f/EPA
United States
Environmental Protection
Agency
Region V
Air & Radiation Branch
230 S. Dearborn Street
Chicago, Illinois 60604
EPA 905/2-83-001
June 1983
The Impact of
Coal Cleaning as a
Sulfur Reduction Strategy
In the Mid west
Do not WEED. This document
should be retained in the EPA
Region 5 Library Collection.
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THE IMPACT OF COAL CLEANING AS A
SULFUR REDUCTION STRATEGY IN THE MIDWEST
by
R.D. Doctor, J.L. Anderson,
D.B. Garvey, C.D. Livengood, and P.S. Farber
EPA 905/2-83-001
ANL/ECT-TM-7
ARGONNE NATIONAL LABORATORY
9700 South Cass Avenue
Argonne, Illinois 60439
IAG No. AD89F2A161
Project Officer: Rizalino Castanares
June 1983
U.S. Environmental Protection
Region 5, Library
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ACKNOWLEDGMENTS
The authors gratefully acknowledge the valuable contributions of the
EPA project officers, John Paskevicz and Rizalino Castanares, to the planning
and performance of the work presented in this report. Thanks are also
extended to B.C. O'Meara and L.S. Benson of Argonne for their preparation of
the printed text.
iii
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CONTENTS
ABSTRACT 1
1 INTRODUCTION 1
2 POWER PLANTS IN THE STUDY REGION 4
2.1 Screening Criteria 4
2.2 Characteristics of Plants 4
2.3 Characteristics of Fuel Supplies 4
2.3.1 Data Sources. 4
2.3.2 Coal Washability Data 6
2.3.3 Current Status of Coal Washing 6
3 DESULFURIZATION TECHNOLOGIES 7
3.1 Physical Coal Cleaning 7
3.1.1 PCC Commercial Technology 7
3.1.2 PCC Systems Overview 10
3.1.3 PCC Level 1 System 10
3.1.4 PCC Level 2 System 12
3.1.5 PCC Level 3 System 15
3.1.6 PCC Level 4 System 17
3.1.7 PCC Existing Capacity 21
3.1.8 PCC Equipment Service 21
3.1.9 PCC Costs 30
3.2 Flue-Gas Desulfurization 30
3.2.1 FGD Commercial Technology 30
3.2.2 FGD Existing Capacity 32
3.2.3 FGD Equipment Service 34
3.2.4 FGD Costs 34
4 COMPARISON OF PCC AND FGD 38
4.1 Emissions Corresponding to ROM Coal 38
4.2 Emissions under 1980 Conditions 39
4.3 Purchase Patterns for Coal in 1980 39
4.4 Emissions with Full, Cleaning 42
4.5 Comparison of PCC and Partial FGD Costs 52
4.6 Statewide Sulfur Reductions 53
5 REGULATORY AND INSTITUTIONAL CONSIDERATIONS 56
5.1 Background 56
5.2 Constraints on Voluntary Use of Cleaned Coal.... 57
5.3 Options for Increasing the Use of Cleaned Coal..... 58
5.3.1 Policies to Encourage the Use of Cleaned Coal 58
5.3.2 Policies to Require the Use of Cleaned Coal 60
v
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CONTENTS (Cont'd)
6 CONCLUSIONS 62
6.1 Data on Power Plants' Coal Usage 62
6.2 Emission Reductions Due to Coal Cleaning 63
6.3 Coal Cleaning vs. Partial FGD 63
6.4 Regulatory and Institutional Considerations 64
REFERENCES 67
APPENDIX A: COAL SUPPLY DATA 69
APPENDIX B: COMPUTER MODELS OF COAL PREPARATION 77
APPENDIX C: COMPARISON OF PCC AND PARTIAL FGD DATA 113
FIGURES
1 Block Diagram for Level 1 PCC 12
2 Block Diagram for Level 2 PCC 13
3 Block Diagram for Level 3 PCC 16
4 Block Diagram for Level 4 PCC 22
5 Physical Coal Cleaning Plants in Illinois, Indiana, and Ohio 23
6 Coal Sulfur Content vs. Equivalent Scrubbing Capacity, 1980 33
7 Summary and Comparison of Calculated FGD System Availabilities....... 35
8 Power-Plant S02 Emission Rates, 1980 40
9 Power-Plant S02 Emissions, 1980 41
10 Number of Power-Plant Coal Purchases 43
11 Coal Tonnages Corresponding to Power Plants' Purchases 44
12 Sulfur Dioxide Emissions Rates for Selected Utilities 45
13 Total Sulfur Dioxide Emissions for Illinois, Indiana, and Ohio 55
C.I Cumulative S02 Removal as a Function of Cost 116
VI
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TABLES
1 Power Plants with Coal-Firing Capacities of 500 MWe or Greater 5
2 Levels of Physical Coal Cleaning 7
3 Major Equipment for Level 1 PCC Plant 11
4 Major Equipment for Level 2 PCC Plant 14
5 Major Equipment for Level 3 PCC Plant 18
6 Major Equipment for Level 4 PCC Plant 20
7 Inventory of Illinois PCC Plants 24
8 Inventory of Indiana PCC Plants 27
9 Inventory of Ohio PCC Plants 28
10 Adjusted Capital and Annual Costs for Operational FGD Systems by
Process Type 37
11 Summary of PCC Sulfur Reductions, PCC Costs, and FGD Costs 54
A.I Available Preparation Equipment for Coal Mines in Illinois 72
A.2 Available Preparation Equipment for Coal Mines in Indiana 73
A.3 Available Preparation Equipment for Coal Mines in Kentucky 74
A.4 Available Preparation Equipment for Coal Mines in Ohio 75
A.5 Available Preparation Equipment for Coal Mines in Pennsylvania. 76
C.I Data on PCC and Partial FGD 115
VII
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THE IMPACT OF COAL CLEANING AS A
SULFUR REDUCTION STRATEGY IN THE MIDWEST
by
R.D. Doctor, J.L. Anderson,
D.B. Garvey, C.D. Livengood, and P.S. Farber
ABSTRACT
The potential for reduction of sulfur dioxide
emissions through coal cleaning is examined for electric-
utility power plants in the Ohio, Indiana, and Illinois
region. Twenty-four plants burning predominantly high-sulfur
coal and having capacities of 500 MWe or greater are identi-
fied, and the characteristics of their coal supplies are
analyzed. The sulfur reductions attainable via coal cleaning
for the various coals are estimated, and the costs are com-
pared with those for equivalent sulfur dioxide reductions
using flue-gas desulfurization. Coal cleaning is shown to be
a cost-effective option for approximately half of the plants
studied, although the total sulfur dioxide reduction poten-
tial is much less than for flue-gas desulfurization.
Regulatory and institutional considerations relevant
to mandatory coal cleaning requirements are evaluated, as are
options for encouraging greater voluntary use of cleaned
coal. Actions at the state level to promote greater use of
cleaned coal are found to be most likely.
1 INTRODUCTION
Reduction in sulfur dioxide (802) emissions from stationary sources has
long been one of the most prominent objectives of pollution-control legisla-
tion and regulation. Emphasis at the federal level has been on developing
requirements for new coal-fired power plants and industrial boilers, but the
possible impacts of emissions from existing facilities has recently been given
new importance in the continuing studies of acid-rain causes and effects.
Many such facilities are operating under emission regulations much less
stringent than those for new boilers and can be expected to continue in
operation for a number of years. This is particularly true in light of the
recent slowdown in new power plant construction. Thus, any strategy for
regional or national reductions in S02 emissions must consider options for
increased control of existing sources.
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This study had as its primary focus the question of what SC>2 reductions
could be obtained in the Midwest by applying extensive physical coal cleaning
(PCC) to fuels being burned by major power plants. In addition, we examined
briefly the cost tradeoffs betwen coal cleaning and partial flue-gas desulfur-
ization (FGD), as well as the legislative/regulatory options available for
implementing a requirement for coal cleaning.
The study involved 24 power plants in Illinois, Indiana, and Ohio that
have capacities of at least 500 MWe, burn coal with more than one percent
sulfur, and have no FGD systems. We examined the Federal Energy Regulatory
Commission (FERC) records (form 423) of 1980 coal purchases for these plants
to determine the states, counties, and mine seams that were the sources of the
principal coals supplied to each plant. After making these determinations, we
used the coal-cleaning ("washing") characteristics of these coals (as pre-
viously determined by the U.S. Bureau of Mines) in conjunction with a PCC
computer code to model the results of coal washing for these plants. All but
one of the coals surveyed showed some reduction in total sulfur content with
cleaning. These reductions varied from 0-50%, with an average value of 29%.
The costs of equivalent sulfur dioxide reductions by means of PCC and
FGD were estimated and compared on the basis of dollars per ton of S02
removed. The results indicate that PCC is the most cost-effective control
option for about half of the plants. However, it must be noted that FGD has a
greater total potential for S02 control due to the higher removal efficiencies
possible with currently available technology.
Another factor that makes evaluation of the study results difficult is
that most of the coals studied appear to already be receiving some degree of
cleaning. Since this information is not reported by the utilities, we
inferred the use and degree of cleaning through analysis of raw and delivered
coal characteristics together with information on cleaning equipment available
at specific mines. Considerations, aside from environmental concerns, that
promote the use of cleaning include the large quantities of refuse produced by
certain mining techniques, high shipping charges that make preshipment removal
of mineral matter (ash) desirable, and plant operational benefits attributable
to cleaner and less variable coal. PCC has already achieved wide acceptance,
although the high degree of cleaning observed in this study is usually only
applied to metallurgical coals. Thus, the potential S02 reduction achievable
by mandatory PCC is actually somewhat less than projected in this report, by
an amount corresponding to current washing practices.
Many plants also fire a variety of coals, some of which differ sub-
stantially in sulfur content from the principal coals analyzed in this study.
Thus, actual emissions may differ significantly from those predicted on the
basis of a single coal per plant. However, while this fact and the current
use of coal cleaning may make development of a suitable control strategy more
challenging, they should not obscure the conclusion that PCC can make a
significant and cost-effective contribution to S02 control for many facilities
in the Midwest.
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Chapter 2 of this report gives the criteria used in selecting power
plants for this study and summarizes the plant characteristics, fuel charac-
teristics and sources of data. Chapter 3 presents descriptions of current PCC
and FGD technology, while Chapter 4 presents the study results and compares
the two approaches to SC>2 control. Policy issues and the conclusions drawn
from the results are given in the final two chapters.
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2 POWER PLANTS IN THE STUDY REGION
2.1 SCREENING CRITERIA
Criteria for screening power plants in the study region included size,
fuel, fuel sulfur content, and current emissions control technologies. Table
1 lists the 24 plants chosen for study as a result of this screening.
The specific screening criteria were:
• Survey region: Illinois, Indiana, and Ohio
• Power-plant size: 500 MW or greater
• Fuel: Coal with a sulfur content exceeding 1%
• Emissions control technologies: Power plants or individual
units with FGD systems were eliminated from consideration.
2.2 CHARACTERISTICS OF PLANTS
The breakdown of power plants with coal-firing capacities in excess of
500 MW and no FGD capacity (or FGD capacity limited to recently constructed
units) is shown in Table 1. Twenty-four plants were identified, of which only
five were of less than 1000 MW capacity and only four were greater than 2000
MW. The typical power plant therefore falls in the range of 1000-2000 MW.
The states rank as follows: Ohio - eleven plants, Indiana - nine plants,
Illinois - four plants. For purposes of this study, these plants have been
randomly ascribed identifying letters, which will be used for the remainder of
the report.
2.3 CHARACTERISTICS OF FUEL SUPPLIES
2.3.1 Data Sources
Public utilities are required to file monthly statements with the
Federal Energy Regulatory Commission describing the sources of their coal.
This one-page form, FERC-423, requests information about the state, county,
and name of the producing mine; coal quantities purchased; and the heating
value, ash, and sulfur content of the coal. This information is part of the
public record of utility activity that is available to any interested party at
either the regional FERC offices or the main office in Washington, D.C. The
Energy Information Agency (EIA) regularly abstracts the information from these
forms relating to coal quantity purchased, heating value, ash, and sulfur
content. These computer files were also available to this study.
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Table 1 Power Plants with Coal-Firing Capacities of 500 MWe or Greater'
State Plant Names
Illinois Coffeen
Kincaid
Joppa Steam
Baldwin
Indiana Petersburg
E.W. Stout
Bailly
Michigan City
Cayuga
R. Gallagher
Gibson
Wabash River
Clifty Creek
Ohio Cardinal
W.C. Beckjord
Miami Fort
Avon Lake
East lake
Conesville
R.E. Burger
Sammis
Kyger Creek
Muskingum R.
J.M. Gavin
Unit
Numbers
1,2
1,2
1-6
1-3
1-3
5-7 ,A3 ,A4
7,8
2,3,12
1,2
1-4
1-4
1-6
1-6
1-3
1-6
5-8
6-9
1-5
1-6
1-5
1-7
1-5
1-5
1,2
Total
Capacity
(MWeb)
1006
1319
1098
1892
1338
705
616
661
1062
600
2672
962
1304
1865
1221
1377
1085
1257
2135
546
2304
1086
1507
2600
Utility
Central 111. Public
Service Co.
Commonwealth Edison
Electric Energy, Inc.
111. Power Co.
Indianapolis Power
& Light Co.
Indianapolis Power
& Light Co.
Northern Ind. Public
Service Co.
Northern Ind. Public
Service Co.
Public Service Co.
of Indiana
Public Service Co.
of Indiana
Public Service Co.
of Indiana
Public Service Co.
of Indiana
Indiana-Kentucky
Electric Corp.
Buckeye Power Co.
Cincinnati Gas &
Electric Co.
Cincinnati Gas &
Electric Co.
Cleveland Elec.
Illuminating Co.
Cleveland Elec.
Illuminating Co.
Columbus & Southern Ohio
Elec. Co.
Ohio Edison Co.
Ohio Edison Co.
Ohio Valley Electric Corp.
AEP: Ohio Power Co.
AEP: Ohio Electric Co.
aInventory of Power Plants in the United States, 1980 Annual, U.S. Depart-
ment of Energy Report DOE/EIA-0095 (June 1981).
^Nameplate (gross) capacity.
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For purposes of all but a very approximate analysis of performance of
coal cleaning systems, it is essential that information about the specific
seam being mined be obtained. For this study, we manually examined the FERC-
423 forms for 1980 and attempted to reconcile those data with industry
reference sources to provide the best basis for the washability calculations.
Part of this information had already been summarized in another study for
plants in Ohio.
The details of this data acquisition, including additional information
for the 53 mines it was possible to identify, are summarized in Appendix A.
2.3.2 Coal Washability Data
The coal washability data were derived by integrating coal washability
and coal reserves data obtained from the U.S. Bureau of Mines. Two computer
programs previously developed by Argonne matched the appropriate entries in
each data set and then merged the data. Approximately 18% of the demonstrated
coal reserves were matched with washability data. However, about 35% of the
reserves that account for 80% of current production were successfully matched.
Specifications as to the location and size of the reserve, and descrip-
tions of the coal with data on selected physical and chemical characteristics
were also included. Washability data are presented for three crush top sizes
(1.5 in., 3/8 in., and 14 mesh) and several specific gravities. In each case,
the values of percent recovery, Btu/lb, percent ash, percent sulfur, Ib
S02/106 Btu, and reserves available at 1.2 Ib S02/106 Btu are given.
2.3.3 Current Status of Coal Washing
Information about the potential ability of any mine to wash coal can be
obtained by reviewing the reported information about preparation equipment.
However, the coal washing plants produce a variety of products, including a
stream of tailings, that are high in sulfur and ash content. Because these
tailings are being sold to the utilities in a few cases, the situation can
arise where a plant with the capability for a high level of cleaning is in
fact selling a coal high in sulfur and ash content to the utility. Levels of
cleaning were assigned to the output from each mine based on a comparison of
the washability data with the full series of mine shipments during the year.
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3 DESULFURIZATION TECHNOLOGIES
Commercially available desulfurization technologies fall into two basic
categories. The first of these are techniques, such as physical coal clean-
ing, that effect the sulfur removal prior to combustion. Although these tech-
nologies have been developing for over 100 years, a number of new and com-
A
mercially significant approaches are being considered. The second class of
desulfurization technologies effects the post-combustion control of sulfur
dioxide through the use of flue-gas desulfurization, which has been in
commercial use at power plants for about 15 years. An overview of these two
contrasting methods follows.
3.1 PHYSICAL COAL CLEANING
Physical coal cleaning processes remove clay, shale, and pyrite from
run-of-mine (ROM) coals. Cleaning is achieved by grinding the coal to liber-
ate impurities that are not chemically bound and then taking advantage of
specific gravity differences between the organic matter that formed the coals
(called macerals) and the denser mineral impurities. Sometimes differences in
surface-wetting properties between macerals and impurities are used for
separation.
General cleaning strategies for plants depend on the desired level of
coal cleaning. These levels are assigned as shown in Table 2.
3.1.1 PCC Commercial Technology
PCC plants may involve up to four major subsystems: 1) comminution
(size reduction), 2) screening, 3) concentration, and 4) dewatering. These
subsystems have to be tailored to the specific coal and desired level of
Table 2 Levels of Physical Coal Cleaning
Level
0
1
2
3
4
No Preparation (ROM)
Top Size Control
Coarse Beneficiation
Moderate Beneficiation
Full Beneficiation
Weight
Yield (%)
100
98-100
75-85
60-80
60-80
Btu
Recovery
(%)
100
100
90-95
80-90
80-90
Reduction
Ash
None
Fair
Good
Good
Excellent
Sulfur
None
None
.Fair
Fair
Good
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8
cleaning. This requirement contrasts markedly with the general applicability
of flue-gas desulfurization.
Comminution
One of the main goals of the crushing operation is to achieve a
specified top-size without creating excessive difficult-to-clean fines. The
optimum size to which coal is crushed depends on its washability and end-use.
Rotary breakers are most often used for preparation of deep-mined
material with a significant amount of roof and floor material. Radial lifting
shelves in the unit lift and drop coals as the unit rotates. Stones, shales,
logs, and other debris too large to pass through the perforations in the drum
are conveniently discarded. Breakers are the lowest in fines production.
Roll crushers squeeze the coal between tooth-covered rollers. They are
also low in fines production and are capable of reducing ROM coal to 1 1/2 in.
or less.
Hammer mills throw coal against breaker blocks and grate bars until the
product is reduced to the size of the grate opening. These machines produce a
large quantity of fines in comparison with the above techniques.
Magnets are often included directly after coarse sizing and crushing in
the comminution circuit. "Tramp iron" that may be present in the crushed coal
is removed by these magnets so that it will not damage downstream equipment.
Screening
Either wet or dry methods may be used to classify coal into different
size ranges before introduction to coal-cleaning circuits. Screens remove
rocks and foreign material prior to crushing, and later in the circuit other
screens are used to separate coal into coarse and fine fractions for marketing
or further preparation. For a Level 1 circuit, comminution and screening are
the only system operations. More advanced circuits use screening for recovery
from heavy-media circuits and dewatering of coarse coal.
