EPA-650/2-75-034
April 1975
Environmental Protection Technology Series
.•:v:-:-t-
-------
EPA-650/2-75-034
FUELS TECHNOLOGY:
A STATE-OF-THE-ART REVIEW
by
E. H. Hall, D. B. Peterson, J. F. Foster,
K. D. Kiang, andV. W. Ellzey
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
Contract No. 68-02-1323, Task 14
ROAPNo. 21ADE-010
Program Element No. 1AB013
EPA Project Officer: C. J. Chatlynne
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
WASHINGTON, D. C. 20460
April 1975
-------
EPA REVIEW NOTICE
This report has been reviewed by the National Environmental Research
Center - Research Triangle Park, Office of Research and Development,
EPA, and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental
Protection Agency, nor does mention of trade names or commercial
products constitute endorsement or recommendation for use.
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environ-
mental Protection Agency, have'been grouped into series. These broad
categories were established to facilitate further development and applica-
tion of environmental technology. Elimination of traditional grouping was
consciously planned to foster technology transfer and maximum interface
in related fields. These 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
9. MISCELLANEOUS
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY series. This series describes research performed to
develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and non-
point sources of pollution. This work provides the new or improved
technology required for the control and treatment of pollution sources
to meet environmental quality standards.
This document is available to the public for sale through the National
Technical Information Service, Springfield, Virginia 22161.
Publication No. EPA-650/2-75-034
11
-------
ABSTRACT
A state-of-the-art review of various fuel-cleaning, fuel-
conversion, and emission-control technologies was conducted. Classes of
technology included in the study are: physical coal cleaning, chemical
coal cleaning, residual oil desulfurization, coal refining (liquefaction),
coal and oil gasification, fluidized-bed combustion of coal, and stack
gas cleaning. For each technology the extent of current practice and
the status of systems under development is presented.
iii
-------
TABLE OF CONTENTS
Pace
INTRODUCTION xv
SUMMARY AND CONCLUSIONS xvii
PHYSICAL COAL CLEANING 1-1
CHEMICAL COAL CLEANING 2-1
DESULFURIZATION OF RESIDUAL FUEL OIL 3-1
Introduction 3-1
Process Description for Residual Oil Desulfurization 3-2
Foreign Plans for Desulfurization of Residual Fuel Oil .... 3-4
Residual Oil Desulfurization Capacity and Production in
the United States 3-5
References for Section 3 3-6
COAL REFINING AND LIQUEFACTION 4-1
Introduction 4-1
H-Coal Process (Hydrocarbon Research, Inc.) 4-3
Synthoil Process (Bureau of Mines) 4-7
Solvent Refined Coal (SRC) Process 4-10
CONSOL Synthetic Fuel (CSF) Process 4-13
Bergius Coal Liquefaction Process 4-16
COED Process (FMC Corporation) 4-18
CONSOL ZnCl2 Process 4-21
LOW-AND INTERMEDIATE-BTU GAS FROM COAL AND OIL 5-1
Introduction 5-1
Status of the Technology 5-3
Moving Bed/Dry Ash 5-12
Lurgi (The American Lurgi Corp.) 5-12
Wellman-Galusha (McDowell Wellman Co.) 5-16
Bureau of Mines Stirred-Bed 5-19
Gegas (General Electric Company) 5-22
Kellog Fixed-Bed Gasifier (MW Kellog Co.) 5-25
Moving Bed/Slagging 5-27
Thyssen-Galoczy * 5-27
Fluid-Bed/Dry Ash 5-30
iv
-------
TABLE OF CONTENTS
(Continued)
Winkler (Davy Power Gas Company) 5-30
Snythane (Bureau of Mines) 5-33
C02 Acceptor (Consolidation Coal Co.) 5-35
Exxon 5-38
HRI Gasification (Hydrocarbon Research Incorp.) .... 5-40
COGAS (Cogas Development Company) 5-43
Bituminous Coal Research 5-45
Fluid Bed/Agglomerating Ash 5-47
U-Gas (Institute of Gas Technology) 5-48
Westinghouse 5-51
Ash Agglomeration (Union Carbide/Battelie) 5-54
Entrainment 5-57
Bigas (Bituminous Coal Research Inc.) 5-58
Combustion Engineering Inc 5-60
Foster-Wheeler (Foster-Wheeler Corporation) 5-62
Garret Flash Pyrolysis (Garret Research and
Development Co.) 5-65
Entrainment/Slagging 5-68
Koppers-Totzek (Koppers Engineering and Construction) . 5-68
Texaco 5-72
Babcock & Wilcox 5-74
Molten Bath 5-77
Molten Iron (Applied Technology Corp.) 5-77
Kellog Molten Salt (M. W. Kellog Company) 5-80
Atomics International Molten Salt 5-83
Underground Gasification 5-86
Gasification of Refinery Residues 5-89
Flexicoking (Exxon Corporation) 5-90
Texaco Partial Oxidation (Texaco Oil Company) 5-93
Shell Gasification Process (Shell Oil Company) 5-96
H-Gas (Hydrocarbons Research Inc.) 5-99
IGT (Institute of Gas Technology) 5-102
HIGH-BTU GAS FROM COAL 6-1
Introduction 6-1
Status of the Technology 6-3
-------
TABLE OF CONTENTS
(Continued)
The Lurgi Process (American Lurgi Corp 6-9
The Koppers-Totzek Process (Heinrich Koppers, G.m.b.H) . 6-13
The Hygas Process (Institute of Gas Technology) .... 6-15
Variations of the Hygas Process 6-15
The Synthane Process (Bureau of Mines) 6-19
The Bi-Gas Process (Bituminous Coal Research) 6-21
The CC>2 Acceptor Process (Consolidation Coal Company) . 6-23
The Hydrane Process 6-25
The Ash Agglomeration Process (Union Carbide-
Battelle) 6-28
The Kellog Molten Salt Process (M.W. Kellog Co.) .... 6-30
Atgas Process (Applied Technology Corp.) 6-32
Garret Flash Pyrolysis (Garret Research and
Development) 6-34
Cogas (Cogas Development Company) 6-36
Supplemental Bibliography for Coal Gasification 6-38
FLUIDIZED BED COMBUSTION 7-1
Atmospheric Fluidized-Bed Combustion 7-1
Pressurized Fluidized-Bed Combustion 7-5
Ignifluid Combustion 7-9
Two-Stage Fluidized Combustion 7-12
STACK GAS SCRUBBING 8-1
Introduction 8-1
Status of the Technology 8-2
Throwaway Processes 8-4
Limestone Injection 8-4
Limestone Scrubbing 8-7
Lime Scrubbing 8-10
Double Alkali 8-13
Recovery Processes 8-16
Wellman Lord Process 8-16
Catalytic Oxidation 8-19
Magnesium Oxide Scrubbing 8-22
Chiyoda Process 8-25
The Citrate Process 8-28
Selected Bibliography for Section 8 8-31
vi
-------
TABLE OF CONTENTS
(Continued)
Page
ACKNOWLEDGEMENTS 9-1
APPENDIX A
ENVIRONMENTAL CONSIDERATIONS FOR THE GASIFICATION OF COAL A-l
vii
-------
LIST OF TABLES
Page
Table 1.1. Production and Cleaning of Bituminous Coal and
Lignite in the United States 1-3
Table 1.2. Types of Equipment Used in Cleaning Bituminous
Coal and Lignite in the United States 1-5
Table 1.3. Status of New Coal Cleaning Processes 1-8
Table 2.1.1. TRW-Meyers Process For Chemical Cleaning 2-4
Table 4.0. Coal Liquefaction Processes 4-2
Table 4.1. H-Coal Process 4-6
Table 4.2. Synthoil Process 4-9
Table 4.3. Solvent Refined Coal Process . . . 4-12
Table 4.4. Consol Synthetic Fuel (CSF) Process 4-15
Table 4.6. Coed Process 4-20
Table 4.7. Consol Zinc Chloride Process 4-23
Table 5.0. Status of Low- and Intermediate-Btu Gasification:
A Summary 5-7
Table 5.1.1. Lurgi: State of the Art 5-14
Table 5.1.2. Wellman-Galusha: State of the Art 5-18
Table 5.1.3. Bureau of Mines Stirred-Bed Producer: State of the Art 5-21
Table 5.1.4. The Gegas Process: State of the Art 5-24
Table 5.1.5. The Kellogg Fixed-Bed Process 5-26
Table 5.2.1. Thyssen-Galocsy: State of the Art 5-29
Table 5.3.1. Winkler: State of the Art 5-32
Table 5.3.2. Synthane: State of the Art 5-34
Table 5.3.3. CO- Acceptor: State of the Art 5-37
Table 5.3.4. Exxon: State of the Art 5-39
viii
-------
LIST OF TABLES (Continued)
Page
Table 5.3.5. HRI: State of the Art 5-42
Table 5.3.6. Cogas: State of the Art 5-44
Table 5.3.7. Bituminous Coal Research 5-46
Table 5.4.1. U-Gas: State of the Art 5-50
Table 5.4.2. Westinghouse: State of the Art 5-53
Table 5.4.3. Ash Agglomeration 5-56
Table 5.5.1. Eigas: State of the Art 5-59
Table 5.5.2. Combustion Engineering Inc 5-61
Table 5.5.3. Foster-Wheeler 5-64
Table 5.5.4. Garrett Flash Pryolysis 5-67
Table 5.6.1. Koppers-Totzek: State of the Art 5-70
Table 5.6.2. Texaco: State of the Art 5-73
Table 5.6.3. Babcock and Wilcox: State of the Art 5-76
Table 5.7.1. Molten Iron: State of the Art 5-79
Table 5.7.2. Kellogg Molten Salt: State of the Art 5-82
Table 5.7.3. Atomic International Molten Salt: State of the Art . 5-85
Table 5.8. Underground Gasification 5-87
Table 5.9.1. Flexicoking: State of the Art 5-92
Table 5.9.2. Texaco Partial Oxidation: State of the Art 5-95
Table 5.9.3. Shell Gasification Process 5-98
Table 5.9.4. H-Gas: State of the Art 5-101
Table 5.9.5. IGT: State of the Art 5-103
Table 6.0. Status of High-Btu Gasification: A Summary 6-4
Table 6.1. Lurgi: State of the Art 6-10
Table 6.2. Koppers-Totzek State of the Art 6-14
ix
-------
LIST OF TABLES (Continued)
Page
Table 6.3. Hygas: State of the Art 6-18
Table 6.4. The Synthane Process (U.S. Bureau of Mines) 6-20
Table 6.5. Bigas: State of the Art 6-22
Table 6.6. CO- Acceptor: State of the Art 6-24
Table 6.7. Hydrane: State of the Art 6-27
Table 6.8. Ash Agglomeration 6-29
Table 6.9. Kellogg Molten Salt 6-31
Table 6.10. Molten Iron: State of the Art 6-33
Table 6.11. Garrett Flash Pyrolysis 6-35
Table 6.12. Cogas: State of the Art 6-37
Table 7.1. Atmospheric Fluidized-Bed Combustion: State of the Art 7-3
Table 7.2. Pressurized Fluidized-Bed Comfustion: State of the Art 7-7
Table 7.3. Ignifluid Combustion: State of the Art 7-11
Table 7.4. Two-Stage Fluidized Combustion: State of the Art. . . 7-13
Table 8.0. Summary of Stack Gas Scrubbing Facilities 8-3
Table 8.1.1. Limestone Injection 8-6
Table 8.1.2. Limestone Scrubbing Process 8-9
Table 8.1.3. Lime Scrubbing 8-12
Table 8.1.4. Double Alkali ( Sodium Scrubbing-Lime Regeneration) . . 8-15
Table 8.2.1. Wellman Lord Process 8-18
Table 8.2.2. Catalytic Oxidation 8-21
Table 8.2.3. MgO Scrubbing 8-24
Table 8.2.4. Chiyoda Process 8-27
Table 8.2.5. Citrate Process 8-30
-------
LIST OF FIGURES
Page
Figure 1.1. Flow Diagram for a Typical Modern Coal
Cleaning Plant 1-6
Figure 3.1. Block Flow Diagram for Multi-Purpose Desulfur-
ization Plant 3-3
Figure 4.1.1. H-Coal Reactor with Ebullient Bed 4-4
Figure 4.1.2. Schematic of H-Coal Process Development Unit 4-5
Figure 4.2. Synthoil Pilot Plant Flow Sheet 4-8
Figure 4.3.1. Solvent Refined Coal Pilot Plant 4-11
Figure 4.4.1. Consol Synthetic Fuel Process 4-14
Figure 4.5.1. Bergius Catalytic Hydrogenation: German
Commercial Practice 4-17
Figure 4.6.1. Coed Process with added Char Gasification: FMC-OCR . . 4-19
Figure 4.7. Consol ZnCl. Process 4-22
Figure 5.0. Gasifier - Combined Cycle Complex 5-4
Figure 5.1.1. The Lurgi Process 5-13
Figure 5.1.2. Wellmann-Galusha Fuel Gas Generator 5-17
Figure 5.1.3. Bureau of Mines Gasifier 5-20
Figure 5.1.4. Gegas Process Development Options 5-23
Figure 5.1.5. Kellogg Fixed-Bed Gasifier 5-25
Figure 5.2.1. Thyssen-Galocsy Slagging Gas Generator 5-28
Figure 5.3.1. Winkler Gasifier 5-31
Figure 5.3.2. Synthane Process 5-33
Figure 5.3.3. C0_ Acceptor Process Diagram 5-36
Figure 5.3.5. Schematic Flow Sheet of Anthracite Gasification
Pilot Plant 5-41
xi
-------
LIST OF FIGURES (Continued)
Page
Figure 5.4.1. Gasifier to be Used in IGT's U-Gas System 5-49
Figure 5.4.2. Westinghouse Multistage Fluidized-Bed Gasifi-
cation Process 5-52
Figure 5.4.3. Union Carbides' Agglomerated Ash Process 5-55
Figure 5.5.1. Bigas Process 5-58
Figure 5.5.3. Foster Wheeler 5-63
Figure 5.5.4. Garrett Clash Pyrolysis Process 5-66
Figure 5.6.1. Koppers-Totzek Gasifier 5-68
Figure 5.6.2. Simplified Flow Diagram of the Texaco Gasifier. . . . 5-72
Figure 5.6.3. Babcock and Wilcox - Du Pont Gasifier 5-75
Figure 5.7.1. Molten Iron Process 5-78
Figure 5.7.2. Kellogg Molten-Salt Process 5-81
Figure 5.7.3. Atomics International Molten Salt Gasification. . . . 5-84
Figure 5.9.1. Flexicoking (Exxon Corporation) 5-91
Figure 5.9.2. Texaco Partial Oxidation Process 5-94
Figure 5.9.3. Shell Gasification Process for Fuel Gas Manufacture . 5-97
Figure 5.9.4. H-Gas Process 5-100
Figure 5.9.5. The IGT Process 5-102
Figure 6.0. Generalized Schematic for Production of SNG From Coal 6-2
Figure 6.1. Lurgi Process 6-9
Figure 6.2. Koppers-Totzek 6-13
Figure 6.3. Hygas Process 6-16
Figure 6.4. Synthane Process 6-19
Figure 6.5. Bigas Process 6-21
xii
-------
LIST OF FIGURES (Continued)
Pafie
Figure 6.5. The C0« Acceptor Process 6-23
Figure 6.7. Hydrane Process 6-26
Figure 6.8. Union Carbides' Agglomerated Ash Process 6-28
Figure 6.9. Kellogg Molten Salt Process 6-30
Figure 6.10. Atgas Process 6-32
Figure 6.11. Garrett Flash Pyrolysis Process 6-34
Figure 6.12. A Cogas Process Diagram 6-36
Figure 7.1. Atmospheric Fluidized-Bed Combustion Power Plant. . . 7-2
Figure 7.2. Pressurized Fluidized-Bed Combustion Power Plant. . . 7-6
Figure 7.3. Ignifluid Utility Boiler 7-10
Figure 8.1.1. Limestone Injection 8-5
Figure 8.1.2. Limestone Scrubbing Process 8-8
Figure 8.1.3. Lime Scrubbing 8-11
Figure 8.1.4. Sodium Scrubbing with Lime Regeneration
(Double Alkali) 8-14
Figure 8.2.1. Sodium Scrubbing with Sulfur Dioxide
Recovery (Wellman Lord) 8-17
Figure 8.2.2. Catalytic Oxidation 8-20
Figure 8.2.3. Magnesium Oxide Scrubbing with Sulfuric Acid Recovery 8-23
Figure 8.2.4. Chiyoda Thoroughbred 101 Flue Gas Desulfurization
Process 8-26
Figure 8.2.5. The Citrate Process 8-29
xiii
-------
TABLE OF CONVERSION FACTORS
Multiply
English Unit
by
Conversion
To Obtain
Metric Unit
acres
acre- feet
barrel, oil
British Thermal Unit
British Thermal Unit/pound
cubic feet/minute
; cubic feet /second
cubic feet
cubic feet
cubic inches
degree Fahrenheit
feet
gallon
gallon/minute
horsepower
inches
inches of mercury
pounds
million gallons /day
pound /square inch (gauge)
square feet
square inches
tons (short)
yard
0.405 hectares
1233.5 cubic meters
158.97 liters
0.252 kilogram-calories
0.555 kilogram calories/kilogram
0.028 cubic meters/minute
1-7 cubic meters/minute
0.028 cubic meters
28.32 liters
16.39 cubic centimeters
0.555(°F-32)(a) degree Centigrade
0.3048 meters
3.785 liters
0.0631 liters/second
0.7457 kilowatts
2.54 centimeters
0.03342 atmospheres
0.454 kilograms
3785 cubic meters/day
1.609 kilometer
(0.06805 psig+1)(a) atmospheres (absolute)
0.0929 square meters
6.452 square centimeters
0.907 metric tons (1000 kilograms)
0.9144 meters
(a) Actual conversion, not a multiplier.
xiv
-------
FINAL REPORT
on
FUELS TECHNOLOGY
A STATE-OF-THE-ART REVIEW
to
ENVIRONMENTAL PROTECTION AGENCY
from
BATTELLE
Columbus Laboratories
March 14, 1975
by
E. H. Hall, D. B. Peterson, J. F. Foster,
K. D. Kiang, and V. W. Ellzey
Contract No. 68-02-1323
Task No. 14
Task Officer: C. J. Chatlynne
Control Systems Laboratory
U.S. Environmental Protection Agency
INTRODUCTION
The steadily increasing demand for energy in the United States
and around the world combined with the need to consider environmental
factors have given impetus to a large number of developments in many
energy-related technologies. This study was conducted for the Control
Systems Laboratory of the U. S. Environmental Protection Agency to provide
a current assessment of the status of these varied activities. The study
included the following technologies.
Fuel Cleaning
1. Physical coal cleaning
2. Chemical coal cleaning
3. Residual oil desulfurization
xv
-------
Fuel Converstion
4. Coal refining (liquefaction)
5. Coal and oil gasification, low- and intermediate-Btu gas
6. Coal gasification, high-Btu gas
Emission Control
7. Fluidized-bed combustion
8. Stack gas scrubbing.
For each of these technologies the objective was to assess the current
status of the technology in terms of: the extent of actual application,
the types of research and development projects in progress, the operating
histories of pilot or demonstration plants, the problems which remain to
be solved, and current projections for the completion of each development
stage.
The format of the report has been designed to facilitate
periodic updating of the information to keep it current. Each of the
technologies listed above is treated in a separate section of the report.
Where appropriate, specific processes within a given technology are des-
cribed briefly and a flow chart is included to show the process principles.
This is followed by a state-of-the-art table which includes the following
information: the type of facility; the location; the owner or contractor;
the status/operating history; the name, address, and telephone number of a
contact person knowledgable with respect to the process; and a list of
references pertinent to the specific process. This basic information has
been presented as concisely as possible so that the reader may turn to a
specific process and quickly find the pertinent details regarding the
status of the process. The numbering of pages, tables, and figures is
distinct within each section so that additional processes can be included
readily at a later date, if desired.
xvi
-------
SUMMARY AND CONCLUSIONS
The status of each of the eight energy technolgies under con-
sideration in this study varies from the development stage to established
conmercial practice. To provide an overview of the current situation,
the status of each technology is summarized briefly in the following
paragraphs.
Physical coal cleaning is an established conmercial technology.
Conventional coal washing cannot remove sulfur bound to the coal structure
and is thus limited in its effectiveness. Nevertheless, it is a useful
technique which represents a partial solution to the problem of SO.
emissions from coal combustion. Experimental studies are in progress in
an attempt to find improved cleaning methods. Such advanced methods all
are faced with the problem of developing equipment capable of high
throughput rates.
Chemical coal cleaning is in the early development stage. No
pilot plants have been built to date. Chemical coal cleaning processes
promise more complete removal of sulfur than physical coal cleaning at a
lower cost than conversion of coal to clean liquid or gaseous fuels.
Desulfurization of residual oil is an established technology
which has not been practiced widely in the United States for economic
reasons. High-sulfur resid has generally been used in maritime applica-
tions or exported. This is expected to change as these outlets become
inadequate to absorb the volume of high sulfur resid produced. Direct
or indirect desulfurization, gasification, or fluidized-bed combustion of
high-sulfur residual oils will have to be employed to utilize the heavy
fractions in an environmentally acceptable manner.
Coal refining or liquefaction processes are in various stages
of development. The Bergius process was used in Germany during World
War II but no active development of the process is underway now. The
largest scale developments of other processes include a 1.5 ton-per-hour
COED pilot plant and a 2 ton-per-hour SRC pilot plant. The latter is not
yet completely operational.
xvii
-------
Coal gasification technology is both commercial and develop-
mental. First generation systems, such as Lurgi, Wellman-Galusha, Winkler,
and Hoppers-Totzek, are commercially available. Lurgi units are to be
used in commercial-scale SNG plants now in the planning stage. Advanced
gasification systems have not been developed to demonstration scale at
this time. The Hygas, 3 ton per hour pilot plant, and the CO Acceptor,
1.5 ton-per-hour pilot plant represent the largest scale in this country.
A 4 ton-per-hour COGAS pilot plant has been operated in England and a
smaller PDU unit of the same type has been operated at Flainsboro, New
Jersey.
Fluidized-bed combustion of coal is being developed in both
atmospheric and pressurized systems. A 30 MW atmospheric fluidized-bed
boiler is under construction in West Virginia. Pressurized systems show
promise of excellent combustion efficiency and SO, and NO control. The
^ X
largest unit is a 12.5 inch diameter (about 0.65 MW) miniplant at Linden,
New Jersey.
Stack gas scrubbing is a demonstrated technology which has been
difficult to reduce to sound engineering practice with high reliability.
The number of operating units is increasing and experience gained is
helping in the solution of problems. Recent installations are showing
higher availability factors than early test units. The total capacity of
operational units and units under construction is about 8,000 MW with an
additional 26,000 MW planned.
It is evident that progress is being made across a broad front
in energy technology. Some techniques for reducing the environmental
impact of fuel combustion are available now and should be used as effec-
tively as possible. Other technologies under development will provide a
range of options so that the best strategy for fuel use can be adopted
in each situation.
xviii
-------
SECTION 1
PHYSICAL COAL CLEANING
Introduction
Physical coal cleaning, or mechanical cleaning, is the process
of removing ash (rock) and sulfur (pyrite) from coal by a process other
than chemical modification or destruction of either the coal or the
impurities. Thus, physical coal cleaning is generally unable to remove
impurities that are chemically combined with the coal substance. Sulfur
incorporated into the chemical structure of the coal ("organic" sulfur)
is a major example. Most physical cleaning processes use water and are
commonly called coal washing.
The cleaning process can be based on any physical or physical-
chemical difference between the coal and the impurity. The most commonly
employed property is density: "pure" bituminous coal having a specific
gravity of about 1.3, "rock" about 2.0 to 2.7, and pyrite about 4.8-5.0.
The physical-chemical surface properties are also employed in the froth
flotation process.
The impurities may be derived from the roof or floor of the mine
or be imbedded in the coal seam itself. Impurities may occur as massive
pieces, as microscopic particles, or in intermediate sizes. Crushing the
coal physically releases the impurity particles from the coal substance.
History
Physical coal cleaning has been practiced in some form as long
as coal has been mined. Originally, hand picking was used to remove
large pieces of rock from the mined coal. Later, mechanical pickers,
whose operation depended on differences in the shape of coal and rock
(largely slate) particles were developed. Such processes became increasingly
impractical with the development of mechanized mining which reduced the
1-1
-------
1-2
average size of both coal and impurity. Various "washing" processes,
borrowed from the field of one beneficiation and largely based upon
separation by specific gravity, have become the major coal cleaning
processes.
After about 1945, the electric utilities began to dominate the
coal market, and pulverized coal firing became almost exclusively the
method of firing utility boilers with coal. Under these circumstances,
the conclusion was reached that the most economical way of separating
the coal, ash, and sulfur was by burning in the utility boiler furnace,
and the practice of coal cleaning diminished.
Table 1.1 shows the recent trend in coal cleaning, characterized
by a steady decline in both the total annual tonnage cleaned and the
percentage of the total annual production cleaned. This trend was
interrupted in 1972.
Reasons for Coal Cleaning
Coal was originally cleaned to improve its appearance to the
customer. However, the removal of ash minerals increased the heating
value, reduced the ash problems encountered by users, and reduced shipping
costs per unit of heating value.
Current interest in coal cleaning for steam coals centers on
sulfur reduction. Various state and federal regulations have been or
are expected to be applied to limit the emissions of sulfur oxides. These
regulations effectively would limit the sulfur content of coal to about
1 percent. The supply of such coals in the Eastern United States is quite
limited, and a method of economically reducing the sulfur content of
eastern coals could have great value. Potential future interest in coal
cleaning may result from restrictions on the release of lead, cadmium,
mercury, etc, from coal burning equipment. These potential pollutants
are removed in part by the cleaning process.
It is not possible to clean eastern coals as a class to 1 percent
sulfur or less. For this reason, attention has been diverted to other
methods of complying with sulfur emission regulations, such as stack gas
scrubbing, gasification, and chemical refining. However, coal cleaning
-------
TABLE 1.1. PRODUCTION AND CLEANING OF BITUMINOUS COAL AND LIGNITE
IN THE UNITED STATES (U.S. DEPT OF INTERIOR BUREAU
OF MINES MINERALS YEARBOOK)
Total Production
Quantity Cleaned
Percentage Cleaned
1964
487
310
63.7
1965 1966
512 534
332 341
64.9 63.8
1967
553
349
63.2
106 tons
1968
545
341
62.5
1969
561
335
59.7
1970 1971
603 552
323 271
53.6 49.1
1972
595
293
49.
2
-------
1-4
offers a known route to a significant reduction in sulfur emissions, and
may be of assistance in connection with other clean-up processes. For
example, a reduced sulfur content in the coal would permit use of a less
efficient stack gas scrubber. Also, a reduced sulfur content would reduce
the hydrogen consumption of some chemical coal refining processes.
While the total impact of universal coal cleaning has not been
m*
evaluated, a recent Bureau of Mines publication permits a rough
estimate of the impact. Based upon samples from 322 mines, mostly in the
eastern United States, the average sulfur content of the coal could be
reduced from 3.2 percent to 2.3 percent at a 90 percent yield when crushed
to a top size of 1-1/2 inch. Similarly, coal crushed to 3/8 inch and
14 mesh would yield sulfur levels of 2.0 and 1.8 percent, respectively.
Simultaneously the ash content would be reduced from an average of 14
percent to 7.2 percent, 6.5 percent, and 6.0 percent, at the same levels
of coal size. Slight additional gains could be obtained by cleaning at
lower yields.
State of the Art
Table 1.2 lists the types of equipment and processes now
dominating the coal cleaning field. A typical coal cleaning plant will
use several types of equipment or processes. Figure 1.1 is a flow dia-
gram for a modern coal cleaning plant. Some plants may replace the dense
media vessel by jigs, the dense media cyclones by tables,etc. Coal
cleaning plants may also use series cleaning, where the product or waste
stream from one process is sectioned by another process.
Current Research
Research in coal cleaning on related topics is carried out by
the U.S. Bureau of Mines, the manufacturers of coal cleaning equipment,
and various universities. The research done by manufacturers of coal
cleaning equipment is regarded as proprietary and little information is
available concerning such research. It is believed to be largely concerned
with optimizing equipment and plant design. The Bureau of Mines, with
EPA sponsorship has a research program ranging from optimization of existinj
equipment to explorations of new cleaning concepts.
^References for this Section are given on Page 1-9.
-------
1-5
TABLE 1.2. TYPES OF EQUIPMENT USED IN CLEANING BITUMINOUS COAL
AND LIGNITE IN THE UNITED STATES (U.S. DEFT.
INTERIOR BUREAU OF MINES MINERALS YEARBOOK)
Jigs
Tables
Classifiers
Launders
Dense Media
Magnetite
Sand
CaCl2
Flotation
Pneumatic
Total
1967
161
50
4
5
219
66
33
3
101
8
21
349
1968
159
47
5
4
215
71
27
2
99
9
17
340
106 tons
1969
155
45
3
5
208
72
24
2
98
10
19
335
cleaned*
1970
140
44
4
5
193
77
23
2
102
11
18
323
1971
115
36
2
5
158
70
18
2
90
9
15
271
1972
128
40
3
5
176
75
15
2
92
13
12
293
*Rounding errors not adjusted.
-------
1-6
Waste •«-
l/4"x21
Product
FIGURE 1.1. FLOW DIAGRAM FOR A TYPICAL MODERN
COAL CLEANING PLANT
Overall efficiency, 85 to 90 percent.
-------
1-7
The difficulty with most of the new* cleaning concepts is in
devising equipment that can economically treat the large tonnages involved
in coal cleaning.
Table 1.3 lists the recent and current research in new coal
cleaning processes. A short description of these processes is given in
Appendix lA,which follows this Section. It may be noticed that these new
processes are generally directed towards the cleaning of fine coal, about
28 mesh and smaller. Particle dynamic effects make compact, high-capacity
equipment for cleaning fine coal particularly difficult to achieve.
Concluding Remarks
Several features make coal cleaning a difficult field for signifi-
cant technical inovation. First, the field itself is old and has been
extensively developed. Second, most of the coal cleaning processes are
adaptations from the field of ore beneficiation which has perhaps justified
a higher level of research and development than coal itself. Third, the
existing methods, when properly applied, do an excellent job of separating
coal from mineral impurities when they exist as separate particles, and no
physical process can separate the coal and impurity combined in a single
particle. Thus, a new process can offer little or nothing in terms of its
separating ability. To improve separations, coal must be cleaned in
finer sizes, and the capacity of a cleaning device is generally inversely
proportional to the particle size of the coal being cleaned. For this
reason, most coal cleaning plants do not fine crush or grind before cleaning,
even if the cleaned coal will subsequently be crushed at the plant (see
Figure 1.1).
If a significant technical innovation should occur in coal
cleaning, it will almost certainly be in the cleaning of fine coal. How-
ever, the existing froth flotation processes make a good separation on
fine coal and hence represents an entrenched competition to any new process.
Its disadvantage is in producing a wet product which normally must be dried
before shipment.
*Most, but not all, of the "new"coal cleaning concepts are attempts to
adapt mineral beneficiation processes developed in other fields.
-------
TABLE 1.3. STATUS OF NEW COAL CLEANING PROCESSES
Process
Two Stage Froth Flotation
Differential Grinding and
Classification
Electrostatic
Electrophoretic
High Gradient Magnetic
Separation
"Chemical" Comminution
Organization
Bureau of Mines
Bureau of Mines
Bituminous Coal
Research, Inc.
ILOK
Bureau of Mines
MIT
Syracuse University
Research Corp.
Status
Entering Fullscale
(12 ton/hr)
Prototype
Laboratory
Pilot Plant
Unknown
Laboratory
Laboratory
Laboratory
Laboratory
Reference
2,3
4
5
6
4,7
8
3
9
Remarks
Considered promising
Currently inactive
I
00
-------
1-9
References for Section 1
(1) Deurbrouck, A. W., "Sulfur Reduction Potential of the Coals of the
United States", U.S. Dept. of Interior, Bureau of Mines Report of
Investigations 7633 (1972).
(2) Miller, K. J., and Baker, A. F., "Flotation of Pyrite from Coal",
U.S. Dept of Interior Bureau of Mines Technical Progress Report 51
(Feb. 1972).
Miller, K. J., "Flotation of Pyrite from Coal: Pilot Plant Study",
U.S. Dept. Interior Bureau of Mines Report of Investigations 7822
(1973).
(3) Private communication from A. W. Deurbrouck, Bureau of Mines.
(4) Abel, W. T., et al, "Removing Pyrite from Coal by Dry-Separation
Methods", U.S. Dept of Interior Bureau of Mines, Report of
Investigations 7732 (1973).
(5) Saltsman, R. D., "The Removal of Pyrite from Coal", ASME Publication
68-WA/FU-2 (December 1968).
(6) Foster, J. F., et al, "Assessment of the Potential for Collodial
Fuels in Department of Defense Applications", Battelle Columbus
Laboratories report to Defense Advanced Research Projects Agency,
Contract No. DAAH01-74-C-0837, AO No. 2758 (August 15, 1974).
(7) Glenn, R. A., and Grace, R. J., "A Study of Ultrafine Coal Pulveri-
zation and Its Application", U.S. Dept. of Interior, Office of Coal
Research, Research and Development Report No. 5 (1963).
(8) Miller, K. J., and Baker, A. F., "Electrophoretic - Specific Gravity
Separation of Pyrite from Coal", U.S. Dept. of Interior Bureau of
Mines, Report of Investigations 7440 (October 1970).
(9) "Chemical Comminution Shows Promise for Coal", Chemical and
Engineering News, pages 16-17 (Septebmer 2, 1974).
-------
1-10
Appendix 1A
Description of New Coal Cleaning Processes
Two-stage Froth Flotation. Conventional froth-flotation coal
cleaning uses frothing agents and conditions which float the coal from
the mineral matter. This results in particles containing both coal and
pyrite, and very fine pyrite particles, appearing in the cleaned coal.
A second froth flotation process,which floats the pyrite from the coal,
removes these mixed and fine particles and yields a cleaner product.
It is reported that negotiations are underway to install a
full scale prototype in an existing coal cleaning plant. The fine coal
stream is 12 tons/hr.
Differential Grinding and Classification. The Bradford breaker,
dating to 1874, is an early example of this process. Typically, the
impurities in coal are more resistant to crushing or grinding than is the
coal. Thus, after crushing or grinding the impurity particles are larger
than the coal particles and can be separated by some classification step,
in current concepts, by an air classifier after a fine grinding step.
Although moderately successful technically, the required equipment appears
to be too large and expensive to justify the moderate sulfur reduction
obtained, even when carried out at the utility plant where the coal is
ground for pulverized coal firing.
Electrostatic Cleaning. A number of laboratories have investi-
gated separating coal and mineral matter by employing differences in
resistivity and dielectric constant. Generally restricted to treating
fine coal, the processes work but a machine with economical capacity has
not been devised.
-------
1-11
Electrophoretic Cleaning. This process is based on the differential
motion of coal and mineral matter in a suspending fluid when subjected to
an electric field. The process effects a separation, but economical
machinery has not been envisioned.
High Gradient Magnetic Separation. This process, which depends
on a high gradient, in contrast to a high field, is one of the newer
separation processes. Little information is available concerning its
application to coal cleaning. It will probably work in the technical
sense, but devising a machine of realistic capacity will probably be
difficult.
"Chemical" Comminution. This process is akin to differential
grinding. A liquid agent, such as methanol or ammonia, causes the coal
to fragment along existing fracture planes without affecting the mineral
matter. The fragmented coal and unaffected mineral matter can then be
separated by some conventional cleaning process.
-------
SECTION 2
CHEMICAL COAL CLEANING
Introduction
The processes for chemical cleaning of coal expose the mined coal
to chemicals which dissolve or convert undesirable impurities preferentially
into forms that can be easily separated. The treatment is primarily directed
at the removal of sulfur compounds that otherwise would appear as gaseous
waste products when the coal is burned or converted to liquid and gas fuels.
Coal can also be chemically treated to remove ash, but the low-ash product
may not justify the cost of the extra step. Washed or mechanically cleaned
coal may be a preferred feed to the chemical cleaning process to reduce the
chemicals consumed and the costs for cleaning high-ash coals.
Chemical cleaning is most effective in dissolving the discrete
particles of iron sulfide mineral occluded among the layers of the coal
seam. Coal also contains varying proportions of sulfur combined as sulfur
compounds in the nonmineral structure. This organic sulfur is highly
resistant to chemical treatment and the undissolved part is discharged
as sulfur-containing gases when the coal is used. Thus, the choice between
sulfur removal by pretreatment with chemicals or by post combustion flue gas
cleaning (Section 8) depends upon the particular coal to be treated and
the level of sulfur that can be tolerated in the products of conversion or
combustion.
This section describes individually the
TRW-Meyers process,
Battelle process,
neither of which has advanced to as large-scale testing as have the flue-
gas cleaning processes described in Section 8. The chemical cleaning
processes differ primarily in the chemicals employed and in the results
2-1
-------
2-2
obtained. The TRW-Meyers process removes only the pyritic surfur from the
coal, but the Battelle process is said to remove the pyritic sulfur and
a significant portion of the organic sulfur.
