,
and replacement of the scrubbing system. (20, pp!6-20)
4.4.3.2 Will County Power Station
The Will County Power Station of Commonwealth Edison
has one 167 MW boiler fitted with a flue gas desulfurization
unit. The coal fuel has a heating value of 9463 Btu/lb, ash
content of 10%, and sulfur content of 2.1%.
In February, 1972, the boiler was fitted with a wet
limestone scrubbing system consisting of two modules,
referred to as A and B. Table 4.9 summarizes the monthly
availabilities of the two modules. (20,p28). Problems with the
system soon became apparent. Low wash water pressure contri-
buted to the constant problem of demister plugging. This
problem caused both modules to be out of service several
days of each month of operation initially. Some modifications
in the wash water system yielded no improvements, so the
demister elements had to be hand washed, which introduced
broken elements into the slurry system.
Module B had to be taken out of service to correct
excessive vibration in the reheater section. Both modules
experienced additional problems of erosion and plugging of
spray nozzles, deposit buildup on venturi nozzles, corrosion
cracking, sulfite binding, and fan vibrations.
In 1973, problems with the demister continued, high-
lighted by the loosening of the demister in Module B, and
the subsequent plugging of the reheater by chloride pitting
corrosion. In April Module B was taken off stream indefinitely
until Module A is satisfactory. A system of continuous under-
spray and intermittent overspray was installed on Module A
to reduce demister plugging.
22
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In 1974 operation of Module A has improved somewhat,
although problems still remain, such as: freezing of the
venturi throat drive, tank screen blinding, dust corrosion,
and vibrations. Some parts of Module B have been used in
Module A modifications. (20, pp26-30).
4.4.3.3 Hawthorn Power Station
The Hawthorn Power Station of Kansas City Power and
Light uses flue gas desulfurization on Units 3 and 4. Each
boiler is rated at 140 MW for natural gas, and 100 MW for
coal. Two types of coal are burned: one with heating value
of 11,400 Btu/lb, 14% fly ash, and 3% sulfur; the other with
heating value of 9800 Btu/lb, 11% ash, and .6% sulfur.
Initially both units employed limestone injection
followed by wet limestone scrubbing of the tail gas. After
developing plugging in the tubes of Boiler 4 due to limestone
injection, the ground limestone was injected into the flue gas
near its entry into the scrubber.
Problems encountered by the four identical modules, two
per unit, have been similar. Many of the problems, have been
reduced by process and equipment modifications.
The reaction tank of each module initially had problems
with buildup of hard mud in the corners of the tanks.
Installation of welded triangle plates and make-up water
nozzles near the plates improved the situation.
Plugging problems in the marble bed of the absorber
have been solved by installation of stainless steel drain
pots with expanded metal covers. The liquid to gas ratio
in the scrubber has been increased.
Early spray nozzles used in the units lasted for a very
short time, and their frequent replacement was a rather
23
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expensive operation. A much cheaper shop-made nozzle also
did not last very long. Performance of the nozzles was
improved greatly by the use of ceramic nozzles.
The typical demister problems encountered elsewhere have
been minimized by the addition of retractable water lance
blower under the demister, and by moving the rotary water
lance blowers to between the demister vanes.
Availability of the unit on Boiler 3 has increased to
about 70 percent/ while No. 4 has lagged behind somewhat
due to limestone injection related problems. (20, pp36-39)
4.4.3.4 Reid Gardner Power Station
The Reid Gardner Power Station of the Nevada Power
Company uses flue gas desulfurization on its two units,
each rated at 126 MW. The two sodium carbonate based
desulfurization units have operated since March, 1974. Each
boiler has a single module unit.
Both units have operated satisfactorily since their
start-ups. The operations have been subjected to frequent
interruptions due to a lack of the sodium carbonate source,
trona. Availabilities during adequate supplies of trona
have been 100%, and each unit has operated for 900 hours.
None of the problems of scaling, demister plugging, erosion,
and corrosion associated with previously mentioned units
have surfaced. (20, pp44-45)
4.4.3.5 Cholla Power Station
The Cholla Power Station of the Arizona Public Service
Company has a wet limestone scrubbing system installed on
its single 115 MW unit. The double-train unit has operated
satisfactorily since' its start-up in late 1973; however
some problems have been evident:
24
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Initial heavy vibrations in the reheat section have been
reduced significantly by the installation of baffles to
evenly distribute the desulfurized flue gas.
Improper operation of the by-pass damper continues to reduce
the scrubber efficiency by allowing some flue gas to pass
freely to the stack.
Early problems experienced with the flooded disk, which
maintains an equal pressure drop in the system at all loads,
have been corrected by eliminating buildup problems around
the disk shaft, and by adjustment of the controls.
Some corrosion and plugging problems have been experienced,
but they are relatively minor in scale. It is hoped that
proper maintenance will keep such trouble spots to a minimum.
In one common trouble area, demister plugging, a new wash
water system appears to keep buildup at a minimum. (18, pp3-7)
4.4.3.6 Olin Corporation Sulfuric Acid Plant
Since the startup of this Wellman-Lord unit on the tail
gas from a 750 ton per day sulfuric acid plant at Paulsboro,
New Jersey, operation has been about what was expected,
except for the sodium hydroxide makeup rate, which was initially
about 50 percent above design: 3.75 TPD, vs the design rate 2.5 TPD.
Some corrosion problems were present in the early operations,
but these problems have been corrected. (24, p43)
4.4.3.7 Wood River Power Plant
The Wood River Plant of Illinois Power Company has a
Cat-Ox system installed on its 110 MW unit. The unit has not
operated very much since its startup in September, 1972, because
of the conversion of the reheat section from natural gas
25
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fuel to fuel oil, and problems associated with this conversion,
Units on new power plants will not require reheat sections.
During a 24 hour test run, some aspects of the unit
operation were noted:
Conversion of S02 to SO., reached 93%, which is over the
guaranteed 90%.
92% removal of SO- was achieved, better than the guaranteed
85%.
Acid of 78% concentration was produced when the absorption
tower operated at design temperature.
Acid mist leaving the system measured 0.529 mg per cubic
foot, compared to the design guarantee of 1 mg/cu ft. (27, pp51-52)
4.4.4 Vendor Capacity
The claim is sometimes made that stack gas scrubbing re-
presents an unfeasible means of meeting the Clean Air Act
deadlines, simply because the supplying capability of U. S.
manufacturers of scrubbing equipment is inadequate. However,
the Industrial Gas Cleaning Institute, which represents over
two dozen major U. S. suppliers of SO_ control technology, has
claimed that U. S. suppliers could build 525 systems, averaging
460 MW each within the next seven years. This represents a total
of 241,500 MW, which is about 81 percent of the U.S. 1972 total
steam-electric generating capacity of about 300,000 MW. This does
not consider Japanese suppliers, some of whom are actively seek-
ing U.S. business. (23, p85)
26
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4.5 Environmental Effects
4.5.1 Wet Limestone
4.5.1.1 Sludge Generation
The wet limestone process generates a sludge stream
that is composed mainly of CaSO- and CaSO.. In Japan a
further oxidation step yields gypsum (CaSO.) which is market-
able; however, in the United States an adequate supply is
available, thus the sludge has limited economic use. Table
4.10 shows the average hourly sludge output for four operating
wet limestone units, and an approximate composition of the
sludge. (17, p6)
Many factors affect the quantity and composition of the
sludge, including:
o Size of the power plant
o Type of boiler
o Type of fuel burned
o Sulfur and ash content of the fuel
o Method of fly ash removal
o Method of S02 removal
o Stoichiometric ratio of calcium to S02
o Efficiency of the S02 removal
The calcium compounds in the sludge are mainly calcium
sulfite (CaS03) and calcium sulfate (CaSO ). The relative
amount of each depends on the degree of oxidation in the
scurbber, which in turn depends on:
o Fly ash content
o pH of the slurry
o Amount of oxygen in the flue gas
27
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4.5.1.2 Disposal Problems
The wet limestone process is known as a throwaway process,
because the generated product has no present practical use,
and must be disposed of. Disposal causes problems in two
areas: large specific volume of the sludge requires a large
area for disposal, and dangers of ground water pollution
require special attention.
The specific volume of the sludge is a function of its
composition. Fly ash alone packs to a volume of about 20
cubic feet per ton of solids, while the sludge packing volume
varies from 45 to 75 cubic feet per ton of solid. The former
is for sulfates, the latter sulfites. (17, p 8)
A 500 MW plant with an average load factor of 0.6, and
burning 3.5% sulfur, would produce a 50% solids sludge at a
rate of 1 x 10 cubic feet per year if equipped with a wet lime-
stone scrubbing unit. If the remaining life were 20 years,
o
this unit would generate a total of 2.09 x 10 total cubic feet
of sludge. The pond to contain this sludge would be about one-
half mile by one-half mile and 37.5 feet deep. (15, p2)
A new 1000 MW plant with a load factor of 80% would pro-
duce a 50% solids sludge at the rate of about 2.8 x 10 cubic
Q
feet per year, or a total of 8.4 x 10 cubic feet during its
30-year lifetime. This would require a pond of almost one
square mile area, and 37.5 feet deep.
If a substantial portion of the U.S. utility industry
adopts wet limestone scrubbing, a likewise substantial
amount of sludge will be produced. Using the 1972 U.S. total
installed steam-electric capacity, and assuming that 54%
are coal-fired, yields about 162 million KW of coal-fired
capacity. If 50 percent of this capacity, or 81 million KW
installs wet limestone scrubbing, and if these plants
operate at 60% load factor, then 3.25 x 10 cubic feet of
28
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sludge are generated during 20 years of operation. This is
equivalent to about 23 square miles of 50 feet deep sludge.
(28, p 53)
Not only the sheer volume of the sludge presents problems
in its disposal, but the danger of water pollution also con-
cerns the pollution abatement interests. The presence of
CaSO.,.1/2 H-O and some trace metals in the sludge, and their
availability for leaching by rainwater, poses a potential hazard
via ground water pollution. This is not peculiar to sludge dis-
posal however, as ash disposal poses the same type problems.
(17, p8)
4.5.1.3 Ultimate Disposal Techniques
It is evident that the one big problem remaining in the
technology of wet limestone scrubbing is sludge disposal.
Quite an effort is being directed towards rendering the
sludge easier to handle by reducing its size and altering
its physical properties. Table 4.11 shows the current sludge
disposal techniques employed by utilities. (17, plO)
One approach to ultimate disposal of the sludge is
chemical fixation, followed by use of the resulting material
for landfill. The companies with methods of chemical fixation
are: Dravo Corporation, IU Conversion Systems Inc., and
Chemfix. (21, P 22-25)
The Chemfix process reportedly can handle a wide range of
solid content sludges to produce a soil-like substance, which
does not prevent rain water percolation, yet is stable and
controls pollution by chemically binding the constituents.
The sludge is reacted with sodium silicate and one or more
of these settling agents: portland cement, lime, calcium
sulfate, and calcium chloride. The result is a gelatine-
like material whose hardening time is fixed depending on the
pumping time required. The product is acceptable for disposal
with no further treating.
29
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The Dravo process treats a wide range of solid content
sludges to produce a clay-like material. The sludge is reacted
with an admixture called Calcilox just before pumping to the
disposal site. Final settling and curing requires about 30
days. The resulting material has been accepted for disposal
without containment in at least one site in Pennsylvania.
The IUCS process uses fly ash and lime addition to fix the
sludge. In some cases dewatering of the sludge is required
before addition of the agents. Testing has shown that the
resulting material can develop high strength very quickly.
It has also been shown that the combination of trace elements
into new crystaline phase can reduce the availability of
toxic materials to ground water. The process may also be
used to make synthetic aggregate suitable for road base
materials.
Another approach to the bulk size reduction and improve-
ment of the physical properties of the sludge is by dewatering,
followed by use as landfill. The problem of leachability
remains, and covering with clay may be all that is needed
to prevent contamination of the ground water.
A sulfate sludge dewatered by filtration or centrifu-
gation may require only additional solar drying to reduce the
water content to a level suitable for compaction. A sulfite
sludge may require more than simple centrifugation of filtration,
such as the addition of dry fly ash to the sludge, or the
use of thermal drying. Another solution might be oxidation
of the sulfite to achieve the easier dewatering properties
associated with sulfate sludges.
The simplest way to dispose of the sludge is by ponding.
The sludge is pumped or hauled to a pond designed to contain
the raw sludge for a long period of time. The pond is lined
with impervious material such as butyl rubber or clay.
Leakage detection systems are employed.
30
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4.5.2 Wellman-Lord/Allied and Cat-Ox
4.5.2.1 By-Products
The main product of the Wellman-Lord/Allied desulfurization
process is elemental sulfur having a quality suitable for
sale to manufacturers of sulfuric acid via the contact process.
A 1000 MW unit fired with 3.5 percent sulfur coal, and having
a load factor of 0.8 produces about 63,210 tons per year of
elemental sulfur. It produces a total of 1.9 million tons
in its 30 year life. A 500 MW plant with a load factor of
0.6 produces 20,706 tons per year of sulfur, or about 520,000
tons in the 20 years of remaining life. (12, Appendix B)
A purge stream is required to control the buildup of
non-regenerable sodium salts in the process. This stream is
concentrated and dried, resulting in an 85 percent Na2S04
product. Davy Powergas is currently researching means of
regenerating the sodium ion, so that the amount of purge can
be significantly reduced. (13, p5)
The product of the Cat-Ox system is 80% sulfuric acid.
A 1000 MW plant burning 3.5 percent sulfur coal, and having
a load factor of 0.8, produces about 212,400 tons per year,
or 6.4 million tons in a 30 year lifetime, based on 100 percent
sulfuric acid. A 500 MW plant with 0.6 load factor generates
about 69,600 tons per year 100 percent acid, or about 1.76
million tons in a 20 year remaining life. (25, p46)
4.5.2.2 Marketing Problems
Wellman/Allied and Cat-Ox both produce sulfuric acid
related products, 80 percent acid in the Cat-Ox system, and
sulfur available for sulfuric acid manufacturing from the
Wellman/Allied process.
31
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If a substantial section of the utility industry turns
to sulfuric acid producing methods of S02 control, the acid
production could be quite substantial. For example, sulfuric
acid production from desulfurization systems could equal
about 60 million tons per year of acid, almost double the
U.S. 1972 production of 31.3 million tons. The expected
variation in the approach that the utility industry will take
to solve the S02 pollution problem will dampen the effects on
market systems. However, the potential for upset is present.
(15, p4)
As a product, elemental sulfur has certain advantages
over the 80% sulfuric acid produced by the Cat-Ox process. It
is an inert material, thus if necessary, could be dumped with
no fear of polluting effects. The specific volume of the sulfur
is lower than the acid specific volume, and can be more easily
stored.
32
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4.6 Installation
4.6.1 Installation Time
Installation time is of course a function of a varied
set of parameters associated with a particular project. In
the case of flue gas desulfurization units, the situation
facing contractors is the installation of a relatively new
technology, sometimes on premises that were constructed with
no intent of future additions. These factors tend to extend
installation time0 As more and more of the units are in-
stalled, the acquired experience in this area will probably
reduce somewhat the required installation time.