Concentration
Concentration is the operation in which the coal and impurities are
actually separated. General methods can be classified as water-only, heavy-
media, and dry separation. Some specialized fine-coal recovery methods
include froth flotation and oil agglomeration.
Jigs are the oldest and simplest of all coal washing devices. Their
principal service is on coarse-sized coal, and they remain the most widely
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used devices in this country. In jigging, a series of pulses (at the rate of
one pulse per second) moves up through the coal-filled bath to provide a rough
classification of the coal and mineral impurities by density. The denser
impurities are drawn off the bottom and discarded, while the top fraction is
withdrawn as product coal. These devices produce a large "middling" product,
which is either recycled or sent to other concentrating systems.
The concentrating table is widely used for fine-coal cleaning. Tables
are large tilted rhomboid-shaped decks with ridges (riffles) that span the
table diagonally. Reciprocating motion of the table causes feed material to
fan out onto the deck into strata of different density. Tabling concentrates
the heaviest and finest of the particles at the bottom of the deck while the
lightest and coarsest particles congregate at the top of the deck. This
system is particularly applicable for washing soft and friable coals that
degrade easily.
Hydrocyclones are separating devices for medium- to fine-sized coal.
These devices make use of high centrifugal forces to effect the separation of
denser impurities from the coal. Heavy-media cyclones add 325-mesh magnetite
to the wash circuit to increase the wash water's apparent density (to a
specific gravity, or S.G., of 1.3-1.8), which provides for a finer "cut" on
the pyritic impurities. Currently, this represents the most advanced form of
physical coal cleaning available. The circuit becomes more complicated by the
need to recover magnetite so as to minimize processing costs. The dense-media
recovery unit is generally a drum-type magnetic separator that provides for
the effective recovery of all but the smallest of magnetite particles.
Froth flotation has come into wide use for the recovery of the heating
value of coal fines produced by the comminution step. In contrast to the
other concentrating processes, flotation does not use specific gravity as the
basis of the separation. The wetting properties of the macerals and the
impurities are characteristically different, the ash being hydrophilic (water-
attracting) while the macerals are hydrophobic (water-repelling). Blowing
fine bubbles of air through the aqueous phase (usually enhanced by surfact-
ants) floats the coal up to the surface for recovery.
While flotation is effective in ash removal, one serious deficiency is
its difficulty in selectively rejecting pyrites. The wetting properties of
pyrites are similar to those of coal macerals, and it is generally necessary
to reclean the froth, with slight modifications of the surface tension, so as
to remove the pyrites.
Dewatering
After washing the coal, excess moisture must be reduced to minimize the
penalties incurred in decreased heating value of the fuel, increased trans-
portation costs, and handling and shipping problems. The types of equipment
used in this service are directly related to the coal grind. They are
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10
screens, centrifugal dryers, various types of vacuum dryers, filter presses,
belt filters, thermal dryers, and water clarifiers.
3.1.2 PCC Systems Overview
General cleaning strategies for plants depend on which of the following
levels of coal cleaning are desired.
1. Run-of-Mine. Level 1 involves no cleaning but reduces ROM
coal to user's size specifications, prepares it for ship-
ment, and possibly reduces moisture content (an important
consideration for low-rank western coals). Coal prepared
in Level 1 facilities may have to be blended with other
coals to meet S02 emission standards.
2. Coarse-to-Moderate Beneficiation. Levels 2 and 3 use low-
efficiency separation devices to process easy-to-clean
coals (coarse coal only in Level 2) and therefore should
be employed to remove pyritic sulfur from coal that com-
plies or almost complies with S02 emission standards.
3. Full Beneficiation. Level 4 makes use of high-efficiency
separation methods to clean the +28 mesh size fractions,
while the ultrafine coal (-28 mesh) is cleaned using
hydrocyclones. Thus, all coal is cleaned at this level.
The coal processing equipment used will vary with coal characteristics and, to
a lesser extent, with site-specific constraints that require the development
of the most suitable combination of unit operations for each coal-cleaning
case. Consequently, very few physical coal cleaning plants are identical,
clearly indicating that no standard solution for upgrading coal exists.
Equipment and/or unit operations can be subtracted or added to adapt to
changes in the coal characteristics during the life of a plant. It is also
possible to convert the plant to another level of physical coal cleaning.
This feature allows the construction and operation of low-level cleaning
plants that are designed to be changed to higher level plants at a later date.
For descriptive purposes, "typical" flowsheets have been developed for the
various cleaning levels. The following descriptions are adapted from Ref. 4.
3.1.3 PCC Level 1 System
Coal for power generation is usually shipped in 2 in. or 1-1/2 in. x 0
size ranges, thus necessitating the crushing of oversize ROM coal. The
screening and crushing processes to achieve the required size reduction repre-
sent the minimal effort in coal preparation practice.
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11
A rotary breaker could be selected to size eastern bituminous coals,
because of their hardness and resiliency. The rotary breaker not only reduces
the size of the ROM coal, but also allows the rejection of rock (e.g., roof
material from underground mines or overburden from surface mines) in the same
operation.
An eastern bituminous coal is typically processed for sizing and rock
rejection at its respective mine site. A list of major equipment is included
(Table 3), and a process flow diagram is shown in Fig. 1.
The coal generally is delivered to the receiving hopper by trucks (when
the coal is mined by open pit) or by belt conveyor (when mined by underground
methods). The receiving hopper is equipped with grizzly bars to limit the
size of the coal pieces entering. The oversize coal pieces are broken to pass
through the grizzly or are removed.
From the receiving hopper, the coal is fed by a reciprocating feeder to
a stationary grizzly. This grizzly is equipped with parallel bars that divert
the +3 in. oversize coal to a rotary breaker. The -3 in. undersize from the
grizzly is collected on a belt conveyor. In the rotary-breaker, the +3 in.
raw coal is reduced to 3 in. top size. The rotary-breaker product is dis-
charged to a belt conveyor and combined with the grizzly undersize for trans-
portation to a storage silo. The unbroken material leaving the rotary-breaker
eye contains shale, or other waste rock and debris, which is collected in a
rock bin for disposal by truck.
Before the coal is discharged into the storage silo, it is sampled and
weighed. A suspended magnet is provided for the removal of tramp iron.
Table 3 Major Equipment for Level 1 PCC Plant
Quantity Equipment
(1) ROM hopper with grizzly bar, 500 tons
(1) Reciprocating feeder, 60 in. duplex
(1) Stationary grizzly, 5 ft x 12 ft
(1) Rotary breaker, 12 ft (diameter) x 28 ft
(1) Rock bin, 100 tons
(2) Belt conveyors, 48 in. wide
(1) Belt scale
(1) Tramp iron magnet
(1) Sampling system
(1) Storage silo, 15,000 tons,
70 ft (diameter) x 200 ft
(1) Rail scale
(3) Dust collectors, 21,500 ft /min
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12
3.1.4 PCC Level 2 System
Level 2 PCC involves the clean-
ing of a course size fraction of the
raw coal, preceded by a dry screening
operation at a screen-opening size
that allows the removal of dry fine
coal without blinding the screen
cloth. Depending on the moisture
content of the raw coal, dry screening
is usually limited to a minimum open-
ing size of 1/4 in. Larger screen
openings of 3/8 or 1/2 in. generally
permit more efficient screening and
should be used if characteristics of
the raw coal allow use of those larger
openings without impairing the final
product quality. Vibrating screens
are required for the dry screening
operation.
The preferred method of clean-'
ing the coarse coal fraction is in a
jig, which is characterized by high
capacity per unit and separation effi-
ciencies that are sufficient for a
Level 2 effort.
MEDIUM SULFUR COAL
ROM
SCREENING AND
CRUSHING
MINE
ROCK
3"xO
STORAGE
MINIMUM 15,000 TONS
UNIT TRAIN
LOAD OUT
Fig. 1 Block Diagram for Level
1 PCC
Level 2 cleaning is represented
by the flow sheet in Fig. 2 and equip-
ment list in Table 4. The ROM coal is delivered to a receiving hopper
equipped with grizzly bars to limit the size of coal pieces entering the
hopper. The oversize pieces are removed or (if not rock) broken to pass into
the hopper. From the receiving hopper, the coal is fed by a reciprocating
feeder to a stationary grizzly, which consists of parallel bars to remove the
+6 in. oversize coal. The oversize fraction is directed to a rotary breaker
for reduction to 6 in. top size. The -6 in. undersize from the grizzly and
the crushed coal from the rotary breaker are combined and conveyed to the raw-
coal storage silo.
The oversize from the rotary breaker, containing rock or other debris,
is collected in a rock bin for transfer into trucks for disposal.
The coal, before being discharged into the raw-coal storage silo, is
sampled and weighed. A magnet suspended over the belt conveyor removes tramp
iron to provide protection against equipment damage. The storage silo is
equipped with hoppers and feeders that permit the withdrawal of coal at a
predetermined rate and its discharge onto the plant feed conveyor. This
conveyor is equipped with a belt scale to monitor coal feed rate to the plant.
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13
ROM
MINE
ROCK
SCREENING AND
CRUSHING
."(6") xO
STORAGE
DRY
SCREENING
4" (6") x 0
CLEANING
DEWATERING
THICKENING
DEWATERING
3/8" x 0
DEWATERING
CRUSHING
CLEAN COAL
STORAGE
1 1/2" xO
REFUSE
DISPOSAL
4"(6")x1/4"
UNIT TRAIN
LOAD OUT
WATER FLOW
— SOLID FLOW
Fig. 2 Block Diagram for Level 2 PCC
-------
14
Table 4 Major Equipment for Level 2 PCC Plant
Quantity Equipment
(1) Hopper bin with grizzly, 500 tons
(5) Reciprocating feeders
(1) Vibrating grizzly, 5 ft x 12 ft
(1) Rotary breaker, 12 ft (diameter) x 28 ft
(1) Rock bin, 100 ton
(5) Belt conveyors, 48 in. wide
(3) Belt scale
(1) Tramp-iron magnet
(2) Coal sampling systems
(1) Raw coal silo, 15,000 tons,
70 ft (diameter) x 200 ft
(4) Vibrating screen, 8 ft x 20 ft
(4) Dewatering screens, 8 ft x 16 ft
(1) Head tank
(1) Baum jig, two-compartment
(1) Refuse bin, 300 tons
(4) Thickening cyclones, 24 ft (diameter)
(1) Sieve bend, 5 ft wide
(1) Vibrating centrifuge
(1) Thickener, 75 ft (diameter)
(2) Crusher, double roll, 36 in. x 60 in.
(1) Disc vacuum-filtering system,
12.5 ft (diameter), 13 discs
(2) Mixing tanks
(1) Storage silo, 15,000 tons,
70 ft (diameter) x 200 ft
(1) Rail scale
(1) Fine coal sump
(2) Fine coal pumps
(2) Thickener pumps
(1) Sump pump
(3) Dust collectors, 15,000 ft^/min
(3) Dust collectors, 21,500 ft /min
Upon discharge from the plant feed conveyor, the coal is screened dry
on a vibrating screen to remove the oversize, which is sent to be washed. The
screen undersize, consisting typically of 3/8 in. x 0 coal, is discharged
directly onto the clean-coal collecting conveyor for transportation to the
clean-coal storage silo.
The vibrating-screen oversize (typically 6 in. x 3/8 in.) is fed to the
washing section. Coal cleaning takes place in a two-compartment Baum-type
jig. During the passage of coal through the jig, heavier refuse particles are
rejected and conveyed to the refuse bin for disposal. The clean coal is
-------
15
discharged from the jig with the process water and divided into two parallel
streams for passage over two vibrating dewatering screens. The dewatered 6
in. x 3/8 in. clean coal continues in two streams to two double-roll crushers
for size reduction to 2 in. top size and is then discharged to the clean-coal
belt conveyor for transfer to the clean-coal silo. The effluent from the
dewatering screens, including some 3/8 in. x 0 solids, is collected in a fine-
coal sump and pumped to thickening cyclones, which remove most of the water.
The overflow from these cyclones contains coal fines up to 28 mesh. Part of
this overflow is used as process water in the jig, while the remainder is
directed to a static thickener located outside the washing plant.
The cyclone underflow contains most of the solids, which are dewatered
on sieve bends to settle out the -28 mesh solids, the effluent from which is
sent to a thickener. The oversize from the sieve bend (3/8 in. x 28 mesh) is
further dewatered in vibrating centrifuges and discharged onto the clean-coal
conveyor. The effluent of the vibrating centrifuge is also directed to the
thickener.
All dilute fine-coal slurry streams from dewatering processes are
collected in the static thickener to recover the solids and clarify the water.
The recovery process starts with the settling of the solids in the thickener,
aided by flocculant. The underflow is pumped to a disc vacuum filter for
dewatering of the settled material with the filter cake discharged to the
clean-coal conveyor. The clarified overflow from the thickener is pumped to
the plant for reuse in the process.
3.1.5 PCC Level 3 System
The PCC Level 3 effort can be considered as an extension of a Level 2
effort in that fine coal cleaning is added to the coarse coal cleaning of
Level 2. For Level 3, however, all of the coal feed, including the fines, is
wetted (in the Level 2 plant, only the +3/8 in. fraction is washed). There-
fore, thermal drying of the fine fraction is an essential part of Level 3. As
shown in Fig. 3, ROM coal is delivered to a receiving hopper equipped with
grizzly bars to limit the size of the coal entering the hopper. The oversize
pieces are removed or broken to pass through the grizzly. The coal is then
fed to a stationary grizzly by a reciprocating feeder. The grizzly, equipped
with parallel bars, removes the -6 in. coal and discharges the -1-6 in. coal to
a rotary breaker for size reduction below 6 in. The undersize coal from the
grizzly and the crushed coal from the breaker are transferred to a belt
conveyor and conveyed to the raw-coal silo. The rotary-breaker rejects are
transported by a belt conveyor to a rock bin and transported by trucks to a
disposal site.
The plant feed belt conveyor accepts the sized coal from the raw-coal
silo through reciprocating feeders, and a belt scale monitors plant feed rate.
-------
16
ROM
r
MINE ROCK
DEWATERING
THICKENING
SCREENING AND
CRUSHING
6"(4") x 0
STORAGE
DEWATERING
+ 3/B"
CLEANING
REFUSE DISPOSAL
WATER FLOW
SOLID FLOW
WET SCREENING
3/8" x 0
DEWATERING
T
.JL.
28 MESH x 0
DESLIMING
3/8" x 28 MESH
28 MESH x 0
•3/8
CRUSHING
CLEANING
3/8" x 28
MESH
DEWATERING
OEWATERING
LL
t 1..
28 MESH x 0
THERMAL
OEWATERING
CLEAN COAL
STORAGE
UNIT TRAIN
LOAD OUT
Fig. 3 Block Diagram for Level 3 PCC
-------
17
The raw coal is discharged to a chute, thoroughly wetted, and screened
at 3/8 in. The +3/8 in. coal is sluiced into a Baum-type jig washer. During
passage through the jig washer the refuse is separated from the coal and
rejected by bucket elevators discharging to a refuse belt conveyor.
The clean coal from the jigs is dewatered on stationary and vibrating
screens and classified into two fractions: 6 x 1-1/2 in. coarse coal, which
is subsequently reduced to 1-1/2 in. top size in a double roll crusher, and a
1-1/2 by 3/8 in. size fraction that is further dewatered in vibrating
centrifuges.
Effluent from the centrifuges and dewatering screens containing -3/8
in. clean coal is combined with the raw 3/8 in. x 0 coal, collected in a fine-
coal sump, and pumped to a cluster of six classifying cyclones. Part of the
overflow of these cyclones is diverted to a static thickener, while the re-
maining part is reused as process water in the jigs. The underflow from the
cyclones is fed to Deister tables for cleaning. Clean coal is dewatered on
sieve bends, screens, and vibrating centrifuges with the effluents from each
operation being drained to a static thickener. The dewatered 3/8 in. x 28
mesh fine coal is discharged onto the thermal-dryer feed belt conveyor.
Refuse from the Deister tables is dewatered in a spiral classifier and dis-
charged to the refuse belt conveyor. Water (from this operation) containing
fine solids is drained to the static thickener.
All -28 mesh fine solids contained in the plant effluents are settled
out in the static thickener with the aid of flocculant. The underflow from
the thickener is pumped to disc-type vacuum filters, from which the dewatered
solids are also fed to the thermal dryer. The filtrate is pumped back to the
thickener feedwell.
Clarified overflow from the thickener is collected for reuse in a sump
where makeup water is added to balance the plant water circuit.
The thermal dryer receives 3/8 in. x 0 clean coal via belt conveyor at
the dryer feed bin. To obtain the specified 6% surface moisture of the total
clean coal product, only part of the coal requires thermal drying. Coal dry-
ing takes place in a fluidized-bed-type thermal dryer, where a rising current
of hot air contacts the coal particles and removes moisture. After drying,
the fine coal is combined with the coarse coal. This composite product is
sampled, weighed, and transferred to the clean-coal silo.
Table 5 lists the major equipment in the Level 3 PCC plant.
3.1.6 PCC Level 4 System
The flow sheet for Level 4 PCC incorporates heavy medium cleaning
processes for the size fractions above 28 mesh. The coarse coal is processed
in heavy-medium vessels, whereas the fine coal is treated in heavy-medium
-------
18
Table 5 Major Equipment for Level 3 PCC Plant
Quantity Equipment
(1) ROM hopper with grizzly, 300 tons
(1) Feeder, 60 in. duplex, reciprocating
(1) Stationary screen, 5 ft x 12 ft
(1) Rotary breaker, 12 ft (diameter) x 28 ft
(1) Rock bin, 100 tons
(5) Belt conveyors, 48 in. wide
(1) Belt conveyor, 42 in. wide
(3) Belt scales
(1) Tramp-iron magnet
(2) Coal-sampling systems
(1) Raw-coal silo, 15,000 tons,
50 ft (diameter) x 120 ft
(4) Reciprocating feeders
(2) Jig washers
(4) Dewatering screens, 8 ft x 16 ft
(6) Dewatering screens, 6 ft x 16 ft
(1) Head tank
(6) Classifying cyclones, 24 in. (diameter)
(6) Vibrating centrifuges, 36 in.
(1) Double roll crusher, 36 in. x 60 in.
(2) Mixing tank
(2) Disc vacuum-filter systems,
12.5 ft (diameter), 13 discs
(1) Hammer mill
(1) Fluidized-bed thermal dryer
(1) Clean-coal silo, 15,000 tons,
70 ft (diameter) x 200 ft
(1) Rail scale
(2) Fine-coal sumps, 2500 gal
(2) Fine-coal pumps
(1) Sump pump
(2) Thickener pumps
(1) Refuse bin, 300 tons
(2) Dust collectors, 21,500 ft^/min
(2) Dust collectors, 15,000 ft /min
(12) Double-deck Deister tables
(1) Spiral classifier
(4) Sieve bends, 5 ft
-------
19
cyclones or similar devices. The ultrafines are cleaned in two stages of
hydrocyclones to maximize pyrite removal and accommodate the cleaning of
oxidized coal, which is not possible using froth flotation.
