SEPA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600/7-79-l78d
Laboratory November 1979
Research Triangle Park NC 27711
Technology Assessment
Report for Industrial
Boiler Applications:
Synthetic Fuels
Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-178d
November 1979
Technology Assessment Report
for Industrial Boiler Applications:
Synthetic Fuels
by
William C. Thomas
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
Contract No. 68-02-2608
Task No. 49
Program Element No. INE825
EPA Project Officer: William J. Rhodes
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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PREFACE
The 1977 Amendments to the Clean Air Act required that emission standards
be developed for fossil-fuel-fired steam generators. Accordingly, the U.S.
Environmental Protection Agency (EPA) recently promulgated revisions to the
1971 new source performance standard (NSPS) for electric utility steam
generating units. Further, EPA has undertaken a study of industrial boilers
with the intent of proposing a NSPS for this category of sources. The study
is being directed by EPA's Office of Air Quality Planning and Standards, and
technical support is being provided by EPA's Office of Research and Develop-
ment. As part of this support, the Industrial Environmental Research
Laboratory at Research Triangle Park, N.C., prepared a series of technology
assessment reports to aid in determining the technological basis for the
NSPS for industrial boilers. This report is part of that series. The com-
plete report series is listed below:
Title Report No.
The Population and Characteristics of Industrial/ EPA-600/7-79-178a
Commercial Boilers
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178b
Applications: Oil Cleaning
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178c
Applications: Coal Cleaning and Low Sulfur Coal
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178d
Applications: Synthetic Fuels
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178e
Applications: Fluidized-Bed Combustion
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178f
Applications: NO Combustion Modification
X
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178g
Applications: NOX Flue Gas Treatment
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178h
Applications: Particulate Collection
Technology Assessment Report for Industrial Boiler EPA-600/7-79-178i
Applications: Flue Gas Desulfurization
These reports will be integrated along with other information in the
document, "Industrial Boilers - Background Information for Proposed Standards",
which will be issued by the Office of Air Quality Planning and Standards.
ii
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ABSTRACT
This report Is part of a series of technology assessment reports pre-
pared for the EPA to aid in their determining the technological basis for
new source performance standards for industrial boilers. The report
addresses the use of synthetic fuels produced from coal as precombustion
emission controls for new industrial boilers. The synthetic fuels technolo-
gies considered include coal gasification (low-, medium-, and high-Btu) and
liquefaction. Major emphasis is placed on examining the reduction of SOX,
NOX, and particulate emissions in the industrial boiler flue gases.
Based on detailed analyses of costs, energy, and environmental impacts,
low-Btu coal gasification was selected as the "best synthetic fuels from
coal" emission control technique for industrial boilers. Two low-Btu gasi-
fication systems, the Wellman-Galusha gasifier with either the Stretford
(W-G/S) or monoethanolamine (W-G/MEA) acid gas removal process, were selected
for the detailed analyses. Also, in performing the detailed analyses, two
coal feedstocks (low-sulfur western and high-sulfur eastern) and five boiler
capacities (8.8, 22, 44, 58.6, and 117 MWT heat input) were considered.
All of the low-Btu gasification systems examined were capable of meet-
ing the most stringent target NOX and particulate emissions control
levels considered (86 ng NOX/J and 4 ng particulates/J heat input to the
boiler). With respect to S(>2 emissions, the W-G/S systems using a low-
sulfur coal feed could achieve a stringent target emission control level of
43 ng S02/J heat input. Using a high-sulfur coal feed, the W-G/S sys-
tems could achieve a moderate target control level of 150 ng S(>2/J heat
input. The W-G/MEA systems were only considered for the high-sulfur coal
cases and could be designed to achieve either the moderate or stringent
target S02 control level.
The results of the costs analyses indicated that the annualized costs
of the gasification/low-Btu gas-fired boiler systems were approximately 20
to 170 percent greater than the annualized costs of an equivalent capacity
(on a boiler heat input basis) direct coal-fired boiler without pollution
controls. The percentage increase in incremental costs varied indirectly
with boiler capacity. For a given boiler capacity, the W-G/S system using
low-sulfur coal had the lowest incremental costs, while the W-G/MEA system
using high-sulfur coal had the highest incremental costs. All of the low-
Btu gasification/boiler systems consume more energy (40-65%) than equivalent
capacity uncontrolled coal-fired boilers. The low-Btu gasification systems
are also sources of gaseous, liquid, and solid discharges. However, there do
not appear to be any uncontrollable adverse environmental impacts. For regu-
latory purposes, this assessment must be viewed as preliminary, pending the
results of the more extensive examination of impacts called for under Section
III of the Clean Air Act.
Ill
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ACKNOWLEDGMENTS
The author wishes to express his appreciation to the following personnel
for their contributions to this report:
S.S. Patel and A. Fodder (Hittman Associates, Inc.) for their input
to the coal liquefaction sections;
P.J. Murin and T.G. Sipes for their contributions to the low-Btu
gasification sections;
M.J. Harris, S. Bailey, and J.C. Fischer for their outstanding job
in typing the report; and
W.R. Menzies and G.C. Page for their excellent review comments and
technical assistance.
Guidance and review by W.J. Rhodes of EPA/IERL-RTP also aided signifi-
cantly in the successful completion of this technology assessment report.
IV
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CONTENTS
Preface ii
Abstract iii
Acknowledgements iv
Figures xi
Tables xiii
1. EXECUTIVE SUMMARY 1-1
1.1 Introduction 1-1
1.1.1 Background and Obj active 1-1
1.1.2 Approach and Report Organization 1-2
1.2 Summary of Best Emission Reduction Systems 1-6
1.2.1 Principles of Emissions Control 1-12
1.2.2 Applicability and Limitations to Boiler Size 1-13
1.2.3 Emission Control Efficiency 1-13
1.2.4 Cost Impacts 1-15
1.2.5 Energy Impacts 1-20
1.2.6 Environmental Impacts 1-22
1.2.7 Commercial Availability 1-22
2. DESCRIPTION OF SYNTHETIC FUELS FROM COAL SYSTEMS 2-1
2.1 Low- and Medium-Btu Coal Gasification 2-3
2.1.1 System Description 2-3
2.1.1.1 Coal Pretreatment 2-5
2.1.1.2 Coal Gasification 2-8
2.1.1.3 Gas Purification 2-13
2.1.1.4 Pollution Control Operations 2-18
2.1.2 Status of Technology 2-28
2.1.2.1 Status of Coal Pretreatment Processes 2-28
2.1.2.2 Status of Gasification Processes 2-28
2.1.2.3 Status of Gas Purification Processes 2-30
V
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CONTENTS (Continued)
2.1.3 Applicability and Limitations 2-31
2.1.4 Factors Affecting Performance 2-32
2.1.5 System Performance 2-33
2.1.5.1 Emissions Reduction Potential 2-33
2.1.5.2 Impacts on the Boiler 2-35
2.2 High-Btu Coal Gasification 2-35
2.3 Coal Liquefaction 2-36
2.3.1 System Description 2-36
2.3.1.1 Coal Pretreatment 2-36
2.3.1.2 Coal Liquefaction 2-38
2.3.1.3 Separation 2-40
2.3.1.4 Purification/Upgrading 2-40
2.3.2 Status of Development 2-41
2.3.3 Applicability to and Limitations for
Industrial Boilers 2-41
2.3.3.1 Use of Coal-Derived Solid or Liquid
Fuels in Boilers 2-50
2.3.3.2 Coal-Liquids Fuel Characteristics 2-51
2.3.4 Factors Affecting Performance 2-55
2.3.4.1 Type of System 2-56
2.3.4.2 Coal Characteristics 2-57
2.3.4.3 Operation Variables 2-59
2.3.4.4 Hydroprocessing 2-62
2.3.5 System Performance 2-66
2.3.5.1 Emission Reductions 2-66
2.3.5.2 Boiler Impacts and Maintenance
Requirements 2-70
References 2-71
3. SELECTION OF "BEST CANDIDATE" SYNTHETIC FUELS SYSTEMS 3-1
3.1 Selection of "Best Candidate" Low-Btu Coal
Gasification Systems 3-6
3.1.1 Comparison and Selection of a Candidate
Low-Btu Gasifier 3-7
VI
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CONTENTS (Continued)
3.1.2 Comparison and Selection of Candidate Acid Gas
Removal Processes 3-11
3.1.3 Summary of "Best Candidate" Low-Btu Gasification
Systems 3-20
3.2 Selection of "Best Candidate" Medium-Btu Coal
Gasification Systems 3-22
3.2.1 Comparison and Selection of a Candidate
Medium-Btu Gasifier 3-23
3.2.2 Comparison and Selection of "Best Candidate"
Acid Gas Removal Processes 3-25
3.2.3 Summary of "Best Candidate" Medium-Btu
Gasification Systems 3-28
3.3 Selection of "Best Candidate" Coal Liquefaction Systems ... 3-29
3.3.1 Comparison of the Candidate Coal Liquefaction
Systems 3-33
3.3.2 Selection of "Best Candidate" Coal Liquefaction
Systems 3-42
References 3-45
4. COST ANALYSIS OF SYNTHETIC FUELS FROM COAL SYSTEMS 4-1
4.1 Contributors to Control Costs and Cost Bases 4-3
4.1.1 Capital Requirement 4-3
4.1.2 Operating Costs 4-4
4.1.3 Annualized Costs 4-5
4.2 Low-Btu Coal Gasification 4-7
4.2.1 Costs Summary and Analysis 4-9
4.2.2 Cost Bases 4-18
4.2.2.1 Cost Basis for Low-Btu Gasification
Systems ; 4-18
4.2.2.2 Cost Basis for Low-Btu Gas-Fired Boilers .. 4-23
4.2.3 Cost Sensitivity Analysis 4-23
4.2.4 Confidence Interval for Low-Btu Gasification/
Boiler Annualized Costs 4-26
4.3 Medium-Btu Coal Gasification 4-27
4.3.1 Costs Summary and Analysis 4-29
vii
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CONTENTS (Continued)
4.3.2 Cost Bases 4-34
4.3.3 Cost Sensitivity Analysis 4-42
4.4 Coal Liquefaction 4-42
4.4.1 Cost Bases 4-45
4.4.2 Costs Summary and Analysis 4-53
4.4.3 Cost Sensitivity Analysis 4-53
4.5 Summary 4-57
References 4-61
5. ENERGY IMPACTS OF SYNTHETIC FUELS FROM COAL SYSTEMS 5-1
5.1 Low-Btu Coal Gasification 5-2
5.1.1 Comparison of Energy Requirements 5-6
5.1.2 Methods of Reducing Energy Consumption 5-8
5.2 Medium-Btu Coal Gasification 5-10
5.2.1 Basis for Energy Consumption Data 5-13
5.2.2 Comparison of Energy Consumption 5-16
5.2.3 Methods of Reducing Energy Requirements 5-18
5.3 Coal Liquefaction 5-19
5.3.1 Discussion of Energy Consumption 5-22
5.3.2 Methods of Reducing Energy Consumption 5-27
5.4 Summary of Energy Impacts 5-27
References 5-29
6. ENVIRONMENTAL IMPACTS OF SYNTHETIC FUELS FROM COAL SYSTEMS 6-1
6.1 Low-Btu Gasification 6-3
6.1.1 Air Pollution 6-3
6.1.1.1 Air Pollutants in Boiler Combustion
Gases 6-3
6.1.1.2 Air Pollutants from the Gasification
System 6-5
6.1.2 Water Pollution 6-8
6.1.2.1 Coal Storage Runoff 6-14
6.1.2.2 Ash Sluicing Water 6-14
viii
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CONTENTS (Continued)
6.1.2.3 Process Condensate 6-15
6.1.2.4 Stretford Process Blowdown 6-17
6.1.3 Solid Waste 6-19
6.1.4 Other Environmental Impacts 6-23
6.2 Medium-Btu Coal Gasification 6-24
6.2.1 Air Pollution 6-24
6.2.2 Uater Pollution 6-29
6.2.3 Solid Wastes 6-30
6.2.4 Other Environmental Impacts 6-32
6.3 Coal Liquefaction 6-32
6.3.1 Pollutant Releases 6-32
6.3.1.1 Air Pollution 6-34
6.3.1.2 Water Pollution 6-37
6.3.1.3 Solid Wastes 6-42
6.3.1.4 Trace Elements 6-44
6.3.2 Physical Disturbances 6-44
6.3.3 Plant Construction, Operation and Decommission 6-46
6.3.4 Other Impacts 6-46
References 6-49
7. EMISSION SOURCE TEST DATA 7-1
7.1 Low- and Medium-Btu Gas Emission Test Data 7-1
7.1.1 Riley Morgan Combustion Tests 7-2
7.1.2 Institute of Gas Technology Combustion Tests 7-6
7.2 Coal Liquids Emission Source Test Data 7-12
7.2.1 Combustion Facilities and Emission Monitoring 7-13
7.2.2 Comparison of Emissions 7-18
7.2.3 Discussion of Emissions Monitoring Methods 7-19
References 7-21
APPENDIX A - CAPITAL AND OPERATING COSTS FOR LOW-BTU COAL
GASIFICATION SYSTEMS AND LOW-BTU GAS-FIRED
INDUSTRIAL BOILERS A-l
ix
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CONTENTS (Continued)
APPENDIX B - CAPITAL INVESTMENT REQUIREMENTS AND ANNUALIZED
COSTS FOR MEDIUM-BTU COAL GASIFICATION SYSTEMS
AND MEDIUM-BTU GAS-FIRED INDUSTRIAL BOILERS B-l
APPENDIX C - CAPITAL INVESTMENT REQUIREMENTS AND ANNUALIZED
COSTS FOR COAL LIQUEFACTION SYSTEMS AND COAL
LIQUIDS-FIRED INDUSTRIAL BOILERS C-l
APPENDIX D - ENERGY REQUIREMENTS FOR LOW-BTU GASIFICATION
SYSTEMS - EXAMPLE CALCULATION D-l
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FIGURES
Number Page
1.1-1 Schematic of study approach 1-3
1.2-1 Incremental annualized costs of low-Btu gas-fired boilers
versus boiler input heat rate 1-17
1.2-2 Cost effectiveness of low-Btu gasification/steam
generation systems in controlling SOz emissions 1-18
2.1-1 Schematic of study approach 2-4
2.1-2 Low- or medium-Btu coal gasification system process and
pollution control modules 2-6
2.1-3 Flow diagram for the modules in the air pollution
control operation 2-19
2.1-4 Major process modules generating wastewater in a
typical coal gasification plant 2-24
2.1-5 Flow diagram for the modules in the water pollution
control operation 2-25
2.1-6 Flow diagram for the modules in the solid waste control
operation 2-27
2.3-1 Module diagram for coal liquefaction systems 2-37
2.3-2 Flow diagrams of advanced liquefaction processes 2-48
2.3-3 Effect of hydrogen consumption upon sulfur in filtered SRC .. 2-60
2.3-4 Variation of nitrogen content of SRC-I liquids with
changes in temperature and coal-feed rate 2-61
2.3-5 Effect of temperature on sulfur removal 2-63
2.3-6 Effect of temperature on nitrogen removal 2-64
3.1-1 Schematic of study approach 3-2
3.1-2 Wellman-Galusha quench/cooling steps 3-13
3.2-1 Lurgi quench/cooling steps 3-26
3.3-1 Solvent Refined Coal (SRC-I) system 3-30
3.3-2 H-Coal system 3-32
3.3-3 Exxon Donor Solvent (EDS) system 3-34
xi
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FIGURES (Continued)
Number Page
4.2-1 Annualized costs of low-Btu gasification/steam generation
system versus boiler S02emission level ...................... 4-15
4.2-2 Incremental annualized costs of low-Btu gas-fired boilers
versus boiler input heat rate ............................... 4-16
4.2-3 Cost effectiveness of low-Btu gasification/steam
generation systems in controlling SOa emissions ............. 4-17
4.3-1 Annualized costs of medium-Btu gas-fired industrial
boilers [[[ 4-30
4.3-2 Incremental cost of medium-Btu gas-fired industrial
boilers ......... . ........................................... 4-31
4.3-3 Cost effectiveness of medium-Btu gasification/steam
generation system in controlling S02 emissions .............. 4-32
4.4-1 Cost analysis of coal liquids-fired industrial boilers ...... 4-54
4.4-2 Cost effectiveness of coal liquefaction systems as SOa
emission controls for industrial boilers .................... 4-55
5.1-1 Simplified flow diagram - Wellman-Galusha low-Btu
gasification system ......................................... 5-3
5.1-2 Energy consumption of low-Btu gasification systems .......... 5-5
5.2-1 Energy consumption of medium-Btu gasification systems ....... 5-12
5.2-2 Simplified flow scheme - Lurgi medium-Btu coal
gasification system ......................................... 5-14
5.3-1 Energy consumption in coal liquefaction systems ............. 5-24
6.3-1 Pollutant releases from coal liquefaction system ............ 6-33
6.3-2 EDS commercial plant study design water systems
coordination flow plan ...................................... 6-39
6.3-3 EDS commercial plant study design ash handling system
flow plan ...................... ....................... ..... , 6-45
7.1-1 NO emission data for coal derived syngas combustion ........ 7-4
7.1-2 NOX emission data (normalized with respect to furnace
heat input) for coal derived syngas combustion .............. 7-5
7.1-3 Fuel NO,, emissions for coal derived syngas combustion ....... 7-7
X
7.1-4 Conversion of NHs to N0y in coal derived syngas combustion .. 7-8
7.1-5 Conversion of NHs to NOX for medium-Btu gas combustion
using baffle burner ......................................... 7-10
7.1-6 Conversion of NHs to NO for medium-Btu gas combustion
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TABLES
Number
1.1-1 Study Basis Boiler Sizes and Coal Feeds 1-5
1.1-2 Target Emission Control Levels for Synthetic Fuels
from Coal Technologies 1-5
1.2-1 Comparison of Candidate Gasifiers 1-7
1.2-2 Candidate Acid Gas Removal Processes for Gasification
Systems 1-9
1.2-3 Candidate Coal Liquefaction Systems 1-10
1.2-4 "Best Candidate" Synthetic Fuels Systems 1-11
1.2-5 Cost Analysis of Low-Btu Coal Gasification Systems for
Industrial Boilers 1-16
1.2-6 Sensitivity Analysis—Low-Btu Gas-Fired Boiler
Annualized Costs 1-19
1.2-7 Effect of Coal Transportation Costs on Annualized
Low-Btu Gas-Fired Boiler Costs 1-21
1.2-8 Air Pollution Impacts from Low-Btu Gasification Systems 1-23
1.2-9 Water Pollution Impacts from Low-Btu Gasification Systems ... 1-24
1.2-10 Solid Waste Impacts from Low-Btu Gasification Systems 1-25
2.1-1 Functions of Modules in Coal Pretreatment Operation 2-7
2.1-2 Typical Raw Product Gas Compositions for Low- and
Medium-Btu Gases 2-8
2.1-3 Population of Low/Medium-Btu Gasifiers 2-10
2.1-4 Low-Temperature Acid Gas Removal Processes 2-16
2,1-5 Direct Conversion Primary Sulfur Recovery Processes 2-21
2.1-6 Promising Low- and Medium-Btu Gasification Systems 2-29
2.1-7 Promising Acid Gas Removal Systems 2-30
2.3-1 State of the Art of Coal Liquefaction Processes 2-42
2.3-2 Operating Characteristics of Coal Liquefaction Process 2-45
2.3-3 General Comparison and Relative Technical Status of
Four Hydrogenation Liquefaction Processes 2-49
Kill
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TABLES (Continued)
Number Page
2.3-4 Range of Analyses of Fuel Oils 2-52
2.3-5 Properties of No. 2 Fuel Oil and Coal Liquids 2-54
2.3-6 Properties of SRC-I and Base Coals 2-55
2.3-7 Hydrogen Consumption and Sulfur Content of Coal Liquids
in Liquefaction Systems 2-57
2.3-8 Sulfur in Feed Coals and Flue Gases from Combustion of
Feed Coals and SRC Products 2-58
2.3-9 Hydroprocessing Conditions and Yields for Upgrading
SRC Recycle Solvent and H-Coal Distillate 2-65
2.3-10 Effect of S02 Emission Levels on Sulfur Content
Tolerance in Liquid Fuels 2-68
2.3-11 EDS Fuel Oil Combustion Test - Particulate Emissions 2-70
3.1-1 Target Emission Control Levels for Synthetic Fuels
from Coal Technologies 3-3
3.1-2 Ultimate Analysis of Base Coals 3-6
3.1-3 Comparison of Candidate Gasifiers 3-8
3.1-4 Estimated Compositions of Low-Btu Gases from
Wellman-Galusha Gasifier 3-12
3.1-5 Physical Solvent Acid Gas Removal System 3-15
3.1-6 Chemical Solvent Acid Gas Removal Systems 3-16
3.1-7 Combination Physical/Chemical Solvent Systems and Direct
Conversion System 3-17
3.1-8 Sulfur Content of the Two Base Case Low-Btu Gases 3-21
3.2-1 Estimated Compositions of Medium-Btu Gases from
Lurgi Gasif ier 3-24
3.3-1 Candidate Coal Liquefaction Systems 3-35
3.3-2 Hydrogenation Subsystems and Components Requiring
Engineering Development 3-37
3.3-3 Sources and Characteristics of Air Emissions 3-39
3.3-4 Sources and Characteristics of Wastewater Streams 3-40
3.3-5 Modular Solid Waste Discharges 3-41
3.3-6 Fuel Composition and Combustion Emissions for
Liquefaction Fuels 3-44
xiv
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TABLES (Continued)
Number Page
4.1-1 Values Used for Annual Cost Items 4-6
4.2-1 Cost Analysis of "Best Candidate" Low-Btu Coal
Gasification Systems for Industrial Boilers 4-8
4.2-2 Annualized Cost for Uncontrolled Coal-Fired Industrial
Boilers 4-11
4.2-3 Capital Investment Requirements for Low-Btu Wellman-
Galusha Gasification Systems 4-12
4.2-4 Annualized Costs for Low-Btu Wellman-Galusha Gasification
Systems 4-13
4.2-5 Annualized Costs for Low-Btu Gas-Fired Industrial Boilers ... 4-14
4.2-6 Labor Requirements for Low-Btu Gasification/Steam
Generat ion 4-22
4.2-7 Sensitivity Analysis—Low-Btu Gas-Fired Boiler
Annualized Costs 4-24
4.2-8 Effect of Coal Transportation Costs on Annualized Low-Btu
Gas-Fired Boiler Costs 4-25
4.3-1 Cost Analysis of "Best Candidate" Medium-Btu Coal
Gasification Systems for Industrial Boilers 4-28
4.3-2 Capital Cost Items for Medium-Btu Gasification Systems 4-35
4.3-3 Estimated Installed Equipment Costs for Lurgi Medium-Btu
Gasification Systems 4-37
4.3-4 Estimated Total Capital Requirements for Lurgi Medium-Btu
Gasification Systems 4-38
4.3-5 Estimated Maintenance Costs for Lurgi Medium-Btu
Gasification Systems 4-39
4.3-6 Annualized Costs for Lurgi Medium-Btu Gasification Systems .. 4-40
4.3-7 Sensitivity Analysis - Medium-Btu Gas-Fired Boiler
Annualized Costs 4-43
4.3-8 Effect of Coal Transportation Costs on Annualized
Medium-Btu Gas-Fired Boiler Costs 4-44
4.4-1 Cost Analysis of "Best Candidate" Coal Liquefaction
Systems for Industrial Boilers 4-46
4.4-2 Emissions from Coal Liquids Combustion 4-47
4.4-3 Total Capital Requirement for SRC-I Process 4-49
4.4-4 Total Capital Requirements for Exxon Donor Solvent Process .. 4-50
xv
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TABLES (Continued)
Number Page
4.4-5 Annualized Costs for SRC-I Process 4-51
4.4-6 Annualized Costs for Exxon Donor Solvent Process 4-52
4.4-7 Cost Sensitivity - Coal Liquids-Fired Boilers 4-56
4.4-8 Effect of Coal and Product Transportation Cost on
Annualized Coal Liquids-Fired Boiler Costs 4-58
4.5-1 Synfuel Economics Summary 4-59
5.1-1 Energy Consumption for Wellman-Galusha Low-Btu
Gasification Systems 5-4
5.1-2 Detailed Summary of Energy Consumption for Wellman-
Galusha Low-Btu Gasification Systems 5-7
5.2-1 Energy Consumption for Lurgi Medium-Btu Gasification
Systems 5-11
5.2-2 Detailed Summary of Energy Consumption for Lurgi
Medium-Btu Gasification Systems 5-17
5.3-1 Major Equipment Consuming Electric Power in Coal
Liquefaction Systems 5-20
5.3-2 Thermal Efficiencies of Coal Liquefaction Systems 5-21
5.3-3 Energy Consumption for Coal Liquefaction Systems 5-23
5.3-4 Electric Power Requirements for EDS System 5-25
5.3-5 Fuel Gas Consumption for EDS System 5-26
5.3-6 Steam Requirements for EDS System 5-27
6.1-1 Air Pollution Impacts from "Best Candidate" Low-Btu
Gasification Systems 6-4
6.1-2 Water Pollution Impacts from "Best Candidate" Low-Btu
Gasification Systems 6-9
6.1-3 Water Quality Parameters of Quench Liquor from a Chapman
Fixed-Bed Atmospheric-Pressure Gasifier 6-10
6.1-4 Composition of Quench Liquor from a Chapman Fixed-Bed
Atmospheric-Pressure Gasifier 6-11
6.1-5 Composition of Slowdown from Stretford Process 6-13
6.1-6 Solid Waste Impacts from "Best Candidate" Low-Btu
Gasification Systems 6-20
6.2-1 Summary of Air Pollution Impacts for Lurgi Medium-Btu
Gasification Systems 6-25
xvi
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Number Page
6.2-2 Summary of Minor Emissions from Lurgi Medium-Btu
Gasification Systems 6-28
6.2-3 Summary of Solid Wastes from Lurgi Medium-Btu
Gasification Systems 6-31
6.3-1 Estimated Air Emissions from the EDS Liquifaction Process ... 6-35
6.3-2 Aqueous Wastes from Off-Site Wastewater Treating
Facilities of the Commercial EDS Liquefaction Plant 6-40
6.3-3 Aqueous Wastes from Miscellaneous Waste Streams of the
Commercial EDS Liquefaction Plant 6-41
6.3-4 Solid Wastes from EDS System 6-43
6.3-5 Occupational and Health Hazards of Liquefaction Systems 6-48
7.1-1 Analytical Parameters and Analysis Methods for Riley
Syngas Combustion Tests 7-3
7.1-2 Analytic Instrumentation Equipment Used for IGT
Combustion Tests 7-9
7.1-3 Summary of IGT Baseline Combustion Tests 7-12
7.2-1 Emissions Source Test Data for Coal Derived Liquids 7-14
xvii
-------
SECTION I
EXECUTIVE SUMMARY
1.1 INTRODUCTION
1.1.1 Background and Objective
The Clean Air Act Amendments of 1977 require the Environmental
Protection Agency to coordinate and lead the development and implementation
of regulations on air pollution. These include standards of performance for
new and modified sources of pollution. Specifically mentioned in the Act
are fossil fuel-fired steam generators. Accordingly, EPA has undertaken a
study of industrial boilers with intent to propose standards of performance
based upon the results of this and other studies.
There are many ways to reduce emissions from fossil fuel-fired
industrial boilers. These methods or techniques can be broadly classified
as:
Precombustion techniques
• Combustion techniques
Post-combustion techniques.
This report presents the results of a study conducted to evaluate the use of
synthetic fuels from coal technologies as precombustion emission controls
for new industrial boilers. The synthetic fuels technologies examined
1-1
-------
included coal gasification (low-, medium-, and high-Btu) and liquefaction.
Major emphasis was placed on the reduction of SO , NO , and particulate
. XX
emissions in the industrial boiler flue gases. However, other gaseous
pollutants in the flue gases, as well as gaseous emissions, liquid effluents,
and solid wastes from the synthetic fuels systems, were also examined.
The results of this evaluation will be used by the EPA to assess the
need for, and, if appropriate, to prepare a new source performance standard
for small industrial boilers. Factors that were considered in evaluating
the synthetic fuels technologies include: development status, capital and
operating costs, energy impacts, environmental impacts, and performance data.
1.1.2 Approach and Report Organization
A multiphased approach was used to evaluate the synthetic fuels tech-
nologies as shown in Figure 1.1-1. First, the population of synfuels systems
and their important components were identified. Because of the large number
of systems that were considered, general type descriptions were prepared for
each technology detailing items such as:
• Status of development,
Applicability and limitations,
• Factors affecting performance, and
• System performance.
Using status of development as the major criterion, a preliminary screening
of the synfuels population was performed in order to select several candidate
systems for further study. As indicated in Figure 1.1-1, the systems descrip-
tion and preliminary screening step are addressed in Section 2 of this report.
