United States
Environmental Protection
Agency
Office of
Research and Development
Washington, D.C. 20460
EPA-600/7-76-024
OCTOBER 1976
EPA PROGRAM CONFERENCE REPORT-
FUEL CLEANING PROGRAM:
COAL
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental Protection Agency,
have been grouped into seven series. These seven broad categories were established to facilitate
further development and application of environmental technology. Elimination of traditional grouping
was consciously planned to foster technology transfer and a maximum interface in related fields. The
seven series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT RESEARCH AND DE-
VELOPMENT series. Reports in this series result from the effort funded under the 17-agency Federal
Energy/Environment Research and Development Program. These studies relate to EPA's mission to
protect the public health and welfare from adverse effects of pollutants associated with energy
systems. The goal of the Program is to assure the rapid development of domestic energy supplies in an
environmentally-compatible manner by providing the necessary environmental data and control
technology. Investigations include analyses of the transport of energy-related pollutants and their
health and ecological effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environmental issues.
This document is available to the public through the National Technical Information Service,
Springfield, Virginia 22151.
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EPA-600/7-76-024
October 1976
EPA PROGRAM CONFERENCE REPORT
FUEL CLEANING PROGRAM:
COAL
from coal sessions of
The Fourth National Conference on
Energy and the Environment
Cincinnati, Ohio
Co-chaired by
William N. McCarthy Jr.
Office of Energy Minerals and Industry
Environmental Protection Agency
Washington, D.C. 20460
Stanley Jacobsen
Coal Preparation and Analysis Branch
U.S. Bureau of Mines
Bruceton, PA.
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EPA REVIEW NOTICE AND DISCLAIMER
This report has been reviewed by the Office of Energy, Minerals and Industry, Environmental Protec-
tion Agency, and approved for publication. Mention of trade names or commercial products does not
constitute endorsement or recommendation for use.
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FOREWORD
This report is composed of papers presented at two sessions of the Fourth National Conference
on Energy and the Environment at Cincinnati, Ohio on October 6, 1976. They represent the Environ-
mental Protection Agency's interagency program for coal cleaning.
Because environmental standards affect the development of a technology for utilizing much of
the nation's coal, the most desirable means for minimizing pollution from coal is being sought.
Pollutants can be controlled: prior to combustion by systems for cleaning (processing) coal of
undesirable constituents; during combustion, as for example, by using fluidized bed combustion
techniques; after combustion by processing effluents and emissions, as for example, gas flue clean-
ing; or by combinations of these various methods depending on the properties of various coals in
conjunction with their energy generating systems.
The purpose of these sessions, and this report, is to spot-light coal cleaning technology as the
primary means for reducing and controlling the undesirable emissions resulting from the combustion
of coal.
in
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CONTENTS
Page
Foreword iii
List of Figures vi
List of Authors x
Acknowledgments xi
Part I. Physical/Resource Aspects
The Need for Coal Cleaning 1
MarkD. Levine, Robert E. Fullen, William N. McCarthy Jr., Gary J. Foley
Coal Resources, A Continuing Assessment 10
S. Z. Altschuler and J. E. Johnston
Contaminants in Coals and Coal Residues 14
E. M. Wewerka, J. M. Williams and N. E. Vanderborgh
Effect of Coal Preparation on Northern Appalachian Reserves 29
R. E. Hucko and J. A. Cavallaro
Designing A Regional Atmospheric Control Strategy For Electric Utilities 39
Gerald A. Isaacs, Timothy W. Devitt, and Ray W. Cunningham
Part II. Cleaning Processes
Implementation of Coal Cleaning for SCh Emission Control 49
James D. Kilgroe
Physical Coal Cleaning Contract Research By The U.S. Bureau of Mines 57
P. S. Jacobsen and A. W. Deurbrouck
Review and Status of The TRW/Meyers Process 65
R. A. Meyers, L. J. Van Nice and M. J. Santy
Hydrothermal Coal Desulfurization With Combustion Results 79
E. P. Stambaugh, A. Levy, R. D. Giammar and K. C. Sekhar
The Homer City Coal Cleaning Demonstration 88
J. F. McConnell
Discussion 103
Appendix
About the Authors 115
Metric Conversion Table 118
Technical Report Data 119
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FIGURES
Number Page
THE NEED FOR COAL CLEANING 1
1.1.1 The Need for Coal Cleaning: Issues 4
1.1.2 Method Of Approach: Assumptions Behind Coal Forecasts 4
1.1.3 Supply/Demand Forecasts For Low Sulfur Coal 1977-1985 4
1.1.4 Low Sulfur Coal Demand Cases 5
1.1.5 U.S. Low Sulfur Coal Demand Forecast: Cases 1 and 2 5
1.1.6 Low Sulfur Coal Supply Cases 5
1.1.7 U.S. Low Sulfur Coal Supply Forecast: Cases 1 and 2 5
1.1.8 Comparison of Supply and Demand Cases for Low Sulfur Coal 6
1.1.9a Conclusions from Analysis of Supply and Demand for Low Sulfur Coal 7
1.1.9b Conclusions from Analysis of Supply and Demand for Low Sulfur Coal 7
1.1.9c Conclusions from Analysis of Supply and Demand for Low Sulfur Coal (continued) . . 7
1.1.10 The Role of Coal Cleaning 8
1.1.11 Quantities of U.S. Coal Mechanically Cleaned (1965-1973) 8
1.1.12 U.S. Coal Cleaning by Region (1973) 8
1.1.13a The Need for Coal Cleaning: Conclusions 9
1.1.13b The Need for Coal Cleaning: Conclusions 9
1.1.13c The Need for Coal Cleaning: Conclusions . 9
COAL RESOURCES, A CONTINUING ASSESSMENT 10
1.2.1 Coal Fields of the Conterminous United States 11
1.2.2 Classification of Coal Resources by the U.S. Geological Survey
and the U.S. Bureau of Mines . , 11
1.2.3 The Reserve Base by Coal Type and Sulfur Categories (In Billions of Tons) 12
1.2.4 Other Harmful Elements May Further Reduce the Tonnage of Usable Coal 13
CONTAMINANTS IN COALS AND COAL RESIDUES 14
1.3.1 What is Coal? 20
1.3.2 Coal-Forming Processes 20
1.3.3 Physical Composition of Coal (Spackman) 20
1.3.4 Elemental Composition of Organic Coal Components 20
1.3.5 Functional Group Model of Bituminous Coal (Wiser) 21
1.3.6a Potential Organic Contaminants from Coals 22
1.3.6b Potential Organic Contaminants from Coals (continued) . . 22
1.3.6c Potential Organic Contaminants from Coals (continued) 22
1.3.7 Major Inorganic Elements in Coals 23
1.3.8 Major Minerals in Coals 23
1.3.9 Iron Sulfides Cause Major Environmental Problems 23
1.3.10a Trace Elements of Environmental Concern in Coal 24
1.3.10b Trace Elements of Environmental Concern in Coal (continued) 24
1.3.11a Summary of Potential Environmental Contaminants in Coals 24
1.3.11b Summary of Potential Environmental Contaminants in Coals (continued) 24
1.3.12a Coal Processing Steps 25
1.3.12b Environmental Contamination from Coal Mining 26
1.3.12c Environmental Contamination from Coal Storage and Transport 26
1.3.12d Environmental Contamination from Coal Combustion 26
1.3.12e Environmental Contamination from Coal Preparation 26
1.3.12f Balance of Environmental Contamination for Coal Processing and Utilization 27
1.3.13 Environmental Problems from Discarded Coal Wastes • . . . 28
1.3.14 Aqueous Drainage from Pennsylvania Coal Refuse Dumps 28
1.3.15 EPA Proposed Regulations for Aqueous Effluents from Coal •
Mining Point Sources — October 1975 28
1.3.16 Environmental Trade-offs for Coal Preparation 28
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Number Page
EFFECT OF COAL PREPARATION ON NORTHERN APPALACHIAN RESERVES 29
1.4.1 Typical Washability Analysis (Report of Investigation 8118) 34
1.4.2a Pyritic Sulfur Reduction for Northern Appalachian Region Coals 35
1.4.2b Total Sulfur Reduction for Northern Appalachian Region Coals 35
1.4.3 Northern Appalachian Region Coal Samples Meeting EPA SO2 Standard 35
1.4.4 Components of the Reserve Base 36
1.4.5 Coal Reserve Base in the Eastern United States 36
1.4.6 Coal Reserve Base in the Eastern United States 36
1.4.7 Reserve Base of Northern Appalachian Bituminous Coal 36
1.4.8 Computerized Output of Typical Reserve Base (Report of
Investigation 8680) 37
1.4.9 Tonnages by Sulfur Range in Pennsylvania 37
1.4.10 Tonnages by Sulfur Range in Northern Appalachian Region 37
1.4.11 Effect of Crushing and Cleaning at 1.60 Specific Gravity on the
Availability of <0.85 Percent Sulfur Coal 38
1.4.12 Effect of Crushing and Cleaning at 1.30 Specific Gravity on the
Availability of <0.85 Percent Sulfur Coal 38
1.4.13 Comparison of the Effect of Crushing and Cleaning at 1.60 and 1.30
Specific Gravities on the Availability of <0.85 Percent
Sulfur Coal 38
DESIGNING A REGIONAL ATMOSPHERIC CONTROL STRATEGY FOR ELECTRIC UTILITIES . . . . 39
1.5.1 Coal Cleaning Yield Curve Sinclair Mine — Seam 9—Underground 44
1.5.2 Coal Cleaning Cost-Plant Size Relationship 44
1.5.3 Total Cost for Two-Stage Coal Cleaning as a Function of Cost
and Btu Recovery Efficiency 44
1.5.4 Capital Intensity Comparision-FGD and Coal Cleaning 44
1.5.5 Erosion Failures — Plants 45
1.5.6 Strategy Elements for a Regional Control 45
1.5.7a Data Requirements for a Regional Control 45
1.5.7b Data Requirements for a Regional Control 45
1.5.8a Comparison of Costs for FGD Control with Costs for a Combined
Strategy Using FGD, Coal Cleaning and Fuel Redistribution 46
1.5.8b Comparison of Costs for FGD Control with Costs for a Combined
Strategy Using FGD, Coal Cleaning and Fuel Redistribution 46
1.5.9 Conclusions 46
IMPLEMENTATION OF COAL CLEANING FOR SO2 EMISSION CONTROL 49
2.1.1 Physical and Chemical Cleanability 54
2.1.2 Costs for Various Sulfur Pollution Control Methods 54
2.1.3 Potential Levels of Desulfurization for U.S. Utility Coals 54
2.1.4 Status of Selected Chemical Treatment Processes 54
2.1.5 Status of Physical Coal Cleaning 55
2.1.6 Summary of the Physical Desulfurization Potential of Coals by Region 55
2.1.7 Effectof Cleaning Variable on Coal Pollution Potential 55
2.1.8 Emission Control Strategies for SO? Emission Control 55
2.1.9 Barriers to Implementation of Coal Cleaning for SO2 Emission Control 56
2.1.10 Barriers to Implementation of Coal Cleaning for SO2 Emission Control (continued) . .56
2.1.11 Conclusion: Status of Coal Cleaning Technology 56
2.1.12 Conclusion: Methods for Accelerating Implementation of Coal
Cleaning Technology 56
vii
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Number Page
PHYSICAL COAL CLEANING CONTRACT RESEARCH BY THE U.S. BUREAU OF MINES 57
2.2.1 Reduction in Total Sulfur of Eastern Coals (48 mesh by 0) Using
High Gradient Magnetic Separation 62
2.2.2 Reduction in Ash of Eastern Coals (48 mesh by 0) Using High
Gradient Magnetic Separation 62
2.2.3 Coal Floatation Recovery in the Absence of Abrasion 62
2.2.4 Effect of Dextrin Addition on Coal-Pyrite Flotation with
Potassium Amyl Xanthate (Kax) as Collector 62
2.2.5a Ash Reduction for Total U.S. (455 Samples) 63
2.2.5b Pyritic Sulfur Reduction for Total U.S. (455 Samples) 63
2.2.5c Sulfur Reduction for Total U.S. (455 Samples) 63
2.2.5d Sulfur Emission Reduction for Total U.S. (455 Samples) 63
2.2.6 Total U.S. Coal Samples Meeting EPA SO2 Standards (455 Samples) 64
2.2.7 Combination Coal Preparation and Flue Gas Desulfurization (FGD)
Treatment to Meet New Source Performance Standards for Steam Generators . . . 64
2.2.8 U.S.B.M. Coal Preparation Process Development Facility,
Bruceton, Pennsylvania (14 May 76) 64
REVIEW AND STATUS OF THE TRW/MEYERS PROCESS 65
2.3.1 Description of the Meyers Process 68
2.3.2 Crystals of Sulfur Produced by Meyers Process 69
2.3.3 Chemical Equation and Enthalpy Associated with the Leaching Step 70
2.3.4 Kinetics of the Leaching Step 70
2.3.5 Chemical Equation and Enthalpy Associated with the Regeneration Step 70
2.3.6 Kinetics of the Regeneration Step 70
2.3.7 Simultaneous Ferric Sulfate Leach and Regeneration-Based Pyrite
Removal Process 71
2.3.8 Pyrite Leaching Rates from Upper Freeport and Lower Kittanning Mine Coals 71
2.3.9 Effect of Coal Top-Size and Cleaning on Leach Rate 71
2.3.10 Pyrite Removal as a Function of Time-Washed Vs. Unwashed Coal At
Same Starting Pyrite Concentration 71
2.3.11 Artist Conception of the Reactor Test Unit (RTU) 72
2.3.12 Reactor Test Unit (RTU) Capabilities 72
2.3.13 Capital Investment Overview for the Meyers Process 73
2.3.14e Relating Capital Investment to Process Flow: Off Site
Requirements 73
2.3.14a Relating Capital Investment to Process Flow: Reaction 73
2.3.14b Relating Capital Investment to Process Flow: Washing 73
2.3.14c Relating Capital Investment to Process Flow: Sulfate Removal 74
2.3.14d Relating Capital Investment to Process Flow: Sulfur Removal 74
2.3.15 Coarse Coal Design: Pit Reactor Type 75
2.3.16 Coarse Coal Design: Continuous Reactor Type ., 76
2.3.17 Distribution of Sulfur Forms (Dry Moisture Free Basis)
In Run-Of-Mine U.S. Coals 77
2.3.18 Meyers Applicability, Energy Efficiency and Cost 78
2.3.19 Meyers Strategy and Market Potential 78
2.3.20 Meyers Reactor Test Unit (RTU) Funding) ! ! 78
HYDROTHERMAL COAL DESULFURIZATION WITH COMBUSTION RESULTS 79
2.4.1 Synoposis of Presentation 84
2.4.2 Hydrothermal Coal Process 84
2.4.3 Sulfur Emissions of Low-Sulfur Coals from Hydrothermal Coal Process 84
viii
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Number Page
2.4.4 Some Toxic Metals Extracted by Hydrothermal Treatment of Ohio Coals 84
2.4.5 Leaching of HIT Coals with Inorganic Acids 85
2.4.6 Laboratory Scale Combusion Unit 85
2.4.7a Differential Thermal Analyses of Coal Samples in an Atmosphere of Air 85
2.4.7b Differential Thermal Analyses of Coal Samples in an
Atmosphere of Nitrogen 85
2.4.8a Combustion Results (Martinka Coal) 86
2.4.8b Combustion Results (Martinka Coal) 86
2.4.8c Combustion Results (Martinka Coal) 86
2.4.9a Combustion Results (Westland Coal) 87
2.4.9b Combustion Results (Westland Coal) 87
2.4.9c Combustion Results (Westland Coal) 87
HOMER CITY COAL CLEANING DEMONSTRATION 88
2.5.1 Overview of Homer City Generating Complex 93
2.5.2 Homer City Coal Cleaning 94
2.5.3 Homer City Coal Cleaning (Continued) 94
2.5.4 Homer City Generating Complex Alternative SOi Control Strategies 94
2.5.5 Washability Data, PA Mines Vs Helen & Helvetia Mines 95
2.5.6 MCCS Deep Coal Cleaning Requirements 95
2.5.7 MCCS Coal Heat Content Balance 95
2.5.8- Since Figures 2.5.8 through 2.5.13 are identical except
2.5.13 for highlighting of a subsystem, they are not included
2.5.14 Homer City —MCCS 97
2.5.15 Effect of Size on Quality of 1.3 Specific Gravity Float Product 98
2.5.16 Btu and Sulfur Distribution 98
2.5.17 Homer City Site: Early Construction (24 May, 1976) 99
2.5.18 Homer City Site: Early Construction (24 May, 1976) 99
2.5.19 Homer City Site as of August 30,1976 99
IX
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LIST OF AUTHORS
Altschuler, S.Z. Kilgroe, James D.
Cavallaro, J.A. Levine, Mark D.
Cunningham, Ray W. Levy, A.
Deurbrouck, Albert W. McCarthy, William N. Jr.
Devitt, Timothy W. McConnell, J.F.
Foley, GaryJ. Meyers, R.A.
Fullen, Robert E. Santy, M.J.
Giammar, R.D. Sekhar, K.C.
Hucko, R.E. Stambaugh, E.P.
Isaacs, Gerald A. Vanderborgh, N.E.
Jacobsen, P.S. Van Nice, L.J.
Johnston, J.E. Wewerka, E.M.
Williams, J.M.
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ACKNOWLEDGMENTS
The Office of Energy, Minerals and Industry of the Environmental Protection Agency is apprecia-
tive of the help and support provided to assemble the papers for the conference and the publication of
them in this report. Particular thanks are due the co-sponsors of the conference, the Dayton and Ohio
Valley Sections of the American Institute of Chemical Engineers and the Air Pollution Control Associa-
tion Technical Committee TT-5.1. The assistance of the authors of each of the papers is gratefully
acknowledged.
Many thanks are due to Automation Industries, Inc., Vitro Laboratories Division, for preparation
of the slides and other illustrative material under demanding time and production specifications.
Gratitude for the assistance of Stanford Research Institute, and Cameron Engineers, Inc. Denver,
Colorado is acknowledged.
Special recognition and appreciation is extended to Dr. Edmund J. Rolinski as Conference
general chairman, and Professor Louis Theodore, of Manhattan College, Department of Chemical
Engineering, as Conference technical chairman; and Stanley Jacobsen, of the U.S. Bureau of Mines,
co-chairman of the sessions on Coal Preparation for Pollution Control.
William N. McCarthy )r.
Washington, D.C.
October 1976
XI
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PART 1. PHYSICAL/RESOURCE ASPECTS
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THE NEED FOR COAL CLEANING
Mark D. Levine
Robert E. Fuller)
William N. McCarthy, Jr.
CaryJ. Foley
This presentation is entitled "The Need for Coal Cleaning." The talk could also have been
entitled "Is There a Need for Coal Cleaning?" or "What are the Circumstances Under Which There is a
Need for Coal Cleaning?"
Figure 1.1.1 raises four issues concerning the need for coal cleaning. The first is: how will a
near-term increase in coal use affect the environment? The second issue is: can policies be adopted
that will minimize adverse environmental impacts and increase coal use? Thirdly, is there a shortage of
low sulfur coal, and is there likely to be a shortage in the near future? And finally, can coal cleaning
reduce the overall environmental impacts of coal use?
Many of the presentations we will hear in the sessions today will treat these issues. This
particular talk will focus on the last two of the issues concerning the availability of low sulfur coal and
the potential for coal cleaning to increase supply of low sulfur coal, thus reducing emissions of sulfur
to the environment.
To address these issues, we have performed projections of supply and demand for low sulfur
coal between 1975 and 1985. As shown in Figure 1.1.2, the projections are based on several
straightforward assumptions. These assumptions are:
• The demand projections for coal are based on the Federal Energy Administration
reference case demand projection for coal. The demand for low sulfur coal was derived
from projections for total coal demand.
• The supply projections are derived from industry and Environmental Protection Agency
sources.
• The sulfur content of future coal supplies is estimated from the results of tests carried
out over the past decade by the U.S. Bureau of Mines.
• We assumed that all new energy facilities will be in compliance with air quality stan-
dards.
Figure 1.1.3 presents the sources for the projections. The demand projection is primarily based
on the Federal Energy Administration's "National Energy Outlook" for 1976. The supply projection is
derived from industry sources, including the Keystone Coal Industry Manual, the National Coal
Association, and analyses performed by the Policy Planning Division of the Environmental Protection
Agency. The disaggregation of coal supply by sulfur content was accomplished using data from tests
performed by the U.S. Bureau of Mines (with support from EPA pass through funds). This information
has recently been published in a report entitled "Sulfur Reduction Potential of Coals of the United
States." Finally, assumptions about the use of scrubbers in new coal-fired power plants were made
using EPA and industry survey results.
Figure 1.1.4 summarizes our two demand cases for low sulfur coal. Demand Case 1, derived
from the Federal Energy Administration's "National Energy Outlook" projection of coal demand by
sector, assumed that 60 percent of new coal-fired power plants will use scrubbers to remove sulfur, in
conformance with the results of the EPA and industry surveys. Demand Case 2 is different from
Demand Case 1 in the assumption that only 35 percent of new coal-fired power plants will use
scrubbers for sulfur removal. Thus, Demand Case 2 represents a greater demand for low sulfur coal
because of the reduced use of scrubbers.
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Figure 1.1.5 illustrates the demand projections for Demand Cases 1 and 2. This figure shows a
small projected increase in demand for low sulfur coal in the industrial, residential/commercial, and
export sectors of the economy. The substantial increase in demand for low sulfur coal (over 60 percent
from 1975 to 1985) is due to increasing use of low sulfur coal by electric utilities. The lower portion of
the graph for electric utilities shows the utility demand for low sulfur coal for Demand Case 1 (that is,
for the case in which 60 percent of new coal-fired plants employ scrubbers). The entire cross-hatched
area for electric utilities shows the demand for low sulfur coal in Demand Case 2 (for which 35 percent
of new coal-fired plants are assumed to use scrubbers). Demand Case 2 requires substantially greater
amounts of low sulfur coal than Demand Case 1: approximately 1 quadrillion Btu (50 million tons) per
year in 1980 and 2 quadrillion Btu (100 million tons) per year in 1985. The unshaded portion of the
graph shows the increased demand for higher sulfur coal by electric utilities. The small area in
the upper right hand corner of the figure is the projected demand for coal by synthetic fuel facilities.
The major point of Figure 1.1.5 is that the two demand cases represent a significant increase in demand
for low sulfur coal between now and 1985, and the increase is due almost entirely to the use of coal by
electric utilities.
Figure 1.1.6 summarizes the two supply cases that are used in this analysis. Supply Case 1, based
on industry projections, indicates that 85 percent of the growth in low sulfur coal production is
projected to take place in the western states. These projections result in annual growth of Western
coal production of 35 percent between 1975 and 1980, and of 15 percent per year in Western coal
production from 1980 to 1985. Supply Case 2 assumes that these high growth rates of Western coal
production are not attained. The objective of Supply Case 2 is to assess the impacts of a high, but
reduced, growth rate of Western coal. Supply Case 2 still has a substantial growth rate for Western coal
production: 20 percent annual production increase from 1975 to 1980 and 10 percent annual produc-
tion increase from 1980 to 1985.
Figure 1.1.7 presents Supply Cases 1 and 2. This figure clearly indicates that almost all of the
increased production of low sulfur coal is derived from the growth in Western coal production. Even
for Supply Case 2, in which Western coal production growth rates are reduced, almost all of the
growth in low sulfur coal is derived from the West. There is a slight increase in the production of
Southern Appalachian coal of low sulfur content. No increase in production of low sulfur coal in
Northern Appalachia, Alabama or the Midwest is projected between now and 1985.
Figure 1.1.8 provides a comparison of the supply and demand projections for low sulfur coal.
The graph in the upper left hand corner is a comparison of Demand Case 1 and Supply Case 1. This is
the case for which we have assumed that 60 percent of new coal-fired power plants use scrubbers and
that Western coal development occurs at the higher rate. We note that there could be a very small
deficit of low sulfur coal until 1978 and a small surplus of low sulfur coal after 1978. The basic
conclusion from this graph is that for a scenario consisting of Demand Case 1 and Supply Case 1,
supply and demand for low sulfur coal are well balanced between the present and 1985.
The graph in the upper right of Figure 1.1.8 compares Demand Case 1 with Supply Case 2, in
which the rate of increase of Western coal production is somewhat reduced. This graph shows an
increasing deficit of low sulfur coal, particularly after 1980, and growing to over 2 quadrillion Btu per
year (or over 100 million tons) by 1985.
Demand Case 2, in which we assume that only 35 percent of new coal-fired power plants employ
scrubbers also results in substantial deficits of low sulfur coal, as shown by the two graphs at the
bottom of Figure 1.1.8. The combination of Demand Case 2 and Supply Case 1 results in a deficit of low
sulfur coal of approximately 2 quadrillion Btu per year by 1985. The worst case is the combination of
Demand Case 2 (lower scrubber use) and Supply Case 2 (lower Western coal growth). In this case,
there is a potential deficit of low sulfur coal amounting to over 4 quadrillion Btu per year by 1985, or
more than 200 million tons of low sulfur coal per year.
Figure 1.1.9 summarizes the conclusions from the two supply projections and the two demand
projections. We conclude that if Western coal production grows at projected rates and if 60 percent of
new coal-fired power plants install scrubbers, there will be no substantial shortage of low sulfur coal to
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meet EPA emission standards between 1975 and 1985. However, if the growth rates of Western coal
production are reduced by about one third, then our projections indicate an annual shortage of low
sulfur coal of slightly less than 1 quadrillion Btu in 1980 and almost 2.5 quadrillion Btu, or 120 million
tons per year, in 1985. Furthermore, if only 35 percent of new coal-fired power plants install scrubbers,
then an additional shortage of low sulfur coal of approximately 1 quadrillion Btu in 1980 and 2
quadrillion Btu could occur in 1985.
The results of this analysis lead us into a discussion of the need for coal cleaning. As shown in
Figure 1.1.10, the potential shortage of low sulfur coal between the present and 1985 leads us to ask the
question to which the remainder of this talk is devoted: Can the use of coal cleaning increase the
supply of low sulfur coal to meet this potential deficit of low sulfur coal?
To understand the future role of coal cleaning it is useful to look at past trends. Figure 1.1.11
shows quantities of U.S. coal that have been mechanically cleaned between 1965 and 1973. Both on a
percentage basis, and also in absolute amounts, coal cleaning has seen decreasing use over the last
decade. This figure does not tell the whole story, since it does not indicate the degree to which the
coal has been cleaned. Nonetheless, the trend is clear: in the past decade, the use of coal cleaning
devices for coal has decreased.
To understand the potential of coal cleaning to help meet any future shortage of low sulfur coal,
it is useful to note the amount of coal that can meet EPA's sulfur emission standards before and after
cleaning. This information is presented in Figure 1.1.12. The information represents an average of the
samples that have been studied by the U.S. Bureau of Mines. We make the assumption that this
average figure is indicative of the sulfur content of the coal reserves in the regions. For Alabama, the
eastern Midwest and western Midwest, the percentage of coal meeting EPA sulfur emission standards
is not greatly changed through the use of coal cleaning. However, for the Northern Appalachia,
Southern Appalachia, and Western coal regions the percentage of coal that meets sulfur emission
standards can be increased significantly through the use of coal cleaning. The percentage of coal that
meets these standards increases from 4 percent to 12 percent in Northern Appalachia; from 35 percent
to 50 percent in Southern Appalachia; and from 70 percent to 94 percent in the West. Of these regions,
Southern Appalachia and the West represent large quantities of coal and thus have the greatest
potential for using coal cleaning to reduce potential future deficits of low sulfur coal. Using the
information presented in Figure 1.1.12 and the supply and demand projections for low sulfur coal, we
have analyzed several strategies for increasing the availability of low sulfur coal. The results of this
analysis are shown in Figure 1.1.13. Figure 1.1.13a indicates that the full application of coal cleaning
technologies could result in an additional 0.5 quadrillion Btu (25 million tons) per year of low sulfur
coal for Supply Case 2 in 1985 and 1.2 quadrillion Btu (60 million tons) per year for Supply Case 1 in
1985. Thus, without changing the projected mix of coal supply, a growth of coal cleaning capacity
alone could contribute in significant measure to a reduction in potential shortages of low sulfur coal.
A second strategy to increase production of low sulfur coal is to combine full application of coal
cleaning with an increased growth in Southern Appalachian coal. If the growth rate of Southern
Appalachian coal were increased from current projections of 2 percent per year to a growth rate of 6
percent to 10 percent per year and coal cleaning were used to reduce the sulfur content, then a
substantial increase in low sulfur coal supply would be obtained. For a 6 percent annual growth in the
production of Southern Appalachian coal, over 1 quadrillion Btu (50 million tons) per year of additional
low sulfur coal could result in 1985. A 10 percent annual growth rate of Southern Appalachian coal
could yield as much as 2.5 quadrillion Btu (125 million tons) per year of low sulfur coal in 1985, with full
use of coal cleaning.
Figure 1.1.13c compares the results of the two Supply and two Demand Cases already analyzed
with a new supply strategy that combines a 10 percent annual growth rate in the production of
Southern Appalachian coal with increased use of coal cleaning.
This analysis makes clear that coal cleaning offers one approach that can significantly reduce the
likelihood of shortages of low sulfur coal in the next decade and thereafter.
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HOW WILL A NEAR-TERM INCREASE IN COAL USE
AFFECT THE ENVIRONMENT ?
CAN POLICIES BE ADOPTED THAT WILL MINIMIZE
ADVERSE ENVIRONMENTAL IMPACTS OF
INCREASED COAL USE ?
IS THERE A SHORTAGE OF LOW SULFUR COAL ?
CAN COAL CLEANING REDUCE OVERALL
ENVIRONMENTAL IMPACTS OF COAL USE ?