The Level 4 PCC process equipment list is shown in Table 6 with a flow-
diagram in Fig. 4. The ROM coal is delivered by trucks or by belt conveyor to
a receiving hopper equipped with grizzly bars to limit the size of coal pieces
entering the hopper. The oversize pieces are removed or broken to pass
through the grizzly. From the receiving hopper the coal is fed by a recipro-
cating feeder to a stationary grizzly, which consists of parallel bars for the
removal of the +4 in. coal. This oversize fraction goes onto a rotary breaker
for size reduction. The undersize from the grizzly and the 4-in. top size
rotary-breaker product are combined and conveyed to a storage silo. The over-
size from the rotary breaker, containing rock or other debris, is collected in
a rock bin and transferred to trucks for disposal.
Before being discharged into the raw-coal storage silo, the 4 in. x 0
raw coal is sampled and weighed. A suspended magnet over the belt removes
tramp iron for protection against damage to downstream equipment.
The 4 in. x 0 raw coal is delivered to the washing plant by a belt con-
veyor. The coal is wet-screened at 3/8 in., and the oversize material is fed
to a heavy-medium vessel. The design specific gravity of the heavy medium
chosen for a typical bituminous coal is 1.40. After separation, the product
and refuse are discharged to vibrating screens to remove the heavy medium from
the solids and to rinse off magnetite attached to the coal and refuse
particles. Double-deck screens are used to classify the clean coal to obtain
a 4 x 1-1/2 in. size fraction, which is crushed to minus 1-1/2 in. in a gear
roll crusher. The product and rejects are discharged to a clean-coal conveyor
and a refuse conveyor, respectively.
The 3/8 in. x 0 slurry from the raw-coal screens is sluiced to vibrat-
ing screens preceded by sieve bends and deslimed at 28 mesh. The 3/8 in. x 28
mesh fraction is fed into a sump, mixed with heavy medium, and pumped to
heavy-medium cyclones. After separation in the cyclones, heavy medium is
drained and rinsed off the products on vibrating screens preceded by sieve
bends. The recovered heavy medium is returned to the cyclone feed sump. The
clean-coal product is dewatered in a vibrating centrifuge and discharged onto
a clean-coal conveyor, which carries the coal to a thermal dryer. After rins-
ing, the refuse is added to the conveyor with the coarse refuse.
The magnetite-containing effluents from all rinsing screens and the
centrifuge are collected in a static thickener to obtain clarified water and
an underflow, which is pumped to double-drum magnetic separators. The re-
covered magnetite is recycled, while magnetite losses are replaced by raw
magnetite.
The desliming-screen slurry containing the minus 28 mesh solids is
pumped to a two-stage hydrocyclone system. The underflow of the primary
-------
20
Table 6 Major Equipment List for Level 4 PCC Plant
Quantity Equipment
(1) ROM hopper with grizzly, 500 tons
(1) Reciprocating feeder, 60 in. duplex
(1) Stationary grizzly, 5 ft x 12 ft
(1) Rotary breaker, 12 ft (diameter) x 28 ft
(1) Rock bin, 100 tons
(6) Belt conveyors, 48 in. wide
(1) Belt conveyor, 36 in. wide
(3) Belt scales
(1) Tramp-iron magnet
(2) Sampling systems
(1) Raw-coal silo, 15,000 tons,
50 ft (diameter) x 120 ft
(4) Reciprocating feeders
(4) Raw-coal screens, 8 ft x 20 ft
(8) Sieve bends, 7 ft
(6) Sieve bends
(2) Sieve bends, 5 ft
(20) Dewatering screens, 8 ft x 16 ft
(2) Dewatering screens, 6 ft x 16 ft
(4) Heavy-medium vessels, 14 ft wide
(4) Heavy-medium cyclone, 24 ft (diameter)
(36) Primary hydrocyclones, 12 in. (diameter)
(18) Secondary hydrocyclones, 12 in. (diameter)
(1) Roller crusher, double roll, 36 in. x 60 in.
(1) Clean-coal silo, 15,000 tons,
70 in. (diameter) x 200 ft
(1) Rail scale
(1) Vibrating centrifuge
(2) Solid-bowl centrifuges
(2) Vacuum filter, disc systems,
12.5 ft (diameter), 13 discs
(1) Dilute-medium thickener, 50 ft (diameter)
(1) Thickener, 190 ft (diameter)
(4) Magnetic separators, 30 in. x 84 in., double drum
(1) Fluidized-bed thermal dryer
(1) Screw feeder, 9 in. (diameter)
(2) Vibrating feeders
(2) Heavy-medium sumps
(2) Fine-coal sumps, 2500 gal
(2) Cyclone sumps, 950 gal
(4) Fine-reject sumps, 500 gal
(1) Heavy-medium storage sump
(4 Thickener pumps
(6) Sump pumps
(2) Hydrocyclone pumps
(2) Heavy-medium pumps
(2) Flocculant systems
-------
21
Table 6 (Cont'd)
Quantity Equipment
(1) Magnetite storage bin, 100 tons
(2) Dust collectors, 21,500 ft^/min
(3) Dust collectors, 1500 ft3/min
(1) Refuse bin, 500 tons
hydrocyclones is diluted with water and reprocessed in the secondary hydro-
cyclones, where a refuse product is obtained. These rejects are dewatered in
solid-bowl centrifuges and disposed of with the other plant refuse.
The secondary hydrocyclone overflow is combined with the magnetic-
separator effluent, added to the raw coal, and eventually reprocessed in the
first-stage hydrocyclones. The overflow of the primary hydrocyclones
containing the clean-coal product is thickened in a static thickener and
dewatered in a vacuum-filtration system. The dewatered clean coal is added to
the 3/8 in. x 28 mesh clean coal and conveyed to the thermal dryer.
In order to maintain a specified surface moisture of the total clean
coal, the 3/8 in. x 0 fraction is thermally dried in a fluidized-bed-type
dryer equipped with dry and wet dust-collection sections to obtain acceptable
stack-gas emissions. After drying, the coal is combined with the coarse clean
coal, weighed, automatically sampled, and discharged into the clean-coal silo.
3.1.7 PCC Existing Capacity
The existing capacity of PCC equipment (effective for Level 2 and
higher cleaning) in Illinois, Indiana, and Ohio is displayed in Fig. 5 and
given explicitly in Tables 7-9 (based on data from Ref. 1). This inventory
shows Illinois with the greatest coal-cleaning capacity, followed by Ohio and
Indiana. These figures do not relate the capacity factors for these installa-
tions, because that information is not generally reported.
3.1.8 PCC Equipment Service
The issue of physical-coal-cleaning equipment service has not received
much attention. In this respect PCC stands in marked contrast to FGD tech-
nologies. Failures in operating FGD systems increase sulfur-oxide emissions,
while outage times in a coal-cleaning circuit can usually be made up so that
the average monthly production of the preparation plant remains constant.
Additionally, it appears that many PCC facilities are designed for only
-------
22
ROM
MINE ROCK
CRUSHING AND
SCREENING
6"I4") xO
STORAGE
3/8"
WET SCREENING
3/8" x 0
CLEANING
DEWATERING
OEWATERING
3/8" x 28 MESH
DESLIMING
CLEANING
28 MESH x 0
OEWATERING
OEWATERING
t
J
CRUSHING
3/8" x 28
MESH
CLEANING
THICKENING
REFUSE DISPOSAL
I 28 MESH xO
•-T
OEWATERING
OEWATERING
THERMAL
DEWATERING
I J
CLEAN COAL
STORAGE
— WATER FLOW
SOLID FLOW
UNIT TRAIN
LOAD OUT
Fig. 4 Block Diagram for Level 4 PCC
-------
23
200-,
I5
-------
Table 7 Inventory of Illinois PCC Plants
Company
Amax Cnal Co.
Amax Co.ll Co.
Amax Coal Co.
Consolidation
Coal Co.,
Midwestern
Region
Consolidation
Coal Co.,
Midwestern
| Region
j
! Consolidation
Coal Co.,
Midwestern
Region
Consolidat Ion
Coal Co.,
Midwestern
Region
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Concentration
Comminution Heavy- Dewaterlng
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen Jig TaMes Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Sun Spot Mine, 3,500 XX X XX XX
Vermont
Leahy Mine. 12,000 X X X X X X
Campbell Hill
Delta Mine, A, 750 X X X X X X
Marlon
Burning Star 6,500 XX X
No. 1 Mine,
DuQuoln
Burning Star 6,500 XX X
No. 3 Mine,
Sparta
Burning Star XX X
No. 4 Mine,
Cutler
Burning Star X
No. 5 Mine,
DeSoto
Buckheart Mine 7,000 XXX X X
17, Canton
Orient Mine 3, 14,000 X X X X XX X
Ualtonvllle
Orient Mine 6, 6,000 XX X
Waltonvllle
Crown IT Mine, X X X X X
Vlrden
-------
Table 7 (Cont'd)
Company
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Freeman United
Coal Mining Co.,
Dlv. Material
Service Corp.
Inland Steel
Coal Co.
Inland Steel
Coal Co.
Midland Coal
Co., A Dlv. of
ASARCO, Inc.
Midland Coal
Co., A Dlv. of
ASARCO, Inc.
Monterey Coal Co.,
A Dlv. of Exxon
Coal USA, Inc.
Monterey Coal Co.,
A Dlv. of Exxon
Coal USA, Inc.
Morris, Coal, Inc.
Old Ben Coal Co.
Old Hen Coal Co.
Old Ben Coal Co.
Old Ben Coal Co.
Concentration
Comminution Heavy- Devaterlng
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen Jig Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Fidelity Mine 7,500 X X
11, nuQuoln
Orient Mine 4, 7,000 X X X XX
Marlon
Inland Mine X X X X X X
No. 1, Sesser
Inland Mine X X X X X X
No. 2, Senser
Rapatee Mine, X X X X X X
Mlddlegrove
Elm Mine, 7,000 XX XXX XX
Trlvoll
Monterey No. 1 12,000 X X X X X X X
Mine,
Carllnville
Monterey No. 2 20,000 XXXXX X X X
Mine, Alters
Morris No. 5, 5,000 XXXXX X X
Pittsburgh
Old Ben No. X X X X X
21, Sesser
Old Ben No. X XX X XXXX
25, Benton
Old Ben No. X X
26, Sesser
Old Ben No. X XX X XXXX
27, Benton
-------
Table 7 (Cont'd)
Company
Peabody Coal Co.
Peabody Coal Co.
Peahody Coal Co.
Peabody Coal Co.
Peabody Coal Co.
Sahara Coal Co.,
Inc.
Southwestern
Illinois Coal
Corp.
ZelRler Coal Co.
Zelgler Coal Co.
Zelgler Coal Co.
Concentration
Comminution Heavy- De water Ing
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen Jig Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Mine No. 10, 15,500 XX XX
Pawnee
Eagle Surface XX X
Mine,
Shawneetown
Eagle No. 2 10,000 X X
Mine,
Shawneetown
River King U.G. 7,000 XXX X
No. 1 Mine,
Freeburg
Will Scarlet 6,500 XX X
Mine, Stonefort
1-0
Central Prepara- 12,000 XX X ON
tlon Plant,
Harrlsburg
Streamline Mine, X X X X X XX
Percy
Murdock Mine, X X X X X X
Murdock
Spartan Mine, 4,000 X X X X X X X
Sparta
Mine No. 11, XXXXXX X X
Coultervllle
-------
Table 8 Inventory of Indiana PCC Plants
Company
Concentration
Commt nut ion
Heavy-
Medium
Dewaterlng
Unit Name, Dally
Location Capacity Breaker Crusher Magnet Screen Jig Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Amax Coa1 Co.
Chinook Mine,
Brazil
5,500 X
Amax Coal Co. Mlnnehaha Mine, 8,000
SulIt van
Amax Coal Co. Ayrshire Mine, 16,000 X
Chandler
Peahody Coal Co. Hawthorn Mine, 5,000
Carlisle
Peahody Coal Co. Universal Mine, 6,000 X
Universal
Peahody Coal Co. Lynnvllle Ml lie 14,000 X
Nos. 1 & 2,
Lynnvllle
Peahody Coal Co. Squaw Creek 6,000 X
Mine, Boonvllle
-------
Table 9 Inventory of Ohio PCC Plants
Company
Central Ohio
Coal Co.
Consolidation
Coal Co.,
Midwestern
Region
East Falrfleld
Coal Co.
Holmes Limestone
Co.
Horizon Coal Co.
Horizon Coal Co.
Industrial
Mining Co.
Island Creek
Coal Co.
K&R Enterprises,
Inc.
KSR Enterprises,
Nacco Mining Co.
North American
Coal Corp.
North American
Coal Corp.
Unit Namp, Pally
Location Capacity
Musklngum Mine, 12,000
Cumberland
Georgetown 15,000
Preparation
Plant No.
19, Cadiz
East Fairfleld 3,600
Prep. Plant
North Lima
Preparation
Plant Div.,
Berlin
Bollvar/Strasburg 1,500
Operation,
Zanesville
Rosevllle 1,000
Operations,
Zanesvllle
Rogers Mine, 2,500
Lisbon
Vail Mine
(Northern Dlv.),
Freeport
Stark No. 1 S
Kefferrose Pits,
C.in field
Keffler Rose Mine
No. 2, Canfleld
Powhatan No. 6, 11,000
Alledonia
Powhatan No. 1,
Mine, Powhatan
Point
Powhatan No. 3
Mine, Powhatan
Point
Concentration
Comminution Heavy- Dewaterlng
Medium
Breaker Crusher Magnet Screen Jig Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
XXXXX X XX X
XXXXXXX X X
XXX X X X
X X
XXX X
X XXX
XX XX X
x x xxx
X XXX XX
X XX X XXX
XX X XXX
XXX X
XX X
-------
Table 9 (Cont'd)
Company
North American
Coal Co.
Oglpbay Norton
Co.
Ohio Coal &
Construction
Corp.
Peahody Coal Co.
Pe.ibody Coal Co.
Qimrtn Mining Co.
Ouarlo Mining Co.
R4K Coal Co.
Southern Ohio
Coal Co.
Southern Ohio
Coal Co.
Yonghlogheny f.
Ohio Coal Co.
Youghlogheny &
Ohio Coal Co.
Concentration
Comnliuitlon Heavy- Oewaterlng
Unit Name, Dally Medium
Location Capacity Breaker Crusher Magnet Screen .Hg Tables Cyclone Cyclone Flotation Thickener Dryer Centrifuge
Powhatan No. 5, X X
Mine, Powhatan
Point
Saglnaw Mining 4,500 X
Co. Mine, St.
Clalrsvllle
Rayland Plant & 300 XXX XX
Dock
(Bargeloadlng),
Wlnlersvllle
Broken Aro Mine, 8,000 X
Coslioclon
Sunnyhllt Mine, «,000 XXX X
New Lexington
Powhatan No. 4 7,500 X X X X X X
Mine, Powhatan
Point
Powhatan No. 7 8,400 X XX XXX
Mine, Powhatan
Point
Rice 1,2,3,4,5, 15,000 XX X XX X X
6,7,8, Polen,
Barb Tipple,
Bell.ilre Dock,
Lamlra Prep.
Plant, Cadiz
Melgs Mine No. 1, 18,850 X X X X X X X
Athens
Raccoon Mine No. 7,000 XXXXX X X X
3, Athens
Allison Mine, 5,000 X X X X X X
Bcallsvltle
Nelms Mine 5,000 X X X X X
Cadiz Portal ,
Cadi 7.
-------
30
3.2 FLUE-GAS DESULFURIZATION
Most of the FGD systems currently operating in the field represent an
early generation, if not the first generation, of their respective tech-
nologies. Consequently, there remain uncertainties about costs, materials of
construction, and reliability of the units in service. The investment costs,
operating costs, and total costs vary significantly, depending on the year of
construction, FGD vendor, unit size, fuel burnt, and sludge-disposal methods.
3.2.1 FGD Commercial Technology
Limestone and lime FGD systems can be considered relatively mature
technologies that have experienced more than a decade of utility service.
Further evolutionary development of the technologies may still be anticipated.
Other FGD processes are reaching a point in their development where it is
possible to begin assessing their commercial performance in detail. Existing
processes include:
• Lime/Limestone
• Lime/Limestone with Adipic-Acid Addition
• Lime/Limestone with Forced Oxidation
• Lime/Limestone with Alkali Fly-Ash Addition
• Lime/Spray-Drying
• Dual-Alkali
• Wellman-Lord
• Sodium Carbonate
The operation of these systems and their ability to control S02
emissions have been demonstrated. Current efforts are being directed toward
improving the process economics, availability, and sulfur-dioxide-removal
efficiency.
Lime/Limestone FGD Systems
The lime and limestone FGD processes are considered as one reference
technology, or base case, for the FGD technologies discussed in this report.
This method of S02 removal has been applied in many coal-fired electric-
generating stations, and many more units are in the design or construction
phase. Historically, capital investments and operating costs vary greatly
-------
31
from application to application. The different costs reflect significantly
different site properties, the sulfur content of the coal used, different SC^
removal requirements, etc. Major advantages of this base-case technology
include the extensive experience gained with it to date and the availability
of the materials needed. Disadvantages include a high rate of forced outages,
corrosion and erosion problems, and the need to dispose of great quantities of
sludge.
Lime/Spray-Drying FGD Systems
The spray-drying/baghouse technology represents an improvement over the
dry injection/baghouse process in that (1) sorbents other than (scarce)
nahcolite can be used; (2) a somewhat higher SC>2 removal efficiency can be
achieved; and (3) depending upon the sorbent used, the waste-disposal diffi-
culties can be significantly reduced. In principle, this technology, which
has been commercially applied at both utility and industrial facilities, can
be used with all types of coal. However, economic considerations are still
being evaluated for its application to coals with a sulfur content of greater
than 2.5-3%.
Dual-Alkali FGD Systems
Dual-alkali scrubbing is a wet, regenerable process combining absorp-
tion of S02 (with an aqueous alkali solution) and regeneration of the
absorbent (with lime). The dual-alkali systems utilize a clear sodium-
sulfite-based absorption solution. Compared with lime/limestone systems, they
have reduced problems with plugging, scaling, and erosion. Existing systems
remove S02 with 90-95% efficiency. Although some systems have had mechanical
or chemical problems, they have shown themselves reliable; less than 10% of
their total operating time has been interrupted with forced outages. This FGD
technology has good retrofit potential, based on the small size of its com-
ponents. The process does require a large land area for disposing of the
solid waste it generates. Economically, dual-alkali systems appear to be
competitive with the wet lime and limestone systems. The process has been
commercially applied in the U.S. Three full-scale demonstration systems are
operating with coal-fired utility boilers, and several commercial units are in
operation with coal- and oil-fired industrial boilers. Further development
work is needed to evaluate, characterize, and compare full-size coal-fired
demonstration facilities; to test systems using limestone as a regenerant; and
to develop methods for upgrading the quality of sludge.