-------
2-3
2.1 Chemical Gleaning Processes
2.1.1 TRW-Meyers Process
This process employes a chemical leach of the coal with aqueous
ferric sulfate at temperatures of between 50 and 130 C. The reagent is
selective for pyrite, removing 83-98 percent of the pyrite in 19 different
coals tested. The reduction in total sulfur was 40 to 82 percent. The
products of the reaction are dissolved ferrous sulfate and sulfuric acid,
and precipitated free sulfur. The depleted leach solution is removed by
drainage and rinsing after which it is regenerated to ferric sulfate by
oxidation with air. Precipitated free sulfur is washed out with an
appropriate solvent or vaporized and recovered by condensation.
-------
TABLE 2.1.1. TRW-MEYERS PROCESS FOR CHEMICALLY CLEANING
Facllty
Bench Scale
Pilot Plant
Location
Redondo Beach,
Calif.
Same
(Contact: R. A.
Californ
Ownor(s)
or Contractor
TRW, Inc.
(EPA support)
Same
Meiers, Applied
a, September 24, 197
Status/Operating History
1971-present. Continuous leaching of crushed coals with
ferric sulfate solution to determine leaching characteristics
and recoveries. Obtained data for pilot plant design.
Capacity about 2 lb per hr.
1973. Design study for pilot plant completed. Capacity,
500-1000 lb coal/hr
Sept. 1974. Contract for construction and operation of
pilot plant being negotiated.
NJ
I
•P-
Technolbgy Division, TRW Systems Group, Redondo Beach,
Tel. 213-535-1549
Reference
J. W. Hamersma, M. L. Kraft, W. P. Kendrick and R. A. Meyers, "Chemical Desulfurieation of Coal to Meet Pollution Standards",
American Chemical Society, Divtson of Fuel Chemistry Preprints Volume 19, No. 2, pp 33-42. Paper presented at 167th National
Meeting, Los Angeles April 1-5, 1974. Also an adaptation of the paper in Coal Mining and Proce8sing. Volume 11, No. 8,
pp 36-39 (August 1974).
-------
2-5
2.2.2 Battelle Process
This is a proprietary process concerning which no details are
to be released until its patent position has been established. It is
stated that "The feasibility of producing low sulfur coal by chemical
desulfurization has been established in laboratory scale experiments.
Heating a variety of coals in aqueous solutions at elevated temperatures
and pressures extracts the pyritic sulfur and the sulfate sulfur along
with a significant portion of the organic sulfur."
-------
SECTION 3
DESULFURIZATION OF RESIDUAL FUEL OIL
Introduction
At the present time, only .07 percent of U.S. residual fuel oil
capacity is being desulfurized in the United States because of the pro-
hibitive economics inherent in the processes known for such desulfurization.
Some low sulfur residual fuel oil has been produced and used domestically,
but this residual product has been derived from the refining of very sweet
(^0.15 percent S) crude oil from either domestic or foreign sources.
The demand for residual fuel oil in the United States has been
increasing at a rate of from 4 to 7 percent per year over the past few
years, and is expected to continue. In 1972 the supply of the product
was 925.6 million barrels, made up from U.S. producers, imports, and
inventory changes^1)*. Of this 1972 supply, a total of 591.7 million
barrels of residual fuel oil were imported into the United States, while
the United States produced 292.5 million barrels. Imports of desulfurized
residual fuel oil have come mainly from the Caribbean, with small amounts
from Canada's Shaheen's Isomox Plant, Italy, and Venezuela. The countries
in the Caribbean supplying low-sulfur residual fuel oil are the Bahamas,
the Netherland Antilles, and Trinidad. These countries have been able to
desulfurize residual fuel oil commercially at a profit because of proximity
to large producing fields, availability of natural gas for plant fuel,
circumvention of certain U.S. import quotas, low taxes or tax exemptions,
the availability of deep water unloading sites, and less stringent environ-
mental requirements than in the United States.
The sulfur contained in the crude oil tends to be concentrated
in the heavier fractions during the refining operations. When refineries
are operated to maximize the yield of lighter fractions, such as gasoline,
aviation fuel, and distillate oil, the yield of residual fuel oil is
* References cited in this section are given on page 3-6.
3-1
-------
3-2
relatively low and the sulfur content is high even if the original crude
had a low sulfur content. The common practice is to sell such high-sulfur
residual oil to the maritime industry or to export it.
Process Description for Residual Oil Desulfurization
Two approaches may be employed for the desulfurization of residua]
oils. Indirect desulfurization consists of vacuum distillation, hydro-
desulfurization of the vacuum gas oil, and reblending with a small portion
of the bottom fraction. Most of the foreign and domestic low-sulfur-fuel-
oil capacity is based on such indirect processing. This approach is not
entirely satisfactory from the standpoint of supplying the demand for low-
sulfur fuels as none of the heavy, high-sulfur vacuum bottom fraction is
processed. In direct desulfurization the entire residuum is processed to
yield low sulfur fuel oil. This is basically accomplished by a catalytic
hydrogen treatment. The difficulty in this type of approach lies in the
wide variation in feedstock properties when processing different heavy
fractions from various original crude oils.
Specific processes which could be used are generally proprietary;
some details of the H-Oil process were recently published ' •
The H-Oil process employs an ebulliated bed of catalyst. The heavy oil and
hydrogen are passed upward through an isothermal reactor (700-800 F) con-
taining the catalyst. The desulfurization follows a psuedo second-order
rate equation since the reaction is proportional to the square of the con-
centration. To solve the 'problems of reduced desulfurization rate as the
sulfur concentration is reduced, the process uses a series of staged
reactors. Another problem is catalyst aging. High catalyst efficiency is
by using a catalyst counterflow. Fresh catalyst is introduced into the
last stage and spent catalyst is withdrawn from the first stage. It is
reported that the H-Oil process can be made flexible with respect to feed-
stock characteristics and product line demand. A flow diagram of a multi-
purpose plant is shown in Figure 3.1. The required hydrogen is produced
from light ends and no hydrocarbon raw material is required other than the
-------
Hydrogen
Fuel Gas H2S Free
Atmospheric
Res id
, •
H-Oil Unit
1
Hydrogen
Production
Naphtha
Light
Ends
Processing
i
H2S
Rich
Gas
Sulfur
Plant
Fuel Oil
Stabilizer
Elemental
Sulfur
Low Sulfur Fuel Oil
FIGURE 3.1. BLOCK FLOW DIAGRAM FOR MULTI-PURPOSE DESULFURIZATION PLANT
(Source: Reference 3)
-------
3-4
fuel oil feed. The process has been in operation at the Lake Charles,
Louisiana refinery of the Cities Service Oil Company since 1967. The
capacity is now 6,000 bbl/day. Total process costs were reported to
range from 88 to 138 cents per barrel of feed depending upon the type of
feed. The ratio of fuel oil product to feedstock charge ranged from 0.94
to 0.98.
Foreign Plans for Desulfurization of
Residual Fuel Oil
Due to the expected increasing international demand for low-
sulfur residual fuel oil, there are many plans by both American and
foreign companies to expand production capacity, but practically all out-
side thii
follows:
(4)
side this country. Some of these plans, announced or underway are as
• By the end of 1973, Shaheen Natural Resources, a
Canadian firm, planned a new refinery for Newfound-
land and Refinery, Ltd. The throughput of the
refinery is 100,000 bbl/day, and it has been estimated
that some 35,000 bbl/day of low-sulfur residual oil will
be produced.
• By the end of 1973, Creole, a subsidiary of Exxon,
planned to expand its capacity by 50,000 bbl/day for
low-sulfur residual fuel oil.
• Another desulfurization plant in the Bahamas was planned
for startup in 1973, by the Bahamas Oil and Refinery
Company, owned by New England Petroleum Company and
Standard Oil and Refining Company. It had planned to
expand its crude capacity from 250,000 to 400,000 bbl/day.
• In 1973, Ameranda-Hess, in the Virgin Islands planned
to expand its existing facility for production of low-
sulfur residual oil by an unknown quantity.
-------
3-5
• By 1975, a new Virgin Islands hydrodesulfurization
plant will come on stream. The Virgin Islands
Refining Company will produce low-sulfur residual
oil by an indirect process; this plant is currently
under construction by Procon, a subsidiary of UOP.
• Shaheen Natural Resources plans other desulfurization
plants. A $223 million refinery is to be built in Nova
Scotia at Park Haekensberry on the Strait of Conso.
Plans include a 200,000 bbl/day refinery, from which
80,000 bbl/day of low-sulfur residual fuel oil would
be produced.
• There is also conjecture on other desulfurization
plants. For example, Shell is building a new plant
in Curacao, but it is unknown whether it is an
additional refining facility or a replacement for
an existing facility.
Residual Oil Desulfurization Capacity
and Production in the United States
The following is a tabulation of desulfurization capacity in
the United States as of January 1, 1974, (no statistics could be found
concerning actual production):*- '
CAPACITIES OF UNITED STATES FACILITIES FOR DESULFURIZATION
OF RESIDUAL FUEL OIL
(Charge capacity in barrels per stream day)
State Refinery Capacity
Kansas CRA Incorporated, Phillipsburg 4,500
Louisiana Cities Service Oil Company,
Lake Charles 6.000
Total 10,500
-------
3-6
References for Section 3
(1) Preprint from the 1972 Minerals Yearbook, U.S. Bureau of Mines,
U.S. Department of the Interior.
(2) Gregoli, A. A., and Hartos, G. R., Pollution Control and Energy
Needs. Advances in Chemistry Series 127, R. M. Jimeson and R. S.
Spindt, Editors, American Chemical Society, Washington, D.C., 1973,
Chapter 9, "Hydro-desulfurization of Residuals", pp 98-104.
(3) Johnson, A. R., et al, ibid, Chapter 10, "H-Oil Desulfurization of
Heavy Fuels", pp 105-120.
(4) Anon., "Desulfurization Refinery Capacities", Environmental Science
and Technology, Vol. 7, No. 6, pp 494-496 (June 1973).
(5) Cantrell, Ailleen, Director of Editorial Surveys, The Oil and Gas
Journal, Vol. 72, No. 13, pp 82-103 (April 1973).
-------
SECTION 4
COAL REFINING AND LIQUEFACTION
Introduction
Two objectives of processes for coal refining and liquefaction are
to segregate for disposal the ash, sulfur, and nitrogen impurities from the
fuel or energy values, and to convert the fuel fraction to easily storable
and pumpable products for use in conventional liquid fuel systems.
Refined liquid fuels have more hydrogen relative to their carbon
content than does the solid coal from which they are derived. Therefore,
liquefaction processes have the common feature of increasing the hydrogen/
carbon ratio, either by adding hydrogen to the fuel molecule or extracting
some of the carbon from the fuel in a form that can be separated from the
primary liquid product.
The seven processes described in this section by individual
summaries of reaction conditions, process diagrams, development history, and
present status have differences that are distinguished primarily in the reactors
and the reaction conditions that they are designed to accommodate. Table 4,0
outlines the features that appear to distinguish each process from the
others.
Evaluation and rating of processes for use in commercial-size
installations must eventually consider specific sites, available coal
supplies, known process technology, production flexibility and available
markets for the range of product specifications, before a choice can be
made. Most of the processes described here are not developed enough
for direct comparisons and recommendations. All may be suitable for
large-scale operation in favorable circumstances unless current
technological uncertainties require uneconomic solutions.
4-1
-------
4-2
TABLE 4.0 COAL LIQUEFACTION PROCESSES
Distinguishing Features
Process
Reactor System
Other Features
4.1 H-Coal
4.2 Synthoil
4.3 SRC
4.4 CSF
4.5 Bergius
4.6 COED
4.7 Zinc chloride
molten catalyst
Coal and catalyst particles
suspended in circulating
liquid under hydrogen
High velocity flow of coal/
oil slurry with hydrogen
through fixed catalyst bed
Dissolve coal, treat with
H2 gas, filter and pre-
cipitate coal in solution
for clean, ash-free, low-
sulfur fuel
Dissolution of coal in pro-
cess solvent, with lique-
faction in stirred suspen-
sion by hydrogen transfer
from solvent to coal
High-pressure catalytic
hydrogenation of coal
slurry in oil fraction
from process
Low temperature carboni-
zation of fluidized bed of
coal with hot gas. Adap-
tation of commercial
carbonization processes
with substitution of
fluidized beds
Zinc chloride catalyst as
molten bath stirred with
suspended coal or coal
extract under hydrogen
pressure
Clear liquid decanted
from settling chamber
Unreacted solids separ-
ated by centrifuge
Primarily fuel in utility
or boiler use. Fired as
pulverized solid or
molten liquid.
Recovered solvent is
re-hydrogenated sep-
arately before recycle
Only process operated
on large commercial scale
(Germany, World War II)
Superseded by plans for
more efficient and
economical processes
Relatively low liquid
yield compared with
other processes. Appears
technically proven for
commercial scale
Large proportion of
catalyst relative to
coal (2:1) requires
efficient separation and
recycle
-------
4-3
4.1 H-Coal Process (Hydrocarbon Research, Inc.)
Description of the Process. Dried and pulverized coal is slurried
with recycled process oil and charged to a hydrogen-pressurized reactor
with an ebullient bed of liquid-suspended circulating catalyst particles.
Figure 4.1.1 is a diagram of the reactor in steady state operation, where
the ebullient bed is maintained for uniform temperature and composition of the
reaction mixture. Fluid slurry and gas are introduced from a plenum cham-
ber through a distribution plate near the bottom. Products are removed
from the top, as gas, clear liquid, and solid ash plus undissolved coal
dispersed in a part of the liquid. Catalyst is sized to remain in the bed,
and does not appear in the products. A small stream of catalyst suspension
is removed continuously for separation, regeneration, and return to the
reactor, so that catalyst activity can be maintained during continuous
operation.
Figure 4.1.2 is a schematic representation of the process develop-
ment unit, which has been operated to produce either synthetic crude oil
or low sulfur fuel oil. Liquid yields are about 3 bbl/ton of coal on a
moisture-and ash-free basis, and depend upon coal fed and product selected.
-------
4-4
CATALYST
INLET
SOLID-LIQUID
LEVEL
CATALYST-
LEVEL
COAL
SLURRY OIL
RECYCLE
TUBE
CLEAR
!QU
SOLID
SETTLED
CATALYST
LEVEL
D1STRIBUTOI
PLENUM
CHAMBER
GAS INLET
FIGURE 4.1.1. H-COAL REACTOR WITH EBULLIENT BED
-------
HYDROGEN RECYCLE
HYDROGEN
COAL
HYDROCARBON GASES
RECYCLE GAS
PURIFICATION
LIGHT DISTILLATE
REACTOR!
PREHEATER
T
WATER
ATMOSPHERIC
DISTILLATION
HOI OIL
REC'QE
•IfDROCLONE
Y.
HEAVY
DISTILLATE
VACUUM
DISTILLATION
r BOTTOMS SLURRY
FIGURE 4.1.2 SCHEMATIC OF H-COAL PROCESS DEVELOPMENT UNIT
-------
TABLE 4.1 H-COAL PROCESS
Facilty
Bench Scale 1 Ib
coal/hr
Process Development
Unit ~ 200 Ib coal/
hr
Pilot Plant
(proposed) 10-30
tons coal/hr
Location
Trenton, N.J.
Owner (a)
Hydrocarbon Res ea ret
Inc. ,
1964-1974
Initial support:
OCR, 1965-1967
Industrial support
1968-1973
Pilot plant pro-
posal to OCR 1974
Status/Operating History
Data primarily from Illinois No. 6 and Wyodak coals established
effect of operating variables on yields in bench scale
unit (3/4" dia.)
Process development unit confirmed bench scale results and
demonstrated sustained operation with satisfactory control of
ebullient bed (8-1/2" dia.).
Proposed (1974) pilot plant with 4.6-foot-diameter reactor to
provide design data for demonstration plant with reactors
10 feet or more in diameter.
.p-
I
Contacts: M. C. Chervenak or C. A. Johnson, Hydrocarbon Research, Inc., Trenton, N.J. Tel 609/394-3101
References (1> Johnson, Clarence A., Chervenak, Michael C., Johanson, Edwin S., Present Status of the H-Coal
Process, presented at the "Clean Fuels From Coal" Symposium, Institute of flas Technology,
Chicago, Illinois (September 10-14, 1974).
(2) Johnson, C. A., Chervenak, M. G., Johanson, E. S., and Wolfc, R. H., Scale-Up Factors in the H-Coal
Process, Chemical Engineering Progress (Vol. 69 No. 3) (March 1973). V *
(3) Johnson, C. A. and Livingston, J. Y., H-Coal; How Near to Commercialization?, presented at
The University of Pittsburgh, School of Engineering, Symposium (August 6-8, 1974).
-------
4-7
4.2 Synthoil Process (Bureau of Mines)
Description of the Process. A slurry of 35 parts coal in 65
parts recycle oil is mixed with gaseous hydrogen and injected under pressure
*
(4000 or 2000 psi) into a preheater (Figure 4.2) packed with ceramic
pellets for efficient heat exchange. The feed to the reactor is heated to
•k
reaction temperature (450 or 430 C) before passing into a tubular reactor
containing a fixed bed of cobalt-molybdenum catalyst pellets. Throughput
•j
of slurry at the high rate of 261 Ib/hr/ft of reaction volume, together
with hydrogen, induces turbulence which promotes heat transfer, helps keep
catalyst surfaces clean, and prevents solids from settling out of the
stream. Gas and liquid products are separated from the process stream and
are further purified to remove sulfur and nitrogen. Unreacted hydrogen is
recycled, and solid residues may be pyrolyzed to yield additional liquid
product before being gasified to produce make-up hydrogen.
Yields from the small-scale unit (50 Ib coal/hr) were about
3 bbl oil/ton coal. This unit has made continuous runs up to 500 hr before
voluntary shutdown. A process development unit to react.one ton of coal
per hour is in the advanced planning stage. (August 27, 1974)
*Values used in experimental tests to produce a range of product specifi-
cations.
-------
COAL-J
Recycle oil
Reoctor
Flare stock
Pre-
heoter
Back pressure
regulator
High pressure receivers
Slurry feed
pump
6os
compressor
Low pressure receivers
Furnaces-'
Centrifuge
Whole
product
I
00
NET PRODUCT OIL
Recycle gas
compressor
FIGURE 4.2.1 SYNTHOIL PILOT PLANT FLOW SHEET
-------
TABLE 4.2 SYNTHOIL PROCESS
Factlty
Continuous,
2 Ib coal/hr
15 Ib coal/hr
Pittsburgh, PA
Location
Owner(s)
or Contractor
Bureau of Mines,
Pittsburgh Energy
Research Center
Status/Operating History
This 3/16-inch tubular reactor was superseded after successful
operation with up to six weeks continuous running.
This 1.1-inch tubular reactor is now in operation to determine
yields. Runs have been completed up to 500 hours. Yield:
3 bbl oil per ton of coal. Oil specifications controlled by
process conditions. Premium grade fuel oil with 0.2 percent
S and <0.1 percent ash, or heavy fuel oil at lower cost.
Process demonstration unit is in advanced planning stage.
Favorable feasibility analysis completed. 4-inch to 6-inch
dia. tubular reactor will be used.
Comments: Accepts variety of pulverized coals. Flexibility In
product specifications. No apparent attrition of
catalysts. Possible by-product S and ammonia. High
ash residue.
vo
Contact: Dr. Sayeed Akhtar, Bureau of Mines, Pittsburgh, PA 15213; 412/892-2400 X306
References: (1) Akhtar, Nestor J. Mazzocco, Welntraub, Murray, and Yavorsky, Paul M., Synthoil Process for
Converting Coal to Nonpolluting Fuel Oil, presented at the 4th Synthetic Fuels from Coal
Conference, Oklahoma State University, Stillwater, Oklahoma (May 6-7, 1974).
(2) Yavorsky, Paul M., Synthoil Process Converts Coal Into Clean Fuel Oil. Symposium on "Clean
Fuels from Coal", Inst. Gas Technology, Chicago (Oct. 14, 1973).
(3) Yavorsky, Paul M., Akhtar, S., and Freidman, S., Converting Coal Into Non-Polluting Fuel Oil.
Chemical Engineering Progress (Vol. 69 No. 3) (March 1973).
-------
4-10
4.3 Solvent Refined Coal (SRC) Process
Description of the Process. This process is being developed to
provide primarily a clean fuel suitable for firing in utility boilers and
steam plants. One part of -7-mesh coal is mixed with 3 parts of a liquid
fraction recycled from the product stream to form a slurry for process
feed. The slurry passes through a preheater and a dissolver under hydrogen
pressure of about 1000 psi. About 90 percent of the coal substance
dissolves at 440 C (825 F) during a residence time of about 30 to 60 minutes
(Figure 4.3.1). Undissolved solids (about 50 percent carbon) are separated
by filtration. The off-gases from the reactor are washed to separate H S,
which goes to sulfur recovery. Part of the sulfur-free gaseous hydrogen-
hydrocarbon mixture is used for recycle together with make-up hydrogen, ob-
tained by gasification of the carbon in the solid residue. Process solvent
is recovered for recycle when the hot liquid filtrate is flash distilled
in a vacuum column. The distillation residue is the major product. This
solvent-refined coal product is low in ash and sulfur, with a softening
point of about 150 C (300 F), so that it may be fired as a liquid or a
solid with appropriate equipment. Gasification of the solid residue to
water gas in a separate reactor is contemplated to provide makeup hydrogen
to the SRC process. The water gas mixture of hydrogen, carbon monoxide,
and carbon dioxide could be treated in a catalytic shift converter and
washed to remove CO to give hydrogen of adequate purity. An alternative
has been investigated in which the water gas, fed to the process with
steam, is added to the slurry as the primary process feed before entering
the preheater. Results are described in progress reports to OCR from
Pittsburg and Midway and are to be published.
-------
OISSOLVER
825
X
X
\
N
1
^^ S
PREHEATER
np/*vn c
1000
(TO \
\2000j
PSIG
I
MAKE-UP
,. HYDROGEN
COMPRESSOR
VACUUM
DISTILLATION
r
LIGHT
OIL
FLASH
DISTILLATION
SOLVENT-REFINED
COAL
LIGHT
OIL
*- COKE
FIGURE 4.3.1 SOLVENT REFINED COAL PILOT PIANT
-------
TABLE 4.3 SOLVENT REFINED COAL PROCESS .
Facllty
Bench Scale -
~ 0.5 to 1 Ib coal
per hour
Location
Kansas City, MO
Pilot Plant - 2 tons Fort Lewis, WA
coal per hour
Pilot Plant - 500 Ib
coal per hr
Wilsonville, AL
Owner(s)
or Contractor
ittsburgh & Midway
Coal Mining Co.
(OCR)
Southern Services,
Inc.
[EEI, Southern Co.)
Status/Operating History
Bench scale studies from 1962 to 1966 and 1968 to present to
study product properties and solubility rates as functions
of operating parameters.
Construction completed and components undergoing performance
tests in September, 1974. Continuous integrated operation
not yet achieved.
Intermittent operations at less than rated capacity since
January, 1974. One continuous test for 45 days. Estimated
availability of quantities of light oil product for evaluation
in " a month or two". (September, 1974). Some reported
difficulties with filtration step being below rated capacity.
Contacts: Everett L. Huffman, Southern Services, Inc. Box 2625 Birmingham AL 35203 Telephone 205/870-6324
Bruce K. Schmid, Pittsburgh and Midway Coal Mining Company, Ft. Lewis, WA Telephone 206/964-8155
Reference: B. K. Schmid, "The Solvent Refined Coal Process", Symposium on Coal Gasification and
Liquefaction. Univ. of Pittsburgh, Pittsburgh, PA., (August 6-8, 1974)
l-1
N)
-------
4-13
4.4 CONSOL Synthetic Fuel (CSF) Process
Description of the Process. Crushed and dried coal (1 part) is
mixed (Figure 4.4.1) with a process middle-fraction recycled solvent
(2.5 parts) and dissolved at process temperature (400 C). Solvent is pre-
pared for recycle by catalytic hydrogenation and serves as a hydrogen donor
during liquefaction of 70 to 85 percent of the raw coal in a stirred reactor
under solvent vapor pressure for 30 minutes. Hydrogen transferred from
donor to coal is about 0.7 weight percent of the coal. Unreacted coal and
ash are separated by filters, hydroclones, centrifuges, or a combination
thereof. The oil product would be suitable as utility fuel or as low-
sulfur feed to an oil refinery.
-------
MAKE
GAS
PURGE &
RECYCLE GAS
VACUUM
DISTILLATION
12-26
IN. H«. ABS
FLASH
DISTILLATION
SPENT WATER
WATER
ACID
FIGURE 4.4.1
CONSOL SYNTHETIC FUEL PROCESS. 1 TON PER HOUR
PILOT PLANT FOR CRUDE OIL PRODUCTION
-------
TABLE 4.4 CONSOL SYNTHETIC FUEL (CSF) PROCESS
Factlty
Bench scale -
20 Ib coal/hr
Pilot Plant,
1 ton coal/hr
Location
Library, PA
Cresap, WV
Owner(s)
or Contractor
Consolidation Coal
Company (OCR
"Project
Gasoline") 1964-
1970
Fluor Corporation,
contractor
(OCR, Am. Electric
Power Co., Allegheny
Power Co.)
Status/Operating History
Bench scale provided design data for pilot plant
Pilot plant construction started 1967. Recurring mechanical
and operational difficulties with about 500 hours total
operation until shutdown in April, 1970.
Three year contract to revamp, modify, (18 months, standby to
July, 1974 thru Dec, 1974) and operate (18 months) plant for
for liquefaction data to design demonstration plant.
Plans for modification and operation Include components testing,
integration, and possibly three modes of operation for pro-
duction of liquid fuel: (1) hydrogenation of extract as
hydrogen donor, (2) fixed catalyst bed to hydrogenate coal +
recycle oil slurry, (3) ebullated catalyst bed with coal,
reclrculated oil, and hydrogen.
Contact: Harold L. Finch, Fluor Corporation, Cresap, WV, (near Moundsville, 26041) Telephone 304-845-2211
August 27, 1974
References: (1) J. A. Phinney, "Clean Fuels via the CSF Process", Symposium on Clean Fuels from Coal.
Institute of Gas Technology, Chicago, IL October 10-14, 1973.
(2) Press Release, "OCR's West Virginia Pilot Plant to Test Coal-to-Llquid Process Components",
Office of Coal Research, Washington, D.C. .June 7, 1974.
-------
4-16
4.5 Berglus Coal Liquefaction Process
Description of the Process. Germany used the Bergius process to
produce gasoline and lubricating oils on a commercial scale during World
War II by catalytic hydrogenation of brown coal. Figure 4.5.1 shows a
flow diagram of the process. After the war, the United States Bureau of
*
Mines operated a pilot plant at Louisiana, Mo, to study the direct
hydrogenation-liquefaction of American bituminous coals by the Bergius
process as well as modifications for improved efficiency. Improvements were
incorporated into the process, and operation was generally successful.
Work was discontinued in the early '50's because the process was un-
economic as long as petroleum was available. There are no active studies
of the Bergius process now (1974).
* H. R. Batchelder, "Synthetic Fuels, Economics, and Future Trends",
Chapter I, Advances in Petroleum Chemistry and Refining, Vol. 5 pp 1-77
(1962).
-------
CATALYST
1.5-5% BAYERMASSE
1.3% IRON SULFATE
56,600 SCF H2/TON
MIDDLE OIL
FIGURE 4.5.1 BERGIUS CATALYTIC HYDROGENATION GERMAN
COMMERCIAL PRACTICE
-------
4-18
4.6 COED Process (FMC Corporation)
Description of the Process. The COED process carbonizes coal in
a series of four fluidized bed reactors by direct contact with heated,
fluidizing gas. Gases pass successively from the higher to lower tempera-
ture beds as the carbonized char effluent flows countercurrent to the gas
from low to higher temperatures. Bed temperatures are controlled to dry,
devolatilize, and pyrolyze caking coals without softening and agglomera-
tion (Figure 4.6.1). Flue gas flows through the first stage at 300 C
(550 F), to a drier for the incoming coal, and through a clean-up section
to the stack. Steam and oxygen injected into the fourth stage are con-
trolled to maintain a temperature of 850 C (1550 F) by burning a part of
the char. The gases and volatiles from the fourth stage flow successively
through the third stage at 565 C (1050 F), the second stage at 450 C (850 F),
and thence to the oil recovery unit where gases are separated for purifi-
cation and liquids proceed to a hydrogenation unit to produce a synthetic
crude oil suitable for refining. The major products and approximate
yields per ton of coal are: liquid syncrude, 1 barrel; 600 Btu fuel gas,
8000 SCF; char, 1200 Ib.
-------
COAL
PYROLYSIS GAS
GAS COOLING
AND CLEAN-UP
FLUIDIZING ,
COAL "V GAS FLUIOIZING
PREPARATION^ GAS
FINES
PROCESS FINES
PROCESS LIQUOR
i
M
VO
FIGURE 4.6.1 COED PROCESS WITH ADDED CHAR GASIFICATION FMC-OCR
-------
TABLE 4.6 COED PROCESS
Facllty
Bench Scale and
Process develop-
ment Unit (100
Ib coal per hr)
Pilot Plant 1.5
tons coal/hr
Demonstration plant
25,000 tons coal
per day
Location
Princeton, MJ
Owner(s)
or Contractor
PMC Corp. (OCR)
Status/Operating History
Bench scale research and PDU operated 1962 to 1970 to provide
data for pilot plant.
1970 to present. Six typical coals and lignite processed in
integrated operations up to 30 days. Two-week runs in hydro
treating section. Puily operational. Total coal processes
has been 18,000 tons. Sufficient data for design of
demonstration plant.
Conceptual design and economic study completed 1974
Contact: *. J. Brun.vold. Manager. Commercial Deveiopment. COED Process. PMC Corporation, Box 8, Princeton, NJ 08540
Telephone 609/452-2300 July 29, 1974
Reference. (1) Hamshar, J. A., Terzian, H. D.. Scotti, L. J.. Clean Fuel. Pron, Coal By Tt.e COED Process, for presentation
v / ^^ Envi;omnental protection Agency Symposium, St. Louis, Missouri (May 1974).
,«N * _.., t t i««.. T V Ford L McMunn. B. D., Multi-Stage Fluldlzed-Bed Pyrolvais of Coal at the
<2> JS^r CORJ-plirpIanL to, preUnUtfon a^An^rlcln Instltut^ of Chemical Engineer. 77th National meeting.
Pittsburgh, Pennsylvania (June 2 to 5, 1974).
(3) Scotti, L. J., "The COED Process - Technology and Economic Feasibility", University of Pittsburgh Symposium
(August 6-8, 1974).
-p-
IxJ
o
-------
4-21
4.7 CONSOL ZnCl2 Process
Description of the Process. Molten zinc chloride is used as a
hydrocracking catalyst mixed with a tetralin extract of coal or with un-
treated coal in about 2:1 proportions of catalyst and coal substance. The
reaction mixture is maintained in a stirred reactor under hydrogen pressure
of 100 to 200 atmospheres at temperatures of 360 to 425 C. Specific con-
ditions are selected to control the proportions of gasoline and low-sulfur
fuel oil, which are the major products. The process has been operated on
a bench scale in continuous units for hydrocracking (Figure 4.7A) and for
regeneration of the spent catalyst (Figure 4.7B) by combustion of retained
impurities in a fluidized bed of inert particles. Most of the work was
carried out between 1964 and 1967 under sponsorship of the Office of Coal
Research. Recent studies of methods for regeneration of the spent catalyst
have been made by Consolidation Coal Company. It is reported that a re-
sumption of work on a larger scale is under consideration for renewed
support by the Office of Coal Research.
A unique advantage of this process is the demonstrated capability
to convert a large part of the coal substance directly into naphtha boiling
in the gasoline range and having a high octane number. Reaction conditions
are relatively mild and residence time in the reactor is reasonably low.
The major disadvantage is the use of massive quantities of zinc
chloride catalyst which must be purified and recycled economically to
arrive at a commercially viable process.
-------
4-22
ROD OUT
,. COOLING AIR
•TC W«ll
PURSE
r -.'. ,!• 1—!-
Lr iTT.
2-ALTCRNATING
SYRINGE FCtOltRSl
FLUIOIZED
COMBUSTOR
IncemieoO
Caolmg Wol«f
r—VENT
Ej
/
LANCED
i
i
&
1
ji
l>»Th«k ^
T*»lo« l
allT*
Mllt*>
Condemtr
?S«i40
toe COO
SZ'ion*
Dpi :»0-
^ Ti>0*F
VENT—
6
ELECTROSTATIC
PRECIHTA10R
SflSclllOi 2T'U"«
OpT«C50'F
PURGE
ROOOUT
UTC
! Cooing
Co-1
TO
LINE OUT
OR
MATERIAL
BALANCE
-Po-«r Supply
a CAS
RECOVIW
LWEOUT ELECTROSTATIC
PREOPITATOR
4"Lwgllior
tbrk 0*nill«
UNEOUT RECEIVER
B. Catalyst Regeneration System
CATALYST\ I
/*AYAlW^Y II
CATALYST H
MELT TANK Q^
C METERED
•F
^
J
— W
CATALYST
UIPIRMIMR TAMK
OTbiw*>in\> iMnrv
*1
y
LUMP EXTRACT Q
1- •
EXTRACT 1
•111?! T YAeliky II
MELT TANK l^
1
»
I
j
ss*
pL
M
—
i — i
HYDR(
+*Jd
? FEED PUMP
HYDROCRACKING
REACTOR
A
i
EXTRACT
FEED PUMPS
(2 syringe
type) '
£
>GEN
1.
f*
•» —
•
.c
:B
1
CATALYST
, RECIEVERS
(3)
PRESSURE
CONTROLLER
a>
3
y
-Epl LEVEL
— C-l CONTR
1
i
m
:
•
c
1
rP-1
M
r
i
rGAS
RECOVERY
1
CONDENSER
GAS METERING
a AND SAMPLING
t-fi i
/pa u
SPCV
MISTER
LIQUID
PRODUCT
RECEIVERS
fJ,«
DISTILLATE
CATALYST TO
REGENERATION
A. Hydrocracklng Process
FIGURE 4.7. CONSOL ZnCl2 PROCESS
-------
TABLE 4.7 CONSOL ZINC CHLORIDE PROCESS
Facilty
Bench Scale
Hydrocracking,
Batch Autoclave
300 ml.
Continuous stirred
reactor, 500 g
inventory
Catalyst regenera-
tion, continuous
feed at 2-120 g/
min.
Location
Library, PA
Owner(s)
or Contractor
Consolidation Coal
Company (OCR)
Status/Operating History
Reaction rates and conversions determined on bench scale equip-
ment 1964-1967'.
In-house studies of catalyst regeneration, 1973.
Process demonstration unit under consideration for OCR
support, 1974.
Contact: Dr. Everett Gorin, Research Division, Consolidation Coal Company, Library, PA 412/288-8700
References: (1) Zielke, C. W., Struck, R. T., Evans, J. M., Costanza, C. P., Gorin, E., Molten Zinc Halide Catalysts
For Hydrocracking Coal Extract and Coal. I&EC Process Design and Development, Vol. J5 pp 158-164 (1966).
(2) Struck, R. T., Clark, W. E., Dudt, P. J., Rosenhoover, W. A., Zielke, C. W., Gorin, E., Kinetics of
Hydrocracking of Coal Extract with Molten Zinc Chloride Catalysts in Batch and Continuous Systems. I&EC
Process Design and Development, Vol. 8. pp 546-551 (1969).
(3) Zielke, C. W., Struck, R. T., and Gorin, E., Flutdtzed Combustion Process For Regeneration of Spent
Zinc Chloride Catalysts. I&EC Process Design and Development, Vol. 8 pp 552-558 (1969)
(4) Zielke, C. W., Rosenhoover, W. A., Gorin. "Direct Zinc Chloride Hydrocracking of Subbituminous Coal--
Regeneration of Spent Melt", Preprints Volume 19, No. 2, PP 306-311, Division of Fuel Chemistry,
Am. Chem. Soc., 167th National Meeting, Los Angeles, CA (April, 1974).
-------
SECTION 5
LOW-AND INTERMEDIATE-BTU GAS FROM COAL AND OIL
Introduction
Gaseous products have been generated from coal for more than
150 years, and,although gas from coal was once used extensively for
commerical and residential lighting and cooking, it has never been a
significant factor in the U. S. energy economy. That situation is likely
to change within the next few decades. Increasing costs and decreasing
supplies of clean fuels coupled with the existence of extensive domestic
reserves of coal has led to a dramatic resurgence in coal gasification
research and development.
Gasification of coal transforms an abundant but inconvenient
dirty solid fuel into a convenient and clean gaseous fuel. In general,
the process involves reaction of coal with air, oxygen, or steam,or
mixtures of these gases to yield a combustible product containing carbon
monoxide, carbon dioxide, hydrogen, methane, and nitrogen.
Low-Btu gas (about 125-175 Btu/SCF) is obtained when coal is
gasified with air-steam mixtures with the result that nitrogen is the
major component of the product gas. Because of its low heating value,
it cannot be economically stored or pipelined over long distances.
Nonetheless, there are many potential uses near the source of production
including power generation, steam generation,and industrial heating. Such
uses are likely to be especially significant in areas such as the East
and Mid-west where most of the coal is relatively high in sulfur.