THE NEED FOR COAL CLEANING: ISSUES
Figure 1.1.1
DEMAND PROJECTIONS USE FEA
REFERENCE CASE
SUPPLY PROJECTIONS ARE DERIVED
FROM INDUSTRY AND EPA SOURCES
THE AVERAGE SULFUR CONTENT OF
COAL DEPOSITS IS ACCURATELY
REPRESENTED BY U.S.B.M. SAMPLES
COMPLIANCE WITH AIR QUALITY
STANDARDS FOR ALL NEW
FACILITIES
METHOD OF APPROACH:
ASSUMPTIONS BEHIND COAL FORECASTS
Figure 1.1.2
METHOD OF APPROACH: SOURCES
1. DEMAND PROJECTION
• FEA NATIONAL ENERGY OUTLOOK (19761-PROJECTED COAL
DEMAND BY SECTOR
2. SUPPLY PROJECTION
• KEYSTONE COAL INDUSTRY MANUAL (1975)
• OTHER INDUSTRY SOURCES
• EPA ANALYSES
3. SUPPLY/DEMAND ANALYSIS BY SULFUR
CONTENT
• SULFUR REDUCTION POTENTIAL OF THE COALS OF THE UNITED STATES,
EPA AND U. S. B. M. (APRIL 1976)
• USE OF SCRUBBERS BY UTILITIES FROM EPA SURVEYS (1976)
SUPPLY/DEMAND FORECASTS FOR LOW
SULFUR COAL 1977-1985
Figure 1.1.3
-------
DEMAND CASE 1:
• FEA NATIONAL OUTLOOK PROJECTION OF COAL
DEMAND BY SECTOR
• 6Q% OF NEW COAL FIRED POWER PLANTS USE SCRUBBERS
TO REMOVE SULFUR
DEMAND CASE 2:
• FEA DEMAND PROJECTION
• 35% OF NEW COAL FIRED POWER PLANTS USE SCRUBBERS
TO REMOVE SULFUR
LOW SULFUR COAL DEMAND CASES
Figure 1.1.4
SUPPLY CASE 1:
• INDUSTRY PROJECTIONS WITH 85% OF SROWTH OF LOW
SULFUR COAL PRODUCTION IN WESTERN STATES
• RESULTS IN 35% ANNUAL GROWTH IN WESTERN COAL
PRODUCTION (1976-1980) AND 15% ANNUAL GROWTH
IN WESTERN COAL PRODUCTION (1980-1985)
SUPPLY CASE 2:
• INDUSTRY PROJECTIONS WITH REDUCED GROWTH
IN WESTERN COAL PRODUCTION:
20% ANNUAL PRODUCTION GROWTH (1976-1980)
10% ANNUAL PRODUCTION GROWTH (1980-1985)
LOW SULFUR COAL SUPPLY CASES
Figure 1.1,6
— SYNTHETIC FUEL FACILITIES
DEMAND CASE 2
(35% of new Coal
Fired Plants use
scrubbers)
DEMAND CASE 1
(60% of new Coal
Fired Plants use
scrubbers)
1980
YEAR
CD UNCIEANED COAL
E2 CLEANED AND LOW SULFUR COAL
U. S. LOW SULFUR COAL DEMAND
FORECAST: CASES 1 AND 2
Figure 1.1.5
LOW SULFUR: <
0.6 LB SULFUR/10* Btu
a
-------
ac
o
CJ
CD «"
O S
2 —
«* Z
>- S
-------
• IF WESTERN COAL PRODUCTION GROWS AT PROJECTED RATES, AND
IF 60% OF NEW COAL FIRED POWER PLANTS INSTALL SCRUBBERS,
THEN, NO SHORTAGE OF LOW SULFUR COAL TO MEET
EPA EMISSIONS STANDARD IS EXPECTED DURING THE
PERIOD 1975-1985
CONCLUSIONS FROM ANALYSIS OF SUPPLY
AND DEMAND FOR LOW SULFUR COAL
Figure 1.1,9a
• HOWEVER, IF GROWTH RATES OF WESTERN COAL PRODUCTION ARE
REDUCED BY ABOUT ONE-THIRD, AND
IF, AGAIN, 60% OF NEW COAL FIRED POWER PLANTS INSTAU SCRUBBERS,
THEN, AN ANNUAL SHORTAGE OF LOW SULFUR COAL OF
0.8x 10"- Btu 140 MILLION TONS) IN 1980 AND
2.4 x Iff* Btu 1120 MILLION TONS! IN 1985
could occur
CONCLUSIONS FROM ANALYSIS OF SUPPLY
AND DEMAND FOR LOW SULFUR COAL
(Continued)
Figure 1.1.9b
• IF WESTERN COAL PRODUCTION GROWS AT PROJECTED RATES, AND
• IF ONLY 35% OF NEW COAL FIRED POWER PLANTS INSTALL
SCRUBBERS,
AN ADDITIONAL ANNUAL SHORTAGE OF LOW SULFUR
COAL OF
0.8x 10n Btu 140MILLION TONS/ IN 1980 AND
2.0x 10" Btu HOO MILLION TONS) IN 1985
COULD OCCUR
CONCLUSIONS FROM ANALYSIS OF SUPPLY
AND DEMAND FOR LOW SULFUR COAL
(Continued)
Figure 1.1.9c
-------
THUS, THERE IS A POTENTIAL SHORTAGE
OF LOW SULFUR COAL BETWEEN THE
PRESENT AND 1985 (and thereafter). CAN
THE USE OF COAL CLEANING INCREASE
SUPPLY OF LOW SULFUR COAL TO MEET
THIS POTENTIAL DEFICIT?
THE ROLE OF COAL CLEANING
Figure 1.1.10
YEAR
1965
1966
196?
1968
1969
1970
1971
1972
1973
MECHANICALLY CLEANED COAL
(PERCENT)
64.9
63.8
63.2
62.5
59.7
53.6
49.1
49.2
49.1
(MM TONS)
332
340
350
340
334
322
271
292
290
QUANTITIES U.S. COAL
MECHANICALLY CLEANED (1965-1973)
Figure 1.1.11
REGION
NORTHERN APPALACHIA
SOUTHERN APPALACHIA
ALABAMA
EASTERN MIDWEST
WESTERN MIDWEST
WESTERN
CLEANED
(PERCENT!
73.3
68.0
95.8
81.0
51.1
15.8
PERCENT MEETING EPA SULFUR EMISSIONS STANDARDS
BEFORE CLEANING
4
35
30
1
2.5
70
AFTfR CLEANING
12
50
30
2
5.5
94
U.S. COAL CLEANING BY REGION (1973)
Figure 1.1.12
-------
IF NEW COAL CLEANING CAPACITY IS EMPLOYED TO REDUCE
SULFUR CONTENT OF ALL NEW SOURCES OF COAL SUPPLY TO
THE EXTENT PRACTICABLE WITH STATE-OF-THE-ART COAL
CLEANING TECHNOLOGY,
THEN, THE POTENTIAL DEFICIT OF LOW SULFUR COAL
IN 1985 IS REDUCED BY 0.5 x 10™BTU (25 MILLION
TONS) FOR SUPPLY CASE 2 AND BY 1.2 x 10
(BO MILLION TONSI FOR SUPPLY CASE 1
BTU
• IF THE GROWTH RATE IN PRODUCTION OF SOUTHERN APPALACHIAN
COAL WERE INCREASED ABOVE 2% PER YEAR (SUPPLY CASES 1
AND 2), AND ADDITIONAL COAL CLEANING CAPACITY CONSTRUCTED
FOR THE NEW COAL, THEN SUBSTANTIAL REDUCTIONS IN ANY DEFICIT
OF LOW SULFUR COAL COULD BE ACHIEVED:
ANNUAL INCREASE IN
SOUTHERN APPALACHIAN
COAL PRODUCTION
10%
ADDITIONAL LOW
SULFUR COAL
l.lx 1015 BTU
1.7 x 1015 BTU
2.5 x 1015 BTU
THE NEED FOR COAL CLEANING:
CONCLUSIONS
Figure 1.1.13a
THE NEED FOR COAL CLEANING:
CONCLUSIONS
Figure 1.1.13b
DEMAND
CASE 1:
60% OF NEW COAL FIRED
POWER PLANTS USE
SCRUBBERS
DEMAND
CASE 2:
35% OF NEW COAL FIRED
POWER PLANTS USE
SCRUBBERS
SUPPLY CASE 1:
HIGH WESTERN COAL GROWTH
RATE (35% AND 20%)
NO DEFICIT IN LOW
SULFUR COAL IN 1985
2.0 x if)15 BTU (100 MILLION
TONS) SHORTAGE OF LOW
SULFUR COAL IN 1985
SUPPLY CASE 2:
REDUCED WESTERN COAL
GROWTH RATE 115% AND 10%)
2.4 x 1015 BTU (120 MILLION
TONS) SHORTAGE OF LOW
SULFUR COAL IN 1985
4.4 x 1015 BTU (220 MILLION
TONS) SHORTAGE OF LOW
SULFUR COAL IN 1985
SUPPLY CASE 2
with 10% GROWTH IN
SOUTHERN APPALACHIAN
COAL AND MAXIMAL USE
OF COAL CLEANING
NO DEFICIT IN LOW SULFUR
COAL IN 1985; 3% ANNUAL
GROWTH IN COAL CLEANING
CAPACITY
1.3x 10lsBtu (65 MILLION
TONS) SHORTAGE OF LOW
SULFUR COAL IN 1985; 2%
ANNUAL GROWTH IN COAL
y CLEANING CAPACITY
THE NEED FOR COAL CLEANING:
CONCLUSIONS
Figure 1.1.13c
-------
COAL RESOURCES, A CONTINUING ASSESSMENT
S.Z. Altschuler
J. E. Johnston
Abstract
Coal resources of the United States, as estimated in January, 1974, total about 4 trillion short
tons, of which 437 billion tons constitute the coal base (measured and indicated reserves).
Approximately 200 billion tons of coal in this reserve base is sufficiently low in sulfur content
(<1 percent sulfur) to be used with little or no sulfur reduction treatment. Some coals are enriched
with traces of various elements, notably beryllium and cadmium, which may, upon further concentra-
tion in ash or other products, become environmentally hazardous. Other minor or trace elements may
be critical factors in process technology.
Unusual concentrations of zinc and uranium in coal and lignites of particular coal basins,
notably in Texas and North Dakota, exemplify opportunities for recovery of those resources as well as
the inherent properties of coal.
It is vital to augment conventional evaluation of coal quality with detailed and regional analyses
of the inorganic constituents in coal. The U.S. Geological Survey is currently establishing, in coopera-
tion with other federal and state agencies, a national inventory of coal data which will be placed in
computerized data banks. The data will be recoverable not only in written form, but on various scale
topographic maps in a great number of different combinations.
(Editor's note: This paper had not been approved for publication and therefore the abstract only
is offered. Readers are directed to the panel discussion portion of this document for additional
information from author Altschuler.)
10
-------
NORTHERN GREA
0 200 400 600 KILOMETRES
COAL FIELDS OF THE CONTERMINOUS
UNITED STATES
(FROM AVERITT, 1975)
Figure 1.2.1
COAL RESOURCES
HYPOTHETICAL
(IN KNOWN
DISTRICTS)
UNDISCOVERED
SPECULATIVE
(IN UNDISCOVERED
DISTRICTS)
o >-
ll
i|
si
cc a
O CJ
• INCREASING DEGREE OF GEOLOGIC ASSURANCE
CLASSIFICATION OF COAL RESOURCES BY
THE U. S. GEOLOGICAL SURVEY AND THE
U. S. BUREAU OF MINES
Figure 1.2.2
11
-------
LIGNITE
SUB-BITUMINOUS
BITUMINOUS
ANTHRACITE
LOWS MODERATES HIGHS UNKNOWN
(<1%) (1-3%) 073%) (S undetermined)
55.5 71.4 31.5
THE RESERVE BASE BY COAL
TYPE AND SULFUR CATEGORIES
(IN BILLIONS OF TONS)
Figure 1.2.3
-------
TOTAL COAL IN GROUND
KNOWN
ESTIMATED TO BE PRESENT
BEDS THICK
ENOUGH TO MINE
ACCURATELY
MEASURED
ROUGHLY
MEASURED
BEDS TOO
THIN TO MINE
— SHALLOW ENOUGH
— TOO DEEP TO MINE
UNEXTRACTABLE
RECOVERABLE
TOO MUCH SULFUR
COAL USEABLE NOW*
•OTHER HARMFUL ELEMENTS MAY FURTHER REDUCE TONNAGE OF USEABLE COAL
500
1500
2500
3000
3500
BILLIONS OF TONS
HOW MUCH OF THE U.S. COAL IS PRESENTLY
EXTRACTABLE AND USABLE?
Figure 1.2.4
-------
CONTAMINANTS IN COALS AND COAL RESIDUES
E. M. Wewerka
J.M.Williams
N. E. Vanderborgh
INTRODUCTION
Coal is one of our most abundant sources of energy. Even with the enhanced role that coal will
play in the future, known reserves are estimated to be sufficient for at least three or four centuries. The
utilization of this form of fossil fuel, however, is fraught with environmental problems. In each step
from mine to utilization various contaminants are released into the environment. The dust and gases in
mines, drainage from coal mines and refuse, and stack emissions from coal-fired systems are examples
of environmental problems that continue to plague our society.
In the past, the environmental degradation from coal mining, processing, and burning was
reluctantly accepted. However, concern over environmental quality has resulted in the establishment
of regulations or guidelines for nearly all forms of coal utilization. Unfortunately, in many instances,
the statutory regulation of coal pollution has preceded the availability of the technology necessary to
achieve compliance with the law. Therefore, over the next decade, a massive effort must be launched
to develop suitable environmental control technology. The technical approach to control of coal
contamination, however, is not straight-forward. Compromises and trade-offs between efficient
energy use and the sometimes uncertain environmental consequences must be considered. Often the
choice of control technology for one area will affect that required in another. Ultimately, decisions
must be based on knowledge of the origins, magnitude, and behavior of the various kinds of coal
contaminants.
In this paper, we review some of the current information on the chemical and physical structure
of coals to establish the source and nature of potential environmental contaminants. With this as
background, we then discuss the nature of the major contaminants released into the environment
during coal mining, handling, and combustion. Finally we will consider coal preparation, which is one
of the most widely used forms of environmental control technology. Our discussion of coal cleaning
will center on the environmental compromises and implications attendant in using this method to
produce a cleaner burning fuel.
THE ORIGIN OF ENVIRONMENTAL CONTAMINANTS IN THE STRUCTURE OF COAL
Coal is a combustible carbonaceous rock formed from plant remains and various inoganic
components (Figure 1.3.1). Because of this, coal is a highly heterogeneous materal that contains a wide
variety of inorganic and organic impurities in addition to the carbonaceous matrix. Most of the
environmental contamination from coals is a direct consequence of these impurities.
The Formation and Structure of Coal
The diverse composition of coal arises from the geological and chemical conditions present
during coal formation. As outlined in Figure 1.3.2., the first step of coal formation is thought to be the
deposition of plant remains and inorganic sediments under reductive conditions, usually in a freshwa-
ter swamp or lake. Eventually, under heat and pressure, these deposits are transformed into peat. The
step from peat to coal is a chemical modification that involves mainly the loss of COi and water.
Physically, coal contains both organic-rich and inorganic-rich regions. The organic part of the
coal structure, which comprises about 70 to 90 percent of the total, is present in the form of distinct
physical entities called macerals, which have differing sizes and shapes (Figure 1.3.3). The mor-
phologies of the macerals are thought to be related to the original plant constituents. The mineral
matter in coals appears as small particles and grains or thick layers interspersed within the organic
components.
14
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Environmental Contaminants From the Organic Structure of Coal
The organic coal components contain mainly, C, H, N, O, and S; however, as detailed in Figure
1.3.4, there is considerable variation in these elements in coals. Lower rank coals, such as lignite, are
typified by a lower percentage of C and H and a relatively higher percentage of N, O, and S, whereas
the converse is true for the higher rank coals.
The organic matter in coals is predominately in the form of aromatic and hydroaromatic
hydrocarbons. The O, S, and N atoms form various functional groups that are dispersed throughout
the carbon skeleton. The prevalent functional groups in coals are phenols, acids, ethers, and groups
containing sulfur and nitrogen.
Various models have been proposed to illustrate the structural details of the organic coal
components. These are based on the known chemistry of coals, and are meant to suggest the major
features of molecular composition rather than to be exact representations. One of the more popular
structural models, devised by Wiser, is shown in Figure 1.3.5. This structure, of course, bears a
remarkable resemblance to the molecular configurations present in the humic components of plant
materials.
The molecule pictured in Figure 1.3.5 is very large, and, indeed, the general chemical inertness
of coals is a reflection of the large sizes of their constituent molecules. However, during combustion,
the large organic molecules can break down into smaller entities which can more easily escape into the
environment as gaseous pollutants or as water contaminants. Also, coals contain some smaller organic
molecules that are entrapped within the coal lattice. These may be released during processing or
storage without the necessity of molecular cleavage.
By referring to the model in Figure 1.3.5, it is relatively easy to envision the types of organic
molecules that are released by coals during combustion, oxidation, or weathering. Due to their
preponderance, various aromatic and aliphatic hydrocarbons are common contaminants. Also, be-
cause heteroatom linkages are often susceptible to cleavage, molecules containing N, O, and S atoms
are prevalent coal contaminants. Typical examples of the types of organic molecules in the emissions
or discharges from coals are pictured in Figures 1.3.6a, b and c.
Environmental Pollutants From the Inorganic Constituents of Coal
Most of the inorganic coal components were deposited either as sediments in the original bed
or as secondary materials during the formation of the coal; however, some of the trace or minor
elements in coals were probably present originally in the plants.
The most abundant inorganic elements in coals (excluding S, N, and O) are listed in Figure 1.3.7.
These are the elements that, for the most part, form the major minerals found in coals. These minerals
fall into the four main classes listed in Figure 1.3.8. They are the aluminosilicates (Na> K, Al, Si), the
sulfides (Fe), the carbonates (Ca, Mg, Fe), and silica (Si). Generally, the aluminosilicates (clay minerals)
and quartz tend to be chemically stable. Neither is volatile or likely to be leached from the coal. During
combustion these minerals will form ash. Another troublesome aspect of the clay minerals is that they
will fragment during burning to form small particulates (fly ash) that mix with the stack gases. The
carbonates also form ash during combustion. In addition, they are partially water soluble and may be
leached out of coals or wastes.
Among all of the coal constituents, environmental contamination caused by pyritic materials is
the most severe. The sulfides are not particularly soluble or volatile per se, but when pyrite (or
marcasite) is exppsed to atmospheric conditions, it can interact with air and water at ambient tempera-
ture to produce soluble iron sulfate and sulfuric acid. This reaction of the iron sulfides in coals is, in
fact, responsible for the formation of acid mine drainage, a most serious water pollution problem.
Also, during the combustion of coal, the sulfur in the iron sulfides (along with added amounts of
organic sulfur) is oxidized to SCh, the most prevalent air contaminant associated with the burning of
coal. The chemical reactions for the formation of sulfuric acid and sulfur dioxides from iron sulfides
appear in Figure 1.3.9.
15
-------
In addition to these major inorganic elements, coals also contain a wide variety of trace or minor
elements. A listing of some of the trace elements of environmental concern in coals is given in Figures
1.3.10a and b. The soluble forms of these elements may be released into the environment by aqueous
leaching of coals or their residues. Also, some of the toxic trace elements assume volatile forms during
coal burning; these can escape into the atmosphere along with the more inert gaseous products.
THE RELEASE OF ENVIRONMENTAL CONTAMINANTS FROM COALS DURING PROCESSING AND
COMBUSTION
In the preceding section, we discussed the structure of coal, and how the various types of
contaminants originate in the coal. In addition, we briefly considered how these contaminants are
transported into the environment, either as gaseous or water-borne pollutants (Figures 1.3.11a and b).
In this section, we will consider the types of contaminants that are released from coals during the
various processing and utilization steps. Then, we will go on to discuss the environmental cir-
cumstances surrounding coal preparation, particularly to emphasize its use as an environmental
control method.
The usual sequence of coal production and utilization steps appears in Figure 1.3.12a. After
mining, nearly all coal is subjected to storage and transportation steps prior to utilization (combus-
tion). In addition, about one-half of the coal mined in the U.S. is washed or prepared before it is used
to remove some of the unwanted mineral matter. Each processing, handling, or utilization step results
in the production of significant environmental pollutants.
Environmental Pollution from Coal Mining
Coal mining is one of our most dangerous industries. Therefore, the environmental and health
hazards associated with this phase of coal production are under much scrutiny. As shown in Figure 1.
3.12b, both atmospheric and aqueous contaminants are produced by coal mining.
The main atmospheric contaminants from coal mining are dust and gases. Dust is generated by
physical abrasion of the coal, and under confined conditions, such as in underground mines, the
respiration of this dust is a major health problem. The release of methane and other combustible gases
from the coal beds is another serious problem associated with coal mining. Underground, when
ventilation is poor, these gases can accumulate in explosive concentrations.
Acid drainage is by far the most serious water problem associated with coal mining. As detailed
earlier, acid formation results from the pyritic material present in the coal. More than 3 million tons of
sulfuric acid are discharged annually into waterways from coal mines. Acid mine drainage is responsi-
ble for contaminating some 7,000 miles of streams in the Appalachian region.
The spoil material from coal mining (overburden and mine wastes) contributes to contamination
on a much smaller scale than do mines. For environmental purposes most of this type of waste is used
as fill material after mining has been completed. However, coal mine spoils are a local source of acid
drainage and mineral contaminants in water.
Contaminants Produced by Coal Storage and Transportation
Neither the seriousness nor the extent of environmental contamination from coal storage or
transportation has been adequately assessed. As seen in Figure 1.3.12C, the potential exists for the
release of pollutants into both the atmosphere and aqueous environment during these handling
operations. Because of the transient nature of coal during storage and transportation, gaseous and
aqueous pollutants from these sources will often be more diffuse or less visible than those from
stationary sources.
16
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Environmental Contamination From Coal Combusion
The environmental contaminants produced by the burning of coal in boilers, power generators,
and other stationary sources (see Figure 1.3.12d) are well identified, and we need dwell only briefly on
this topic here.
The oxides of sulfur, nitrogen, and carbon are the most notorious air contaminants produced by
the combustion of coal. These contaminants enter the atmosphere in great quantities. In 1974, about
20 million tons of SCh and 5 million tons of nitrogen oxides (NOx) were discharged into the environ-
ment from coal burning. In addition to these gaseous contaminants, coal combustion also produces
large quantities of finely divided mineral particulates (fly ash) that also escape into the environment in
copious quantities. Finally, in the last few years it has been recognized that certain toxic trace
elements, such as Pb, Hg, As, and Cd may be released into the atmosphere in worrisome quantities
from coal combustion sources. It is not yet clear whether these elements are in a completely volatile
state or whether they are absorbed at the surface of fly ash or other particulate emissions.
The burning of coal also produces solid waste materials that need to be disposed of in
environmentally compatible ways. The bulk of this residue is bottom ash formed by the nonvolatile
mineral matter in the coal. In addition, to lessen the air pollution load, increasing amounts of fly ash
are being removed from the stack components by precipitators and other devices. About 70 million
tons of bottom and fly ash are produced annually in the U.S. from coal combustion. There is growing
awareness that the discarded solid wastes from coal combustion may themselves be a serious source
of environmental contamination. In particular, these materials may be subjected to leaching by
rainwater or surface flows that could produce mineral or trace element contamination.
Environmental Contaminants From Coal Preparation
The final coal processing step that we will consider is coal washing or preparation. In contrast to
the previous areas discussed, this step is conducted specifically to reduce the concentration of some
of the undesirable mineral impurities. There are, of course, economic benefits to be derived from coal
washing, such as the reduced cost of shipping, storing and burning a higher quality product, but for
the future, coal preparation is best envisioned as a pollution control measure.
Coal preparation is largely a mechanical process, involving a series of crushing, sizing, separat-
ing, and drying steps. In most cases, the coal is separated from the mineral matter on the basis of
density. Modern coal preparation plants can recover about 90 percent of the energy content of the
coal, while reducing the sulfur content to less than 1 percent.
The mineral refuse and wastes from coal preparation are also a recognized source of environ-
mental contamination, as detailed in Figures 1.3.12e and 1.3.13. Coal preparation refuse is subjected to
weathering and leaching processes that frequently produce acids and highly mineralized drainage.
The relative seriousness of this problem can be judged by comparing the quality of the aqueous
effluents from typical coal refuse dumps (Figure 1.3.14) with the proposed EPA standards for such
effluents shown in Figure 1.3.15. It is seen that in no instance does the quality of the waste bank
effluents (e.g., see the Fe, Al, Mn, and pH values) approach the criteria established by EPA. It has been
estimated that more than 3,000 miles of streams in Appalachia alone are contaminated from coal refuse
dumps.
In addition to water contamination, burning refuse dumps produce substantial air pollution.
Approximately 1 percent of the total nationwide quantities of sulfur-, nitrogen-, and carbon-oxide
emissions are attributed to burning coal wastes. Although this may be considered a small contribution,
these contaminants occur in highly localized regions. Finally, we must also point out that structural
instabilities in coal refuse banks have resulted in landslides or cave-ins that have claimed several
hundred lives over the last 20 years. The problems associated with coal refuse dumps are not isolated
incidences. Of the 3,000 to 5,000 refuse dumps in the U.S., about one-half are the sources of some
type of health or environmental problem.
17
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Environmental Trade-offs in the Coal Preparation/Utilization Cycle
A preliminary function of coal preparation is to reduce the mineral matter in raw coals so th.it
the emissions from the burning of these coals can meet established guidelines. Indeed, about 100
million tons of potential contaminants are removed annually from U.S. coals by coal preparation. The
waste materials produced by coal preparation area major source of environmental contamination.
As shown in Figures 1.3.16 and 1.3.12f, coal preparation is in effect an environmental trade-off: a
serious health and pollution problem is simply being transferred from one segment of the environ-
ment to another. Undoubtedly the rationale for this transfer is based on the assumption that contami-
nation from solid waste material concentrated in remote disposal areas is easier to control or alleviate
than the more ubiquitous forms that are discharged by the burning of coal. Conceivably, the com-
bined hazards from coal refuse dumps present a less serious threat to human health than the highly
mobile emissions from burning coal, although this point could be debated at some length. Environ-
mental control of discarded coal refuse, until recently, has been largely neglected. Until adequate
assessment and cleanup of this source of contamination is effected, the full implications of coal
preparation as a viable pollution control measure cannot completely be evaluated.
SUMMARY
Most of the major environmental pollutants from coals originate as impurities in the coal
structure. These include various organic compounds, minerals, and trace elements that are released
into the air and water when coal is mined, processed, and utilized. The use of coal preparation to
produce cleaner burning fuels involves an environmental compromise, wherein reduced emissions
and solid wastes from coal burning sources are achieved at the expense of greater environmental
degradation from coal cleaning wastes.
REFERENCES
1. Bhatt, H. G. Factors Affecting the Selection of Mine Drainage Treatment Methods. Proc.
Fifth Symp. on Coal Mine Drainage Research, Coal and the Environment Technical
Conference, Louisville, KY, Oct. 22-4,1974. pp. 331-56.
2. Busch, R. A., R. R. Backer, and L. A. Atkins. Physical Property Data on Coal Waste
Embankment Materials, U.S. Bur. Mines. Rept. Invest. 7964,1974.
3. Coalgate, J. L., D. J. Akers, and R. W. Frum. Cob Pile Stabilization, Reclamation, and
Utilization. Research and Development Report No. 75, Interim Report No. 1, West
Virginia University, School of Mines, Coal Research Bureau, 1973.
4. Davies, W. E. Geologic Factors in Waste Bank Stability. Mining Cong. J., Jan. 1973. pp.
43-46.
5. Deurbrouck, A. W., and P. S. Jacobsen. Coal Cleaning: State of the Art. Conference
on Coal and the Environment, Louisville, KY, Oct. 22,1974.
6. Lowry, H. E., Ed. Chemistry of Coal Utilization. Supplementary Volume, John Wiley
and Sons, New York, 1963.
7. Martin, j. F. Quality of Effluents from Coal Refuse Piles. Pap. Symp. Mine Prep. Plant
Refuse Disposal, 1st, Louisville, KY, Oct. 22-4,1974. pp. 26-37-
8. Murchison, D., and T. S. Westol, Eds. Coal and Coal Bearing Strata. Oliver and Boyd,
London, 1968.
18
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9. National Academy of Sciences. Underground Disposal of Coal Mine Wastes. Report to
the National Science Foundation, Washington, DC, 1975.
10. Wewerka, E. M., J. M. Williams, P. L. Wanek, and J. D. Olsen. Environmental Contami-
nation From Trace Elements in Coal Preparation Wastes: A Review and Assessment of
the Literature. EPA/ERDA publication, in press.
19
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COAL IS A COMBUSTIBLE SEDIMENTARY ROCK
FORMED FROM PLANT MATERIALS AND
INORGANIC SEDIMENTS IN VARIOUS STAGES
OF METAMORPHISM
WHAT IS COAL?