Wellman-Lord FGD System
Wellman-Lord is an aqueous process that employs a sodium-sulfite
scrubbing solution to remove SC^ from flue gas. Thermal regeneration enables
-------
32
the system to recover the sulfite and produce a concentrated stream of 862 •
This process has been applied commercially both in the U.S. and overseas to
desulfurize flue and waste gases from oil- and coal—fired boilers, nonferrous
smelters, sulfuric-acid plants, and Glaus plants. This FGD process has all of
the advantages associated with sodium-sulfite-based scrubbing: a high SC^
removal efficiency, no plugging or scaling in scrubbing, and a low liquid-to-
gas ratio. It is a closed-loop operation, producing marketable end products
with no large-scale solid-waste disposal problems. The regeneration loop is a
complicated process requiring a relatively high energy input and relatively
higher capital and operating costs than throwaway processes. Further develop-
ment is needed to investigate specific process improvements, to evaluate the
process performance in full-scale demonstrations with coal-fired boilers, and
to test the Wellman-Lord system in combination with downstream sulfur-
reduction systems, particularly those using coal as a reducing agent.
Sodium-Carbonate FGD System
The aqueous-carbonate process combines the spray-dryer technology with
methods of regenerating the sorbent material and producing a marketable end
product with the sulfur removed from the flue gas. This FGD technology can
therefore greatly reduce the amount of sorbent (^2^3) required and can also
produce revenues that partially offset its own costs. Regeneration and
sulfur-recovery techniques make the system complex, however, and this com-
plexity raises both investment costs and operating and maintenance costs. On
the other hand, SG^ removal efficiencies can potentially exceed those that are
possible with other advanced FGD technologies. A 100-MW test facility is cur-
rently under construction.
One major issue of considerable importance to the further use of this
technology is the sludge-disposal problem associated with FGD. Over the next
few decades, there will be increasing problems with siting landfills for the
solid wastes continuously generated by coal-burning facilities. .Precombustion
removal of ash and sulfur through PCC could help ease this problem.
3.2.2 FGD Existing Capacity
The deployment status of FGD technology and its relation to coal sulfur
content can be seen in Fig. 6. Not shown in this figure are the relative
capacity factors for the various systems. If this consideration were in-
cluded, the role of scrubbing would be reduced, although the high-sulfur
component would be reduced more significantly than the low- and medium-sulfur
components.
-------
EQUIVALENT SCRUBBED CAPACITY (1000 MW)
OQ
o
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ee
-------
34
3.2.3 FGD Equipment Service
The results of a recent Argonne study on FGD system availability
appear in Fig. 7. In this study, the system availability was correlated with
the inlet concentration of S02 and design scrubbing efficiency (which are
related to system size and sorbent utilization). The trends indicate that all
the technologies exhibit high availability when used in low-sulfur-coal
applications, but availability decreases for high-sulfur-coal applications.
As the coal sulfur content increases to 3.5% and the required removal
efficiency increases, dual-alkali systems maintain system availabilities of
80% or higher, while all the lime/limestone FGD systems show marked declines
in availability. The problems with water chemistry are apparently compounded
by closed-water-loop operations (where the operation minimizes the make-up
water needed to produce fresh scrubbing liquor by recycling as much water as
possible from other stages of the operation), and these systems exhibit system
availabilities much lower than the open-water-loop systems. Adipic acid
leaves this trend unaffected, although alkali-ash addition makes it much
worse.
The Wellman-Lord system has an apparent advantage over lime/limestone
systems for high-sulfur coals at high removal efficiencies. The system
availability exhibited by this system is interpreted as falling off at nearly
the same rate as for dual-alkali systems, but at an availability lower by a
constant factor. This may be attributed to the overall increased complexity
of the system, especially the regeneration loop.
3.2.4 FGD Costs
Capital and annual cost data for operational FGD systems have been
obtained continuously since March 1978 for the EPA. Costs for each system
are obtained directly from the utilities and then itemized by individual FGD
cost elements. The itemized costs are then adjusted to a common basis to
enhance comparability. This adjustment includes estimating costs not given by
the utilities and escalating all costs to common dollars (mid-1981). All
adjusted cost data and computations are reviewed and verified with the
appropriate utility before publication.
The key factors used to produce these cost adjustments are:
Capital Costs
• All costs associated with control of particulate-matter
emissions are excluded.
• Capital costs for modifications necessitated by installa-
tion of an FGD system are added if they were not included
in the reported costs.
-------
lOO-i
E-
J
5
CJ
Q
O
LIME/LIMESTONE (CLOSED WATER CYCLE)
LIME/LIMESTONE (OPEN WATER CYCLE)
WELLMAN-LORD
DUAL ALKALI
SODIUM CARBONATE
10 12
SYSTEM STRESS
Fig. 7 Summary and Comparison of Calculated FGD System Availabilities
(Source: Ref. 5)
-------
36
• Sludge disposal costs are adjusted to reflect a 20-year
life span for retrofit systems and a 30-year life span for
new systems.
• Any unreported direct and indirect costs incurred are
estimated and included.
• All capital costs are escalated to mid-1981 dollars.
• All $/kW values reflect the gross generating capacity of
the unit.
Annual Costs
• All costs are adjusted to a common 65% capacity factor.
• Direct costs that were not reported are estimated and
added.
• Overhead and fixed costs that were not reported are esti-
mated and added.
• All annual costs are escalated to mid-1981 dollars.
• All mill/kWh values are based on a 65% capacity factor and
the net generating capacity of the unit.
A summary of these data (Table 10) shows the cost trends, which provide
a fair match with the deployment of existing equipment as outlined in Sec.
3.2.2.
-------
Table 10 Adjusted Capital and Annual Costs for Operational FGD Systems by Process Type
Capital
Process Type
Limestone
Lime
Dual alkali
Lime/alkaline
fly-ash
Sodium
carbonate
Wellntan-Lord
Limestone/
alkaline
f 1 v-ash
Range,
S/kW
23.7-170.4
29.4-213.6
47.2-174.8
43.4-173.8
42.9-100.8
132.8-185.0
49.3-49.3
Average,
S/kW
67.9
81.8
97.8
93.9
69.2
153.1
49.3
Reported
AdluBted
Annual
Range,
o3 mtll/kWh
37.2 0.1-7.8
43.7 0.3-11.3
55.3 1.3-1.3
44.0 0.4-5.4
26.2 0.2-0.5
20.6 13.0-13.0
0.0 0.8-0.8
Average,
mlll/kWh o
1.6 2.2
3.2 2.7
1.3 0.0
2.1 1.9
0.4 0.1
13.0 0.0
0.8 0.0
Capital
Range,
$/kW
38.3-194.3
60.4-210.0
87.8-163.9
52.5-184.4
87.1-150.9
254.6-282.2
102.6-102.6
Average,
$/kW a
98.9 44.0
116.5 44.2
146.7 82.9
122.8 51.4
110.9 26.4
271.6 12.1
102.6 0.0
Annual
Range ,
mlll/kWh
1.6-14.6
4.0-17.6
5.0-13.9
3.0-14.1
5.8- 7.4
16.7-20.8
5.4- 5.4
Average,
mlll/kWh o
6.1 3.1
8.1 3.6
8.7 3.8
1.2 3.8
6.4 0.7
18.1 1.9
5.4 0.0
"Standard deviation.
-------
38
4 COMPARISON OF PCC AND FGD
Assessment of emissions on the basis of pounds of S02 per million Btu
was necessary for this study. This corresponds to the way most emission regu-
lations are written and avoids difficulties that could occur due to differ-
ences in specific mining techniques. For example, it would be necessary to
consider the mining technique if the comparison were based on S02 emissions
per ton of coal. Consider the case of a uniform coal bed that can be strip-
mined in one part of a county, while for the remainder of the county the bed
must be deep—mined. Strip—mining typically permits rather close control over
the quality of the ROM coal, and significant amounts of the shale matrix are
excluded from the ROM coal. This is not the case for deep-mined coal. Today,
deep-mining of coal is highly automated, and it is common for these automated
procedures to include significant amounts of the roof and floor material in
the ROM product. If the coals obtained by these two methods were compared on
the basis of S02 emissions per ton, the outputs of the strip-mine and the deep
mine would appear quite different. However, using the heating value (Btu/lb)
of the coal as the basis of comparison would yield a single value for the
outputs of the two mines. Throughout this study we will continue to use this
"Btu" basis rather than "tons of coal."
4.1 EMISSIONS CORRESPONDING TO ROM COAL
Characterizing the emissions corresponding to the ROM coals requires
the following data:
• ROM coal characteristics for major coal suppliers to the
power plant, or
• "As-received" coal characteristics for the major coals
supplied to the power plant, together with a knowledge of
the preparation level for the coal.
For the majority of the power plants considered in this study, both of these
techniques were used to complement each other. It was possible to identify 53
mines located in Illinois, Indiana, Ohio, Kentucky, West Virginia, or Pennsyl-
vania that served as the principal suppliers to the utilities of interest in
Illinois, Indiana, and part of Ohio. Appendix A contains a series of tables
with specific data for these mines. A perusal of these data should demon-
strate that at least a modest level of coal preparation is typical for coals
provided by these principal suppliers. However, it should be remembered that
current deep-mining techniques virtually require some coal washing to remove
roof and floor materials. This removal is undertaken by the companies for
reasons unrelated to environmental concerns about sulfur reduction. Rela-
tively minor sulfur reductions are typical of most cleaning operations
employed for steam coal.
-------
39
The ROM emissions for each power plant's principle coal is rendered
graphically for 15 plants in Fig. 8, and for all plants in Fig. 12 to facili-
tate comparisons with the PCC techniques. One other significant issue was
addressed by this study in order to clarify the overall environmental impact
of any particular power plant. This is to link the S02 emissions per million
Btus with a plant capacity factor to calculate the thousands of tons of S02
per year that a specific power plant would be expected to generate (see the
explanation of Fig. 9 that follows).
4.2 EMISSIONS UNDER 1980 CONDITIONS
In order to determine power-plant S02 emissions for 1980, it was
necessary to analyze the monthly Form 423 data that each utility provides to
the FERC. For each coal purchase, the utility supplies FERC with coal
quantity purchased; heating value; ash content; sulfur content; and state,
county, and name of the producing mine (see Appendix A).
By reviewing the coal-cleaning equipment available to each supplier, it
was possible to assign approximate coal-cleaning levels to each producing
mine. These levels were:
• ROM (PCC Level 1),
• Coarse-to-moderate cleaning (PCC levels 2 and 3), and
• Full beneficiation (PCC level 4).
These levels are the same as those referenced in Sec. 3.1.2.
Power-plant S02 emissions in pounds of S02/10 Btu (Fig. 8) and overall
S02 emissions for 1980 in thousands of tons (Fig. 9) were calculated for each
utility by using a computer program to merge coal suppliers' cleaning-level
data with coal purchase data from the Form 423 file. No credit was taken for
sulfur removed with the boiler bottom ash. This is typically 5% of the total
sulfur. Figure 9 shows which plant/coal combinations actually account for the
greatest S02 emissions. These estimates are the multiplicative products of S02
emissions rate, power-plant size, and power-plant capacity factor.
4.3 PURCHASE PATTERNS FOR COAL IN 1980
Several trends were noted in the utility coal-purchase patterns for
large and small coal purchases. The purchase-pattern trends are related here,
because they may bear on future deployment of PCC systems. The trends are:
• Mine-mouth power plants typically make modest purchases
each month from other mines in addition to their major
purchase from the adjacent mine.
-------
40
i
i
I
1
I
1
Legend
CZJ Full
2Z3 Coarse-Moderate
ROM
E 0 P
POWCR PLANTS
S R T U K V
POWER PLANTS
8 L
POWCR PLANTS
Fig. 8 Power-Plant S02 Emission Rates, 1980
(Ib S02/106 Btu)
-------
41
in
z
1 »«•!
i
I
0 E 0 P H
POWER PLANTS
Legend
C3 Full
EZ2Coarse-Moderate
E3ROM
g
&
T U
POWER PLANTS
^% 380-
I/I
O
POWER PLANTS
Fig. 9 Power-Plant S02 Emissions, 1980
(103 ton S02/yr)
-------
42
• Most plants that are not mine-mouth power plants typically
have from one to three favored suppliers that account for
the bulk of their coal.
• Very few facilities have adopted a strategy of making many
small «10,000 ton) coal purchases.
In the absence of these trends, the number of coal mines and coals that
would have to be evaluated for their washability characteristics would esca-
late significantly. The number of small coal purchases indicated by Fig. 10
appears to be significant. However, as Fig. 11 shows, the total tonnage of
coal involved appears to be all but insignificant, with the exception of
facilities D and E. Based on these considerations, it would not seem neces-
sary to evaluate any but the large (>10,000 ton) coal purchases.
4.4 EMISSIONS WITH FULL CLEANING
This study's guidelines recognized that the utilities should be free to
determine their own optimal supply strategy. Consequently, the estimated
emissions for the fully cleaned coal were based on the reductions that could
be achieved by a PCC Level 4 plant recovering 80 percent by weight (wt %) of
the ROM coal from the power plant's principal supplier. The amount of coal
provided by the principal supplier varied from 23-100% of the power plant's
feed, but on the average it was 62%. It should be noted that two plants (L,D)
failed to properly complete their FERC Form 423s and could not be included in
this study. Plant W burns an unusually high-quality coal that showed an
increase in sulfur content with washing because of a combination of low
pyritic-sulfur content and Btu losses in cleaning. There seems to be no
logical reason for considering this coal further in a washing strategy.
Lastly, it was not possible to adequately characterize the principal coal
feeding plant X.
The emissions rates for 20 utility power plants appear in Fig. 12. The
first bar (identified as "1980 Emissions") in each figure indicates the total
1980 emissions from all coal mines and all coal purchases regardless of size.
The second bar ("Major Coal ROM") results from considering the single largest
supplier mine for each power plant in 1980 and using the anticipated emissions
rate for that coal if it were at the mean value for the given seam and county
(see Appendix A). The difference between this value and the "1980 Emissions"
bar reflects a combination of several factors:
• Averaging properties from all the coal purchases,
• Departures of the ROM coal from the mean value for the
seam, and
• Existing application of some level of PCC techniques to the
coal.
-------
£ i 10 KTONS
Fig. 10 Number of Power-Plant Coal Purchases
-------
•*J
H-
OQ
O
O
01
H
O
§
Pi
- (0
O
0>
TO
-
K1ONS OF COAL PURCHASED
M H » "
S 8 S S
K1ONS Or COAL PURCHASED
A v
So
z *
o 3r-
KTONS Of COAL PURCHASED
I ! I i
0
«
(D
-------
o
10 «
i-
|H
I
45
PLANT A
i
PLANT B
w,
i
PLANT c
W'-
y//.
//A
'
1980 MAJOR CLEANED CLCANCO
EMISSIONS COAL ROM 87.57. 80r.
fig. 12 Sulfur Dioxide Emissions Rates for
Selected Utilities
-------
o
•» 4-1
1
1
p
46
PLANT £
PLANT F
1
1
PLANT G
r4';l
1
^
Y/.'/l
0/A
m
•'///A
K: ->:/l
^>/H
* / / f*
'//A
/ / / A
///A
1980 MAJOR CLEANED CLEANED
EMISSIONS COAL ROM 37,57. eor:
Fig. 12 (Cont'd) Sulfur Dioxide Emissions Rates
for Selected Utilities
-------
j
a
n
47
PUNT H
3
D I
o
tn
2£3
%
M
///'\
PLANT
v//A
/A
//
/A
^//A
• / // 4
'///A
|H
o
"> .4
j-
PLANT J
1980 MAJOR CLEANED CLEANED
EMISSIONS COAL ROM 87.sr. scr.
Fig. 12 (Cont'd) Sulfur Dioxide Emissions Rates
for Selected Utilities
-------
48
PUNT K
1
1
| '
PLANT M
.•
'"'A
m
2
PLANT N
n
ty/A
V//A
-------
o
"> 4-1
1-
o
«" t-i
49
PLANT 0
i
i
PLANT P
/ ' ' •
V/xVl
PLANT Q
1980 MAJOR CLEANED CLEANED
EMISSIONS COAL ROM 87.53 607.
12 (Cont'd) Sulfur Dioxide Emissions Rates
for Selected Utilities
-------
j»
m
2
O
«i
^
50
PLANT R
PLANT S
V/A
22;
PLANT T
S.'7/A
1960 MAJOR CLtANCO CLEANED
EMISSIONS COAL ROM 87.57. BCT.
Fig. 12 (Cont'd) Sulfur Dioxide Emissions Rates
for Selected Utilities
-------
o
"> 4-1
51
PLANT U
PLANT V
1980 MAJOR CLEANED CLEANED
EMISSIONS COAL ROM 87.57. 80S
Fig. 12 (Cont'd) Sulfur Dioxide Emissions Rates
for Selected Utilities
The first two of these factors could either increase or decrease the
difference, while the third factor will almost always decrease the "1980
Emissions" bar.
A computer code that predicts PCC plant washing performance for
specific coals was then employed (further discussion of the code is found in
Appendix B). The results of this code show that the pyritic sulfur that can
be removed by PCC plants when washing to the 80% recovery level will fall in
the range of 0-50% of the total sulfur content of the coal, with an average
value of 29%.
-------
52
4.5 COMPARISON OF PCC AND PARTIAL FGD COSTS
The costs of PCC and partial FGD* were compared by calculating system
costs on the basis of the dollar cost per ton of S02 removed ($/ton SO™). The
coal-cleaning model is described in Appendix B, while the FGD model is based
on design studies using the TVA Shawnee code, as summarized in a recent EPRI
study. The following assumptions were made in these models:
• Economics were based on November 1982 dollars.
• ROM coal was assumed to have a base selling price at the
mine-mouth of $28.15/ton for a 10,678 Btu/lb heating-value
coal typical of the Illinois basin.^ Adjustments made to
account for the heating-value variation among the coals
considered were calculated at ($2.60/ton)/10^ Btu.
• Two PCC Level 4 plants were considered. One recovered
87.5% by weight of the coal, and the second recovered 80%
by weight of the coal.
• The PCC plant was assumed to be available for 3000 h/yr of
operation. The remainder of the time could be used for
maintenance activity.
• A single conservative shipment rate of $4.64/ton was used
for PCC plants that were not mine-mouth operations. This
was the mean value from a recent survey of shipment costs
for 36 midwestern utilities' coal contracts.
• A constant cleaning cost of $4.74/ton (1978 dollars subse-
quently adjusted to $6.87/ton in November 1982 dollars) was
used for the 80% recovery PCC Level 4 plant.
• The emissions rate for the 80 wt % coal-recovery Level 4
PCC system served as the design base for the FGD system.
• The base FGD system consisted of 500 MW of scrubbed capa-
city and used four modules of 167 MW-equivalent scrubbing
capacity. Three modules are needed in constant operation
with a fourth on standby. No adjustments were made for FGD
system availability.
*The FGD system would treat only the partial volume of flue gas — 32% on the
average — that if scrubbed with 90% efficiency and mixed with unscrubbed gas
would yield the same net emissions as are obtained firing cleaned coal.