The candidate synfuels systems identified in Section 2 were screened a
second time in order to select 1 or 2 "best candidate" systems for detailed
analysis. The criteria used were:
1-2
-------
Population
of Systems
Section 2
Description of
Technologies
and
Preliminary
Screening
Candidate
Systems
Section 3
Selection of
"Best Candidate"
Systems
i
u>
"Best Candidate"
Systems
Section 1
Selection of
Best Systems
and
Executive Summary
Detailed Analysis
Economic
Energy
Environmental
Section
k
5
6
Figure 1.1-1. Schematic of study approach.
-------
• System performance,
Status of development,
• Applicability to industrial boilers,
• Preliminary cost considerations,
• Preliminary energy considerations, and
• Preliminary environmental considerations.
The results of the second screening step are presented in Section 3.
The next step in the study approach was to perform detailed analyses of
costs, energy, and environmental impacts for the "best candidate" systems.
The results of those analyses are presented in Sections 4, 5, and 6 respec-
tively. In performing the analyses, the synfuels systems were considered
for application to several boiler sizes and fuels (see Table 1.1-1). The
EPA had indicated at the beginning of this study that the coal-derived syn-
fuels systems should be compared to other control technologies for coal-fired
boilers. Therefore, the boiler sizes and fuels indicated in Table 1.1-1
correspond to the coal-fired "standard boilers" examined by the other EPA
contractors for the Industrial Boiler Program.
The final step in the study approach was to identify the available
source test data for combustion of the synthetic fuels in industrial boilers.
That information is contained in Section 7.
In the ensuing discussion of emission control technologies, candidate
technologies were compared using three emission control levels labelled
"moderate, intermediate, and stringent" (see Table 1.1-2). These control
levels were chosen only to encompass all candidate technologies and form
bases for comparison of technologies for control of specific pollutants con-
sidering performance, costs, energy, and non-air environmental effects. From
these comparisons, candidate "best" technologies (systems) for control of
individual pollutants are recommended for consideration in subsequent indus-
trial boiler studies. The systems selected and a discussion of their perfor-
mance and impacts are presented in Section 1.2. These "best technology"
1-4
-------
TABLE 1.1-1. STUDY BASIS BOILER SIZES AND COAL FEEDS
Base Coal Analyses
Boiler Heat Input,
MWT (106 Btu/hr)
8.8
22
44
58.6
117.2
(30)
(75)
(150)
(200)
(400)*
Composition, Wt %
Carbon
Hydrogen
Sulfur
Oxygen
Nitrogen
Moisture
Ash
Heating Value,
MJ/kg (Btu/lb)
Eastern
High Sulfur
64.80
4.43
3.54
6.56
1.30
8.79
10.58
27.4
(11,800)
Western Low
Sulfur
57.60
3.20
0.60
11.20
1.20
20.80
5.40
22.3
(9,600)
This boiler size was examined only for a limited number of cases using
low-Btu gasification.
TABLE 1.1-2.
TARGET EMISSION CONTROL LEVELS FOR SYNTHETIC FUELS
FROM COAL TECHNOLOGIES
SOa, NOX, Particulates,
ng/J ng (as N02)/J ng/J
(lb/106 Btu) (lb/106 Btu) (lb/106 Btu)
Coal Gasification
Moderate Control
Intermediate Control
Stringent Control
Coal Liquefaction
Moderate Control
Intermediate Control
Stringent Control
150 (0.5)
86 (0.2)
43 (0.1)
86 (0.2) 13 (0.03)
520 (1.2) 300 (0.7
260 (0.6) 220 (0.5) 13 (0.03)
86 (0.2)
86 (0.2)
1-5
-------
recommendations do not consider combinations of control technologies and have
not undergone the detailed environmental, cost, and energy impact assessments
necessary for regulatory action. Therefore, the levels of "moderate, inter-
mediate, and stringent" and the recommendation of "best technology" are not
to be construed as indicative of the regulations that will be developed for
industrial boilers. EPA will perform rigorous examination of several compre-
hensive regulatory options before any decisions are made regarding the stan-
dards for emissions from industrial boilers.
1.2 SUMMARY OF BEST EMISSION REDUCTION SYSTEMS
In coal gasification systems the most important factor with respect to
the system's performance as a precombustion emission control technique is
the type of acid gas removal (AGR) process employed. Thus, for the gasifi-
cation technologies it was necessary to examine both gasifiers and AGR
processes. Approximately 70 low- and medium-Btu coal gasifiers and 70 AGR
processes were considered in Section 2. From these populations, 14 gasifiers
and 14 AGR processes were selected for additional consideration (see Tables
1.2-1 and 1.2-2). High-Btu coal gasification was eliminated from considera-
tion as an emission control technique for industrial boilers. This was
because 1) medium-Btu gas is just as applicable for use in industrial
boilers as high-Btu gas, 2) high-Btu gasification is merely an extension of
medium-Btu gasification (shift and methanation processing required in addi-
tion to medium-Btu gasification processing), and 3) high-Btu gasification
has higher energy and cost impacts than medium-Btu gasification. Over
twenty coal liquefaction processes were identified in Section 2. From this
population four processes (see Table 1.2-3) were selected as candidates for
additional consideration.
From the comparative evaluation of the systems listed in Tables 1.2-1
through 1.2-3, "best candidate" systems were selected for detailed analysis.
These "best candidate" systems are listed in Table 1.2-4. A brief descrip-
tion of these systems is also contained in Table 1.2-4.
1-6
-------
TABLE 1.2-1. COMPARISON OF CANDIDATE GASIFIERS
fiasifier
HI:C:
SI. logins
l.mvi
i:i-<;a;.
t:fKi[ini.m
(Wi l[.uti. )
Type
of Cas Pressure Development Status
Mcdiui.i- High Demonstration
Btu 1'ressure plaivt (started
1976)
Low- or Ui^b Not been UL-raon-
Mediuui- Pressure strated; pilot
Ntu plant started in
August 1976
Low- of Al/ao- Commercial ly
Medium- spheric available (since
Btu 1945) for l.ow-
Stit £as; not
commercial ly
demonstrated fjr
roediura-Btu g UET
phenols in raw pro-
duct gas; gas treat-
ment produces process
condensate and
quenching liquor.
Waste streams from UNA
gas purification;
process coiidensate,
quenching liquor;
coal fines.
S-'o^l
^ l o i c
CI'KKt'
SJaL-iii
er Wlu-eler/
Low-Btu Atmo- P Hot plctnt
Atmo- DeHionstx-ation
spheric plant construction
begun in 1977
Medium- High Pilot plant
IStu Pressure (1958-1965)
Medium- Atmo- Commercially
btu spheric available since
1952
Accepts all coal types
(lignite nor been tested);
<0.07 mtn sized coal;
crushing and pulverizing
requ i rud; additives
icqui red.
Lignite, subbituinlnous, non-
caking bituminous; 19-38 mm
sized coiil; crushing and
sizing required; partial
oxidation may be needed for
strongly caking coals.
bituminous char, lignite
chfir, lignite; 6.4-19 mm
sized coal; <35% moisture;
Crushing and sizing required *
Accepts nil coal types; 7i),Di
to 902 less than 0.074 mm;
pulverizing required; M-B%
moisture; possible addition
of fluxing agents to lower
ash fusion temp.
Additive hopper
vent gas
Slag slurry
(solid &
Coal hopper
vent gas
Asli pan gas
Ash
Poke hole gases
Coal lock gas
Slag quench
vent gas
Slag quench
b1owdown
Slag slurry
Coal bjn N2 venc
Slag
Slag slurry
Essentially no tars DNA
or oils in raw proJucL
gas; gas purificatLou
tnay create additional
unwanted streams.
Waste streams from gaa 77
purification; tars/
oils, coal dust.
Waste streams from gas 85
purification; proctisy
condensate, quenching
liquor, coal tines.
Essentially no tars, 75
oil, naphthas or
phenols in raw product
gas; gas treatment
produces process con-
densate and quenching
liquor.
(Continued)
-------
TABLE 1.2-1. Continued
I
CXI
Caslfier
Luigi
Pressuri zed
We 1 Iman-Ga 1 usha
(MKUC)
Ri ley-Morgan
Texaco
Wi-llman-Calusha
WJnkler
WoodaJ 1-
nni-.klian/linu
Integrate
Type
of Gas Pressure
Low- nr High
Medium- Pressure
Btu
Low- or High
Medium- Pressure
Btu
Low- or Atmo-
Medlutn- spheric
Btu
Medium- High
Btu Pressure
Low-Btu Atmo-
spheric
Low- or Atmo-
Hedlum- spheric
Btu
Low-Btu Atmo-
spheric
. Product Has Energy
Cold lias
Environmental Impacts Efficiency
Development Status
Commercially
available (since
1941)
Pilot plant (since
1958) ; not com-
mercially demon-
strated for
medium-Btu
Commercially
available for low-
Btu gas (Pilot
plant since 1975);
not commercially
demonstrated for
medium-Btu gas
Pilot plant
Commercially
available (since
1941)
Commercially
available since
1926
Commercially
available (since
1940)
Output
Feedstock Restrictions
Accepts all coal; strongly
caking coals may need par-
tial oxidation or agitation;
crushing and sizing
required; <35% moisture;
3.2-38.1 mm sized coal.
Accepts .ill types; 50Z
•^12.7 mm sized; no predrying;
crushing and sizing required.
Accepts all coal types; 3.2-
51 mm sized coal; crushing
and sizing required.
Accepts all coal types; 702
less than 0.074 mm; crushing,
pulverizing, slurry
preparation required.
Can use anthracite, bitumi-
nous, charcoal, or coke; 7.9-
14.3 mm for anthracite; 26-51
mm for bituminous; crushing
and sizing required.
Lignite, subblturalnous, weakly
caking bituminous; <9.53 ma
sized coal; crushing required;
<30Z moisture for lignites;
<18Z moisture for higher rank
coals; partial oxidation may
be required.
Lignite, bituminous; 6.4-38.1
mm sized coal; crushing and
sizing required; drying not
required; partial oxidation
for strongly caking coals.
Direct
Coal lock gas
Ash lock gas
Ash
Ash quench
water
Coal lock gas
Ash lock gas
Ash
Coal lock gas
Ash pan gas
Ash
Poke hole gases
Slurry prepara-
tion vent gas
Slurry steam
purge
Preheater flue
gases
Slag slurry
Coal bin gas
Ash hopper gas
Ash
Poke hole gases
Coal bin Hz vent
Dry ash bin N;
vent
Ash slurry
settler vent
Dry ash
Ash slurry
Coal hopper vent
gas
Ash lock gas
Ash
Indirect
Waste streams from
gas purification;
process condensate,
quenching liquor,
tars, oil, phenols,
NH3.
Waste streams from
gas purification;
process condensate,
quenching liquor,
coal fines.
Waste streams from
gas purification;
process condensate,
quenching liquor,
coal fines.
Essentially no tars,
oils, naphthas, or
phenols in raw product
gas; gas treatment
produces process con-
densate and quenching
liquor.
Waste streams from
gas purification; coal
fines, process conden-
sate, quenching liquor.
Essentially no tars,
oils, or naphthas in
raw product gas; treat-
ment produces process
condensate and quenching
liquor.
Waste streams from gas
purification; tar.
process condensate, dust ,
«)
63-80
79
64-6S
77
75
55-72
77
.
i.oal Energy Input
UNA: ll.itj not
-------
TABLE 1.2-2. CANDIDATE ACID GAS REMOVAL PROCESSES FOR GASIFICATION SYSTEMS
Acid Gas Removal Process
Description
Physical Solvent Processes
Estasolvan
Fluor Solvent
Purisol
Rectisol
Selexol
Chemical Solvent Processes
Benfield
DEA
DGA
DIPA
MDEA
MEA'
Combination Physical/
Chemical Processes
Amisol
Sulfinol
Direct Conversion Process
Stretford
Physical solvent processes remove acid gases from the raw product gas
by physical absorption in an organic solvent. They are most suited
for high pressure applications because the solubilities of acid gases
in the solvents are directly proportional to the acid gas partial
pressure. Most of the solvents used in these processes have an
appreciably higher affinity for H2S than for COz, and can, therefore,
be used in a manner that allows for selective removal of H2S.
Chemical solvent processes remove acid gases by adsorption followed by
formation of a chemical complex between the acid gas and solvent. In
most of these processes the solvent is regenerated by thermal
decomposition of the chemical complex.
Combination chemical/physical solvent processes use a physical solvent
together with an alkanolamine chemical solvent additive. Both the
chemical and the physical solvents remove C02, HjS, and HCN; but the
physical solvent is primarily responsible for the removal of acid gases
such as CS2, mercaptans, and COS.
The Stretford process is a liquid phase direct conversion process. H2S
is removed by adsorption in an alkaline solution, with subsequent
oxidation of the sorbed HjS to elemental sulfur. Organic sulfur com-
pounds are not removed by the Stretford process.
-------
TABLE 1.2-3. CANDIDATE COAL LIQUEFACTION SYSTEMS
i
M
O
Characteristics
Status of Development
SRC-I
SRC-II
H-Coal
Exxon Donor Solvent (EDS)
Operational and
Maintenance Requirements
Applicability
Environmental Impacts*
Financial impact
(capital cost of the
liquefaction plant Is
prorated to the boiler
size)
Energy Impact**
1700 kg/hr pilot plant
oppr.it inj;, Ft. lewis, WA
210 kg/hr pilot plant,
UilsonviUe, AL
Solids accumulation
control in the
dissolve? on western
coals
Solids-liquid separa-
tion (filtration)
equipment
Slurry pumps
Solid fuel produced can
only be used in
pulverized coal boiler
Control of sulfur release
by sulfur recovery pro-
cess followed by tail-
gas unit
Particulate control from
coal preparation
Hastewater treatment to
reduce organic and in-
organic constituents in
waste streams
1700 kg/hr pilot plant
operating, Ft. Lewis, WA
210 metric ton/hr demon-
stration plant planned,
West Virginia
Solids accumulation
control in the dissolver
on western coals
Vacuum distillation column
Slurry pumps
Liquid fuel can be used
in conventional fuel oil-
fired boiler
Control of sulfur release
by sulfur recovery process
procpss followed by tall-
gas unit
Particulate control from
coal preparation
Wastewater treatment to
reduce organic and In-
organic constituents in
waste streams
Disposal of solid wastes • Disposal of solid wastes
Capital cost may be as
high as 50 percent of
the companion utility
boiler plant.
Thermal efficiency
60-75Z
Capital cost may be as
high as 60-75 percent of
the companion utility
boiler plant.
Thermal efficiency •
60-75Z
100 kg/hr PDU operating,
Trenton, NJ
20 metric ton/hr pilot
plant under construction,
Cattlesburg, KY. Start-up
in early 1979
Ebullated bed reactor
Circulating slurry pumps
Liquid fuel can be used
In conventional fuel oil-
fired boiler
Control of sulfur release
by sulfur recovery
process followed by tail-
gas unit
Particulate control from
coal preparation
Wastewater treatment to
reduce organic and in-
organic constituents in
waste streams
Disposal of solid wastes
Capital cost may be as
high as 60-75 percent of
the companion utility
boiler plant.
Thermal efficiency •
60-75S
0.9 and 2.4 kg/hr bench
scale units and 34 kg/hr
pilot plant operating.
Baytown, TX
8.6 metric ton/hr under
construction, Baytown, TX
Operation in 1980
Circulating slurry pumps
Flexlcoking
Liquid fuel can be used
conventional fuel oil-
fired boiler
Control of sulfur re-
lease by sulfur recovery
process followed by tail-
gas unit
Particulate control from
coal preparation
Wastewater treatment to
reduce organic and in-
organic constituents in
waste streams
Disposal of solid
wastes
Capital cost may be as
high as 60-75 percent of
the companion utility
boiler plant.
Thermal efficiency
60-75*
*Sec Table 3.3-3, 3.3-4, and 3.3-5.
**Thermnl Efficiency is defined as tne energy content of all useful products expressed as a percentage of the energy content of the fi'ed co.nl.
-------
TABLE 1.2-4. "BEST CANDIDATE" SYNTHETIC FUELS SYSTEMS
"Best Candidate" Systems
Description
Low-Btu Coal Gasification
Wellman-Galusha gasifier
with Stretford AGR process
Wellman-Galusha gasifier
with monoethanolamine (MEA)
AGR process
System operates at nominally atmosphere pressure; utilizes an
alkaline solution to remove H2S but does not remove COS; does
not require a separate sulfur recovery process; capable of
achieving stringent control levels for NO and particulatss,
stringent S02 level for low sulfur coal feed, and moderate
S02 control level for high sulfur coal feed.
System operates at nominally atmospheric pressure, although
gas is moderately compressed (ijO.3 MPa) for AGR process;
requires separate sulfur recovery unit for AGR process off-
gas (Claus/SCOT units); capable of achieving stringent
control levels for NO , SO , and particulate emissions.
Medium-Btu Coal Gasification
Lurgi gasifier with
Stretford AGR process
Lurgi gasifier with
Rectisol AGR process
Coal Liquefaction
SRC-I
Exxon Donor Solvent (EDS)
High pressure operation (il2.4 MPa); utilizes alkaline solution
to remove HzS but does not remove COS; does not require
separate sulfur recovery process; capable of achieving
stringent control levels for NOX and particulates, stringent
S02 level for low sulfur coal feed, and intermediate SOz
control level for high sulfur coal feed.
High pressure operation (>2.4 MPa); utilizes cold methanol
for essentially complete removal of sulfur species; can meet
stringent control levels for SOx, NOx, and particulate
emissions.
High pressure operation (^10 MPa); noncatalytic hydrogenation
system; produces low melting point (155°C) solid fuel;
capable of meeting stringent particulate control level with
80* percent efficiency particulate control device on flue
gas; capable of meeting moderate SOz control level for high
sulfur coal feed and intermediate SOz control level for
low sulfur coal feed; NOX emission reduction is questionable.
High pressure operation (^14 MPa); donor solvent type
hydrogenation system; produced distillate fuel oil type
liquid product; includes liquids hydrotreating as part of
process; capable of meeting stringent SOz (extra hydro-
treating may be necessary for high sulfur coal feed) and
particulate control levels; NOx emission reduction is not
well defined.
1-11
-------
Based on the results of the detailed evaluations of the synfuels systems
listed in Table 1.2-4, the two low-Btu gasification systems (Wellman-Galusha
gasifier with either the Stretford or monoethanolamine AGR process) were
selected as the best emission control systems for industrial boilers. Sec-
*
tions 1.2.1 through 1.2.7 summarize the results of the detailed analyses per-
formed for those two systems. The following text briefly discusses why the
"best candidate" medium-Btu gasification and liquefaction systems were not
selected as the best systems.
There currently are no commercially operating medium-Btu gasification
or liquefaction plants in the U.S. If and when built though, these plants
are expected to be large capacity installations. Typical design capacities
being considered are approximately 1760 MW (6000 x 10s Btu/hr) of medium-
Btu gas output and approximately 3520 MW (12,000 x 106 Btu/hr or 50,000
bbl/SD) of coal liquids output. However, the industrial boilers examined in
this study have relatively small fuel needs (up to 120 MW thermal heat
input or 400 x 106 Btu/hr). Thus, an industrial boiler would require only
a small percentage of a large synfuel plant's fuel production. Unless an
unusual set of economic situations existed, a small industrial boiler operator
probably would not (or could not), on his own, invest the capital necessary
to build and operate a large medium-Btu coal gasification or liquefaction
plant. The only way a small industrial boiler operator could utilize medium-
Btu gas or coal liquids would be 1) to purchase a minor interest in a large
plant being constructed by others, or 2) to purchase a portion of the fuel
production from an existing plant. Both of those situations, however,
require that someone already has built or wants to build the synfuels plant.
Given these circumstances, medium-Btu coal gasification and liquefaction
were not selected as the best emission control systems for industrial boilers.
1.2.1 Principles of Emissions Control
Converting coal into a "clean" low-Btu gas with subsequent combustion in
a boiler, reduces SO^, NOV, and particulate emissions (versus direct coal
X A
1-12
-------
combustion) by removing the pollutant's precursors. With respect to parti-
culate emissions, the coal ash content is physically separated from the gas
when the coal is gasified. Any entrained ash or coal particles are subse-
quently removed from the gas in the hot cyclones and gas quenching and
cooling steps. SO emissions are reduced by removing sulfur species such
as H2S and COS from the low-Btu gas prior to combustion. Nitrogen oxide
emissions are also reduced because low-Btu gas contains only small quantities
of nitrogen compounds (NHa and cyanides) which can be oxidized to NO . More-
over, low-Btu gas burns with a low flame temperature which helps reduce the
formation of NOX by thermal fixation.
1.2.2 Applicability and Limitations to Boiler Size
The low-Btu gasification systems examined are applicable to any size
industrial boiler. For the smallest industrial boilers examined (8.8 MVL,
thermal input or 30 x 106 Btu/hr), one 3 m (10 ft) diameter Wellman-Galusha
gasifier is required. For the larger boilers, multiple gasifiers are used
(10 gasifiers are required for a boiler with a thermal input of 117.2 MWL or
400 x 106 Btu/hr).
1.2.3 Emission Control Efficiency
There are no actual test data for the combustion of low-Btu gas in
industrial boilers. However, S02 and particulate emission estimates based on
engineering calculations should be good approximations for actual combustion
results. NO emissions cannot be estimated quite as confidently. The mech-
anisms for NO formation are quite complex. Hence, an "a priori" estimate
X
cannot be made.
As mentioned previously, the performance of synthetic fuels from coal
systems as precombustion emission controls for industrial boilers was evalu-
ated with respect to three target emission control levels (see Table 1.1-2).
The target emission control levels attainable by the low-Btu gasification
system examined are discussed in the following text.
1-13
-------
For a low sulfur coal feed which produces relatively small amounts of
organic sulfur compounds (^50 ppmv), the Wellman-Galusha/Stretford (W-G/S)
system can produce a fuel gas capable of meeting a stringent target S02 con-
trol level of 43 ng S02/J (0.1 lb/106 Btu). For a high sulfur coal feed, the
COS concentration of the low-Btu gas is greater (estimated at ^300 ppmv) . In
this situation, the W-G/S system can only achieve a moderate target S02 level
of 150 ng/J (0.35 lb/106 Btu) since the Stretford process does not remove COS.
However, the monoethanolamine (MEA) system can remove both COS and H2S from
the low-Btu gas. Thus, the Wellman-Galusha/MEA (W-G/MEA) system can produce
a fuel gas from a high sulfur coal capable of meeting a stringent target S02
control level.
The MEA process can be designed to provide less complete removal of
sulfur species if increased S02 emission levels are acceptable. Thus, the
W-G/MEA system was examined for all three target SOa emission control levels.
However, the H2S removal reaction in the Stretford process is very fast, and
residual levels are normally less than 100 ppmv. It is not possible to
operate the process to achieve significantly less H2S removal (although H2S
residuals around 100 ppmv may be possible with a less efficient type of
contactor). For this reason, the W-G/S system was only examined for one
target S02 emission control level (moderate control for high sulfur coal and
stringent control for low sulfur coal).
For all of the cases examined, particulate emissions arising from com-
bustion of the low-Btu gas are estimated to be similar to those for natural
gas combustion—4 ng particulate/J (0.01 lb/106 Btu). This level is below
the target particulate emission control level of 13 ng/J (0.03 lb/106 Btu).
NO emissions from combustion of any of the low-Btu gases examined are
also estimated to be similar to those for natural gas combustion—50-100 ng
NO /J (0.12-0.23 lb/106 Btu). This level is comparable to the target NOV
X X
emission control level of 86 ng/J (0.2 lb/106 Btu). This estimated emission
level is based on a limited number of tests conducted in small test furnaces.
1-14
-------
In these tests, NO emissions were found to be similar to or less than those
/s
from natural gas combustion. The results were for combustion of low-Btu
gases essentially free of NH3 or cyanides. If present, those compounds can
be oxidized to NO , increasing the overall quantity of NO formed.
X X
1.2.4 Cost Impacts
The results of the economic evaluation of the low-Btu gasification/steam
generation systems examined in this study are summarized in Table 1.2-5.
Shown are the annualized costs of the low-Btu gas-fired boilers in dollars
per year and dollars (per year) per unit of design heat input rate to the
boiler. The difference (incremental costs) between these annualized costs
and those for direct coal-fired boilers (without emission controls) are also
listed in Table 1.2-5. The trend in the incremental annualized boiler costs
is readily apparent when they are plotted as incremental costs per unit of
heat input rate to the boiler versus heat input rate (see Figure 1.2-1). As
shown in this figure, the low-Btu gasification/steam generation systems are
more effective at higher heat input rates. This is due to realizing greater
economies of scale in the low-Btu gasification/steam generation systems
versus the direct coal-fired steam generation systems. Another result of
the economic evaluation is that the annualized costs for the Wellman-Galusha/
MEA systems do not vary discernibly with the level of SOa control.
At higher boiler heat input rates the gasification/steam generation sys-
tems are also more cost effective in controlling S02 emissions. This is
illustrated in Figure 1.2-2 where the incremental annualized boiler costs per
kg of S02 controlled (versus a direct coal-fired boiler) are plotted as a
function of boiler heat input rate.
A complete cost component breakdown of the annualized costs for selected
low-Btu gas-fired boilers is presented in Table 1.2-6. All of the synfuel
cases examined are not included in this table since it is for illustrative
purposes only. However, in all cases, the capital related charges and
1-15
-------
TABLE 1.2-5. COST ANALYSIS OF LOW-BTU COAL GASIFICATION SYSTEMS FOR INDUSTRIAL BOILERS*
Annualized low-Btu
gas-fired boiler costs
Boiler heat
input, MW
(10s Btu/hrf
8.8 (30)
8.8 (30)
8.8 (30)
22 (75)
22 (75)
22 (75)
44 (150)
44 (150)
44 (150)
58.6 (200)
•53.6 (200)
58.6 (200)
117.2 (400)
117.2 (400)
Coal feed
to gasifier
Low-sulfur
High-sulfur
High-sulfur
Low-sulfur
High-sulfur
High-sulfur
Low-sulfur
High- sulfur
High-sulfur
Low- sulfur
High-sulfur
High-sulfur
Low-sulfur
High- sulfur
Sulfur control
technique and
level of control
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
SO 2 control
efficiency,
94. 2C
94. 2d
94. 2-98. 2e
94.2°
94. 2d
94. 2-98. 2e
94. 2C
94. 2d
94. 2-98. 2e
94. 2C
94. 2d
94. 2-98. 2e
94. 2C
94. 2d
S103/yr
2100
2320
2540
2890
3380
3870
4450
5340
6050
5320
6530
7350
9340
11,810
per unit of heat
Input. $/kW
(S/10S Btu/hr)
239 (70,000)
264 (77,200)
289 (84,700)
131 (38,500)
154 (45,100)
176 (51,600)
101 (29,700)
121 (35,600)
138 (40,300)
91 (26,600)
111 (32,700)
125 (36,800)
80 (23,400)
101 (29,700)
Increase in costs
over uncontrolled
coal-fired boiler costs
$103/yr Z of coal-fired
1120
1370
1590
1020
1530
2020
1330
2260
2970
950
2280
3100
1410
4030
115
144
168
54
83
110
42
73
97
21
54
74
18
53
wellman-Galusha gasifier; mid-1978 dollars; 60Z annual operating factor.
Low-Btu gas-fired costs were compared to uncontrolled coal-fired boiler
identical boiler heat Inputs.
CS02 emission level Is 30 ng/J (0.07 lb/10s Btu).
dS02 emission level is 140 ng/J (0.32 lb/10s Btu).
CS02 emission levels are 140-43 ng/J (0,32-0.10 lb/10s Btu).
All systems have estimated NOX and particulate emissions as follows:
NOX—50-100 ng/J (0.12-0.23 lb/106 Btu)
particulates—<4 ng/J (<0.01 lb/10s Btu).
costs for systems using the same coal feedstock and having
-------
180 -
Ou
G
(4
QJ
ffi
A
co
-------
•o
OJ
o
1-1
4-1
c
o
o
CM
o
00
co
M
C
I
O
U
CSI
O
CO
14-
12-
10-
8-
2-
• Low Sulfur Western Coal;
Stretford; Stringent Control
X High Sulfur Eastern Coal;
MEA; Intermediate Control3
O High Sulfur Eastern Coal;
Stretford; Moderate Control
30
60
90
120
Input Boiler Heat Rate, MW_
Values for Moderate and Stringent SC»2 Control have less than
a 5% variation from the intermediate control value.
Assumes that total incremental control costs are allocated
to SC-2 removal.
Figure 1.2-2. Cost effectiveness of low-Btu gasification/steam
generation systems in controlling S02 emissions.