4.6.1.1 Will County Power Station
In September 1970, Babcock and Wilcox was authorized to
begin detail engineering of a wet limestone stack gas scrubbing
unit for the Will County Power Station of Commonwealth Edison.
Completion of the project was set at December 31, 1971, by the
Illinois Commerce Commission. It was apparent that orders
for major equipment items would have to be placed early to
meet the deadline, so authorization to purchase was given
on September 28, 1970. By July, 1971, most of the major
equipment items were at the site.
Erection was scheduled to begin on April 1, 1971, but
it was delayed for six weeks because it was discovered that
a slab type of foundation would not support the scrubber
system.
In spite of the late start, the unit was essentially
complete by the end of February, 1972, one year and seven
months after the beginning of detail engineering. (26, p92)
33
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4.6.1.2 Phillips Power Station
In the case of the Phillips Power Station of the Duquesne
Light Company, the contract was awarded to the Chemico Corporation
in July, 1971, and Duquesne felt that a reasonable target
date for completion would be July, 1973, which was 34 months
after the, decision to install a scrubbing system. Under
pressure from the State of Pennsylvania, the target date for
completion was set at January 1, 1973.
On July 9,1973, six months late, the first portion of
the unit was completed. Several reasons for the delay
were: some development engineering was required to adapt
the scrubbers, some suppliers were late with their orders,
and some major delays occurred in the field. (22, pp3-5)
4.6.1.3 Wood River Power Plant
The original schedule for the Cat-Ox unit ?.t the Wood
River plant of Illinois Power Company called for design and
cost estimates to begin in June, 1970, with detail engineering
and procurement to be initiated in November, 1970. The
electrostatic precipitator unit was to be placed in operation
early in 1972, and the complete flue gas desulfurization unit
operational early in 1974.
Some construction delays occurred, then the natural gas
shortage prompted a redesign of the reheat section to operate
on fuel oil. A change to external burners was also found
to be necessary.
The reheat section will .not be needed on a unit installed
on a new plant. (27, pp 51-52)
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4.6.1.4 A Wellman-Lord/Allied Unit
Davy-Powergas has been awarded a contract to construct
a Wellman-Lord/Allied desulfurization system on a new power
plant. The project was awarded in the Spring of 1974, and
engineering, procurement, and construction is expected to
take thirty to thirty-three months. (13, p4)
4.6.2 Space Requirements
One of the major factors to be considered in anticipating
a flue gas desulfurization system is the amount of space the
unit will require. This factor is especially important when
considering retrofitting a system in a rather congested power
plant.
4.6.2.1 Wet Limestone
In a wet limestone unit the main space-taking elements
are the limestone pile and related equipment, scrubbing trains,
and the sludge disposal facilities. The requirements of these
three areas for a 500 MW unit are shown below: (22, pp88-89)
2
Limestone pile and slurry preparation 76,800 ft
o
Four scrubbing trains (side by side) 30,888 ft
2
Sludge disposal pond 153,000,000 ft
The sludge pond is fifty feet deep.
Sometimes there is simply not enough space at the power
plant for on-site disposal of the sludge. In this case a
thickener may be used, along with a small pond. The thickened
sludge is then hauled away for disposal.
A new 1000 MW unit requires 8 scrubbing trains to process
the stack gas, twice the limestone pile that a 500 MW unit
needs, and 2.67 times the sludge pond area. The space requirements
35
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are shown below:
2
Limestone pile and slurry preparation 153,720 ft
2
8 scrubbing trains 61,776 ft
Sludge pond 409,000,000 ft2
4.6.2.2 WeiIman-Lord/Allied
In the Wellman-Allied process, the main areas are the
flue gas scrubbing trains, and the S0» reduction-regeneration
and purge treatment area. Space requirements for a 500 MW
unit are: (12, pp!37-139)
2
4 scrubbing trains 34,690 ft
2
Reduction-regeneration and purge 43,420 ft
A 1000 MW plant requires twice the space for the scrubbing
trains that a 500 MW unit does; however, the reduction-regen-
eration area will not increase its size linearly with capacity
because larger tanks and vessels can be used. Assuming a
size increase in this area governed by a 0.5exponent yields
the following space requirements for a 1000 MW unit:
2
8 scrubbing trains 69,380 ft
2
Reduction, regeneration, purge 61,400 ft
Not included in the space requirements for the Wellman-
Lord/Allied system is a required sulfur product storage
area. This area, including tanks and a dike surrounding them,
will likely require an area equal to about one-sixth the
process area.
4.6.2.3 Cat-Ox
The cat-Ox system has its space requirements in two main
areas: the actual process area, and storage space for the
36
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produced sulfuric acid. For a 500 MW plant the areas are:
(25, p46)
Process 47,340 ft2
2
Acid Storage 52,600 ft
A new 1000 MW plant requires:
Process 115,550 ft2
Storage 96,300 ft2
4.6.3 Retrofitting Problems
Some power plants have adequate open areas near the
stack that can be used for scrubbing trains or converters, and
areas available elsewhere to locate other facilities. In these
cases retrofitting is not a large problem, and the installation
costs associated with these units is not much more than a com-
parable installation in a new plant.
The arrangement of some power plants is such that retro-
fitting a flue gas desulfurization unit presents a major problem.
Retrofitting at these sites is likely to require large expenditures
for extra ductwork, foundations, steel structures, and the re-
location of existing equipment, buildings, railroad tracks, etc.
As examples:
Installation of a wet limestone scrubbing system at the W.H.
Sammis Power Plant of the Ohio Edison Co. would require moving of
about 1000 feet of railroad track, relocation of a considerable
portion of the coal pile, and the installation of considerable
extra ductwork on three of the units. (29, p9)
Retrofitting a wet limestone system at the Eastlake Power Plant
of the Cleveland Electric Illuminating Co. would require demoli-
tion and reconstruction of two service buildings, relocation of
37
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a silo and part of a conveyor, and rerouting of a pipe bridge.
(29, p!3)
4.6.4 Time Out of Service for Retrofitting
Although the actual construction effort involved in
retrofitting a flue gas desulfurization unit may be quite
extensive, the actual tie-in time that is required is not
exceedingly long.
If planned properly, tie-in of the scrubber duct to the
boiler duct can be done in two to three weeks. As this is the
amount of time boilers are usually shut down for maintenance,
tie-in can usually be accomplished in a way that minimizes power
plant outage. (29, p8)
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TABLE 4.1
MAJOR EQUIPMENT AREAS FOR 500 MW NEW FGD SYSTEM *
SCRUBBER
Met
Limestone
Wei Iman-
Lord/
Allied
Cat-Ox
FEED
PREPARATION
1 Wet Ball
Mill
PARTICULATES
REMOVAL
4 Venturi
Scrubbers
4 Venturi &
MBA Sumps
4 Venturi
Scrubbers
4 High T.
High Eff.
Preci pi tators
S02
REMOVAL
4 S02 Scrubbers
4 Effluent Hold
Tanks
Isoprene Lining
10 Slurry Recycle
Pumps
40 Soot Blowers
4 S02 Scrubbers
4 SO. Converters
2 Acid Absorbers
and mist
El imi nators
6 Acid Circulation
Pumps
GAS HANDLING, REHEAT
& HEAT RECOVERY
4 Gas Reheaters
4 ID Fans
4 Gas Reheaters
4 ID Fans
4 Fluid/Air
• Heaters
4 ID Fans
PRODUCT
TREATING
BY-PRODUCT TREATING
& REGENERATION
*
1 SO- Reduction
Unit
4 Condensate
Heaters
6 Acid
Circulation
Pumps
1 Chiller Crystal-
1 i zer Tank
1 Centrifuge
1 Rotary Dryer
1 Dust Collector
2 Evaporator-
Crystal 1 izer
CO
vo
* Total Cost Greater than 100 M 1975 $
-------
TABLE 4.2
ANNUAL UTILITY CONSUMPTION BY FGD PROCESSES
WET LIMESTONE
WELLMAN-ALLIED
CAT-OX
Electricity KWH
Steam MLB
Fuel Oil GAL
Natural Gas MCF
Process Water MGAL
500 MW
73.3 x 10l
2.36 x 10l
136,000
1000 MW
179 x 10C
5.77 x 10l
332,500
5UO MW
68.9 x 106
1 .612 x 10£
2.36 x 106
433,400
19,000
1000 MW
3.94 x 10"
5.77 x 10l
1 ,059,000
46,500
500 MW
168.4 x 106 58.8 x 1Of
8.057 x 10*
1000 MW
187 x 10'
1 .28 x
Cool ing Water MGAL
6,160,000
15,045,000
6 ,687,000
680,000
-------
TABLE 4.3
ANNUAL ENERGY CONSUMPTION BY FGD PROCESSES
Electricity KWH
WET LIMESTONE
500 MW
1000 MW
73.3 x 106 179 x 106
WELLMAN-ALLIED
500 MW
1000 MW
68.9 x 106 168.4 x 106
CAT-OX
500 MW 1000 MW
,6
58.8 x 10L
187.0 x 10l
Equivalent BTU
6.96 x 1011 1.56 x 1012
6.55 x 1011 1.47 x 1012
5.59 x 1011 1 .63 x 1012
Steam MLB
Equivalent BTU
1.612 x 106 3.94 x 106
2.1 x 1012 5.1 x 1012
(1.28 x 10°)
(1 .67 x TO12]
Fuel Oil GAL
2.36 x 10C
5.77 x 10'
2.36 x 106 5.77 x 1O6 8.057 x 10f
Equivalent BTU
3.54 x 1011 8.66 x 1011
3.54 x 1011 8.66 x 1011 1 .2 x 1012
Natural Gas MCF
433,400
1 .059 x
Equivalent BTU
4.33 x 1011 1 .06 x 1012
Total BTU
1.05 x 1012 2.43 x 1012
3.54 x 1012 8.50 x 1012
1 .76 x 10
12
Total Heat Rate
10,184
9,047
1 1 ,139
10,157
9,71 7
8,700
-------
Table 4.4
Process
Flue Gas Desulfurization in Janan
(REF. 19)
Application Through 1974 Application From 1975-76
Size Range MW
Wet Lime-Lime-
stone Scrubbing
7 Utility Boilers
4 Industrial Boilers
1 Copper Smelter
3 Sintering Plants
1 Heating Furnace
1 Diesel Engine
9 Utility Boilers
2 Industrial Boilers
3 Sintering Plants
30-500
22-175
29
26-279
32
62
-P.
no
Double-Alkali
H2S04 Absorbent
1 Utility Boiler
5 Industrial Boilers
1 Utility Boiler
1 Industrial Boiler
250-350
27-230
Double-Alkali
NaSOo Absorbent
1 Utility Boiler
9 Industrial Boilers
2 Sulfuric Acid Plants
2 Utility Boilers
1 Industrial Boiler
150-450
25-150
37-43
Double Alkali
(NH4)2S03,(NH4)2
S04, A12(S04)3,
Carbon Absorbent
1 Utility Boiler
1 Industrial Boiler
1 Sintering Plant
1 Sulfuri c Acid Plant
1 Industrial Boiler
150
31-53
46
82
WeiIman-Lord
1 Utility Boiler
10 Industrial Boilers
1 Claus Furnace
2 Industrial Boilers
250
50-400
23
Magnesium Oxide
1 Copper Smelter
1 Sulfuric Acid Plant
1 Claus Unit
28
25
162
Carbon , Copper
Oxide, Ammonia
1 Industrial Boiler
2 Claus Furnaces
37
3-14
-------
Table 4.5
Total Flue Gas Desul furi zati on Figures
CO
Appli cation
Utility Boilers
Industrial Boilers
Sulfuric Acid Plants
Claus Units
Sintering Plants
Others
For Japan
(REF. 19)
Number of Sites
Through 1974 1975-76
12 12
30 7
3
4
4 3
4
Total MW
Through 1974
1816
2884
162
202
341
151
1975-76
3734
663
-
-
534
_
Totals
57
22
5556
4931
-------
Table 4.6
Flue Gas Desul furization Units On Stream
Loca ti on
Arizona Public Service
Choi la No. 1
Ci ty of Key West
Key West Power Plant
Commonwealth Edison
Will County No. 1
Dairyland Power Co-op.
Alma Station
Detroi t Edi son
St. Clai r No. 6
Duquesne Light
Phi Hips
General Motors
Chevrolet Parma 1,2,3,4
11 1 i noi s Power
Wood River No. 4
Kansas City Power & Light
Hawthorn No. 3
Kansas City Power & Light
Hawthorn No. 4
Kansas City Power & Light
La Cygne No. 1
Kansas Power & Light
Lawrence No. 4
Kansas Power & Light
Lawrence No. 5
Louisville Gas & Electric
Paddy's Run No. 6
Nevada Power
Reid Gardner No. 1
Nevada Power
Reid Gardner No. 2
Potomac Electric 8 Power
Dickerson No. 3
Southern California Ed.
Mojave No. 1
Southern California Ed.
Mojave No. 2
Tennessee Valley Authority
Shawnee No. 10
by 1974 On U.S. Utilities
(REF. 20)
Process Size MW Type*
Limestone 115 R
Limestone 37 N
Limestone 167 R
Lime Injection 80 R
Limestone 180 R
Lime 410 R
Double Alkali 32 R
Cat-Ox 110 R
Limestone
Injection f, Scrubbing 140 R
Limestone
Injection?. Scrubbing 100 R
Limestone 820 N
Limestone
Injection & Scrubbing 125 R
Limestone
Injection & Scrubbing 400 N
Lime 65 R
Sodium Carbonate 125 R
Sodium Carbonate 125 R
Mag-Ox 100 R
Limestone 160 R
Lime 160 R
Lime/Limestone 30 R
Fuel XS Year Comr
Coal .44 1973
Oil 2.4 1972
Coal .6-3.0 1972
Coal 3.0-3.5 1971
Coal 3.7 1974
Coal 1.0-2.8 1973
Coal 2.5 1974
Coal 2.9-3.2 1972
Coal .6-3.0 1972
Coal .6-3.0 1972
Coal 5.2 1973
Coal 3.5 1968
Coal 3.5 1971
Coal 3.5-4.0 1973
Coal .5-1.0 1973
Coal .5-1.0 1973
Coal 2.0 1973
Coal .5- .8 1974
Coal .5- .8 1973
Coal - 1972
N = New
R=Retrofi t
44
-------
Table 4.7
Planned Flue Gas Desulfurization Units
on U.S.
Process
Limestone Scrubbing
Limestone Scrubbing
Lime Scrubbing
Lime Scrubbing
Li me /Li me stone
Li me /Limes tone
Sodi urn Carbonate
Sodium Carbonate
Wei Iman/Al 1 ied
Wellman/Al lied
Mag-Ox
Mag-Ox
Utilities
(REP. 20)
type
N
R
N
R
N
R
N
R
N
R
N
R
(1975-1980)
Number
25
3
7
17
8
2
1
1
1
2
-
1
Total MW
8576
1002
3950
5560
3748
830
125
125
375
455
-
120
45
-------
Table 4.8
Utility and Unit
Status of U.S. Utilities : Flue Gas Desulfurization Units
(REP. 20)
Status
Arizona Public Service
Cholla No. 1
Some mechanical problems such as frequent reheat section vibration,
unit availability consistently above 90%
Boston Edison
Mystic No. 6
System shut down indefinitely due to lack of EPA funding. Recent
availabilities are: March - 87%, April - 81%, May - 57%, June - 80%
Commonwealth Edison
Will County No. 1
Dai ry Power Co-op.
