United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 2771 1
EPA-600/7-78-173a
August 1978
Assessment of Coal
Cleaning Technology:
An Evaluation of
Chemical Coal
Cleaning Processes
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development. U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of. control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service. Springfield, Virginia 22161.
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EPA-600/7-78 173a
August 1978
Assessment of Coal Cleaning
Technology:
An Evaluation of Chemical
Coal Cleaning Processes
by
G.Y. Contos, I.F. Frankel, and LC. McCandless
Versar, Inc.
6621 Electronic Drive
Springfield, Virginia 22151
Contract No. 68-02-2199
Program Element No. EHE623A
EPA Project Officer: James D. Kilgroe
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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ABSTRACT
This Task report is the result of a nine month study on one phase of
a three-year contract commissioned by the Fuel Process Branch of the
Industrial Environmental Research Laboratory of the U.S. Environmental
Protection Agency at Research Triangle Park, North Carolina. The primary
objective of the total program is to perform a comprehensive collection
and evaluation of physical and chemical coal cleaning technology for the
removal of sulfur from coal.
This specific Task report covers the technical and economic evaluation
of major U.S. chemical coal cleaning processes.
A variety of chemical coal cleaning processes are under development
which will remove a majority of pyritic sulfur from the coal with accept-
able heating value recovery i.e. 95 percent BTU recovery. Some of these
processes are also capable of removing organic sulfur from the coal, which
is not possible with the physical coal cleaning processes. Chemical coal
cleaning processes can remove as much as 95 to 99 percent of pyritic sulfur
and up to about 40 percent of the organic sulfur from the run-of-mine coal.
This removal efficiency could result in total sulfur reductions in U.S.
coals in the range of 53 to 77 percent.
This report presents available technical and economic information
on major chemical coal cleaning processes identified during the study.
Information on each process is provided in a format to identify:
• Process details,
• Developmental status,
• Technical evaluation, including process potential for sulfur
removal, sulfur by-products, process advantages and disadvantages,
environmental aspects, research and development needs, and
• Process economics.
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ACKNOWLEDGMENT
The preparation of this Goal Cleaning Technology Development Task
Report was accomplished through the efforts of the staff of The Engineering
Technology Division of Versar, Inc., Springfield, Virginia, under the
direction of Dr. Robert G. Shaver, Vice President and Mr. Lee C. McCandless,
Operations Manager.
Acknowledgment is specifically given to the major authors of this
report, Mrs. G. Y. Cantos and Dr. I. F. Frankel of Versar.
Mr. James D. Kilgroe, and Mr. David A. Kirchgessner, Project Officers,
Fuels Process Branch, Energy Assessment and Control Division, through
their assistance and direction, made a valuable contribution to the prepara-
tion of this report.
Also our appreciation is extended to the Versar staff with special
thanks to:
Dr. Marvin Drabkin
Ms. Jean Buroff
Mrs. Judi Robinson
Appreciation is also gratefully extended to the secretarial staff of
Versar, Inc., for their efforts in typing and revising this document.
Thanks are also extended to the various organizations and process developers
who supplied the data used and analyzed in this report.
in
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CONTENTS
Abstract ^
Acknowledgment !!.'.'!..'!.' iii
Figures ...*.".'.'. vii
Tables x
1. Introduction 1
Project Objectives 2
Project Methodology 3
Data acquisition 3
Develop data base 3
Process and cost information analysis 4
Process and cost comparison 8
2. Summary 9
Magnex Process 10
Syracuse Process 10
Meyers Process 14
Ledgeraont Process 14
ERDA Process 15
G.E. Process 15
Battelle Process 15
JPL Process 16
ICT Process 16
KVB Process 17
APCO Process 18
Sunmary of Minor and Miscellaneous Processes 18
3. Evaluation of Chemical Coal Cleaning Processes 22
TRW Meyers Chemical Coal Cleaning Process 23
Process description 23
Status of the process 26
Technical evaluation of the process 28
Process economics 36
Ledgenont Chemical Coal Cleaning Process 44
Process description 44
Status of the process 47
Technical evaluation of the process 49
ProoBss economics 51
MagneSSehentical Coal Cleaning Process 55
Process description 55
Status of the process 57
Technical evaluation of the process 58
Process economics 68
Syracuse tesearch Chemical Coal Comminution Process .... 73
Process description 73
Status of the process 76
iv
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CONTENTS
(continued)
Technical evaluation of the process 78
Process economics 90
ERDA Chemical Coal Cleaning Process 95
Process description 95
Status of the process 96
Technical evaluation of the process 98
Process economics 102
General Electric Chemical Coal Cleaning Process 106
Process description 107
Status of the process 109
Technical evaluation of the process Ill
Process economics 117
Battelle Chemical Coal Cleaning Process 122
Process description 122
Status of the process 128
Technical evaluation of the process 133
Process economics 140
JPL Chemical Coal Cleaning Process 146
Process description 146
Status of the process 150
Technical evaluation of the process 152
Process economics 160
Institute of Gas Technology (IGT) Chemical Coal
Cleaning Process 165
Process description 165
Status of the process 167
Technical evaluation of the process 169
Process economics 130
KVB Chemical Coal Cleaning Process 184
Process description 185
Status of the process 187
Technical evaluation of the process 188
Process economics
Atlantic Richfield Company Chemical Coal Cleaning
Process 199
Process description 199
Status of the process 199
Technical evaluation of the process 19i>
Process economics 200
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CCHSTTENTS
(continued)
Miscellaneous Chemical Coal Cleaning Processes 201
University of Houston Process 201
National Research Council (NRC), Canada Process 201
Jolevil Process 202
Ohio State University Process 202
Western Illinois University Process 203
Texaco Process 204
U.S. Steel Process 204
Kellogg Process 204
Chemical Construction Corporation (Chemico) Process . . . 205
University of Florida Process 205
Laramie Process 206
Dynatech Process 206
Kyoto Process 206
Methonics Process 207
Rare Earth's Process 207
MIT Process 207
Rutgers University Process 207
The Gulf & Western Process 208
Colorado School of Mines Research Institute
(CSMRI) Process 208
4. Process and Cost Comparison 209
Sulfur Removal and Heating Value Recovery Potential .... 209
Cost Comparison for Major Chemical Coal Cleaning
Processes 212
Capital cost comparisons 213
Operating cost comparisons 213
5. References 219
6. Glossary 223
Appendix I 225
Appendix II 248
Appendix III 250
Appendix IV 255
Appendix V 260
Appendix VI 263
Appendix VII 265
Appendix VIII 278
vo.
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FIGURES
Number Page
1 TFW (Meyers') process flow sheet 24
2 Meyers process vs. physical coal cleaning; trace element
removal data 34
3 Lodgement oxygen leaching process flow sheet 48
4 Magnex process flow sheet 56
5 Magnex process washability plot for a 6 inch x 100 mesh
coal 64
6 Magnex process efficiency comparison of laboratory and
pilot plant data 66
7 Syracuse coal ccnminution process flow sheet 74
8 Syracuse process chemical comtninution plus physical coal
cleaning 77
9 Syracuse process vs. mechanical crushing: size consist
comparison using Illinois no. 6 coal 80
10 Syracuse process vs. mechanical crushing: percent ash vs.
percent recovery of Illinois no. 6 coal 81
11 Syracuse process vs. mechanical crushing: percent sulfur
vs. percent recovery of Illinois no. 6 coal 82
12 Syracuse process vs. mechanical crushing: sulfur washability
curves for Pittsburgh coal (two hours) 85
13 Syracuse process vs. mechanical crushing: sulfur washability
curves for Pittsburgh coal (four hours) 86
14 ERDA process flow sheet 97
15 General Electric microwave process flow sheet 108
vii
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FIGURES (continued)
Number
Page
16 G.E. process: percent sulfur removal vs. exposure time
multiple exposure 112
17 G.E. process: percent sulfur removal vs. exposure tine
single exposure 113
18 Battelle hydrothermal process flow sheet 125
19 Battelle hydrothermal process material balance for reactor
and solid/liquid separation sections 127
20 JPL process flow sheet 147
21 JPL process: percent sulfur and chlorine in coal vs. time of
chlorination 154
22 IGT process flow sheet 168
23 IGT process: percent sulfur removal vs. temperature 172
24 IGT process: effect of holding time on sulfur removal .... 175
25 KVB process flow diagram 186
Appendices
1-1 Meyers process flow sheet for fine coal 230
HI-1 Magnex pilot plant schematic, crushing step 251
HI-2 Magnex pilot plant schematic, heating step 252
IH-3 Magnex pilot plant schematic, carbonyl treatment step .... 253
m-4 Magnex pilot plant schematic, magnetic separation step. . . . 254
IV-1 Syracuse process vs. mechanical crushing: size consist of
Upper Preeport coal 257
viii
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FIGURES (continued)
Number Page
IV-2 Syracuse process vs. mechanical crushing: percent sulfur
vs. percent recovery of Upper Freeport coal 258
IV-3 Syracuse process vs. mechanical crushing: size consist of
various Pittsburgh coals 259
V-l EHDA process flow sheet suggested by Bechtel 261
VIII-1 KVB process flow sheet suggested by Bechtel 279
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TABLES
Number
Page
1 Summary of Major Chemical Goal Cleaning
Processes 11
2 Process Information Surmary of Minor Chemical Coal
Cleaning Processes 19
3 Process Information Suimary of Miscellaneous Chemical Coal
Cleaning Processes 21
4 Meyers' Process Summary of Pyritic Sulfur Removal Results .... 31
5 Meyers' Process Coal Balance 38
6 Meyers' Process Raw Materials, Utilities and Waste Streams
Balance 39
7 Summary of Economics for The Meyers' Chemical Coal Cleaning
Process 41
8 Installed Capital Cost Estimate for The Meyers' Chemical
Coal Cleaning Process 42
9 Estimated Annual Operating Costs for The Meyers' Chemical
Coal Cleaning Process 43
10 Typical Values of Key Parameters In the Conceptual Ledgeroont
Oxygen/Leaching Process for Bituminous Coal 46
11 Summary of Economics for The Ledgemont Chemical Coal Cleaning
Process 52
12 Installed Capital Cost Estimate for The Ledgemont Chemical
Coal Cleaning Process 53
13 Estimated Annual Operating Costs for The Ledgencnt Chemical
Coal Cleaning Process 54
14 Sulfur awl Ash Removal From Lower Freeport Seam Coal By The
Magnex-^Process 60
x
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TABLES (Continued)
Number Page
15 Sulfur ani Ash Removal Fran Pittsburgh Seam Coal By The
MagneS-^Process 62
16 Sulfur ajjj^ Ash Removal From Pittsburgh Seam Coal By The
jss vs. Conventional Gravity Separation 62
17 Analysis of MagneJHProcess Pilot Plant Feed Coal 63
18 Summary of Laboratory Evaluation of MagneSHProcess Pilot
Plant Feed Coal 63
19 Summary of Economics for The MagnePChemical Goal
Cleaning Process 70
20 Installed Capital Cost Estimate for The Magr
Coal Cleaning Process 71
21 Estimated Annual Operating Cost for The Magnex~thendcal
Coal Cleaning Process 72
22 Product Recovery of Four Samples of Treated Illinois
No. 6 Coal At 1.4% Sulfur 84
23 Product Recovery of Four Samples of Treated Upper
Freeport Coal at 0.9% and 1.3% Sulfur 84
24 Product Recovery of Five Samples of Treated Pittsburgh
Seam Coal (Green County) at 2.5% and 2.3% Sulfur 87
25 Summary of Economics for The Syracuse Research Chemical
Comminution Process Plus Coarse Coal Beneficiation 92
26 Installed Capital Cost Estimate For The Syracuse Research Chemical
Comminution Process Plus Coarse Coal Beneficiation 93
27 Estimated Annual Operating Costs For The Syracuse
Research Chemical Comminution Process Plus Coarse
Rprna-Fi r?i a-h -i run
94
28 Pyrite Removal From Representative Goals Using the
ERDA Process 99
XI
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TABLES (Continued)
Nurrber
Page
29 Organic Sulfur Removal From Representative Coals Using
ERDA Process 99
30 ERDA Process Qxydesulfurization of Representative Coals 99
31 Summary of Economics for The ERDA Chemical Coal Cleaning
Process 103
32 Installed Capital Cost Estimate For The ERDA Chemical Coal
Cleaning Process 104
33 Estimated Annual Operating Cost For One ERDA Chemical Coal
Cleaning Process 105
34 Analysis of Coal Samples Used In The Evaluation of The
G.E. Process 110
35 Analysis For Raw and G.E. Process Treated Coals 114
36 Sunmary of Economics For The General Electric Chemical Coal
Cleaning Process 119
37 Installed Capital Cost Estimate For The General Electric Chemical
Coal Cleaning Process 120
38 Estimated Annual Operating Costs For The General Electric
Chemical Coal Cleaning Process 121
39 Typical Valves of Key Parameters in Battelle Hydrothernal
Coal Process 124
40 Estimated Heat and Power Consumption of The Battelle
Hydrothermal Coal Process 129
41 Trace Element Reduction In Coals Treated By The Battelle
Hydrothermal Process 132
42 Continuous Bench-Scale Results for The Battelle Process 136
xxi
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TABLES (Continued)
Number Page
43 Summary of Economics For The Battelle Chemical Goal
Cleaning Process 143
44 Installed Capital Cost Estimate For The Battelle Chemical
Coal Cleaning Process 144
45 Estimated Annual Operating Costs For The Battelle Chemical
Coal Cleaning Process 145
46 Properties of Nine Selected Coals For The JPL Process
Experiments 151
47 Summary of Economics For The JPL Chemical Coal Cleaning
Process 162
48 Installed Capital Cost Estimate For The JPL Chemical Coal
Cleaning Process 163
49 Estimated Annual Operating Cost For The JPL Chemical Coal
Cleaning Process 164
50 IGT Process Thermobalance Sulfur Removal Results 171
51 IGT Process Typical Batch Reactor Runs With Specified
Feedstocks 174
52 Summary of Economics For The IGT Chemical Coal Cleaning
Process 181
53 Installed Chemical CVy*l Estimate for the IGT Chemical
Coal Cleaning Process 182
54 Estimated Annual Operating Costs For The IGT Chemical
Coal Cleaning Process 183
xiii
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TABLES (Continued)
Hunter
Page
55 Coal Desulfurization Data using the KVB Process 189
56 KVB Process Coal Balance 194
57 KVB Process Raw Materials, Utilities and Waste Streams
Balance 195
58 Summary of Economics For The KVB Chemical Coal Chemical
Process 196
59 Installed Capital Cost Estimate For The KVB Chemical Coal
Cleaning Process 197
60 Estimated Annual Operating Cost For The KVB Chemical Coal
Cleaning Process 198
61 Process Performance and Cost Comparison For Major Chemical
Coal Cleaning Processes 211
62 Operating Cost Comparisions For Major Chemical Coal Cleaning
Processes 215
63 Cost Effectiveness and Other Comparisions of Chemical Coal
Cleaning Processes 217
APPENDICES
1-1 Meyers' Process: Relative Rate Constants for Pyritic
Sulfur Removal 228
1-2 Meyers' Process Mass Balance for Fine Coal 234
1-3 Meyers' Process Coal Desulfurization Process Equipment List . . . 244
II-l Representative Analyses of Illinois #6 and Kentucky
Coals
. 249
IV-1 Analyses of Upper Freeport Seam, Pittsburgh Seam, Blended
(Upper and lower Freeport Seam) Coal, and Illinois
Number 6 Seam Coal Samples 256
XLV
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APPENDICES TABLES (Continued)
Number Page
VT-1 JPL Process: Proximate Analysis Data of Two Tested Coals . . . 264
VII-1 IGT Process: Analysis of Western Kentucky No. 9 Coal
Used in Batch Reactor Runs 266
VII-2 IGT Process: Thexmobalance Test Run Data, Pretreated
Western Kentucky No. 9 Coal 267
VII-3 IGT Process: Theritbbalance Run Data, Western Kentucky
No. 9 Coal (Rapid Heat-Up Rate) 268
VII-4 IGT Process: Thermobalance Run Data, Illinois No. 6 Coal . . . 269
VII-5 IGT Process: Batch Reactor Test Run Data for Pretreated
Western Kentucky No. 9 Coal 270
VII-6 Illinois No. 6 Coal Analysis 271
VII-7 IGT Process: Batch Reactor Tests - Pretreated Illinois
No. 6 (-10 +40 MESH) Coal 272
VII-8 Pittsburgh Seam/West Virginia Coal Analysis 273
VII-9 IGT Process: Thernbbalance Run Data, Pretreated Pittsburgh
Seam, West Virginia Coal 274
VII-10 Analyses of Pittsburgh Seam Coal (Pennsylvania Mine) 275
VII-11 IGT Process: Thermobalance Run Data, Pittsburgh Seam Coal
(Pennsylvania Mine) 276
VII-12 Illinois No. 6 Analyses 277
xv
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SECTION 1
INTRODUCTION
A major concern for preserving the quality of the environment resulted
in Congress passing the Air Quality Act of 1963 which initiated a concerted
effort by Federal, State and local Governments to clean up the quality of
the Nation's air. This act placed special emphasis on the problem of
sulfur oxide emissions from the combustion of coal and oil in stationary
plants.
The U.S. Environmental Protection Agency under the Clean Air Act of
1970 and the Clean Air Act Amendments of 1977 is charged with the promulga-
tion of standards and the implementation of state and federal plans for the
reduction of sulfur dioxide emissions.
In 1974, sulfur oxide emissions from coal combustion were in excess of
18.6 million metric tons (20.5 million tons). With the projected increase
in the use of coal as a major energy source, improved methods are needed for
the control of this pollutant emission. Industrial coal consumption is_prp-
jected to quadruple from 61.7 million metric tons (68 minim tons) in 1975
to 251 million metric tons (277 million tons) in 1985. Utility coal consump-
tion is projected to increase from 366 million metric tons (404 million tons)
to 707jnillion metric tons (779 mill inn tons).l The success of the National
Energy Plan depends heavily on the adequacy of pollutant emission control
technology.
The possible solutions to this problem are the following processes
which are capable of attaining sulfur dioxide reductions:
• Flue gas desulfurization - removes SO2 from coal combustion flue
gases;
• Physical coal cleaning - removes pyritic sulfur from coal prior
to combustion;
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• Chemical coal cleaning - removes pyritic and organic sulfur
from coal prior to combustion;
• Synthetic fuel production - conversion of coal into clean burning
gaseous or liquid fuels; and
• Fluidized bed conbustion - burning coal in the presence of additives
that will remove sulfur as a mineral residue.
Several chemical coal cleaning processes are under development that
claim removal of substantial quantities of organic sulfur as well as
greater than 90 percent reduction of pyritic sulfur. If these processes
are found to be feasible on a commercial scale, they could have a significant
impact on coal utilization. It has been estimated that chemical processes
which can remove as much as 95 to 99 percent of pyritic sulfur and up to
40 percent of organic sulfur from raw coal could achieve total sulfur
reductions in U.S. coals in the range of 53 to 77 percent.
Recognizing the importance of chemical coal cleaning processes as a
potential sulfur dioxide pollutant control option, the Energy Assessment
and Control Division of the Industrial Environmental Research Laboratory of
EPA contracted with Versar to study the technical and economic feasibility
of the chemical coal cleaning processes. This study is one task of a major
study titled "Coal Cleaning Technology Development".
PROJECT OBJECTIVES
The objective of this study was to survey the field of chemical coal
cleaning processes to identify active and inactive processes and perform
a critical evaluation of competing processes. The purposes of this
evaluation were fourfold:
• To provide updated information on technical and economic viability
of these processes and identify their developmental stage;
• To examine their performance characteristics and environmental
aspects;
• To develop quantifiable technical and economic parameters for
purposes of process comparison; and
• To identify specific research and development needs for processes
showing a potential for substantial reduction of sulfur in coals.
•, •
2
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PROJECT METHODOLOGY
The conduct of the project may be described in terms of the following
four work phases:
• data acquisition;
• develop data base;
• process and cost information analysis; and
• process and cost comparison.
Data acquisition
The data needed for this study were obtained by four different methods.
First, by reviewing published information in the technical literature,
patents and government documents made available by EPA. These references
are cited throughout this report and listed in Section 5. The second
method involved using data compiled by EPA during a previous study on
chemical coal cleaning. The third method involved telephone and mail
contact with the developer of each process to obtain detailed process and
economic information. The fourth method of data acquisition was by inter-
viewing process developers and making site visits to process laboratories
or pilot plants.
The data needed for this report were assembled and compiled in the time
frame May through September, 1977. The chemical coal cleaning is, however,
a dynamic field and several of the processes are under further investigation
and development. It is likely that the on-going effort could have a
significant impact on some processes and could have resulted in process
designs that are superior to the ones described and discussed in this
report. This report, therefore, may not include the latest thinking of some
of the developers on their process flow diagram and design specifications.
Develop Data Base
At the onset of the project it was recognized that an organized data
base on the chemical coal cleaning processes was essential to formulate
meaningful conclusions regarding the performance of various processes,
their developmental stage and their economics. Therefore, an initial
objective of this phase was to prepare a "Process Information Form" to
3
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serve as a check list for obtaining and recording important technical and
economic data. Eftphasis was placed on completing the form, to the extent
possible, from available in-house information prior to contacting the
process developers or knowledgeable personnel on each process for missing
information. The use of these forms prevented the inadvertent omission
of important process details during phone contacts and personal interviews.
The completed forms, also, served as the principal source of data for
process evaluation work.
Process and Post Information Analysis
Subsequent to data base compilation, the major tasks involved in data
analysis were:
• To review the collected data on individual processes for adequacy
and probable accuracy;
• To develop or compile tabular and graphical representations of
available data on each process in a format to allow the formulation
of meaningful conclusions; and
• To identify critical process parameters and prepare a list of
criteria for process and cost evaluation work.
Engineering judgement was used in selecting or developing schematic
flow sheets for processes on which adequate experimental data are unavailable.
The process economics prepared for these processes are based on preliminary
aeptual processing schemes and, as such, are engineering estimates. The
process operating conditions, the process chemistry, the levels of removal
of mineral and organic sulfurs, the heating value and yield recovery
information are based on Versar's evaluation of the individual developer's
claims. These are reported in appropriate sections of this report.
Vhere cost information was supplied by a developer, these costs were
utilized,to the extent possible, as the basis of the cost information in
this report. However, these costs were modified to allow the evaluation
of the various processes on a comparable basis. Cross-checks were made
whenever information was available from different sources.
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Cost Basis—
Interest posts and equity financing charges—Capital investments
involve the expenditure of money which most be financed either on borrowed
money or from internal equity. Estimates for this study have been based
on 10 percent cost of capital, representing a composite number for
interest paid or return on investment required.
Time index for costs—All cost estimates are based on First Quarter
1977 prices and, when necessary, have been adjusted to this basis using
the Chemical Engineering or the Marshall and Stevens Cost Indices.
Useful service life—The useful service life of process equipment
varies depending on the nature of the equipment and process involved, its
usage pattern, maintenance care and numerous other factors. Individual
companies have their own service life values based on actual experience
and use these internal values for amortization. Another source of service
life information, less relevant than company experience, is the Internal
Revenue Service guidelines. A useful service life of 20 years was used
for all equipment in this study.
Capital costs—Capital costs are defined for the purposes of this
report as all front-end loaded, out-of-pocket expenditures for the provision
of the coal cleaning facilities. Ihese costs include land, equipment
construction and installation, buildings, services and engineering costs.
When capital costs were known for a specific coal cleaning technology,
cost adjustment to the typical plant size was made using an exponential
factor of 0.65.
Contingencies—A contingency allowance of 20 percent is added to
installed capital cost in all estimates, with the exception of TEW's. A
lower contingency allowance (10 percent) was used for the latter process
since it is at a more advanced stage of development and adequate process
data were available to develop the economics of this process with a greater
degree of confidence.
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Capital equipment amortization—It is assumed that regardless of tax
and depreciation considerations, a plant operator would probably finance
and amortize a chemical coal cleaning plant by means of an equal-payment,
self-liquidating loan or its equivalent. If the loan is payable with
equal installments, the amount due per period per dollar of loan as a
function of the loan period and interest rate is given by:
R = i (l+i)n
where R = capital recovery per period per dollar invested
i = interest rate per period expressed as a decimal
m = number of periods in the amortization schedule
As mentioned above, all annual capital recovery costs were calculated
based upon a 20-year lifetime and a 10 percent interest rate. The capital
recovery factor is then
R= (
(1.1 '-I
Operating expenses — Annual costs of operating a coal cleaning facility
include labor, supervision, labor additive and support costs; maintenance
cost, taxes and insurance costs; power, water and steam costs; raw coal
and chemical costs and refuse disposal cost.
• Labor, supervision and labor additive and support costs — Where not
provided by the process developer, the following costs were used:
Direct Labor (DL) $14,400/man year
Supervision (SL) $19,200/man year
Labor Additives (LA) @ 30 percent (DL + SL)
Services & Support @ 20 percent (DL + SL + IA)
• Maintenance cost — Where not provided by the process developer,
maintenance is taken as 5 percent of total invested capital.
• Taxes and insurance costs — Taxes and insurance are taken as 2 and
1 percent, respectively, of the total invested capital.
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• Fewer, energy and utilities costs—Where not provided by the process
developer, costs for power, energy and utilities were taken as:
Electric power, mil/kwh 25
Cooling water, $/l,000 liters ($/l,000 gal) 0.013(0.05)
Process water, $/l,000 liters ($/l,000 gal) 0.066(0.25)
Steam (110 to 220 psia), $/l,000 kg ($/l,000 Ib) 8.81(4.0)
For the ICT process, since the process is at a very early stage of
development and adequate process data were unavailable to estimate the
electric power and water requirements, these costs were taken as 5 percent
of the raw coal cost.
Where appropriate, product coal or raw coal has been used to supply
in-process fuel needs or for generating steam for in-process use.
• Raw coal and chemical costs—The cost of one ton raw coal input
to each cleaning plant was taken as $27.6 per metric ton ($25/ton).
Chemical costs are, however, variable for each individual process. Where
the total cost of the chemicals was not provided by the process developer,
individual costs listed below were used to estimate this cost.
Lignin sulfonate binder, $Ag($/lb) 0.13(0.06)
Lime, $/kkg($/tcn) 38.5(35.0)
Iron carbonyl, $Ag ($/lb) 0.222 (0.101)
Liquid ammonia, $/kkg($/ton) 143(130)
Chlorine, $/kkg($/ton) 38.6(35.0)
Oxygen, $/kkg($/ton) 27.6(25.0)
Nitrogen dioxide, $/kkg($/tcn) 220(200)
Caustic soda, $/kkg($/ton) 176(160)
For the ICT process, these costs were taken as 5 percent of the raw
coal cost.
• Cost for solid waste disposal'—For those processes which generate
quantifiable amounts of solid waste, the cost for disposal was assumed
to be $1.1 per metric ton ($1.0/ton).
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Process and Post Conparison
Sulfur removal level, heating value recovery potential, capital
investment and operating cost comparisons were made between competing
processes. Ihese are discussed in Section 4.
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SBCTTCN 2
Chemical coal cleaning processes are still under development. None
of these processes have been tested in units larger tfian eight metric
tons per day and only one process even at that size. Consequently, perform-
ance and cost comparisons are relatively uncertain at this time. The
chemical coal cleaning processes vary substantially in their approach,
because of the large number of possible reaction mechanisms and chemicals
which can be used to effect removal of sulfur and other reactive impurities
in coal. Most chemical processes remove over 90 percent of the pyritic
sulfur and several remove up to 40 percent of the organic sulfur as well.
Twenty-nine chemical coal cleaning processes were identified during this
technology overview study. Eleven U.S. developed processes ,are classified
as manor processes; seven U.S. and Canadian processes are classified as minor
processes due to their early stage of development or inactive status. The
remaining eleven U.S. , Japanese and Austrailian processes are judged to
deserve no further consideration. These processes are listed in tables later
in this section. Other processes of importance nay exist, but have not been
"identified in the extensive search conducted in this study.
The eleven major chemical coal cleaning processes exhibit a great deal
of diversity with respect to such variables as:
• type of coal successfully desulfurized
• degree of coal crushing and grinding prior to chemical processing
• state of process development
• process chemistry
• major process steps
• kinds and amounts of sulfur removed
• prospects for technical and economic success
-------
Table 1 shows a listing of the major processes and briefly sunmarizes
sane of the above factors. The _first_fc»ur processes listed (Magnex,
Syracuse, TRW, and Lodgement) will remove pyritic sulfur only; the remain-
ing^ s^veiyMrpcesses (ERDA, GE, Battelle, JPL, IOT, KVB, and ARCO)
claim to remove most of the pyritic sulfur and varying amounts of
organic sulfur. Also, the first two processes are unique in that the coal
is chemically pretreated, then sulfur separation is subsequently achieved by
mechanical means. The remaining nine processes are more typically chemical
in that sulfur compounds in the coal are chemically attacked and converted.
A capsule summary of each major process follows.
MACHEX PROCESS
In this process, dry, pulverized (minus 14 mesh) coal is pretreated
with iron penta-carbonyl to render the mineral components of the coal
magnetic. Separation of coal from pyrite and other mineral elements is
then accomplished magnetically. The process has been proven on a pilot plant
scale using the carbonyl on a once through basis. The cost of the Magnex pro-
cess critically depends on the recycle of iron-carbonyl. It is claimed that
iron-carbonyl can be produced on-site from carbon monoxide released in the
process. However, the continuous recycle of carbon monoxide to produce
low-cost iron-carbonyl requires demonstration. If success is not achieved,
the process may prove economically infeasible. Approximately 40 coals,
mostly of Appalachian origin, have been evaluated on a laboratory scale.
These coals are rich in pyritic sulfur and are thus applicable to this
process. For the most part, the process will produce coals which meet State
regulations for sulfur dioxide emissions of 4.3 kg SO2/106 kg cal
(2.4 Ib SO2/106 HKJ).
SYRACUSE PROCESS
Coal of about 3.8 cm (IV) top size is chemically camdnuted by exposure
to moist ammonia vapor at intermediate pressure. After removing the ammonia,
conventional physical coal cleaning then effects a separation of coal from
pyrite-rich ash. Generally, 50-70% of pyritic sulfur has been removed from
Appalachian and Eastern Interior coals, producing coals which meet state
regulations for sulfur dioxide emission. Construction of a 36 metric tons
10
-------
TABLE i. siww OF mm CHEMICAL COAL CLEANING PROCESSES
PROCESS &
SPONSOR
"MAGNEX"®
HAZEN RESEARCH
INC., GOLDEN
COLORADO
"SYRACUSE"
SYRACUSE
RESEARCH CORP.,
SYRACUSE, N.Y.
'BEYERS", TRW,
INC. REDONDO
BEACH, CAL.
"UXL' KENNECOTT
COPPER CO.
LEDGEMONT, MASS.
METHOD
DRY PULVERIZED COAL
TREATED WITH FE
(CO) 5 CAUSES PYRITE
TO BECOME MAGNETIC.
MAGNETIC MATERIALS
REMOVED MAGNETICALLY
COAL IS COMMINUTED
BY EXPOSURE TO NH3
VAPOR; CONVENTIONAL
PHYSICAL CLEANING
SEPARATES COAL/ASH
OXIDATIVE LEACHING
USING FE2(S04)3 +
OXYGEN IN WATER
OXIDATIVE LEACHING
USING 02 AND WATER
8 MODERATE TEMP.
AND PRESSURE
TYPE SULFUR
REMOVED
UP TO 90%
PYRITIC
50-70%
PYRITIC
90-95%
PYRITIC
90-95%
PYRITIC
STAGE OF
DEVELOPMENT
BENCH & 91 KG/HR
(200 LB/HR) PILOT
PLANT OPERATED
BENCH SCALE
8 METRIC TON/DAY
PDU FOR REACTION
SYSTEM. LAB OR
BENCH SCALE FOR
OTHER PROCESS
STEPS.
BENCH SCALE
PROBLEMS
DISPOSAL OF S-CONTAIN-
ING SOLID RESIDUES.
CONTINUOUS RECYCLE OF
CO TO PRODUCE FE
(C0)5 REQUIRES
DEMONSTRATION
DISPOSAL OF SULFUR
CONTAINING
RESIDUES.
DISPOSAL OF ACIDIC
FES04& CAS04, SULFUR
EXTRACTION STEP
REQUIRES DEMONSTRA-
TION
DISPOSAL OF GYPSUM
SLUDGE. ACID
CORROSION OF
REACTORS
ANNUAL OPERATING
COST J/TON CLEAN
COAL INCLUDING
COST OF COAL
10.7
37.0
43.4
«,9
RAW COAL COST IS INCLUDED AT $25/TON.
-------
TABLE 1, SuWMY OF WJOR CHEMICAL OWL CLEWING PROCESSES
PROCESS &
SPONSOR
"ERDA" (PERC)
BRUCETON, PA,
"GE" GENERAL
ELECTRIC CO, ,
VALLEY FORGE,
PA.
"BATTELLE"
LABORATORIES
COLUMBUS, OHIO
"JPL" JET
PROPULSION
LABORATORY
PASADENA, CAL.
"IGT" INSTITUTE
OF GAS
TECHNOLOGY
CHICAGO, ILL.
METHOD
AIR OXIDATION &
WATER LEACHING a
HIGH TEMPERATURE
AND PRESSURE
MICROWAVE TREATMENT
OF COAL PERMEATED
WITH NAOH SOLUTION
CONVERTS SULFUR
FORMS TO SOLUBLE
SULFIDES
MIXED ALKALI
LEACHING
CHLORINOLYSIS IN
ORGANIC SOLVENT
OXIDATIVE PRETREAT-
MENT FOLLOWED BY
HYDRODESULFURIZATION
ATHJrc
TYPE SULFUR
REMOVED
^5Z PYRITIC;
UP TO 40*
ORGANIC
~75% TOTAL S
**£!» PYRITIC;
'V'25-50K ORGANIC
•^OZPYRITIC; UP
TO 70% ORGANIC
•^EZPYRITIC; UP
TO 85% ORGANIC
STAGE OF
DEVELOPMENT
BENCH SCALE 11 KG/
DAY (25 LB/DAY)
CONTINUOUS UNIT
UNDER CONSTRUCTION
BENCH SCALE
9 KG/HR (20 LB/
HR) MINI PILOT
PLANT AND BENCH
SCALE
LAB SCALE BUT
PROCEEDING TO
BENCH AW) MINI
PILOT PLANT
LAB AND BENCH
PROBLEMS
GYPSUM SLUDGE DISPOSAL
ACID CORRROSION AT
HIGH TEMPERATURES
PROCESS CONDITIONS
NOT ESTABLISHED
CAUSTIC REGENERATION
PROCESS NOT
ESTABLISHED.
CLOSED LOOP REGENERA-
TION PROCESS UNPROVEN,
RESIDUAL SODIUM IN
COAL
ENVIRONMENTAL
PROBLEMS. CONVER-
SION OF HCL TO CL2
NOT ESTABLISHED
UDWBTU YIELD (<55%).
CHANGE OF COAL M/VTRIX
ANNUAL OPERATING
COST I/TON CLEAN
COAL INCLUDING
COST OF COAL
51.6
11.8
55.9
46,0
65.8
•RAW COAL COST is INCLUDED AT $25/TON.
-------
TABLE 1, SUWW OF MJOR CHEMICAL COAL CLEANING PROCESSES
PROCESS &
SPONSOR
"KVB" KVB, INC,
TUSTIN, CAL.
"ARCO''ATLANTIC
RICHFIELD
COMPANY
HARVEY/ ILL.
METHOD
SULFUR IS OXIDIZED
IN NOo-CONTAINING
ATMOSPHERE. SULFATES
ARE WASHED OUT.
TWO STAGE
CHEMICAL
OXIDATION
PROCEDURE
TYPE SULFUR
REMOVED
"^Z PYRIT1C; TO
m ORGANIC
^EZ PYRITIC;
SOME ORGANIC
STAGE OF
DEVELOPMENT
LABORATORY
CONTINUOUS 0.<6
KG/HR Q LB/HR)
BENCH SCALE UNIT
PROBLEMS
WASTE & POSSIBLY
HEAVY METALS DISPOSAL
POSSIBLE EXPLOSION
HAZARD VIA DRY OXIDA-
TION.
UNKNOWN
ANNUAL OPERATING
COST $/TON CLEAN
COAL INCLUDING
COST OF COAL
"7.5
46-58
(ESTIMATES)
"RAW COAL COST is INCLUDED AT $25/TON.
-------
(40 tens per day) pilot plant is contemplated, tto major technical
problems have been reported for this process other than potential problems
involving scale-up to pilot plant size.
MEYERS PROCESS
This process is the most advanced of the chemical coal cleaning pro-
cesses, with an 9 metric ton per day Reaction Test Unit (KTO) in operation.
The process removes 80-99% of the pyritic sulfur from nominally 14 mesh top
size coal. The process uses an aqueous solution of ferric sulfate and
sulfuric acid to effect a chemical leaching at moderate temperatures and
pressures, but at rather long holding periods (8-13 hours). Thirty-two
different coals have been tested: twenty-three from the Appalachian Basin;
six from the Interior Basin; one from Western Interior Basin and two
western coals. The Meyers process is more applicable to coals rich in
pyritic sulfur, thus about one-third of Appalachian coal could be treated
to sulfur contents of 0.6 to 0.9 percent to meet the sulfur dioxide emission
requirements of current EPA NSPS. Process by-products are elemental sulfur,
gypsum from waste water treatment, and a mixture of ferric and ferrous
sulfate, with the latter presenting a disposal problem.
LEDGQCtTT PROCESS
The Lodgement oxygen leaching process is based on the aqueous oxida-
tion of pyritic sulfur in coal at moderately high temperatures and pressures.
The process has been shown to remove more than 90% of the pyritic sulfur in
coalfl of widely differing ranks, including lignite, bituminous coals, and
anthracite, in bench-scale tests. However, little, if any, organic
sulfur is removed by the process. The process became inactive in 1975
during divestiture of Peabody Goal Company by Kennecott Copper Co. Although
not as well developed as the Meyers process, the Ledgemont process is judged
to be competitive in cost and sulfur removal effectiveness. The principal
engineering problem in this process is the presence of corrosive dilute
sulfuric acid, which may pose difficulties In construction material
selection and In choosing means for pressure letdown. The process also has
a potential environmental problem associated with the disposal of line-
gypsum-ferric hydroxide sludge which may contain heavy metals.
14
-------
ERDA PROCESS
The ERDA air and steam leaching process is similar to the Ledgemont
oxygen/water process except that the process employs higher temperature
and pressure to effect the removal of organic sulfur and uses air instead
of oxygen. This process can remove more than 90% of the pyritic sulfur
and up to 40% of organic sulfur in coals starting with minus 200 mesh
coal. Coals tested on a laboratory scale include Appalachian, Eastern
Interior and Western. The developer's claim is that using this process,
an estimated 45 percent of the mines in the eastern United States could pro-
duce environmentally acceptable boiler fuel in accordance with current EPA
standards for new installations. Effort to date is on a bench scale, but a
mini-pilot plant is expected to start up soon. The problems associated with
this process are engineering in nature. The major one is associated with
the selection of materials for the unit construction. Severe corrosion
problems can be expected in this process as the process generates dilute
sulfuric acid which is highly corrosive at the operating temperatures and
pressures.
G.E. PROCESS
Ground coal (40 to 100 mesh) is wetted with sodium hydroxide solution
and subjected to brief (V30 sec.) irradiation with microwave energy in an
inert atmosphere. After two such treatments, as much as 75-99% of the total
sulfur is converted to sodium sulfide or polysulfide which can be removed by
washing. No significant coal degradation occurs. That portion of the process
which recovers the sulfur values and regenerates the NaOH is not proven.
Work to date is in 100 gram quantities, but scale-up to 1 kg quantities is
presently in progress. The process appears to attack both pyritic and organic
sulfur, possibly at about the same rate. Appalachian and Eastern Interior
coals having wide ranges of organic and pyritic sulfur contents have been
tested with about equivalent success.
BAHELUS PROCESS
In this process, 70 percent minus 200 mesh coal is treated with aqueous
sodium and calcium hydroxides at elevated temperatures and pressures, which
removes nearly all pyritic sulfur and 25-50% of organic sulfur. Test work
15
-------
en a bench and pre-pilot level en Appalachian and Eastern Interior coals has
resulted in products which meet current EPA NSPS for sulfur dioxide emissions.
Hie conceptualized process, using line-carbon dioxide regeneration of the
spent leachant, removes sulfur as hydrogen sulfides which is converted to
elemental sulfur using a Stretford process. In addition to being a costly
process, there are two major technical problems:
• The feasibility of the closed-loop caustic regeneration feature
in a continuous process is as yet undemonstrated; and
• The products may contain excessive sodium residues, causing low
melting slags and making the coal unusable in conventional dry-
bottom furnaces.
JPL PROCESS
This process uses chlorine gas as an oxidizing agent in a solution
containing trichlorethane to convert both pyritic and organic forms of
sulfur in coal to sulfuric acid. Since removal of sulfur can approach the
75% level, without significant loss of coal or energy content, products
should generally meet current EPA NSPS for sulfur dioxide emissions. To
date the process has been tested on a laboratory scale only, on two
Eastern Interior coals, however the effort will progress to bench-scale
and pre-pilot plant scale in the near future. The project is supported by
the Bureau of Mines. There are some potential environmental problems with
the process. The trichloroethane solvent is listed by EPA as a priority
pollutant in terms of envirormental effects. A major drawback is in the
need to recycle by-product hydrochloric acid for conversion to chlorine.
At a chlorine consumption rate of 250 kg per metric ton of coal, the
incorporation of a Kel-Chlor unit in the JPL system will add approximately
$10/TOetric ton of coal. This may be a difficult economic problem for the
JPL process to surmount.
IGF PROCESS
This process employs essentially atmospheric pressure and high temper-
atures [about 400°C (750°F) for pretreatment and 815°C (1500°F) for hydro-
desulfurization] to accomplish desulfurization of coal. These high
temperatures cause considerable coal loss due to oxidation, hydrocarbon
16
-------
volatilization and ooal gasification, with subsequent loss of heating value.
Experimental results have indicated an average energy recovery potential of
60% for this process. The treated product is essentially a carbon char with
80-90% of total sulfur removed. Most of the experimental work to date has
been accomplished vdth four selected bituminous coals with a size of plus
40 mesh. Present effort is on a bench-scale level. The net energy recovery
potential of the system and the change in the coal matrix by the process have
been identified as possible severe problems for the ICT process. The process
must be developed to a stage where the process off-gas can be satisfactorily
utilized for its energy and hydrogen content. If this cannot be technically
and economically accomplished, the process will prove to be inefficient and
too costly for commercialization.
KVB PROCESS
This process is based upon selective oxidation of the sulfur constituents
of the coal. In this process, dry coarsely ground coal (plus 20 mesh) is
heated in the presence of nitrogen oxide gases for the removal of a portion
of the coal sulfur as gaseous sulfur dioxide. The remaining reacted, non-
gaseous sulfur compounds in coal are removed by water or caustic washing.
The process has progressed through laboratory scale, but was discontinued
recently for lack of support. Laboratory experiments with five different
bituminous coals indicate that the process has desulfurization potential of
up to 63 percent of sulfur with basic dry oxidation and water washing
treatment and up to 89 percent with dry oxidation followed by caustic
and water washing. The washing steps also reduce the ash content of the
coal.
In cases where dry oxidation alone could remove sufficient sulfur
to meet the sulfur dioxide emission standards, this technology may
provide a very simple and inexpensive system. Potential problem areas for
this system are:
• oxygen concentration requirements in the treat gas exceed the
explosion limits for coal dust, and thus the application of
this process may be hazardous.
• Nitrogen uptake by the coal structure will increase N0x emission.
17
-------
AHDO PROCESS
Little information is available on this process. It is presently in
the pre-pilot plant stage of development and is alleged to remove both
pyritic and organic sulfur. Ihe process was wholly funded internally until
recently, when EPRI financed a study on six coals in which there was a wide
distribution of pyrite particle size. Energy yield for the process is
alleged to be 90-95%, and ash content can be reduced by as much as 50%.
SUMMARY OF MINOR AND MISCELLANEOUS PROCESSES
Tables 2 and 3 summarize process information on the minor and
miscellaneous chemical coal cleaning processes.
18
-------
TABLE 2 . PROCESS INFORMATION SIM4ARY Cf MINOR CHEMICAL COftL CLEANING PROCESSES
Process
Colo. Sch. of
Mines Res.
Inst.
Jolevil
U. of Houston
Ohio State U.
NIC
(Canada)
W. 111. U.
Texaco
Method
Selective ferrofluid
wetting of pulverized
coal constituents
followed by magnetic
separation
Unknown
Hydrothermal alka-
line leaching
Microbiological
oxidation
Oil agglomeration
of very fine coal
particles leaving
rejected pyrites
in water slurry
Microbiological
oxidation of
pyrite particles
to increase hydro-
phobic properties
Hydrosulfuriza-
tion in plasma arc
HjOi oxidation during
pipeline transport
Type S
Removed
Pyritic
Unknown
Pyritic &
Hum organic
Pyritic
Pyritic
Pyritic
Both
Pyritic
Stage of
Development
Starting lab work
Allegedly active
& being marketed
Lab scale
Lab scale
Active
Active on lab
scale
Active, at low
level
Inactive
Problems,
Garments
EPRI funded
Unknown
Alleges improve-
ment on Battelle
process.
Internally funded
7+ day process.
Internally funded
May be especial-
ly applicable in
recovery Cf fines
May make oil
agglomeration
mare efficient
Seeking funding
"
EXuiUid.cs
No data
Unknown
No data
No data
52/ton applied
to fines recovery
No data
No data
-------
TREBLE 2 . (continued)
Process
U. of Fla.
Methonics, Inc.
Rare Earth
Industries
MIT
Gulf « Vtestern
New South
wales
Method
Gas oxidation/
reduction at very
high tenperature
Met hydrogenation
Rare earths recycled
as S-getters during
SRC liquefaction
Catalytic desulfuri-
zation of petroleum
fractions
FT»I liquefaction
via graft polymeri-
zation
HtOt oxidation
Type S
Removed
Both
Both
Both
Not Given
Not Given
Not Given
Stage of
Development
Inactive
Inactive
Inactive
Active
Inactive
Discontinued
Problems,
Coranents
Poor yield;
no data since
1975
Company probably
no longer exists
Conpany probably
no longer exists
Not applicable
to coals
Changes coal
matrix. Prior
ERDh funding now
discontinued
Method is analyt-
ical, not meant
to be coal
cleaning
Economics
No data
No data
No data
No data
No data
No data
10
o
-------
TOBI£ 3. PROCESS JNPORMKTICN SUTOAFQf OF MISCEIUNEOUS CHEMICAL COM, CLEANING PROCESSES
Process
U.S. Steel
Chsnioo
ERDA
(Laramie)
Rutgers
Dynatech
Kyoto Univ.