Figure 1.3.1
LIGNITE
BITUMINOUS
ANTHRACITE
K)
O
COAL-FORMING PROCESSES
Figure 1.3.2
A
MINERALS
^10 WT%
B
MACERALS (ORGANIC)
90 WT%
PHYSICAL COMPOSITION OF COAL (SPACKMAN)
ELEMENT
CARBON
HYDROGEN
OXYGEN
SULFUR
NITROGEN
RANGE (WT%>
65
2.0
2.0
0.5
0.5
-93
- 6.0
-20
- 6.0
- 2.0
ELEMENTAL COMPOSITION OF
ORGANIC COAL COMPONENTS
Figure 1.3.3
Figure 1.3.4
-------
H
H
FUNCTIONAL GROUP MODEL OF BITUMINOUS
COAL (WISER)
Figure 1.3.5
-------
AROMATIC POLYCYCLIC
HYDROCARBONS HYDROCARBONS
CH3
ALICYCLIC
HYDROCARBONS
OH
C02H
HO
PHENOLS
ACIDS
POTENTIAL ORGANIC CONTAMINANTS FROM COALS
POTENTIAL ORGANIC CONTAMINANTS FROM COALS
(CONTINUED)
Figure 1.3.6b
Figure 1.3.Ea
O'
OXYGEN
HETEROCYCLICS
NITROGEN
HETEROCYCLICS
POTENTIAL ORGANIC CONTAMINANTS FROM COALS
(CONTINUED)
Figure 1.3.6c
-------
ELEMENT
SILICON
IRON
ALUMINUM
CALCIUM
POTASSIUM
MAGNESIUM
TITANIUM
SODIUM
RANGE
0.6
0.3
0.4
0.1
0.1
0.1
0.0
0
(WT%)
-6.1
-4.3
-3.1
-2.7
-0.4
-0.3
-0.3
-0.2
ALUMINOSILICATES
(10-90 WT%)
ILLITE
KAOLIMTE
MIXED LAYER CLAYS
SULFIDES (0-40%)
PYRITE
MARCASITE
MAJOR INORGANIC ELEMENTS IN COALS
Figure 1.3,7
SILICA (0-20 WT%)
QUARTZ
CARBONATES (0-10 WT%)
CALCITE
DOLOMITE
SIDERITE
MAJOR MINERALS IN COALS
Figure 1.3-8
SULFUR OXIDE EMISSIONS
4 FeS2
Fe203 + 8 S02+A
ACID MINE DRAINAGE
2 FeS2 + 2 H20 + 7 02-»-2 FeS04-l-2 H2S04+A
A = HEAT
IRON SULFIDES CAUSE MAJOR
ENVIRONMENTAL PROBLEMS
Figure 1.3.9
-------
ELEMENT*
BERYLLIUM
MANGANESE
NICKEL
COPPER
ZINC
ARSENIC
RANGE (ppm)
0 - 31
6 - 181
0.4- 104
2 - 185
0 - 6000
0.5- 106
*IN ORDER OF INCREASING.ATOMIC WEIGHT
TRACE ELEMENTS OF ENVIRONMENTAL
CONCERN IN COAL
Figure 1.3.10a
AQUATIC TRANSPORT MODE
SOLUBLE ORGANIC MOLECULES
POLYAROMATIC HYDROCARBONS
LEACHABLE MINERALS AND TRACE ELEMENTS
ACID DRAINAGE
SUMMARY OF POTENTIAL ENVIRONMENTAL
CONTAMINANTS IN COALS
Figure 1.3.11a
ELEMENT*
SELENIUM
YTTRIUM
CADMIUM
MERCURY
LEAD
RANGE (ppm)
0.4-8
0.1 - 59
0.1 - 65
.01- 1.6
4 -218
*IN ORDER OF INCREASING ATOMIC WEIGHT
TRACE ELEMENTS OF ENVIRONMENTAL
CONCERN IN COAL
(Continued)
Figure 1.3,10b
ATMOSPHERIC TRANSPORT MODE
VOLATILE HYDROCARBONS
PARTICULATES AND DUST
VOLATILE TRACE ELEMENTS
OXIDES OF SULFUR, NITROGEN AND CARBON
SUMMARY OF POTENTIAL ENVIRONMENTAL
CONTAMINANTS IN COALS
(Continued)
Figure 1.3.lib
-------
MINING
\
STORAGE/
TRANSPORTATION
UTILIZATION
(COMBUSTION)
PREPARATION
COAL PROCESSING STEPS
Figure 1.3.12a
-------
MINING
ATMOSPHERIC
POLLUTION
HYDROCARBON
GASES
DUST
AQUATIC/
TERRESTRIAL
POLLUTION
• SPOIL LEACHING/
BURNING
• ACID DRAINAGE
ENVIRONMENTAL CONTAMINATION FROM
COAL MINING
Figure 1.3.12b
UTILIZATION
(COMBUSTION)
ATMOSPHERIC
POLLUTION
• SULFUR, NITROGEN
AND CARBON OXIDES
• PARTICULATES
• TRACE ELEMENTS
AQUATIC/
TERRESTRIAL
POLLUTION
SLAG/FLY ASH
LEACHING
ENVIRONMENTAL CONTAMINATION
FROM COAL COMBUSTION
Figure 1.3.12d
STORAGE AND TRANSPORT
ATMOSPHERIC
POLLUTION
HYDROCARBON
GASES
DUST
AQUATIC/
TERRESTRIAL
POLLUTION
COAL LEACHING/
BURNING
ENVIRONMENTAL CONTAMINATION FROM
COAL STORAGE AND TRANSPORT
Figure 1.3.12c
PREPARATION
ATMOSPHERIC
POLLUTION
NIL
AQUATIC
TERRESTRIAL
POLLUTION
REFUSE LEACHING/
BURNING
ACID DRAINAGE
SLURRY/PROCESS
WATER
ENVIRONMENTAL CONTAMINATION
FROM COAL PREPARATION
Figure 1.3.12e
-------
ATMOSPHERIC
POLLUTION
COAL
PROCESS
STEP
AQUATIC/
TERRESTRIAL
POLLUTION
HYDROCARBON GASES
DUST
HYDROCARBON GASES
DUST
MINING
SULFUR, NITROGEN AND
CARBON OXIDES
PART1CULATES
TRACE ELEMENTS
STORAGE/
TRANSPORTATION
PREPARATION
SPOIL LEACHING/
BURNING
ACID DRAINAGE
UTILIZATION
(COMBUSTION)
COAL'LEACHING/
BURNING
SLAG/FLY ASH
LEACHING
REFUSE LEACHING/
BURNING
ACID DRAINAGE
SLURRY/PROCESS WATER
BALANCE OF ENVIRONMENTAL CONTAMINATION
FOR COAL PROCESSING AND UTILIZATION
Figure 1.3.12f
-------
STRUCTURAL INSTABILITIES
ACIDIC AND MINERALIZED DRAINAGE
WASTE DUMP BURNING
ENVIRONMENTAL PROBLEMS
FROM DISCARDED COAL WASTES
Figure 1.3.13
SAMPLE
\
2
3
4
5
CONDUCTANCE
(MKROMHOS-CM'I
13600
12400
4400
3500
3000
PH
3,1
2.7
3.0
3.7
4.0
SULFATE
40500
17750
3000
1125
1600
IRON
6168
3197
30
130
1
ALUMINUM
999
1014
87
68
50
MANGANESE
63
31
50
15
90
CALCIUM
340
180
MAGNESIUM
250
140
SODIUM
100
60
POTASSIUM
5
15
CONCENTRATIONS IN MILLIGRAMS PER LITER
AQUEOUS DRAINAGE FROM
PENNSYLVANIA COAL REFUSE DUMPS
Figure 1.3.14
EFFLUENT CHARACTERISTIC
IRON, TOTAL
IRON, DISSOLVED
ALUMINUM, TOTAL
MANGANESE, TOTAL
NICKEL, TOTAL
ZINC, TOTAL
TSS
pH
MAXIMUM FOR ANY 1 DAY
(MILLIGRAMS PER LITERI
7.0
0.60
4.0
4.0
0.40
0.40
70
WITHIN THE
RANGE 6.0 TO 9.0
AVERAGE OF DAILY VALUES
FOR 30 CONSECUTIVE DAYS
SHALL NOT EXCEED
(MILLIGRAMS PER LITEfl)
3.5
0.30
2.0
2.0
0.20
0.20
35
REDUCED ATMOSPHERIC EMISSIONS
FROM COAL COMBUSTION
REDUCED SOLID WASTES FROM COAL
COMBUSTION
VERSUS
INCREASED SOLID AND LIQUID WASTES
FROM COAL PREPARATION
ENVIRONMENTAL TRADE-OFFS FOR
COAL PREPARATION
EPA PROPOSED REGULATIONS FOR AQUEOUS EFFLUENTS FROM COAL
MINING POINT SOURCES - OCTOBER 1975
Figure 1.3.15
Figure 1.3.16
-------
EFFECT OF COAL PREPARATION ON NORTHERN APPALACHIAN RESERVES
R. E. Hucko
J. A. Cavallaro
The Air Quality Act of 1963 initiated a concerted effort by Federal and local governments to
preserve the Nation's air quality. Because air pollution from combustion of fossil fuels has long been
recognized as a problem by the EPA and its counterparts, major emphasis has been placed on
developing methods for controlling sulfur oxide emissions.
Coal-fired electric utility plants are the major source of sulfur oxide air pollution in the United
States today. In 1974, the electric utilities burned 390 million tons of coal with an average sulfur content
of 2.2 percent. The amount of coal consumed by electric utilities is anticipated to reach 500 million
tons by 1980 and approximately a billion tons by the year 2000. It is, therefore, imperative that sulfur
oxide emissions be controlled.
Most of the Nation's coal reserves are too high in sulfur content to be fired directly and meet
existing emission control standards without some pretreatment and/or stack gas scrubbing. It is
recognized, however, that coal preparation will reduce the sulfur levels of the vast majority of
reserves, thereby producing coal of adequately low sulfur content to meet existing standards or
producing a partially desulfurized coal to be used in conjunction with stack gas scrubbing.
The Bureau of Mines has published reports detailing the extent of coal reserves of the United
States by state, county, coalbed, rank, and sulfur content. In addition, other Bureau of Mines studies
have delineated the sulfur release potential of coals from principal utility-coal-producing coalbeds of
the United States. An effort to determine how the present reserves of the Northern Appalachian
region would be distributed by sulfur content if they were subjected to various levels of coal
preparation is reported in this paper. This study was applied to the bituminous coal reserves of the
Northern Appalachian region because many of the coals of this area are amenable to upgrading by
physical beneficiation. Included in this region are Maryland, Pennsylvania, Ohio, and 40 northern
counties of West Virginia.
COAL WASHABILITY STUDIES
In 1965, the National Air Pollution Control Administration funded a study by the Bureau of
Mines to determine the forms of sulfur in the major sources of utility steam coals and the washabilities
of these coals. A washability analysis is an evaluation of those physical properties of a coal that
determine its amenability to improvements in quality by cleaning. This includes stage crushing to
release impurities and specific gravity fractionation to show the quality and quantity of the cleaned
product. A washability study is made by testing the coal sample at preselected, carefully controlled
specific gravities. This is termed "float-sink" analysis or specific gravity separation. Chemical analyses
of the various specific gravity fractions of the coal are made, and these indicate how well the coal can
be prepared. The results of this study have been published as a Burea.u of Mines Report of Investiga-
tions O entitled "Sulfur Reduction Potential of the Coals of the United States."
Six-hundred-pound face samples were collected from surface and deep mines which were
producing coal primarily for consumption by electric utilities. In general, coalbed samples were
collected to reflect current production and known reserves. An attempt was made, however, to
sample the largest utility-coal-producing mines; those sampled to date represent mines that provide
more than 70 percent of the annual utility coal production.
The 600-pound channel samples collected in the field were processed in the following manner.
Each sample was air-dried and then crushed to 11/2-inch top size using a single-roll crusher. The sample
was then coned, long-piled, and shoveled into four pans, according to ASTM specifications, and
divided into two portions by combining opposite pans.
29
-------
One of the 11/2-inch by 0 portions was processed as is, and the other portion was crushed in a
jaw mill to %-inch top size. This %-inch by 0 material was then riffled into two portions; one was
processed as is (%-inch by 0), and the other was crushed to 14-mesh top size (14-mesh by 0) in a
hammer mill and processed.
The various sized fractions were then float-sink tested at 1.30, 1.40, 1.60, and 1.90 specific
gravities using a commercial organic liquid of standardized specific gravity; the solution tolerance is
±0.001 specific gravity unit and was monitored using a spindle hydrometer. Upon completion of the
float-sink testing, the specific gravity fractions of the three sized samples were analyzed for ash, pyritic
sulfur, and total sulfur content.
The float-sink data from the channel samples are not to be construed as representing the quality
of the product loaded at the mine where the sample was taken but rather as indicating the quality of
the bed in that particular geographical location. Float-sink data are based upon theoretically perfect
specific gravity separations that are approached but not equaled in commercial practice.
Shown in Figure 1.4.1 is a typical washability analysis as presented in the sulfur reduction
potential study. In addition to giving weight and Btu recoveries, Btu/lb, and ash and sulfur percentages
at the various separation densities, a subprogram calculates the pounds of SOa per million Btu and
then interpolates the results to show which values, if any, will meet the EPA new-source emission
standard of 1.2 Ibs SO2/MM Btu.
Results from this study are subdivided into the following coal producing regions:
• Northern Appalachian Region
• Southern Appalachian Region
• Eastern Midwest Region
• Western Midwest Region
• Western Region
In the Northern Appalachian region, to which this paper is addressed, 227 coalbed samples
were collected: from Maryland (34), Ohio (58), Pennsylvania (103), and northern West Virginia (32).
The average raw coal of the region contained 15.1 percent ash, 2.01 percent pyritic sulfur, 3.01 percent
total sulfur, and 12,693 Btu per pound, which would produce 4.8 pounds SO2/MM Btu fired at the
powerplant.
As shown in Figure 1.4.2, crushing to 14-mesh and washing at 1.60 specific gravity would provide
an average pyritic sulfur reduction of 65 percent and a total sulfur reduction of 41 percent, which
would result in an SO2 emission reduction of 46 percent.
Figure 1.4.3 shows that only 4 percent of the raw coal samples as mined could meet the current
EPA emission standard of 1.2 pounds SO2/MM Btu. However, 12 percent of the samples would comply
at a Btu recovery of 90 percent when crushed to 11/a-inch top size, and 31 percent would comply at a
Btu recovery of 50 percent when crushed to 14-mesh top size. At a less stringent emission standard of
2.0 pounds of SO2/MM Btu, 15 percent of the raw coal samples would meet this standard with no
preparation, approximately 35 percent would comply at a 90-percent Btu recovery when crushed to
11/2-inch top size, and about 70 percent would comply at a 50-percent Btu recovery when crushed to
14-mesh top size.
RESERVE BASE SURVEY
In 1975, the Eastern Field Operation Center of the Bureau of Mines published a two-volume
compilation of coal reserve data (2-3) for the United States as of January 1,1974. The components of the
reserve base, as defined by the Bureau and incorporated into the survey, are shown in Figure 1.4.4.
30
-------
This Bureau of Mines study was initially funded by the U.S. Environmental Protection Agency. In 1972,
the study was made a part of on-going Bureau programs.
Various State and Federal agencies have previously made coal resource and reserve estimates;
however, because these estimates were often based upon different criteria and assumptions, the
resulting reports varied widely in tonnage values. In contrast, the Bureau of Mines report contains
determinations, developed by uniform criteria, of the location and extent of the reserve base of coal
recoverable by today's mining methods. Data were compiled from a total of 281 sources which are
referenced in the report.
The volume that covered the Eastern United States indicated a coal reserve base of 202.3 billion
tons (Figure 1.4.5). Included in this estimate are bituminous coal (194.0 billion tons), anthracite (7.3
billion tons), and lignite (1.0 billion tons). The reserve base is divided into those coals minable by
underground methods and those minable by surface methods (Figure 1.4.6). The reserve base minable
by underground methods includes 161.5 billion tons of bituminous coal and 7.2 billion tons of
anthracite. Lignite is not considered minable by underground methods. The reserve base minable by
surface methods includes 32.5 billion tons of bituminous coal, 90 million tons of anthracite, and 1
billion tons of lignite.
Figure 1.4.7 shows the reserve base of bituminous coal for those states in the northern
Appalachian region. The totals for West Virginia, however, include those counties in southern West
Virginia that are considered to be part of the southern Appalachian region. The reserve base of
bituminous coal in the northern Appalachian region (this excludes southern West Virginia) is 68.3
billion tons, which represents 35 percent of the total bituminous reserves of the Eastern United States.
As shown in Figure 1.4.8 (from Rl 8680), the data are organized by state, county, coalbed, and
rank. The coal reserve base was, through statistical probability, distributed by increments throughout
the range of sulfur contents determined from coal quality data on file in the energy data bank
maintained by the Bureau of Mines. Only raw coal sulfur analyses were collated with the reserve data
to approximate the sulfur content of in-place coalbeds. The computer distribution included all surfur
categories between the extremes of highest and lowest; no tonnages of coal were allotted to sulfur
categories higher or lower than those levels actually observed. Distribution of the coal reserve base,
by sulfur content, was based on the assumption that the quality of coal remaining in the ground is
basically equivalent to that of the coal that has been mined.
EFFECT OF BENEFICATION ON COAL RESERVES
Given the two sources of data described above, the obvious question arises as to what extent
U.S. coal reserves can be upgraded by utilizing coal preparation techniques. The sulfur content of
Eastern coals varies widely, ranging from a low of 0.3 percent to as much as 5.6 percent. In determining
the potential of coal preparation to produce low-sulfur coal, however, the form in which sulfur occurs
and its amenability to removal are as important as the amount present. Therefore, answering the
question posed above requires intermeshing the two studies previously discussed in order to deter-
mine the tonnages that will exist in each sulfur category following various levels of coal preparation.
To carry out these calculations, it was necessary to make several assumptions. These include:
• For a given coalbed, the percent reduction in sulfur attributable to a given level of coal
preparation is the same regardless of the raw coal sulfur content. Although this is only
an approximation, it is borne out well by Bureau of Mines Report of Investigations Rl
8118.
• The reserves listed as unknown (sulfur contents) in Rl 8680 were considered to be
distributed throughout the sulfur ranges in the same proportion as the remainder of the
reserves in that same coalbed.
31
-------
• In Rl 8680 data do not exist for the sulfur contents in several of the coalbeds. Also, in Rl
8118, sulfur reduction data are not available for every coalbed in the Northern Appalac-
hian region. The percentages of the total reserves for which both sulfur content and
sulfur reduction data are available amount to 93 percent in Maryland, 90 percent in
Pennsylvania, 83 percent in Ohio, and 65 percent in northern West Virginia. It was,
therefore, assumed that tonnages calculated based on reserves for which data were
available could be multiplied by a factor (e.g., 100/90 in Pennsylvania) in order to
represent the total reserves.
The calculations intermeshing the two studies were made according to the following proce-
dure:
1. All reserve data for a given coalbed within a given state were compiled from Rl 8680.
2. Since the upper sulfur limit is simply given as greater than 3.0 percent in Rl 8680, the
average percent sulfur greater than 3.0 was calculated by a mass balance.
3. Using Rl 8118, percent sulfur reductions and percent yield for each coalbed in question
were obtained by Lagrangian interpolation from the given data.
4. The sulfur reduction and yield percentages for each level of preparation were applied
to the reserve data for each coalbed as compiled in step 1.
5. After the calculations were made for all reserves of known sulfur distribution, the new
tonnage corresponding to each sulfur category was increased by the appropriate
percentage as discussed in the third assumption above.
6. The tonnages thus calculated were summarized by States.
Figure 1.4.9 presents a partial summary of the data generated for Pennsylvania. The 10 sulfur
categories listed in the reserve base study have been compressed into 3 in order to make the numbers
more comprehensible. The tonnages cleanable to less than 0.85 percent sulfur (low-sulfur coal) are the
ones of greatest concern because coals cleaned to this sulfur level will generally meet the EPA
new-source emission standard of 1.2 pounds SCh/MM Btu. Strictly speaking, for the coals of this
region, those cleaned at 1.30 specific gravity will have sufficient Btu's per pound to meet the standard;
those cleaned at 1.60 must generally contain no more than 0.82 percent sulfur. As shown in Figure
1.4.9, the present reserve base of coal in Pennsylvania that is less than 0.85 percent sulfur is 591.46
million tons. From reserves somewhat higher in sulfur, coal preparation produces substantial quan-
tities of less than 0.85-percent-sulfur coal. For example, crushing to 11/2-inch top size and cleaning at
1.60 specific gravity results in 1,968.56 million tons of this low-sulfur coal; i.e., over three times as
much as presently available. However, crushing to 14-mesh top size and cleaning at 1.60 specific
gravity would produce 4,774.77 million tons, an eightfold increase. As would be expected, the bulk of
the reserves lie in the 0.85 to 3.0 percent sulfur range. From another point of view, 6 percent of
Pennsylvania's coal reserves with a sulfur content greater than 0.85 percent can be upgraded to
low-sulfur coal «0.85 percent) by crushing to Wa-inch top size and washing at 1.60 specific gravity; 18
percent can be upgraded to low-sulfur coal by crushing to 14-mesh top size and washing at 1.60
specific gravity.
The tonnages, by sulfur category and extent of preparation, for the entire Northern Appalachian
region are given in Figure 1.4.10. The present reserves with sulfur content less than 0.85 percent
amount to 1,727.45 million tons. Crushing to 11/2-inch top size and washing at 1.60 specific gravity
yields 4,172.32 million tons of low-sulfur coal, which is 2.4 times the existing reserves. Crushing to
14-mesh top size and cleaning at 1.60 specific gravity would result in a total of 8,546.31 million tons of
low-sulfur coal which is 4.9 times the present reserves. Four percent of the Northern Appalachian
region reserves with a sulfur content greater than 0.85 percent can be upgraded to low-sulfur coal by
crushing to iy2-inch top size and washing at 1.60 specific gravity; the percentage increases to 10 when
crushing to 14-mesh top size and washing at 1.60 specific gravity.
32
-------
Examination of the figures in Figure 1.4.10 reveals that crushing to 14-mesh top size and cleaning
at 1.60 specific gravity results in a greater tonnage of low-sulfur coal than is obtained when cleaning at
1.30. This apparent anomaly is understandable, however, when one considers that all coals will reach a
point of liberation beyond which the pyrite is totally free and washing at successively lower specific
gravities will simply reduce the yield of clean coal.
Figures 1.4.11 and 1.4.12 show graphically the effect of crushing to various top sizes on the
tonnages of low-sulfur coal potentially available in the Northern Appalachian region. In examining
these figures, as well as those in Figure 1.4.9 and 1.4.10 to establish the benefits of coal preparation, it
is necessary to keep several things in mind. First of all, even though the tonnages of low-sulfur coal
(less than 0.85 percent sulfur)) resulting from coal preparation are a relatively small fraction of the total
reserve base; they represent sizable quantities of coal, equivalent to many years of production at
current and foreseen rates. Moreover, many powerplants constructed prior to 1975 can be brought
into compliance with local emission standards by simply cleaning to an intermediate sulfur level.
In summary, coal preparation has the potential of providing sizable tonnages of coal that will
meet the EPA new-source emission standards. In addition, for powerplants built prior to 1975, far
greater quantities of coal can be burned after upgrading by coal preparation.
REFERENCES
1. Cavallaro, J. A., M. T. Johnston, and A. W. Deurbrouck. Sulfur Reduction Potential of
the Coals of the United States: A Revision of Report of Investigations 7633. BuMines Rl
8118,1976. 323pp.
2. Thomson, R. D., and H. F. York. The Reserve Base of U.S. Coals by Sulfur Content (In
Two Parts) 1. The Eastern States. BuMines 1C 8680,1975. 537pp.
3. Thomson, R. D., and H. F. York. The Reserve Base of U.S. Coals by Sulfur Content (In
Two Parts) 2. The Western States. BuMines 1C 8693,1975. 322pp.
33
-------
STATE: PA (BITUMINOUS)
COUNTY: ARMSTRONG
COALBED: UPPER FREEPORT
RAW COAL MOISTURE: 1.1%
CUMULATIVE WASH ABILITY DATA
SAMPLE CRUSHED TO PASS 3/8 INCH
PRODUCT
FLOAT - 1.30
FLOAT - 1.40
FLOAT - 1.60
FLOAT - 1.90
TOTAL
EPA STANDARD
RECOVERY, %
WEIGHT
47.3
67.9
77.6
B2.9
100.0
57.4
Btu
57.9
81.5
91.2
95.2
100.0
69.5
CALORIFIC
CONTENT
Btu/!b
14481
14194
13892
13576
11826
14359
ASH, %
4.0
5.9
7.9
10.0
21.6
4.9
SULFUR, %
PYRITIC
.17
.24
.35
.45
1.59
20
TOTAL
.84
.89
.99
1.07
2.22
.86
EMISSION
POTENTIAL
Ib S02/MM Btu
1.2
1.3
1.4
1.6
3.8
1.20
TYPICAL WASHABILITY ANALYSIS
(REPORT OF INVESTIGATION 8118)
FIGURE 1.4.1
34
-------
z- 70
o
a
UJ
cc
\
\
\ \ ^ 14 MESH
\ \ 3/8"
- \ ^^
vl
\
\
1.30 1.40 1.50 1.SO
SPECIFIC GRAVITY OF SEPARATION
PYRITIC SULFUR REDUCTION FOR NORTHERN
APPALACHIAN REGION COALS
Figure 1.4.2a
30 -
1.30 1.40 1.50
SPECIFIC GRAVITY OF SEPARATION
TOTAL SULFUR REDUCTION FOR NORTHERN
APPALACHIAN REGION COALS
Figure 1.4.2b
a RAW COAL
b 1* INCH
TOP SEE,
90% BTU
RECOVERED
c 14 - MESH
TOP SIZE,
sm BTU
RECOVERED
0 2 4 6 B 10 12 14 16 18 20
SULFUR EMISSION POTENTIAL, Ib S02/MM Btu
NORTHERN APPALACHIAN REGION
COAL SAMPLES MEETING EPA SO2 STANDARD
Figure 1.4,3
-------
1. BITUMINOUS/ANTHRACITE COAL, 28 INCHES
OR MORE THICK, TO DEPTHS OF 1,000 FEET
2. SUBBITUMINOUS COAL, 60 INCHES OR MORE
THICK, TO DEPTHS OF 1,000 FEET
3. LIGNITE, 60 INCHES OR MORE THICK, TO
DEPTHS OF 120 FEET (ONLY SURFACE MINING)
COMPONENTS OF THE RESERVE BASE
Figure 1.4.4
2,982
65,665
10,623
25,541
1,048
118
21,077
31,001
987
3,650
39,590
BO
70
° 60
=; so
UJ*
3 40
LU
85 30
UJ
OE
20
10
0
40.3 PCT
_
27.4 PCT
16.2 PCT
-
-
-
'///,
'///,
n
_
-
_
16.1 PCT
^
-
-
-
COAL RESERVE BASE IN THE EASTERN
UNITED STATES, Millions of Tons
Figure 1.4.5
KEY
( STRIP
RESERVE BASE
' (UNDERGROUND!
RESERVE BASE
STATE
MARYLAND
OHIO
PENNSYLVANIA
WEST VIRGINIA
TOTAL
MINING
METHOD
DEEP
STRIP
DEEP
STRIP
DEEP
STRIP
DEEP
STRIP
DEEP
STRIP
SULFUR CONTENT, WEIGHT-PERCENT
<1.t>
106.45
28.56
115.45
18.87
981.15
55.45
11,086.60
3,005.46
12,289.65
3,108.34
10-3.0
623.94
66.59
5,449.88
990.96
18,013.46
71721
12,583.41
1,422.82
34,670.69
3,197.58
> 3.0
171.18
16.24
10,109.36
2,524.87
3,568.14
231.52
6,552.88
270.40
20,401.56
3,043.03
UNKNOWN
0
34.57
1,754.09
117.93
2,215.60
83.57
4,142.92
509.55
8,112.61
745.82
TOTAL
901.57
145.96
17,428.78
3,652.63
22,778.35
1,087.75
34,365.81
5,208.23
75,474.51
10,094.57
•=1.0 1.D-3.Q =>3J) UNKNOWN
SULFUR CONTENT, wt-pct
COAL RESERVE BASE IN THE EASTERN UNITED STATES
Figure 1.4.6
RESERVE BASE OF NORTHERN APPALACHIAN
BITUMINOUS COAL, Millions of Tons
Figure 1.4.7
-------
COUNTY
053 GALLIA (OHIO! ^^ ^^
RESERVES
BED :033
DEEP =-28
STRIP=>28
TOTAL
BED: 036
DEEP =-28
STRIP=-2B
TOTAL
— i
£0.4
.00
.00
.00
.00
.00
.00
0.5-0.6
.00
.00
.00
.00
.00
.00
0.7-0.8 0.9-1.0
.00 .00
.00 .00
.00 .00
.00 .00
.00 .00
.00 .00
1.1-1.4
.00
.00
.00
.00
.00
.00
BY SULFUR RANGE
1.5-1.8 1.9-2.2
.00 .00
.00 .00
.00 .00
.00 9.57
.00 3.36
.00 12.93
2.3-2.6
.36
.95
1.31
13.63
4.78
18.41
2.7-3.0
1.9B
5.12
7.08
17.81
6.24
24.05
PERCENT
=»3.0
31.06
80.63
111.69
82.08
28.79
110.87
UN-
KNOWN
.00
.00
.00
.00
.00
.00
TOTAL NA°NA°LF
33.44 53
86.80
120.24
122.88 13
43.10
165.98
AVG
S %
3.5
3.6
RESERVES BY SULFUR RANGE (MM OF TONS)
COAL
RAW
CRUSHED TO Vk INCHES TOP SIZE
CLEANED AT 1.30
CLEANED AT 1.60
CRUSHED TO % INCH TOP SIZE
CLEANED AT 1.30
CLEANED AT 1.60
CRUSHED TO 14 MESH TOP SIZE
CLEANED AT 1.30
CLEANED AT 1.60
< 0.85% S
591.46
2,623.59
1,968.56
3,826.91
3,341.73
4,234.54
4,774.77
0.85-3.00% S
19,608.89
7,437.11
18,465.68
7,539.97
17,148.11
6,692.13
16,074.77
>3.0%S
3,665.63
83.69
796.47
66.39
503.03
48.65
106.31
COMPUTERIZED OUTPUT OF TYPICAL RESERVE BASE
(REPORT OF INVESTIGATION 8680)
Figure 1.4.8
TONNAGES BY SULFUR RANGE
IN PENNSYLVANIA
Figure 1.4.9
RESERVES BY SULFUR RANGE (MM OF TONS)
COAL
RAW
CRUSHED TO 154 INCHES TOP SIZE
CLEANED AT 1.30
CLEANED AT 1.60
CRUSHED TO % INCH TOP SIZE
CLEANED AT 1.30
CLEANED AT 1.60
CRUSHED TO 14 MESH TOP SIZE
CLEANED AT 1.30
CLEANED AT 1.60
-= 0.85% S
1,727.45
4,237.93
4,172.32
6,485.79
6724.53
7,136.62
8,546.31
0.85-3.mS
38,995.41
20,398.17
43,396.58
22,350.99
44,595.82
21,691.77
45,873.05
=» 3.0% S
27,535.04
637.26
14,164.45
651.68
9,918.26
395.59
5,956.40
TONNAGES BY SULFUR RANGE
IN NORTHERN APPALACHIAN REGION
Figure 1.4.10
-------
10,000
__ 1 1/2" 3/8" 14MESH
TOP COAL SIZE AFTER CRUSHING
EFFECT OF CRUSHING AND CLEANING
AT 1.60 SPECIFIC GRAVITY ON THE
AVAILABILITY OF <0.85 PERCENT
SULFUR COAL.