Although intermediate-Btu gas (about 300-500 Btu/SCF) is
usually produced by gasification with steam and oxygen, there are also
processes in which pure oxygen is not required (e.g., the C02-Acceptor
Process and the Union Carbide-Battelle Ash Agglomeration Process). In the
latter processes the heat necessary for gasification is provided by some
method other than reaction of oxygen and carbon.
Processes in this chapter are classified on the basis of the
type of fuel-bed. They range in degree of development from those that
5-1
-------
5-2
have not yet reached the pilot stage to those such as the Lurgi, the
Winkler and the Koppers-Totzek that have been operated on a commercial
scale for a number of years. Some of the advanced design gasifiers
described in this chapter are primarily intended for integration into
processes for producing high-Btu gas (Section 6). They are included
here because they can be operated to produce intermediate and/or low-
Btu gas. It should be noted that many of these advanced design gasifiers
are designed to operate at very high pressures (in excess of 1000 psi)
in order to increase direct yields of methane. Such high pressures are
unnecessary in the production of a low Btu-fuel gas.
Underground (in situ) gasification and the gasification of high-
sulfur refinery residues are also considered.
References to each specific process are given at the foot of the
respective "State-of-the-Art" table. General references to coal gasifica-
tion are given on Page 6-37.
Many of the gasification processes developed prior to 1960 have been
omitted because they are not presently receiving serious consideration for
the production of fuel gases. Several excellent reviews of these earlier
(*)
processes are available in the literature.
At this stage of development, environmental factors are best
treated in rather general terms. Moreover, because of the considerable
overlap in the environmental aspects of various gasification systems, it
is convenient to discuss all of the processes in this chapter and those in
Section 6 (Pipeline-Quality Gas) together. This discussion is presented
in Appendix A.
(*) Newman, L. L., Industrial and Engineering Chemistry, 40(4), 559-81
(1948); Shires, G. L., Chem. Eng. and Mining Rev., pp 43-50 (Aug.
15, 1958), pp 41-47 (September 15, 1958).
-------
5-3
Status of the Technology
Interest in the production of low- and intermediate-Btu fuel
gases has developed comparatively recently. The most attractive applica-
tion is in an integrated gasification-power plant complex. The clean gas
may be used as a fuel for either a conventional steam generating plant or
in one of the advanced power cycles, which are potentially much
more efficient (41). The combined (gas turbine/steam turbine) cycle is
the most highly developed of the advanced cycles and is thus the one most
frequently considered for eventual integration with a coal or oil gasifi-
cation plant. Figure 5.0 illustrates a possible configuration for such
an integrated system.
A demonstration plant is now in operation in West Germany which
generates about 170 MW of power from low-Btu gas produced from coal in
Lurgi gasifiers (Table 5.1.1). Presently, the overall thermal efficiency
is only 36 percent; however, this could be increased substantially by
increasing pressure levels and turbine inlet temperatures.
In the U.S., a number of more advanced gasification processes
are being developed for integration with combined-cycle power plants. In
particular, Foster-Wheeler Corporation is expected to begin construction
soon on a 50 TPH pilot plant which in phase I operation will provide low-
Btu gas to modified existing boilers. In phase II, projected to begin in
early 1978, the low-Btu gas will fuel a combined-cycle plant to produce
about 130 MW of power. Westinghouse has a 1200 Ib/hr process development
unit of its fluidized-bed gasifier in the pre-commission stage. If signif-
icant success is achieved in tests with this unit, they may go directly to
a full-size pilot integrated with a combined-cycle power plant rated at
about 120 MW. These projects are funded by OCR.
Texaco Oil and United Aircraft have carried out pilot-scale
studies of the combustion of low-Btu gas in an existing gas turbine system.
The gas produced from oil (13 API, 650 F initial B.P., 2 percent S) by
Texaco1s Partial Oxidation Process, was burned in a Pratt & Whitney FT 4
combustor test stand (43). Results demonstrate that low-Btu gas can be
-------
5-4
COAL OR RESIDUAL OIL
AIR
POWER
TURBINE
COMPRESSOR
TURBINE
^
r-x
— i
,^
ELECTRIC
GENERATOR
STEAM
BOILER
TO
STACK
*
. ElECtr.iC
GENERATOR
PUMP
FIGURE 5.0. GASIFIER - COMBINED CYCLE COMPLEX
-------
5-5
efficiently burned, and necessary gas turbine modifications are described.
The Texaco gasifier can also accept coal and high-sulfur residual oils.
Other gasification processes being developed for integration
with combined cycle power plants include the following: Gegas (General
Electric), U-Gas (IGT) , COGAS , Combustion Engineering, Kellog Molten Salt,
and Atomics International Molten Salt.
Probably the most demanding requirement for gasification pro-
cesses integrated with combined-cycle systems is gas purity. Current
specifications require that particulates be reduced to 0.08 Ib/MMCF or
less. No particulate size is specified, but to minimize blade erosion few
particles should be larger than 20 or 25/A(41).
Total sulfur in the fuel is limited to 162 Ib/MMCF of which
hydrogen sulfide can be no more than 0.18 percent (vol.).
Ideally, the gas should be purified while it is still at high
temperatures, but most present methods require the gas to be cooled to a
relatively low-temperature (250 F or lower). Several hot-gas purification
processes are being investigated.(*' Development of a successful process
would lead to a significant increase in thermal efficiency.
In the more immediate future, low- and intermediate-Btu gas will
probably find use as a fuel in modified existing boilers. Although it
will not be possible in all cases to retrofit existing boiler to burn low-
Btu gas (27), this process could free considerable quantities of natural
gas for other uses/**) Recent studies (26) suggest that low-Btu gas from
coal may compete favorably with stack-gas scrubbing in coal burning plants.
Commonwealth Edison of Chicago is installing three Lurgi gasifiers
to produce 150-200 Btu/SCF fuel gas from coal. The gas will be burned in
modified existing boilers at its Powerton Station in Pekin, Illinois
(Table 5.1.1); and OCR and TVA plan to install two or more stirred-bed
(TJSBM) gasifiers at a TVA power plant for a similar purpose (Table 5.1.3).
Gasifiers are also likely sources of low- and intermediate-Btu
gas for industrial use. Several Wellman-Galusha gasifiers are currently
(*) Among these are Exxon's process using dolomite in a fluidized bed,
Battelle's molten salt process, the Bureau of Mines iron oxide process
and IGT's Meissner process.
(**) More than 65 percent of the natural gas sold in this country is con-
sumed by the electric utility industry and industry generally.
-------
5-6
being used for this purpose (Table 5.1.2) and more wide-spread use of
gasifiers can be expected as supplies of natural gas become tighter.
The current status of each of the processes considered in this
Section is described in individual state-of-the-art tables that follow;
a .summary of.this information is given in Table 5.0.
An excellent and relatively recent evaluation of the technology for pro-
ducing low- and intermediate-Btu gas from coal appears in Reference 8; the
status of in situ gasification is appraised in Reference 45.
It is also useful to consider some of the more general problems
associated with unit operations common to most of the processes for
generating low- and intermediate- Btu fuel gases. Among these are the followin)
Coal Mining. The development of advanced surface and under-
ground mining technology that will increase productivity and
coal recovery and at the same time meet health, safety and environ-
mental standards will have an important bearing on coal gasifi-
cation.
Coal Preparation. At present it is not possible to crush or
grind coal to a specific size without production of surplus fines.
In most of the fluid-bed processes the coal must be sized to pre-
vent high fuel losses due to carbon-carry over, and most fixed-bed
processes cannot accept fines.
Coal Feeding. Because operating pressures are generally
rather moderate, typically a few hundred psi, feeding coal to the
gasifier is not nearly as great a problem as when SNG is being
produced (pressures often 1000 psi or greater). Nonetheless,
considerable development effort in this area is justified.
Refractory Problems. Under conditions prevailing in many
gasifiers,Si02 reacts with hydrogen to produce SiO and water
vapor. This reaction is reversed downstream, where temperatures
are lower and pipes can become clogged with Si09. Presently,
the approach is to use expensive alumina refractries (39).
-------
TABLE 5.0. STATUS OF LOW AND INTEPHEDIATE-BTU GASIFICATION} A SUMMARY
Process/Developer
Current Status
Comments
Moving-Bed/Dry Ash;
Lurgi
Wellman-Galuaha
U.S. Bureau of Mines*
Gegas/General Electric
Kellog
Moving Bed/Slagging;
Thyssen-Galocsy
Flutd-Bed/Dry Ash;
Winkler
Synthane*/US Bureau
of Mines
C02 Acceptor*/Con-
solldation Coal
Exxon Oil Company
Hydrocarbons Research
Inc.
Commercial
Commercial
1200 Ib/hr FDU, Morgantown, W.Va.
50 Ib/hr unit in operation since
1971; 1200 Ib/hr PDU is in the
design stage,
4 TPH pilot should be in operation
in mid-1975; Houston, Texas
Defunct
Commercial
3 TPH pilot under construction at
Bruceton, Pa. Expect completion
in Jan. 1975.
1.5 ton/hr pilot in operation since
1972 at Rapid City, S.D.
20 ton/hr pilot under construction
at Baytown, Texas
10 ton/day process development unit
available in Trenton. N.J.
Because the maximum size of the gasifier is limited, several
gasifier units must be operated in parallel. Older models
accepted only noncaking coals. Modified version has been
tested successfully with caking coals. See Table 5.1.1.
Standard gasifier accepts only anthracite or coke. Agitator
model also accepts bituminous coal. See Table 5.1.2.
OCR and TVA plan to install two or more commercial-size
gasifiers designed on the basis of this unit. Tests indicate
that it can accept strongly caking coals.
Hope to develop a unique coal extrusion process for feeding
coal to the gasifier. Also developing membrane systems for
gas clean-up. Process will be used to produce lov-Btu gas
for power plants.
40 TPD pilot plant was Operated In Germany In 1943-44. Work
Interrupted by WW II and not resumed.
See Table 5.3.1
Studies with a 40 Ib/hr gasifier indicate process can accept
any U.S. coal.
Can only accept lignite and subbituminous coal. Problems with
refractory failure and plugging of acceptor lines during
start up seem to be solved.
Process will be used to produce intermediate Btu gas for
upgrading to SNG.
First operated in 1958 with anthracite.
accept bituminous coal.
Modified in 1972 to
-------
TABLE 5.0 (Continued)
Procett/Developer
Current Status
Comments
COGAS/Cogaa Development
Company
Bituminous Coal
Research*
Fluidized Bed/Agglomera-
ting Ash;
U-Gas/IGT
Westtnghouse*
Ash Agglomeration*/
Battelie-Union
Carbide
Entrained Flow;
Blgas*/Bltumlnoua Coal
Research
Combustion Engineering4
Poster-Wheeler*
4 ton/hr pilot in operation since
March 1974, In Leatherhead,
England. Also, a 400 Ib/hr pilot
has been In operation In Flalnsboro
N.J, since May 1974.
Bench-scale
10 ton/hr pilot is In design stage.
1200 Ib/hr PDU mechanically com-
plete; expect first hot testa In
January 1975; Walt* Mill, Pa.
1200 Ib/hr PDU under construction
at W. Jefferson, 0. Estimate
completion in first quarter 1975.
5 ton/hr pilot under construction ai
Homer City, Pa. Estimate com-
pletion in early 1975.
5 ton/hr pilot.
50 ton/hr pilot. Construction is
expected to begin in fourth quartet
of 1974.
Process will be used to produce Intermedtate-Btu gas for
upgrading to SNC.
$2,575,000, 50-month contract with OCR to cover bench-scale
and PEDU work.that will provide the basis for design of a
pilot plant. Process will be used to produce low-Btu gas
for power plants.
Seeking funding for pilot plant. Present studies are being
made with a 4 ft. diameter gasifier. Primary purpose Is to
provide low-Btu gas for power plants.
If significant success is achieved with this unit, a decision
could be made to go directly to a full-size pilot integrated
with a combined-cycle power plant (120 MM).
co
Presently negotiating contract for construction. Very little
information available at this time. Process will be used to
produce low-Btu fuel gas for power plants.
In phase I the pilot plant will provide low-Btu gas for
modified existing boilers. In phase II (early 1978) the gas
will fuel a combined-cycle power plant.
-------
TABLE 5.0 (Continued)
Process/Developer
Current Status
Comments
Garret Flash Pyrolysis
Garret Research &
Development Co.
Entrained Flow/Slagging;
Koppers-Totzek
Texeco
Babcock & Wilcox -
DuPont
Molten Bath;
Molten Iron/Applied
Technology Corp.
MoltenSalt/M. W.
Kellog Co.
Molten Salt/Atomics
International
Underground gasifi-
cation*
Gasification of Residual
Oils:
Flexicoking/Exxon
Corp.
Texaco Partial Oxida-
tion/Texaco Oil Co.
SRP/Shell Oil Company
10 ton/hr pilot plant has been
proposed.
Commercial
Not presently operational
No longer in use.
Bench-scale.
Bench-scale.
Bench-scale.
Pilot scale testa at Hanna, Wyo.
Commercial
Commercial
Commercial
Seeking support. A bench-scale unit (50 Ib/hr) has been in
operation since Jan. 1973.
See Table 5.6.3.
Texaco has previous pilot plant experience and a semi-commercial
unit was in operation for a number of years.
A 17 ton/hr commercial unit was operated for about one year in the
early fifties by DuPont at Belle, West Virginia. Dismantled.
Studies have involved a 25 inch I.D. induction furnace to
simulate the gasifier (4,000 Ib capacity).
A process development unit is planned and preliminary flow sheets
and cost estimates have been made.
Process will be used to produce low-Btu fuel gas for power
plants.
See Table 5.8.
See Table 5.9.1.
See Table 5.9.2.
See Table 5.9.3.
vO
-------
TABLE 5.0 (Continued)
Process/Developer
Current Status
Comments
H-Cas/Hydrocarbons
Reaearch Inc.
IGT
Laboratory-scale.
Laboratory-scale.
Studies with a lab scale unit capable of processing up to
15 B/D demonstrate that res id and heavy sour crudes can be
gasified.
Studies of the kinetics of oil char gasification. Economic
analysis of the process.
*Procesa is currently fu
ded In whole or inpart by OCR or US I ureau of Mines.
I
l->
o
-------
5-11
Hot Char Transport and Injection. Many of the new processes
require the recycling of char. Development of a system capable
of transporting and injecting char at high temperatures and
pressures without producing serious erosion is a problem that
requires much more work.
Quench Chamber Corrosion. In many cases, the gasifier effluent
is quenched to scrub out heavy hydrocarbons and particulates. Be-
cause of the high temperatures and the corrosive nature of the gas
(relatively high concentrations of hydrogen sulfide), materials
for this stage of the system are subject to severe corrosion. Con-
siderable research is still needed on materials for this stage (39).
Gas Clean-up. Substantial improvements in overall efficiency
could be realized if processes can be developed that will clean the
gas at high temperatures. A number possible methods are presently
being investigated.
-------
5-12
5.1 Moving Bed/Dry Ash
In moving-bed gasifters the fuel bed is supported by a grate and
maintained at constant depth. Fuel moves slowly downward through various
zones in the bed and solid residue (dry ash) is discharged from the bottom.
Because of the counter-current flow of gas and fuel, heat economy is
excellent, and the relatively long residence time of fuel in the reactor
leads to high carbon conversion. The unit processes are relatively
simple and the technology is well-developed; however, this type of gasifier
generally has been operated only with non- or weakly-caking coals
and sized fuel must be used for maximum output. Methods of easing or
eliminating these restrictions on the coal feed are being investigated
and results will be considered in this section.
5.1.1 Lurgi (The American Lurgi Corp.)
Description of the Process. The Lurgi gasifier (Figure 5.1.1),
which is water-jacketed, operates at pressures of 300-500 psi. Lump coal
(1 inch to 28 mesh) is fed through a lock hopper system and distributed
by a rotating arm. Oxygen (or air) and steam are fed through the grate
to gasify the coal and ash is removed by the rotating grate through an
ash lock on the bottom of the unit. Excess steam is added to keep the
ash from slagging. The Lurgi gasifier combines hydrogasification and
production of synthesis gas in one reactor: synthesis gas generated in
the lower region of the gasifier by reaction of steam and oxygen with coal
passes up through the -coal bed to devolatilize, dry, and hydrogasify the
coal. Bottom temperatures are about 1800 F and the crude gas leaving the
gasifier is at about 1100 F.
The raw gas undergoes direct spray washing with water to partially
cool and clean the gas. Following further cooling in a waste-heat boiler,
remaining tars and oils are removed by a water-cooled condenser. Tars
and oils are separated and recycled to the gasifier.
-------
5-13
Finally, hydrogen suflide and carbon dioxide are removed by a
purification process, such as Rectisol,to yield a product with a heating
value of about 450 Btu/scf if the gasifier is oxygen blown.
o
FEED COAL
RECYCLE TAR
DRIVE
GRATE
DRIVE
STEAM*
OXYGEN
SCRUBBING
COOLER
Purification
GAS
WATER JACKET
FIGURE 5.1.1. THE LURGI PROCESS
(9)
-------
TABLE 5.1.1. LURGI: STATE OF THE ART
Factlty
300
55
22
4.
25
45
15
50
x 106 SCF/day
x 106 SCF/day
x 106 SCF/day
x 106 SCF/day
x 106 SCF/day
x 106 SCF/day
x 106 SCF/day
Location
Sasolburg, South
Africa
Dora ten, Germany
Melbourne, Australia
Daud Khel, Pakistan
Heat fie Id, Scotland
Coleshlll, England
Seoul, Korea
Owner (s)
or Contractor
South Afrlclan Coal,
Oil and Gas Corp.
Dors ten, Stelnkolen-
gas AC
Morwell Gas and
Fuel Corp.
Pakistan Industrial
Development Corp.
The Scottish Gas
Board
West Midlands Gas
Board
Naju, Honam
Fertilizer Corp. Lt
Statua /Operating History
Started operation in 1955 with 10 gasifiers; added 3 more in 1966.
Synthesis gas for Flscher-Tropsch synthesis Is major product.
Gu cleanup with Rectlsol; waste water cleanup with Phenosolvan.
Output is limited by purification capacity not gasification (4).
Started operation in 1955. 6 gasifiers produces town gas from
high volatile coal.
Started operation in 1956. 6 gasifiers produces town gas from
lignite.
Started operation in 1957. 2 gasifiers produces synthesis gas
from high volatile, high-sulfur coal.
Started operation in 1960. 4 gasifiers produces town gas from
weakly-caking high-volatile coal.
In 1973-74 tests were carried out to determine the ability of a
modified Lurgi gaslfier to accept caking coals. These tests,
sponsored by AGA and OCR, involved Illinois 15 and #6, Montana
Rosebud Subbltumlnous, Pittsburgh Seam #8 and simulated run of
the mine coal. All were successfully gasified. On basis of
results, Lurgi will guarantee its gasifiers will accept 111.
#5 and (W and the Montana Subbltuminous. More work will be
needed before that guarantee can be extended to other coals.
Started operation in 1963. 2 gasifiers produces town gas from
caking sub -bituminous coal.
Started operation in 1963. 3 gasifiers. Produces synthesis gaa
1 from graphite anthracite.
x 106 SCF/day Prlatlna. Yugoalovta Government Started operation In 1972. 3 gasifiers. Produces town gas and
synthesis gas from poor quality lignite. 3 more gasifiers are
to be added. Use Rectlsol for gas cleanup; Phenosolvan Is used
to cleanup waste water.
Ln
-------
TABLE 3.1.1 (Continued)
Facllty
160 x 10 SCF/day
60 ton/hr Pilot
Location
Luenen, W. Germany
Pekln, 111
Owner(s)
or Contractor
r~*~*^** - - —
Steinkolen-
Elektrlzltat AG
(STEAG)
Commonwealth
Edison of Chicago
REFERENCES:
(1) Hottel, H. C
..I
id Howard J. B., New Energy Technology;
i ± i nu U UC ^ • •* • ^ • »i»« »BMT*MK »• — • — m r _ij_^_ -LJ-M. —^___
(2) The Supply Technical Advisory Task FJorce-Synthetlc Gas-C
• _- . . ,* nl • i /* .11 1 OTQ \
Federal Power Commission (April 1973
(3) "Evaluation of
oal Gasification Tec
Academy of Englieerlng, Washington,
(4) Hoogendoorn, Jat1
Fuels from Coal
(6) Squires, Arthur
(7) Rudolph, Paul F
Chemical Soclet)
inology. Part II, Lov
C., "Gas from Coal
pp 111-126, Chicago
(5) Anon,"Coal Gasification Plant Begins
(Division of Fuels
Status/Operating History
tarted operation In 1972. 5 gaslflers (operated with air). Low-
Btu gas (~180 Btu/SCF) Is used to power a combined-cycle genera-
ting plant with a total net output of 170 MW. No provisions for
desulfurlzation at present - to be added.. Can be operated with
slightly caking coals but coals with pronounced caking properties
are not satisfactory. An 800 MW Unit of this type planned for
operation In 1981. (7,8)
istlmate completion by 3rd quarter of 1976. Will Involve 3 gasl-
flers. Low-Btu (150-200 Btu/SCF) fuel gas desulfurlzed with hot
potassium carbonate) will be burned in modified existing boilers.
Six different coals will be Investigated during early tests.
ome Facts and Assessments. MIT Press, Cambridge, Mass. (1971).
).C. (1973).
Lurgi Gasiflcati
(1973).
Operation Soon", Che
al, Prepared by the Synthetic Gas-Coal Task Force for the
- and Intermedlate-Btu Gas", National Research Council, National
on at SASOL", Institute of Gas Technology Symposium on Clean
Tiical and Engineering News ; (November 5, 1973).
340-346, Science Vol. 184, No. 4134 (April 19, 1974).
' _ _ . _ . .. f,i < II A.AMJ
Ui
Jhemistry) Symposium
M., "Clean Fuels fronCoal Gasification", p jtu-jtu, «*.«=..»— -~. —.,—..-- • >-. -"-.-„ Am<>_lcfln
H "A New Fossll-Fieled Power Plant Prccess Based on Lurgi Pressure Gasification of Coal , American
n. , n new two.94.1. »!__,.„..«- or,^ 1Ti,i-iif» PmjpT- TvrlAS.
on Coal Combustion In Present and Future Power Cycles,
(8) SiS* ^>H!:'"c;mELed"Gas-Mand1Steam-Turbine Process with Lurgi Coal Pressure Gasification", Institute of Gas Technology
Symposium on'ciean Fuels from Coal, pp 127-142, Chicago (1973).
(9) Moe, James M., "SNG from Coal via the Lurgi Gasification Process , Ibid, pp 91-110.
-------
5-16
5.1.2 Wellman-Galusha (McDowell Wellman Co.)
Description of the Process. A tvo-compartment feed bin is
mounted on top of the gasifier. Disc valves permit fuel from the lower bin
to flow continuously through the feed pipes to fill the fire chamber, and
revolving grates discharge ash from below. The gasifier is water-jacketed
and the inner wall is one inch steel plate, which requires no refractory
lining.
Air (and/or oxygen) and steam enter from the bottom of the grate
to gasify the coal. The standard Wellman-Galusha producer is shown
schematically in Figure 5.1.2. An agitator producer is available which
has a revolving horizontal arm, which also spirals vertically below the
surface of the coal bed to retard channeling and maintain a more uniform
fuel bed.
The product gas for the air-blown process has a heating value
of 150-170 Btu/SCF and contains very little methane (less than 2.5 percent
for bituminous coal). The gasifier can also be oxygen blown, in which case
an intermediate-Btu gas would be produced.
The standard gasifier accepts only anthracite or coke; the
agitator gasifier also accepts bituminous coal.
-------
5-17
WATER JACKET
DISTRIBUTOR
COMBUSTION
ZONE
TYPICAL BUILDING
AND FUEL ELEVATOR
OUTLINE
FUEL BIN
VALVES CLOSED
LOCK HOPPER
WATER SEAL AND
DUST COLLECTOR
GASIFICATION
ZONE
FIGURE 5.1.2. WELLMANN-GALUSHA FUEL GAS GENERATORd)
-------
TABLE 5.1.2. WELUMAN-GALOSHAt 8TAT1 OP THE ART
Facilty
Location
Owner(•)
or Contractor
Status/Operating History
This Is a commercial gastfier that has been in use in the U S
for 30-40 years. Several are currently in operation including
those at the following locations:
National Line and Stone, Carey, Ohio
M.A. Hanna, Oregon
Olin-Matheson, Kentucky
New Jersey Zinc, Astabula, Ohio
Glen-Cery Corp., Reading, Fa.
There are also units operating in Canada, India, Tiwan and
Cuba.
Supplier in the U.S. is McDowell-Weliman Engineering Co.,
Cleveland, Ohio
Ui
i
1-1
oo
(Contact; John F. Magnueon, McDowell -We llraan Engineering Co., Cleveland, Ohio (216) 621-9934)
References:
(1) "Gas Generator Research and Development: Survey and Evaluation" Phase One. Prepared by Bituminous Coal
Research for the Office of Coal Research (August 1965).
(2) "Evaluation of Coal Gasification Technology. Part II. Low-and Intermediate- Btu Gas". Office of Coal
Research, Washington (1973).
-------
5-19
5.1.3 Bureau of Mines Stirred-Bed
Description of the Process. Many U.S. coals are unsuitable
for use in moving-bed gasifiers because of their caking properties. The
Bureau of Mines has studied the possibility of processing strongly
caking coals in pressure gasifiers in which the fuel bed is continuously
stirred. Vigorous, continuous stirring throughtout the bed breaks up
coke formations and results in uniform bed conditions.
The unit shown schematically in Figure 5.1.3 has a diameter
of 3.5 feet and is operated at moderate pressures. A variable-speed drive
acting through two mechanisms rotates the shaft and moves it vertically
in reciprocal motion. It does not appear necessary to extend stirring
into the oxidation zone, and thus the lower rabble arm is not subjected
to high temperatures in an oxidizing environment.
Air and steam are admitted below the grate. Temperatures are
held below the ash fusion temperature to avoid forming clinkers which
could clog the grate. Coal is fed intermittently through lock hoppers.
Ash discharged by eccentric rotation of the grate is removed through lock
hoppers.
The product gas has a heating value in the range 140 to 165 Btu/
SCF.
-------
5-20
GRATE DRIVE
STEAM
RUPTURE DISK
> AGITATOR DRIVE
AGITATOR
GRATE
AIR
FIGURE 5.1.3. BUREAU OF MINES GASIFIER
(1)
-------
TABLE 5.1.3. BUREAU OF MINES STIRRED-BED PRODUCER: STATE OF THE ART
Faellty
Location
Owner(s)
or Contractor
Status/Operating History
1200 Ib/hr process
development unit
Morgantown, W. Va,
U. S. Bureau of
Mines
This unit has been In operation since 1972. Preliminary tests
reported In 1972' *•' demonstrated that strongly caking coal can
be gasified In a stlrred-bed producer. Presently studying
optimization of operating conditions. Studies are to be
carried out at pressures of 15, 100, 150, and 280 psi. Also,
plan runs with TVA coal with the goal of providing conceptual
design for commercial gasiflers for TVA.
The OCR-TVA program calls for installation of 2 or more
stirred-bed gasiflers at a TVA power plant. In addition, a
cess Is to be developed for hot-gas cleanup.
N3
(Contact: A. J. Llberatore, U. S. Bureau of Mines, Morgantown, West Virginia, (304) 599-7161)
(1) Lewis, P. S., Llberatore, A. J. and McGee, J. P., "Strongly Caking Coal Gasified by Stlrred-Bed Producer",
RI 7644, U. S. Bureau of Mines, Morgantown, West Virginia (!°72).
(2) Rafuse, R. V., Goff, G. B., and Liberatore, A. J., "Noncakit,; . oal Gasified In a Stirred-Bed Producer", Bureau of
Mines Clean Energy Program, Technical Progress Report, 77 (March 1974).
-------
5-22
5.1.4. Gegas (General Electric Company)
Description of Process. General Electric is developing a
moving-bed gasifier capable of producing low-Btu gas for combined-cycle
power generating plants (Figure 5.1.4). Considerable emphasis has been
given to the development of a coal-extrusion feed system in which fines and
feed coal are compacted and injected into the gasifier in a single operation,
lar recovered from the off-gas is used as a binder. This unique feed
system would permit the use of a wide variety of coals with the well-
established moving-bed technology. A conventional lockhopper feed
system Is considered a development option.
The gasifier is air blown and will operate at a pressure of
about 30O psl under dry ash conditions.
General Electric has devoted considerable research and develop-
ment effort to a membrane purification system for use with the Gegas process.
-------
5-23
WATER
WATER
FEED
LOCKHOPPER
REFRACTORY
DILUENT
SWELLING ACCOMMODATION SWELLING PREVENTION
(BULK DILUENT) " (HOMOGENEOUS DILUENTS)
FIGURE 5.1.4. GEGAS PROCESS DEVELOPMENT OPTIONS
(2)
-------
TABLE 5.1.4. THE GEGAS PROCESS: STATE OF THE ART
Facllty
Location
Owner(a)
or Contractor
Status/Operating History
50 Ib/hr bench-
scale gaslfier
1200 Ib/hr process
development unit
Schenectady, N.Y.
General Electric Co.
In operation since 1971. Considerable effort devoted to R&O
of coal extrusion process for feeding coal to the gaslfler,
and on ability of process to accept a wide variety of coals
Design stage.
Ul
i
NJ
-P-
Commentst Primary purpose Is to produce low-Btu gas suitable for use In combined cycle power plants. GE Is also doing con-
siderable R&D on membranes for clean-up of the off-gas at 300 psl.
(Contact; Dr. Paul H. Kydd, General Electric Co., Schenectady, N.Y. (5180-346-8771; X6535)).
References;
(1) Perry, Harry, "Coal Conversion Technology", Chemical Engineering, pp 95-96, Vol. 81, No. 15, (July 22, 197.4).
(2) Courtesy General Electric Co., Schenectady, N.Y.
-------
5-25
5.1.5 Kellogg Fixed-Bed Gasifier (MW Kellogg Co.)
A simplified flow diagram of the processes is shown in Figure
5.1.5. Sized coal with up to 20 percent fines is fed through lock hoppers to the
gasifier which operates at about 15-25 psi. Steam and air, enriched air, or oxygen,
are fed through the bottom of the grate.
Particulate matter is removed from the offgas leaving the gasifier by
eye lones,and tars and other condensables are removed in a condenser with a
steam drum.
The depth of ash in the gasifier is kept constant by use of a
variable-speed revolving grate. Accumulated ash is dumped by gravity and
removed from the gasifier by a lock hopper system. Stirring of the bed
increases the variety of coals that can be accepted.
After desulfurization, the product gas has a heating value of
about 150 Btu/SCF if the gasifier is air blown. If oxygen is used, the
heating value is about 300 Btu/SCF.
Coal
Condenser waste
heat boiler
Steam drum
Oxygen
Air
Product gas
Water
Ash
FIGURE 5.1.5. KELLOGG FIXED-BED GASIFIER
-------
TABLE 5.1.5. KELLOGG FIXED-BED PROCESS
Faellty
Location
Owner(•)
or Contractor
Statua/Operating History
ton/hr Pilot
Houaton, Texaa
M.W. Kellogg Co.
Will begin operation in mid-1975.
(Contact: George
Chedaey, M.W. Kelloga Co., Houaton, Texaa (713) 626-3236)
Ul
i
fo
Reference:
(1) Anon, Chemical and Engineering Neva, pp 17-18 (Auguat 12, 1974).
-------
5-27
5.2 Moving Bed/Slagging
In these gasifiers the moving bed is operated at temperatures
that are high enough (2700 to 3000 F) to keep the ash in a molten state.
Operation under slagging conditions results in increased steam decomposi-
tion and allows for higher throughput. It also results in the cracking of
tars and oils so that a cleaner raw product is obtained.
A number of moving-bed/slagging gasifiers were built in Europe
prior to 1950 and operated on a commercial scale. The Thyssen-Galoczy is
representative of this type of gasifier.
5.2.1 Thyssen-Galoczy
Description of Process. The gasifier is blast-furnace shaped
with three sets of tuyeres (Figure 5.2.1). Those comprising the lowest set
are actually water-cooled burners in which gas from the process is burned
in a mixture of steam and oxygen. Those at the upper levels admit oxygen.
Only one of the two upper levels of tuyeres is used at any given time (the
choice depends upon operating conditions). The gasifier operates at
atmospheric pressure and 2900 F.
The base of the reactor has a refractory lining to resist erosion
by molten slag. Coarse coal (1.5-2.5 inches) is charged to the gasifier
by means of a bell arrangement. Slag is tapped at a level just below the
gas burners, and iron, if any, is tapped at the bottom of the shaft.
The process was intended for use on any caking or noncaking fuel,
and regardless of ash content or melting point. However, the only demon-
strations appear to have been on closely sized coke of good quality. Under
these circumstances the gas produced is composed principally of carbon
monoxide (65-70 percent) and hydrogen (23-25 percent). Very little (0.2
percent) methane is produced.
-------
5-28
FIGURE 5.2.1. THYSSEN-GALOCSY SLAGGING GAS GENERATOR(1)
-------
TABLE 5.2.1 THYSSEN-GALOCSY: STATE OF THE ART
Facllty
Location
Owner(a)
or Contractor
Status/Operating History
2 ton/dav Pilot
40 ton/day Pilot
Duisburg-Hamborn,
Germany
Wanne-Elckel,
Germany
Thyssen'sche Gas
und Wasserwerbe
Krupp Treibstoffwerk
Reliable Information not available
s Tests were carried out In late 1943 and early 1944 with the
hope of demonstrating that this unit could gasify any grade
of fuel In any size or combination of sizes from No. 4 mesh
to 3 Inches, caking or noncaking and regardless of ash con-
tent. Testing was interrupted by the war and work was not
resumed.^'
Oi
i
VO
References;
(1) Wright, C. C., Barclay, K. M., and Mitchell, R. F., Ind. Eng. Chem. pp 578-9, Vol. 40, (1948).
(2) Von Fredersdorff, C. C., Elliot, M.A., "Coal Gasification", In Chemistry of Coal Utilization. H. H. Lcvry,
Editor, Supplementary Volume, John Wiley and Sons, Inc., New York, pp 892-1022 (1963).
-------
5-30
5.3 Fluid-Bed/Dry Ash
In fluidized-bed reactors, the gas flows through the bed and the
size of the coal particles is such that the bed behaves like a fluid. In
general, fluidized-bed reactors can accept fuels with wide variations in
quality, and because of characteristically high heat transfer, bed tempera-
tures are uniform and easily controlled. Hie very effective gas-solid con-
tact leads to increased reaction rates and thus high volume efficiencies.
On the other hand, pretreatment is required to prevent agglomeration, and
carbon carryover in the product gas can result in high fuel losses, par-
ticularly with unreactive or friable fuels. Also, the range of possible
operating conditions is restricted by the fluidization characteristics of
the fuel.
5.3.1 Winkler (Davy Power Gas Company)
Description of the process. The Winkler process (Figure 5.3.1)
is a commercially proven, fluidized-bed, atmospheric pressure system
which can be either air-or oxygen-blown. Crushed coal is fed to the
gasifier through variable speed screws. The gasifying medium fludizes
the coal bed and gasifies the coal at uniform temperature. Oxygen (or
air) and steam are added at both the bottom and the top of the bed.
Top addition serves to increase the conversion of carbon in the gasifier.
About 70 percent of the ash is carried out of the generator
with the product gas while the remainder leaves at the bottom of the fluid
bed. To prevent the deposit of molten particles in the exit ducts,
part of the waste heat recovery system is installed in the generator
immediately above the gasification zone. This cools the gas sufficiently
to prevent sintering of the fly ash on the walls.
The Winkler generator is applicable to a variety of coals;
however, caking coals, as a rule, cannot be gasified without pretreatment
which results in a lower overall conversion efficiency. The Davy-Power
Gas Company (the American supplier) is studying the possibility of
pressurizing the Winkler Generator.
The product gas from gasification with oxygen has a heating value
of about 280 Btu/SCF, while that from air-gasification is about 120 Btu/SCF.
-------
5-31
PURGE AND INERT
GAS LINES T0
STACK
GAS TO DUST
'COLLECTOR
WASTE HEAT
STARTER —
GENERATOR
STEEL SHELL
REFRACTORY LINING
RATCHET DRIVE
WATER-COOLED
SHAFT
STEAM
OXYGEN OR
ENRICHED AIR
WATER-
JACKETED
SCREW CONVEYOR
SCRAPER FOR
ASH REMOVAL
GRATE
RATCHET DRIVE
WATER-COOLED SHAFT
'ASH
RECEIVER
FIGURE 5.3.1. WINKLER GASIFIER
(3)
-------
TABLE 5.3.1 WINKLER: STATE OP THE ART(1)
Facilty
Commercial
Commercial
Commercial
(Contacti I. N. Bar
References
Location
Gorazde,
Yugoslavia
Kutahya, Turkey
Madras, India
chick, Davy-Pwwer Ga
Owner (B)
or Contractor
Fabrlka Azotnlh
Jendlnjenja
Azot Sanyyll TAS
Neyveli Lignite Corp
, Lakeland, Florida
Status /Operating History
Started operation in 1953. One gaslfier with a- normal
operating capacity of 190 x 1CP SCF/hr. Produces synthesis gas.
Started operation in 1959. Two gaaifiera; each with a normal
operating capacity of 450 x ItP SCF/hr. Produces synthesis gas.