(Japan)
Kellogg
Mfithod
Fused NaOH @ high
temperature
Viet oxidation using
air i high tempera-
ture and pressure
Leaching vising
HjSOi, or HjSOH-Hl2Oj
Microbiological oxi-
dation of organic S
Microbiological
oxidation
dj/Oi wet oxidation
High tenperature and
pressure
leaching in KCH solu-
tion w/FejOa catalyst
Type S
Removed
Both
Doth
Pyritic
Organic
Pyritic
Probably both
Both
Stage of
Development
Inactive
Inactive
Inactive-prev. on
lab basis only
Inactive
Inactive
Unknown
Discontinued
Problems,
Ccnroents
Excess Ma in
product; coal
matrix affected
™«~»-
Inactive since
1975
Recently dis-
continued;
negative results
Inactive
No answer to
our letter of
inquiry
Poor yield;
coal matrix
altered
EUUKJld.CS
No data
No data
No data
No data
~$4/ton (company
data)
No data
No data
-------
SECTION 3
EVALUATION OF CHEMICAL COAL CLEANING PROCESSES
Coal has traditionally been cleaned by sizing and specific gravity
separation to reduce the quantity of ash forming mineral constituents, which
include pyritic sulfur. However, these physical coal cleaning techniques
are only capable of reducing the pyritic sulfur content of the coal, often
with a considerable loss of heating value due to a large quantity of fine
coal in the refuse from the plant.
A variety of chemical coal cleaning processes are under development
which will remove a majority of pyritic sulfur from the coal with accept-
able heating value recovery, i.e. 95 percent BTU recovery. Some of these
processes are also capable of removing organic sulfur from the coal, which
is not possible with the physical coal cleaning processes.
This section presents available technical and economic information
of eleven major chemical coal cleaning processes identified during a nine
month study. A detailed evaluation is included on each process in a format
that identifies:
• Process details;
• Developmental status;
• Technical evaluation, including process potential for sulfur
removal, sulfur by-products, process advantages and disadvantages,
environmental aspects, research and development needs; and
• Process economics.
The first four processes discussed are capable of reducing only the amount
of pyritic sulfur in the feed coal, while the next seven processes are
capable of reducing both pyritic and organic sulfur.
22
-------
TEW MEYERS' CHEMICAL COftL CLEANING PROCESS
Process Description
The Jfeyers1 process, developed at 13W, is a chemical leaching process
using ferric sulfate and sulfuric acid solution to remove pyritic sulfur
from coal. The leaching takes place at temperatures ranging from 50° to
130°C (120°-270°F); pressures from 1 to 10 atmospheres (15-150 psia) with a
residence tine of 1 to 16 hours. Process development and optimization
studies conducted to date have included a number of alternative processing
methods.
Some of the variations which have been tested and considered are:
• Air vs. oxygen, for regeneration
• Coal top sizes from 0.64 cm ft inch) to 100 mesh
• leaching and regeneration in the same vessel and in separate
vessels
• Removal of generated elemental sulfur by vaporization or
solvent extraction.
Current development work is directed toward elemental sulfur recovery by
acetone extraction. This system appears to be promising and may prove to be
economical. However, since the technical and economic feasibility of this
modification has not yet been proven, Versar, with T5W's concurrence, elected
to assess their most promising process for fine maig (top size of 8 mesh or
finer). This system includes the removal of elemental sulfur with superheated
steam. Ohe flow sheet for this preferred system is shown in Figure 1. She
diagram includes the four distinct sections2 of the process which are ctescrib-
ed below.
Reaction Circuits-
Crushed coal, with a nominal top size of 14 nesh, is mixed with hot
recycled iron sulfate leachant. Ohe mixing is performed in a continuous
reactor witfi about 15 minutes residence time, tte wetted coal, having under-
gone about 10 percent pyrite extraction in the mixer, is introduced into the
reaction vessel at about 80 psig and about 102°C (215°F). in this
step, about 83 percent of the pyrite reaction takes place under conditions
23
-------
to
ao do —* do cfc>
FIOUBE 1 TRWIMEVEIVSI PROCESS FLOW SHEET
-------
of 5.4 atm. (80 psi) and 118°C <245°F). with varying residence tine for
different coals. Oxygen from an oxygen plant,v«iich is an integral part of
the coal cleaning plant/is simultaneously added to regenerate the leachate.
The slurry then moves to a secondary reactor where the reaction continues
to about 95% completion.
Wash Circuit—
The iron sulfate leachate is removed from tihe fine coal in a series
of countercurrent washing and separation steps. She slurry from the second-
ary reactor is filtered and washed with water. Both the filtrate and the
wash water are sent to the sulfate removal circuit. The filter cake is
reslurried, filtered a second time and then reslurried with recovered clear
water and finally dewatered in a centrifuge.
Sulfate Removal Circuit—
The prime function of this circuit is to concentrate the leachate for
recycle. The filtrate and the wash water from the first stage filter are
fed to a triple effect evaporator which recovers most of the wash water.
The by-product iron sulfate crystals which are found in the third evaporation
stage are removed from the concentrated leachate and stored or sent to
disposal. The remaining wash water from the first filter is partially
neutralized with lime to precipitate a gypsum by-product. Ihe partially
neutralized wash water is combined with the dilute leachate from the
centrifuge and recycled to the process as leach solution.
The fuel requirement of this circuit is equal to a few percent of the
product coal. Make-up water is needed to replace water of crystallization
and water vaporization losses due to vacuum filters and vacuum evaporator.
Sulfur Removal Circuit—
Wet coal from the centrifuge is flash-dried by high temperature steam
which vaporizes both the water and the sulfur. The dry coal is separated
from the hot vapors in a cyclone and cooled to give the clean product.
The hot vapor from the cyclone is scrubbed with large quantities of recycled
hot water from the evaporator. The gas and liquid phases from the gas
cooler are separated in a cyclone. Ohe liquid stream from the cyclone which
contains water and sulfur is phase separated in a vessel. The gas phase
25
-------
consisting of saturated steam is compressed, reheated and recycled to the
drier.
It is recognized that the processing steps and equipment needed for re-
covering sulfur from fine or suspended coal sizes would be different from
those required for coarser material. The process developer's claim is that
coarse coal can be treated in non-pressurized reaction vessels and would
employ support equipment which is significantly lower in cost than that
necessary for the fine coal system. However, since the coarse coal process-
Ing has not been studied to an extent permitting the assessment of its
technical feasibility, Versar elected to limit this assessment of the Meyers'
process as applied to the fine coal.
Status of the Process
TEW has conducted extensive bench-scale testing of the major treatment
units for the Meyers' process.2 More than 45 different coals have been test-
ed, and over 100 complete material balances on the process have been calcula-
ted and tabulated. The initial bench scale program was directed toward
generating critical process data for the chemical removal of pyritic sulfur.
This program was aimed at optimizing the leaching and regeneration steps,
evaluating analytical techniques and studying other process improvements.
From these data -die chemistry and rate expressions for the various processing
steps have been determined. Additionally, the applicability of the Meyers'
process to a variety of finals has been established during a survey program.
nh this latter study, the process was compared to physical cleaning for
thirty-five different coals.*'* It is the developer's r*]*™ that in all
but two cases the Meyers' process was superior.
In addition to the work under various EPA contracts, TFW has funded in-
dependent evaluations of the process by Battelle Columbus Laboratories and
Stanford Research Institute. EPA also has funded independent studies done
by Exxon, Dow Midland, Dow-Texas and ABC (Oak Ridge). An evaluation of the
process has also been done by the University of Michigan for the Electric
Power Research Institute. As a result of these extensive studies of the
Meyers' process, this chemical coal cleaning process is probably the best
characterized process of all the chemical coal cleaning technologies
currently underway.
26
-------
Developmental efforts for this process began in 1969. The bench-scale
testing effort generated the data necessary for the design of the eight metric
ton/day Fteactor lest Unit (RTU). The erection of this unit at the Capistrano
Test site was completed in early 1977. With EPA's sponsorship, the RTU
started up in June, 1977.
Currently, THtf efforts are directed toward:
• Bench-scale investigations in support of the FTO program on iuproved
techniques for sulfur by-product recovery and on the identification
and evaluation of process modifications with potential for reducing
processing costs; and
• Testing the RTO. The unit has been run with coal slurry and plans
are to introduce the leachate in the circuit in the near future.
The RIU is designed to handle coal less than 0.32 cm (1/8 inch) in size
and variable test parameters of temperature, pressure, residence tiro and
oxygen concentration. Limited ability to filter and wash the coal to remove
the spent leachate is also included. This unit does not have the capability
to remove the elemental sulfur produced by the leaching reaction or to
handle coal particle sizes greater than 0.32 cm (1/8 inch).
The first ten months of operation of the RIU will be dedicated to treat-
ment of two types of coal from the Martinka mine. It has been established
that this coal will not meet the current NSPS S02 emission standards by
physical coal cleaning techniques. The specific samples have been selected
in cooperation with American Electric Power Service Corp. (AEP), which has
elected to participate in this program for cleaning the Martinka mine coal
to an acceptable fuel.
The selected coals will be treated in the RlU for the purposes of re-
moving the pyritic sulfur. The treated coal will be washed and filtered to
remove the iron salts leaving a wet filter cake (17 to 28 percent moisture
by weight) containing some elemental sulfur. The product coal from this
operation will be sent to various equipment suppliers to dry the coal and
recover the elemental sulfur.
Extensive investigations are projected to optimize this process techni-
cally and ecaicndcally. Some of the studies projected are:
27
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• Pelletizing the powdered product coal, by compaction, without binder,
to sizes greater than 0.95 on (3/8 inch) to permit shipping in open
hopper cars.
• Determine the effects of desulfurized coal on combustion and perfor-
mance characteristics of utility boilers.
• Determine the effects of desulfurized coal on performance character-
istics of electrostatic precipitators employed to remove particulates
from the boiler flue gas.
Technical Evaluation of the Process
This process has been extensively studied and is currently on an eight
metric ton/day pilot plant stage. Thus, an assessment of its industrial
potential is possible at this time. Only pyritic sulfur is removed by this
process. As such, the process is more applicable to coals rich in pyritic
sulfur. These coals are found in the Appalachian region of the United States
which now supplies about 60 percent of the current U.S. production. An esti-
mated one third of Appalachian production can be treated to a level permitting
the burning of the product in conformance with the new source sulfur dioxide
emission standards. Some Interior Basin coal can also be treated by this
process to meet the new sulfur dioxide emission guidelines.
A Meyers' treatment plant can be either located at a centralized process-
ing site or at a power plant site. If the treatment plant is located at a
large power plant site, steam and power requirements might be purchased. This
could result in some cost savings. Furthermore, the Meyers' processing plant
can operate steadily with shutdowns only for required or scheduled normal
maintenance. Thus, the plant would only have to be designed to furnish suffi-
cient coal for the power plant's average load factor, which is, in general,
60 percent of the full name plate capacity. Additionally, capital and operat-
ing costs for such a plant would be even more favorable if the process were
integrated with coal-fired power generating far-ill ties which would already
have included adequate raw coal handling, crushing, pulverizing and fine coal
handling facilities. In some instances, when the treatment plant is added to
a plant with a very large coal demand, it is possible that the entire operate
ing cost of the system can be absorbed by the power plant due to improved
product yield.
28
-------
Another option for the Meyers' processing plant, which is potentially
attractive, is a conbination physical and chemical cleaning operation. In
this case, the run-of-ntine coarse coal containing high ash and high pyritic
sulfur would be fed to a physical cleaning plant to reduce the ash content of
the coal by about 75 percent. The ash discard consisting of about 15 percent
of the PCM coal will contain primarily ash and 10 to 15 percent pyritic sul-
fur. Ohe low ash coal can then be fed to a gravity separation system. The
heavy fraction from the float/sink system, consisting of 40 to 50 percent of
the total coal, will be used as feed to the Meyers' process. This latter
fraction, containing high concentration of pyritic sulfur, will be reduced
to 14 mesh top size and fed to a fine coal Meyers' circuit to yield a pro-
duct with a very low sulfur content. Ihe desulfurized sample may then be
recombined with the float fraction giving an overall yield of about 80 per-
cent on the run-of-nine coal feed. Thus, the combined treated product con-
taining 10-20 percent of the total sulfur of the RDM coal will meet the NSPS
standards of sulfur dioxide emission while only processing a fraction of the
total coal through the Meyers' process.
Potential for Sulfur Removal—
Only pyritic sulfur is removed by this process. A survey program
(EPA Contract No. 68-02-0627) has established that this process is able to
remove 80-99 percent of the pyritic sulfur (23 to 75 percent of the total
sulfur from 23 Appalachian Basin Coals and 91-99 percent of pyritic sulfur
(43 to 55 percent of total sulfur) from the six Eastern Interior Basin
Coals. Tests with Vfestern coals showed 92 percent removal of the pyritic
sulfur (65 percent of total sulfur) from a single Vfestern Interior Basin
Coal, and 83-90 percent removal of the pyritic sulfur (25-30 percent of
total sulfur) from the two Vfestern coals. Iwo other Western coals (from
Edna and Belle Ayr mines) were also investigated, however, since these coals
contain very low pyritic sulfur (0.14 - 0.22 wt%), the results of these
tests are inconclusive. Under the same program, tests conducted on float-
sink have indicated that conventional coal cleaning at 1.9 specific
gravity could reduce only tare of the coals tested to a sulfur content as
low as that obtained by the Meyers' process.
29
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3 **
The results of these investigations are presented in Table 4. ' Most coals,
ground to 100 mesh x 0, were found to give the maximum pyrite removal (90-99
percent) . Ifcwever, several of the coals required 150 and some 200 mesh
size reduction to achieve ultimate amounts of pyrite removal. The size re-
duction also resulted in an increase in the rate of pyrite removal so that, in
most cases, the reaction time was reduced considerably.
These studies also provided data which allowed formulation of expressions
for pyritic sulfur removal. The kinetic equation developed for lower Kittan-
ning coal is given in Appendix I. Using this equation, the removal of pyritic
sulfur was measured as a function of time at 102 °c (215 °F) for 18 Appalachian
and 3 Eastern Interior region coals. The results presented in Table 1-1,
Appendix I, indicate that significant pyrite removal rate differences do exist
between various coals.
Sulfur By-Products —
The by-products of the Meyers' process are elemental sulfur/ a mixture
of ferrous and ferric sulfate and calcium sulf ate (gypsum) fron the waste-
water treatment. Hie by-product chemistry of the process is represented by
the treating step, Equation 1, and the solution, regeneration step, Equation
2.2
5 FeS2 + 23 Ee2 (SO^-f 24 H2O -> 51 IeSO,+ 24 H2SO,+ 4 S (1)
O2 + 4 !eSC\ + 2 H2SO^ •* 2 Pe2 (SO,) 3 + 2 H2O (2)
Once the coal enters the Meyers' reaction vessels, it is not exposed to
the atmosphere again until all reactions and washings are completed and the
coal is cooled to a point permitting no further emissions of volatile matter.
One possible sulfur dioxide (S02) emissions source is the scrubber vent gas.
Most of the sulfuric acid (HjSOJ is recycled, although some is lost at
the filter wash and will be limed and disposed of with solid waste.
Benefit Analysis —
The major benefit associated with the Meyers' process is the removal
of pyritic sulfur from pyrite rich coals (primarily Appalachian coals) to
a sulfur level consistent with the current standards for sulfur emissions
from power plants and industrial sources. TRW investigations indicate
30
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TABLED fEYERS' PROCESS - SUTWRY OF PYRITIC SULFUR REMOVAL RESULTS (100-200 HICRGN [OP-SIZE COAL)
MINE
APRRLflCHIAN COALS
KOPPERSTONE NO. 2
HARRIS NOS. 182
WARWICK
MARION
MATHIES
ISABELLA
LUCAS
JANE
MARTINKA
NORTH RIVER
HlffHREY NO. 7
NO. 1
BIRD NO. 3
WILLIAMS
SHOEMAKER
MEIGS
FOX
DEAN
POHHATTAN NO. 4
ROBINSON RUN
DELMONT
MUSKINGH4M
EGYPT VALLEY #21
EASTERN INTERIOR
rms
ORIENT NO. 6
EAGLE NO. 2
STAR
HOMESTEAD
CAMP NOS. 1&2
KEN
KSTHW COALS
NAVAJO
COLSTRIP
HUilJiL INTERIOR
MS
HELTON NO. 11
SEAM
CAWBELL CREEK
EAGLE & NO. 2 GAS
SEWICKLEY
UPPER FREEPORT
PITTSBURGH
PITTSBURGH
MIDDLE KITTANNING
LOWER FREEPORT
LOWER KITTANNING
CORONA
PITTSBURGH
MASON
LOWER KITTANNING
PITTSBURGH
PITTSBURGH
CLARION 4A
LOWER KITTANNING
DEAN
PITTSBURGH NO. 8
PITTSBURGH
UPPER FREEPORT
MEI6S CREEK
PITTSBURGH NO. 8
HERRIN NO. 6
ILLINOIS NO. 5
NO. 9
NO. 11
NO. 9 (H.KY.)
NO. 9
NOS. 6,7,8
ROSEBUD
DES HDINES NO. 1
STATE
H. VIRGINIA
W. VIRGINIA
PENNSYLVANIA
PENNSYLVANIA
PENNSYLVANIA
PENNSYLVANIA
PENNSYLVANIA
PENNSYLVANIA
N. VIRGINIA
ALABAMA
H. VIRGINIA
E. KENTUCKY
PENNSYLVANIA
W. VIRGINIA
W. VIRGINIA
OHIO
PENNSYLVANIA
TENNESSEE
OHIO
H. VIRGINIA
PENNSYLVANIA
OHIO
OHIO
ILLINOIS
ILLINOIS
W. KENTUCKY
W. KENTUCKY
H. KENTUCKY
W. KENTUCKY
N. MEXICO
MONTANA
IOWA
1 TOTAL SULFUR W/H IN COAL"
INITIAL
0.9
1.0
1.4
1.1
1.5
1.6
1.8
1.8
2.0
2.1
2.6
3.1
3.1
3.5
3.5
3.7
3.8
1.1
4.1
4.4
4.9
6.1
6.6
1.7
4.3
4.3
4.5
4.5
4.8
0.8
1.0
6.4
AFTER MEYER'S PROCESS
CURRENT RESULTS
0.6
0.8
0.6
0.7
0.9
0.7
0.6
0.7
0.6
0.9
1.5
1.6
0.8
1.4
1.7
1.9
1.6
2.1
1.9
2.2
0.8
3.2
2.7
0.9
2.0
2.5
1.7
2.0
2.8
0.6
0.6
2.2
MEYER S
PROCESS PYR1TE
CONVERSION I W/W
92
94
92
96
95t
96
94t
91
92
91
91
90
96t
96t
80
93
89
94t
85
97t
96*
94t
89
96*
94
91t
93
89
91
90
83
02
MEYER S PROCESS
TOTAL SULFUR
DECREASE I WA<
33
23
54
50
56
54
64
63
70
55
42
48
75
50
51
48
57
49
53
50
80
47
59
44
54
43
47
55
42
25
30
65
I SULFUR
IN COAL *
AFTER FLOAT-SINK
0.8
0.9
1.0
1.2
1.7
1.5
0.7
0.8
0.8
2.2
1.9
2.3
1.5
2.3
3.6
2.8
2.0
3.0
3.3
3.0
2.1
4.4
4.6
1.4
2.9
3.0
3.2
2.9
3.5
—
—
3.9
• DRY, MOISTURE-FREE BASIS
A 1.90 FLOAT MATERIAL, 14 MESH X 0, IS DEFINED HERE AS THE LIMIT OF CONVENTIONAL COAL CLEANING
+ RUN AT 190 X 0
-------
that samples from coal mines in Montana through Iowa, Illinois, Ohio,
Pennsylvania, Vfest Virginia and Kentucky, representing a wide range of U.S.
production, have been desulfurized to meet these standards. Physical cleaning
of these ooals has, in general, been unable to accomplish similar results with-
out significant coal reject losses. Based on studies conducted by University
of Michigan and Exxon, the net heat energy recovery for the Meyers' process is
87 to 92 percent.
It has been concluded that with Appalachian ooals, little or no reaction
of the reagents with the coal matrix occurs. Thus, it is expected that the
Mayers' processing of the coals will not change the fluidity of the slag which
could cause fouling of heat-receiving surfaces. Additionally, the caking prop-
erties of coal will be inproved by removal of a portion of the coal ash by the
leachate.
It is also expected that the combustion properties of the coal will
remain unchanged. However, it is anticipated that the Meyers' processing may
affect fly-ash resistivity, by reducing the efficiency of electrostatic
precipitators (ESP) used for dust control purposes. The addition of condition-
ers, in small quantities, may be required in order to improve this efficiency.
However, it is claimed that there is still a reasonable chance that the ESP's
may operate in a normal fashion due to the presence of small quantities of
iron sulfate in the coal which may decompose to produce sulfur trioxide
necessary for conditioning. Studies on the combustion characteristics of the
treated coal and related effects on ESP's are in the planning stage.
A study has been conducted with respect to the trace elements extracted
and the degree of extraction achieved by this process. Fifty coal samples
have been analyzed in duplicate or triplicate for 18 trace elements which are
of interest to the Environmental Protection Agency. The samples included 20
"as received", 20 Meyers' process, and 10 float sink treated coal samples. The
conclusions drawn from the study follow:4
• As, Cd, Mn, Ni, Pb, and Zn are removed to a significantly
greater extent by the Meyers' process.
32
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• F and Li are partitioned to the refuse a greater amount by
physical separation procedures,
• Ag and Cu are renewed with a slight preference for float-sink
separation, and
• Cr and V are removed by both processes with equal success.
The data on six elements, B, Be, Hg, Sb, Se, and Sn yielded negative or incon-
clusive results. Figure 2 depicts the trace element removal data?
No analysis has been conducted to determine the nitrogen content of the
treated product. However, it is anticipated that the nitrogen content of the
feed coal will be either unaffected by this process or slightly increased due
to nitrogen used for coal blanketing.
The Meyers' process is a more efficient pyritic sulfur removal method
than high gravity physical cleaning. However, it is obviously more compli-
cated and therefore more expensive. Although the process is chemically
efficient, it has drawbacks: (1) the long residence time, (2) the difficulty
of washing the iron sulfate out of the coal, (3) the need for an extraction
to remove elemental sulfur, (4) the process is limited in application due to
removal of the pyritic sulfur only, and (5) the generation of 2.65 weight
percent iron sulfate waste for each one percent by weight pyritic sulfur
removed which needs to be treated prior to disposal. The elemental sulfur
and gypsum by-products from the Meyers' process are in a relatively compact
form and are manageable (0.40 and 0.54 weight percent, respectively, on
coal feed, per one percent pyritic sulfur removed).
Environmental Aspects—
Ihe major environmental problem associated with this process is the
disposal of a large quantity of iron sulfate by-product which is acidic
and highly corrosive. Treatment of this waste and the recovery of sulfuric
acid may be required to provide an environmentally sound solid waste material
for disposal. Additionally, the ferric sulfate dissolves a small amount of
coal ash. Since the ash is rejected from the process with the iron sulfate,
this solid waste will contain sore traces of heavy metal salts. The quantity
of trace metals rejected will depend upon the coal, as will the nature of
sludges and the ratio of coal to waste.
33
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40 60 80
% REMOVAL
100
100
80
i/»
!£ 60
2
# 40
20
i i i i i i
20 40 60 80 100
% REMOVAL
100
30
60
40
20
0
Ag
0 20 40 60 80 100
% REMOVAL
20 40 60 80 100
% REMOVAL
20 40 60 80 100
% REMOVAL
Ni
20 40 60 80 100
% REMOVAL
FIGURE 2 MEYERS' PROCESS VS. PHYSICAL COAL CLEANING: TRACE ELEMENT
REMOVAL DATA
34
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The iron sulfate waste is dewatered prior to disposal. However, it should
be rendered essentially insoluble to yield an environmentally safe material.
Several techniques have been suggested to accomplish this:
• Conversion of ferrous sulfate to basic iron sulfate ;
• Itoasting to iron ores and producing a concentrated stream
of S02 ; and
• Direct treatment with lime to produce calcium sulfate and
iron oxides which are both relatively insoluble.
The elemental liquid sulfur which is removed during the coal drying
stage may be cast into blocks and stockpiled or sold where a market exists.
The gypsum by-products can be dewatered and disposed of by standard
acceptable practices.
The only water that leaves a Meyers' process plant is low pressure steam
that is vented to the atmosphere and is environmentally acceptable.
Cne possible sulfur dioxide emission source from this process is from
the vent gas scrubber which is incorporated in this system for the removal
of traces of acid mist. This emission is expected to be primarily oxygen
containing about ten percent S02 and organics.
Problem Areas—
The disposal of by-product generated by the Meyers' process is the main
problem area for this process. Handling of this material has to be determined
for each commercial plant since their quantity depends upon the coal feed.
The quality and potential saleability of by-products are unknowns.
Ohe sulfur recovery system, by superheated steam, is yet unproven.
Water and sulfur vapor discharge from the gas/solid cyclone separator with-
out some coal fines is unlikely. Any coal fine carry over from this
operation will hinder the subsequent water/sulfur phase separation
operations. Furthermore, the by-products, not water and sulfur, win be
contaminated with coal.
R&D Efforts and Needs—
Specific research efforts and needs for the Meyers' process are summariz-
ed below:
35
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• A new and premising Meyers' system ccrrbines the coal drying
and sulfur recovery operations. Additional experimental work,
both in bench and pilot scale is required to properly optimize
and demonstrate this recovery circuit.
• Bench-scale testing should continue in support of the KTU for
identification of process improvements necessary for overall
process optimization. It is recommended that this investigations
be primarily aimed to improve the techniques of elemental sulfur
removal. Additionally, since it is recognized that a large
percentage of the total equipment cost is due to the reactor/
regeneration circuit, any process improvement in this section will
affect the process cost favorably.
• Studies should be conducted to define the combustion behavior of
the treated coal and to evaluate the pollutant emissions from the
burning of the product coal.
• Ohe effect of the treated product on the operational efficiency
of electrostatic precipitators must be evaluated.
• The characteristics, resource recovery and treatment alternatives
of the iron sulfate waste material must be investigated to provide
a more manageable material for disposal.
• The feasibility of coarse coal processing in unpressurized
systems should be further investigated to permit a better
assessment of sulfur removal potential and leaching residence
time of the coarse coal system.
Process Economics
A variety of organizations have made cost evaluations of the various
Meyers1 process options.5'6'7 ^ 8 ihe range of operating costs on an
annual basis estimated by various organisations is $13 to $19 per metric
ton of clean coal. In most cases, these costs were developed based on
lowering the sulfur level of a given coal to a level meeting the current
NSPS sulfur dioxide emission standard of 2.16 kg. per million kg cal
36
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(1.2 pounds per million BfTU). In one case (the Bechtel study8) costs were
based on an arbitrary 90 percent removal of pyritic sulfur. In 1975,
the economics of various process options were analyzed in detail by TFW
for EPA under Contract No. 68-02-1336.2
The economic estimates presented herein are based on a plant which
processes 300 metric tcns/hr (7,200 metric tons/day) [330 tons/hr (8,000
tons/day)] coal. The coal, which is assumed to have 3.2 percent pyritic
sulfur and 2 percent moisture, is processed to remove 95 percent of the
pyritic sulfur. This information is based on the most recent (1975) TRW
flow schema and economic evaluation for the fine coal processing system;
however, it assumes a grass roots plant which includes off-site facilities
such as grinding and handling, product compacting, office buildings, rail
facilities, etc.
The detailed flow sheet for the battery limit plant is given in
Appendix I. one corresponding mass balance and stream properties are also
given in Appendix I. The mass balance shown in Appendix I represents only
one of the three trains required for processing 300 metric tons/far (330
tons/tar) coal. TEW has determined that a 100 metric tons/hr (110 tons/tor)
operation is about the maximum size for a single train based on available
commercial equipment. It has been assumed that the plant will operate 24
hours per day and 8,000 hours per year.
A summary pertinent to the coal balance, based on EOT generated mass
balance, is given in Table 5. The cither raw materials, utilities and
waste streams have been expressed as a function of the product coal, less
moisture, in Table 6. The ash loss is taken as the initial pyritic content
less the pyrite and iron and sulfur containing residual salts left from the
reacted pyrite, without correcting for the oxygen component of the sulfates.
The major equipment for each battery limit process train is given in
Appendix I. A sunroary of economics for the TBW process is given in Table 7.
Details on the installed capital costs for this process are given in Table 8.
Details on the corresponding estimated armualized operating costs are
presented in Table 9. No credits have been given to any by-prcduct (elemental
sulfur and gypsum). The unit operating costs shown are based on a coal yield
37
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TABLE 5. MEYERS' PROCESS COM, BALANCE
Coal feed
Coal (MPF)
Pyrite (PeS2)
Sub-total
Fuel*
Coal (MPF)
Iiroci ^n
Sub-total
Product
Coal (MPF)
3xid
Sub-total
Ash loss, by difference
Iron and sulfur compounds
Product
Coal, dry basis
Moisture
Crve Process Train- Three Process Trains
Metric tons (tons)per hr. Metric ims f-t-nnair»»r
85.26 (94.00)
5.44 (6.00)*
90.70 (100.00)
3.63 (4.00)
.01 (0.01)
3.64 (4.01)
81.63 (90.0)
0.26 (0.29)
81.89 (90.29)
5.17
(5.70)
Ttotal
81.99 (90.29)
1.22 (1.35)
3.28 (3.61)"
86.39 (95.25)
2,046,192 (2,256,000)
130,608 (144,000)
2,176,800 (2,400,000)
87,072
218
87,290
(96,000)
(240)
(96,240)
1,965,120 (2,160,000)
6,313 (6,960)
1,965,433 (2,166,960)
124,077 (136,800)
1,965,433 (2,166,960)
29,387 (32,400)
78,582 (86,640)
2,073,402 (2,286,000)
* equivalent to 3.2 weight percent pyritic sulfur
A Product ooal used as fuel
t Net product without binder
<* Assumes 4 percent equilibrium moisture
38
-------
DVELE 6. tfeyers* Process Par Materials, Utilities arri VfastK Stream Balance
Hourly units
Product coal, dry basis
Coal received, dry basis
Ash loss
Oxygen, 99.5%
Binder
Fuel coal, dry basis
Power
Water*
Iron sulfate wastes
Sulfur by-product
Gypsum
Lime, dry basis
units per process train Unit Ratio
metric tons (Tons) 81.9 (90.3)
metric tons (Tons) 90.7 (100.0)
metric tons (Tons) 5.2 (5.7)
metric tons (Tons) 3.5 (3.9)
metric tons (Tons) 1.3 (1.4)
metric tons (Tons) 3.6 (4.0)
hw 8,400
liters 2,180,000
metric tons (Tons) 7.3 (8.1)A
metric tons (Tons) 1.2 (1.3)f
metric tons (Tons) 1.45 (1.6)
metric tons (Tons) 0.45 (0.5)
1.0
1.107
0.063
0.043
0.015
0.044
93.0
26,620
0.090
0.014
0.018
0.006
* Includes 36,000 I/tain cooling water and 420 1/min process water
A Includes 0.9 metric tons/hr water
t Includes 0.1 metric tons/hr coal
39
-------
of 90 percent and a heating value yield of 94 percent, as estimated by TEW.
The single largest cost item is the purchased coal used as feed to the
chemical processing plant. It is TPW's claims that based on the current
conceptual process designs/ a broad spectrum of Eastern coals can be
upgraded to meet the current NSPS S02 emission standards at about the same
costs.
40
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TABLE 7. SUM4AEY OF BOONCMICS FOR THE MEYERS' CHEMICAL
COAL CLEANING PEOCESS
Basis: 7,200 itetric tons (8,000 tons) per day of 6,800 kg cal/kg
(12,300 BTU/lb) ooal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
90% weight yield, 94% heating value recovery
Installed Capital Cost: $109,100,000
Annual Operating Costs
on Clean Coal Basis;
$37,243,000 process cost, excising coal cost
$103,243,000 process cost, including ooal cost*
$17.28/hetric ton ($15.67/ton), excluding ooal cost
$47.90/faetric ton ($43.45/ton), including coal cost*
$2.42/106 kg cal ($0.61/106 BTO), excluding coal cost
$6.71/L06 kg cal ($1.69A06 BTO), including coal cost*
* Coal costed at $27.60/toetric ton ($25/ton)
41
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TABLE 8. INSTALLED CAPITAL COST ESTIMATE FOR THE MEYERS'
CHEMICAL COAL CLEANING PROCESS
$1977 (1st Quarter)
Coal handling and preparation 8,830,000
Desulfurization process costs *
Reaction section 20,800,000
Wash section 7,460,000
Sulfur removal section 9,600,000
Sulfate removal section 5,550,000
Compacting and product handling 5,120,000
Building and miscellaneous 700,000
Utilities (off-sites) f 28,330,000
Site development and general 4,530,000
Subtotal 90,920,000
Engineering design @ 10% 9,090,000
Contingency @ 10% 9,090,000
Total Installed Plant Capital (TPC) 109,100,000
* Based on TIW's most recent estimate (1975)
Includes control rooms, plant laboratory, administration building,
maintenance shop and stockrooms and stores.
Off-sites include the following facilities:
steam generation
water supply
process water and potable water
fire protection
cooling water
oxygen-nitrogen plant
instrumentation
Includes railroad facilities for incoming and outgoing cars and loading
and unloading facilities for raw materials and loading facilities for
by-products waste sulfates.
42
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TABLE 9. ESTIMATED ANNUAL OPERATING COSTS FOR THE
MEYERS' CHEMICAL COAL CLEANING PROCESS
Amortization 20 years @ 10% interest (factor = 0.1175) $12,820,000
Taxes @ 2% TPC 2,180,000
Insurance @ 1 % TPC 1,090,000
Labor (direct, indirect, additives, support) 2,322,000
General and administrative § 1.5% TPC 1,640,000
Maintenance and supplies e 5% TPC 5,460,000
Utilities:
Electric power 5,040,000
Water 724,000
Steam & Fuel*
Chemicals:
Binder 4,272,000
Line 420,000
Waste Disposal 1,275,000
Total Annual Processing Cost 37,243,000
Raw coal, 2.39 x 106 metric tons (2.64 x 106 tons) 66,000,000
TOKAL ANNUAL COST $103,243,000
* Heating requirement of the process has been estimated at 3 x 10s
kg caVhr (291 x 106 HTU hr); it is assumed that 11 metric tons/hr
(12 tons/hr) of clean coal will be adequate to provide in process
heating needs.
43
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LEDGEM3NT CHEMICAL COAL CLEANING PROCESS
Process Description
The Ledgexncnt oxygen leaching process is based upon the aqueous
oxidation of pyritic sulfur in coal at elevated temperatures and pressures
using a stream of oxygen as the oxidant. The process has been developed
by the Ledgemont Laboratory of the Kennecott Copper Corporation. The pro-
cess was patented in 1976. 10
There has been no R&D effort by Ledgemcnt on the process since 1975.
Based on a series of tests run prior to 1975, the Ledgemcnt process claims
to remove 90% of the pyritic sulfur from a wide variety of bituminous coals
with essentially zero organic sulfur removal. The product is suitable for
oonbustion in standard utility boilers, but will meet EPA NSPS for sulfur
dioxide emissions only if the organic sulfur level in the coal is 0.7-0.8%
or less.
The Ledgemcnt process as crpriPpHTai "* *^ r consists of five principal
steps:
Coal Preparation —
The raw coal is crushed and ground to a suitable particle size for
maximum leaching efficiency. The ground coal goes directly to a slurry
tank for mixing with water. Alternatively, the RCM coal may be subjected
to physical coal cleaning to remove pyrite and ash, before introduction into
the process.
Oxidation Treatment —
The coal slurry is then fed to leaching reactors where essentially
all of the pyritic sulfur is oxidized to soluble sulfates and insoluble
iron oxide under suitable conditions of temperature, pressures, slurry
density, oxygen dispersion, mixing and residence time. The proposed initial
reaction is as follows:
2lteS2 + 7Oz + 2H2O •»• 2PeSQn + 2H2SOif (1)
Wien the process operates at the preferred temperature and pressure [between
50° and 150°C (120° and 300°F), 20 to 25 atm (300 to 350 psig) oxygen
pressure] , it is claimed that 75 percent of the iron sulfate formed in
44
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reaction (1) converts to iron oxide, as in equation (2), below:
4PteSO^ + 02 + 4HzO -»• 2Fe203 + 4H2SO,» &
Accordingly, the overall desulfurization reaction would be:
16FeS2 + 59O2 + 28H20 •»• 4FeSOi, + 6Fe203 + 28H2SOi, (3)
Sate organic sulfur nay also be removed by the following reaction:
2Ri-S-R2 + 3O2 + 2H20 ->• 2Rj + 2R2 + 2H2SO% (4)
The Lodgement laboratory has found that organic sulfur removed in the
aqueous oxidation process is highly variable, and depending on the feed coal
used, has ranged fron 0-20% removal. The inert iron oxide formed in
reaction (2) would be removed with the product coal.
Fuel Separation—
Ohe desulfurized coal slurry is partially dewatered and filtered. The
filter cake is then water washed.
Drying and Agglomeration—
The washed coal is sent to a suitable drier where water is evaporated
leaving a clean, dry solid fuel. This material is then compacted to a
suitable pellet size for shipment to a power plant.
Wastewater Treatment—
The acid water overflow from the thickening, filtration and washing
steps are sent to a wastewater treatment facility where line is added,
neutralizing the dilute sulfuric acid stream and precipitating any
solubilized ash, according to the following reaction:
Peso* + 7H2SOH + 8Ca(OB)2 -»• Fe(OH)2 + SCaBO* + 14H2O (5)
The mixture of iron hydroxide and gypsum is thickened and filtered with the
water overflow being recycled to the leaching process. The gypsum sludge
is disposed of in a landfill. Analyses of representative mala which have
been treated by the Ledgemont process are given in Appendix II.
Table 10 presents lodgement's current best estimates of key parameters
which would be involved in the process design of a continuous system,l s
45
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TRBLE 10. Topical Values of Key Parameters in the Conceptual ! 2
Ledgeocnt Oxygen Leaching Process for Bituminous Coal
Operating Factor: 333 days per year
Overall Yield (avg. ooal): 97-98%
Net yield after fuel uses: =90%
Net heating value yield (avg. coal): 93-95%
Pyritlc sulfur renewal: 90%
Organic Sulfur Renewal: 0-20%
Chemical Process
Coal preparation
Coal desulfurization
Treated coal/water separa-
tion system
Mesh size
Coal/water in feed
Reaction tine
Tencerature
Oxygen pressure
Oxygen consvnption
per metric ton coal
feed
Thickening;
Thickening area
required
Underflow «r»i ifl
comjtail-t.df"if7i
Filtration:
Filtration rate
Percent solids in
fuel cake dis-
charge
Hash water/dry
solids
Typical Value
80% -100 mesh
0.2/1
2 hours
130" C (266C F)
20 atm. (300 psig)
0.138 metric ton
(0.125 ton)*
Wastewater treatment
(11 sq ft/TTO)
43% solids
23 kg/hr/.09 m*
(50 Ib/hr/sq ft)
66%
.46/1
0.25 T/T coal feed*
The oxygoi danand includes the following:
metric ten Ot/cafrt~r"ic toon coal
Ox for pyrita reaction
Oi for Fe*** Fel+
Ox uptake by coal
Ox to tarn COt
Ox to form COx
Ox lost to flashing
0.035t
0.0019
0.054
0.031
0.0014
0.0019
Total 0.1252
t Based on 2% pyritic sulfur in the coal. The anount of Ox used in organic
aii fi^y oxidation is unknown.
$ 1*1*3 is "[vn ** t^+^ly 8 tines the stoichionetric requirement for neutralization.
46
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process energy efficiency is estimated to be 83-85%. The bulk of
the process energy use would be in treated ooal drying and in oxygen plant
operation. Oxidation of the ooal results in conversion of carbon to carbon
dioxide and carbon monoxide as well as trace amounts of higher hydrocarbons.
Approximately 5-7% of the heating value of the coal is estimated to be lost
at the process operating conditions.
Based on the published ledgetnont process information and recent con-
tacts with the Ledgemont Laboratory, a schematic flow diagram for a
7,200 metric tons (8,000 tons) per day coal processing plant is
shown in Figure 3. The process removes little or no organic sulfur and
90% of the pyritic sulfur (starting with 2% pyritic sulfur in the raw coal
feed).
Status of the Process
The Ledgemont Laboratory of the Kennecott Copper Corporation began work
on a process for ooal desulfurization in 1970. The R&D effort was carried
out in partnership with the Peabody Coal Company - then a wholly owned
Kennecott subsidiary. The joint effort culminated in the Ledgemont flow-
sheet, the basic features of which have been demonstrated at the bench and
semi-pilot scale levels. It is claimed that each step of the process has a
complete experimental study to determine the operating range of process
variables. Complete reports setting forth the experimental work, process
specifications and process economics have been prepared. Ohe entire develop-
mental effort has been internally funded throughout - to the extent of
approximately two million dollars.
In 1975, the FTC ordered the divestiture of Peabcdy Coal by Kennecott,
and this resulted in halting further development work on the Ledgemont
process. Plans for install ing a 1/2 metric ton per day pilot scale de-
sulfurization operation were scrapped and no further R&D work is planned.
Kennecott is currently exploring the possibilities of licensing the Ledge-
roont process.
47
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OFFGAS
ROM COAL <
00
DESUIFURIZED
COAL
GYPSUM t
^_ IRON HYDROXIDE
TO WASTE
DISPOSAL
NEUTRALIZER
FIGURE 3 LEDOEMONT OXYGEN LEACHING PROCESS FLOW SHEET
-------
Technical Evaluation of the Process
The Lodgement Laboratory has made available an in-house report containing
all of the information made public to date on the process. In addition, the
Bechtel Corporation has made a technical and economic study of the Ledgemcnt
process.8 A study of this information plus direct contacts with Ledgemcnt
personnel has permitted the following assessment of the process to be made.12
Potential for Sulfur Removal—
The Ledgemcnt process has been shown to remove more than 90% of the
pyritic sulfur in ™->aig Of widely differing ranks including lignite, high
volatile B bituminous, and semi-anthracite, in bench-scale autoclave equip-
ment. Iteaction conditions have been standardized at 130° - 132°C (265°-270°F),
20 atm (300 psig) oxygen pressure and two hours residence time. Several
bituminous coals including Illinois 16, Chio #6, and Kentucky, have been
treated in "semi-pilot scale" equipment with consistent removal of 90%
of the pyritic sulfur. The data on these coals is tabulated in Appendix II.
Little, if any, organic sulfur is removed by the process (from 0-20%,
depending on coal treated) and there is no credit taken in the conceptual
process for this type of sulfur removal.
Sulfur By-Products—
The Ledgemcnt process produces a gypsum by-product which is unsaleable
since it is contaminated with ferric hydroxide.
Benefit Analysis—
The main benefit associated with the process is the demonstrated removal
of 90% or better of the pyritic sulfur from a wide variety of coals. Other
advantages of this process when compared to processes with a similar leaching
mechanism, i.e., ferric sulfate leaching as in the TFW Process, include:
• No elemental sulfur is formed. This eliminates the difficult and
expensive sulfur extraction step required after ferric sulfate
leaching;
• No regeneration of the leach solution is required;
• Considerably less washing is required because of the lower levels of
sulfate ions in the Ledgemcnt leach solution as compared with TOW
49
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ferric sulfate leach solutions. TMs has the further effect of
reducing the volume of the neutralization tanks; and
• The reaction time in aqueous oxygen leaching is less than one
quarter of that required for ferric sulfate leaching. For example,
only two hours is required to remove greater than 90% of the pyritic
sulfur from Illinois 16 coal, whereas 8-10 hours are required for the
average coal in the TEW ferric sulfate process.
The above advantages all have a significant effect on process economics.
Environmental Aspects—
The Ledgemont process has one potentially serious environmental problem -
disposal of approximately 0.3 metric ton of l±nre-gypsum-ferric hydroxide
sludge per metric ton of coal fed to the process. Ihis sludge is bulky
and requires substantial land storage space, and, although it has not yet
been determined, the sludge may contain trace elements such as heavy metals
which could pose a threat of uncontrolled leaching into ground water.
Problem Areas—
The principal problem areas in this process appear to be associated with
the presence of high temperature, 120°C (250°F) dilute sulfuric acid at
elevated pressures, 25 atm (350 psia). At these temperatures, the dilute
acid (a few percent) is highly corrosive. The presence of this material
poses problems in material selection and in choosing means for pressure
letdown.
A significant effort will be required to find a suitable material for
lining those pieces of equipment which will be exposed to corrosive add.
Ihis would include all equipment involved in the coal desulfurization step
from feed-effluent heat exchangers through flash gas scrubber, pumps,
heaters, reactors, pressure letdown devices, and treated coal slurry flush
tanks.
A possible cladding material suggested for lining the Ledgemont
reactors is a 60-40 tantalum-niobium alloy, which costs $154 per kilogram
($70 per pound) and is as costly as silver. Any further optimization study
by Ledgemont should include consideration of the lining materials problem.
50
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The second major engineering problem associated with the corrosivity
of sulfuric acid is a means to accomplish pressure letdown. Normal valving
will probably not withstand the erosion; ceramic equipment may be required.
A possible problem may occur if coal loss through oxidation in produc-
tion-scale equipment at the elevated temperature and pressures involved is
greater than anticipated.
R&D Needs—
In terms of an aqueous coal oxidation process under active development,
the Lodgement process has been superseded in part by the EFDA oxydesulfuriza-
tion process. The ERDA process is based on a similar oxidative leaching
mechanism but claims to effect substantial organic sulfur removal in addition
to 90-100% pyritic sulfur removal. The Ledgemont process may effect
significant organic sulfur removal at pressures higher than those studied
to date.
Process Economics
The ledgemont laboratory11 has provided Capital and operating costs
based on a 7,200 metric tons (8,000 tons) per day coal processing plant,
values of key parameters as shown in Table 10 and the process conceptual
flow sheet (Figure 3).
A summary of economics of the ledgemont process is given in Table 11.
Details on capital and annual operating costs are presented in Tables 12
and 13, respectively. These costs are presented as received, except that
Versar has added a 20% contingency factor to the depreciable portion of
the capital investment. Operating cost components are shown both as
dollars per metric tons (dollars per ton) of product coal and as dollars
per million Kg cal (dollars/106 ECU) heating value. It should be noted
that no by-product credit is taken for the 3,600 netric ton (4,000 ton)
per day of nitrogen which would be co-generated in the oxygen preparation
plant.