Figure 1.4.11
_ 1 1/2" 3/8" 14MESH
TOP COAL SIZE AFTER CRUSHING
EFFECT OF CRUSHING AND CLEANING
AT 1.30 SPECIFIC GRAVITY ON THE
AVAILABILITY OF <0.85 PERCENT
SULFUR COAL
Figure 1.4.12
10,000
O
o
=>
C/3
o
oc
in
CO
to
C/3
LU
C/5
8,000
4,000
1JO
1 1/T 3/T 14 MESH
TOP COAL SIZE AFTER CRUSHING
COMPARISON OF THE EFFECT OF CRUSHING AND CLEANING
AT 1.60 AND 1.30 SPECIFIC GRAVITIES ON THE AVAILABILITY
OF < 0.86 PERCENT SULFUR COAL
Figure 1.4.13
38
-------
DESIGNING A REGIONAL ATMOSPHERIC CONTROL
STRATEGY FOR ELECTRIC UTILITIES
Dr. Gerald A. Isaacs
Timothy W. Devitt
Ray W. Cunningham
INTRODUCTION
A significant amount of work is being conducted to demonstrate that physical coal cleaning can
be used to reduce SCh emissions from coal-fired boilers. This paper addresses some of the factors that
bear upon the viability of coal cleaning as an effective sulfur dioxide emission control measure. It
presents recent data developed by PEDCo on an EPA sponsored study that investigates the potential
role of coal cleaning in an $62 compliance strategy for selected power generating stations within EPA's
Region IV. Some of the factors that should be considered in designing a regional control strategy
utilizing coal cleaning, flue gas desulfurization (FGD), low sulfur coal, and redistribution of existing
coal supplies are discussed; and an example is presented to show the effect of these factors.
WASH ABILITY DATA
The theoretical limit to which any coal can be physically cleaned is established by the organic
sulfur content of the coal. A washability analysis takes the form of size-gravity fractional analyses of
appropriate coal properties; a washabililty curve can be constructed by starting with the cleanest
fraction in terms of Ibs SCh per million Btu and adding successively dirtier fractions. The resulting
curve starts at zero Btu recovery and the organic sulfur content, and ends at 100 percent Btu recovery
and the raw coal sulfur content. Figure 1.5.1 shows that a good empirical approximation to the curve is
given by an equation of the form:
y = a + b x + cednoo~xl
where the coefficients a, b, c, and d are determined experimentally.
An estimate of washability in this form can be useful in determining the feasibility of cleaning a
given coal to a prescribed SCh level. In the given example, it is evident that the coal from this mine
cannot possibly be cleaned to meet an emission limitation of 3 Ibs SCh per million Btu because of the
high organic sulfur content of the coal (3.2 Ibs SCh/MM Btu). A four-pound limitation can be met if a 10
percent Btu loss can be tolerated. This loss can be reduced somewhat if a coal middlings fraction can
be used economically at another power plant that is within or close to the area for which the regional
strategy is being developed.
COST DATA
Among several investigations of the cost of pollution control conducted by PEDCo, two are
especially appropriate to an SCh strategy optimization program. The first is a computerized program
that estimates the installed capital and annualized costs for gas desulfurization systems. Input to these
programs is specific design and operating information on each boiler for which controls are proposed.
The second investigation resulted in a similar computer program that estimates the capital and
operating costs for coal cleaning plants. This program calculates costs for a three-cleaning-circuit
plant, with provision for two stages in the coarse-coal circuit.
Coal cleaning costs are a function of several variables including design of the coal cleaning
circuits. The effects of plant size and economies of scale were investigated by simulating a specific
plant configuration at several different throughput capacities. The results, presented in Figure 1.5.2,
show that cleaning costs per unit of coal decrease with increasing plant size. Assuming an equation of
the form:
39
-------
y = a xb
a least-squares best fit of the data resulted in the relationship:
y = 39 x -°38
which agrees well with the traditional rule-of-thumb that plant cost bears a 0.6 power relationship to
plant size. It appears that economies of scale are reasonably approached only for coal cleaning plants
with capacities larger than about 500 tons of coal per hour.
A significant portion of the cost of coal cleaning is the heating value that is discarded in the
reject circuit. Total Btu losses exceeding about 5 percent generally cannot be tolerated economically
unless some of the potential Btu losses are recovered elsewhere in the system. If losses exceed that
amount, coal cleaning ceases to be competitive with flue gas desulfurization. Therefore, the cost of
Btu losses, as well as other operating maintenance and capital charges, must be and were added to the
costs generated by our coal cleaning cost estimating program. Total costs, including lost heating value,
were determined for a two-stage cleaning plant having an input capacity of 2,000'tons of coal per hour.
The effects of coal price and recovery yield are shown in Figure 1.5.3. At a coal price of $1.00 per
million Btu, the total cost of coal cleaning is doubled if the yield drops to about 92 percent, as
compared with owning and operating costs only (100 percent yield).
LIMITATIONS AND DISADVANTAGES OF COAL CLEANING
The sensitivity to coal costs and yield has been cited as a major disadvantage of coal cleaning.
However, to the extent that they consume energy, it is evident that all major pollution control
processes are fuel-cost sensitive. The principal limitation of physical coal cleaning is that the degree of
sulfur removal is theoretically limited to the proportion of pyritic sulfur in the coal. In practice, the
limitations are even more stringent. For a typical coal it may be practical to remove only 20 to 40
percent of the sulfur by physical cleaning, whereas an FGD system may provide 85 percent SCh
removal efficiency. The low efficiency of sulfur removal, therefore, greatly restricts the number of
cases for which coal cleaning is economically feasible.
The sulfur and ash removed from the coal create special environmental problems at the coal
cleaning site. Cleaning plant refuse, containing finely divided sulfurous materials, poses significant
problems of water pollution potential. Proper disposal is an important factor to be considered in
evaluating the feasibility of coal cleaning.
It has been suggested that the cleaning process may create problems for wet bottom boilers
because of elevation of ash fusion temperatures. Further testing with specific boiler designs is needed
to resolve this issue. It has also been suggested that the lower sulfur content of the cleaned coal may
adversely affect electrostatic precipitator performance. In the cases that we have investigated, the
sulfur levels have not been reduced enough to create true low-sulfur coals; we believe that the
reduced ash loadings to the boilers will offset any deterioration of precipitator efficiency that may
occur due to lowered sulfur content.
BENEFITS OF COAL CLEANING
In the cases where coal can be physically cleaned to meet SCh emission restrictions, the coal
cleaning strategy should be compared with other control strategies; i.e., the use of alternative coal
supplies and the use of an FGD system. A comparison of coal cleaning and use of alternative coal is
relatively straightforward, consisting essentially of comparing the cost of delivered cleaned coal with
the cost of alternative coals, other factors being equal.
In situations where coal cleaning is technologically and economically feasible, the percent of
sulfur removal that is required must necessarily be relatively low. Since FGD systems are capable of
removing at least 85 percent of the SCh that is generated, an FGD system need clean only a fraction of
40
-------
the flue gas at a power station to match the sulfur removal capabilities of coal cleaning. In such a
situation, although the apparent costs of coal cleaning and FGD may be essentially equal, several
factors favor the use of coal cleaning over FGD systems.
A coal cleaning system tends to produce a relatively consistent low-ash fuel that enhances the
operation of the boiler and produces a minimum of refuse at the power plant. In contrast, an FGD
system can derate power system output and produces sludge that must be handled on-site.
In cases where the annualized costs for coal cleaning are equal to the annualized costs for an
FGD.system, the coal cleaning option may be preferable for a utility since it is less capital intensive. For
comparative purposes, two strategies were investigated for five power stations in Region IV, one using
FGD exclusively, and the other using relatively extensive coal cleaning. Figure 1.5.4 shows that the
ratio of capital to annualized cost for an FGD system ranges from 3.0 to about 3.2, whereas with coal
cleaning the ratio ranges from 1.1 to 2.6. The difficulty of obtaining capital gives the utilities an
incentive to opt for coal cleaning over FGD.
We have also concluded that firing cleaned coal can result in lower costs for boiler mainte-
nance. Our studies indicate that for some coals it may be possible to remove 12 percent of the weight
of the coal while reducing the total Btu content by only 5 percent. At the same time, the ash reduction
on a mass basis would total 47 percent. Since pulverizer wear and maintenance are closely related to
the ash content of coal, it is expected that pulverizer and ash handling equipment maintenance would
be reduced considerably with the burning of cleaned coal. Ash erosion and corrosion of boiler tubes
and flues would also be reduced — beneficial effects that would not accrue in an FGD operation.
We have accumulated some data that relate boiler outage rates to coal properties. Data such as
those shown in Figure 1.5.5, support our conclusion that certain types of boiler failures may be
reduced significantly if coal ash and sulfur contents are reduced via coal cleaning. Several similar
relationships between boiler failures and average annual sulfur and ash contents were determined to
be significant at a 90 percent confidence level. Cleaned coal could thus improve boiler availability and
the resulting capacity factor, since forced outages as well as maintenance costs would be reduced.
In boiler operation, fluctuations in coal quality often make it necessary to increase excess air
rates, thus reducing boiler efficiency. The product of a coal cleaning plant is a more consistent fuel
than raw coal, and this fuel consistency thereby reduces excess air requirements. The lower ash
content in cleaned coal also reduces thermal losses in the boiler ash. The net result is an improved
heat rate, at least in terms of the coal that is fed to the boiler. This increase helps to defray part of the
total cost of coal cleaning.
At various power plants it has become necessary to derate boiler capacities because of deterio-
ration of coal quality. It seems reasonable that coal cleaning could be used to upgrade fuel quality so
that some boilers could be uprated, at least where the unit capacities are not turbine-limited.
REGIONAL STRATEGY ELEMENTS
Designing a regional compliance strategy is considerably more complex than planning for a
single plant. A region suitable for a region-wide compliance strategy should have the following
characteristics:
• Contain several power plants whose mangements are willing to work together to
formulate a combined SCh emission compliance strategy. This entails coordination of
coal procurement activities, joint ownership of preparation plants, and equitable cost
distribution.
• Individual power plants within the region would not all be subject to the same SCh
emission restriction.
• Access to multiple coal supplies.
41
-------
By effectively pooling their joint coal resources, the participants in a regional strategy may be
able to attain all applicable emission requirements at a lower total overall cost than if each participant
adopts an individual compliance strategy. The regional strategy entails a mix of controls which may
include the use of joint coal suplies, coal cleaning plants, and flue gas desulfurization equipment.
INPUT DATA FOR A REGIONAL COMPLIANCE STRATEGY
An effective regional strategy can be developed only if sufficient data are availble to allow
detailed problem definition and analysis. These data can then be reduced to yield an optimum
solution. The following data are required:
• Coal costs, FOB mine — $/MM Btu
• Coal properties — Btu/lb, % sulfur
• Coal cleaning costs — $/kWh output
• Coal cleaning curves — Ib SCh/MM Btu vs % Btu recovery
• Coal supply capacities — MM Btu/week
• Transportation costs — $/MM Btu
• FGD costs —$/kWh
• FGD SCh removal — percent
* Fuel requirements — MM Btu/week
• SCh regulations — Ib SCh/MM Btu
• Power demand — peak kW, kWh/week
• Station heat rates — Btu/kWh
COAL CLEANING APPLICATIONS AS PART OF A REGIONAL STRATEGY
An example of the use of coal cleaning, flue gas desulfurization, low sulfur coal, and fuel
redistribution in a regional strategy is illustrated in this section. The regional strategy considered a
number of coal-fired power plants in EPA's Region IV. The plants derive virtually all of their coal from
mines in Ohio, Illinois, Kentucky, Tennessee, and Alabama. SO2 restrictions at the plants range from
1.2 Ibs SOi per million Btu to 5.2 Ibs SO2 per million Btu. The coal transportation system includes
barge, rail, and truck modes. Plant capacities range from approximatey 250 MW to 2,600 MW.
This strategy was compared with the use of FGD at all plants where SCh control is required.
Figure 1.5.8 shows that fuel redistribution eliminates incremental coal costs at Plants 1, 3, and 5. For
this study incremental transportation costs were assumed to be negligible because of the regional
transportation cost structure. Costs increased at Plants 7, 8,10, and 11, where FGD systems are used in
conjunction with uncleaned coal because of the stringent SOa emission regulations. Coal cleaning
plants are assumed for Plants 4 and 9. Cost of the combined strategy is about 19 percent lower than the
FGD strategy on an annual basis; it is 21 percent lower on a capital investment basis.
CONCLUSIONS
Coal cleaning techniques have been utilized for several years, and many coal cleaning plants are
currently in operation. Rather conventional coal cleaning methods can be used to produce coals that
comply with SCh regulations in some cases. The principal advantages of coal cleaning are reduced
42
-------
maintenance costs, increased boiler availability, boiler rating increases, and better boiler heat rates.
These beneficial effects tend to offset the costs of the cleaning process.
The benefits and disadvantages of coal cleaning strategies are not yet fully documented. There
is a possibility that coal cleaning may alter ash characteristics enough to create firing difficulties with
wet-bottom boilers. It has been suggested also that ESP performance may deteriorate, but since sulfur
removal by coal cleaning is moderate (typically less than 50 percent), this effect should be insignific-
ant; the reduced ash loading to the ESP would probably more than compensate for any loss in
efficiency due to slightly increased fly ash resistivity. Pollution problems resulting from coal cleaning
will mainly occur at the cleaning plant in the form of liquid and solid wastes.
It has become apparent that coal cleaning may be viable for reducing SCh emissions at certain
power plants, especially those where emission requirements are not especially severe with respect to
the coal that is presently fired. Where high SCh removal efficiencies are required, FCD systems are
more economical because fuel loss penalties become excessive for coal cleaning plants.
The concept of using coal cleaning as part of an overall SO> compliance strategy seems to have
merit where several power plants in an area are subject to various SCh regulations. A preliminary study
of selected power generating stations within EPA's Region IV indicates that coal cleaning for two of
nine plants can be used in conjunction with fuel redistribution to optimize compliance costs for the
entire system. This strategy is about 20 percent less expensive, not including potential benefits from
reduced maintenance, etc., than if FGD were used at all plants now out of compliance.
43
-------
< 10
h-
z
LU
5 .
O.
g «4
X fi
§ '
CLEAN COAL
CO
0 10 20 30 40 50 60 70 80 90 100
CLEAN COAL Btu YIELD, percent
COAL CLEANING YIELD CURVE
SINCLAIR MINE - SEAM 9 - UNDERGROUND
Figure 1.5.1
80%
100%
85% 90% 95%
Btu RECOVERY
TOTAL COST FOR TWO-STAGE COAL CLEANING AS A
FUNCTION OF COST AND Btu RECOVERY EFFICIENCY
Figure 1.6.3
0 500 1000 1500 2000
COAL CLEANING PLANT CAPACITY - TONS/HR
COAL CLEANING COST-PLANT SIZE RELATIONSHIP
Figure 1.5.2
PLANT
1
3
4
5
9
CAPITAL COST
f{W)
FGD
27.9
B2.0
82.3
36.0
53.7
CC
18.4
29.4
45.9
24.7
38.9
ANNUAL COST
f/JW
FGD
8.6
16.2
27.6
11.1
17.8
CC
10.8
26.6
18.0
19.1
19.8
HAT/0 OF COST
CAPITAL TO ANNUAL
FGD
3.2
3.2
3.0
3.2
3.0
CC
1.7
1.1
2.6
1.3
2.0
CAPITAL INTENSITY COMPARISON - FGD AND
COAL CLEANING
Figure 1.5.4
-------
I 1 1 1 1 1
INDEPENDENT VARIABLES
COAL SULFUR CONTENT
1967 1968 1969 1970 1971 1972 1973 1974
YEAR
EROSION FAILURES - PLANT 8
Figure 1.5.5
COAL COSTS, FOB MINE - $/106 BTU
COAL PROPERTIES - BTU/LB, PERCENT SULFUR
COAL CLEANING COSTS - $/KWH OUTPUT
COAL CLEANING CURVES - LB S02 /106 BTU
VS PERCENT BTU RECOVERY
COAL SUPPLY CAPACITIES - 106 BTU/WEEK
DATA REQUIREMENTS FOR
A REGIONAL CONTROL
Figure 1 .5.7a
MANAGEMENT COOPERATION BY SEVERAL
POWER PLANTS FOR IMPLEMENTATION OF
A COMBINED POLLUTION CONTROL
STRATEGY.
EXISTENCE OF VARIOUS S02 RESTRICTIONS
AMONG COOPERATING POWER PLANTS.
ACCESS TO VARIOUS COAL SUPPLIES.
STRATEGY ELEMENTS FOR
A REGIONAL CONTROL
Figure 1.5.6
FGD COSTS - $/KWH
FGD SO, REMOVAL - PERCENT
FUEL REQUIREMENTS - 106 BTU/WEEK
POWER DEMAND - PEAK KW, KWH/WEEK
SO2 REGULATIONS - LB SO2 / 106 BTU
STATION HEAT RATES - BTU/KWH
TRANSPORTATION COSTS - $/106 BTU
DATA REQUIREMENTS FOR
A REGIONAL CONTROL
(Continued)
Figure 1.5.76'
-------
PLANT
1
2
3
4
5
6
CAPITAL COST
$(MM)
FGD
27.9
-
52.0
82.3
36.0
-
BEST
STRATEGY
-
-
-
45.9
-
-
ANNUAL COST
SIMM)
FGD
8.6
-
16.2
27.6
11.1
-
BEST
STRATEGY
-
-
-
18.0
-
-
COMPARISON OF COSTS FOR FGD CONTROL
WITH COSTS FOR A COMBINED STRATEGY
USING FGD, COAL CLEANING
AND FUEL REDISTRIBUTION
Figure 1.5 8a
1. TECHNOLOGY IS HERE-NUMEROUS COAL
CLEANING PLANTS ALREADY IN OPERATION.
2. BENEFITS AND DISADVANTAGES HAVE NOT
BEEN FULLY DOCUMENTED.
3. COAL CLEANING IS VIABLE ONLY FOR
SPECIFIC PLANTS AND SYSTEMS.
4. THE CONCEPT OF USING COAL CLEANING AS
PART OF AN OVERALL STRATEGY
INCORPORATING OTHER TECHNIQUES
WITHIN THE SYSTEM SEEMS TO HAVE
SPECIAL MERIT.
CONCLUSIONS IN DESIGNING A REGIONAL
ATMOSPHERIC CONTROL STRATEGY FOR
ELECTRIC UTILITIES
PLANT
7
8
9
10
11
TOTAL
CAPITAL COST
$(MM)
FGD
99.6
99.7
53.7
114.4
124.2
689.8
BEST
STRATEGY
102.6
106.8
35.3
116.1
136.5
217.0
ANNUAL COST
$(MM)
FGD
30.3
31.1
17.8
36.0
38.3
543.2
BEST
STRATEGY
31.2
33.1
16.8
36.5
41.6
177.2
COMPARISON OF COSTS FOR FGD CONTROL
WITH COSTS FOR A COMBINED STRATEGY
USING FGD, COAL CLEANING, AND FUEL
REDISTRIBUTION
(Continued)
Figure 1.5.8b
Figure 1.5.9
-------
PART II. CLEANING PROCESSES
-------
IMPLEMENTATION OF COAL CLEANING
FOR SOa EMISSION CONTROL
James D. Kilgroe
INTRODUCTION
Sulfur oxide air pollution emissions from coal combustion exceeded 20.5 million tons in 1974.
With the increasing use of coal as an energy source, improved methods are needed for the control of
this pollutant. Major strategies for the control of SCh emissions include the use of coal cleaning, the
combustion of coal in chemically active fluidized beds, the removal of pollutants by flue gas scrubbing
and the generation of clean synthetic fuels. An economically attractive control strategy is coal clean-
ing. This paper presents the current status of coal cleaning technology, and discusses barriers which
must be overcome before this technology can be widely implemented for SO2 emission control.
TECHNICAL STATUS
Coal Cleanability
The sulfur content of coal normally ranges from less than 1 to more than 7 percent. Sulfur
appears in coal in three forms: mineral sulfur in the form of pyrite (FeSi), organically bound sulfur, and
trace quantities of "sulfate" sulfur. Sulfate sulfur occurs in coal as a result of the attack of oxygen on
the mineral pyrite. It is soluble in water and can be removed in wet coal preparation plants. Organic
sulfur occurs as part of the organic coal structure and cannot be removed by physical coal preparation
techniques. Pyrite occurs in coal seams in sizes ranging from small discrete particles to large lumps. It
can be found intimately dispersed in the coal substance, in bands, in layers, or in large pieces.
Physical preparation or cleaning techniques are capable of removing varying fractions of the
pyritic sulfur as determined by the properties of each coal. Chemical processes are capable of
removing over 95 percent of the pyritic sulfur and up to about 70 percent of the organic sulfur.
Laboratory float-sink studies have been performed on over 455 U.S. coals to determine their
physical cleanability.O The samples tested were from mines in the six major coal producing regions of
the U.S., the mines which provide more than 70 percent of the coal used in U.S. utility boilers.
The results of these float-sink tests indicate that in general pyrite removal increases with
reduced particle size and specific gravity of separation. This fact is extremely important. It implies that
to enhance pyritic sulfur removal more of the coal must be crushed and processed at finer particle
sizes than historically practiced in coal preparation. A second important fact determined by these
studies is that the final sulfur levels to which coals can be cleaned vary from coal region to coal region
and from one coal bed to another within the same region (coal cleanability also varies to a lesser extent
from location to location within the same mine). These differences in physical cleaning potential are
the result of variations in the organic and pyritic sulfur levels and the morphology of the coal-pyrite
matrix.
Sulfur removal by chemical methods is dependent upon coal properties and process conditions
— time, pressure, temperature, and chemical reagents. A number of experimenters have studied
these relationships^'3). In other instances the availabililty of information is limited because it is
considered to be proprietary. Process costs will probably limit the amount of sulfur which can be
removed to about 95 percent of the pyritic sulfur and 40 percent of the organic sulfur.
Figure 2.1.3 presents parametric relationships between the degree of cleaning (pyritic and
organic sulfur reduction), the sulfur level of the cleaned coal, and the percentage of utility coals which
can be cleaned to a specified sulfur content.
49
-------
Status of Coal Cleaning Technology
Coal preparation processes for steam coal are oriented toward the removal of ash and mining
residue. Chemical coal cleaning is in the early stages of development and it is estimated that a
commercial plant could not be put into operation for at least 5 to 10 years. Figure 2.1.4 summarizes
several chemical coal cleaning processes now under development. The remaining discussions will deal
primarily with the use of physical coal cleaning as an SCh pollution control method.
The physical removal of pyritic sulfur from steam coal has not been commercially used as a
method of SCh emission control. The physical removal of pyrite from many coals will require crushing
to fine particle sizes prior to separation. Separation at these fine sizes, while not impossible, repre-
sents a shift to a mix of equipment and operating conditions which are different from those tradi-
tionally used for steam coal preparation. Dewatering and drying of a large percentage of fine coal may
be required for many of the new plants.
The variability of sulfur forms within a coal bed or mine presents a special problem which will
require the development of improved technology if coal cleaning is to be used for SCh emission
control. Methods are needed for controlling the sulfur variation in the plant feed and process
instrumentation is needed to control the product sulfur level.
The coal preparation plant performance in removing pyritic sulfur can be seriously affected by
wide variations in feed coal properties. Development of mining and blending schemes to minimize the
pyritic sulfur variations in the feed coal will be needed to insure a product coal which consistently
meets fuel sulfur requirements. Currently there is little published data on the variability of fuel sulfur
forms in coal beds. The effects of mining, blending, and preparation plant operations in "averaging
out" the cleaned coal sulfur level are unknown. Because of these factors, the cleaning plant must now
be designed to remove sufficient pyritic sulfur so that even at peak raw coal sulfur levels (both organic
and pyritic), the product coal sulfur will be maintained below that required by the fuel sulfur emission
regulation. This approach may not be practical in some cases as it would require the reject of large
quantities of fuel which do not exceed the emission regulation.
A long term objective would be to develop process instruments and controls which could be
used to adjust plant operating conditions in response to the changes in the feed coal sulfur content.
This method of control would allow optimization of sulfur removal and Btu recovery. Unfortunately
instruments which can be used for a real time determination of coal sulfur, ash, and Btu values are not
commercially available.
Options for Using Coal Cleaning
Physical coal cleaning can be used on a limited number of U.S. coals to meet federal new source
performance standards (NSPS) for steam generators. Moreover a large number of coals can be
physically cleaned and used:
• To meet stringent state SCh emission standards.
• In conjunction with flue gas desulfurization (FCD) to lower emission control costs.
• To produce a multiplicity of product coals, each with a different fuel sulfur value.
Only 14 percent of the 455 U.S. coals tested by the Bureau of Mines are capable of meeting NSPS
standards without cleaningf1). Physically cleaned at atop size of IT/i-inch, and with a Btu recovery of 90
percent (10 percent of the heat from the mined coal would be lost), a total of 24 percent of these coals,
could meet NSPS. The percentage of coal which will be cleaned to NSPS levels could be increased by
either a reduction in the particle size of coal being cleaned or a reduction in the Btu recovery value of
the cleaned product. In the latter case the reject coal could probably be used in a boiler with FGD.
A much larger percentage of coals is capable of meeting widely varying state standards. Figure
2.1.6 presents data on the amounts of pyritic sulfur which can be removed from coal samples from six
50
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regions by crushing to a 3/8-inch top size and by separating at a specific gravity of 1.6. As illustrated the
average fuel sulfur values for the cleaned coals from these six regions range from 1.3 to 5.5 Ibs SCh/mm
Btu. In all cases the Btu recovery exceeds 92 percent. Many states have emission regulations which
range from 2.0 to 5.0 Ibs SCh/mm Btu and a large portion of the tested coals can be cleaned to meet
these regulations. Figure 2.1.7 presents the relationship between selected cleaning conditions and the
number of samples which can be cleaned to meet specific emission standards.
The use of physical coal cleaning in combination with flue gas desulfurization (FCD) represents
an approach where the advantages of each technique can be used to minimize emission control costs
while permitting the most effective use of U.S. coal resources. A recent study on the use of a
combination of physical coal cleaning and flue gas desulfurization shows significant economic advan-
tages to this combined pollution control method(4). In 36 case studies in areas where local regulations
for SCh emissions vary from 1.2 to 1.6 Ibs SCh/mm Btu, the cost of using a combination of conventional
coal cleaning and flue gas desulfurization was 2 to 55 percent lower than flue gas desulfurization alone
for new plants, and 10 to 60 percent lower for existing plants. The arithmetic average for the cases cited
showed costs which were about 30 percent lower for new plants and 40 percent lower for existing
plants.
An alternative strategy which would make greater utilization of our coal resources would be to
prepare (clean) coal in such a fashion that it is divided into a number of fractions — each with a
different sulfur content. Each coal fraction could thus be used in a different boiler to meet different
sulfur emission regulations. The multi-stream coal cleaning strategy being used at the Pennsylvania
Electric Co. Homer City Plant for the physical desulfurization of coal is an example of this approach to
pollution control. At the Homer City plant, the product coals will include 800 tph of coal with an
equivalent sulfur emission value of 4.0 Ibs SCh/mm Btu and 400 tph of coal with a sulfur emission value
of 1.2 Ibs SCh/mm Btu.
The production of multiple coal streams in commercial plants to produce fuel for several
non-utility markets has significant potential. Mine-mouth preparation plants of advanced design could
produce a number of product coals with different fuel sulfur levels. The lower sulfur fuels could be
sold for use in small commercial or industrial boilers in which the scale of operation makes FGD
uneconomical. The higher sulfur coals could be used in existing boilers which are not subjected to
stringent standards or they could be burned in large boilers equipped with FCD systems.
BARRIERS TO THE IMPLEMENTATION OF COAL CLEANING TECHNOLOGY
Technical and Regulatory Uncertainties
There is still considerable economic risk related to technical and regulatory uncertainties which
act as effective barriers to the implementation of physical coal cleaning as an SCh emission control
strategy. The use of coal cleaning as a tool for meeting SCh emission regulations is based upon
engineering and scientific judgment. This pollution control strategy has been used only in a few
isolated cases, generally with easily cleaned coals. The unknown economic risks are primarily related
to the requirement for meeting consistent fuel sulfur specifications. In a given plant, the mix of
equipment or the process controls may not prove to be adequate to consistently remove pyritic sulfur
to the required degree. Technical solutions to this problem would involve a number of economically
unattractive alternatives:
• Adjust the preparation plant operating conditions in a manner which would reduce the
fuel recovered from the plant feed.
• Make extensive equipment modifications.
• Add a partial FGD system to the boiler.
A great deal of this economic risk could be reduced by more flexible regulatory activities. The
modification of existing emission regulations to permit emissions to be averaged over a moderate time
51
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period, say 8 hours, would greatly alleviate this risk. In cases where a mix of emission regulations apply
to a single site, the use of a site average emission regulation could, in some instances, reduce control
costs and risks.
Other technical or regulatory uncertainties include:
• The costs of pollution control requirements for advanced coal preparation plants.
• Changes in boiler operating and maintenance costs which result from the firing of
cleaned coal.
• The effects of firing cleaned coal on the performance of electrostatic precipitators.
'Extensive commercialization of physical coal cleaning for SCh emission control probably cannot
be expected until these uncertainties are resolved.
Institutional and Economic Barriers
A number of institutional and economic barriers block implementation of the use of coal
cleaning for SCh emission control. Among these barriers are existing investments and contracts, the
dependency of the utility industry upon other organizations for its fuel supply, a limited supply of
personnel familiar with coal cleaning, and the high cost of capital.
Vertical integration in the utility industry is not common. Few utilities own their own fuel
resources. A large percentage of coal resources are owned by railroads, steel companies, coal
companies, oil companies, and private owners. The common practice is to obtain coal through short
or long term contracts. Further, the coal supplier has traditionally cleaned his coal primarily to remove
ash and mining residue. In today's coal market there is not a clear recognition by the supplier of clear
cost differentials based upon the coal sulfur levels. The supplier thus does not have an economic
incentive to clean his coal with the objective of removing sulfur. While the coal industry enjoys a
healthy market with high profits, investment is largely directed to expansion of capacity through
mechanization, and to the use of goods and services needed to meet new mine safety and environ-
mental regulations. Incentives for coal cleaning in the coal industry must come from the market
(utilities), regulatory activities, or tax laws. None of these incentives is now operable.
Utilities can contract with coal suppliers for coal cleaning, or they can clean the coal themselves.
However, in some instances current investments and contract commitments are disincentives to this
action. An example of these disincentives is the extensive use of Pittsburgh bed coal by utilities in the
Appalachian region. A number of coal companies have high investments in existing mines and a
number of utilities have long term contracts for this Pittsburgh bed coal. This coal is high in organic
and pyritic sulfur and cannot be easily used to meet emission standards with little or no cleaning.
However, the costs of breaking existing contracts, developing new mines, and constructing coal
preparation plants may be more costly than the use of FGD on either existing or new generating units.
Another problem in implementing coal cleaning technology is that of identifying coal reserves
that are adaptable to physical cleaning. Although cleanability studies have been performed by the
Bureau of Mines, their work has been restricted to coals available from existing mines. Cleanability
data are also needed on coal seams and geographic areas not currently developed. In this way
promising new resources can be identified for development.