Started operation in 1959. Three gasifiers, each with a normal
operating capacity of 1550 x 103 SCF/hr.
(813) 646-7100)
(1) "Evaluation of Coal Gasification Technology, Fart II Low—and Intermediate—Btu Gas" National Research Council,
National Academy of Engineering, Washington, D.C. (1973).
(2) Banchlck, I.N., "The Winkler Process tor Production of Lov-Btu Gas from Coal", Institute of Gas Technology
Symposium on Clean Fuels from Coal, pp 163-178, Chicago (1973).
(3) Indian Government Sponsored Study of Commercial Coal Gasification Processes, V. N. Kaaturiranzan, M. Satyapal,
R. R. Iyer, D. G. Rao and S. B. ChatterJi, reproduced by Koppers Company, Inc., Pittsburgh (1973).
(4) Perry, Harry, "Coal Conversion Technology", Chemical Engineering, pp 88-102,(July 22, 1974).
Oi
u>
(1) A number of other commercial-scale Winkler gasifiers have been operated since 1926. This table, includes only
those presently in operation (for a complete list see reference 2).
-------
5-33
5.3.2 Snythane (Bureau of Mines)
Description of the Process. A flowsheet for the Synthane process
is shown in Figure 5.3.2. Crushed coal is fed from a lock hopper system to
a pretreater where the caking tendency of the coal is destroyed by treat-
ment with oxygen and steam at 750 F. Pretreated coal, together with any
volatile matter, and excess steam is ted into a two-zone gasifier which
consists of a dense fluid bed in the top section and a dilute fluid bed
in the bottom section.
Coal undergoes devolatilization and noncatalytic methanation at
1100 to 1470 F and 1000 psi in the dense fluid bed, and is then gasified
with steam and oxygen in the dilute fluid bed at 1750 to 1800 F to produce
the synthesis gas for the upper bed. The raw gas is quenched to remove
tar, and H-S is removed by scrubbing.
Operation with steam and oxygen produces a gas of about 300 Btu/scf
while operation with steam and air yields a gas of about 180 Btu/scf.
The process accepts all types of coal.
t
H2S
STEAM AND
OXYGEN
FLUID-BED
PRETREATER
800 F
PURIFICATION
T
Product
Gas
CHAR TO POWER PLANT
FIGURE 5.3.2. SYNTHANE PROCESS(4)
-------
TABLE 5.3.2. SYNTHANE: STATE OF THE ART
Facilty
Location
Owner(•)
ot Contractor
Status/Operating History
75 ton/day Pilot
Bruceton, Pa.
U.S. Bureau of Mines
Construction about 60% completed as of July 1974. Expect
completion in January 1975. Cost $13 x 10 . Studies on a
wide variety of coala with a 40 Ib/hr gasifier indicate
process will accept any U.S. coal.
t
U)
-p-
(Contact: J. Forney, U.S. Bureau of Mines, Pittsburgh. Pa., (412) 892-2400)
References;
(1) Hottel, H. C., and Howard, J. B., New Energy Technology - Some Facts and Assessments. MIT Press, Cambridge
Mass. (1971).
(2) "Evaluation of Coal Gasification Technology, Part II Low- and Intermediate- Btu Fuel Gas", R&D Report No.
74, Interim Report No. 1, Office of Coal Research, Washington, D.C. (1973).
(3) The Supply-Technical Advisory Task Force-Synthetic Gas-Coal, prepared by Synthetic Gas-Coal Task Force
for the Federal Power Commission (April, 1973).
(4) Forney, A. J., Hayncs, W. P., Elliot, J. J., Gasior, S. J., Johnson, G. E. and Starkey, J. D., Jr., "The
Svnthane Coal-to-Gas Process", Institute of Gas Technology Symposium on Clean Fuels from Coal, pp. 199-208,
Chicago, (1973).
-------
5-35
5.3.3 CO Acceptor (Consolidation Coal Co.)
Description of the Process. There are two reactors, the
gasifier and the regenerator (Figure 5.3.3). Crushed coal is fed through
lock hoppers to the gasifier where it is devolatilized and then gasified
at 150 psi and at temperatures in the range of 1500 to 1550 F. Introduction
of the feed at the bottom of the reactor fluidized bed provides sufficient
residence time for the cracking of coal volatiles.
The devolatilized char is fluidized and partially gasified
by steam. Heat for devolatilization and gasification is provided by
reaction of carbon dioxide in the gas stream with the acceptor, calcined
dolomite. Hot calcined acceptor flows by gravity from the regenerator to
the gasifier and is introduced above the gasifier char bed. Acceptor
showers through the char bed supplying both sensible and chemical heat and
collects in a reduced cross-section boot at the bottom of the gasifier.
Spent acceptor is segregated from the lower density char and
carried pneumatically to the regenerator where it is calcined at 1870 F.
Heat for this process is provided by combustion of residual char with air.
The product is an intermediate-Btu gas.
The process is designed to operate with lignite or subbituminous
coal.
-------
5-36
FLUE CAS
ASH
REGENERATOR
PRODUCT CAS
If- 11 ATM
GASIFIER
FIGURE 5.3.3. CO2ACCEPTOR PROCESS DIAGRAM
-------
TABLE 5.3.3. C<>2 ACCEPTOR: STATE OP THE ART
Factlty
40 ton/day Pilot
plant
Location
Rapid City, S.D.
Owner(s)
or Contractor
Consolidation Coal
Co., (OCR and AGA
support) (plant
constructed and
operated by Stearns
Roger Corp.)
Status/Operating History
Plant cost about $9.3 x 10 . In operation since April 1972,
25 runs were completed in the period 4/72 - 5/74; three were
of 100 or more hours.
Mechanical problems in earlier runs slowed the
acquisition of fundamental data. More recent runs have
been more successful.
- Problem of refractory failures has been solved.
- Corrosion of fired heaters by H,S has been eliminated by use
of ZnO system to remove H S. However, formation of metal
carbides by carbon deposition still resulted in loss of
metal. Hope to solve this by adding steam to the gas going
to these burners.
- Problems with char combustion and plugging of acceptor lines
during start-up also appear to be solved.
- Designed for use with lignite and subbituminous coal.
- Designed to operate at pressure of 150 to 300 psi and tempera-
tures up to 1800 F.
(Contact! Carl E. Fink. Consolidation Coal Co.. Rapid City, S.D., (605) 342-6416)
Ln
t
U>
References:
(1) Hottel, H. C., and Howard, J. B., New Energy Technology - Some Facts and Assessments. MIT Press, Cambridge. Mass..
(1971).
(2) "Evaluation of Coal Gasification Technology, Part II, Low- and Internediate-Btu Fuel Gas, Office of Coal Research,
Washington, D.C. (1973).
(3) The Supply-Technical Advisory Task Force-Synthetic Gas-Coal, prepared by Synthetic Gas-Coal Task Force for the
Federal Power Commission (April, 1973).
(4) Fink, Carl E., "The CO Acceptor Process", Institute of Gas Technology Symposium on Clean Fuels from Coal, pp 301-
310, Chicago (1973). i
(5) Annual Report for Calendar Year 1972, Office of Coal Research, U.S. Dept. of Interior, Washington (1973).
(6) Annual Report 1973-74, Office of Coal Research, U.S. Dept. of Interior, Washington (1974).
-------
5-38
5.3.4 Exxon
Description of the Process. Exxon is developing a fluid-bed gasi-
fier for production of intermediate-Btu gas from coal. Very little has been
published about this process, though it is known that it operates at pressures
of a few hundred psi and does not require oxygen. Presumably, the heat
required for gasification is obtained from hot char produced in another reactor
by partial combustion of coal with air. Coal is fed to the gasifier by a
lock hopper system.
-------
TABLE 5.3.4 EXXON: STATE OF THE ART
Facllty
.5- ton/day process
development unit
500 ton/day pilot
Location
Baytown, Texas
M it
Owner (a)
or Contractor
Exxon Oil
ii ii
Status/Operating History
In operation since 1967.
Results demonstrate process wroks with wide variety of coals.
Construction is expected to be completed by fall of 1976.
(Contract has been let.)
Comments: Proprietary process. Very little information available.
(Contact; R. Pennington, Exxon Corp., Baytown, Texas (713) 427-5711)
References:
(1) Anon, "New Processes Brighten Prospects of Synthetic Fuels from Coal", p. 97, (April, 1974).
-------
5-40
5.3.5 HRI Gasification (Hydrocarbon Research Incorporated)
The HRI fluid-bed process is shown schematically in Figure 5.3.5.
Coal fines are charged to a hopper which is then pressurized to transfer
the coal to the gasifier which operates at 400 psi. Steam and oxygen (or
air) are preheated to about 1000 F before entering the gasifier.
Coal flows downward through the gasifier and dry ash is removed
from the bottom. The gas is scrubbed to remove particulates and desulfurized.
If the gasifier is air blown, a 150 Btu/SCF fuel gas is obtained.
Gasification with oxygen increase the heating value to about 250-350 Btu/SCF.
-------
CLEAN SYNTHESIS GAS OR FUEL GAS
GAS
PURIFICATION
SULFUR
RESIDUE
STEAM
WASHED ANTHRACITE REFUSE
AND RUN-OF-MINE ANTHRACITE
COAL DRYING
AND GRINDING
HRI FLUID
BED GASI-
FIER
ASH
CHAR
Ui
-e-
AiR ASH
OXYGEN STEAM
OR AIR
FIGURE 5.3.5. SCHEMATIC FLOW SHEET OF ANTHRACITE GASIFICATION PILOT PLANT
-------
TABLE 5.3.5. HRI: STATE OF THE ART
Facilty
10 ton/day
Location
Trendton, N. J.
(Contact: Mr. J.
Owner(a)
or Contractor
Hydrocarbon Researct
Inc.
Y. Livingston. Hydrc
Statu*/Operating History
Run
In operation for a period of about three nontha In 1958.
Six runa were made, the laat one for a 2 week duration.
waa terminated voluntarily and inspection revealed unit
was In good condition.
In 1972 the gaalfier was modified to gaaify bituminous coal
under contract with Bureau of Mines in conjunction with its
aynthane program. That work la completed.
(Original unit waa deaigned primarily to gasify anthracite
refuse and/or run-oftnlne anthracite.)
Ul
t
carbon Research, Inc., N.Y. (212) 349-1480
Reference;
(1) "Gasification of Anthracite Breaker Refuse and Anthracite to Produce Clean Fuels", A Proposal from HRI to OCR (1972).
-------
5-43
5.3.6. COGAS (Cogas Development Company)
Description of Process. COGAS is a fluidized-becl process that
produces both synthetic crude oil and gaseous products from coal. The
initial step involves a multi-stage pyrolysis of the coal to extract the
volatile matter and produce a low-volatile char. This part of the process
together with fixed-bed hydrotreating of the raw liquid from pyrolysis is
the COED process described in Chapter 7. It is the source of synthetic
crude.
The char that is produced is gasified to produce an intermediate-
Btu gas suitable for upgrading to SNG. Because the gasification process
is proprietary in nature, little information has been published. The char
is gasified with steam or steam and hydrogen at 1600 to 1700 F and low
pressures (15 to 40 psi). The heat necessary for gasification is provided
by combustion of a portion of the char in air "with provision for preventing
the air from mixing with the product gas".
Part of the raw gas from the gasifier is used in the hydrotreater
to upgrade the raw oil produced by pyrolysis. Gaseous products from pyrolysis
are combined with the raw gas from the gasifier and purified to produce a
product with a heating value of about 400 Btu/SCF.
-------
TABLE 5.3.6. COCAS: STATE OF THE ART
Facilty
Location
Owner(s)
or Contractor
Status/Operating History
100 ton/day Pilot
5 ton/day Pilot
Leatherhead,
England
Plainsboro, N.J.
(Contact: Howard
Operated for Cogaa
Development Co.
by the British
Coal Utilization
Board
Cogas Development
Co. (a consortium
of FMC Corp., Con-
solidated Natural
Gas, Panhandle
Eastern Pipe Line,
Republic Steel,
Rocky Mountain
Energy and Tenn.
Gas Transmission
Co.)
Operational since March 1974. Mechanical problems were few and
were overcome with relative ease. Past several months have
been devoted to proving process operability.
Operational since late spring of 1974. No information available.
Through calendar 1974, Cogas Development. This Included bench
scale work, process and economic studies, and the design,
construction and operation of two pilot plant facilities.
Malakoff (General Ma
lager), Cogaa Development Co., Princeton, N. J. (609) 452-2300
References:
(1) Dierdorff, L. H., Jr., and Bloom, R
at the West Coabt Meeting of the So<
(2) -
Jr., "The COCAS Pr
iety of Automotive E
>ject - One Method of Coal to Gas Conversion", paper presented
tigineers, Portland, Oregon (August 20-23, 1973).
™ - — -—• v «»..Q v « ^••*. «w *.^ wy w«. *»uh. wu*w v. m. v» t £•
Perry, Harry, "Coal Conversion Technology", Chemical Engineering, pp 88-102 (July 22, 1974).
-------
5-45
5.3.7. Bituminous Coal Research
On April 4, 1974, OCR announced that a 50-month contract had been
awarded to BCR to develop a multiple fluidized-bed gasification process to
produce low-Btu and intermediate-Btu fuel gases from coal.
-------
TABLE 5.3.7. BITUMINOUS COAL RESEARCH
Factlty
Bench-scale
Location
Monroeville, PC.
Owner(a)
Bituminous Coal
Research (funded
by OCR)
Status/Operating History
A §2,575,000, 50-month contract was awarded in April 1974.
This will cover'bench-scale and process development unit work that
will be the basis for design of a pilot plant.
Some laboratory investigations have already been carried out
in a small fluidized-bed batch reactor to verify proposed rate
equations, to determine the degree of steam or C02 decomposi-
tion that could be achieved in a reactor of reasonable size,
and to provide physical data such as minimum fluidizing
velocity, etc.
Ul
i
-P-
CT>
References:
(1) Department of t
(2) Annual Report 1
te Interior News Release
J73-74, Office of Co4l
, April 4, 1974.
Research, U.S. Depi
. of Interior, Washington, D.C. (1974).
-------
5-47
5.4 Fluid Bed/Agglomerating Ash
Selective, continuous removal of ash from a fluidized bed rich in
carbon can be a difficult problem. One solution is to permit ash particles
to reach temperatures at which agglomeration occurs. When they become
sufficiently heavy, ash agglomerates separate from the bed and can be removed.
The Union-Carbide-Battelle process to be described in this
section also makes use of ash agglomerates to supply heat to the gasifier
and by so doing eliminates the need for a costly oxygen plant when intermediate-
Btu gas is to be produced.
-------
5-48
5.4.1 U-Gas (Institute of Gas Technology)
Description of the process. Caking coals are pretreated with
air at 800 F and 350 psia to render them noncaking (Figure 5.4.1), Treated
coal overflows into the fluidized-bed gasifier where it reacts with air
and steam at about 1900 F. Part of the fluidizing gas enters through a
grid which is sloped toward one or more cones contained in the grid. The
rest flows upward at high velocity through the throat at the cone apex
creating a submerged jet within the cone. The temperatures generated
within the jet are somewhat higher than in the rest of the bed. As carbon
is gasified in and near the jet, ash is heated to its, softening point,
the sticky ash surfaces cling to one another, and ash agglomerates grow
in the violently agitated jet. When they become heavy enough, the agglo-
merates fall counter to the high-velocity gas and are separated from the
bed.
Gas above the bed is at a temperature of between 1500 and 1900 F
and the residence time is sufficient to allow for thermal cracking of
tars and oils. Most of the dust in the raw gas is removed by internal
cyclone separators and returned to the fluidized bed. After separation
of fine dust in external cyclones, the gas is at 1550 F. IGT is developing
a high temperature Meissner (800 F) process for desulfurization of this gas.
Gasification with air and steam produces a gas with a heating
value of about 150 Btu/scf. When oxygen is used for gasification the
heating value is about 300 Btu/scf.
The process can accept all ranks of coal and lignite.
-------
5-49
COAL FEED
FRETREATHENT
(IF NECESSARY)
RAM GAS TO
TREATING
EITHER HIGH-
OR LOW-
TEMPERATURE
OPERATION
2nd STAGE
DUST REMOVAL
AIR
AIR AND STEAM
SOLIDS FEEDER
AIR AND
STEAM
ASM REMOVAL
FIGURE 5.4.1. GASIFIER TO BE USED IN IGT'S U-GAS SYSTEM(l)
-------
TABLE 3.4.1 U-GAS: STATE OF THE ART
Facilty
Location
Owner(a)
OT Contractor
Status/Operating History
10 ton/hr Pilot
n.a.
IGT
Design stage. Seeking funding.
Presently, studies are being made with a 4 ft diameter agglomera-
tlng-ash gaslfler. In operation since June
(Contact: John W. Loading, IGT, Chicago, (312) 225-9600, Ext. 841)
References;
(1) Loading, John W., and Tsaros, Constantine, L., "IGT U-Gia Process", Institute of Gas Technology Symposium
on Clean Fuels from Coal, pp 241-273, Chicago (1973).
(2) "Evaluation of Coal-Gaslflcatlon Technology, Part II, Low-nnd Intermedlate-Btu-.Fual Gases", National Research
Council, National Academy of Engineering, Washington, O.C. (1973).
(3) Perry, Harry, "Coal Conversion Technology", Chemical Engineering, pp 88-102,(July 22, 1974).
Ui
i
01
o
-------
5-51
5.4.2. Westinghouse
Description of the Process. This process, which is in the
design stage, is intended to operate in conjunction with a combined cycle
power plant. The gasification process is shown schematically in Figure
5.4.2. Crushed coal is dried in a fluidized bed and transported to the
devolatilizer-desulfurizer unit. Here devolatization, desulfurization,
and hydro-gasification are combined in a single,recirculating fluidized-
bed reactor operating at 1300 to 1700 F and 20 to 30 atmospheres.
Dried coal fed into a central draft tube of this reactor is
diluted with large quantities of recycled solids--char and lime sorbent.
These solids, flowing at rates up to 100 times the coal feed rate, prevent
or control the agglomeration of the coal feed as it devolatilizes.
A dense dry char is collected in the fluidized bed at the top
of the draft tube. Lime is added to this bed to remove sulfur. Spent
sorbent is withdrawn from the reactor after stripping out the char. The
final gasification of the low-sulfur char is conducted in a fluidized
bed with a lower leg which serves as a combustor. In this section, char
from the devolatilizer-desulfurizer is burned with air at about 2100 F
to provide the gasification heat. Ash agglomerates fall to the lower bed
leg are removed.
In the upper section of the bed gasification occurs at 1800-
2000 F. After removing particulates with cyclone separators, the clean
fuel gas passes to the gas turbine plant.
-------
5-52
Clean Fuel Gas
Lime
Sorbent -^
CaO
oal
i
H
-
.
i
*.
_•
*
j
J
I
— —
ri
; I
C/iar
" — — .
C npnl
Cnrhant PaC
jUl UClll vu J
to Gas Turbine
I
_ i
LJ
•vif^-'- Total Gasifier
' .*• * • .".
"~~~* ''•".•.•'.."""'"
/V - V
1 f Agglomerating
/: Combustor
i"".
4':
k^ Ai r
y Steam
i
J
Hot Fuel Gas
Recirculating Bed
Devolati lizer/Desulf urizer
Ash
Crushed_
Coal
Hot
Gases
Coal Dryer
FIGURE 5.4.2. WESTINGHOUSE MULTISTAGE FLUIDIZED BED GASIFICATION PROCESS
-------
TABLE 5.4.2 WESTINGHOUSE: STATE OF THE ART
Facllty
Location
Owner(s)
or Contractor
Status/Operating History
'1200 Ib/hr process
development unit
Waltz Mill,
Pennsylvania
Westinghouse
(supported by. OCR
Public Service
Indiana, AMAX Coa
Company, Bechtel
Cor"., and
Peabody Coal Co.)
Unit, which cost $5.5 x 106 for design and construction, Is now
mechanically complete and In the pre-commlsslon stage. Expect
first hot tests In January 1975. Unit Includes gaslfler and
devolatizer/desulfurlzer. Test program will establish inherent
operating characteristics of the gasification system and pro-
vide data for design of larger units.
If significant success Is achieved with this unit, a decision
could be made to ge directly to design of a full-size gen-
erating pilot plant gasifier to be used with a combined-cycle
plant of about 120 MW. This Is expected to be located at
Dresser Station, Terre Haute, Indiana.(1)
(Contact: John Holmgren, Westinghouse, Waltz Mill, Pennsylvania, (412) 722-5552).
References
(1)
(2)
(3)
rgy",
"Coal Technology: Key to Clean Energy", Annual Report 1973-74, Office of Coal Research, Washington, D.C. (1974).
Archer, D.H., Vidt, E.J., Kealrns, D.L., Morris, J.P., and Chen, J.L.,"Coal Gasification for Clean Power
Production", Institute of Gas Technology Symposium on Clean Fuels from Coal, op 447-484, Chicago, (1973).
Evaluation of Coal Gas Technology, Part II, Low-and Intermediate-Btu Fuel Gases, National Research Council,
National Academy of Engineering.
Archer D. H Kearns, D. L., and/Vidt, E. J., "Development of a Fluidlzed-Bed Coal Gasification Process for Electric
Power Generation . presented at the 4th Synthetic Fuels from Coal Conference. Oklahoma State University. Stillwater,
Oklahoma (May,6-7, 1974).
Ln
i
-------
5-54
5.4.3 Ash Agglomeration (Union Carblde/Battelle)
Description of Process. A simplified flow sheet for this process
is shown in Figure 5.4.3. Crushed, dried coal is charged to the tapered
transition zone of the gasifier which operates at 1800 F and 100 psi. Super-
heated steam enters below the fluidized-bed distribution plate. Hot ash
agglomerates, flowing countercurrently, provide heat to support the
gasification reactions.
Coal is converted to gas and char as it moves upward through the
gasifier. Char separated from the raw exit gas is sent to the burner where
it is combusted with air to reheat ash agglomerates. Ash-free flue gas
from the burner passes through a heat recovery system and is expanded in a
gas turbine to generate process power.
Ash agglomerates, stripped of carbon by the upward flow of steam
in the gasifier, leave the bottom of the gasifier and are recycled to the
burner.
The raw product gas is cleaned by cyclones and Venturi scrubber
systems.
Because the coal fed to the gasifier is greatly diluted by a
large quantity of circulating ash, the process is expected to accept caking
coals without pretreatment. Also, the generation of hot ash agglomerates
in a vessel separate from the gasifiers permits production of an intermediate-
Btu gas without the usual requirement of an oxygen plant.
-------
5-55
GASIFICATION
REACTOR
COAL-
STEAM
RAW PRODUCT GAS
FLUE GAS
RECYCLE
RESIDUE
COAL OR
CHAR
BURNER
1
STEAM
STEAM
GENERA-
TOR
J
GAS
PURIFICATION
RECYCLE BURDEN
ASH
RESIDUE
CARBON DIOXIDE
•AND OTHER ACIDIC
IMPURITIES
•STEAM
COMBUSTION
AIR
COMPRESSED
PRODUCT GAS
FIGURE 5.4.3. UNION CARBIDES' AGGLOMERATED ASH PROCESS
(3)
-------
TABLE 5.A.3. ASH AGGLOMERATION
Faciley
Location
Owner(•)
or Contractor
Status/Operating History
1200 Ib/hr process
development unit
West Jefferson, 0
Battelie (Funded by
OCR and AGA)
(Patent for the
process Is held by
Union Carbide.)
Under construction. Estimate completion in first quarter of
197S. Unit will not Include a gas purification system.
Earlier studies included bench-scale studies of both the coal
burner and the gasifier. Erosion by fly ash from the burner
at simulated turbine conditions was also investigated.
Cn
ON
(Contact; W. M. Goldberger, Battelle Columbus Labs., (614) 299-3151)
References:
(1) Corder, W. C., Batchelder, H. R., and W. M. Goldberger, "The Union Carbide/Battelle Coal Gasification Process
Development Unit Design", Presented at the Fifth Synthetic Pipeline Gas Symposium, Chicago (Oct. 1973).
(2) "Evaluation of Coal-Gasification Technology, Part II, Low- and Intermediate- Btu Fuel Gas", Report by National Research
Council, National Academy of Engineering.
(3) Goodridge, E., "Status Report: The AGA/OCR Coal Gasification Program", Coal Age 78, 54-59 (January 1973).
-------
5-57
5.5 Entraimnent Reactors
In entrainment or suspended bed reactors, pulverized coal is
carried along with the gas. The major advantage of this type of system is
the ability to accept all types of coal. Particles undergo only occasional
collisions and, therefore, caking tendencies are of no consequence. Carbon
carry-over is usually high and separation of ash solids from gases is a
problem. With cocurrent flow, the temperature of the exist gas is high
and a heat recovery system is required if good thermal efficiency is to be
achieved. Overall energy production rates per unit volume of space in
entrained gasifiers are much greater than those for moving-bed and fluid-
bed gasifiers because of high reaction rates resulting from the large surface
areas of the fuel particles.
-------
5-58
5.5-1 Bigas (Bituminous Coal Research Inc.)
Description of the Process. A flow diagram for the Bigas process
is shown in Figure 5.5.1. Piston feeders charge dried pulverized coal
and steam into the two-stage gasifier near the bottom of stage II (upper
section) where it mixes with hot gas rising from stage I and is devolatilized
and partially gasified. Residual char entrained in the raw product gas
leaving the top of the gasifier is separated by cyclones and recycled to
Stage I where it is gasified with steam and oxygen under slagging conditions
(2700-2800 F). Raw gas from the cyclones passes through a water quench
system and a desulfurization unit.
If oxygen and steam are used for gasification, the product gas
has a heating value of 380 Btu/SCF, with air and steam the heating value of
the gas is 210 Btu/SCF.
H2s
COAL
PREPARATION
STI
1
:AN
AIR/ OXYGEN •" *
STEAM j
RAW -^-
1 GAS
UPPER
REACTOR
1700 r
1000-1500
PSIG
GASIFIER
2700 F
1000-1500
PSIG
~\-
QUENCH «
f^**-b ur«T i PIIRTPTPATTDN
1 RECOVERY
/ PRODUCT GAS
RECYCLE
CHAR
ASH-SLAG
FIGURE 5.5.1. BIGAS PROCESS
(3)
-------
TABLE 5.5.1. BIGAS: STATE OF THE ART
Facllty
Location
Owner(s)
or Contractor
Status/Operating History
5 ton/hr pilot
Homer City, Pa.
(Contact: Robe
Bituminous Coal
Research (with
support from OCR
and AGA) (Stearns
Roger Corp. is
responsible for
construction)
rt Grace, Bituminous
Under construction. Estimate completion in early 1975.
Estimated cost is about $25 x IQo. This will be a fully
integrated plant. Lab- and process development-scale
(6000 SCF/hr) studies of methanation are being carried out to
determine optimum operations conditions for the pilot plant.
Acid gas removal by Selexol process.
Coal Research, Pittsburgh, Pa., (412) 327-1600)
References:
(1) Hottel, H. C. a
(2) "Evaluation of
National Academ
(3) Grace, Robert J
pp 179-198, Chi
(4) "Clean Energy f
(5) "Coal Technolog
id Howard, J. B., Nev
oal Gasification Technology
' of Sciences, Washit
, "Development of tl
ago (1973).
om Coal - A National
: Key to Clean Enei
Energy Technology;
Part II, L
gton, D.C. (1973).
e Bigas Process", In:
Priority", 1973 Ann
gy", Annual Report 1'
Some Facts and Assessments. MIT Press, Cambridge, Mass (1971).
>w- and Intermediate-Btu Fuel Gases; National Research.Council,
titute of Gas Technology Symposium on Clean Fuels from Coal,
al Report, Office of Coal Research, Washington, D.C. (1973).
73-74, Office of Coal Research, Washington, D.C. (1974).
Ui
i
Ui
VO
-------
5-60
5.5.2 Combustion Engineering Inc.
Description of Process. Combustion Engineering has undertaken
a four-phase program for the development of a process for conversion of
coal to a clean fuel gas for electric power generation. An entrainment-type
gasifier operating at atmospheric pressure will generate low-Btu gas for
use in either a conventional steam or combined-cycle power plant.
The combustion and reducing chambers of the gasifier are enclosed
by water-cooled walls that are studded and refractory-covered. Coal and
recycled char are burned in the lower combustion section of the gasifier,
and essentially all of the ash is converted to molten slag.
Steam and pulverized coal are injected into the upper (reducing)
section of the gasifier where they encounter the hot gases leaving the
combustion zone. Coal is devolatilized and is gasified by reaction with
steam. The gas is cooled, mechanically cleaned and scrubbed to remove
particulates prior to removal of H.S by the Stretford gas/liquid contact
process.
If the gasifier is air-blown, the product gas is expected to
have a heating value of about 130 Btu/SCF. if it is oxygen blown, the
heating value will be about 285 Btu/SCF.
-------
TABU 5.5.2. COMBUSTION ENGINEERING INC.
Facllty
5 ton/hr process
development unit
Location
N.A.
Owner(s)
or Contractor
Combustion Engineer-
Ing Inc. (cospon-
sored by OCR and
Consolidated Edisor
of New York)
(Contact: John Andsrson, Combustion En
Status/Operating History
Presently negotiating contract for construction of facility.
Very little information available.
;lneering Inc., Windsor, Conn. (203) 688-1911)
Ui
References:
(1) "Clean Energy f
Washington, D.C
(2) "Coal Technolog>
otn Coal - A National
(1973).
Key to Clean Energy
Priority", 1973
", Annual Report
Annual Report (Calendar Year 1972), Office of Coal Research,
19)73-74, Office of Coal Research, Washington, D.C. (1974).
-------
5-62
5.5.3 Foster-Wheeler (Foster-Wheeler Corporation)
Description of Process. Foster-Wheeler Corporation is designing
an air-blown, entrained-flow gasifier for the production of clean, low-Btu
gas as a fuel for conventional steam and combined-cycle power plants. A
schematic is shown in Figure 5.5.3.
Dry, pulverized coal is fed into the second (upper) stage of the
two-stage gasifier where it is entrained by hot gases from the first stage
and devolatilzed at 1800-2100 F and 350 psig. The fixed-carbon in the coal
is converted to a low density char which is separated from the gas stream
by a series of cyclones and fed to the lower stage of the gasifier which
is operated at slagging temperatures (2500-2800 F).
The nozzles through which char, air,and steam are fed into this
stage are arranged so that slag is thrown out against the walls. The slag
runs down the walls through a collector at the bottom and is quenched in a
water bath.
It is expected that char will be essentially completely gasified
in the lower stage.
The hot (1800 F) gas leaving the upper stage is cooled and then
scrubbed to remove particulates and ammonia. Desulfurization is carried
out in a closed-cycle wet-scrubbing system.
The clean, low-Btu gas is expected to have a heating value of
165 Btu/SCF.
-------
COAL
PULVERIZATION
RAW GAS
COAL
FEED
STAGE II
COMPRESSED
AIR
LIMESTONE
X
GASIFIER
STAGE I
CHAR FEED
LOW BTU GAS
CHAR SEPARATION
AND COOLING
EXISTING BOILERS
AND STEAM TURBINES
GAS COOLING
(HEAT EXCHANGER)
GAS SCRUBBER
(PARTICULATE
AND AMMONIA)
SOUR WATER
STRIPPING
AND SLUDGE
REMOVAL
WASTE
WASTE HEAT
BOILER
SLAG
ELECTRIC
GENERATOR
SULFUR
REMOVAL
(SELEXOL)
SULFUR
RECOVERY
(CLAUS)
SULFUR
FUEL GAS
FIGURE 5.5.3. FOSTER WHEELER
(3)
-------
TABLE 5.5.3. FOSTER-WHEELER
Faellty
Location
Owner(s)
or Contractor
Status/Operating History
5 ton/hr Pilot
South Dakota
Foster Wheeler
(cosponsored and
cofunded by OCR,
Pittsburgh &
Midway Coal Mining
Co., Turbodyne and
Northern States
Power Co.)
Process design is completed. Construction is expected to begin
in last quarter of 1974 and should be in operation by early
1977. Based on bench-scale studies with a 100 Ib/hr unit.
In phase I, low-Btu gas will go to modified existing boilers
to generate power. In phase II, estimated to begin in early
1978, the gas will fuel a combined-cycle plant to generate
about 130 MW of power.
Ul
i
(Contact: E. Danon, Foster-Wheeler C
>rp., Livingston, New Jersey (201) 533-3653)
References:
(1) Clean Energy from Coal: A National Priority, 1973 Annual Report, Office of Coal Research, pp 40-41, Washington, D.C.
(1973).
(2) "Evaluation of Coal-Gasification Technology, Part II, Low- and Intermediate-Btu Fuel Gases", National Research
Council, National Academy of Engineers, Washington D.C. (1973). (Process is listed under Pittsburgh and Midway Coal
Company - the former project manager.)
(3) McCallister, R. A., and Ashley, G. C., "Coal Gasification to Produce a Low-Btu Fuel for a Combined-Cycle Power Station",
Presented at American Power Conference, Chicago (April 29, 1974).
-------
5-65
5.5.4 Garrett Flash Pyrolysis (Garrett Research and Development CO.)
Description of Process. Pulverized coal is fed to the gasifier
which operates at about 50 psi (Figure 5.5.4). The coal is rapidly heated
to 1500 to 1700 F by hot recycle char in entrained flow. Because of the
short residence time in the pyrolysis zone (two seconds or less), gas-
phase cracking reactions are minimized with a resultant high direct yield
of hydrocarbons. At 1600 F, typical gas composition is reported to be as
follows: H2, 35.3; CO, 22.4; C02> 9.1; CH4> 18.8; C2+ (Predominantly
ethene), 14.1 (Vol. %; nitrogen-free basis).
Char is separated from the gas leaving the pyrolysis reactor by
a series of cyclones and sent to the char heater. A portion of the char is
partially burned with air, and after separation from combustion gas, is
recirculated to the pyrolysis reactor to provide process heat. This latter
feature makes it possible to produce nitrogen-free gas of about 600 to 650
Btu/SCF without using pure oxygen.
In addition to the product gas, the Garrett process also produces
high yields of char and tar. (At 1600 F the relative yields (by weight)
of gas, char, and tar are about 30, 56, and 14, respectively (1).)
-------
5-66
I
COMBUSTION
GAS
\/eYCLONES
AIR
COAL
FEED
CHAR
BURNER
ENTRAINED FLOW
REACTOR
PYROLYSIS GAS
PRODUCT
GAS
GAS
PROCESSING
CYCLONES
CHAR
PRODUCT
FIGURE 5.5.4. GARRETT FLASH PYROLYSIS PROCESS
(4)
-------
TABLE 5.S.4. GARRET FLASH PYROLYSIS
Facllty
Location
Owner(a)
or Contractor
Statua/Operating History
10 ton/hr Pilot
LaVerne, Ca.
Garret Research and
Development
(research subsidiary
of Occidental
Petroleum)
Proposed. Seeking support. A bench scale pyrolysis unit
(50 Ib/hr) has been in operation since Jan. 1973 (2).
1/1
o\
(Contact: D. E. jdams, Garrett Research and Development, La Verne, Ca., (714) 593-7421)
References:
(1) McMath, H. G.,
Atmkin, R. E., and S
Process", Presented at the 66th Ann
iss, A., "Production
>£ Gas from Western Sub-Bituminous Coals by the Garret Flash
Meeting AICHE Philadelphia, Pa. (November 1973).
(2) McMath, H. G., Lumkin, R. E., Longanbach, J. R., and Sass, A., "A Pyrolysis Reactor for Coal Gasification", Chemical
Engineering Progress, Vol. 70, No. 6, pp 72-3 (June 1974).
(3) Adams, D. E., Sack S., and Sass, A., "Coal Gasification by Pyrolysis", ibid pp 74-75.
(4) Adams, D. E., Sack S., and Sass, A., "The Garret Pyrolyais Process", presented at the 66th Annual Meeting AICHE,
Philadelphia, Pa. (November 15, 1973).
-------
5-68
5.6 Entrainment/Slagging Reactors
Operating temperatures are high enough to produce slagging con-
ditions. A large fraction of the ash (more than 50 percent in the Koppers-
Totzek process) flows down the gasifier walls as molten slag into a slag
quench tank; the remainder of the ash leaves the gasifier as fine fly ash
entrained in the exit gas. The higher temperatures lead to higher specific
gasification rates.
5.6.1 Koppers-Totzek (Koppers Engineering and Construction)
Description of Process. The Koppers-Totzek gasifier, shown
schematically in Figure 5.6.1, is an oxygen-blown, entrained-flow system
which has been used extensively for production of hydrogen in the synthesis
of ammonia.
Dried, pulverized coal is screw-fed into pairs of opposing burners
arranged so that their jet discharges converge. Gasifiers may employ either
two or four such burner heads.
Reaction temperatures at the burner discharge are in the range
3300 to 3500 F, while the exit gas temperature is at about 2750 F. Under these
conditions only gaseous products are generated (no tars, condensable hydro-
carbons, or phenols).
Approximately half of the coal ash drops out as slag into a slag
quench tank below the gasifier while the other half leaves as fly ash
with the product gas. When necessary, molten ash particles can be
solidified by water sprays to prevent buildup in tubes of the waste-
heat boiler. After further cooling, the gas is purified by conventional
methods.