Alma Station
Module A availabilities are: April - 73%, May 93%, June - 54%,
July - 95%, August - 91%, September - 85%; Module B is down until
Module A is satisfactory
Demonstration unit with longest run of two days
Duquesne Light
Phillips Station
Only about 40% of stations capacity is treated because fly ash
overloads the clarifier. Operating time for Modules 1-4 have been
1756, 762, 815, 1707 hours
General Motors
Parma Plant
Availability has been 100% since April, but only two modules have
operated at a time because of low demand
II1i noi s Power
Wood River
Unit operated 700 hours in last two years because of conversion
of reheater to fuel oil
Kansas Power & Light
Hawthorn No. 3
Availability has increased from 30% in 1973 to 70% recently
Kansas Power & Light
Hawthorn No. 4
Converted from injection to tail end scrubbing. More oroblems
encountered here than with Unit 3
Kansas Power & Light
LaCygne
Kansas Power & Light
Lawrence No. 4
Many initial deposit problems due to poor P^ control. Recently
availability is =80% with weekly cleaning of each module
SO- removal is only 75% and daily automatic, weekly manual wash-
ing is required. Precipitator and system to be replaced in 1977
Kansas Power & Light
Lawrence No. 5
Many of No. 4's problems encountered here as well as poor gas
distribution
Louisville Gas & Electric
Paddy's Run
Southern California Edison
Mojave No. 2
Nevada Power
Reid Gardner No. 1
Availability near 100%; however, since unit is on a peaking
boiler, many runs do not justify start-up
Availability over 80%
Availability over 90% until Na2C03 supply diminished
Potomac Electric & Power
Dickerson No. 3
Prior to August, unit was frequently down, but no record keot.
Since August availability is 34%
46
-------
Table 4.9
County No. 1 Flue Gas Desulfurization Avai1abi1ity
Peri od
March 1972
Apri 1
May
June
July
August
September
October
November
December
(REF. 20)
v a i 1 a b i
A
0
33.9
69.5
8.4
0
78.7
0
0
0
21.8
li
35
13
31
30
0
20
29
0
0
29
ty %
B
.4
.7
.8
.9
.6
.5
.7
Peri od
January 1973
February
March
Apri 1
May
June
July
August
September
October
November
December
Avai
A
0
21.
64.
6.
0
*
51.
19.
0
32.
50.
0
labi
9
8
2
9
4
2
0
8
lity %
B
0
24.3
10.7
13.1
0
0
0
0
0
0
0
0
Peri od
January 1974
February
March
April
May
June
July
August
Avai
A
0
0
20.
72.
93.
54.
95.
91 .
labi
9
3
1
5
8
3
li
1
0
0
0
0
0
0
0
0
-------
Table 4.10
Characteristics of Sludge from Wet Limestone Units
(REF. 17)
Station Sludge Output Rate Sludge Composition Dry Basis (wt%) Estimated Solids Con-
LT/hr (Dry Basis)* CaSO?-l/2 H?0 CaSO,,-2H90 CaCO. Fly Ash tent of Dewatered
4 * Sludge Wt.%
Will County No. 1 17.5 50 15 20 15 35
Key West Power St. 2.4 20 5 74 1 50
La Cygne 12.5 12.5 40 30 15 35
00 Cholla 3.1 15 20 - 65 50
*LT = long tons
-------
Table 4.11
Sludge Disposal in U.S. Utilities^
Effluent
Pretreatment
Ultimate Disposal
Lawrence
4
Hawthorn 3
Will County
Key West
La Cygne
Cholla
Paddy1 s
Phillips
Mojave 2
Parma
a)
b)
c)
d)
e)
Run
Cl
So
Ai
Ch
Management Cla
& 5 Closed Loop
& 4 Open Loop3
1 Closed Loop
Open Loop
Closed Loop
Open Loop
Closed Loop
Closed Loop
Closed Loop
Closed Loop
osed loop forclarifi
lar evaporation
ded by solar evaporat
icago fly ash method
ri f i er Vac-Fi
X
X
__
*_ — •—
X X
X
X
X X
er, open loop
i on
Iter Pond Chemical
X
X
xd
X
X
X
x xe
x xe
__
for pond
Pondry Landfill
X
X
X
X
X
X
X
X X
X X
X
Dravo fly ash method
-------
FIGURE 4.1 WET LIMESTONE PROCESS FLOWSHEET
GAS
TO -*
STACK
in
O
FLUE GAS FROM POWER PLANT
SCRUBBING SECTION
RECIRCUALTION
TANKS
LIMESTONE PREPARATION SECTION
SLUDGE HANDLING SECTION
-------
FIGURE 4.2
WELLMAN-LORD/ALLIED PROCESS FLOWSHEET
FLUE GAS
REHEAT
FLUE GAS
PRESCRUBBING
AND S02
REMOVAL
FLUE GAS
COMPRESSION
FLUE GAS
TO STACK
r
-i
MAKE-UP
SYSTEM
I
I
SULFITE IsOL'N
I
MaOH OR Na2C03
EVAPORATION
AND
CRYSTALLIZATIO
-*- FLY ASH
SLURRY
I ?
PURGE
SOL'N
VENT GAS
TO
ABSORBER
SO,
so2
PURIFICATION
COMDENSATE
r
PURGE
SYSTEM
I
SO,
1
NATURAL
GAS
so2
REDUCTION
TAIL GAS
TO
ABSORBER
PURGE SOLIDS I
SULFUR
_l
-------
FIGURE 4.3
CAT-OX PROCESS FLOV7SHEET
(i:,'TEGRATED SYS TE' I)
tn
ro
-'; O I
•recipitator
Converter
Acid
Storage
Economize]
and
Acid
Absorber
Acid Cooler
and
Circulator
TO
STACK
RECYCLE
ACID
80%
-------
10 --
9 --
8 ..
7--
Q
S3
ID
«
54-
4 •-
3--
2--
FIG. 4.4 Flue Gas DesulCurization in Japan
TOTAL
(REF. 10)
UTILITY
BOILERS
INDUSTRIAL BOILERS
1J72
1973
1974
YEAR
53
1975
1976
-------
30
in
I 20
FIG. 4.5 Total Flue Gas
Desulfurization By
U.S. Utilities
(REF. 20)
1.0
1972
.•J73
J/J74
1976
YEAR
1977 1978
1979
1980
54
-------
5. Solvent Refined Coal
5.1 Process Description
The solvent refined coal (SRC) process evaluated in this
study is based on the Stearns-Roger Corporation design performed for
the Pittsburg and Midway Coal Mining Company (2, Appendix A).*
Some modifications to the process have been made (3, pp. 198-199).
The plant is designed to operate at steady state conditions for
340 days/year (93.2% onstream factor). Since SRC is easily stored
and shipped, SRC plants need not be integrated with a single power
plant, but could serve several power plants within a given geograph-
ical area. For this study, two different size SRC plants have been
considered. The first is sized to produce fuel corresponding to a
particular power plant consumption. The second is assumed to be four
times this size. It is convenient to identify the size of the SRC
plants in terms of the equivalent power production from use of the
solvent refined coal. Thus, four different size SRC plants were
considered:
500 MW
2000 MW ~ Servin9 a 50° MW Power plant
1000 MW _ serving a 1000 Mw power piant
4000 MW
Salient consumption/production figures are given in the following
table:
Power Plant Size 1000 MW 500 MW
SRC Plant Size 4000 MW System 1000 MW 2000 MW System500 MW
SRC Product:
109 BTU/D 717.2 179.3 293.7 73.4
Coal Feed: T/D 39,016 9,754 15,972 3,993
Sulfur Product:
LT/D 861 215 352 88.1
Cresylic Acid
Product: T/D 488 122 200 49.9
* Appendix A of reference 2.
55
-------
The SRC product from the plant can be produced as a solid or
a liquid. It is expected to have the following properties:
HHV (BTU/LB) 15,960
% S 0.6 - 1.0
% Ash 0.1 - 0.2
The process has been divided into nine different sections. A
brief description of each section follows:
5.1.1 Section 1 - Coal Handling and Grinding
(2, App. A, pp 3-2 to 3-14)
Raw coal from storage is crushed to reduce the coal
particle size to < 1/8" (1/8 x 0). Oversize coal is recirculated
to the crushers. The fine coal is then processed through flash
dryers to remove moisture. Wet coal drops countercurrent to
rising hot flue gases from the dissolver preheater waste heat
boilers.
5.1.2 Section 2 - Slurry Preheat and Dissolvers
Coal is slurried with solvent (anthracene oil) at the proper
ratio (about 2:1 to 3:1 solvent to coal) and pumped through preheat
exchangers. Hydrogen is added to the slurry and it is then passed
through the dissolver preheaters and dissolvers. The coal dissolves
in the anthracene oil in the presence of hydrogen at a pressure of
1000 psig and a temperature of 825°F. The dissolution of coal involves
hydrogenation and depolymerization. The coal depolymerization and
dissolving process begins in the preheater where the material goes
through a gel stage and dissolution is completed to equilibrium in
the dissolver (1, p. 17). Heavy oils, hydrocarbons, H9S and CO., are
formed. Undissolved material consists of the ash content of the coal.
56
-------
Effluent from the dissolvers is cooled by heat exchange
with slurry feed and then combined into a single stream before
entering the high pressure flash vessel where vapor and liquid
are separated. The vapor stream containing light hydrocarbons,
phenols, cresols, water vapor, CO-, and fuel gas is fed to the
gas-liquid separation portion of the plant (Section 4).
The make-up and recycle hydrogen compressors are included
in this section.
5.1.3 Section 3 Ash Filtering and Drying
Slurry from the high pressure flash vessel flows to the
filter feed vessel and then to the rotary precoat filters.
These units which operate at 150 psig and 600°F are used to
separate the ash residue and undissolved carbon from the SRC-
solvent solution. The filter cake is washed with light sol-
vent to remove SRC-solvent solution. The ash portion contain-
ing some carbon is transferred to the ash drying section for
further solvent recovery and then to storage.
5.1.4 Section 4 - Solvent, Light Oil, and Cresylic Acid Recovery
Vapor from the high pressure flash vessel (Section 2) is
cooled and partially condensed in a series of heat exchangers.
Vapor-liquid separation occurs in the high pressure condensate
separator. Gas from the separator is used for power recovery
in an expansion turbine before flowing to Section 7. A por-
tion of the gas is blended with make-up hydrogen and sent via
the hydrogen recycle compressor to join the slurry at the
preheater inlet.
The water phase (containing phenols) from the high pressure
condensate separator is sent to the phenol and cresylic acid
recovery unit. The organic phase flows to the first stage
high pressure condensate flash drum.
57
-------
The condensate from this vessel is combined with filter
vent gas and flashed in the intermediate flash vessel. Remain-
ing liquid is flashed again in the low pressure flash vessel.
Gas streams from the two flash vessels (rich in H , CO.,, H_S,
2 & A
and C, - C-.) are compressed and sent to Section 7.
The liquid stream from the low pressure flash vessel is
preheated and sent to the fractionation area. This area con-
sists of two fractionation towers—the wash solvent splitter
column and the light ends column. In the wash solvent splitter
column, anthracene solvent is removed from the bottom and re-
cycled to the coal slurrying section. Wash solvent and lighter
materials are removed overhead and sent to the light ends column,
Here, wash solvent is removed from the bottom and returned to
the filters in Section 3. Light hydrocarbons and light oils
(containing cresylic acid) are removed overhead and sent to
the cresylic acid recovery unit.
Filtrate (containing the SRC) from the filtrate separator
is sent to the vacuum preflash vessel for removal of light
materials. These compounds are sent to Section 4. The liquid
phase is preheated in a fired heater and pumped to the vacuum
flash vessel. Vapors leaving the vacuum flash vessel flow
through a series of exchangers for heat recovery and then to
the fractionation area. Liquid from the vacuum flash vessel
is the solvent refined coal. It may be used in this form (the
temperature must be maintained above 300°P) or it may be trans-
ferred to Section 5 to be solidified.
5.1.5 Section 5 - Product Solidification
This section is necessary if it is desired to produce
a solid product. Liquid SRC is transferred to flaking drums
58
-------
and solidified using cooling water. The solid product is
transferred to storage silos via conveyors. From here it can
be loaded on rail cars or barges for shipment.
5.1.6 Section 6 - Hydrogen Plant
Hydrocarbons and light oil by-product streams are used
as hydrogen plant feed. No natural gas is imported. A con-
ventional steam reforming unit followed by shift conversion
is used to produce the required amount of hydrogen. Steam
produced is used elsewhere in the process and CO- produced
is vented.
5_._!.? Section 7 - Sulfur Removal and Recovery
The H2S removal facility is a conventional regenerative
amine unit. Feed for the unit consists of the following
streams:
H -rich vent gas from the expander
First stage high pressure condensate flash vapor
Intermediate flash vessel vapor
Low pressure flash vessel vapor
Light ends column overhead vapor
H-S is absorbed in amine solution in the absorber and stripped
out in the stripper. Desulfurized gas from the unit is used
as plant fuel. The H2S rich gas (stripper overhead) is sent
to a conventional Glaus unit for the production of elemental
sulfur.
5.1.8 Section 8 - Steam and Power Generation
The plant is in energy balance with respect to steam and
electric power consumption. Steam generation and electric
59
-------
power generation facilities are included. Fuel gas and light
fuel oil produced by the process are used in the boilers.
5.1.9 Section 9 - Other Offsites
This section includes other offsites—water treating,
the cooling tower and cooling water system, the tank farm,
the instrument and service air facilities, the waste water
disposal facilities, and the general plant buildings.
60
-------
5.1.10 Energy Balance
MM Btu/Hr
1000
Energy Consumption 4000
Dissolver Preheaters
Vacuum flash preheater
Wash solvent splitter
heater
Ash residue drying
Power generation
Hydrogen plant fuel
Hydrogen plant feed
Miscellaneous
MW
MW System
5078
1291
1176
201
143
1951
3299
201
1000 MW
1269
323
294
50
36
488
825
50
500 MW
2000 MW System
2079
528
482
82
59
799
1350
82
500 MW
520
132
120
21
15
199
337
21
Total
13,340
3,335
5,461
1,365
Energy Production
Fuel Gas 9352
Light Oil burned as 3988
fuel
Total 13,340
2338
997
3,335
3829
1632
5,461
957
408
1,365
61
-------
5.2 Complexity
A solvent refined coal (SRC) plant is a complicated
process involving many processing steps and many major pieces
of equipment. The major processing steps along with the
equipment used are listed below:
Coal Handling and grinding: conveyors, feeders,
crushers, screens, dryers, cyclones, bag filters,
blowers
Slurry preheat and dissolvers: gas compressors,
expanders, fired heaters, vessels designed for severe
process service
Ash filtering and drying: rotary precoat filters
which must remove very small ash particles at high
temperature and pressure, blowers, bag filters, com-
pressors, feeders, conveyors, rotary indirect fired
dryer, transfer and loading blowers, storage silos
Solvent, light oil, and cresylic acid recovery:
compressors, fractionation towers, fired heaters,
steam jets
- Product solidification: flaking drums, conveyors,
bucket elevators, storage silos
- Hydrogen plant: fuel fired catalytic reformers
Sulfur removal and recovery: absorbers, strippers,
fired heaters, reactors
- Steam and power generation: boilers, turbines,
generators, transformers, electrical switch gear, and
electric power distribution facilities
62
-------
Other offsites: cooling tower, chemical treatment
facilities, air compressors, dryers, filters, waste
water treatment facilities, buildings
Also included in almost all sections of the plant are
pumps, heat exchangers, tanks, and drums (as well as other
processing equipment).