Difficulties which utilities may experience in raising capital may also serve as a barrier to
implementation. Investors may be reluctant to support the capitalization of coal cleaning facilities
because of the technical and regulatory uncertainties involved. Existing tax credits for equipment
depreciation may also favor FCD over coal cleaning. Low interest rate government loans, positive
environmental regulations, and modified tax laws could eliminate this economic barrier.
52
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The lack of familiarity of the utility industry with coal cleaning as a pollution control may also
serve as barrier to implementation. New technology is adopted in an industry only after it has been
adequately demonstrated and accepted as a viable technology by a majority of the industry members.
This barrier to implementation can best be overcome by joint government-industry research, de-
velopment and demonstration (RD&D) activities. The utilities involved in this RD&D activity must be
deeply involved and must eventually be committed to the development of new technology for the
entire industry. The utility industry has not been oriented toward RD&D, and the development of
government/industry teams is difficult. Current economic limitations on utility and government man-
power available for RD&D compound this difficulty.
CONCLUSIONS
Physical coal cleaning can be used to meet a variety of state and federal SCh emission regula-
tions, singly or in combination with flue gas desulfurization. There is an increasing awareness by the
coal and utility industries of coal cleaning as a method of SCh control. However, this technology will
not be widely used as pollution control strategy until a number of technical, regulatory, and institu-
tional problems are resolved. They include:
• The determination of the performance and costs of coal preparation equipment and
processes in removing sulfur.
• The development of improved methods for controlling the sulfur levels in coal pro-
duced by coal preparation plants.
• A clear acceptance by industry and regulatory agencies of this pollution control strate-
gy-
REFERENCES
1. Cavallaro, J. A., M. T. Johnston, and A. W. Deurbrouck. Sulfur Reduction Potential of U.S.
Coals: A Revised Report of Investigation, EPA 600-2-76-091 or Bureau of Mines Rl 8118,
Washington, D.C., April 1976.
2. Hamersma, J. W., and M. L. Kraft. Applicability of the Meyers Process for Chemical Desulfuri-
zation of Coal: Survey of Thirty-Five Coals, EPA-650-2-74-025-a, Washington, D.C., September
1975.
3. Reggel, et al. Preparation of Ash-free, Pyrite-free Coal by Mild Chemical Treatment, pre-
sented at American Chemical Society (Division of Fuel Chemistry) National Meeting, New
York City, August 27-September 1,1972.
4. Aresco, S. J., L. Hoffman, and E. C. Holt, Jr. Engineering/Economic Analyses of Coal Prepara-
tion with SOz Cleanup Processes for Keeping Higher Sulfur Coals in the Energy Market,
Preliminary Report on U.S. Bureau of Mines contract J0155171, The Hoffman-Munter Corpora-
tion, Silver Spring, Maryland, June 1976.
53
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TOTAL SULFUR AND SULFUR FORMS
- ORGANIC SULFUR
- PYRITIC SULFUR
PHYSICAL AND CHEMICAL CHARACTERISTICS
OF COAL-MINERAL MATRIX
- SIZE AND DISTRIBUTION OF PYRITE
- TOTAL MINERAL MATTER
- HEAT CONTENT
t£ 100
UJ
ce w
. 80
W
S !0
g BO
J—
S 50
cc
a 40
LLJ
| 30
S3 20
10
n
v ^
- ££
. y M
o"
^ ^^
<^
' ^
-------
CURRENT TECHNOLOGY
USED COMMERCIALLY FOR REMOVAL OF ASH
AND MINING RESIDUE
INCREASED RECOGNITION OF POTENTIAL USE
FOR S02 EMISSION CONTROL
CONSTRUCION OF A 1200 tph PLANT AT
HOMER CITY, PA. FOR SO2 EMISSION CONTROL
LU
O
CE
CO
LU
_l
CL
2
co
O
O
co
D
DEVELOPMENT NEEDS
OPTIMIZE EQUIPMENT AND CIRCUITS FOR
PYRITE REMOVAL
PROCESS CONTROLS
DETERMINATION OF COSTS
STATUS OF PHYSICAL COAL CLEANING
Figure 2.1.5
2 t 6 B 10 12 14 16 18 20 22 24
COAL POLLUTANT (OR SULFUR EMISSION) POTENTIAL
Ib S02/mm Btu
EFFECT-OF-CLEANING VARIABLE ON
COAL POLLUTION POTENTIAL
Figure 2.1.7
CUMULATIVE ANAL YSES OF FLOAT 160 PRODUCT FOR 3/8 TOP SIZE
COAL
REGION
NOTHERN
APPALACHIAN
SOUTHERN
APPALACHIAN
ALABAMA
EASTERN
MIDWEST
WESTERN
MIDWEST
WESTERN
TOTAL U. S.
NO.
SAMPLES
227
35
10
95
44
44
455
PERCENT
Btu
RECOVERY
92.5
96.1
96.4
94.9
91.7
97,6
93.8
ASH
8.0
5.1
5.8
7.5
6.3
6.3
7.5
PYRITIC
SULFUR
0.85
0.19
Q.49
1.03
1.80
0.10
0.85
TOTAL
SULFUR
1.86
0.91
1.16
2.74
3.59
0.56
2.00
POUNDS
SO/101
Btu
2.7
1.3
1.7
4.2
5.5
0.9
3.0
CALORIFIC
CONTENT, Btu
m POUND
13,766
14,197
14,264
13,136
13,209
12,779
13,530
SUMMARY OF THE PHYSICAL DESULFURIZATION
POTENTIAL OF COALS BY REGION
Figure 2.1.6
PARTIAL PHYSICAL CLEANING FOR
PYRITE REMOVAL
- EASILY CLEANED COALS
- MODERATE EMISSION STANDARDS
TOTAL PHYSICAL CLEANING
- SINGLE SULFUR LEVEL PRODUCT
- MULTIPLE SULFUR LEVEL PRODUCTS
COMBINATIONS OF PHYSICAL COAL
CLEANING AND FGD
COMBINATIONS OF PHYSICAL AND
CHEMICAL COAL CLEANING
EMISSION CONTROL STRATEGIES FOR
SO2 EMISSION CONTROL
Figure 2.1.8
-------
TECHNICAL & REGULATORY
UNCERTAINTIES
PERFORMANCE OF EQUIPMENT IN
REMOVAL
SULFUR
PROCESS CONTROL
EFFECTS OF CLEANED COAL ON:
- BOILER PERFORMANCE
- ESP PERFORMANCE
- RESIDUE DISPOSAL REQUIREMENTS
POSSIBLE NEW REGULATORY ACTIONS
BARRIERS TO IMPLEMENTATION OF COAL
CLEANING FOR SO2 EMISSION CONTROL
INSTITUTIONAL AND ECONOMIC
UNCLEAR COST DIFFERENTIAL FOR SULFUR
CLEANED COAL
NON-UTILITY OWNERSHIP OF COAL RESOURCES
TOTAL COSTS RELATIVE TO OTHER S02 CONTROL
METHODS
- EXISTING INVESTMENTS AND CONTRACTS
- COSTS OF NEW MINES AND FACILITIES
- COST AND SCARCITY OF CAPITAL
BARRIERS TO IMPLEMENTATION OF COAL
CLEANING FOR SO2 EMISSION CONTROL
(Continued)
Figure 2.1.10
Figure 2.1.9
CURRENT STATUS
ACCEPTANCE OF COAL CLEANING FOR S02 CONTROL
-UTILITIES
-COAL INDUSTRY
AWARENESS BY LEGISLATORS AND REGULATORY
AGENCIES
ACCELERATION
OF TECHNOLOGY DEVELOPMENT
CONCLUSION: STATUS OF COAL CLEANING
TECHNOLOGY
Figure 2.1.11
METHODS FOR ACCELERATING
IMPLEMENTATION
POSITIVE LEGISLATIVE AND REGULATORY ACTIONS
TECHNOLOGY DEVELOPMENT
-IMPROVE PROCESS CONTROLS
-OBTAIN ADDITIONAL CLEANING EQUIPMENT PERFORMANCE
DATA
-REFINE CLEANING AND POLLUTION CONTROL COSTS
-OBTAIN ADDITIONAL RESERVE DATA
CONCLUSION: METHODS FOR ACCELERATING
IMPLEMENTATION OF COAL CLEANING TECHNOLOGY
Figure 2.1.12
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PHYSICAL COAL CLEANING CONTRACT RESEARCH BY THE U.S. BUREAU OF MINES
P. S. Jacobsen
A. W. Deurbrouck
INTRODUCTION
Physical coal cleaning research as typically performed by the U.S. Bureau of Mines has involved
mainly in-house evaluations. Very little contract research has been funded. This trend is now being
altered as a result of increased national attention being paid to coal and its preparation to meet
ever-expanding demands for energy consistent with legislated environmental restraints. The Bureau of
Mines and EPA under an interagency agreement have responded to meet this energy demand with
increased programs in both in-house and contract research on physical coal cleaning. Current and
proposed contract research is discussed in this paper.
SPECIFIC STUDIES
Contracts in the following specific areas are now current:
• Surface phenomena in the dewatering of coal.
• Control of black water in coal preparation plant recycle and discharge.
• High gradient magnetic separation (HGMS).
• Adsorption-desorption reactions in the desulfurization of coal by a pyrite flotation
technique.
Surface Phenomena in the Dewatering of Coal
USBM/EPAContract No.: G0155137
Duration: 36 months
Starting date: July 1,1975
Total dollar value: $75,779
Syracuse University
During this investigation, experiments will be conducted to characterize the dewatering of
fine-size coal, to estimate the effect of an electric field on the dewatering process, to determine the
influence that slurry pH has on dewatering, and to assess the influence of selected chemical additives
on moisture retained in filter cakes.
Control of Black Water in Coal Preparation Plant Recycle and Discharge
USBM/EPA Contract No.: G0155158
Starting date: July 1,1975
Duration: 24 months
Total dollar value: $55,366
Pennsylvania State University
Under this grant, a laboratory investigation of the flocculation process is being carried out in the
treatment of black water from coal preparation plants. In this investigation, a quantitative evaluation
will be made of the interrelation of coagulation rate, settling rate, and sludge volume to establish a
technique for producing as dense a sludge as possible from a thickener operating at the highest
possible rate. Further, the results of studies on the coagulation of heterogeneous systems will be used
to develop mathematical models to simulate the coagulation of particles in practical systems.
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High Gradient Magnetic Separation (HGMS)
USBM/EPA Contract No.: H0366008 USBM/EPA Contract No.: H0366009
Starting date: March 1,1976 Starting date: March 19,1976
Duration: 12 months Duration: 13 months
Total dollar value: $85,020 Total dollar value: $94,690
General Electric Company Massachusetts Institute of Technology
USBM-National Science Foundation
Starting date: March 1,1976
Duration: 15 months
USBM funding: $25,000 Total: $132,100
Indiana University Foundation
General Electric Company, in conjunction with The Massachusetts Institute of Technology (MIT)
and Eastern Associated Coal (EAC), is attempting to establish the technical feasibility of removing a
substantial fraction of the inorganic sulfur from dry coal powders at commercially significant process-
ing rates. Reduction of sulfur by HGMS could permit the direct combustion of large coal reserves east
of the Mississippi River, which have a high percentage of pyritic sulfur but are low in organic sulfur. In
tests to date, significant reductions in pyritic sulfur, as well as ash, were achieved. The data are
presented in Figures 2.2.1 and 2.2.2.
Under another Bureau of Mines-EPA contract, researchers at the Massachusetts Institute of
Technology are studying the application of HGMS to the recovery of fine-size magnetite from dense-
medium circuits in coal preparation plants.
In addition, the Bureau of Mines is partially funding HGMS investigations being conducted at
the Indiana University Foundation. The general objective of this project is to transfer the new high
gradient magnetic separation technology to the beneficiation and concentration of coal and metallic
ores (ferrous and nonferrous), and make possible the recovery of coal and ores not currently
economically viable.
Adsorption-Desorption Reactions in the Desulfurization of Coal by a Pyrite Flotation Technique
USBM/EPA Contract No.: H0155169
Starting date: July 1,1975
Duration: 24 months
Total dollar value: $102,252
University of Utah
Recent studies by the Bureau have demonstrated that a promising new two-stage pyrite flotation
technique can reduce the pyritic sulfur content of fine coal. Several aspects of this proposed flotation
separation require detailed study at a fundamental level and constitute the basis for this investigation.
Specific details of the proposed research work under this contract include:
• Identify and characterize the hydrophilic polymeric second-stage coal depressants.
• Determine the important operating variables which control the adsorption-desorption
reactions, and relate these results to the flotation response of the mineral constituents.
• Establish procedures, as necessary, to allow for subsequent coal flotation and plant
water recycle without deleterious effects due to residual reagent concentrations.
Studies of colloidal depressant adsorption by one of the coals have shown that starch (dextrin)
has a high adsorption potential, and that effective coal depression can be achieved by relatively low
(0.1 mg/1) concentrations (Figure 2.2.3) which correspond to less than monolayer coverage. The
flotation response of coal-pyrite in the presence of xanthate, however, is not significantly affected by
dextrin additions of less than 60 mg/1 (Figure 2.2.4).
58
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GENERAL STUDIES
Contracts in the following more general areas are now current or are being negotiated:
• Lignite upgrading.
• Characteristics and removal of pyritic sulfur from selected U.S. coals.
• Computer simulation of coal preparation plants.
• Engineering/economic analysis of coal preparation with SCh cleanup processes for
keeping higher sulfur coals in the energy market.
Lignite Upgrading — USBM Contracts Under Negotiation.
The lignite deposits of North Dakota and Montana represent one of the largest fossil fuel
reserves of the United States, totaling more than 23 billion tons of recoverable reserves. The utilization
of this fuel has been limited by its high inherent moisture content, tendency toward spontaneous
combustion, and its often high sodium content. The goal of the Bureau of Mines program to upgrade
lignite will be to produce a final product that will contain 10 percent moisture and 0.3 percent sodium.
The final product will be a pellet of sufficient mechanical strength to resist breakage during shipment
and storage and will be resistant to spontaneous combustion.
The reduction of the sodium content of lignite and the pelletization and heat drying of the
lignite pellets are the major unit operations in a proposed 5-ton-per-hour pilot plant for upgrading
lignite. Two contracts are being negotiated, one to develop a practical continuous process for
removing sodium from lignite by ion exchange, and another to demonstrate the pelletization of lignite
and the subsequent drying of the pellets to a moisture content of 10 percent or less.
Characteristics and Removal of Pyritic Sulfur From Selected U.S. Coals
USBM/EPA Interagency Agreement
Starting date: July 1,1965
Duration: Continuing
Total dollar value per fiscal year: $150,000
In 1965, the Federal Government funded a continuing study by the Bureau of Mines; and in
1967, a similar study for 2 years' duration by the Commercial Testing and Engineering Company to
determine the forms of sulfur in the major sources of utility steam coals, and the washabilities of these
coals. Rl 8118 entitled "Sulfur Reduction Potential of U.S. Coals" has been published; the data in this
report were compiled from the work done in these two studies, thus covering work performed from
1965 to mid-1974.
This report presents the results of a washability study of 455 raw coal channel samples with
special emphasis on sulfur reduction. The information generated by this study is necessary to assess
the impact physical desulfurization of coal might have on the level of sulfur oxide emissions from
stationary combustion sources. This study is being continued by the Bureau of Mines under the
Interagency Agreement.
Figure 2.2.5 shows that significant reductions of impurities can be obtained, especially ash and
pyritic sulfur contents, by crushing and gravimetric separation.
Figure 2.2.6 shows that only 14 percent of raw coal samples as mined could meet the new source
SCh emission standard of 1.2 pounds SCWMM Btu. Twenty-four percent of the samples would meet
the standard at a 90-percent Btu recovery when crushed to 11/2-inch top size, while 32 percent would
meet the standard at a Btu recovery of 50 percent when crushed to 14-mesh top size.
59
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The composite data (Figure 2.2.7) show that if all the coals were upgraded at a specific gravity of
1.60, the analyses of the clean coal products of the various regions would range on the average from
5.1 to 8.3 percent ash, 0.10 to 1.80 percent pyritic sulfur, 0.56 to 3.59 percent total sulfur, and 12,779 to
14,264 Btu per pound; and would produce 0.95 to 5.5 pounds of SCh/MM Btu at Btu recoveries ranging
from 91.7 to 97.6 percent. The corresponding SCh removal efficiencies required for a stack gas
scrubbing system to bring these coals into compliance with the Federal sulfur emission regulations of
1.2 pounds SO2/MM Btu would range from zero to 78 percent.
Computer Simulation of Coal Preparation Plants
USBM/EPA Interagency Agreement
USBM Contract No.: G0155030
Starting date (Phase II): December 1,1975
Duration: 21 months
Total dollar value (Phase II): $93,657
University of Pittsburgh
To assist in the prediction of full-scale coal preparation plant operation, a computer simulation
program is being developed under contract with the University of Pittsburgh. The standard prediction
of product quality is included (such as ash, sulfur, Btu, and yield), calculated on the basis of extensive
equipment performance distribution data collected by the Bureau of Mines. Several other features,
though, are more novel. This includes the mathematical modeling of the rotary breaker, other
crushers, screens (both wet and dry), centrifugal and thermal dewatering equipment, and hydraulic
and static thickeners. The overall capability of the computer program is such that a build-your-own
preparation plant can be simulated. In addition, the capital and operating costs for that particular plant
will be available from an extensive economic-evaluation subroutine. This complete simulation pro-
gram will thus enable rational choices to be made of alternate circuits for ash and sulfur reduction
based on reliable engineering data and overall capital operating economics. A more complete sum-
mary of this computer simulation study is being presented at the 14th International Symposium on The
Application of Computer Methods in the Mineral Industries, October 4-8, 1976, at The Pennsylvania
State University.
Engineering/Economic Analysis of Coal Preparation With SCfe Cleanup Processes for Keeping Higher Sulfur
Coals in the Energy Market
USBM/EPA Contract No.: J0155171
Starting date: June 30,1975
Duration: November30,1976
Total dollar value: $79,534
Hoffman-Muntner Corporation
An interesting study has just been completed for the Bureau of Mines by the Hoffman-Muntner
Corporation entitled "Engineering/Economic Analysis of Coal Preparation With SCh Cleanup Processes
for Keeping Higher Sulfur Coals in the Energy Market." This study was done to evaluate the economic
potential of coal preparation when combined with stack gas scrubbing. Generally speaking, of the
various methods for reducing the sulfur content of coals, the physical removal of pyritic sulfur is the
lowest cost and most widely applied technology. However, a number of those coals currently being
mined and utilized cannot, by physical upgrading alone, meet the new source sulfur emission
standard of 1.2 pounds of SCh per million Btu. The concept of physical coal cleaning combined with
flue gas desulfurization is not new. For some time there have been discussions, speculations, and
some preliminary assessments addressing the possible benefits of physical coal desulfurization fol-
lowed by flue gas desulfurization.
The Hoffman-Muntner study is an in-depth analytical assessment of a number of theoretical
case studies. In these studies, actual coal use areas, coal source areas, and the most probable coalbed
source are defined. An economic evaluation is then made of the cost of a new utility plant exclusively
60
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removing SO? by stack gas scrubbing down to the new source emission standard. This is followed by a
similar evaluation of the combined use of physical coal cleaning plus stack gas scrubbing to attain the
same sulfur emission level.
The complete results of this study will be presented at the National Coal Association/Bituminous
Coal Research Coal Conference in Expo 3, October 19-21, in Louisville, Kentucky.
U.S. Bureau of Mines Coal Preparation Process Development Facility
USBM/EPA Contract: J0366002
Starting date: April 5,1976
Duration: 9 months
Total dollar value: $412,000
Birtley Engineering Corporation — Professional Services for Design and Engineering Data for
the Coal Preparation Process Facility, Equipment, and Structural Support.
USBM/EPA Contract No.: J0366050
Starting date: July 15,1976
Duration: 8 months
Total dollar value: $206,665
Williams/Trebilcock/Whitehead (Architect-Engineering Services)
The coal preparation research of the U.S. Bureau of Mines is widely recognized for its depth and
general applicability to the needs of industry. Nevertheless, in the United States there is no govern-
ment operated fully integrated process-development-type facility for testing a new coal washing
technique, flowscheme, or piece of equipment.
With the implementation of a central coal preparation process development facility operated by
the Bureau at the Bruceton, Pa., location, many of the past problems of introducing new technology to
the industry would be alleviated. Unbiased engineering data could be readily scaled up to full-size
commercial coal preparation plant operation. Moreoever, the expense of evaluating processes that
prove to be of limited value to the industry would be greatly reduced.
The pilot plant section of the proposed facility will have a nominal capacity of 10 to 25 tons per
hour of raw coal depending on the flowscheme used; process flexibility will be a prime design
requisite of this pilot plant.
The facility will contain also an equipment and process development area smaller in scale than
the pilot plant to initiate work on research projects before they are taken into the pilot plant section for
scale-up to commercial realization. Supporting bench-scale and analytical laboratories and offices for
engineering support personnel will complete the proposed Coal Preparation Process Development
Facility, as shown in an artist's rendering in Figure 2.2.8.
SUMMARY
This brief report of U.S. Bureau of Mines-EPA contract research shows the wide spectrum of
interest these agencies have in physical coal preparation. As increasing attention is given by the Nation
to energy-related problems, the Bureau and EPA will keep pace with expanding programs in contract
research of both physical and chemical coal preparation.
61
-------
MAGNETIC HELD INTENSITY
(Ut oersteds)
10.69
21.38
42.75
64.13
85.5
21.38
21.38
21.38
21.38
21.38
0
0
moan
Ian/sec)
2.80
2.80
2.80
2.80
2.80
1.51
3.26
4.55
5.86
9.80
1.74
2.98
REDUCTION M SULFUR
(front)
11.1
42.5
48.8
56.8
44.0
51.3
48.7
18.8
21.4
7.1
9.2
0
REDUCTION IN TOTAL SULFUR OF EASTERN
COALS (48 mesh by O) USING HIGH
GRADIENT MAGNETIC SEPARATION
MAGNETIC FIELD INTENSITY
fkHo oersteds)
10.69
21.38
42.75
64.13
85.5
21.38
21.38
21.38
21.38
21.38
0
0
VELOCITY
Ian/sec)
2.80
2.80
2.80
2.80
2.80
1.51
3.26
4.55
5.86
9.80
1.74
2.98
REDUCTION IN ASH
(percent/
32.6
43.1
48.6
55.2
47.9
44.7
45.6
16.7
14.7
8.5
7.0
15.3
Figure 2.2.1
ICO
O
o
o
u
COAL FLOTATION
n -1:
SEAM:
SIZE:
pH:
2 MINUTES
LOWER FREEPORT
48x65 MESH
5.7
40
0.1
100
DEXTRIN ADDITION, MG/I
COAL FLOATATION RECOVERY
IN THE ABSENCE OF ABRASION
Figure 2.2.3
REDUCTION IN ASH OF EASTERN
COALS (48 mesh by O) USING HIGH
GRADIENT MAGNETIC SEPARATION
Figure 2.2.2
COAL PYRITE/MARCASITE
SIZE: 65 X 100 MESH
IxlO'3 M KNO
pH: 6.5
- nn i\ntUn
0.5 5 IT 50 100
DEXTRIN ADDITION, MG/I
EFFECT OF DEXTRIN ADDITION ON COAL-PYRITE FLOTATION
WITH POTASSIUM AMYL XANTHATE (KAX) AS COLLECTOR.
Figure 2.2.4
-------
£
70
60
50
40
* *
\ \ .14
\
MESH
1 1/2" "
4r
1.40 1.50 1.60
SPECIFIC GRAVITY OF SEPARATION
ASH REDUCTION FOR
TOTAL U.S. (455 SAMPLES)
Figure 2,2.5*
70
1
i
s
^
60-
50-
40 -
30
14MESH
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY OF SEPARATION
PYRITIC SULFUR REDUCTION FOR
TOTAL U.S. (455 SAMPLES)
Figure 2.2 5b
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY OF SEPARATION
SULFUR REDUCTION FOR
TOTAL U.S. (455 SAMPLES)
Figure 2.2.5c
c
0>
O
CJ
Q
LU
cc
q
w
LU
cc
D
LL
_J
CO 20
1 1/2"
1.30 1.40 1.50 1.60
SPECIFIC GRAVITY OF SEPARATION
SULFUR EMISSION REDUCTION
FOR TOTAL U.S. (455 SAMPLES)
Figure 2.2.5d
63
-------
REGION
NORTHERN APPALACHIAN
SOUTHERN APPALACHIAN
ALABAMA
EASTERN MIDWEST
WESTERN MIDWEST
WESTERN
TOTAL
UNITED STATES
RESULT OF CLEANING
At 1.60 SPECIFIC GRAVITY
-------
REVIEW AND STATUS OF THE TRW/MEYERS PROCESS
R. A. Meyers
LJ. Van Nice
M. J. Santy
INTRODUCTION
Coal can be desulfurized prior to combustion using the Meyers Process(1-2) to meet governmen-
tal requirements for sulfur oxide emissions.
The physical form of the coal remains unchanged, only sulfur and some inorganic materials are
removed. The process removes up to 80 percent of the total sulfur content of coal through chemical
leaching of 90 to 95 percent of the pyritic sulfur contained in the coal matrix with aqueous ferric sulfate
solution at temperatures of 90° to 130°C. The ferric sulfate content of the leach solution is regenerated
at similar temperatures using air or oxygen; and elemental sulfur and iron sulfates are recovered as
reaction products, or alternatively, gypsurn can replace a portion of the iron sulfates as a product.
The process consists of several steps including crushing, chemical treating, sulfur removal, and
solution regeneration (Figure 2.3.1). While the process is new, the unit operations are based on
various existing technologies such as: processes for the heap leaching of copper (operation 1), (Figure
2.3.3), regeneration of steel mill waste pickle liquor (operation 3), and the recovery of elemental sulfur
from volcanic ash (operation 2). The chemistry of the process is represented by the treating step
(Equation 1) and the solution regeneration (Equation 2):
- FeS2 + 4.6 Fe2 (SO^s + 4.8 hhO >10.2 FeSC>4 + 4.8 hhSCU + 0.8 S (1)
2.4 O2 + 9.6 FeSO4 + 4.8 H2SO4 > 4.8 Fe2 (SCMa + 4.8 H2O (2)
A set of products which can be obtained from a 440 tph (6,400 hrs/yr operation) Meyers Process
plant removing 1.0 percent by weight pyritic sulfur from coal is shown below:
_ Product _ Tons/year _ ______
Elemental Sulfur 11254
CaSO4»2H2O 15137
FeOH SO4 74509
The process applies primarily to coals rich in pyritic sulfur rather than those with mainly organic
sulfur. Such coal is found in the Appalachian region of the United States which now supplies 60
percent of the current U.S. production. This production can be lowered to sulfur contents of 0.6 to 0.9
percent for an estimated one-third of the production, at which level the emission requirements for
new power plants can be met(3). Most remaining Appalachian coal and Eastern Interior Basin coal can
meet state and local standards for existing power plants after treatment by the Meyers Processf4).
TEST PLANT
The Process is under development for the Environmental Protection Agency. Because of the
success of extensive laboratory and bench-scale testing (over 200 separate material balanced leach and
regeneration runs on over 30 different coals), the process is now in scale-up. A Reactor Test Unit (RTU)
sized to process up to 8 tons per day of coal is being built, under the sponsorship of EPA at TRW's
Capistrano Test Site (Figure 2.3.11). The RTU facility will be capable of on-line evaluation of the
following critical process operations:
• Leaching of pyritic sulfur from 10 to 100 mesh top-size coal.
65
-------
• Regeneration of ferric sulfate both separately, for processing larger top-size coal or low
pyrite coal, and in a single vessel with the leaching step for processing of suspendable
coal.
• Filtration of leach solution from reacted coal.
• Washing of residual iron sulfate from the coal.
Iron sulfate crystallization, elemental sulfur recovery, and coal-drying unit operation will be
evaluated in an off-line mode. Coarse coal processing (%- to 3/s-inch top-size) has been very promising
in laboratory tests5. If this approach proves out in bench-scale evaluation, coarse coal leaching units
may be added to the RTU.
Processing fine coal allows the highest rate of pyritic sulfur removal, while processing coarse
coal, although slower, allows lower cost coal dewatering units and the direct shipping of desulfurized
coal product without need for pelletizing.
ENGINEERING DESIGN AND COST ESTIMATES
Conceptual design or cost estimates of full-scale plants have recently been prepared by a
number of organizations including TRW(5), Dow Chemical USA(6), Exxon(7) and EPR1 - U. of Michi-
gan(8). They show that the process is economically competitive with projected costs for flue gas
scrubbing, particularly for small installations or the average coal-fired electric utility where power
generation load factors are less than 90 percent.
Some of the process variations which have been tested and engineered include the following:
• Leaching and regeneration temperatures of 90° to 130°C.
• Leaching and regeneration in the same or separate vessels.
• Removal of generated elemental sulfur by vaporization or solvent extraction.
• Air vs oxygen for regeneration.
• Feed coal top-sizes of 1/4-inch, 14-mesh, 100-mesh and near 200-mesh.
• Slurry solids content from 20 to 33 percent.
• Oxygen partial pressures of 1 to 8 atm.
• Combinations of the process with coal cleaning plants.
• Collocation with the power plant at a mine or at a separate site.
A processing cost range (investor financed) of $7 - $14/ton of coal is reported by Dow(6) for
treatment of fine coal, with a thermal efficiency of 90 percent from run-of-mine coal crushing to
desulfurized and crushed product coal. A processing cost range (utility financed) of $6 to $10/ton is
reported by TRW(5) for treatment of fine coal and $3 to $6 for treatment of coarse %- or %-inch top-size
coal. Coal yield, on a Btu basis, is 94 percent for fine coal and 90 to 95 percent for coarse coal. Overall
process thermal efficiency based on an Exxon developed flowsheet was recently calculated at 92.1
percent(7).
A TRW developed flow diagram for treatment of fine coal (14-mesh top-size) by the Meyers
Process is shown in Figure 2.3.14. In this design, leaching and regeneration is accomplished in the
same vessel at a temperature of 120°C and oxygen partial pressure of 1 to 5 atm. Approximately 85
66
-------
percent of the pyrite is reacted in the first vessel. Reaction is completed to the 90 to 95 percent level in
the second reactor. The coal is then washed free of residual iron sulfate and conveyed to a dryer where
generated elemental sulfur is vaporized and the coal is dried. The products of this particular design are
those described above. The capital cost for a coal desulfurization plant to provide low sulfur utility
coal, which was developed from a detailed flow diagram and equipment list, is $100/KW power plant
name plate capacity operating at baseload(5). This is for removal of 3 percent sulfur from raw
run-of-mine coal. For lower pyritic sulfur coals, cleaned coal or less than baseload utilities, the capital
cost is diminished. The relative cost of each section is shown in Figure 2.3.13.