1-18
-------
TABLE 1.2-6. SENSITIVITY ANALYSIS—LOW-BTU GAS-FIRED
BOILER ANNUALIZED COSTS
Coal Low Sulfur Western High Sulfur Eastern
Boiler Input Heat Rate, MW
Labor and Maintenance
Utilities
Overhead
Capital Charges
8.8
11.4
1.4
4.3
5.2
58.6
Percent
7.7
1.1
3.2
5.8
8.8
of Annualized Costs
10.3
1.3
3.9
4.7
58.6
6.3
0.9
2.6
4.7
Fuel (Low-Btu gas)
Labor & Maintenance 23.8 18.2 22.4 15.6
Coal 4.3 11.3 6.9 16,5
Other Operating Costs 4.3 12.2 6.9 16.8
Overhead 9.0 6.8 8.6 5.8
Capital Charges 36.2 33.6 34.9 30.6
Total Fuel 77.6 82.1 79.7 85.3
Annualized Costs,
103$/year 2100 5320 2320 6530
Basis: 1) A Stretford is the acid gas removal system for all cases shown.
2) The first four items in the table above - labor and maintenance,
utilities, overhead, capital charges - refer to the gas-fired
boiler system. The fifth item - fuel - is low Btu gas from the
Wellman-Galusha System. Percentages under fuel are the various
cost components of the gasification system.
1-19
-------
operating and maintenance costs are the largest contributors to annualized
costs. The coal cost is the next largest contributor.
The coal costs used in this study are typical of minemouth costs. Since
some degree of coal transportation and handling is likely for most industrial
applications, the effect of coal costs on annualized costs was evaluated.
Moreover, since the coal-to-gas energy conversion in the gasification system
is less than unity, an increase in coal costs will affect the annualized costs
of a low-Btu gas-fired boiler to a greater extent than the annualized direct
coal-fired boiler costs. Examples of the extent of this impact are presented
in Table 1.2-7. For illustrative purposes, coal transportation costs were
taken as $1.00/GJ and $0.50/GJ for the low sulfur western and high sulfur
eastern coals, respectively.
1.2.5 Energy Impacts
The gasification of coal to produce a low-Btu gas incurs a significant
energy penalty. For the Wellman-Galusha/Stretford (W-G/S) system gasifying
low sulfur western coal, about 39 percent more energy is input to the system
in the form of coal, steam, and electricity than is recovered in the product
low-Btu gas. Thus, for direct coal-fired and low-Btu gas-fired boilers with
the same heat input rate, a low-Btu gasification/boiler system will consume
39 percent more energy than the direct coal-fired boiler (excluding auxiliary
energy requirements of the boilers). To gasify high sulfur eastern coal,
the W-G/S system energy penalty is about 48 percent. The Wellman-Galusha/MEA
(W-G/MEA) system using high sulfur eastern coal has an even higher energy
penalty of about 64 percent. However, as was true for the economic impacts,
the energy penalty of W-G/MEA is essentially unaffected by the SOz control
level achieved.
The major contributor to the energy consumed by the low-Btu gasification
systems is the gasification inefficiency. This includes both conversion
losses and the energy content of the by-product tars and oils. Use of the
1-20
-------
TABLE 1.2-7. EFFECT OF COAL TRANSPORTATION COSTS ON ANNUALIZED LOW-BTU GAS-FIRED BOILER COSTS'
I
ro
Input Heat Rate
to Boiler, MW_
(106 Btu/hr)
Low Sulfur Western Coal
8.8 { 30)
ri8.6 (200)
High Sulfur Eastern Coal
8.8 ( 30)
58. h (200)
Coal Cost
Coal-fired Boiler
Annualized Costs,
$10'/yr
980
4370
950
4250
• Base Case Values
l-ow-Btu Gas-fired
Boiler Annualized Costs,
$10Vyr
2100
5320
2320
6530
Coal Transportation Costs Added '
Incremental
Costs,
$103/yr
1120
950
1370
2280
Coal-fired Boiler
Annualized Costs,
$10'/yr
1140
5480
1040
4800
Luw-Btu Gas- Fired
Boiler Annualized Costs,
$10'/yr
2330
6830
2430
7760
Increment-,-!
CllSt!!,
$10'/yr
1191)
nso
I39U
2.'i60
AiJ gasification facilities use the Stretford process
bBase Case Values: Low Sulfur Western (LSW) - S0.40/GJ; High Sulfur Eastern (USE) - $0.68/GJ
"^Transportations Costs: LSW - $l.OO/GJj HSE - $0.50/0J
-------
by-products' energy would lower the energy penalties just presented by about
20 percentage points (e.g., from 64 to 44 percent for a W-G/MEA system gasify~
ing high sulfur eastern coal).
1.2.6 Environmental Impacts
The low-Btu gasification systems examined are sources of gaseous, liquid,
and solid discharges. However, there do not appear to be any uncontrollable
adverse environmental impacts associated with the production and use of low-
Btu gas. Tables 1.2-8, 1.2-9, and 1.2-10 summarize the air emissions, water
effluents, and solid wastes from the various low-Btu gasification systems
examined.
1.2.7 Commercial Availability
In the U.S. at the present time, there are no commercially operating
low-Btu coal gasification systems which incorporate an acid gas removal (AGR)
process for gas cleanup. However, the AGR processes considered in this study
are commercially available from a number of process licensors and vendors.
The ability of those vendors, as well as gasifier vendors, to meet an
increased demand for their systems cannot be easily estimated. Most likely
though, a rapid rise in demand would strain supplies, at least until addi-
tional fabrication capacity could be constructed. A more gradual rise in
demand for low-Btu gasification facilities would probably have little impact
on supplies since industry would have time to respond to the new market
conditions.
1-22
-------
TABLE 1.2-8. AIR POLLUTION IMPACTS FROM LOW-BTU GASIFICATION SYSTEMS3
i
NJ
CO
Systems
Coal
Feed
Low
sulfur
Low
sulfur
SOj
Control Level
(Z Reduction)
Direct coal
combustion
(uncontrolled)
Stringent (94. 2)
Sulfur
Species
Emission Removal
Source Process
Combustion
gas
Combustion Stretford
gas
S02
ng/J (lb/10'Btu)
520 (1.2)
30 (0.07)
ng/J
340-400
50-100
Emissions
NOx
(lb/10*Btu)
(0.78-0.94)
(0.12-0.23)
Other Pollutants
Partlculates
ng/J (lb/10'Btu) Pol lu tan
600-1900 (1.4-4.5)
<4 (<0.01) Organlcs
CO
Change from.
t Uncontrolled
-
Trace elements
High
sulfur
High
sulfur
Direct coal
combustion
(uncontrolled)
Hoderate(94.2)
Moderate(94.2)
Intermediate
(96.5)
String ent(98. 2)
Gasification
systemC
Combustion
gas
Combustion Stretford
gas
Gasification
system'
Combustion KEAe
gas
Gasification
system4
Combustion HEAe
gas
Gasification
system"1
Combustion MKAC
gas
Gasification
system"1
1.9 (0.005)
2400 (5.7)
140 (0.32)
9.0 (0.02)
140 (0.32)
13 (<0.03)
86 (0.2)
13 (<0.03)
43 (0.1)
13 (<0.03)
<0.4
280-330
50-100
<0.4
50-100)
<0.4
50-100
<0.4
50-100
<0.4
(<0.001)
(0.64-0.76)
(0.12-0.23)
(<0.001)
(0.12-0.23)
(<0.001)
(0.12-0.23)
(<0.001)
(0.12-0.23)
(<0.001)
Small Organics
CO
NHs
HCN
COS
950-3100 (2.2-7.2)
<4 (<0.01) Same as
Small Same as
<4 (<0.01) Same as
Snail Same as
<4 (<0.01) Sane as
Small Same as
<4 (<0.01) Same as
Small Same as
+
+
+
+
•t-
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
fwellman-Galusha gasifier with the indicated sulfur control processes.
•H- Increase; + slight Increase; — decrease; - slight decrease.
"llajor emissions of SOt, NOx came from incinerated coal-feeder vent. Other emission sources are Incinerated start-up gases, fugitives, and Stretford
.oxldizer vent.
Major emissions of SO?, NOx came from incinerated coal-feeder vent, with smaller amounts from SCOT tail gas. Other emission sources are Incinerated
start-up gases and fugitives.
Including Claus and SCOT for acid gas treatment.
-------
TABLE 1.2-9. WATER POLLUTION IMPACTS FROM LOW-BTU GASIFICATION SYSTEMS3
Coal Feed S0z Removal Levelb
Sulfur Species
Removal Process
Effluent Generated
Type
Quantity, ng/J
(lb/106 Btu)
Low Sulfur
94.2%
Stretford
coal pile runoff
ash sluicing water
process condensate
Stretford blowdown
• not quantified0
• not quantified*1
5600 (13)e»f
300 (0.7)
f,g
High Sulfur
94.2 93.2% Stretford or MEA
i
ro
94.2%
94.2-98. 2%
Stretford
MEA
coal pile runoff
ash sluicing water
process condensate
Stretford blowdown
process condensate
• not quantified0
• not quantified^
1400 (3.4)e»f
610 (1.4)f'g
9100
(21)
e,f
, Wellman-Galusha gasification system.
Effluents are the same for moderate, intermediate and stringent control levels.
c The quantity of water runoff from coal storage piles is largely site dependent; where coal is
stored in small quantities, covered bins are usually employed, resulting in no water runoff from
. coal storage.
The quantity of water used for ash sluicing varies widely, depending on the practices of the indi-
vidual gasifier operators. The ash may be removed essentially dry, with the addition of little
water. As a worst case, 1 kg of water may be used per kg of ash removed. This results in ash
sluicing water of 3400-5600 ng/J (8-13 lb/106 Btu).
e The quantities of process condensate depends on the water content of the coal feed, the desired
temperature of cooled product gas, and the pressure of the product gas. Systems featuring the MEA
process produce a gas at 280 kPa (40 psla). Values shown are the quantities of condensate sent to
on-site multiple effect evaporators. Residual wastes from the evaporators may be as little as 5Z
f of the values shown.
The estimated compositions of process condensate and Stretford blowdown are shown in Tables 6.1-3,
6.1-4, and 6.1-5.
8 Based on: complete conversion of HCN in feed gaa to NaCNS; 21 conversion of HzS to Na2Sa02;
purge when salts concentration reaches 25% (Ref. 6-5, 6-8, 6-9).
-------
TABLE 1.2-10. SOLID WASTE IMPACTS FROM LOW-BTU GASIFICATION SYSTEMS3
I
N>
Ln
Coal Feed
Low sulfur
Low sulfur
High sulfur
High sulfur
S02 Removal Level Acid Gas
(Control Efficiency, %) Removal Process
Direct Coal Combustion
(Uncontrolled)
lb (94.2) Stretford
Direct Coal Combustion
(Uncontrolled)
Moderate (94.2) MEA°
Intermediate (96.5) MEAC
Stringent (98.2) MEAC
Moderate (94.2) Stretford
Solid Waste Generated
Type
Bottom ash
Gasifier ash
Cyclone dust
Sulfur cake
Bottom ash
Gasifier ash
Cyclone dust
Sulfur
MEA blowdown
Sulfurd
MEA blowdown
Sulfurd
MEA blowdown
Sulfur cake
ng/J (lb/106 Btu)
473-1810
3760
420
508
775-2880
6540
367
1650
116
1680
116
1690
116
3300
(1.1-4.2)
(8.73)
(.977)
(1.18)
(1.8-6.7)
(15.2)
(.853)
(3.83)
(0.27)
(3.90)
(0.27)
(3.93)
(0.27)
(7.67)
fWellman-Galusha gasification system.
The same system is used for moderate, intermediate, or stringent.
^Including Glaus to treat acid gas; SCOT to treat tail gas.
Ash and dust are the same for all 3 control levels.
-------
SECTION II.
DESCRIPTION OF SYNTHETIC FUELS FROM COAL SYSTEMS
The combustion of coal in an industrial boiler produces flue gases con-
taining sulfur and nitrogen oxides and entrained particulates. The quanti-
ties of those pollutants depend on several factors including:
the sulfur and ash content of the coal feed,
the type of boiler used, and
the heat input rate to the boiler.
The levels of uncontrolled SOz, NO , and particulate emissions from coal-
fired industrial boilers can be estimated using EPA emission factors
(Ref. 2-1). Those estimated uncontrolled emissions (expressed as ng pollu-
tant per Joule of heat input to the boiler or Ib per 106 Btu input) are shown
below for combustion of the high sulfur eastern and low sulfur western coals
being examined in this study.
Coal Feed
Wt. % Sulfur
Wt. % Ash
Higher Heating Value,
MJ/kg (Btu/lb)
Flue Gas Components,
ng/J (lb/106 Btu)
Particulates
Pulverized Coal
Spreader Stoker
All Other Stokers
High Sulfur
Eastern Coal
3.54
10.6
27.4 (11,800)
3080 (7.16)
2510 (5.83)
960 (2.23)
Low Sulfur
Western Coal
0.6
5.4
22.3 (9,600)
1930 (4.48)
1570 (3.65)
600 (1.39)
2-1
-------
High Sulfur Low Sulfur
Eastern Coal Western Coal
Flue Gas Components,
ng/J (lb/106 Btu)
S02; all types 2420 (5.62) 510 (1.18)
NO ; as N02
Pulverized Coal 330 (0.767) 400 (0.930)
Stokers 270 (0.627) 340 (0.790)
Emission control techniques for industrial boilers using coal as the
starting fuel can be divided into three categories:
Pre-combustion controls
- Synthetic fuels from coal
Physical or chemical coal cleaning
Combustion controls
- Combustion modifications
• Post-combustion controls
Particulate removal
- Flue gas desulfurization
- Flue gas treating for NC>
X
This study addresses the use of synthetic fuels from coal as a precombustion
emission control. The synfuels techniques examined are coal liquefaction
and low-, medium-, and high-Btu coal gasification.
These coal conversion techniques reduce the formation of SOa, NOV and
X
particulates by converting coal into "clean" fuels. During the conversion
process, ash is removed and portions of the nitrogen and sulfur content of
the coal react to form NH3, HCN, H2S, COS, etc. The nitrogen and sulfur
compounds are then removed by commercially available processes. The quality
of the final product from a gasification or liquefaction process depends on
2-2
-------
the purification and upgrading processes employed. It is possible to
produce a coal-derived gaseous fuel that is essentially identical to natural
gas (the least polluting fossil fuel currently available), or a coal-derived
liquid fuel that is comparable to high-grade distillate fuel oil.
The approach used in assessing synthetic fuels from coal technologies
as emission controls for industrial boilers was presented in Section 1 and
shown schematically in Figure 1.1-1. The first step in the approach is to
describe the technologies and select a set of candidate systems for further
analysis (See Figure 2.1-1). The results of this first step are presented
in this section. Section 2.1 deals with low- and medium-Btu coal gasifica-
tion, Section 2.2 with high-Btu gasification, and Section 2.3 with coal
liquefaction.
2.1 LOW- AND MEDIUM-BTU COAL GASIFICATION
Coal can be gasified with either air or pure (98+ percent) oxygen to
produce synthetic gas. If air is the reactant, a low-Btu gas results; if
pure oxygen is the reactant, a medium-Btu gas is produced. Since the only
difference in a low- or medium-Btu system is the presence or absence of an
oxygen production unit, these two types of gasification systems are described
together in the following sections.
2.1.1 System Description
Coal gasification systems can be considered to consist of three basic
process operations: coal pretreatment, coal gasification, and gas purifica-
tion. Each of these operations consist of process modules which are employed
to satisfy the functions of the operations. In addition, pollution control
operations are required to handle the multimedia (air, water, and solid)
effluents from the three process operations. The pollution control opera-
tions can be conveniently grouped into air pollution control, water pollution
control, and solid waste management modules. The selection of specific
2-3
-------
r
~i
Population
of Systems "~
Section 2
Description of
Technologies
and
Preliminary
Screening
Candidate
Systems
Section 3
Selection of
"Best Candidate"
Systems
I
NJ
I
•P-
"Best Candidate"
Systems
Section 1
Selection of
Best Systems
and
Executive Summary
Detailed Analysis
Economic
Energy
Environmental
Section
4
5
6
Figure 2.1-1. Schematic of study approach.
-------
processes for a process or pollution control module depends on the intended
use of the low- or medium-Btu gas, the product specifications associated
with that end use, and the requirements of the other processes within an
integrated gasification system. The process modules and their general
relationship within a system are depicted in Figure 2.1-2. The various
pollution control modules which may be required in a gasification system are
also listed in Figure 2.1-2.
In the following text, the purpose of the three basic operations and
pollution control modules is discussed and a list of available processes is
presented. Again, it is not possible to identify a process or set of pro-
cesses to be used in a specific facility. Those are decisions that must be
made when the facility is being designed, and will depend on plant location,
the available coal feed, the desired product gas specifications, and economic
and environmental considerations.
2.1.1.1 Coal Pretreatment—
The primary function of the coal pretreatment operation is to supply a
coal feed which satisfies the physical specifications of the gasification
operation. Coal handling and storage modules are generally required in
this operation. The need for other processing modules such as grinding and
screening depends on the nature of the coal feedstock and the requirements
of the other coal pretreatment modules and the gasification operation.
Coals having excess moisture may need to be dried while caking bituminous
coals may need to be partially oxidized to reduce their caking tendencies.
The feed coal must be crushed and sized for fixed-bed gasifiers or
pulverized for fluid-bed or entrained-flow gasifiers. Fines from crushing
processes which cannot be fed directly to a fixed-bed gasifier can either
be sold as a by-product, consumed to supply on-site fuel needs, or
briquetted and fed to the gasifier. Table 2.1-1 lists the functions and
equipment used in each of the seven coal pretreatment process modules
indicated in Figure 2.1-2.
2-5
-------
I Coa
N?
I
Opemt Ion
Partial Oxidation
Crushing
SUlflR
Pulverizing
Storage
Conveying
_1 Coal Gasification
Operation
- Can PurlHcatlo
Operation
Air
Pollution Control Operations
Sulfur Control
Hydrocarbon Control
Nitrogen Oxides Control
Oil/Water Separation
Suspended Solids Removal
Dissolved Organica Renoval
Hitsolved Inorganlcn Rewoval
Chemical Fixation
Sludge Reduction
Landfill
Figure 2.1-2. Low- or medium-Btu coal gasification system process and pollution control modules.
-------
TABLE 2.1-1. FUNCTIONS OF MODULES IN COAL PRETREATMENT OPERATION
Module
Function
Equipment Used
N>
I
Handling/ Movement of coal to and from other pretreat-
Transportation ment modules and to the gasification operation.
Storage Provides adequate reserves to allow for
supply/demand surges (mine or gasification
plant downtime) and possibly blending
capability to provide a uniform feed to
the gasification operation.
Crushing/ Size reduction and elimination of over- and
Sizing underslze coal particles from a fixed-bed
gaslfier feed stream. Size specifications
dictated by mechanical characteristics of
gaslfier.
Briquet ting Compaction of coal fines to produce a
briquette of a size suitable for feed to a
fixed-bed gasifier. Certain binders, such
as asphalt or tar, may be required, along
with a baking or curing step, to give the
briquette the required structural strength.
Pulverizing Size reduction to provide a feedstock for a
fluid- or entrained-bed gasifier.
Drying Mechanical dewaterlng or heat treatment to
remove excess moisture from coal feed.
Partial Method of achieving a reduction in the caking
Oxidation tendencies of a feed coal by contacting the coal
with hot air or combustion gases under con-
trolled conditions (temperature; time) in a
suitable reactor.
Belt conveyors
Bucket elevators
Covered/uncovered bins - up to about 1.8 x 106
kg (2000 short tons) per bin; uncovered ptles
on ground for greater than 2.3 x 10* kg
(250,000 short tons)
Crushing - double and single roll crushers,
rotary breakers, impactora, cage mills
Sizing - Coarse (>50 mm [2 in.] particles) -
grizzly screens
Medium (>13 mm [Ij in.] particles) -
revolving, shaking or vibrating
screens
Fine (>2 mm (0.08 in.] particles) -
oscillating screens
Coal fines hopper, feeder and either a rotating
or a plate-type press along with provisions for
adding a binder. A baking oven may also be
required.
Hammer mills
Cage mills
Impactors
Ball mills
Mechanical: centrifugal; filtration
Thermal: fixed- or fluid-bed driers.
Same as thermal driers.
Source: Ref. 2-2
-------
2.1.1.2 Coal Gasification—
The function of the coal gasification operation is to produce a raw
low- or medium-Btu gas by reacting coal with a steam/air or steam/oxygen
mixture. If air is the source of oxygen, a low-Btu gas with a heating
value of around 5.6 K3/m3 (150 Btu/scf) is produced. When essentially pure
oxygen is used, a medium-Btu gas is produced with a heating value around
13.0 MJ/m3 (350 Btu/scf). Table 2.1-2 shows ranges in raw product gas
composition that are typical for coal-derived low- and medium-Btu gases.
TABLE 2.1-2. TYPICAL RAW PRODUCT GAS COMPOSITIONS
FOR LOW- AND MEDIUM-BTU GASES
Composition, vol. % (dry)
C02
CO
CH.»
H2
N2
HaS, ppmv
NHs , ppmv
HHV, MJ/m3 (Btu/scf)
Low-Btu Gas
3-14
16-29
1-5
11-23
40-63
400-6, 900a
b
4.8-7.3 (130-200)
Medium-Btu Gas
6-31
17-61
1-14
23-39
1-3
3, 700-15, 000a
b
9.4-13.9 (250-370)
HaS concentration is proportional to the coal sulfur content. Range shown
for medium-Btu gas and lower end of range for low-Btu gas are based on
available data. Upper end of range for low-Btu gas is what might be
expected from gasifying a 3.5 percent sulfur coal (based on engineering
calculations).
Amount dependent on coal nitrogen content and gasifier operating
conditions. Data are not available to give a representative range.
Source: References 2-2 through 2-18
2-8
-------
Numerous reactions occur when coal is gasified. Among the more impor
tant ones with respect to the major raw gas constituents are:
1) C + %02 + CO 4) 2H2 + C
2) H20 + C -> CO + H2 5) CO + 3H2 + CHU + H20
3) CO + H20 t C02 + H2
From the viewpoint of producing a clean fuel for use in an industrial boiler,
reactions involving the sulfur and nitrogen present in coal are of greater
interest than the reactions listed above. This is because these reactions
result in the formation of a variety of compounds which, if not removed in
downstream processing steps, can be oxidized to S02 and NO., in the boiler.
X
Included in the list of sulfur and nitrogen reactions products are:
H2S • NH3
COS • Cyanides
• CS2 • Thiocyanates
These compounds are formed from free radicals liberated from the coal mole-
cule as well as by reactions such as:
H2S + C02 + COS + H20
2H2S + C02 + CS2 + 2H20
Close to 70 different gasifiers have been used commercially in the past
or are currently under development (Ref. 2-2) (see Table 2.1-3). Among the
important characteristics which distinguish one gasifier from another are:
• Bed type
- Fixed or supported bed (includes moving bed designs)
- Fluidized bed
- Entrained bed
2-9
-------
TABLE 2.1-3. POPULATION OF LOW/MEDIUM-BTU GASIFIERS
Gasifier type
Gasitier name
Licensor/Developer
Status
Fixed-Bed. Dry Ash
Lurgl
Wellman-Galusha
Chapman (Wllputte)
Woodall-Duckhaa/Gaa Integrale
Rlley Morgan
Pressurized Wellman-Calusha
(MERC)
Foster Wheeler/Stoic
Kilngas
Kellogg Fixed Bed
GEGAS
Consol Fixed Bed
IFE Two Stage
Kerpely Producer
Marlschka
Plntsch Hillebrand
U.G.I. Blue Water Gas
Power Gas
Wellman Incandescent
BCR/Kaiser
American Lurgi Corp. (USA)
McDowell Wellman Engr. Co. (USA)
Wllputte Corp. (USA)
Woodall-Duckham. Ltd. (USA)
Rlley Stoker Corp. (USA)
Morgantown Energy Research Center/
ERDA (USA)
Foster Wheeler Energy Corp. (USA)
Allls Chalmers Corp. (USA)
M. W. Kellogg Co. (USA)
General Electric Research and
Development (USA)
Consolidation Coal Co. (USA)
International Furnace Equipment
Co., Ltd.
Bureau of Mlnes/ERDA (USA)
Unknown
Unknown (Germany)
U.G.I. Corp./DuPont (USA)
Power Gas Co. (USA)
Applied Technology (USA)
Unknown
Present commercial operation
Present commercial operation
Present commercial operation
Present commercial operation
Present demonstration unit testing;
commercially available
Present development unit testing
Demonstration unit planned
Present development unit testing;
commercially available
Present development unit testing
Present development unit testing
Present development unit testing
Past commercial operation
Past commercial operation
Past commercial operation; anthracite
or coke only
Past commercial operation
Past commercial operation; coke only
Past commercial operation
Present commercial operation
Past development unit testing
Fixed-Bed. Slagging Ash
BGC/Lurgi Slagging Gasifier
GFERC Slagging Gasifier
Luena
Thyssen Galocsy
British Gas Council (GB)
Lurgl Mlneralbltechnlk (W. Germany)
Grand Forks Energy Research
Center/ERDA (USA)
Unknown
Unknown
Present development unit testing
Present development unit testing;
lignite only
Past commercial operation; coke only
Past commercial operation; coke only
(Continued)
2-10
-------
TABLE 2.1-3. Continued
Gasifier type
Gaslfier name
Licen3or/Developer
Status
Fluidized-Bed. Dry Ash
Winkler
Hygas
Synthane
Hydrane
Cogas
Exxon
BCR Low-Btu
COz Acceptor
Electrofluidlc Gasification
LR Fluid Bed
HRI Fluidlzed Bed
BASF-Flesch-Demag
GECB Marchwood
Heller
Fluidlzed-Bed. Agglomerating A«h
U-Gas
Battelle/Carblde
Westinghouse
City College of NY Mark 1
Two-stage Fluldlzed
ICI Moving Burden
Entrained-Bed. Dry Ash
Garrett Flash Fyrolysls
Blanch!
Davy Powergas Co. (USA)
Institute of Gas Technology (USA)
Pittsburgh Energy Research Center/
ERDA (USA)
Pittsburgh Energy Research Center/
ERDA (USA)
Cogas Development Co. (USA)
Exxon Corp. (USA)
Bituminous Coal Research (USA)
Consolidation Coal Co. (USA)
Iowa State Univ./ERDA (USA)
Unknown (Germany)
Hydrocarbon Research Inc. (USA)
Badische Anilln und Soda Fabrlk
(Uesc Germany)
Unknown
Unknown (Germany)
Institute of Gas Technology (USA)
Battelle Memorial Institute (USA)
Westlnghouse Electric Corp. (USA)
Hydrocarbon Research Inc. /A.M.
Squires (USA)
British Gas Council (England)
Imperial Chemical Industries, Ltd.
(England)
Garrett Research and Development
Co. (USA)
Unknown (France)
Present commercial operation
Present development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Past commercial operation
Past development unit testing
Past development unit testing
Past development unit testing
Past development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Past development unit testing
Present development unit testing
Past development unit testing;
lignite only
(Continued)
2-11
-------
TABLE 2.1-3. Continued
Gasifler type
Caslfler name
Licensor/Developer
Statin
Panlndco
USBM Annular Retort
USBM Electrically Heated
Entrained-Bed. Slagging Ash
Koppera-Totzek
Bi-Gas
Texaco
Coalex
PAMCO/Foster Wheeler
Combustion Engineering
Brigham Young University
Babcoclc and Wilcox
Ruhrgas Vortex
IGT Cyclonizer
Inland Steel
USBM, Morgantown
Great Northern Railway
FRS Cyclone
Molten Media. Slagging Ash
Kellogg Molten Salt
Atgas/Patgas
Rockgas
Runnel Single Shaft
Sun Gasification
Otto-Hummel Double Shaft
Source: Ri'f. 2-2
Unknown (France)
Bureau of Mines/ERDA (USA)
Bureau of Mlr.es/ERDA (USA)
Koppera Co. (USA)
Bituminous Coal Research, Inc.
(USA)
Texaco Development Corp. (USA)
Inex Resources, Inc. (USA)
Pittsburgh and Midway Coal Co./
Foster Wheeler (USA)
Combustion Engineering (USA)
Brigham Young University/
Bituminous Coal Research (USA)
The Babcock and Wilcox Co. (USA)
Ruhrgas A. G. (West Germany)
Institute of Gas Technology (USA)
Inland Steel Co. (USA)
Morgantown Energy Research
Center/ERDA (USA)
Great Northern Railway Co. (USA)
Unknown (England)
M. W. Kellogg Co. (USA)
Applied Technology Corp. (USA)
Atomics International (USA)
Union Rhelnische Braun Kohlen
Kraftstoff A. G. (West Germany)
Sun Research and Development Co.