-------
53
• Adjustments to the FGD base capacity were made using a
power factor of 0.8. No system was permitted to exceed 750
MW or be smaller thn 375 MW.
• The FGD system retrofit increased the base cost by 30%.
• The FGD system was assumed to operate at 90% efficiency.
This eliminated reheat requirements by permitting a large
fraction of the flue gas to bypass the FGD system.
Details of the resulting cost comparisons based on these assumptions appear in
Appendix C. A summary of these data appears in Table 11. The general conclu-
sion to be drawn is that, for 50% of these power plants, PCC is more cost-
effective than FGD in meeting the minimal sulfur reductions set forth by the
base conditions. A more detailed trade-off study would be needed for another
one-quarter of the plants, while PCC appears to be less cost-effective for the
remaining plants. Thus, there is not a clear advantage in employing either
technology. This is due largely to the wide variations in coal cleanability
and the limitations (relative to FGD) on sulfur removal attainable through
existing PCC technology. Consideration of other factors, such as effects on
power-system availability, waste-disposal concerns, and overall level of S02
reductions needed, is necessary before a control strategy can be formulated.
In addition to these technical factors, regulatory and institutional concerns
can be expected to play an important role. These concerns are discussed in
Chapter 5.
4.6 STATEWIDE SULFUR REDUCTIONS
The total S02 emissions with and without coal cleaning are shown in
Fig. 13 for Ohio, Indiana, and Illinois. Within a 95% confidence limit, there
do not appear to be any statistically significant state-by-state variations
with respect to total sulfur reduction (at 80 wt % recovery), PCC costs, or
FGD costs.
The figure clearly shows that power plant S02 emissions in each state
are lower than those that would result if only the principal coal were burned
with its ROM sulfur content. Note that in Indiana the total emissions are
heavily influenced by two plants that already purchase cleaned coal.
Consequently, the Indiana 1980 emissions closely resemble those for cleaning
at 80 wt % recovery.
In addition to cleaning, many plants buy coal from multiple sources.
Much of the coal purchased to supplement the principal coals is lower in
sulfur content, thereby reducing the annual totals still more on a statewide
basis. However, those coals were not subjected to coal cleaning in this study
and hence should not be directly compared against the cleaning results.
-------
54
Table 11 Summary of PCC Sulfur Reductions, PCC Costs, and FGD Costs
PCC Level 4, 80 wt %
Plant3
A
B
C
E
F
G
H
I
J
K
M
N
0
P
Q
R
S
T
U
V
Average
% S Reduction
14.57
34.12
39.20
24.12
26.16
23.65
41.19
23.65
34.08
17.74
27.60
32.56
31.12
33.54
10.60
14.57
39.20
29.87
50.03
32.98
29.03
$/Ton S02
1366
354
616
1162
818
778
426
778
871
883
664
434
435
851
2057
1366
616
569
483
611
809
FGDb
($/Ton S02)
525
741
1090
978
814
746
979
589
1294
593
754
674
699
1162
649
630
976
598
1231
854
829
T
-»O
FGD
<80% +20%
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10 5
>120%
X
X
X
X
X
5
Plants D and L - Omitted because of improper FERC Form 423 reporting.
Plant W - Burns unusually high-quality coal.
Plant X - Inadequate washing data in USGS files.
This FGD system would treat the volume of flue gas that (if scrubbed
with 90% efficiency) could be mixed with the unscrubbed gas to yield
the same net emission as PCC.
-------
55
TOTAL SULFUR DIOXIDE EMISSIONS FOR 4 ILLINOIS PLANTS
O 1000-
USE OF ONLY MAJOR
COAL AT EACH PLANT
SO2 EMISSIONS (1
O
> o
C
AL
DAI
1
\^r
| S
£/
I
1980 ROM CLEANED CLEANED
EMISSIONS 87.5% 80%
1500-
vt
SO2 EMISSIONS (K TON
M 0
O 0
O 0
0*
p-
S
V
V
ALL V
COALS /,
V
USE OF ONLY MAJOR
COAL AT EACH PLANT
TOTAL SULFUR DIOXIDE EMISSIONS
FOR 8 INDIANA PLANTS
\/
I/
K
1
r/
T980 ROM CLEANED CLEANED
EMISSIONS 87.5% 80%
1500-
^?
z
O 1000-
^
S02 EMISSIONS (1
w
0
9 O
TOTAL SULFUR DIOXIDE EMISSIONS FOR S OHIO PLANTS
USE OF ONLY MAJOR
ALL COAL AT EACH PLANT
C<
DAI
s p
\
I
!
1980 ROM CLEANED CLEANED
EMISSIONS 87.5% 80%
Fig. 13 Total Sulfur Dioxide Emissions for
Illinois, Indiana, and Ohio
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56
5 REGULATORY AND INSTITUTIONAL CONSIDERATIONS
5.1 BACKGROUND
Fuel pretreatment was included as a "... technological system for con-
tinuous reduction of the pollution generated by a source ..." in the 1977
Amendments to the Clean Air Act. In EPA's promulgation of the utility-boiler
new-source performance standards (NSPS) in 1979,^ physical coal cleaning was
determined to be an acceptable method for achieving a portion of the
percentage reduction of S02 required. Reductions in sulfur content from fuel
pretreatment could be credited toward meeting the requirement for greater than
70% reduction. Utilities have not typically considered the addition of coal
cleaning as part of a 1979 NSPS-compliance strategy, since the use of an FGD
system would be necessary in any case to achieve compliance with the
percentage-reduction requirement. Utilities may have decided that the cost
and effort needed to gain credit from washing coal was simply not economical.
Portions of the utility industry are supporters of the virtues of coal
cleaning. The Electric Power Research Institute (EPRI), for example, not only
has funded a coal-cleaning test facility, but has become an active proponent
of the advantages of cleaned coal to utilities. EPRI noted that less than
20% of the coal used annually by the utility industry is cleaned, despite the
benefits EPRI perceives in cleaning coal — lower shipping costs, improved
boiler operation, and reduced sulfur emissions. If cleaned coal is used to
augment scrubbers, EPRI argued that the performance of the FGD is improved and
some of the operating costs (sludge disposal, limestone) are reduced.
American Electric Power (AEP) has also been quoted as "... enthusiastically
endorsing coal cleaning." AEP, however, was enthusiastic over the use of
cleaned coal for improving the performance of boilers and the availability of
power plants, not over the sulfur-reduction potential of cleaning. AEP stated
that it would be "... cheaper to buy high-quality cleaned coal to get peak
availability from existing plants than to build new plants to replace what is
lost to bad coal."16
More recently, congressional activity in the area of legislation to
control acid rain has focused attention on strategies for S02 reduction,
including coal washing. Several of the many bills introduced into the 97th
Congress (e.g., H.R. 4829, the Moffett Bill) specifically referred to precom-
bustion fuel cleaning as an approach to emission reduction. Congressional
debate had indicated an interest in a mandatory coal-washing policy, but no
bill specified such pretreatment as a requirement. In most cases, the pro-
posed legislation gave states in the Acid Rain Mitigation (ARM) region — 31
states east of the Mississippi plus Iowa, Missouri, Arkansas and Louisiana —
significant flexibility in choosing S02 reduction methods. Proposed
legislation to control acid rain was introduced into the 98th Congress.
Again, coal washing is an optional strategy for S02 reduction but not a
requirement. Congressional interest in the sulfur removal possible with coal
-------
57
washing may be reviving. For example, the Congressional Research Service has
recently initiated a study of coal washing — costs, SC>2 reduction potential,
market forces, etc.
5.2 CONSTRAINTS ON VOLUNTARY USE OF CLEANED COAL
There are a number of potential constraints on the widespread voluntary
use of coal-cleaning — those that involve possible institutional limits on
the expansion of the coal-cleaning industry and those that involve the limits
to the acceptability of cleaned coal by the utility industry. Among the most
obvious problems facing the coal-cleaning industry are the lack of demand for
the product and the major capital-investment requirements for construction of
a new cleaning plant. The low demand is a function of the costs of cleaned
coal (as noted in Sec. 3.1.9), possibly exacerbated by the current decline in
the demand for energy and the postponements and cancellations of proposed new
power plants. (For example, in 1977 the Energy Information Administration
projected a need for 242 GW of additional coal-fired generating capacity
coming on-line between 1980 and 2000. The most recent projection, NEP-3
[July 1980] has reduced the additional capacity needs to 181 GW.) The major
investors in coal-cleaning facilities are large coal companies and utilities.
Investment in a coal-cleaning plant by an independent entrepreneur seems
unlikely, unless a market for the product were more assured. In addition, the
likely economies of scale place smaller coal producers at a disadvantage,
making them unable or unwilling to invest in cleaning facilities.
There are additional constraints on the possible expansion of a coal-
cleaning industry that arise from environmental regulations. Coal-preparation
plants emit pollutants to air, water, and land in the process of cleaning
coal. Consequently, plants face both known regulations (e.g., air-quality
NSPS limiting particulate-matter emissions, water-quality limits on toxic
effluents) and possible future regulations (e.g., if coal cleaning waste is
classified as hazardous under RCRA, significant costs will be associated with
safe disposal). Not only is there uncertainty about the environmental regula-
tions with which the cleaning plant must comply, there is uncertainty about
the future of regulations for the potential customers of the cleaned coal.
The uncertainties in this case range from possible Congressional revisions to
the Clean Air Act (e.g., making the Act less stringent by dropping the
percentage-reduction requirement or making it more stringent by adding acid-
rain controls) to variations in EPA's implementation (e.g., requiring revi-
sions to make state-implementation-plan [SIP] emission limits more stringent
in nonattainment areas or allowing SIP revisions to relax emission limits in
attainment areas).
Although coal cleaning has long been used for removing ash and improv-
ing the Btu content of coal, utilities (or other sources of demand for washed
coal) appear to have a generally limited knowledge of developments in cleaning
technologies and the uses of cleaned coal as a sulfur reduction technique. A
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58
study conducted by Battelle Columbus for EPA included interviews with a number
of utility officials and concluded that "existing engineering/economic studies
of physical coal cleaning are believed to provide a wholly inadequate basis
for investment decision making." Even if a utility executive had adequate
knowledge to make an investment decision, the current tax status of the
investment might dissuade him. A utility's investment in a coal-cleaning
facility does not have the same tax status as an investment in an FGD system.
The latter is defined as a pollution-control investment, with such financial
advantages as accelerated depreciation and investment tax credit. On the
other hand, if independent coal companies were to invest in cleaning facili-
ties, the costs could be added to the fuel costs to the utility and possibly
become part of the fuel adjustment clause, passing the costs directly on to
the consumer. The pass-through of the costs is not a certainty, however; it
would depend on the decision of a public utility commission.
5.3 OPTIONS FOR INCREASING THE USE OF CLEANED COAL
If it is assumed that cleaning coal is a useful method for reducing SOo
emissions and that it is desirable to encourage the use of cleaned coal in
coal-burning facilities, then there are a number of policies that could be
initiated by the federal or state government either to encourage or to require
the increased use of cleaned coal.
5.3.1 Policies to Encourage the Use of Cleaned Coal
Encouraging an expanded supply of and demand for cleaned coal by pro-
viding incentives is difficult and not likely to be effective in the short
run. Following is a list of some actions the state or federal government
could take to overcome some of the barriers to an expansion of the coal-
cleaning industry:
• Provide loan guarantees for the construction of coal-
cleaning plants
• Provide tax incentives or direct subsidies
• Clarify the acceptability of the additional costs of
cleaned coal for a fuel adjustment
• Undertake a substantial publicity (i.e., public informa-
tion) program
• Provide price guarantees for the cleaned coal
• Reduce uncertainty in the market by stabilizing SIP regula-
tions.
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59
Other possible actions could be taken at the federal government level:
• Alter the current IRS approach and allow coal-cleaning
plants to be treated as pollution-control investments
• Set a time period for a moratorium on changes in NSPS
regulations, thus ensuring a more stable market
• Consider incentives to coal cleaning in the proposals for
an industrial-boiler NSPS.
The actions listed above all work through encouraging the supply of and demand
for cleaned coals, and all assume that the demand for cleaned coal will exist.
If this assumption is not valid, the government will find itself locked into a
position of permanent subsidization of an industry, which seems unlikely to be
a cost-effective approach to reducing SC^ emissions. In some cases, the
actions would require the commitment of an indeterminate amount of public
funds to support one industry. Considering the current depressed economy,
large federal deficits, and declining state revenues, it seems unlikely that
such government action will take place.
The Environmental Protection Agency could review possible actions to
encourage coal cleaning, although the EPA has limited statutory authority
available for requiring the use of cleaned coal. According to the Clean Air
Act Amendments (Sec. Ill), the EPA is empowered to set standards of per-
formance for new sources, but not to require any specific control technology.
EPA's allowance for crediting fuel pretreatment toward the percentage removal
requirement of the 1979 NSPS could be viewed as a policy of encouragement. In
addition, the agency could:
• Review and simplify the procedures required for monitoring
coal samples and determining S02 removal efficiency.
• Set a higher limit on the minimum lot—size subject to
sampling (The current NSPS sets a lot size as the weight
of coal processed in 24 hours; if more than one coal is
treated in a single day. a sample of each type must be
collected and analyzed.)
• Encourage the inclusion of a requirement for cleaned coal
in an SIP, by preparing control guidelines for reasonably
available control technology (RACT) for SC^, indicating the
potential clean-up from washing coal and the acceptability
of such an SIP attainment strategy.
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60
5.3.2 Policies to Require the Use of Cleaned Coal
Another set of policies could be undertaken to require the use of
cleaned coal. Congressional action as part of acid-rain legislation could
establish a mandatory coal-washing policy. The most likely governmental level
for action to increase the use of cleaned coal is, however, at the state
level. State air-quality-control agencies could make the SIP requirements for
existing coal-fired facilities more stringent or require a percentage reduc-
tion from a base year of emissions. The justification for such an action
would need to be the protection or enhancement of air quality in the state —
to bring a nonattainment area into attainment, to protect a PSD increment, to
provide a growth allowance for future sources of SC^ emissions, or to protect
sensitive ecosystems. Increasing the stringency of SC>2 regulations would not
necessarily lead to an increased use of washed coal, however. Lower-sulfur
coal could be purchased and blended. In the midwestern states reviewed in
this study, a requirement to use local coal might be necessary to avoid the
increased use of out-of-state lower-sulfur coal. A local coal requirement
would likely require action by the state legislature.
Depending on the statutory power of a state regulatory agency, a
specific requirement for use of washed coal in utilities could be made (action
to revise state codes might be necessary in some states). Regulations could
be promulgated to:
• Require a percentage reduction of sulfur by washing for all
sources. Such a requirement might be technically infeasi-
ble for all the coals in a state or might be very ineffi-
cient in terms of Btu losses. Therefore, limits need to be
set.
• Require the removal of x% of sulfur, if uncontrolled
emissions are > y Ib S02/106 Btu and if < z% loss in Btu
occurs. If the coal cannot be washed to x%, or if the raw
coal is already low in sulfur content, or if significant
losses in terms of Btu content will occur, then the
requirement will not be enforced.
• Set an emissions cap for each power plant in the state. An
emissions cap would need to be carefully chosen, such that
the use of washed coal would be encouraged. This option is
a combination of mandatory and incentive approaches.
• Set regulations for each source. The results of this study
suggest that a source-specific regulatory strategy would be
the most effective choice for The states and utility plants
reviewed. This alternative would place heavy demands on
the staff of an agency. Moreover, in the absence of a
local air-quality problem (such as nonattainment) or of a
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61
federal requirement for states to reduce SC^ emissions
(such as proposed in the acid-rain bills in the U.S.
Congress), a selective regulatory action could face serious
problems of acceptability. Equity issues could be referred
to in an initiative that would require one power plant to
use washed coal, increasing the costs of its fuel, while
another power plant would not be so required.
An effort to implement a mandatory coal-washing policy was undertaken
in Ohio, starting with the 1979-80 legislative session. A number of bills
were discussed at the committee level, but none were reported out of the
committee for consideration by the General Assembly. The bills proposed
revising the state code, allowing the director of the state EPA to require
coal washing by all the utilities. The director was to issue specific coal
ashing standards for each source, giving consideration to "... whether the
requirement of such action would be technically infeasible or economically
unreasonable and whether the costs of such requirements would be dispropor-
tionate to the benefits to be derived therefrom." Initially the Ohio EPA
had considered including industrial boilers in the proposed requirement, but
instead decided to concentrate on utilities. A number of utilities and small
coal producers objected to the proposed bill. The agency has not revived the
proposal, since there has been a substantial voluntary increase in the use of
washed coal by the utility companies in the state.
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62
6 CONCLUSIONS
6.1 DATA ON POWER PLANTS' COAL USAGE
The selection of power plants for study and determination of their coal
supply characteristics was accomplished with the aid of reports and data bases
available from the U.S. Federal Energy Regulatory Commission, the Energy
Information Agency, and the Bureau of Mines. In most cases, these data were
adequate to identify the mines supplying each plant, to establish coal-
purchase patterns, and to predict S0~ emissions corresponding to the delivered
coals. Unfortunately, two plants with relatively high S02 emissions reported
coal-purchase data in such a way that the specific suppliers could not be
identified. These plants had to be dropped from consideration in the study.
Two other plants were also dropped: one because it fires coal that is not
amenable to cleaning, and the other because its source of raw coal could not
be adequately characterized. This left 20 plants for evaluation.
The coal-purchase data revealed that:
• Power plants, even mine-mouth facilities, typically buy
from several suppliers.
• Most plants have one to three suppliers that account for
the bulk of their coal; on the average, 62% of the coal for
a given plant comes from a single source.
• Most plants buy coal in lots of 10,000 tons or more.
• Total annual S02 emissions (a function of plant size, coal
characteristics, and capacity factor) vary over a range of
about 6.75 to 1 among plants.
The last fact listed implies that significant emission reductions could be
obtained through application of coal cleaning (or other controls) to only a
subset of the plants included in this study.
Most of the plants already have S02 emissions lower than are predicted
from run-of-mine characteristics of the major coal purchases. In some cases,
this is due to small purchases of low-sulfur coal for blending. However,
analysis of delivered-coal versus raw-coal characteristics indicates that some
degree of coal cleaning is being employed by many suppliers (approximately
one-third of the coal evaluated in this study). Details of the cleaning
processes are not generally available, although data on coal-cleaning equip-
ment installed at specific facilities are reported. We utilized those data,
together with the coal characteristics, to infer the cleaning level for each
coal. We concluded that very little coal is receiving the extensive cleaning
modeled in this study (see Fig. 9), so no attempt was made to develop incre-
mental S02 reductions for changing from coarse to full beneficiation.
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63
6.2 EMISSION REDUCTIONS DUE TO COAL CLEANING
The principal coal (i.e., the coal from the single largest supplier)
was identified for each power plant and subjected to a washability analysis.