REFERENCES
1. Hamersma, J. W., and M. L. Kraft. Applicability of the Meyers Process for Chemical Dulfuriza-
tion of Coal: Survey of Thirty-Five Coals, Environmental Protection Technology Series, EPA
650-2-74-025a, Washington, D.C., September 1975.
2. Hamersma, J. W., et al. Applicability of the Meyers Process for Chemical Desulfurization of
Coal: Initial Survey of Fifteen Coals, Systems Croups of TRW Inc., Redondo Beach, CA,
Report No. EPA 650-2-74-025, Contract No. 68-02-0647, April 1974.
3. Lorenzi, L. Jr., J. S. Land, L. J, Van Nice, and R. A. Meyers. Engineering Economics and
Pollution Control Assessment of the Meyers Process for Removal of Pyritic Sulfur from Coal,
Preprints Div. of Fuel Chemistry, Am. Chem. Soc., 17 (2) 16,1972.
4. Lorenzi, L. Jr., J. S. Land, L. J. Van Nice, E. P. Koutsoukos, and R. A. Meyers. Coal Age, 77 (11)
76,1972.
5. U.S. Environmental Protection Agency, Research Triangle Park, N.C., Bench Scale Develop-
ment of a Process for the Chemical Extraction of Sulfur from Coal, Systems Group of TRW,
Inc., Redondo Beach, CA, Contract No. 68-02-1336. Report in Preparation.
6. Nekervis, W. F., and E. F. Hensley. Conceptual Design of a Commercial Scale Plant for
Chemical Desulfurization of Coal, Environmental Protection Technology Series, EPA 600-2-
75-051, September 1975.
7. McCee, E. M. Evaluation of Pollution Control in Fossil Fuel Conversion Processes, Coal
Treatment: Section 1. Meyers Process, Environmental Protection Technology Series, EPA
650-2-74-009K, September 1975.
8. Tek, M. Rasin. Coal Benefication, An Evaluation of Coal Conversion of Processes, PB-234202,
1974.
67
-------
PROCESS DiSCHIPTION
f1> CRUSHED COAL IS TREATED WITH WARM FERRIC SULFATE SOLUTION
F«S2 * 4.6 F«2(SO4)3 + 4.8 H2O—10.2 F«SO4 + 4.8 HjSO4 + 0.8S
(2 GENERATED SULFUR IS REMOVED WITH A WARM SOLVENT »ATH OR BY VAPORIZATION
Ot FERRIC SULFATE SOLUTION IS REGENERATED WITH O2 AND EXCESS FERRIC AND
FERROUS SULFATE IS REMOVED
9.6 F«5O4 " 4.8 H?SO4 + 2.4 O2 — 4.8 F«2(SO4)3 + 4.8 HjO
DESCRIPTION OF THE MEYERS PROCESS
Figure 2.3.1
68
-------
CRYSTALS OF SULFUR PRODUCED BY
MEYER'S PROCESS
Figure 2.3.2
-------
FeS2 + 4,6 Fe2(SO,)3 + 4.8 H20 -10.2 FeSO, + 4.8 H2S04 + O.B S I -
AH = -55 Kcal/g-mole FeS2 = -0.10 MM Btullb-mole FeS2 Reacted >^j
CHEMICAL EQUATION AND ENTHALPY
ASSOCIATED WITH THE LEACHING STEP
Figure 2.3.3 .
PYRITE REMOVAL OCCURS IN THE MIXER, LEACH-REGENERATION REACTOR,
AND AMBIENT PRESSURE REACTOR. THE REMOVAL RATE IN ALL THREE
REACTORS IS GOVERNED BY THE EMPIRICAL LEACHING RATE EXPRESSION
:KLWp2Y2,
WHERE
Wp - WT PERCENT PYRITE IN COAL
Y - FERRIC ION TO TOTAL IRON RATIO IN THE REACTOR REAGENT
K L = RATE CONSTANT, A FUNCTION OF TEMPERATURE AND COAL
TOP-SIZE
KINETICS OF THE LEACHING STEP
Figure 2.3.4
1.0 FeS04+ 0.5 H2S04 + 0.25 02 — 0.5 Fe2 (804)3 * °-5 H2°
AH =-18.6 Kcai/g-mole FeSO 4 =-.0335 MM Btu/lb-mole FeS04
CHEMICAL EQUATION AND ENTHALPY
ASSOCIATED WITH THE REGENERATION STEP
Figure 2.3.5
REAGENT REGENERATION IS GOVERNED BY THE RATE EXPRESSION
WHERE
KR = AR expl-E, /RT),
P0 = OXYGEN PARTIAL PRESSURE
Fe+ 2 = FERROUS ION CONCENTRATION IN THE REAGENT SOLUTION
A R AND E R ARE CONSTANTS
THE REAGENT REGENERATION RATE OPERATES SIMULTANEOUSLY WITH THE
LEACHING RATE IN THE LEACH-REGENERATION REACTOR
KINETICS OF THE REGENERATION STEP
Figure 2.3.6
-------
OPERATION
1. SLURRY MIXING AND
HEATING
2. SIMULTANEOUS LEACHING
AND REGENERATION
3. SETTLING
TEMP, °C
20-120
120
90
PYRITE
REMOVAL, %
10-20
80-90
90-95
RATIO OF Fe+++
TO TOTAL Fe(Y)
08-05
05-09
0.9-08
SIMULTANEOUS FERRIC SULFATE LEACH AND
REGENERATION-BASED PYRITE REMOVAL PROCESS
Figure 2.3.7
4 8 12 16 20 24 28 32 36 40 44 48
TIME/HOURS
EFFECT OF COAL TOP-SIZE AND
CLEANING ON LEACH RATE
Figure 2.3.9
1 UPPER FREEPORT SEAM COAL (60 MESH TOP SIZE)
2 LOWER KITTANNING COAL (14 MESH TOP SIZE)
SUSPENDABLE COAL LEACHING WITH 5 WT % Fe REAGENT SOLUTION
20 WT % ROM COAL SLURRIES
120'C, 100 PSIG
— 'L-R —
1.0
2.0
3.0 4.0 5.0
REACTION TIME, HOURS
6.0
7.0
8.0
PYRITE LEACHING RATES FROM UPPER FREEPORT
AND LOWER KITTANIMING MINE COALS
Figure 2.3.8
0.05-
ff.25-
oc
ffi
0.45-
02468
LEACH TIME, HOURS
PYRITE REMOVAL AS A FUNCTION OF TIME
WASHED VS UNWASHED COAL AT SAME
STARTING PYRITE CONCENTRATION
Figure 2.3.10
-------
ARTIST CONCEPTION OF THE REACTOR
TEST UNIT (RTU)
Figure 2.3.11
ONE THIRD (1/3) TON PER HOUR
CONTINUOUS LEACHING AND
REGENERATION
COAL TOP SIZE RANGE = 8 MESH
TO 100 MESH
REACTOR TEST UNIT (RTU) CAPABILITIES
Figure 2.3 12
-------
ITEM PERCENT OF TOTAL
REACTION 25
WASHING 9
SULFATE REMOVAL 12
SULFUR REMOVAL 7
PROCESS TOTAL 53
OFF SITE REQUIREMENTS 27
CONTINGENCY 20
BUILDINGS:
LABS
SHOPS
OFFICES
STORAGE
DISPOSAL
OFF SITE REQUIREMENTS
27% OF TOTAL CAPITAL
INVESTMENT
CRUSHING
GRINDING
UTILITIES:
STEAM
ELECTRICAL
AIR
WATER
COMPACTING
SHIPPING
CAPITAL INVESTMENT OVERVIEW
FOR THE MEYERS PROCESS
Figure 2.3.13
RELATING CAPITAL INVESTMENT TO PROCESS FLOW:
OFF SITE REQUIREMENTS
(FINE COAL PROCESSING TRW-MEYERS PROCESS)
Figure 2.3.14 e
REACTION
25% OF TOTAL CAPITAL INVESTMENT
WASHING
9% OF TOTAL CAPITAL INVESTMENT
MIXING
t
COAL
w
w
REACTION/
REGENERATION
T
OXYGEN
fe
w
SECONDARY
REACTION
FILTRATION
^
w
WASHING
^
w
DEWATERING
r
..*.
RELATING CAPITAL INVESTMENT
TO PROCESS FLOW: REACTION
(FINE COAL PROCESSING TRW-MEYERS PROCESS)
Figure 2.3.14a
RELATING CAPITAL INVESTMENT
TO PROCESS FLOW: WASHING
(FINE COAL PROCESSING TRW-MEYERS PROCESS) CONTINUED
Figure 2.3.14b
-------
SULFATE REMOVAL
12% OF TOTAL CAPITAL INVESTMENT
SULFATE REMOVAL
A
1
' W
NEUTRALIZATION
4
IRON
SULFATE
RELATING CAPITAL INVESTMENT TO PROCESS FLOW:
SULFATE REMOVAL
(FINE COAL PROCESSING TRW-MEYERS PROCESS) CONTINUED
Figure 2.3.14c
SULFUR REMOVAL
7% OF TOTAL CAPITAL INVESTMENT
1
r
SULFUR
VAPORIZATION
fc
W
DRYING
I
SULFUR
PRODUCT
COAL
RELATING CAPITAL INVESTMENT TO PROCESS FLOW:
SULFUR REMOVAL
(FINE COAL PROCESSING TRW-MEYERS PROCESS) CONTINUED
Figure 2.3.14d
74
-------
,
COAi DiSULFURIZATiON - }/4 INCH CONTINUOUS PROCESS
p
1 I
1 *
I
\
1.
T
f "____» •****«.
— ***;vV<
_L ; '
r V" f^
4-;.;.:.H
y' r V : » » T^
f*nrirrE»ia^*^
^v-
Figyre 4
TRW
COARSE COAL DESIGN: CONTINUOUS
REACTOR TYPE
Figure 2.3.15
-------
<
COAt OESUlfURIZATION 1/4 INCH PIT REACTOR
COARSE COAL DESIGN: PIT REACTOR TYPE
Figure 2.3.16
-------
5.5
5.0
4.5
DC
0.
cc
35
d'd
3.D
2.5
O 2.0
DC 1.5
0.
0.5
0.0
APPALACHIAN
INTERIOR BASINS
WESTERN
r7 -
= 4 .
0.0
2.5
0.5 1.0 1.5 2.0
ORGANIC SULFUR, PERCENT
DISTRIBUTION OF SULFUR FORMS
(DRY MOISTURE FREE BASIS)
IN RUN-OF-MINE U.S. COALS
Figure 2.3.17
77
-------
THROUGH USE OF THE MEYERS PROCESS, SOME
90 BILLION TONS OF APPALACHIAN COAL
RESERVES COULD BE PROCESSED TO MEET NEW
SOURCE PERFORMANCE STANDARDS (NSPS)
INCREASED USE OF EASTERN COAL WITHOUT FGD
TO MEET NSPS
- OVERALL ENERGY EFFICIENCY OF THE PROCESS IS 87-91 PERCENT
- COST ESTIMATES FOR THE PROCESS $8-12/TON
- ABLE TO REMOVE 90 TO 95 PERCENT OF THE PYRITIC SULFUR
MEYERS APPLICABILITY, ENERGY
EFFICIENCY AND COST
Figure 2.3.18
MAY BE COMBINED WITH PHYSICAL COAL CLEANING
AS MEANS OF REDUCING MEYERS PROCESS
CAPITAL COSTS
THE GREATEST POTENTIAL MARKET IS UTILITY,
COMMERCIAL, INSTITUTIONAL AND INDUSTRIAL
BOILERS
MEYERS STRATEGY AND MARKET POTENTIAL
Figure 2.3.19
EPA HAS FUNDED FOR $5M FOR DESIGN,
CONSTRUCTION, AND ONE YEAR TEST
- 8.0 TON/DAY PILOT PLANT
- CONSTRUCTION STARTED IN JULY 1976
- EPA IS SEEKING USiR INTEflEST DURING
ONE YEAR TEST PHASE
MEYERS REACTOR TEST UNIT (RTU) FUNDING
Figure 2.3.20
-------
HYDROTHERMAL COAL DESULFURIZATION
WITH COMBUSTION RESULTS*
E. P. Stambaugh
A. Levy, R. D. Ciammar
K. C.Sekhar
INTRODUCTION
Coal is the major source of energy for the United States and will continue to be so for many
years. However, much of this abundant source of energy contains high concentrations of sulfur,
nitrogen, and ash which includes significant quantities of toxic metals. During the combustion of coal,
these materials find their way into the environment and thus constitute a health hazard.
Conceptually, the simplest option for reducing the SOx health hazards associated with coal
combustion would be to burn run-of-the-mine low-sulfur coal. However, most of our coal supply has a
sulfur content too high to permit direct combustion.
Another alternative is to clean the coal by chemical beneficiation prior to combustion. One
potential chemical process for the desulfurization of coal is based on hydrothermal technology.
Research results, as discussed in this paper, have confirmed the initial assessment that this approach is
a potential means of producing an environmentally acceptable solid fuel from certain coals.
PROCESS DESCRIPTION
As applied to the chemical cleaning of coal, hydrothermal processing entails heating an aque-
ous slurry of coal and a chemical leachant, at a temperature and for a period of time sufficient to
promote the extraction of the impurities from the coal. The basic process as depicted schematically in
Figure 2.4.2 comprises 5 major processing operations:
• Coal Preparation
• Hydrothermal Treatment (desulfurization)
• Solids/Liquid Separation
• Fuel Drying
• Leachant Regeneration
Coal preparation may be composed of a simple grinding operation to reduce the raw coal to the
desired particle size. On the other hand, this operation may entail two operations — grinding of the
coal to the desired particle size followed by a physical beneficiation operation to remove a portion of
the ash and the pyritic sulfur.
Hydrothermal treatment entails basically three processing steps. First, the prepared coal is
mixed with the leachant to produce the raw coal slurry. Next, the raw coal slurry is pumped through
heated autoclaves, where it is heated to a temperature necessary for extraction of the sulfur and a
significant portion of the ash. From the autoclaves, the coal product slurry passes through a heat
exchanger where it is cooled. It then exits to a receiving tank.
This work was sponsored by the U.S. Environmental Protection Agency, Research Triangle Park,
North Carolina, under Contract No. 68-02-2119.
79
-------
The coal product slurry is then pumped from the receiving tank into a filter where the product
coal is separated from the spent leachant. The product coal is then washed to remove the residual
spent leachant. The final product is a solid fuel containing reduced concentrations of sulfur and,
depending on the leaching conditions and the leachant, ash.
Drying of the fuel to remove the residual moisture is optional. In some uses, it may be desirable
to burn the clean coal wet, i.e., as received from the filters. In other cases, removal of a part or all of
the residual moisture may be desired. In any event, drying of the coal can be achieved in a variety of
commercial available dryers.
The spent leachant may be regenerated for recycle in several ways. One approach entails
carbonation of the spent leachant to remove the sulfur as hbS. The H2S is then converted to elemental
sulfur by the Claus or Stretford Process. The resulting liquor, after sulfur removal, is treated further
with lime and then recycled to the mixing (slurry) tank.
COAL PREPARATION FOR COMBUSTION STUDIES
For the EPA combustion study, hydrothermally treated (HTT) coals were prepared from (1) a
Lower Kittanning seam coal from the Martinka No. 1 Mine located in West Virginia, and (2) a Pittsburgh
seam coal from the Westland Mine located in Pennsylvania. Both coals, even after physical beneficia-
tion, contained sulfur concentrations greater than the equivalent of 1.2 pounds of sulfur dioxide/MM
Btu (Federal Sulfur Emission Standards for new sources). Therefore, in order to use the coals as a
source of fuel, the coals must be cleaned before combustion or the stack gases scrubbed for SOx
removal.
The HTT coals were prepared in the miniplant facility (a small pilot plant with a production rate
of about 1/4 ton/day). Sodium hydroxide and a mixture of sodium hydroxide and lime were used as the
leachants.
Several types of HTT were prepared:
• Low-sulfur, residual alkali, residual ash in which the residual alkali was sodium. In this
case, sodium hydroxide was used as the leachant. Sodium content of the HTT coal was
at a level attainable by water-washing. The sodium chemically bound to the coal and
that associated with the ash was not removed by the water wash.
• Low-sulfur, residual alkali, residual ash in which the residual alkali was primarily cal-
cium. In this case, a mixed leachant system composed of NaOH-Ca (OH)a was used to
desulfurize the coal and to replace with calcium the majority of the sodium normally
retained in the coal when NaOH was used as the leachant.
• Low-sulfur, low-ash, low-alkali coal noted as deashed HTT coal. This coal was prepared
by washing the sodium hydroxide HTT coal with dilute sulfuric acid.
Analyses of these coals before and after treatment are shown in the following tables.
80
-------
ANALYSIS OF HIT COALS AND CORRESPONDING RAW COALS
Marti nka#1 Coal
NaOH-Ca (OH)2
Analysis
Proximate Analysis
hbO, %
Ash, %
Volatile
Fixed Carbon
Heat value, Btu/lb (MAP)
SO2, Ib/MM Btu
Ultimate Analysis
hhO, %
Carbon, %
Hydrogen,%
Nitrogen, %
Sulfur, %
Ash, %
Oxygen, % by difference
Sodium, %
Calcium, %
Raw
0.41(0.51)*
19.7(24.65)
29.2(36.6)
50.7(63.7)
(15,210)
2.94
0.41(0.51)
67.0(83.4)
4.4(5.5)
1.21(1.50)
1.79(2.24)
19.7(24.65)
5.5(6.9)
0.20(0.03)
0.13(0.16)
NaOH Leachant
3.05(3.65)
13.4(16.03)
28.5(34.1)
35.0(65.8)
(14,800)
0.97
3.05(3.65)
71.4(85.5)
4.5(5.4)
1.3(1.56)
0.60(0.72)
13.4(16.03)
5.7(6.8)
4.6(5.51)
0.15(0.18)
Leachant
0.40(0.56)
28.0(39.1)
26.3(36.7)
45.3(63.3)
(14,691)
1.16
0.4(0.56)
56.4(81.2)
3.8(5.3)
1.1(1.54)
0.61(0.85)
28.0(39.1)
7.7(10.75)
1.4(1.96)
6.6(9.2)
*Numbers in parentheses refer to moisture ash free basis.
ANALYSIS OF HIT COALS AND CORRESPONDING RAW COALS
Analysis
Proximate Analysis
H20, %
Ash, %
Volatile
Fixed Carbon
Heat value, Btu/lb (MAF)
SO2, Ib/MM Btu
Ultimate Analysis
H20, %
Carbon, %
Hydrogen, %
Nitrogen, %
Sulfur, %
Ash, %
Oxygen, % by difference
Sodium, %
Calcium, %
Raw
<0.1(<0.1)*
10.0(11.1)
36.9(41.0)
53.1(59.1)
(14,950)
3.01
<0.1(<0.1)
73.9(82.1)
5.1(5.7)
1.5(1.7)
2.02(2.5)
10.0(11.1)
7.5(8.3)
0.20(0.02)
0.08(0.09)
Westland Coal
NaOH Leachant
0.4(0.5)
13.3(15.4)
31.2(36.1)
55.1(63.8)
(14,320)
1.50(c)
0.4(0.5)
70.3(81 .5)
4.3(5.0)
1.5(1.7)
0.93(1.07)
13.3(15.4)
4.3(10.8)
2.08(2.4)
0.20(0.23)
Mixed Leachant
8.2(10.8)
16.5(21.9)
30.4(40.4)
44.9(59.6)
(14,100)(al
1.50(c)
8.2(10.8)
63.7(84.6)
4.3(5.7)
1.4(1.9)
0.67(0.89)
16.5(21.9)
5.2(6.9)
0.19(0.25)
6.0(8.0)
Deashed HIT
Westland Coal
4.31(4.60)
2.19(2.24)
31.5(33.7)
62.0(66.3)
(14,349)
-------
Examination of the data indicates that:
• Environmentally acceptable solid fuel, with respect to sulfur content, can be produced
by hydrothermal treatment of Martinka and Westland coals using sodium hydroxide and
a mixture of sodium hydroxide and calcium hydroxide as the leachant systems. The
clean coals contained a sulfur equivalent of 0.97 to 1.26 pounds of SCh/MM Btu assum-
ing all sulfur would be emitted during the combustion process. (The high sulfur values
of 1.50 pounds SCh/MM Btu in the sodium hydroxide HTTcoal and 1.56 pound SCh/MM
Btu in the deashed HTT coal resulted from incompleted desulfurization caused by
failure of one of the autoclave heaters.)
• A small loss in heating value of these coals resulted from the hydrothermal treatment.
Treatment of other coals, not on this program, has resulted in again in heating value.
• Ash content of the HTT coals is a function of the leachant system. The mixed leachant
resulted in an increase in the ash content. In this system, the majority, if not all, of the
calcium remained with the coal, whereas about 30 percent of the ash was extracted from
the Martinka coal by the sodium hydroxide leachant. Washing the sodium hydroxide
leached HTT coal with sulfuric acid resulted in the extraction of 85.5 percent of the ash
to produce a product containing 2.25 percent ash.
• Alkali retention by the coal is dependent on the leachant system. Sodium hydroxide
leachant produced coals containing about 2 and 5 percent sodium (MAP), respectively.
Sodium retention was reduced significantly by using the mixed leachant system.
Although data are not shown, concentrations of certain trace metals — berylium, boron,
vanadium, arsenic, lead, and thorium — were reduced significantly by the hydrothermal treatment.
COMBUSTION OF HTT COALS
Preliminary results from the combustion of certain HTT coals in a laboratory-scale combustion
unit (Figure 2.4.6) confirmed early beliefs that the use of these coals as a source of energy should result
in reduced sulfur dioxide emissions to the atmosphere. Furthermore, the alkali in the HTT coals acts as
a sulfur scavenger during the combustion process, thereby reducing sulfur emissions even further.
Combustion unit operation
The laboratory-scale combustion facility used was specifically designed for the evaluation of
small quantities of solid fuels.
A procedure was followed in conducting the combustion experiments. To warm up the system,
the primary, secondary, and cooling air flow were started and the electrical furnaces and air line
heaters were energized. During warm-up, the fuel reservoir was filled and all analytical instruments
were calibrated. When the combustion chamber reached 1500°F, a propane flame was established to
heat the combustion chamber to 1750°F. When this temperature was reached and all calibrations
completed, the fuel feed was started.
After a steady coal flame had been established, the propane was turned off and the combustion
experiment was started. During the experiment, the ash was collected, the flue gases were analyzed,
the air flows were measured, and the coal rate was determined volumetrically. Upon completion of an
experiment, the system was cooled and ash was removed, weighed, and submitted for analysis.
Combustion Results
General Combustion Behavior. In terms of ignition, the HTT coals appeared to ignite somewhat
easier than the raw (untreated) coals. This observation is supported by differential thermal analysis
shown in Table 2.4.7. In general, the ignition point for the HTT coals was approximately 50° to 75°C
82
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lower than the ignition point for the raw coals. No appreciable difference in flame stability between
HIT coals and raw coals was observed.
Sulfur Oxide Emissions. The SCh level in the flue gases of the burned coal was monitored
continuously throughout a given run. Also, for each run, the SCh levels were calculated from the sulfur
content of the coal and the amount of combustion air assuming total oxidation of the sulfur to SCh.
The measured and calculated SCh values are shown in Figures 2.4.8 and 2.4.9.
From a comparison of the measured and calculated SCh values, these coals could be burned
directly without violating Federal Sulfur Emission Standards. The reduced sulfur levels result, in part,
from the hydrothermal treatment and, in part, from the presence of the sodium and/or calcium in the
HTT coals which acts as a sulfur scavenger and traps the sulfur before it is (which would be) emitted to
the atmosphere. Analyses of the various ashes from the combustions revealed that the sulfur was
captured as the corresponding sulfates. The degree of sulfur capture appears to be dependent on the
alkali content of the coal, combustion residence time, and maybe dependent on the ash composition.
NOx Emissions. Hydrothermal treatment of coal does not extract the nitrogen. Therefore, the
combustion gases from HTT coals contain approximately the NOx concentration as do those from the
raw coals.
Trace Metals Emissions. Hydrothermal treatment of coal results in the extraction of a number of
the trace metals. Therefore, trace metals emissions from the combustion of HTT coals should be lower
than those from the combustion of the corresponding raw coals. However, measurements have not
yet been made to confirm this supposition.
CONCLUSIONS
From the results of the data presented, the following conclusions can be drawn:
• Hydrothermal processing is a technically feasible approach for reducing sulfur in certain
high-sulfur coals to environmentally acceptable levels.
• The sodium and/or calcium in the HTT coals acts as a sulfur scavenger during the
combustion process, thereby reducing sulfur emissions still further.
• The HTT coals burn as good or better than the corresponding raw coals.
83
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PROCESS DESCRIPTION
PREPARATION OF HYDROTHERMAL
TREATED COALS (HTT)
COMBUSTION STUDIES
SYNOPSIS OF PRESENTATION
Figure 2.4.1
COAL SOURCE
SEAM
1. LABORATORY SCALE
LOWER KlTTANNING
UPPER FREEPORT
OHIO 6
PTTTSBURGH 8
PITTSBURGH
2. PBEPILOT PLANT
LOWER KFTTANNING
UPPER FHEEPORT
S02 EQUIVALENT LB/10 'Btu
RAW COM
U
2.4
35
4.6
3.4
4D
2.4
HTT COAL
0.9
OJ
1.2
0.9
0.7
1.1
OJ
SULFUR EMISSIONS OF LOW-SULFUR COALS
FROM HYDROTHERMAL COAL PROCESS
HYDROTHERMAL COAL PROCESS
Figure 2.4.2
METAL
ARSENIC
BERYLLIUM
BORON
LEAD
THORIUM
VANADIUM
CONCENTRATION, PPM
RAW COAL
25
10
75
20
3
40
LEACHED PRODUCT
2
3
4
5
0.5
2
AVERAGE VALUES FOR 3 OHIO COALS: CN 719-SEAM 6,
HN 658-SEAM 6A, AND JACKSON-SEAM 4.
ELECTRIC
•*• POWER
PLANTS
INDUSTRIAL
"BOILERS
SOME TOXIC METALS EXTRACTED BY
HYDROTHERMAL TREATMENT OF OHIO COALS
Figure 2.4.3
Figure 2.4.4
-------
STATE
KENTUCKY
KENTUCKY
OHIO
OHIO
OHIO
OHIO
OHIO
PENNSYLVANIA
PENNSYLVANIA
WEST VIRGINIA
SEAM
LEATHERWOOD
LEATHERWOOD
6
6
BA
8
8
UPPER FREEPORT
8
BLOCK 5
ASH CONTENT
RAW COAL
wn
5.63
5.63
12.8
13.2
4.63
9.88
9.88
9.64
8.48
5.59
ACID LEACHED COAL
ASH Wn
2.00
1.85
3.36
5.34
2.90
1.64
3.24
2.07
1.77
0.71
SODIUM. WTJo
0,23
0.21
0.058
0048
0.50
0033
0.044
0.064
0.043
0.10
g? LEACHING OF HIT COALS WITH INORGANIC ACIDS
Figure 2.4.5
LABORATORY SCALE COMBUSTION UNIT
Figure 2.4.6
STARTING EXOTHERM. °C
IGNITION POINT, "C
SECONDARY EXOTHERM "C
END OF EXOTHERM, "C
WESTLAND
RAW COAL.
LOW ASH
233
426
615
MAR1INKA
RAW COAL
243
432
622
WESTLANO
COAL
SODIUM
TREATED
252
344
488
564
MARTINKA
COAL
SODIUM
TREATED
263
360
508
578
WES HAND
COAL
MIXED
LEACHAHT
268
344
494
555
MARTINKA
COAL
MIXED
252
376
493
553
DTA PERFORMED WITH STONE MODEL 202 AT !5°C'MIN AND DYNAMIC GAS FLOW OF 94 ML 'WIN
DIFFERENTIAL THERMAL ANALYSES OF COAL
SAMPLES IN AN ATMOSPHERE OF AIR
Figure 2.4 7a
STARTING ENDOTHERM/C
PEAK NO. 1, °C
PEAK NO. 2, °C
PEAK NO. 3, °C
END OF ENDOTHERM. °C
PEAK NO. 4, °C
WCSJLAHD
RAW COAL.