(USA)
Dr. C. Otto and Co.
Past development unit testing;
lignite only
Past development unit testing;
lignite only
Past development unit testing
Present commercial operation
Present development unit testing
Present development unit testing
Present development unit testing;
commercially available
Present development unit testing
Present development unit testing
Present development unit testing
Past commercial operaclon
Past commercial operation
Past development unit testing
Past development unit testing
Past development unit testing
Past development unit testing
Past development unit testing
Present development unit testing
Present development unit testing
Present development unit testing
Past commercial operation
Past development unit testing
Past development unit testing
2-12
-------
• Operating conditions
- Pressure: atmospheric or pressurized
- Temperature
Gasification media
- Reactants: steam, air, oxygen, other additives
- Coal feed/reactant ratios
- Mode of reactant introduction
Coal feeding
- Mode: continuous or intermittent
- Mechanism: lock hopper, slurry, screw, etc.
- Location: top or center of gasifier
• Ash removal
- Mode: continuous or intermittent
- Ash condition: dry or slagged (fused)
- Location: from the gasifier or from the product
gas stream
• Energy input for gasification
- Autothermic: energy supplied by partial
combustion of the feed coal in the gasifier
- Electrothermic: energy supplied by electrical
resistance heating
- Solids circulation/heat transfer: energy
supplied by external heating and circulation
of additives or inert solids
2.1.1.3 Gas Purification—
With respect to producing a clean fuel, the most important part of a
coal gasification system is the gas purification operation. The purpose of
this operation is to remove undesirable constituents such as particulates,
tars, oils, and acid gases from the raw product gas. The modules needed
to satisfy these cleanup requirements include:
2-13
-------
particulate removal,
• gas quenching and cooling, and
• acid gas removal.
A. Particulate Removal—Removal of coal dust, ash and tar aerosols
entrained in the raw product gas leaving the gasifier is the primary function
of this module. Specific processes commonly used to accomplish this are:
• cyclones,
electrostatic precipitators (ESP), and
• water or oil scrubbers.
B. Gas Quenching and Cooling—In the gas quenching and cooling module,
tars and oils are condensed and particulates and other impurities such as
ammonia and cyanides are scrubbed from the raw product gas. Quenching
involves the direct contact of the hot raw gas with an aqueous or an organic
quench liquor. Extensive cooling of the gas stream occurs initially, pri-
marily through vaporization of the quenching medium. Further gas cooling
can be accomplished using waste heat boilers followed by air- and/or water-
cooled heat exchangers.
C. Acid Gas Removal—Acid gases such as HaS, COS, CSz, mercaptans, and
SOa are removed from the raw product gas in this module. The commercially
available acid gas removal processes, all of which operate at temperatures
below 150°C, can be divided into the following categories:
Physical Solvent Processes
Chemical Solvent Processes
Combination Chemical/Physical Solvent Processes
Direct Conversion Processes
• Catalytic Conversion Processes
Fixed-Bed Adsorption Processes
2-14
-------
Table 2.1-4 lists 70 low-temperature acid gas removal processes and their
development status identified from available information (Ref. 2-2). A brief
description of the processes in each of the six categories is given in the
following text .
Physical solvent processes remove acid gases from the raw product gas
by physical absorption in an organic solvent. They are most suited for high
pressure applications because the solubilities of acid gases in the solvents
are directly proportional to the acid gas partial pressure. Most of the sol-
vents used in these processes have an appreciably higher affinity for H2S
than for COa, and can, therefore, be used in a manner that allows for selec-
tive removal of
Chemical solvent processes remove acid gases by adsorption followed by
formation of a chemical complex between the acid gas and solvent. In most
of these processes the solvent is regenerated by thermal decomposition of
the chemical complex. These processes are generally identified by the type
of solvent used. Amine, ammonia, and alkaline salt solutions are the three
solvents in common use.
Combination chemical/physical solvent processes use a physical solvent
together with an alkanolamine chemical solvent additive. Both the chemical
and the physical solvents remove COa , HaS, and HCN; but the physical solvent
is primarily responsible for the removal of acid gases such as CSa, mercap-
tans, and COS.
Direct conversion processes remove H2S by adsorption, with subsequent
oxidation of the sorbed H2S to elemental sulfur. These direct conversion
processes are divided into two general categories: dry oxidation and liquid
phase oxidation.
Catalytic conversion processes are divided into two categories: a)
those that convert organic sulfur to HaS, and b) those that convert organic
sulfur and HaS to SC-2. Most of these processes are generally not considered
2-15
-------
TABLE 2.1-4. LOW-TEMPERATURE ACID GAS REMOVAL PROCESSES
Process Category
Process Name and Status
Physical Solvent
Selexola>e
Fluor solvent3
Purisola
Rectisola»e
Estasolvan3
Union Oilb
Solvent
- Amine Solvent
- Alkaline Salt Solution
- Ammonia Solution
Combination Chemical/Physical
Solvent
Mono e thanolamine (MEA)a
Diethanolamine (DEA)a
Triethanolamine (TEA)a
Methyldiethanolamine (MDEA)a
Glycol-aminea
Diisopropanolamine (DIPA)a
Diglycolamine (DGA)a
Caustic Washa
Seaboard0
Vacuum Carbonate0
Hot Potassium Carbonate3
Catacarb3
Tripotassium Phosphate0
Benfielda»e
Alkazid*
Sodium Phenolate0
Lucasa
Chemo Trenna
Collinsa
Amisola
Sulfinola
Direct Conversion
- Dry Oxidation
- Liquid Oxidation
Iron Oxide (Dry Box)a
Activated Carbona
Clausa
Great Lakes Carbon Co.b
Burkheiserc
Ferroxc
Knoxob
Gluddc
Manchester0
Cataband
Thyloxc
2-16
-------
TABLE 2.1-4. Continued
Process Category
Process Name and Status
Direct Conversion
- Liquid Oxidation (Cont'd)
Catalytic Conversion
- Organic Sulfur to HzS
- Organic Sulfur to
and SO 2
Fixed-Bed Adsorption
Giammarco-Vetrocoke3
Fischer3
Staats.tijnen-Otto/Autopurif ication3
Peroxc
Stretforda»e
Takahax3
CASd
Townsend"
Wiewiorowskid
Sulfonlyd
Nalcod
Sulphoxided
Permanganate and Dichromate3
Lacey-Kellerd
Sulfoxd
Direct Oxidation3
Carpenter Evans3
Peoples Gas Co.3
Holmes-Maxteda
British Gas Councild
Iron Oxide Catalysts3
Chromia-Aluminum Catalystsd
Copper-Chromium-Vanadium
Oxide Catalystsd
Cobalt Molybdenum Catalysts3
App1eby-Frod ingham3
Katasulf3
North Thames Gas Board3
Soda Iron3
Activated Carbon3
Hainesd
Molecular Sieve3
Zinc Oxide3
Commercially Available
blinder Development
C0bsolete/Inactive
dPilot Plant
eHave been used or are being used in commercial or demonstration
gasification plants
Source: Ref. 2-2, 2-17, 2-19 through 2-35
2-17
-------
to be acid gas removal processes; however, they can be used to convert hard-
to-remove acid gases such as COS, CSz, and mercaptans into compounds such as
H2S and SOz, which can then be handled by other acid gas removal processes.
Fixed-bed adsorption processes remove acid gases by adsorption on a
fixed sorbent bed. The amount of acid gases removed is dependent on the
surface area available for adsorption. Regeneration of the sorbent is
generally accomplished by thermal methods.
2.1.1.4 Pollution Control Operations—
Air emissions, liquid effluents, and solid wastes from the process
operations just described will require pollution control modules. The
function of these modules is to achieve levels of control that are consistent
with environmentally acceptable plant practices.
A. Air Pollution Control—Air pollutants from low-Btu gasification
processes are primarily coal dust, coal feeder vent gases, combustion gases,
process tail gases and tank vents. These streams are processed in various
combinations of control modules to achieve particulate control, sulfur
control and recovery, hydrocarbon control and nitrogen oxides control. A
flow diagram of these modules is presented in Figure 2.1-3. In this figure,
the gaseous effluents which may be directed to these four modules and
potential flow paths between the modules are identified. The nature of the
contaminated gaseous effluents dictate which modules are required to treat
the gases.
1) Particulate Control Module - Coal dust from the coal pretreatment
and coal gasification operations are the principal particulate emissions
requiring control. Other emission sources include the ash handling system
and the permanent coal storage pile. The severity of the particulate
emission problem will vary from site to site. Water sprays are used at coal
conveying transfer points at some sites; however, these may or may not be
effective control devices.
2-18
-------
Figure 2.1-3. Flow diagram for the modules in the air pollution control operation.
-------
The many processes and variations of processes that could be used to
control particulate emissions from coal gasification processes are
generally divided into the following four categories, based on the
collection mechanism used:
• Mechanical collectors
- Settling chambers
- Cyclones
- Filters
• Electrostatic precipitators
• Wet collectors
- Spray chambers
- Wet scrubbers
• Afterburners
2) Sulfur Control Module - All operations in low- or medium-Btu coal
gasification plants are potential sources of sulfur-bearing gaseous
effluents. Examples of these effluents are:
• Tail gases from the acid gas removal module,
• On-site power generation flue gases,
• Vent gases from the water pollution control module,
• Coal feeder vent gases from the coal gasification
module, and
• Gases from the particulate control module.
The function of the sulfur control module is to reduce the concentrations
of the sulfur compounds such as HzS, COS, CSa, and SC-2 to levels acceptable
for discharge to the environment.
2-20
-------
The processes capable of removing sulfur compounds from gas streams can
be divided into three general categories.
• primary sulfur recovery processes,
• tail gas cleanup processes (secondary recovery), and
• sulfur oxides control processes.
The principles of operations of the sulfur control processes are discussed
in the following paragraphs.
There are numerous processes based on removal of sulfur compounds from
gas streams, followed by recovery of the sulfur as a by-product. These direct
conversion processes can be classified as either dry oxidation or liquid phase
oxidation and are listed in Table 2.1-5. The principle of operation involves
the oxidation of sulfur compounds to elemental sulfur, which is a salable by-
product. The two most widely used direct conversion processes are the Claus
(dry oxidation) and the Stretford (liquid phase oxidation) processes.
TABLE 2.1-5. DIRECT CONVERSION PRIMARY SULFUR RECOVERY PROCESSES
Dry Oxidation Processes
Iron Oxide (Dry Box) Sulfreen
Activated Carbon Great Lakes Carbon
Claus
Liquid Oxidation Processes
Burkheiser Stretford
Ferrox Takahax
Konox C.A.S.
Fludd Townsend
Manchester Wiewiorowski
Cataban Sulfonly
Thylox Nalco
Giammarco-Vetrocoke Sulphoxide
Fischer Permanganate and Dichromate
Staatsmijnen-Otto Lacey-Keller
Autopurification Sulfox
Perox Direct Oxidation
References: 2-19, 2-23, 2-29
2-21
-------
Tail gas cleanup processes are used to remove and, in some cases,
recover the sulfur compounds remaining in the tail gases of primary sulfur
recovery processes. These processes, when combined with a Glaus unit for
example, can provide an overall sulfur removal effectiveness of up to 99.9+
percent. Commercially available tail gas cleanup processes are classified
as follows:
Process Type Process Name
Removal of sulfur compounds and Beavon
recovery of elemental sulfur Cleanair
CBA
Sulfreen
Reduction of sulfur compounds SCOT
to HaS which is recycled to a Trencor-M
Claus unit
Sulfur oxides control processes are not major functions within coal
gasification plants. They are primarily flue gas desulfurization
processes and are generally used to control sulfur emissions from on-site
coal-fired heaters and boilers.
3) Hydrocarbon Control Module - The function of this module is to
reduce the hydrocarbon content of process tail gases, vent streams and other
waste streams to levels acceptable for discharge to the environment. There
are two basic methods of hydrocarbon control: afterburners and adsorbers.
Afterburners simply convert hydrocarbons to COa and HaO by oxidation.
Adsorbers use sorbents such as activated carbon to remove the hydrocarbons
from the gas stream.
4) Nitrogen Oxides Control Module - A nitrogen oxide control strategy
for the combustion gases emitted from coal or low/medium-Btu gas-fired
boilers and furnaces may be required. NO* formation in the gasification
module is expected to be low since the raw gas passes through a reducing
atmosphere before leaving the gasifier. The nitrogen that does react in
2-22
-------
the gasifier should form NHa , HCN, thiocyanates, and other nitrogen-
containing organics rather than nitrogen oxides (Ref. 2-36). There are
three basic processes that can be used to control NOx emissions from
boilers and furnaces:
• Combustion modifications,
• Post-combustion flue gas cleaning, and
• Fluidized-bed combustion.
These are processes which would not be considered central to those in coal
gasification plants.
B. Water Pollution Control—In a coal gasification facility, the
specific sources which generate wastewaters will determine the type of
contaminants that are present in those streams. Wastewater sources in a
coal gasification plant are shown in Figure 2.1-4 along with descriptions
of the particular type of wastewaters they generate. Typical wastewaters
and the modules required to treat them are shown schematically in Figure
2.1-5.
The suspended solid contaminants are primarily particulates that are
generated when the coal is crushed and sized and/or when ash is quenched as
it is discharged from the gasifier. Dissolved and suspended organics are
volatile hydrocarbons that are condensed in the quench liquor during the
subsequent raw gas cooling step. Dissolved inorganic gas contaminants such
as C02, H2S, and NHs are produced in the same manner as the dissolved
organics. Dissolved salts accumulate when reuse of the upgraded wastewaters
is maximized. At higher concentrations, salts begin to scale-out on heat
exchanger and process equipment surfaces; consequently, close monitoring of
dissolved solids in the wastewater will be an essential control practice.
The various types of processes which can be used to satisfy the
requirements of the four water pollution control modules are listed below:
2-23
-------
WATER SPRAY
RUN-OF-MINE
COAL
to
I
N>
OXYGEN
RODUCT^
COAL STORAGE
AND
PRETREATMENT
ACID
GAS
REMOVAL
COAL PILE RUNOFF;
COAL WASHING/
CLEANING PROCESS
WASTES
ORGANIC
SEPARATION
PROCESS
BY-PRODUCT
TARS AND OILS
TO STORAGE
ASH QUENCHING/
SLUICING WATER
PROCESS
CONDENSATE
COOLING TOWER
SLOWDOWN
BOILER SLOWDOWN
AND WATER TREAT
MENT WASTES
WASTEWATER
TREATING
CLEAN
PRODUCT
GAS
^ RECOVERED BY-PRODUCT,
NH3 AND PHENOLS
RECLAIMED
WATER
Figure 2.1-4. Major process modules generating wastewater in a typical coal gasification plant.
-------
NJ
I
Ln
EVAPORATION
PONDS
WATER RECYCLE
TO COOLING
TOWERS OH
ASH QUENCH
LEGEND
AIR EM3SIONS
~]—a LIQUID EFFLUENTS
"TV. SOLID WASTES
Figure 2.1-5. Flow diagram for the modules in the water pollution control operation.
-------
• Oil/Water Separation and Suspended Solids Removal Modules
- Oil/water separator
- Filtration
Flocculation/flotation (dissolved air)
Dissolved Organics Removal Module
- Extraction
- Adsorption
- Biological treatment
- Cooling tower oxidation (stripping)
• Dissolved Inorganics Removal Module
Stripping
- Brine concentration
Ion exchange
- Membrane desalination
C. Solid Waste Pollution Control—The solid waste pollution control
module treats and disposes of the following classes of wastes:
• Ash
• Coal residue
• Biological oxidation sludge
• Spent catalysts and filter media
Coal fines
• Sulfur
Coal fines may be collected and burned on site; coal fines and sulfur may
be sold as by-products. The other wastes may or may not require treatment
before disposal, depending upon their composition. Chemical fixation and
sludge reduction modules can be used to treat these solid wastes. Figure
2.1-6 is a flow diagram of the modules for solid waste control. Landfill
by definition, is the ultimate disposal technique for these wastes.
2-26
-------
NJ
I
LEGEND
AM EMISSIONS
LIQUID EFFLUENTS
•-K. SOLID WASTES
Figure 2.1-6. Flow diagram for the modules in the solid waste control operation.
-------
2.1.2 Status of Technology
The production of low- and medium-Btu gas from coal has been practiced
both in the United States and overseas for many years. It is estimated that
at one time there were some 11,000 coal gasifiers in use in the U.S. But
as the availability of natural gas increased, the number of operating
gasification systems declined significantly. At the present time there are
only a few coal gasifiers operating in the United States on a commercial
basis (Ref. 2-37). However, in general low/medium-Btu coal gasification can
be regarded as being commercially available.
2.1.2.1 Status of Coal Pretreatment Processes—
The coal pretreatment processes which may be required in a low- or
medium-Btu coal gasification plant (see Table 2.1-1), with the exception of
partial oxidation, have been used for years in the gasification, coal-fired
electric utility and charcoal industries (Ref. 2-38). However, much work,
e.g., the Bureau of Mines work with the Synthane Process, has been done to
develop a reliable partial oxidation process for reducing the caking
tendencies of certain types of coal (Ref. 2-39). Therefore, the development
status of all of the coal pretreatment processes is such that they can be
regarded as commercially available.
2.1.2.2 Status of Gasification Processes—
Low- and medium-Btu gasification systems being considered today are in
varying stages of development. The development status of the 70 gasifiers
which have been used commercially in the past or are currently under
development are shown in Table 2.1-3 (Ref. 2-2). A number of the smaller
systems are commercially available, and a few (Wellman-Galusha and Chapman)
are operating in the United States. Several of the other systems, e.g.
the Lurgi and the Koppers-Totzek, have been or are currently operating
commercially in foreign countries.
2-28
-------
As part of an environmental assessment of low- and medium-Btu gasifica-
tion technology, Radian Corporation has compiled a list of fourteen gasifiers
which appear to be the most promising candidates for satisfying near-term
commercial needs for low/medium-Btu gas. This list is shown in Table 2.1-6.
TABLE 2.1-6. PROMISING LOW- AND MEDIUM-BTU GASIFICATION SYSTEMS
First Group1 Second Group2 Third Group
3
Wellman-Galusha Chapman (Wilputte) Pressurized Wellman-
Galusha (MERC)
Lurgi Riley Morgan
Woodall Duckham/ BGC/Lurgi Slagging
Gas Integrale Gasifier
Koppers-Totzek Texaco
Winkler Bi-Gas
Wellman Incandescent Coalex
Foster-Wheeler/Stoic
Commercially available; significant number of units currently operating in
the U.S. or in foreign countries.
Commercially demonstrated in limited applications.
Commercial or demonstration-scale units operating or being constructed;
technology is promising and should be monitored.
Source: Ref. 2-37
The major criterion used in making these selections was development status
(Ref. 2-2). There are many gasifiers which are not likely to be used in the
near future. These include gasifiers that have been operated in the past but
have been abandoned for various reasons. Other gasifiers are in such early
stages of development that their technical and economic feasibility cannot be
adequately assessed. All gasifiers that are not either commercially available
or currently being tested on a demonstration or large pilot-plant scale were
not included in the list of promising processes (Ref. 2-2). While the major
factor in Radian's selections was development status, consideration was also
given to 1) applicability to low/medium-Btu gasification, 2) energy efficien-
cy, 3) process limitations, 4) environmental impacts and 5) costs (Ref. 2-2).
2-29
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2.1.2.3 Status of Gas Purification Processes—
The processes for quenching/cooling and removing particulates from raw
low-or medium-Btu gas are commercially proven (Ref. 2-40). For acid gas
removal, either high (>150°) or low temperature processes can be used in
theory. However, while high temperature processes have thermal advantages,
they are unfortunately only in the development stage. For this reason exist-
ing and proposed gasification plants use low temperature processes (Ref. 2-5,
2-41, 2-42, 2-43, 2-44). Although most of the available processes (see Table
2.1-4) were developed for use in the natural gas, coking, refinery and chemi-
cal process industries, there do not appear to be any prohibitive technical
problems associated with their use in coal gasification plants.
In 'a previous Radian environmental assessment of low- and medium-Btu
gasification technology, fourteen promising acid gas removal processes
were selected from the low temperature acid gas removal systems summarized
in Table 2.1-4. These fourteen processes are listed in Table 2.1-7.
TABLE 2.1-7. PROMISING ACID GAS REMOVAL SYSTEMS
Process category Process name
Physical solvent Rectisol
Selexol
Purisol
Estasolvan
Flour solvent
Chemical solvent MEA (monoethanolamine)
MDEA (methyldiethanolamine)
DEA (diethanolamine)
DIPA (diisopropanolamine)
DGA (diglycolamine)
Benfield
Combination chemical/physical solvent Amisol
Sulfinol
Direct conversion Stretford
Source: Ref. 2-2
2-30
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The criteria for the selection of these fourteen systems were their appli-
cability to low/medium-Btu gasification, development status, environmental
impacts, energy requirements, costs, and process limitations (Ref. 2-2).
2.1.3 Applicability and Limitations
Both low- and medium-Btu gas are suitable fuel sources for industrial
boilers (Ref. 2-45). While their combustion characteristics are somewhat
different than those of natural gas, those differences can be compensated
for in the design of a new boiler. For retrofit situations use of either
synthetic fuel will require at least modification or replacement of the
burners and fuel lines. Use of low-Btu gas will also slightly derate
(<10% for a 6 MJ/m3 low-Btu gas) a natural gas-fired boiler (Ref. 2-46).
However, these disadvantages are off-set by the capital cost savings that
result from being able to use the existing boiler.
There are several important factors to be considered in making a choice
between using low- and medium-Btu gas. First, and most important, is the
cost of the fuel gas. Industrial boiler operators are cost sensitive and
are likely to select the system which offers the lowest cost. Other factors
which are also important include the availability of land and environmental
considerations.
Medium-Btu gasification systems require a greater capital investment per
unit of energy produced than low-Btu systems. This is due mainly to the
medium-Btu system's need for an oxygen production unit, but also reflects
the greater complexity of medium-Btu systems. In order to take advantage
of economies of scale and hence reduce the cost of the product gas, medium-
Btu gasification facilities tend to be large capacity installations. Such
is the case for the Lurgi medium-Btu plants currently operating overseas in
Yugoslavia and South Africa. In comparison to the fuel needs of even a
large industrial boiler (117 MW heat input or 400 x 106 Btu/hr), a medium-
Btu gasification facility would have a much larger capacity (>1500 MW or 5.1
x 109 Btu/hr). On the other hand, low-Btu systems typically have capacities
2-31
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similar to those of industrial boilers: 10 to 118 MWT (30-400 x 106 Btu/hr) .
Thus, unless the medium-Btu gas could be used in more than one industrial
boiler, low-Btu gas appears to be a better choice.
In addition to costs, land availability and environmental considerations
are important factors. Although a low-Btu gasification facility does not
require substantial land area, a gasification/boiler facility will require
more land than a boiler by itself. If this additional land is not available
an alternative would be to site the fuel generation facility offsite and pipe
the fuel gas to the boiler. Also, there are environmental discharges asso-
ciated with a gasification facility. Depending on local conditions, it may
be impossible to install a new emission source at or near the boiler site.
If so, off-site fuel generation would again be an alternative. In either of
these situations where the fuel gas must be transported, medium-Btu gas has
an economic advantage over low-Btu gas because of its greater energy content
CVL3 MJ/m3 vs ^6 MJ/m3 for low-Btu gas), and hence lower transportation costs,
2.1.4 Factors Affecting Performance
The performance of low- and medium-Btu coal gasification systems as
emission control techniques for industrial boilers depends on the performance
of the gas purification operation. And, more specifically, it depends on the
performance of the acid gas removal unit in removing HaS and organic sulfur
compounds (predominantly COS) from the product gas. Under proper operating
conditions, i.e., temperatures, pressures, etc., the chemical, physical, and
combination chemical/physical solvent acid gas removal processes listed in
Table 2.1-7 are capable of effecting essentially complete removal of sulfur
species from the synthetic gases (Ref. 2-2). Unfortunately, the minimum
operating pressure for complete sulfur species removal for these processes
ranges from around 1.4 MPa for some of the amine processes to around 6.9 MPa
for most of the physical solvent processes (Ref. 2-23). While at operating
pressures below those just stated, the system's performance is lessened, the
extent to which system performance is affected is not known. However,
2-32
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because the amine processes use chemical means to absorb acid gases, they are
affected less by pressure than the physical solvent processes.
The removal efficiency of direct conversion processes, such as the
Stretford process, is not significantly affected by the gas stream pressure
(Ref. 2-23). However, while these processes are very effective in removing
HaS, they are not effective in removing organic sulfur compounds (Ref. 2-2).
Thus, the performance of a gasification system employing a direct conversion
acid gas removal process is limited by the organic sulfur content of the
raw product gas.
2.1.5 System Performance
Currently, there are no data available on the actual emissions resulting
from combustion of low- or medium-Btu fuel gas derived from coal in indus-
trial boilers. However, based on typical fuel gas compositions and limited
small-scale tests, estimates of emissions can be made. These estimates as
well as a discussion of the impact of utilizing low- and medium-Btu gas in
industrial boilers are presented in the following sections. For all situa-
tions addressed here, it is assumed that the gasification system includes
quenching/cooling and acid gas removal.
2.1.5.1 Emissions Reduction Potential—
By incorporating particulate removal and quenching/cooling in a coal
gasification system, essentially all of the entrained particulates, and 99+%
of the tars and oils can be removed from the low- or medium-Btu product gas.
This can be accomplished by using cyclones (60-80 percent removal of the
incoming particulates and heavy tars), water or oil scrubbers (60-70 percent
removal of the incoming tars and oils), and/or electrostatic precipitators
that can be designed to remove up to 99 percent of the residual particulates,
tars, and oils (Ref. 2-36, 2-47, 2-48, 2-49). The cleaned synthetic gases
are essentially particulate free, and any residual tar and oil aerosols
2-33
-------
should be destroyed during combustion. Thus, negligible particulate emis-
sions will result. This implies that low- or medium-Btu gasification effects
essentially complete control of particulate emissions from the utilization
of coal in an industrial boiler.
When coal is combusted, NOX emissions range from 270 ng NOX/J (0.63
lb/106 Btu) for small boilers to 400 ng/J (0.93 lb/106 Btu) for larger indus-
trial boilers (Ref. 2-1). Limited laboratory tests on the combustion of low-
or medium-Btu gas have indicated that NOX emissions are similar to (Ref.
2-36) or less than (Ref. 2-50) those produced by the combustion of natural
gas (50-100 ng NOX/J) (Ref. 2-1). These results are for fuel gases contain-
ing very little, if any, ammonia or cyanide compounds. For gasification
systems with quenching/cooling and acid gas removal processes, this is a
reasonable assumption. However, if ammonia and cyanides are present, they
will be oxidized, by varying degrees, to NOX (Ref. 2-36, 2-50).
When coal is converted into low- or medium-Btu gas, approximately 90-98
percent of the coal sulfur is converted to hydrogen sulfide (H2S) (Ref. 2-5
2-6, 2-49). Under the proper operating conditions, the acid gas removal
processes listed in Table 2.1-7 can remove essentially all (99+ percent) of
the H2S in a gaseous stream (Ref. 2-2, 2-4, 2-23, 2-51, 2-52, 2-53, 2-54).
Thus, low- and medium-Btu coal gasification can effect at least 90-1- percent
control of sulfur emissions resulting from utilizing coal in industrial
boilers.
In terms of SOa emissions per unit heat input to the boiler, a repre-
sentative range for coal derived gases is 40-130 ng S02/J (0.09-0.30 lb/106
Btu), as determined from residual sulfur levels remaining after treatment
by an acid gas removal process. This compares to uncontrolled emissions of
510-2420 ng S02/J (1.18-5.62 lb/106 Btu) for direct combustion of 0.6-3.5
percent sulfur coal (Ref. 2-1).
2-34
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2.1.5.2 Impacts on the Boiler—
The use of coal derived low- or medium-Btu gas in a new industrial
boiler has several advantages over a direct coal-fired boiler. First, a gas-
fired boiler is a much simpler piece of equipment to operate than a coal-
fired boiler. There is no need for ash handling equipment and the only fuel
handling equipment required is piping. Second, due to the less complex
nature of gas-fired boilers, maintenance requirements will be less than for
a coal-fired boiler.
On the other hand, the production and use of coal derived gases in an
industrial boiler can have adverse impacts. The primary concerns are the
reliability/operability of the gasification system and how that affects the
desired operability of the boiler. In order to minimize adverse impacts,
installation of spare capacity or sparing of key process units in the gasi-
fication system may be required. Another alternative would be to provide a
backup fuel source (such as distillate fuel oil) for the boiler. Incorpo-
rating any of these options into a gasification/steam generation system
design must be made on a case by case basis, taking into consideration the
particular requirements of the boiler system. In addition, in the selection
and design of the boiler, consideration must be given to the different com-
bustion characteristics (e.g., heat release rate and flame temperatures) of
coal-derived gases versus natural gas.