The computer model used is based on a typical Level 4 cleaning plant flow-
sheet, and no optimization was attempted for specific coals. In commercial
practice, cleaning plants are generally unique, being designed with particular
coals and markets in mind. Thus, some performance improvements over those
predicted here may be possible, although it is not feasible to make any
quantitative estimates at this time.
A larger uncertainty in the results stems from the observed variations
in coal washability, even for coal samples from the same seam and mine. Where
possible, we used washability data obtained using coal samples from the
particular mine supplying the principal coal. In other cases, the closest
possible match was at the county and coal-seam level. More accurate predic-
tions would require extensive sampling and washability analysis of coal yet to
be extracted at each mine.
The average sulfur reduction predicted was about 29%, with a standard
deviation of 9.9%. The minimum reduction was only 10.6%, while a 50% reduc-
tion was predicted for one coal. Differences in the fraction of the sulfur
occuring as pyrites and in the size distribution of the pyritic particles
account for most of the variation. The degree of reduction also depends
somewhat on the weight recovery of coal in the cleaning process (i.e., how
much coal the operator is willing to throw out along with the unwanted mineral
matter). We investigated both 80% and 87.5% weight recovery and found that
the lower recovery improved the sulfur removal by an average of about 22% over
the higher value. Our results are thus based on 80% recovery, which is within
the range of accepted commercial practice.
6.3 COAL CLEANING VS. PARTIAL FGD
The costs for sulfur dioxide control by PCC (in terms of $/ton S02
removed) were compared with those for limestone-slurry FGD. It was assumed
that the FGD systems would be designed to meet, but not improve on, the S02
emissions rates set by PCC. This was accomplished by specifying FGD systems
sized to treat only a portion — 32% on the average — of the flue gas at an
S02 removal rate of 90%. When this portion of the gas stream was mixed with
the untreated gas, the net effect was the same as for combustion of cleaned
coal. A 30% increase in FGD system installed cost was used to account for
retrofit difficulty.
The comparison indicated that:
• PCC is more cost-effective than FGD for 50% of the plants,
• PCC and FGD costs are comparable for 25% of the plants,
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64
• FGD Is more cost-effective for the remaining 25% of the
plants, and
• There are no statistically significant variations (at a 95%
confidence level) in percentage sulfur reduction, PCC
costs, or FGD costs among the three states included in this
study.
Costs (in 1983 dollars) for PCC ranged from $354 to 2057/ton S02, with
an average of $809/ton SC^. For FGD, the range was $525-1294/ton SCU, with an
average value of $829/ton SC>2« While these costs are indicative of the values
and variations that could be expected, they have not been adjusted for site-
specific technical and economic factors that could significantly affect the
results in any given case.
Other factors should also be considered in comparing PCC and FGD.
Specifically, PCC can:
• Reduce coal-transportation requirements (reduced secondary
emissions and public safety hazards),
• Produce a more uniform fuel,
• Improve boiler efficiency by reducing slagging on boiler
tubes,
• Reduce load factors for ash-collection and handling systems
(as well as any existing FGD systems), and
• Improve overall plant availability.
In contrast, FGD systems can:
• Accommodate coal switching and
• Achieve much higher sulfur reductions than PCC.
Furthermore, PCC plants can be (and generally are) constructed at a mine or
central location independent of any particular consumer. Assuming that there
is a sufficient market for the cleaned coal, this removes the economic con-
straint encountered in retrofitting new control equipment (e.g., FGD systems)
on older plants.
6.4 REGULATORY AND INSTITUTIONAL CONSIDERATIONS
The existing use of coal cleaning is fairly widespread, but it is not
directed primarily at sulfur reduction. Voluntary application of "deep"
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65
cleaning techniques such as those modeled in this study is likely to be
constrained by a number of factors, including:
• A less favorable tax status for PCC plants as contrasted to
FGD systems,
• Lack of an assured, stable market for the coal,
• Major capital investment requirements,
• Economic disadvantages (scale factors) for small producers,
• Uncertainties regarding future environmental legislation
and impacts of existing regulations under the RCRA, and
• A perceived lack of adequate data for investment decision-
making .
A number of possible measures to encourage the voluntary use of cleaned coal
were suggested in Sec. 5.3.1. These included such actions as loan and price
guarantees, changes in the tax laws, and stabilization of regulations for a
guaranteed period of time. None of these measures is likely to have much
effect in the short term, and those requiring commitment of government funds
would almost certainly be difficult to legislate.
Requirements for coal cleaning have been proposed at the federal level
as part of acid-rain legislation. While these are still under consideration,
the most likely governmental level for implementing a cleaning requirement is
the state level. State Implementation Plans could be revised to:
• Require a percentage SC>2 reduction for all sources,
• Set an emissions cap for each power plant,
• Require a percentage removal of sulfur if uncontrolled
emissions are greater than a threshold value, or
• Regulate SO* levels for each source individually.
Application of any of these measures could promote the use of cleaned costl.
However, the regulations would have to be flexible and applied with care to
avoid driving certain coals (and coal producers) from the marketplace because
of poor cleanability. Furthermore, actions involving emissions caps could
stimulate the transportation of low-sulfur coals unless requirements for
"local" coal use were also enacted. Experience in Ohio has indicated that it
is quite difficult to put together an acceptable legislative/regulatory
package.
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66
In conclusion, coal cleaning has the potential for significant sulfur
reductions when applied to many of the coals now being used in the study
region. The technology should be considered in formulating any SC>2 control
strategy, but problems arising from coal variability, limited efficacy as
compared to FGD, and multiplicity of coal suppliers make a universal cleaning
requirement difficult to design and implement.
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67
REFERENCES
1. Nielson, G., Ed., 1981 - Keystone Coal Industry Manual, McGraw Hill, New
York (1981).
2. Jones, R., and M. Jones, The Effect of Coal Cleaning on the Quantity of
Sulfur Dioxide and Ash Produced by Coal-Fired Power Generation in the
Northeastern United States, U.S. Department of Energy Report,
DOE/ET/12512-2 (May 15, 1982).
3. Argonne National Laboratory and Bechtel Corporation, Environmental
Control Implications of Generating Electric Power from Coal, Argonne
National Laboratory Report, ANL/ECT-3, Appendix A, Part 2 (Dec. 1977).
4. Environmental Control Implications of Generating Electric Power from
Coal, prepared by Bechtel Corp. for Argonne National Laboratory, ANL/ECT-
3, Appendix A, Part 1 (Dec. 1977).
5. Doctor, R., Utility Flue Gas Desulfurization: Innovations and System
Availability, Argonne National Laboratory Report, ANL/ECT-11 (March
1982).
6. Laeske, B., Trends in Commercial Application of FGD Technology, EPA/EPRI,
7th Symp. on Flue-Gas Desulfurization, Hollywood, Fla. (May 17-20, 1982).
7. Dunlop, W., Economic and Design Factors for Flue Gas Desulfurization
Technology, Electric Power Research Institute Report, EPRI CS-1428 (April
1980).
8. Economic Indicators, Chemical Engineering 30(1) (Jan. 10, 1983).
9. Coal Outlook, Pasha Publications, Washington, D.C., 5(46) (Nov. 29,
1982).
10. Phillips, P.J., et al., Coal Preparation for Combustion and Conversion,
Electric Power Research Institute Report, EPRI AF-971 (May 1978).
11. Coal Outlook Supplement, Pasha Publications, Washington, D.C., 5(40)
(Oct. 18, 1982).
12. Burhoff, J., et al., Technology Assessment Report for Industrial Boiler
Applications: Coal Cleaning and Low Sulfur Coal, U.S. Environmental
Protection Agency Report, 600/7-79-178c, p. 338 (Dec. 1979).
13. 42USC 1857 et seq., Sec. lll(a)(l).
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68
14. 44 FR33580 - 33624, NSPS: Electric Utility Steam Generating Units (June
11, 1979).
15. Lihach, N., More Coal Per Ton, Electric Power Research Institute Journal,
pp. 6-13 (Jan. 1981).
16. Blackmore, G., Coal Preparation Improves Utility Efficiencies, Coal Age,
pp. 70-77 (Jan. 1981).
17. DDE/Office of Policy, Planning, and Analysis, Energy Projection to the
^ear 2000, U.S. Department of Energy Report, DOE/PE-0029 (July 1980).
18. Use of Coal Cleaning for Compliance with SO* Emission Regulations,
prepared by Battelle Columbus Laboratories, for U.S. EPA/IERL, PB81-
247520 (Sept. 1981).
19. Bill to Enact Sec. 3704.17 of the Revised Code, 113th General Assembly,
Regular Session (1979-1980).
20. Private Communication with Staff of Ohio Environmental Protection Agency
(March 2, 1983).
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69
APPENDIX A
COAL DATA BASE
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71
As a result of work performed at Argonne National Laboratory using the
large analytic and reserve coal data files from the United States Bureau of
Mines (USBM), it was decided to facilitate future coal studies by organizing
these data in a manner that would allow for quicker and easier retrievals by
computer. Therefore, the complete USBM analytic and reserve data files (6.9
megabytes of data) were stored in 1978 in an interactive data base (this
provides for data current as of 1976).
o
In a related effort, coal-washability and coal-reserves data were
integrated to match reserves and washability whenever possible. Two computer
programs were developed to match the appropriate entries in each data set and
then merge the data into the form presented in the report. Approximately 18%
of the total demonstrated coal reserves were matched with washability data.
Moreover, about 35% of the reserves that account for 80% of current production
were successfully matched. Each set of merged data specifies the location and
size of the reserve, selected physical and chemical characteristics of the
coal, and washability data at three crush sizes (1.5 in., 3/8 in., and 14
mesh) and several specific gravities. In each case, the percent recovery,
Btu/lb, percent ash, percent sulfur, and Ib SC^/IO Btu are given. These
data, combined with the mine-specific information that appears in Tables A.l-
A.5, served as the basis for this report. The tables include data for 53
mines that were principal suppliers to those plants in Illinois and Indiana
(with a few in Ohio) that are part of the FERC midwestern distribution grid.
The mine identifications were obtained from the FERC regional office in
Chicago, with supplementary information from Ref. 1.
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Table A.I Available Preparation Equipment for Coal Mines in Illinois
Plant
Number
1
2
3
4
5
6
7
8
9
in
II
12
13
1'.
IS
Locat ton
of Mine:
County
(Nearest
City) Seam
Wahash »">
(Keens-
burg)
Montgomery 16
(Coffeen)
Jefferson 16
(Walton-
vllle)
Williamson 16
(Marlon)
Macoupln 16
(Carl 1ns-
vllle)
Macoupln 16
(Albera)
Christian »6
(Pawnee)
Randolph 16
(Marlssa)
St. Clalr 16
(Marlssa)
Saline 15,16
(llarrls-
burg)
Randolph 15,16
(Percy)
Randolph 16
(Percy)
Douglas '6
(Murdock)
Williamson ?
(')
Macoupln ?
Mine
Wahash
Illllsboro
Orient 13
Orient »4
Monterey
11
Monterey
12
Mine 110
Baldwin
fl
River
King 16
Central
Prepara-
tion
Plant
Captain
Stream-
line
No. 5
Mine
No. 4
Mine
Ca r t e r
Available Preparation Kqulpment
«l WO -V U
r4 3 O V «
«j.u So«'SSS" * £ K
*-*'5S!»j:'3IJ'2u2«i>''u2«
Company Cle.mlnp, xmoai/iaM^oou.'nXHU.o
Amax Coal 2-1 XXX
Co.
Consoll- I
dated Coal
Co.
Freeman 2-3 X XXX XXX
United Coal
Co.
Freeman 2-3 XX XXX
United Coal
Co.
Monterey 2-iXXX X XX X X
Coal Co.
Monterey 2-3 XXX X XX X X
Coal Co.
Peabody 2-3 X X X X
Coal Co.
Peabody 1
Coal Co.
Peabody 1
Coal Co.
Sahara 4-5 X XXX XX X X
Coal Co.
South- 2-3
western
Illinois
Coal Co.
South- 2-3 XXX X X
western
Illinois
Coal Co.
/legler 1 X X
Coal Co.
Zlegler 2-3
Co.il Co.
? 2-3
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Table A.2 Available Preparation Equipment for Coal Mines in Indiana
Plant
Nnmtwr
r
2
3
4
5
6
7
8
9
10
U
12
13
14
15
16
17
1ft
19
of Mlnr:
Count y
(Nr.iri'Sl
City) So.im
Plkf '
(Srlvln)
Clay 111
(Brazil)
Sullvan V1.V11
(Sul Ivan)
Warwick VI
(Chand ler
Knox 1
(Evans-
vltle)
Knox 7
(F.vana-
vllle)
Veralllton 7
Pike ?a
(Velpen)
Warwick VI, VI I
(Warwick)
Pike (Oak- V
land City)
Pike (Oak- Vb
land City)
Greene VI
(Carlisle)
Greene 7
(Dugger)
Verallllon VI
(Universal)
Warwick V
(Lynevllle)
Vlgo 7
(Terre
Haute)
Pike
Pike
Duhols (In
eastern KY
and U. Va.)
Mlnr
Alihol t
Clilnook
Ml nnehjha
Ayrshire
Blcknell
Pit 11
Apraw
Lee
Velpen
Tell City
Old Ben
11
Old Ben
12
Hawthorne
Sycamore
Universal
Lynevllle
1 & 2
Pit *1
Enos
Marlah
Hill
-
•n u -t
Z "3 g |g
ivir^-^^'-^I^^liS.rlsS
Company Clr.inlnR s*jj2£uS*3£. SSS.gj.w
AnTmti 1
Co.il anil
Kitrrgy (.0.
Aroax Coal 1 XXXX XX X
Co.
.ana* i.o.,1 1 XX XXX
Co.
Amax Coat I- ) XXXX XXXX
Co.
Blcknel! 1
Mineral fl
Co.
Black 4-5
Beauty Coal
Co., Inc.
Cambridge 1
Hopf Mining 1
Co.
Ohio Valley 1
Coal
Old Ben 1
Coal Co.
Old Ben 4-5
Coal Co.
Peabody 2-3 X XX
Coal Co*
Peabody 1
Coa 1 Co .
Peabody 1 X X XX
Coal Co.
Peabody 2-3 XXX XXX
Coal Co.
S&G 1
Excavating
Closed 1
Closed 4-5
DM. Con) 1
OJ
FlvP seams mined In county
''Lower Mlllcnhnrp,
-------
Table A.3 Available Preparation Equipment for Coal Mines in Kentucky
Plant
Number
1
2
3
6
5
6
7
Locat ion
of Mine:
County
(Nearest
City) Seam
Muhlenberg ?
(Central
City)
Muhlenberg 19
(Green-
ville)
Ohio 19
(Center-
town)
Ohio 19,11,13
(Beaver
Dan)
Ohio 19
(Beaver
Da.)
Hopkins 16
(Hadlson-
vllle)
Ohio T
C t) U
M ft. u • M jo « <« -^ £e
u « « c: e • 4 c ~4 u « u
«^£b«-H«l-4Ot.« >. j< • ft*
Level of §E 2 £>S^'3^US^"SS5w
Mine Company Cleaning 2 » " « « » H < <-> <-> •• ~> » P to °
Glbralter Peabody 1
Coal Co.
River Peabody 2-3 XX XX
Queen Coal Co.
Alston Peabody 1
Coal Co.
Homestead Peabody 1 X
Coat Co.
Ken Peabody 4-5 X X X X X X
Coal Co.
Donbov Tower 4-5
Resources
Inc.
ElmCrove Closed 1
-------
,0 3D -J 0* iji *«• Ul f"J -*
3? 3? |f «»£ o| >jf of 3? ». sir
S i S. £° ST !r 5 — § 2.3 a? <* ^ ' 2
S " ti ~3 S 3 ° " s s i" I
Bl « '3 *-**«• 3 TC a
5 -" i •
7P ; si":: 3s" sz *z z
r 1 IT 3- 3-
1
owso z > ^ jj 5" •* ?
si* 1? !• 3 •a vs- *s s
?r ^ •« a w • » ^
fc N 1 J ff
N> 3 O
~* "*O*O O» OS 0»0 O"*O b»« — 0
. O e • 01 a» a atn ffc: ?£ s= 3 »
ffS- 5. ' ^3 2.S- | ?
a it • i » •
"ii1" " i ~ " i
J W
X
X
X X
X XX
X
X
X
X
z ~e
\ r
*3 ^»
° c o ° r
•» Z 0 -^ O
" *» e ^
^ o» 3 z »
1 >< 3 •*
a no
rr —3
A
3
*
3
n
a
"S
3
n r*
^ <
s —
3" o
H
0)
cr
1— >
>
*•
^
ft>
I j.
•«•
?
H
(t
T3
(U
H
1 03
Magnets
Breaker
Crusher
Dryer
Screens
Washing
Tables
Air Tables
Cyclone
Centrifuge
Flotation
Jigs
Heavy Media
Thickener
Filter
Other
>
a
?
M
l»
S
•1
§
n
s
f
3
rt
H-
O
3
t4
C
•o
3
3
rr
b
n
o
CB
-
H-
3
m
CO
3
O
y
o
-------
Table A.5 Available Preparation Equipment for Coal Mines in Pennsylvania
Plant
Number
1
2
3
Location
of Mine:
(Nearest
City) Sea* Mine
Greene Waynes- Boyle
(Greens- burg
burg)
Allegheny Pittsburgh Champion
(Imperial) 1
Greene Sewlckley Dunkard
(DIUIner)
Available Preparation Equipment
5 f g IB
sss 89. s a s D !; J s •,
Level °f g, 3 3 S, Z 'ma H o c o eoS^-ij:
Company Cleaning ^£iS«5H3o
-------
77
APPENDIX B
COMPUTER MODEL OF COAL PREPARATION
-------
79
B.I INTRODUCTION
Computer models for several levels of physical coal cleaning were
developed for Argonne National Laboratory by the Center for Energy and
Environmental Studies of Carnegie-Mellon University (Contract No. 31-109-38-
5236). The authors of the September 1979 study were C.N. Bloyd, J.C. Molburg,
D.R. Lincoln, and E.S. Rubin. This study surveyed four preparation levels,
from a simple crushing and sizing operation through complete heavy-media
washing (including intermediate-size coal and fines).
The essential parameter of coal preparation is overall plant yield, the
ratio of mass output to mass input of moisture-free coal. The Btu recovery of
the coal based on this parameter and the related production of hundreds of
thousands of tons of refuse annually for an average-size coal-cleaning plant
is the controlling parameter in the model. What follows is a description of
the computer model for the coal-preparation plant as found in the draft
report.
-------
80
3 COMPUTER MODELS OF COAL PREPARATION
3.1 INTRODUCTION
With respect to both economic and environmental consequences, the
essential operating parameter of coal preparation is overall plant yield.*
Since raw coal feed cost is the largest component of total product cost, the
amount of material discarded, as indicated by overall yield, must significant-
ly impact cost. The most evident environmental impact of coal cleaning is
the production of refuse. While reduced yield may be required to improve
the characteristics of prepared coal, it is necessarily accompanied by in-
creased refuse production. Therefore, overall yield has been chosen as a
principal variable for the models described below.