A major advantage of this process is the wide variety of acceptable
feedstocks (all ranks of coal, char, petroleum coke, tars, heavy residuals,
light to heavy oils and pumpable slurries of carbonaceous materials in hydro-
carbon liquids).
The present generation gasifiers operate at atmospheric pressure
but units capable of operating at pressures up to about 15 atms are presently
under development.
-------
5-69
WASTE HEAT.
BOILER
FEED WATER —
HIGH-PRESSURE
STEAM
l—GAS OUTLET
FEED
COAL WATER
SCREW
FEEDER
WATER—
COAL
LOW-PRESSURE
STEAM
FIGURE 5.6.1. KOPPERS-TOTZEK GASIFIER
(3)
-------
TABLE 5.6.1. KOPPERS-TOTZEK: STATE OP THE ART
Facllty
Location
Owner(•)
or Contractor
Status/Operating History
10.4 x 10° SCF/day
7.8 x 106 SCF/day
15.5 x 106 SCF/day
6.55 x 10° SCF/day
6.3 x 106 SCF/day
38.6 x 106 SCF/day
8.07 x 106 SCF/day
28.85 x 106 SCF/day
13.4 x 10 SCF/day
7.98 x 10 SCF/day
74.45 x 106 SCF/day
it
it
60 x 10° SCF/day
Oulu, Finland
Tokyo, Japan
Puentei de Garcia
Rodriguez, Spain
Zandvoorde, Belgium
EsCarreja, Portugal
Ptolemais, Greece
Lampang, Thailand
Kutahya, Turkey
East Germany
Zambia, Africa
Ramagundam, India
Talcher, India
Korba, India
Modderfontein,
South Africa
Typpi Oy
Nihon Suiso Kogyo
Kalaha, Ltd.
Empreaa Nactonal
"Calvo Sotelo" de
Combustibles
Liquidos y
Lubricantes
S.A. Union Chimlque
Beige
Amoniaco Fortugues
S.A.R.L.
Government of Greece
Chemical Fertilizer
Co., Ltd.
Azot Sanayii T.A.S.
VEB Germania,
Chemieanlagen und
Apparatebau
Industrial Develop-1
tnent Corp., Zambia
Fertilizer Corp. of
AE & CI Ltd.
5 gasifiera (3 ordered in 1950; 2 ordered in 1955)
Produce synthesis gas from coal dust, oil and peat.
3 gasifiera produce synthesis gas from coal dust (ordered in
1954)
4 gasifiera (3 ordered in 1954; 1 ordered in 1961) produce
synthesis gas from lignite dust and/or Naptha.
2 gasifiers produce synthesis gas from bunker-C-oll, convertible
to coal dust (ordered in 1955).
2 gasifiers produce synthesis gas from heavy gasoline but
convertible to coal dust (ordered in 1956).
6 gasifiera (4 in 1959; 1 in 1969; 1 in 1970) produce synthesis
gas from lignite dust and bunker-C oil.
1 gasifier produces synthesis gas from lignite dust (ordered
in 1963).
4 gasifiers produce synthesis gas from lignite dust (ordered
in 1966).
2 gasifiers produce gas for hydrogenation from vacuum residue and/
or fuel oil (ordered in 1966).
1 gasifier produces synthesis gas from coal dust (ordered in 1967).
3 gasifiers produce synthesis gas from coal dust (ordered in 1969).
As above (ordered in 1970).
As above (ordered in 1972).
6 gasifiers produce synthesis gas from coaldust (ordered in 1972).
Ui
^j
o
(Contact: J. F. Farnsworth, Koppers Engineering and Construction, Pittsburgh, Pa., (412) 391-3300)
-------
TABLE 5.6.1. (Continued)
References:
(1) "Evaluation of Coal-Gasification Technology, Part II, Low- and Intennedlate-Btu Fuel Gases", National Research Council
and National Academy of Engineering, Washington, D.C. (1973).
(2) Farnsworth, J- F-» Leonard, H. F., Mltsak, D. M., and Wlntrell, R., "Production of Gas from Coal by the Koppers-
Totzek Process", Symposium on Clean Fuels from Coal, pp 143-162, Institute for Gas Technology, Chicago (1973).
(3) Indian Government Sponsored Study of Commercial Coal Gasification Processes, V. N. Kasturlranzan, M. Satyapal, R. R. Iyer,
0. G. Rao and S. B. Chatterjl, reproduced by Koppers Engineering and Construction Company, Pittsburgh (1973).
(4) Magee, E. M., Jahnig, C. E., and Shaw, H., "Evaluation of Pollution Control In Fossil Fuel Conversion Processes,
Section 1: Koppers-Totzek", Prepared for Office of Research and Development, USEPA, Washington, D.C. (January 1974).
Ln
i
-------
5-72
5.6.2. Texaco
Description of Process. A simplified schematic of the Texaco
gasifier is shown in Figure 5.6.2. Coal is fed to the gasifier as a
slurry. The coal-water slurry is pumped through a preheater in which the
water is vaporized and the mixture heated to about 1000 F. The steam-coal
mixture is then blown into the top of the gasifier, and preheated oxygen
is fed through a separate water-cooled nozzle. The steam-coal ratio is
controlled by a cyclone separator ahead of the gasifier. Temperatures in
the reaction zone range from 2000-2500 F and the operating pressure is
400 psi.
Slag is withdrawn from the bottom of the unit and quenched with
water. Heat from the gas leaving the reactor is recovered by a waste
heat boiler.
The gasifier can be blown with either oxygen or air.
COAL WATER
Mt+C0
OXYGEN
ASH a WATER
FIGURE 5.6.2. SIMPLIFIED FLOW DIAGRAM OF THE TEXACO
GASIFIER
(1)
-------
TABLE 5.6.2. TEXACO: STATE OF THE ART
Facilty
Location
(Contact: Peter L.
Owner(s)
or Contractor
Paul, President, Texa
Status/Operating History
At the present time, Texaco has no commercial units in
operation that use coal as a feedstock. However, Texaco
has previous pilot experience in coal gasification operations
(Morgantown, W.Va.) and a semi-commercial unit was in
operation for a number of years that produced synthesis
gas from coal.
i
•^i
OJ
co Development Corp., New York, N.Y. (212) 953-6734
References;
(1) Von Fredersdorff, C. G., Elliot, M. A., "Coal Gasification" in Chemistry of Coal Utilization. H. H. Lowery, Editor,
Supplementary Volume, John Wiley and Sons, Inc., N.Y., pp 982-3 (1963).
(2) Bituminous Coal Research, Inc., "Gas Generator Research and Development Survey and Evaluation - Phase One", R&D Report
No. 1., U.S. Dept. of Interior, O.C.R., Washington (1965).
-------
5-74
5.6.3 Babcock & Wilcox
Description of the Process. A schematic of the commercial-scale
unitjwhich was installed at the Belle, West Virginia plant of the du Pont
Company^is shown in Figure 5.6.3. The refractory-lined gasifier was
cylindrical with a primary and a secondary reaction zone. Pulverized
coal was swept into burners in the primary zone with steam and oxygen.
The lower or primary zone operated at slagging temperatures and molten slag
was continuously tapped from the bottom of the gasifier. The secondary zone
operated at lower temperatures. A waste-heat boiler recovered heat from
the hot (about 2000 F) exit gas.
This process accepts all types of coal. It produces a gas which
is primarily carbon monoxide and hydrogen (in nearly equal yields). The
methane yield is less than one percent.
-------
5-75
SYNTHESIS
GAS
OXYGEN, STEAM &
PULVERIZED COAL
PRIMARY CHAMBER
— HEAT RECOVERY
SECONDARY
" CHAMBER
OXYGEN, STEAM &
PULVERIZED COAL
BURNERS
FIGURE 5.6.3. BABCOCK AND ^ILCOX - DU PONT GASIFIER
(1)
-------
TABLE 5.6.3. BABCOCK & WILCOX: STATE OF THE ART
Facilcy
Location
Owner(s)
or Contractor
Status/Operating History
500 Ib/hr process
development unit
3,000 Ib/hr Pilot
17 TFH Commercial
Plant for Produc-
tion of Synthesis
Gas
Morgantown, W.Va.
Belle, W.Va.
Belle, W.Va.
Designed and con-
structed by B&W at
U.S. Bureau of
Mines in Morgantown
Installed by duPont
Began operating in Summer of 1951. Operational data have been
Jegan operatln;
published.<2>
Began operation in fall of 1951. Provided performance data for
design of commercial unit. Operational data have been
published.(2)
Plant was operated for 1 year. Operational data has not been
published. Plant has been dismantled.
(Contact: Sidney
iatell, U.S. Bureau o
: Mines, Morgantown, W.Va (304) 599-7000)
References:
(1) VonFredersdorff,
Supplementary VojLume
(2) Grossman, P. R.
ASME Transactioni
S. C. and Elliot, M
, John Wiley and
md Curtis, R. W., "
, 26, 689-95 (1954)
A., "Coal Gaaificat
Sons, Inc., New York
'ulverized-Coal-Fired
.on", in Chemistry of Coal Utilization, H.H. Lowry (Editor),
p 974 (1963).
Gasifier for Production of Carbon Monoxide and Hydrogen",
-------
5-77
5.7 Molten Bath
Gasification of coal has also been carried out in baths of molten
iron and molten salts. An important consideration common to such systems
is the ability to accept all types of coal. Also, a significant fraction
of the sulfur may be removed in the bath. Unfortunately, such processes
usually involve formidable materials problems.
5.7.1 Molten Iron (Applied Technology Corp.)
Description of Process. There are three variations of the basic
process: The Two-stage Coal Combustion Process which produces a 190 Btu/
SCF fuel gas, the PATGAS Process which produces a 315 Btu/SCF gas, and the
ATGAS Process which produces SNG (the Atgas Process is described in
Section 6.10).
In the Two-stage process coal and limestone are injected with
compressed air into a molten iron bath at 2500 F (Figure 5.7.1). Fixed
carbon and sulfur dissolve and are retained by the iron, while the coal
volatiles crack and appear as offgas. Dissolved carbon is gasified by
reaction with additional air which is injected slightly below the surface
of the molten iron to yield carbon monoxide.
To prevent build-up of sulfur in the molten iron, dissolved
sulfur is continuously transferred to a molten, lime-bearing slag floating
on the surface of the iron. The slag, containing 4 to 8 percent sulfur
as calcium sulfide, and all of the coal ash, is continously removed and
desulfurized. The raw gas (30 percent CO, 15 percent H2> 55 percent N2)
can be used as a low-Btu (190 Btu/SCF) fuel gas.
In the PATGAS Process steam is used as the carrier for coal and
limestone,and oxygen (rather than air) is injected into the molten bath.
In this case the offgas is 63.5 percent CO, 36 percent HZ and 0.5 percent
N_, and has a heating value of 315 Btu/SCF.
-------
5-78
co2
t
PURIFICATION
LOW- OR INTERMEDIATE-BTU GAS
OESULfURIZEO SLAS
1 I
ASH SULFUR
FIGURE 5.7.1. MOLTEN IRON PROCESS
(1)
-------
TABU 5.7.1. MOLTEN IRONS STATE OF THE ART
Facllty
Location
Owner(s)
or Contractor
Status/Operating History
Applied Technology
Corp.
Pre-pilot stage. Studies have involved a 25 inch I.D. induction
furnace (4000 Ib capacity) to simulate the gasifier, and use of
air to produce low-Btu fuel gas. The off gas handling system
was equipped to permit continuous analysis for S02, N02, NO,
H2. °2« C02 and co- Expendable, non-cooled ceramic lances were
used for injection. Results indicate a boiler feed gas with
less than 50 ppm SC>2 can be generated from high-S coal
(3.5 percent)(1)
(Contact: Ronald
J. McGarvey, Appliec
Technology Corp., Pittsburgh, Fa (412) 782-0682)
Cn
References:
(1) LaRosa, Paul am
Symposium on Cl
(2) "Evaluation of <
National Academ
(3) "Clean Energy f
Washington, D.C
McGarvey, Ronald J.
an Fuels, pp 285-300
oal Gasification
of Engineers, Washi
om Coal: A National
(1973).
, "Fuel Gas from
0, Chicago (1973).
Technology, Part II, Lov
ngton, D.C. (1973).
Priority", 1973
Moltjen Iron Coal Gasification", Institute of Gas Technology
-and Intermediate-Btu Fuel Gases, National Research Council,
Anmjal Report (for Calendar Year 1972) Office of Coal Research,
-------
5-80
5.7.2 Kellogg Molten Salt (M. W. Kellogg Company)
Description of Process. When intermediate Btu-gas is to be
produced, crushed, dried coal and sodium carbonate from lock hoppers are
carried into the molten-salt gasifier by preheated oxygen and steam.
(Figure 5.7.2). The gasifier operates at 1700 F and about 1200 psi;
however, lower pressure can be used if high yields of methane are not
required.
Under these conditions the major gasification reactions are coal
with steam, which is catalyzed by sodium carbonate, partial-combustion of
coal and non-catalytic methanation.
A bleed stream of molten salt containing ash is withdrawn from
the bottom of the gasifier and quenched with water. Sodium carbonate is
dissolved and the ash is separated by filtration. The filtrate is carbonated
with carbon dioxide from the purification system to precipitate sodium
bicarbonate. The bicarbonate is filtered off and heated to regenerate the
carbonate salt for recycle to the gasifier.
After the raw gas is processed to recover heat and entrained
salt, carbon dioxide and the remaining sulfur are removed by the Selexol
process. (A significant fraction of the sulfur is removed by reaction with
molten carbonate in the gasifier.)
Gasification can also be carried out with steam and air to produce
a low-Btu fuel gas. In this case, the gasifier can be operated at much
lower pressures.
-------
5-81
COAL—*
HEAT RECOVERY
AND REMOVAL
OF ENTRAINED
SALT
t
PURIFICATION
PREHEATED
STEAM AND
OXYGEN
MELT PURGE
FIGURE 5.7.2. KELLOGG MOLTEN-SALT PROCESS
(2)
-------
TABLE 5.7.2. KELLOGG MOLTEN SALT: STATE OP THE ART
Facllty
Location
Owner(a)
or Contractor
Status/Operating History
M.W. Kellogg Company
Bench acale studies only. The molten salt creates serious corro-
sion problem, but these have been solved by use of an aluminum
oxide refractory, Monofrax A. Report no corrosion after
600-700 hrs continuous operation.
A process development unit is planned. Preliminary flow sheets
and cost estimates have been made* Seeking support.
Gasification of coal In molten K2C03 to produce a fuel
suitable for magnetohydrodynamic systems is also being
studied by Kellogg with support from OCR (4).
(Contact: A. E. Cover, M. W. Kellogg Company, Houston, Texas, (713) 626-5600).
Ul
co
References:
(1) Cover, A. E. am
from Coal, Oklat
(2) Cover, A. E., S«
Institute of Gas
(3) Evaluation of Cc
Council, Nation*
Schrelner, W. C., "Che Kellog Molten Salt Process", Presented at the 4th Conference on Synthetic Fuels
" Stlllwater, Oklahonja (1974).
oma State University
hreiner, W. C., and
Technology Symposiujn on Clean Fuels fronl Coal, ~p"p 273-284, Chicago (1973).
al-Gasification Techiology, Part II, Low-] and Intermediate-Btu Fuel Gases, National Research
>kaperdas, G. T., "The Kellogg Coal Gasification Process: Single Vessel Operation".
K AH f 1 .. «_ V..K 1 M JT__I O.. _1 _~ 1-11 lot. n\- * s«n^^\ * *
1 Academy of Science
Washington, B.C. (»1973).
(4) "Coal Technology: Key to Clean Energy", Annual Report 1973-74, Office of Coal Research, p 62, Washington, D.C. (1974).
-------
5-83
5.7.3 Atomics International Molten Salt
Description of Process. This process Involves gasification of
coal with air in molten sodium carbonate to produce a clean low-Btu fuel
gas.
Crushed coal and compressed air together with a small amount of
sodium carbonate make-up are fed into the molten salt bath which operates
at 1800 F and a pressure of 5 to 10 atmospheres. Coal is partially oxidized
by air to CO, C02 and H20 with complete release of coal volatiles into the
product gas stream. These reactions take place rapidly at the relatively
low operating temperature primarily because of the catalytic effect of
sulfates and sulfides dissolved in the melt.
Because sulfur and ash from the coal are retained in the melt,
the off-gas can be burned in a conventional gas-fired boiler without costly
clean-up processes.
The sulfur and ash content of the melt will be optimized to provide
satisfactory operation of the bath while minimizing the flow rate of the
sidestream of melt which is taken to the regeneration system for removal
of sulfur and ash, and regeneration of sodium carbonate. Regeneration
involves quenching with enough water to dissolve the salts, filtering off
the ash,and carbonation with product gas to regenerate sodium carbonate and
release hydrogen sulfide. Sodium carbonate is crystallized from the regener-
ated solution and dried; hydrogen sulfide is converted to elemental sulfur
by the Glaus process.
The product gas has a heating value of about 150 Btu/SCF.
-------
AIR
SECOND/ KV AIR
COMPRESSOR
BLOWER
PRIMARY AIR
NET
POWER
i
00
ASH
SULFUR
FIGURE 5.7.3.
ATOMICS INTERNATIONAL MOLTEN SALT GASIFICATION
PROCESS(1)
-------
TABLE 5.7.3 ATOMIC XNTERNATZON MOLTEN SALT: .STATE OF THE ART
Facllty
Location
Owner(s)
or Contractor
Status/Operating History
5 Ton/hr Pilot
Norwalk Station,
Conn.
Atomics Intel-nation*
Conceptual design. Seeking Funding.
Bench scale tests on 3 ft I.D. gasifier. Batch process. Ash
build-up determines length of run. Completed runs at atmospheric
pressure with processing of 170 Ib/hr; next runs will involve
500 Ib/hr at 5 atm.
Ul
i
03
Ul
(Contact: Charles A. Trilling, Atcmics International, Canoga Park, Ca., (213) 341-1000)
References:
(1) Trilling, Charlds A., "Molten Salt Process for the Gasification of Coal", Prepared for presentation at the Workshop on
Materials Problems and Research Opportunities in Coal Conversion, Ohio State University (April 16-18, 1974).
(2) "Evaluation of Coal Gasification Technology, Part II, Low- and Intermedlate-Btu Fuel Gases'
National Academy of Engineering, Washington, D.C. (1973).
National Research Council,
-------
5-86
5.8 Underground Gasification
Description of Process^ Underground gasification of coal is the
burning of coal in situ in the presence of air, oxygen, steam-air, or steam-
oxygen mixtures introduced into the seam by boreholes or shafts. The
process permits recovery of a low-Btu gas without recourse to mining
operations. The chemistry is essentially the same as that involved in
the other processes described in this chapter.
The technology of underground gasification has been thoroughly
reviewed in a recent report to the U.S. Bureau of Mines prepared by A. D.
Little, Inc. (44).
The English chemist Sir William Ramsey carried out small-scale
studies of underground gasification prior to World War I, and the Russians
did rather extensive work in the period from 1933 to about 1965. Major
research efforts were also concentrated in the United Kingdom and in the
United States during the period following World War II. However, research
activity in the area of underground gasification was essentially abandoned
in all three countries by the early sixties.
The studies did demonstrate the technical feasibility of under-
ground gasification-at least on a relatively small scale, but the gas
produced was generally of poor quality.
More recently, the U.S. Bureau of Mines has shown renewed interest
in underground gasification, and experimental studies are now being con-
ducted at a site near Hanna, Wyoming which will explore the technological,
economic,and environmental feasibility of the underground gasification of
western subbituminous coal (46).
-------
TABLE 5.8 UNDERGROUND GASIFICATION
Factlty
Commercial
Experimental
Experimental
Experimental
Experimental
Experimental
Location
BSR
orgas, Alabama
anco-Casino, Italy
andre, Belgium
Newman Spinney and
Bayton (England)
lanna, Wyo.
Owner(s)
or Contractor
iovernment
US Bureau of Mines
and Alabama
Power Co.
Socogaz and
Mineraria, Valdarn<
Soxogaz, Charbonnag
de France and
Charbonnage de
Pologne (Poland)
National Coal
Board
US Bureau of Mines
Status/Operating History
y July 1941, when USSR entered WW II gas was being produced from
5 underground gasification installations. Further development
was interrupted by the war. By 1958, USSR was producing 27 x 10E
SCF low-Btu gas-, however, interest in gasification declined in
the early sixties apparently because of increased availability of
natural gas (2).
irst of a long series of experiments on in situ gasification
were begun in early 1947. Studies were made with air, 02-
enriched air with and^without steam and with 02-steam mixtures.
Later (1951) studied methods of increasing seam permeability
(electrolinking and hydraulic fracturing). Work at Gorgas was
terminated in 1959. Present US activity is centered at Hanna,
Wyo. (see later entry). (2).
Underground gasification tests in lignite seam (15-60 ft thickness),
Early tests (1947) produced 7 MMSCF/D of gas with average
heating value of 100 Btu/SCF. No longer in operation.(2)
Experimental work on semi-anthracite seam about 3 ft thick was
carried out in 1948-50. Results were poor and work was discon-
tinued. (50 percent of the Belgian coal reserves is in seams
too thin for conventional mining).(2).
dork began in 1949 and continued through 1960. Culminated with a
pilot electrical-generating station operating on low-Btu gas from
the Newman Spinney installation. The plant generated a total of
about 3.5 KWH from 238 MMSCF of gas with an average heating value
of 58.8 Btu/SCF (fluctuated between 40 and 84 Btu/SCF).(2)
[gnition for 1st trial was in March 1973, and continued through
April 1974, 30 ft seam. Forward burning did not go well.
Switched to backward burning in May with considerably greater
success. Between Sept. and Feb. gas was produced at a rather
steady rate of about 1.6 MMSCFD (dry). The heating value was
about 130 Btu/SCF. There were no significant process problems.
Preliminary estimates indicate about 65 percent coal recovery
(to be verified by seismic and coring studies).
oo
-------
TABLE 5.8 (Continued)
Facllty
Location
Ouner(s)
OT Contractor
Status/Operating History
First phase involved air injection. Second phase, which will
run about 3-4 months, will involve injection of 02-enriched air
and pneumatic linking. If results are as successful as Phase I,
it will have been demonstrated that it is possible to sustain
a reasonable steady flow of gas of approximately uniform
composition.(4)
i
oo
oo
References:
(1) Elder, J. L.,
Volume, John Wi
(2) A. D. Little, I
Washington, D.C
(3) Nadkarni, R. M.
Symposium on Cl
(4) Private Communi
(5) Schrider, Leo A
Fifth Synthetic
he Underground Gasification of Coal", Chejmistry of Coal Utilization. H. H. Lowry, Editor, Supplementary
ey and Sons, Inc., Naw York, pp 1023-104
c., "A Current Appraisal of Underground
PB 209 274, NTIS, S
Bliss, Charles and
an Fuels from Coal,
jrlngfield, Va., 280
Jatson, W. I., "Unde
>p 611-637, Chicago
(1963).
oal Gasification", U.S. Dept. of the Interior, Bureau of Mines,
p (April 1972).
ground Gasification of Coal", Institute of Gas Technology
1973).
ation,
, and Paslni, J., Underground Gasification of Coal—Pilot Test, Hanna, Wyoming, presented at the AGA
Pipeline Gas Symposium (October 1973).
-------
5-89
5.9 Gasification of Refinery Residues
Although this section will be devoted to processes developed
primarily or exclusively for the gasification of low-cost refinery residues
or "bottoms", it should be noted that many of the processes described
earlier in this chapter can - in some cases without significant
modification - be used to gasify residual oils.
Commercial scale Koppers-Totzek gasifiers in Belgium and Greece
have operated with Bunker-C oil feed to produce synthesis gas for a number
of years (Table 5.6.1). All of the molten bath processes can accept high
(*)
sulfur residual oils, and Covers and Schreiner briefly discussed applica-
tion of the Kellogg Molten Salt Process to the cracking of heavy oils to
produce liquid and/or gaseous products. Product distribution for a given
feed depends upon bath temperature,which can be controlled by addition of
lithium and potassium carbonates to the sodium carbonate to lower the
freezing point.
Also, it should be added that the technology for production of fuel
gases, in particular SNG from naptha and kerosine fractions boiling up
to 600 F, is well developed. A complete list of plants for production of
SNG from petroleum, announced as of April 15, 1973, has been published/47^
(*) Cover, A.E. and Schreiner, W. C., The Kellogg Molten Salt Process,
Presented at the 4th Conference on Synthetic Fuels from Coal,
Oklahoma State University, Stillwater, Oklahoma (May 1974).
-------
5-90
5.9.1 F.lexicoklng (Exxon Corporation)
Description of Process. A simplified schematic of the Flexi-
coker is shown in Figure 5.9.1. Residuum feed injected into the reactor
is in part thermally cracked to a wide range of volatiles, and in part
converted to coke which deposits on fluidized circulating coke particles.
Heat is supplied to the reactor by recirculating a stream of coke particles
from a heater vessel. Volatiles leaving the reactor are quenched in the
scrubber section. Materials boiling above about 950 F condense and can
be recycled to the coking reactor.
Coke produced in the reactor flows to the heater and is
partially devolatilized at 1150 F. A coke-stream also goes from the
heater to the gasifier where it is reacted at an elevated temperature
with air, or oxygen and steam to produce the product gas (coke gas).
The coke gas from the gasifier and the light hydrocarbons
produced by devolatilization in the heater are cooled and coke fines are
removed for further processing* The clean product gas has a heating
value of about 100 to 130 Btu/SCF if air is used for gasification.
The process is expected to convert 98 percent by weight of
a vacuum residuum to gaseous and liquid products. Greater than 99 per-
cent of the metals in the feed are concentrated in a 2 percent solids
purge. Approximately 95 percent of the total sulfur in the residuum can
be recovered as elemental sulfur by commercially available processes.
-------
5-91
SIMPLIFIED FIEXICOKING
FLOW PLAN
REACTOR PRODUCTS
TO FRACTIONATOR
STEAM
STEAM
GENERATION COOLING
COKE-GAS
STE
FIGURE 5.9.1. FLEXICOKING (Exxon Corporation)
(1)
-------
TABLE 5.9.1. FLEXICOKING: STATE OP THE ART
Facilty
Location
Owner(a)
or Contractor
Status/Operating History
2 bbl/day Process
Development Unit
750 bbl/day Proto-
type Unit
21 x 103 bbl/day
Commercial Unit
Commercial Unit
Baton Rouge, La.
Baytown, Texas
Kawasaki, Japan
Nagoya, Japan
Exxon Corp.
TOA Oil of Japan
This integrated coking/gasification unit has been commissioned
and is in operation. Data indicate that typical coke
desulfurization levels are 70 percent or higher.
Starting up.
Under construction. Due onstreara in 1975.
Being designed.
(Contact: M. P. Mai
golis, Exxon Researc
and Engineering, Florham Park, N.J. (201) 474-0100)
VD
References:
(1) Matula, J. P., W
Institute, Proce
(2) Rionda, J. A., J
Residua Processi
sinberg, H. N. and W
idings, Division of i
., Bodnick, S., Ket
ig", presented at Na
issman, W., "Flexico
efining, 37th Midyea
, T. K., Metrailer,
ional Petroleum Refl
ting: An Advanced Fluid Coking Process", American Petroleum
Meeting, New York (May 8-11, 1972).
'. J., Savage, H. R., and Duir, J. H., "Recent Advances in
ers Association Annual Meeting (April 2, 1974).
-------
5-93
5.9.2. Texaco Partial Oxidation (Texaco Oil Company)
Descripiton of the Process. Oil and recycled soot undergo partial
oxidation in a refractory-lined generator with either air or oxygen. Steam
is added to moderate the temperature. An especially developed feed system
for oil, steam and oxidant is carefully matched to a highly efficient
burner which results in very effective mixing and combustion.
In addition to oxidation of hydrocarbons to hydrogen and carbon
monoxide, steam cracking, hydrocracking and carbonization reactions also
take place in the generator. The relative importance of these reactions
is determined by such factors as operating temperature and pressure, flow
rate, and ratios of oxidant to hydrocarbon and steam to hydrocarbon feed.
Commercial units have been operated at pressures up to 1200 psi
and large-scale pilot units have been operated at pressures up to 2500 psi.
Temperatures range from 1800 to 3000 F.
Generators can be operated in the direct water quench mode
(Figure 5.9.2) or with a waste-heat boiler between the generator and
scurbber. The direct water quench approach is usually favored if processing
of the gas involves shift conversion.
Sulfur in the residuum is converted to hydrogen and carbonyl sulfides
and can be removed by any of the commercially available processes such as
Rectisol, Benfield, etc. Elemental sulfur is the ultimate by-product.
Feed stocks with up to one weight percent ash have been used
commercially without difficulty. Ash components are partially sequestered
in ungasified soot, which is scrubbed from the gas with water. The
ungasified carbon is ultimately recycled to extinction.
Clean low-Btu (about 130 Btu/SCF) gas is produced if air is the
oxidant. The heating value is increased to about 320 Btu/SCF if oxygen is
used in place of air.
SNG can be produced if the product gas is shift converted and
catalytically methanated.
A wide variety of sulfur-containing distillate and residual fuel
oils have been processed commercially.
-------
5-94
GENERATOR WITH DIRECT WATER QUENCH
OIL AND SOOT
STEAM
OXYGEN
1
TO SHIFT
GENERATOR
SCRUBBER
SCRUBBING
WATER
SOOT AND WATER
TO RECOVERY
FIGURE 5.9.2. TEXACO PARTIAL OXIDATION PROCESS(1>
-------
TABLE 5.9.2 TEXACO PARTIAL OXIDATIONS STATE OF THE ART
Facllty
Location
Owner(s)
or Contractor
Status/Operating History
The Texaco Process has been licensed for use in more than 60 plants
in over 20 countries throughout the world for production of high
purity hydrogen or synthesis gas.
A wide variety of feed stocks have been employed, and 35, pri-
marily the more recent ones, have used heavy oils.
Ul
i
References:
(1) Child, Edward T.
Symposium on Coa
"Texaco: Heavy Oil
Gasification", presented at the University of Pittsburgh School of Engineering
symposium on uoa Gasification and L?quifaction, Pittsburgh, Pa. (August 6-8, 1974). „*..••* n on
(2) Schlinger, W. G. and Slater, W. L., "Partial Oxidatlon-A Minimum Pollution Route for Hydrogen Manufacture , American
Chemical Society Meeting, Petroleum Division, Los Angeles, Calif. (April 1971).
(3) Crouch, W. G., Schllnger! W. G., Klapatch and Vitti, G. E., "Recent Experimental Results on Gasification Combustion of
Low-Btu Gas for Gas Turbines", Combustion, pp 32-25 (April 1974).
-------
5-96
5.9.3 Shell Gasification Process (Shell Oil Company)
Description of Process. A simplified flow diagram is shown in
Figure 5.9.3. The hydrocarbon feed and oxidant (air and/or oxygen) are
preheated and fed to the reactor. When the oxidant is either oxygen or
enriched air, steam must be injected as well in order to moderate reactor
temperature. The principal reaction is parted oxidation of the hydrocarbon
to carbon monoxide and hydrogen, but other reactions such as steam cracking,
hydrocracking and carbonization also occur.
The hot reactor-effluent (2,200 to 2,400 F), containing about
three percent of the feed as soot, is cooled by passage through a waste-
heat boiler. Soot is recovered from the crude gas leaving the waste-heat
boiler and recycled to extinction with fresh feed. The product gas is
virtually free of entrained carbon ( < 5 pnnn).
Sulfur is converted primarily to hydrogen sulfide and traces of
carbonyl sulfide which are removed, together with most of the carbon dioxide,
in a Shell Sulfinol process unit. The desulfurized gas typically contains
less than 5 ppm sulfur. The ultimate by-product is elemental sulfur.
If air is used as the oxidant, the heating value of the gas is
about 120 Btu/SCF. If oxygen is employed the value is about 300 Btu/SCF.
Less than one (vol) percent methane is produced.
-------
STEAM
PRE-HEATERS
HIGH PRESSURE STEAM
OXYGEN
OR AIR
TO POWER PLANT
FUEL GAS TO
SULFINOL UNIT
CARBON SLURRY
SEPARATOR
BOILER FEED
WATER
HYDROCARBON FEEDSTOCK
FRESH
WATER
CARBON-FREE
CIRCULATION
WATER
VD
WASTE
WATER
FIGURE 5.9.3. SGP FOR FUEL GAS MANUFACTURE
(1)
-------
TABLE 5.9.3. SHELL GASIFICATION PROCESS
Facllty
Commercial
Location
(Contact: J. A,
Owner(a)
or Contractor
Shell Oil Company
Sykea, Jr., Shell 0
Status/Operating History
100 reactor units have been Installed in 34 plants around the
world since 1958. They operate on a variety of feedstocks.
Largest plant (Germany) produces 140-160 MMSCF/D of synthesis
gas for production of methanol and ammonia.
i
\o
00
1 Company, Houston, Texas (713) 795-3903)
References!
(1) Dravld, A. N., Kuhre, C. J., and Sykes, J. A., Jr., "Power Generation Using the Shell Gasification Process",
Presented at the Third International Conference on Fluidized-Bed Combustion (Oct. 1972).
(2) Plummer, J. B., Kuhre, C. J., Reed, C. L., and Sykes, J. A., Jr.,"The Generation of Clean Gaseous Fuels from
Petroleum Residues," Presented at the American Institute of Chemical Engineers Meeting, Tulsa, Oklahoma (May 11-13, 1974).
(3) Kuhre, C. J., and Sykes, J. A., Jr., "The Shell Gasification Process for the Substitute Natural Gas Industry",
Presented at the IGT-SNG Symposium, Chicago (March 12-16, 1973).
-------
5-99
5.9.4 H-Gas (Hydrocarbons Research Inc)
Description of Process. A simplified flow diagram is shown in
Figure 5.9.4. Hydrogasification and gasification steps are carried out in
separate zones within a single reactor vessel. Feedstock is hydrogasified
to produce light hydrocarbon gases. Coke and some heavy residual oil are
gasified with steam and oxygen to generate hydrogen for the hydrogasification.
Coke generated in the hydrogasification zone passes to the
gasification zone on an inert heat carrier. The coke is gasified, and
the inert carrier passes back to the hydrogasification zone.
Gases from the hydrogasifier are quenched with a stream of gas oil
and fed to a liquid recovery section. Liquid hydrocarbons (C,- and higher)
are recovered by fractionation and absorption. Recovered heavy gas oil is
fed to the gasification zone. A portion of light distillate is recycled
to the hydrogasifier zone of the reactor.
The net yield of C$ - 400 F distillate is fed to a hydrotreater
for desulfurization. The product from this process provides the fuel
required by the plant.
Condensed water, containing dissolved ammonia and acid gases, is
recovered and fed to the water-treating system.
Figure 5.9.4 shows the additional processes required to upgrade
the gas to SNG. In this case, the gaseous product stream from the liquid
recovery system is fed with high-pressure steam to a shift converter. The
effluent from the shift converter is treated to remove acid gases and then
is catalytically methanated to SNG.
-------
Feedstock
Steam
1
Liquid Fuel
Desulfurizer
Hydragas-
tfication
Oiygen
Effluent
fHeovy
Recycle gas
Liquid
Recovery
gas oil
Oxygen
Plant
Light distillate
Effluent
water
Liquid plant fuel
r— Steam
Gas
Shift
Converter
Gas
C02
t
coz a HZS
Removal
Ammonia & hydrogen sulfide
Go s
Gas
Water
Treating
1
Sulfur
Manufacture
Gas
Pipeline gas
t
Methane
Production
LPGas
Recovery
LP-go$
Sulfur
product
Ui
I
o
o
FIGURE 5.9.4. H-GAS PROCESS(l)
-------
TABLE 5.9.4. H-GAS: STATE OF THE ART
Facilty
Location
Owner(s)
or Contr/ief'nr
Hydrocarbon Research
Inc.
(Contact: Jim Llvligston, Hydrocarbons 1
Status/Operating History
Bench-scale studies with a unit capable of processing up to
15 B/D have been completed. Results demonstrate that hydro-
gasification process is applicable to processing reaid,
heavy sour crudes and heavy sour distillate fractions.
esearch Inc, New York, N.Y. (212) 349-1480
Ui
i
Reference:
(1) Anon, "SNG Process Passes Pilot Plant Test", The Oil and Gas Journal, pp 32-33 (April 9, 1973).
-------
5-102
5.9.5 IGT (Institute of Gas Technology)
Description of Process. A schematic diagram of the process
is shown in Figure 5.9.5. Feedstock is hydrogasified at 1,300 to 1,400 F
and 1,000 psi in a fluidized bed of solids. The solids act as a heat carrier
and also carry off excess carbon.
Carbon-coated solids from the hydrogasifier are continuously
circulated to a second vessel where the carbon is gasified at 1700-1800 F
and 1000 psi with steam and oxygen to produce hydrogen for the hydrogasifier.
The high pressure leads to significant yields of methane directly from the
residue carbon. The raw gas is shift converted and treated for acid-gas
removal before being sent to the hydrogasifier.
Raw gas from the hydrogasifier is cooled and scrubbed to remove
excess steam and light oils and then desulfurized. The product is not
expected to require catalytic methanation. The heating value should be
about 930 Btu/SCF.
OKI
FIGURE 5.9.5. THE IGT PROCESS
-------
TABU 5.9.5. IGTi STATE OF THE ART
Facilty
Location
Owner(a)
or Contractor
IGT
Status/Operating History
Laboratory studies of the kinetics of oil char gasification.