2.2 HIGH-BTU COAL GASIFICATION
High-Btu coal gasification is a technology being developed to convert
our country's vast coal resources into synthetic natural gas (SNG). High-
Btu gasification is merely an extension of medium-Btu gasification. While
the latter process produces a product gas with a high CO and H2 content,
high-Btu systems go one step further and convert the H2 and CO into methane.
Since this methanation step (as well as the shift conversion reaction
required prior to methanation) involves an exothermic reaction, the energy
conversion efficiency of a high-Btu system is lower than a medium-Btu system.
2-35
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The lower energy conversion efficiency, along with the added capital costs
for the methanation and shift conversion units, result in higher costs for
high-Btu gas (versus medium-Btu gas). Thus, unless an unusual set of site
specific conditions exist, medium-Btu gas is economically more attractive
than high-Btu gas for use in an industrial boiler.
In light of the above considerations, it does not seem appropriate to
consider high-Btu coal gasification as an emission control technique for
industrial boilers. Accordingly, high-Btu gasification is not addressed
further in this technology assessment report.
2.3 COAL LIQUEFACTION
Coal liquefaction is currently under development as a segment of the
National Energy Plan (NEP). Liquefaction is intended in part to convert
fossil fuels such as coal and oil shale to a form compatible with present
end uses. It is also intended to permit environmentally acceptable use of
presently accessible fossil-fuel supplies which fail to meet environmental
requirements in conventional applications (Ref. 2-55). Therefore, in addi-
tion to converting forms (solids to liquids) for end-use considerations, the
liquefaction facilities can be considered a fuel pretreatment for pollution
control purposes.
2.3.1 System Description
Coal liquefaction technology consists of four basic operations and
auxiliary processes. These operations are 1) coal pretreatment, 2) coal
liquefaction, 3) separation, and 4) purification/upgrading. The processes
in these operations are shown in Figure 2.3-1.
2.3.1.1 Coal Pretreatment—
Coal pretreatment processes used in coal liquefaction technology are
similar to those required for gasification technology. Coal pretreatment
2-36
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NJ
I
1
/H
7-^
IMdiricMioi
MUILIUT noccws-
O.VH
sw us
Figure 2.3-1. Module diagram for coal liquefaction systems.
-------
can include crushing/grinding, pulverizing, sizing, drying, and/or slurrying/
preheating.
2.3.1.2 Coal Liquefaction—
There are four basic processes that can be used in the coal liquefac-
tion operation. These processes are: hydrogenation, pyrolysis/hydrocarbon-
ization, extraction, and catalytic synthesis, which is gasification followed
by synthesis and other processes.
A. Hydrogenation—Hydrogenation is gaining prominence over other
systems because it is in an advanced stage of development, provides more
flexible utilization of product fuel, has higher overall conversion
efficiencies, and shows better market potential and economic advantages.
Hydrogenation involves direct conversion of coal to liquids through the
addition of hydrogen to coal at elevated temperature and pressure. The
three types of hydrogenation systems, which are distinguished by the
hydrogen transfer method used in the reactor, are: noncatalytic, catalytic
and donor solvent.
In noncatalytic hydrogenation, coal is partially dissolved in a
hydrogen-rich solvent and the undissolved solids are filtered out. The
solvent is recovered from the high-boiling product and recycled to the
dissolver. In a commercial plant the carbonaceous solids will be gasified
to produce hydrogen. The Solvent Refined Coal (SRC) process uses this
method. Two types of SRC processes are being developed: SRC-I and SRC-II.
In SRC-I, slurried coal is liquified and the product is separated from the
unreacted residue by filtration. Recycled solvent for coal-slurry prepara-
tion is recovered from the product mixture by distillation. The rest of
the liquid product is solidified to produce a boiler fuel having lower
sulfur and ash content than the base coal. In SRC-II, more hydrogen is
added to coal in the liquefaction reactor. The process consumes almost
twice the amount of hydrogen that is consumed in the SRC-I process (Ref.
2-56). The unreacted solids are separated from the product by vacuum
2-38
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distillation. A fraction of the liquid product is recycled for slurry
preparation. The product liquids may be hydroprocessed for further up-
grading, depending upon the product quality desired.
In catalytic hydrogenation, pulverized coal is slurried with coal-
derived recycled oil, mixed with hydrogen, and fed to a catalytic reactor
operating at moderate temperatures and high pressures. The recycled
aromatic solvent recovered from the process does not require hydrotreating.
The H-Coal and Synthoil processes use catalytic hydrogenation.
In the third type of hydrogenation, the donor solvent system, no
catalyst and only a small amount of molecular hydrogen are used in the
reactor. The feed coal reacts with the donor hydrogen from the solvent and
yields liquid products. The solids-free liquid product from the reactor
is hydrotreated in the presence of a catalyst, and part of this hydrotreated
liquid product is used as recycled slurry solvent. The Exxon Donor Solvent
(EDS) and Consol Synthetic Fuels (CSF) processes employ this method.
B. Carbonization—In carbonization systems, coal is pyrolyzed to
recover products by application of heat, either without direct addition of
hydrogen (pyrolysis), or with the addition of hydrogen (hydrocarbonization).
In this system, most of the carbon remains as a solid. Liquids and gases
containing a higher hydrogen-to-carbon (H/C) ratio than the original coal
are recovered. Pyrolysis processes produce significant quantities of
by-product gas and char. The liquid product is further hydrogenated for
desulfurization and quality improvement. Char-Oil Energy Development
(COED), Clean Coke, and Occidental Research Corporation (ORC) flash
pyrolysis processes use this method of coal liquefaction.
C. Extraction—In the Supercritical Gas Extraction Process, extractant
gas near its supercritical temperature is used to extract liquid from coal.
Advantages of this system include easy separation (by cooling and depres-
surization) of the liquid products and extractant gas, and production of
products which contain more hydrogen and are of lower molecular weight than
2-39
-------
the products of other processes. Unfortunately, the SGEP has not been
developed beyond the laboratory stage.
D. Catalytic Synthesis—In the system which uses gasification of coal
followed by syngas synthesis, carbon monoxide and hydrogen react in the
presence of the Fischer-Tropsch catalyst to produce a wide variety of liquid
products such as LPG (Cs-Cn), gasoline (Cs-Cu), and middle oils (diesel,
furnace). This system is not currently receiving an extensive amount of
support from the United States Industrial sector because of its complex
nature and high cost of implementation. However, it is being used commer-
cially in foreign countries.
2.3.1.3 Separation--
The types of separation processes needed are dependent upon the type of
coal liquefaction process used. For hydrogenation liquefaction the
following separation processes may be needed:
• Flashing and condensation
Filtration
• Centrifugatlon
• Solvent de-ashing
Vacuum distillation, and
Coking.
The separation processes associated with pyrolysis/hydrocarbonization and
extraction processes include quenching the hot raw gases, separating the
quenched oil from the quench liquor, and filtering the product oil.
2.3.1.4 Purification/Upgrading—
The processes used to purify and upgrade the coal-derived liquids
include fractionation (distillation) and hydrotreating (hydroprocessing).
Upgrading the raw coal-derived liquids by hydrotreating usually involves
2-40
-------
the addition of hydrogen in the presence of a catalyst. This process also
reduces the sulfur and nitrogen content of the coal-derived fuels.
2.3.2 Status of Development
A number of processes are currently being developed to produce liquid
fuels from coal. The basic idea when converting coal to liquid fuels is to
obtain a product that has a higher H/C ratio than the original coal. This
is achieved by either the addition of hydrogen or the removal of carbon.
The H/C weight ratio of coal is about 1: (15-20) while for oil it is about
The current status of coal liquefaction processes is presented in Table
2.3-1. Operating characteristics of these processes are given in Table 2.3-2.
The Fischer-Tropsch process is the only coal liquefaction process currently
in commercial operation. However, four hydrogenation liquefaction processes
are in advanced stages of development, and could be commercially available
in the late 1980's (Ref. 2-57). These processes are: SRC-I, SRC-II, H-Coal,
and EDS. Block diagrams for these four processes are presented in Figure
2.3-2. More detailed descriptions of these coal liquefaction processes can
be found in the reports: Environmental Assessment Data Base for Coal Lique-
faction Technology; Volume I - Systems for Fourteen Liquefaction Processes;
Volume II - Detailed Discussion of H-Coal, Synthoil and Exxon Donor Solvent
Processes (Ref. 2-58). A general comparison and a summary of the technical
status of these four processes are shown in Table 2.3-3.
2.3.3 Applicability to and Limitations for Industrial Boilers
The applicability of coal-derived liquid fuels to industrial boiler
usage is dependent upon the type of fuel desired for implementation. Because
a number of different fuels are potentially available, ranging from solid to
high quality liquid, a choice must be made to determine which of the many
processes is most suitable for producing a fuel of the desired quality. The
following section compares the applicability of different types of coal
2-41
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TABLE 2.3-1. STATE OF THE ART OF COAL LIQUEFACTION PROCESSES
System Type
Process Name
Hydros? nation Systeas
Catalytic
Bergius
Developer
Sponsor(m)
I. G. Farben
Present Status -
Pilot /Commercial
PDU/*
Plant Future Plans
• 18 commercial plants were operating No plants currently operating.
H-Coal
Syntholl
Disposable Catalyst
Zinc Halide
Catalytic Coal
Liquefaction
(Gulf CCl)
Noncatalytlc
Solvent Refined Coal
(SRC)
Hydrocarbon Research,
Inc.
Department of Energy
(DOE)
Ashland Oil Co.
Conoco Coal Develop-
ment Company
Mobil Oil Corp.
Standard Oil Co.
(Indiana)
Electric Power
Research Institute
(EPRI)
State of Kentucky
Pittsburgh Energy
Research Center
(PERC) - Division of
DOE
PERC-DOE
Continental Oil Co.
Shell Oil Company
PERC-DOE
Gulf Research and
Development Co.
National Science
Foundation (NSF)
Pittsburgh and Midway
Coal Mining Company
(PAMCO)
DOE
Southern Services,
Inc.
EPKI
DOE
In 1944 with a total capacity of
3.64 Billion metric tons of oil per
year, Germany.
• 45-TPD demonstration plant was
operated in late 1950, Louisiana, MO.
• 2.7-TPD PDU operating, Trenton, NJ.
• 546-TPD pilot plant under
construction, Catlettsburg, KY.
Developing catalytic
hydrogenatlon processes (H-Co*l
Syntholl. Disposable Catalyst)
are modern versions of Bergius
process.
Basic process sections of the
pilot plant are due to be
started up in early part of
1979. A two-year operating
period is planned.
e 2.3 and 23 kg/hr bench-scale units
operating, Bruceton, PA.
s 9-TPD PDU under construction,
Bruceton, PA.
• 4.6 kg/hr bench-scale unit
operating, Bruceton, PA.
e 0.45-TPD PDU rearing completion,
Bruceton, PA.
PDU not operating.
plans unknown.
Further
Runs of over 2,000 hours
planned In PDU. Bench-scale
unit will continue to provide
additional data.
c 0.6 kg/hr bench-scale unit operating, Operation of PDU will begin
Library, PA. 1978 and will continued Into
• 1.1-TPD PDU under construction, FT 80.
Library. FA.
e 2.3 kg/hr bench-scale unit operating.
e 1-TPD PDU began operation in 1975,
Hannarvllle, PA.
e 45-TPD pilot plant operating, Ft.
Lewis, WA.
• 5.5-TPD pilot plant.
AL.
Ullsonvllle.
Conceptual design for
demonstration plant being
prepared.
Operation of Ft. Lewis plant
on SRC-I node completed.
Modified SRC-II operations
continue Into FY 81. A
demonstration SRC-II plant
processing 5454-TPa coal la
planned for construction In
Wast Virginia.
Operation In Ullsonvllle
plant may be extended for
another three years. A
demonstration SRC-I plant
processing 5454-TPD coal Is
planned for construction In
Kentucky.
(Continued)
2-42
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TABLE 2.3-1. Continued
System Type
Process Name
Present Status - PDU/*
Pilot /Commercial Plant
Future Plans
Solvent Refined
Lignite (SRL)
COSTEAM
Donor Solvent
Pott-Broche
Exxon Donor Solvent
(EDS)
Clean Fuels Froo
Coal (CFFC)
Consol Synthetic
Fuels (CFS)
Arthur D. Little
(•ADL)
University of North
Dakota
Grand Forks Energy
Research Center
(GFERC), Division of
DOE
PERC-DOE
CFERC-DOE
I. G. Farben
Exxon Research and
Engineering Company
DOE
Atlantic Richfield Co.
Phillips Petroleum Co.
EPR1
Consortium of Japanese
Companies
The Llitmus Company
DOE
Consolidation Coal
Company
DOE
American Electric
Power Corp.
Allegheny Power Corp.
Flour Enggs & Consts.,
Inc.
Arthur D. Little, Inc.
Foster v/heeler Energy
Corp.
PERC-DOE
• 0.55-TPD PDU operating, Grand Forks.
ND.
t 0.5 kg/hr bonch-scale unit operating,
Bruceton, PA.
• 2.3 kg/hr continuous process unit
under construction. Grand Forks, ND.
• 114-TPD demonstration plant operated
from 1937-1944, Uelheim, Germany.
• 0.9 and 2.4 kg/hr bench-scale
units operating, Baytown, TX.
• 0.9-TPD pilot plant operating.
Baytown, TX.
• 13.8 kg/hr modified PDU unit
operating.
• 18-TPD pilot plant operated from
1968 to 1970. Revamped since 1974
and supplemented with new process
units, Cresap, WV.
Bench-scale experimental work done
by ADL, Cambridge, MA.
Delayed coker PDU operating.
Operating data obtained will
be used to design a pilot plant.
0.9-9 TPD PDU planned to be
built at Grand Forks, ND.
No plants currently operating.
Developing donor-solvent based
extraction processes (EDS, CSF,
ADL) are modern versions of
Pott-Broche process.
227-TPD pilot plant under
construction near Baytown, TX.
Operation will begin in 1980.
Operation of PDU planned
through 1978. Data obtained
will be used to design and
construct a pilot plant.
Integrated operation of the
plant may begin in the second
half of 1978. Various methods
of solids-liquid separation
will be tested.
Further experimental studies
to be continued for obtaining
operating data to design PDU.
LiquJ-coal
Arthur C. McKce Co.
Bench-scale experimental vork
being conducted. Cleveland, OH.
Unknown.
Other Hydrogenatlon
Processes
Direct Hydrogenation
Rockwell International
Corp. (Rockt-tdyne
Dlyjlslonj.
DOE"
• Bench-scale reactor testing was
Initiated in 1976.
• 0.9-ton/hr reactor testing started
in et.ily 1977.
9-tons/hr reactor operated
for obtaining more design
data.
(Continued)
2-43
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TABLE 2.3-1. Continued
System Type
Process Name
Developer
Sponsor(s)
Fresent Status - FDD/*
Pilot/Commercial Plant
Future Flans
Carbonisation Systems
Char Oil Energy
Development (COED)
Clean Coke
Coal con
FMC Corporation
DOE
EFRI
United ttatee Steel
and
Inc.
Consultants.
DOE
TOSCQAL
Flash Pyrolysls
Extraction
Supercritical Gas
Extraction (SGE)
Catalytic Synthesis
Flscher-Tropsch
Onion Carbide Corp.
rhemlnl Construction
Corp. (later with-
drawn from the
agreement)
DOE
The Oil Shale Corp.
(TOSCO)
Occidental Research
Corp. (ORC)
DOE
State of Kentucky
Coal Research
Establishment (CRE)
British National Coal
Board (NCB)
Lurgi-Ruhrchemle
(ARCE). Oberhausen.
Germany
FERC-DOE
e 33-TPD pilot plant operated from 1970
to 1974. Princeton. NJ.
• 0.*S-TPD KW operatUg. Pittsburgh.
PA.
• 272-TPD saml-vorka hydrogenatioB
pilot plant operated from 1952-
1938.
• 4.6 kg/hr and 1B-TFD hydro-
carbonization reactor scala-upe
were operated In aarly 1960.
• 236J-TPD deaunatratlon plant MM
planned In 197S. Bear Athens, IL.
e 23-TFD pilot plant originally
built to process shale was tested
with coal, Golden, CO.
• 3.2 TPD PDU operated for testing
the process. This PDU has
currently been revised, La Verne,
CA.
• 2.8-TPD second PDU started
operating In 1977, La Verne, CA.
• Experimental work done over a
number of years. Stoke Orchard,
U.K.
• 20 kg/hr PDU commissioned by CRE.
a 7272-TPD commercial plant
operated by South African Coal,
Oil and Gas Corp. (SASOL) of the
Republic of South Africa.
Sasolburg, South Africa.
e Frame-sprayed catalyst system
is being developed.
Pilot pUat dlsassssit lad afur
processing 16,162 ton* of coal.
In a COED relevant develoassnt.
OOOA1 process la bain* developed
for ualng char fro* COCO proc«a«
to produce synthesis gaa.
Different coals will be tested
In PDU through 1978. 91-TPD
pilot plant design being
prepared.
Demonstration plant project
was suspended by DOE in Dec.
1976. The economics were
thought to be marginal and
technical problems with the
fluid-bed carbonizer were
thought to be bigger than first
believed.
to future plans known.
The PDU operations will
continue through 1978. Tar
hydrotreatIng will also be
tested In PDU. A detailed
design for a 227-TPD pilot
plant is being prepared.
Air Products and Chemicals.
Inc. has been contracted to
examine the engineering of the
process and to Investigate Its
commercial potential.
SASOL-II plant under con-
struction In South Africa
at the new town Secunda,
located In the Transvaal
province.
Data obtained will be used
to design a pilot plant.
* All tons are in metric tons.
2-44
-------
TABLE 2.3-2. OPERATING CHARACTERISTICS OF COAL LIQUEFACTION PROCESS
System Type
Acceptable
Process Name Coal Type
Hydrogenation Systems
Bergius Bituminous
Sub- bituminous
Lignite
H-Coal Bituminous
Sub-bituminous
Lignite
Syntnoil Bituminous
Sub-bituminous
Lignite
"J0 Disposable Catalyst Bituminous
4s Sub-bituminous
*"" Lignite
Zinc Halide Bituminous
Sub- bituminous
Lignite
Gulf CCL Bituminous
Sub-bituminous
Ligni te
SRC Bituminous
Sub-bituminous
Lignite
SRL Lignite
COSTEAM Lignite
Characteristics of
Coal Pretreatment Operation
Acceptable Coal
Cool Feeding Size, mm
System (moisture content, Z)
Coal/solvent slurry 0.25
(1.5)
Coal/solvent slurry <0.35
(0)
Coal/solvent slurry 60K0.149
Coal/solvent slurry 60%<0.149
Coal/solvent slurry —
Coal/solvent slurry —
Coal/solvent slurry <3.31
Coal/solvent slurry
Coal/solvent slurry <0.149
(20 to 30)
Characteristics of
Liquefaction Reaction Operation
Type of
Reaction Vessel
Ebullated bed
(catalytic)
Fixed bed
(catalytic)
Stirred tank
Molten bed
(catalytic)
Fixed bed
(catalytic)
Tubular flow
Tubular flow
Stirred bed
Operating
Pressure
MPa
68.94
20.20
13.73-27.46
11.5-23.0
10.49-20.98
13.72
10.29
17.35
27.44
Operating
Temp ern tu re
"C
482
454
449
449
400
482
454
510
427
(Continued)
-------
TABLE 2.3-2. Continued
System Type
Process Name
Pott-Broche
EDS
CFFC
CSF
ADL
Llqul-coal
Direct Hydrogenation
Extraction Systems
SCE
Characteristics of
Coal Pretreatnent Operation
Acceptable
Coal Type
Bituminous
Sub-bituminous
Lignite
Bituminous
Sub-bl luminous
Lignite
Bituminous
Sub-bituminous
Lignite
Bituminous
Sub-bituminous
Lignite
Bituminous
Sub-bituminous
Lignite
Bituminous
Sub— bituminous
Lignite
Bituminous
Sub-bituminous
Lignite
Bituminous
Sub-bituminous
Lignite
Coal Feeding
System
Coal/solvent slurry
Coal /sol vent slurry
Coal/solvent slurry
Coal/solvent slurry
Coal/solvent slurry
Coal /sol vent slurry
Pneumatic
Lock hoppers
Acceptable Coal
Size, on
(moisture content. Z)
953X0.084
(0.5)
<0.54
<--)
~~
<1.19
(1.0)
80Z< 0.074
(— )
<0.149
(2.0)
<0.074
(-)
<0.074
(— )
Characteristics of
Liquefaction Reaction Operation
Type of
Reaction Vessel
Tubular flow
Tubular flow
Multistage
ebullated bed
(catalytic)
Stirred tank
Stirred tank
Tubular flow
Entrained bed
—
Operating Operating
Pressure Temperature
MPa °C
10.10 430
13.72 449
14.60 427
0.98-2.74 407
0.79 399
6.86 427
6.35 982
10.1 399
(Continued)
-------
TABLE 2.3-2. Continued
System Type
Process Name
Carbonization Systems
COED
Clean-coke
Coalcon
TOSCOAL
Fl.Tsh Pyrolysis
Catalytic Synthesis
Fi scher-Tropsc h
(gasification)
Acceptable
Coal Type
Bituminous
Sub-bituminous
Lignite
Sub-bituminous
(high volatile)
Bituminous
Sub-bituminous
Lignite
Sub— bituminous
Bituminous
Sub-bituminous
Lignite
Depends upon
the gasifier
used
Characteristics of
Coal Pretreatment Operation
Characteristics of
Liquefaction Reaction Operation
Acceptable Coal
Coal Feeding Size, ran
System (moisture content, %)
Pneumatic
Coal/solvent slurry
Lock hoppers
Pneumatic
Pneumatic
Depends upon
the gasifier
used
3.51
(6.0)
0.149-3.51
50Z, 0.149
(1.0)
12.7
0.074
Depends upon
the gasifier
used
Type of
Reaction Vessel
Multistage
fluldized bed
Fluldized bed
Fluidized bed
Fluidized bed
Entrained bed
Moving bed
Operating
Pressure
MPa
0.12
0.57-0.82
(carbonizer)
16.82-25.44
(hydrogenation)
3.28
0.08
0.08
2.30
Operating
Temperature
°0
316-816
(4 stages)
732
469
560
482
593
593-927
-------
SOLVENT RiFINCD COM.
FWCESS
SOIVEIT KFIMO COAl-ll MOCESS
REOCLED GAS
CWfjJfSSOR
VENT
GASES
MATER
SOLID
FUEL
(SK)
N3
I
00
H-COAL PROCESS
)0t TO
EXXON DONOR SOLVENT PROCESS
ASH
RESIDUE
RECrCLED
SOLVENT
Figure 2.3-2. Flow diagrams of advanced liquefaction processes.
-------
TABLE 2.3-3.
GENERAL COMPARISON AND RELATIVE TECHNICAL STATUS
OF FOUR HYDROGENATION LIQUEFACTION PROCESSES
Technical Status
PDU Scale of Operations
(metric tons/day, coal)
Size of Pilot Plant
(metric tons/day, coal)
Pilot Plant Scheduled
Operat ion
Fuel Types
Coal Feed
General Comparisons
Fuel Flexibility
Reactor Operating Severity
Process Scale-up Risk
Number of New Components
SRC- 1
0.9
a) 45
b) 5.5
a) Late 1974
b) Mid-1976
Refined coal
(solid fuel)
Eastern
Western
Developed to
produce
substitute
solid boiler
fuel only
Moderate
Moderate
High
SRC-II .
0.9
27.3
Mid-1977
Distillate oil
Eastern (high
pyrites only)
Poor
High
High
High
H-Coal*
0.27
227.3-545.4
April 1979
Distillate oil
residual oil
Eastern
Western
Superior
Moderate
Moderate*
Low*
EDS*
0.27
227.3
January 1980
Distillate oil
Eastern
Western
Good
Low
Low*
Low*
and Design of Commercial
Equipment
Reactor Complexity Moderate Moderate
Fuel Utilization,
Combustion
Raw Product, Stability, Moderate Poor
Compatibility
Combustion Experience Moderate Limited
Moderate
Poor
Limited
Low
Poor
Limited
*Assumes successful operation of pilot plant in 1979-1980.
2-49
-------
liquefaction fuels to several boiler configurations in use today. The fuel
characteristics of various coal-liquids are also discussed.
Commercial coal liquefaction facilities will produce fuels in much
larger quantities than are required by any one industrial boiler. Therefore
the liquefaction plant will be considered as an off-site supplier of fuel.
2.3.3.1 Use of Coal-Derived Solid or Liquid Fuels in Boilers—
The products from the four coal liquefaction processes of concern are a
solid fuel and a liquid fuel or chemical feedstock. The solid fuel produced
by the SRC-I process cannot be used in all industrial coal-fired boilers.
However, the liquid fuels can be used in oil-fired boilers.
The solid fuel from the SRC-I process cannot be used in conventional
stoker boilers, which comprise about 11 percent of industrial and commercial
boilers currently in use (Ref. 2-59). The spreader stoker, for example,
burns large size coal particles both above and on the grate. Since the
solids from SRC-I have a low melting point (approximately 155°C), they will
melt on the grate before they are combusted. The melted SRC-I will then pass
through the grate into the plenum chamber and be removed with the ash. This
results in very inefficient combustion.
Four percent of industrial and commercial boilers are pulverized coal
boilers (Ref. 2-59). Some of the pulverized coal boilers may be retrofitted
to burn SRC-I fuel. However, preliminary results from SRC-I handling and
burning tests indicate that some modifications may be required for the opera-
tion of the fuel handling and storage equipment, pulverizers, boiler burners
and the combustion process itself. Such modifications for the ball-and-race
mill might include reduction of the loading force and/or race speed and
change in the operating procedure to minimize holdup of SRC in the pulverizer
(Ref. 2-60). For combustion, the dual-register burner may have to be rede-
signed with a water-cooled coal nozzle (Ref. 2-61).
2-50
-------
Approximately 34 percent of industrial and commercial boilers in opera-
tion are oil-fired (Ref. 2-59). It is anticipated that coal liquids may
replace a portion of the petroleum-based fuel oil-fired industrial boilers
with modifications in the combustion process. Only minor modifications may
be required in the handling and storage of coal liquids.
Coal-derived heavy liquid fuels can be burned in boilers using petroleum-
based residual oils (Nos. 4, 5, and 6 fuel oils). These boilers presently
comprise 20 percent of industrial and commercial boilers in operation (Ref.
2-59). Analyses (Ref. 2-60) of petroleum-based fuel oils (Nos. 1, 2, 4, 5,
and 6) are given in Table 2.3-4. Fuels from both the H-Coal (fuel-oil mode)
and SRC-II processes may be used to replace residual fuel oil. Utilization
of EDS liquid fuel as residual fuel will depend on the extent of hydrotreat-
ment.
Fourteen percent of industrial and commercial boilers use No. 2 fuel oil
(Ref. 2-59). The EDS process produces a distillate fuel which can be substi-
tuted for petroleum-based No. 2 fuel oil. Mild hydroprocessing may be
required for H-Coal and SRC-II liquids to produce a product similar to No. 2
fuel oil.
2.3.3.2 Coal-Liquids Fuel Characteristics—
Coal liquids are analogous to petroleum residual fuels. However, analy-
sis of these coal liquids shows that their chemical compositions and certain
physical properties are sufficiently different to require possible handling
and combustion modifications before use in industrial boilers. Coal liquids
are more aromatic and their carbon/hydrogen ratios are considerably higher
than those of petroleum crudes and fuels. Moreover, the concentrations of
heteroatoms such as nitrogen and oxygen are much higher. Coal liquids con-
taining residual fractions high in asphaltenes are incompatible when blended
with typical petroleum fuels. The sulfur contents of both coal liquids and
petroleum residuals can vary considerably. The physical properties of coal
liquids are also quite variable; they depend on the type of coal used and the
2-51
-------
TABLE 2.3-4. RANGE OF ANALYSES OF FUEL OILS
NS
I
NS
Grade of Fuel Oil
Weight, Percent
Sulfur
Hydrogen
Carbon
Nitrogen
Ash
Gravity
Deg API
Specific
kg/m3
Pour Point, °C
Viscosity
Centistokes @ 37.8°C
SUS @ 37.8°C
SSF @ 50"C
Water & Sediment, Vol. Z
Heating Value (MJ/kg)
(calculated Btu/lb)
gross
No. 1
0.01-0.5
13.3-14.1
85.9-86.7
Nil-0.1
40-44
0.825-0.806
110.06-107.49
0 to -45.6
1.4-2.2
45.75-46.19
(19,670-19,860)
No. 2
0.05-1.0
11.8-13.9
86.1-88.2
Nil-0.1
28-40
0.887-0.825
118.39-110.06
0 to -40
1.9-3.0
32-38
0-0.1
44.59-45.94
(19,170-19,750)
No. 4
0.2-2.0
(10.6-13.0)*
(86.5-80.2)*
0-0.1
15-30
0.966-0.876
128.80-116.95
-23.3 to 10
10.5-65
60-300
tr to 1.0
42.52-45.12
(18,280-19,400)
No. 5
0.5-3.0
(10.5-12.0)*
(86.5-89.2)*
0-0.1
14r22
0.972-0.922
129.76-123.03
-23.3 to 26.7
65-200
20-40
0.05-1.0
42.1-44.2
(18,100-19,020)
No. 6
0.7-3.5
(9.5-12.0)*
(86.5-90.2)*
0.01-0.5
7-22
1.022-0.922
136.33-123.03
-9.4 to 29.4
260-750
45-300
0.05-2.0
40.5-44.17
(17,410-18,990)
*Estimated.