51
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TABLE 11. SUMMARY CP ECONOMICS FOR THE LEDGEMQNT
CHEMICAL COAL CLEANING PROCESS
Basis: 7,200 metric tens (8,000 tens) per day of 6,800 kg calAg
(12,300 BTU/lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
90% weight yield, 94% heating value recovery
Installed Capital Cost: $114,020,000
Annual Operating Costs
on Clean Coal Basis:
$45,300,000 process cost, excluding coal cost
$111,300,000 process cost, including coal cost*
$21.02/foetric ton ($19.07/ton), excluding coal cost
$51.64/faetric ton ($46.85/ton) f including coal cost*
$2.94AOG kg cal ($0.74/106 BTU), excluding coal cost
$7.23/106 kg cal ($1.82/106 BTU), including coal cost*
* Coal costed at $27.60/taetric ton ($25/ton)
52
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TABLE 12. INSTALLED CAPITAL COST ESTIMATE FOR THE
LEDGEMDNT CHEMICAL COAL CLEANING PROCESS2 8
$ 1977
Coal handling and preparation* $14,400,000
Desulfurizaticn process costs
Iteaction equipnent 19,700,000
Liquid/solid separation 11,100,000
Neutralization 8,100,000
Drying 4,600,000
Compacting and product handling^ 5,120,000
Building and
Utilities (off-sites)0 22,400,000
Site development and general 2,300,000
Subtotal 87,700,000
Engineering design @ 10% 8,770,000
Contingency @ 20% 17,530,000
Total Installed Plant Capital (TPC) $114,020,000
* Crushing raw coal to -100 mesh and includes site development
A Versar estimate
t Included in coal preparation and handling cost
a Includes oxygen plant
53
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TABLE 13. ESTIMATED ANNUAL OPERATING COSTS FOR THE LEDGEMONT
CHEMICAL COAL CLEANING PROCESS
Amortization 20 years @ 10% interest (factor = 0.1175) 13,400,000
Taxes @ 2% TPC 2,300,000
Insurance @ 1% TPC 1,100,000
Labor (direct, indirect, includes G&A) 1,600,000
General and administrative (included above) —
Maintenance and supplies 7,300,000
Utilities:
Electric power 7,000,000
Water 100,000
Steam 3,500,000
Chemicals: 8,200,000
Oxygen
Line
Flocculant
Binder
Waste Disposal 800,000
Total Annual Processing Cost $ 45,300,000
Paw coal, 2.39 x 10s metric tons (2.64 x 106 tons)
66,000,000
TOTAL ANNUAL COST $111,300,000
54
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CHEMICAL COAL CLEANING PROCESS
The Magnex^process is a coal benef iciation process which utilizes
vapors of iron pentacarbonyl [Pe(CO)5] to render the mineral components
of the coal magnetic. It has been experimentally demonstrated that free
iron resulting from decomposition of the pentacarbonyl selectively
deposits on or reacts with the surface of pyrite and other ash forming
mineral elements to form magnetic materials. Microscopic observations
and chemical analyses suggest that for pyrite the magnetic material is a
coating of a pyrrhotite-lite mineral, while for ash the magnetic material
is metallic iron. It has also been demonstrated that the pentacarbonyl
does not deposit iron on the surface of coal particles. Reactions
suggested for this process are:11*
• Iron carbonyl decomposition
Fe(CO) 5 J Fe + 500 (1)
• Reaction of iron carbonyl with pyrite
FeS2 + X Fe(CO)5 . Fe(1 + X)S2 + 5X00 (2)
pyrrhotite-like
• Reaction of iron carbonyl with ash-fonning minerals
Ash + Fe(CO) 5 -»• Fe • Ash + 5OO (3)
iron crystallites
on ash
Process Description
process involves four major steps:
• crushing and grinding
• heating and pretreatment
• carbonyl treatment, and cooling
• magnetic separation.
Figure 4 presents a flow diagram for the MagneTprocess as described by the
process developer, Hazen Research, Inc., of Golden, Colorado.
Run-of-roine {ROM) coal is crushed to minus 14 mesh and then fed to the
thermal pretreating unit where it is heated to about 170°C (365°F) in the
presence of steam. Ohe steam and thermal treatment condition the coal to
improve the selectivity of the magnetic coating (increase yield and reduce
sulfur content of the coal) .
55
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VENT
STEAM
ROM
COAL
CRUSH
AND
GRIND
HEAT
TRANSFER
OIL
~~ •*•
/
COAL HEATER
MID CONDITIONER
HOT OIL
HEATER
CARBONVL
REACTOR AND
VAPORIZER
SPONGE —
IRON
BLEED
I co a f* ico)61
MAGNETIC SEPARATOR
BINDER
CLEAN
COAL
COMPACTOR
FIGURE 4 MAGNEX PROCESS FLOW SHEET
-------
The heated ooal is then gravity fed to the iron pentacarbonyl reaction
vessel where it is subjected to the treatment vapors at atmospheric pressure
for a residence tine of thirty minutes to one hour. The reactor is
insulated and maintains the sensible heat of the coal.
carbonyl treated coal is conveyed to the magnetic separation
section. Die treated coal passes across three induced magnetic rolls in
series. Ihe first roll removes the strongly magnetic minerals and the
second and third rolls remove the weakly magnetic minerals. Several com-
mercially available magnetic separators have been evaluated under funding
by EPRI. The report will be released in 1978.
After passing through the magnetic separator, the clean coal is
conveyed into a storage bin. Some clean coal from the storage may be
returned to the 00 burner for in-process use; the remaining will be
conveyed to the compactor unit. The pelletized coal will be then con-
veyed to the product storage for subsequent shipment.
The process consumes 1 to 20 kilograms of iron pentacarbonyl per
metric ton of coal (2-40 Ib/ton) , depending on the feed ooal; and generates
0.6 to 13.0 kilograms (1.4 to 28.6 Ib) of gaseous carbon monoxide (00)
for recycle.
"In the 1977 pilot plant, the GO-rich gas was not recycled to iron
carbonyl generation. Rather, it was discharged through a hypochlorite
scrubber to remove traces of iron carbonyl". Since the major operating
cost for this process is associated with the consumption of the iron
pentacarbonyl, it is planned to react the GO-rich gas with iron to produce
iron carbonyl on-site. Even with a projected 00 recirculation system,
a bleed stream may be discharged from the reactor.
Status of the Process
The MagneaPprocess has been under development for 30 months. Far
the first 18 months, the process has been investigated on a laboratory scale,
using initially 75 gram samples and later one kilogram samples, on a batch
57
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scale basis. To date about 40 coals, mostly Appalachian in origin, have
been tested!" She major emphasis of the laboratory work has been on the
chemistry of the process. During this study efforts were directed to deter-
mine the effects of process variables such as reactor temperature, iron
carbonyl requirements and reaction residence time.
"On February 17, 1976, United abates Patent #3,938,966 was issued
to Hazen Research, Inc. The Magnetf^prooess is owned by NEDDOG TECHNOLOGY
GROUP. NBGLOG plans to continue process development and initiate design,
construction and operation of a 54 metric tons (60 tons) per hour
demonstration plant. The Magnex^ pilot plant schematics are given in
Appendix III.
Start-up operation for the pilot plant was in November, 1976. The coal
selected for the pilot plant evaluation was from the Allegheny group of
Pennsylvania. This coal was run in the pilot plant during the first quarter
of 1977 and was upgraded to meet the current new source sulfur dioxide
emission standard of 2.2 kg per million Kg cal (1.2 Ib S02 per million BTU).
Washability studies of this coal had indicated that conventional gravity
cleaning would not significantly reduce the sulfur content of the feed coal.
Under funding from the Electric Power Research Institute, a study on
the mechanical aspects of magnetic separation of carbonyl treated coal has
been conducted. The result of this study is scheduled to be published in
the spring of 1978 (EPRI KP-980-1).
At the present, various coal samples are being evaluated in the
laboratory stage and research and developmental work is proceeding in the
area of iron carbonyl generation.
Technical Evaluation of the Process
|5j
The Magnex^process removes only pyritic sulfur and therefore, it is
more applicable to coals rich in pyritic sulfur, which are found in the
Appalachian region. The process also reduces the ash content of the coal.
It is claimed that fine coal crushing is not necessary to enable the
Magnex^process to find a wide application in pyrite-rich coal desulfuriza-
58
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ticn. The Bureau of Mines prediction curves which correlate pyrite particle
size with pyrite sulfur removal do not cLLlow accurate prediction of sulfur
reduction for a given coal by the Magnex~process. These curves are only
applicable to gravity coal cleaning techniques. It has been reported that
in one test the average pyrite particle size of the minus 14 mesh coal
sample was 15 micron. Removal of pyritic sulfur from this sample by the
Magnex process was approximately 80 percent; while a 30 percent sulfur
removal was predicted for this coal using the Bureau of Mines prediction
curves.
published information is available on Magnexprccess test
results. A report covering the applicability of this process for desulfuri-
zation of coals surveyed may be issued in the future. However, available
information is discussed below.
Potential for Sulfur Removal —
Laboratory experiments conducted by Hazen indicate that the Magnex^
process can remove enough sulfur and ash from many Appalachian coals to pro-
duce compliance coals. However, significant iron carbonyl consumption rate
differences do exist between pyrite removal in various coals (2-40 Ib per
ton of coal processed) .
In a test with coal from the lower Freeport Seam, ash was reduced
from 27 to 9 percent and pyritic sulfur from 2.1 to 0.3 percent with a
coal product yield at 73 percent. Table 14 presents results from
this test. l5 These results were obtained with iron carbonyl addition
rate of 2 kilograms per metric ton (4 Ib per ton) of coal, ih a similar test
with a different sample of the same coal, using an iron carbonyl
rate of 31 kilograms per metric ton (62 Ib per ton) of coal, ash was reduced
from 27 to 5 percent and pyritic sulfur from 2.1 to 0.2 percent with a product
yield of 46 percent. These results indicate that better product quality can
be achieved with this process with greater amounts of iron carbonyl addition,
but at the expense of the product yield.
59
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TABLE 14. SULFUR AND ASH REMDVAL FROM LOWER FREEPORT
SEAM COAL BY THE MAGNEJ^PRXESS
Results:
Analyses,dry Clean Coal
Yield, wt. % 72.7
Ash, % 9.4
Pyritic Sulfur, % 0.33
Total Sulfur, % 0.88
Calorific Value, BTO/lb 13,970
Refuse Calculated Peed
27.3
73.8
6.88
7.28
2,997
27.0
2.12
2.63
10,974
Distribution, %
Weicfct
Ash
Pyritic Sulfur
Heating Value
73
25
11
93
27
75
89
7
Conditions:
Teirperature
Tine
Feed Size
Iron Carbcnyl
190-195°C
1 hour
14 by 150-nesh
4 Ib/ton (0.2%)
60
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Table 15 presents a set of results with a Pittsburgh seam ooal. 3h this
test ash was reduced fron 17.0 to 10.2 percent and pyritic sulfur from 1.6
to 0.56 with a coal product yield of 87.1 percent. These results were
achieved with iron carbonyl addition rate of 32 Ib/ton. This Pittsburgh seam
coal is a metallurgical grade coal and is presently cleaned by heavy media
washing for the coarse coal and Deister taM*»-« for the fines. In Table 16,
results of the conventional gravity cleaning are compared to two test results
obtained while processing this feed in the ffegnex=systan. As shown, the coal
products obtained with carbonyl treatments are superior in terms of sulfur
content to that obtained by conventional cleaning techniques.
During the first quarter of 1977 a .Cpal feed from the Allegheny Group of
Pennsylvania was evaluated on the MagneaFpilot plant. Table 17 presents the
analysis of the feed coal. Two shipments of this coal were received from the
same mine and seam. The ash content of the first shipment was considerably
lower than the second (12.7 vs. 18.3 percent); however, the sulfur content of
both shipments was the same (0.71 percent inorganic and 0.56 percent organic
sulfur). Washability curves presenting specific gravity versus yield, cumu-
lative percent ash float and ash sink, and plus or minus 0.10 specific
gravity distribution curve of the PCM pilot feed are given in Figure 5. This
plot indicates that at a specific gravity of 1.5 (where 10 percent of the raw
coal feed lies within - 0.10 specific gravity curve) theoretical perfect
sink/float cleaning would yield 87.7 percent clean coal containing 9.5 per-
cent ash and 1.13 percent sulfur. While significant ash reduction can be
achieved at that specific gravity by sink/float techniques, the resulting
coal will not meet the current new source emission standard of 2.2 kg SO2
per nri.llinn Kg cal (1.2 Ib SO*, per million BTU).
The results of the laboratory MagneaPevaluation of the pilot plant feed
are presented in Table 18. These data indicate that at 170°C (338°F) and 20 kg
of iron carbonyl per metric ton (40 Ib/ton) of coal, the clean coal yield was
81 percent with product sulfur content equivalent to 1.82 kg S02 per million
Kg cal (1.01 Ib S02 per mi in™ RTU).
61
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TABLE 15. SULFUR AND ASH REMOVAL FROM PITTSBURGH SEAM
(SM
GOAL BY THE M&GNEX=PROCESS
Results:
Analyses, dry
Yield, wt.%
Ash, %
Pyritic sulfur, %
Toted sulfur, %
Calorific value, BTU/lb
Distribution, %
Weight
Ash
Critic sulfur
Heating value
Conditions:
Temperature
Tine
Feed size
Iron carbonyl
Clean Coal Refuse
87.1 12.9
10.2 63.1
0.56 8.65
1.33 8.88
13,655 4,697
87 13
52 48
30 70
95 5
170°C
1 hour
14-mesh by zero
32 Ib/ton (1.6)
Feed
100.0
17.0
1.60
2.30
12,499
TABLE 16. SULFUR AND ASJ1 REMOVAL FROM PITTSBURGH SEAM COAL
EM
BY THE MAGNET-PROCESS VS. CONVENTIONAL GRAVITY
SEPARATIONS
Clean Coal
Carbonyl, treatment flA
Conventional processing
Carbonyl, treatment B"
Feed coal, average
Yield, wt.
87.1
82.0
75.3
~~
% Ash, %
10.2
8.4
8.3
17.7
Pyritic Sulfur, %
0.56
0.93
0.49
1.64
A Carbonyl
rate 32 Ib/ton.
t Carbonyl addition rate is greater than 32 Ib/ton; however, the exact level
is unknown.
62
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TABLE 17. ANALYSIS OF
PROCESS PILOT PLANT FEED GOAL
Sample NumberA
11089
10442
Ash, wt. %
Total sulfur, wt. %
Organic sulfur, wt. %
Inorganic sulfur,t wt. %
Calorific value, BTU/lb
Emission, Ib SO2/106 BTO
18.29
1.27
0.56
0.71
11,980
2.12
12.7
1.27
0.58
0.70
12,903
1.97
A Two shipments of coal were received. Although they were from the
same mine and seam, the ash content was significantly higher in 11089.
t Inorganic sulfur = pyritic + sulfate.
TABLE 18. SIBMARY OF LABORATORY EVALUATION OF
PILOT PLANT FEED COAL*
PROCESS
Test Numbers
*, ,_ i
Carbonyl LLedtufcuvt
Temperature
Dosage
Clean coal
Yield
Ash
Total sulfur
Inorganic sulfur
Heating value
f*ni pp JT>
Units
°C
Ib/ton
%
%
%
%
BTU/lb
Ib SO2A06 BTU
A
170
2.5
96.4
11.6
1.08
0.34
12,992
1.66
B
170
10
86.4
11.8
0.89
0.24
12,964
1.38
C
170
40
81.0
10.7
0.66
0.09
13,160
1.01
Feed coal was 10442, minus 14-mesh, 1.27% total sulfur, 0*71% inorganic
sulfur, 12.7% ash, 12,736 BTU/lb.
63
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I I I I I I I I I I
±0.10 SPECIFIC —
GRAVITY DISTRIBUTION
CUMULATIVE % TOTAL
SULFUR, FLOAT
CUMULATIVE
|— % ASH,
FLOAT
SPECIFIC GRAVITY —
90
100
SPECIFIC GRAVITY
0.6
I
O.8
I
1.0
I
I
1.2
I
I
1.4
I
I
1.6
I
1.8
I
2.0
2.2
I
0
I
4
I
CUMULATIVE % SULFUR, FLOAT
8 12 16 20
I
I
12
I
I
16
I
I
24
I
28
L
32
_J
CUMULATIVE % ASH. FLOAT
FIGURE 5 MAGNEJFPROCESS WASH ABILITY PLOT FOR A
6 INCH X 100 MESH COAL
64
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Figure 6 is the graphical representation of the laboratory data with
superimposed pilot plant test data shown by asterisk.*6 In two pilot plant
runs, using 75 and 10 kg (15 and 20 Ibs.) of iron carbonyl per ton of coal,
the clean coal yields were significantly higher (7.9 and 3.6 percentage
points, respectively) than the results obtained from the laboratory runs. The
sulfur dioxide to BTO ratios for the pilot tests were close to that predict-
ed by the laboratory runs. Pilot plant results indicated that for coal used
in this evaluation 10 kg per metric ton (20 Ib per ton) of iron carbonyl was
adequate to yield a product to meet the current new source SO2 standard.
Sulfur By-Prcducts— ^
CM
There are no sulfur by-products generated by the MagnesFprocess. The
process is a totally dry method of sulfur removal and the waste is a dry
mineral refuse.
Benefit Analysis— _.
The main benefit associated with the Magneorprocess is that it is a
totally dry process and has no coal washing and dewatering problems. The
process utilizes moderate temperature and residence time and atmospheric
pressures. Furthermore, the MagneaFprouess achieves good ash removal, higher
pyritic sulfur removal and higher yields when compared to a conventional
gravity separation. The net heating value recovery of the system is esti-
mated to be 76 percent, assuming clean product coal is used to generate steam
KM
and burn the CD released in the process. In the projected MagneSFsystem, where
plans are to recdrculate the CO for the production of iron carbonyl, the net
heating value yield could be as much as SO percent. This is because only a
small bleed stream will be incinerated or scrubbed in the alternative system.
The process is, however, restricted to the removal of mineral sulfur
and ash and also requires rather extensive monitoring because of the use of
highly toxic iron pentacarbonyl and the generation of carbon monoxide.
No analysis has been conducted to determine the nitrogen or the trace
ntent of the treated product. However, it is anticipated that the
will remove seme of the trace metals in the coal while
reducing the total ash content of the coal feed.
65
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100
30
40
1.70
10
20
30
40
Ibs of F«
-------
Environmental Aspects—
The treat-gas stream used in this process consists of iron penta-
carbonyl and carbon monoxide. Both of these gases are toxic and thus
extensive safety measures should be taken to isolate and contain these
hazardous materials. There are several other industries in the U.S. which
currently use toxic materials. For example, toxic nickel carbonyl is used
in nickel powder manufacturing. Since the ha sard of nickel carbonyl is
recognized, safety precautions have been instituted at these plants to
render their operations environmental ly safe. Similar control and safety
measures could be instituted at
Extensive use of lock-hoppers will be made to isolate the toxic com-
pounds. The bleed gas from the reactor would be incinerated or scrubbed.
Toxic gas alarm systems will be utilized as a warning measure in cases of
unavoidable gas emissions. Ohe use of proper ventilation system coupled
with adequate air emission controls will minimize the adverse environmental
effects Trim Magnpx^" ^ci 1 j
In the vicinity of the plant, coal handling, crushing, grinding and
•
conveying operations will be enclosed to provide dust control. Use of
cyclones and bagnouses for solids recovery and particulate emission control
will be adequate.
There will be no waterbome waste generated by the MagnejPplant. How-
ever, the dry refuse generated by this facility will contain heavy metals,
sulfur compounds, and will be enriched in iron content. This waste will
have essentially the same characteristics as the refuse material generated
by physical coal cleaning plants. However, it will be in a totally dry and
relatively compact form and as such it will be more manageable.
Problem Areas—
Ohe major problem area for this process is to develop and demonstrate
the production of low-cost iron pentacarbonyl using the CO generated from
the decomposition of the treat gas. The use of impure 00 in iron carbonyl
manufacture is highly questionable.
67
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Crushing coal to much less than 14 mesh top size may be necessary to
enable the MagneaFprocess to be applicable to coals containing a widespread
pyrite particle size. Should the results of further investigations necessi-
tate fine coal crushing for pyrite liberation, the commercially available
magnetic separators may be inadequate for fine size magnetic mineral separa-
tion. Further develppniental and demonstration work would then be necessary
in the area of fine particle magnetic separation from the carbonyl treated
coal feed.
R&D Efforts and Needs—
The specific research efforts and needs for this process are:
• demonstrate the process of on-site iron carbonyl manufacture
from the recycle CO.
• design, assemble and operate a demonstration plant [54 metric tons
(60 tons) per hour plant] incorporating and integrating the iron
carbonyl manufacturing from recycle CO.
• demonstrate what size consist various coals must be crushed to,for
pyrite liberation,prior to iron carbonyl treatment.
• study physical, chemical and combustion characteristics of the
treated product in order to define its combustion behavior and to
evaluate the pollutant emissions from the burning of the treated
material.
Process Economics
The IfegneaPprocess is a totally dry process and therefore the capital
costs associated with equipment installation are relatively low.
The economic estimates presented herein are based on a plant which
processes 300 metric tons (330 tons) per hour, 7,200 metric tons (8,000 tons)
per day of coal. The coal is assumed to have 0.70 weight percent organic
sulfur and 1.22 weight percent pyritic sulfur which is processed to meet
the current new source sulfur dioxide emission standard of 2.2 kg S02/
million Kg cal (1.2 Ib S02/million BTU). It is also assumed that the
coal is treated with 10 kg of iron carbonyl per metric ton (20 Ib/ton).
68
-------
A surnnary of economics for the Magnex process is given in Table 19.
Petal Is on the capital costs are presented in Table 20. The capital estimate
for the desulfurization circuit is based on preliminary estimates reported
by Hazen. The total capital estimate assumes a grass roots plant which
includes off-site facilities such as coal crushing and handling, product
compacting, office buildings, rail facilities, etc. The estimated annual
operating costs are presented in Table 21. It is assumed that iron carbonyl
can be manufactured on-site at a cost of $0.22 per kilogram ($0.10 per Ib).
This is the price of iron carbonyl projected by Hazen. The current vendor
quotes of iron carbonyl range up to $3.3 per kilogram ($1.50 per pound).'
Therefore, the economic feasibility of this process is dependent upon the
developer's success in producing low cost iron carbonyl on-site.
69
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TABLE 19. SUMMARY OF ECONOMICS FOR THE MAQEX
CHEMICAL COAL CLEANING PROCESS
Basis: 7,200 metric tons (8,000 tens) per day of 6,800 kg cal/kg
(12,300 BTU/lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
79.4% weight yield, 80% heating value recovery
Installed Capital Cost: $37,815,000
Annual Operating Costs
on Clean Coal Basis: $19,238,000 process cost, excluding coal cost
$85,238,000 process cost, including coal cost*
$10.12/inetric ton ($9.18/ton), excluding coal cost
^44.84 /foetric ton ($40.67 /ton), including coal cost*
$1.47 AO6 kg cal ($0.37 /IQ* BTU), excluding coal cost
$6.52 /106 kg cal ($1.64 AO6 BTU) , including coal cost*
* Coal costed at $27.60/taetric ton ($25/ton)
70
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TABLE 20. INSTALLS) CAPITAL COST ESTIMATE FOR THE MAGNEX
CHEMICAL COAL CLEANING PROCESS
$ 1977 (1st Quarter)
Coal handling and preparation* $ 6,000,000
Desulfurization process costs
Carbonyl treatment and generation 5,250,000
Magnetic separation 11,925,000
Heating 2,000,000
Compacting and product handling* 5,120,000
Bui Ming and miscellanousa 700,000
Utilities (off-sites)* 3,565,000
Site development and general3 4,525,000
Subtotal 29,085,000
Engineering design @ 10% 2,910,000
Contingency @ 20% 5,820,000
Total Installed Plant Capital (TPC) $37,815,000
* Versar estimate based on crushing raw coal to -14 mesh
A Hazen estimate
t Versar estimate
a Includes administration building, maintenance shop, stockrooms and stores
9 Versar estimate includes the following facilities:
low pressure steam generation
.water treatment for boiler make-up
water supply
process and potable water
fire protection
instrumentation
electrical
3 Includes railroad facilities for incoming and outgoing cars and loading
and unloading facilities for raw materials and loading facilities for
refuse material
71
-------
TABLE 21. ESTIMATED ANNUAL OPERATING COSTS FOR THE MAGNEX
CHEMICAL COAL CLEANING PROCESS
Amortization 20 years @ 10% interest (factor = 0.1175) 4,444,000
Taxes @ 2% TPC 757,000
Insurance @ 1% TPC 378,000
Labor (direct, indirect, additives, support) 219,000
General and administrative @ 1.5% TPC 567,000
Maintenance and supplies @ 5% TPC 1,891,000
Utilities:* 1,400,000
Electric power
VSater ,
Steam & fuel
Chemicals: A
Iron carbonyl^ 5,333,000
Binder 3,811,000
Waste Disposal, 438,000
Total Annual Processing Cost 19,238,000
Raw coal 2.39 x 106 metric tons (2.64 x 106 tons) 66,000,000
TOTAL ANNUAL COST $85,238,000
* Excluding CO incineration and steam generation.
It has been assumed that 11.8 metric tons/hr (13 tons/hr) product coal
will be used to provide in-process needs (CO incineration and steam
generation).1
Hazen estimate; operating cost of iron pentacarbonyl manufacturing on-site.
72
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SYRACUSE RESEARCH CHEMICAL COAL COMMINUTION PROCESS
The Syracuse Research Corporation has developed a process for the chemi-
cal fracturing or occmninuting of coal, which is an alternative to mechanical
crushing and fine grinding. The process is a precursor to the removal
of pyritic sulfur and ash-forming components of coal by physical coal clean-
ing methods. Since the process is chemical in nature and it does remove
pyritic sulfur when combined with a physical coal cleaning process, it has
been included in this study of chemical coal cleaning processes.
Chemical comminution is a process that involves the exposure of the coal
to certain low molecular weight chemicals that are relatively inexpensive and
recoverable (usually ammonia gas or a concentrated aqueous ammonia solution).
"The chemical disrupts the natural bonding forces acting across the internal
boundaries of the coal structure where the ash and pyritic sulfur deposits
are located. An apparent breakage of natural bonds occurs along these
boundaries, thus exposing the ash and pyrite for follow-on separation. Do
significant dissolution of the coal occurs, nor is there any apparent re-
action between the non-coal constituents and the ccraninuting chemical." 1T
"Since no mechanical breaking is involved in the chemical comminution
approach, the size distribution of the comminuted (fractured) coal is govern-
ed by the internal fault system, the chemical employed, and the process oper-
ating parameters. Ihe size distribution of the pyrite and other mineral con-
stituents in the coal is solely dependent upon the characteristics and histo-
ry of the coal being treated." 17
Process Description
A conceptual flow sheet for the Syracuse process is presented in Figure
7. The starting material is raw coal which has been sized to 3.8 cm (1% in)
x 100 mesh. The minus 100 mesh coal is separated and shipped directly to the
physical cleaning plant. The 3.8 cm x 100 mesh coal is weighed and charged
to a batch reactor. In a typical cycle, the reactor is then closed and
evacuated by a rotary seal pump for removal of air. The reactor is then
pressurized with ammonia vapor to about 9 atm (120 psig). In a full scale
operation this would be accomplished in two steps, first to 5 atm (60 psig)
by equalizing ammonia pressure with another batch reactor (operated in
73
-------
RAW .
COAL
NH, VAPOR
CRUSHING
ROM COAL
SIZED TO IV
1
1 • ,-----
1 j
1 i
* >
_JLjf /-
1
xo
\
K.
DILUTE NH, LIQUOR
JL
WASH
COLUMN
n
")
OMPRESSOR
cz
NH, RECOVERY
COLUMN
REACTOR
NH,
TRANSFER
COMPRESSOR
NH,
REACTOR
DEWATERING
SCREEN
H,0
FINES TO
CLEANING PLANT
HOT
H,O
STEAM
•\REFRIGERATED
1 LIQUID NH,
/STORAGE
STEAM
^_J—
EVAPORATOR
FIGURE 7 SYRACUSE COAL COMMINUTION PROCESS FLOW SHEET
-------
parallel and just completing its' reaction cycle), and then to 9 atm
(120 psig), losing ammonia from either the amtonia compressor or from an
evaporator which draws from a liquified anrnonia storage tank. The reactor
is held at 9 atm (120 psig) pressure for 120 minutes. During the reaction
period, the temperature in the reactor rises 50°C to 65°C above the
anbient temperature due to heat of solution of arrmonia absorbed by moisture
in the coal. The coal is conrainuted to about 1 cm (3/8") top size.
At the end of the reaction cycle, the reactor is depressurized to 0.14
atm (2 psia) by first equalizing with another reactor which is charged with
fresh coal, and then exhausting with a transfer compressor. These steps
minimize loss of ammonia in coal. By this time, the temperature of the coal
has dropped to about 27°C (BO°F). The vacuum is then released in the
reactor, and the coal is conveyed directly to a slurry mix tank prior to
washing. The cycle of a batch is suggested as follows:
Operation Time (Min)
Charging 30
Evacuation 30
Equalizing to 5 atm (60 psig) 30
Pressurizing and holding at
9 atm (120 psig) 120
Equalizing to 5 atm (60 psig) 30
Depressurizing to 1.1 atm
(2 psig) 30
Release vacuum and discharge 30
Idle time as required
TOTAL 300 plus idle time
All vent gases are collected through a rotary seal pump and scrubbed.
The scrubber effluent is added to coal slurry.
Ocnminuted coal is slurried with a recycle stream pumped from the am-
monia wash column. This recycle stream contains minus 30 mesh coal of 15-
20% solids, plus 5-10% dissolved aranonia. A 35% solids slurry is formed
with the comminuted coal and is punped to the midpoint of the wash coluon.
75
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As the goal sinks in this colum it is washed free of ammonia with hot water.
Goal containing about 20% moisture settles to the bottom of the colum and
is periodically discharged by a rotary valve to a dewatering screen.
The coal on the dewatering screen is washed to remove all minus 28
mesh fines and discharged to a stockpile, where it can then be sent to a
cleaning plant. The minus 28 mesh fines from the dewatering screen leaves
as a 20% slurry, and are sent to a clarifier. The fines are recovered as a
40% sludge, which is sent to the cleaning plant. The clarifier overflow
water is recycled to product washing.
Ohe ammonia recovery colum is equipped with a feed preheater, a reflux
condenser, and dome-cap trays. The colum operates at one atmosphere pres-
sure, nominally and the reboiler is heated by 2.7 atm (25 psig) steam.
Ammonia is released from the incoming ammonia solution, and ammonia vapor
containing about 2% moisture is cooled to 30°C (90°F) as it leaves the column.
This vapor is compressed to 9.5 atm (125 psig) by the recycle compressor,
and the vapor ammonia is either recycled immediately to a reactor, or is
condensed and stored in a tank.
As has been stated above, all products from the chemical conminution
step would be sent to a conventional coal cleaning or washing plant for
separation of beneficiated coal from pyrits and ash-enriched refuse. A
proposed operation of this type is illustrated in the flow sheet given in
Figure 8. This flow sheet is proposed by the Syracuse Research Corporation.1?
Status of the Process
In 1971 Syracuse Research Corporation initiated development of a program
aimed at the removal of pyritic sulfur and ash-forming substances from coal.
The results of this effort have been patented in the Lhited States and in a
number of foreign countries. During a portion of the project, effort was
supported by the Energy Research and Development Administration, and a final
report was published.18
All work to date has been performed on a laboratory or bench scale at the
facilities of Syracuse Research. The largest tests have been with 23 kg
(50 Ib) batches of coal, which were run in large, specially constructed
steel "bombs".
76
-------
COAL WASHING WITH CHEMICAL COMMINUTION
<1000TofnP*Hou Produadl
FIGURE 8 SYRACUSE PROCESS CHEMICAL COMMINUTION PLUS
PHYSICAL COAL CLEANING
77
-------
Proof of the "deanability" of the chemically comninuted coal product
has been limited to development of laboratory washability data, followed
by complete sulfur and ash analyses of the various fractions, and develop-
ment of cumulative percent sulfur and percent ash contents versus percent
coal recovery curves. It appears that no chemically camtinuted coal has
yet been subjected to separation in a coal washing plant, or even on coal
washing pilot plant equipment.
In 1977 marketing of the process was undertaken by Catalytic, Inc. of
Philadelphia, Pennsylvania and a complete report of the process and pro-
cess economics was prepared.17
Exploratory efforts by Catalytic, Inc. to build and operate a pilot
plant at a suitable location include negotiations for a site at Homer City,
Pennsylvania or at TVA.19
Catalytic performed a study, at EPRI's request, comparing chemical
comminution with mechanical crushing, both followed by heavy medium
separation facilities for the Homer City application.
Technical Evaluation of the Process
Potential for Sulfur Removal—
As stated previously, chemical communition by itself does not remove
sulfur from coal. However, chemical fracturing exposes unwanted mineral
matter in coal so that it may be more readily and efficiently removed in
the following cleaning operation. After chemical communition, both the
mineral matter and the coal itself are claimed to have a larger particle
size than mechanically fractured coal, when seeking the same pyritic sulfur
or ash liberation rate.
Since coal which has been chemically comminuted liberates pyritic sulfur
more readily than mechanically fractured coal of the same size consist, the
user can employ higher sulfur coals as feed stock to achieve a given sulfur
level in the cleaned product. Conversely, for a given level of sulfur,
chemical comminution will generally yield increased coal product.
78
-------
In order to illustrate these Plains, Figures 9, 10 and 11 are graph-
ical presentations of washability studies completed on TTIinois No. 6
(Franklin County) coal. Analyses of this coal and other coals discussed
in this section are given in Appendix II.
In Figure 9, size consists are plotted for the following top sizes:
3.8 on (1% in) ROM; 1 cm (3/8 in) mechanically crushed; 14 mesh mechani-
cally crushed; and 3.8 cm (lh in) Syracuse process product (exposed for 120
min. to NH3 gas @ 9 atm (120 psig) and 24°C (75°F) . Die Syracuse process
product contains 4.5% of minus 100 mesh fines, whereas the 1 cm (3/8 in) and
14 mesh mechanically crushed samples contain 8% and 22%, respectively, of
minus 100 mesh fines. Since the initial 3.8 cm (1% in) RCM contains 2.5%
of fines, this means that chemical comminution has resulted in only a fjmll
amount of fines in the coal, while mechanical crushing results
in larger amounts of fines. Generally, the minus 100 mesh fines are
separated prior to heavy media coal separation and are either lagooned or
are subjected to mare intensive beneficiation such as flotation. Thus,
according to the data of Figure 9, for Illinois No. 6 coal, the use of
chemical comminution results in greater yields of coal for physical
beneficiation than do the mechanically crushed coals.
In Figure 10, the washability data has been plotted to show percent
cumulative ash in the four samples of Illinois No. 6 coal versus recovery
of plus 100 mesh coal. This data indicates that, at any given recovery
level, the 14 mesh mechanically crushed coal contains less ash than the
chemically crushed coal and consequently is somewhat superior to the
chemically comminuted coals in terms of ash rejection.
In Figure 11, the washability data is plotted to illustrate percent
cumulative sulfur versus recovery. In this comparison, the chemically
comminuted coal is clearly superior to the other three samples. For example,
at a 90% recovery of plus 100 mash coal, sulfur content would be 1.3.%,
for the Syracuse product, 1.48% for 1 cm (3/8 in) mechanically crushed
coal, 1.44% for 14 mesh mechanically crushed coal and 1.51% for 3.8 cm
(1% in) RGM sample, respectively. For a selected sulfur value of 1.40%,
weight yield recoveries would be 96%, for the Syracuse product, 78% for
14 mesh mechanically crushed coal, 70% for 1 cm (3/8 in) mechanical crushed
coal, and 49% for 3.8 cm (1% in) RCM sample.
79
-------
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LZ
° 1 1/2in.. R.O.M. Sample
• 3/8in., Mechanically Crushed
A 14Mesh, Mechanically Crushed
4 1 1/2in.. Chemically Fragmented.
Gaseous Ammonia. IZOptig,
75° F. Exposure Time: 120mm.
6 8
Cumulative X Ash
10
\2
14
FIGURE 10 SYRACUSE PROCESS VS. MECHANICAL CRUSHING: PERCENT ASH
VS. PERCENT RECOVERY OF ILLINOIS NO. 6 COAL
-------
100
o 1 1/2in , R.O.M. Sample
• 3/8in.. Mechanically Crushed
14Meth, Mechanically Crushed
1 1/2in.. Chemically Fragmented
Gaseous Ammonia, 120psig,
75° F, Exposure Time: 120min.
1.0
FIGURE 11
1.6
Cumulative % Sulfur
SYRACUSE PROCESS VS. MECHANICAL CRUSHING: PERCENT SULFUR
VS. PERCENT RECOVERY OF ILLINOIS NO. 6 COAL
-------
Figures 10 and 11 are based on recoveries of plus 100 mesh coal only.
When these recoveries are adjusted for the rejected minus 100 mesh fines,
the absolute recovery levels of all four coal samples will be lowered.
However, as shown in Table 22, for any given percent sulfur value the
product recovery potential is greater for the chemically comminuted coal.l?
The above example based on Illinois No. 6 coal illustrates a favorable
application of the Syracuse chemical ccnranuticn process, in that product
recoveries from the Syracuse process are superior to recoveries from RDM
or mechanically crushed coals at any sulfur level. However, for optimum
results on some coals the residence time at full pressure, 9 atm (120 psig),
may extend beyond 2 hours, to 3 or possibly 4 hours. For other coals
however, 30 minutes is a sufficient residence time. Furthermore, the
process is not superior to mechanical crushing on some coals.
As an example where the process is not superior to mechanical crushing
the data pertaining to an Upper Freeport (Westmoreland County, Pennsylvania)
coal is reproduced in Table 23 and Appendix HI. Coal recovery of fines-free
Syracuse process product is poorer than one or both of the mechanically
crushed products at lower sulfur values. Specifically, at a sulfur value of
0.9% the Syracuse product recovery is 77% versus 87% and 72% respectively for
the 14 mesh and 1 cm (3/8 in) mechanically crushed coals. However, as shown
in Table 23, on an overall yield recovery basis the Syracuse process is
slightly superior to either mechanically crushed coal product.l8 At a 1.3%
sulfur content, the Syracuse process product is also inferior on a fines-free
basis, but on an overall basis it approximates the recovery of the 1 cm
(3/8 in) mechanically crushed coal. Thus, technically, there is little
advantage of using the chemical comminution instead of mechanical crushing
on the Upper Freeport coal.
The effect of gaseous amncnia exposure time on sulfur washability curves
is illustrated in Figures 12 and 13. These show size consist and sulfur
washability on samples of Pittsburgh seam coal (Green County) which has been
treated as follows:
ROM;
minus 1 cm (3/8 in), mechanically crushed;
minus 14 mesh, mechanically crushed;
chemically comminuted, 2 hrs @ 9 atm (120 psig) & 75°F;
chemically comminuted, 4 hrs @ 9 atm (120 psig) & 75°F.
83
-------
TAH£ 22. PRODUCT FECOVERY OP POOR SAMPLES OF TFEHED TTI.TNOTS no. 6
COAL AT 1.4% SULFUR
Percent
Percent Recovery,
Minus 100 fines free
Sanpla Top Size mesh fines basis
3.8 on (1>! in) ROM
Goal 2.5 50
1 on (3/8 in) Mechanically
Crushed 8 70
14 MMih, M«4um1railly
Crushed 22 78
3.8 on (1% in)
rtlMirfr^llY
-------
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PITTSBURGH SEAM COAL I » 100MI
GREENE COUNTY
X -M M.Midunlctllr C
-------
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PITTSBURGH SEAM COAL i • IOOM i
GREENECOUNTV
X -14M.MKhwic.llyC.inhw).
40.74* < 100 M
• -3/1". MKhwiuUy Cruihcd.
IO.H*< IOOM
O fi.O-M. Smpto Co*l,
6.4M < 100 M
A ChMiiaHv Fragnwiud.
Qtwout E«powit Tnw, 4 hri.
120pit. 10.31X < IOOM
I
2.0
2.S
3.0
SULFURIfERCENTI
I
IS
1
40
FIGURE 13 SYRACUSE PROCESS VS. MECHANICAL CRUSHING: SULFUR WASHABILITY
CURVES FOR PITTSBURGH COAL (FOUR HOURS)
-------
As shown in Figure 12, the sulfur washability curve for the plus 100 mesh
portion of the 2 hr. chemically comminuted coal overlaps the curve for the
RDM coal, and the minus 14 mesh coal demonstrates the best washability.
In Figure 13, the plus 100 mesh portion of the 4 hr. chemically comminuted
coal is comparable to the minus 14 mesh mechanically crushed coal at the
lower sulfur levels and to the minus 1 cm. (3/8 in) mechanically crushed
coal at the higher sulfur levels. However, when these coals are compared
on an "as is" basis, the severe losses (about 40%) to fines of the minus
14 mesh coal alters the comparative results. This is shown in the data
of Table 24. On. an overall basis, the recovery of minus 14 mesh coal is
TAHTfl 24. PRODUCT KHUUVEtQf OF FIVE SAMPLES OF TREATED
PITTSBURGH SEAM GOAL (GREEN COUNTY) AT 2.5%
AN) 2.3% SUIFUR
Sample
3.8 cm (1% in) ROM
Minus 1 cm (minus 3/8 in)
Mechanically Crushed
Minus 14 m, Mechanically
Crushed
2 hr. Syracuse Process
4 hr. Syracuse Process
% Minus
100 Mesh
Fines
5
10
40
7
9
% Recovery
Fines
Free At
2.5%S
86
88
92.5
85
90
% Recovery % Overall
% Overall Fines Free Recovery
Recovery
At 2.5%S
82
79
55.5
79
82
At At
2.3%S 2.3%S
67% 64
75 67.5
85 51
66 61
85 77
lamples demonstrate approxi-
[ hr chemical
lv comminuted
sample is clearly best, and the 2 hr chemically comminuted sample is
superior only to the minus 14 mesh sample. It is therefore quite probable
that optimum plant operating conditions for different coals will be different,
and optimum conditions will have to be established by laboratory tests.
In this respect, the chemical conminution process is no different than
most other chemical coal cleaning processes.
87
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As previously mentioned, the potential for removal of pyrltic sulfur
from BOM mechanically crushed coal, or chemically comminuted coal has been
assessed to date only by laboratory washability data. This laboratory
technique yields optimal results which are rarely duplicated in fun-scale
coal cleaning plants. Therefore, the washability comparisons made
with respect to sulfur removal or product recovery, between chemically
coiirdnuted coal and mechanically crushed coals may be altered in plant
operation.
Based on available data, it is anticipated that the Syracuse chemical
comminution process followed by conventional physical coal cleaning, will
remove 50 to 70 percent of pyritic sulfur in coals, with product recoveries
of 90 to 60 weight percent. The coals used in laboratory studies contained
high organic sulfur. Therefore, even removal of 100% of pyritic sulfur
would not bring these coals into compliance with current EPA NSPS for S02
emissions. It is also concluded that the Syracuse chemical comminution
process, followed by conventional physical coal cleaning, will bring seme
coals into compliance range if the organic sulfur level is sufficiently low.
Sulfur By-Products—
Chemical comminution in itself does not result in removal of sulfur
from coal or in any chemical change in the sulfur. However, it does
liberate pyrite and other mineral impurities from coal, so that a more
efficient separation of pyrite and other minerals may be achieved in a sub-
sequent physical coal cleaning step.
As a result, pyrites are concentrated and discarded in the refuse from
the physical coal cleaning plant. There are no other sulfur by-products.
Environmental Aspects—
The chemical ccmnanution process, per se, appears to possess no
undesirable environmental aspects. Ammonia gas and resulting ammonium
hydroxide are utilized or operated on in a completely closed system, so
that fire or explosion hazards, or escape of concentrated vapors to the
worker operating areas should be only a small possibility. In the event
of a process stream leaking to the environment, there should be sufficient
provision of seal pumps or compressors to minimize large losses. Small
-------
losses can be safely allowed to dissipate to the environment with no
adverse environmental effects.
After physical coal cleaning of chemically conrtLnuted coal, the pyrite-
rich refuse must be disposed of in the same manner as other sulfur-rich
refuses.
Benefit Analysis—
The Syracuse chemical comminution process in ocirbination with a
conventional physical coal cleaning process, offers a means to remove up
to 90% of the pyritic sulfur in some coals, with improved coal heating-
values, and significantly decreased quantities of minus 100 mesh fines, as
compared to mechanical crushing processes in combination with the same
conventional physical coal benefication processes. This process also
reduces the ash content of the coal, however not to the same extent as
mechanical crushing followed by physical cleaning.
Problem Areas—
The chemical ocnntinution process appears to be fully developed, without
any major problems at this point. However, it should be mentioned that
both the pilot plant and commercial plant designs are based on a reactor
residence time of 120 minutes even though available experimental data show
that some coals require as much as 4 hours (240 minutes) for good comminu-
tion. For coals requiring a longer residence time than 120 nrLn., it is
obvious that plant throughput rate and operating economics will be adversely
affected.
R&D Efforts and Needs—
A reporL on the processing of 16 coals was due to be issued in 1977-78.20
It should increase knowledge regarding the spectrum of rraia which can be
successfully and feasibly chemically comminuted. The data from this report
may also clarify any necessity for providing reactor residence times
greater than 120 min.
No additional laboratory research effort is recommended at this time.
However, construction and operation of a pilot plant would contribute
greatly to confirmation of plant design parameters and process operating costs.
89
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Process Eocnonics
A conceptual plant design for a commercial chemical cxxmtinution process
was developed by Catalytic, Inc.17 to simulate that part of coal cleaning
it would supplant, i.e., mechanical grinding. Versar has utilized the
Catalytic, Inc. cost data and have modified and supplemented it as necessary.
Syracuse process cost estimates have been prepared for a grass-
roots plant which includes:
• raw coal receiving, storage, coarse crushing and handling
facilities, chemical ocntiinuticn, coarse beneficiation, and
drying, compaction, and shipping facilities;
• the Catalytic estimate for chemical ccraninution was based on
a 27,000 metric ton/day (30,000 ton/day) plant. Capital costs
for the 7,200 metric tons (8,000 tons) per day comminution plant
were scaled down using the 0.6 exponential factor. Operating
costs were, for the most part, scaled down linearly;
• amortization of all capital was calculated on the basis of 20
years capital recovery at 10% interest cost;
• drying and coal handling capital costs were based on data avail-
able from a Dow Chemical Co. cost document,5 scaling down with a
0.65 exponential factor, and adjusting for the relative cost
indecies of 1st quarter 1977 versus 1975. It has been assumed
that the coarse beneficiated coal will require no compaction;
• operating and maintenance costs for coarse beneficiation were
obtained (without breakdown) from an unpublished 1977 Gibbs &
Hill study; and
• the coarse beneficiation process alleges an 80% weight yield and
a 95% heating value recovery from the feed coal. No weight or
heating value loss is charged against the chemical ccnminution
step.
A summary of economics for chemical ccnminution plus physical bene-
ficiation is presented in Table 25. Details on the capital costs and
operating costs are given in Tables 26 and 27, respectively.
Using the cost estimation techniques and assumptions described above,
the cost of chemical comminution plus physical beneficiation is $6.36 per
90
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metric ton ($5.77/ton) of clean coal, or $0.78/106kg cal ($0.20/106BHJ)
excluding coal costs. Assuming a coal cost of $27.6/metric ton ($25/ton),
these costs become $40.82/metric ton ($37.02/ton) of clean coal or $5.03/
106kg cal ($1.27/106HIU).