Economic analysis.
I
M
O
(Contact: Dennis Duncan, I(T, Chicago, Illinois (312) 225-1455)
References:
(1) Anon, "High-Sulfur Resid Eyed for SNG Feed", Oil and Gas Journal, pp 36-37 (February 12, 1973).
-------
SECTION 6
HIGH-BTU GAS FROM COAL
Introduction
Between 1946 and 1971 natural gas production increased 351 percent
while reserves increased by only 90 percent*- Since the American Gas
Association (AGA) began publishing natural gas statistics in 1946, new
additions to reserves exceeded production every year until 1968. In that
year the situation was reversed and that trend has continued in subsequent
years with the gap between production and addition to reserves growing
increasingly wider**.
The Federal Power Commission has estimated that the annual deficit
in domestic natural gas may reach 17.1 trillion cubic feet by 1990***.
Clearly, a number of alternative sources must be developed if the projected
gap between supply and demand is to be bridged.
The production of high-Btu gas from coal probably has the greatest
long-term potential for assuring an adequate supply of pipeline-quality gas
to meet our national requirements. High-Btu gas from coal is more than 90
percent methane and has a heating value in the range 900 to 1,000 Btu/scf.
It is prepared by upgrading the mixture of carbon monoxide, carbon dioxide,
hydrogen and methane generated by the primary gasification of coal. Up-
grading includes purification, increase in the ratio of hydrogen to carbon
monoxide by the water-gas shift reaction and catalytic methanation to con-
vert carbon monoxide and hydrogen to methane (Figure 6.0).
References for a given process are given at the foot of the respec-
tive "State of the Art" table. General references for coal gasification
are given on Page 6-37.
General environmental factors associated with the gasification
of coal are discussed in Appendix A. Because of the considerable overlap
in the environmental aspects of producing the various qualities (in Btu/SCF)
of gas from coal all of the processes described in this section and in
Section 5 (low- and intermediate-Btu gas) are treated together in the dis-
cussion in Appendix A.
* Federal Power Commission, Annual Report (1972).
** Except for 1970, in that year, addition to reserves exceeded production
because of the inclusion of the vast but remote North Slope reserves in
Alaska.
*** National Gas Supply and Demand 1971-1990, FPC Staff Report No. 2 (Feb.,
1972).
6-1
-------
Coal
Oxygen S team
to sulfur recoverj
I
I
Coal
Preparation
1
Ref
[
use
Pretreatment shtft Acid-gas
— . ^^ rrtn 1 f \ r- nt-1 nn ,.,.,. ^^ 'imihhr'r .< . .^kr ConVPralnn _.... ^^ -piafnnvnl
•""T1*^ tO prtiVtillL •*"" ~|~~ ~*f^ uUo 11 ICatlOu ™~^^* .Jt.i.uuui_i. •» j1 ^^- i.njii «i IIK,«III —r—^^-
j caking | [
j r -" L j
T
Ash
I
<
t
1 ^
Catalytic TVvinc - ...^ RNfl
Methanation *" DrylnS 1 ^
t !
3H2-K:0-CH4+H20 L_ compression -*
FIGURE 6.0. GENERALIZED SCHEMATIC FOR PRODUCTION OF SNG FROM COAL
-------
6-3
Status of the Technology
Applications have already been filed for two commercial-scale
(250 MMSCF/D) plants for the production of SNG from coal. Both will be
based on the Lurgi process, and construction of the first of these plants
is expected to begin in the third quarter of 1975, with start-up estimated
for early 1978. At least two other plants of this size, also based on
Lurgi technology, are in the planning stage (see Table 6.1).
Plants based on emerging technology are expected to result in
lower capital investment and operating costs -- and hence in lower SNG
prices. However, none of the new processes is beyond the pilot plant
stage (Table 6.0). and it is unlikely that commercial-scale plants based
on any of these will be built before 1980.
All of the plants presently in the pilot stage have received
support from the Office of Coal Research (OCR), the American Gas Association
or both. Funding of a number of alternative processes is desirable
because of the rather considerable extension of technology involved and
the consequent danger of encountering "dead-ends".
Hopefully, at least one of the processes now under development
will show sufficient promise to warrant the design and construction of a
demonstration plant to determine commercial feasibility. This aspect of
the development program will probably require generous government support.
OCR has proposed that $1.5 billion will be required for design, site
selection, construction and operation of five demonstration plants (40),
but that figure is probably too low.
At this stage of development, it is difficult to anticipate
potential problem areas. An evaluation by the National Academy of Engineer-
ing (7) identified some of the major advantages and disadvantages of several
of the new processes and outlined specific problems associated with the more
advanced of these. Hottel and Howard (1) made a rather similar analysis a
few years earlier. In Tables 6.1-6.12 that follow, the state-of-the-art
-------
TABU 6.0. STATUS OF HIGH-BTU GASIFICATION: A SUMMARY
Pr oc es s/Oeveloper
Current Status
Comments
Lurgl
Koppers-Totzek
Hygas/IGT*
Steam Oxygen
Steam Iron
Electrothermal
Synthane*/US Bureau of
Mines
Blgas*/BItuminou3 Coal
Research
C02Acceptor*/Consolida-
tion Coal
Demonstration tests (up to 2.5 MM
SCF/D) of production of SNG from
coal have been carried out in
Westfleld, Scotland.
Applications have been filed with
FPC for construction and operation
of two 250 MMSCF/D plants in New
Mexico (see Table 6.1).
Gaslfier technology is well-
developed (commercial). No plans
have yet been announced to use
K-T gasifiers in an SNG-plant.
3TPH pilot in operation in Chicago
since May 1971.
Present pilot is integrated with a
steam-oxygen unit for producing
hydrogen for the gasifier.
Blaw-Knox is presently designing
a steam-iron unit.
Built and tested briefly but
presently "mothballed"
3 TPH pilot plant is under con-
struction at Bruce ton, Pa.
5 TPH pilot plant is under con-
struction at Homer City, Pa.
1.5 TPH pilot plant in operation
since April 1972 at Rapid City,
S.D.
Major disadvantage is small throughput, size of gasifier is
limited. Commercial scale plants will require several
(27-33) gasifiers in parallel. As a result, capital invest-
ment and operating costs are relatively high. Also, relatively
low yield of CH4 ( <10%) during gasification. Results at
Westfield and Sasolburgh (Table 6.1) indicate methanation is
now commercially feasible.
Major disadvantage is the very low yield of City (—0) during
gasification.
Plant includes all essential operations except shift conversion.
The most advanced of the new processes. The complexity of
the process-in particular transfer and injection of char at
high temperature and pressure-is a problem. Mid-1975 target
date for design of a commercial plant.
Presently undergoing shakedown.
May prove to be most economical way to produce hydrogen for the
Hygas process.
Considered to be too expensive at present.
Construction is about 60% completed as of July 1974. Expect
completion in January 1975. This will be a fully integrated
plant. Relatively simple process. The relatively low yield
of CH4 (25-30%)** during gasification is a disadvantage.
Expect completion in early 1975. Plant will be fully integrated.
Throughput for this process will be high but a large 03 plant
is required and the relatively low yield of CH4 (207.)** during
gasification is a disadvantage.
Plant does not include provisions for methanation. Many of the
problems that plagued earlier runs have been solved and operations
are now going more smoothly.
cr>
-------
TABLE 6.0 (Continued)
Process/Developer
Current Status
Comments
Hydrane*/US Bureau of
Mines
Ash Agglomeration*/
Battelle,. Union-Carbide
Kellogg Molten Salt/
M.W. Kellogg Co.
Atgas (Molten Iron)/
Applied Technology
Corp.)
Garret Flash Pyrolysis/
Garret Research and
Development
COGAS/Cogas Development
Co.
1 TPH pilot is presently being
designed.
1200 Ib/hr PDU is presently under
construction at West Jeffersion.O
Bench scale.
Bench scale.
Bench Scale (50 Ib/hr) in operation
since January 1973.
4 TPH pilot in operation since
March 1974 in Leatherhead, England,
Also, a 400 Ib/hr pilot in opera-
tion since May 1974 in Plainsboro,
N.J.
Major advantage is that acceptor eliminates need for 02 plant
and reduces the need for shift conversion. However, a very
complex fluidized system is involved and control and scale-up
may present problems.
Other disadvantages include a rather low yield of CH4 (/
during gasification and the fact that only lignite and sub-
bituminous coals can be processed.
Work thus far has been limited to laboratory-scale (see Table
6.7). The major advantage of the process is the high yield
(-75%)** of CH4 from hydrogasification. However, this is a
relatively complex operation and may require extensive
development.
Estimate completion in first quarter of 1975. Gas purification,
•shift conversion and methanation are not included. Major
advantages are that no 02 plant is required and that a relatively
clean product gas is obtained. Disadvantages include the low
CH4 yield (less than 57.)** and the difficulty of transferring
hot ash agglomerates between ccrabus tor and gasifier.
Molten carbonate creates serious corrosion problems; these
apparently have been solved by use of Monofrax A.Process is
rather complex. Direct yield of CH4 is low (/~'5%)**. A proc-
ess development unit is planned (preliminary flow sheets and
cost estimates have been prepared).
Lance design is complicated (must be compatible with molten
iron and slag). Essentially no CH4 is formed in the gasifier
because of the low pressure and high temperature.
A 10 TPH pilot plant has been proposed. Process produces large
quantities of tar and char as byproducts.
Expect test runs to cover an extended duration and provide basis
for construction of a larger pilot or a demonstration plant.
*Presently funded by OC
**Methane analysis in vo
gasified.
. or US Bureau of Mines.
ume % on a dry, C02-free basis.
Val
es are only approximate and will depend upon the coal being
-------
6-6
for each of twelve new processes is reviewed, and Table 6.0
presents a summary view of the current status of these processes with some
comments on problem areas.
At the same time, it is useful to consider some of the more
general developmental problems associated with unit operations common to
most processes.
Coal Mining. The development of advanced surface and under-
ground mining technology that will increase productivity and coal
recovery and at the same time meet health, safety and environ-
mental standards will have an important bearing on coal gasifica-
tion.
Coal Preparation. At present it is not possible to crush
or grind coal to a specific size without production of surplus
fines. In most of the fluid-bed processes the coal must be sized
to prevent high fuel losses by carbon-carryover, and most fixed
bed processes cannot accept fines.
Coal Feeding. Because most of the new processes operate
at high pressures, coal feeding is a major design problem.
Lock-hoppers are most commonly used, but they result in rather
large energy losses, and it is difficult to find a material that
will seal against high pressures after more than a relatively
few cycles. Other feed systems such as slurries and piston
feeders are being investigated, but considerably more development
work is required.
Refractory Problems. Under conditions prevailing in the
gasifier SiO- reacts with hydrogen to produce SiO and water vapor.
This reaction is reversed downstream, where temperatures are
lower, and pipes can become clogged with SiO». Presently, the
approach is to use expensive alumina refractories (39).
Hot Char Transport and Inlection. Many of the new processes
require the recycling of char. Development of a system capable
of transporting and injecting char at high temperatures and
pressures without producing serious erosion is a problem which
requires much more work.
-------
6-7
Slag and/or Ash Removal. The high operating pressures in-
volved in most of the new processes make the withdrawal of slag
or ash from the gasifier a difficult design problem. The most
commonly proposed method involves quenching in water and removal
as a slurry through a lock-hopper system.
Gas Clean-up. Incomplete removal of char from the gasifier
effluent could result in poisoning of the shift catalyst or in
char accumulation downstream.
Quench Chamber Corrosion. In many cases, the gasifier
effluent is quenched to scrub out heavy hydrocarbons, and
particulates. Because of the high pressures and temperatures and
the corrosive nature of the gas (relatively high concentration
of hydrogen sulfide), materials for this stage of the system are
subject to severe corrosion. Considerable research is still
needed on materials for this stage (39).
Methanation. The recent studies by CONGO Methanation Com-
pany at Westfield Scotland and by Lurgi in Sasolburg, South Africa
(see Table 6.1) are encouraging. In the Westfield demonstration,
up to 2.5 x 106 SCF/day of SNG were produced by methanation of gas from
a Lurgi gasifier after shift conversion and purification.
Technical details have not yet been published.
In any case, the development of new and imporoved catalysts
and reactors for methanation should continue to be an area of
considerable activity.
Char Utilization. Char is produced in some of the advanced
gasification process. Some of this is expected to be used to
generate hydrogen and/or process steam. Thus far, however, these
processes for char utilization have received rather limited
attention.
-------
6-8
The AGA recently identified 176 sites with sufficient uncommitted
reserves of coal mineable at acceptable costs and with adequate water to
operate SNG plants, each capable of producing 250x 10 SCF/day, over a period
of at least 25 years. 141 of these sites are west of the Mississippi River.
A developing coal gasification industry will require the continued
support of strong research programs, both fundamental and applied, in such
areas as reaction kinetics, catalysis, gas purification, materials, etc.
Over the longer range, it is probable that new methods will con-
tinue to emerge with the potential for lower SNG costs and more efficient
utilization of coal. It is important that funding agencies and the
industry itself remain sufficiently alert and flexible to encourage and
promote promising new approaches.
-------
6-9
6.1 The Lurgi Process (American Lurgl Corp.)
Description of the Process. The primary gasification process is
described in Section 5.1. To prepare pipeline-quality gas, the raw gas
from the Lurgi gasifier is shift-converted to increase the hydrogen/carbon
monoxide ratio, purified and catalytically methanated.
Coal
Coal
Prepa ration
-^
i
1
OO
~-
Light 4
Oil
fC^iaH
iLockl
Steam ^
?>
Oxygen
\
^>
/
•j Raw Gas
Gasifier,
'>
/ 1
.s
700°-UOOCF
~<^
^sh 1
Lock
<^_L^
1 Ash
Quench
\
a,
r
-^
Shift
'
Dehydration
and
Purification
II
{
C02
I
H2
k
7
^
CO2 + H2S
Purification
I
* f
^
Methanation
o
Pipeline
Gas
FIGURE 6.1. LURGI PROCESS
-------
TABLE 6.1 LURGI: STATE OF THE ART
Facllty
Location
Owner(s)
or Contractor
Status/Operating History
Methanation pilot
Saaolburgh, South
Africa
Methanation pilot
Westfield, Scotland
50 x 10° SCF/day
(Demonstration)
Burnham, N.M.
250 x 10 SCF/day
South African Coal,
Oil and Gas Corp.
Sponsored by a group
of U.S. oil com-
panies headed by
Continental Oil Co
in collaboration
with the Scottish
Gas Board
ElPaso Natural Gas
(plant will be
owned and opera-
ted by Fuel Con-
version Co. - a
wholly owned
subsidiary)
In conjunction with Lurgi Mineraloeltechnik GmbH, SASOL has
studied catalytic methanatlon of CO-rich synthesis gas—a slip
stream of about 700 scf/hr from SASOL1s commercial plant
(Table 5.1.1)--with a special methanation catalyst developed by
BASF, Results during the 1-1/2 yr teat indicate methanatlon can
be carried out without carbon formation to yield an SNG with
less than 1% (Vol.) H_ and less than 0.17. CO and a heating
value of 970 Btu/scf. Trace components in synthesis gas
leaving Rectisol wash have little influence on catalyst
activity and life. Based on results for runs of 2600 hrs they
calculate an expected life time of 16,000 hrs for the special
BASF catalyst^6'7'.
Town gas from the Westfield plant (Table 5.1.1) is being upgraded
to SNG as a demonstration of commercial feasibility. Up to 2.5
MMSCF/D of SNG is produced by methanatlon of purified (Rectisol)
gas in a fixed-bed adiabatlc reactor containing a Ni-based
catalyst. Product gas is 90-957. CH^ and has a heating value of
about 980 Btu/SCF^8'. Results demonstrate that methanation is
commercially feasible. Tests will conclude in September 1974.
Awaiting final FPC approval. Expect to begin construction in
3rd quarter of 1975 and to begin operation in mid-1976. Capital
investment will be $20 x 10^. Function will be to test process
operation. Goals include operating at 20% above design
capacity and 30% above design pressure. Will also be used to
train operators for their 250 MMSCF/D facility and the Wesco
plant (see below).
Construction will begin concurrently with the test facility
described above. Expect start-up in Jan. 1978 and full
production in July 1978. Gas will cost $1.51/103 ft3 (first year
price in 1973 dollars). Capital investment in plant and mine is
estimated at $605 x 10&.
i
i—1
o
-------
TABLE 6.1 LURGI: STATE OF THE ART {CONTINUED)
Facllty
Location
Owner(s)
or Contractor
Status/Operating History
250 x 10 SCF/day
an Juan County,
N.M.
250 x 10° SCF/day
N.A.
1000 x 10 SCF/day
(4 plants)
Eastern Wyo.
Southern Illinois
Dunn County,
North Dakota
Pacific Coal Gasifi-
cation Co., and
Transwestern Coal
Gasification Co.
(WESCO will build
and operate the
plant; Utah Inter-
national Inc. will
supply water and
coal.)
Panhandle Eastern
Pipeline Co. and
Peabody Coal Co.
Natural Gas Pipeline
Company of Americ i
Authorization for the project filed with FPC on Feb.. 7,
Capital costs estimated to be about $500 x 106
Slated for completion In late 1977.
1973.
Feasibility study In progress (by M. W. Kellogg and American
Lurgl Corp.). Projected for operation In 1978-80.
Feasibility studies are underway.
Plans are for four plants and possibly eight. Mining will be
from 110,000 acres of leased land In N. Dakota. Each mine
will cost about $100 million and the associated gasification
plant $370 million. The first plant Is scheduled
to go on line in 1982. (9)
References;
(1) Hottel, H.C. and Howard J.B., New Energy Technology; Some Facts and Assessments. MIT Press, Cambridge,
Mass. (1971).
(2) The Supply-Technical Advisory Task Force-Synthetic Gas-Coal, prepared by the Synthetic Gas-Coal Task Force
for the Federal Power Commission (April 1973).
(3) Rudolph, Paul F. N., "The Lurgl Process, The Route to SNG from Coal", presented at the Fourth Snythetlc
Pipeline Gas Symposium, Chicago (1972).
(4) "Evaluation of Coal Gasification Technology. Part I. Pipeline Quality Gas", R&D Report No. 74-Interlm
Report No. 1, Office of Coal Research, Washington, D.C. (1973).
(5) Moe, James M., "SNG from Coal via the Lurgl Process", Institute of Gas Technology Symposium on Clean Fuels
from Coal, pp 91-110, Chicago (1973).
-------
TABLE 6.1 (Continued)
Facilty
Location
Owner(s)
or Contractor
Status/Operating Hlitory
References Continued
(6) Moeller, F. W.,
(April 1974).
(7) Hoogendoorn, Ja
Fuels from Coal
(8) Anon, "Coal Caa
(9) "Report to Proj
Force, Suppleme
Roberts H., and Bri
C., "Gas from Coal
pp 91-110, Chicago
ficatlon Plant Beglt
>ct Independence fllu
t 1 (July 8, 1974).
z B., "Methanation o
with Lurgl Gasificat
(1973).
s Operation", Chemic
print, Federal Energ
Coal Caa for SNC", Hydrocarbon Processing, pp 69-74
on of SASOL", Institute of Gas Technology Symposium on Clean
1 and Engineering News, p 21 (November 5, 1973).
Agency", Prepared by the Interagency Synthetic Fuels Task
-------
6-13
6.2 The Koppers-Totzek Process (Heinrlch Koppers, G.m.b.H)
Description of the Process. The primary gasification process is
described in Section 5.6.1. The raw gas from the Koppers-Totzek gasifier
is desulfurized, shift converted and catalytically methanated.
COAL
STEAM
1
COAL PREPARATION
COAL
,
GASIFICATION
i
I
OXYGEN
DESULFURIZATION
i
CO SHIFT
AND
METHANATION
i
C02 REMOVAL
PIPELINE GAS
FIGURE 6.2. KOPPERS-TOTZEK
(1)
-------
TABLE 6.2. KDPPERS-TOTZEK: STATE OF THE ART
Facilty
Location
Owner(«)
or Contractor
(Contact: J. F. Fa nsworth, Koppers Eng
Status/Operating History
The Koppers-Totzek gaslf ier has been used on a commercial scale
for production of synthesis gas for a number of years (see
Table 5.6.1). However, it has not been used to prepare SNG.
Cost estimates of SNG production have been made (1) and potential
environmental effects have been considered (2).
I
t~>
4*
Peering and Construction, Pittsburgh, Pa. (412) 391-3300)
References;
(1) Farnsowrth, J. Prank, Mitsak, D. M.,
Leonard, H. F., and
Untrell, Reginald, " Production of Gas from Coal by the
•L ctJ. n» vw* wi 9 w * * «,«*»*«| • **taw*»*»f •* • ••• > «— ™- — f — - - - w * v »
Koppers-Tottek Process", IGT Symposium on Clean Fuels from Coal, pp 143-162, Chicago (1973).
(2) Magee, E. M., and Shaw, H., "Evaluation of Pollution Control In Fossil Fuel Conversion Processes, Koppers-Totzek
Process", prepared for Office of Research and Development, USEPA, Washington, D.C. (January 1974).
-------
6-15
6.3 The Hygas Process (Institute of Gas Technology)
Description of the Process. There are three Hygas processes
(Figure 6.3) which differ essentially only in the method of generating the
hydrogen required for the fluidized-bed hydrogasifier.
Coal is crushed, dried and sized, and, if necessary, treated with
air at 750-800 F to prevent caking. It is then slurried with light oil (a
by product of the process) and pumped into the upper section of the hydro-
gasifier at 600 F and 1000 psig, where most of the oil is evaporated and
recovered for recycle.
In the next stage the coal is devolatilized and partially rnethanated
at 1200-1400 F by hot> hydrogen-rich gas. Devolatilized char passes into
the bottom stage where it is partially gasified at 1700 F by reaction with
steam and hydrogen-rich gas. Residual char which still contains unreacted
carbon can be used in the processes described below to generate the
hydrogen-rich gas for the hydrogasifier.
Raw gas from the hydrogasifier is purified, passed through a shift
converter, and then catalytically methanated.
Variations of the Hygas Process
(1) Electrothermal. Residual char from the hydrogasifier is
reacted with steam to produce a hydrogen-rich gas. The heat required for this
highly endothermic reaction is furnished by direct-current heating of a
fluidized bed of char. Excess char from this electrothermal reactor is used
to generate the electrical power required.
(2) Steam-Iron. In this variation of the Hygas process hydrogen
for the gasifier is produced by the reaction of steam with iron at 1500 F
and 1000 psi. The resulting iron oxide is reduced back to iron by producer
gas generated from spent char. This process is potentially superior in
efficiency and economics to both the electrothermal and the steam-oxygen
processes.
-------
COAL ""•" j) »
-------
6-17
(3) Steam-Oxygen. Similar to electrothermal variation except that
the heat required for the char-steam reaction is supplied by combustion of
a portion of the char with oxygen. The quantities of steam and oxygen used
relative to char are adjusted to maintain an operating temperature of about
1800 to 1900 F.
-------
TABLE 6.3. HYGAS: STATE OF THE ART
Facllty
3 ton/hour Pilot
Location
Chicago, Illinois
(Contact: Bernard
Owner(a)
or Contractor
Institute of Gas
Technology (OCR
and AGA Funded)
S. Lee, Institute of
Status/Operating History
Started operation in May 1971, Cost $107. Initially used H2
produced by reforming CH4. Pilot does not include shift con-
verted (technology for this process is well developed.
Methanation carried out over Ni on keiselguhr).
Steam-02 plant to produce H2 for gasifier is now completed
and undergoing shakedown (July 74). An electrothermal unit
was built and tested briefly but not now economically attrac-
tive and unit has been "moth balled"
Steam-iron unit is being designed by Blaw-Knox. This may
prove to be most economical method of generating H2 for the
process.
Operating problems with "off-the-shelf" equipment caused
frequent shutdowns earlier. These are being solved and semi-
continuous operation of gasifier has been achieved. Operated
at pressures up to 1300 psi.
Continuous runs of more than 100 hrs have been made with fully
integrated unit. Product gas was less than 0.1 ppm S, and
had HV of 930-1007 Btu/SCF (N2-free basis) Longest continuous
run to date (July 1974) was 28 days.
Mid-1975 target date for design of a commercial scale
(250 MMSCFD) plant. Will involve 3 parallel trains.
Gas Technology, Chicago, Illinois (312) 542-7080)
I
h-1
00
References;
(1) Hottel, H. C., and Howard, J. B., New Energy Technology. Some Facts and Assessments. Cambridge, Mass., MIT Press (1971).
(2) "Evaluation of Coal Gasification Technology. Part I. Pipeline Quality Gas", R&D Report No. 74 - Interim Report No. 1,
Office of Coal Research, Washington, D.C. (1973).
(3) The Supply-Technical Advisory Task Force - Synthetic Gas-Coal, prepared by Synthetic Gas-Coal Task Force for the
Federal Power Commission (April 1973).
(4) Schora, F. C., Jr., Lee, B. S., Huebler, J., "The Hygas Process", p 219, Institute of Gas Technology Symposium on Clean
Fuels from Coal, Chicago (1973).
(5) Annual Report for Calendar Year 1973, OCR, U.S. Dept. of the Interior.
(6) Annual Report 1973-74, OCR, U.S. Dept. of the Interior.
-------
6-19
6.4 The Synthane Process (Bureau of Mines)
Description of the Process. The primary gasification is described
in Section 5.3.2. Raw gas from the fluid-bed gasifier is cleaned, passed
through a shift converter, scrubbed almost free of sulfur compounds and
carbon dioxide, and then catalytically methanated to produce pipeline
quality gas (Figure 6.4).
co2 + H2s
STEAH AND
OXYGEN
CHAR TO POWER PLANT
FIGURE 6.4. SYNTHANE PROCESS(4)
-------
TABLE 6.4 THE SYNTHANE PROCESS (U.S. BUREAU OF MINES)
Facllty
75 ton/day Pilot
Plant (fully In-
tegrated to produce
SNG)
Location
Bruceton, Pa.
Owner(s)
or Contractor
U.S. Bureau of Mines
Construction is about 607. completed as of July 1974. Expect
completion in Jan. 1975. Cost $13 x 10°. Studies on a wide
variety of coals with a 40 Ib/hr gasifier indicate process will
accept any U.S. coal. Also, studying methanation using both
parallel plate- and tube wall-type reactors with Ranay nickel
as tt*e catalyst. Shift catalysts are also being studied.
Status/Operating History
(Contact:
References:
(A. J. Forney, U.S. Bureau of Mines, Pittsburgh, Pa., (412) 892-2400)
(1) Hottel, H. C. and Howard, J. B., New Enerav Technology - Some Facts and Assessments. MIT Press, Cambridge
Mass (1971)
(2) "Evaluation of Coal Gasification Technology, Part I, Pipeline Quality Gas", R&D Report No. 74, Interim
Report No. 1, Office of Coal Research, Washington, D.C. (1973).
(3) The Supply-Technical Advisory Task-Force-Svnthetic Gas-Coal, prepared by Synthetic Gas-Coal Task Force
for the Federal Power Commission (April, 1973).
(4) Forney, A. J., Haynes, W. P., Elliot, J. J., Gasior, S. J., Johnson, G. E. and Starkey, J. D., Jr., "The
Synthane Coal-to-Gas Process". Institute of Gas Technology Symposium on Clean Fuels from Coal, PP 199-208,
Chicago (1973).
ro
o
-------
6-21
6.5 The Bi-Gas Process (Bituminous Coal Research)
Description of the Process. The primary gasification process is
described in Section 5.5.1. After the gas from that process (operating
with oxygen) is shifted to the proper hydrogen/carbon monoxide ratio, the
hydrogen sulfide and carbon dioxide are selectively removed in a SELEXOL
unit prior to catalytic methanation (Figure 6.5).
co
COAL
STI
CDAI ;
PREPARATION
OXYGEN
STEAM
:AM
— *
— *
RAW ^t*—
1" GAS
UPPER
REACTOR
1700 F
1000-1500
PSIG
GASIFIER
2700 F
1000-1500
PSIG
v_ ^
\
QUENCH &
» HEAT
RECOVERY
7
RECYCLE
CHAR
r— C
i
PIPELINE
GAS
— » SHIFT -
EHYDRATION
1
PURIFICATION
1
p
• METHANATION
ASH-SLAG
FIGURE 6.5. BIGAS PROCESS(4)
-------
TABLE 6.5. BIGAS: STATE OF THE ART
Factlty
5 ton/hr Pilot
Location
Homer City, Pa.
Owner (s)
or Contractor
Bituminous Coal
Research (with
support from OCR
and AGA). (Steam
Roger Corp. is
responsible for
construction).
Statua /Operating History
Under construction. Estimate completion in early 1975. Estimated
cost is about $25 x 106. This will be a fully 'integrated
plant. Lab- and process development scale (6000 SCF/hr) studies
of methanation are continuing to develop optimum operation condi-
tions for the pilot plant. Acid gas removal by Selexol process.
(Contact: Robert Grace, Bituminous Coal Research, Pittsburgh, Pa. (412) 327-1600)
References; ^ „„„.., H n, anA HnMflrd. j.B.. New Energy Technology; Some Facts and Assessments. MIT Press. Cambridge
Mass. (1971).
(2) "Evaluation of Coal Gasification Technology. Part I, Pipeline Quality Gas", National Research Council,
National Academy of Engineering, Washington, D.C. (1973).
(3) The Supply-Technical Advisory Task Force-Synthetic Gas-Coal, prepared by Synthetic Gas Coal Task Force for
the Federal Power Commission (April, 1973).
(4) Grace,' Robert J., "Development of the Blgas Process", Institute of Gas Technology Symposium on Clean Fuels
from Coal, pp 179-198, Chicago, (1973).
(5) "Clean Energy from Coal--a National Priority", 1973 Annual Report, Office of Coal Research, Washington,
D.C. (1973).
(6) "Coal Technology: Key to Clean Energy", Annual Report 1973-74, Office of Coal Research, Washington,
D.C. (1974).
(7) Hegarty, W.P. and B.E. Moody, "Evaluating the Blgj.s SNG Process", Chemical Engineering Progress, Vol. 69,
No. 3, pp 37^42 (1973).
NJ
NS
-------
6-23
6.6 The CO^ Acceptor Process (Consolidation Coal Company)
Description of the Process. The primary gasification process is
described in Section 5.3.3. Raw gas from the gasifier is purified and
catalytically methanated (Figure 6.6). Because the purified gas has a high
hydrogen/carbon monoxide ratio, shift conversion may not be necessary.
r
HEAT RECOVERY
AND
WATER WASH
1
PURIFICATION
RAW GAS
(1500 F)
FROM GASIFIER
METHANATION
• DEHYDRATION
PIPELINE
GAS
FIGURE 6.6. THE C02 ACCEPTOR PROCESS
-------
TABLE 6.6.
CO. ACCEPTOR:
STATE OF THE ART
Facilty
40 Ton/day Pilot
plant
Location
Rapid City, S.D.
Owner(s)
or Contractor
Consolidation Coal
Co., (OCR and AGA
support) (plant
constructed and
operated by Steam
Roger Corp.)
Status/Operating History
- Plant cost about $9.3 x 10 . In operation since April 1972,
- 25 runs were completed in the period 4/72-5/74. Three
continuous runs of 100 or more hours.
- Mechanical problems in earlier runs have slowed the
acquisition of fundamental data. More recent runs have
been more successful.
• Problem of refractory failures has been solved.
- Corrosion of fired heaters by H.S has been eliminated by use
of ZnO system to remove H.S. However, formation of metal
carbides by carbon deposition still resulted in loss of
metal. Hope to solve this by adding steam to the gas going
to these burners.
- Problems with char combustion and plugging of acceptor lines
during start-up also appear to be solved.
- Designed for use with Lignite and subbituminous coal.
- Designed to operate at pressure of 150 to 300 psi and tempera-
tures up to 1800 F.
(Contact; Carl E. Fink, Consolidation Coal Co., Rapid City, S.D., (605) 342-6416)
NJ
•e-
References:
(1) Hottel, H. C., and Howard, J. B., New Energy Technology - Some Facts and Assessments. MIT Preas, Cambridge, Mass.,
(1971).
(2) "Evaluation of Coal Gasification Technology, Part I, Pipeline-Quality Gas, Office of Coal Research,
Washington, D.C. (1973).
(3) The Supply-Technical Advisory Task Force-Synthetic Gaa-Coal. prepared by Synthetic Gas-Coal Task Force for the
Federal Power Commission (April, 1973).
(4) Fink, Carl E., "The CO Acceptor Process", Institute of Gas Technology Symposium on Clean Fuels from Coal, pp 301-
310, Chicago (1973). 2
(5) Annual Report for Calendar Year 1972, Office of Coal Research, U.S. Dept. of Interior, Washington (1973).
(6) Annual Report 1973-74, Office of Coal Research, U.S. Dept. of Interior, Washington (1974).
-------
6-25
6.7 The Hydrane Process
Description of the Process. This process (Figure 6.7) involves
direct hydrogasification of raw coal in a rather unique two-stage hydro-
gasifier. Pulverized coal is fed into the upper stage which is a free-fall
dilute-phase reactor operated at 1650 F and 1000 psi. The coal is devolati-
lized while flowing in dilute-phase suspension concurrently downward with a
hot stream of gas which is about 50 percent hydrogen and 50 percent
methane. Char from this stage flows into the second stage (fluidized-bed)
where partial gasification and methanation occur in the presence of almost
pure hydrogen to produce the feed gas for the upper stage. The result is
an off gas rich in methane (about 70 volume percent) which requires only
light methanation, and which is relatively simple to purify because of its
low carbon dioxide content ( <17»). Hydrogen sulfide removed from the gas
stream can be fed directly to a Glaus plant without further reduction in
carbon dioxide.
Residual char from the second stage is drawn off through a stand-
pipe and is fed directly to the hydrogen-rich synthesis gas generator.
Residual char from the hydrogen plant (0.137 Ib/lb dry coal) may be used as
fuel for steam and power generation since it contains enough carbon to be
combustible.
-------
Cool
preparation
Gas
from
fluid
bed
Coal
hydrogenation
(dilute phase)
1
Hydrogen
Char
Hydrogen
plant
Hot char
I Pipeline
gas
Raw
product
Gas
Gas
cleanup
Light
methana-
tion
2- 3% CO
to
Char
hydrogenation
(fluid bed)
*4-
Oxygen
Steam
Ash
FIGURE 6.7. HYDRANE PROCESS
-------
TABLE 6.7 HYDRANE: STATE OF THE ART
Facllty
1 Ton/hour Pilot
Location
N.A.
U.S. Bureau of Mines
(Contact: James
Owner(s)
or Contractor
A. Gray, U.S. Bureau
Status/Operating History
Under design.
Free-fall dilute-phase reactor has been operated as a separate
lab-scale unit at pressures of 35 to 205 atra. and at tempera-
tures up to 1650 F. Carbon conversion was satisfactory and
the kinetics have been well-defined (3,6).
Second-stage reactor also has been operated as a seperate unit
on a bench scale.
In past two years major emphasis has been operation of an
integrated two-stage hydrogasifier (lOlb/hr). Because of the
equipment scale, early attempts at operating 2nd stage as a
fluid bed were plagued with basic design problems. Nonethe-
less, steady state was attained for short periods in several
runs. Total C conversion was over 50 percent for both stages.
H2 consumption per unit of CH4 produced was low (1.38). Hope
to develop a smooth-running unit to generate basic data on 2nd
stage using freshly produced char from stage 1, to measure
liquid product yields, and to prove operability.
Also, obtaining data on production of hydrogen-rich synthesis
gas from Hydrane char.
of Mines, Pittsburgh, Pa (412) 892-2400)
0\
Ni
References:
(1) Hottel, H. C.,
(2) "Evaluation of
Office of Coal
(3) Feldman, H. F.,
and Howard, J. B.,
loal Gasification Te
esearch, Washington
Mima, J. A., and Ya
ew Energy Technology
hnology. Part 1. Pip<
D.C. (1973).
orsky, P. M., "Press
Some Facts and Assessments. Cambridge, Mass., MIT Press (1971).
line-Quality Gas", R&D Report No. 74 - Interim Report No. 1,
irized Hydrogasification of Raw Coal in a Dilute-Phase Reactor'
165th Annual ACS Meeting, Dallas, Texas, April 1973. (Preprinted).
(4) Yavorsky, Paul M., "The Hydrane Process", p 209, Institute of Gas Technology Symposium on Clean Fuels from Coal,
Chicago (1973).
(5) Feldmann, J. F., Wen, C. Y., Simons, W. H., Yavorsky, P. M., "Supplemental Pipeline Quality Gas from Coal by the
Hydrane Process", Paper presented at the 71st National Meeting AICE, Dallas (February 20-23, 1972).
(6) Feldmann, H.F., Simons, W. H., Mima, J. A., and Hiteshue, R. W., Preprints of Fuel Div., ACS, Chicago (Sept. 1970).
-------
6-28
6.8 The Ash Agglomeration Process (Union Carbide-Battelle)
Description of the Process. The primary gasification process is
described in Section 5.4.3. Raw gas from this fluidized bed gasifier passes
through a heat recovery system and is expanded in a gas turbine to generate
process power. This gas is then shifted, purified and catalyticly methanated
(Figure 6.8).