63
-------
5.3 Flexibility
Due to its complexity an SRC plant is extremely costly
and would appear to be economically attractive for supplying
power plant fuel only when applied on a very large scale. For
example, the use of a centrally located SRC plant which supplied
fuel for a number of power plants in the area may be promising
(particularly for new power plants). From the results of this
study it appears that the minimum economic size for a centrally
located SRC plant would be in the range of 30,000-40,000/tpd
coal feed (perhaps larger), supplying fuel for about 3,000-4,000/MW
of power (at a heat rate of 8700 Btu/kwh and a load factor of
80%) .
It is expected that an SRC plant would operate at a
relatively constant capacity for 340 days/year (93.2% on-stream
factor). The SRC product (liquid or solid) will be stored such
that changes in power plant demand for fuel will simply result
in a changing inventory of SRC. Long term reduced demand for
fuel could be accommodated by shutting down parallel trains
of equipment in the various sections of the SRC plant.
Since an SRC plant is so large and complex, start-ups
and shut-downs are expected to be rather lengthy and complicated
procedures. Therefore, it would appear to be desirable to
run the plant at a relatively constant through-put. Major
maintenance and inspection work is expected to be done during
an annual turn-around of about three weeks duration.
64
-------
5.4 Status of Technology
5.4.1 Description of Present Status
The solvent refined coal (SRC) process was developed on
a laboratory scale by Spencer Chemical Corporation (now
Pittsburg and Midway Coal Mining Company). The design basis
for the process was developed during the period of 1962-1965
in the pilot plant studies of Spencer Chemical Corporation
(1, pp. 17, 19). The pilot plant was designed for 100 Ib/hr
of feed coal at a 2:1 solvent to coal ratio. The unit is
located in Kansas City, Missouri. (5, pp. 9, 13).
Process Research, Inc., carried out a conceptual design
9
study for a 222 x 10 Btu/day SRC plant which could supply fuel
for a 950-1000 MW power station (1, p. 20). A 6 ton/day pilot
plant is being built at Southern Electric Company's Ernest C.
Gaston Plant. This plant, which is to be used to study the
steps in the solvent-refining process, is about ready for
start-up. A 50 ton/day pilot plant sponsored by OCR is being
built at Tacoma, Washington by Pittsburg and Midway Coal
Mining Company. This plant is scheduled for a 1974 start-up
(1, p. 17) .
Coal News reports that Wheelabrator-Frye Inc., Southern
Company, and Gulf Oil Corporation have contracted for con-
struction of a 1000 ton/day SRC demonstration plant. The
plant site has not yet been selected. If the demonstration
plant is successful, the plan calls for expansion to 10,000
tons/day of SRC. Technology used will be that developed by
Pittsburg and Midway Coal Mining Company, a subsidiary of
Gulf Oil Corporation. (30, p. 2)
65
-------
The SRC process is not presently commercial in that no
commercial size units are in operation. The process uses
unit operations which are commercial. They simply have not
as yet been demonstrated for this process.
5.4.2 Areas of Uncertainty
Since the SRC process has never been operated on a
commercial scale, there are many areas of uncertainty re-
garding the process. Some of these are listed below:
• Dissolver temperature. This can vary from 385 to
480°C (725-896°F). The optimum temperature is believed
to be about 440°C (825°F). Above this temperature, coking
occurs and below it, the viscosity increases rapidly. For
example, a ten-fold increase in viscosity of the mixture has
been observed as the temperature is decreased from 482°C to
425°C (1, p. 20).
• Solvent to coal ratio. This can vary from 2:1 to
4:1.
• Dissolver residence time. This can vary from 1/4-4
hours.
• Hydrogen requirement. This has been found to vary
from 0.8 to 1.5 lb H2/100 Ib of coal feed (1, p. 20).
• Gel formation. Considerable difficulties have been
encountered due to the formation of a gel (with an accompany-
ing viscosity increase) as the temperature of the slurry is
being increased. The gel disappears when the temperature
becomes high enough to form a true solution (1, p. 20; 4, p. 24)
66
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• Phenol and cresylic acid recovery unit. The pro-
cess for recovery of phenol and cresylic acid from water and
hydrocarbon streams is somewhat undefined at the present
time. More development work will be necessary to establish
a suitable process (2, App. A, p. 3-12).
• Filtration step. The separation of ash from the
coal-solvent solution under pressure is expected to be a very
troublesome operation. The filtration step must be conducted
at 550-700° F and 100-200 psig. The ash solids to be removed
are 1-40 microns in size making the filtration task formidable
(4, p. 24).
Other methods have been considered for removal of ash from the
coal-solvent solution. Some of these are listed below:
- Centrifuges
Hydroclones
Cartridge filters
• Degree of ash removal. Ash in the solvent refined
coal is expected to range from 0.05 to 0.10% (1, p. 20; 2, App.
B, p. 3-1). Pilot plant studies have shown that ash in the
solvent refined coal varies from 0.17 to 0.48% (5, pp. 252-253).
• Degree of sulfur removal. This will vary and will de-
pend on the type of sulfur originally present in the coal as
well as on the process operating conditions (3, p. 207). The
process will remove virtually all of the pyritic sulfur and
about 50-70% of the organic sulfur originally present (4, p. 24).
Pilot plant studies have shown that the solvent refined coal
has a sulfur content of 0.45 to 1.22% when the feed coal con-
tained 0.81 to 4.18% sulfur on an as received basis (5, pp.
252-253).
67
-------
• Product distribution. Of particular importance
is the amount of cresylic acid produced. This can vary from
1-4% of the coal feed. For this study a value of 1.2% was
used (2, App. A, p. 4-4). Also important is the quantity of
phenol produced. This can vary from 0.2-0.5% of the coal
feed. A value of 0.36% was used for this study (2, App. A,
p. 4-4).
68
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5.5 Environmental Effects
The primary purpose of an SRC plant as evaluated in
this study is to produce a low sulfur, ash-free fuel for
power plant use. The sulfur content of the SRC is expected
to be about 1% (2, p.10; 3, p. 206) which would result in
a power plant emission of 1.25 Ib S02/MM Btu assuming an SRC
higher heating value of 16,000 Btu/lb. This almost exactly
matches the current EPA emission standard of 1.20 Ib S02/MM Btu,
If emission standards become more stringent, the sulfur content
of the SRC can probably be reduced to 0.4-0.6% by process modi-
fications at increased cost (1, p. 23; 3, p. 207). A sulfur
level of 0.6% in the SRC would result in a power plant emission
of 0.75 Ib S02/MM Btu.
Elemental sulfur is formed in the SRC plant via a conven-
tional Claus unit after the H-S-rich gases have been treated
in an amine unit. The quantity of sulfur produced is shown
below for the different plant sizes.
Power Plant Size 1000 MW 500 MW
SRC Plant Size 4000 MW 1000 MW 2000 MW 500 MW
Sulfur Product: LT/D 861 215 352 88.1
In the economic study, the sulfur was given a value of
$5/LT which amounts to a credit of 0.62 C/MM Btu. This is
virtually negligible in the overall cost of the process (<1%).
The economics would not be significantly affected if the sulfur
had no credit at all. If a significant increase in sulfur
selling price could be acheived (say to $30/LT), the process
cost would drop by about 3.10 C/MM Btu.
There appears to be some question about the ash content of
SRC. Some sources expect it to be as low as 0.05% (1, p. 20)
while others predict a value of 0.10% (2, App. B, p. 3-1).
69
-------
Pilot plant studies have yielded somewhat higher values-0.17
to 0.48% (5, pp. 252 - 253). If the SRC is assumed to have
0.20% ash, the overall ash removal efficiency of the process
will be about 99%, assuming that the coal originally contains
about 10-12% ash.
% Ash Removal=100 - [ - ^0.20) ] 100 = 99.0
The SRC process was modified to eliminate the carbon
burn-off section of the plant. Therefore, the ash from the
drying section will contain about 30-35% carbon (2, App. A,
p. 5-21) . This increases the quantity of material to be
disposed of by 50%. It is assumed that the ash (containing
carbon) will be used as land-fill.
Substantial quantities of cresylic acids are formed in
the SRC process. These compounds reportedly can vary from 1-4%
of the coal feed. For this study, a value of 1.2% was used (2,
App. A, p. 4-4) . The following table shows the amount of cre-
sylic acid assumed to be produced for the different plant sizes
Power Plant Size 1000 MW 500 MW
SRC Plant Size 4000 MW 1000 MW 2000 MW 500 MW
Cresylic Acid: T/D 488 122 200 49.9
A sales price of $100/T (5<=/lb) was used for cresylic
acid. The sale of cresylic acid has a significant impact on
the process economics. If either the sales price or the
amount produced doubled, the process operating cost would drop
by 7.07 C/MM Btu.
Carbon dioxide is produced in large volumes in the hydrogen
plant. No credit was taken for this compound.
There are several waste water streams from the process.
Process water which contains cresylic acid will be filtered
70
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through activated carbon filters. Process area runoff water
will go to a separate storm sewer and to a holding pond. Oil
separation will be accomplished by an API skimmer. Aeration
may be required. Other area runoff water and cooling tower
blowdown will be discharged to the sewer with no treatment.
Sewage will be treated in a package unit before being dis-
charged (2, App. A, p. 3-14).
71
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5.6 Installation
Since the SRC process is not commercial at the present
time, some uncertainties exist when attempting to predict the
length of time required for a full size unit to be placed on
stream.
As shown in Figure 5.2, about 11-12 years are believed
to be required for commercialization of a large SRC process.
The time can be broken down briefly as follows:
Demonstration plant: 3 years
Feasibility studies, environmental studies,
licenses and permits, design and engineering:
4 years
Procurement and construction: 4 years
Start-up: 1 year
An SRC plant is a complex process employing many process-
ing steps and many pieces of equipment. In addition, the process
appears to be economic only when applied at a very large scale.
Although no layout drawings are available at the present time,
it is believed that a plant capable of processing 10,000 T/D
of feed coal would require about 50 acres of land - perhaps more
if additional raw coal storage is to be provided for. Naturally,
larger plants will require even more space.
As stated previously, the installation of a large, cen-
trally located SRC plant appears to be the most promising. The
plant would be sized for about 30,000 - 40,000 T/D of coal
feed and would supply fuel for about 3,000 - 4,000 MW of power.
Presumably, the power would be generated by several stations
and the SRC would be transported to the power plants as required
by rail or barge.
72
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FIGURE 5.1
SOLVENT REFINED COAL PROCESS FLOW DIAGRAM
FOR USE IN
PLANT
STEAM
& POWER
GENERATION
FUEL GAS K, OTL
U)
HYDROGEN
PLANT
RAW
COAL_
FEED
COAL
HANDLING
& GRINDING
LIGHT OIL
GAS
SLURRY
PREHEAT
DISSOLVER
RE-
CYCLED
SULFUR
REMOVAL &
RECOVERY
SULFUR
BY-PRODUCT
ASH
FILTERING
DRYING
I
SOLVENT
& LIGHT
OIL
RECOVERY
OTHER
OFFSITES
PRODUCT
SOLIDIFI-
CATION
SRC
CRESYLIC ACID
BY-PRODUCT
-------
Fig. 5.2
ANTICIPATED COAL LIQUEFACTION PROJECT SCHEDULE
(REF. 8)
ACTIVITIES
Demonstration nlant
Feasibility Studies for
Commercial f 1 v.it
Environmental Studies
Licenses & Permits .
Environmental Impact
Statement
Design & Engineering
Specification?, Bidding
& Contract:; A *.-•:.- -'.s
Equipment Procurement
Site Access and
Preparation
Mine Development &
Construction
Plant Construction
Plant Startup
9 10 11 12
Years
74
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6. LOW BTU GAS
6.1 Process Description
Supplies of low sulfur petroleum fuels are becoming
scarce, therefore, power plants will have to use high sulfur
fuel but with some kind of desulfurization. Production of
intermediate or low Btu gas from coal, which can be used
in a power plant, is a possible alternative. This route
has two major advantages:
1) the gas can be generated under pressure which is
an advantage for the existing as well as the new power plants
since it permits some operating economics.
2) the gas is produced under reducing conditions which
convert coal sulfur to H2S which is readily removed by well-
proven absorption processes.
Types of Gasifiers
There are three types of gasifiers that are being inves-
tigated on various levels of development. They are:
1) Fixed Bed Gasifiers: This type has the advantage of
a counter-current flow which aids the overall conversion con-
siderably. It also has the advantage of having distinct
temperature zones inside the gasifier. However, it has some
disadvantages such as the low throughput and the restriction
of feed to noncaking pre-sized coal particles. This type of
gasifier is best exemplified by the Lurgi gasifier (7).
2) Entrained Bed Gasifiers; This type has the advan-
tage of high throughput, and it can use any type
of coal without requiring sized coal particles, it has
75
-------
the disadvantages of high temperature operation and
the requirement for large volume reactors since complete con-
version is difficult to acheive in one pass. This type is
best exemplified by Koppers-Totzek gasifier (7).
3) Fluidized Bed Gasifiers: The major advantages of this
type are the long solids residence time and the excellent heat
transfer characteristics which aid in char gasification. It
has some disadvantages in that it has to operate below ash
fusion temperature to prevent agglomerates formation and it
also requires some pretreatment for caking coals. This type
is exemplified by the Hygas gasifier (7).
Since the Lurgi gasifier is the most advanced type (62
gasifiers are already installed in 14 installations) it will
be used for the purposes of this comparative study.
The Lurgi Gasifier
The gasifier is the major piece of equipment in a Lurgi
gasification plant. Coal is fed through a lock hopper. In
the gasification zone, coal is contacted with a mixture of
steam and air. The coal is gasified and a stirring mechanism
keeps the coal and ash particles from fusing together. The
ash is then recovered at the bottom through a revolving grate
into a lock hopper from which it is ultimately discharged.
The raw gas leaving the gasifier contains liquid hydrocarbons
and tars distilled from the coal. They are condensed and are
either recycled to the gasifier or used as fuel gas. This
leaves a gas containing H_S which is removed by conventional
purification equipment.
For this study, a Benfield system is employed for H2S
removal. The concentrated H_S stream is converted to elemental
sulfur in a conventional 2-stage Glaus plant. The Glaus plant
tail gas is incinerated and vented to atmosphere; no tail gas
76
-------
treatment is included. The system has been designed to give
an overall sulfur recovery of 90%. Total emissions from the
gasification plant and power plant are 0.6 Ibs S02/MM Btu,
based on the coal feed to the gasifiers.