LOW ASH
400
442
516
555
584
--
MAPTINKA
RAW COAL
405
455
530
563
585
-
WESTLAHD
COAL
SODIUM
TREATED
385
462
519
-
550
622
MARTINKA
COM
SODIUM
TREATED
375
466
513
557
WESTLANO
COAL
MIXED
LEACHANT
329
467
514
-
550
678
MARTINKA
COAL
MIXiO
LEACHANT
414
475
520
554
665
OTA PERFORMED WITH STONE MODEL 202 AT IfC/MIN AND DYNAMIC GAS FLOW OF 94 MI/MIN
DIFFERENTIAL THERMAL ANALYSES OF COAL
SAMPLES IN AN ATMOSPHERE OF NITROGEN
Figure 2.4.7b
-------
COAL TYPE
RAW
MARTINKA
CAUSTIC
MARTINKA
MIXED
LEACHANT
MARTINKA
COMBUSTION CONDITION:
COAL FEED RATE LB/HR
AIR FEED RATE LB/HR
SECONDARY AIR. PSI RATIO
FURNACE TEMPERATURE, °F
1.27
12.26
4.0
2095
1.40
16.46
4.3
1740
1.6
16.6
1703
COMBUSTION RESULTS (MARTINKA COAL)
Figure 2.4.8a
COAL TYPE
RAW
MARTINKA
CAUSTIC
MARTINKA
MIXED LEACH ANT
MARTINKA
COAL ANAL YSIS
1 moisture free):
CARBON
HYDROGEN
NITROGEN
OXYGEN
SULFUR
ASH
SODIUM
CALCIUM
VOLATILE MATTER
FIXED CARBON
HEATING VALUE,
Btu/lb moisture ash free (MAR
67.57
4.60
1.30
4.3
2.00
20.22
-
-
29.21
50.83
15086
69.58
4.32
1.41
7.03
0.64
17.07
2.61
0.11
27.43
51.15
14881
59.9
3.94
1.21
5.66
0.55
28.3
1.29
5.95
26.41
45.48
14690
COMBUSTION RESULTS (MARTINKA COAL)
Figure 2.4.8b
COAL TYPE
RAW
MARTINKA
CAUSTIC
MARTINKA
MIXED LEACHANT
MARTINKA
GAS ANALYSIS IAS MEASURED):
co2%
o2%
COppm
NO x ppm
SO. ppm
THEORETICAL S02 ppm
S02 to/mm Btu (MAF)
SULFUR CAPTURE, %
RESIDENCE TIME (MILLI SEC)
CARBON BURNOUT. %
14.4
1,5
705
650
1910
1877
2.97
-
110
--
12.8
6.3
72
780
120
493
1.03
75.67
168
99.3
14.0
4.5
115
690
290
495
1.16
41.4
169
-
COMBUSTION RESULTS (MARTINKA COAL)
Figure 2.4 8c
-------
COAL TYPE
RAW
WESTLAND
MIX
LEACH ANT
WESTLAND
CAUSTIC
WESTLAND
ACID
LEACHED
WESTLAND
COMBUSTION CONDITION :
COAL FEED RATE, LB/HR
AIR FEED RATE, LB/HR
SECONDARY AIR, PSI RATIO
FURNACE TEMPERATURE,"F
1.46
16,6
4.3
1873
1.28
14.6
7.8
2090
1.3
16.28
4.4
1760
1.2
17.8
-
1888
COAL TYPE
RAW
WESTLAND
MIX
LEACHAHT
WESTLAND
CAUSTIC
WESTLAND
ACID
LEACHED
WESTLAND
COAL ANAL YSIS (MF):
CARBON
HYDROGEN
NITROGEN
OXYGEN
SULFUR
ASH
SODIUM
CALCIUM
VOLATILE MATTER
FIXED CARBON
HEATING VALUE, Btu/lb
moisture ash free (MAR
73.9
5.1
1.5
7.5
2.02
10.0
0.02
0.08
36.9
53.1
14955
69.38
4.68
1.53
5.66
0.73
18.0
0.21
8.0
40.4
59.6
15066
70.36
4.44
1.31
9.68
0.91
13.30
1.90
0.18
31.33
55.32
14388
76.0
4.6
1.5
10.3
1.05
2.2
0.43
0.09
31.5
62.0
14349
00
XI
COMBUSTION RESULTS (WESTLAND COAL)
Figure 2.4.9a
COMBUSTION RESULTS {WESTLAND COAL)
Figure 2.4.9b
COAL TYPE
RAW
WESTLAND
MIX
LEACHANT
WESTLAND
CAUSTIC
WESTLAND
ACID
LEACHED
WESTLAND
GAS ANAL YSIS (AS MEASURED)
C02%
02%
CO PPM
NO x PPM
S02 PPM
THEORETICAL S02
SO 7LB/ MM Btu MOISTURE
ASH FREE (MAF)
SULFUR CAPTURE, %
RESIDENCE TIME (MILLI SEC)
CARBON BURNOUT, %
14.9
3.7
70
625
1115
1610
3.00
30.7
157
95.4
12.6
4.0
55
585
250
580
1.27
56.9
93
14.2
6.0
77
770
220
651
1.46
66.2
168
99.4
12.6
5.0
55
1075
525
660
1.5
20.5
163
96.8
COMBUSTION RESULTS (WESTLAND COAL)
Figure 2.4.9c
-------
HOMER CITY COAL CLEANING DEMONSTRATION
J. F. McConnell
Regulations, established under the Federal Clean Air Act Amendments, have set primary and
secondary air quality standards. Specific standards of performance under these amendments have
been set for sulfur oxide emissions from large stationary sources which include coal burning electric
utility boilers. Compliance with the sulfur oxide emission limitations of these standards can be met
through control of sulfur burned or by reduction of sulfur oxides in flue gas, i.e., flue gas desulfuriza-
tion(FGD).
General Public Utilities Corporation (GPU), a holding company, owns three operating com-
panies in New Jersey and Pennsylvania. A subsidiary company, Pennsylvania Electric Company
(Penelec) jointly owns Homer City Generating Station, a mine mouth coal fired generating station in
central Pennsylvania, with New York State Gas & Electric Corporation, a non-affiliated company.
Homer City went into commercial operation in 1969 with two 600 MW capacity units, a third 650 MW
unit, scheduled for commercial operation in 1977, is under construction. Dedicated mines (Helen and
Helvetia) produce coal for the station with about 2.8 percent sulfur.
Pennsylvania's large stationary source sulfur oxide emission regulations for existing sources
outside of air basins permit a maximum emission level of 4.0 pounds of SCh per million Btu (MM Btu).
Normal run of mine coal from Helen and Helvetia cannot meet this requirement. New source
performance standards, applicable to the new unit, are more restrictive and limit emissions to 1.2
pounds of SOi/MM Btu.
In order to comply with emission standards for SCh, the Owners of Homer City planned to
install a flue gas desulfurization system (FGD) on the new unit. The Owners further planned to
construct a coal washing plant to desulfurize coal sufficiently to comply with Pennsylvania's regula-
tions for existing large stationary sources. This coal washing facility, being designed and constructed
by Heyl and Patterson, Inc., is currently under construction and will be in commercial operation by
April 1977. This coal washing facility features high gravity heavy medium cyclone circuits designed to
desulfurize and recover a maximum amount of Btu from the raw coal feed stock. Figure 2.5.2 depicts
the flow sheet of this plant which will provide prepared fuel for all of the station. A lime/limestone flue
gas scrubber was selected for Unit 3 and placed on order in January 1975.
Indigenous coal deposits in the Penelec service territory, largely the Allegheny series of coal
seams, have long been recognized for their susceptibility to desulfurization by so-called coal washing.
This is a consequence of both a relatively low percentage of chemically bound organic sulfur and high,
but relatively free inorganic sulfur in the pyritic form. Recognizing these inherent characteristics,
CPU's R&D efforts in coal utilization have focused on developing advanced coal preparation methods.
Favorable findings from R&D directed at coal washing encouraged the consideration at Homer
City of advanced preparation methods as a possible alternative to FGD. A large R&D and engineering
evaluation program by GPU/Penelec consultants and Heyl and Patterson on behalf of the Owners,
concluded that an advanced state-of-the-art heavy medium cyclone plant, preparing multiple streams
of coal — multi-stream coal cleaning system (MCCS) — was capable of processing Homer City coal
reserves into compliant fuel without supplemental FGD. In August 1975, the Homer City Owners made
the decision to proceed with the design and construction of new low gravity heavy medium cyclone
circuits to accomplish deep coal washing in an MCCS concept to meet new stationary source perfor-
mance standards for Unit 3. The flue gas scrubber was cancelled. Figure 2.5.3 depicts the Homer City
MCCS concept.
A multi-stream coal cleaning system, per se, is not a new idea — industry has used the concept.
EPA discussed the concept in their report (l-A-6) on the High Sulfur Combustor Power Plant in April
1973. The GPU-Penelec MCCS system, as the Homer City Owners, NYSE&G and Penelec are applying
88
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it, includes a number of innovative applications and extensions of existing technology to multi-stream
coal processing. These innovations relate to:
• Extending the range of application of heavy medium cyclone equipment to smaller sized
coal fractions (100-mesh from the usual 28-mesh bottom size).
• Substitution of full stream electro magnetic separators for drain and rinse screens in the
9-mesh x 100-mesh coal circuit for recovering magnetite.
• Extending the range of operating specific gravity of heavy medium cyclones to 1.8 at the
upper end and to 1.3 at the lower end.
• Development of a novel control system for tighter control of the specific gravity of
operation in the nominal 1.3 specific gravity circuit operating on fine size coal.
THE COAL CLEANING APPROACH
The clean coal quality requirements which Homer City coals must meet to satisfy new source
emission requirements of 1.2 Ibs of SCh/MM Btu are;
• 0.6 Ib S/MM Btu
• 0.9% S or less
• 15,000 Btu/pound or greater
A study of the coal bed seam characteristic information in the U.S. Bureau of Mines reports Rl
7633 and 8118 provided considerable data on these coals and on the Upper and Lower Freeport and
Lower Kittanning Seams, which comprise the bulk of the reserves committed to the Homer City
Station. Comparative rank of Homer City Station reserves is shown in Figure 2.5.5. To meet clean coal
quality requirements for the average, and not the best of coal reserves, it was evident that coal
cleaning objectives must involve cleaning circuits capable of operating effectively at a specific gravity
of separation of 1.3 and that the coal supply should have recovery characteristics that would provide
the required quantities of Btu needed for each of the generating units. The targeted requirements of
fuel for the Homer City Generating Station are as follows:
Unit 3 Units 1&2
(new source) (existing sources)
Btu/year x 1012 38.5 74.7
Percent of Requirements 34.0 66.0
Lbs. S/MM Btu 0.6 2.0
The expected preparation plant performance, with the final flow sheet design, discussed later,
is as follows:
Units 1&2 Unit3 Refuse
Recovery (weight percent) 56.2 24.7 19.1
Recovery (Btu percent)* 61.6 32.9 5.5 (Loss)
Product Btu/pound (dry basis) 12549** 15200 3367
Ash Percent 17.8 2.8 69.7
Sulfur Percent 2.24 0.88
Pounds Sulfur/MM Btu 1-79 0.58
* Gross recovery 94.5 percent net recovery is 93.5 with losses for thermal dryer included.
** Blend of middling and clean coal.
89
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THE COAL CLEANING PLANT DESIGN
The detailed coal preparation plant arrangement developed by the Homer City Coal Preparation
Plant contractor, Heyl and Patterson, Inc., and by CPU, Penelec and its consultants, incorporates the
following designs as illustrated in Figure 2.5.14.
Crushing and Classification
A portion of the cleaning plant is dedicated to crushing and size classification. Provision is made
to selectively crush all major sources of supply to the cleaning plant in variable speed cage crushers to
control the production of plus 1/4-inch and minus 100-mesh material while optimizing the release of
pyrite and ash.
Coarse Coal Cleaning
The coarse coal cleaning circuit cleans plus V4-inch coal in heavy medium cyclones at 1.8 specific
gravity. Cleaned plus 1/4-inch coal becomes part of the moderately cleaned middlng coal blend.
Medium Coal Cleaning
The medium coal cleaning circuit cleans 14- x 9-mesh coal in two stages of heavy medium
cyclones. The first stage cleans at 1.3 specific gravity. The clean coal overflow product of this circuit is
available as intensively cleaned coal for use in Unit 3. Surplus 1.3 float product from this stage is
blended into the moderately cleaned middling coal. Underflow from the first stage is recleaned in the
second stage of heavy medium cyclones at 1.8 specific gravity. Underflow from this stage is refuse
coal, underflow is 1.8 float —1.3 sink and is blended into middling coal.
Fine Coal Cleaning
The fine coal cleaning circuit cleans 9-mesh x 100-mesh coal in heavy medium cyclones at 1.3
specific gravity. In this circuit, underflow from the classifying and deslimming screens is pumped to
14-inch classifying cyclones. Underflow containing mostly 9-mesh x 100-mesh coal is cleaned at 1.3
specific gravity in heavy.medium cyclones. Overflow product is partially dewatered and washed of
fines in spiral classifiers. This product makes up the major portion of intensively cleaned coal for Unit
3.
Fine Coal Scavaging Circuit
The fine coal scavaging circuit deals with 9-mesh x 100-mesh, 1.3 specific gravity sink coal and
minus 100-mesh coal. Coal prepared in this circuit is blended into moderately cleaned middling coal.
Coarser material is cleaned in hydro-cyclones. Hydro-cyclone underflow is sent over Deister tables for
pyrite removal.
DESIGN DISCUSSION
The Homer City Coal Cleaning plant is designed to remove the maximum technically feasible
amount of pyritic sulfur from the intensively cleaned product for Unit 3 consistent with the Btu
requirements of that Unit. The coal preparation plant arrangement incorporates the following design
features:
• Provision has been made to selectively crush all major sources of supply to the cleaning
plant (Helen, Helvetia and outside truck coal) when needed to provide additional
capability to meet sulfur quality and Btu requirements. The most favorble coals will be
crushed to amplify their impact on intensively cleaned product. Cleaning plant design
provides for crushing up to 75 percent of design tonnage input to maximum of 10
percent plus '/i-inch oversize.
90
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• The intensive cleaning circuits will be designed to operate an effective specific gravity of
separation of 1.3. Feed will be classified to 1/4-inch x 9-mesh and 9-mesh x 100-mesh
and dealt with in independent circuits. Operating conditions and medium gravities will
be optimized for sulfur reduction and Btu yield in each classified size heavy medium
cyclone circuit.
• Recovery of magnetite in the 9-mesh x 100-mesh coal fraction will be accomplished
with electro-magnetic separators — drain and rinse screens, normally used for this
purpose, will not be used.
• Heavy medium cleaning circuits assure sharpness of separation through application of
the following design concepts:
— Classified feeds
— Light apex volumetric loadings in the cyclones
— Use of fine particle size medium
— Control of medium viscosity by reduction of bituminous contamination
' The most obvious feature of the Homer City Coal Cleaning plant is that it deliberately deals with
a fine size consist of coal at low gravity with heavy medium cyclones. Figure 2.5.15 illustrates the well
known characteristic of the Allegheny series of coals; that size reduction releases pyrite and ash.
Based on float-sink data on run-of-mine coal for Homer City, insufficient margin for sulfur reduction
and Btu yield is attainable from 11/4-inch x 100-mesh coal. The relative quality and yield from 1/4-inch x
100-mesh size fraction is substantially better, hence the desirability of crushing. Some Btu will be lost
below 100-mesh size and the washability of crushed 1 % x 14-inch coal will not equal the natural sizes,
nevertheless, overall improvement results as inferred in Figure 2.5.16.
Heavy medium cyclones have been selected because of the large amount of near gravity
material at 1.3 specific gravity. The inherent sharpness of separation of heavy medium cyclones is
essential for quality and Btu recovery. Heavy medium cyclones are employed in the high gravity
circuits to assure the maximum overall Btu recovery.
There is obviously no purpose in extending the complexity, difficulty, and cost of coal prepara-
tion beyond that which is necessary to achieve the required quality of coal from the available coal
reserves. The incentive to clean steam coals has existed mainly to reduce ash content to meet boiler
specifications for fuel or to reduce transportation cost. The application of coal preparation for
substantial sulfur reduction to meet emission regulations is not common, and introduces the difficulty
that the products must consistently and reliably meet quality standards hour by hour, or the power
plant user is in technical violation of State and Federal Regulations. The same requirement applies to
FGD. The use of a multi-stream coal cleaning system does offer one environmental advantage,
however. Even if, at certain times, excessive misplaced material is generated by the low specific gravity
circuits, the net sulfur in the combined low and high gravity circuits remains unchanged and the total
sulfur oxide emission and environmental consequence from a multi-unit station will be unchanged.
CONCLUSIONS
The multi-stream coal cleaning concept, as discussed in this paper, can provide an
alternate and possibly more economical approach for the control of SCh emissions from
coal fired boilers if the proper coal reserves are available. It has the flexibility, from a
systems point of view, to be used singly or in conjunction with flue gas desulfurization.
The decision of the Homer City owners to install an MCCS system is not a risk-free
decision. There are risks associated with unknowns in the character of coal reserves still
to be mined that could adversely affect product quality. This might force a retrofit with a
91
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partial flue gas scrubbing or chemical system to incrementally improve sulfur quality.
There are also risks not discussed in this paper associated with the operation of boilers
and precipitators with a 3 percent ash, low sulfur fuel.
There is a need for additional research and development work in a number of areas of
cleaning plant design. Some of these are:
— Development of efficient and cost effective techniques to physically clean the minus
100-mesh coal size fraction, which has the most significant potential for sulfur reduction
and Btu yield improvement.
— Development of techniques to dewater and handle fine coal and refuse.
— Determination and better understanding of the optimum loadings and operating
parameters of equipment as applied in low gravity cleaning circuits.
There is a need to recognize the inherent variability of coal quality and to reflect this
through the application of a longer time constant in environmental regulations. This
would permit more economical designs that would accomplish the same environmental
improvements.
REFERENCES
1. Deurbrouck, A. W. Sulfur Reduction Potential of the Coals of the United States, Bureau of
Mines Report of Investigations, 1972.
2. McConnell, James F., and Statler, Charles. Multi-Stream Coal Cleaning Strategy for Control of
Sulfur.
3. Statler, C. W. Multi-Streams Coal Washing, A Systems Approach for the Control of Sulfur.
92
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OVERVIEW OF HOMER CITY
GENERATING COMPLEX
Figure 2.5.1
-------
COAL FEED FIRST PHASE
1 '/4 x 28 MESH
COARSE COAL
500 TPH
BY-PASSED
COAL
DEWATERING & DRYING
CLEANED COAL
HOMER CITY COAL CLEANING
FIRST PHASE PREPARATION PLANT
Figure 2.5.2
SULFUR j Jf\.
REMOVAL ! IS
(1.8 S.G.)
* L! 1
REDISTRIBUTION ._
OF SULFUR ! .
M
A
FC
CC
CCS
SYSTEMS APPROACH
)R SO2 EMISSION
3NTROL
i n
-I V
L |1.2#S027
#3
UNIT
4
y J /MM Btu
j 4.0 S02/
#2
UNIT
n
#1
UNIT
i i
/MM Btu
HOMER CITY COAL CLEANING
Figure 2.5.3
COST COMPARISON - COAL PREPARATION VS FGD
CAPITAL INVESTMENT
FOR SO,CONTROL, SMM
COAL PREPARATION FACILITIES
ORIGINAL PLANT (FOR USE WITH FGD)
MCCS ADDITION
FGD
SUB TOTAL
ANNUAL REVENUE REQUIREMENTS
FOR SO, CONTROL, $MM
FIXED CHARGES
OPERATING AND MAINTENANCE EXP.
FGD
COAL PREPARATION
SUB TOTAL
SCHEDULED IN
SERVICE DATES
MAR. 1977
DEC. 1977
FGD
18
59
77
11.6
10.6
3.2
25.4
MCCS
.
18
32
0
50
7.5
0
7.6
15.1
HOMER CITY GENERATING COMPLEX
ALTERNATIVE SO2 CONTROL STRATEGIES
Figure 2.5.4
-------
5.0 •
4.0
3.0
2.0
1.0
UPPER FREEPORT
E-SEAM
RAW COAL
RANGE OF MINE SAMPLE DATA
AND FLOAT-SINK DATA
LOWER FREEPORT
D-SEAM
RAW COAL
- HELEN
\
HELVETIA No. 6
No. 9
HELVETIA No. 8
D-SEAM 1.3S.G. FLOAT
a.
b.
c.
d.
0.6 Ib SULPHUR/MM Btu
0.9% SULPHUR
15,000 Btu/lb
2.5 TO 3.6% ASH
2 4 6 8 10 12 14 16
CUMULATIVE NUMBER OF MINES REPORTING
WASHABILITY DATA, PA. MINES VS.
HELEN & HELVETIA MINES
Figure 2.5.5
18
MCCS DEEP COAL CLEANING
REQUIREMENTS
Figure 2.5.6
COAL HEAT CONTENT —
HC 1 &2
«•
— 100%— |
1
1st STEP
62%
94%
I
2nd STEP
32%
Existing Units
New Units
MCCS COAL HEAT CONTENT BALANCE
Figure 2.5.7
-------
EDITOR'S NOTE: Since Figures 2.5.8 through 2.5.13
are identical except for individual highlighting of a
subsystem, they are not included here.
96
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SIMPLIFIED DIAGRAM
COAL CLEANING CIRCUITS
HELVETIA COAL
TRUCK COAL
HELEN COAL
v CRUSHERS
SCREEN 186TPH1%"x%"
TRASH SCREEN
REJECT
SCREEN
HYDROCYCLONE
DEISTER
597 TPH 2mm x 0
H.M.C. 1.8 Sp. Gr.
D&R SCREEN
SCREEN
D&R
E2!EN V D&R SCREEN
DEEP CLEAN
COAL
111TPH
I .
THICKENER No. 1
MIDDLING 1 COAL
MIDDLING 1 COAL
104
SPIRAL CLASSIFIER
THICKENER No. 2
MIDDLING COAL
203 TPH
DEEP CLEAN
COAL
234 TPH
MIDDLING COAL
224 TPH
266 TPH 2mm x 0
CRUSHING & SIZE SEPARATION
FINE COAL - DEEP CLEANING
MEDIUM COAL - CLEANING
COARSE COAL - CLEANING
E) FINE COAL - SCAVENGING
HOMER CITY -
Figure 2.5.14
MCCS
-------
318x114 1/8x10 Mesh 28 x 65 Mesh
114 x 118 10 x 28 Mesh 65 x 100 Mesh
SIZE FRACTION
EFFECT OF SIZE ON QUALITY FOR HOMER CITY COAL
Figure 2.5.15
100
I
FLOAT 1.25 1.30 1.35 1.40 1.45 1.50 1.55 1.60 1.65 1.70 1.75
1.30 1.35 1.40 1.45 1.50 1.55 1.60 1.65 1.70 1.75 1.80 SINK
SPECIFIC GRAVITY WEIGHT FRACTIONS
HEAT & SULFUR DISTRIBUTION
HOMER CITY COAL WASHABILITY
Figure 2.5.16
2.0
1.6
1.2
0.8
0.4
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HOMER CITY SITE: EARLY CONSTRUCTION
(24 MAY 76)
Figure 2.S.17
HOMER CITY SITE: EARLY CONSTRUCTION
(24 MAY 76)
Figure 2.5.18
HOMER CITY SITE AS OF AUGUST 30, 1976
Figure 2.5.19
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DISCUSSION
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DISCUSSION
William N. McCarthyJr.
Moderator
After the papers were presented the authors assembled for a discussion with the audience. The
discussion revealed interest in the validity and usefulness of data and methodology of on-going
programs. The final disposition of contaminants and pollutants, and the chemical and physical
changes resulting in coal-ash from different processes and coals were examined. Elements from coal
being introduced into the environment in trace quantities, but in unprecedented volume, were of
particular interest and some concern. The need for determining and evaluating these contaminants
was expressed. The merit of averaging data of coal cleaning characteristics by regions was challenged,
and the necessity of linking specific coals to specific processes or combinations of pollutant control
processes was discussed.
Considerable interest in the economics of processes was expressed; and the need for such data
endorsed. However, little economic data are available. It was also observed that the Environmental
Protection Agency and the Federal Power Commission are working to merge data based on environ-
mental information to provide more responsive and effective programs.
The source for the following discussion was a tape recording made at the meeting. As the
audibility of the tape was not perfect in every instance due to a number of participants speaking
simultaneously, this is not a verbatim report.
CHAIRMAN WILLIAM MCCARTHY: Do we have any questions?
PAUL CHEH, ONTARIO HYDRO: Yes. I have a question for Dr. Issacs. In developing your
(pollution) control strategy, I gather your objective function is to minimize the cost of the system. Is
that right?
DR. GERALD ISSACS, PEDCO: Yes, that's correct.
CHEH: Have you done any analysis in terms of comparing different systems and how to derive a
reasonable — I don't know how to define reasonable — allocation for pollution control strategy for
such systems?
ISSACS: Yes, we're looking into coming up with a minimum cost strategy for some other
systems right now in some on-going work. We are further developing a computer program that will
optimize the selection of the coals to be used, the distribution of those coals among the power plants,
and the optimum placement of coal cleaning plants and flue gas desulfurization systems within a given
matrix of power plants.
CHEH: Could you be specific as to what type of program you intend to use?
ISSACS: I'm not sure I am qualified to answer. I am not doing the programming on it. I thinkwe
started with a linear type (inaudible) computer program for optimizing sulfur oxide emission control
using combinations of coal cleaning and flue gas desulfurization for processing different coals. But I'm
not sure this is going as well as expected and we may be looking at some different avenues.
DR. H. R. HICKEY, of TVA, asked about the cost per kilowatt hour of flue gas desulfurization.
The cost of the scrubber for Homer City was discussed.
MR. JAMES F. MCCONNELL, GENERAL PUBLIC UTILITIES: It may appear to be $35 per kilowatt if
they're using one third of the station capacity. The FGD system applied to the actual firing system
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control would probably be closer to $80 per kilowatt. Divided over a coal station's generating capacity,
it will come out something like $30 per kilowatt, I believe. Our numbers were closer to $80-$85 per
kilowatt for an FGD system.
MR. TIM DEVITT, PEDCO: The FGD system, we assume, had an 85 percent sulfur removal
capability so it only needed 42 percent removal capability, only about half. . .
Several talking at once and inaudible . . . ayes, I think so, yes.
ISSACS: Does it include sludge disposal facilities?
MCCONNELL: Yes.
ISSACS: Our numbers included sludge disposal and capital investment.
TOM PONDER, PEDCO: You'll find you have to have the same bases for everyone so cost
estimates will come out the same. In many cases particulate control costs are included along with the
SO2 part of it, and also you'll see stack process costs included. So if we could get everyone on the same
basis on the same process it would help. That's a big problem in this kind of work.
HERBERT SPENCER 111, WESTERN PRECIPITATION DIVISION OF JOY MANUFACTURING:
What's the effect of pyritic sulfur removal from coal prior to burning on a particulate collector? You're
well aware many manufacturers in the past used sulfur content as a means of deciding how big to build
their units. I did notice though that in the Battelle system it appeared you got some changes in ash
chemistry that might affect ash resistivity in a positive way . . .
JAMES KILGROE, EPA: We didn't exactly get into that in any extent in our discussion today. You
know that's quite an element in our program and we are being supported by other groups down at
Research Triangle Park. In our new contracts we're looking at what is the prospect when we start
removing sulfur. What are the elements of the change of resistivity and flexibility in removability in fly
ash? That is some of the stuff Battelle is doing. They are collecting fly ash from combustor gas and are
trying to determine what the resistivity is by various methods. There is also a point of view the
resistivity is in the combustion process, and how the particles are formed will also affect collectability.
That is something we want to look into and determine whether or not combustor tests are really giving
something that is really meaningful or whether we have to get especially constructed combustor sets
like the Bureau of Mines is trying to develop and the Australians have.
E. P. STAMBAUGH, BATTELLE COLUMBUS: We have measured the resistivity of a few of our
samples and found the resistivity appears to fall within the range of about 108 to 1010 centimeters which
is within the range of collectability. But there will need to be more work done in that area. I don't recall
what the resistivities were on the broad range of coals, but on the HTT coals they were within the
vicinity of 108 to 1010.
SPENCER: I expected to see a reduction since it looked like, at least in the western coals, you
had a higher sodium content and appear to attach sulfur to the ash.
STAMBAUGH: Well, during the leaching of the coal, the resistivity changes with the acid to base
ratio of the constituents, as we add higher sodium or calcium. We are changing the composition of the
ash by quite a bit by extracting bismuth, silica, and trace metal values which will affect it.
SPENCER: One other question along that line. What about the effect on boiler operations of the
fusion temperature of the ash? Do you have slagging problems or not?
STAMBAUGH: It looks as if the slagging temperatures may be reduced in some cases, raised in
other cases. So there still needs to be more work done in that area, which we will be doing for EPA.
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MR. ART LYALL, RESEARCH DEVELOPMENT: What happens to the solubilized trace elements —
lead, antimony, and the other compounds in the process?
STAMBAUGH: They would go with the spent leachant. We find during leachant regeneration by
treatment with CO2 that a large number of them precipitate. We have not really conducted enough
work yet to see if they will build up on recycle. But, we would hope to develop a method for
recovering these trace metal values.
DR. EUGENE WEWERKA, LASL: Along that same line, I wonder if Bob Meyers might comment
about the same topic. You indicated in your talk, I believe, that there were trace contaminants
removed from the coal. Could you tell us what they are and where they end up in the process and so
on?
DR. ROBERT A. MEYERS, TRW: In our process we are making iron sulfates as a product of the
process. We are not making USP grade iron sulfates, but, rather, iron sulfates that contain their natural
abundance of trace elements which are obtained from the coal.
MR. SAHRAB HOSSAIN, CATALYTIC, INC: Is there any waste water discharge from coal
cleaning plants? If so, how do you treat it?
MCCONNELL: Basically there is not. The take up water is supplied, and the water that is lost
from the plant is either through the evaporator or some amount of moisture attached to the refuse.
Basically there is no waste water stream.
KILGROE: There are new proposed EPA effluent guidelines for new preparation plants which
essentially say that there will be no discharge. They are to recycle all the water. On existing plants, of
course, there is some discharge depending upon state and local regulations. The industry is progress-
ing toward no discharge.
TIM SALOWITZ, EPA: About the refuse program that's generating from coal cleaning and
preparation techniques: Currently, it is being stored on site. Is that the dominant technique? As future
state and federal regulations for industrial wastes get tighter, what's the current thinking on disposal
techniques for the future?
KILGROE: I guess that's one of our major concerns. We have a large contract calling for
environmental assessment of coal preparation processes: What are the environmental impacts of
cleaning coals? How do you get rid of residues? What are the leachant problems?
The work we have been doing with LASL is really looking at the leach outs from coal preparation
plant wastes. We are going to look at that considerably. I might mention that in the previous
"incarnation" I was involved with EPA's solid waste program for about four years. So I think we're
aware of that problem.
MR. TIM FIELDS, EPA: What is the current practice, storing on site? Stockpiling?
KILGROE: Yes. Would anyone like to comment on that?
WEWERKA: The problem of solid waste from coal preparation probably can be considered as a
two pointed situation to look at from here on out. There are regulations and guidelines forthcoming
for the disposal practices of these materials. They'll have to be disposed of in such a way that there
aren't any structural problems and that types of effluents are at a minimum. The type of guidelines Jim
just mentioned apply not only to the coal preparation plants, but also to waste materials from the
plants.
The amount of dissolved materials or contaminants which will be allowed in waste water are
very, very small. There is no question that in the future, disposal must be done in an environmentally
compatible way. The problem is the material which already has been disposed of, which I mentioned
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this morning. There are about 300 billion tons of this stuff around the countryside, this is a different
aspect. It is not that the technology can't be found that will come up with a way to treat those waste
materials but, proving the legal responsibility for them is a problem. A great number are completely
abandoned and nobody wants to take responsibility for them. As to who eventually will have to bear
the cost of cleaning up that aspect of the situation is not at all clear at this point.