91
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TABLE 25. SUMMARY OF ECONOMICS FOR THE SYRACUSE RESEARCH
CHEMICAL COMMINUTION PROCESS PIUS COARSE COAL
BENEFICIATION
Basis: 7,200 metric tons (8,000 tons) per day of 6,800 kg calAg
(12,300 BTU/lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
80% weight yield, 95% heating value recovery
Installed Capital Cost: $48,960,000
Annual Operating Costs
on Clean Coal Basis: $12,190,000 process cost, excluding coal cost
$78,190,000 process cost, including coal cost*
$6.36/Metric ton ($5.77/ton), excluding coal cost
$40.82 Aetric ton ($37.02 /ton), including coal cost*
$0.78/106 kg cal ($0.20/106 BTU), excluding coal cost
$5.03/106 kg cal ($1.27/LO$ BTU), including coal cost*
* Coal costed at $27.60/inetric ton ($25/ton)
92
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TABLE 26. INSTALLED CAPITAL COST ESTIMATE FOR THE SYRACUSE
RESEARCH CHEMICAL COftONUTION PROCESS PLUS COARSE
COAL BENEFICIAnON*
Coal $ 1977
Coal handling and preparation $ 5,080,000
Desulfurizationprooess costs
Chemical comminution^ 15,877,000
Coarse beneficiation (cleaning) 8,215,000
Drying and conveying 4,430,000
Product handling* 4,060,000
Building and miscellaneous —
Utilities (off-sites) —
Site development and general
Subtotal 37,662,000
Engineering design @ 10% 3,766,000
Contingency @ 20% 7,532,000
Total Installed Plant Capital (TEC) $48,960,000
* Including incoming coal handling facilities, contninution process facilities,
physical coal cleaning facilities, refuse disposal, product drying,
storage and handling.
A Catalytic, Inc. estimates includes power substation, cooling tower, air
ucupressor, site development, building and fire protection.
Assumes the coarse benef iciated coal can be handled and shipped without
93
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TABLE 27. ESTIMATED ANNUAL OPERATING COSTS FOR THE SYRACUSE
RESEARCH CHEMICAL COMMINUTION PROCESS PLUS COARSE
COAL BENEFICIATION
Amortization 20 years @ 10% interest (factor = 0.1175) $ 5,750,000
Taxes @ 2% TPC 980,000
Insurance @ 1% TPC 490,000
Labor* (direct, indirect, additives, support) 620,000
General and administrative (included in labor) —
Maintenance and supplies 1,910,000
Operating and maintenance costs for physical coal cleaning 1,260,000
Utilities:^
Electric power 560,000
Water 80,000
Steam 400,000
Chemicals:
Liquid ammonia 140,000
Waste Disposal —
Total Annual Processing Cost 12,190,000
Raw coal, 2.39 x 106 metric tons (2.64 x 106 tons) 66,000,000
TOTAN ANNUAL COST $78,190,000
*
Catalytic Inc. estimate.
Costs for chemical comminution process, only. These costs were taken
as 5 percent of total comminution plant cost.
Chemical comminution process, only.
94
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ERDA CHEMICAL COAL CLEANING PROCESS
The ERDA air/steam leaching process is similar to the Ledqemant oxyqen/
water process /except that the process employs higher temperature and pressure
to affect organic sulfur removal and uses air instead of oxygen. A coal de-
sulfurization process very similar to the ERDA process is also described in a
U.S. patent 3,824,084 assigned to the Chemical Construction Corporation.
In the ERDA chemical coal cleaning process the pyritic sulfur is first
oxidized to soluble sulfates. It is m aimed tfiat when the process operates
at the preferred temperature and pressure of 150 °C (302°F) and 34 atm (500
psia) , essentially all the soluble sulf ate is oxidized to insoluble iron
oxide and sulfuric acid. Details on the pyrite removal reactions are given
below.
2FeS2 + 7 O2 + 2H20 -»• 2FeSC\ + 2H2SO,» (1)
4FeSOi, + O2 + 4H20 •+ 2Pe2O3 + 4H2SO,, (2)
The resulting stoichionetric reaction for pyrite removal is
4IeS2 + 15 O2 + 8H2O -»• 2Fe2O3 + 8H2SOi, (3)
The organic sulfur leaching chemistry is not well known. It is the
developers belief that the major portion (>50 percent) of the organic sulfur
in coal is of the dibenzothiophene (DBT) type which is inert to air at relative-
ly high pressure and temperature. However, the remaining fraction of organo-
sulfurs are not DBT-lite and can react with air and steam to produce sulfuric
add.2 1 The suggested organic sulfur removal reaction is as follows
R! - S - R2 + - O2 + H2O •»• Rj + R2 + H2SO^ (4)
Process Description
In -Hie ERDA air/steam oxidative desulfurization process the coal slurry is
heated in the presence of compressed air at temperatures of 150°C to 200°C (300°-
400°F) , pressures 34 to 102 atm (500 to 1500 psia) , and residence time of 1
hour or less. At these operating conditions, it is claimed tiiat essentially
all the mineral sulfur and approximately 40 percent of the organic sulfur is
removed as sulfuric acid. The ERDA process has been conceptualized by Bechtel".
95
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A detailed flew diagram for this process including mass balance and stream
properties, as developed by Bechtel is given in Appendix v.
A simplified flow diagram of the process as developed by Bechtel, is
shown in Figure 14. Pulverized coal is mixed with water in the slurry mixing
tank. The coal slurry is pumped to feed-effluent exchanges where the feed
is heated with recovered heat from the reacted product. The feed is further
heated in the flash gas quench tower by direct contact with desulfurization
reaction off-gas, recycled from the product slurry flash tank. The feed slurry
at operating temperature and pressure is passed through a series of reaction
vessels where the sulfur in coal is oxidized in presence of compressed air.
The product slurry is next flashed into product slurry tank and subsequently
thickened, filtered and dried prior to compacting. A portion of the clean
coal is burned to provide heat for drying.
The coal thickener overflow is combined with the filtrate from the coal
filter and sent to lime treatment for neutralization of sulfuric acid and
ferrous sulfate. The sulfuric acid in this stream is converted to gypsum
and the ferrous sulfate to gypsum and ferrous hydroxide. These reaction
products are sent to gypsum sludge thickener and subsequently filtered. The
filter cake from this operation constitutes the solid waste from this process.
The thickener overflow and the filtrate constitute the recycle water, which
is sent to the slurry mixing tank.
Status of the Process
The ERDA chemical coal cleaning process was conceived approximately seven
years ago by Dr. Friedman at the Bureau of Mines and the process is currently
under study at ERDA1 s Pittsburg Energy Research Center (PEBC). Initial experi-
ments on the air steam oxydesulfurization of coal were carried out using a
batch, stirred autoclave system with 35 gram coal samples. This apparatus was
modified to allow continuous air flow through the stirred reactor while the
coal-water slurry remained as a batch reactant.
The current effort at FERC,centers on completing the installation of a
25 kg/day fully continous unit. The unit was expected to be available for
start-up testing in late 1977?2 The system consists of a slurry feeder, slurry
96
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PULVERIZED COAL
OFFGAS
REACTORS
SLURRY
MIXING
TANK
AIR
COMPRESSOR
THICKENER
LIME
RECYCLE H2 O
L
FL
OU
^-,_,-^
ASHO/
ENCH
mi^fm
kS
POWER
"" • -
^t
^
- — --
v
,4 — 1
1
FLASH
TANK
BINDER
FLUE GAS
T
t
AIR
DRYER
CLEAN COAL
COAL
• GYPSUM
FILTER
FIGURE 14 ERDA PROCESS FLOW SHEET
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pre-heater, air preheater, a single Monel pressure vessel capable of operating
at up to 69 atra (1,000 psig), two parallel pressure let-down tanks and a pro-
duct recovery tank. This system is designed to obtain data on reaction rates
and develop information on process engineering and economic evaluation. It
is hoped that operating data will be available within 9 months so that a de-
cision can be made regarding the design, construction, and operation of a
larger continuously operated process development unit (PDU). There is a pos-
sibility that a large, private engineering group may assume the PDU effort,
with support from ERDA.
Technical Evaluation of the Process
Technical evaluation presented here in is based upon published informa-
tion and discussion with ERDA researchers, as well as the Bechtel8 conceptual-
ization of this process and their prepared economic evaluation.
Potential for Sulfur Removal—
The developer's claim is that using this process, an estimated 45 percent
of the mines in the eastern United States could produce environmentally ac-
ceptable boiler fuel in accordance with current EPA standards for new installa-
tions.23 Available data from batch operations indicate that at mild temperatures
of 150° to 160°C (300°-320°F) the ERDA air/steam oxydesn] furization process can
remove more than 90 percent of the pyritic sulfur in coals. Table 282'presents
pyrite removal information from several representative coals . The process
is also claimed to remove up to 40 percent of coal's organic sulfur if the
reaction temperature is raised to 180-200°C (360-400°F), this latter informa-
tion is shown in Table 29.29 Table 30*3 indicates that at low operating tempera-
tures of 150 to 160°C (300-320°F) several high sulfur content coals, such as
coals from Iowa and Indiana (Lovilia #4 and Minshall seams, respectively), can
be significantly reduced in sulfur content by this process. Higher tempera-
tures and pressures will be required to reduce the sulfur contents of these
coals further.
The coal preparation requirements of this process are not known at this
time. Minus 200 mesh ROM coal has been used in most runs, but a few runs using
98
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28. PXEUE RQEVAL FPCM REPKESQ1TATTVE GOALS USING THE ERDA PROCESS
Tenp, Pyritic sulfur, wt. %
Sean state ^C _ Untreated' Treated
NO. 5 Illinois 150 0.9 0.1
Minshall Indiana 150 4.2 0.2
Lovilia No. 4 Iowa 150 4.0 0.3
Pittsburgh Chio 160 2.8 0.2
Lower Freeport Pennsylvania 160 2.4 0.1
BrooJcrille Pennsylvania 180 3.1 0.1
TRHLE 29. GROttOX: SULFUR RQCVAL FRCM REPRESQJTATIVE OQftLS USING THE
EFDA PBCXTRS
Taip, Organic sulfur, wt. %
Sean State. ^c Untreated Treated
2.0 1.6
0.5 0.4
1.1 0.8
1.5 0.8
1.0 0.8
2.3 1.3
1.5 1.2
Bevier
Mannoth*
Wyoming No. 9*
Pittsburgh
TfiMTT Fxeeport
TTHnrvl« NO. 6
ffinshall
Kansas
Montana
Ironing
Ohio
Pennsylvania
TTHnrda
Indiana
150
150
150
180
180
200
200
TABLE 30. EBDA wnrgss OKflSSULFORIZATIEN OF REPRESENTATIVE COALS
Teop, Total Bulrur, wt. % Sulfur, lb/10* BTO
Sean State °C Untreated Treated Untreated Treated'
Indiana 150 5.7 2.0 4.99 1.81
No. 5 minds 150 3.3 2.0 2.64 1.75
Lovilia No. 4 Iowa 150 5.9 1.4 5.38 1.42
Montana 150 1.1 0.6 0.91 0.52
Pennsylvania 150 1.3 0.8 0.92 0.60
Vfyaring No. 9* Wyoming 150 1.8 0.9 1.41 0.78
Pittsburgh Chio 160 3.0 1.4 2.34 1.15
Ereeport Pennsylvania 160 2.1 0.9 1.89 0.80
99
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minus 14 mesh ooal are claimed to produce conparable results. Due to physical
sizing limitations in the mini-pilot plant minus 200 mesh ooal will be pro-
cessed.
Sulfur By-Products —
The by-products from this process are dilute sulfuric acid and probably
some unhydrolyzed ferrous and ferric sulfate. These are treated with line
according to the following equations.
H2SO,, + Ca(CH)2 -» 2H20 + CaSO*
PeSO,, + Ca(OH)2 •»• Ete(CH)2 + CaSO,
The gypsum (CaSO*) and ferrous hydroxide can be disposed of as filter
cake. The filtrate from this operation can be recycled to the slurry mixing
tank.
Benefit Analysis —
The main benefit associated with the ERDA air/steam oxydesulfurization
process is the developer's claim for both mineral and organic sulfur removal.
The process utilizes a relatively simple technique and inexpensive reagents
for coal desulfurization. additionally it requires no extraction or washing
techniques for the removal of sulfur by-products.
It is also claimed that in the ERDA chemical ooal cleaning process, sulfur
is removed without incurring excessive oxidation of coal. The heat energy
recovery of the system is said to be better than 90 percent. Ash is decreas-
ed only to the extent of sulfur removed. Consequently most coals have shown
very slight decrease in heat content after this treatment. The ERDA air/
steam process also destroys caking properties of coals, and thus the process
can be «!»-» utilized as a pretreatment step for coal gasification.
Nitrogen content of the treated product has been determined and
there is no change upon treatment. No analysis has been conducted to
determine the trace elements.
Environmental Aspects —
There are no serious air emission problems anticipated with this process.
The of f gas from the reaction section will be scrubbed and condensed prior to
100
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venting. In the vicinity of the plant, coal handling, crushing, grinding and
conveying operations will be enclosed, to provide dust control. There should
be essentially no waterborne waste generated by this system, provided the
plant is designed to operate as a close loop system. The water balance in the
system is claimed to be very good, with minimal make-up water requirement.
A potentially serious environmental problem associated with this process
is the disposal of gypsum and ferrous hydroxide solid waste. This filter cake,
approximately 0.1 metric ton per metric ton of coal will contain some trace
metals and should be disposed of in an environmentally safe manner.
Problem Areas—
The problems associated with this process are engineering in nature.
The major one appears to be associated with the selection of materials for the
unit construction. The process generates dilute sulfuric acid which is highly
corrosive at the process operating conditions.
A significant effort must be directed toward process optimization studies
in order to select an economical and suitable material for lining the vessels
and equipment in contact with the acid. This includes all equipment in the
reaction section, feed preheaters, off-gas flash gas tank and scrubber system,
and pressure let down equipment.
The cladding material selected by Bechtel for the economic assessment of
this process is a 60-40 tantalum-niobium alloy at a thickness of approximately
2 mn (5/64 inch)6 . The cost per square foot of the lining material is report-
ed to be three tines as much as the cost of the 7.62 cm (3-inch) thick carbon
steel shell material selected for the high pressure reactor vessels.
The second major engineering problem is to select a means for pressure
let-down to avoid erosion problems that may occur due to exposure of hardware
to corrosive acid. Normal valving will erode in acid atmosphere.
Therefore, other systems must be considered for pressure let-down.
R&D Efforts and Needs-
Specific research efforts and needs for this process are:
• Conduct bench scale tests to determine the coal preparation
requirements for this process. The feasibility of coarse coal
101
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(minus 14 mesh) processing should be further investigated to permit
better assessment of sulfur removal potential and residence time
requirement for the coarse coal system.
• Conduct pilot plant level technical effort to verify process data
generated during the batch reactor operations and to establish
accurate neat and material balance information for process economics
evaluation and process development unit (PDU) design.
• Design, engineer, construct, and test a PDU having a throughput
capacity of at least one metric ton/day. The PDU should integrate
all major processing sections, including coal feed preparation and
product compacting.
• Conduct studies to define the combustion behavior of the treated
coal and to evaluate the pollutant emissions from the burning of
the product coal.
• The effect of the treated product on the operational efficiency
of electrostatic precipitators must be evaluated.
Process Economics
The economic estimates presented herein are based on Bechtel's conceptual
design. However, the Bechtel cost estimate was modified by Versar to allow
the evaluation of the ERDA process on a comparable basis with other processes
included in this report. The estimates are based on a plant processing 300
metric tons (330 tons) per hour of pulverized coal (80 percent finer than
200 mesh). It has been assumed that the plant will operate 24 hours per day
and 330 days per year basis.
The detailed flow sheet for the battery limit plant is given in
Appendix V.
A summary of economics for the ERDA process is given in Table 31. Details
on the installed capital cost for this process are given in Table 32, and the
corresponding estimated annual operating costs are presented in Table 33. The
unit operating costs shown are based on a net coal yield of 90 percent and a
heating value yield of 94 percent. It has been assumed that the coal win be
upgraded to meet the current NSPS sulfur dioxide emission standards.
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TABLE 31. SUMMARY CF ECONCMICS FOR THE ERDA CHEMICAL
COAL CLEANING PROCESS
Basis: 7,200 metric tons (8,000 tons) per day of 6,800 kg calAg
(12,300 BTO/lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
90% weight yield, 94% heating value recovery
Installed Capital Cost: $166,810,000
Annual Operating Costs
on dean Coal Basis: $56,595,000 process cost, excluding coal cost
$122,595,000 rpocess cost, including coal cost*
$26.26/fretric ton ($23.82/ton), excluding coal cost
$56.89/taetric ton ($51.60/ton), including coal cost*
$3.69/106 kg cal ($0.92/106 BTU), excluding coal cost
$7.98/106 kg cal ($2.00A06 B3U), including coal cost
* Coal costed at $27.60/taetric ton ($25/ton)
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TABLE 32. INSTALLED CAPITAL COST ESTIMATE FCR THE EPDA
CHEMICAL COAL CLEANING PROCESS
$ 1977
Coal handling and preparation* $ 18,000,000
Desulfurization process costs^ 100,000,000
Contacting and product handling"1" 5,120,000
Building and miscellaneous'* 700,000
Utilities (off-sites)A —
Site development and general* 4,500,000
Subtotal $128,320,000
Engineering design @ 10% 12,830,000
Contingency @ 20% 25,660,000
Total Installed Plant Capital (TPC) $166,810,000
* Versar estimate based on coal crushing and grinding to 80 percent
-200 mesh
A Bechtel estimate adjusted to 1st quarter 1977 price using CE plant
cost index. Includes off-sites.
t Versar estimate
« Versar estimate;includes administrative building, the maintenance shop,
stockrooms and stores
Versar estimate; includes railroad facilities for incoming and outgoing
cars and loading and unloading facilities for raw materials and loading
facilities for by-product waste material
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TABLE 33. ESTIMATED ANNUAL OPERATING COSTS FOR THE ERDA
CHEMICAL COAL CLEANING PROCESS
Amortization 20 years @ 10% interest (factor = 0.1175) 19,600,000
Taxes @ 2% TPC 3,336,000
Insurance @ 1% TPC 1,668,000
labor (direct, indirect, additives & support) 753,000
General and administrative @ 1.5% TPC 2,502,000
Maintenance and supplies @ 5% TPC 8,340,000
Utilities;* 12,744,000
Electric power
Hater 480,000
Steam —
Chemicals :
2,660,000
Binder 4,272,000
Waste Disposal 240,000
Total Annual Processing Cost 56,595,000
Raw coal, 2.39 x 106 metric tons (2.64 x 106 tons) 66,000,000
TOTAL ANNUAL COST $122,595,000
* Total excluding product drying and water, it has been assumed that
25.8 metric tons/hr (28.5 tons/hr) product coal will be used for
in-process drying needs.
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GENERAL ELECTRIC CHEMICAL COAL CLEANING PROCESS
The General Electric microwave process for chemically cleaning coal
consists of the following steps:
• Crushed and ground coal (40 to 100 mesh) is wetted with a sodium
hydroxide solution, then subjected to a brief (<30 sec) irradiation
with microwave energy in an inert gas atmosphere. Both pyritic
and organic forms of sulfur react with the sodium hydroxide to
form soluble sodium sulfide (Na2S) and polysulfides (Na2S ) during
a
irradiation.
• The coal is washed to remove the partially spent caustic and the
sodium sulfides, then it is again wetted with caustic solution,
and subjected to microwave radiation for an equivalent period.
• The coal is again washed to remove the partially spent caustic and
the soluble sulfides, it is then dried and compacted.
The uniqueness of microwave treatment lies in the fact that the sodium
hydroxide and the sulfur species in the coal can be heated more rapidly and
efficiently than coal itself. Thus the reaction between sodiun hydroxide and
sulfur occurs in such a short tine and with such low bulk temperatures that
an insignificant amount of coal degradation occurs. As a result, the heating
value of the coal is either unchanged or is slightly enhanced.
A number of bituminous coals having total sulfur contents from 1 to 6%,
and having either predominately pyritic sulfur or organic sulfur contents,
have been tested with total sulfur removals of 70 to 99%. Thus, the process
does address itself to both of the two major forms of sulfur in coal. For
roost coals, two microwave irradiation treatments with fresh caustic are
necessary. However, for the few onals with relatively low total sulfur con-
tent, a single treatment may be adequate to reduce the sulfur to a sufficient-
ly low level to meet EPA NSPS standards for SO2 emissions. Single treatments
are generally 30-70% effective in total sulfur removal.
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Process Description
In the absence of a flow sheet from G.E., a schematic flow sheet (Figure
15) of the desulfurization steps of the process has been proposed and
discussed with G.E. project personnel. They agree with its principal
features, which are as follows:
• 40 mesh top-size coal is slurried with a 20% solution of sodium
hydroxide so that the coal is thoroughly wetted by the caustic.
• The moist coal is then subjected to microwave radiation for
seconds. During this brief time, 30-70% of the total sulfur in the
coal is converted to sodium sulfide (Na2S) or polysulfide (Na2S),
and seme of the water is evaporated.
• The coal is then slurried in water to dissolve and remove the sodium
sulfides, dewatered, and then resaturated with about the same
concentration and amount of caustic as previously.
• After a second exposure to microwave energy, the desulfurized coal
is again washed free of sulfides and excess caustic, and is dewatered
and dried to the extent required for on-site use, or is dried and
compacted prior to shipping. Depending on the coal itself, and
certain operating factors, 70% of the total sulfur in the coal will
have been removed.
A schematic flow sheet has been proposed for the sulfur recovery
process steps, which is also shown in Figure 15. This is necessary for an
adequate conceptualization of the entire G.E. process and for process cost
estimation. It is G.E. 's present intent to process wash waters containing
sulfur by carbonating these liquors to produce hydrogen sulfide gas (IfeS),
and then recover elemental sulfur via the Glaus Process. The sodium
carbonate jwhich also results- from the carbonation step /would be treated with
lime to regenerate soluble sodium hydroxide and insoluble calcium carbonate.
The latter is then kilned to produce the COa and limp (CaO), which are both
recycled and reused. This regeneration process is almost identical to the
one being considered by the Battelle Institute as a part of their chemical
coal cleaning process.
107
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BINDER
RECYCLED
ItaOH SOLUTION
O
00
STEAM
EVAPORATOR
CONCENTRATED
NiOH SOLUTION
TO BLENDER
FILTER
FIGURE 1 5 GENERAL ELECTRIC MICROWAVE PROCESS FLOW SHEET
-------
The regeneration process at first glance appears simple and compact, however
it nay prove energy intensive due to:
• evaporative heat required to concentrate solids in the several
filtrate streams.
• heat input to the kiln.
It will, therefore, be necessary to use ndnimim quantities of water and
sodium hydroxide reactant in order to conserve heat energy in the subsequent
sodium hydroxide regeneration steps.
Status Of The Process
All work to date has been done on a laboratory scale with small (10-100g)
quantities of coal subjected to microwave radiation from a 1 KW, 2.4 GHz or a
2.5 KW, 8.35 GHz generator. The coal is first impregnated with a 20% solution
of sodium hydroxide (NaOH), and sufficient caustic solution is retained on
the coal after dewatering so that about 16 parts of NaOH are present per 100
parts of coal at time of treatment. Batch tests have been made on a number
of coals in which the coals were irradiated once or twice for varying periods
of time. However, exposure periods exceeding 30 seconds rarely gained
further benefits.
Goals tested are obtained from the Fuel Sciences Department of Pennsyl-
vania State University. As shown in Table 34, these coals provide a sulfur
spectrum ranging from low organic-high inorganic to high organic-low inorganic
sulfur.21* These are all bituminous coals, with heating values of 6,200-7,500
kg calAg (11,300-13,400 BTU/lb) and a size consist of -40 to +100 mesh.
A 12 KW microwave generator has been requisitioned and will be in opera-
tion by the end of 1977. At that time, test runs will be made on quantities
of coal up to 1 kilogram. These tests will, also be made in conjunction with
a pressure chamber which will allow microwave irradiation under pressures of
7.8 atm. (100 psig) with various gases. The principal functions of the inert
gases are to retain any evaporated water as water vapor, to exclude oxygen
from the working atmosphere, to minimize formation of undesired oxysulfur
reaction products and to eliminate possibility of fire in case an electrical
discharge occurs in the reaction zone.
109
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TABLE 34.
ANALYSES OF COAL SAMPLES USED IN TOE EVALUATION OF TOE G.E. PROCESS
Sulfur Content, %
Coal *
P90C-26
PSOC-252
PSOC-255
PSOC-257
PSOO294
PSOC-320
PSOC-353
PSOC-272
PSOC-273
Geographic Origin
Illinois #6 Seam
Illinois #5 Seam
Lower Kittaning Seam from Pa.
Upper Freeport Seam from Pa.
Pittsburgh Seam from Pa.
Pittsburgh Seam from Pa.
Clarion Seam from Pa.
Kentucky Seam 19
Kentucky Seam #11
Pyritic
4.23
2.82
4.49
1.06
2.27
0.45
4.65
0.03
0.2-0.3
Organic
2.08
1.84
0.78
0.56
0.34
0.64
1.21
3.80
4.49
Sulfate
0.35
0.06
0.03
0.01
0.07
0.07
0.06
0.14
-------
•iotax suirur icomDustiDie to t*j2) removaxs or /:>» nave ceen acmevea tear
most bituminous ooals provided that tvro sequential treatments are given.
However, much remains to be done in terms of economic optimization of the
process.
Technical Evaluation of the Process
Potential for Sulfur Removal—
A substantial removal of sulfur from bituminous oc«i appears technically
feasible with this process, providing that microwave treatment of the coal
is accomplished in two steps (See Figure 16).21* It should be noted that
when this figure was initially drawn by G.E., all analytical data indicated
that 95-100% removal of sulfur could be achieved as a result of the taro step
treatment. Since that time, additional analytical techniques have been
utilized and are yielding conflicting data. For example, on untreated coals
the Leco and the Eschka methods show nearly identical sulfur analyses. Cti
G.E. process treated coals, the Eschka (barium sulfate precipitation) method
shows considerably more residual sulfur in the coal then does the Leco
(conbustion) method. Two conclusions are possible:
• The G.E. process does remove 75% or more of total S from coal, but
not necessarily 95-100% in a 2-step process as was previously
claimed.
• Since the sulfur which is not removed does not snow up in a Leco
ccnbustion-type analysis, it may end up in the ash and thus may
still not result in 902 emissions. Further effort to resolve this
matter is in progress.
A one-step treatment is effective to the extent of 30-70% sulfur removal,
as shown in Figure 1725 and Table 35,2" depending on the coal itself and
other processing factors. Sulfur removal in subbituminous coal, anthracite,
or lignite has not yet been attempted.
Sulfur By-products—
The only projected by-product from the G.E. process will be elemental
sulfur. This will be obtained by carbonation of the intermediate by-products,
sodium sulfide and sodium polysulfide, to form gaseous hydrogen sulfide
(H2S). Hydrogen sulfide can then be reacted to form elemental sulfur via the
111
-------
100-1
90
80
70-
60-
SO
111
e
40
•
•
• •'
30
20 i
10
• IteOH (SLURRY)
ItaOH (DRIED)
DOUBLE TREATMENT
0 20 40 60 80 100
EXPOSURE TIME (SEC)
FIGURE 16 G.E. PROCESS: PERCENT SULFUR REMOVAL VS. EXPOSURE TIME
MULTIPLE EXPOSURE
112
-------
80
0 /
70
60
M*OH (SLURRY)
SO
*
O
Ul
40
cc
oc
Ik
2
30
20°
10
• I • a
NO. 273 • NiOH (POWDER)
• M*OH (SLURRY
Q IteOH (DRIED)
'NO. 272
0 20 40 60 80 100
EXPOSURE TIME (SEC)
FIGURE 17 G.E. PROCESS: PERCENT SULFUR REMOVAL VS. EXPOSURE TIME
SINGLE EXPOSURE
113
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TABLE 35. ANALYSES FOR RfiW AND G.E. PROCESS TREATED COALS
%S IN %C
PSOC 294
Pittsburgtt-uostly 2.02 1.21 62.65
pyritic
Single
Treatment, 1.29 1.24 59.21
30 sec.
Double
Treatment 0.4 1.09 53.87
PSOC 273
Kentucky 111 4,18 1.33 60.19
organic
Dbl. Treatment < 0.1 1.15 63.34
30 sec.ea.
15 Goal
Clarion Co. 2.37 1.53 78.82
Penna .mostly
pyritic
411 tO, % Ash % 11,0 % V.M. % PC
4.24 10.08 19.94 0.7 34.74 45.32
3.88 12.36 22.02 -
2.22 14.06 29.24 3.0 24.7 46.10
4.80 18.62 12.88
4.39 22.14 8.98
5.69 9.12 2.47
Single Treatment 0.88 1.49 75.51 5.17 11.44 5.53
30 see.
-------
Glaus or Stretford process. Other byproducts attributable to imperfec-
tions in the caustic recovery and the Glaus or Stretford process areas are
possible but are presently unknown.
Benefit Analysis—
The G.E. chemical coal cleaning process possesses some excellent
potential benefits, as follows:
• On the snail scale thus far tested, the process appears highly
efficient in removing sulfur from bituminous coal, regardless
whether the sulfur is pyritic or organic.
• The coal matrix is only slightly affected by the process, and weight
and heating value yields of product based on feed coal appear to be
high but little data is currently available.
Environmental Aspects—
Few environmental problems of a special nature are apparent. TVro
process steps will require built-in design safeguards to prevent their
becoming safety or environmental problems, as follows:
• Carbonation of the spent aqueous stream containing sulfides or poly-
sulfides will result in the generation of highly toxic hydrogen
sulfide gas. Since this gas is valuable and will be further
processed to elemental sulfur, a properly designed enclosed
reaction system should minimize the problems from this unit.
• Ihe high intensity microwave generators which will be used, must be
completely shielded. If adequate shielding is not provided, other
microwave transmissions (TV, radio, telephone microwave transmitters)
will be affected. In addition, humans can be affected adversely
by exposure to microwaves, which can produce cataracts in the eyes.
No analyses of toxic trace elements are available at this time.
Problem Areas—
There are potential problems which can be recognized on the basis of its
early state of development. Some of these potential problems are:
115
-------
• Scaling up the process, particularly from batch-wise microwave
treatments to large scale continuous mode operation, may prove
difficult.
• The sodium hydroxide regeneration step may prove more costly
and energy intensive than now estimated, particularly
if the proportion of caustic to coal is high.
• If sodium is retained in the coal to a significant extent(>0.5%),
the ash resulting from subsequent coal combustion may be in the
form of slag and thus the coal will not be usable in most boilers.
R&D Efforts and Needs—
As mentioned above, the G.E. process is at a very early stage of devel-
opment. Consequently, there are a number of areas which need research and
development before a comprehensive technical and economical evaluation can
be completed. Some of these are as follows:
• The present scale of batch size for jrradiator (10-100g) needs
to be increased.
• An optimum microwave frequency for coal processing needs to be
selected, concurrently with such parameters as NaOH/coal ratio,
NaOH solution strength, pressure, presence or absence of inert
gases, irradiation field strength and irradiation exposure time.
• Optimization of a single treatment step could lead to elimination
of the present two step irradiation process, resulting in important
economic benefits.
• The size consist of the coal should be varied in the experimental
program. In general, the larger the size consist, the cheaper
the coal preparation costs and the more storeable and shippable
the product would be. In addition, other coals such as sub-
bituminous, anthracite and lignite should be tested.
116
-------
• More complete weight balances, and analyses of trace elements
are needed to evaluate the process.
• Since there has been no research effort on byproduct recovery
(through evolution of H2S gas), and sodium hydroxide recovery,
these process steps should be thoroughly investigated. If sulfur
recovery is not essentially conplete, recycling of the iitpure caustic
soda may result in reduced efficiency of sulfur removal in the coal.
• In the coal treatment steps and in the subsequent sodium hydroxide
regenerations system, there are a number of dewaterings and
filtrations (such as separation of calcium carbonate from sodium
hydroxide). Special emphasis should be placed on investigating
these operations, since an inefficient filtration could prove to be
a process bottleneck and require very expensive equipment.
• Process research studies should attempt to minimize sodium hydroxide
and water use, as the economics and the net energy yield of
the process will be very adversely affected by excessive use and
the resultant recovery of these materials.
• Any sodium build-up in coal (as ash) should be noted as this
would be detrimental to combustion in some boilers.
Process Economics
Capital costs and operating costs were developed by Day & Zimmerman
Go., Philadelphia, Pa., for G.E. for the coal needs of a 500 MW coal-burning
power plant [requiring the use of about 4,500 metric tons (5,000 tons) per
day of 5,550 kg calAg (10,000 EOU/lb) coal].
The G.E. cost estimate was based on nM-t-ain assumptions which are
sufficient for G.E. *s purposes, but which do not make it comparable with
other process cost estimates included in this report, ihe G.E. last
estimates were altered as follows:
• Production capability was increased from about 4,500 metric ton
(5,000 tons) per day of 5,550 kg cal/kg (10,000 RTO/lb) coal to
7,200 metric tons,(8,000 tons) per day of 6,800 kg calAg (12,300 BTO/
1±>) coal.
117
-------
• Capital costs were increased to the larger capacity using the 0.6
exponential factor, except microwave reactor costs, which were
extrapolated linearly. In addition, capital costs for product cotpac-
tion were added, and a 20% contingency was applied to the total.
• Operating costs, other than capital amortization,taxes and insurance,
were increased linearly. The capital cost was amortized over a
period of 20 years at 10% interest per year.
• An operating factor of 70% was initially used by G.E. on the basis
of coupling their desulfurization process to a utilities steam plant.
However, by uncoupling, a 90.4% operating factor is possible and
is being assumed.
• Weight yield and BTU yield are assumed at 96% although no supporting
data are available.
The new estimates for the G.E. process are reasonably comparable with
estimates available for other processes and are quite comparable for a
specific set of estimates recently prepared by Bechtel Corp. for six
other chemical coal cleaning processes. The new capital estimate is
$102,000,000 and the new operating costs are $39,820,000 per year. This data
is summarized in Table 36. Details on the capital costs and operating
costs are given in Tables 37 and 38, respectively.
118
-------
TABLE 36. SlMiARY CF ECONOMICS FOR THE GENERAL ELECTRIC
CHEMICAL COAL CLEANING PROCESS
Basis: 7,200 metric tons (8,000 tons) per day of 6,800 kg cal/kg
(12,300 BlU/lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
96% weight yield, 96% heating value recovery
Installed Capital Cost: $102,000,000
Annual Operating Costs
on Clean Coal Basis: $39,820,000 process cost, excluding coal cost
$105,820,000 process cost, including coal cost*
$17.33/foetric ton ($15.72/ton), excluding coal cost
$46.05/tetric ton ($41.77/ton), including coal cost*
$2.54/106 kg cal ($0.64/106 BTO), excluding coal cost
$6.72/106 kg cal ($1.69/10* BTU), including coal cost*
* Coal costed at $27.60/taetric ton ($25/ton)
119
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TABLE 37. INSTAT.T.FT) CAPITAL COST ESTIMATE FCR THE GENERAL
ELECTRIC CHEMICAL COAL CLEANING PROCESS*
$ 1977
Coal handling and preparation^ $ 11,284,000
Desulfurization process costs
Microwave reactors 29,200,000
Product washing & recovering ' 19,616,000
Claus process 5,627,000
Evaporators 4,426,000
Compacting and product handling^ 8,309,000
Building and miscellaneous
Utilities (off-sites) —
Site development and general
Subtotal $ 78,462,000
Engineering design @ 10% 7,846,000
Contingency @ 20% 15,692,000
Total Installed Plant Capital (TPC) $102,000,000
Capital costs scaled up from estimates made by Day & Zimmerman Co. on
a smaller installation. All costs are on a fully installed basis.
Includes storage, sludge pond, railroad sidings.
Includes treated coal washing tanks, thickeners, surge tanks, vacuum
filters and pumps.
Versar estimate, includes product drying prior to compaction and
handling.
120
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T&BT.K 38. ESTIMATED ANNUAL OPERATING COSTS FOR THE GENERAL
ELECTRIC CHEMICAL COAL CLEANING PROCESS
Amortization 20 years @ 10% interest (factor = 0.1175) 11,980,000
Taxes @ 2% TPC 2,040,000
Insurance @ 1% TPC 1,020,000
Tflbnr (direct and indirect) f 1,830,000
Maintenance and supplies 5,310,000
General and administrative (included in labor)
Maintenance
Utilities:
Electric powerf 3,100,000
Water* 100,000
Steam + 4,070,000
Chemicals: f
Sodium hydroxide 4,64U,000
Line 1,220,000
Bander* 4,510,000
Waste Disposal
Total Annual Processing Cost $ 39,820,000
Raw coal, 2.39 x 106 itetric tons (2.64 x 106 tons) 66,000,000
TOTAL ANNUAL COST $105,820,000
Information supplied by the process developer.
*
Estimated by Versar.
121
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CHEMICAL COAL CLEANING PROCESS
The Battelle hydrothermal coal pccooess (BHCP) is based upon hydrothermal
alkali leaching of mineral and organic sulfur compounds from coal. The
process presently proposed by Battelle employs sodium and calcium hydroxides
as a mixed leachant and operates under conditions of elevated temperatures
and pressures. The desulfurized coal, after filtration and washing to
separate the spent leachant, is dried and compacted for use in coal-fired
utility boilers. At the present stage of development, the process must be
considered as partially conceptual.
The BECP desulfurization step has been tested on a series of raw
bituminous coals and has been shown to extract essentially all of the pyritic
sulfur and 25 to 50% of the organic sulfur starting with a range of total
sulfur content of 2.4 to 4.6 percent. The product is a solid fuel which
meets the current new source standard of a maximum of 2.16 kilograms of sulfur
dioxide emission per million kg cal (1.2 lbs/106 BTU) with certain coels.
Process Description
The proposed process consists of five principal steps:
Coal Preparation—
The raw coal is crushed and ground to suitable particle size, generally
70 percent minus 200 mesh. The coal then goes directly to a slurry tank for
mixing with the leachant. Alternatively, the coal can be first physically
beneficiated to remove sane ash and pyritic sulfur before introduction into
the slurry tank.
Hydrothermal Treatment—
The coal slurry is pumped into a reactor where it is heated to tempera-
tures in the range of 200° to 340°C (400° to 650°F) and subjected to a
pressure in the range of 18 to 170 atm (250 to 2,500 psig) to extract sulfur
and dissolve a portion of the ash from the coal. Residence time is approxi-
mately 10 minutes. It is essential that this operation and the following
one be carried out in an oxygen-free atmosphere to minimize the formation of
oxysulfur compounds which prevent the quantitative recovery of sodium
hydroxide from the spent leachant.
122
-------
The reocntended leachant for the process is a mixture of 8 to 10 percent
sodium hydroxide (NaOH) solution in a 3 percent calcium hydroxide (Ca(OH)2)
slurry. Concentrations of these components of the leachant will vary
depending on coal properties.
Fuel Separation—
The desulfurized coal is separated from the leachate by means of
filtration and water washing. The leachate is then concentrated before
regeneration.
Drying and Agglomeration—
Water is evaporated from the coal in a drier, leaving dry, clean,
solid fuel. This material is then compacted to a suitable pellet size for
shipment to the user.
leachant Regeneration—
A chemical regeneration step using carbon dioxide is used to remove
sulfur from the leachate as hydrogen sulfide. This gas is then converted
to elemental sulfur by either the CLaus or Stretford process.
Table 39 presents Battelle's current best estimates of some key parameters
which would be involved in a continuous process if the BBCP is based on lime-
carbon dioxide regeneration of the spent leachant.26
A simplified schematic flow diagram of the conceptualized BIEP based on
a plant processing 300 metric tons (333 tons) per hour [7,200 metric tons
(8,000 tons) per day] of coal feed is shown in Figure 18. The key chemical
reactions in the process are shown below:
2FeS2 + 6NaOH •»• Fe2O3 + Na2S2 + 2Na2S + 3H20 (1)
Na2S + 2NaDH + 2002 •* 2Na2003 + H2S t (2)
CaO + H2O + Na2003* 2Na OR + Ca003 (3)
Ca003-»- CaO + CO2 t (4)
The schematic incorporates raw coal grinding, and treated coal
drying and compaction steps, not included in the latest Battelle process
flow sheet. Battelle proposes the production of treated coal as a wet
material which is stared in silos prior to shipment to the utility. If
located at power plant site the utility would be responsible for grinding
123
-------
TKELE 39. TXPICAL VALUES OF KEY PARAMETERS IN
BATIEriE HYDRDTHERMAL COAL PROCESS
Overall yield (average coal): 90-95%
Overall heating value yield (average coal) : within ±3-10% of original
heating value
Unit Process
Coal Preparation
Coal Desulfuriza-
tion
Treated Coal/Water
Separation System*
Sulfide Stripping
Parameter
mesh size
water/coal in feed
NaOH/coal in feed
CaOH/coal in feed
reaction time
temperature
pressure
f iltrationArashing:
percent solids in final
cake discharge
wash water/dry solids
OR
centrifugingA'ashing:
percent solids in final
cake discharge
wash water/dry solids
total sodium in treated
coal
total calcium in treated
coal
temperature
002 concentration in
stripping gas
pH of stripped liquor
lypical Value
70% minus 200 mesh
2
0.16
0.05
10 minutes
275°C (525°F)
50-55 atm. (700-800 psig)
9 stages in series
(optimum)
45% (optimum)
1.5 (optimum)
3 stages in series
(optimum)
55% (optimum)
1.25 (optimum)
0.25-1.96 wt.% (MAP)A
8.0-9.2 wt.% (MAF)A
50-80°C (120-180°F)
20-100%
8
* Results of a computer simulation study
+ Battelle has used a value of 2.0 for costing purposes, using a combina-
tion of filtration and centrifuging to accomplish solid/liquid separation
in the cost study.
A Range of values (moisture and ash-free basis) determined from hydro-
thermal treatment of Westland and Martinka coals/ EPA Contract No.
68-02-2119.
124
-------
CON DE MIA ft
in
CO.
UAKCUT •*
CARSON
PURI
SOOI IN
COLUtl
• lltOi
IHOKIOC
FIIR
«
ON
_
RECIRCUL
UtOHLCA
_ 1
^ 1 '
U,
db
\/
^<,
ATEU
:HANI
>
111
II \ x=L»llU(l n, n
db db . fl^VV rni«n 1
OCUIIIURIIATU1H ' t>sJxH 1 II II
RIAC10R NH 1 U "
ER 1 ,
/'>N| CONC HtOHl
I >( ? )" N», t SOLUTION
SOLUTION 1
JULflOf /CAUSTIC \ HJIFIDE
COHCCNTRATOR . _
1 |H,S
1
f
1 * ClCQ. /^^>V
\ . . 1 , CAU1TIC * « I ) , STBitinun
REGENERATOR- (LURRV $^-4 PROCESS
J*
i
-------
the raw coal and drying the treated coal. Battelle has included a charge
to the BHCP for the cost of drying in their latest cost estimate. However,
to make the cost estimate comparable to the other processes being
considered in this study, i.e., for a plant not necessarily located
adjacent to a power plant, the drying of the minus 200 nesh coal followed
by a compaction (briquetting) step are included in the flow sheet and cost
estimate.
The steps involved in leachant regeneration represent Battelle's
latest thinking on this phase of the process - there is no performance data
available as yet on continuous closed loop operation. The following
3attelle-supplied information has been used in deriving the overall
material balance shown in Figure 19.
• Five percent of the feed coal (including varying amounts of ash,
coal and trace metals) is assumed to be dissolved in the
desulfurization step. The dissolved material is precipitated
as a result of pH change, and leaves the process as filter cake.
Battelle has indicated that on an overall basis, between 5 and
10% of the average coal is solubilized. In the sulfide stripping
operation, carbonation of the sodium sulfide-bearing caustic
solution, results in lowering the pH to approximately 8 at which
point most of the dissolved coal, ash and trace heavy metals
precipitate from solution.
• An intermediate material balance (shown in Figure 19)26 around the
raw coal slurry preparation, desulfurization, solid-liquid separa-
tion and evaporation operations has been supplied by Battelle
based on the values of the parameters shown in Table 39. The
material balance shown in Figure 19 is based on a computer model
of the process and conservatively assumes 100% and 0% removal of
pyritic and organic sulfur, respectively, from the coal. Ch this
basis, the product coal has 0.81% total sulfur (MAF) equivalent to
2.3 kg/106 kg cal (1.3 lb/106 BTU) of sulfur dioxide emissions
(based on a 6,900 kg calAg or 12,500 BTU/lb coal). Battelle makes
a further assumption, believed to be conservative, that the
126
-------
PULVERIZED
COAL
20 TTH Moisture
BO TFH Ash
292.8 TPII C.N.ll.O
ft. 5 TPH Fyrltlc B
l.J_ TPH Org. S
400.0 TPII Conl
64 TPH HaOH
20 TPII CaO
BOO TPH 11.0
Step
TPH Ash
TPII C. N, II, 0, orgS
TPII Co (Oil) 2
TPII Fp(OII}2
TPII HnOH
TPII H(i?S
TPII
TPII
(401.15) TPH Dry Solids)
1281.0 TPII
c
Wnsh Water Mnkeup
•v«85 1TII
80 TPH Ash
3.65TPII NaOlt
1.08 TPII Na2S
0.37 TPII Na2S203
291.58TPII C,N,li,0,orgS
23.21 TPII Cd(OII)2
6.30 TPII Fe(OII)2
596.61 TPII II20
I90T.B2
rator
"Wet Goal
Solid-Liquid Separation Step
50.52 TPII NaOII
7.14 TFII Hn2S
2.41 TPII Ha,S201
1023.42 TPt, ,,J 3
1083.48 TPII
FIGURE 19
BATTELLE HYDROTHERMAL PROCESS: MATERIAL BALANCE FOR REACTOR
AND SOLID / LIQUID SEPARATION SECTIONS
-------
calcium in the product coal will capture at least another 10% of
the sulfur (by a "getting" action) during oontoustion thereby
reducing the net sulfur dioxide emission of this coal to 2.12 kg
S02/106 kg cal (1.17 Ib S02/106 BTU), which is below the EPA NSPS
value. By-product sulfur would be generated at the rate of 2.9
metric tons (3.2 tons) per hour based on: (a) the above information,
(b) an assumed 100% conversion of the sodium sulfide to hydrogen
sulfide (H2S) and (c) theoretically complete conversion of the H2S
to S in the Stretford process.
• All of the lime input to the process would remain with the treated
coal. The excess of lime is intended to reduce sodium entrapment
by the coal. The lime make-up rate, on a once-through basis is
14.5 metric tons (16 tons) per hour.