Figure 6.1 shows a schematic diagram for producing low
Btu gas by the Lurgi process. For the purpose of this inves-
tigation two gasification plants were considered. The first
supplies sufficient energy to a 500 MW existing power plant
operating at a load factor of 60%, and the second supplies a
new 1000 MW power plant operating at 80% load factor. Both
plants utilize coal having 3.5% by weight sulfur, 5% by weight
moisture and 12% by weight ash. The heating value for coal
was assumed to be 12,000 Btu/ib. The heat rate for the exist-
ing plant was assumed to be 9,500 Btu/kwh while that for the
new plant was assumed to be 8,700 Btu/kwh. Table 6.1 shows
the material balance for both cases, while Table 6.2 presents
the annual utilities consumption.
77
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6.2 Complexity
The major process steps are shown in the flow diagram of
Figure 6.1. The gasification section for a 1000 MW power plant
consists of thirty trains of gasifiers with their accessories.
There are three trains of equipment for fines agglomeration, H»S
removal, and sulfur recovery. The Glaus plant is a two-stage
system with no tail gas clean up. Although a three-stage Glaus
plant may cut S02 emissions from the sulfur plant in half, it
was assumed that the added investment would not be justified
since the sulfur plant emissions are below regulation standards
(see Table 6.1). In each section of this process, several
heat exchangers, pumps and columns are involved. The gasifier
design is the only complex portion of this plant. The design
of the rest of the equipment is relatively simple.
78
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6.3 Flexibility
Operation of a coal gasification plant is more like that
of a chemical plant than of a power plant. It is relatively
complex since it requires contorl of the flow and composition
of more process streams. It is more difficult to start up and
shut down and it requires more time to reach optimum conditions
than does a power plant. Because of these reasons, special
training of operators may be necessary and could prove to be
expensive for small power plants. Another major disadvantage is
the necessity to start up and shut down the facility simultan-
eously with the power plant since large-scale storage of gas is
very costly and impractical. For example, for a 500 MW exist-
ing plant operating at 60% load factor it would require about
250,000 brake horsepower to compress only one hour's gas production
from 16 psi to 500 psi in a three stage compressor with cooling
between stages. The compressed gas needs a spherical storage
vessel of 130 feet inside diameter.
Production of low Btu gas could therefore be more appli-
cable to industrial power plants than to utility plants be-
cause the output of such a plant does not vary appreciably
and thus the gasification plant can be designed for a relatively
constant output which avoids the problems of instability
during frequent start ups and shut downs or during cyclic
increases and decreases in production.
79
-------
6.4 Status of Demonstrated Technology
Several gasification processes are being investigated
at various levels of development. Some of these are already
into the commercial stage. Table 6.3 shows these various
projects and their stage of development.
80
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6.5 Environmental Effects
The major effect on the environment is the disposal of
ash which amounts to about 200 M tons/yr for the 500 MW
plant and approximately 500 M tons/yr for the 1000 MW plant.
This ash can be disposed of by land filling. The sulfur pro-
duced from the 500 MW plant would amount to 52 M tons/yr, and
that from the 1000 Mw plant about 126 M tons/yr. It is
assumed that such amounts of sulfur can be readily marketed
and should not present any major problem. S0~ emissions would
amount to approximately 0.58 Ibs SO^/MM Btu of coal gasified,
which is below the national standards of 1.2 Ibs SO_/MM Btu.
A major environmental advantage of the low Btu gas
combustion in power plants is the reduction of NO emissions
by 60 - 90% over the conventional boilers (11).
81
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6.6 Installation
As shown in Figure 6.2, it requires eight to nine years
to get the gasification plant to a producing stage. About
half this time is needed for preliminary studies and design
of the facility. The second half is spent in construction
and start up of the plant. The Lurgi gasification plant re-
quires a relatively large piece of land since several trains
of gasifiers are needed. It was assumed for this study that
the gasification plant could be locazed adjacent to the power
plant thereby minimizing the length of gas transmission lines,
82
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TABLE 6.1
oo
GO
STREAM
MATERIAL BALANCE FOR LOW BTU GAS PROCESS*
EXISTING 500 MW
POWER PLANT - 60% LF
SO Emissions, Ibs. SO2/MM BTU
coal feed***
NEW 1000 MW
POWER PLANT - 80% LF
Raw Coal Feed: T/HR
(3.5% S; 12% Ash; 5% HO)
MM BTU/HR
Steam: T/HR
Ash: T/HR
Air: MM SCF/HR
Sulfur: T/HR**
Clean Gas: MM SCF/HR
: 109 BTU/HR
314
7,536
240.1
37.6
15.2
9.9
38.67
4.75
575
13,800
439.
69
27.
18.
70.
8.
8
8
1
82
7
0.58
0.58
* Reference: "Clean Fuel Gas From Coal", Lurgi Mineraloltechnik GmbH, October, 1971.
** 90% recovery
*** Total emissions for both gasification plant and power plant.
-------
TABLE 6.2
ANNUAL UTILITIES - LOW BTU GAS PLANTS
ITEM
EXISTING 500 MW PLANT NEW 1000 MW PLANT
Quantity
Cost M$ QuantityCost M$
Feed Water
$0.20/Mgal.
Cooling Water
$0.02/Mgal.
Steam
$0.50/Yl Ib
1.29 x 10 Mgal 25.8 3.15 x 10 63.0
230.2 x 105 Mgal 460.4 562.7 x 105 1125.5
25.2 x 105 Mlb 1261.9 61.6 x 105 3082.1
Reference: "Clean Fuel Gas From Coal", Lurgi Mineraloltechnik,
October, 1971.
84
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TABLE 6.3
COAL GASIFICATION PROCESSES FOR PRODUCTION OF LOW B.T.U. GAS
CO
en
PROCESS
Commerc ial
W i n k 1 e r
Demonstration
Lurgi
Pilot Plants
1 . USBM
2. G.E.
3. Combustion
Engineering
Consol idated
Edison
4. Westinghouse
5. Pittsburg-
Midway
6. IGT-U-gas
REACTOR
BED TYPE
Entrai ned
Fi xed
Fixed
Fi xed
Entrai ned
Multiple
Fluid Beds
Entrai ned
(2-stage)
Fluid Bed
NATURE OF
RESIDUE
Dry Ash
Dry Ash
Dry Ash
Dry Ash
Slag
Dry Ash
Slag
Dry Ash
PRESSURE
ATM.
1
20
20
8
1
.10-16
4-35
20
TEMP.
°F
1500
1000
1000
1000
>2100
1300-1700
& 2000
>2100
1900
CAPACITY
T/D
2000
2000
20
0.25
180
15
1200
30-50
SOURCE: - Chemical Engineering, July 22, 1974
-------
RAW COAL
FEED
STEAM
ASH
00
o»
AIR
FIGURE 6.1
LURGI LOW BTU GAS PROCESS
COAL
PREPARATION
& HANDLING
70%
i
LURGI
GASIFIERS
AIR
320
Psi
HEATER
AIR COMPRESSOR
& TURBINE
CLEAN GAS
16 Psi
290 °F
30%
RAW
GAS
250 Psi
FINES
AGGLOMERATION
~
REMOVAL
(BENFIELD SYSTEM)
2-STAGE
GLAUS
PLANT
SULFUR
•-\rr. —*
-7R
-------
Fig. 6.2
ANTICIPATED COAL GASIFICATION PROJECT SCHEDULE
(RE?. 8)
ACTIVITIES
Preliminary Studio.-:-
& Estimates
Environmental Ctuclins
Licences & Permi!:.-;
Environmental Iroact
Statement
FPC Approval
Design & Engineering
Specification*, Bidding
& Contract Avarcl:;
Equipment Procurement
Site Access and
Preparation
Mine Development &
_Const ruction
Plant Construction
Plant Startup
PLANNING
CONSTRUCTION
1 2 3 4 5 6.7 89 10
Year After Obtaining Coal Lease
87
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7. ECONOMIC COMPARISON OF PROCESSES
7.1 Basis for Costs
Investment and operating costs for the wet limestone
process, the Wellman/Allied process, and the solvent refined
coal process were obtained using cost models developed by
Kellogg and reported in a recent study for EPA (7). The wet
limestone model is based on a study by Catalytic, Inc. (31).
The basis for the Wellman Lord/Allied model is the demonstration
plant now under construction at the D. H. Mitchell plant of
the Northern Indiana Public Service Company. The cost model
for solvent refined coal is based on the report by Stearns-
Roger for the Pittsburg and Midway Coal Mining Comapny (2).
Costs for the Cat-Ox process were taken from a recent TVA
study for EPA (12). These were adjusted to a basis consistent
with the other processes. Cost data for Lurgi low Btu gas
were taken in part from a cost model for substitute natural
gas, as reported in the Kellogg study previously cited, and
partially from confidential Kellogg sources.
To obtain a consistent economic basis for the processes
so that valid cost comparisons could be made, a standard cost
accounting format has been utilized. This format, which is
based on a utility financing method recommended in a report
to the Federal Power Commission (32), was used by Kellogg
in the report previously mentioned to develop a general cost
model. The general cost model has been used for all cost com-
parisons. A detailed description of the model including
definition of terms is discussed in the Appendix.
All plants are assumed to have a midwest (Cincinnati)
location. Costs are on an end-of-1973 basis, since most of
the available cost information is referenced to this time.
No contingencies are included in the estimates.
To further establish a uniform cost basis, standard unit
-------
prices were assumed for all raw material, utilities, and by-
products. These values are listed in Table 7.1.
89
-------
7.2 Energy Conversion Efficiency
Table 7.2 presents a summary of the energy conversion
efficiencies and heat rates of each process. These are based
on the data developed in preceding sections of the report on
the energy consumption of each process. The low Btu gasification
process is the least efficient followed by SRC and then stack gas
scrubbing.
90
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7.3 Manpower Requirements
Table 7.3 presents the total number of operators for
each process. It is clear that stack gas scrubbing requires
far less working labor than the other two processes.
91
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7.4 Economics of Each Process
7.4.1 Flue Gas Desulfurization
This section details an economic analysis of three
flue gas desulfurization processes: wet limestone, Wellman-
Lord/Allied, and Cat-Ox. Tables 7.4, 7.5, and 7.6 outline
the annual scrubbing costs of the three processes. Figures
7.1, 7.2, and 7.3 add the scrubbing cost to the coal cost,
and show the total production cost of energy to the power
plant in $/MM Btu. Figure 7.4 shows the effect of varying
load factor on the total production cost.
The wet limestone and Wellman-Lord/Allied scrubbing costs
are based on the M. W. Kellogg scrubber cost models (3, pp.
77 - 135). The Cat-Ox scrubbing costs are calculated from
equipment and utility costs outlined in the TVA report (12,
pp 244 - 249), and from equations presented in the M. W. Kellogg
general cost model (3 pp 54 - 76).
In the Wellman-Lord/Allied and Cat-Ox processes, credits
are given for the by-products generated.
7.4.2 Economics of SRC
The total plant investment (TPI) for the SRC process was
calculated based on the MWK cost model (3, pp. 198 - 203). This
model in turn was based on the Stearns-Roger design (2, App. A).
For the 1000 MW new plant, a credit of $30/kw was applied to
the TPI for the SRC process due to savings at the power plant
(coal handling, ESP's, ash handling, etc.).
Total capital required (TCR) includes interest during
construction, startup costs, and working capital and is cal-
culated by the following:
92
-------
TCR =1.21 TPI + 0.8 (TO) (CO) (1 -I- F) + 0.4 ANR
Where TO = Total number of shift operators
CO = hourly rate per operator (Gulf Coast), $1 hr.
F = Location Factor (=1.53 for Cincinnati)
ANR = Annual cost of raw materials and utilities less
by-product credits, M$/yr.
93
-------
For the SRC process, ANR is calculated from
ANR = ACOAL + ACHEM - ASULF - ACRES
Where ACOAL = Annual cost of coal, M$/yr
ACHEM = Annual cost of chemicals, M$/yr
ASULF - Annual credit for sulfur, M$/yr
ACRES = Annual credit for cresylic acid, M$/yr
The total annual production cost (TAG) including return of
capital, payment of interest, and income tax on equity return
is given by:
TAG = 0.225 TPI + 2.1 (TO) (CO) (1 + F) + 1.04 ANR
The total annual production cost for the SRC process was
calculated in M $/yr and C/MM Btu for four different cases.
The effect of coal price on TAG was investigated (coal prices
of $5, $10, and $15/T were used). Also the effect of load factor
on TAG (at a coal price of $10/T) was calculated.
7.4.3 Economics of Low Btu Gas
The following is a detailed discussion of the cost
figures appearing in Tables 7.11 - 7.12 which display a
summary of the process economics.
Total Plant Investment
The bare costs (BARC) of sections 1, 2, 3, 4 and 7
were determined using a cost estimation model for a base case
of an SNG plant developed by MWK. Some adjustment was made
in the cost of Section 7 since the cost of this section would
be higher for the SNG plant. The bare costs of Section 5 and
6 were obtained by proper adjustments of current prices
offered by some producing companies at the end of 1973 (9, 10).
94
-------
As shown in the Appendix, the plant investment (TPI) can be
approximated as 1.12 BARC, where BARC is the sum of equipment
and other material costs, labor costs, and home office
engineering costs. This relation was used in the calculation of
the individual section's investment.
For comparison of low Btu gas vs. stack gas scrubbing
to service a new power plant, it was estimated that the low
Btu gas plant can be credited with 40 $/kw of power plant
capacity due to savings in the power plant investment. Such
savings are a result of eliminating some major equipment
from the power plant (such as coal handling, ESP units, etc.)
when it uses clean gas as a fuel.
Annual Cost of Raw Material and Utilities less Credits (ANR)
ANR can be calculated from:
ANR = Annual Coal Cost (ACOAL) + Annual Utilities -
Annual Credits
ANR was calculated for three prices of the coal feed as shown
in Tables 7.11 - 7.12. Changes in the steam cost were con-
sidered to be small in comparison with those of the changes
in the coal price, and thus were neglected.
Total Capital Required
The total capital required (TCR) for the gasification
plant is:
TCR = 1.15 TPI + 0.8 (TO)(CO) (1 + F) + 0.4 ANR
This equation was used in the calculations. Two values for
TCR of the new plant are shown in Table 7.12 as a result
of using the adjusted TPI which takes into account the 40 $/kw
credit for comparison with stack gas scrubbing.
95
-------
Total Annual Production Cost
Based on a twenty year life for the gasification plant,
the total annual cost of production is:
TAG = 0.217 TPI +2.1 (TO)(CO) (1 + F) +1.04 ANR
The changing price of coal will affect only the last term of
the above equation.
Values for total annual production cost on a yearly
basis as well as on a cents per MM Btu basis are shown in
Tables 7.11 - 7.12 for three different coal prices. The
effect of load factor on TAG for an existing plant and a
new plant is shown in figure 7.7, for a coal price of $10/Ton,
The effect of coal cost on TAG is presented for these two
plants in figure 7.8.
Doubling the coal price form 5 to 10 $/T results in a
32% increase in the cost of producing the gas and the effect
is linear in the cost range 5-15 $/T.
96
-------
7.5 Cost Comparison
Figures 7.9 - 7.10 show the total annual cost of all
the investigated processes vs. coal cost for the existing
500 MW plant operating at 60% load factor and the new 1000
MW plant operating at 80% load factor respectively. For
both plants, stack gas scrubbing appears to be superior
to the use of SRC or low Btu gas. The wet limestone process
semms to be the cheapest scrubbing method and costs only about
half that of SRC or low Btu gas. Quadrupling the size of
the SRC plant reduces the cost of production by almost 40%
and makes the process competitive with stack gas scrubbing
at low coal prices.