-------
liquefaction process employed. Petroleum residuals have higher concentra-
tions of nickel and vanadium (10 to 500 ppm) than coal liquids (Ref. 2-61).
However, coal-derived liquids contain more iron (VLO to 60 ppm),
A comparison of physical and chemical characteristics of a typical
petroleum No. 2 fuel oil and coal liquids is given in Table 2.3-5. Coal
liquids (Ref. 2-62) in the table are recycled SRC solvent (obtained from
SRC-I and considered here to be analogous to SRC-II liquid fuel), H-Coal
distillate (obtained by operating H-Coal process in fuel oil mode without
hydroprocessing), and EDS distillate. In comparison, No. 2 fuel oil exhibits
higher hydrogen content than coal liquids. Also, nitrogen content in these
coal-liquid fuels is considerably higher than No. 2 fuel oil. According to
the fuel characteristics shown in one source (Ref. 2-64), the ash content of
SRC-II liquid oil was between No. 2 and No. 6 fuel oil. Viscosity of coal
liquid fuels is high and the coal liquids must be heated for proper atomiza-
tion in the boiler.
The properties of SRC-I (solid fuel) are compared with those of base
coals in Table 2.3-6. The sulfur content of the base coals is reduced to 0.8
and 0.1 percent respectively for the high sulfur Kentucky and low sulfur
Wyoming coals. The ash content in both cases was reduced to 0.3 percent or
less. The hydrogen content, as expected, is somewhat higher for the SRC-I
as compared with the base coal. Some nitrogen enrichment has occurred, giv-
ing SRC-I a slightly higher nitrogen content than the base coal.
Oxygen contents of the SRC-I are about half the value of the base coal.
The Hardgrove grindability index for SRC-I is 145 (Ref. 2-66), indicating
that the power required to pulverize should be significantly less than that
required for base coal, which has a Hardgrove grindability index of about 50
to 100. As mentioned earlier, some modifications will be required to pul-
verize SRC-I. Babcock and Wilcox Company's E-21 ball-and-race mill (Ref.
2-67) and C-E Deep Bowl Mill No. 271 (Ref. 2-68) have shown satisfactory
performance in pulverizing SRC-I.
2-53
-------
TABLE 2.3-5. PROPERTIES OF NO. 2 FUEL OIL AND COAL LIQUIDS
Typical
Petroleum No. 2
Fuel Oil
Fuel Ref. 2-62
Elemental Composition, wt Z
Hydrogen
Sulfur
Nitrogen
Oxygen
Trace Contaminants, ppm wt
Titanium
Sodium
Potassium
Calcium
Vanadium
Lead
Iron
Chloride
Physical Properties
Gravity, "API
Aromatic Carbon, %
Flash Point, "C
Heat of Combustion MJ/kg (Btu/lb)
KV, CS at (43.3°C)
KV, CS at (98.9°C)
12.9
0.093
0.008
<0.01
<1.0
0.55
0.37
0.17
<0.1
_
0.2
-
33.6
19.0
67.2
45.4 (19500)
2.61
1.09
Raw SRC-I
Recycled
Solvent*
Ref. 2-62
7.4
0.37
0.62
3.9
20.0
0.39
0.19
0.35
0.9
0.9
61.0
35.0
5.3
74.0
82.2
39.4 (16920)
5.79
1.48
Raw EDS
Raw H-Coal 205-425 °C
Distillate Distillate
Ref. 2-62 Ref. 2-63
9.1 10.0
0.10 0.3
0.39 0.2
1.5 1.9
0.59
0.08
0.14
0.1
<1.0
10.3
14.7 18.0
55.0
90.5 91.1
42.1 (18080) 44.2 (19000)
3.0 SUS @ 37.88C - 38
*SRC-I recycled solvent Is considered analogous to SRC-II liquid fuel.
-------
TABLE 2.3-6. PROPERTIES OF SRC-I AND BASE COALS
Ultimate Analysis
wt %
Moisture
Ash
C
H
N
S
0
Heating Value, HJ/kg
(Btu/lb)
Kentucky High
Sulfur Coal
2.2
10.5
70.1
4.9
1.4
3.5
7.3
29.4
(12,600)
Kentucky
SRC-I
1.1
0.3
86.1
5.7
1.7
0.8
4.3
36.2
(15,600)
Wyoming Low-
Sulfur Coal
6.5
7.3
63.4
4.5
1.0
0.6
16.7
23.9
(10,300)
Wyoming
SRC-I
0.2
0.2
88.4
5.5
1.3
0.1
4.3
36.6
(15,700)
Source: Ref. 2-65
2.3.4 Factors Affecting Performance
In coal liquefaction systems, sulfur and nitrogen present in coal react
with hydrogen to form hydrogen sulfide (H2S) and ammonia (NHa), respectively.
The system operating characteristics play an important role in the efficiency
of these conversions. The primary variables that could affect the conver-
sions are:
• Type of system
• Coal characteristics
• Operation variables
- Hydrogen consumption
Reactor space velocity
Reaction temperature and pressure
• Hydroprocessing of the raw product
2-55
-------
2.3.4.1 Type of System—
In the coal liquefaction reactor, coal is solubilized in the solvent
and is further hydrogenated by the addition and/or transfer of hydrogen to
remove sulfur, nitrogen, and oxygen. Liquid and gaseous products are pro-
duced by hydrocracking. The severity of the reaction is measured by the
extent to which hydrogenation and hydrocracking reactions proceed.
In the SRC-I solid system, the reaction severity is low. The hydrogena-
tion and hydrocracking reactions result in the desired product having respec-
tive sulfur and ash contents of about 0.7 and 0.1 percent. Nitrogen contents
may be slightly increased.
In the SRC-II (liquid) system, a portion of the reactor effluent slurry
is recycled back to the reactor. The mineral residue in the product slurry
is believed to act as a catalyst and enhance hydrocracking reactions. More
hydrogen is transferred, and the main product is a distillate fuel with sul-
fur and nitrogen contents of about 0.3 and 0.9 percent, respectively. Lower
sulfur and nitrogen contents in the final product signify larger amounts of
hydrogen sulfide and ammonia generated in the reactor, and a reaction
severity greater than in the SRC-I system.
In the H-Coal reactor, hydrogenation and hydrocracking reactions are
activated by the addition of a catalyst, which helps minimize hydrogen con-
sumption. The reactions are sufficiently complete to allow production of
fuel oil distillate (204+0C oil) with a sulfur content of 0.6 percent.
Operating with a higher consumption of hydrogen in the reactor, the system
produces syncrude with a sulfur content of 0.2 percent. The reaction severity
is higher than in the SRC system.
In the EDS liquefaction reactor, the solubilized coal is hydrocracked
to liquid products, which are separately hydrogenated in a catalytic reactor
to reduce the sulfur and oxygen content. The process produces a variety of
2-56
-------
liquid products with sulfur content of less than 0.1 percent. The reaction
severity in the liquefaction reactor is low, but the combined severity of the
liquefaction reactor and hydrogenation reactor is quite high.
In summary, the effect of system type in producing lower sulfur and
nitrogen content fuels is that higher sulfur and nitrogen removal efficien-
cies are obtained with higher severity of hydrogenation and hydrocracking
reactions. Table 2.3-7 shows the variation in hydrogen consumption and sul-
fur content of the product with the type of liquefaction system.
TABLE 2.3-7. HYDROGEN CONSUMPTION AND SULFUR CONTENT
OF COAL LIQUIDS IN LIQUEFACTION SYSTEMS
Hz consumption,
% by wt of dry coal*
% sulfur in 205+0C
SRC-I
(solid)
(Ref. 2-56)
2.20
0.70
SRC -I I
(liquid)
(Ref. 2-56)
4.30
0.30
H-Coal
(fuel oil)
(Ref. 2-69)
3.88
0.58
EDS
(Ref. 2-70)
3.05
0.10
oil
* Coal type: Illinois No. 6, sulfur content 3.5%.
2.3.4.2 Coal Characteristics—
Coal contains organic sulfur (bound in organic compounds) and mineral
sulfur (as pyrites and other iron compounds). Mineral sulfur is easily
removed during the hydrogenation reaction with very little hydrogen con-
sumption. A summary of data on low-sulfur, low-ash SRC-I product from
various coals in the Wilsonville pilot plant is presented in Table 2.3-8.
Nitrogen removal is more difficult than sulfur removal because the
reaction between nitrogen and hydrogen does not take place easily. Nitrogen
removal from the feed coal ranges from approximately zero to 40 percent.
About half of the nitrogen removal goes into the production of ammonia.
2-57
-------
TABLE 2.3-8. SULFUR IN FEED COALS AND FLUE GASES FROM COMBUSTION
OF FEED COALS AND SRC PRODUCTS
Smith & Roland, Powder
River, Belle Ayr
Emergy Field/Emery
Illinois No. 6/Monterey
Illinois No. 6/Burning
Star
N> Pittsburgh/Loveridge
Ul
Kentucky No. 9 and
No. 14 (Ad) /Colonial
Kentucky No. 9 and
No. 14 (fid) /Colonial
Indiana V/Old Ben
Sulfur
Total
0.81
0.94
3.89
3.10
2.79
4.04
3.66
3.21
in Feed
wt %
Organic
0.71
0.72
2.53
2.00
1.76
1.01
1.50
1.25
Coala
Mineral
0.10
0.22
1.36
1.10
1.03
3.03
2.16
1.96
Flue Gas
Feed Coalb
590 (1.36)
610 (1.41)
3030 (7.04)
2520 (5.85)
2060 (4.78)
3130 (7.27)
3010 (7.24)
2530 (5.88)
S02, ngS02/J (lb/1
SRC Product6
80 (0.18)
180 (0.41)
480 (1.12)
340 (0.78)
460 (1.07)
220 (0.52)
300 (0.70)
320 (0.75)
O6 Btu)
Sulfur
Removal0
87
71
84
87
78
93
90
87
Coal contains organic sulfur (bound in organic compounds) and mineral sulfur (as pyrites and other
iron compounds). The total sulfur is the sum of organic and mineral sulfur.
Run-of-mine coal.
Takes no credit for low-sulfur liquids and gases produced. Calculated from flue gas SOa values.
wide range of coal composition from the same mine.
eSRC product made from designated feed coal.
Source: Ref. 2-71.
-------
2.3.4.3 Operation Variables—
The effects of operating variables such as hydrogen consumption, space
velocity, temperature, and pressure on removal of sulfur and nitrogen are
considered jointly since space velocity, temperature, and pressure all affect
hydrogen consumption. An increase in reaction temperature and pressure
causes increased reaction rates, along with an increase in hydrogen consump-
tion. An increase in residence time (decrease in space velocity) also
increases the consumption of hydrogen. Since hydrogen consumption is
influenced by all these variables, it can be used as an indicator of the
sulfur and nitrogen removal.
A. Desulfurization—Increased hydrogen consumption indicates an
increase in sulfur removal. The effect of hydrogen consumption on the
sulfur content in SRC produced from various coals is shown in Figure
2.3-3 (Ref. 2-72). Reactor temperature and residence time have greater
effects on sulfur removal than reactor pressure (Ref. 2-73). At low
temperatures, the relationship between sulfur removal and hydrogen con-
sumption is approximately linear. However, as the temperature is increased,
more sulfur is removed but at a lower rate. Sulfur removal can also be
increased by increasing reactor pressure and residence time.
B. Denitrogenation—During coal hydrogenation, nitrogen reacts with
hydrogen to form ammonia. An increase in temperature increases hydrogen
consumption; however, nitrogen removal at higher temperatures does not
significantly change. Figure 2.3-4 summarizes calculated nitrogen contents
against the operating conditions employed (Ref. 2-72). The lines drawn for
the effect of the variables represent averaged results. It appears that
the actual effect of these variables is small, on the order of 0.1 wt
percent nitrogen content change for change in pressure from 6.86 to 10.49
MPa, or a change in coal rate from 400 to 799 kilograms per hour per cubic
meter of contactor.
2-59
-------
1.4
1.2
x 1.0
«k
o
* 0.8
»•*
1 0.6
to
0.4
0.2
ILLINOIS
443°C
KENTUCKY #9 and
#14 454°
PITTSBURGH
466°C
I
454°C
L
1.0 2.0 3.0
HYDROGEN CONSUMPTION, % MAP COAL
4.0
Figure 2.3-3. Effect of hydrogen consumption upon sulfur
in filtered SRC (Ref. 2-72).
2-60
-------
5
*«
2.2r-
2.0-
1.8
. 1-6
1.4
2.2r
2.0-
3
i
1.6
1.4
405
_BASIS
PRESSURE, MPa
6.86 10.49 17.46
SOLVENT + VACUUM BOTTOMS OIL
A o a
SOLVENT + FILTERED LIQUID 524°C
* •
6.76 MPa
0 10.49 MPa
17.46 MPa
320 640
COAL RATE, kg/hr/m3
960
1280
6.86 MPa
.10.49 MPa
17.46 MPa
I
415 425 435
CONTACTOR TEMPERATURE, "C
445
Figure 2.3-4. Variation of nitrogen content of SRC-I liquids with changes
in temperature and coal-feed rate (Ref. 2-72).
2-61
-------
2.3.4.4 Hydroprocessing—
Raw coal-derived liquid fuels differ from petroleum-derived fuels in
that they are very aromatic and, as such, are hydrogen deficient. Hydro-
processing of these fuels to increase the hydrogen content consists of
catalytically adding chemical hydrogen to fuel. Hydrogenation also decreases
the sulfur and nitrogen content of the coal liquids. The hydroprocessing
variables that affect sulfur and nitrogen removal from coal-derived liquids
are catalyst type and hydrogen consumption.
A. Catalyst Type—Mobil Research and Development Corporation (Ref.
2-73) has evaluated several catalysts for upgrading coal-derived liquids to
turbine fuels. The evaluations were based on bench-scale apparatus using
coal-derived liquids from SRC and H-Coal pilot plants. Commercial CoMo/
A1203 catalyst (Cyanimid HDS-1441A) and NiMo/Al203 catalyst (Ketjen 153S)
have shown good performances. Solvent hydrogenation studies performed by
Exxon Research and Engineering Company (Ref. 2-74) indicated that the
denitrogenation capability of the nickel-molybdate catalyst appears to be
somewhat greater than that of the cobalt-molybdate catalyst.
B. Hydrogen Consumption—Hydrogen consumption for a hydroprocessing
reaction depends on the degree of heteroatom (0, N, S) removal desired.
Lower space velocities and higher temperatures increase the hydrogen
consumption, which in turn increases the degree of heteroatom removal.
Figures 2.3-5 and 2.3-6 show the effect that average operating temperature
has on desulfurization and denitrogenation during hydrotreating operations
(Ref. 2-74). It should be noted that temperatures and space velocities
reported by Exxon Research and Engineering Company are relative values;
that is, they are reported as functions of reference values (R.V.) defined
by Exxon. The feedstock for the experimental runs, characterized as
"simulated heavy solvent" (Ref. 2-74), consists of multipass spent solvent
from the EDS pilot plant. Table 2.3-9 represents mild, moderate, and
severe hydroprocessing conditions for recycled SRC solvent and H-Coal
2-62
-------
0.40
0.38
0.36
0.34
0.32
0.30
2 0.28
3
Of
~* 0.26
1 0.24
Q_
0.22
0.20
0.18
0.16
0.14
0.12
0.10
0.08
0.06
0.04
60
OPERATING CONDITIONS
MASS SPACE VELOCITY: 1.26-1.33 x R.V.
PRESSURE: 10.10 -10.49 MPa
FEED SULFUR CONTENT: 0.48 WT. I
_L
J_
70 80 90 100
TEMPERATURE - REFERENCE VALUE, °C
110
120
Figure 2.3-5. Effect of temperature on sulfur removal (Ref 2-74)
2-63
-------
.036
.034
.032
.030
.028
« .024
o
I
z .022
! .020
•
' .016
.014
.012
.010
.003
.006 -
.004
OPERATING CONDITIONS
MASS SPACE VELOCITY: 1.26-1.33 x R.V.
PRESSURE: 10.10 - 10.49 MPa
FEED NITROGEN CONTENT: 0.54 MT. %
60
70 80 90 100
TEMPERATURE - REFERENCE VALUE, °C
110
120
Figure 2.3-6. Effect of temperature on nitrogen removal (Ref. 2-74)
2-64
-------
TABLE 2.3-9.
HYDROPROCESSING CONDITIONS AND YIELDS FOR UPGRADING
SRC RECYCLE SOLVENT AND H-COAL DISTILLATE
K3
I
Coal Liquid
Hydroprocessing Conditions:*
Pressure, MPa
LHSV
Temperature, °C
H2 Consumption (m3/m3 oil)
(SCF/Bbl)
Yields, wt %
Ci-Ca Gas
c.,
C5
C6 + Liquid
H2S
NH3
H20
Heteroatom Removal, wt %
Sulfur
Oxygen
Nitrogen
Total Liquid Product Properties
Gravity, "API
Hydrogen, wt %
Sulfur, wt %
Nitrogen, wt %
Oxygen, wt %
SRC Recycle Solvent
Feed Mild
17.2
2.9
359
202.9
(1140)
0.16
0.22
0.11
98.90
0.34
0.22
1.72
85
39
30
5.3 13.0
7.4 8.9
0.37 0.06
0.62 0.44
3.9 2.4
Moderate
17.2
0.8
377
402.3
(2260)
0.11
0.07
0.05
98.34
0.38
0.62
3.73
97
85
83
19.5
. 10.3
0.01
0.11
0.6
Severe
17.2
0.4
381
498.4
(2800)
0.42
0.22
0.12
98.05
0.39
0.73
4.17
98
95
96
23.4
11.0
0.01
0.02
0.2
H-Coal Distillate
Feed Mild
10.3
2.9
369
101.5
(570)
0.04
0.01
0.03
99.60
0.13
0.18
0.90
95
54
40
17.1 21.3
9.8 10.6
0.13 0.007
0.38 0.23
1.5 0.7
Severe
17.2
0.5
372
307.9
(1730)
0.20
0.10
0.06
100.21
0.14
0.46
1.58
99
93
99
28.0
12.2
< 0.002
<0.005
0.1
* Catalysts: American Cyanimid HDS-1141A. (CoMo) for SRC Recycle Solvent and Ketjen 153S (NiMo)
for H-Coal Distillate.
Source: Ref. 2-61
-------
distillate (Ref. 2-61). The sulfur removal for recycled SRC solvent is
greater than 85 percent for all three conditions, while nitrogen and oxygen
removal varied from 30 to 96 percent. For H-Coal distillate, the sulfur
removal was greater than 95 percent, while oxygen and nitrogen removal varied
from 30 to 99 percent.
2.3.5 System Performance
There is limited storage and combustion data on coal liquefaction
products from any of the processes. The Ft. Lewis, Washington, SRC-I pilot
plant with a capacity of 45 metric tons per day, produced a 2725 metric ton
sample of solid SRC fuel for combustion testing at the 22 MW Plant Mitchell
power station of the Georgia Power Company. The combustion tests were
performed in the second quarter of 1977. Small-scale tests on home heating
units and industrial boilers, and some limited laboratory tests have been
performed with SRC-II, H-Coal, and EDS liquid fuels. Large-scale boiler
tests, using SRC-II fuel from several coals at the Ft. Lewis pilot plant,
are being planned. Tests on H-Coal and EDS fuel products will be initiated
in 1979 and 1980, respectively (Ref. 2-75).
2.3.5.1 Emission Reductions—
The results of combustion tests performed on coal-derived solid and
liquid fuels are discussed in this section. These results were primarily
concerned with sulfur dioxide, nitrogen oxides, and particulate matter
emissions.
A. Sulfur Dioxide—When combusted, most of the coal-derived liquid
and solid fuels will meet an S02 emission level of 520 ng S02/J (1.2 lb/106
Btu) without any post-combustion controls (flue gas desulfurization). SRC-I
fuel with a heating value of 37 MJ/kg (16,000 Btu/lb) will meet this S02
emission level if its sulfur content is less than 0.96 percent. For an
SRC-I fuel with a heating value of 35 MJ/kg (15,000 Btu/lb) the sulfur
2-66
-------
content will need to be less than 0.90 percent. The SRC-I produced during
the Ft. Lewis pilot plant runs had a typical sulfur content of 0.7 percent
and when burned in the Plant Mitchell facility S02 emissions ranged from 400
to 460 ng/J (0.9-1.1 lb/106 Btu) (Ref. 2-76, 2-77). This is approximately
an 80-85 percent reduction of the emissions that would arise from direct-
firing of the original coal feed. SRC-I produced from other high sulfur
coals, however, may produce higher S02 emissions and will require flue gas
desulfurization (FGD) to meet an emission level of 520 ng S02/J. SRC-II,
H-Coal, and EDS liquid fuels can probably meet a 520 ng S02/J emission level
without FGD.
In order to meet an emission level of 260 ng S02/J, (approximately
90 percent control of direct, high sulfur coal-fired emissions), SRC-I
would need to have a sulfur content below 0.48 percent. This is well below
the typical SRC-I value of 0.7 percent, and would restrict usage of many
SRC-I products. SRC-I made from low sulfur coals such as those from
Kentucky, Indiana, and the West could meet this level without post-
combustion controls, but the use of low sulfur coal negates the purpose of
SRC-I production. The heavy liquid fuels from SRC-II, H-Coal, and EDS
will probably meet a 260 ng SOz/J emission level, but in some cases
additional hydroprocessing may be required.
To meet an emission level of 90 ng SOz/J (approximately 96 percent
control of direct, high sulfur coal-fired emissions), the use of SRC-I fuel
is uncertain (Ref. 2-78). The residual sulfur content of the SRC-I fuel
would need to be 0.16 percent. To meet this emission level would require
the use of low sulfur coal or flue gas desulfurization processes.
To meet a 90 ng S02/J emission level, many of the SRC-II, H-Coal, and
EDS liquid fuels will require additional hydroprocessing to reduce their
sulfur content to 0.2 percent or less. Table 2.3-10 shows the maximum
acceptable sulfur content in the various coal-derived liquid fuels to meet
the three emission levels just discussed.
2-67
-------
TABLE 2.3-10. EFFECT OF S02 EMISSION LEVELS ON SULFUR CONTENT TOLERANCE IN LIQUID FUELS
Fuel Type
SRC-I
SRC-I
SRC-II, H-Coal,
Average
Heating Value,
MJ/kg (Btu/lb)
34,9
37,2
39.5
(15,000)
(16,000)
(17,000)
Typical Sulfur
Content of Fuel,
wt %
0.7
0.7
SRC-II - 0.3
Acceptable Sulfur Content of Fuel, wt % for
Flue Gas S02 Limits of ng/J (lb/106 Btu)
520 (1.2)
0.90
0.96
1.02
260 (0.6)
.0.45
0.48
0.51
90 (0.2)
0.15
0.16
0.17
and EDS (raw H-Coal - 0.5
7" fuel) EDS - 0.3
00
SRC-II, H-Coal 44.2 (19,000) SRC-II - 0.01 1.14 0.57 0.19
(hydroprocessed H-Coal - 0.002
fuels), and EDS EDS - 0.3
-------
B. Nitrogen Oxides—Depending upon the removal of nitrogen from coal
in the liquefaction process and/or during hydroprocessing, and the success
of developing combustion modifications, flue gas denitrification may or may
not be necessary. The results of the SRC-I tests at Plant Mitchell indicate
NOX emissions around 190 ng NOX/J (Ref. 2-76, 2-77). Unfortunately, these
figures are somewhat suspect due to excess air problems experienced while
operating the boilers. Further testing is required to determine the actual
N0x content of the combustion gas.
Laboratory testing done on an 880 kW boiler (Ref. 2-79) by KVB, Inc.,
revealed that by using combustion conditions typical of many large utility
boilers, NOX levels could be reduced to 170 ng NOX/J using SRC fuel oil
(SRCO).
C. Particulate Matter—No conclusive results were obtained from the
Plant Mitchell test site for particulate matter. It is known that the ash
content of the base coal is reduced to between 0.1 and 0.6 percent in the
SRC-I process. It is also thought that burning of the low-sulfur, low-ash
SRC will probably produce a high-resistivity fly ash, which may reduce the
collection efficiency of conventional cold precipitators which operate near
150°C.
For coal liquids the particulate emissions will depend more on the
percent of carbon unburned during combustion than on the amount of ash in
the coal liquids. Coal liquids have a very low ash content, and one test
on EDS (Ref. 2-63) showed that practically all Lhe carbon is combusted.
Table 2.3-11 compares the particulate emissions (Ref. 2-63) from EDS coal
liquids with those from low-sulfur fuel oil (LSFO) and regular-sulfur fuel
oil (RSFO).
2-69
-------
TABLE 2.3-11. EDS FUEL OIL COMBUSTION TEST - PARTICULATE EMISSIONS
Particulate emissions
Total particulates
mg/m3
Total particulates,
% wt. (in fuel)
Ash content of sample
% wt.
Coal
205-538°C
27
0.03
0.027
liquids
205 °C+
33
0.04
0.03
Petroleum
LSFO*
50
0.06
0.02
fuel oils
RSFO*
131
0.07
0.08
*LSFO: Low-sulfur fuel oil
RSFO: Regular-sulfur fuel oil
Source: Ref. 2-63
2.3.5.2 Boiler Impacts and Maintenance Requirements—
To date, no commercial coal liquefaction plants have been built and
only limited combustion tests have been performed on the coal-derived
liquids. As a result, information regarding maintenance requirements and
the impact these coal-derived fuels would have on an industrial boiler are
not available. However, the impacts and maintenance requirements for coal
liquids-fired boilers should be similar to those of oil-fired boilers.
2-70
-------
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California, 23(1). March 1978.
2-65. Sage, W.L., W. Downs and P.L. Cioffi. Characteristics of Solvent
Refined Coal: Dual Register Burner Tests, FP-628, EPRI 1235^-5.
Prepared for Electric Power Research Institute by the Babcock &
Wilcox Company, Ohio. 1978.
2-66. Borio, R.W., et al. Solvent Refined Coal Evaluation: Pulverization,
Storage, and Combustion. .EPRI l235-2b. Prepared for Electric Power
Research Institute by C-E Power Systems. Connecticut. June 1976.
2-67. Downs, W., et al. Investigating Storage, Handling and Combustion
Characteristics of Solvent Refined Coal: Task C Extension, EPRI .
1235-4. Prepared for Electric Power Research Institute by the Babcock
& Wilcox Company. 1976.
2-68. Borio, R.W. Laboratory Analysis of Solvent Refined Coal. EPRI
1235-2a. C-E Power Systems. Combustion Engineering, Inc. June 1976.
2-69. U.S. Department of Energy. H-Coal Integrated Pilot Plant: Phase I -
Final Report, Contract No. EX-76-01-1544. Prepared for U.S. Depart-
ment of Energy by Hydrocarbon Research Inc. November 1977.
2-70. Fant, B.T. Exxon Donor Solvent Coal Liquefaction Commercial Plant
Study Design. Prepared for U.S. Energy Research and Development
Administration by Exxon Research and Engineering Company. Florham
Park, New Jersey. January.
2-71. Balzhiser, R.E. R&D Status Report: Fossil Fuel and Advanced Sys-
tems Division, EPRI Journal, Vol. 3, No. 5. June 1978.
2-72. Nongbri, G. and N. Stewart. Solvent Refining of West Kentucky 9-14
Coal. EPRI Af-499. Prepared for Electric Power Research Institute
by Mobil Research and Development Corporation. Paulsboro, NJ.
October 1977.
2-73. Dabkowski, M.J. , et al. Upgrading of Coal Liquids for Use as Power
Generation Fuels. EPRI AF-44. Prepared for Electric Power Research
Institute by Mobil Research and Development Corporation. Paulsboro,
NJ. October 1977.
2-74. Epperly, W.R. EDS Coal Liquefaction Process Development. Phase
IIIB. FE-2893-3. Prepared for U.S. Department of Energy by Exxon
Research and Engineering Company. Florham Park, NJ. July*-Septeraber
1977.