GASIFICATION
REACTOR
COAL—*
STEAN
PRODUCT GAS
RECYCLE
RESIDUE
. RECYCLE
BURDEN
FLUE CAS
ASH
RESIDUE
COAL OR
CHAR
BURNER
STEAN
STEAN
GENERATOR
GAS
PURIFICATION
COMBUSTION FLUE
AIR GAS
CONPRESSED
PRODUCT GAS
CARBON DIOXIDE
• AND OTHER
ACIDIC INPURITIES
•STEAN
FIGURE 6.8. UNtON CARBIDES' AGGLOMERATED ASH PROCESS
-------
TABLE 6.8. ASH AGGl OPERATION
Facllty
Location
200 Ib/hr Process.
Development Unit
West Jefferson, 0
Owner(s)
or Contractor
Battelle (Funded by
OCR and AGA)
(Patent for the
process is held by
Union Carbide.)
Status/Operating History
tnder construction. Estimate completion in first quarter of
1975.
Earlier studies included bench-scale studies of both the coal
burner and the gasifier. Erosion by fly ash from the burner
at simulated turbine conditions was also investigated.
The Process Development Unit will not include systems for gas
purification, shift conversion or methanation.
NJ
VD
(Contact; W. M. Goldberger, Battelle Columbus Labs.. (614) 299-3151)
(1) Corder, W. C., Batchelder, H. R., and W. M. Goldberger, "The Union Carbide/Battelle Coal Gasification Process
Development Unit Design", Presented at the Fifth Synthetic Pipeline Gas Symposium, Chicago (Oct. 1973).
(2) "Evaluation of Coal-Gasification Technology, Part IT, Low- arul Intermediate- Btu Fuel Gas", Report by National Research
Council, National Academy of Engineering (1973). ,Q,,%
(3) Goodridge, E., "Status Report: The AGA/OCR Coal Gasification Program", Coal Age 78, 54-59 (January 1973).
-------
6-30
6.9 The Kellogg Molten Salt Process (M. W. Kellogg Co.)
Description of the Process. The primary gasifier system is
described in Section 5.7.2. After the gas leaving the gasifier is pro-
cessed to recover heat and entrained salt, it is passed through a shift
converter to increase the ratio of hydrogen to carbon monoxide. It is
subsequently purified and catalytically methanated.
C0
COAU—*
PREHEATED
STEAH AND
OXT6EN
HEAT RECOVERY
AND REMOVAL
OF ENTRAINED
SALT
PURIFICATION
i
• METHANATION
PIPELINE
GAS
FIGURE 6.9. KELLOGG MOLTEN SALT PROCESS
(2)
-------
TABLE 6.9. KELLOGG MOLTON SALT: STATE OF THE ART
Factlty
References:
(1) Cover, A. E. an
from Coal, Okla
(2) Cover, A. E., S
Institute of Ga
(3) Evaluation of C
Council, Nation
Location
Owner(s)
or Contractor
M.W. Kellogg Compaq
Status/Operating History
Uench scale studies only. The molten salt creates serious corro-
sion problems, but these have been solved by use of an aluminum
c-xide refractory, Monofrax A. Report no corrosion after
('00-700 hrs continuous operation.
A process development unit is planned. Preliminary flow sheets
and cost estimates have been made. Seeking support.
OJ
(Contact: A. E. Cover, M. W. Kellogg Company, Houston, Texas, (713) 626-5600).
Schreiner, W. C., The Kellogg Molten Salt Process, Presented at the 4th Conference on Synthetic Fuels
, Stillwater, Oklahoma ('1974).
Skaperdas, G. T., The Kellogg Coal Gasification Process: Single Vessel Operation,
n on Clean Fuels fronj Coal, po 273-284, Chicago (1973).
oma State University
hreiner, W. C., and
Technology Symposiu... _..
al-Gasification Technology, Part I, Pipeline-Quality Gas, National Research
1 Academy of Sciences, Washington, D.C. (|l')73).
-------
6-32
6.10 Atgas Process (Applied Technology Corp.)
The primary gasification is essentially the same as that described
earlier in Section 5.7.1 for production of internediate-Btu gas in a molten
iron bath. The intermediate Btu gas is upgraded by the water-gas shift
reaction followed by purification and catalytic methanation.
CO,
COAL-
p
HEAT
RECOVERY
ADD REMOVAL
OF DUST
15 psla .
COMPRESSION
600 psl^
SHIFT
STEAM
OFF-GAS
/ \
SLAG
HOLTON IRON
OXYGEN
OESULFURIZEO SLAG
OESULFURIZATION
II
ASH SULFUR
t
PURIFICATION
PIPELINE
GAS
FIGURE 6.10. ATGAS PROCESS^1)
-------
TABLE 6.10. MOLTEN IRON: STATE 0? THE ART
Facllty
Location
(Contact: Ronald
Owner(s)
or Contractor
Applied Technology
Corp.
J. McGarvey, Appllec
Status/Operating History
I'n-piLot stage. Studies have involved a 25 inch I.D. induction
furnace (4000 Ib capacity) to simulate the gasifier, and using
air to produce low-Btu fuel gas. The off gas handling system
was equipped to permit continuous analysis for 502, N02» N0»
H2» ^2» ^°2 an<* CO. Expendable, non-cooled ceramic lances were
used for injection. Results indicate a boiler feed gas with
less than 50 ppm S02 can be generated from high-S coal
(3.5 percent) (1)
LO
UJ
Technology Corp., Pittsburgh, Pa (412) 782-0682)
References:
(1) LaRosa, Paul an
Symposium on Cl
(2) "Evaluation of '
National Academ
(3) "Clean Energy f
Washington, D.C
McGarvey, Ronald J.
an Fuels, pp 285-300
oal Gasification Tec
of Engineers,
om Coal: A National
(1973).
, "Fuel Gas from Molten Iron Coal Gasification", Institute of Gas Technology
0, Chicago (1973).
inology, Part I, Pipeline-Quality Gas, National Research Council,
Washington, D.C. (1973). I
Priority", 1973 Annual Report (for Calendar Year 1972) Office of Coal Research,
-------
6-34
6.11 Garrett Flash Pyrolysis (Garrett Research and Development)
Description of the Process. The primary gasification process
is described in Section 5.5.4. The raw pyrolysis gas (600 to 650 Btu/SCF)
is separated from char in a series of cyclones and is upgraded to pipeline
quality by shift conversion, purification and catalytic methanation. The
process produces about 8,500 SCF/ton of coal (for pyrolysis at 1700 F).
AIR
i
COMBUSTION
GAS
CYCLONES
COAL
FEED
CHAR
BURNER
ENTRAINED FLOW
REACTOR
PYROLYSIS GAS
O
PIPELINE
GAS
GAS
PROCESSING
CYCLONES
0
CHAR
PRODUCT
FIGURE 6.11. GARRETT FLASH PYROLYSIS PROCESS
(2)
-------
TABLE 6.11. GARRETT FLASH PYROLYSIS
Facilty
10 Ton/hr Pilot
References :
(1) McMath, H. G.,
Process", Pres
Location
LaVerne, Ca.
(Contact: D. E.
Lumkin, R. E., and S
ited at the 66th Ann
Owner (s)
or Contractor
Garrett Research and
Development
(research subsidiar
of Occidental
Petroleum)
Adams, Garrett Resean
iss, A., "Production
lal Meeting AICHE Phi
Status/Operating History
Proposed. Seeking support. A bench scale pyrolysis unit
(50 Ib/hr) has been in operation since Jan. 1973 (2).
Process", Pres hted at the bbth Annual neecing AU-HE, mi, . .
(2) McMath, H. G., Lumkln, R. E., Longanbach, J. R., and Sass, A., "A Pyrolysis Reactor for Coal Gasification , Chemical
Engineering Progress, Vol. 70, No. 6, pp 72-3 (June 1974).
(3) Adams, D. E., Sack S., and Sass, A., "Coal Gasification by Pyrolysis , ibid pp 74-75.
(4) Adans, D. E., Sack S., and Sass, A., "The Garret Pyrolysi* Process", presented at the 66th Annual Meeting AICHE,
Philadelphia, Pa. (November 15, 1973).
-------
6-36
6.12 Cogas (Cogas Development Company)
Description of the Process. A brief description of the gasifi-
cation process based on the limited information available is given in
Section 5.3.6.
The raw gas from the gasifier is converted to SNG by shift-
conversion, purification and catalytic methanation. Since the gasification
is carried out at low pressures, the gas must be compressed to meet pipeline
specification.
CLEAN
WATER
WASTE
DISPOSAL
ISOUR
WATER
COAL J COAL
25.000 1 PREPARATION
T/SO
MAL^
•— *l
PYROLYSIS +
'RODUCT RECOVERY
0!L
HYDHOTREATING
1
\~
S_T£
i-*
H i
ASH
DISPOSAL
AN
1
ASH
r
GASIFICATION
>
AIR
!:AS
SHIFT
CONVERSION
••inin«L»
.... lyyftmi
SY!f
CAS
PYROLYSSS CAS 1
' KOOCEN
1
SYNT
GAS
!
1
KESISI
HYC80CER
PRODUCTiO-'J
SULFUR ^SULFUR
.._ .«. Pl*«T
COfHjS
THESIS^ CAS
I FURIFICATIOH
i I
CO-
OFF- CAS I
<
PURIFIED
CAS
tfETHANE
SYNTHESIS
i*H& -1- COMPRESSION
PIPELINE C*S
*250 HHSCF.
CRUDE OIL
27,000 6/'
FIGURE 6.12. A COGAS PROCESS DIAGRAM
-------
TABLE 6.12. COGAS: STATE OF THE ART
Facilty
100 Ton/day Pilot
5 Ton/day Pilot
Location
Leatherhead, Englanc
Plalnsboro, N.J.
Owner(s)
or Contractor
Status/Operating History
Operational since March 1974. Mechanical problems were few
and were overcome with relative ease. Past several months
have been devoted to proving process operability.
Operational since late spring of 1974. No information available.
Operated for Cogas
Development Co.
by the British
Coal Utilization
Board
Cogas Development
Co. (a consortium
of FMC Corp.,
Consolidated Nature
Gas, Panhandle
Eastern Pipeline,
Republic Steel,
Rocky Mountain
Energy and Tenn.
Gas Transmission
Co.)
(Contact: Howard Mtlakoff (General Manager), Cogas Development Co., Princeton, N. J. (609) 452-2300
References;
(1) Dierdorff, L.
at
(2) Perry, Harry,
Jr., and Bloom, R.
HJ , xi..,
the West Coast Meeting of the Sot
"Coal Conversion Techr
, Jr., "The COGAS Prt
iety of Automotive Ei
ology", Chemical Engi
ject - One Method of Coal to Gas Conversion", paper presented
gineers, Portland, Oregon (August 20-23, 1973).
neering, pp 88-102 (July 22, 1974).
-------
6-38
Supplemental Bibliography for Coal Gasificationd)
(1) Hottel, H. C. and Howard, J. B., New Energy Technology. Some Facts
and Assessments. Cambridge, Mass., MIT Press (1971).
(2) Von Fredersdorff, C. G., Elliot, M. A., "Coal Gasification" in
Chemistry of Coal Utilization. H. H. Lowey, Editor, Supplementary
Vol., John Wiley and Sons, Inc., New York, pp 892-1022 (1963).
(3) The Supply-Technical Advisory Task Force - Synthetic Gas-Coal, pre-
pared by Synthetic Gas-Coal Task Force for the Federal Power Commission
(April 1973).
(4) Bituminous Coal Research, Inc., "Gas Generator Research and Develop-
ment Survey and Evaluation-Phase One", R&D Report No. 20, Interim
Report No. 1, U.S. Dept. of Interior, Office of Coal Research,
Washington, D.C. (August 1965).
(5) Waterman, W. W., "Summary Presentation of an Overview of Coal Conver-
sion Technology", IGT Symposium on Clean Fuels from Coal, pp 673-682,
Chicago (1973).
(6) "Report to Project Independence Blueprint, Federal Energy Agency",
Prepared by the Interagency Synthetic Fuels Task Force, Supplement 1
(July 8, 1974).
(7) "Evaluation of Coal Gasification Technology. Part I. Pipeline Quality
Gas", National Research Council, National
Academy of Engineering, Washington, D.C. (1973).
(8) "Evaluation of Coal Gasification Technologies, Part II, Low- and
Intermediate-Btu Fuel Gases", National Research Council, National
Academy of Engineering, Washington, D.C. (1973).
(9) Bodle, W. W., Vyas, K. C., "Clean Fuels from Coal-Introduction to
Modern Processes", IGT Symposium on Clean Fuels from Coal, pp 49-91
Chicago (1973).
(10) Wen, C. Y., Editor, "Optimization of Coal Gasification Processes",
R&D Report No. 66, Interim Rep rt No. 1, U.S. Dept. of Interior,
Office of Coal Research, Washington, D.C. (1972).
(11) Connor, Jack G., "Coal Gasification: A Review of Status and Technology",
paper presented to AAAS National Meeting, San Francisco (Feb. 26, 1974).
(1) References to specific processes appear in the individual sections of
Sections 5 and 6.
-------
6-39
(12) Wen, C. Y., Li, C. T., Tscheng, S. H. and O'Brien, W. S., "Comparison
of Alternative Coal-Gasification Processes for Pipeline Gas Produc-
tion", Energy Sources, 1(1), 31 (1973).
(13) Perry, Harry, "Coal Conversion Technology", Chemical Engineering,
pp 88-102 (July 22, 1974).
(14) Chopey, Nicholas P., "Gas-from-Coal: An Update", Chemical Engineering,
pp 70-73 (March 4, 1974).
(15) Anon, "New Processes Brighten Prospects of Synthetic Fuels from Coal",
Engineering and Mining Journal, Vol 75, No. 175, pp 91-97 (April 1974).
(16) Hale, Dean, "Coal Gasification Takes on a New Look", Pipeline and
Gas Journal, pp 23-26 (March 1974).
(17) "Coal Gasification--The Future Fuel Source", Gas Turbine International,
pp 19-24 (May-June 1974). (Excerpted from Office of Coal Research
1973-1974 Annual Report.)
(18) Levene, Harold D., "Gasification or Liquifaction: Where We Stand",
Coal Mining and Processing, pp 43-48 (January 1974).
(19) Goodridge, Edward, "Status Report: The AGA/OCR Coal Gasification
Programs", Coal Age, pp 54-59 (January 1973).
(20) Qader, S. A., "Low-Btu Gas Production from Coal", Intermet Bulletin,
4(3), 36-42 (1974).
(21) Quader, S. A., "SNG Production", Intermet Bulletin, .2(3), 34-38 (1973).
(22) Huebler, Jack, "Coal Gasification: State of the Art", Heating/Piping/
Air Conditioning, 45(1), 149-155 (1973).
(23) Seigel, H. M. and Kalina, T., "Coal-Gasification Costs May lower",
The Oil and Gas Journal, pp 87-94 (February 12, 1973).
(24) Mehta, D. C. and Crynes, B. L., "How Coal-Gasification Commonbase
Costs Compare", The Oil and Gas Journal, pp 68-71 (February 5, 1973).
(25) Agosta, J., et. al., "Status of Low-Btu Gas as a Stragety for Power
Station Emission Control", AICHE 65th Annual Meeting, New York
(November 1972).
(26) Agosta, J., et.al., "The Future of Low-Btu Gas in Power Generation",
Proceedings of the American Power Conference, 35 510-22 (1973).
(27) Ball, D., Smithson, G., Engdahl, R. , and Putnam, A., "Study of Potential
Problems and Optimum Opportunities in Retrofitting Industrial
Processes to Low- and Intermediate- Energy Gas from Coal", Prepared
by Battelle-Columbus Laboratories for Office of Research and Develop-
ment, U.S. EPA, Washington, D.C. (May 1974).
-------
6-40
(28) Magee, E. M., Jahnig, C. E., and Shaw, H., "Evaluation of Pollution
Control in Fossil Fuel Conversion Processes", Prepared by Esso
Research and Engineering Company for Office of Research and Develop-
ment, U.S. Environmental Protection Agency, Washington, D.C. (January
1974).
(29) Ashworth, R. A., and Hsieh, B. C., "Low Btu Gasification of Coal:
Who Needs it and How Can It be Improved?", presented at the EPA
Symposium on Environmental Aspects of Fuel Conversion Technology,
St. Louis (May 13-16, 1974).
(30) Rubin, E. S. and MCMichael, "Some Implications of Environmental
Regulating Activities on Coal Conversion Processes", ibid.
(31) "Environemntal Considerations in Future Energy Growth", Volume 1,
Report prepared by Battelle Memorial Institute for the Office of
Research and Development, EPA (April 1973).
(32) Forney, A. J., et.al., "Analyses of Tars, Chars, Gases and Water
Found in Effluents from the Synthane Process", U.S. Bureau of Mines,
Technical Progress Report 76 (January 1974).
(33) "U.S. Energy Outlook: Coal Availability", A Report by the Coal Task
Group, National Petroleum Council (1973).
(34) "Project Independence: An Economic Evaluation", MIT Energy Laboratory,
Printed in Techn< !ogy Review, pp 26-58 (May 1974).
(35) Siegel, Howard M., "The Cost and Commercialization of Gas and Liquids
from Coal", IGT Symposium on Clean Fuels from Coal, pp 653-661,
Chicago (1973).
(36) Siegel, H. M. and Kalina, T., "Technology and Cost of Coal Gasifica-
tion", Mechanical Engineering, pp 23-28 (May 1973).
(37) Moe, J. M., "SNG From Coal via the Lurgi Process", IGT Symposium on
Clean Fuels from Coal, pp 91-105, Chicago (1973).
(38) "Development of Information for Standards of Performance for the
Fossil Fuel Conversion Industry", prepared for Industrial Studies
Branch, EPA, by Battelle, Columbus Laboratories (June 21, 1974).
(39) Anon, "Expert Examines Materials Problems", Chemical Engineering,
pp 58-59 (July 22, 1974).
(40) "Gas Industry Research Plan: 1974-2000", American Gas Association
(January 1974).
(41) Robson, F. L., "Fuel Gasification and Advanced Power Cycles- A Route
to Clean Power", presented at the Third International Conference
on Fluidized Bed Combustion, Vol. 11, pp 205-225 (December 1973).
-------
6-41
(42) Matthews, C. W., "A Design Basis for Utility Gas from Coal", ibid,
pp 229-245.
(43) Crouch, W. B., et al., "Recent Experimental Results on Gasification
Combustion of Low-Btu Gas for Gas Turbines", Combustion, pp 38
(April 1974).
(44) A. D. Little, Inc., "A Current Appraisal of Underground Coal Gasifi-
cation", U.S. Dept. of the Interior, Bureau of Mines, Washington,
D.C. PB 209 274, NTIS, Springfield, Va., 280 p (April 1972).
(45) Nadkarni, R. M., Bliss, C. and Watson, W. I., "Underground Gasifica-
tion of Coal", Institute of Gas Technology Symposium on Clean Fuels
from Coal, Chicago, pp 611-637 (1973).
(46) Schrider, L. A., and Pasini, J., Underground Gasification of Coal --
Pilot Test, Hanna, Wyoming, presented at the AGA Fifth Synthetic
Pipeline Gas Symposium (October 1973).
(47) Linden, Henry R. , "The Role of SNG in the U.S. Energy Balance",
presented at the IGT Symposium on SNG from Hydrocarbon Liquids,
pp 55-76 (March 1973).
-------
SECTION 7
FLUIDIZED BED COMBUSTION
7,1 Atmospheric Fluidized-Bed Combustion
Description of the Process. The combustion of solid fuels takes
place in a fluidized-bed of limestone (or dolomite), solid fuel and ash
at 2-15 ft/sec and temperatures of 1400-1800 F. About 50 percent of the
combustion heat can be removed by the immersed heat transfer tubes and the
surrounding water walls. The high heat transfer rate in the fluidized bed
2 2
(50 Btu/hr ft F as compared to 10-15 Btu/hr ft F in conventional boilers)
3
resulted in a high volumetric heat release rate of 5,000,000 Btu/hr ft in
3
the combustion space as compared to 20,000 Btu/hr ft in a pulverized-coal-
fired boiler. This feature makes the fluidized bed boiler compact enough
to allow complete or partial shop fabrication of the boiler, thus reducing
significantly the capital investment.
Since the fluidized-bed boiler is operated at 1400-1800 F, the
S0_ released during the combustion by the high sulfur fuel can be ideally
absorbed by the limestone or dolomite present in the bed. To reduce the
solid waste disposal burden, the spent limestone may be regenerated at
slightly reducing conditions at high temperatures (2000 F). To increase
the overall combustion efficiency, the elutriated carbon would be combusted
in a separate combustor at a much higher temperature (2000 F) (Carbon Burn-
up Cell). The bench and pilot data indicate that N0x emission is low and
on the order of 260 ppm. Over 90 percent S02 removal and an overall com-
bustion efficiency of over 98 percent can be achieved.
The conceptual design of modular boiler concepts of single bed
level and packed bed configuration has been studied for utility and
industrial applications. A schematic diagram of an atmospheric pressure
fluidized bed combustion power plant is shown in Figure 7.1.
7-1
-------
7-2
PARTICULATE
EVAPORATOR
SUPERHEATER
EVAPORATOR
Mm ^^^*c jr
X&
FORCE DRAFT
FAN
<
4
1
r-r—
LIME
REMOVAL-^
1
r
COAL
\
^
•>•
V
1
V
1
INDUttU UKAf 1 hAN— ,
ECONOMIZER-, 1
^V1
1
I J
Y
< I
SORBENT
REGULATOR
-Sulfote — Ash —
RE HEATER
STEAM^
TURBINE
i
i
i
i
i
\
i
V
inn
Uu
FEED WATER PUMP
ft-
STACK
SULFUR
RECOVERY
UNIT
1
Y
t
SULFUR OR
SULFUR 1C
ACID
FIGURE 7.1. ATMOSPHERIC FLUIDIZED-BED COMPUSTION POWER PLANT
-------
TABLE 7.1. ATMOSPHERIC FLUIDIZED-BED COMBUSTION STATE OF THE ART
Facilty
1. C.R.E. Pilot Com-
bustor (31 x 3',
1 MW)
2. BCURA Pilot Com-
bustor (27" dia)
3. PER Pilot Com-
bustor (12" x
16", 20" x 6')
4. ANL Bench Cora-
bustor (6")
5. B.M. Pilot Com-
bustor (18")
6. Foster-Wheeler
Cold Unit (6'x6')
7. 30 MW Multicell
Fluidized-Bed
Boiler
Location
Cheltenham, U.K.
Leatherhead, U.K.
Alexandria,
Virginia
Chicago, Illinois
Morgantown, West
Virginia
Livingston, New
Jersey
Rivesville, West
Virginia
Owner(s)
or Contractor
National Coal Board-
Coal Research Esta-
blishment
BCURA Limited
Pope, Evans &
Robbins (Funded by
OCR & EPA)
Argonne National
Laboratories (EPA)
Bureau of Mines
(EPA-BM)
Foster-Wheeler Co.
(OCR)
Pope, Evans &
Robbins (OCR)
Status/Operating History
- Bench scale work since 1963, pilot unit in operation since 1970,
development work aimed at utility and large-scale boiler appli-
cation ( 2fps), conceptual design studied by Babcock & Wilcox
Ltd., Preece, Caradew, and Rider Ltd.
- Research began In 1964, pilot unit in operation since 1966,
development effort aimed at small industrial application (10 -
14 fps), conceptual design studied by John Thompson Ltd.
- Bench & pilot work since 1965, aimed at development of packaged
coal burned boiler, the pollution control studies were
supported by EPA
- Pilot data have demonstrated 3-cell concept: boiler (1400 -
1800 F, 37. excess air), carbon burn-up cell (2000 F, >3% excess
air), and regenerator (>1850 F, <.5% excess air). All operated
at 6-14 fps
- In operation 68-72, fundamental combustion studies
- In operation 68-72, studies on heat transfer, coal, and boiler
tubes
- Studies on coal feeding and tube bank design
- Boiler dimension = 12' x 38' r 25'
- Construction in progress since 1974, to be completed in 1976
- Plant cost is estimated at $11.0 x 10 with annual operating
cost at $1.5 x 106
- To demonstrate the operability and reliability of a large
fluidized-bed combustion system.
i
CO
Contact: J. W. Bishop, Pope, Evans & Robbins, Inc. 320 King Street, Alexandria, Virginia 22314.
-------
7-4
TABLE 7.1. (Continued)
References:
(1) N.C.B. Final report to EPA, "Reduction of Atmospheric Pollution",
Vol. I, II, III, (1971).
(2) Skinner, D. G., "The Fluidized-Bed Combustion of Coal", Mills & Boon
Limited, (1971).
(3) The 2nd and 3rd International Conference on Fluidi^ed-Bed Combustion
Syposium at Hueston Woods, Ohio (1968, 1970).
(4) Jonke, A. A., et al., ANL Report to EPA, ANL/ES-CEN-1004 (1971).
(5) Robison, E. B., et al., PER reports to OCR and EPA (1972, 1970).
(6) Annual Report 1973-74 of Coal Technology (Key to Clean Energy), OCR,
U.S. Department of the Interior, Washington, D.C. (1974).
-------
7-5
7.2. Pressurized Fluldized-Bed Combustion
Description of the Process. The combustion system is similar
to atmospheric fluidized-bed combustion except that it operates at 10 atm
pressure. The pressure operation reduces the boiler size significantly.
To increase the heat transfer surface, deep bed combustion with immersed
tube banks are proposed. High temperature compressed air is directed to
a gas turbine to recover the heat energy. This operation also serves to
reduce the heat transfer surface requirement.
In the pressurized combustion, a much lovar NO emission (150
X
ppm) has been demonstrated. Over 99 percent combustion efficiency and
sulfur removal has been established by BCURA experiments at low bed veloc-
ities (2 ft/sec) and with a Ca/S ratio of 1.6.
The prospect of reduced corrosion and erosion to the steam
tubes at low fluidized combustion temperatures provides a potential of
advanced steam condition. The gas turbine inlet temperature may also be
increased. Therefore, a thermal efficiency up to 47 percent is feasible
for a pressure fluidized-bed combustion combined cycle plant, which may
be compared with 35 to 38 percent achieved by conventional steam-electric
power plants.
The critical elements to the pressurized combustion at the present
development stage is the demonstration of effective hot gas clean-up, thus,
a reasonable turbine blade life may be expected, and the demonstration of
deep bed combustion of immersed steam tubes.
A schematic diagram of a pressurized fluidized-bed combustion
power plant is shown in Figure 7.20
-------
7-6
Cyclone
•0-
j C
Lime
Coal
Sor bent
Regenerator
Sulfate. Ash
Sulfur or
Sulfuric Acid
Cleaned
Combustion
Gas
FIGURE 7.2. PRESSURIZED FLUIDIZED-BED COMBUSTION POWER PLANT
-------
TABLE 7.2. PRESSURIZED FLUllHZED-UED COMBUSTION STATE OF THE ART
Facilty
1. BCURA Pilot Cqm-
bus t oxr (A 8" x
24"^
£H /
2. ANL Bench Com-
bustor (6" diam)
3 . ESSO Bench Corn-
bus tor (3" diam)
4. ESSO Minplant
. (12.5" dia«v.65
MW)
5. CPU -400 Pilot
Plant Unit (71
dia. 4atm, ~1.8
MUM
1 iw y
Location
Leatherhead, U.K.
Chicago, Illinois
Linden, New Jersey
Linden, New Jersey
Menlo Park,
California
Owner (s)
or Contractor
BCURA Limited
Argonne National
Laboratories (EPA)
EXXON Rd.E. (EPA)
EXXON Rd.E. (EPA)
Combustion Power
Company
Status/Operating History
- In operation since 1969, designed at 6 atm
- Excellent combustion efficiency and SOo and NOX control have
been demonstrated at low gas velocity (2 fps) and temperatures
1470-1750 F (Work 'jointly supported by NCB-EPA and NCB-OCR)
- At low temperature (< 1600 F), there was no significant
deposition on turbine blade cascade, but sufficiently extensive
at bed temperature of 1750 that constant blade cleaning is
required for continuous operation
- Extensive fundamental data have been generated
- Proposed one-stage and two-stage regeneration schemes were
proved not feasible
- Combustion and regeneration study since 1968
- In operation at present without regeneration unit
- Unit designed at 10 atm
- Recent data appears to indicate that quality of fluidization
needs to be improved
- A turbine blade cascade is being designed by Westinghouse and
to be added to the Miniplant
- Deep bed combustion with ir^r-ersed tube bank and effective
hot gas clean-up needs to be demonstrated
- Originally designed for refuse burning, without immersed tube
bank, the modification has been made to burn coal (funded by OCR
- The granular filter for hot gas clean-up is to be installed for
later refuse and coal tests.
Contacts: Hoke, R. EXXON Rd.E., Linden, New Jersey and Furlong, D. L., Combustion Power Company, Menlo Park, California.
-------
7-8
TABLE 7.2. (Continued)
References:
(1) Skinner, D. G., "The Fluidized-Bed Combustion of Coal", Mills
and Boon Limited (1971).
(2) Jonke, A. A., et al, "Reduction of Atmospheric Pollution by the Appli-
cation of Fluidized-Bed Combustion", Annual Report (1974).
(3) BCURA, "Pressurized Fluidized-Bed Combustion", Report to OCR (1973).
(4) Molen, R. H. V., "Operational Experience with the CPU-400 Pilot
Plant", Paper presented at 78th AIChE National Meeting, Salt Lake
City, Utah (1974).
-------
7-9
7.3. Ignifluid Combustion
Description of the Process. The Ignifluid process was invented
by A. A. Godel in the late 40's and later developed by Societe Anonyme
Activit and Babcock-Atlantique in the 1950's. A conventional stoker is modified
to create a fluidized bed on the grate. The fluidized bed is operated between
1000 and 1200 C to agglomerate coal ash which is carried out of the bed on
the moving grate. Partial combustion occurs in the bed and secondary air
(^50 percent) is supplied above the bed to complete the combustion. The
system offers low particulate emission as more than 50 percent of coal ash
is removed as clinker from the grate. However, the Ignifluid process is
deprived of the S00 and NO., control potential, which is favored at much
^ x
lower combustion temperatures.
There are four Ignifluid boiler plants in operation. A typical
Ignifluid utility boiler is shown in Figure 7.3.
-------
7-10
FIGURE 7.3. IGNIFLUID UTILITY BOILER
-------
TABLE 7.3. IGNIFLUID COMBUSTION STATE OF THE ART
Facilty
Semi-Industrial •
Ignifluid plant
Ignifluld Boiler
Plants
Location
Vernon, France
La Taupe
Solvay
Casablanca
La Rochette
Owner (s)
or Contractor
Societe Anonyme
Activit/Babcock-
Atlantique
Babcock-Atlant ique
Babcock-Atlantique
Babcock-Atlant ique
Babcock-Atlantique
Status/Operating History
- Combustion test began in 1953
- Commercial operation since early 1960's, 4 Ignifluid boiler .
plants in operation, and proposals have been made to build a
250 MW power plant in Europe and large scales in the United
States
- S02 and NOX control needs further development
- 77,000 Ib/hr steam output since 1969
- 110,000 Ib/hr steam output since 1970
- 254,000 Ib/hr steam output since 1967
- 110,000 Ib/hr steam output since 1961 •
(Contact: Godel A. A. Societe Anonyme Activit, 66 Rue d'Auteuil, Paris, XVIe, France)
References:
(1) Godel A. A. d Cosar P. "The Scale-up of a Fluidized-Bed Combustion System to Utility Boilers", AIChE
Symposium Seriea, No. 116, Vol. 67, (1971).
(2) Svoboda J. J., "Ignifluid Contribution to Air Pollution Control", The 2nd International Conference on
Fluidized-Bed Combustion, Hueston Woods, Ohio, (1968).
-------
7-12
7.4. Two-Stage Fluldized Combustion
Description of the Process. This two-stage fluidized combustion
concept has been developed in the Fuel Research Institute, Czechoslovakia,
since 1952. Combustion of solid fuel with ash content as high as 75 percent
without clinker formation is carried out in the first stage fluidized
combustor at temperatures below 1000 C. Unburned combustion gas and
particles from the first stage are burned in a second combustion space
(such as cyclone furnace) at higher temperatures from 1000 to 1200 C.
There is no need for immersing heat transfer tubes in the fluidized
combustor to recover heat for burning low grade fuels. It is demonstrated
that the combustion efficiency improves as the ash content of the fuel
increases, a unique feature of this combustion process. It was also
demonstrated that the fluidized furnace can burn solid and liquid fuels
with 100 percent interchangeability, semioperational and operation boilers,
and retrofit of old boilers up to 25 MW were demonstrated.
-------
TABLE 7.4. TWO-STAGE FLUIDIZED COMBUSTION STATE OF THE ART
Factlty
Fluidized Furnace
lab scale
Semi-operational and
operational
(Dukafluid)
Retrofit
Location
Prague,
Czechoslovakia
Owner(s)
or Contractor
Fuel Research
Institute
CKD DUKA
Status/Operating History
Research work on the fluidized-bed combustion of solid fuels
has been done since 1952
Fundamental laboratory investigation of small furnaces was
conducted in 1958 and 1959
Two stage combustion of low grade fuel with ash content up to
75 percent, with the first stage at fluidized bed combustion
at temperatures less than 1000 C and the second stage (such
as cyclone furnaces) at temperatures from 1000 to 1200 C
Semioperational fluidized furnaces with capacity of 4 t/hr
and 14 t/hr in operation in 1960 and 1961
Investigation extended to fluid fuels in 1967-1970 and solid
and liquid fuels with 100 percent interchangeability was
demonstrated.
Fluidized furnace retrofitted to an old power plant of 125 t/hr
capacity (1971)
(Contact: Pavel Novotny, The Fuel Research Institute, Be'chovice, Czechoslovakia)
References:
(1) Pavel Novotny, Sb. Prednasek 50 (Padesatemu) Xyrocf Ustavu Xyzk. Xyuziti, Paliv, 1972.
(2) Pavel Novotny, Technical Digest I, 1968.
-------
SECTION 8
STACK GAS SCRUBBING
Introduction
The removal of S02 from stack gases has been the object of
extensive research and development over the past several years. More than
50 individual processes can be identified which are technically feasible
in that they have demonstrated ability to remove SO- from gas streams.
The state of development of these processes varies from bench scale through
commercial scale demonstration. Removal processes for SO- may be divided
into two basic types: throwaway systems in which the SO^ is converted to
a product intended for discard as a solid waste, and recovery systems in
which the SO- is converted to a useful product. Of the many possible
systems, only a few are sufficiently developed for inclusion in this report.
They are:
Throwaway Systems
Limestone injection
Limestone scrubbing
Lime scrubbing
Double alkali
Recovery Processes
Wellman-Lord
Catalytic oxidation
Magnesium oxide
Chiyoda
Citrate.
Each of these processes is described briefly in the following pages and
a summary of the status of operation units is given. Projected start-up
dates for units under construction also are included for each type of
process.
8-1
-------
8-2
Status of the Technology
Although the technology for removal of SO. from stack gases has
been successfully demonstrated for some time, the reduction of the
technology to sound engineering practice and widespread acceptance has
been slow. This is particularly true from the standpoint of high system
reliability which is required for utility application. As experience is
accumulated and obvious problems addressed and solved, the availability
of the scrubber to the boiler has increased significantly for a number of
the test units. Acceptance of S02 removal technology is also increasing
and the number of units in operation or under construction has increased
during the past year. A summary of the installed capacity of units
described in this report is given in Table 8.0. There are 15 operational
units with a total installed capacity of 2720 MW, with an additional 13
units of 5000 MW capacity under construction. At this stage in the
development and application of stack gas scrubbing, there is a heavy
dependence on throwaway-type systems. Of the total installed capacity
of operational systems, 83 percent is of the throwaway type, while
97 percent of the capacity under construction is throwaway. Since this
survey was completed, an EPA report became available entitled, "Flue Gas
Desulfurization, Installations and Operations", September 1974. According
to that report, the stress on throwaway systems extends to planned units
as well. Only 2 of 57 units, for which a process has been selected, are
planned to use a recovery-type system.
-------
8-3
TABLE 8.0. SUMMARY OF STACK GAS SCRUBBING FACILITIES
MW Capacity (Number of Units)
Process Operational Under Construction
Limestone injection
Limestone scrubbing
Lime scrubbing
Double alkali
Wellman-Lord
Catalytic oxidation
Magnesium oxide
Chiyoda
Citrate
785
1128
325
32
--
110
340
--
Pilot
(4)
(4)
(3)
(1)
(1)
(2)
Scale
2325 (6)
2510 (4)
25 (1)
115 (1)
--
--
25 (1)
Totals 2720 (15) 5000 (13)
-------
8-4
8.1 Throwaway Processes
8.1.1 Limestone or Lime Inlection
Limestone injection involves injection of powdered limestone in
the flue gas usually directly in the boiler along with the coal. The lime-
stone then is calcined to lime (CaO) which reacts with SCL in the gas stream
forming CaSCL which is removed with a wet scrubber. A schematic of simple
limestone injection excluding the wet scrubber is shown in Figure 8.1.1.