If the coal costs less than 10 $/ton, low Btu gas is
cheaper than SRC if the plants are to service only one 500
MW existing or 1000 MW new power plant.
97
-------
TABLE 7.1
UNIT PRICES USED IN COST COMPARISONS
(Basis: End of 1973)
Item
Unit Price
Limestone
Ammonia
Sodium Carbonate
Filter-Aid
Catalyst (Cat-Ox)
$ 4.00/ton
$ 50.00/ton
$ 40.00/ton
$ 50.00/ton
$ 44.00/cu. ft.
Steam
Process Water
Cooling Water
Power
Natural Gas
Fuel Oil
$ 0.50/M Ibs
$ 0.20/M gal
$ 0.02/M gal
8.0 mills/kwh
$ 0.50/MSCF
$ 0.80/MM Btu
Sulfur
Cresylic Acid
Sulfuric Acid (80%)
$ 5.00/LT
$100.00/ton
$ 4.63/ton
98
-------
Table 7.2
Process Energy Conversion Efficiency
Flue Gas Desulfurization
Low
Power Plant WetWellman-Btu
Power Plant with no S02 controls Limestone Lord/Allied Cat-Ox SRC Gas
EXISTING 500 MW
% Efficiency 35.9
33.5
30.6
35.1 26.1 22.6
Heat Rate
BTU/KWH
9,500
10,184 11,139 9,717 13,060 16,132
NEW 1000 MW
% Efficiency 39.2
37.7
33.6
39.2 28.5 24.7
Heat Rate
BTU/KWH
8,700
9,047 10,157 8,700 11,960 14,770
99
-------
Table 7.3
Process Manpower Requirements'
Flue Gas Desulfurization
SRC
Power Plant
Wet
Limestone
Wellman-
Lord/Allied Cat-Ox
Sized For
Power Plant
Sized for 4
Times Larger
Low
Btu
Gas
o
o
EXISTING 500 MW
Total Operators
16
90
222
159
NEW 1000 MW
Total Operators
16
160
396
300
References: 3,12
-------
Table 7.4
ECONOMICS OF WET LIMESTONE SCRUBBING
Total
Total
Existing
Plant Investment, M$ 29
Capital Requirement, M$ 34
500
,115
,880
MW
New 1000
40,799
48,610
MW
Raw Material & Utility Cost, M$/yr
Limestone
Ammonia
Process Water
Fuel Oil
Electricity
712
10
27
283
586
.5
.6
.2
.5
.4
1,740
19
66
692
1,432
.5
.5
.4
.0
ANR, M$/yr 1,620.2 3,950.4
Total Annual Scrubbing Costs
M$/YR 9,029 14,153
MILLS/KWH 3.43 2.01
C/MM BTU 36.11 23.09
101
-------
Table 7.5
ECONOMICS OF WELLMAN-LORD/ALLIED SCRUBBING
Existing 500 MW New 1000 MW
Total Plant Investment, M$ 31,921 46,561
Total Capital Requirement, M$ 37,820 55,930
Raw Material and Utility Costs
Less Credits, M$/yr
Sodium Carbonate 334.9 817.8
Natural Gas 216.7 529.3
Filter Aid 18.3 44.7
Electricity 551.5 1,346.8
Steam 806.0 1,968.4
Cooling Water 123.2 300.9
Process Water 3.8 9.3
Fuel Oil 283.5 692.4
Sulfur Credit (141.6) (345.8)
Purge Disposal 16 .6 40.6
ANR, M$/yr 2,212.9 5,404.2
Total Annual Scrubbing Costs
M$/YR 10,477 17,259
MILLS/KWH 3.98 2.46
C/MM BTU 41.90 28.29
102
-------
Table 7.6
ECONOMICS OF CAT-OX SCRUBBING
Existing 500 MW New 1000 MW
Total Plant Investment, M$ 42,572 78,534
Total Capital Requirement, M$ 49,498 90,435
Raw Material & Utility Costs
Less Credits, M$/yr
Catalyst 138.4 351.5
Electricity 470.4 1,495.9
Fuel Oil 960.0
Cooling Water 133.7 13.6
Steam Credit - (640.0)
Sulfuric Acid Credit (636.1) (1,203)
ANR, M$/yr 1,066.4 18.0
Total Annual Scrubbing Cost
M$/YR 11,496 18,929
MILLS/KWH 4.37 2.70
C/MM BTU 46.05 31.05
103
-------
Table 7.7
SRC PROCESS
1000 MW NEW POWER PLANT
1000 MW SRC PLANT
80% LF
60.97 x 1012 BTU/YR
Total Plant Investment
Section Description
1 Coal Preparation
2 Preheater, Dissolvers
3 Ash Filtration, Drying, Disposal
4 Solvent, Light Oil, Cresylic Acid
Recovery
5 Product Solidification, Handling,
Storage
6 Hydrogen Plant
7 Sulfur Removal and Recovery
8 Steam and Power Generation
9 Other Offsites
TPI
Credit
TPI Adjusted
Coal Price
$5/T $10/T
TCR: M$ 206,000 212,000
TCR Adjusted: M$ 169,700 175,700
Raw Materials and Utilities w
Costs Less Credits M$/YR
ACOAL 16,582 33,163
ASULFUR: $5/LT (366)
ACRESYLIC ACID: $100/T (4,145)
ACHEMICALS 359
Cost: M$
10,000
40,000
15,000
30,000
10,000
10,000
10,000
10,000
29,000
164,000
30,000
134,000
$15/T
219,000
182,700
49,745
ANR: M$/YR 12,430
Total Annual Production Cost
29,011
45,593
0.225 TPI
2.1 (TO) (CO) (1 + F)
1.04 ANR
TAG: M$/YR
: C/MM BTU
12,926
49,026
80.4
30
5
30
66
,150
,950
,171
,271
108.7
47,
83,
417
517
137
.0
104
-------
Table 7.8
SRC PROCESS
1000 MW NEW POWER PLANT
4000 MW SRC PLANT
80% LF
243.8 x 10
12
BTU/YR
Total Plant Investment
Section Description
1 Coal Preparation
2 Preheater, Dissolvers
3 Ash Filtration, Drying, Disposal
4 Solvent, Light Oil, Cresylic Acid
Recovery
5 Product Solidification, Handling,
Storage
6 Hydrogen Plant
7 Sulfur Removal and Recovery
8 Steam and Power Generation
9 Other Offsites
TPI
Credit
TPI Adjusted
Coal Price
$5/T S10/T
TCR: M$ 513,100 539,700
TCR Adjusted: M$ 367,900 394,500
Raw Materials and Utilities
Cost: M$
24,400
97,700
36,700
73,300
24,400
24,400
24,400
24,400
73,300
403,000
120,000
283,000
$15/T
566,200
421,000
Costs Less Credits, M$/YR
ACOAL
ASULFUR: $5/LT
ACRESYLIC ACID: $100/T
ACHEMICALS
ANR: M$/YR
Total Annual Production
0.225 TPI
2.1 (TO) (CO) (1 + F)
1.04 ANR
TAG: M$/YR
: C/MM BTU
66,326
49,718
Cost
51,707
130,110
53.4
132,652
(1,464)
(16,580)
1,436
116,044
63,675
14,728
120,686
199,089
81.7
198,978
182,370
189,665
268,068
110.0
105
-------
Table 7.9
SRC PROCESS
60% LF
500 MW EXISTING POWER PLANT 24.97
500 MW SRC PLANT
Total Plant Investment
Section Description
1 Coal Preparation
2 Preheater, Dissolvers
3 Ash Filtration, Drying, Disposal
4 Solvent, Light Oil, Cresylic Acid
Recovery
5 Product Solidification, Handling,
Storage
6 Hydrogen Plant
7 Sulfur Removal and Recovery
8 Steam and Power Generation
9 Other Offsites
TPI
Credit
TPI Adjusted
Coal Price
$5/T $10/T
TCR: M$ 114,000 116,700
TCR Adjusted: M$ 114,000 116,700
Raw Materials and Utilities
Costs Less Credits, M$/YR
ACOAL 6,788 13,576
ASULFUR: $5/LT (150)
ACRESYLIC ACID: $100/T (1,697)
ACHEMICALS 147
ANR: M$/YR 5,088 11,876
Total Annual Production Costs
0.225 TPI 20,588
2.1 (TO) (CO) (1 + F) 3,347
1.04 ANR 5,292 12,351
TAG: M$/YR 29,227 36,286
C/MM BTU 117.0 145.3
X 1012 BTU/YR
Cost: M$
5,600
22,200
8,300
16,600
5,600
5,500
5,600
5,500
16,600
91,500
91,500
$15/T
119,500
119,500
20,364
18,664
19,411
43,346
173.6
106
-------
Table 7.10
SRC PROCESS
60% LF
500 MW EXISTING POWER PLANT 99.86
2000 MW SRC PLANT
Total Plant Investment
Section Description
1 Coal Preparation
2 Preheater, Dissolvers
3 Ash Filtration, Drying, Disposal
4 Solvent, Light Oil, Cresylic Acid
Recovery
5 Product Solidification, Handling,
Storage
6 Hydrogen Plant
7 Sulfur Removal and Recovery
8 Steam and Power Generation
9 Other Offsites
TPI
Credit
TPI Adjusted
Coal Price
$5/T S10/T
TCR: M$ 283,500 294,400
TCR Adjusted: M$ 283,500 294,400
Raw Materials and Utilities
Costs Less Credits, M$/YR
ACOAL 27,166 54,332
ASULFUR: $5/LT (599)
ACRESYLIC ACID: $100/T (6,792)
ACHEMICALS 588
ANR: M$/YR 20,363 47,529
Total Annual Production Cost
0.225 TPI 50,625
2.1 (TO) (CO) (1 + F) 8,256
1.04 ANR 21,177 49,430
TAG: M$/YR 80,058 108,311
: C/MM BTU 80.2 108.5
x 10 12 BTU/YR
Cost: M$
13,600
54,600
20,600
40,900
13,600
13,600
13,600
13,600
40,900
225,000
225,000
$15/T
305,300
305,300
81,498
74,695
77,683
136,564
136.8
107
-------
Table 7.11
LOW BTU GAS PROCESS
500 MW EXISTING POWER PLANT
(60% LF - 24.97 X 1012 BTU/YR.)
Total Plant Investment
Section Description
Cost: M$
1 Coal Preparation % Handling 2,450
2 Fines Agglomeration 5,794
3 Coal Gasification 16,710
4 Glaus Plant 2,663
5 H2S Removal Unit 2,263
6 Heater, Air Compressor and Turbine 4,723
7 Other Off sites 15,611
TPI
No Credit
$5/T
TCR: M$ 63,211
Raw Materials and Utilities
Costs Less Credits, M$/YR
ACOAL 8,252
ASULFUR: $5/LT
UTILITIES
ANR: M$/YR 9,768
Total Annual Production Cost
0.217 TPI
2.1 (TO) (CO) (1 + F)
1.04 ANR 10,159
TAG: M$/YR 27,005
: C/MM BTU 108.1
50,214
Coal Price
$10/T $15/T
66,512 69,813
16,504 24,756
(232)
1,748
18,020 26,272
10,896
5,950
18,741 27,323
35,587 44,169
142.5 176.9
108
-------
Table 7.12
LOW BTU GAS PROCESS
1000 MW NEW POWER PLANT
(80% LF - 60.97 x 1012 BTU/YR.)
Total Plant Investment
Section Description
1 Coal Preparation & Handling
2 Fines Agglomeration
3 Coal Gasification
4 Glaus Plant
5 H2S Removal Unit
6 Heater, Air Compressor and Turbine
7 Other Offsites
TPI
Credit
TPI Adjusted
Coal Price
$5/T $10/T
TCR: M$ 106,017 114,076
TCR Adjusted 11$ 58,817 66,876
Raw Materials and Utilities
Costs Less Credits, M$/YR
ACOAL: M$ 20,148 40,296
ASULFUR: $5/LT (566)
UTILITIES 4,271
Cost: M$
3,52.3
7,381
34,278
3,824
3,254
7,473
22,446
82, 179
40,000
42,006
$15/T
122,135
74,935
60,444
ANR: M$/YR 23,853
Total Annual Production Cost
44,001
64 ,149
0.217 TPI
2.1 (TO) (CO) (1 + F)
1.04 ANR
TAG: M$/YR
: C/MM BTU
24,807
45,079
73.9
9,115
11,157
45,761
66,033
108.3
66,715
86,987
142.7
109
-------
1.00
Figure 7.1
WET LIMESTONE OPERATING COSTS
EXISTING 500 MW PLANT
0.6 LOAD FACTOR
0.50
Scrubbing Cost
1.00
0.50
WET LIMESTONE OPERATING COSTS
NEW 1000 MW PLANT
0.8 LOAD FACTOR
PCrubbing Cosi
I
I
10
COAL COST $/TON
110
15
-------
Figure 7.2
1.00
0.50
WELLZIAN-LORD/ALLIF.D OPERATING COSTS
EXISTING 500 MW PLANT
0.6 LOAD FACTOR
Scrubbing Co-it
U
1.00
0.50
WELLMAN-LORD/ALLIED OPERATING COSTS
NEW 1000 :iW PLANT
'|j. 8 LOAD FACTOR
Scrubbing Cost
i i i i
i i i
10
COAL COST $/TON
111
15
-------
Figure 7.3
1.00 -
0.50
O
<
EH
1.00
0.50
CAT-OX OPERATING COSTS
EXISTING 500 MW PLANT
0 . 6 LOAD FACTOR
Scrubbing Cost
CAT-OX OPERATING COSTS
NEW 1000 MW PLANT
0.8 LOAD FACTOR
Co "j h
1111
j i i i
\ I
10
COAL COST $/TOM
112
15
-------
0.50
Figure 7.4
STACK GAS SCRUBBING
TOTAL PRODUCTION COSTS
VS
LOAD FACTOR
COAL @ $10/TON
1.50
I
1.00
1 CAT-OX EXISTING 500 MW
2 CAT-OX NEW 1000 MW
3 WELLJIAN/ALLIED
EXISTING 500 MW
4 WET LIMESTONE
EXISTING 500 MW
5 WELL: IAN/ALL i ED
NEW 1000 MW
6 WET LIMESTONE
NEW 1000 MW
30
40
50 60
LOAD FACTOR
113
70
80
,•90
-------
7.5
SRC CO.VV VS COAL COST
1.50
1.00
0.50
J L
J L
J I I I 1 1 1 L
COAL
114
-------
7 . C
2.00
1.50
I
vt-
1.00
0.50
SRC COST Vr LOAD FACTOR
COAL 5 $1.1/T
T •> '\ o • T'' ••
J- ., -J V.4 -'.V
500 I-1W - 2000 MW System
1000 nw •• -iODO MW Gvsten
0.3 0.4 0.5 0.6 0.7
LOAD FACTOR
115
0.8
0.9
-------
0.5 -
Figure 7.7 .