• Based on the Battelle intermediate material balance given in Figure
19, assuming 100% conversion of the sodium carbonate to sodium
hydroxide and no leachant purge required, recycle NaOH would be
supplied at the rate of 48.5 metric tons (53.5 tons) per hour,
including fresh material at the rate of 3.8 metric tons (4.2 tons)
per hour.
Battelle has supplied estimates of the heat and power consumption in
the major process steps shown in Figure 19. Table 40 is a tabulation of the
estimated values of the heat and power requirements of the BHCP.26
It can be noted from Table 40, that limestone calcination and drying of
the coal, make up 39% and 47%, respectively, of the heat consumption of
the process. These two process steps together, in effect, use about 24% of
tiie input coal heating value. There would be some economy in process heat
requirements, if hot flue gas from the calcination operation can be used
in the wet coal drying process.
Status of the Process
The original Battelle hydrothermal coal process has been under develop-
ment at the Columbus laboratories since 1960 under Battelle sponsorship.
The desulfurization step has been carried through pre-pilot level (continuous
128
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TABLE 40. ESTIMATED HEAT AND POWER CONSUMTPION CF THE
BATTELLE HYDFDTHERMAL COAL PROCESS
Heat Consumption [based on 360 metric tons (400 tons) per hour of coal
feed]
Process Step(s) Heat Consumption 106 kg cal/hr (106 BTU/hr)
Desulfurization 33 (131)
Evaporation of water 47 (187)
Leachant regeneration 20 (78)
Limestone calcination 272 (1,081)
Drying of coal* 330 (1,308)
TOTAL 702 (2,785)
Thermal Efficiency of Process [based on 6,900 kg cal/kg (12,500 BTU/lb) of
feed coal]
Coal heat input = 2,520 x 106 kg cal/hr (10,000 x 106 BTU/hr)
Process heat consumption = 702 x 106 kg cal/hr (2,785 x 106 BTU/hr)
Heat loss (solubilized coal) - 50 x 106 kg cal/hr (200 x 106 BTU/hr)**
Thermal efficiency (T.E.) = 70%
Power Consumption kwh/naetric ton
Power Conatmption (kwh/ton) coal feed
Desulfurization 6.8 (6.2)
Solid/liquid separation and washing 6.2 (5.6)
Calcination 18.4 (16.7)
Sulfur recovery plant (Stretford 21.2 (19.2)
Process)
Off-sites 1.3 (1.2)
TOTAL 53.9 (48.9)
* Based on drying the filtered, washed coal with an initial 45% moisture
to 5% moisture.
** Based on Battelle value of 5% loss of coal due to solubilization by
leachant and a Versar assunptian of 1,000 kg cal/hr (4,000 BTU/hr) for
average heat content of this material.
129
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bench-scale) laboratory investigations. In this effort, sulfur extraction
from approximately twenty different eastern and midwestern bituminous coals
have been studied. Battelle has published pyritic sulfur extraction data on
6 coals, organic sulfur extraction data on 6 coals, and overall sulfur
reduction data on 6 coals.27 In all of these studies, the S02 emission on
the BEEP treated coals was equal to or less than the EPA-NSPS of 2.16 kg/
106 kg cal (1.2 lb/106 BfTU) for coal-fired steam generators.
liquid/solid separation and regeneration of spent leachant are being
studied in bench-scale equipment in an dtter.pt to:
• establish definitive information as to whether the process can
operate in closed-loop fashion; and
• improve the economic viability of the process by reducing the cost
of these two high cost segments.
The EPA has funded a third area of interest in the BHCP: a conbustion
study on HECP treated coals (Contract No. 68-02-2119). This study was a
laboratory scale evaluation of BHCP treated coal conbustion characteristics.
This work was completed and reported in "Study of the Battelle Hydrothermal
Treatment of Coal Process", to IERL, REP, in November of 1976.
With respect to regeneration of spent leachant, experimental efforts
have concentrated on screening the use of zinc and iron compounds as
possible regenerants for spent leachant from the coal desulfurization step.
Results so far have not indicated significant process viability for either
of these two heavy metals as alkali regenerants. In the case of zinc, there
are indications of residual zinc build-up in the coal as well as environment-
al problems expected when zinc sulfide is roasted to regenerate the zinc
oxide. 3h the case of iron oxides, or hydroxides as possible regenerants,
there has been no notable success to date.
lb date, no experimental work has been attempted on optimization of the
solid, liquid separation treatment of the slurry from the desulfurization
step. A computer model has been developed in order to optimize (on paper)
the relationships between the parameters involved, including the method of
130
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separation (filtration, oentrifugaticn or thickening), the number of
separationArashing stages involved, the wash water/dry solids ratio, the
percent of water in the underf low coal and the amount of entrained sodium
in the coal. These parameters have all been related to the cost contribution
per ton of coal product. This study has shown that 9 countercurrent
filtration/washing stages at an overall wash water/dry solids ratio of 1.5
with a final solids level of 45% in the underflow (filter cake), gave the
lowest operating cost contribution per metric ton of product, i.e., $10.50/
metric ton ($9.50/ton). At a cost contribution of $10.50 metric ton
($9.50/ton) with nine filtraticnAashing stages and 45% solids in the
underflow, the lowest entrained sodium level was determined to be 0.0018,
i.e., about 1.8 kq entrained sodium per metric ton of dry solid (3.6 Ibs/ton).
Using a value of 0.005 metric ton of bound sodium in the treated
coal per metric ton of dry solid, the total sodium input to the process
(as 73% NaOH) would be about 0.016 metric ton per metric ton of dry product
coal, i.e., 16 kg/foetric ton (32 Ib/ton). With caustic at $176/metric ton
($160/ton), the sodium input represents about 27% of the total cost contri-
bution of the solid/liquid separation portion of the process. This caustic
input value is still subject to experimental verification.
In the preliminary combustion studies with two BHCP treated coals
under Contract No. 68-02-2119, the combustion characteristics of these coals
were determined in two test facilities at Battelle, a one-half kg/hr (one Ib/
hour) laboratory-scale furnace and a 10-40 kg (20-80 Ib) per hour multi-
fuel furnace facility. Tests in both units were conducted with dry,
pulverized BHCP treated coal. The results of these tests indicated that
the treated coals would meet the present U.S. EPA-NSPS for sulfur dioxide
emissions and that combustion of these coals proceeded as well or better
than the corresponding raw coals.28
The BHCP appears to have a significant effect on the trace elements
levels of the treated coals. Table 41, compares the concentrations of twelve
trace elements in raw coals and in the leached product for three Chio coals.27
Based on these results, there would be less trace metals emissions to be
expected from combustion of BHCP coals as compared to raw coals. Varying
quantities of the leached trace elements would be expected to precipitate
131
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TABLE 41. TRACE ELEMENT REDUCTION IN COALS TREATED
OJ
to
BY THE
Metal
Lithium
Beryllium
Boron
Phosphorus
Chlorine
Potassium
Vanadium
Arsenic
Molybdenum
Barium
Lead
ThoH urn
BATTELLE HXDROTHEKMAL
PROCESS
Concentration, ppm
Raw Coal
15
10
75
400
20
5000
40
25
20
25
20
3
Leached Product
3
3
4
80
2
200
2
2
5
4
5
0.5
Percent
Reduction
80
70
95
80
90
96
95
92
75
84
75
83
* Average value for 3 Ohio coals: CN719-Seam 6, HN658-Seam 6A, and
Jackson-Seam 4. Analyses were conducted by Battelle.
-------
with the solubilized coal in the sulfide stripping operation and then be
removed in the filter cake in the subsequent filtration operation.
Landfilling of this material could present some environmental problems.
A potentially serious problem indicated by the preliminary combustion
studies is the potential for slagging and fouling of furnaces due to the
high alkali content of the BHCP coals. Battelle has determined that the
critical level for sodium in utility coals is 0.5%. It appears that sodium
levels above 0.5% will make these coals unusable in dry-bottom furnaces due
to lowered ash melting temperature and resulting slag-forming tendencies.
Wet-bottom furnaces (slag-tapping type) may be adaptable to the high sodium
coals although the possibility of fouling of heat transfer surfaces due to
the formation of slag can occur in either type of furnace. Further combustion
studies are needed to investigate the potential severity of this problem
in prototype boiler units.
It should be noted that the function of the calcium hydroxide in the
mixed leachant is to displace the sodium which can combine with the coal
during the hydrothermal treatment. By the use of mixed leachant, Battelle
hopes to keep the ultimate sodium level in the treated coal to 0.5% or
below. However, a complicating factor is the presence of high ash levels in
oertain feed coals which seems to prevent the calcium oxide functioning as a
sodium replacement in the treated coal. An example of this is the treatment of
Martinka coal with the mixed leachant. This coal had a sodium level, after
treatment, of 1.96 weight percent, which is believed to be due to the
high ash content (20%) of the raw coal. The treatment of a lower ash
coal (10%) with mixed leachant resulted in residual sodium levels of as
low as 0.25 weight percent (Westland coal). Based on these results,
Battelle is suggesting the necessity of monitoring all incoming coals to
a BHCP plant so that suitable coal blending can be carried out to prevent
high ash levels in the coal feed to the process.
Technical Evaluation of the Process
One BHCP is one of the few chemical coal cleaning processes that has
made significant advances to a point permitting at least partial engineering
evaluation. Based on the information available, a technical evaluation of
tiie process follows.
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Potential for Sulfur Removed.—
Ohe ability of the process to remove sulfur is shown in the table below.27
PYRETIC SULFUR EXTRACTION BY THE BHCP
Percent Pyritic
Source of Coal
Mine
CN719
Belmont
NE41
Ken
Beach Bottom
Eagle 1
*Mnisture and
Seam
6
8
9
14
8
5
ash fine**
State
Ohio
Ohio
Ohio
JHy.
Pa.
111.
basis.
Sulfur*
Raw
Coal
4.0
1.6
4.0
2.1
1.7
1.5
Coal san
oa^r
Coal
0.1
0.1
0.1
0.2
0.1
0.2
cles were s
Extraction
Percent
99
92
99
92
95
87
urolied from the various
mines. Analyses were conducted by Battelle on raw and hydrothentially
treated coals.
Ninety percent or greater pyritic sulfur removal has been demonstrated on a
variety of bituminous coals from Ohio, Pennsylvania, Illinois and Kentucky.
It is believed that pyritic sulfur can be essentially completely removed
(95%) from any bituminous coal using the BHCP.
It is believed that the BHCP is capable of removing 25-50% of organic
sulfur from a wide variety of coals. The table below27 presents typical
organic sulfur extraction data from the BHCP.
EXTRACTION OF ORGMHC SULFUR BY THE BHCP
Percent Organic
Source
Mine
Sunny H111
Martinka f 1
Westland
Beach BuLLcui
Reign f 1
*Mni ai-nna an
of Coal
Seam
6
Lower
Kittaning
8
8
4A
r? ash ft-Be 1:
Sulfur*
State
Ohio
W. Va.
Pa.
W. Va.
Ohio
laois nnal
i«w
Coal
1.1
0.7
0.8
1.0
2.3
. sanoles
BHCP
Coal
0.6
0.5
0.5
0.7
1.1
3 were suppliei
Extraction
Efficiency,
Percent
41
24
38
30
52
1 from the various mar
All analyses were conducted by Battelle on raw and hydrothermally treated coals.
134
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Experiments have been conducted also on a semicontinuous bench-scale
to confirm the results of laboratory batch experiments. Die equipment has
a capacity of about 9 kilograms (20 pounds) of coal per hour and all of
the basic steps of the desulfurization process are included. Table 42
presents results of the continuous bench-scale experiments on two coals,
Martinka and Renton - a West Virginia and a Pennsylvania coal respectively,
along with similar data from laboratory batch operations. 2 9 These
experiments were not necessarily run under the same conditions, but it is
shows a comparison of desulfurized in the batch, bench-scale work compared
to similar conditions in a continuous operation. The operation, however,
has not yet employed recycled, regenerated reactants, so that the influence
en leaching due to buildup of contaminants in the system is unknown.
Sulfur By-Products —
In the conceptualized BHGP using lime-carbon dioxide regeneration of
the spent leachant, sulfur is removed from the process as hydrogen sulfide
which is then converted to elemental sulfur-using either the Glaus or
Stretford process (currently, Battelle prefers the Stretford process) .
Benefit Analysis —
The main benefit associated with the BHCP, is the demonstrated removal
of essentially all of the pyritic sulfur and a substantial portion (up to
50%) of the organic sulfur from a wide variety of bituminous coals.
benefits claimed for the process include the substantial removal
of trace metals from the coal.
The process may produce a coal having substantial problems in the coal
combustion process due to the increased sodium level in the BHCP treated
coal. Cry* "!«» with high sodium content increase the slagging tendency of
the ash and create ash removal problems in dry bottom boiler. Additionally,
high sodium levels in coal cause fouling of heat transfer surfaces in
all types of boilers.
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TABLE 42. CONTINUOUS BENCH-SCALE RESULTS FOR THE BA.TTELLE PROCESS
Sulfur Analysis, SO2 Equivalent,
wt % kg/10*kg cal
(lb/106 BTU)
Goal Source Raw BHCP
___ Raw BHCP
Mine Seam Coal Coal
1. Laboratory Scale
Martinka No. 1 Lower Kittanning 1.07 0.39 3.87(2.15) 1.57(0.87)
(W. Va.)
Rentcn Upper Freeport 1.32 0.52 4.36(2.42) 1.66(0.92)
(Pa.)
2. Continuous Bench-Scale Studies
Martinka No. 1 Lower Kittanning 2.77 0.76 7.20(4.00) 1.89(1.05)
(W. Va.)
Renton Upper Freeport 1.20 0.60 4.32(2.40) 1.42(0.79)
(Pa.)
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Environmental Aspects—
The BHCP is claimed to be essentially free of environmental problems
due to the "closed-loop" feature of the process. However, this assertion is
open to question due to the following factors:
• The feasibility of the closed-loop feature in a continuous process
is as yet undencnstrated. In limited batch-type evaluation of the
carbon dioxide/Lime regeneration process for the mixed leachant
(four conplete recycles of the regenerated mixed leachant were
carried out), there is a tendency for oxysulfur compound build-up
which inhibits the desulfurization ability of the recycled mixed
leachant. A fairly sizable purge stream may have to be
discharged from the system for disposal. This stream would contain
some dissolved organics and trace metals from the hydrothermally
treated coal. Additionally, pH adjustment of this stream prior
to disposal would create large quantities of dissolved salts.
Disposal of this stream could therefore pose environmental problems.
• In -die processing scheme proposed by Battelle, the ash solubilized
by the hydrothermal treatment would precipitate as a result of the
carbonation of the spent leachant (in the sulf ide stripping step).
The filtered ash would contain some precipitated metals and
insoluble inorganics and could pose environmental problems if
placed in ordinary landfills.
• Elemental sulfur recovery from the sulfide stripping operation will
be accomplished by treatment of the hydrogen sulfide in either a
daus or Stretford process. Tail-gas from the daus or Stretford
process will require scrubbing for sulfur dioxide or hydrogen
sulfide removal, respectively.
137
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• Conveying of the minus 200 mesh dry treated coal to either a
briquetting operation or intermediate storage, may create
particulate emissions problems (and possible spontaneous combustion
problems due to the pyrophoric nature of this material). Use of
baghouses, water sprays and cyclones may be necessary for
recovery of the sub-micron-size solids before venting the gases to
the atmosphere.
• In the closed-loop calcination of the precipitated calcium
carbonate to regenerate calcium oxide, the possibility of inpurity
buildup in the lime, i.e., heavy metals and ash components from
the coal, could require periodic purge of this material. Disposal
of the purged material could pose environmental problems.
Problem Areas—
The two overriding problem areas in the BHCP are:
• Demonstration of a technically and economically feasible closed-
Icop process by which the alkaline leachant may be regenerated
and recycled, has not yet been achieved.
• A value of 0.5 weight percent or less residual sodium in the
treated coal, in order to prevent slagging and fouling tendencies
of the ash during firing in utility furnaces, has not been achieved
for some coals.
Severe corrosion problems may occur in the desulfurization reaction
since alkalies at high temperatures >250°C (482T) in the presence
of water are notorious for initiating stress corrosion failures of
materials. Battelle has found only one material (Inconel 671 alloy),
which has shown the possibility of being able to withstand the desulfuri-
zation reaction conditions without undergoing relatively rapid failure.
However, this material has not been evaluated in any long-term production
cycle under actual reaction conditions (as part of a prototype vessel).
Inconel 671 reactors will be extremely costly.
138
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Preliminary indications are that f iltration of the mixed leachant
treated coal slurry is extremely slow, even at relatively coarse mesh
sizes (up to minus 20 mesh).
Nothing is really known at this time about the influence of the
buildup of contaminants in the leaching ability of the recycled mixed
leachant. Contaminants can interfere with the reactions involved in
the calcium oxide-carbon dioxide regeneration system thereby preventing
efficient recovery of the leachant. Laboratory-scale investigations
have only been able to affect 84% sulfur removal from the spent leachant
using carbonation-liming, even though Battelle believes that essentially
100% removal can be achieved.29 It should be noted that the lower
result was achieved in an oxygen-free atmosphere is essential in order
to obtain complete sulfur removal from the spent leachant, i.e., avoid
the formation of oxysulfur compounds which.are not reactive in the
carbonation step.
Goal loss due to solubility by the alkali leachant at elevated
temperatures, may be more severe in actual practice than is now anticipated.
R&D Efforts and Needs—
Based on a discussion with Battelle personnel and examination of
Battelle reports available to Versar on the BHCP, the following PSD efforts
and needs have been identified.
• Determine the conditions for sulfur removal during the leaching
step to enable optimization of: residence time; temperature;
particle size of coal; water to coal ratio; sulfur removal;
leachant concentration; leachant alternatives; and coal loss due
to solubilization by the leachant.
• Develop the best technology for separating the treated coal from
the spent leachant and for washing the coal free of sodium and
sulfur after treatment.
139
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• Study the effect of coal mesh size on water retention of mixed
leachant-treated coal.
• Determine the best trade-off between reaction conditions, reaction
systems, and post-treatment for consistently keeping the residual
sodium content in the treated coal to 0.5 percent or lower.
• Identify and demonstrate the best technology to regenerate the
spent leachant in a closed loop process.
• Determine in prototype reaction equipment the best materials of
construction for the critical steps of the process.
• Continue the studies on the effect of residual sodium levels in
treated coal on the slagging and fouling tendencies in boilers.
• Determine the fate of trace metals extracted from raw coal by the
EHCP, including possibilities for recovering these materials as a
highly enriched stream.
• Apply the BHCP technique to other types of coals including sub-
bituminous, lignite and bituminous coals with a high ratio of
organic to pyritic sulfur (55-60% organic, 45-50% pyritic), in
order to determine the applicability of the process to as wide a
variety of coals as possible.
No attempt has been made to prioritize the list presented above.
However, when completed, the present Battelle laboratory studies (EPA Contract
No. 68-02-2187) on spent leachant regeneration and solid-liquid separation
techniques should provide a definitive answer on the viability of the H**3*
as a closed-loop process.
Process Economics
Battelle has revised and updated an earlier cost estimate of their
conceptualized BHCP. The current estimate reflects the results of bench-
scale experiments carried out in order to bracket the range of variables
involved and at least establish the most likely methods to be used in the
closed-loop process.29
140
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A summary of BHCP eoonond.es is presented in Table 43. Details on
the capital oosts and operating costs are given in Tables 44 and 45
respectively. Versar has included the following modifications of the
Battelle estimate:
• An estimate of the cost of coal preparation including handling,
grinding and storage facilities.
• An estimate of the cost of product coal compaction,
handling and storage.
• Proration of the Battelle plant size of 363 metric tons (400 tons)
per hour to 300 metric tons (333 tons) per hour. The latter
capacity is equivalent to 7,256 metric tons (8,000 tons) per
day. A 0.6 exponential factor was used to adjust plant size.
• A 20% contingency factor was added to the Battelle capital cost.
• Variable operating costs were prorated based on the 7,256 metric
ton (8,000 tons) per day coal processing rate.
The auxiliaries and offsites are not shown in the conceptual process
flow diagram (Figure 18), but are included in the Battelle cost estimate.
The major item is silo storage for 20 days' production. Other significant
offsites included in the design are a steam plant and cooling towers. An
allowance has also been made for site preparation, buildings (offices,
maintenance shop, laboratory, change house, etc.), electrical distribution,
and offsite piping.
The Bechtel Corporation has a] BO prepared a cost estimate for BHCP8
using the same basic flowsheet and with the two plant capacities being roughly
equivalent. Battelle uses 360 metric tons (400 tons) per hour of raw coal
feed with a 90% operating factor, and Bechtel uses 300 metric tons (333 tons)
per hour of raw coal feed with a 100% operating factor. The Bechtel process
scheme features a more elaborate system of process heat recovery and heat
utilization than does the Battelle process and also omits the cost of
an evaporation system to concentrate the diluted spent caustic leachant
from the filtration/washing step. The Bechtel process flowsheet includes
141
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receiving, storage and grinding of the raw coal, plus compaction of the
dried treated minus 200 mesh ooal to permit handling and transportation
to a utility not located adjacent to the coal treatment plant.
A major difference in the approach used in the two operating cost estimates,
is the use of cleaned coal by Bechtel to provide heat input to the calcium
carbonate calcination operation, thereby reducing the net coal yield from
the process. Battelle uses raw coal as fuel in the calcium carbonate
calcination step since they believe that the sulfur dioxide generated would
be absorbed by the lime formed in the process. However, no estimate is
provided by Battelle of the purge rate required from the regenerated lime
stream, in order to control calcium sulfate build-up.
An analysis of the Bechtel data indicates that the annual operating
costs developed by Battelle and Bechtel for the BHCP are quite comparable
even though the Battelle capital cost is approximately 60% greater than
that of Bechtel. None of the major operating cost components show any
large differences between the two estimates. Both estimates reflect the
energy-intensive nature of the process, showing 25-35% of the operating
cost being accounted for by fuel cost. Caustic soda makeup cost could go
significantly higher in actual practice if the mijoed-leachant approach
fails to minimize sodium entrapment by the treated coal. Another unknown
factor which could add significantly to the BHCP operating cost, would be
the need for spent leachant purge, if this were required due to impurity
buildup in closed-loop operation. Battelle estimates that a 10 percent
purge would require an additional 0.016 metric ton of NaOB/metric ton
of coal processed, adding $2.82/toetric ton ($2.56/ton) of input coal
processed [$3.48/faetric ton ($3.16/ton) of equivalent heating value product
coal]. Additionally, spent leachant purge will probably incur appreciable
disposal costs.
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TABLE 43. SUMMARY CF ECONOMICS FOR THE BATTELLE
CHEMICAL COAL CLEANING PROCESS
Basis: 7,200 metric tons (8,000 tons) per day of 6,800 kg cal/kg
(12,300 MU/Lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
95% weight yield, 88% heating value recovery
Installed Capital Cost: $168,630,000
Annual Operating Costs
on Clean Coal Basis: $74,203,000 process .cost, excluding coal cost
$140,203,000 process cost, including coal cost*
$32.61/metric ton C$29.58/ton), excluding coal cost
$61.63/tetric ton ($55.90/ton), including coal cost*
$5.15A06 kg cal ($1.30/106 BTU), excluding coal cost
$9.74/10s kg cal ($2.45/106 BTO), including coal cost*
Coal costed at $27.60/netric ton ($25/ton)
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TABLE 44. INSTALLED CAPITAL COST ESTIMATE FOR THE BATTELLE
CHEMICAL COAL CLEANING PROCESS
$ 1977
Coal handling and preparation* $ 16,600,000
Desulfurization process costs^ 108,000,000
Ccnpacting and product handling* 5,120,000
Building and miscellaneous^ —
Utilities (off-sites}+ —
Site development and general' —
Subtotal $129,720,000
Engineering design @ 10% 12,970,000
Contingency @ 20% 25,940,000
Total Installed Plant Capital (TPC) $168,630,000
* Versar estimate.
A Battelle estimate for a grass roots plant including all off-site
requirements, scaled to 7,200 metric tons (8,000 tons) per day plant
size.
t Included in the grass roots plant cost under desulfurization process
cost.
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TABLE 45. ESTIMATED ANNUAL OPERATING COSTS FOR THE BATTELLE
CHEMICAL COAL CLEANING PROCESS
Airortizaticn 20 years @ 10% interest (factor = 0.1175) $ 19,814,000
Taxes @ 2% TPC 3,370,000
Insurance @ 1% TPC 1,680,000
Labor (direct, supervisory and additives) 2,100,000
General and administrative @ 1.5% TPC 2,530,000
Maintenance and supplies 10,000,000
Utilities:
Electric power 3,800,000
Water 300,000
Steam and fuel* 19,000,000
Chemicals:
Caustic soda 3,900,000
Lime 3,200,000
Binder 4,509,000
Waste Disposal ~~
Total Annual Processing Cost $ 74,203,000
Raw coal, 2.39 x 106 metric tons .(2.64 x 106 tons) 66,000,000
TOTAL ANNUAL COST $140,203,000
Additional raw coal is purchased to provide fuel needs for
carbonate calcining and drying. It has been assumed that the sulfur
dioxide generated vrould be absorbed by the line formed in the process.
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JPL CHEMICAL COAL CLEANIN3 PBOCESS
The Jet Propulsion Laboratory (JPL) , California Institute of Teohnol-
ogy, at Pasadena, California, is developing a chemical coal cleaning process
which attacks both pyritic and organic sulfur compounds in coal, and
allegedly results in the removal of up to 75% of the total sulfur in coal. 30
Both types of sulfur are attacked during a low temperature coal chlorinolysis
step, followed by hydrolysis and dechlorination.
Process Description
A flow diagram based on the JPL process is shown in Figure 20. 3 1
Chlorine gas is sparged into a suspension of moist, pulverized coal (minus
100 to minus 200 mesh) in methyl chloroform (1,1,1-trichloroethane) at
74 °C (165°F) and atmospheric pressure for 1 to 4 hours. The suspension
consists of approximately 1 part coal to two parts solvent. Chlorine (Cl?)
usage is 3 to 3.5 moles of chlorine per mole sulfur, or about 250 kg C12
per metric ton (500 Ibs/ton) of coal. Moisture is added to the feed coal
to the extent of 30-50% by weight.
After chlorination the coal slurry is distilled for solvent recovery,
and the solvent is recycled for reuse in the chlorinolysis step. The chlo-
rinated coal is then hydrolyzed with water at 50-70°C (120-150°F)for 2
hours, and then filtered and washed. The coal filter cake is simultaneously
dried and dechlorinated by heating at 300-500°C (570-930°F) with super-
heated steam (or possibly a vacuum) for about 1 hour.
There are a number of by-product streams which are as follows:
• Vented gas from the chlorinolysis reactors contains unreacted chlorine
(Cl,) and by-product hydrogen chloride (HC1) . The gas is cooled to condense
d-, which is recycled, and the relatively non-condensible HC1 gas is piped
to a Kel-Chlor process unit which converts the HC1 to
• Vapors from the solvent evaporation step are cooled to permit con-
densation and recycling of the methyl chloroform. The HC1 gas is piped to
a Kel-Chlor unit for conversion.
• Filtrates and wash water from the filtration of hydrolyzed coal contain
hydrochloric acid and sulfuric acid. The HC1 is driven off in a stripper and
146
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WATER•
SOLVENT RECYCLE
JL SOLVENT .
^\EVAP f
BINDER
~]
ROM COAL '
MAKEUP
HO
ACID .-••
CONCENTRATOR
MCI RECOVERY UNIT
B> PRODUCT
H,S04
FIGURE 20 JPL PROCESS FLOW SHEET
-------
recycled to a Kel-Chlor unit. Ohe residual dilute sulfur ic acid is con-
centrated to a saleable 91% sulfuric acid.
• Superheated steam exhausting from the dechlorination will also contain
HC1 gas which must be condensed as hydrochloric acid and recycled to a Kel-
Chlor unit for chlorine recovery.
The chemistry of this process is somewhat complex, but is hypothesized as
follows:30
. H+
R-S-R1 + Cl - Cl" j RSC1 + R'Cl (1)
where R and R1 represent hydrocarbon groups, and S stands for sulfur.
S-S Bond (Electrophilic cleavage) REACTION -
+ - H+
RS-SR1 + Cl -d •- RSC1 + R'SCl (2)
Sulfonyl chloride is oxidized to sulfonate or sulfate according to the
following reactions;
Cl,, H~0 HJD
RSC1 - - - =-— R302C1 - - - — RSOgH + HCl
RSC1 + 2d2 + 3H20 - ^RS03H + 5HC1 (3)
or
Cl,, H,0 i
RSC1 - = - =-— R30C1 - = - -SO. + RC1
a2,
3C12 + 41^0
+ 6Hd (4)
pyritic sulfur reactions are summarized as follows:
+ 2C1 - ^FeCl + SC1 (5)
2FeS + 7C12 - ^2FeCL3 + 4SC12 (6)
+ 10SC12 - -2FeCl3 + 7S2C12 (7)
S2C12 + 81^0 + 5C12 - -^804 + 12 HCl (FAST) (8)
148
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RH + S2C12 - — RS2CL + HC1 (SLCW) (9)
+ 7CL2 + BHjO - "~FfeC12 + 2R^°^ + 12Ha-
"These reactions are exothermic in nature and occur favorably at moderate
temperature. Hie overall chlorine requirement for conversion of organic
sulfur to sulfonate sulfur and sulfate sulfur are approximately 3 moles of
dj, and 4 moles of &_ respectively per mole of organic sulfur and 3.5 moles
of C12 per mole of inorganic sulfur." 3C
"In the presence of water and at a temperature (i.e./ > 50°C) higher
than room temperature, the S2C12 formed from FeS2 chlorination is readily
converted to Hd and I^SCX. At room temperature, without the
presence of adequate moisture content, this reaction is slow and S2C1_ may
react with organic compounds to form organo-sulfur compounds. Cn the other
hand in an organic solvent, at a slightly elevated temperature/ the rate of
chlorination of coal is slower than in aqueous media at room temperature.
Reaction in an organic solvent gives a greater degree of structural
loosening of coal and consequently may remove more organic sulfur with a
lesser degree of chlorination. Structural loosening of coal by the action
of the organic solvent will make chlorine more accessible to sulfur compounds.
High chlorine solubility in an organic solvent may also be advantageous
for desulfurizat ion . Moreover, an organic solvent may dissolve some of
the organo-sulfur compounds. Chlorination of the coal matrix is mainly
a substitution reaction and hydrogen chloride is evolved as a product. If
coal is chlorinated under mild conditions the chlorine can be completely
removed as hydrogen chloride by heating at 300-500 °C. Chlorination
at high temperature and pressure results in coal which is difficult to
dechlorinate. "
Chlorinated coal is hydrolyzedto give hydrochloric acid according
to the following reaction.
RC1 + BO - —RCH + HC1
where R represents a hydrocarbon group in coal.
The sulfur converted to sulfates or sulfonate is water soluble and is
leacbable by water washing at 60°C (140°F)with retention times up to 2 hours
in a stirred reactor.
149
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Dechlorination—
After hydrolysis, the coal is dechlorinated by heating in steam or an
inert gas atmosphere. This can be acoarplished easily because of chlorination
at low temperature. The possible reactions during dechlorination are:
in an inert gas atmosphere:
RH + R'Cl —RR1 + HC1 (11)
and
in steam atmosphere:
RCl(s) + H20(g) -ROH(s) + HCl(g) (12)
This reaction is endothermic and proceeds favorably at a moderately high
temperature [300-500°C (570-930°F)].
According to the literature,steam will assist pyritic sulfur removal.
Dechlorination in a steam atmosphere proceeds by substitution of -d in
chlorinated coal by -OH and possibly -H groups from ILO. "No loss of hating
value is experienced for the processed coal when dechlorinated in a steam
atmosphere."30
Status of the Process
As of mid-July, 1977, effort on this process was on a laboratory scale
batch operation using 100 g. coal samples. It was expected at that time that
larger scale (1 kg) batch runs would be initiated in the near future, and at
a still later date, a 1 kg/hour mini-pilot plant would be constructed and
operated.
The early stages of the process research work were supported by the
National Aeronautics and Space Administration (NASA) under Contract No.
NAS 7-100. Recently the project obtained support from the Bureau of Mines
for a period of approximately 16 months. The new contract requires that
specific rraig be evaluated under the sponsored program. The nine coals
selected are given in Table 46.
150
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TABLE 46. PROPERTIES OP NINE SELECTED COALS
PROCESS EXPERIMENTS*
ERDA
PSOC NO.
108
219
190
276
026
342
240A1
097
086
FOR THE JPL
SULPHUR FORMS
SEAM, COUNTY & STATE
Pittsburgh, Washington,
Pennsylvania
Kentucky #4, Hopkins,
Kentucky
Illinois 16, Khox,
Illinois
Ohio #8, Harrison,
Ohio
Illinois #6, Saline,
Illinois
Clarion, Jefferson,
Pennsylvania
Big D, Lewis,
Washington
Seam 80, Carbon,
Wyoming
Zap, Meroer,
N. Dakota
RANK
HVA
(Bit.)
HVA
HVA
HVA
HVC
HVA
Subbit.B
Subbit.A
Lignite
ORGANIC
1.07
1.08
1.90
1.73
2.08
1.39
1.75
0.84
0.63
PYRTETC
2.06
1.40
1.05
1.34
4.23
5.01
1.60
0.38
0.56
TOTAL
3.13
2.56
3.05
3.07
6.66
6.55
3.36
1.23
1.22
* This table was obtained from JPL
151
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Technical Evaluation of Process
Potential for Sulfur Removal—
The process claims a 97-98% weight recovery of input coal, with
about a 2% loss in heating value, and 70-75% removal of total sulfur. Two
high sulfur coals have been examined carefully for sulfur removal. The
Illinois No. 5 high volatile bituminous coal from Hillsboro mine had 4.77%
total sulfur content. The other high volatile bituminous coal was a
Kentucky No. 9 coal from Hamilton, Kentucky. Proximate analyses of these
two coals are given in Appendix VI .
Experimental data obtained with Illinois No. 5 (Hillsboro) coal is pre-
sented below.
JPL PROCESS: PRELIMINARY CHLORINOLYSIS DATA FOR ILLINOIS
NO. 5 COAL DESULFURIZAT10N *
Raw Coal Treated Coal Sulfur Removal
Sulfur Form (% Sulfur)<{) (% Sulfur) (%)
Pyritic 1.89 0.43 77f
Organic 2.38 0.72 70
Sulfate 0.50 0.35 100A
Total 4.77 1.50 76
* (Chlorination - stirred reactor, 74°C(165°F), 1 atm (14.8 psig), 1 hour,
powdered coal 100-150 mesh witii 50% water, methyl chloroform to coal
2/1; hydrolysis and water wash - stirred reactor, 60°C(140°F), 2 hours,
excess water).
* Analyses by Galbraith laboratories, Inc., Rnoxville, Tennessee
Additional water washing should remove 100% of sulfate
Up to 90% pyritic sulfur removal has been achieved in other conditions
The overall sulfur removal is 76% with a reduction from 4.77%
to 1.50%. Results of experiments with this coal indicate that
removals up to 70% organic sulfur, 90% pyritic sulfur and 76% total sulfur
have been achieved.
152
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The kinetic data for chlorination and desulfurization of minus 100 mesh,
Illinois No. 5 coal are presented in Figure 21.31 The initial rate of
chlorination is very fast. The chlorine content in coal is 23% in half an
hour and then slowly increases to 26% within the next one and a half hours.
Within the initial half an hour period most of the pyritic sulfur and a
portion of organic sulfur are converted to sulfate sulfur. In the next
one and a half hour period pyritic and organic sulfurs are slowly converted
to sulfate sulfur. Based on the sulfur balance, the gain in sulfate sulfur
is equal to the combined reduction of pyritic and organic sulfurs. The
above reactions extend to the hydrolysis period. The overall sulfate
compounds produced either directly or indirectly through sulfonate are
removed from coal in the hydrolysis step as indicated by the analysis of
hydrolysis solution.
Experimental data obtained from a run on minus 200 mesh Kentucky No. 9
(Bamilton, Ky.) coal is given below.
PHFT.TMTTJABV CHDQRINDLYSIS DMA FOR THE JPL DESULFURIZATION
PROCESS ON BIHMENOUS GOAL (HAMZLTCN, KENTUCKY) *
Raw Coal Treated Coal
Sulfur Form (% Sulfur)A (% Sulfur)A Sulfur Removal (%)
Pyritic 0.08 0.03 62.5
Organic 2.67 1.16 56.5
Sulfate 0.15 0.29 100f
Total 2.90 1.48 59.0
* Chlorination - stirred reactor, 74°C(165°F), 1 atm (14.8 peig), up to 4
hours, minus 200 mesh coal with 30% water, methyl chloroform to coal 2/1;
hydrolysis and water wash - stirred reactor, 60°C (140°F), 2 hours,
excess water.
Analyses by Galbraith laboratories, Knoxville, Tennessee
100% sulfate removal by added water wash.
The sulfur content of this coal is predominately organic (>90%). About
57% of the organic sulfur, and 59% of the total sulfur, are removed.
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ORGANIC AND PYRITIC SULFUR
TIME, hr
FIGURE 21 JPL PROCESS: PERCENT SULFUR AND CHLORINE IN COAL
VS. TIME OF CHLORINATION
-------
The data en the above two ooals is the only detailed experimental results
available at this time. Based on these results and discussions with JPL pro-
ject personnel, it is concluded that the removal of pyritic sulfur by the JPL
process is somewhat more complete than removal of organic sulfur. Consequent-
ly, if a high percentage of total sulfur removal is desired, the ooal should
be rich in pyritic sulfur rather than in organic sulfur. Neither product from
the two above experiments will meet EPA-NSPS SO2 emissions of 2.16 kg/106 kg cal
(1.2 Ib SOa/106 HRJ) when burned. A more accurate assessment of the sulfur
removing potential of this process must therefore await results from the 9
coals to be tested under the Bureau of Mines contract.
Sulfur By-Products—
All sulfur removed from coal by the JPL process is converted to sulfate
ion (SO2=), and as presently conceived, this sulfur species will be retained
in aqueous solution as sulfuric acid, concentrated to about 91% and sold. However,
analysis of the JPL process scheme indicates that trace metals extracted
from the coal will exit the system with the by-product acid. Therefore, it
is doubtful that the impure sulfuric acid by-product can be sold without
some prior clean-up.
Environmental Aspects—
There appear to be several severe potential environmental problems
associated with this process. The hydrocarbon solvent used for the chlorinoly-
sis reaction is 1,1,1-trichloroethane which has been listed by the EPA as
a priority pollutant. Most of the substances on the list of priority
pollutants are suspected carcinogens. The release of even small quantities
of this material to the environment will probably be prohibited from a new
source processing plant. Vent gases from the chlorinolysis reactors contain
chlorine and by-product hydrogen chloride. Although these will presumably
be sent to the Kel-Chlor process unit there is a potential for release of
gases from this process unit. Filtrate from the hydrolysis unit will
contain hydrochloric add, sulfuric acid and probably chlorinated hydrocarbons
and organic sulfonates. This filtrate will be concentrated in a sulfuric
acid concentration step which will probably require a bleed stream to
remove impurities from the concentrated sulfuric acid product. The disposal
155
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of this bleed stream will present seme environmental problems. Also there
may be sane environmental problems associated with the operation of the Kel-
Chlor Chlorine recovery process.
Benefit Analysis—
The JPL chemical coal cleaning process provides a number of advantages
which include: a significant degree of sulfur removal, including organic
sulfur removal; removal of a number of trace metals contained in the original
coal which would otherwise result in undesirable emissions to the atmosphere;
and a product coal that is useful for direct combustion or for gasification
operations since the treated coal is alleged to be non-caking and non-swelling.
Data relating to the degree of removal of trace metals in JPL process-
treated-coal is given in the following Table.31
JPL PROCESS RESULTS ON TRACE METAL REMOVAL FROM COAL*
Original Coal ' Treated Goal
Elements (ppm) (ppm)
As 21
Hg 0.6 <0.5
Ti 476 460
Pb 18 4
Va 15 <1
P 736 126
Se <1 <1
Li 93
Be 31
Ba 38 30
* A high sulfur bituminous coal with 11% ash, from Hillsboro, Illinois
chlorinated at 74°C (165°F) and atmospheric pressure for 1 hour, followed
by aqueous leaching at 60°C (140°F) and atmospheric pressure for 2 hours.
A Chemical analyses were conducted by the Galbraith Lab., Inc.,
Khoxville, Tennessee.
156
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Although the JPL process is based on chlorination and dechlorinatlon
of coal, the product coal contains no more than, or even less chlorine than
the elemental chlorine in the raw coal. Data demonstrating this is given
in the following table.
JPL PROCESS PRELIMINARY DECHLORINATION DATA. (HILLSBORD,
ILLINOIS BITUMINOUS COAL)
Coal
Raw
Chlorinated coal
(after hydrolysis)
Qechlorinated coal
3echlorinated coal
)echlorinated coal
Dechlorination
Temp
°C (*F)
-
-
450 (840)
500 (930)
550(1,020)
Time
(Hrs)
-
-
1
1
1
Atmosphere
-
-
Steam
Vacuum
Vacuum
Elemental Chlorine
(wt.%)
0.14
11.0
0.064
0.15-0.30
0.06
The dechlorination can be accomplished by either superheated steam treat-
ment or by imposing a vacuum. The former step appears to be the one of
choice, and it serves an important secondary function of drying the coal.
Problem areas—There are a number of real and potential problem areas
which can adversely affect the technical and economic feasibility of the
process. Some of these problem areas are as follows:
• Chlorine, hydrogen chloride (gas), hydrochloric acid, and sulfuric
acid (dilute and concentrated) are all utilized or produced by the
JPL process. All are highly acidic and corrosive in nature and
will require special, and therefore expensive, materials of
construction. In several steps of the process two of these
chemicals coexist. For example, the vent gases from the chlorina-
tion step and from the subsequent distillation step will probably
157
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contain hydrogen chloride and chlorine, plus some methyl chloroform
solvent vapor. The wastewater from the ooal filtration step after
hydrolysis, contains hydrochloric acid, sulfuric acid plus chlorinat-
ed hydrocarbons and organic sulfonates. The exhaust steam from the
deohlorination step [carried out at 300° - 500°C (570° - 930°F)],
contains hydrogen chloride, and may present a very severe corrosion
problem.
• The JPL process as presently conceived recovers all sulfur
removed from the coal as sulfuric acid. It appears that an trace
metals removed from the coal will remain with this acid, and tend
to make this by-product relatively unmarketable.
• A key factor in the economic feasibility of the JPL process is
the cost of chlorine. JPL has estimated the usage of chlorine
to be about 250 kg/metric ton (500 Ibs/ton) of coal (dry basis).
The exact requirement for chlorine will largely depend on the
sulfur content of a given ooal. Purchase of chlorine for usage
on a once through basis is out of the question, since this
commodity presently sells for $150-$165/metric ton ($135-$150/ton).
At these prices, the cost of chlorine alone would be about $39/
metric ton ($35/ton) of feed coal.
Furthermore, there would be equivalent large quantities of by-
product hydrogen chloride to be stored and disposed of. There are two
major processes for conversion of hydrogen chloride to chlorine. The
"Uhde" process converts hydrochloric acid to chlorine by an electrolytic
process, which is electrical energy intensive. The "Kel-Chlor" process
of Pullman Kellogg Div. of Pullman, Inc. is believed to be less energy
intensive and it is used by DuPont in one commercial installation on
the Gulf Coast of Texas. JPL contemplates incorporating a Kel-Chlor unit
in their system and has included a "Kel-Chlor" unit in their rough flow-
sheet.
The cost of producing chlorine by the "Kel-Chlorn process varies with
a number of factors, including:
158
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• whether the hydrogen chloride is available as a dry gas (preferable)
or as a dilute solution.
• the purity of the delivered chlorine (oxygen being the main inpurity
likely).
• whether gaseous or liquified chlorine product is required.
Not all of the conditions inposed on a "Kel-Chlor" facility by the JPL
process can be defined at this time. Nevertheless, a rough figure of
$38.60/taetric ton ($35/ton) of "Kel-Chlor" chlorine has been used in
costing the JPL process. This price of $38.60Aetric ton of chlorine
includes all manufacturing costs, fixed costs including depreciation and
interest, and assume a source of hydrogen chloride at no cost.32 At a
rate of 250 kg Cl2/tetric ton (500 3b/ton) of coal this will add about
$10/toetric ton ($9/ton) of coal before any other cost item is considered.
R&D Efforts and Needs—
The process research program at JPL appears well-geared to the needs
of the process. Many of the basic parameters of the process appear to be
well established. The present contractual requirement to test sulfur removal
on nine additional coals, inclining two sub-bituminous coals and one lignite
is highly desirable. This work will determine the applicability to the
process to the various coal reserves in the U.S. There are, however, a
few important areas of research and development which require further
investigation. These are:
• The trace metals removed from the coal will probably be difficult
to concentrate and dispose of. At present, it appears that these
elements will end up in the concentrated sulfuric acid, and their
presence may render the acid unmarketable. Research effort is
therefore necessary to determine the extent of acid contaminaticn
and its marketability. Effort may be required to find means for
removing the trace element from the acid or from its' precursor,
the coal filtrate. As a last resort it may be necessary to lime
the acid by-product and produce a gypsum which would be dewatered
159
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and land-disposed. This would result in additional costs not
presently considered.
• A cursory investigation of the "Kel-Chlor" process shows that
product chlorine can be furnished in gaseous form, at various
pressures, or as a liquid under pressure. If the chlorine is
furnished as a gas without prior pressurization and distillation
it will be less costly but will contain 7-8%, by volume, of oxygen.
Feeding an impure chlorine as this to the chlorinolysis reactor
may have unpredictable consequences. Therefore, the technical and
economic alternatives concerning the purity of the recycled chlorine,
will probably require experimental verification.
• Most of the JPL effort has been based on finely divided coal
(minus 100 to minus 200 mesh feed). If the process is nearly as
efficient on a larger coal particles, say minus 14 or minus 28
mesh, additional benefits would be derived from decreased coal
preparation costs. Kinetic studies on onals of various size
consists are desirable therefore to establish minimum coal
preparation requirements.
• Due to the highly corrosive nature of hydrochloric acid, sulfuric
acid, chlorine, hydrogen chloride, and various mixtures of these
reagents, it is strongly reccnroended that both engineering and
laboratory effort be directed toward selection of materials of
construction for equipment used in each process step, and for the
connecting piping, controls and instrumentation.
Process Economics
Capital and annual operating costs have been developed for the JPL
chemical coal cleaning process, and are presented in Tables 47, 48 and
49. Both sets of cost data are based, in part, on cost data furnished
by JPL. However, changes have been made in the JPL data to produce
cost data which is comparable to that produced for other chemical coal
cleaning processes studied. Changes made are as follows
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• At the present time JPL is using minus 100 to minus 200 mesh coal
as feed to their process. Accordingly, capital estimates for
receiving ROM ooal, crushing, grinding and handling minus
200 mesh coal have been used. In time, if a coal feed stock of
plus 100 mesh, or minus 14 mesh, can be efficiently utilized
by the process, these costs can be greatly decreased.