The first commercial application of this process was at Union
Electric's Meramec Station in St. Louis, Missouri, in 1968. The experiment
was terminated in 1971 due to the unusual susceptability of the Meramec
boilers to plugging in the convection passages. Other attempts at lime-
stone injection have been made at Kansas Power and Light's Lawrence Plant
and Kansas City Power and Light's Hawthorn plant. The Lawrence operation
has experienced severe plugging and scaling and may be converted to tail
end limestone scrubbing. The Hawthorn plant, after extensive modification,
has improved reliability considerably, though sufficient time has not
elapsed for realistic evaluation. In one of the two units at Hawthorn
limestone is injected downstream of the air heater. The process does operate
sufficiently well to permit these two Kansas utilities to meet environmental
regulations most of the time.
Limestone injection in general has not been successful enough to
warrant plans for future units. In general, the trend is away from lime-
stone injection and towards straight limestone scrubbing.
Lime injection has been tried on an 80 MW unit at the Alma Sta-
tave i
.(**)
(*)
tion of Dairyland Power Cooperative in 1971. Results, however, have not
been encouraging as S0« removal efficiency is only around 25 percent
* Statement of Dairyland Power Cooperative to the State of Wisconsin Depart-
ment of Natural Resources Public Hearing (July 8, 1972).
** Electrical Week, March 10, 1975.
-------
COAL
r-SUPPLY
\ LIMESTONE
1 SUPPLY
r*--\
I I
I I
«r ^w
±
A J
TL
MILL
FURNACE
AIR
HEATER
TO SCRUBBER
OR COLLECTORS
00
ASH
FIGURE 8.1.1. LIMESTONE INJECTION
-------
TABLE 8.1.1. LIMESTONE INJECTION
Facllty
Meramec
140 MW
Lawrence #4
125 MW
Lawrence #5
400 MW
Hawthorn #3 & #4
130 MW
Location
St. Louis, Missouri
Lawrence, Kansas
Lawrenee, Kansas
Hawthorn, Kansas
Owner(s)
or Contractor
Union Electric Co.,
Combustion
Engineering
Kansas Power &
Light & Combustion
Engineering
Kansas Power &
Light & Combustion
Engineering
Kansas City Power &
Light; Combustion
Engineering
Status/Operating History
Started up in September 1968. Unit experienced severe plugging
problems in the "boiler convection passages due in part to the
boiler design. Scaling and deposition in ID fans was also a
problem. Project was terminated in June 1971.
Started up in October 1968. Unit has experienced low S02
collection efficiency and severe scaling. Half of unit is
taken out of service nightly for cleaning. Unit may be con-
verted to straight tailend limestone scrubbing.
Started up in September 1971. Unit has experienced scaling in
the marble bed scrubber and plugging of the demister similar
to unit #4. Unit 5 may also be converted to straight tailend
limestone scrubbing.
Unit #3 started in November 1972, and Unit #4 in August 1972.
Both units were originally straight boiler injection of
limestone but Unit #4 was converted to inject limestone down-
stream of the air heater to prevent calcining. Both units
initially experienced severe plugging and scaling. After
many modifications reliability has been significantly improved,
but more time is necessary for a realistic evaluation.
oo
i
-------
8-7
8.1.2 Limestone Scrubbing
Limestone scrubbing is very similar to lime scrubbing except
the absorbent is CaCO instead of Ca(OH) . The advantage of limestone
scrubbing is that the calcining operation converting limestone into lime
can be avoided resulting in lower cost and energy consumption. Figure 8.1.2
gives a simplified process flow sheet for a typical limestone scrubbing
installation.
Limestone scrubbing installations, however, have initially
shown less success than lime scrubbing installations. The major problems
are scaling in the scrubber, plugging of the demister, and corrosion and
erosion of stack gas reheat tubes. The problem of scaling has been
especially troublesome in closed loop operation where the calcium level
reaches saturation and forms scale (CaSO,). In one case, Arizona Public
Service's Cholla plant, good operation has been achieved since
December 1973 The pond evaporation rate is high and a relatively large
fresh water make up rate is permitted minimizing problems with satura-
tion and scaling. On closed loop operation, where the evaporation rate is
much less, high reliability has not yet been established although con-
siderable progress is being made at Will County.
At least six new limestone scrubbing installations have been
planned,however, making it the most popular form of S02 removal in the
United States at the present time. Limestone scrubbing is a throwaway
process and sludge disposal may be a serious problem in many cases.
-------
To sludge
waste pond
400 gpm at
6.5 % solids
6000 gpm
Venturi
A 290,000cfm at 120 F
385,000 cfm II tl20 9Pm of evaporated water)
at350F II
Absorber
Sump
), 000 gpm
150 gpm
(demister
underwosh)
1
X-
Venturi
recircutotion
tank
.
fir
T T T
Absorber
recirculation
tank
, r
Venturi
pumps
Note: Flow rates are for
one module serving about
100 MW of boiler capacity.
130 gpm
at 20 % solids
From mill
system
00
oo
Absorber
pumps
Recycle and makeup water
(390 gpm plus pump gland losses)
FIGURE 8.1.2. LIMESTONE SCRUBBING PROCESS
-------
TABLE 8.1.2. LIMESTONE SCRUBBING PROCESS
Facilty
Will County
156 MW
Stock Island
37 MW (Oil)
La Cygne
820 MW
Cholla
115 MW
St. Clair
180MW
Mohave
160 MW
Widows Creek, 550MW
Sherburne County
2 units 680 MW each
Gibson
75 MW
Location
Joliet, Illinois
Key West, Fla.
La Cygne, Kansas
Joseph City, Ari.
East China Town-
ship, Michigan
Bullhead City,
Nevada
Stevenson, Ala.
Indiana
Owner(s)
or Contractor
Commonwealth Edison;
Babcock and Wilcox
City of Key West;
Zurn Industries
Kansas City Power
& Light; Babcock
& Wilcox
Arizona Public
Service; Research
Cottrell
Detroit Edison;
Peabody
Southern California
Gas & Electire,
Universal Oil Prod
TVA
Northern States
Power; Combustion
Engineering
Public Service of
Indiana; Combustion
Engineering.
Status/Operating History
Unit started up in February 1972. Major problem has been in
sludge disposal (sludge has characteristics of quicksand).
Other .problems have been in plugging of demisters and corrosion
of reheat tubes.
Startup in August 1973. System uses a sea water slurry of
native coral as the scrubbing medium. System has had minimal
operating experience due to problems in controlling the liquid
level in the scrubber. Sludge disposal on the small island is
also a problem.
Startup in February 1973. Seven module system with only two
modules completed thus far. System is similar to that of Will
County. Each of the seven scrubber modules is capable of being
isolated from the system for repair and full load can be
achieved on six modules. Unit has experienced problems with
nozzle pluggage. Due to combined problems with scrubber and
generating plant little operating data is available.
Started up in December 1973. Scrubber has operated well with
80 to 90 percent availability and greater than 90 percent
S02 removal. Low rainfall and high pond evaporation rates
minimize problems of closed loop operation, however. Some
problems have been experienced in corrosion of expansion joints
and flue gas reheater tubes.
Expected to startup in 1974. Uses Lurgi venturi scrubber
followed by tray tower.
Expected to start up in 1974.
Expected to start up in 1975.
1 unit expected to start up in 1976, the other in 1977.
Expected to start up in 1976.
oo
vo
-------
8-10
8.1.3 Lime Scrubbing
Lime scrubbing is a wet process for removing S0? from flue gas
using hydrated lime (Ca(OH)_) as the absorbent. The hydrated lime is
usually ground to a fine powder and introduced to a scrubber in a water
slurry where it reacts with S0? in the flue gas to form CaSO, and CaSO, .
These constituents are then precipitated and settled out of the liquid
slurry either in tanks or ponds and disposed of by landfill. A simple
schematic diagram is shown in Figure 8.1.3.
Of all flue gas desulfurization processes, lime scrubbing has
achieved the greatest success in this country thus far. This is due in
large part to the successful operation of Louisville Gas and Electric's
Paddy's Run station between April 1973 and December 1973. During this time
the unit achieved 90 percent availability with relatively few problems
using carbide sludge as the reactant. Carbide sludge is a waste product
of acetylene manufacture and is similar to hydrated lime though hydrated lime has
not been proven equivalent for scrubbing pruposes. The Paddy's Run station
has seen little operation recently due to the boiler heat rate being too high
for economical plant operation.
Two other attempts at lime scrubbing in the United States are
the Duquesne Light Phillips Station and the Southern California Edison
Mohave Station. Phillips has experienced problems with corrosion and
erosion including stack leakage and is currently being operated primarily
for particulate removal with 50 percent S0_ removal. Mohave is a recent
proprietary installation and only sketchy information is available.
There are currently four new sizable units planned for lime
scrubbing. Two are at Bruce Mansfield Station of Pennsylvania Power
Company and two at Conesville Station of Columbus and Southern Ohio
Edison. Two major problems with lime scrubbing are disposal of the waste
sludge (throwaway process) and the expense and energy necessary to make
lime from limestone.
-------
SCRUBBED
GAS
i
1
1
1
1
1
FLUE 1
GAS 1
BY-PASSl
I
1
FLUE !
GAS
FEED
Hrj
Ca(OH)2 — i
IT i
f-HMIXIN
j PNK
t
3CRUBBEI
I
3
1
*
*
SCRUBBER
EFFLUENT
i '
DELAY
TANK
i
POND
1
I
i
oo
FIGURE 8.1.3. LIME SCRUBBING
-------
TABLE 8.1.3. LIMB SCRUBBING
Facllty
Paddy's Run
65 MW
Phillips
180 MW unit
100 MW scrubber
Mohave
790 MW unit
160 MW scrubber
Bruce Mansfield
Units #1 & #2
Both units 880 MW
Conesville
2 units
375 MW each
Location
Louisville, Ky.
So. Heights, Pa.
Bullhead City,
Nevada
Shippingport, Pa.
Conesville, Ohio
Louisville Gas &
Electric; Combus-
tion Engineering
Duquesne Light;
Chemtco
Cvner(a)
or Contractor
Southern California
Edison; S teams-
Roger
Pennsylvania Power
Co. Chemico
Columbus & Southern
Ohio Electric Co.
Universal Oil
Products.
Status/Operating History
Started up in April 1973. System used carbide lime sludge
(similar to hydrated lime Ca(OH>2). Perhaps the most success-
ful S02 removal demonstration project in the U.S. to date.
From startup to December 1973, system demonstrated 90 percent
availability. System was shut down due to high heat rate and
uneconomical boiler operation and not because of scrubber
problems. System used a borrow pit for sludge disposal and natur
natural gas for stack gas reheat.
Started up In April 1973. First demonstration of use of hydrated
lime (Ca(OH)2> in the U.S. System was shut down in October
1973 due to leakage in the stack, corrosion in ID fans and
corrosion and erosion in scrubber. System was restarted for
flyash collection with reactant addition sufficient to prevent
corrosion and give over 50 percent S0£ removal.
Started up in January 1974. Scrubber is a unique horizontal type
with an electrostatic precipitator upstream for flyash removal.
Availability has been over 80 percent. Major problems have
been in corrosion and erosion of pumps. Unit has not used high
sulfur coal (coal sulfur is around 0.5 percent) and is in an
area where high pond evaporation occurs minimizing problems
of closed loop operation.
Unit #1 to start up in 1975. Unit #2 to start up in 1976.
Units to start up in 1976.
oo
i
ro
-------
5-13
8.1.4 Double Alkali
The double alkali processes involves the use of NaOH or an
ammonia salt as a primary absorbent for removing SCL from the flue gas
followed by reaction with lime or limestone to regenerate the primary ab-
sorbent and yield an insoluble waste product (CaSO.). A simplified
schematic diagram of the process is shown in Figure 8.1.4.
One of the main problems with the double alkali process is the
difficulty in regenerating Na.SO . The industrial boiler of the General
Motors Parma plant is currently the only commercial double alkali process
in operation and has experienced some difficulty with plugging in the
causticizer, but operation is improving with experience.
-------
FLUE
GAS
BY-PASS
FEED
Co(OH),
t
SCRUBBER
GAS
f
SCRUBBER
TL
SCRUBBER
EFFLUENT
1
1 -
MIXING
TANK
J
1
CAUS
SCRUBBER
FEED
THICKENER
WASH
WATER
VACUUM \ WASTE
FILTER JcALCIUM
SALTS
MAKE-UP
Na2C03
HOLDING
TANK
00
I
FIGURE 8.1.4. SODIUM SCRUBBING WITH LIME REGENERATION (Double Alkali)
-------
TABLE 8.1.4. DOUBLE ALKALI (SODIUM SCRUBBING-LIME REGENERATION)
Facllty
General Motors
32 MW (steam only)
Caterpillar Tractor
2 units ,
10 MW }steam
8 MW \ only
Caterpillar
Tractor
15 MW
8 MW
8 MW
steam
only
Gadsby Station
2500 cfm pilot
Scholz
25 MW
Location
Parma, Ohio
Joliet, Illinois
Mossville, 111.
Salt Lake City,
Utah
Sneads, Florida
Owner(s)
or Contractor
Argonaut Engr., Div.
of CMC; Combustion
Equipment Assoc.
Caterpillar Corp;
Zurn Industries
iaterpillar; Food
Machinery Company
Utah Power & Light;
Envirotech Corp.
Gulf Power Combus-
tion Equipment
Associates
Status/Operating History
Started up in April 1974. The first major problem has been
caking in the causticizer (see Figure 8.1.4). Insufficient
time has elapsed for effective evaluation.
Units due to start up in 1975.
Unit due to start up in 1975
Unit started up in early 1974. Uses NaOH to scrub flue gas
followed by CaO to regenerate the absorbent and yield an
insoluble waste product. Envirotech is offering system for
full scale application.
Anticipated startup is in 1975.
00
i
-------
8-16
8.2 Recovery Processes
8.2.1 Wellman Lord Process
The Wellman Lord Flue Gas desulfurization process is a wet
process using a concentrated caustic solution (sodium sulfite) as the
absorbent. In removing S0_ from the gas stream sodium sulfite is con-
verted to sodium bisulfite which is then disproportionated with heat
(steam) to regenerate sodium sulfite while forming a concentrated SCL
gas (90 percent S0_). The sodium sulfite is returned to the absorber
and the concentrated SO. stream can be processed to sulfurlc acid or
elemental sulfur by conventional means. S0_ removal efficiency of the
process is believed to be greater than 90 percent. The process is
handled by Davy Powergas of Lakeland, Florida. A schematic flow diagram
of the process is shown in Figure 8.2.1.
The first boiler application of the Wellman Lord process was on
the Japan Synthetic Rubber Chiba plant in 1971. The facility serves two
oil fired boilers with a capacity of 286,000 pounds of steam per hour
each. The first U.S. installation on flue gas, and first known installation
on coal will be the Northern Indiana Public Service Company's Mitchell
Station at Gary, Indiana.
There is concern that impurities in the coal ash could
accelerate the undesired formation of sodium sulfate when sodium sulfite
is oxidized. Sodium sulfate along with other impurities must be purged
from the scrubbing liquor with a bleed stream and represent a disposal
problem. At Chiba about 10 percent of the sodium content is lost on
each pass through the scrubber as a result of this purge. Flyash in the
regeneration loop also must be purged.
-------
SCRUBBED
GAS
FLUE I
GAS |
BY-PASS
FLUE
GAS
FEED
I
CAUSTIC
MAKE-UP
SCRUBBER
1
STEAM
EVAPORATOR
CRYSTALLIZER
CONDENSER
S02
CONDENSATE
SEPARA
TION
H20
. M.L. .--
RETURN[J
BLEED
SCRUBBER FEED
SULFURIC ACID
PLANT «
DISSOLVING
TANK
FIGURE 8.2.1. SODIUM SCRUBBING WITH SULFUR DIOXIDE RECOVERY (Wellman Lord)
-------
TABLE 8.2.1. WELLMAN LORD PROCESS
Facilty
Mitchell Station
Location
Gary, Indiana
Owner(s)
or Contractor
Northern Indiana
Public Service Co.
& Environmental
Protection Agency
Status/Operating History
Will be the first boiler application of process in U.S. Process
will be applied to a 115 MW coal fired utility boiler. The
recovered concentrated SC>2 stream will be reduced with natural
gas to elemental sulfur (Allied Chemical Process). Process has
been used successfully on oil fired boilers in Japan and on
SO,, tail gas from Claua units in refineries.
oo
i
oo
-------
8-19
8.2.2 Catalytic Oxidation
The catalytic oxidation process (CAT-OX) uses a fixed bed catalytic
converter to oxidize the SO in the flue gas to SO which can then be col-
lected in an absorption tower with water resulting in about 78 percent sul-
furic acid. The flue gas must be at about 850 F entering the converter.
For a new power plant installation, this could be done directly. In a retro-
fit application, flue gas temperatures are from 250 F to 350 F leaving the
air preheater thus requiring the flue gas to be heated to 850 F with an
auxiliary fuel (oil or natural gas) . Much of the heat put in is recovered
in a regenerative heat exchanger. A simplified schematic diagram is
shown in Figure 8.2.2.
There is only one commercial scale application of the CAT-OX
process; a 110 MW coal fired boiler at the Wood River Station of Illinois
Power. The concept has been demonstrated briefly and sulfuric acid pro-
duced. The major problems have been in obtaining suitable gas reheat.
Originally the system was designed for firing natural gas directly into
the flue gas for reheat, but, shortages have forced the use of oil. There
have been problems with temperature control with oil and also the possi-
bility of oil soot contaminating the catalyst. A one-year test program
will start in early 1975, during which time it is hoped that feasibility
will be demonstrated.
-------
CAT-OX
MIST
ELIMINATOR
FLUE GAS
FROM EXISTING
ID FAN
RECYCLE
00
I
ro
o
STORAGE
FIGURE 8.2.2. CATALYTIC OXIDATION
-------
TABLE 8.2.2. CATALYTIC OXIDATION
Facllty
Location
Wood River
110 MW (coal)
Wood River, 111.
Owner(s)
or Contractor
llinois Power;
Monsanto
System originally started up in 1972. Major problems have been
in controlling gas reheat temperature at catalytic converter
inlet using fuel oil. The effect of flyash on catalyst life
also has not yet been determined.
Status/Operating History
00
-------
8-22
8.2.3 Magnesium Oxide Scrubbing
The MgO wet desulfurization process utilizes finely ground
magnesium oxide in a water slurry as the scrubbing medium in conventional
scrubbing equipment. The MgO reacts with the SO in the flue gas forming
MgS03 which is dewatered and sent to a sulfuric acid plant to regenerate
the MgO. Regeneration is accomplished by heating the MgSO- in a rotary
kiln yielding MgO and an SO -rich gas. The S0?-rich gas is then processed
through a conventional contact sulfuric acid plant to make a commercial
grade sulfuric acid. A simplified schematic flow sheet is shown in
Figure 8.2.3.
In the two full-scale demonstration projects of MgO scrubbing
In this country the scrubbing process itself has shown promise. The major
problems in both cases have been mechanical failures of piping, pumps,
and related equipment. Also,some doubt still exists as to the ability
of the unit to operate over a long term on regenerated MgO with a minimum
of fresh MgO makeup. This is an important consideration due to the high
cost of magnesium oxide. Also, MgO units operating on coal will require
a purge stream to control the flyash concentration in the regeneration
loop.
-------
Flue gas
containing S02
o
eg
X
£
(J)
j- o
S?
cr +
— 10
O> (/)
25
ja +
E O
o ®
c/) S
Venturi
absorber
scrubber
\/
JTL VI
a>
TJ
a>
_o
CQ
Pump
Centrifuge
U^!-
Pump MG0
H20
Fan
Dryer flue gas
Air
t
P
H2S04
plant
H2S04
S02 rich
flue gas
Fan
Fan
u>
Cyclone
Fuel
rr
MGS03
MGS04
MG0
Fuel
Carbon
FIGURE 8.2.3. MAGNESIUM OXIDE SCRUBBING WITH SULFURIC ACID RECOVERY
-------
TABU 8.2.3. MgO SCRUBBING
Faellty
Mystic
150 MW (oil)
Dickerson
190 MW
Location
Boston, Mass.
Boston Edison;
Chemico
Dickerson, Maryland
Owner(B)
or Contrcctor
Potomac Electric
Power; Chemico
Status/Operating History
Unit was first started up In April 1972. Unit was Initially
plagued with mechanical problems such as corrosion and erosion
of pumps valves and piping. Through proper equipment selection
and experience, progress has been made in this area. S02
removal has been over 90 percent when the scrubber Is operating.
Scrubber availability has averaged less than 50 percent over
Its operating life. No decision has been made to equip other
units.
Unit started up in 1974. Major problems have been In mechanical
failures external to the scrubber. MgO scrubbing process has
worked satisfactorily.
oo
i
NJ
-------
8-25
8.2.4 Chiyoda Process
The Chiyoda "Thoroughbred 101" flue gas desulfurization process
is a wet process which removes SCL and SCL from a gas stream by absorption
^ J
in dilute H2S04. After oxidation of the SCT to sulfate (SOT) with the
aid of a soluble catalyst, Fe^SO^) , part of the H-SO is reacted with a calcium
compound such as limestone to form gypsum. The remainder of the H-SO,
is recycled to the absorber as shown in the schematic flow diagram in
Figure 8.2.4.
This process was originally designed for oil fired systems and
in order to use it on coal fired systems some modifications are necessary.
(1) An efficient particulate collection device is needed
ahead of the absorber to reduce the dust concentration
to an acceptable level. Since most coal fired utility
boilers in this country already have electrostatic
precipitators for fly ash collection this may not be
a problem, although, collection efficiency may have to
be increased in some cases.
(2) A vacuum filter may be needed for removing the residual
fly ash from the dilute H2S04 to prevent flyash contami-
nation of the gypsum.
This process has never been reportedly applied to a coal fired boiler,
although there are five installations on oil fired boilers in Japan.
Chiyoda recently announced plans to install a 23 MW demonstration plant
at the coal fired Scholz plant of Gulf Power Company near Sneads, Florida
as the first attempt. Even with efficient flyash collection enough dust
may penetrate to the absorber and cause plugging. The ash may also
cause contamination of the gypsum and impair its value as a salable
product.
-------
ABSORPTION 5>X|DATION
VENT
CRYSTALLIZATION
-A
REHEATER
QXjDIZER
WATER CENTRIFUGE
PRESCRU1SEJ ABSORBER
MAKE-UP WATER
CONVEYOR
oo
to
8Oa CONTAINING
GASES
PUMP
PUMP
PUMP
FIGURE 8.2.4. CHIYODA THOROUGHBRED 101 FLUE GAS DESULFURIZATION PROCESS
-------
TABLE 8.2.4. CHIYODA PROCESS
Factlty
Scholz
25 MW
Location
Snead, Florida
Owner(s)
or Contractor
Ihiyoda Chemical
Engineering and
Construction Co.
Status/Operating History
Plans were announced in December 1973 to build a 23 MW demon-
stration unit. Will be the first Chiyoda unit in the U.S.
and the first anywhere on coal. There are five Chiyoda units
on oil fired installations in Japan.
oo
i
NJ
-------
8-28
8.2.5 The Citrate Process
The Citrate process involves absorption of the SO in the flue
gas in citric acid (C,H00 ) or some other carboxylate solution followed
bo/
by reaction of the spent solution with H_S in a closed vessel to precipi-
tate the absorbed S0_ as elemental sulfur. First the flue gas must be
washed to remove particulates and SCL before entering the absorber. The
sulfur precipitate is removed from the regenerated solution by oil
floatation and melting. A schematic flow diagram of the Citrate process
is shown in Figure 8.2.5.
This process was developed by the Bureau of Mines at Salt Lake
City and tried on a small scale at the San Manuel copper smelter near
Tucson, Arizona beginning in November 1970. The pilot plant (300 cfm)
was plagued with failures of the gas cleaning system, pump breakdowns,
and plugging of flow lines with precipitated and melted sulfur. S0_
removal of 90 to 99 percent was readily obtainable.
The process is now being developed by Pfizer with support from
the Bureau of Mines, Peabody Engineering Co. and Arthur F. McKee. A
2000 cfm pilot plant, built on skids, is now operating at a 150 MW power plant
in Terre Haute, Indiana on 3.5 percent sulfur coal. The chemical process
was generally been satisfactory but the unit has been troubled with mech-
anical failures. Thus far methane (natural gas) has been used to
generate H^S from elemental sulfur.
-------
GAS
CLEANING
AND
COOLING
Flue
Cleaned and
cooled ga»
i — •
H20 — •>
*—
1
1
*
S02 ABSORPTION I SULFUR PRECIPITATION
1 AND
1
To atmosphere
1
S02
liquor
SOLUTION REGENERATION
1
C0?
|
vd
f
^
r"
1
3*
y
> Sulfur
slurry
SULFUR SEPARATION
K2S-C02
Recycle liquor
•
-
1 * C
r-~5
>^-o X' —
t^S Sulfur Y
""I nni«H»r V_
Molten
x
\
_r
— X*
H2S GENERATION
r////
//// °°
X/VX* ro
>
_j Sfeam
CH«
FIGURE 8.2.5. THE CITRATE PROCESS
-------
TABLE 8.2.5. CITRATE PROCESS
Facllty
Terre Haute
2000 cftn
Location
Terre Haute, Ind.
Owner(s)
or Contractor
Pfizer Chemical;
Peabody Engineering
Arthur F. McKee
Status/Operating History
Pilot plant unit mounted on skids. Has had mechanical
failures though chemical process has proven satisfactory.
Much Information is proprietary at this time.
oo
i
-------
8-31
Selected Bibliography for Section 8
(1) Oxley, J. H. et al, Sulfur Emission Control for Industrial Boilers.
paper presented at the American Power Confernece (April 1974).
(2) Land, G. W. , Nichoson, F. E., Status of Flue Gas Desulfurization
Projects. Amax Coal Co. (May 1974).
(3) Rosenbaum, J. B. et al, Sulfur Dioxide Emission Control by Hydrogen
Sulflde Reaction in Aqueous Solution. Bureau of Mines (1973).
(4) Rosenberg, H. S. et al, State of the Art Report on Status of Develop-
ment of Process for Abatement of S02 Emissions by Stack Gas Treatment.
report to American Electric Power Service Corporation (March 1973).
(5) Flue Gas Desulfurization. Installations and Operations. U.S.
Environmental Protection Agency (September 1974).
(6) National Public Hearings on Power Plant Compliance with Sulfur Oxide
Air Pollution Regulations. U.S. Environmental Protection Agency (January 1974)
-------
SECTION 9
ACKNOWLEDGEMENTS
The authors wish to acknowledge the contributions of the many
representatives of industry and of various government agencies who
supplied current information on the status of specific projects. The
advice and assistance of Mr. Paul Spaite, a consultant, and the leader-
ship of both Mr. G. R. Smithson, Jr., Associate Manager of the Energy
and Environment Program Office and Dr. J. H. Oxley, Manager, Fuels and
Combustion Systems Section also are gratefully acknowledged. Dr. Charles
Chatlynne, the EPA Task Officer, provided sound and helpful direction to
the program.
9-1
-------
APPENDIX A
ENVIRONMENTAL CONSIDERATIONS FOR THE GASIFICATION OF COAL
-------
APPENDIX A
ENVIRONMENTAL CONSIDERATIONS FOR THE GASIFICATION OF COAL
Gasification of coal has associated with it a number of potentially
undesirable environmental effects which must be held within acceptable
limits. Toward that end, EPA has initiated a continuing program aimed at
providing environmental assessments and the necessary emissions control and
abatement technology for synthetic fuel processes. This program will
operate in parallel with the gasification research and development programs
described earlier (Sections 5 and 6). Hopefully, potential environmental
problems will be characterized well enough and soon enough to permit proper
abatement systems to be incorporated into the design and construction of
commercial plants.
Applications have already been filed with the Federal Power
Commission for the construction of two commercial-scale (250 x 10& SCF/D) plants
for the production of SNG using the well-developed Lurgi process (see
Table 6.1). The possible environmental impact of these plants has received
careful attention from the designers and exacting scrutiny by the various
regulatory agencies. Operating experience at these installations should
provide valuable feed back.
The environmental impact of coal gasification processes has
received considerable attention (3, 6, 7, 28, 29, 30, 31)*; and for purposes
of this report a brief outline of the major problem areas should be
sufficient.
Coal Mining. Although the environmental problems will be of
the same type as presently encountered in coal production, the
magnitude of the mining effort that will be required to support
a mature coal-gasification industry is such that this aspect
warrants very careful attention.
The two commercial-scale plants to be constructed in New
Mexico will each require about 25,000 tons of coal per day to
produce 250 x 10& CFD of SNG. By 1990 it is estimated that SNG
^References cited in this Appendix refer to items contained in the Supple-
mental Bibliography for Coal Gasification on Page 6-37.
A-l
-------
A-2
12 3
production alone will amount to 1.6 x 10 ft /yr*. This will require
about 100-150 x 10 ton/yr of coal**; in constrast, total U.S. production
was about 613 x 106 ton/yr in 1970 (33).
Also, because the cost of coal is an important factor in
'fcfck
determining the price of the product gas , there will be a
strong economic incentive to use surface-mined coal whenever
possible. This will present a particularly challenging problem
in the arid regions of the West where land reclamation is difficult.
At present, there are no Federal Regulations governing
restoration of land following surface mining. However, the
Senate and House both have recently passed relatively strict
laws, and a conference committee is now meeting to resolve
differences in the two bills. The overwhelming vote in the
House (291-81) suggests that there is sufficient support to
override a possible veto.
Coal Preparation. Coal cleaning, drying and sizing can
result in air and water pollution as well as a solid waste
problem. However, as in the case of mining, the problems are
no different than those now associated with the production of
coal. The specific pollutants and the processes by which they
reach the environment are reasonably well understood; and
control equipment is commercially available.
The solid wastes produced during coal cleaning may require a
significant commitment of land resources. A modern 1,000 TPH
cleaning plant requires between 40 and 90 acres for waste disposal (6).
* "The Coal Gasification Market", prepared by marketing consultants Frost
& Sullivan of N.Y. A brief summary of some of their major findings
appears in Chemical Engineering, pp 59-60 (July 22, 1974). This figure
is in reasonable agreement with estimates in the National Petroleum
Councils, U.S. Energy Outlook: An Initial Appraisal, 1971-85 (Novem-
ber 1971). See also Reference 6.
** Based on data in Reference 33, pp 58-70.
*** For example, a $1.00 increase in the cost of coal results in a 13
-------
A-3
Coal GasificaMon. A number of products are recovered in
various process streams which are potential sources of pollu-
tion. The variety and nature of these products depend upon
operating conditions and the basic unit operations involved
(3, 6, 28, 30, 32). Some of these products such as tar, oils
and char can be recycled and others such as phenols, ammonia
and sulfur may be marketable byproducts. Table A.I indicates
the yields of products expected from a 250 MMCFD gasification
plant operating on Illinois No. 6 coal (3.7 percent S). Ranges
are necessary because of dependence of yields upon the nature
of the gasification process.
A. J. Forney, et al., carried out extensive studies of the
various effluents associated with the Synthane coal-to-gas pro-
cess (32), and they have published the analyses of tars, chars,
gases and waters produced as effluents when different coals are
used. Although yields can vary quantitatively and qualitatively
for different processes, the results are indicative of the complexity
of these streams.
Large quantities of water are required in the gasification
of coal. For example, the 250 MMSCF/D WESCO plant will require
5,100 gpm of raw water intake (8,200 acre-feet per year). This
amounts to about 1.4 pounds of raw water intake per pound of
. coal. In general, the higher the heating value of the product
gas, the greater the water requirements per unit of product gas.
Some large western coal deposits which are likely to be considered
for gasification are in water-deficient areas. This may not be
a serious constraint in the early stages of development, but
the overall management of water resources in these areas should
be an important consideration.
In addition to serving as a raw material in gasification
i.e, as a source of hydrogen), water is also involved in a number
of process steps such as cooling and scrubbing*. The studies
by Forney et. al. on the chemical composition of aqueous process
streams indicates their complexity (Tables A.2 and A.3). In
"(5)In the Lurgi process being used at WESCO about 10 percent of the water
will be consumed in gasification, 70 percent will be returned to the
regional atmosphere and the remaining 20 percent is disposed of on-
site -- principally as sludge and wetted ash. There will be no
return of waste water to the source (San Juan River). (Based on infor-
mation in "Coal Gasification: A Technical Description, published
by WESCO.)
-------
A-4
TABLE A.I. BYPRODUCT YIELDS IN COAL GASIFICATION(a)
Product Yield (long tons/day)
Sulfur 300-450
Ammonia 100-150
Hydrogen Cyanide 0 to possibly 2
Phenols 10-70
Benzene 50-300
Oil and Tars Trace to 400
Mercury Less than 5 Ibs/day
(a) For production of 250 MMCFD of SNG from
Illinois No. 6 Coal (3.77»S). Taken from
Reference 3 page X-2.
-------
A-5
TABLE A. 2. BYPRODUCT WATER ANALYSIS FROM SYNTHANE GASIFICATION OF VARIOUS
COALS, MG/1 (EXCEPT PH)(32)
pH
Suspended solids..
Phenol
COD
Thiocyanate
Cyanide
NH-,
Chloride
Carbonate
Bicarbonate
Total sulfur
Coke
plant
9
50
2,000
7 000
1 000
100
5 000
•
-
Illinois
No. 6
coal
a f.
600
2 600
15 000
152
0 6
*8 100
500
3 6, 000
2 11 000
31,400
WyoTn ing
subbi-
tumi-
nous
coal
87
140
A 000
A 7 000
0 21
9 5^0
-
Illi-
nois
char
7 Q
24
?on
1 700
o i
31
-
North
Dakota
lignite
9 2
64
38 000
?2
O 1
7 700
-
Western
Kentucky
coal
80
55
3 , 700
1 Q ftOO
?00
0 S
1 0 000
-
Pitts-
burgh
seam
coal
90
23
i -jftn
1 Q 000
1 RS
0 6
1 1 000
-
ii> percent free NH3.
•'<
26
20
5
8
2
2
Average (by weight)
4
3
2
0.8
360
160
130
90
60
40
40
30
30
3n
20
20
6
6
3
2
-------
A-6
commercial plants It will probably be economically imperative to
purify water for reuse, and therefore there should be no major
waste-water effluent except that used to slurry ash for disposal.
Removal of hydrogen sulfide from the raw gas leaving the
gasifier is an important consideration. In almost all cases the
sulfur is ultimately recovered as elemental sulfur. The various
processes involved and their application to coal gasification have
been described in detail elsewhere (8,38).
Large quantities of solid waste are produced during f.a
*
cation . Most of this is ash, but processing to remove sulfur
may also contribute to the solid waste burden. Some processes,
such as Hygas, C02 Acceptor and those involving molten salt
baths, generate additional solid waste streams.
In conclusion, gasification does involve potentially
undesirable environmental effects. It would be unrealistic to
think that these adverse effects can be completely eliminated;
however, careful planning and good engineering practice should
make It possible to hold them to an acceptable level. Coal
mining and preparation are probably the areas that present the
most significant environmental problems; this is undoubtedly
one of the reasons for renewed interest in underground gasification.
However, the technical and environmental feasibility of under-
ground gasification on a large-scale have not yet been demonstrated.
Moreover, the apparent attractiveness from an environmental view-
point may result primarily from the fact that much less is known
about the potential environment consequences of underground
gasification on a large-scale.
* A typical 250 x 10 SCF/day gasification plant will produce between
1,000 and 3,000 ton/day of ash. The CO Acceptor Process will also
discharge about 900 ton/day of spent dolomite.
-------
A-7
1. REPORT NO.
EPA-650/2-75-034
TECHNICAL REPORT DATA
friease read Inunctions on the reverse before completing)
. TITLE AND SUBTITLE
Fuels Technology
A State-of-the-Art Review
2.
5. REPORT DATE
A.pril 1975
3. RECIPIENT'S ACCESSION>NO.
6. PERFORMING ORGANIZATION CODE
E. H. Hall, D. B. Peterson, J. F. Foster,
K.D.Kiang, and V.W.Ellzey
8. PERFORMING ORGANIZATION REPORT NO
PERFORMING ORG-VNIZATION NAME AND ADORE!
Battelle Columbus Laboratories
505 King Avenue
Columbus, Ohio 43201
10. PROGRAM ELEMENT NO.
1AB013: ROAP 21ADE-010
11. CONTRACT/GRANT NO.
68-02-1323, Task 14
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND.PERIOD COVERED
Final Task; 7-12/74
14. SPONSORING AGENCY CODE
16. SUPPLEMENTARY NOTES
The report gives results of a state-of-the-art review of various fuel-cleaning,
fuel-conversion, and emission control technologies. It includes the following
classes of technologies: physical and chemical coal cleaning, residual oil
desulfurization, coal refining (liquefaction), coal and oil gasification, fluidized-
bed combustion of coal, and stack gas cleaning. For each technology, the report
presents the extent of current practice and the status of systems under development.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Fuels
Flue Gases
'oal Preparation
Desulfurization
Residual Oils
Refining
Gasification
Fluidized-Bed
Processing
.imiefaction
. DISTRIBUTION £
Pollution Control
Stationary Sources
Stack Gas Cleaning
hemical Coal
Cleaning
hysical Coal
Cleaning
19. SECURITY^
13B,
21D
21B
081
07A, 07D
13H
8. DISTRIBUTION STATEMENT
119. SECURITY CLASS (ThisReport}
Jnclassified
21. NO. OF PAGES
253
Unlimited
120. SECURITY CLASS (Thispage)
Jnclassified
22. PRICE
CPA Form 2220-1 (9-73)
------- |