COST OF LOW ETU GAS VS LOAD FACTOR
(COAL at 10 $/T)
J I
I III I I
J I
0.3 0.4 0.5 0.6 ,0.7
LOAD FACTOR
116
0.8
-------
Fimirr*. 7. S
2.0
COST OF LOW BTU HAS VS COAL COST
1.5
EH
W
I
1.0
0.5
J \ \ \ 1 \ \ I I I
I I I I
10
COAL COST: $/T
117
15
-------
2.00
Figure 7.0
co:;rARi:;o:i OF PROCESSES
EXISTING 500 MV7
60% LF
1.50
CO
1.00
0.50
I I I I I I I
j I
10
COAL COST: S/T
118
15
-------
Figure 7.10
2.00
COMPARISON OF PROCESSES
NEW 1000 MW
80% LF
1.50
U 1.00
0.50
l i
l i
i i
10
COAL COST: $/T
119
15
-------
8. REFERENCES
1. Battelle Columbus, Liquefaction and Chemical Refining
of Coal, July 1974.
2. Pittsburg and Midway Coal Mining Company, Economic
Evaluation of a Process to Produce Ashless, Low-Sulfur
Fuel from Coal, Prepared for Office of Coal Research,
U.S. Department of the Interior, Interior Report No. 1,
1969.
3. The M. W. Kellogg Company, Evaluation of R&D Investment
Alternatives for SO Air Pollution Control Processes,
1 ' ' '" " —' '— - j£ ~ -•-- ~~ L - ~~~~— ~ " •- —
September 1974.
4. Bechtel Corporation, Fuel vs. Stack Gas Desulfurization,
Paper 18a, 76th National Meeting, AIChE, March 7-14,
1974.
5. Spencer Chemical Division, Gulf Oil Corporation, Solvent
Processing of Coal to Produce a Deashed Product, Prepared
for Office of Coal Research, U.S. Department of the Interior
Research and Developemnt Report No. 9.
6. Chemical Engineering - July 22, 1974 "Coal Conversion
Technology".
7. Chemical Engineering Progress - December 1973, "Low
B.t.u. Gas for Power Plants".
8. A leading Research Institute - confidential
9. Personal communication - Ben field Corporation
10. Personal communication - vendor
120
-------
11. The M.W. Kellogg Company, "SO Control Technology for
^C
Combustion Sources", June 1974.
12. Tennessee Valley Authority, Detailed Cost Estimates for
Advanced Effluent Desulfurization Processes, Prepared
for Control Systems Laboratory, National Environmental
Research Center, March 29, 1974.
13. Davy Powergas, Continuing Progress for Wellman-Lord
SO., Process, Paper for Flue Gas Desulfurization Symposium,
November 4-7, 1974.
14. Tennessee Valley Authority, TVA-EPA Study of the Marketability
of Abatement Sulfur Products, Paper for Flue Gas De-
sulfurization Symposium, November, 1974.
15. Tennessee Valley Authority, Flue Gas Desulfurization By-
Product Disposal/Utilization Review and Status, Paper
for Flue Gas Desulfurization Symposium, November, 1974.
16. Northern Indiana Public Service Company, The D.H.
Mitchell Station Wellman-Lord SO^ Emission Control Facility,
Paper for Flue Gas Desulfurization Symposium, November,
1974.
17. Battelle Columbus, Lime/Limestone Sludge Disposal-Trends
in the Utility Industry, Paper for FGD Symposium,
November, 1974.
18. Arizona. Public Service Company, Operational Status and
Performance of the Arizona Public Service Co. Flue Gas
Desulfurization System at the Cholla Station, Paper for
FGD Symposium, November, 1974.
19. Chuo University, Status of Flue Gas Desulfurization
Technology in Japan, Paper for FGD Symposium, November,
1974.
121
-------
20. PEDCo Environmental Specialists, Status of Flue Gas
Desulfurization in the United States, Paper for FGD
Symposium, November, 1974.
21. The Aerospace Corporation, Disposal of By-Products From
Non-Regenerable Flue Gas Desulfurization Systems,
Paper for FGD Symposium, November, 1974.
22. Dequesne Light Company, Duquesne Light Company Phillips
Power Station Lime Scrubbing Facility, Paper for FGD
Symposium, November, 1974.
23. Millon R. Beyshock, "Coping With S02", Chemical Engineer-
ing, October 21, 1974"!
24. John C. Davis, "S02 Absorbed from Tail Gas With Sodium
Sulfite", Chemical Engineering, November 29,1974.
25. Monsanto Enviro-Chem Systems Inc., "Four SO2 Removal
System", Chemical Engineering Progress, August, 1974.
26. Commonwealth Edison Co., "Operation of a Limestone Wet
Scrubber", Chemical Engineering Progress, June, 1973.
27. Illinois Power Company, "The Cat-Ox Process at Illinois
Power", Chemical Engineering Progress, June, 1974.
28. National Coal Association, Steam-Electric Plant Factors
January, 1974.
29. The M. W. Kellogg Co., An Evaluation of the Controllability
of Power Plants Having a Significant Impact on Air Quality
Standards, August, 1974.
30. Coal News, No. 4241, November 27, 1974.
122
-------
31. Catalytic, Inc.,"A Process Cost Estimate of Limestone
Slurry Scrubbing of Flue Gas", Parts I & II, January, 1973,
32. "The Supply - Technical Advisory Task Force - Synthetic
Gas From Coal", Final Report, April, 1973.
123
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9. APPENDIX
(Excerpted from reference 3)
124
-------
4. THE GENERAL MODEL
4.1 The General Process Model
The plants in the models have, as far as possible, been made
self-contained apart from the intake of basic raw feed materials;
i.e., the plant should not be buying natural gas or electricity.
If possible, it should not even be buying desulfurized fuel oil
since supply cannot be assumed. There are obviously exceptions
if the plant is an addition to a larger conventional plant; e.g.,
with stack gas scrubbing for a power plant it would be illogical
not to assume a supply of power. In general, a large plant having
a coal feed will generate its own power, steam and heat requirements
by burning coal and scrubbing the stack gases.
It was not a primary concern to provide special chemical by-products
from any process, but to avoid additional treatment facilities
for impure materials by routing these side streams back to the
plant fuel supply where possible. This approach simplifies the
models and minimizes the effect of credits for special chemical
by-products on the plant costs.
The cost of equipment and raw material, utility and waste product
quantities have all been related to one or more basic process
parameters; e.g., in the stack gas scrubbing models, the basic
process parameters are flue gas flow rate and sulfur content of
the fuel. For a plant producing high quality fuel, the basic
process parameters are product flow rate and properties of the
raw feed materials.
Where possible, equipment costs were related directly to the basic
process parameters. However, the format of some of the estimates
used to develop the models prevented this. In these cases, the
available cost information was carefully examined relative to the
General Cost Model to determine exactly what the costs included.
125
-------
The equipment costs were extracted from these estimates by using
the relationships between construction labor costs, other material
costs and equipment costs given in the General Cost Model.
Each plant design was examined to fix maximum train sizes for
each group of equipment. It has been assumed that N trains cost
N times the cost of one train. Where a plant is largely made up
of several trains, size variations were only taken in increments
of their size.
For the smaller plants, it was possible to examine the cost of
every item of equipment and assign an exponent of size to give
cost variations. However, for the larger plants, whole sections
have been grouped together. The following is given as a general
guide to the exponents for equipment cost vs. size ( 9,14,21) :
Increasing number of trains of equipment 1.0
Blowers 0.9
Solids grinding equipment 0.8
Steam generation equipment 0.8
Process furnaces and reformers 0.7
Compressors 0.7
Power generation equipment 0.7
Solids handling equipment 0.6
Offsites 0.6
Other process units 0.6
4.2 The General Cost Model
4.2.1 Bases For Costs
All costs in the models are those in existence at the end
of 1973. To update prior cost information used in the con-
struction of the models, an annual inflation multiplication
126
-------
factor of 1.05 has been used. All costs other than unit
costs for labor, raw materials, etc., are shown in thousands
of dollars (M$).
The direct field construction labor cost, L, and the direct
cost of operating labor, CO, both refer to a Gulf Coast
(Houston) location. For any other location, they are adjusted
through the use of a location factor, F, which is explained
in section 4.3.
Whenever possible in the development of the cost models dis-
cussed in this report, major equipment costs, E, have been
related to plant size variations. The reference values of E
have been taken from actual plant cost estimates when these
were available. Sometimes, however, the cost estimates were
not available in such a detailed breakdown. In such cases,
the relationships developed in the General Cost Model were
used to analyze the cost data. The relationships in the
General Cost Model were developed based on procedures reported
and recommended in the literature ( 9,13) and on Kellogg's
general experience.
4.2.2 Capital Cost Model
Major equipment costs, E, represent the cost of major
equipment delivered to the site, but not located, tied-in
to piping, instruments, etc., or commissioned. It includes
material costs only. Major equipment is defined to include
furnaces, heat exchangers, converters, reactors, towers,
drums and tanks, pumps, compressors, transportation and
conveying equipment, special equipment (filters, centrifuges,
dryers, agitators, grinding equipment, cyclones, etc.), and
major gas ductwork.
Other material costs, M, represent the cost of piping,
electrical, process instrumentation, paint, insulation,
foundations, concrete structures, and structural steel
127
-------
for equipment support. It does not include such items as
site preparation, steel frame structures, process buildings,
cafeterias, control rooms, shops, offices, etc.
M has been taken as a fixed fraction of E. Whenever possible,
this fraction has been determined from an estimate covering
the particular plant under consideration. This fraction is
often different for each section of the plant. if particular
details were not available, the following relationships have
been assumed ( 9):
Solids handling plant: M = 0.40E
Chemical process plant: M = 0.80E
Direct field construction labor costs, L, are based on Gulf
Coast rates and productivities. Again, L has been taken
as a fixed fraction of E. Wheneve.r possible, it has been
derived from an estimate covering the particular plant under
consideration. This fraction is often different for each
section of the plant. If_ particular details were not available,
the following relationships have been assumed (9 ):
Solids handling plant: L = 0.40E
Chemical process plant: L = 0.60E
Indirect costs associated with field labor have been assumed
as follows:
Fringe benefits and payroll burden = 0.12 L
Field administration, supervision
temporary facilities = 0.17 L
Construction equipment and tools = 0.14 L
Total field labor indirect costs = 0.43 L
128
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Home office engineering includes home office construction,
engineering and design, procurement, client services,
accounting, cost engineering, travel and living expenses,
reproduction and communication. This could range from under
10% to almost 20% of the major equipment and other material
costs. In the model, this has been assumed to be 15% of the
total direct material cost (E + M) .
The bare cost of the plant, BARC, is defined as the sum of
equipment costs, other material costs, construction labor
and labor indirects, and home office engineering. For a
Gulf Coast location, it is given by:
BARC = E+M + L + 0.43L + 0.15 (E + M)
= 1.15 (E + M) + 1.43 L
For any other location, it is given by:
BARC = 1.15 (E + M) + 1.43 L-F
where F is the location factor (see section 4.3).
Taxes and insurance can be 1-4% of the bare cost. In the
model, they have been assumed to be 2%. Contractor's
overheads and profit could depend on several factors, but
are generally in the range of 6-13% of the bare cost. A
value of 10% was chosen for the model.
A contingency has been included in the model and is expressed
as a fraction of the bare cost. It represents the degree
of uncertainty in the process design and the cost estimate.
The contingency, CONTIN, could range from zero for a well-
established process to 0.20 or more for a process still under
development.
129
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The total plant investment, TPI, is defined as the sum of
the bare cost (including contingency), taxes and'insurance,
and contractor's overheads and profit. It is therefore
given by:
TPI = (1.0 + CONTIN) BARC +0.02 (1.0 + CONTIN) BARC
+ 0.10 (1.0 + CONTIN) BARC
= 1.12 (1.0 + CONTIN) BARC
In order to obtain the total capital required for construction
of a particular plant, some additional costs should be added
to the total plant investment. These costs are:
1. Start-up costs
2. Working capital
3. Interest during construction
Start-up costs, STC, have been assumed to be 20% of the total
net annual operating cost, AOC (see section 4.2.3 for
explanation of AOC). Thus:
STC = 0.20 AOC
Working capital, WKC, is required for raw materials inventory,
plant materials and supplies, etc. For simplification, it
has also been assumed to be 20% of the total net annual
operating cost, AOC.
Thus:
WKC =0.20 AOC
Interest during construction, IDC, obviously increases with
the length of the construction period which, to some extent,
is a function of the size of the plant. The construction
of plants the size of the stack gas scrubbing units is now
taking about 2-3 years and projects of the magnitude and
130
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complexity of a substitute natural gas plant or a power
station are taking 4-5 years. Two different values for the
interest during construction have therefore been assumed.
The first is intended to be used for stack gas scrubbing
units fitted to existing power plants or for constructions
well under $100 million:
IDC =0.12 TPI*
The second is for the larger, more complex plants such as
substitute natural gas, solvent refined coal, and power plants
IDC =0.18 TPI*
The total capital required, TCR, is equal to the sum of the
total plant investment, start-up costs, working capital, and
interest during construction.
Thus:
TCR = TPI + STC + WKC + IDC
For stack gas scrubbing units, this can be reduced to:
TCR = TPI +0.20 AOC +0.20 AOC +0.12 TPI
= 1.12 TPI + 0.40 AOC
For the larger plants, this can be reduced to:
TCR = TPI +0.20 AOC + 0.20 AOC +0.18 TPI
= 1.18 TPI + 0.40 AOC
From section 4.2.3, AOC is calculated from:
AOC = 0.078 TPI + 2.0 TO'CO (1.0 + F) + ANR
*See Appendix A for derivation of equation
131
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where TO = total number of shift operators
ANR = Annual cost of raw materials, utilities, and
waste disposal, less by-product credits.
Therefore, for stack gas scrubbing units, the equation for the
total capital required becomes:
TCR = 1.12 TPI + 0.40 [0.078 TPI + 2.0 TO'CO (1.0 + F) + ANR]
= 1.12 TPI + 0.03 TPI + 0.8 TO-CO (1.0 + F) + 0.40 ANR
= 1.15 TPI + 0.8 TO. CO (1.0 + F) + 0.40 ANR
For the larger plants, the equation for the total capital
required becomes:
TCR = 1.18 TPI + 0.40 [0.078TPI + 2.0 TO-CO (1.0 + F) + ANR]
= 1.18 TPI + 0.03 TPI + 0.8 TO-CO (1.0 + F) + 0.4 ANR
= 1.21 TPI + 0.8 TO-CO (1.0 + F) + 0.4 ANR
The buildup of costs to determine the total capital required is
illustrated in Figure 4.1.
4.2.3 Operating Cost Model
The total net annual operating cost, AOC, is the total cost of
operating the plant less the credits from the sale of by-products,
It does not include return of capital, payment of interest on
capital, income tax on equity returns or depreciation. The total
net annual operating cost is made up of the following items:
1. Annual cost of raw materials, utilities, and waste
disposal, less by-product credits
2. Annual cost of operating labor and supervision
3. Annual cost of maintenance labor and supervision
4. Annual cost of plant supplies and replacements
5. Annual cost of administration and overheads
6. Annual cost of local taxes and insurance
132
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The annual cost of raw materials, utilities, and waste disposal,
less by-product credits, ANR, is clearly a function of the
particular process under consideration. It is given by
different relationships for each model.