2-76
-------
2-75. Spencer, D.F., S.B. Alpert and R.H. Wolk. Review of Alternative
Liquefaction Processes. EPRI: Electric Power REsearch Institute,
Palo Alto, CA. 1978.
2-76. The Southern Company Services, Solvent Refined Coal Burn Test. April
1978.
2-77. Budden, Kenneth G., and Subhash S. Patel. Air Emissions from Combus-
tion of Solvent Refined Coal. Final Report. Report No. EPA-600/7-79-
004, EPA Contract No. 68-02-2162. Columbia, MD, Hittman Associates,
Inc., January 1979.
2-78. Alpert, S.B., et al. Review of Solvent-Refined Coal Technology.
Electric Power Research Institute. March 1978.
2-79. Arand, J.K. and L.J. Muzio. Combustion and Emission Evaluation of
SRC Fuel Oil, A Synthetic Liquid from Coal, KVB 19900-733. Prepared
for Gulf Mineral Resources by KVB, Inc. Tustin, CA. December 1977.
2-77
-------
SECTION III
SELECTION OF "BEST CANDIDATE" SYNTHETIC FUELS SYSTEMS
In the previous section, the population of coal gasification and
liquefaction systems were identified and discussed. From that population,
a list of systems considered to be likely candidates for use as precombustion
emission controls for industrial boilers were identified. For the coal
liquefaction systems, the preliminary screening step identified four candi-
date systems: SRC-I, SRC-II, H-Coal, and Exxon Donor Solvent (EDS). For
low- and medium-Btu coal gasification, fourteen candidate gasifiers and
fourteen acid gas removal (AGR) processes were identified (see Tables 2.1-6
and 2.1-7).
The second step in assessing the synfuels from coal technologies is to
compare the candidate systems and select several "best candidate" systems
for detailed analyses of costs and energy and environmental impacts (see
Figure 3.1-1). The results of those comparisons and selections are presented
in this section. Low-Btu coal gasification is addressed in Section 3.1,
medium-Btu gasification in Section 3.2, and coal liquefaction in Section 3.2.
In selecting "best candidate" systems, the following criteria were
considered:
• System performance,
• Status of development,
• Applicability,
3-1
-------
NJ
Population
of Systems """
Section 2
Description of
Technologies
and
Preliminary
Screening
Candidate
Systems
Section 3
Selection of
"Best Candidate"
Systems
"Best Candidate" I
Systems
Section 1
Selection of
Best Systems
and
Executive Summary
Detailed Analysis
Economic
Energy
Environmental
Section
4
5
6
Figure 3.1-1. Schematic of study approach.
-------
• Preliminary cost considerations,
Preliminary energy considerations, and
• Preliminary environmental considerations.
A discussion of how these criteria were applied to the synthetic fuels from
coal systems is presented in the following text.
Obviously, a primary concern in the selection of a synthetic fuels sys-
tem is the system's performance, i.e., what emissions will result from com-
bustion of the synthetic fuel. In applying this selection criteria, system
performance was compared to three target control levels for SOX, NOX, and
particulate emissions. Labeled "moderate, intermediate, and stringent",
these target control levels were chosen only to encompass all candidate tech-
nologies and form bases for comparison of technologies for control of specific
pollutants considering performance, costs, energy, and non-air environmental
effects. Table 3.1-1 summarizes the target emission control levels selected
for the synthetic fuels technologies. The following text briefly discusses
the rationale behind the selections.
TABLE 3.1-1. TARGET EMISSION CONTROL LEVELS FOR SYNTHETIC FUELS
FROM COAL TECHNOLOGIES
S02, NOX Particulates,
ng/J ng (as N02)/J ng/J
(lb/106 Btu) (lb/106 Btu) (lb/106 Btu)
Coal Gasification
Moderate Control
Intermediate Control
Stringent Control
Coal Liquefaction
Moderate Control
Intermediate Control
Stringent Control
150 (0.5)
86 (0.2)
43 (0.1)
520 (1.2)
260 (0.6)
86 (0.2)
86 (0.2) 13 (0.03)
300 (0.7)
220 (0.5) 13 (0.03)
86 (0.2)
3-3
-------
The moderate S02 target control level for gasification systems was set
at 150 ng/J (0.35 lb/106 Btu) heat input to the boiler. This emission
level is what would be obtainable by removing essentially all of the H2S
from a high sulfur coal derived low-Btu gas. The stringent SOa control
level was set at 43 ng/J (0.1 lb/106 Btu). The NO^ and particulate
X
emission target control levels were set at 86 ng NOx/J (0.2 lb/106 Btu)
and 13 ng particulates/J (0.03 lb/106 Btu). These levels were selected
because they are comparable to those for natural gas combustion. Also,
because these levels are considered low, but should be readily attainable
by this technology, only one target level of control was chosen for NO and
X
particulates.
For the coal liquefaction systems, the moderate target SOa control
level was set at 520 ng/J (1.2 lb/106 Btu) heat input to the boiler.
This level is what appears to be attainable by the SRC-I process (the
most advanced liquefaction system) using a high sulfur coal feed. The
stringent target control level was set at 86 ng/J (0.2 lb/10 Btu), which
represents what would be obtainable by additional hydroprocessing of the
synthetic liquids produced by the SRC-II, H-Coal, or EDS processes. The
moderate target NOX control level was set at 300 ng/J (0.7 lb/106 Btu),
which is what would be expected from direct coal combustion. This is a
reflection of the difficulty that the liquefaction processes have in
removing nitrogen from the synthetic liquids. The stringent target NO
control level was set at 86 ng/J (0.2 lb/106 Btu). This level is equal
to the gasification target control level and could be obtainable with
additional (possibly extensive) hydroprocessing. Only one target particu-
late control was selected - 13 ng/J (0.03 lb/106 Btu). This level is
what would normally be expected from combustion of low ash containing
synthetic liquid fuels.
3-4
-------
In choosing the "best candidate" systems for achieving a given emission
control level, system performance is evaluated for two coal feedstocks—a
high sulfur eastern coal and a low sulfur western coal (see Table 3.1-2).
Examining other coals, such as a low or medium sulfur eastern or medium
sulfur western, was not felt to be necessary. The rationale for this decision
can best be explained by considering, for example, low-Btu coal gasification.
By including sulfur species removal in the low-Btu gasification system,
several constraints are imposed on the processing scheme. Specifically, the
currently available sulfur species removal techniques require the feed gas
to be at a relatively low temperature, and essentially free of particulate
matter. Thus, prior to sulfur removal the raw gas from the gasifier is
treated in a series of quenching and cooling units. A side benefit of the
quenching/cooling steps is the removal of particulate matter and most of
the nitrogen bearing compounds (NH3 and HCN) present in the raw low-Btu
gas. The amounts of particulates and nitrogen species removed have little
influence on the energy, environmental, and cost impacts of the gasification
system. Therefore, control of particulate and N0x emissions via low-Btu
coal gasification has minimal dependence on the coal feedstock composition.
As would be expected though, the impacts of controlling sulfur emis-
sions via coal gasification do depend on the coal feed sulfur content.
However, the quantity of sulfur species present in the raw low-Btu gas (and
hence the quantity which must be removed to meet a given SOa emission
control level) is directly proportional to the coal sulfur content. Thus, by
examining both a low and high sulfur coal feed, the range of impacts will
be examined. And, from that information the impacts associated with a
medium sulfur coal could be easily interpolated.
Status of development is also an important selection criteria. Emis-
sion standards for industrial boilers are expected to be proposed by 1981.
Therefore, the systems being assessed in this report must be either
currently commercially available or have reasonable expectations of being
successfully demonstrated and commercially available by 1981.
3-5
-------
TABLE 3.1-2. ULTIMATE ANALYSIS OF BASE COALS
Eastern High Sulfur Western Low Sulfur
Composition, wt %
Carbon 64.80 57.60
Hydrogen 4.43 3.20
Sulfur 3.54 0.60
Oxygen 6.56 11.20
Nitrogen • 1.30 1.20
Moisture 8.79 20.80
Ash 10.58 5.40
Heating Value, MJ/kg (Btu/lb) 27.4. (11,800) 22.3^(9,600)
Applicability is the third major criteria used in selecting "best
candidate" systems. Some candidate control systems may not be feasible for
certain boiler types or capacities.
Costs, energy, and environmental impacts of the emission control
systems are as important as the three criteria mentioned above. However,
for the process screening step discussed in this section, only preliminary
estimates of these factors are used. Detailed analysis of costs, energy,
and environmental impacts will be performed in Sections 4, 5 and 6 respec-
tively for each of the "best candidate" systems selected.
3.1 SELECTION OF "BEST CANDIDATE" LOW-BTU COAL GASIFICATION SYSTEMS
In selecting "best candidate" low-Btu gasification systems, it is
necessary to select not only "best candidate" gasifiers, but more importantly
to select "best candidate" acid gas removal (AGR) processes. As discussed
in Section 2, the performance of a gasification system as a precombustion
emission control depends on its ability to produce a "clean" burning fuel.
Sulfur compounds are removed by the AGR process employed, while particulates
and fuel bound nitrogen compounds (e.g., NHs and cyanides) are mainly
3-6
-------
removed when the raw low-Btu gas is quenched and cooled. Since quenching/
cooling is a prerequisite for all of the AGR processes considered in this
study, control of particulate and N0x emissions is a side benefit of SOz
emissions control.
The candidate gasifiers identified in Section 2 are compared in
Section 3.1.1 and a "best" or representative candidate is selected. The
compositions of the raw and cooled low-Btu gases produced by this gasifier
from the two base case coal feedstocks are also presented in this section.
Then, in Section 3.1.2 the candidate AGR processes are compared and "best
candidate" processes selected. Finally, Section 3.1.3 is a brief summary of
the "best candidate" systems selected, i.e., the combination of gasifiers
and acid gas removal processes for which detailed analyses will be performed
in Sections 4, 5 and 6.
3.1.1 Comparison and Selection of a Candidate Low-Btu Gasifier
Fourteen candidate low- and/or medium-Btu gasifiers were identified in
Section 2. Examination of this list indicates that four of those gasifiers
can only be operated with pure (98+ percent) oxygen as the gasifying agent
and hence are considered as medium-Btu gasifiers. The ten gasifiers which
can use air as the gasifying agent, as well as the four medium-Btu gasifiers,
are listed in Table 3.1-3. Also included in this table are the data which
were used to compare the low-Btu gasifiers. The result of the comparisons
was the selection of the Wellman-Galusha gasifier as the "best candidate".
The rationale behind that selection is presented in the following text.
Six of the ten low-Btu gasifiers listed in Table 3.1-3 are commercially
available. In addition, the Foster Wheeler/Stoic, which is currently being
demonstrated, is nearly identical to the commercially available Woodall-
Duckham/Gas Integrale gasifier and as such is considered commercially
available. The other three gasifiers, BI-GAS, Coalex, and Pressurized
Wellman Galusha (MERC) are in the pilot or demonstration plant stage of
3-7
-------
TABLE 3.1-3. COMPARISON OF CANDIDATE GASIFIERS
I
00
Gaslfier
BGC
Slagging
Lurgl
Bl-Gas
Chapman
(Wilputte)
Coalex
Foster Wheeler/
Stoic
GFERC
Slagging
Koppers-
Totzek
Type
of Gas
Medium-
Btu
Low- or
Marlt nn I
Hecnuiit—
Btu
Low- or
Medium-
Btu
Low-Btu
Low-Btu
Medlum-
Btu
Medlum-
Btu
Cold Gas
Environmental Impacts Efficiency
Pressure
High
Pressure
High
Atmo-
spheric
Atmo-
spheric
Atmo-
spheric
High
Pressure
Atmo-
spheric
Development Status
Demonstration
plant (started
1976)
Hot been demon-
plant started in
August 1976
Commercially
available (since
1945) for Low-
Btu gas; not
commercially
demonstrated for
nedium-Btu gas
Pilot plant
since 1976
Demonstration
plant construction
begun in 1977
Pilot plant
(1958-1965)
Commercially
available since
1952
Feedstock Restrictions
Accepts all types; strongly
caking requires agitation;
13-51 mm size coal; <20Z
moisture; crushing and
sizing required; low ash
coal may require fluxing
agents.
Accepts all coal types; 70Z
and pulverizing required;
also slurry preparation or
fluxing agent.
Accepts all coal types; size
<102 mm; crushing and
sizing required.
Accepts all coal types
(lignite not been tested) ;
<0.07 mm sized coal;
crushing and pulverizing
required; additives
required.
Lignite, subbitunlnous, non-
caking bituminous; 19-38 ma
sized coal; crushing and
sizing required; partial
oxidation may be needed for
strongly caking coals.
Bituminous char, lignite
char, lignite; 6.4-19 mn
sized coal; <35Z moisture;
Crushing and sizing required.
Accepts all coal types; 70Z
to 90Z less than 0.074 mm;
pulverizing required; ^1-8Z
Direct
Coal lock gas
Slag quench
vent gas
Slag lock gas
Slag quench blow-
down
Slag slurry
Slurry prepare-
Slag lock gas
Slag slurry
(solid &
liquid)
Barrel valve
vent gas
Poke hole gases
Ash pan gas
Ash
Additive hopper
vent gas
Slag slurry
(solid &
liquid)
Coal hopper
vent gas
Ash pan gas
Ash
Poke hole gases
Coal lock gas
Slag quench
vent gas
Slag quench
blowdown
Slag slurry
Coal bin N;> vent
Slag
Slag slurry
Indirect (Z)a
Waste streams from 83
gas purification;
process condensate
quenching liquor,
coal fines.
Essentially no tars, 69
phenols in raw pro-
duct gas; gas treat-
ment produces process
condensate and
quenching liquor.
Waste streams from DNA
gas purification;
process condensate,
quenching liquor;
coal fines.
Essentially no tars DNA
or oils in raw product
gas; gas purification
nay create additional
unwanted streams.
Waste streams from gas 77
purification; tars/
oils, coal dust.
Waste streams from gas 85
purification; process
condensate, quenching
liquor, coal fines.
Essentially no tars, 75
oil, naphthas or
phenols in raw product
moisture; possible addition
of fluxing agents to lower
ash fusion temp.
gas; gas treatment
produces process con-
densate and quenching
liquor.
(Continued)
-------
TABLE 3.1-3. Continued
CO
VO
Gaslfier
Lurgi
Pressurized
Wellman-Galusha
(MERC)
Rlley-Morgan
Texaco
Wellman-Galusha
Winkler
Woodall-
Duckham/Gas
Integrals
Type
of Gas
Low- or
Medlum-
Btu
Low- or
Medlum-
Btu
Low- or
Medium-
Btu
Medium-
Btu
Low-Btu
Low- or
Medlun-
Btu
Low-Btu
Cold Gas
Environmental Impacts Efficiency
Pressure
High
Pressure
High
Pressure
Atmo-
spheric
High
Pressure
,
Atmo-
spheric
Atmo-
spheric
Atmo-
spheric
Development Status
Commercially
available (since
1941)
Pilot plant (since
1958); not com-
mercially demon-
strated for
medlum-Btu
Commercially
available for lov-
Btu gas (Pilot
plant since 1975) ;
not commercially
demonstrated for
medium-Btu gas
Pilot plant
Commercially
available (since
1941)
Commercially
available since
1926
Commercially
available (since
1940)
Feedstock Restrictions
Accepts all coal; strongly
caking coals may need par-
tial oxidation or agitation;
crushing and sizing
required; <35Z moisture;
3.2-38.1 mm sized coal.
Accepts all types; 501
<12.7 mm sized; no predrying;
crushing and sizing required.
Accepts all coal types; 3.2-
51 mm sized coal; crushing
and sizing required.
Accepts all coal types; 70X
less than 0.074 mm; crushing,
pulverizing, slurry
preparation required.
Can use anthracite, bitumi-
nous, charcoal, or coke; 7.9-
14.3 mm for anthracite* 26-51
mm for bituminous; crushing
and sizing required.
Lignite, subbltumlnous, weakly
caking bituminous; <9.53 mm
sized coal; crushing required;
<30Z moisture for lignites;
<18I moisture for higher rank
coals; partial oxidation may
be required.
Lignite, bituminous; 6.4-38.1
mm sized coal; crushing and
sizing required; drying not
required; partial oxidation
for strongly caking coals.
Direct
Coal lock gas
Ash lock gas
Ash
Ash quench
water
Coal lock gas
Ash lock gas
Ash
Coal lock gas
Ash pan gas
Ash
Poke hole gases
Slurry prepara-
tion vent gas
Slurry steam
purge
Preheater flue
gases
Slag slurry
Coal bin gas
Ash hopper gas
Ash
Poke hole gases
Coal bin Ni vent
Dry ash bin N:
vent
Ash slurry
settler vent
Dry ash
Ash slurry
Coal hopper vent
gas
Ash lock gas
Ash
Indirect (Z)a
Waste streams from 63-80
gas purification;
process condensate,
quenching liquor,
tars, oil, phenols,
NH;.
Waste streams from 79
gas purification;
process condensate,
quenching liquor,
coal fines.
Waste streams from 64-68
gas purification;
process condensate.
quenching liquor,
coal fines.
Essentially no tars, 77
oils, naphthas, or
phenols in raw product
gas; gas treatment
produces process con-
densate and quenching
liquor.
Waste streams from 75
gas purification; coal
sate, quenching liquor.
Essentially no tars, 55-72
oils, or naphthas in
raw product gas; treat-
ment produces process
condensate and quenching
liquor.
Waste streams from gas 77
purification; tar,
process condensate, dust.
Cold Gas Efficiency
Product Gas Energy Output
Coal Energy Input
Source: Ref. 3-1 through 3-16
DNA: Data not available
-------
development. Current plans for these gasifiers do not indicate that they
will be commercially available within the time frame being considered in
this study. Therefore, they will not be considered further.
Of the seven gasifiers considered commercially available, five are
small capacity (coal feed rates approximately 5000 kg/hr or less), atmospheric
pressure units (Ref. 3-1). These include:
• Wellman-Galusha,
Woodall-Duckham/Gas Integrale,
• Chapman,
Riley-Morgan, and
Foster Wheeler/Stoic.
The other two gasifiers typically have larger capacities. The atmospheric
pressure Winkler unit gasifies around 20,000 kg/hr (44,000 Ib/hr), while
a 3 m (10 ft) diameter pressurized Lurgi gasifier has a coal feed rate of
5,000-18,000 kg/hr (11,000-40,000 Ib/hr) depending on coal type (Ref. 3-1).
For the industrial boiler sizes being considered in this study (10-60
MW), the coal feed rate to a companion sized low-Btu gasification facility
would be 2,000-11,000 kg/hr (4,400-24,000 Ib/hr). Thus, a single Winkler or
Lurgi gasifier would be too large for even the largest capacity boiler being
examined, let alone for the smaller boilers. The other gasifiers have
capacities comparable to the smaller boilers, and for the larger boilers
could meet the fuel demand with the installation of multiple gasifiers.
In light of the status of development and capacity considerations of
the ten candidate low-Btu gasifiers, only the five gasifiers listed above
are considered as possible "best candidates". Since all five gasifiers also
operate at atmospheric pressure, have comparable energy conversion effi-
ciencies, and are relatively simple pieces of equipment, their energy and
economic impacts are also comparable. Moreover, the major environmental
3-10
-------
impacts associated with a gasification system originate in the gas cleanup
steps. Thus, based on preliminary estimates of costs, environmental, and
energy impacts, none of the five possible "best candidate" gasifiers are
eliminated or singled out as being superior. Therefore, since all of these
gasifiers are comparable, the Wellman-Galusha gasifier was selected as the
representative "best candidate" gasifier because there are more data avail-
able concerning its waste streams and product gases produced from various
coal types.
The estimated compositions of the raw and quenched/cooled low-Btu gases
produced by gasifying the two study basis coals (see Table 3.1-2) in a
Wellman-Galush gasifier are shown in Table 3.1-4. The major gaseous
components were taken from a study performed by Battelle (Ref. 3-17). The
NHs, HCN, H2S and COS values for the low sulfur coal case were estimated
from experimental data (Ref. 3-7, 3-18, 3-19). For the high sulfur coal
case, values for these minor components were based on engineering estimates,
since data for gasifying high sulfur coal in an atmospheric pressure, fixed-
bed gasifier were not available. Tars and oils in the raw low-Btu gases
were estimated at 10 percent of the coal feed.
Entrained particulates and tars/oils in the raw low-Btu gases produced
by the Wellman-Galusha gasifier are removed by the quench/cooling steps
shown in Figure 3.1-2. These steps include a cyclone for removal of
particulates, an in-line quench, tray and spray scrubbers for tar and oil
removal, and an electrostatic precipitator to remove residual tars, oils
and particulates. Greater than 99.5 percent of the tars, oils and
particulates can be removed by this quench/cooling system (Ref. 3-20, 3-21,
3-22).
3.1.2 Comparison and Selection of Candidate Acid Gas Removal Processes
The preliminary screening step discussed in Section 2 identified the
following candidate acid gas removal (AGR) processes:
3-11
-------
TABLE 3.1-4.
ESTIMATED COMPOSITIONS OF LOW-BTU GASES
FROM WELLMAN-GALUSHA GASIFIER
kg/m3(@ 43°C,
1 atm)
HHV, MJ/m3
Low Sulfur Western
Coal Feed
High Sulfur Eastern
Coal Feed
Composition,** vol. ;
C02
CO
OU
H2
H20
N2
H2S
COS , ppmv
NH$ , ppmv
HCN , ppmv
Tars & Oils,
Raw Gas
I
2.99
25.06
2.47
12.98
12.34
44.02
0.10
50
260
78
0.030
Quenched Gas*
3.11
26.11
2.57
13.53
8.67
45.87
0.11
54
270
81
0.0002
Raw Gas
3.04
25.74
2.56
12.73
9.62
45.53
0.69
270
270
97
0.027
Quenched Gas*
3.08
26.01
2.59
12.87
8.67
46.01
0.70
280
280
98
0.0001
5.48
5.71
5.56
5.62
*The amounts of H2S, COS, NH3, HCN, as well as major gas components, which
will be absorbed from the gas during the quenching steps is not known.
The values shown assume no gas absorption. Tar and oil values are based
on 99.5% removal.
**Major gas components are based on information presented in Ref. 3-17.
H2S, COS, NHs, and HCN values are based on experimental data (Ref. 3-7,
3-18, and 3-19). Tars and oils in raw gas are estimated at 10% of the
coal feed.
3-12
-------
Quench/Cooling
Water
Quench/Cooling
Water
r
(-•
CO
Raw Product
Gas Iiam
Gas Iflee
Electrostatic
Preclpltator
Participates
Participates, Tars,
Oils, and Liquors
to further pro-
cessing
Figure 3.1-2. Wellman-Galusha quench/cooling steps.
-------
• Physical Solvent Processes
- Rectisol
- Selexol
- Purisol
- Estasolvan
- Fluor Solvent
• Chemical Solvent Processes
- MEA (monoethanolamine)
- MDEA (methyldiethanolamine)
- DEA (diethanolamine)
- DIPA (diisopropanolamine)
- DGA (diglycolamine)
- Benfield
Combination Chemical/Physical Solvent Processes
- Amisol
- Sulfinol
• Direct Conversion Process
- Stretford
Pertinent data concerning these processes are presented in Tables 3.1-5,
3.1-6, and 3.1-7. Comparisons of these processes with respect to their use
in low-Btu gasification facilities are summarized in the following text.
The results of the comparisons are the selection of the Stretford and MEA
processes as the "best candidates" for further study.
First, all of the candidate processes are commercially available.
However, most of the processes have not found application in coal gasifica-
tion facilities. The most common applications have been in the purification
of natural gas or refinery gas. These are high pressure applications that
required essentially complete (-5 ppmv) removal of sulfur species. In spite
3-14
-------
TABLE 3.1-5. PHYSICAL SOLVENT ACID GAS REMOVAL SYSTEM
Commercial Application,
Purification
Applicabi] llv to
falsification
Operating Pressure
Maximum Control
Effect iveness
r Hi*h cos2/cs2
rre,sure ^
H?S
„ COS/CS2
Pressure R_gH
Operational, Mainte-
nance Problems, and
Reliability
Estasolvan
Natural gas and
liquid hydrocarbon
gas
Technically feasible
Typically 6.9 HPa
<3 ppmv
<0.25 g/100 scf
<2.0 g/100 scf
Ineffective
Not complex.
Fluor Solvent
Natural gas, ammonia
and hydrogen gas
Technically feasible
5.86-6.90 HPa
ppmv
Data not available
Data not available
Ineffective
Requires low heavy
hydrocarbon content
and high combined
II2S and CO: partial
pressure (275 psl).
Purisol
Natural gas and hy-
drogen streams
Technically feasible
Typically 6.9 MPa
2 ppmv
Data not available
Data not available
Ineffective
Expensive solvent.
Moderately complex
operation.
Rectlsol
Hydrogen synthesis gas,
partial oxidation efflu-
ent g.is and low/medium
Btu coal gas
Proven fur pressurized
] uw/medlum-Rtii coal gns
2.06-6.90 HPa
1 ppmv
1 ppmv
1 ppmv
Ineffective
Inexpensive solvent;
sustained cooling is
required resulting in
a complex flow pattern
for minimization of
Sclexot
Synthesis and natural
gas, and coal gasifies
tion pilot plant pro-
duct gas
Technically feasible
'3. '.5-6. 90 MTa
1 ppmv
1 ppnv
1 ppmv
Tnef f ec tive
Expensive solvent.
Not effective at low
acid gas concentra-
tions. Moderately
comp] ex.
Environmental
Considerations:
System produces an
acid gas stream
System produces a
solvent blowdown
Preliminary Capital
Cost
Utility Requirements:
Steam
Electricity
Cooling Water
Not complex.
Yes
Yes
Data not available
Yes
Yes
Yes
Yes
Yes
Data not available
Yes
Yes
Yes
Yes
Yes
Data not available
Yes
Yes
Yes
energy requirements
by use of heat exchan-
gers. This results
in moderately diffi-
cult start-up and
shutdown.
Yes
Yes
Data not available
Yes
Yes
Yes
Yes
Yes
Approximately 70
percent of MEA
Yes
Yes
Yes
Source: Ref. 3-1, 3-2, 3-23 through 3-26
-------
TABLE 3.1-6. CHEMICAL SOLVENT ACID GAS REMOVAL SYSTEMS
Commercial Application,
Purification
Applicability to
fins! f icatlon
Operating Pressure
Maximum Control
Effectiveness
„ "lgh «£/«,
Pressure „_,,„>
, I'OW COS/CS,
Pressure
Operational, Hainte-
1 Reliability
Environmental
Considerations:
System produces an
acid gas stream
System produces s
solvent blowdown
Preliminary Capital
Coot
Utility Requirements:
Steam
Electricity
Cooling Water
BENFTELD
Pilot plant gasification
producer gas, sour nat-
ural gas
Proven for lov/medluai
Btu gas
0.69-3.18 HPa
2 ppmv
27 pp.
Data not available
Data not available
Data not available
Data not available
Moderately complex de-
Tea
Tes
Approximately 80Z of
NEA; dependent on
tlte partial pres-
sure of CO, and H,S
Tes
Tes
Tes
DIA
Nstural gss and re-
finery raw gaa
Technically feasible
atm +
3 ppm HiS
70
Some
Ineffective
Data not available
Corroalon, foaming.
pressures. High CO
concentrations. . Sim-
ple design and rela-
tively easy operation.
Tes
Tes
$.81 MM for 20 MM scfc
6Z COi, 21 H,S
Tes
Tes
Tes
DGA
Natural, synthesis,
and refinery aour
gases
Technically feasible
(applied on pilot
plant)
Not pressure-
sensitive (atm +)
<« ppmv
90+
Data not available
Data not available
Data not available
Must hive a minimum
cent acid gas. Mod-
erately complex de-
sign, simple opers-
tlon.
Tes
Tea
Approximately 802 of
MEA
Tes
Tes
Tes
DIPA
Nstural gas, refin-
ery gss, synthesis
gss or LPG
Technically feasible
0.1-6.90 HPa
.
5 ppmv ("6.9 HPa)
Some
Some
Leas than 100 ppmv
Moderately complex
tion.
Tes
Tes
Comparable to DGA
or DEA
Tea
Tea
Tes
MDEA MM
Refinery sour gases Rcflnrry K.IS
Technically feasible Technlc.il ly f";i-1l,li.
0.10-0.69 HPa Not lilghly prr-ssnn—
sensitive (atm -O
4 ppmv < 1 ppmv
Host 95+
Data not available - -
* ppmv I 60 ppmv
other amines. Foam-
Ing, corrosion, Mod-
erstcly complex de-
sign, simple operation.