Using these models, specification of overall yield along with certain
coal-specific data is sufficient to estimate prepared coal characteristics
and cost for several plant configurations. These configurations have been
chosen as representative of coal cleaning practice over the usual range of
complexity for steam coal preparation. The simplest, or level one, plant
is limited to thermal drying to given specifications. A level two plant
washes only coarse coal, mixing the finer coal into the product without
preparation. In a level three plant some of the finer coal is washed, but
only in a level four plant are all coal sizes washed. These plants are des-
cribed in more detail following some discussion of coal preparation equipment.
3.2 MODELS OF COAL PREPARATION EQUIPMENT
3.2.1 Rotary Breaker
The rotary breaker product is regarded as run-of-mine feed to our coal
preparation processes. The most important characteristics of breaker operation
are the size distribution of the product stream and the fraction of material
*Defined here as the ratio of mass output to mass input of moisture-free coal.
-------
81
sent to refuse. Since the rotary breaking is taken to be part of mine
operation, the refuse is of no concern to the cleaning plant. The size dis-
tribution, however, is. The rotary breaker model must predict the size dis-
tribution of the product. That distribution may vary widely due to operating
parameters and coal characteristics. However, empirical evidence over a wide
range of coals and sizes suggests that the size distribution satisfies the
following relationship (Landers, 1946):
«
F(x) = exp[-(|-) ] (3_1)
0
where F(x) is the total weight fraction of material which will not pass
through a screen of opening size x. The constants, a and xo, are material
parameters which characterize the subject coal. The range of a is typically
0.5 to 2.9. The screen opening for which F(x) = 1/e = 0.3679 is x0. This
distribution works well to characterize broken or crushed coal. If F(x)
is known for any two values of x, a and x0, can be determined since
log[log(l/F(x))] is linear in log x with slope a.
For example, suppose F(4") = 0.09 and F(l/4") = 0.70. Then the frac-
tion of material which will not pass through 4" and 1/4" sieves is 0.09 and
0.70 respectively, and log [log(l/F(x))] = 0.0194 for x = 4"(log x = 0.6021)
and - 0.8099 for x = 1/4" (log x = 0.6021).
0.0194 - (-0.8099) . 0.8295 = 0>689 „„
~ 0.6021 - (-0.6021) 1-2042 _ l^ J
Then,
-1/2 -1/0-6S9
XQ = x[-£n F(x)] = 0.25[-£n 0.70] = 1.12" (5-3)
Therefore, the cumulative size distribution function for this example is
(x/1.12)0"689
F(x) = e - (5-4)
The weight fraction of material which falls in an interval from Xi to x2
is given by |F(x2) - '
-------
82
To verify equation 3-1, published size distribution data for 19 coals
were checked via least squares regression analysis for adherence to that
equation. The results indicated very close agreement with R^ from 0.9 to 0.99
and an average R~ of 0.98 for log log(l/F(x)) vs. log x.
A relationship between topsize (TS) and xQis expected since the size
distribution is naturally linked to the topsize. By regression analysis of
XQ for the 19 coals considered above, the following relationship has been
obtained
0.467
x = 0.897 TS (3-5)
The results of that regression indicate that £n x0 vs. in TS is linear with
R = 0.89S. Ideally, size distribution data will be available. However, in
its absence equation 3-5 may be used to estimate XG. Note that if one data
point other than x0 is available, it may be used along with equation 3-5 to
approximate the size distribution function. In the absence of any size data,
the parameter, a, may be estimated by
a = 0.4 •<• x0 (3-6)
This very approximate result was also obtained by examination of the 19 coal
sample and simply reflects the fact that F(x) approaches zero as x approaches
the topsize.
3.2.2 Crusher
The significant characteristic of crusher operation for our analysis
is the product size distribution. The discussion of this topic for rotary
breakers applies equally to crushers.
3.2.3 Washers
Since all washers rely on specific gravity differences, a single model
is proposed for all types. That model requires two types of data: coal-speci-
-------
83
fie washability functions and equipment-specific distribution functions. The
weight washability function, w(i , iSg), predicts the mass fraction of coal in
a given size interval, ix, with specific gravity in the interval iSg. For
example, if 15% of 1/4" to 3/8" coal particles have a specific gravity from
1.3 to 1.4, then
W(l/4"-3/8", 1.3-1.4) = 0.15 (3-7}
This washability data is required for all washed sizes.
If the size fraction from the previous example were washed at a speci-
fic gravity of 1.4 the expected mass yield of clean coal would be 0.15. How-
ever, equipment and operating limitations prevent all of the float from enter-
ing the clean coal stream. The distribution' curve for a specific washer indi-
cates the fraction of coal with a given specific gravity that enters the clean
coal stream. This curve will vary according to the washer design, method of
operation, and coal particle size. A typical distribution curve is shown in
Figure 3.1. Suppose, in the example just described, that the fraction of
coal with specific gravity 1.35 (the midpoint of interval iSo) which reports
to the clean coal stream is 0.75. Then the contribution to clean coal of par-
ticles in the size range ix is (0.75)(0.15)A0=o.113 m0, where mo is the total
mass flow rate of feed. Similarly, the total mass flow rate in the clean coal
stream is:
mc = I _Z K(ix, isg)« D(ix, isg) m0 (3-8)
ix isg
where D(ix, iSg) is the fraction of material in size interval ix and specific
gravity interval iSg reporting to clean coal. The midpoint of the specific
gravity interval may be used to locate the appropriate position on the abscis-
sa of the distribution curve.
Simplification of this result is possible through the use of cumula-
tive weight washability functions, which may be designated by W(TS, isg). This
-------
84
1.0
fraction
to
clean coal
0.5
0.0
SG
Figure 3.1 Distribution Function
1.0
fraction
to
clean coal
0.0
Figure 3.2 Ideal Distribution Function
-------
85
function indicates the fraction of coal with topsize TS which has a specific
gravity in range isg. If W(6",iSCT) = 0.37, then the fraction of coal which
will pass through a 6" screen and which has specific gravity in the range
designated by isg is 0.37. A cumulative distribution function may be simi-
larly defined. D(TS, isg) is the fraction of coal of topsize TS and in speci-
fic gravity range isg which enters the clean coal stream. With these func-
tions,
mc = _I K(TS, isg)- D(TS, isg)-BO (3-9)
It is important to note here that mo is the mass flow rate of all material •
which will pass through a screen of opening TS. A typical washer is used
only for a range of sizes from, say, TS to a bottom size, BS. Equation 3-9
can be used for this situation through the use of the previously described
size distribution function. The fraction of coal in the range BS to TS is
F(BS), where F(x) is based on the topsize, TS. The fraction of material in
this size interval and specific gravity interval isg can be designated
W(TS-BS, isg). A mass balance on the material in this specific gravity range
yields:
W(TS-BS, isg)-F(BS) = W(TS,isg)- W(BS,isg)•[l-F(BS)] . (3-10)
Therefore,
W(TS, i so) - W(BS, i „) [l-F(BS)]
WCTS-BS, i._) = * (3-11)
g F(BS)
A combination distribution function for a size range TS to BS can also be
defined, but the algebra used above does not necessarily apply. This results
since the cumulative distribution function represents data from measurements
on actual equipment in operation. If that equipment is processing material,
from BS to TS in size, only the effect on those sizes will be reported. Cumu-
lative washability data, on the other hand, results from tests of all size
-------
86
particles up to the specified topsize. It is possible to define a cumulative
washabiltiy function which applies to a size range BS to TS, thus obviating
Equation 3-11. However, much less data is required to use the suggested
formulation for various size ranges, than would be required if each range
used separate washability data.
Equation 3-8 is consistent with current coal cleaning models used in
the detailed design of cleaning plants where accurate estimates of each flow
stream volume and characteristics are essential. Where somewhat less accuracy
is acceptable the data collection and calculations can be simplified by assum-
ing a special distribution function which is depicted in Figure 3.2. For
this distribution, any material with specific gravity below SG, the specific
gravity of separation at which the washer operates, reports to clean coal.
The remainder reports to refuse. This means that no material is misclassified
according to the specific gravity criteria which is the basis of washer opera-
tion.
To qualitatively assess the effect of this approximation on model
accuracy consider Figure 3.3 where the fraction of misclassified material of
each specific gravity is plotted vs. specific gravity. Note that very little
A
heavy material is substituted for light material except near SG where those
materials differ only slightly in specific gravity (and hence in properties).
The effect of ignoring the misclassification is, therefore, expected to be
slight.
f 1. 0 for SG <_ SG
D(TS, isg) =
• 0.0 for SG > SG
Substituting into Equation 3.8
m
c = m0 I W(TS,.isg) (3-12)
isg : SG
-------
87
0.5
fraction
misclassified
0.0
SG
Figure 3.3 Misclassified Material for a Typical
Distribution Function.
yield 1.0
WCTS,SG)
W(BS,SG)
SG
Figure 3.4 Weight Washability Functions
-------
88
The sum in equation 3.12 has special significance. It is a weight washability
function which is cumulative in size and specific gravity. Its value is
*" ^
the total fraction of feed material with specific gravity not exceeding SG
which will pass through a screen of opening TS. This is washability data
of the sort prepared by the Bureau of Mines (Bu Mines RI-S118, 1976). In
summary, the cummulative washability data provides an adequate estimate of
washer yield for a specified topsize and specific gravity of separation. Note
that equation 3-11 still applies.
Accepting an ideal distribution function the weight washability func-
tion from equation 3-11 is simply washer yield. Total plant yield is deter-
mined by the yields of each washed stream.That is, the yield for any washer is
Y = {W(TS,SG)[1-F(TS)] - W(BS.SG)[l-F(BS)]} 1 (3.13)
F(BS)-F(TS)
where TS and BS are the washer- specific top and bottom size. If Y is
the required yield the washer must operate at a specific gravity which satis-
fies equation 3-13. Figure 3.4 is typical of cumulative weight washability
data.
SG can be determined by trial and error if the weight washability functions
are known. For the initial trial, SG for which W(TS, SG) = Y may be used.
This will usually exceed SG.
Other Washabitity Functions
Properties of the washed product may be determined by mass or energy
balances similar to that leading to equation 3-11. Therefore, the heating
value and weight fraction sulfur and ash are given by:
BTU(TS-BS, §G) = {BTU(TS, SG) - BTU(BS, SG)[l-F(BS)]}__1 C3-lla)
F(BS)
SUL(TS-BS, SG) = {SUL(TS, SG) - SUL(BS, SG)[1-F(BS)]) 1 (3.lib)
F(BS)
ASH(TS-BS, SG) = {ASH(TS, SG) - ASH(BS, SG)[l-F(BS)]} 1 (3.lie)
F(BS)
-------
89
3.24 Level 1
Preparation at this level does not involve any washing. Its objective
is to satisfy customer specifications or shipping requirements by adjusting
coal size and moisture content. Preliminary size control of the mine issue
is accomplished by a rotary breaker which also eliminates gross contaminants
such as large rocks or timber. The product from the rotary breaker will be
referred to as run-of-mine coal. Since the only effect on yield of this
breaking operation is the elimination of large rocks which would dilute the
coal, and since laboratory tests which are used to ascertain coal character-
istics do not account for such dilution, it is consistent to regard this size-
controlled product as run-of-mine coal. This most basic level of preparation
is therefore regarded as part of the mining process. It is, in fact, part of
most modern mines. Hence, "Level 1" preparation is used to refer to addition-
al size control beyond that obtained with the rotary breaker and possible
moisture control.
Figure 3.5 is a flow diagram for the Level 1 plant.Run-of-mine coal is
classified and crushed to the specified top size with single or double roll
crushers. If moisture reduction is necessary a thermal drier, fired by
prepared coal, is used. The various stream flow rates are determined as
follows. The symbols used are:
Y = overall plant yield
Y. = yield for washer j
•
fflppj = required prepared coal flow rate (tons/hr)
ihj_ = coal flow rate for stream i (tons/hr)
Yt£j = thermal dryer yield
•
M = rate of moisture removal (tons/hr)
LHV = lower heating value (Btu/ton)
-------
90
rora
THERMAL
DRYER
V
(Storage^
-3> Effluents
Figure 3.S Level 1
-------
91
= heat required per unit of moisture removed by thermal dryer
(Btu/ton)
MJ_ = weight fraction moisture in stream i
HHY = higher heating value (Btu/ton)
ASH = weight fraction ash
SUL = weight fraction sulfur
ksul = ratio of sulfur adsorbed by dryed coal to sulfur emitted by
combusted coal.
= (underscore) indicates moist basis.
The yield of all crushing processes is assumed to be 1.0. Therefore,
the overall yield of the level one plant is:
Y0 = Ytd = 221 (3-14)
Except for the adsorption of a small amount of sulfur, the moisture-free coal
which enters the thermal dryer is the same as that which leaves. Therefore,
rfu = m7 (3-15)
Also,
"3 = '"ppd * "4 (5~16:i
Therefore, the yield may be expressed as:
The rate of coal combustion depends on the required rate of moisture removal,
If ktcj is the heat required (Btu) to remove one ton of moisture from the dry-
ing coal and ft is the rate of moisture removal (tons/hr).
m4 = ktd M/LHV ppd (3-18)
Notice that this equation determines the moist coal flow rate. This is due
to the use of the moist basis lower heating value . LHV . indicates the
actual heat delivered to the moist coal since it claims no credit for latent
heat of inherent or surface moisture. Determination of LHV- A is discussed
-------
92
later.
• •
... in-? m_
M = m - m- = - £ — - 3 (3-19)
1 - M2 1 - M3
Using equation 3-15
ft « *2 - 2 - 3 - (3-20)
Combining equations 3-18 and 5-20 with
Mo -Mr
B = _ "2 ..."3 _ (3-2»
td
^
ii— ppd "• 'ppd iiii-ppd
But m = m + m4 [from equations 3-15, 5-16] (3-23)
ppd
So> *4 " Cfippd + V ktd
A mass balance relates m4 to m4
ra4 -(1-M4) = m4 (3-25)
Noting that M4 = MS = Mppd>
n^ = M4/(l-Mppd) (3-26)
Substituting this into Equation 3.24 and solving for m4 yields
ktdB k B -1
LHv ,
——ppd
The yield from equation 3-17 is therefore:
ktd'B k .B ^ .!
] (3-28)
Characteristics of the prepared coal may be determined on either a
moisture-free or moist basis from characteristics of the raw coal. It is
assumed that an ultimate analysis of the moisture-free raw coal and the weight
fraction of moisture in the raw coal are available. It is also assumed that
the higher heating value of the moisture-free raw coal is known. Then, in
-------
93
our notation, the following quantities are known directly; SUL , ASH ,
H, 0, N, C, and Mronr These characteristics may also be expressed on a moist
basis.
SUL = SUL (1-M ) (3-29)
- rom rom ronr
ram ' ASHrom C^ (3-30)
rom -
On a dry basis no change would be expected due to moisture removal by
the thermal dryer. This is true except for the adsorption of SC>2 from the
thermal dryer combustion gases onto the drying coal. Define ksui as the frac-
tion of generated S00 which is adsorbed. Then
m
SUL = SUL (1 + ksul • _1) (3-32)
ppd rom auj m
Using equations 3-22 and 3-25
m4 ktd (l-Mppd)B
— = - (3-33)
in LHV ppd
2 ^r
Therefore,
fcsul ktd Cl-Mpnd)B
SUL = SUL [1 + - — - i^L~ ] (5-34)
rom Mil
Assuming HHVrom is kno\vn, LHVppd may be determined as follows (Btu/
HHVPPd '
= HHVppd - -18.1020 (3-36)
' LHVppd Cl - M)- M '1020
H is the weight fraction of hydrogen in the moisture free coal.
Example for Level 1
Data: m , = 1000 tons/hr H = 0.05 ASH-nm =0.20
ppd rom
kt£j = 4.0 106 Btu/ton ksul = 0.52
Mrom = °'25 HHVronf 1250° Btu/lb
= °'10 SUIrom= °'03
-------
94
HHVppd = ^'rom = 1250°
LHVppd = HHVppd - 9180-H = 12500 - 459 = 12041
pd = LHVppd (1 - Mppd) - Mppd 1020
= 12041 (1-0.10) - 0.10(1020) = 10735 Btu/ Ib.
= 21.5'106 Btu/ton
ktd-B k -B -1 -1
v , _ n a. ——— t •!• ^" "\
Ytd - [1 + LHV Cj-r^ - )
——ppd
M - M
B = rom ppd
(l-Mrom)Cl-Mppd)
0.25 - 0.10
= 0.195
(1-0. 25) (1-0. 10)
(4.0 -106)(0-.193) 4.0-106(0.193) -1
Ytd = [1 + - -, - Cjr^ - - 1 - ) ] = 0.98
[21.5-106] l U
-------
95
ROM
rotary
breaker
crushing
drying
Figure 3.6 Level 2
•>• refuse
m3 =
m =
4
BTU
- F(S2)3
Yo -
F(S2)
m ,/Y
ppd
- F(S2)]
d =
[BTU(S2, 2.0)[1-F(S2)] + BTU(S - S , SG)-F(S2)-Y.
[SUL(S2, 2.0)[l-F(S2)j + SUL(Sr S2, SG)-F(S2)-Y ] J_
o
[ASH(S2, 2.0)[1-F(S2)] + ASH(Sj- S2> SG)-F(S2)-Y ]_i_
(3-38)
(3-39)
(3-40)
(3-41)
(3-42)
(5-43)
(3-44)
(3-45)
(3-46)
(3-47)
-------
96
Example for Level 2
Size distribution data:
SIZE
3 in.
1 in.
1/2 in.
1/4 in.
10 mesh (0.069")
28 mesh
100 mesh
FRACTION OVERSIZE
0.000
0.175
0.362
0.530
0.785
0.905
0.964
Determination of F(x)
F(
1")
=
log(l) =
loglog
o
"
1
-0.
0.
•• > ~
121
000
0
0
-0
-
.175
.000
.121
(-0.978)
(-1.161)
F(0.
log
loglog
(0
0
0.
1.
069
")
.069)
1
.785
854
161
= 0.
= -1.
= -0.
0.738
785
161
978
= 0.069[-£n (0.785)]- 1/°-738 = 0.472
Therefore
F(x) = e
x 0.738
0.738
For example, F(0.25) = e"
Cumulative washability data:
_ Q.535 which agrees with the data above.
TS = 5.0'
TS = 0.25'
SG FLOAT W %S % ASH BTU/LB K
1.5 0.7634 0.99 10.37 13065 0.7564
1.6 0.8308 1.08 12.02 12796 0.8096
1.7 0.8643 1.20 12.96 12618 0.8471
1.9 0.8975 1.33 14.07 12385 0.8835
TOTAL 1.0000 1.36 20.20 11316 1.0000
K
7564
8096
8471
8835
0000
%S
0.92
0.98
1.06
1.15
1.29
%ASH
6.99
8.40
9.63
11.07
18.43
BTU/LB
13588
13343
13117
12830
11561
-------
97
Let S2 = 0.25" and YQ = 0.90.