The total number of operators employed on all shifts, TO,
is different for each process and is either given as an
equation or number for each particular model. It has been
assumed that each operator works 40 hours per week for 50
weeks per year (2000 hours per year) . If CO is the hourly
rate for an operator (Gulf Coast basis) , then the annual
cost of operating labor is given by:
Operating labor (Gulf Coast) =
= 2 TO. CO M$/yr
The annual cost of operating labor for any other location
has been assumed to be:
Operating labor = 2 TO -CO (0.5 + 0.5 F)
Supervision was assumed to be 15% of operating labor. Thus,
the total cost of operating labor and supervision, AOL, is
given by:
AOL = 1.15 [2 TO -CO (0.5 + 0.5 F) ]
= 2.3 TO -CO (0.5 + 0.5 F)
The annual cost of maintenance labor has been assumed to be
1.5% of the total plant investment. Maintenance supervision
is 15% of maintenance labor. Therefore, the total annual
cost of maintenance labor and supervision, AML , is:
133
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AML = 1.15 (0.015 TPI)
= 0.018 TPI (rounded up)
Plant supplies and replacements include charts, cleaning
supplies, miscellaneous chemicals, lubricants, paint, and
replacement parts such as gaskets, seals, valves, insulation,
welding materials, packing, balls (grinding), vessel lining
materials, etc. The annual cost of plant supplies and re-
placements, APS, has been assumed to be 2% of the total plant
investment. Thus:
APS =0.02 TPI
Administration and overheads include salaries and wages
for administrators, secretaries, typists, etc., office
supplies and equipment, medical and safety services, trans-
portation and communications, lighting, janitorial services,
plant protection, payroll overheads, employee benefits, etc.
The annual cost of administration and overheads, AOH, has
been assumed to be 70% of the annual operator, maintenance
labor, and total supervision costs. Thus:
AOH = 0.70 [2.3 TO-CO (0.5 + 0.5F) + 0.018 TPI]
=1.7 TO-CO (0.5 + 0.5F) + 0.013 TPI (rounded up)
Local taxes and insurance include property taxes, fire and
liability insurance, special hazards insurance, business
interruption insurance, etc. The annual local taxes and
insurance, ATI, have been assumed to be 2.7% of the total
plant investment. Thus:
ATI = 0.027 TPI
The total net annual operating cost, AOC, is therefore given
by:
134
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AOC = ANR + AOL + AML + APS + AOH + ATI
= ANR + 2.3 TO.CO (0.5 + 0.5F) + 0.018 TPI
+ 0.02 TPI + 1.7 TO.CO (0.5 + 0.5F) + 0.013 TPI
+ 0.027 TPI
= 0.078 TPI + 4.0 TO-CO (0.5 + 0.5F) + ANR
= 0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR
In order to obtain the total annual production cost, the
following items must be added to the total net annual
operating cost:
1. depreciation
2. average yearly interest on borrowed capital
3. average yearly net return on equity
4. average yearly income tax
The straight-line method was used to determine depreciation,
based on the total capital required less the working capital
For stack gas scrubbing units (15 year life), the annual
depreciation, ACR, is:
ACR = 1/15 (TCR-WKC)
= 0.067 (TCR-0.20 AOC)
For substitute natural gas and solvent refined coal plants
(20 year life), it is given by:
ACR = 0.050 (TCR - 0.20 AOC)
For power plants, both conventional and combined cycle (28
year"life), it is:
ACR = 0.036 (TCR - 0.20 AOC)
135
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Interest on debt and return on equity are calculated following
a procedure recommended in the literature (13) and illustrated
in Appendix A. The procedure assumes a fixed debt-to-equity
ratio, an interest rate on debt, and the required net (after
tax) rate of return on equity. Interest on debt and return
on equity are calculated over the plant life, and the yearly
average is expressed as a percentage of the total capital
required (TCR). Assuming a 75%/25% debt-to-equity ratio,
a 9% per year interest rate, and a 15% per year net rate of
return on equity, the annual interest and return, AIC, is
given by:
AIC = 0.054 TCR
Federal income tax is the average yearly income tax over the
plant life, expressed as a percentage of the total capital
required. The calculation of income tax is illustrated in
Appendix A. Based on the assumptions listed in the preceding
paragraph and an assumed tax rate of 48%, the annual federal
income tax, AFT, is given by :
AFT = 0.018 TCR
The total annual production cost, TAG, is given by:
TAG = AOC + ACR + AIC + AFT
For stack gas scrubbing plants, this can be reduced as
follows:
TAG = AOC + 0.067 (TCR -0.20 AOC) + 0.054 TCR + 0.018 TCR
= AOC + 0.067 TCR - .013 AOC + 0.054 TCR + 0.018 TCR
= 0.139 TCR +0.99 AOC
136
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Substituting for TCR and AOC from preceeding equations:
TAG = 0.139 [1.15 TPI + 0.8 TO-CO (1.0 + F) + 0.40 ANR]
+ 0.99 [0.078 TPI + 2.0 TO-CO (1.0 + F) + ANR]
= 0.237 TPI + 2.1 TO-CO (1.0 + F) + 1.04 ANR
Making the appropriate substitutions, the total annual
production cost for substitute natural gas and solvent
refined coal plants is:
TAG = 0.225 TPI + 2.1 TO-CO (1.0 + F) + 1.04 ANR
For power plants, this equation becomes:
TAG = 0.208 TPI + 2.1 TO-CO (1.0 + F) + 1.04 ANR
The buildup of costs to determine the total annual production
cost is illustrated in Figure 4.2.
4.3 Effect of Location on Plant Cost
The cost models have been developed using U.S. Gulf Coast 1973
costs as a basis. In order to predict plant costs for other
locations, factors have been developed which relate construction
labor costs at various locations to Gulf Coast labor costs. By
multiplying the field labor construction portion of plant cost
by this location factor, the total plant cost is adjusted to
the desired location.
Labor rates for different crafts were obtained from the literature
(10) and escalated to the end of 1973. Using an average craft
mix obtained from in-house information (12), an average construction
labor rate was obtained for each location. Productivity factors
for the various locations, also obtained from in-house data, were
used to create the rate for equal work output. These rates were
137
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then normalized, using Houston (Gulf Coast) as a basis, to yield
relative field labor construction costs.
Table 4.1 lists the relative labor costs determined for twenty
cities. They range from 1.0 for Houston to 2.08 for New York.
Costs are generally highest in the Northeastern quarter of the
country and lowest in the South. These factors are shown on a
map of the U.S. in Figure 4.3.
Table 4.2 lists average location factors for each state. Allowance
has been made in the factor for the importation of temporary labor
to the more remote states. The factors are shown on a map of the
U.S. in Figure 4.4.
Figure 4.5 gives the relationship between major equipment
cost, E, total plant investment, TPI, and location factor, F,
when the contingency, CONTIN, is zero.
138
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4.4 Nomenclature
M
BARC
Major equipment costs
Other material costs
Direct field labor costs (Gulf Coast)
Bare cost
M$
M$
M$
M$
CONTIN
TPI
STC
WKC
IDC
TCR
ANR
AOL
AML
APS
Location factor
Contingency
Total plant investment
Start-up costs
Working capital
Interest during construction
Total capital required
Annual cost of operating labor and
supervision
Annual cost of maintenance labor and
supervision
Annual cost of plant supplies and re-
placements
M$
M$
M$
M$
M$
Annual cost of raw materials, utilities,
and waste disposal, less by-product
credits M$/year
M$/year
M$/year
M$/year
139
-------
AOH
ATI
AOC
TO
CO
ACR
AIC
AFT
TAG
COHP
TAXI
FLIC
ENGR
Annual cost of administration and
overheads
M$/year
Annual cost of local taxes and insurance M$/year
Total net annual operating cost
Total number of shift operators
Hourly rate for shift operators (Gulf
Coast)
Annual depreciation
Annual interest on debt and return on
capital
Annual federal income taxes
Total annual production cost
Contractor overhead & profits
Taxes and insurance
Field Labor Indirect Cost
Engineering Fees
M$/year
$/hour
M$/year
M$/year
M$/year
M$/year
M$/year
M$/year
M$/year
M$/year
140
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TABLE 4 .1
LOCATION FACTORS FOR MAJOR U.S. CITIES
Location
Atlanta
Baltimore
Birmingham
Boston
Chicago
Cincinnati
Cleveland
Dallas
Denver
Detroit
Kansas City
Los Angeles
Minneapolis
New Orleans
New York
Philadelphia
Pittsburgh
St. Louis
San Francisco
Seattle
Houston
Location Factor F
1.10
1.41
1.16
1.23
52
,53
1.86
1.07
1.03
1.73
1.37
1.44
1.54
1.16
2.08
82
52
2.01
1.45
1.21
1.00
1
1
141
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TABLE 4.2
AVERAGE LOCATION FACTORS FOR EACH STATE
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
D.C.
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
N. Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
S. Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
W. Virginia
Wisconsin
Wyoming
1.2
2.1
1.3
1.2
1.5
1.2
1.7
1.4
1.4
1.2
1.1
2.0
1.3
1.7
1.6
1.5
1.4
1.5
1.1
1.2
1.4
1.3
1.7
1.5
1.1
1.6
1.3
1.4
1.4
1.2
2.1
1.3
2.1
1.2
1.3
1.6
1.4
1.2
1.6
1.3
1.1
1.3
1.2
1.1
1.2
1.2
1.4
1.2
1.5
1.5
1.3
142
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FIGURE 4.1
RELATIONSHIP BETWEEN CAPITAL COST FACTORS IN THE GENERAL COST MODEL
MAJOR EQUIPMENT COSTS (E)
OTHER MATERIAL COSTS IM)
DIRECT FIELD CONSTRUCTION
LABOR COSTS (L)
OJ
FIELD LABOR INDIRECT COSTS
[FLIC - 0.43 L}
ENGINEERING FEES
IENGR * 0.15 IE +• MII
FRINGE BENEFITS &
PAYROLL BURDEN
FIELD ADMINISTRATION,
SUPERVISION & TEMPORARY
FACILITIES
CONSTRUCTION EQUIPMENT
& TOOLS
DIRECT PLANT
CONSTRUCTION COSTS
INDIRECT COSTS
OF CONSTRUCTION
TAX & INSURANCE
[TAX! = 0.02 8ARC!
BARC PLANT COST
[BARC =-• 1.15
(E 1- M! -t '. 43 Li
1
CONTRACTOR
OVERHEADS & PROFITS
JCOHP - C.10 BARC!
2
COST OF SITE
WORKING CAPITAL
IWKC = 0.20 AOC;
CONTINGENCY
(CONTIN)
TOTAL PLANT
INVESTMENT (TPI)
STARTUP COSTS
[STAR = 0.20 AOC]
INTEREST ON 4
CONSTRUCTION
CAPITAL
- -.
TOTAL CAPITAL REQUIREMENT
(TCR)
1. SEE DEFINITION ON PAGE 58.
2. COST WOULD NORMALLY BE INCLUDED ONLY IF PURCHASE IS REQUIRED. COST IS USUALLY SMALL AND HAS NOT BEEN INCLUDED IN MODEL.
3. SEE NOTE 3 OF FIGURE 4.2.
4. SEE FIGURE 4.2.
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FIGURE 4.2
RELATIONSHIP BETWEEN PRODUCTION COST FACTORS IN THE GENERAL COST MODEL
RAW MATERIALS
UTILITIES
CATALYSTS & CHEMICALS
WASTE DISPOSAL
BY-PRODUCT CREDIT
COST OF MATERIALS LESS
BY-PRODUCT CREDITS (ANR)
OPERATING LABOR &
SUPERVISION (AOL)
MAINTENANCE LABOR &
MATERIALS IAML = 0.018 TPI]
PLANT SUPPLIES &
REPLACEMENTS [APS = 0.02 TPI)
ADMINISTRATIVE & PLANT
OVERHEADS
[AOH = 0.70 (AOL + AMD]
DIRECT & INDIRECT COST
DEPRECIATION
[ACR = (TCR-WKQ/YEARS]
COST OF MONEY
[AIC = 0.054 TCR]
FEDERAL INCOME TAX
[AFT = 0.018 TCR]
LOCAL TAX & INSURANCE
[ATI = 0.027 TPIJ
FIXED COST
TOTAL ANNUAL PRODUCTION COST
[TAC]
1. AVERAGE OVER THE PLANT LIFE, ASSUMING 75% DEBT AT 9% INTEREST RATE PER YEAR. AND 25% EQUITY GIVING A NET RETURN OF
2. AVERAGE OVER THE PLANT LIFE, ASSUMING 48% FEDERAL INCOME TAX RATE.
3. ANNUAL OPERATING COST IS: AOC = ANR + AOL + AML + APS + AOH + ATI.
15%.
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FIGURE 4.3
LOCATION FACTORS FOR SELECTED CITIES
NEW YORK
^°?QA PITTSBURGH •/ ' PHILADELPHIA
,,~ 139\m , Co ^-TV.^V , 82
BALTIOMORE
1.41
••ilSSO'JRi
KANSAS
\ _ CITY
1.37
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FIGURE 4.4
AVERAGE LOCATION FACTORS BY STATE
1.3
VA'RKA'NSAS '.".']$.• •::'.it^ttSt^\^J^^^
-------
FIGURE 4.5
EFFECT OF LOCATION FACTOR ON TOTAL PLANT INVESTMENT
(CONTINGENCY = 0)
TPI = C • E
SCALE UP
FACTOR C
4.4 ._
4.2
4.0 - -
3.8 - -
3.6 - -
3.4 - -
3.2 - -
3.0 - -
2.8 --
2.6 --
2.4 - -
2.2 ._
2.0
CHEMICAL
PROCESSING
PLANT
SOLID
HANDLING
PLANT
1.0 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 2.0
LOCATION FACTOR F
147
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TECHNICAL REPORT DATA
(Please read Jazinictions on the reverse before completing)
1. REPORT NO.
EPA-450/3-75-047
4. TITLE AND SUBTITLE
Comparison of Flue Gas Desulfurization, Coal
Liquefaction, and Coal Gasification for Use
at Coal-Fired Power Plants
3. RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
The M. W. Kellogg Company
Research and Engineering Development
1300 Three Greenway Plaza East
Houston, Texas 77046
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
No. 68-02-1308
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
Final Report
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
The report presents a technical and economic comparison of the use of
flue gas desulfurization, coal liquefaction, and coal gasification as a means
of preventing SO? emissions at coal-fired power plants. The report assesses
the status of technology, process complexity, process flexibility, environmental
effects, installation difficulties, energy conversion efficiency, manpower
requirements, and economics of each approach to controlling S02 as it would be
applied to electric power plants. Three different flue gas desulfurization
systems were evaluated as well as one coal liquefaction and one coal gasification
processes. Two power plant cases are evaluated, an existing 500 MW plant operating
at 60 percent load factor and a new 1,000 MW plant operating at 80 percent load
factor.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Chemical Reaction
Gasification
Liquefaction
Desulfurization
Economic Analysis
Design
Sulfur Dioxide
Limestone
Coal
Sulfur
Calcium Oxides
Combustion Product:
Flue Gases
Air Pollution Control
Electric Power Plants
Boilers
13B
13. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
155
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
148
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