• The JPL capital investment costs do not include product coal
compaction costs. Some additional capital and operating costs
have therefore been added.
• JPL depreciates their plant over a period of 15 years, but does
not include the cost of capital. A capital recovery factor based
on a 20-year plant life, paying 10% for the cost for the capital
has been used.
• The capital and particularly the operating costs for a "Rel-Chlor"
plant are greater than the costs used by JPL. Accordingly, recent
data from Pullman-Kellogg has been used.32
• Costs associated with the use of superheated steam to dechlorinate
and dry coal have been underestimated by JPL since the steam usage is
not known. However, since the TFW process uses almost 500 kg of
superheated steam per metric ton (1,000 Ibs/ton) of coal to
sublimate free elemental sulfur from its product, the same value
of superheated steam consumption for the JPL process has been used.
Assuming that product coal will be used to generate this steam,
and further assuming an 85% combustion efficiency and a 6,800
kg calAg (12,300 KTU/lb) coal, it is estimated that 470 metric
ton ( 520 tons) per day of product will be consumed internally for
this purpose. Further, assuming a 2% loss in ooal heating value
due to processing, the thermal (BTO) efficiency of the process is
approximately 91%.
161
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TABLE 47. SUMARY CF BCONCMICS FOR THE JPL CHEMICAL
COAL CLEANING PROCESS
Basis: 7,200 metric tons (8,000 tons) per day of 6,800 kg cal/kg
(12,300 BTU/lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
91% weight yield, 91% heating value recovery
Installed Capital Cost: $103,200,000
Annual Operating Costs
on Clean Coal Basis: $44,410,000 process cost, excluding coal cost
$110,410,000 process cost, including coal cost*
$20.38/metric ton C$18.49/ton), excluding coal cost
$50.67/metric ton C$45.97 /ton), including coal cost*
$2.97/106 kg cal ($0.75/106 BTU), excluding coal cost
$7.40/106 Kg cal ($1.86/106 BTU), including coal cost*
* Coal costed at $27.60/tastric ton ($25/ton)
162
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TABLE 48. INSTALLED CAPITAL COST ESTIMATE FOR THE JPL
CHEMICAL COAL CLEANING PROCESS
$ 1977
Coal handling and preparation* $ 16,600,000
Desulfurization process costs^ 12/290,000
Compacting and product handling* 5,120,000
Building and miscellaneous
Utilities (off-sites) ^
Kel-Chlor'" 45,375,000
Site development and general^
Subtotal $ 79,385,000
Engineering design @ 10% 7,938,000
Contingency § 20% 15,877,000
Total Installed Plant Capital (TPC) $103,200,000
* Versar estimate, installed cost
A JPL grass roots estimate including site development
t Battery limits plus grass roots requirements not otherwise furnished;
based on Pullraan-Kellogg estimate
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TABLE 49. ESTIMATED ANNUAL OPERATING COSTS FOR THE JPL
CHEMICAL COAL CLEANING PROCESS
Amortization 20 years @ 10% interest (factor = 0.1175)* $ 7,274,000
Taxes @ 2% TPC^ 884,000
Insurance @ 1% TPCT 442,000
Labor (direct and indirect) 2,200,000
General and administrative @ 1.5% TPC 1,500,000
Maintenance and supplies @ 5% TPCr 2,210,000
Utilities:
Electric power 1,200,000
Water. 100,000
Steam
Chemicals:
a
Chlorine 23,000,000
Miscellaneous chemicals 1,300,000
Binder 4,300,000
Waste Disposal —
Total Annual Processing Cost $ 44,410,000
Raw coal, 2.39 x 106 metric tons (2.64 x 106 tons) 66,000,000
TOTAL ANNUAL COST $110,410,000
* 30% of Kel-Chlor facilities; 100% others.
Excluding Kel-Chlor.
470 metric ton/day product coal will be consumed internally to
generate steam.
a Kel-Chlor process, including chemicals, depreciation, utilities, labor,
maintenance and interest on construction costs of 70% of capital.
164
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INSTITUTE OF GAS TECHNOLOGY (ICT) CHEMICAL COAL CLEANING PROCESS
The IGT flash desulfurization process is based upon chemical and thermal
treatment of coal. In this process, sulfur is removed from the coal by a
hydrogen treatment under the proper conditions of temperature, heat-up rate,
residence time, coal size, hydrogen partial pressure and treatment gas can-
position.
An oxidative pretreatnent is included in this system to prevent caking
and also to increase the sulfur removal in the subsequent hydrotreating step.
Both pyritic and organic sulfur are removed by the combination of these treat-
ments. The treated product is a solid fuel (possibly char) which presumably
may be burned without a need for flue gas scrubbing.
This report contains a conceptualized process design and process
economics based upon IGT data. Subsequent to our cut-off date for data
input, IGT has developed its own conceptualized process design that includes
the effects of many factors derived from IGT's general background in coal
conversion. The IGT-developed process efficiencies and costs are signifi-
cantly better than those reported here, based upon the earlier IGT report
specific to this program. The following discussion, therefore, does not
include IGT's latest thinking on the process design; it should be regarded
as preliminary and subject to significant process efficiency improvements and
downward product cost modification.
Process Description
The process employs essentially atmospheric pressure and high tempera-
tures labout 400°C (750°F) for pretreatment and 800°C (1500°F) for hydrode-
sulfurization] to enhance the desulfurlzation of the coals. These high tempera-
tures cause considerable coal loss due to oxidation, hydrocarbon volatiliza-
tion and coal gasification, with subsequent loss of heating value. Batch
reactor tests have indicated an average product recovery potential of 60 weight
percent based on the feed.
165
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Experiments have been conducted with several coals in both laboratory and
bench scale batch hardware to test IGT concepts and to determine the pretreat-
ment and hydrodesulfurization operating conditions. Adequate experimental
data on heat and material balances are not yet available to conceptualize a
process design. It is, however, anticipated that the process will employ the
following equipment or processing steps:
• Fluidi zed bed reactors will be used for both pretreatment and
hydrodesulfurization stages;
• Air will be used as the source of oxygen;
• Off-gases from the hydrodesulfurization/ provided they contain
hydrogen partial pressure, would be compressed and recycled to
the hydrogeneration reactor to provide the necessary hydrogen
for desulfurization of coal.
• Hydrogen make-up may be necessary to maintain hydrogen partial
pressure.
• The exothermic pretreatment reaction would provide a portion
of the heat necessary for the endothermic hydrodesulfurization
reactions.
• The sulfide and sulfate sulfur would be removed from the hydro-
desulfurized product by either chemical or mechanical means.
This step will be necessary when the coal char product from the
processing of certain coals contains residual sulfur levels
exceeding the allowable limits.
• The hydrogen sulfide/carbon dioxide gases recovered from the
hydrodesulfurizer off-gas will be treated in a Glaus plant to
produce elemental sulfur.
• Purification of the off-gas from the hydrodesulfurizer system
will be necessary prior to recycle.
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• Off-gas clean-up from the pretreater will be necessary prior to
venting the gases to the atmosphere.
Versar has provided a suggested process flow sheet which integrates the
IGT concepts and is shown in Figure 22. This flow sheet has been provided to
permit the development of process economics on a consistent basis with other
processes.
Status of the Process
The IGT process is in an early stage of development. An extensive bench
scale and pilot level technical effort is needed before an integrated process
design is conceptualized. The program, sponsored by EPA, is now directed to-
ward testing in a 25 cm (10-inch) continuous fluidized-bed unit, which is sized
for coal feeds of 10 to 45 kilograms (25 to 100 pounds) per hour.
Two pretreatment runs of about seven hours each have been made in this 25 cm
(LO-inch )unit. A beneficiated Illinois No. 6 coal, which was crushed to minus
14 mesh and contained 2.43 weight percent of total sulfur, was used as feed.
The objectives of these runs were to test the operating conditions over a
sustained period of time and to produce pretreated material for subsequent
hydrodesulfurization evaluations. The pretreatment runs have been successful
and they have confirmed most of the results of corresponding batch tests.
These runs indicated that a temperature of 400°C (750°F), a residence time of
30 minutes, an actual gas velocity of 0.3 meter (one foot) per second in the
bed and 0.616 cubic meter of oxygen per kilogram [ one standard cubic foot
(SCF) per pound ] of coal is adequate to pretreat the coal when the unit is
fed at a rate of about 23 kilograms (50 pounds) per hour. However, material
and heat balance information generated on one of these runs, contradicts con-
clusions derived from the batch runs. The analyses of data indicated very low
quantities of light hydrocarbon in the off-gases [90 kg cal/cu m(10 BTO/SCF) ]
and a very high solids recovery around the pretreatment unit (97.7 wt%). Thus
only 2.3 wt % of the coal was consumed in off-gases and water as compared to
the expected 8 to 12 percent. Information from a single run is not adequate
167
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VENT
HjO-
KRUB8ER
Lmuon
\
MAKEUP H2
OFF•QAS
SCRUBBER
COOLER
FLU1DIZED BED
PRETREATER
N^,
OS
00
ROM COAL
HEAT
EXCHANGER
KRETREATED
CRUSHED
COAL
\ r
WASTE HjO WASTE SOLIDS
HEAT
EXCHANGER
n
tTEAM
I " HVDRI
W xEXTRA
STEAM
HVDRODESULFURIZER
EXTRACTOR
WASHHjO
i
CAUSTIC
MAKE-UP *
CAUSTIC
ELEMENTAL
SULFUR
PLANT
ELEMENTAL
SULFUR
VENT
CLEAN CHAR
PRODUCT
OYPSUM
FIGURE 22 IQT PROCESS FLOW SHEET
-------
to draw definitive conclusions, however, if these data are confirmed in the
Pilot Demonstration Unit (PDU), then no excess heat would be available from
the pretreatment stage for either steam generation or on-site consumption.
The data from the larger unit will be used to establish the necessary
energy and material balance information for the design of an integrated system
and for an accurate economic evaluation of the process.
Supportive runs are being continued in the batch reactor to determine the
effects of nitrogen, carbon monoxide, water vapor and hydrogen sulfide con-
centrations in the treat gas on the hydrodesulfurization operation. Addition-
ally, crushing tests on a run-of-mine, Illinois No. 6 coal are being conducted
to determine the crusher conditions to minimize fines in coal preparation and
to define the coal preparation requirements for the process.
IGT estimates that this process could be ready for commercialization in
four or five years after the successful operation of a pilot demonstration unit.
Technical Evaluation of the Process
This process is currently at the bench scale level, thus, a definitive
assessment of its industrial potential is not possible at this time. However,
available information is sunmarized in the following subsections.
Potential for Sulfur Removal—
Laboratory and bench scale experiments conducted thus far indicate that
the IGT process can remove 83 to 89 percent of the total sulfur from four
bituminous feed coals. The process removes both pyritic and organic sulfur.
In most cases, enough sulfur is removed so that the treated product could be
burned in oonformance with current EPA new source performance standards for
SOz emissions.
A preliminary evaluation of the desulfurization potential of four select-
ed bituminous coals was conducted in a laboratory device (thezmobalance) with
169
-------
2 to 6 gram coal samples. Pyritic, organic and total sulfur removal rates ob-
tained from these investigations are reported in Table 50! 'Detailed laboratory
information reported by IGT is included in Appendix VII. Samples for the above
thermobalance tests were +40 mesh pretreated coal. The feed was placed in
the sample basket and then lowered into the treating zone. A heating rate of
2.8°C(5°F) per minute was used up to the terminal temperature of 815°C (1500°
F). Soaking time at the terminal temperature was 30 minutes for each test.
Table 50 indicates that for the Western Kentucky No. 9 coal, in addition
to 98 percent pyritic sulfur removal, 88 percent of oroanic sulfur removal
was also achieved. Sufficient total sulfur removal was realized in this test
so that S02 emissions from combustion of the treated product would be 0.76 kg/
106kg cal (0.42 lb/106 BTU).
The sulfur reduction obtained for the Pittsburgh seam coal from the West
Virginia mine was 98 percent pyritic and 83 percent organic sulfur. The re-
duction in total sulfur content, accounting for sulfide/sulfate compounds,
was 83 percent, with sufficient sulfur removed to comply with current EPA
new source performance standard of 2.16 kg/10' kg cal (1.2 lb/106 BTU) of SO2.
Results for the Pittsburgh seam coal from the Pennsylvania mine indicate
that in addition to all of the pyritic sulfur, 77 percent of the organic
sulfur was also removed. This coal having a lower initial total sulfur and
relatively low initial organic sulfur content also yielded a product with
acceptable SO2 emission value.
The sulfur reduction obtained for a beneficiated Illinois No. 6 coal was
98 percent pyritic and 82 percent organic sulfur. This sulfur reduction was
such that SO2 emissions from combustion of the treated product would be
below the current new source SOz standards.
The results of all thermobalance tests conducted with the above mentioned
four feeds are superimposed in Figure 23.3* These experiments were con-
ducted using varying heat-up rates of 2.8 to 11 °C (5 to 20°F) per minute up
to temperatures of 538° to 815°C (1000° to 1500°F) and soaking times at the
terminal temperature from a few minutes to 5.5 hours. The plot indicates that
all coals behaved similarly and that higher temperatures (about 815 °C) are
needed to achieve adequate hydrodesulfurization.
170
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TABLE 50. IGT PROCESS THERMOBALANCE SULFUR REMOVAL RESULTS
Raw Goal
Characteristics
Source of
Coal
Western Ky #9
Pittsburgh Seam From
W. Virginia
Pittsburgh Seam From
Pa. Mine
Illinois #6
Feed
Type
ROM
Highly
Caking
High Ash
ntent
Sulfur*
Content wt.%
of Feed
(dry basis)
3.03
2.41
1.01
2.28
Sulfur Removal
Efficiency,
Weight Percent
Pyritic Organic
97.8
98.4
88.5
Total
89.4
83.1 83.0
100.0 77.1 78.1
98.0 82.0 87.7
NOTES:
Experimental Conditions Were: At 1500°F terminal temperature,
5°F heat-up rates and 30 mlns. soaking time.
* Sulfur content of +40 mesh material.
The pyritic sulfur removal during pretreatment ranges
from 38% to 51%.
The organic sulfur removal during pretreatment ranges
from 0% to 10%.
171
-------
o
u
s
-------
Batch reactor evaluations have been made using the Western Kentucky No. 9
and Illinois No. 6 coals to verify the thermobalance test results. This re-
actor operates as a fluidized bed, similar to the mode of operation anticipat-
ed for the commercial plant. The unit is capable of handling larger samples
(75 to 150 grams); therefore, a more complete characterization of the treated
product was achieved. Table 518
-------
TABLE 51. IGT PROCESS TOPICAL BATCH REACTOR RUNS WITH SPECIFIED FEEDSTOCKS
Run Ma.
Goal type
Sanple
fenoinal Vaqperature, *F
Ileat-Up Rate, *P/tain.
Soaking Tine, min.
Sulfur, wt.%
Sulfida
Sulfate
Pyritic
Organic
Total
Itotal Sulfur Removal, wt.%
Yield, wt.% (Fran Feed Goal)
Heating Value, BHU/lb.
Sulfur Bniaalon, Ib/lO'BTU
RB-76-3
Run-of Mine H. Ky. 19
Peed
0.02
0.60
1.06
1.82
3.50*
-
12,454
5.62
Pretreated
Goal
750
30
0.04
0.10
1.54
1.38
3.06*
20.6
90.8%
11,809
5.18
Product
1,500
5
30
0.12
0.00
0.02
0.37
0.51
90.9
62.2%
11,967
0.85
BR-76-34
Hashed 111. 16
Pre treated
Feed Pool
750
30
0.01 0.01
0.13 0.04
0.84 0.65
1.50 1.52
2.48* 2.22*
19.1
90.4%
13,022 12,915
3.76 3.44
Product
1,500
5
30
0.05
0.05
0.03
0.47
0.60
84.7
62.9%
12,793
0.94
•Cajtaulatad *oc -HO ttosh fraction.
-------
0 -A RAW COAL
10 -
20
30-
40-
50-
60-
VI
70-
80-
90-
100-
PRETREATED COAL (total wlfur)
PRETREATEO COAL (orgmic wlfur)
ORGANIC SULFUR
TOTAL SULFUR
PYRITIC SULFUR
1B
\^ I
46 60
76
90 105
RESIDENCE TIME AT 1500° F, min
FIGURE 24 IGT PROCESS: EFFECT OF HOLDING TIME ON SULFUR REMOVAL
175
-------
A supply of run-of-mine Illinois No. 6 coal has been obtained. This coal
is considerably different from the previous beneficiated Illinois No. 6 feed.
It is much higher in moisture, ash and sulfur content and the fixed carbon is
lower. With its low heating value and high sulfur content this coal would be
a good feed candidate to demonstrate the desulfurization potential of the
process in the 25.4 cm (10-inch) unit.
Sulfur By-Products—
In the IGT process the sulfur components of the coal are converted primar-
ily into sulfur oxides and hydrogen sulfides. Gaseous sulfur dioxide and sul-
fur trioxide generated will most probably be removed in an off-gas scrubber
system. Sulfur removed as gaseous hydrogen sulfide will be subsequently con-
verted to elemental sulfur in an ancillary process.
ICT has suggested the removal of any remaining sulfide and sulfate from
the treated product by chemical or mechanical means. This after treatment
could also precipitate other sulfur compounds. For example if caustic is used
as the extracting medium, its regeneration would result in the precipitation
of gypstxn (CaSOi,).
Benefit Analysis—
The main benefit associated with the IGT process is the removal of both
pyritic and organic sulfur from coals to an extent permitting the burning of
the treated product in conformance with EPA's current NSPS for S02 emissions.
If this claim is verified in an integrated pilot system, this process could
represent a potential major technology for the control of sulfur oxide emis-
sions from combustion of coals, primarily from coals which contain large
quantities of organic sulfur.
She nitrogen content of the product fuel from the IGT hydrodesulfurizer
is about half of the content of that of the raw coal based upon results of
batch reactor tests. A reduction in the nitrogen content of the treated fuel
may help to reduce the NO emissions during combustions. No analysis has
Ji
been yet conducted to determine the trace metals content of the treated pro-
duct. However, it is anticipated that the IGT high temperature desulfuriza-
tion process, by incorporating a gas purification system, might provide a
method for the control of mercury and other trace metals.
176
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The process, however, has a low net yield (approximately 60 percent),
with a heating value of about 5 percent lower than that of the feed stock.
The net energy yield is calculated to be 57 percent. The net energy yield
of the process may be even lower than that estimated above due to the extreme
operating temperatures [816°C (1500°F)] of the hydrodesulfurization unit.
Additionally, the IGT process changes the matrix of the coal. The treated
product is a solid fuel (possibly a char) with its volatile matter reduced
significantly. Thus modified combustion equipment may be required for the
utilization of the treated product.
Environmental Aspects—
It would be unrealistic to assume that there will not be some unavoidable
adverse environmental effects from this process.
Gaseous emissions from the integrated system will primarily include water
vapor, carbon dioxide, and nitrogen, along with quantities of sulfur and nit-
rogen oxides. There will also be some solid by-products such as sulfur and
gypsum which may be sold or disposed of. Pollution controls will be needed
to ensure that the process meets emissions standards in a practical manner
with all relevant U.S. coals.
Since the IGT process is not developed to a level to permit the discuss-
ion of specific Heta-n« of ail its environmental emissions, discussed below
are only major anticipated pollutants and some general means for their control.
Sulfur dioxide-—Since coal pretreatment is used to avoid the caking of
coals in the subsequent hydrcdesulfurizer, substantial sulfur dioxide evolution
will take place. The effluent stack gases will carry as much as 25 to 30 per-
cent of the coal's sulfur. This will amount to over 181 metric tons (200 tons)
per day sulfur dioxide emission when charging high-sulfur coal (5-6 wt% total
sulfur in coal) at a feed rate of 7200 metric tons (8000 tons) per day. The
coal pretreating temperature is anticipated to be 400°C(750°F). The off-gas
from such pretreat operations will need to be scrubbed. The investment for
SOz removal from a 180 metric tons/day scrubber could be over 8 million dollars.
Process heat needs, not recoverable from the pre treatment system, can be
supplied by burning a portion of the product char. If the treated material is
177
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not adequately desulfurized, stack gas scrubbing for S02 removal win be
required. An alternative source is the production of low heating value (low-
BTU) gas from the treated product by one of the several comercial processes.
Such gas products can be then used for firing process heaters. However,
investment for this alternative route may be much greater.
Another alternative which may be adaptable for firing the product chars
containing high residual sulfur is a fluidized-bed ccmbuster using lime. In
this case, lime addition may adsorb the residual sulfur and avoid the need for
stack-gas scrubbing.
Hydrogen sulfide—An acid-gas scrubbing process will be most likely used
to remove carbon dioxide (C02) and hydrogen sulfide (H2S) from the hydrcdesul-
furizer effluent gas system. The H2S removed in this step will represent the
major sulfur content of the feed coal. It is anticipated that IGT will select
the daus process approach to recover elemental sulfur from this stream. If
so, stack-gas scrubbing will also be required for the clean-up of the Glaus
plant tail gas.
Trace metals—The mercury in the coal tends to be concentrated in the
pyrite, although a substantial fraction may be organically bonded. The pre-
treatment step of the IGT process at 400°C(750°F) may release as much as 1/3 of
the coal's mercury into the pretreater flue gas stream. Another mercury emis-
sion source would be the hydrodesulfurizer. However, this mercury can be re-
moved within the gas purification system, primarily in an activated carbon
tower. This mercury will be retained on the active carbon. Disposal of the
spent carbon by proper burial should protect against any contamination by the
mercury. Thus, the IGT process may also provide a route for control of the
nercury that would be mainly emitted to the atmosphere when burning the same
coal without treatment.
No beryllium or vanadium emissions should occur from the IGT reaction
system; these trace metals are expected to be found in the treated product.
Some volatilization of cadmium compounds can take place; but any
cadmium volatilized from the hydrodesulfurization system may be picked up by
the gas purification system.
173
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Particulates— In the vicinity of the plant, coal handling, crushing,
grinding and conveying operations may need to be enclosed to provide dust con-
trol. These controls should help to meet plant emission restrictions in par-
ticulates. Where ground coal is pneumatically conveyed, use of bag house or
several cyclones for solid recovery may be adequate before venting the gases
to the atmosphere.
Waste waters—Since this process is in an early stage of development,very
little is known regarding process waste waters. However, the potential air
pollutants in the coal are normally converted to water soluble salts and thus
the process waters may contain high concentrations of dissolved solids, hydro-
gen sulfide, ammonia, phenol, benzene and dissolved oils. Concentration of
these contaminants will be dependent en the quantity of the discharge waters
and on the design of the various scrubbers selected for the integrated system.
Problem Areas—
It is as yet premature to define potential problem areas for this process
precisely, since the XGT concepts are not at a developmental stage where an
integrated system may be conceptualized. The net energy recovery potential
of the system and the change in the coal matrix by the process have been iden-
tified as possibly severe problems for the IGT process.
R&D Efforts and Needs-
Specific immediate research efforts and needs for this process are:
• Prove the concept on larger continuous equipment to assess
the process viability and establish heat and material balance
information.
• Establish the process engineering of an integrated system
to estimate the process economics.
• Design, assemble and operate a small pilot plant incorporating
and integrating the major segments of process.
• Study physical, chemical and combustion characteristics of the
treated product in order to define its combustion behavior and
to evaluate the pollutant emissions from the burning of the
treated material.
179
-------
Conclusions derived fron the above reconnended studies will indicate
whether this process warrants further optimization and dettonstration studies.
Process Economics
Heat and material balance information have not been established for the
IGT process; therefore, economic factors have not been determined by IGT.
Hcwever, a preliminary rough economic evaluation was developed by Versar
for this process using: (1) Figure 22 as the accepted flew sheet for this
process and (2) the economics developed for the Lurgi process as the basis
for the estimate.
It is Versar's contention that since the IGT chemical coal cleaning
process is a gasification method for removing sulfur it will use many of
the unit operations employed by the Lurgi's system. Adjustment of Lurgi
process economics for known differences will yield a rough estimate for the
IGT process.
A summary of economics for the IGT process is given in Table 52.
It can be seen from Table 52 that the sulfur removal cost is very high due
to low yield and low BTU recovery. Details on the capital costs are given
in Table 53. The total differences between the Lurgi and the IGT process
result from (1) lower reactor cost for IGT due to lower operating pressures;
(2) lower gas treatarent and purification cost due to lower gas volume and
lower operating pressures; (3) elimination of the methanation and oxygen
manufacturing operations and (4) addition of extraction, filtration,
thickening, product drying and compacting operations. The estimated
operating costs of the IGT process are presented in Table 54.
180
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TABLE 52. SIM1ARY CF ECONCMICS FOR THE IGT CHEMICAL
COAL CLEANING PROCESS
Basis: 7,200 metric tons (8,000 tons) per day of 6,800 kg cal/kg
(12,300 BTU/lb) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
60% weight yield, 57% heating value recovery
Installed Capital Cost: $134,620,000
Annual Operating Costs
on dean Coal Basis: $38,277,000 process cost, excluding coal cost
$104,277,000 process cost, including coal cost*
$26.64v^netric ton ($24.16/ton), excluding coal cost
$72.57/faetric ton ($65.83/ton), including coal cost*
$4.09A06 kg cal ($1.03/10* BTU), excluding coal cost
$11.16/106 kg cal ($2.81/106 BOU), including coal cost*
* Coal costed at $27.60/netric ton ($25/ton)
181
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TABLE 53. INSTALLED CHEMICAL COST ESTIMATE FOR THE IGT
CHEMICAL COAL CLEANING PROCESS
$ 1977*
Coal handling and preparation $ 7,020,000
Desulfurization process costs
Gasification 10,8 00,000
Gas cooling 1,980,000
Shift conversion 4,140,000
Gas purification 16,470,000
Sulfur recovery^ 4,950,000
Compression 1,800,000
Extraction 720,000
"Water, pollution control . 7,900,000
Compacting and product handling' 10,890,000
Building and miscellaneous 700 QQQ
Utilities (off-sites)a 29,000,000
Site development and general* 7,200,000
Subtotal . $103,570,000
Engineering design § 10% 10,350,000
Contingency @ 20% 20,700,000
Total Installed Plant Capital (TPC) $134,620,000
* Lurgi process cost estimates published in April 1973 were used as basis.
These estimates were prepared by the Synthetic Gas-Coal Task Force
appointed by the National Gas Survey of the Federal Power Commission.
Cost adjustment to a 7,200 metric ton (8,000 ton) per day plant was
made using an exponential factor of 0.6. Cost estimates were further
adjusted to the first quarter 1977 prices using the Marshall and Stevens
Cost Indices
A Data supplied by General Electric
t Includes filtration, thickening, drying and compacting
£
Includes administrative building, maintenance shop, stockrooms
and stores.
Includes steam plant, in-plant electric power, distribution
cooling tower, boiler feed water treatment, instrument and
plant air, fuel gas distribution, cxiiiiiunications and water
* pollution control.
Includes site preparation, rail facilities, fire protection,
safety system, chemical and by-product storage.
182
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TABLE 54. ESTIMATED ANNUAL OPERATING COSTS FOR THE IGT
CHEMICAL COAL CLEANING PROCESS
.Amortization 20 years @ 10% interest (factor = 0.1175) 15,800,000
Taxes @ 2% TPC 2,700,000
Insurance @ 1% TPC 1,350,000
Tahnr (direct and indirect) 3,075,000
General and administrative @ 1.5% TPC 2,020,000
Maintenance and supplies @ 5% TPC 6,732,000
Utilities: 3,300,000
Electric power
Mater
Steam & fuel*
Chemicals and Catalyst 3,300,000
Waste Disposal —
Total Annual Processing Cost $ 38,277,000
Raw coal, 2.39 x 106 metric tons (2.64 x 106 tons) 66,000,000
TOTAL ANNUAL COST $104,277,000
* It has been assumed that 9.07 metric ton/hr (10 tons/hr) product
coal will be used to generate steam for in-process needs.
183
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KVB CHEMICAL COAL CLEANING PROCESS
The KVB ooal desulfurization process is based 15301 selective oxidation
of the sulfur constituents of the coal. 3h this process, dry coarsely
ground coal (+28 mesh) is heated in the presence of nitrogen oxide gases
for the removal of a portion of the coal sulfur as gaseous sulfur dioxide
(S02) . The remaining reacted sulfur in the coal is claimed to be in the
form of inorganic sulfates, sulfites or is included in an organic radical.
These non-gaseous sulfur compounds are removed from the pretreated coal by
subsequent washing with water or heated caustic solution f ollowed by water
wash.
The active oxidizing agent is believed to be NO2. The process, however,
uses a gas mixture containing oxygen (0.5 to 20 percent 02 by volume) ,
nitrogen monoxide (0.25 to 10 percent NO by volume), nitrogen dioxide (0.25
to 10 percent N02 by volume) and nitrogen (N2) the remainder.
The process can be operated either on a batch or continuous basis as
desired. There are no data available, as yet, to indicate which system is
more economical. For a continuous operation, the reaction may be carried
out at 120 °C (250°F) 2.4 atm (35 psia) for 1/2 to 1 hour period. The
mechanism of oxidation is still unknown. Details of process chemistry, as
explained by KVB, are given below. 3 5
OxLdant generation NO + 1/202 + N02
Sprite oxidation *eS2 + 6N02 •»• PeSO,, +80^
0
Organic sulfur oxidation II
reactions Ri-S-R2 + N02 •» Ri-S-R2 + NO
0 0
II II
Ri-S-R2 + ND2-" Ri-S-R2 + ND
0
Ri-S-R2 + N02 * Ri + R2 + NO + S03 or S02
II
0
184
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Extraction of sulfur fron Q
an organic radical f|
Ri-S-Rz + 2NaCH -»• RiH + R2H
O
Removal of iron sulfates
in the extractor FeSOi, + 2NaOH -»• Fe(CH) 2 + Na2SOi,
Caustic regeneration Na2SO«f + Ca(OH)2 •* 2NaOH + CaSOi,
Process Description
Laboratory experiments have been conducted with several coals on 50
gram samples in a 2.54 centimeter (one-inch) diameter batch reactor to test
the sulfur removal potential of the process. The process has been concept-
ualized both by KVB36 and Bechtel8. The KVB design incorporates a somewhat
more optimistic water and caustic extraction operation than the flow scheme
suggested by Bechtel. In this section, the flow diagram developed by Bechtel
will be used since it incorporates standard processing equipment in
conceptualizing the process.
A simplified flow diagram of the process is shown in Figure 258. Dry
coal from -die preparation section is pneumatically conveyed to a gas/solid
cyclone where it is separated from its conveying gas (nitrogen). Then it is
gravity fed into a fluidized bed reactor. The reactant gas is introduced
through the bottom of the reactor through a distributor. The reaction gases
leave the reactor, passing through a two-stage cyclone separator which removes
the fine coal particles from the gas.
The treated coal from the reactor is next reacted with caustic solution
to remove additional sulfur (organic sulfur) and also convert the ferrous
sulfate to ferrous hydroxide and solxixLe sodiun sulfate. The coal slurry
from the extractor is filtered and water washed on the filter. The product
coal is then dried prior to compacting. The process also incorporates
treatment of the various effluents from the system.
185
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OASES
COMPRESSOR
SUCTION
DRUM
BLEED
IHjO.MO.I
TO INCINERATION
00
RECYCLE
"*
RECYCLE CAUSTIC
MAKEUP CAUSTIC *J-« ,
THICKENER
. *~-
COAL FIRE
N2 HEATER
\
J
160 LB. STM
WASH HATER
FIGURE 25 KVB PROCESS H.OW DIAGRAM
-------
Nitrogen, (the transporting gas) from the cyclone is passed through a
dust collector for the recovery of fine coal particles and is then dis-
charged via a blower into a coal-fired heater prior to recycling this gas
to the coal preparation and conveying section.
Off-gas from the reactor is scrubbed with water to remove sulfur oxides
and nitrogen oxide gases. The acid product from the scrubber containing
sulfurous, sulfuric and also nitric acid is cooled prior to storage. The
treated gas from the water scrubber is subsequently reacted with calcium
hydroxide to remove carbon dioxide as calcium carbonate sludge. The purified
gas from the 002 remover is cooled to condense water vapor. A fraction
of the gas leaving the purifier is vented to prevent a buildup of inert gas
in the gas stream. By venting a portion of the gas and providing makeup gas,
the required gas proportion can be maintained. The recycle gas is then
combined with makeup NOa and Oj to form the treat-gas. The treat-gas is
compressed and recycled to the reactor.
The filtrate from the coal filter is treated with lime to regenerate
caustic and form gypsum. The sludge from the lime treatment tank is concen-
trated in a thickener. The underflow of the thickener containing a large
fraction of the gypsum is filtered to recover the caustic solution. The
thickener overflow is divided into two streams. Okie portion is recycled to
the extractor and the other is sent to an evaporator for further removal
of gypsum in order to prevent gypsum buildup in the system. The steam
generated in the evaporator is condensed and used as wash water for the
filter cake. The gypsum slurry is cooled and set to the gypsum filter.
Gypsum constitutes the solid waste from this process.
Status of the Process
The process has been tested batchwise in the laboratory, using 50 gram
coal samples. KVB owns all rights to the process as of April 1977 and has
funded all the work thus far. U.S. Patent No. 3,909,211 was issued on
September 30, 1975s7 and the filing of foreign patents in major coal producing
countries is in progress.
187
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The KVB laboratory test work en their chemical coal cleaning process is
presently inactive. Plans are to develop and ccratercially license the
process to coal producers and users. Funding is being actively sought
at this time to speed up the developmental schedule in view of the current
energy shortage.
Technical Evaluation of the Process
This process is in its early stages of development and thus, it is
difficult to make an accurate assessment of its industrial potential.
However, depending on the amount of desulfurization required, the extraction
and washing steps may or may not be required. It should be mentioned that
in cases where dry oxidation only could remove sufficient sulfur to meet
the sulfur dioxide emission standards, this technology could provide a very
simple and inexpensive system. Thus, there may be a potential for this
process for application to some coals, primarily metallurgical grade coals,
where partial removal of sulfur could be very beneficial.
Potential for Sulfur Removal—
laboratory experiments conducted on 50 gram samples in a batch reactor,
with five different coals, indicate that the process has desulfurization
potential of up to 63 percent of sulfur with basic dry oxidation plus water
washing treatment and up to 89 percent with dry oxidation followed by
caustic treatment and water washing. Table 5536 presents the results of
the laboratory studies. Ihe results indicate that higher desulfurization
is achieved when the treat-gas contains 10 percent by volume of nitric
oxide.
The washing step removes iron and loosely bound inorganic material which
reduces the ash content of the coal. KVB claims a 95+ percent ash removal
with their system, however, there are no published experimental results to
substantiate this claim.
Sulfur By-Products—
Ih the KVB process all the pyritic sulfur is converted to either
sulfites or sulfates. No elemental sulfur is produced by this process.
188
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TSfflLE 55. COM, DESULFURIZmCN DMA USING THE KVB PROCESS
Goal Sanple
Identification
Lower
Kittanning
Illinois
IS
K-16914A
K-147024
•
K-16394A
Sim
fteah
14to+28
•14to+28
14to+28
14to+28
SOto+lOi
14to+28
14tof28
14to+28
14to+28
14tof28
14to+28
14to*28
-14tof2l
nxitfat-trin *">
Mra.
Hrs.T
_
3
3
1.5
3
1.5
3
3
3.5
3.0
3.0
3.0
3.0
HO In
Air
% Vol.
_
5
10
10
5
10
10
5
10
5
10
5
10
•F
Gas
Flow .
Vtain,
-
.42
.44
.44
.42
.42
.44
.42
.44
.42
.44
.42
.44
Feed Sulfur
Level
total
4.3
4.3
4.3
4^3
4.3
3.0
3.0
3.0
6.7
5.3
5.3
3.2
3.2
Organic
0.7
0.7
0.7
0.7
0.7
1.9
1.9
1.0
1.16
1.3
1.3
1.9
1.9
Sulfur Level
After Oxidation
Total
S
-
3.3
-
-
-
-
-
-
4.2
4.3
2.7
2.5
2.0
% Sulfur
Removed
-
23
-
-
-
-
-
-
37
19
49
22
38
Sulfur Level
After Hater Wash
Total
S
-
2.4
1.6
-
-
-
2.0
1.9
3.1
3.0
2.5
-
-
% Sulfui
temoved
_
43
63
-
-
-
33
37
54
43
53
-
-
Sulfur Level
After 10% NaCH
Mash 6 water wash
Total
S
4.<>
2.1
0.5
1.4
2.9
2.5
1.0
% Sulfur
Removed*
0
51
89
67
32
17
67
1.2 59
1
3.2
3.1
-
-
-
52
41
-
~
00
vo
No oxidation, wash only.
U.S. Bureau of Mines Designation.
It is claimed that recent tests achieved the same results in 10 minutes using a rotary reactor.
The sapples were dried at 250*F before analysis.
-------
Sulfur is removed from the ooal as sulfur oxides, in the gas stream,
or as soluble sulfates by caustic and water wash. Sulfur leaves the
process as sulfurous and sulfuric acid, which may be ccnmercially saleable,
and as calcium salts which must be disposed.
Benefit Analysis—
The main benefit associated with the KVB process is the developer's
claim that the process removes all three forms of sulfur in the coal
(pyritic, sulfate and organic sulfur). This means that it may have general
applicability and greater capability to handle the variations in sulfur
distribution in the process feed than some other processes.
Additionally, the process is claimed to require relatively coarsely
ground coal (+28 mesh). Biis characteristic would facilitate the feed coal
and product coal handling operations. However, all tests have been made
on very closely sized fractions. This chemical coal cleaning process is
also claimed to reduce a major portion of the ash content of the feed coal.
No analysis has yet been conducted to determine the nitrogen or the
trace metals content of the treated product. However, it is anticipated
that the KVB desulfurization process will remove some of the trace metals
in the coal while reducing the total ash content of the coal.
Ohe process utilizes moderate temperatures, pressures and residence
time and has a high coal yield (up to 87 percent) with essentially complete
recovery of carbon and hydrogen values in the coal feed. The net heating
value recovery of the system is estimated to be about 91 percent.
Environmental Aspects—
Gaseous emissions from the integrated system win primarily include
water vapor, carbon dioxide, nitrogen and may contain some small quantities
of sulfur and nitrogen oxides. Since the basic process is a dry oxidation
system, there will be some dust problems; however, adherence to good engineer-
ing practices should keep these to a miniraum. In the reactor system, the
coal fines in the reaction gases will be recovered because these gases win
be passed through a two-stage, internal cyclone separator prior to leaving
the reactor. Both the feed coal and the treated product would be stored
in lock hoppers and introduced to the reactor or removed from the system
190
-------
through air lock rotary valves. The lock hoppers will be continuously
purged with nitrogen to prevent the formation of an explosive dust. The
vent from each lock hopper may be piped to the lime treatment tank, located
in the caustic regeneration section for the removal of traces of nitrogen
dioxide and sulfur oxides before venting these gases to the atmosphere. In
the vicinity of the chemical coal cleaning plant, coal handling, crushing,
grinding and conveying facilities may need to be equipped with dust control
equipment.
The process generates solid waste consisting primarily of gypsum with
calcium carbonate and coal ash. This waste material must be handled
in an environmentally safe manner since it will contain some trace metals.
Essentially no waterborne waste will be generated by this systan
assuming the plant can be designed to operate as a closed loop system.
Caustic solution would be regenerated and recycled to the extractor and all
water condensate from the process can be utilized as wash water in the
process. The process has a by-product acid stream, originating from
the off-gas scrubber, which may have a market value, or may present a
disposal problem.
Problem Areas—
The KVB process is still at its early stages of development; thus, it
is premature to precisely define problem areas for this system. It should
be mentioned, however, that the oxygen concentration requirements in the
treat-gas exceed the explosion limits for coal dust, and thus the operation
of this process may be hazardous. Furthermore, nitrogen uptake by the
coal structure will increase NO emission and therefore may limit the
Ji
marketability of the product.
R&D Efforts and Needs—
Specific research efforts and needs for this process are:
• A development program is required to determine the effects of
process variables on the sulfur content of the product coal;
191
-------
Extensive bench-scale and pilot level technical effort is
necessary to establish accurate heat and material balance
information and assess the process economics;
Since the process can be carried out using a continuous reactor
or with batch reactors, data should be generated to determine
which system is more suitable for various coal feeds.
It is claimed that a batch reactor system may permit the reaction
and extraction operation to be conducted in the same vessel.
This possibility should be investigated since it may prove to
be very economical.
The basic chemistry of the process should be studied to develop
a better understanding of N02 (active gas) oxidation of coal as
applied to the removal of the various forms of sulfur. This
study should define the rate of the active gas formation, and the
degree of sulfur and ash removal as a function of the processing
variables such as:
- treat-gas to coal ratio
- caustic or water to coal ratio
- caustic concentration
- reactor residence time;
The caustic extracted coals may have a high potential to slag in
boiler furnaces. Therefore, the physical, chemical and combustion
characteristics of the treated product should be studied; and
Studies should be conducted to determine the optutum method of
removal of oxidized sulfur forms from the treated dry coal.
192
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Prooess Eoononics
The cost estimates developed for this process should be considered
preliminary since adequate process engineering information is unavailable
at this time for the development of an accurate and optimum process flow
sheet. The economic estimates presented herein are based on a plant
operating on 7,200 metric tons (8,000 tons) per day of coal throughput.
These economics are based on the Bechtel's flow scheme8 for the chemical
treatment plant; however, it incorporates Versar's estimates for the annual
operating costs based on discussions with KVB.
The flow sheet for this treatment plant, as developed by Bechtel, with
corresponding mass balance and stream properties is given in Appendix VIII.
A summary pertinent to the coal balance is given in Table 56. The other raw
materials, utilities and the waste stream have been expressed as a function
of the product coal less moisture in Table 57.
A summary of economics of the KVB process is given in Table 58. Details on
the estimated installed capital costs for this process, including caustic
extraction, are given in Table 59. However, if the basic dry oxidation
process alone would be sufficient for sulfur removal, this process may prove
to be a relatively low cost method of coal desulfurization.
The estimated annual operating costs are presented in Table 60. The
unit operating costs shown are based on a clean coal yield of 85.3 percent
(dry basis) and a heating value recovery of 91 percent. The single largest
cost item, other than purchased coal used as feed, is the steam requirement
projected for this process. The evaporation system, for the control of
gypsum build-up in the recycle water, is a costly item in the process
economics . it has been assumed that only one-third of the product coal
is less than 28 mesh and these fines are compacted prior to shipment.
193
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TABLE 56. KVB PROCESS COAL BALANCE
Coal Feed
Coal*
tab.
Sulfur
Moisture
Subtotal
Fuel*
Coal*
Ash
Sulfur
Moisture
Product +
Coal*
Ash
Sulfur
Moisture
Ash LOBS by difference
Prodiirf- 3
Coal dry basis
Binder
Moisture
100.0
* Moisture, sulfur and ash free basis.
A Product coal used as fuel in the system
"f Net product without bin**1*
* Ash reduction estimated by KVB for thmr system.
no experimental data to support this fflnlm
# Ash reduction estimated by Bechtel for this system
3 Treated product with binder and 4 percent moisture
There are, however,
194
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TABLE 57. KVB PROCESS RAW MATERIALS, UTILITIES AND WASTE STREAMS BALANCE
Product Coal without binder
Goal received, dry basis
Fuel coal, dry basis
Ash loss
Oxygen
Nitrogen dioxide
Water
Caustic (100%)
Lime (100%)
Steam (150 psia)
Power
Binder
Gypsum waste (63% solid)
basis
Units
Metric Tons
Metric Tons
Metric Tons
Metric Tons
Metric Tons
Metric Tons
Metric Tons
Metric Tons
Metric Tons
Metric Tons
. Kw
Metric Tons
Metric Tons
Basis:
100 metric Tons
coal Received
85.34
97.2
7.96
2.9
2.8
0.3
67
0.5
2.5
75.75
2004*
1.28
5.0
Note: * Power requirement based on 100 metric Tons/hr feed
195
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TABLE 58. SUMMARY OF ECONOMICS FOR THE KVB CHEMICAL
COAL CLEANING PROCESS
Basis: 7,200 metric tons (8,000 tons) per day of 6,800 kg calAg
(12,300 BTU/U>) coal
90.4% operating factor (330 days/yr)
Capital amortized for 20 years @ 10% interest
Grass roots plant installation
85.3% weight yield, 91% heating value reccn^ry
Installed Capital Cost: $65,940,000
Annual Operating Costs
on Clean Coal Basis: $41,059,000 process'cost, excluding coal cost
$107,059,000 process cost, including coal cost*
$20.10 Aetric ton ($18.23/ton), excluding coal cost
$52.40/metric ton ($47.54/ton), including coal cost*
$2.75A06 kg cal ($0.69/106 BTO), excluding coal cost
$7.22/10s kg cal ($1.81-/106 BTU), including coal cost*
* Coal costed at $27.60/taetric ton ($25/ton)
196
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TABLE 59. INSTALLED CAPITAL COST ESTIMATE FOR THE KVB
CHEMICAL COAL CLEANING PROCESS
$ 1977
Coal handling and preparation* $ 6,000,000
Desulfurization process oostsA 35,100,000
Compacting and product handling''' 4,400,000
Building and miscellaneous01 700,000
Utilities (off-sites) —
Site development and general* 4,525,000
Subtotal $50,725,000
Engineering design @ 10% 5,070,000
Contingency @ 20% 10,145,000
Total Installed Plant Capital (TPC) $65,940,000
* Versar estimate based on crushing and sizing the coal to +28 mesh
A Bechtel estimate adjusted to 1st quarter 1977 price usina CE plant
.j. cost index; includes off-sites.
Versar estimate; assumes only one-third of the product coal is less
a than 28 mesh and these fines are compacted prior to shipment.
Includes administrative buildings, the maintenance shop, stockrooms
. and stores.
Includes railroad facilities for incoming and outgoing cars and loading
and unloading facilities for raw materials and loading facilities for
by-product waste material.
197
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TABLE 60. ESTIMATED ANNUAL OPERATING COSTS FOR THE KVB
CHEMICAL COAL CLEANING PROCESS
Amortization 20 years @ 10% interest (factor = 0.1175) $ 7,748,000
Taxes @ 2% TEC 1,319,000
Insurance @ 1% TPC 559 Ooo
Labor (direct, indirect additives and support) 440,000
General and administrative @ 1.5% TPC 989,000
Maintenance and supplies @ 5% TPC 3,297,000
Utilities;
Electric power 1,200,000
Water 71,000
Steam* 16,000,000
Chemicals:
Oxygen 1,848,000
Nitrogen dioxide 1,584,000
Caustic 2,112,000
Lime A 2,310,000
Binder" 1,350,000
Waste Disposal 132,000
Total Annual Processing Cost 41,059,000
Raw coal, 2.39 x 106 metric tons (2.64 x 106 tons) 66,000,000
TOTAL ANNUAL COST $107,059,000
* Assumes purchased steam (150 psia) @ $8.81/1/000 kg ($4/1,000 Ib),
A Assumes one-third of the product will require compaction.