For an overall plant yield of 0.90, the washer yield must be:
Y - 1 + F(S.) 0.90 - 1 + 0.530
Y = — — = = 0.817
1 F(S2) 0.530
The specific gravity of separation for the washer, SG, is calculated as
follows:
Assume SG = 1.57 (value corresponding to W(3, SG) = 0.811). Then from
Equation 3.13 '
_ 1
Y = Yj = {K(3, 1.57) - W(0.25, 1.57)[1-F(0.25)]} ^
= {0.811 - 0.794(1 - 0.53)} ^-gy = 0.826 * 0.811
For SG = 1.55
Yj = {0.797 - 0.783(1'- 0.53)} Q^J = 0.809
A
This is close enough. The value SG "= 1.55 is used for subsequent calcula-
tions. The washer product has the following characteristics (dry basis):
BTU(3"- 1/4", 1.55) = {BTU(3", 1.55)- BTU (1/4", 1 .55) [l-F(l/4")3 >..
= {12931 - 13466- [1-0.55]} f-~ = 12,457 Btu/lb
U • i* ^>
SUL(3"-l/4", 1.55)= {SUL(3",1.55)- SUL(1/4",1 .55) [l
- {0.0104 - 0.0095(1 - 0.53)} ^-^r = 0.0112
ASH (3"-l/4",1.55) = {.1120-0.0770(1 - 0.53)} •—- = 0.143
U • O*5
Characteristics of the prepared coal are:
BTUppd = [BTU(l/4, 2.0)[l-F(l/4")] + BTU(3"-1/4",1 .55)F(l/4) -Y^ i-
= [11561 (1-0.55) + 12457(0. S3)-0. 811] ~Q
= 11,987
SULppd = [SUL(1/4,2.0)[1-F(1/4)J + SUL(3"-1/4",1 . 55) -F(l/4) -0. 811] ~
= [0.0129(1-0.53) + 0.0112 (0. 53) (0. 811)]
= 0.0121
-------
98
ASH
ppd = [ASH (l/4,2.0)(l-F(l/4))+ ASH(3"-1/4",1.55)-F(l/4)-Y^ ^_
[0.1843 (1-0.S3) + 0.143(0.53)(0.811)]
0.90
= 0.165
These are on a dry basis. Note that in this example, the washed sizes
correspond to available data. If they had not, interpolation between sizes
for which data are available would be required.
3.2.6 Level 3 - Washing of Coarse and Medium Coal Sizes
The Level 3 plant has two washing circuits. The coarse coal, sizes Sj
to S-, is washed in a jig type washer while the intermediate coal, 82, 83
is washed in a dense media washer. The unwashed fines are mixed with the two
washed streams to form the product. Only mechanical dewatering is used.
Figure 3.7 represents this configuration.
/ rotary
breaker
I
SiXO
S3XO
^
0
/
watering
i
(D
/
/
^si-
S2XS3
^
(7)
!
\
in°*>.
($)
^
f
«2
washer
©
S1XS2
Fl
washer
\
^,-
© .
de-
watering
©
: (s
Figure 3.7 Level 3
-------
99
] + [F(S3) - F(S2)] Y2 +
Let Y} = Y2 = Y1.
Then Y0 = [1- F(S3)] + [F(S3) - F(S2)J Y' + F(S2)-Y'
= 1 - F(S3) + F(S3)-Y'
Y'
F(S3)
ppd = 3> 2.0)[1-F(S3)J + P(SrS2, SG2)-Y'-[F(S3)-F(S2)]
+ P(S2,
(3-48)
(3-49)
(3-50)
(3-51)
(3-52)
where
^s some property of the prepared coal.
Example for Level 3
This is similar to Level 2 except that 2 washers are used. SG must be
determined for each. Washability data for top sizes at least as large as
S^ and as small S3 are required. For S3 = 28 mesh, the following washability
applies.
TS = 28 mesh = 0.0232"
SG FLOAT
1.5
1.6
1.7
1.9
TOTAL
i ]
Y =
W %S
70.73 0.9'6
78.01 1.01
82.13 1.04
86.25 1.03
100.00 1.43
{ . i + F(0.0232)
v
(F(0.0232)
,-0.0232^0.738
%ASH BTU/LB
7.16 13520
9.02 13196
10.23 12967
11.73 12658
18.99 11284
F(0.0232) = e
= 0.90
0.9 - 1 f 0.9
0.9
= 0.89
-------
100
Washer 1
Assume SGj = 1.85 (at this value W =0.89 for TS = 3.0) Checking with
equation 3.13.
= {W(5, 1.85) - WC0.25, 1.85)[1 - F(0.25)]}
= [0.89 - 0.874(1 - 0.535)] — - — = 0.904 * 0.89
0.535
Washer 2
A
SG = 1.9 •*• Y2 = 0.8835 is the highest SG for which W is available. One
could extrapolate beyond 1.9 but this is a reasonable first approximation
anyway.
Y = {WC0.25. 1.9)[1-F(0.25)] - W(28m. 1 . 9) [1-F(0. 0232)] }
Q2
= [0. 8835(1-. 535)-0. 8625(1-0. 9)] Q g_ = 0.889
Therefore SG = 1.85 , SG2 = 1.9 are used.
The washed coal characteristics:
Washer 1 SG = 1.85
BTU(3"-l/4", 1.85)= {BTU(3'M.85)-BTU(1/4",1.85)
1
= [12443 - 12902(0.465)]
= 12044 BTU/LB
SUL(3"-1/4",1.85) = {SUL(3",1.S5) - SUL(1/4",1 .85) [l-
= [1.30 - 1. 13(0. 465) ] -i = 1.45%
ASH(3"-l/4", 1.85)= {ASH(3",l.S5)-ASH(l/4",1.85)[l-F(l/4)]}
= [13.79 - 10.71(0;465)]g-^j = 16.47%
Washer 2 SG = 1.90
BTU(l/4"-0.0232", 1.90) = {BTU(l/4 ,1 . 9) [l-F(l/4) ]-BTU(0.0232 ,1 . 9) [1-F(0.. 0232) ] }
1 _
' F(0.0232)-F(l/4)
= [12830(0. 465)-1265S(0. !)] = 12877 Btu/lb
-------
101
SUL(l/4"-0. 0232", 1.90) = {SUL(1/4,1 .9) [l-F(l/4)] -SUL(0. 0232 ,1.9) [l-F(0.0232) ] }
* [1.15(0.465)-1.09(. ' FC0.0232)-F(l/4)
ASH(l/4"-0. 0232", 1.90) = {ASH(1/4,1.9) [l-F(l/4) ] -ASH(0. 0232 ,1.9) [1-F(0.0232) ] }
1
= [14.07(0.465)-11.07(.l)] * =14.89% ^(0.0232)^(1/4)
U * *jOD
The prepared coal characteristics are:
BTU d = {BTU(0.0232,2.0) [l-F(0.0232)]+BTU(l/4-0.0232,1.9)(Y2) [F(0.0232)-F(l/4)]
+ BTU(3"-1/4",1.85) (Yj) [F(0.2S)] } ^
= (11284(1-0.9) + 12850(0.89) [0.90 - 0.535]
+ 12044(0.89) [0.535]} - = 12264 Btu/lb
SUL d= (SUL(0. 0232, 2. 0)[1-F(0. 0232)] + SUL(l/4-0. 0232,1. 9)\'2 [F(0.0232)-F(l/4)]
+ SUL(3 - 1/4,1.85)Y1[F(0.25)]} -^
= (0.0143(1-0.9) + 0.0116(.89)(0.9-0.535) + 0.0145 (0. 89) (0.535) )
= 0.0135 or 1.35%
ASH d = {ASH(0. 0232, 2.0) [1-F(0.0232) ] + ASH(l/4-0. 0232 ,1.9)Y2 [F(0. 0232) -
F(0.25)]
+ ASH(3-1/4,1.85) YitFCO.25)]} -
= (0.1899[1-0.9] + 0.1437(0. 89) (0. 9-0. 535)^0.1647(0. 89) (0. 535)} -^
= 0.160 or 16%
3. 27 Level 4, Complete Washing
In this plant all coal sizes are washed. The fines, S, x 0 and the
intermediate coal, $2 x 83, are thermally dried by hot gases from the combus-
tion of cleaned coal in a thermal dryer. In addition to the effect on mois-
ture content, the thermal dryer results in an increase in sulfur content due
to adsorption of S02 from the hot flue gases. Also, the net yield is reduced
due to combustion of the cleaned coal. The final product is a mixture of the
dried coals and the mechanically dewatered coarse coal. Figure 3.8 represents
-------
102
refuse
refuse
Figure 3.8 Level 4
-------
103
= 0.90 {0.535 + 0.957 [0.465]} ~1
= 0.92
The specific gravity corresponding to this yield and associated washa
bility data are found through linear extrapolation of the available data.
Using equation 3.13 it can be verified that:
SGj = 1.97
SG2 = 2.05
SG3 = 2.18
The extrapolations are shown on the accompanying graphs (Figures 3.9-3.12).
Properties of the washed coals are :
Washer 1
BTU(3"-1/4",1.97) = {BTU(3",1.97)-BTU(1/4",1.97)
,
= [12300 - 12580(1 - 0.535)]-= 12057 Btu/lb
SUL(3"-1/4",1.97) = [1.375-1.18(1-0.535)] rO.535 = 1.54%
ASH(3"-1/4",1.97) = [14.4 - 11.6(1-0.535) ]*0. 535 = 16.8%
Washer 2
BTU(l/4"-28mesh,2.05) = {BTU(l/4" ,2.05) [l-F(l/4") ]-BTU(0.0232) [1-F(0. 0232) ] }
_ 1 _
' F(0.0232)-F(l/4)
= [12615(0.465) - 12425(0. 1)] *6$ = 12667
SUL(l/4"-28mesh,2.05) = [1.20(0. 465)-l. 12(0. 1) ] . = 1.22%
U.
ASH(l/4"-28mesh,2.05) = [11 .9(0.465) -12.5(0. 1) ] \ . = 11.74%
\J • «3O O
Washer 5
BTU(28mesh, 2.18) = 12225
SUL(28mesh, 2.18) = 1.17
ASH(28mesh, 2.18) = 13.8
Properties of the thermal dryer feed stream:
-------
104
Figure 5.9
WEIGHT KASHABILITY
2.3.
2.2 _.
SG
2.1
2.0
1.9
1.8
1.7 -' • ( . ' ' ' "
0.80 0.82 0.84 0.86 0.88 0.90
•o
CJ
o
a
n
X
u:
0.92
Kt. Fraction to Clean Coal
-------
105
16
%ASH
14
12 -
10 -
8 -
1.6
1.7
Figure 3.10
ASH WASHABILITY
Extrapolated
l.S
1.9
2.0
2.1
2.2
SG
-------
106
13250
13000_
12750
12500.
12250.
HHV
12000
Figure 3.11
BTU KASHABILITY
Extrapolated
11750
11500
1.6
1.7
1.8
1.9
2.0
2.1
2.2
SG
-------
107
-1.40
1.35.
1.30_
1.25_
1.20_
1.15
1.10
1.05
1.00
Figure 5.12
SULFUR WASHABILITY
Extrapolated
1.6SG 1.7 1.8 1.9 2.0 2.1 2.2
SG
-------
108
1 rr{BTU(28mesh,2.18)-Y'• [l-F(28mesh)]+BTU(l/4"-28mesh,2.05)-Y-
13 Y1 [1
[F(28mesh)-F(l/4")]>
1
•{12225(0.92) (1-0.9) + 12667 (0.92) (0.9-0.535) }
0.92(1-0.0535)
= 12572
SUL13 = 0.92\Q. 465) [1. 17(0. 92) (O.D+1. 22(0. 92) (0.9-0. 535)] * 1.21%
ASH = 2.34[13.8(0.092) + 11 . 74(0. 92)(0. 365)] = 12.20%
The properties of the dried coal are :
BTU., = BTU. . = 12572 Btu/lb ASH., = ASH.- = 12.20%
ID 13 lo io
= SUL,,!. .
- ppd
- < 10800-2000
The prepared coal properties are:
BTU d= { [1-0. 535] (12572) (0. 92) (0. 957) + 12057(0. 92) (0.535) } -~
= 12313 Btu/lb
SUL d = {(0.465)(1.22)(0.92)(0.957) + 1 .54(0. 92) (0.535)
= 1.40%
ASH , = {0.465(12. 2) (0.92) (0.957) + 16.8(0.92) (0.535)
= 14.74%
-------
109
this configuration.
Y0 = [F(S2)]« Yj * {[F(S3)-F(S2)].Y2 + [1-FCS3D]-Y3} Y
td
=Y'
= Y'F(S2) + Ytd {Y'[1-F(S2)]} (3-54)
Y'(F(S) 4 Y[l-F(S)]} (3-55)
]}'1 (3-56)
Properties of the input stream to the thermal dryer: (dry basis)
(3-57)
The properties of the dried stream, P16, are determined as for Level 1.
The prepared coal properties are then :
P j = ill —FfS^)j*Pli*i * Y. j + PiS^—S^, So. ) * Y * r fS~)J v f3-5S)
ppd *i Jo To i £ i £ X*.
Example for Level 4
Data required in addition to that used for the level three analysis is
ktd ~ 4.0«10 Btu required/ton moisture removed
k = 0.32 Ibs adsorbed/lb SCL emitted
M = 0.25
rom
M ,~ 0.10
ppd
HHV = 11316
rom
H = 0.05
Based on these values Y , is calculated as for example 1:
Ytd = 0.957
The washer yields for washers 1,2, and 3 are:
Y' = Yft (F(S2) * Y_[l
-------
110
The specific gravity corresponding to this yield and associated
xvashability data are found through linear extrapolation of the available
data. Using equation 3.13 it can be verified that:
SGj = 1.97
SG2 = 2.05
SG3 = 2.18
The extrapolations are shown on the accompanying graphs (Figures 3.9 through
3.12).
Properties of the washed coals are:
Washer 1
1
BTU(3"-l/4", 1.97) = {BTU(3",1.97)- BTU(1/4",1.97)[l
= [12300-12580(1.-0.535)] Q ^ = 12057 Btu/lb
SUL(3"-l/4", 1.97) = [1.375-1.18(1-0.535)]* 0.535 = 1.54%
ASl!(3"-l/4", 1.97) = [14.4 -11.6(1-0.535)]* 0.535 = 16.8%
Washer 2
BTU(l/4"-28mesh, 2.05) = {BTU(l/4",2.05)[l-F(l/4")]-BTU(0.0232)[1-F(0.0232)]}
1
F(0.0232)
1
= [12615(0. 465)-12425(0.1)] Q 565 = 12667
SUL(l/4"-28mesh, 2.05) = [1 . 20(0.465)-!. 12(0. 1)] &5 » 1.22%
ASK(l/4"-28mesh, 2.05) = [11. 9(0.465) -12.5(0. 1) ] TT-TF = 11.74%
U .
Washer 3
BTU(28 mesh, 2. IS) = 12225
SUL(28 mesh, 2.18) = 1.17
ASH(2S mesh, 2.18) = 13.8
Properties of the thermal dryer feed stream:
-------
Ill
{BTU(28mesh,2.1S)-Y'-[l-F(28raesh)] + BTU(l/4"-28mesh,2.05)
Y'[1-F(S2J]
Y'-[F(28raesh)-F(l/4")]}
0-92Q.0.535)
= 12572
{12225(0.92)(1-0.9) + 12667(0.92)(0.9 - 0.535)}
SUL._ = ___L_ [1.17(0.92)(0.1)+ 1.22(0.92) (0.9-0.535)] = 1.21*
1 0.92(0.465)
ASH = 2.34[13.8(0.092) + 11. 74 (0. 92) (0.365)] = 12.20%
The properties of the dried coal are:
BTU16 = BTU13 = 12572 Btu/lb ASH16 = ASH13 = 12.20%
(0.32) (4.0-106) (1-0.10) (0.193)
SUL16 = SUL17;[1 f - = 1 22%
16 -10 10800-2000
The prepared coal properties are:
BTU d = {[1-0. 535] (12572) (0.92) (0.957)+ 12057 (0. 92) (0.535) } —•
= 12313 Btu/lb
1
SULppd = { (0.465)(1.22)(0.92)(0.957) + 1 . 54 (0. 92) (0.555) } —
1.40%
ASH , = {0. 465(12. 2)(0.92)(0. 957) + 16. 8(0. 92) (0.535) } -^
= 14.74%
-------
113
APPENDIX C
COMPARISON OF PCC AND PARTIAL FGD DATA
-------
115
Table C.I Data on PCC and Partial FGD
Plant
A
B
C
E
F
G
H
1
J
K
M
N
0
P
Q
R
S
T
U
V
1980
Emissions
#S02/MMBtu
5.41
5.13
4.22
4.40
4.41
5.10
8.22
6.44
2.65
6.49
5.77
8.16
6.87
3.45
5.47
4.78
3.36
6.02
5.08
4.42
Coal
Cleaning
Wt. Recovery
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
.800
ROM
800
Coal
*S02/MMBtu
5.99
5.12
9.93
6.54
4.94
3.01
4.31
3.27
5.53
4.08
6.39
4.88
6.72
3.95
6.39
4.88
3.85
2.54
7.35
6.04
6.73
4.87
8.69
5.86
9.15
6.30
4.14
2.75
5.50
4.91
5.99
5.12
4.94
3.01
7.25
5.08
4.86
2.43
6.10
4.09
ZS
Reduction
14.6
34.1
39.2
24.1
26.2
23.7
41.2
23.7
34.1
17.7
27.6
32.6
31.1
33.5
10.6
14.6
39.2
29.9
50.0
33.0
Coal
Cost
$/MMBtu
1.501
2.098
1.508
2.109
1.512
2.110
1.512
2.115
1.500
2.091
1.499
2.087
1.500
2.090
1.499
2.087
1.481
2.053
1.487
2.063
1.542
2.159
1.317
1.930
1.317
1.937
1.504
2.094
1.500
2.099
1.501
2.098
1.512
2.110
1.530
2.147
1.495
2.082
1.317
1.932
PCC Cost
$/Ton S02
1366
355
616
1162
818
778
426
778
871
884
664
434
435
851
2057
1366
616
569
483
611
Equlv.
FGD Cost
S/Ton S02
525
731
1091
978
815
746
979
589
1294
594
754
674
699
1162
649
630
976
597
1231
854
-------
Cumulative SO, removed (ktons)
era
n
H-
i-t
H-
3
OQ .
o g
3 H-
M CU
^ rt
O
m
13
<
(1)
C/3
O
NJ
3 ^
O 0)
-a o
M <
M
O
O O
04 1 1
o
o
*-
o
o
o>
o
o
i
oe
o
0
1
o
o
o
o\
VI
o-
o
(O
o
o
o
O
0
(U
CO
tu
rt
rt
£j*
(D
CO
rt
C
Q*
"<
X)
1— '
CB
3
j— j.
CO
t— •
CO
w
hr)
3
0
rt
§
0
Ml
n
0
CO
rt
V
CO
(B
D.
O
3
J
CO
o
K>
------- |