MCCONNELL: I think there is an assumption here that coal preparation will create large
quantities of waste material that hitherto we didn't have. But we still have to remember that 25 percent
of the coal that comes out of the ground is mineral matter, and it turns out to be mine refuse, bottom
ash, or fly ash. We've always had it. We're not creating it. We're just getting it in a different form, and it
may be more or less difficult to deal with. But we are not, in fact, creating massive new amounts of
material that otherwise wouldn't occur. It is, and always has been a part of a mining enterprise to
produce waste materials that are not put back underground again, at least by present technology.
UNIDENTIFIED VOICE FROM AUDIENCE: But it has a lot more sulfur in it.
MCCONNELL: Right. The sulfur is in it instead of in the air.
MR. S. Z. ALTSCHULER, USCS: Whereas it is true we've always dealt with wastes and their
hazardous trace element burden, there is one aspect of the present technology that differs from the
past, and that is the necessity to treat these extremely large quantities of coal at one or two sites. This is
in contrast to the small quantities burned in the past. So consider something like beryllium falling out
in ash. You're going to be loading the countryside if it is in fly ash fallout, with much more beryllium,
ultimately, than you may have had ever before, despite the fact the concentrations may not be that
much different. So there is a need for concern, more now than in the past, not because we know more
about toxicities, but because we are going to be adding to the burden, maybe by an order of
magnitude.
MR. ALEX WEIR, SOUTHERN CALIFORNIA EDISON: We've published the work we did for the
Electric Power Research Institute on trace elements in fly ash and in scrubber sludge. I think what
you're not taking into account is that elements like beryllium are effectively removed by electrostatic
precipitators and scrubbers. Also, you're talking about well over 90 percent of this material burned
being removed in solid form. What we found was that in scrubber sludge there is very little leaching of
this material into ground water. It depends, of course, on the type of soil; but it would be hundreds of
years before it would affect drinking water standards from an unmined plot.
ALTSCHULER: I am not disputing the fact that we can handle these problems, but we have to
take cognizance of the potential because the type of sludge or waste you get may be low in beryllium
as you say, but in other instances it gets quite high. The Radian Study that was conducted by Radian
Corporation on North Dakota lignites shows quite a variation in the contents of the trace elements
from three different types of waste productions for the same lignite. In one case, for example,
molybdenum went up to 55 parts per million in the physically collected ash from the particulate
collector; whereas for another type of fly ash, it was much lower. It is not that these things are
insurmountable problems, but they have to be looked at.
MR. DOAN PHUNG, INSTITUTE OF ENERGY ANALYSIS: I would like to ask a question of the
gentlemen who gave the paper on trace elements on coal. I have seen a sample of coal, I think from
North Dakota, that has something like 100 parts per million of uranium in the coal, and I want to find
out how widespread these types of coal are.
ALTSCHULER: That type of concentration of uranium is quite widespread since it has been
noticed in many types of lignites and coals, although it is restricted to specific geologic situations,
notably where you have uranium-rich material overlying coal. The material itself is somewhat unstable,
such as volcanic ash. This has appeared in a number of instances in North Dakota lignite and also the
Texas Lignite fields. There is a natural leaching of the ash, and a sodium carbonate rich solution
develops. It leaches uranium from the vitrifying ash. As this solution seeps down, it contacts a coal bed
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immediately underlying, and the coal kind of strips the uranium out. This type of process is evident in
the distribution of uranium within these lignites and coals.
It is usually quite rich in the upper part of the bed and declines very rapidly below. In other
words, the affinity for organic matter stripping action results in the uranium being concentrated in the
uppermost parts of the beds. In the early 1950's these types of resources were thought of, especially in
North Dakota, as uranium recovery potentials. As a fact, there is some recovery practiced in some of
the lignites in Texas which became uraniferous in the same manner.
PONDER: Would anyone comment on what clean coal can do for boiler reliability or heat ratios?
MCCONNELL: We thought we might see, subjectively, 5 percent improvement in reliability. I
really don't think we'd see much change in heat rate.
PONDER: The boiler is not designed for processed coal. It was designed for run of mine coal;
not designed for very low ash, high Btu coal.
MCCONNELL: Right. You may have more, or you may have less of a slagging problem. We think
it would be about the same. The slagging problem is not directly proportionate to amount of ash, but
more a matter of character of the coal. You never know until you try one out.
MR. JACK MCCOVERN, CARNEGIE MELLON UNIVERSITY: I'd like to know if anyone can tell me
whether the physical cleaning of coal will change the storability of it — including chemical cleaning.
Whether the properties will deteriorate differently on storing?
MEYERS: There've been a number of studies which have related pyrite content to the weather-
ing of coal and which try to attribute weathering and spontaneous combustion to the pyritic level. The
correlations haven't been all that good. There is a general suspicion that high pyrite coal weathers to a
higher degree and can ignite more easily in a storage situation than low pyrite coal.
MCGOVERN: How about any decrease in the heating value of coal just from sitting in piles?
MEYERS: There is a non-established link, a strong suspicion pyrite increases weathering and
therefore lowers the heat content faster.
WEWERKA: There have been some studies done on the change in properties in coals with
storage. In general the surface oxidation of organic material and the evolution of things like carbon
monoxide usually begin to occur quite quickly after exposure to the elements, like in a period of
weeks or so.
There is often some substantial loss of heat content over a . . . say a year. You can lose up to 10
percent of the heat content of the coal from oxidation and degradation during storage. There is also a
change in things like agglomerating properties, and what have you; but it is not clear what effect
differences in mineral matter would have on that process. I rather doubt whether change in pyritic
content, for example, would appreciably change the rate of organic material degradation with the
exception of the particle size effect. If you crush it down very, very small during cleaning, smaller than
you might normally for shipping to the consumer, in an unclean state, then you could indeed increase
the rate at which some of these processes occur and agglomerate again before you ship and store the
material.
MR. DAN HUNTER, PHILLIPS PETROLEUM COMPANY: The first set of numbers for the combus-
tion products of the Battelle process showed that nitrogen oxide emissions increase 20 percent. Is this
something that can be attributed to the process?
STAMBAUGH: At this time we don't know the effect of our treatment process on the formation
of NOx. We do know that the process doesn't extract any of the nitrogen. The data on NOx and flue
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gases has been quite scattered so we don't have a good handle on it yet. The nitrogen compounds in
the coal seem to be quite stable. I can't see that the treatment process would have much effect on it.
KILCROE: I think, also, the data are taken from one or two pound combustors and the
combustion configuration probably will not give you reliable data if you try to scale up to a large size
combustor. We are going to do some combustion studies on multi fuels and, I guess, on some other
boilers so as to get a better handle on NOx emissions.
HUNTER: I didn't get the numbers from that chart. Was that a significant difference in flame
temperature in the two cases?
STAMBAUGH: There may have been. I don't recall, but in most cases the flame high tempera-
tures or the wall high temperatures varied from about 1,700 up to about 2,000 degrees. But whether or
not, in that particular example, the flame temperature was different, I don't know.
MCCARTHY: Any other question from the floor? Mark Levine, maybe you have a comment on
the use of your slide?
(EDITOR'S NOTE: In an aside from his formal paper presentation, R. E. Hucko, of the Bureau of
Mines, screened a slide from Levine's talk showing U.S. Coal Cleaning By Region (Figure 1.1.12).
Hucko then pointed out how easy it is to misinterpret the data on the percent of different coals
meeting EPA SO2 emission standards before and after cleaning.)
LEVINE: Thank you. I want to comment on Mr. Hucko's comment on our analysis. It is true we
did not correct for weighted average sampling, primarily because we couldn't, based on existing data,
or couldn't have done it very accurately. And it didn't look, as we looked at the data, as though it
would make very much difference. In fact, I looked at Mr. Hucko's results and discovered his analysis
for Northern Appalachia, in which he did a weighted analysis, came out not very different from the
arithmetic mean.
It turns out there is a difference of a factor of 3 on the arithmetic numbers, the ones we use
between coals "before" and "after" washing—the percentage of coal that meets EPA standards. There
was a factor of 2.8 in his data. The numbers change, if you remember the numbers on the slide, from 4
and 12 percent taken from the U.S.B.M. report, to 2.5 and 7 percent if you work back from his data.
The more important point, however, is that the purpose of the analysis was to indicate in general terms
what coal cleaning could do.
What is important might be whether or not it might be needed, if you consider all the
uncertainties involved in the analysis. The uncertainty associated with knowing exactly what the sulfur
content of coal by regions is, is just one of many factors. I would also point out we don't really know if
the washability studies are very good simulations of what would happen in a commercial plant. We'll
know more about that when there are more commercial plants. Basically, I don't think the conclusions
change much. In fact, as we were doing the analysis, we asked the question if it mattered very much.
The biggest region to be concerned about would be Southern Appalachia. If we changed the
percentages from 35 and 50 percent for before and after coal cleaning—the percentage of coal that
meets standards— to say 20 and 40 percent, it makes a difference in the analysis of .25 quadrillion Btu
out of a total of 2.5 quadrillion Btu. So basically, the analysis is terribly sensitive to that. None the less,
he's right. You want to do as well as you can. In fact there is a real need to do an analysis at the regional
level, as has been pointed out, using U.S.B.M. data.
If I were going to build a coal plant, I would be very certain I did my analysis on the specific
coal—samples of specific coal beds and mines that I was going to purchase from. I hope that answers
the general comment basically. It doesn't matter too much in terms of the general analysis we did. Did
you want to make any further comments?
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HUCKO: Perhaps a quick comment would be appropriate. I think you took my gesture too
much to heart. 1 was not indicting you nor your-analysis in any way. I was indicting us for presenting
misleading data. That was the purpose of my gesture.
LEVINE: There is an interesting point. I think the Bureau of Mines did by far the best analysis of
sulfur content of coal. If they hadn't done the work there wouldn't be anything, essentially. It is useful
for them, for anyone taking that kind of data, to ask how they would be used. I think Mr. Hucko
pointed out that if those data could be presented in such a way that one could go from that
information to more generalizable information about coal in the region, it would make it more useful
for purposes of analysis.
MICKEY: I think this developing some sort of analytical methodology to try and get a grasp on
this problem is extremely important. We can always use improvement in the way we have been doing
it. I think we have an excellent start on this, with the PEDCo Report. This, with the PEDCo Report and
from what I've heard today, sounds like we are getting steam up. It is so important to recognize
quantification of data—of transportation. We have to have customers for one thing. We just can't say
that in a region we have different controls and have to do things in such and such a way.
We have to have customers, industrial customers, residential customers . . . there have to be
distribution and transmission costs. You're talking about siting plants; the transportation cost is part of
it. Then water is a question. Do you ship wet or dry? Do you simply put newly installed cleaning units
at a mine mouth facility or are we talking about cleaning plants at the site of the steam plants?
It seems to me since the Federal Power Commission can get all the steam power plants in one
book—we really aren't talking about an infinite set of things—that really it wouldn't be too much to
think of, possibly, to take a case by case analysis of these, rather than treating them in big groups or in
regions. This, I think, to get started, provides an initial perspective on what the possibilities are. That's
fine and dandy, and necessary. We have to have it, but maybe sometime down the road every single
case must be taken into consideration. Of course, I can't take into consideration plants that haven't
been sited yet; but, since we can put together a report on this like the FPC does every year, it wouldn't
be too formidable to develop viable methodology on a case by case basis around the country and
really have some competence with our strategy development.
LEVINE: I agree. Some work has been done along that line. There is a Schaeffer and Roberts
Report out that looked at coal cleanability in regions of Pennsylvania, and looked both at cleanability
and also primarily economics. FEA is gathering data on existing coal by sulfur content, by use in
electric generating facilities in Ohio. It is my understanding EPA at Research Triangle Park and the
enforcement people are gathering similar data for Ohio. So, I think the renewed interest in coal
cleaning is seen also in the renewed interest in gathering data that can give us some idea of what sort
of strategies we should use.
We've barely begun to look at those problems. I think my colleague, Jerry Issacs, is one example
of having done an unusual study in the sense he looked carefully at the economics. Homer City is
another case. So it is started. But there hasn't been nearly enough, certainly not at the policy level, in
terms of encouraging strategies. For example, I don't know the details, but I know Homer City applied
to EPA for some changes in regulations such that less sulfur would be emitted to the air at a lower cost
to DPU and lesser degradation to the environment. EPA, as far as I know, rejected the change in
regulations. I'm not sure if I have that story entirely straight.
MCCONNELL: We suggested that some consideration be given, rather than controlling each
unit, to control the site; and thereby optimize the coal supply on the basis of the Homer City site. You
can certainly accomplish equal or better environmental protection for less dollars, but it does tend to
circumvent the spirit of implementation of the Clean Air Act.
However, in deference to my customers, of which I am one, I still want to see the teast cost
solution. They really couldn't do that at Homer City.
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KILGROE: A few comments on the EPA point of view. I think they looked at the material we got
at DPU. The decision was that it would reduce costs and create certain regulatory problems. I am
speaking from a researcher's point of view and not the regulatory side of the house; but they, I guess,
turned down that request for that reason. As far as reduced environmental impact, there would have
been the same, I believe, total sulfur emissions from the site. The fact they were using a higher stack
on unit number three would have reduced a salient factor in air quality, so the air quality in the inner
region probably would have been improved somewhat by using dirtier, sulfurwise, coal in the unit
number three. The emissions would be dispersed over a larger area. That's where you get the
statement it would reduce the environmental impact.
PHUNC: I would like to comment on the gentlemen's suggestion of all the data of coal mines
and coal facilities be put in one book like the FPC book. I think that is quite a formidable task. The FPC
does have a book that puts all power plants in it. It is now two years late. It is now 1976 and we don't
have 1974 and 1975 data yet. It seems to me that half of the activity of the FPC is devoted to that book,
and it represents many, many millions of dollars. So unless any agency in the country has a new
mandate, maybe from Congress, to do that kind of activity, it is a formidable task.
HICKEY: I was using the suggestion that they get all the on-stream plants in one book just to
illustrate what we are dealing with. We have a number of plants that add up to the whole; and only by
treating these as individual cases can we come up with any strategy, with a developed methodology for
doing analysis. You have gotten started in two different directions at least. I don't see these published
as a policy in a book every year. I am suggesting we develop strategies that are more realistic so we
avoid the pitfall of drowning in two feet of water by using large scale, large regional averages that
ignore specific plants' circumstances in factors of that nature. Transportation is one of the big ones
and may be overriding in some cases. The other minor complications, such as existing contracts, are a
real fact. You have to begin to see what actually is the situation at each individual plant at any time
when you do the analysis. I would suggest publishing a book saying, "Here are all the answers."
ISSACS: You put emphasis on treating plants on an individual basis. Then are you saying that we
shouldn't take into account the other plants around there, that you treat these one plant at a time? I
don't understand why you're on a plant by plant basis rather than a group of plants together.
HICKEY: I guess the thing that triggers me is, in using this, is that we say we have so much coal
in the Appalachian area; and it can be treated to remove so much sulfur at a certain level. I think there
is great danger in this because of the variability of coals, the variability of organic and inorganic
fractions of these coals, the differences in the ash characteristics in these coals, the operability in
existing boilers. There isn't any question we can answer here today. As Jim (Kilgroe) says, try it and be
sure when you make a statement that is in a given area, say Pennsylvania, there is a certain amount of
coal that can be economically treated by Process "X". I just wonder if we are being realistic.
LEVINE: I was talking to John Fink, of EPA at Research Triangle Park. I'm going out there to see
him because of a statement he made to me that the FPC and EPA data bases have been merged, and all
the environmental information that EPA has on individual plants is combined in a single data base with
the information the FPC has. They both work off the same data base system. Now I don't know any
more about it than that. The reason I am going back is in response to the sort of interest Mr. Hickey
expressed: that is, we are trying to analyze alternative environmental control strategies. Hooking up
with realiable data bases is one of the things we have to do.
MCCARTHY: Some comments from Sam.
ALTSCHULER: I was a late substitute to this symposium and as a result I was not able to present
much for publication, as the proceedings will be coming out in a few weeks. However, people have
asked about copies of the data I presented. I would like to mention that the U.S.G.S. has recently
completed an assemblage of analyses of many, many hundreds of coal samples collected from about
3,000 samples which embrace trace element analyses, of ash, coal, Btu values, sulfur determinations
collected by the Bureau of Mines. All of this is part of a very comprehensive data bank—this is rather
pertinent to the discussion here—that the survey is maintaining for the national interest in coal. This
110
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data bank will include data on structure and stratigraphy, ash content, trace element content. It is
entered in a computer which has the capacity for mapping and contouring the data and superimposing
it on all different scales according to all national scale bases. We hope eventually to be able to contour
such things as individual trace elements in the ground, thickness of coal, associations between thick
coals, associations between trace elements, Btu, etc. Some of this raw data, not the computerized
output, are available in what we call an "open file report."
I mention this because I am apologetic that I won't be able to publish much of that data I
presented in your proceedings. Our open file system consists of reports made available at three survey
repositories—Denver, Washington, D. C., and Menlo Park. The open file report is called "Collection,
Chemical Analysis and Evaluation of Coal Samples 1975." It's number is 76-468. It is published by the
U.S. Geological Survey, Thank you.
KILGROE: It's getting late. I think everyone probably would like to go home. Don't you think so,
Bill?
MCCARTHY: I'm always one to take advantage of an opportunity. Therefore, I have kept this
expertise assembled for longer than scheduled; but you're right. Thank you for coming gentlemen.
The session is adjourned.
111
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APPENDIX
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ABOUT THE AUTHORS
ALTSCHULER, SAMUELZ. is studying the origin and distribution of low sulfur coals by mapping and
geo-chemical investigations for the U.S. Geological Survey, Reston, Va. A U.S. Geological Survey
employee for 25 years, he has been involved in phosphate geology and uranium gee-chemistry
research, analysis and evaluation. He has degrees from Brooklyn College and the University of
Pennsylvania. '
CAVALLARO, JOSEPH A. has been with the Coal Preparation and Analysis Laboratory of the U.S.
Bureau of Mines since 1961. He holds a degree in Chemical Engineering from the University of
Pittsburgh.
CUNNINGHAM, RAY W. is Chief of the Northern Compliance Section, Air Enforcement Branch, of the
U.S. Environmental Protection Agency's Regional Office in Atlanta, Georgia. He coordinates
federal air enforcement activities in the states of Kentucky, Tennessee, North Carolina and South
Carolina. Prior to joining EPA, Mr. Cunningham worked for the Tennessee Valley Authority as an
air pollution control engineer. He holds a B.S. in civil engineering and a master of environmental
engineering degree from the University of Florida.
DEURBROUCK, ALBERT W. is chief of the coal preparation and analysis laboratory at the U.S. Bureau
of Mines, Bruceton, Pennsylvania, Research Station and directs the agency's coal preparation
research program there. He is the author or co-author of numerous papers and articles covering a
wide range of coal preparation activities. He holds a degree in mining engineering from the
University of Idaho.
DEVITT, TIMOTHY W. is Vice-President in charge of Environmental Engineering Studies at the Univer-
sity of Cincinnati. He has directed numerous engineering and strategy development studies
related to energy supply and power systems. He has been a consultant to EPA on various projects,
has provided expert testimony at a number of hearings on environmental control methods, and
presented numerous papers and reports on environmental control. Mr. Devitt holds a B.S. in
Chemical Engineering from the University of California at Berkeley.
FOLEY, GARY J. was an advisor on advanced fossil fuels research and technology to the Deputy
Assistant Administrator, Office of Energy, Mineral and Industry, Environmental Protection Agency
at the time of preparation of this paper. He previously worked in EPA's Industrial Environmental
Research Laboratory and with computer services for the American Oil Company. In September,
1976, he was named associate director for energy of the Organization for Economic Cooperation
and Development, Environmental Directorate, Energy Division, Paris, France. He holds degrees in
chemical engineering from Manhattan College and the University of Wisconsin. He received his
doctorate from the University of Wisconsin.
FULLEN, ROBERT E., an energy economist, has been employed with Stanford Research Institute since
August 1974. Mr. Fullen is an authority on energy modeling to analyze the effects on energy policy
decisions and is an authority on sources of energy information. At SRI, Mr. Fullen has led or
participated in projects for federal and state governments and various private clients. Prior to
joining SRI, Mr. Fullen worked for the Federal Power Commission and the State of Maryland
Power Plant Siting Commission. He has a degree in economics from the University of Maryland.
GIAMMAR, ROBERT D. is a research specialist on environmental emissions from combustion activities
in the combustion section of Battelle Memorial Institute, Columbus Laboratories, Columbus,
Ohio. He holds degrees in mechanical engineering from Case Western Reserve University and
Ohio State University.
HUCKO RICHARD E. is a project leader in the Coal Preparation and Analysis Laboratory of the U.S.
Bureau of Mines at Bruceton, Pennsylvania. He is a graduate of the University of Pittsburgh and
holds bachelor's and master's degrees in civil engineering.
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ISAACS, GERALD A. is a director of various projects related to environmental control of combustion
processes and fuel utilization at PEDCo, Inc. Cincinnati, Ohio. He has been involved in the field of
air pollution control since 1965 when he worked for General Motors Research Laboratories.
Before joining PEDCo he was vice-president and director of engineering for a pollution control
consulting and engineering firm. Dr. Isaacs is a registered engineer and a member of APCA and
the American Institute of Plant Engineers. He has degrees in mechanical engineering and a Ph. D.
in environmental engineering.
JACOBSEN, STANLEY is with the U.S. Bureau of Mines, Bruceton, Pennsylvania, where he is responsi-
ble for engineering and architectural contracts for the proposed U.S.B.M. Coal Preparation
Research Facility. He has worked in coal preparation projects for the bureau for 12 years. He is a
graduate of the University of Washington, Seattle.
JOHNSTON, JOHN E. is deputy chief of coal in the Office of Energy Resources of the U.S. Geological
Survey. He is the author of numerous papers and publications on the geology of fossils, fuels, and
atomic energy resources. He has been particularly active in remote sensing research applied to
natural resources and environmental matters. He is a graduate of the University of North Carolina.
KILGROE, JAMES D. is manager of coal cleaning programs in the fuels process branch of EPA's
Industrial Environmental Research Laboratory at Research Triangle Park, North Carolina. His
responsibilities include interagency programs on environmental assessment and control technol-
ogy. He has been active in energy/environment related R&D for 15 years. His academic honors
include degrees in mechanical engineering from the University of Missouri and the University of
Santa Clara, California.
LEVINE, MARK D. is with the Center for Environmental Systems at Stanford Research Institute, Menlo
Park, California. He recently completed a status report on coal cleaning for the U.S. Environmen-
tal Protection Agency. He also has done work for the Federal Energy Administration, National
Science Foundation, and American Electric Power Association. He is a graduate of the University
of California, Berkeley.
LEVY, ARTHUR is manager of Combustion Systems Section for Battelle Memorial Institute, Columbus
Laboratories. His activities have been primarily in the area of gas-phase and combustion kinetics.
This includes studies on oxidation kinetics of hydrocarbons, the high-temperature kinetics of
flame reactions and combustion processes, and the ambient temperature kinetics of
photochemical-smog systems. Since joining Battelle in 1951 Mr. Levy has authored some 70
publications. Mr. Levy holds degrees in chemistry and physical chemistry from Queens College,
and the University of Minnesota, respectively.
MCCARTHY, WILLIAM N. JR. is senior chemical engineer on the headquarters staff of the Environmen-
tal Protection Agency's Office of Energy, Minerals and Industry, Washington, D.C. He is particu-
larly involved in EPA's fossil fuels programs and notably fluidized bed combustion and coal
processing sections. He has been active in EPA program management. He was a computer systems
analyst and intelligence analyst for the Food and Drug Administration and Department of Defense,
respectively, before joining EPA. He holds degrees in chemical engineering from Catholic Univer-
sity of America and the University of Maryland.
MCCONNELL, James F. is research and development manager for General Public Utilities Service
Corporation. He joined GPU seven years ago after working in the U.S. Navy nuclear program for
General Dynamics. He holds a degree in mechanical engineering from the University of Maryland.
MEYERS, ROBERT A. is manager of coal desulfurization activities at TRW Systems and Energy, Redondo
Beach, California. He holds three U.S. and several foreign patents on coal desulfurization
technology and is principal inventor of the Meyers coal cleaning process. He has published
numerous articles and is the author of a book on coal desulfurization. His academic honors
include degrees from California State College and the University of California at Los Angeles.
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SANTY, MYRRL J. is with TRW Systems and Energy at Redondo Beach, California. He has been
intimately involved in the development of the Meyers coal cleaning process as project engineer
for the coal desulfurization pilot plant design program, including detailed full scale engineering
and economic analysis of the Meyers process. He is an authority on the assessment of effective-
ness of various techniques and processes for eliminating hazards associated with organic waste
disposal. He holds a degree in chemical engineering from the University of Southern California.
SEKHAR, K.C. is a researcher on the fluidized bed combustion processes in the Chemical Process
Development Section of Battelle Memorial Institute Columbus Laboratories, Columbus, Ohio. He
is a graduate of the Indian Institute of Technology, West Bengal, and holds a masters degree in
chemical engineering from the University of Mississippi.
STAMBAUGH, EDCEL P. is research leader of the chemical processes development section of Battelle
Memorial Institute, Columbus Laboratories, Columbus, Ohio. He is engaged in development of
hydrothermal processing as applied to chemical cleaning of coal and production of feedstocks for
coal gasification and liquefaction. He is a graduate of Ohio State University.
VANDERBORCH, NICHOLAS E. is a staff member in the Chemistry-Materials Division of the Los
Alamos Scientific Laboratory. He served on the chemistry faculty of the University of New Mexico
from 1966-1974 and studied electro-chemistry and thermal pyrolysis. Since joining LASL in 1975, he
is involved in environmental chemistry, especially the environmental aspects of coal and coal-
waste storage. He is the author of about 35 publications. He holds a BA degree in chemistry from
Hope College and an M.S. and Ph. D. in chemistry from Southern Illinois University.
VAN NICE, LESLIE J. is assistant manager of the chemical engineering department of TRW Systems and
Energy, Redondo Beach, California. He is responsible for chemical engineering analysis and
chemical process design and evaluation. He is a specialist in the thermodynamic and kinetic
analysis of chemical reaction systems. Since 1972 he has managed and served as chief process
engineer on bench scale work on design of a pilot scale coal desulfurization plant. He is a
chemical engineering graduate of the University of California, Berkeley.
WEWERKA, EUGENE M. is a staff member at the University of California's Los Alamos Scientific
Laboratory, Los Alamos, New Mexico. Since joining LASL in 1965, he has been involved in research
on the chemistry of carbons and graphites, studies of polymer structure-property relationships,
and investigations of the properties and compatabilities of materials for weapons systems. He is
principal investigator of a research program on environmental contamination from coals and coal
wastes. Wewerka is an adjunct professor of chemistry at the University of New Mexico and the
author or co-author of about 30 scientific publications. He holds degrees in chemistry and physical
organic chemistry from the University of Minnesota.
WILLIAMS, JOEL M. is a staff member at the University of California's Los Alamos Scientific Laboratory.
He has been involved in research on synthetic carbons and graphites, carbon-aluminum compo-
sites and polymeric structures. Currently, he is a task leader in a research program on environ-
mental contamination from coals and coal wastes. Before joining LASL, he was a research chemist
at DuPont and an assistant professor of chemistry at the University of Minnesota. He is the author
or co-author of more than 25 publications. Williams has a degree in chemistry from the College of
William and Mary and a Ph.D. in physical-organic chemistry from Northwestern University.
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METRIC CONVERSIONS
To Convert From
Btu/hour
Btu
calorie
centimeter of Hg
centipoise
degree centigrade
degree Fahrenheit
foot
ft3/sec
gallon/min
inch
kWh
month
Ib/in2
Ib/in3
psi
ton (assay)
tonne
year (calendar)
To
watt (W)
joule (J)
joule (J)
pascal (Pa)
pascal (Pa-s)
degree kelvin (k)
degree celsius
meter (m)
meter3/sec
meter3/sec
meter (m)
joule (J)
second (s)
kilogram/meter2
kilogram/meter3
pascal (Pa)
kilogram (kg)
kilogram (kg)
second (s)
Multiply by
2.93077 E-01
1.055056 E +03
4.19002 E +00
1.33322 E+03
1.000E-03
tk=tc + 273.15
tc=(tF-32)/1.8
3.048 E-01
2.831685 E-02
6.309020 E-05
2.54 E-02
3.6E+06
2.628 E +06
2.926397 E-04
2.76799 E +04
6.894757 E +03
2.916667 E-02
1.0000 E+03
3.1536 E+07
118
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing}
1. REPORT NO.
EPA-600/7-76-024
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
EPA Program Conference Report-
Fuel Cleaning Program: Coal
5. REPORT DATE
October 1976 date of Issue
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
Z.S. Altschuler
R.E. Hucko
R.A.
P S Jacobson -J.F. McConnell
J'.D'. Ktlgroe ?•§• Beyers
M.D. LevTne p;£' Stambaugh
8. PERFORMING ORGANIZATION REPORT NO
EPA-600/7-76-024
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Office of Energy, Minerals, and Industry
U.S. Environmental Protection Agency
Washington, D.C. 20460
10. PROGRAM ELEMENT NO.
EHE 623
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
Dayton Section AlChE
c/o Engineering and Science Institute of Dayton
140 East Monument Avenue
Dayton, Ohio 45402
13. TYPE OF REPORT AND PERIOD COVERED
Final to October 76
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
Sessions Proceedings from the Fourth National Conference on Energy and the Environment
EPA Contact: Mr. William N. McCarthy, Jr., (202) 755-2737
16. ABSTRACT
This publication presents the U.S. Environmental Protection Agency's Office of
Energy, Minerals, & Industry's interagency coal cleaning research, development and
demonstration program. This report consists of the papers presented in the two
sessions, Coal Preparation of Pollution Control, of the Fourth National Conference on
Energy and the Environment (October 5-6, 1976, Cincinnati, Ohio). The first session
(section I of the publication) is concerned with the physical chemical and geochemical
aspects of coal including resource distribution and availability. The second session
(.section II of the publication) centers on the cleaning technology, both physical and
chemical, that Is advancing towards commercialization in cooperation with or under
sponsorship from the Government.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Group
Chemical reactivity
cleaning
coal cleaning
coal deposits
coal reserves
contaminants
desulfurization
electric utiIitles
heat of reaction
leaching
reaction kinetics
reactors
BatteI Ie HydrothermaI
Process
Control Technology
Environmental assessment
Homer City
Meyers/TRW Process
TRW/Meyers' Process
7A
7B
7D
I4A
8D
8G
81
I4B
IS. DISTRIBUTION STATEMENT
Release UnlFmtted
Available free from OEM I/EPA while the
supply lasts
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
118
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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