198
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ATLANTIC RICHFIELD COMPANY CHEMICAL COAL CLEANING PROCESS
Process Description
The Atlantic Richfield Company (ARCO) is developing a chemical coal
cleaning process at Harvey, Illinois, which removes both pyritic and organic
sulfur compounds and ash from coal. The process requires the use of
either a recoverable or a non-recoverable reaction promoter.
Very little has been published about the process, no flow sheet is
available, and ARCO has not permitted an on-site inspection.
Status of the Process
Process development work has largely proceeded on the basis of data
generated from batch bench scale experiments. However, a 0.45 kg (1-pound)
per hour continuous reactor system was recently built and is currently being
used to provide additional data.
Until recently ARCO has financed this experimental program without exter-
nal assistance. The Electric Power Research Institute, Palo Alto, California
(EPRI) has financed a study on the continuous reactor system on five coals
in which there is a wide distribution of pyrite particle size. This study
is now complete and a final report is expected to issue in 1978. The EPRI
contract has been extended to demonstrate in the continuous pilot plant, low
cost process options which ARCO has developed.
Technical Evaluation of the Process
Potential for Sulfur Removal—
The five coals selected by EPRI and tested in the ARCO process are:
• Lower Kittanning, Martinka #1
• Illinois #6, Burning Star #2
• Pittsburgh #8, Montour #4
• Western Kentucky #9/14, Colonial
• Sewickley, Green County, Pennsylvania (beneficiated)
The coals were selected to meet the following criteria:
• Mean pyrite crystallite chord size for the five coals should
cover a wide range.
199
-------
• Pyrite and organic sulfur content should cover a wide range.
• Reduction of sulfur content to the NSPS compliance level;
i.e., to 1.1 g/R cal. (0.6 Ibs./S BTU), should be attainable
by removal of pyritic sulfur in the case of at least one coal.
• The coals should be from producing mines on seams with
substantial reserves.
Depending on the coal treated, overall reduction of sulfur was up to 98%
for pyritic sulfur, up to 20% for organic sulfur, and 66-72% for total
sulfur. Overall reduction of iron was up to 96% and of ash up to 78%.
The KHJ yield of the process is estimated at 90-98%. Ash content of the
product is frequently reduced by 50%, compared to feed coal, and the process
weight yield is about 95%, depending on ash removal.
Sulfur By-Products—
ARCO process by-products consist of gypsum plus an iron-containing
by-product. No other data is available.
Environmental Aspects—
The process allegedly has no off-gases. Disposition of trace metals
is unknown, but there is a possibility that some could be commingled with
the by-product gypsum. No other data is available.
Problem Areas—
Although the process appears adequate to meet NSPS for Eastern coals
with low organic sulfur, process improvements are required before high
organic sulfur coals will meet NSPS.
R&D Efforts and Needs—
R&D efforts and needs are not known at this time.
Process Economics
Little was learned about AROO process capital requirements and operating
costs. Various process variations have been estimated at $17 to $31 per ton
of product. The low cost options are now receiving EPRI development support.
Steam requirements are costed at $5.72/1,000 kg ($2.00/1,000 lb.), regardless
of pressure. Solids disposal costs of $llAetric ton ($10/ton) of dry solids
are used.
200
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MISCELLANEOUS CHEMICAL COAL CLEANING PROCESSES
University of Houston Process
Development of this process is proceeding under the direction of
Dr. Attar of the Chemical Engineering Department of the University of
Houston. In a telephone interview in July, 1977, Dr. Attar stated that
the work involves bench-scale development of a nodif ied version of the
Battelle process."0 The significant difference between the two processes is
claimed to be a modified leaching process (proprietary at this time)
which results in much lower residual sodium in the coal than the Battelle
leaching conditions yield.
The University of Houston process claims to remove essentially an of
the pyritic sulfur and better than 40% of the organic sulfur (It is believed
that this process is removing at least the mercaptan and aliphatic organic
sulfur forms). This project is studying methods to regenerate an additive
to the leachant which apparently represses the bonding of sodium to the coal.
Experiments have been on 10 gram samples (using Tin twin #6 coal) to this
point, but larger samples of 454 grams (1 Ib) will be tried. The effort
is being funded internally.
National Research Council (NRC), CfrTwfo Process
The National Research Council of Canada (NRC) is actively developing
and optimizing a process involving the agglomeration of the carbonaceous
constitutents of finely divided coals. Different oils are used as collector
liquids, while the inorganic constituents remain in aqueous suspension and
are rejected.41'112 Oil agglomeration relies on differences in the surface
properties of coal and inorganic minerals to effect separation, as does
froth flotation. However, flotation is effective primarily in the 45 to
200 mesh range, whereas agglomeration is claimed to have no lower limit
on particle size, and can treat particles up to 3 mm (1/8 inch) in diameter.*3
Coal agglomeration is generally considered to be a physical coal
cleaning process as opposed to a chemical coal cleaning process.
201
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However, in the late 1960's and early 1970's NBC performed some
exploratory research utilizing selected bacteria to effect surface oxida-
tion of metal sulfides in ores and pyrite in coal to render the surfaces
more hydrophilic. Selective agglomeration (or flotation) is then even more
effective. After dropping this effort for several years, it was reactivated
in 1977. The research is being performed at the University of Waterloo,
Chtario, Canada, by Dr. Kempton.
Jolevil Process
This process was developed for Jolevil Associates, Inc., Hoover,
Alabama, by the Southern Research Institute, Birmingham, Alabama. The
process is considered proprietary (patent applied for) with only sketchy
details available.*** Jolevil management will release no specific details.
The basic principle involved appears to be wet oxidation of pyritic sulfur
in coal using air at 10-14 atm. (150-200 psi) and temperatures up to 120°C
(250 °F). The process is claimed to remove most of the pyritic sulfur and
does not affect organic sulfur. Indications are that the process could be
used in a coal slurry pipeline application. There is no cost data avail-
able.
Chip State University Process
Development of a microbiological process for coal desulfurization
is under the direction of Dr. Patrick R. Dugan, of the Microbiology Depart-
ment at the Ohio State University, Columbus, Chio. The experimental effort
is currently in the laboratory stage and is privately funded. The work to
date is scheduled to be published.l>s
The study has been conducted for approximately 8 months with a
pulverized coal blend supplied by a local utility. The total sulfur content
of this coal is 4.6% with about 3.1% pyritic sulfur. The coal has been
screened and used in two mash size ranges as well as the "as received"
material. Microbiological treatment of these fractions has resulted in
sulfur reductions as tabulated
202
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RESULTS OF MICROBIOLOGICAL OREAHMENT OF UTILITY
COAL FOR SULFUR REMOVAL
Mesh Size Range
as received
100 - 200 mesh
-200 mesh
Initial Sulfur
Total
4.6
4.1
5.4
Percentage
Pyritic
3.1
2.9
2.9
Final
•total
2.0
1.8
2.0
Sulfur Percentage
Pyritic
0.1
0.1
0.1
Treatment tine was reduced from 20 days in the initial tests to around
7 days in tests currently being run. The microbiological treatment is
effective in removing better than 96% of the pyritic sulfur, but appears to
have little or no effect on organic sulfur. (There is about 20% reduction
of organic sulfur in the -200 mesh fraction; this reduction, however, is
probably within the experimental error of the sulfur determinations.)
Dr. Dugan is currently assessing the results of the work to date and
will decide on the future direction of the effort.
Western Illinois University Process
Dr. M. Venugopalan of the Department of Chemistry of Western Illinois
University, Maoocb, Illinois, has conceived a process for coal gasification
and desulfurization utilizing a plasma jet, and has constructed a laboratory
unit. A few experiments have been carried out to date with seme indication
of success. For example, during an 8-hour run, the total sulfur content of
an essentially dry Illinois #6 coal (plus 6 mesh) was reduced from 2.1%
to 1.5%.1*6 Argon was initially used as the inert plasma gas, but the equip-
ment has been operated on hydrogen gas as well. Runs in a one meter long
tube are carried out with about a 100 g sample of coal using 60-100 watts of
electrical power and achieving temperatures of about 1,200°C. Off-gases are
analyzed for methane, ethane and hydrogen sulfide. Further experiments are
planned utilizing finer coal particles, and varying other parameters in
order to obtain more supportive data. With argon, the methane off-gas is
derived entirely from the coal, but with hydrogen plasma, the coal will
probably not lose very much hydrogen. No other data is available at this time.
203
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Texaco Process
This process was conceptualized for treating a pipelined ooal slurry
in-situ for pyritic sulfur reduction. A pyrite oxidant such as hydrogen
peroxide would be added to the slurry, upstream of the dewatering plant in
order to accomplish pyritic sulfur reduction. A process patent was issued
to Texaco, Inc. (Novenber 23, 1976), but the idea has been shelved for the
present.
U.S. Steel Process
This process was developed by Dr. P. X. Mascantonio at the U.S. Steel
Research Laboratories, Monroeville, Pennsylvania. The process is based on
treatment of coal with a molten mixture of alkali hydroxides at elevated
temperatures and atmosphere pressure. The process, as conceptualized in
U.S. Patent 3,166,483, involves separation of the mixture of fused hydroxides
and desulfurized ooal by decanting, with the molten hydroxide mixture recycled
to the coal processing step. The desulfurized coal is washed free of
residual alkali which is recycled to the coal processing step in a molten
form.1*8 The aqueous wash solution is concentrated to the anhydrous state,
melted and recycled.
The U.S. Steel process was shown to remove significant amounts of
sulfur from the coals tested. However, the physical properties of the
treated product underwent drastic changes, making the material unusable
for combustion in utility boilers. Additionally, high residual sodium
levels would be expected in the treated product, which would create severe
slagging and fouling problems in conventional boilers. The research program
on this approach was discontinued for these reasons.1*9
Kellogg Process
This process was developed by the M.W. Kellogg Company, Houston, Texas.
The process was abandoned as unworkable in 1972 after some preliminary experi-
mental work was attempted and a report issued to IERL/REP/EPA in June 1972.50
The basis of the work performed was to remove sulfur from coal using an iron
oxide catalyst in the presence of hydrogen at elevated temperatures and
pressures. Appreciable desulfurization resulted from this treatment (about
204
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85% total sulfur removal), but the treated ooal yield was only 58%. No
process economics are available, but the poor yield would appear to make
the process unattractive. Also it appears that the ooal matrix might be
adversely affected by this treatment.
Chemical Construction Corporation (Chetnico) Process
The Chemico process consists primarily of the reduction of the pyritic
sulfur content of coal by reaction with water and air at elevated temperatures
and pressures. Experimentation has consisted of limited bench scale
treatment of ground coal in several hundred gram quantities with water and
air. Appreciable pyritic sulfur reduction in the treated coal was claimed.
Chemico obtained a conceptual process patent on July 16, 1974. No
process developed work has been carried out since the patent was issued
and no cost estimates have been published.s 1
The Chemico process is quite similar in concept to the Ledgemont
(Kennecott) and ERDA oxydesulfurization processes.
University of Florida Process
Experimental work was performed under an EFDA grant (No. 801296) at
the Chemical Engineering Department of the University of Florida, Gainesville,
Florida, during 1974 to determine the effectiveness of various gases, at
elevated temperatures and atmospheric pressure, for the desulfurization of
coal. Three gases were used (air, steam and hydrogen) in attempts to
desulfurize 10 high-volatile bituminous coals. Cnly hydrogen was reported
to be effective in reducing the total sulfur to meet the current EPA sulfur
dioxide emission standard.
The results achieved with hydrogen closely corroborate the results
currently being obtained by the IGT hydrodesulfurization process. The
University of Florida work showed that maxiiraxn total sulfur reduction was
achieved by hydrogen treatment and temperatures around 480°C (900°F). At
this temperature, 86% of the total sulfur was removed, including 94% of the
inorganic and 76% of the organic sulfur. An oxidation pretreatxnent was
performed in the Florida work (typically for 10 minutes at 150°C (300°F))
205
-------
in order to reduce coal caking properties. Hydrogenaticn without oxidative
pretreatment took 15 tines as long to remove the same amount of sulfur
as compared to the hydrodesulfurization of pretreated coal. This result
also parallels the IGT observations. Weight loss of the hydrogen treated
coal at 480°C (900°F) was approximately 40%, a result which the IGT work
has also duplicated.
No further work has been carried out at the University of Florida since
these experimental runs were completed and no further work is contemplated.
Laramie Process
The Laramie process developed at EFDA's La ramie, Wyoming, Energy
Research Center, consists of a coal treatment step only - reacting ground
coal at ambient temperatures and pressures with a mixture of sulfuric acid
and hydrogen peroxide. Five different bituminous coals have been treated.
The mild oxidation treatment results an partial pyritic sulfur and ash
extraction into the aqueous phase but does not affect organic sulfur. Studies
to date have only been at the laboratory level. The work on this approach
has been suspended for some time, due to lack of personnel, facilities,
and the need to carry on other more pressing research efforts. There is no
information available regarding the process flow scheme or process economics.
Dynatech Process
The principle of aerobic microbial leaching of pyritic sulfur from coal
formed the basis for a proposal submitted to ZEKL/RTP/EPA in July, 1975,
by the Dynatech Company of Cambridge, Massachusetts. There apparently has
been no experimental work carried out by Dynatech to evaluate the approach
and no action was taken by EPA on the proposal.
Kyoto Process
Laboratory-scale experimentation was carried cut in Japan at Ityoto
University in 1969 in attempts to remove both inorganic and organic sulfur
by reaction with chlorine or hydrogen peroxide at ambient temperatures and
pressures.52 No attempts were made to characterize off-gases or define the
chemical reactions. Indications were that while most of the inorganic sulfur
and some organic sulfur removal was affected, processing times were slow
206
-------
and a large amount of reagent was necessary. As far as is known, there has
not been any follow-up process development work or cost studies performed.
Methonics Process
The intention of Methonics, Inc. was to develop a process based on
hydrogen attack of the organic sulfur portion of coal, after initial dissolu-
tion in a solvent and removal of the pyritic sulfur by filtration. In this
process, the product would no longer be in a solid form. Professor Wiser
of the University of Utah College of Mines and Mineral Industries indicated
that no experimental work was ever performed to develop the Methonics idea.
Rare Earth's Process
This process was proposed by Bare Earth Industries, Inc., Orlando,
Florida, and is entirely conceptual in nature. The process is claimed to
remove organic sulfur from liquefied coal in the solvent refined coal (SBC)
process, using rare earths as scavengers for the sulfur. This sulfur
removal process was considered outside the scope of the present Versar study
since the coal no longer is in the solid form.
MIT Process
The Massachusetts Institute of Technology, Cambridge, Massachusetts,
(MIT), Chemical Qigineering Department, is concerned with developing improved
methods of removing sulfur and nitrogen contaminants in liquid fuels by
catalytic hydrogenation treatment. For coal to be treated by this method,
it would be necessary to subject the coal to liquefaction prior to processing
it. The MIT process, therefore, cannot be considered as a chemical coal
cleaning process since the product is no longer a coal-like material.53'5"
Butgers University Process
This process developed by Rutgers University, New Brunswick, New Jersey,
featured microbiological treatment of coal in an attempt to reduce organic
sulfur levels. Treated coal samples submitted to the Bureau of Mines for
analysis showed no reduction of organic sulfur level. No other information
is available on this process, and it is believed inactive.
207
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The Gulf & Western Process
The Gulf & Western Advanced Development and Engineering Center,
gwarthmore, Pennsylvania, has been involved in a program to develop a coal
desulfurization process. The program objectives as recently reported
included:55
• Exploring the utility of graft polymerization for solubilizing
coal to remove pyritic sulfur and ash.
• Chemically and physically characterizing grafted coal specimens
with respect to composition, molecular weight and other properties.
This program was ERDA funded until the spring of 1977. The process
consisted of an attempt to liquefy coal by a graft polymerization technique
using a free radical mechanism. Apprcodmately 30% of the coal was liquefied
using benzene at 70 °C (160 °F). The sulfur level in the solubilized extract
was 0.7% as compared to 2% in the original coal. At the present time ERDA
is no longer funding the project. The process could not be justified fruit
an economics standpoint.
Colorado School of Mines Research Institute (CSMRI) Process
The Electric Power Research Institute (EPRI) is financing a technical
program at CSMRI in Golden, Colorado, which will evaluate the physical
beneficiation of coals through the use of magnetic fluids.56 Connercially
available magnetic fluids, and some non commercial fluids, will be obtained
and tested with specific coals, starting with high-ash western subbituminous
grades. The work will proceed from laboratory studies through pilot-plant
stage, if justified. Economic as well as technical evaluation will continue
throughout the term of the project.
This project is concerned with stable colloidal suspensions of
submicron size ferro - or ferrimagnetic particles in a carrier such as
water or kerosene, with a dispersing agent. Application of a magnetic field
to such fluids can levitate or float materials which are much more dense
than the fluid itself. Thus, if ash in a coal/ash mixture has a greater
affinity for a magnetic fluid than coal, it may be separated magnetically
from the coal. It is hoped that pyritic sulfur will be selectively removed
with the ash.
208
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SECTION 4
PROCESS AND COST COMPARISON
This section presents a comparison of technical and economic results
obtained from the assessment of major chemical coal cleaning processes
as described and discussed in Section 3 of this report. The analysis and
conclusions presented herein are based on process claims made by individual
developers, research reports and published information.
Most processes included in this report are not at an adequate develop-
mental stage to permit the preparation of a precise engineering process
flew sheet for capital and operating cost evaluation. Thus, the process
economics presented for most processes are best engineering estimates,
based upon the information available.
SULFDR REMOVAL AND HEATING VALUE RECOVERY POTENTIAL
A comparison of process performance and costs can best be accomplished
by looking at each process on a connon coal feed. This basis allows the
comparison of the following parameters process by process:
• Weight yield of clean coal product based upon a feed coal rate
(moisture free basis) of 7,110 metric tons (7,840 tons) per day
[7,200 metric tons (8,000 tons) per day of 2 percent moisture coal];
• Weight percent sulfur in the clean coal product based upon the
sulfur removal efficiency of the process;
• Heating value yield of the process based upon a feed coal value of
6,800 kg cal/kg (12,300 BTU/lb) and net heating value yield in
percent; and
• Costs -
total capital costs for the process,
total annual processing costs,
annual costs per metric ton of clean coal, including coal costs
and excluding coal costs, and
209
-------
annual costs per heating value unit, including coal costs and
excluding coal costs.
This oonparison data is shown in Table 61, arranged according to categories
of processes.
The tximion coal feed selected is a bituminous coal from the Pittsburgh
seam, which cannot readily be cleaned by conventional washing techniques
to meet the current new source performance standards for sulfur dioxide
emission. Ihis coal does have an organic sulfur content low enough (0.7
weight percent) so that complete removal of pyritic sulfur would result in a
product which will meet current NSPS for sulfur dioxide emission.
The percent removal of pyritic and organic sulfur assigned to each pro-
cess is based on data supplied by individual developers. The table indicates
a range of SCfc emission levels for the clean coal products of 1.5 to 3.8 kg/
106 kg cal (0.8 to 2.1 li>/106 BTU). The calculated sulfur levels for pro-
cesses which remove both types of sulfur are lower than the 2.2 kg/106 kg cal
(1.2 lb/106 BTU) NSPS for sulfur dioxide emission. Of the four processes
which remove pyritic sulfur only, two (TRW and Ledgemont) will produce
slightly higher sulfur levels than that required to meet the current NSPS;
however, within the levels of accuracies involved they also might be con-
sidered to be in compliance. The remaining two processes [Magnex and
Syracuse] would produce coal which would be in compliance only with a stand-
ard of 4.3 kg/106 kg cal (2.4 lb/106 BTU) for sulfur dioxide emission.
Processes which remove pyritic sulfur alone are primarily applicable to
coals rich in pyritic sulfur, so that efficient removal of pyritic sulfur
could bring these coals into compliance. Processes which remove both types
of sulfur are primarily applicable to coals which cannot be adequately
treated by pyritic removal processes. All chemical coal cleaning processes
are more selective and efficient than conventional coal cleaning techniques
and it is very likely that each process will eventually find an area of
application.
As shown in Table 61, the heating value yields estimated for these
processes are generally greater than 90 percent with a range from a low
57 percent for the IGT process to a high of 96 percent for the GE process.
210
-------
TABLE 61. PROCESS PERRJRWCE AND COST CtWARISON FOR MJOR CHEMICAL COAL CLEANING PROCESSES
NET COAL YIELD, METRIC TONS
PER DAY (TONS/DAY)
WEIGHT % SULFUR IN THE PRODUCT
HEATING VALUE, KG CAL/KG
(BTU/LB)
KG SOi/MM KG CAL 25/TON).
ARGENT PYRITIC, 0.01 PERCENT SULFATE AND 0.70 PERCENT
30 BTU/LB).
-------
All heating value yields listed in Table 61 reflect both the coal loss due
to processing and the coal used to provide in-process heating needs.
However, with the exception of the IGT process, the actual coal loss due
to processing is claimed to be small. For most processes, the major heating
value loss is due to the use of clean coal for in-process heating.
It is believed that the high yield estimated for the GE process may
not adequately reflect the heat requirements that may be needed to regenerate
the caustic reagent employed in the process. This process is in its
early stage of development and as such, the energy requirements for the
process cannot be properly assessed at this time. It is possible, that in
the final analysis, the heating value recovery from this process will be
more in line with other chemical coal cleaning processes.
COST COMPARISON FOR MAJOR CHEMICAL COM, CLEANING PROCESSES
Estimates of capital and annual operating costs for each major chemical
coal cleaning process are also given in Table 61. These estimates are based on
an assumed plant throughput capacity of 7,200 metric tons (8,000 tons) per
day, equivalent to a 750 M.W. electric power plant. The total annual
operating costs for each process, including and excluding cost of the raw
coal, have been expressed also in terms of dollars per metric ton and
dollars per million kg cal heat.content in the coal.
The capital cost estimate prepared by each process developer was used
as the basis of the cost estimates in this report. In some cases, these
costs were modified to allow the evaluation of the various processes on a
comparable basis. The estimated capital costs assume a grass roots operation
including costs for coal crushing, grinding, product compacting and feed
and product handling. The capital costs also include land acquisition and
site development, off-site facilities, and engineering and design costs.
A contingency allowance of 20 percent has been included in all estimates,
with the exception of TRWs. A lower contingency allowance (10 percent)
was used for the TRW process since it is at a more advanced stage of develop-
ment and adequate process data is available to develop the economics of this
process with a greater degree of confidence.
212
-------
Annual operating costs are based on a 24-hour workday, 90.4 percent
service factor (330 days per year) basis. The capital cost is amortized
over a period of 20 years at 10 percent interest per year. Where adequate
information was available, the utilities and chemical consumptions are based
upon actual process demand. The operating labor costs reflect wage rates
for the Pittsburgh, Pennsylvania, area. The estimates for the maintenance
and supplies, general and administrative, taxes and insurance are taken as
5, 1.5, 2 and 1 percent on total installed plant capital cost (TPC),
respectively.
Capital Cost Comparisons
In general, pyritic sulfur removal processes require the least amount
of capital investment. However, these processes have limited sulfur removal
efficiencies.
Among processes that remove both organic and pyritic sulfur, the KVB
process appears to have the lowest capital investment, since it is a
partially dry process requiring lower investment for the dry reaction
section. The high capital cost of the Battelle process is due to the pro-
cessing steps associated with reagent regeneration.
The high capital cost of the ERDA process is due to costly equipment
associated with the handling of dilute sulfuric acid at elevated tempera-
tures and pressures. At the process operating conditions the dilute
acid is highly corrosive and it poses problems in terms of selection of
construction material for equipment and devices which are exposed to the
corrosive atmosphere.
Very little is known about the ARCO process details and process
chemistry. Therefore, a capital cost estimate was not developed for that
process.
Operating Cost Comparisons
Table 62 presents a summary of operating cost elements for each
process. The ranges of annual operating costs, including raw coal cost, in
terms of S/metric ton and $/106 kg cal are $43.40 to $72.40 and $5.38 to
$11.20, respectively, Pyritic sulfur removal processes using chemical
213
-------
pretreatment are the least expensive of all processes listed in Table 62.
Operating cost for the Magnex process depends primarily on the cost of iron
pentacarbonyl manufacturing. In the estimate presented in Table 61, an
operating cost of $0.22/kg for the iron carbonyl manufacturing was used, as
projected by the developer. The current vendor quotes for iron carbonyl
range up to $3.30/kg. At a consumption rate of 10 kg/foetric ton of coal,
each $0.20 cost increase per kilogram of iron carbonyl manufactured would
increase the annual operating cost of this process by about 27 percent.
Between the two processes which remove pyritic sulfur by leaching, the
TFW process appears to be slightly less costly. In the Ledgemont process
the fixed charges associated with the higher capital investment have an
adverse impact on the annual operating costs. Additionally, the TFW process
has a much higher probability of technical success since it is currently
active at a PDU stage. The Lodgement process, tested only at a mini-pilot
plant level, is currently inactive.
The most expensive processes, in terms of energy output, are the IGT
process followed closely by the Battelle process. Laboratory data available
at this time, indicate a very low BTU recovery for the IGT process. The
Battelle process is adversely impacted by the fixed charges associated with
the high capital investment and by the costs associated with chemicals
consumption and reagent regeneration operations.
The least expensive process capable of removing pyritic and organic
sulfur is the GE process followed closely by the JPL and KVB processes.
The GE estimate is based, however, on early laboratory data and it is
quite possible that the projected costs will prove somewhat inaccurate in
the long run. The basic process utilizes a caustic reagent in coal pretreat-
ment and the costs associated with caustic consumption and caustic regenera-
tion are questionable at this time. The JPL process estimates are also
preliminary since investigations on this process have been initiated recently.
Mare definitive cost information on this process will be available in 1978
214
-------
TABLE K OPERATING COST CtWArtlSONS FOB HUOR QEMICAL COAL CLEAN I NT, PROCESSES
COST ELEMENT
LABOR I G. t A.
AMORTIZATION (20 YDS)
TAXES t INSURANCE
miNTBWCE K Stm-IES
UIILITIES
aeucALS
MAS1E DISPOSAL
ANNUAL PROCESSING CUST
RAW CON.
TOTAL ANNUAL COST
»CYERS
PROCESS
COST I/TOM
UlHI)) PBOOUCT
5.9G2 1.67
12,820 5.39
3,270 1.38
5,<0) 2.20
5,761 2.15
,OTO 27.78
111,3)0 '6.85
HKtfX&*
PROCESS
COST VlON
($1DOO) PRODUCT
7% 0.38
'l,Wi 2.12
1.135 0.%
l,(Bl 0.90
1,'im 0.67
9,Wl '1.36
'138 0.21
19,258 9.18
66,000 31.'0
85,231) '0.67
SYRACUSE
PROCESS
COST i/TON
(tinOO) PRODUCT
620 0.31
5,750 2.72
1,170 O.G9
3,170 1.50
I'lO 0.06
1,220 1.99
-
12,150 5./7
tt,ono 3i. 25
78,190 37.02
ERDA
PROCESS
cost VION
($1000) PRODUCT
3,255 1.36
19,0)0 8.25
5,031 2.11
8,510 3.51
13,221 5.57
6,932 2.92
210 11.10
%,yfi 23.82
tt.OUO 27.78
122,595 51.60
O.E.
PROCESS
COST (/TON
UIQT)) PHUUUCT
1,830 0.72
11,930 1.73
3,nco 1.21
5,310 2.10
7,270 2.87
10,370 1.09
-
39,820 L'../2
tf>,(H) 26.05
Iff i, 820 ill. 77
BATTELLE
PROCESS
COST t/IOH
($1010) PRODUCT
'(,frt) 1.85
19,811 7.91)
5,010 2.00
m.uuu 3.93
25,100 9.21
11,60!1 1.M
-
71.203 /).5»
cf..an A.V
1'0,A)3 ?..«)
JPL
PROCESS
COST VlON
UMni) rnouci
3,711) 1.51
7,2/'l 3,0i
1,32G O.'/.
2,210 O.'J?
1,5m 0.5>l
28,em H.9I
-
'11,110 IK.'ft
ffi.lXIl 27.'«
110,'lin 'f>.97
IGT
PROCESS
COST VTON
(MOID PRODUCT
5,095 3.22
15,80) 9.97
1,050 2.58
6,732 1.2*1
3,3TO 2.08
5,51) 2 .IB
-
3K,2// 21. I/
H,,0» 11. ff.
191,2/7 6S.85
KVB
PROCESS
COST VTON
WOOD) PRODUCT
),f9 0.63
7.718 3.H
1,978 0.88
3.297 1.16
17,271 7.G7
9,20f| 1.09
131 0.06
11, era i8.?3
tt,nrn rt.3i
07,lfj9 •V.5'1
-------
when more process information and accurate material and heat balance
information becomes available. The annual costs reported for the KVB
process are also preliminary since the process is at its early stages of
development and accurate conceptualization of the process for purposes
of economic evaluation is not possible at this time. The main advantage
of the KVB process is the simplicity of the first stage dry oxidation
process. If the dry oxidation process can be successfully demonstrated
using coarse coals, this process would be an inexpensive technology for
beneficiation of coals where partial removal of sulfur would substantially
upgrade the coal.
ftnong the processes capable of removing pyritic and organic sulfur
the EEDA. process has one of the highest probabilities of technical success.
The process is currently active and most technologies employed in this system
have been already tested in other systems such as Ledgemont and TFW. The
process is attractive because it is claimed to remove both types of sulfur
and uses air as a major reagent. Furthermore, the sulfur by-product from
this process is claimed to be dilute sulfuric acid, rather than iron sulfate,
which greatly simplifies the coal washing operations. The process is
somewhat expensive due to high operating temperature and pressure require-
ments and the corrosive nature of dilute acid present in this system. The
dilute sulfuric acid at the operating conditions of the ERDA process will
require the use of expensive construction material and consequently a
higher capital investment cost.
Table 63 presents a cost effectiveness summary derived from information
presented in Table 61. Costs are presented in terms of dollars per percent
of sulfur removed from coal regardless of the quality of the treated
product. However, column 7 of the table shows whether the product would
comply with the current EPA's NSPS for S02 emissions. The processes are
then rated based upon the cost effectiveness of sulfur removal. The
subjective probability of success assigned to each process shown in column
8 of this table is based on integration of several factors such as:
216
-------
TABLE 63. COST EFFECTIVENESS AND OTHER COMPARISONS OF CHEMICAL COAL CLEANING PHCCESSES*
Process
Magnex™
Syracuse &
Physical
Cleaning
TFW
LOL3
ERDA
GE
Battelle
JPL
IGT
KVB
ftHCO
Type of
Sulfur
Removed
PA
P
P
P
(PSO)T
(PSO)
(PSO)
(PSO)
(PiO)
(P«i)
(P&O)
Percent
Sulfur
«
Product
.97
1.506
.83
.83
.65
.50
.65
.60
.55
.68
.69
Percent
Sulfur
Removed
(%)t
0.96
0.43
1.10
1.10
1.28
1.43
1.28
1.33
1.38
1.25
1.24
Process
Cost{$/
metric ton
incl. cost
of coal $
44. U
4U.U
47.9
51.6
56.9
46.0
61.6
50.7
72.6
52.4
_A
Cost Effect-
iveness of
S removal,
S/% S removed
4b.6
94.9
43.5
46.9
44.5
32.2
48.1
38.1
52.6
41.9
_A
Cost
Effect-
iveness
Rank-
ing
2
4
1
3
4
1
5
2
0
3
-
feets
EPA
NSPS*
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Ves
Probability
of Success
(based on
available
info.)
85%
70%
90%
50%
70%
60*
35tt
55%
20%
10%3
_A
Time Frame
for Commerci-
al Avail-
ability
(Years)**
2-3
2-3
-------
• available experimental data;
• our understanding of the status of the process;
• known product quality deficiencies;
• known process problems; and
• the degree and quality of effort assigned to the individual
program.
In conclusion, all chemical coal cleaning processes discussed in this
section offer a possibility of converting coal into clean fuel. Each
process has an area of application. However, processes that remove both
pyritic and organic sulfur will have a greater impact in coal utilization.
If chemical coal cleaning is to be used as an approach for greater utiliza-
tion of coal as an environmentally acceptable fuel, the pyritic and organic
sulfur removal processes should be given the most emphasis and support.
213
-------
SECTION 5
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219
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49. Letter of Mr. J.M. Gross of U.S. Steel to Mr. J. D. Kilgroe of
EPA-IERL. May 18, 1977.
50. Personal Gcnnunication with Warren Schreiner of M.W. Kellogg Company.
July 27, 1977.
51. Personal COnnunication with Tom Dillon of Barnard and Burke.
July 26, 1977.
52. Shigeru, Mukai, et.al., "Desulfurization of Coal by Oxidizing Agents",
Energy Research and Development Administration Transaction Series,
EPDA-tr-49. 1969.
53. Personal Comunication with Satherfield, C.N. of Massachusetts
Institute Technology. May 11, 1977.
54. Satterfield, C.N. ,Massachusetts Institute of Technology, Letter to
James D. Kilgroe, U.S. Environmental Protection Agency. May 11, 1977.
55. Burgess, L.E., "Feasibility Study of Molecular Grafting to Solubilize
Coal - Final Report", Gulf & Western Engineering Center, Swarthmore,
Pennsylvania, ERDA Contract No. E (49-18)-2020. March 1977.
56. Colorado School of Mines Research Institute, "Evaluation of Magnetic
Fluids for Coal Beneficiation". May 1976.
222
-------
SECTION 6
GLOSSARY
ash: The solid mineral residue left after incineration in the presence of
oxygen.
autoclave: A chamber, usually of cylindrical shape, provided with a door
or gate at one end which can be securely closed during operation. It
is built heavily enough to acccncdate pressures of considerable
magnitude. It is used to effect chemical reactions requiring high
temperature and pressure.
beneficiation: A process used to upgrade coal by removing unwanted
impurities.
cladding material: A metal which is banded to another metal by being rolled
together at suitable pressure and temperature.
cyclone: A piece of equipment using centrifugal force to separate materials
by size or density.
electrostatic precipitator: Consists of a source of high voltage current,
an electrode system, an enclosure to provide a collection zone and a
system for removing precipitated dust. Dust particle are electrically
charged by means of ionization of the carrier gas and transported by
the electric field to collecting electrodes. The particles are then
neutralized on the collecting surfaces and removed for disposal.
endothermic: A process or change that takes place with absorption of heat
and requires high temperature for initiation and maintenance.
exothermic: A process or chemical reaction which is accompanied by
evolution of heat.
extractor: Any mechanical device or chemical substance which will allow
the release of one substance from another.
223
-------
filtrate: Liquid passing through a filter.
fluidized bed reactor: A reactor in which finely divided solids are caused
to behave like fluids due to their suspension in a moving gas or
liquid stream.
gas quench tower: A large tower or drum in which a cool liquid is used to
lower the temperature of a hot gas.
incineration; The consumption of material by burning.
leaching: Ihe process of extraction of a soluble component from a mixture
with an insoluble component, by percolation of the mixture with a
solvent.
magnetic fluid: A fluid which is appreciably attracted by a magnet.
magnetic separation: Removal of magnetic material from the coal as it
passes through a magnetic field placed close to the stream of
particles.
microwave: Any electromagnetic radiation having a wavelength in the
approximate range from one millimeter to one meter.
mineral sulfur: Sulfurs that are inorganic in nature (sulfates and
pyrites).
organic sulfur: Sulfur bound in an organic matrix.
pelletize: To form into a solid or densely packed ball or mass.
pyrite: Iron disulfide, FeS2
pyrrhotite: Magnetic pyrites, FeS. A natural iron sulfide. Frequently
has a deficiency in iron. May contain small amounts of nickel,
cobalt, manganese and copper.
sensible heat: The perceptible or measurable effect of energy (heat) on
a substance.
slurry: A watery suspension of solid materials.
224
-------
APPENDIX I
TEW MEYERS' PROCESS
225
-------
KINETIC EXPRESSIONS FOR PYRITIC SULETJR REMOVAL BY THE MEYERS' PROCESS
The survey program (EPA Contract No. 68-02-1647) provided adequate
data which allowed formulation of expressions for pyritic sulfur removal.
Using these data, for lower Kittaning coal, the sulfur removal is expressed
by TRW as:
<**> , ,
r_ = - 3^- = K.W Yz = wt of pyrite removed/100 wts of coal per hr.
Li CTC Li p
(1)
W = wt% pyrite in coal
Y = ferric iron-to-total iron weight ratio in leacher
K. = A^ exp (- E./RT), A. and E.. are constants for each coal and
Xj Xj ^j ^J 11
particle size at least over most of the
reaction range.
This Kinetic equation (Equation 1) can be simplified by holding the reagent
concentration relatively constant and thus can be expressed as
rr = - dWp = KbWp2 (2)
L dt
where KD is a function of temperature, reagent concentration,
coal type, and particle size.
By integrating equation (2), the fraction of pyrite removed as a
function of time can be shown as equation (3)
226
-------
1 1
WF Wp~ = KDtP
W_ -
WF
WFW
P
V^
= KbW
WF
where W - Wp = F , fraction of pyrite removed, Equation (2) can
be expressed as
(3)
Using this equation the removal of pyritic sulfur was measured
as a fraction of time at 100°C for 18 Appalachian and 3 Eastern Interior region
coals.4 The results are presented in Table 1-3 which indicates that significant removal
rate differences do exists between pyrite in various coals.
Hi Table 1-1 the initial weight percent of pyritic sulfur Sp° is
substituted for W and equation (3) is rearranged to equation (4)
^Sp0tp) oK = Actual rate constant (4)
Using this equation and assuming 80 percent sulfur removal as basis
for comparison the values of 1 was calculated for the eighteeen
Appalachian coals. Since extensive engineering and experimental work has been
performed with Martinka coal (as shown in column 7 of Table 1-1) the Sp°t^%
of this coal was set equal to one and was used as the basis of comparison.
The reduced data on (column 7 of Table J-i indicates that the Muskingum coal
reacts much slower (by a factor of about 30) when compared to the Kbpperston
No. 2 coal. 227
-------
TABLE 1-1.
MEYERS' PROCESS: RELATIVE RATE CONSTANTS FOR PYRITIC SULFUR REMOVAL
Coal Mine
Kopperston No. 2
Karris Nos. 1&2
Marlon
Lucas
Shoemaker
Williams
Ken
North River
S^ar
Ma,thies
Pnwhattan No. 4
Homestead
Fox
Isabella
Marti nka
Meigs
Bird No. 3
Dean
Musklngum
Seam
Campbell Creek
Eagle & No. 2 Gas
Upper Freeport
Middle Kittannlng
Pittsburgh
Pittsburgh
No. 9
Corona
No. 9
Pittsburgh
Pittsburgh No. 6
No. 11
Lower Kittannlng
Pittsburgh
Lower Kittannlng
Clarion 4A
Lower Kittannlng
Dean
Meigs Creek No. 9
Top
Size,
Microns
149
149
149
100
149
100
149
149
100
100
75
149
75
149
149
149
100
100
149
Relative Rate Constants
SP°
0.47
0.49
0.90
1.42
2.19
2.23
2.85
1.42
2.66
1.05
2.75
3.11
3.09
1.07
1.42
2.19
2.87
2.62
3.65
hrs
2.0
2.3
3.0
3.25
2.9
3.0
2.5
5.0
3.0
9.0
4.0
3.5
4.5
13.0
10.0
8.5
8.0
10.2
8.0
1
Sp0t80%
1.1
0.89
0.37
0.22
0.16
0.15
0.14
0.14
0.13
0.11
0.091
0.092
0.072
0.072
0.070
0.054
0.044
0.037
0.034
Relative*
Rate
16
13
5.3
3.1
2.3
2.1
2.0
2.0
1.9
1.6
1.3
1.3
1.0
1.0
1.0
0.77
0.62
0.53
0.49
ro
10
CO
NOTE:
* l/Sp°1
relative to value for Martlnka Mine.
-------
MEYERS' PROCESS: CONCEPTUAL DESIGN FOR COMMERCIAL SCALE
Process engineering studies and trade-offs produced a baseline flow
diagram for a commercial scale plant. The flow sheet, which is divided
into its four major sections is given in Figure 1-1. The corresponding
mass balance and stream properties are given in Table 1-2. The baseline
plant size was chosen equal to 100 tons of dry coal feed per hour
equivalent to about 250 Mti power plant feed. This size is about the
maximum size for a single train based on available commercial equipment.
Peed and Mixer—Crushed coal, nominally 14 mesh top size, is feed from
feed hopper A-l. The coal is assumed to have 3.2 percent pyritic sulfur
and 10 percent moisture on a dry basis; thus, the total solids feed rate
is 110 tons per hour (TPH) at room temperature, assumed to be 77°F. The
coal feed, stream 1, is brought to the mix tank, T-l, by conveyor, C-l,
and introduced through the rotary feed valve, RV-1. Recycled leach
solution, stream 4, at its boiling point (215°F) is introduced to the
first mixer stage after first passing through the gas scrubber SP-1. Steam,
streams 2 and 3, is needed to raise the feed coal from 77°F to the 215°F
mixer temperature. Approximately 5.6 TPH of atmospheric pressure steam
is required to heat the coal while 6.5 TPH is available from the flash
drum, T-2. It is possible that the steam would actually be added to
the enclosed conveyor to provide heated coal with an effective 15.6
percent moisture content. The excess 0.9 TPH would be vented through
SP-1 along any flash steam formed in stream 4.
The mixer vessel T-l was sized for three stages of mixing at 0.25
hours per stage. Under the design constraint that the vessel is 75
percent full, the cost model used for vessel sizing found a field
fabricated vessel 18.7 feet in diameter by 32.9 feet long has minimum
cost. The selected vessel size (18 x 36) gives three stages each about
12 feet long and 12.6 feet deep with slightly less than 15,000 gallons in
each stage. Any foam generated during coal wetting will be broken down
and the entrapped air will be scrubbed in SP-1 by the returning leach
solution. The actual air flow through SP-1 is very low and will probably
not exceed the air in the bulk coal (50 cubic feet per minute).
229
-------
A-l
IHO
C-l IV-I
WO IO1AIY
CONVfYOt VAIVI
1.1 M.IA/C
MIX MIX
TANK IAMC
MIMtS
»M I-I l-l M-IA/I «-l V-l l-l
tOMMI- HASH niMAIV rtlMAlY niMAIV KNOCK-OUT JICONOAIV
MHT DMJM MACIOI IIACIOI MCYCU MUM IIACIO*
IUMINATOI MIXIII COMHIKO*
10
M
suuvnio
fUMf
MIA/J
CMCUUIMC
M
HAOOI DBCHAIGC
FIGURE I -1 MEYERS' PROCESS FLOW SHEET FOR FINE COAL
-------
10
U)
M-J CG-» 1-4
WASH CONIACIOI CONIACIOI IAHOM1IIIC Mllll IIII Mil WASH VACUUM CONIACIOft COMlACIOt CIMUIIUGI CUIUAIt
IIUIVU MIXll rtHJUINU* IICCIVII HCtlVIt fUMf MIXU UCUVU
VACUUM IMOMUIIC FNIII MIIMII
CONUIMSII UCflVII
r-e p. n r-4 r-v
WAJMWAIU COOIIhK, WAIIH CONIACIOi
siuwv PUMT ruMr
r-io
COOIINC WAUI
CUAl WMHfUHZAIION MOCtii
WAiHUCIION
4-IO-;5 NO. IU3-OJ
Figure 1-1. (Continued)
-------
4C-I
ICttW
COMVIYOt
O-l II-1
tIAlH IKtlU
MVII v.AV
IUAIII
i-l
CYCLOM
n-J
CUMMUUOI
iC-J
iCO C-l
COM CAS
in DOWN COOIH cooui
KUW CONVIVOI
\1
CYCIONI
S-l
ftlASI
P-II
SUIHM
fUMT
nociu
WAIII
UMTM UMOVAi UOlOH
4-10-71 NO. IUVO)
Figure M-l. (Continued)
-------
NtllilAL-
IZAIION
lANK
J'""" SIAt''
(VAKIIAlOl
i-i
COIK»NI«All
«CYCU
M10IUK
co-.i
SUlfAIt
CIVSlAl
CIMHIfUGl
CINIIAII
tfCUVU
.AHOMIUIC
CONDI Nit »
VACUUM
fUMT
to
r-io
r-iv
UACHKHUIION
KIOINKJMf
r-14
tVAK>KAIUI
COMCtllllAU
r-20
tulO.
IVAKllAIOI
CUNCINIIAIt
r-14 r-i' f-ia
tVAKJtAIOI IVAfORAIOl COOLING
COUCtNllAU HAfM SOIUIION WAUI
PUMC Hiuiri ruMc inuKN ruMf
COM WSUlUJKIiAllON fHOClii
iUUAIl UMOVAl StCIION
6 IO-/1 NO. IJ3i-O<
Figure I-l, (Continued)
-------
1-2.
PROCESS MASS BALANCE FOR FINE COAL
(Stream Flows In Tons Per Hour)
to
Hater
FeS04
Fe.(S04),
H?S04
Pyrlte
Sulfur
Coal
Oxygen
Inert
Total, TPH
T. -F
P. P«19
gpn
P. Ib/ft3
Fe, I
Y
S04/Fe
COAL MAKEUP
FEED STEAM
1 2
10.0 -.9*
6.0
94.0
TTO ^0
77 215
0 -9
.
50.0
-
-
-
FLASH FEED
STEAM SOLN.
3 4
6.5 144.1
3.9
30.6
5.7
67!) T1B7T
215 215
.9 0
614
74.8
5.4
.86
1.75
R-l
FEED
5
159.2
14.4
18.2
8.Q
5.2
.2
94.0
3BO
215
28.8
968
77.3
5.2
.49
1.73
02 RECYCLE
MAKEUP GAS
6 7
1.5
3.9 13.1
Tr .8
37? 1573"
77 264
53.8 53.8
-
-
-
-
-
R-l
GAS
8
14.0
13.4
.8
TS7T
250
28.8
-
-
-
-
-
COMPRESSOR
FEED
9
1.5
13.1
.8
TBTT
177
28.8
-
-
-
-
-
R-l
EXIT
10
147.4
5.8
37.0
5.0
.7
1.1
94.0
29T7o~
250
28.8
907
80.0
6.3
.83
1.64
R-2
FEED
16
140.9
5.8
37.0
5.0
.7
1.1
94.0
spTir
215
0
873
81.3
6.6
.83
1.64
R-2
EXIT
17
140.7
11.1
30.6
6.6
.3
1.2
94.0
TB475-
215
0
874
81.2
6.7
.68
1.64
Excess steam to vent
-------
T&BLE 1-2. (CONTINUED)
Return Vent Crystal lizer
to
hi
Mater
FeS04
Fe2(S04)3
H2S04
Pyrlte
Sulfur
Coal
Oxygen
Inert
Total, TPi:
T, -F
P, Pslg
gpm
P. lb/ft3
Soln. 0;
18 19
131.7 Tr
3.9
30.6
5.7
.4
Tr
171.9 0.4
127 177
28.8 0
S48
78.2
Centrate
20
50.3
2.2
26.0
5.2
83.7
200
30. G
221
95.4
Neutral izer
Return
21
81.4
1.7
4.6
.5
88.2
160
15.0
335
65.6
Neutral izer
to
Crystal 1 izer
22
54.3
1.1
3.1
0.3
58.8
160
15.0
224
65.6
F1 1 trate
to
Cake
Crystal 1 izer F-l
23
105.2
8.3
22.9
4.9
141.3
160
10.0
443
79.6
24
43.1
1.0
3.0
.6
.3
1.2
94.0
143.2
160
0
Wash Contactor
F-l
25
143.
1.
3.
•
147.
Vents
26
1 Tr
0
0 •
6
7 0.0
160 77
10.
0 0
589
-
62.
5
To
F-2
Cont actor Feed
Neutral izer Feed T- 3 Slurry
27
135.5
2.8
7.7
1.7
147.7
160
5.0
561
65.7
28 29
146.3 189.4
.3 1.3
.9 3.9
.2 .8
.3
1.2
94.0
147.7 290.9
160 160
5.0 15.0
601 1065
61.3 68.1
-------
TABLE r-2.
(CONTINUED)
NJ
Water
FeS04
Fe2(S04)3
H«S04
Pyrlte
Sulfur
Coal
Oxygen
Inert
Total. TPH
T. °F
P, Ps1g
gpffl
P. lb/ft3
Cake
F-2
30
47.2
.1
.3
.1
.3
1.2
94.0
143.2
160
0
-
-
Wash
F-2
31
147.2
.1
.3
.1
147.7
160
10.0
607
60.7
Dryer
Water
Return
32
14.3
14.3
215
30.0
60
59.8
Centrifuge
Makeup
Water
33
27.1
27.1
77
30.0
108
62.3
Evaporator
Return
34
72.9
72.9
180
30.0
473
60.2
Feed
SI urry
35
161.5
.1
.3
.1
.3
1.2
94.0
257.5
180
15.0
942
68.2
Cake
Centrifuge
36
14.3
Tr
Tr
Tr
0.3
1.2
94.0
109.8
180
0
-
-
Dryer
Gas
37
258.9
Tr
Tr
258.9
650
20.0
-
-
Dryer
Output
38
273.2
Tr
Tr
Tr
0.1
1.2
41.4
315.9
450
18.0
-
-
Dryer
Coarse
Cut
39
Tr
Tr
Tr
Tr
0.2
Tr
52.6
52.8
450
18.0
-
-
Cyclone
Solids
40
Tr
Tr
Tr
Tr
0.1
Tr
41.3
41.4
450
18.0
-
50.0
Purge Coal
Steam Product
41 42
0.1 0.1
Tr
Tr
Tr
0.3
Tr
93.9
0.1 94.3
300 150
18.0 0
-
50.0
Cyclone
Gas
43
273.2
1.2
.1
274.5
450
17.8
-
-
Cooler
Water
Feed
44
1137.4
1137.4
215
30.0
4745
59.8
-------
TRBLE 1-2.
(CONTINUED)
Separator CrystalHzer Llq. Steam Steam Liq. Steam
N»
Mater
FeS04
Fez(S04)3
H2S04
Pyrlte
Sulfur
Coal
Oxygen
Inert
Lime
fypsum
Total . TPH
T, -F
P, Pslg
gpm
P, lb/ft3
Cool er Gas
Effluent Effluent
45 46
1410.6 258.9
1.2 Tr
.1 Tr
1411.9 258.9
250 250
15.0 15.0
Separator
Liquid
47
1151.7
1.2
.1
1153.0
250
15.0
4851
59.2
Reboiler
Feed
48
1151.7
1151.7
250
40.0
4851
59.2
Mater
Return
49
1151.7
•
1151.7
215
30.0
4802
59.8
Sulfur
Product
50
1.2
0.1
1.3
215
25.0
2.9
112.0
From
EV-1
51
124.1
9.4
26.0
5.2
164.7
120
5.0
516
79.6
to
Vacuum
52
35.4
35.4
115
(1.5
Psla)
From From
EV-2 EV-2
53 54
35.2 88.9
9.4
26.0
5.2
35.2 129.5
150 155
(3.7 5.0
r S 1 a J
-------
Primary Reactor—The fully wetted and deaerated coal slurry from the mixer
is pumped by slurry pump P-l (stream 5) into the first stage of the primary
reactor R-l. Both removal of pyrite and oxidation of ferrous to ferric
iron sulfate occur in this reactor. A five stage reactor was selected
since the cost model showed the minimum cost field fabricated vessel had
length to diameter ratios near five. Uhder the design constraint that the
reactor must have five stages and operates about 85 percent full, the cost
model found a reactor 25.9 feet in diameter by 127.7 feet long operated at
15 psi of oxygen was minimum cost. The selected vessel size (26 x 125)
gives five stages each about 25 feet long by 23 feet deep and holding about
80,000 gallons of slurry. At the residence time of 1.5 hours per stage, a
temperature of 250°F and an oxygen partial pressure of 15 psi, the pyrite
is reduced to 88 percent of the original level and the leach solution is
regenerated to a Y (ferric iron to total iron ratio) of 0.83 in the primary
reactor.
Oxygen Loop—Excess oxygen saturated with steam and containing an equilib-
rium level of inert gas (mainly argon) leaves the primary reactor in stream
8. The gas is contacted with returning leach solution, stream 18, in a
knock-out drum, vessel V-l. The leach solution is wanned to 215°F (stream
4) by condensing steam from the oxygen stream. The gaseous effluent, which
was assumed to leave V-l 50°F warmer than the feed leach solution is split
to give a small vent stream 19 and a recycle oxygen stream 9. The vent
rate is selected to maintain the inert gas at the design level; namely 5
percent on a dry basis. The recycle oxygen is compressed by K-l to the
reactor feed pressure. Makeup oxygen, stream 6, is added to balance the
oxygen used for regeneration in R-l and that vented to remove inerts.
Assuming 15 psia oxygen pressure the gas pressures in reactor R-l at
250°F are as follows:
Oxygen 15.0 psia
Inert Gas .8 psia
Steam 27.7 psia
43.5 psia (28.8 psig)
238
-------
Since the recycle gas must also overcome the liquid head in the reactor
(about 13 psi), the control valve/injector drop (about 10 psi) and other
line losses, the recycle compressor was sized to provide a 25 psi pressure
increase. For the baseline case this results in a 300 horsepower compressor
operating at a 1.58 compression ratio and a compressor outlet pressure of
53.8 psig.
Flash Steam—The heat of reaction and regeneration is accommodated in
three ways: temperatures of the recycled oxygen and the feed slurry are
raised in R-l, heat is lost from the insulated walls of the mixer and
reactors, and water is evaporated from the solutions. Part of the steam
(13.4 TPH) is removed from the recycle oxygen to provide an isothermal
primary reactor R-l at 250°F and part of the steam (6.5 1PH) is removed
by flash drum T-2 in dropping and slurry temperature and pressure from
reactor R-l (250°F) to reactor R-2 (215°F). 3he heat is almost entirely
utilized in heating the feed coal and the recycle leach solution.
Secondary Reactor—Bie secondary reactor, R-2, is operated near the atmo-
spheric boiling point with a residence time of 36 hours. During this tine,
additional pyrite is removed from the coal to provide an overall pyrite
removal of 95 percent while the Y of the solution is decreased to a value
of 0.68 in the reactor effluent. The low value of Y is desired to provide
sufficient ferrous sulfate for removal as the by-product iron form. The
cost model found the minimum cost reactor was 27.9 feet in diameter by
465.9 feet long. The final equipment list and costing used three field
fabricated vessels each 28 feet in diameter and 160 feet long. The reactors
contain no internal stages, but have circulating pumps to avoid large
vertical concentration gradients from occurring in the solution. The
slurry from the secondary reactor, stream 17, is pumped by P-2 to the
first filter, P-l.
Ooal Washing—Bench-scale experience with removal of the sulfate leach
solution from coal shows that the solution may be treated as consisting of
two types. Surface solution is readily removed by flushing with water or
may be readily displaced by a more dilute wash solution. Solution in
the pores of the coal particles requires a definite residence time to reach
239
-------
equilibrium with the bulk or surface liquid. The coal washing section,
therefore, consists of filtration, washing on the filter, equilibration
with dilute solution, a second filtration and wash, equilibration with
wash water and finally dewatering in a centrifuge.
First Filter—Opal slurry from the secondary reactor, stream 17, containing
approximately 33 percent solids is fed to a 12 foot diameter by 24 foot
long rotary vacuum filter, F-l. The filtrate from vacuum receiver V-2,
stream 23, is pumped, P-5, to the sulfate removal section. Dilute wash
solution from the second filter, stream 25, is used to wash the filter
cake and displace the surface solution on the coal particles. This
sulfate rich wash solution, stream 27, is pumped, P-6, from the vacuum
receiver V-3 to the sulfate removal section. Vacuum is provided by a
3,000 standard cubic feet per minute (SCEM) vacuum pump, VP-1, which is
vented, stream 26, back to the enclosed filter F-l. The vapors and gases
removed from the vacuum receivers, V-2 and V-3, pass through a barometric
condenser, B-l, before entering the vacuum pump. In B-l most of the
flash steam is condensed and enters the cooling water loop where it is
pumped to the cooling water tower by P-10.
First Stage Repulping—The washed filter cake from the first filter, stream
24, and dilute wash water Iran the second filter are gravity fed through a
closed chute to a stirred tank, T-3. This 40,000 gallon tank is operated
about three-fourths full to give an average residence time of 30 minutes
to equilibrate pore solution with the bulk liquid. The slurry, stream 29,
is pumped, P-3, to the second stage filter. Pny gases introduced with the
cake are vented to the scrubbing system, stream 26.
Second Filter—The partially washed slurry, stream 29, containing approxi-
mately 33 percent solids, is filtered and washed on a second filter of the
same size and type as the first filter. Filtrate, stream 25, is pumped,
P-7, from the vacuum receiver, V-4, to the first filter wash. Wash water
for the second filter, stream 31, is obtained from the centrate receiver.
The partially spent wash water is pumped, P-8, from the vacuum receiver
V-5 to the first stage contractor. Vacuum is provided by vacuum pump
VP-2 operating through the barometric condenser B-2.
240
-------
Second .Stage Rspulping—Ihe washed filter cake from the second filter,
stream 30, is contacted with water in a 40,000 gallon stirred tank, T-4.
The wash water, streams 32, 34, and 33 is obtained from the dryer, the
evaporators, and makeup, respectively.
Dewatering—The slurry from the second contractor, stream 35, is pumped
P-4, to the dewatering centrifuge, CG-1. The slurry with approximately 33
percent solids is separated in the 36 inch diameter by 90 inch long solid
bowl centrifuge to provide a dewatered coal is expected to have about 15
percent moisture. The centrate from receiver T-5 is pumped, P-9, to
provide the wash, stream 31, for the second filter.
Drying—Goal from the centrifuge, stream 36, is fed to a flash dryer, D-l,
by a screw feeder, SC-1. In this dryer concept the coal is heated to
about 450°F by superheated steam, stream 37, and carried upward to the
enlarged top area of the dryer. The larger particles are removed from
the dryer, stream 39, while the fine particles and gas, stream 38, are
fed to a cyclone, S-l. During the drying in D-l sulfur is also vaporized
from the coal and is present along with water vapor in the cyclone effluent
gas stream 43. Ihe fine coal from the cyclone, stream 40, and coarse coal,
stream 39, are let down to atmospheric pressure by screw conveyor SC-2
which is back purged with a small quantity of steam to prevent the sulfur
containing gas in the cyclone from leaving the system with the coal. The
coal, stream 42, is then transported and cooled to product storage tempera-
ture by the screw conveyor, SC-3 which rejects heat either to cooling
water or to the atmosphere.
Sulfur Removal—The cyclone effluent gas, stream 43, at about 450°F is
cooled by a large spray of water, stream 44, in gas cooler C-l. The water
is obtained from return stream 49 from the sulfate removal section. The
gas and liquid, stream 45, cooled to 250°F is separated in cyclone S-2
to give vapor stream 46 and liquid stream 47. The liquid stream 47
contains the water fed to the gas cooler, stream 44, the water vaporized
from the coal in the dryer, and the sulfur vaporized from the coal. The
liquid is phase separated in vessel S-3. The liquid sulfur by-product,
stream 50, is pumped, P-13, to storage while the hot water, stream 48,
is pumped, P-12, to the sulfate removal section.
241
-------
Steam Circulation—Saturated steam at 250°F from the cyclone, stream 46,
is compressed by K-3, reheated by H-l, and fed to the dryer as stream 37.
Compression is accomplished by two 3500 HP series compressors which make up
the 10 psi pressure drop around the gas circulation loop. The heater pro-
vides nearly 100 million BIU per hour (MM BTO/hr) to the steam to supply
the heat required to heat the dryer feed, stream 36, to 450°F and vaporize
the water and sulfur. Slightly more than 80 MM BTO/hr are rejected to the
hot water loop, stream 48, for use in the sulfate removal section while
about 15 MM BTO/hr are lost from the equipment and lines or rejected as
sensible heat in the hot coal and liquid sulfur. The circulating water
is kept in balance by returning a portion of the water, stream 32, to the
wash section equal to the water vaporized from the feed coal, stream 36.
Neutralization—Sulfate rich wash solution from the wash section, stream
27, is fed to a stirred tank, T-7, and a lime slurry, stream 58f is added
to neutralize part of the sulfuric acid. The tank is sized for about 10
minutes of residence time and has a baffled settling zone. Gypsum slurry
stream 59 is withdrawn for disposal and the partially neutralized liquid
is removed by pump P-19. A portion of the liquid, stream 21, is returned
to the reactor section while the remainder, stream 22, is combined with
the filtrate, stream 23, as feed to the triple effect evaporators.
Evaporation—Evaporator EV-1 is operated at partial vacuum (about 0.1 atmo-
spheres) and uses condensing steam from the second evaporator, stream 53,
to evaporate water, stream 52, in the first evaporator. The evaporated
water is condensed in the barometric condenser, B-3, and any residual gas
is removed by vacuum pump VP-3. Hie partially concentrated leach solution,
stream 51, is pumped, P-14, to the second evaporator, EV-2. Ihe second
evaporator operates at about 155°F and 0.2 atmospheres using steam from
the third evaporator, stream 55, to evaporate the water, stream 53. Ihe
two condensate streams from the reboilers of the first and second evapo-
rators (streams 53 and 55) are combined, stream 34, to provide clean wash
water for the wash section. One leach solution from the second evaporator,
stream 54, which has been concentrated to 8.3 percent iron, is at a
temperature where the solubility of ferrous sulfate is a maximum and is a
solids free solution. This stream is feed to the third evaporator, EV-3,
242
-------
which is operated at atmospheric pressure and at the normal boiling point
of the solution. Heat to vaporize water is provided to the reboiler, E-l,
by the hot water loop from the wash section (streams 48 and 49). The over-
head steam, stream 55, is used in the second evaporator as previously de-
scribed. The leach solution in EV-3 is concentrated to a total iron
concentration of nearly 12 percent which exceeds the solubility of ferrous
sulfate. Thus, crystalline ferrous sulfate forms in EV-3 and a portion of
the slurry, stream 56, is fed to a centrifuge CG-2 to separate the crystals,
stream 57, from the concentrated leach solution, stream 20. The concentrated
leach solution is pumped, P-17, to the reactor section.
Solubilities—Since the solubility of ferrous sulfate in the presence of
ferric sulfate, sulfuric acid and trace ions is not yet fully defined, the
baseline process flows may require some adjustment when pilot scale data
have been evaluated. Nevertheless, the planned mode of operation which
takes advantage of the reported solubility characteristics of ferrous sul-
fate in aqueous solution should be applicable. Below about 150°F, the
equilibrium crystalline phase is PeSOii-THzO which has an increasing solu-
bility with temperature. It reaches a maximum solubility of nearly 60
grams of FeSO., (anhydrous basis) per 100 grams of water. Above about 150 °F
the equilibrium solid phase is FeSOi»-H20 which has a decreasing solubility
in water with increasing temperature. Both the first and second stages
of evaporation are below the saturation limits and are expected to remain
solids free. Only the final stage operates as a crystallizer and produces
crystalline ferrous sulfate both from a decreased solubility at the higher
temperature and from an increased concentration because of evaporation.
243
-------
TABLE 1-3. MEYERS' PROCESS COAL DESULFURIZATICN PROCESS EQUIPMENT LIST
REACTOR SECTION $3.26 MM FOB, $6.36 MM INSTALLED*
1
2
3
4
5
6
7
!u 8
* 9
10
11
12
13
14
15
A-l
C-l
K-l
M-1A/C
M-2A/B
P-l
P-2
P-22A/J
R-l
R-2
RV-1
SP-1
T-l
T-2
V-l
Ground Coal Feed Happer - 5,000 ft3
Feed Conveyor - 20 in Wide x 20 ft, 5 hp, 200 ft/min
Oxygen Recycle Compressor - 300 hp, 1.6 Compression Ratio
Mix Tank Mixers (3) - 15 hp, Stainless Steel (SS)
Primary Reactor Mixers (5) - 200 hp, SS
Slurry Feed Pump - 1,000 gpm, 60 psi, 50 hp, SS
Reactor Discharge Punp - 875 gpm, 5 psi, 3.5 hp, SS
Circulation Pumps (12) - 1,000 gpm, 5 psi, 4.0 hp, SS
Primary Reactor - 26 ft 0 x 125 ft, Carbon Steel (CS) with SS
Secondary Reactor (3) - 28 ft 0 x 165 ft, SS, 0 psig
Rotary Valve - .5 hp, 18 in x 18 in , 20 RPM
Scrubber-Mist Eliminator - 3 ft 0 x 10 ft, SS, 0 psig, Baffles
Mix Tank - 18 ft 0 x 36 ft, SS, 0 psig
Flash Drum - 5 ft 0 x 10 ft, SS, 5 psig
clad, 30 psig
, Danister Pad
Knock-Out Drum - 5 ft 0 x 25 ft, SS, 30 psig, 15 ft Packing, Demister Pad
"Installed costs for each process section were derived through the application of the appropriate
GUthrie factor6 to the FOB cost of individual pieces of equipment.
-------
TABLE 1-3. (CONTINUED)
WASH SECTION $1.16 Ml FOB, $2028 MM INSTALLED
1
2
3
4
5
6
7
8
9
10
11
g «
13
14
15
16
17
18
19
20
21
22
23
24
25
B-l
B-2
OG-1
F-l
F-2
M-4
M-5
P-3
P-4
P-5
P-6
P-7
P-8
P-9
P-10
P-ll
T-3
T-4
T-5
V-2
V-3
V-4
V-5
VP-1
VP-2
Barometric Condenser - SS, Condensation Rate = 13 ton/hr
Barometric Condenser - SS, Condensation Rate = 2.5 ton/hr
Centrifuge (4) - 36 in 0 x 90 in Solid Bowl, SS, 150 hp
Rotary Vacuum Filter - 12 ft 0 x 24 ft Drum, 912 ft2, SS, 8 hp
Rotary Vacuum Filter - 12 ft 0 x 24 ft Drum, 912 ft2, SS, 8 hp
Contactor Mixer, 35 hp, SS
Contactor Mixer, 35 hp, SS
Contactor Slurry Pump - 1,065 gpm, 15 psi, 15 hp, SS
Contactor Slurry Pump - 950 gpm, 15 psi, 10 hp, SS
Leach Filtrate Pump - 450 gpm, 10 psi, 3.5 hp, SS
Leach Wash Water Pump - 560 gpm, 5 psi, 2.5 hp, SS
Filtrate Pump - 590 gpm, 10 psi, 5 hp, SS
Wash Water Pump - 560 gpm, 5 psi, 2.5 hp, SS
Oentrate Pump (4) - 150 gpm, 10 psi, 1 hp, SS
Cooling Water Return Pump - 1,200 gpm, 5 psi, 5 hp
Cooling Water Return Pump - 200 gpm, 5 psi, 1 hp, CS
Contactor - 40,000 gal, 0 psig, SS
Contactor - 40,000 gal, 0 psig, SS
Centrate Receiver (4) - 650 gal, 0 psig, SS
Filtrate Receiver - 2,000 gal, Vac, SS
Wash Receiver - 2,500 gal, Vac, SS
Filtrate Receiver - 2,500 gal, Vac, SS
Wash Receiver - 2,500 gal, Vac, SS
Vacuum Pump - 3,000 SCFM, 200 hp, CS
Vacuum Pump - 3,000 SCFM, 200 hp, CS
-------
TftHLE 1-3. (CONTINUED)
SUUUR REMJVAL SECTION $1.42 NM FOB, $2.94 Ml INSTALLED
1 G-l Gas Cooler - 7 ft 0 x 100 ft, Water Sprays, SS, 15 psig
2 D-l Flash Dryer - 11 ft 0 x 65 ft Drying Section, 22 ft 0 x 20 ft
De-entrainment Section, SS, 20 psig
3 B-l Recycle Gas Heater - 97 M* Bta/ftrt Radiant Section = 6,000 ft2,
Convective Section = 12,000 ft2, SS Ttibes
4 K-3 Conpressor (2) - 1.15 Conpxession Ratio, 3,500 hp
5 P-12 Process Water Purtp - 4,850 gpm, 40 psi, 150 hp, CS
*> 6 P-13 Sulfur Potp - 3 gpm, 25 psi, 0.5 hp, SS
7 S-l cyclone Separator - SS, 15 psig, 120,000 PCEM Capacity
8 S-2 Cyclone Separator - SS, 15 psig, 107,000 ACEM Capacity
9 S-3 Phase Separator - 50,000 gal, 15 psig, SS
10 SC-1 Screw Conveyor - 20 ft x 14 in 0, 2 hp, SS
11 SC-2 Pressure Let Down Screw Conveyor - 20 ft x 14 in 0, 2 hp, CS
12 SC-3 Coal Pooler - Screw Type, 20 ft x 14 in 0, Cooled Shell, CS, 2 hp
-------
TABLE 1-3. (CONTINUED)
SULFRTE REMOVAL SECTION $0.97 MM FOB, $1.68 m INSTALLED
1 B-3 Barometric Condenser - SS, Condensation Pate = 35.4 ton/hr
2 CG-2 Sulfate Crystal Centrifuge - 36 in 0 x 72 in Solid Bcwl, SS, 125 hp
3 E-l Concentrate Pecycle Reboiler - 10,000 ft2, SS/SS
4 EV-1 First Stage Evaporator - Evaporation Rate = 35 ton/hr, 1.5 psia, SS
5 EV-2 Second Stage Evaporator - Evaporation Rate = 35 ton/hr, 3.7 psia, SS
6 EV-3 Third Stage Evaporator - Evaporation Rate = 38 ton/hr, 13 psia, SS
7 M-6 Neutralizer Mixer - 5 hp, SS
8 P-14 Evaporator Concentrate Pump - 520 gpm, 5 psi, 2.0 hp, SS
9 P-15 Evaporator Concentrate Punp - 380 gpm, 5 psi, 1.5 hp, SS
10 P-16 Evaporator Concentrate Punp - 1,380 gpm, 5 psi, 5.0 hp, SS
11 P-17 Leach Solution Return Puip - 220 gpm, 30 psi, 5.0 hp, SS
12 P-18 Cooling Water Return Punp - 8,000 gpm, 5 psi, 30 hp, CS
13 P-19 Leach Solution Return Punp - 560 gpm, 30 psi, 10 hp, SS
14 P-20 Calciun Sulfate Slurry Punp - 3 gpm, 5 psi, 0.5 hp, SS
15 T-6 Centrate Receiver - 900 gal, SS, 0 psig
16 T-7 Neutraliaer Tank - 7,500 gal, SS, 0 psig
17 VP-3 Vacuum Punp - 700 CFM, 50 hp
TOTAL ESTIMATED CAPITAL $6.81 m FOB. $13.26 MM INSTAT.T.Kn
-------
APPENDIX II
LEDGEMONT PROCESS
248
-------
TABLE II-l REPRESENmnVE ANALYSES OF ILLINOIS
#6 AND KENTUCKY CXlALS
Coal Source
Ultimate Analyses (dry basis)
Carbon
Hydrogen
Nitrogen
Sulfur (total)
Sulfur (pyritic)
Oxygen
Ash
Heating value kg cal/kg
(BlU/lb)
Moisture content (RCM)
Illinois #6
(RCM Coal)
62.78
4.31
1.03
4.85
2.0
7.13
19.90
6,180 (11,140)
13.88
Kentucky
(Washed Coal)
71.4
5.08
1.68
3.55
N/A
9.67
8.00
7,395 (13,325)
9.32
249
-------
APPENDIX III
MAGNEX PROCESS
250
-------
+ 14
MESH
COAL
AS RECEIVED 8
TOP SIZED COAL
10"x 20" DENVER
JAW CRUSHER
3/4" TOP SIZE
HAMMERMILL
-14 MESH COAL
14 MESH
SWECO SCREEN
LJ.
UNTREATED
COAL
FIGURE III 1 MAGNEX PILOT PLANT SCHEMATIC, CRUSHING STEP
251
-------
VENT
UNTREATED COAL
FROM CRUSHING STEP
j
FEED BIN 8 SCREW FEED
/SCR SPEED CONTROL
STEAM
GENERATOR
MOISTURE
TRAP
HOT OIL
HEATER
HOLOFLITE HEATER ill
HOT COAL
TO REACTOR
FIGURE III -2 MAGNEX PILOT PLANT SCHEMATIC, HEATING STEP
252
-------
CARBONYL
STORAGE
CARBONYL
METERING
PUMP
HOT COAL FROM
HEATING STEP
VENT
CARBONYL
COLUMN
TREATED
COAL
FIGURE III-3 MAGNEX PILOT PLANT SCHEMATIC, CARBONYL TREATMENT STEP
253
-------
FROM CARBONYL
TREATMENT STEP
FEED
HOPPER
NON MAGNETIC
CLEAN COAL
t
MAGNETIC
REFUSE
FIGURE III -4 MAGNEX PILOT PLANT SCHEMATIC, MAGNETIC SEPARATION STEP
254
-------
APPENDIX IV
SYRACUSE PROCESS
255
-------
TABLE IV-1 ANALYSES OF UPPER FREEPQRT SEAM, PITTSBURGH SEAM,
SEAM) GOAL, AND ILLINOIS NUMBER 6 SEAM GOAL SAMPLES.
18
(UPPER AND LONER FREEPOKT
KJ
We 1 gilt Percent (eicept BTU)
*4
Upper Preeport Sees Coal
Holature
Volet lie
Aeh
Filed C
Sulfur
Brltleh Tltenal Unit*
per pound
Sulphate sulfur
Pyrltlc aulfur
Organic eulfur
Carbon
Hydrogen
N 1 1 rogen
Oxygen
? Coel wu etr dried.
T R.O.M. coel «e received
T I.O.M. cuel ee received
Air Dried
1.01 .
26.31
17. *B
M.J2
2.74
1239?
0.15
2.20
0.41
49.61
4.27
0.99
1. 18
Iron mint
tram eilue
Dry
El
26.60
18.16
SS.99
2.79
12S23
0.1J
2.22
0.42
70.32
4.31
1.00
3.42
bed 5.371 BOleture.
hed I. 191 Mileture.
*
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FIGURE IV -1 SYRACUSE PROCESS VS. MECHANICAL CRUSHING: SIZE CONSIST
OF UPPER FREEPORT COAL
-------
o -11/2"R.O.M. Sample
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x -14 M, Mechanically Crushed,
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FIGURE IV -2 SYRACUSE PROCESS VS. MECHANICAL CRUSHING: PERCENT SULFUR
VS. PERCENT RECOVERY OF UPPER FREEPORT COAL
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VARIOUS PITTSBURGH COALS
-------
APPENDIX V
ERDA PROCESS
260
-------
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Figure V-l (Ctantinved)
-------
APPENDIX VI
JPL PROCESS
263
-------
TABLE VE-1. JPL PROCESS: PROXIMATE ANALYSIS DATA OF TWO TESTED COALS
Fixed Volatile
Coal Carbon Matter Moisture Ash
Illinois
No. 5 42.74% 36.35% 9.88% 11.03%
Kentucky
No. 9 52.45% 35.0% 4.49% 8.06%
31
264
-------
APPENDIX VII
IGT PPOCESS
265
-------
TABLE VH-1. IGT PROCESS: ANALYSIS OF WESTERN KENTUCKY
ND. 9 GOAL USED IN BATCH REACTOR RUNS
Proximate Analysis , wt.%
Moisture
Volatile Matter
Ash
Fixed Carbon
Total
Ultimate Analysis , wt.%
Ash
Carbon
T¥. Billnr-1 r»n»l
Hycuxxjeii
Sulfur
Nitrogen
Oxygen
Total
5.8
36.3
10.6
47.3
100.0
11.24
70.00
4.54
3.74
1.53
8.95
100.00
Goal
5.8
36.3
10.6
47.3
Pretreated Goal
0.8
27.7
11.2
60.3
+40 Mesh
Pretreated
Coal
1.6
26.7
14.1
57.6
100.0 100.0
100.00 100.00
266
-------
TABLE VII-2. IOT PROCESS: THERMOBALANCE TEST BUN DMA, PKEXKEWIB) WESTEKN KB4IUCKY 19 GOAL
Run H>.
Feed Goal*
Pretreated Goal
TB-76-8
KJ
Goal
Heating Rate, "F/taln
terminal Tenperature, °P
Holding Tine i min
Sulfur, wt I
Sulfide
Sulfate
Pyritic
Organic
•total
Height, g
Initial
Treated
Height toes, %
1btal, wt
Octal, wt
Reduced Data
Haight, Ib
Sulfur Haight, Ib
Sulfide
Sulfate
Pyritic
Organic
Ibtal
Sulfur Content, %
Sulfide
Sulfate
Pyritic
Organic
•total
Sulfur Removal, wt »
FLuni Peed
Fran Goal
W. Ky. No. 9
Fret. W. Ky. No. 9
0.02
0.52
0.92
1.57
3.03
100.00
0.02
0.52
0.92
1.57
3.03
0.02
0.52
0.92
1.57
3.03
750
30
0.01
0.10
1.25
1.29
2.65
90.84
9.16
9.16
90.84
0.01
0.09
1.13
1.17
2.40
0.01
0.10
1.25
1.29
2.65
20.5
Feed
0.01
0.10
1.25
1.29
2.65
5
1,500
30
Residue
0.19
0.00
0.03
0.28
0.50
2.2871
90.84
0.01
0.09
1.13
1.17
2.40
1.5766
31.07
31.07
62.62
0.12
0.00
0.02
0.18
0.32
0.03
0.28
0.31
87.1
89.8
*Cnl pointed for -HO mesh fraction.
-------
TABLE VII-3. IOT PROCESS: THHW3BALANCE RUN DMA, WESTERN KBOUCltf
NO. 9 COAL (RAPID HEMHJP WOE)
OS
Line/Goal Feed Ratio
Goal
Heating Rate,eF/taln
Terminal Temperature, °F
Holding Time, min
Sulfur, wt %
Sulfide
Sulfate
Pyritic
Organic
Total
Weight,g
Initial
Treated
Weight loss, %
Total Weight
Goal Weight
Reduced Data
Weight, Ib
Sulfur Weight, Ib
Sulfide
Sulfate
Pyritic
Organic
Total
Sulfur Content, %
Sulfide
Sulfate
Pyritic
Organic
Total
Sulfur Removal, wt %
Fran Feed
From Coal
Feed Goal* Pretreated Goal*
H.Xy.No.9
0.02
0.52
0.92
1.57
3767
100
0.02
0.52
0.92
1.57
77o7
0.02
0.52
0.92
1.57
17C5
750
30
0.01
0.10
1.25
1.29
7755
90.84
9.16
9.16
90.84
0.01
0.09
1.13
1.17
TTW
0.01
0.10
1.25
1.29
7755
20.5
TB-76-24
0:1
Rapid Heating
1500
120
Peed Residue
0.01 0.13
0.10 0.00
1.25 0.02
1.29 0.14
776? OT2T
TB-76-45
TO-76-46
Otl Oil
Pretreated W.Ky.No.9
Rapid Heating
1500
90
Feed Residue
0.01 0.23
0.10 0.00
1.25 0.02
1.29 0.32
7755 5757
Rapid Heating
1500
60
Feed Residue
0.01 0.23
0.10 0.01
1.25 0.02
1.29 0.46
7755" O7
TB-76-47
0:1
Rapid Heating
1500
30
Feed Residue
0.01 0.41
0.10 0.01
1.25 0.02
1.29 O.S7
7755 OT
TB-76-48
Otl
Rapid Heating
1500
15
Peed Residue
0.01 0.50
0.10 0.02
1.25 0.00
1.29 0.68
7755 ITTff
2.5892
1.7646
2.9610
2.0686
2.8700
2.0121
90.84
0.01
0.09
1.13
1.17
77W
0.01
0.10
1.25
1.29
7755
31.85
31.85
61.91
0.08
0.00
0.01
0.09
Off
0.02
0.14
5716"
95.8
96.7
90.84
0.01
0.09
1.13
1.17
77*0"
0.01
0.10
1.25
1.29
7755
30.14
30.14
63.46
0.15
0.00
0.01
0.20
O5"
0.02
0.32
OT
91.3
93.1
90.84
0.01
0.09
1.13
1.17
2730"
0.01
0.10
1.25
1.29
7755
29.89
29.89
63.69
0.15
0.01
0.01
0.29
O5"
0.02
0.46
Off
87.5
90.1
2.7170
1.9329
90.84
0.01
0.09
1.13
1.17
ITW
0.01
0.10
1.25
1.29
776T
28.86
28.86
64.62
0.26
0.01
0.01
0.37
578T
0.02
0.57
0759"
84.2
87.5
2.5688
1.8493
90.84
0.01
0.09
1.13
1.17
27W
0.01
0.10
1.25
1.29
7755"
28.00
28.00
65.40
0.33
0.01
0.00
0.44
Off
0.00
0.68
Off
81.7
85.5
•Calculated for -HO mash.
-------
TABLE VII-4. ICT PROCESS: THHWOBftLANCE RUM DMA, ILLINOIS NO. 6 GOAL
. .
ft
vo
Run Mo.
Heating Rate, °F/tein
Terminal Temperature, °F
Holding Tine, odn
Sulfur, wt *
Sulfide
Sulfate
Pyritic
Organic
•total
Height, g
Initial
Treated
Height loss, «
Tbtal Height
Ooal Weight
Reduoed Data
Height, Ib
Sulfur Height, Ib
Sulfide
Sulfate
Pyritic
Organic
Tbtal
Sulfur Content %
Sulfide
Sulfate
Pyritic
Organic
total
Sulfur Removal, wt %
Fran Freed
From Ooal
Feed Ooal*
0.00
0.01
0.99
1.28
100
100.00
0.00
0.01
0.99
1.28
2~72TT
0.00
0.01
0.99
1.28
Pretreated Ooal
750
30
0.01
0.01
0.63
1.39
IH5T
90.4
9.6
9.6
0.01
0.01
0.57
1.26
I78T
0.01
0.01
0.63
1.39
18.9
Feed
0.01
0.01
0.63
1.39
2.4040
90.4
0.01
0.01
0.57
1.26
0.01
0.01
0.63
1.39
or
TB-76-42
5
1,500
30
Residue
0.04
0.00
0.03
0.37
1.6678
30.65
30.65
62.69
0.03
0.00
0.02
0.23
Off
0.03
0.37
OTTO
86.5
89.0
•Calculated for -MO mesh fracton.
-------
TABl£ VII-5. IGT PHUO25S: BATCH KEflCKJK TEST HUN DMA FOR PRETOEAItC HESITON KENIUCKY NO. 9 GOAL
to
Run Ma.
Peed Goal*
440 Mesh
Pretreated Goal
Feed Ratio
Goal
Heating Rate, °F/hdn
Terminal Taqaerature, °F
Holding Tine, ndn
Sulfur, wt %
. Ky. Nt>. 9
750
30
Sulfide
Sulfate
Pyritic
Organic
total
Weight, g
Initial
Treated
Weight loss, %
Total Weight
Goal Weight
Reduced Data
Height, Ib
Sulfur Height, Ib
Sulfide
Sulfate
Pyritic
Organic
Total
Sulfur Content %
Sulfide
Sulfate
Pyritic
Organic
Total
Sulfur Removal, wt *
From Feed
From Goal
0.02
0.60
1.06
1.82
100.00
0.02
0.60
1.06
1.82
0.02
0.60
1.06
1.82
0.04
0.10
1.54
1.38
175?
90.84
9.16
9.16
0.04
0.09
1.40
1.25
2T7ff
0.04
0.10
1.54
1.38
20.6
BR-76-3
0:1
5
1,500
30
Feed
0.04
0.10
1.54
1.38
75.0
90.84
51.7
31.1
31.1
62.62
0.04
0.09
1.40
1.25
2"77ff
0.04
0.10
1.54
1.38
"OS"
0.08
0.00
0.01
0.23
OZ
0.02
0.37
u73?
Heat Value, BTU/lb
12,454
11,809
91.4
93.1
11,967
•Calculated for 40 mesh fraction.
-------
TABLE VII-6. ILLINOIS NO. 6 ANALYSES
Proximate Analysis , wt.%
Moisture
Volatile Matter
Ash
Fixed Carbon
Total
Ultimate Analysis (dry),wt.%
Ash
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Total
Coal
1.3
37.3
8.5
52.9
Pretreated Coal
0.4
28.5
9.4
61.7
+40 Mesh
Pretreated
Coal
l.P
27.6
8.8
_62.0
100.0
100.0
100.0
8.63
74.50
4.91
2.77
1.49
7:70
9.42
75.20
4.30
2.16
1.66
7.26
8.98
74.80
4.29
2.34
1.55
8.04
100.00
100.00
100.00
271
-------
TABLE VII-7. IOT PROCESS: BATCH REACTOR TESTS-PRKIttEKIED ILLINOIS NO. 6 (-10+40 MRH) COM.
am NO.
Lima/Coal Peed Ratio
Feed Coal*
Pretreated Goal
BR-76-34
0:1
to
Heating Rate, °F/hdn
Terminal Tanperature, °F
Holding Time, rain
Sulfur, wt %
Sulfur Removal, wt %
From Feed
Fran Ooal
Heat ValiM, BTU/lb
750
30
Sulfide
Sulfate
Pyritic
Organic
•total
Height, g
Initial
Treated
Height Loss, %
Total Height
Coal Height
Reduced Data
Height, Ib
Sulfur Height, Ib
Sulfide
Sulfate
Pyritic
Organic
Total
Sulfur Content %
Sulfide
Sulfate
Pyritlc
Organic
Total
0.01
0.13
0.84
1.50
Off '
100.00
100.00
0.01
0.13
0.84
1.50
I74TF
0.01
0.13
0.84
1.50
TtS
0.01
0.04
0.65
1.52
2.22
90.84
9.6
9.6
90.4
0.01
0.04
0.59
1.37
IToT
0.01
0.04
0.65
1.52
13,022
18.9
13,069
5
1,500
30
Feed
0.01
0.04
0.65
75.0
90.4
Residue
0.05
0.05
0.03
0.47
52.2
30.4
30.4
62.9
0.01
0.04
0.59
1.37
or
0.01
0.04
0.65
1.52
0.03
0.03
0.02
0.30
Off
0.03
0.47
uTW
84.1
87.1
12,793
•Calculated for +40 mesh fraction.
-------
TABLE VII-8. PITTSBURGH SEAM, WEST VIRGINIA ANALYSTS
Proximate Analysis, wt.%
Moisture
Volatile Matter
Ash
Fixed Carbon
Total
Ultimate Analysis* wt %
Ash
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Total
Coal
100.0
Pretreated Coal
100.0
+40 Mesh
Pretreated
Coal
100.0
10.87
73.40
4.87
2.77
1.37
6.72
13.07
71.5
3.93
2.36
1.42
7.72
9.83
74.80
4.20
2.16
1.47
7.54
100.0
100.0
100.00
Z73
-------
TABI£ VII-9. ICT PROCESS: THEHMOBAIANCE BUN DMA, PPETREATED PITTSBURGH SEAM, WEST VIRGINIA OQRL
Run Ho.
Lime/Goal Feed Ratio
Goal
Heating Rate, "F/min
Terminal Tfenperature, °F
Holding Tine, ndn
Sulfur, wt %
Sulfide
Sulfate
Pyritic
Organic
Total
Weight, g
Initial
Treated
Weight loss, %
Total Weight
Goal Weight
Reduced Data
Height, Ib
Sulfur Weight, Ib
Sulfide
Sulfate
Pyritic
Organic
Total
Sulfur Content %
Sulfide
Sulfate
Pyritic
Organic
Total
Sulfur Removal, wt %
From Feed
From Goal
Feed Coal*
Pitt.
0.00
0.42
0.63
1.36
100.00
0.00
0.42
0.63
1.36
or
0.00
0.42
0.63
1.36
Pretreainent
Seam, W. Va.
750
60
0.00
0.27
0.37
1.47
T7IT
83.5
16.5
16.5
83.5
0.00
0.23
0.31
1.23
0.00
0.27
0.37
1.47
OB-76-18
0:1
5
1,500
30
Feed
0.00
0.27
0.37
1.47
nr
2.4268
83.50
0.00
0.23
0.31
1.23
T7J7
0.00
0.27
0.37
1.47
or
Residue
0.29
0.00
0.01
0.39
O5"
1.7168
29.26
29.26
59.10
0.17
0.00
0.01
0.23
or
0.01
0.39
Off
86.4
90.0
•Calculated for 40 mesh fraction.
-------
TABLE VII-10. ANALYSES OF PITTSBURGH SEAM COAL (Pennsylvania Mine)
Proximate Analysis/ wt.%
Moisture
Volatile Matter
Ash
Fixed Carbon
Total
Ultimate Analysis, yrt.%
Ash
Carbon
Hydrogen
Sulfur
Nitrogen
Oxygen
Total
Coal
3.0
26.0
33.3
37.7
Pretreated Coal
0.3
19.7
35.3
44.7
+40 Mesh
Pretreated
Coal
0.9
21.2
33.7
44.2
100.0
100.0
100.0
34.34
52.50
3.54
1.35
1.08
7.19
35.41
52.10
2.94
1.23
1.13
7.19
33.99
54.10
3.26
1.11
1.10
6.44
100.00
100.00
100.00
275
-------
TORT* VU-11. IOT PROCESS: THERMOBMANCE FUN DMA, PIT1SBURGH SEAM CURL (FatfcTOWfiNlA
ft" K>« Peed Ooed* Pretreated Goal* TB-76-32
Llme/Qoal Feed Ratio * 0,1
Heating Rate, °F/Mn 5
Terminal Tanperafcure, °F 750 1,500
Holding Time, ndn 30 30
Sulfur, wt % Feed Residue
SulClde 0.01 0.00 0.00 0.21
SulCate 0.44 0.34 0.34 0.00
Pyritic 0.21 0.16 0.16 0.00
Organic 0.35 0.41 0.41 0.12
total 1.01 0.91 0.91 0.33
Weight, g
Initial 100.00 3.3107
Treated 86.34 2.5341
Weight loss, %
" Tbtal Height 13.66 23.46
5\ Goal Height 13.66 23.46
Reduced Data
Height, Ib 86.34 66.08
Sulfur Height, Ib
Sulfide 0.01 0.00 0.00 0.14
Sulfate 0.44 0.29 0.28 0.00
Pyritic 0.21 0.14 0.13 0.00
Organic 0.35 0.35 0.36 O.OB
Ibtal OT Off O7 OI
Sulfur Content %
Sulfide 0.01 0.00 0.00 0.00
Sulfate 0.44 0.34 0.34 0.00
Pyritic 0.21 0.16 0.16 0.00
Organic 0.35 0.41 0.41 0.12
or or or or
Sulfur Removal, wt %
Fran Feed 89.6
Fran Goal . 22.8 92.1
•Calculated for 40 mesh fraction.
-------
TABLE VII-12. ILLINOIS NO. 6 ANALYSES (Hillsboro Mine)
Proximate Analysis, wt %
Moisture 12.02
Ash 22.83
Volatile Matter 30.18
Fixed Carbon 34.97
Ultimate Analysis, wt % (dry)
Ash 25.95
Carbon 57.07
Hydrogen 4.01
Sulfur " 5.06
Nitrogen 0.98
Oxygen 6.82
Heating Value, BTO/lb 10,198
277
-------
APPENDIX VIII
KVB PROCESS
27«
-------
to
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itm
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MOT
FIGURt VIII-1 KVB PROCESS FLOW SHEET SUGGESTED BY BECHTEL
-------
snr" tsxsvz •••—- saa?;s:ic •ssssrs.- — .isr- ——«-.«.-
,>..>, <^
tt«*«UM»«.M.I
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t
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V
«*"" ^A-il-i
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i fcu-
1
1 X5* »HWIIqnM*i
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1 yv ««»»w^i.ii
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Figure VIII-1. (Continued)
-------
1. REPORT NO. 2
EPA-600/7-78-173a
4. T.TLE AND SUBTITLE f^^g^^ ot Coal cleaning Technol-
ogy: An Evaluation of Chemical Coal Cleaning
Processes
7. AUTHOR(S)
G. Y. Contos , I. F. Frankel, and L. C. McCandless
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Versar, Inc.
6621 Electronic Drive
Springfield, Virginia 22151
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
3. RECIPIENT'S ACCESSION NO. 1
5. REPORT DATE
August 1978
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
EHE623A
11. CONTRACT/GRANT NO.
68-02-2199
13. TYPE OF REPORT AND PERIOD COVERED
Final; 4-12/77
14. SPONSORING AGENCY CODE
EPA/600/13
TECHNICAL REPORT DATA
(Please read Inunctions on the rei-enc before completing)
is. SUPPLEMENTARY NOTES IERL-RTP project officer is James D. Kilgroe, Mail Drop 61,
919/541-2851.
16. ABSTRACT,
The report assembles and assesses technical and economic information on
chemical coal cleaning processes. Sufficient data was located to evaluate 11 processes
In detail, ft was found that chemical coal cleaning processes can remove up to 99% of
the pyritic sulfur and 40% of the organic sulfur, resulting in total sulfur removals of
53 to 77%. This performance can be achieved with heat value recoveries of 57 to 96%.
Processes which remove only pyritic sulfur were generally judged to have the highest
probabilities of success. Of techniques which remove both pyritic and organic sulfur,
the ERDA and the GE microwave processes were judged to have the highest probabil-
ities of success.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lOENTIFIERS/OPEN ENDED TERMS
COSATI Field/Croup
Pollution
Coal
Desulfurization
oal Preparation
Pyrite
Microwaves
Organic Sulfates
Economic Analysis
Pollution Control
Stationary Sources
Chemical Coal Cleaning
Pyritic Sulfur
Organic Sulfur
13B 07C
08G,21D 05C
07A,07D
081
20N
8. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21.
295
20. SECURITY CLASS (This page I
Unclassified
22. PRICE
EPA Form 2220-1 (»-73)
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