Tes T.-s
Tes Trs
Data not available $1 MM Tor JO MM m-frl
6Z CO,, 2T II; S
Tes Tes
Tes Tes
Tes Vex
Source: Ref. 3-1, 3-2, 3-2] through 3-27
-------
TABLE 3.1-7. COMBINATION PHYSICAL/CHEMICAL SOLVENT SYSTEMS AND DIRECT CONVERSION SYSTEM
(-•
~J
Commercial Application,
Purification
Applicability to
Gasification
Operating Pressure
Maximum Control
Effectiveness
JHoh HzS
COS/CSj
Pressure B «„
HjS
_ U" oos/cs,
Pressure „ *
Amlsol
Ammonia and methanol
Technically feasible
Typically 1.38 HPa
21 ppmv
Total sulfur
compounds
Data not available
Combination Solvent Systems
Sulfinol
Refinery, natural and synthesis
gases, TJW feed stocks, hydrogen
Technically feasible
atm - 6.90 MPa
<1 ppm
<2 ppm
0.25 grains/100 SCF
Data not available
Direct Conversion
Stretford
Natural, cokeover
and producer gas
Proven
Not pressure sensitive
5 ppmv
Some methymercaptan
Same as high pressure
Operational, Mainte-
nance Problems, and
Reliability
Environmental
Considerations:
System produces an
acid gas stream
System produces a
solvent blowdown
Preliminary Capital
Cost
Utility Requirements:
Steam
Electricity
Cooling Water
Must have a significant
acid gaa partial pressure.
Operation & design are
moderately complex.
Expensive solvent.
Operation & design
are moderately complex.
Tea
Yes
Data not available
Tea
Yes
Tea
Yes
Yes
Data not available
Yes
Yes
Yes
A high CO; concentration
results In lower pH which
reduces efficiency. Complex
chemistry, moderately complex
operation t startup. Acid
gas concentration must be
less than 15-20 percent.
No
Yes
•\.$5 MM for 100 IMSCFD of low
Btu gas from a coal gasifler
gasifying 4J sulfur coal
Yes
Yes
Yes
Source: Ref. 3-1, 3-2, 3-23, J-25, 3-26
-------
of the lack of use in coal gasification facilities, the use of all of the
candidate AGR processes in that application is technically feasible (Ref.
3-1, 3-23).
While technically feasible for use in gasification facilities,
several of the candidate AGR processes are limited in their application due
to the pressure of the gas stream to be treated. The two low-Btu gases
listed in Table 3.1-4 are at near atmospheric pressure. These gases could
be compressed to moderate pressures (less than 0.7 MPa) without incurring
severe economic penalties. However, compression to higher pressures such
as 7 MPa (70 atm) would not be economically desirable.
In light of this constraint, several of the candidate AGR processes
can be eliminated from consideration for use in a low pressure gasification
facility. Included in the list of processes which require high pressures
or for which low pressure operation data are not available are all of the
physical solvent and combination physical/chemical solvent processes as
well as the DEA, DGA, and Benfield processes which use chemical solvents.
The four candidate AGR processes which are effective at near atmospheric
or moderate pressures are the MEA, MDEA and DIPA chemical solvent processes
and the Stretford processes. The MEA process, operating at slightly above
atmospheric pressure C\/0.3 MPa), can achieve levels of 32 pprav H2S and 60
ppmv total sulfur (Ref. 3-24, 3-28). The MDEA process can reduce H2S to
4 ppmv at low pressures (Ref. 3-25), while at 0.5 MPa the DIPA process can
obtain HaS removals to less than 100 ppmv (Ref. 3-25). The Stretford process
is not pressure-sensitive, and can reduce HjS to less than 5 ppmv at low
pressures (Ref. 3-1).
In addition to removing HaS, the three amine processes also remove
organic sulfur compounds. Unfortunately, the Stretford process can only
remove HzS (Ref. 3-1). In the amine processes, the organic sulfur absorbed
3-18
-------
reacts with the solvent to form nonregenerable compounds. In the MEA
process this amounts to 15 to 20 percent of the COS removed (Ref. 3-26).
The operation, maintenance, and reliability of the candidate AGR
processes are addressed in Tables 3.1-5, 3.1-6, and 3.1-7 with respect to:
1) the corrosive or foaming nature of the solvent, 2) the cost of the
solvent, 3) the limiting acid gas concentration, and 4) the process's
complexity. As might be expected, these factors vary over a wide range,
e.g., from MEA being an inexpensive solvent to the more expensive solvent
used in the MDEA process.
Each AGR process generates waste streams that must be disposed of in an
environmentally sound manner. For the three amine processes, there are two
major waste streams: an acid gas stream and a solvent blowdown stream. The
solvent blowdown is generally a very small stream which contains trace
pollutants, dissolved NHa, cyanides, and nonregenerable solvent degradation
products. This stream generally requires some type of treatment before
disposal. The acid gas stream contains the sulfur compounds removed from
the treated gas. The Claus and Stretford processes are sulfur recovery
processes commercially used in the petroleum and petrochemical industry to
treat the acid gas stream from an AGR process. If a Claus process is used,
the Claus tail gas may require additional cleanup to meet environmental
regulations. This can be done with one of the commercially available tail
gas cleanup processes, such as the Beavon or Scott (Ref. 3-25).
Like the amine processes, the Stretford process produces a solvent
blowdown stream which must be treated prior to disposal. However, a
significant advantage of the Stretford process is that it not only removes
HaS, but also converts the H2S removed into elemental sulfur. This feature
means that, unlike the amine processes, a separate sulfur recovery process
is not required.
3-19
-------
Very little general information was available for the preliminary cost
impacts of the AGR processes. This is because costs are highly dependent
of site specific design parameters such as gas flow rate, operating pressure
and temperature, composition of the inlet gas, and desired treated gas
specifications. However, where available, general cost information is
presented in the tables. The costs reported are all in the same general
range. However, since use of the Stretford process does not require
installation of a sulfur recovery unit, as do the other AGR processes, it
appears that the Stretford may be the lowest cost option. A detailed cost
analysis is necessary to confirm this.
Specific data on utility requirements are not available on a common
basis for process comparisons. However, all of the processes require cooling
water, electricity, and steam.
Based on the information just presented, the Stretford and MEA processes
were selected as the "best candidate" AGR processes for use in low-Btu coal
gasification facilities. The Stretford process was chosen because of its
high HzS removal efficiency and its ability to convert HzS into elemental
sulfur. The MEA, MDEA, and DIPA processes appear to be comparable with
respect to the criteria used. The MEA process was selected because it is
more widely used and has sufficient operating and design data available to
assess its costs, environmental, and energy impacts.
3.1.3 Summary of "Best Candidate" Low-Btu Gasification Systems
The "best candidate" low-Btu gasification systems selected for detailed
analysis are the Wellman-Galusha gasifier with either the Stretford or MEA
process used to remove sulfur species from the quenched and cooled low-Btu
gas. Table 3.1-8 shows the sulfur content of the two cooled gases that
will be treated in the Stretford or MEA processes. Also shown in this table
are the maximum residual sulfur levels for each gas in order to meet the
target SOz emission control levels identified earlier.
3-20
-------
The Stretford process can reduce H2S to below 10 ppmv, but does not
remove COS (Ref. 3-1). By examining the COS concentrations of the two
gases, the Stretford process is capable of meeting all three emission
levels for the low sulfur coal case, but only the moderate control level for
the high sulfur coal gas. Thus, the Wellman-Galusha/Stretford system will
be examined in detail for both coal feedstocks.
If the cooled low-Btu gas is first compressed to a moderate pressure
(0.3 MPa), the MEA process can reduce the total sulfur content of the
treated gas to less than 60 ppmv. Since this is below the stringent control
level for both the low and high sulfur coal cases, the Wellman-Galusha/MEA
system could be considered for all cases.
TABLE 3.1-8. SULFUR CONTENT OF THE TWO BASE CASE LOW-BTU GASES
High Sulfur Low Sulfur
Coal Feed Coal Feed
Gas Heating Value, MJ/m3 5.62 5.71
H2S, ppmv 7000 1100
COS, ppmv 280 54
Maximum Allowable Total Sulfur
to Meet Emission Level, ppmv
- Moderate: 150 ng/J 316 321
- Stringent: 43 ng/J 90 92
- Intermediate: 86 ng/J 181 184
However, the MEA process produces an acid gas stream which must be
treated in a sulfur recovery unit. For the high sulfur case, the HaS
concentration of the acid gas stream is estimated to be about 25 vol.
percent. This level of HzS is sufficiently high to allow use of the Claus
process for sulfur recovery. Unfortunately, for the low sulfur coal case
the HaS concentration in the acid gas stream is estimated to be only about
3-21
-------
6 vol. percent. This level is too low for the acid gas stream to be treated
in a Glaus process. The major alternative to the Glaus is use of the
Stretford process which works well on streams with low HaS concentrations.
However, it is not reasonable to examine both the Stretford and the MEA/
Stretford as the sulfur removal/recovery systems for the low sulfur coal
case. While both systems can meet the stringent S02 target control level,
preliminary cost estimates indicate that use of the Stretford alone would
be much cheaper than use of the MEA process followed by the Stretford
process for sulfur recovery.
With respect to NOx and particulate emissions, all of the low-Btu
cases are expected to be able to meet the most stringent target control
level. For particulates the target level is 13 ng/J. The estimated grain
loading in the quenched low-Btu gases is 0.01 g/m3 (Ref. 3-19). This is
equivalent to around 2 ng/J in the combustion flue gases.
When low-Btu gas is combusted, NOX emissions from thermal fixation of
atmospheric nitrogen are estimated (Ref. 3-20) to be less than or equal to
those from natural gas combustion, 50-100 ng/J (Ref 3-29). This emission
range is in line with the target NOX emission control level of 86 ng/J. The
amount of NOX which will be formed from fuel bound nitrogen compounds (NHs
and HCN) cannot be estimated because the quantities of nitrogen compounds
remaining in the cleaned low-Btu are not known. While some will be
removed during both the quenching/cooling steps and the acid gas removal
step, the amounts removed cannot be accurately estimated.
3.2 SELECTION OF "BEST CANDIDATE" MEDIUM-BTU COAL GASIFICATION SYSTEMS
As for low-Btu gasification systems, it is necessary to select not only
"best candidate" medium-Btu gasifiers, but also "best candidate" acid gas
removal processes. The candidate gasifiers are compared in Section 3.2.1,
while the AGR processes are compared in Section 3.2.2. Section 3.2.3
3-22
-------
summarizes the "best candidate" systems, i.e., combinations of gasifiers and
AGR processes selected as a result of the comparisons.
3.2.1 Comparison and Selection of a Candidate Medium-Btu Gasifier
The fourteen candidate gasifiers identified in Section 2 and the data
which were used to compare them were presented in Table 3.1-2. Information
on four of the fourteen candidate gasifiers—Wellman-Galusha, Woodall-
Duckham/Gas Integrale, Foster Wheeler/Stoic, and Coalex—indicate that their
only application is in the production of low-Btu gas. In addition,
information on three other gasifiers—Chapman (Wilputte), Riley Morgan, and
Pressurized Wellman-Galusha—indicate that while it is technically feasible
to operate them to produce medium-Btu gas, that application has not been
commercially demonstrated. Therefore, these seven gasifiers are not
considered as candidates for producing medium-Btu gas.
Of the remaining seven candidate medium-Btu gasifiers, four—GFERC
Slagging, BGC Slagging Lurgi, BI-GAS, and Texaco—are only in the pilot or
demonstration plant stage of development. Moreover, the current development
plans for these gasifiers do not indicate that they will be commercially
available within the time frame being considered in this study. Thus, only
three medium-Btu gasifiers—Lurgi, Winkler, and Koppers-Totzek—can
realistically be considered as potential "best candidates" based on their
status of development and applicability.
However, the Winkler and Koppers-Totzek gasifiers can be eliminated
because they operate at atmospheric pressure. As discussed in Section 2,
economic and size considerations indicate that medium-Btu gas will probably
only be used if land availability or environmental conditions prohibit the
installation of on-site low-Btu gasifiers. Under either of these conditions,
off-site generation of medium-Btu gas and pipelining the gas to the boiler
is an alternative. But, the economics of transporting gas through a pipe-
line are improved if the gas is pressurized. And, while it is possible to
3-23
-------
compress the gas produced by a Winkler or Koppers-Totzek gas, it is less
expensive to compress the oxygen feed to a pressurized gasifier than to
pressurize the much larger quantity of medium-Btu product gas. Thus, the
pressurized Lurgi gasifier is an economic choice over either the atmospheric
pressure Winkler or Koppers-Totzek gasifier if the product gas is to be
transported.
The estimated compositions of the raw and quenched/cooled medium-Btu
gases produced by gasifying the two study coals (see Table 3.1-2) in a
Lurgi gasifier are listed in Table 3.2-1. These gas compositions were
based on published data for gasifying similar coals (Ref. 3-4, 3-16).
Adjustments were made for any differences in coal compositions.
TABLE 3.2-1. ESTIMATED COMPOSITIONS OF MEDIUM-BTU GASES
FROM LURGI GASIFIER
Low Sulfur Coal Feed
Composition, Vol. %
CO 2
CO
ciu
H2
H20
N2
H2S
COS , ppmv
NH3
HCN
Tars and Oils,
kg/m3 «§ 43° C, 1 atm)
HHV, MJ/m3
Raw Gas
16.91
12.12
7.32
19.83
42.66
0.30
0.16
84
0.70
NA
0.023
6.57
Quenched Gas
29.74
21.32
12.88
34.88
0.37
0.53
0.28
150
tr
tr
0.004
11.6
High Sulfur Coal Feed
Raw Gas
12.91
6.95
4.06
15.51
58.94
0.59
0.534
90
0.49
NA
0.012
4.21
Quenched Gas
31.72
17.08
9.98
38.11
0.37
1.45
1.31
220
tr
tr
0.005
10.4
NA - Probably present, but data not available.
tr - Trace.
3-24
-------
Entrained particulates and tars/oils in the raw medium-Btu gases
produced by the Lurgi gasifier are removed by the quench/cooling steps
shown in Figure 3.2-1. The gas is first quenched in a direct contact
scrubber and then further cooled in a series of indirect coolers. The gas
exiting the last cooler is essentially free of tars, oils, NHa, HCN and
entrained particulates (Ref. 3-4, 3-16), but still contains some light
hydrocarbons (Ce - Cg).
3.2.2 Comparison and Selection of "Best Candidate" Acid Gas Removal Processes
The candidate acid gas removal processes for medium-Btu gasification
systems are the same as those for low-Btu systems. Information on the
candidate processes was presented in Tables 3.1-5, 3.1-6, and 3.1-7.
Comparisons of those processes with respect to their use in a pressurized
medium-Btu gasification facility are summarized in the following text. The
results of the comparisons are the selection of the Stretford and Rectisol
processes as the "best candidate" AGR processes for further study.
As described earlier in Section 3.1.2, all of the candidate processes
are commercially available and proven or technically feasible for use in
coal gasification facilities. In addition, since the gas from a Lurgi
gasifier is at a relatively high pressure (^2.4 MPa), all fourteen candidate
AGR processes can provide adequate removal of sulfur species.
With respect to environmental considerations, all of the candidate
processes produce a small solvent blowdown stream which must be treated
before being disposed of. All of the processes, except the Stretford, also
produce an acid gas stream which must be sent to a separate sulfur recovery
process. As discussed previously, the fact that the Stretford process not
only removes sulfur species but also recovers the sulfur value, is a
significant economic advantage over the other candidate AGR processes which
require a separate sulfur recovery process.
3-25
-------
••cycle
Quench
Liquor
Raw Product
Gas from
Caslfier
Wash
Cooler
L—J-
OJ
to
Waste
Heat
Boiler
Indirect Coolers
CW
BFW
CW
Partlculates,
Tars, Oils,
Liquors to
further pro-
cessing
Figure 3.2-1. Lurgi quench/cooling steps.
-------
Data on capital investment requirements for the candidate AGR processes
are limited. The cost information that is available cannot be compared
since it is not on a common basis. However, as mentioned above and in
Section 3.1.2, the Stratford process appears to be the lowest cost option
because it doesn't require a separate sulfur recovery process.
Specific data on utility requirements are not available on a common
basis. However, some general comments can be made regarding regeneration
steam requirements. The physical solvent processes use depressurization
of the rich solvent to release a major portion of the absorbed acid gases.
Thus, high inlet C02 concentrations and high COz removals do not signifi-
cantly increase the regeneration steam requirements. On the other hand, the
regeneration steam requirements for the chemical solvent processes are
directly related to the quantities of acid gases (COz + HzS) removed. This
is a significant disadvantage for the chemical solvent processes since the
two medium-Btu gases that will be treated have high COz concentrations
(MO percent). The combination physical/chemical solvent processes also
suffer from increased regeneration steam requirements as the COz content of
the gas increases. However, since the Stretford process does not remove
, it is not affected by high inlet COz concentrations.
Based on the above discussion, the Stretford and the physical solvent
processes are the potential choices for "best candidate" AGR process. As
stated at the beginning of this section, the processes finally selected were
the Stretford and the Rectisol. The Stretford was selected because it has
significant cost advantages. The Rectisol process was selected because
1) it is representative of the chemical solvent processes, 2) it is the only
physical solvent process which has had commercial application in gasification
plants, and 3) data are available to assess its cost, energy, and environ-
mental impacts.
3-27
-------
3.2.3 Summary of "Best Candidate" Medium-Btu Gasification Systems
The "best candidate" medium-Btu gasification systems selected for
detailed analysis in Sections 4, 5, and 6 are the Lurgi gasifier with either
the Stretford or Rectisol acid gas removal process. For this study, these
facilities are assumed to be at an off-site location with pipeline transmis-
sion of the medium-Btu gas to the boiler. To avoid pipe corrosion problems
(Ref. 3-30), the H2S content of the fuel gas must be below 10 ppmv. While
no information could be found on the maximum permissible level of COS, the
Rectisol process normally effects complete removal of COS concurrently with
H2S removal. However, the Stretford process does not remove COS. Based on
these sulfur removal levels, the estimated emissions of S02 from combusting
the four medium-Btu gases would be as follows:
Low sulfur coal with Rectisol - 2 ng S02/J
(0.005 lb/106 Btu)
Low sulfur coal with Stretford - 40 ng S02/J
(0.09 lb/106 Btu)
High sulfur coal with Rectisol - 2 ng S02/J
(0.005 lb/106 Btu)
High sulfur coal with Stretford - 60 ng S02/J
(0.14 lb/106 Btu)
The first three cases are below the stringent target S02 emission control
level of 43 ng S02/J (0.1 lb/10s Btu), while the last case is below the
intermediate level of 86 ng S02/J (0.2 lb/106 Btu).
NOX emissions from combustion of any of the four medium-Btu gases should
be similar to those from natural gas combustion (Ref. 3-20). The EPA
emission factor for natural gas (Ref. 3-29) is 50-100 ng/J (0.12-0.23 lb/
106 Btu), which is comparable to the target NOX control level of 86 ng/J
(0.2 lb/106 Btu). Particulate emissions should be negligible since all
particulates are removed from the gas during the purification operation.
3-28
-------
3.3 SELECTION OF "BEST CANDIDATE" COAL LIQUEFACTION SYSTEMS
As discussed in Section 2, of the coal liquefaction processes being
developed, the hydrogenation-type processes have gained in importance in
view of the higher conversion efficiencies and lower costs that have been
projected by the process developers and various other organizations. The
SRC-I, SRC-II, H-Coal, and EDS are hydrogenation-type systems and are the
candidate coal liquefaction systems considered in this study.
•
Solvent Refined Coal (SRC-I) System—The SRC-I system is being developed
to convert high-sulfur, high-ash coals to lower-sulfur, low-ash solid fuel.
(SRC-II, a variation of the SRC-I system, produces lower-sulfur and low-ash
liquid fuels from coal.) Figure 3.3-1 is a schematic of the system. The
coal is first pulverized and mixed with a coal-derived solvent in a slurry
mix tank. The slurry is combined with hydrogen and is then pumped through
a fired preheater and passed into a dissolver. In this unit, the coal is
hydrogenated and thereby depolymerized, leading to an overall decrease in
product molecular weight and dissolution of the coal. The solvent is also
hydrocracked in the dissolver unit yielding lower molecular weight hydro-
carbons ranging from light oil to methane. Another reaction occurring in
the dissolver is the hydrogenation of the organic sulfur in the coal which
produces hydrogen sulfide.
From the dissolver, the mixture passes to a separator where the gases
are separated from the slurry of dissolved solids and coal liquids. The
raw gas is sent to a hydrogen recovery and gas desulfurization unit. The
recovered hydrogen is then recycled and combined with the slurry coming from
the slurry mix tank. Hydrocarbon gases are released and recovered and the
hydrogen sulfide is converted to elemental sulfur.
The slurry of undissolved solids and the dissolved coal solution is
then separated in a filtration unit. In a commercial-scale system, the
solids would be sent to a gasifier-converter where they would react with
3-29
-------
RECYCLE HYDROGEN
SLURRY MIX TANK
COAL
COAL
LO
o
GASIFIER
AND SHIFT
CONVERTER
STEAM
OXYGEN
ASH
SOLVENT
RECOVERY
UNIT
LIQUID FUEL
SOLIDIFICATION
HYDROGEN
RECOVERY
AND GAS
DESULFUR-
IZATION
SULFUR
SLURRY
FILTER
HYDROCARBON
GAS
Figure 3.3-1. Solvent Refined Coal (SRC-I) system.
-------
supplemental coal, steam, and oxygen to produce hydrogen for use in the
system. To date, such capability has not been demonstrated on a commercial
scale. The coal solution passes to the solvent recovery unit where the
solvent is separated from the final liquid product, solvent refined coal.
Solvent refined coal (SRC-I) has a solidification point of 175°C to 205°C
and a heating value of approximately 37 MJ/kg.
H-Coal System—A schematic of the system is provided in Figure 3.3-2.
Coal is crushed to less than 250 ym, dried, slurried with recycled oil, and
then pressurized. .Compressed hydrogen is added to the slurry and the mixture
is preheated and charged continuously to the bottom of the ebullated-bed
catalytic reactor. The upward passage of internally recycled reaction
mixture keeps the catalyst in a fluidized state. Catalyst activity is
maintained by the periodic addition of fresh catalyst and the withdrawal
of spend catalyst. The temperature of the ebullated-bed catalytic reactor
is controlled by adjusting the preheater outlet temperature.
Vapor product leaving the top of the reactor is cooled to separate the
heavier components as a liquid. Light hydrocarbons, ammonia, and hydrogen
sulfide are absorbed from the gas stream and sent to a separator and a sul-
fur recovery unit. The remaining hydrogen-rich gas is recompressed and com-
bined with the input slurry. The liquid from the condenser is fed to an
atmospheric distillation unit to separate it into two streams. The overhead
light distillate is refined into useful products. The heavy underflow from
the still is used as recycled solvent for slurrying feed coal. The liquid-
solid product from the reactor, containing unconverted coal, mineral matter,
and oil, is fed into a flash separator. The flashed off material is passed
to the atmospheric distillation unit which yields light and heavy distillate
products. The bottoms product from the flash separator (solids and heavy
oil) is further separated with a hydrocyclone, a liquid-solid separator, and
by vacuum distillation.
The gas and liquid products, composed of hydrogen gases, hydrogen sul-
fide, ammonia, light oil distillate, heavy oil distillate, and residual fuel
3-31
-------
HYDROGEN -
HTMOGEN
HYDROCARBON GAS
HYDROGEN SULFIDC
AND AMMONIA TO
SEPARATION AND
SULFUR RECOVERY
LIGHT
DISTILLATE
TO
FURTHER
REFINING
U>
U)
NJ
COAL-
EBULLATED-BED
CATALYTIC
REACTOR
UNREACTED
CARBON +
MINERAL
MATTER *
LIQUID
TO
HYDROGEN
MANUFACTURE
HEAVY
DISTILLATE
TO FURTHER
REFINING
RESIDUAL
FUEL
Figure 3.3-2. H-Coal system.
-------
oil, may be further refined as necessary. A portion of the heavy distillate
is recycled as the slurry medium. The stream containing the unreacted car-
bon and some liquid eventually will be processed in a commercial installation
to produce additional hydrogen needed for the process.
Exxon Donor Solvent (EDS) System—A schematic of the system is provided
in Figure 3.3-3. The coal is dried and ground to less than 500 ptm and mixed
with recycled solvent to form a slurry. Hydrogen is normally preheated
separately and combined with preheated slurry at the reactor inlet. An
alternate mode of operation combines the hydrogen with the slurry before
preheating.
After liquefaction, the product is sent to the first stage of separa-
tion. Water is removed, hydrogen is recycled, and raw liquid products are
sent to the vacuum separation section. The raw liquid product contains
unreacted carbon and mineral matter.
The primary vacuum flash tower removes the mineral matter, unreacted
coal, and other fractions with boiling points above 540°C (bottoms). The
overhead from the first tower is sent to the secondary vacuum tower, to
separate heavy oil from the light oil as the overhead. This overhead from
the secondary vacuum flash tower is then combined with the lighter liquid
stream recovered from the liquefaction reactor separator system and fed to
the solvent hydrotreating section, consisting of fixed-bed catalytic
reactors. The solvent and naphtha from the solvent hydrotreating section
are then separated by fractionation. Most of the solvent is recycled to the
slurry vessel. Hydrogen, after undergoing acid gas removal, is also
returned to the slurry vessel.
3.3.1 Comparison of the Candidate Coal Liquefaction Systems
The four candidate coal liquefaction systems are compared in Table
3.3-1 with respect to the selection criteria described at the beginning of
3-33
-------
eo
CO
RECYCLE HYDROGEN
SLURRY
PREPARATION
HYDROTREATING
—-\ I 1
I
WATER
SOLVENT
FRACTIONATION
MAKEUP
HYDROGEN
- TO ACID
GAS
REMOVAL
BOTTOMS
SEPARATION
RECYCLE SOLVENT
GAS
NAPHTHA
MIDDLE
DISTILLATE
. HEAVY
DISTILLATE
EXCESS
'SOLVENT
Figure 3.3-3. Exxon Donor Solvent (EDS) system.
-------
TABLE 3.3-1. CANDIDATE COAL LIQUEFACTION SYSTEMS
Characteristics
SRC-I
SRC-II
H-Coal
Exxon Donor Solvent (EOS)
Status of Development
to
U>
Operational and
Maintenance Requirements
Applicability
Environmental Impacts*
1700 kg/hr pilot plant
operating, Ft. Lewis, WA
210 kg/hr pilot plant,
Ullsonvllle. AL
Solids accumulation
control In the
dlsaolver on western
coals
Solids-liquid separa-
tion (filtration)
equipment
Slurry pumps
Solid fuel produced can
only be used in
pulverized coal boiler
Control of sulfur release
by sulfur recovery pro-
cess followed by tall-
gas unit
Farticulate control from
coal preparation
Wastewater treatment to
reduce organic and in-
organic constituents In
waste streams
1700 kg/hr pilot plant
operating, Ft. lewis, UA
210 metric ton/hr demon-
stration plant planned,
West Virginia
Solids accumulation
control in the dlssolver
on western coals
Vacuum distillation column
Slurry pumps
Liquid fuel can be used
in conventional fuel oil-
fired boiler
Control of sulfur release
by sulfur recovery process
process followed by tall-
gas unit
Particulate control from
coal preparation
Wastewater treatment to
reduce organic and in-
organic constituents in
waste streams
100 kg/hr PDU operating,
Trenton, NJ
20 metric ton/hr pilot
plant under construction,
Cattlesburg, KT. Start-up
In early 1979
Ebullated bed reactor
Circulating slurry pumps
Liquid fuel can be used
in conventional fuel oil-
fired boiler
Control of sulfur release
by sulfur recovery
process followed by tall-
gas unit
Farticulate control from
coal preparation
Wastewater treatment to
reduce organic and in-
organic constituents In
waste streams
0.9 and 2.4 kg/hr bench
scale units and 34 kg/hr
pilot plant operating,
Baytown, TX
8.6 metric ton/hr under
construction, Baytown, TX
Operation in 1980
Circulating slurry pumps
Flexlcoking
Liquid fuel can be used
conventional fuel oil-
fired boiler
Control of sulfur re-
lease by sulfur recovery
process followed by tall-
gas unit
Farticulate control from
coal preparation
Wastewater treatment to
reduce organic and In-
organic constituents in
waste streams
Financial Impact
(capital cost of the
liquefaction plant is
prorated to the boiler
size)
Energy Impact**
• Disposal of solid wastes •
Capital cost may be as
high as SO percent of
the companion utility
boiler plant.
Thermal efficiency -
60-75%
Disposal of solid wastes
Capital cost may be as
high as 60-75 percent of
the companion utility
boiler plant.
Thermal efficiency *
60-75X
• Disposal of solid wastes
Capital cost may be as
high as 60-75 percent of
the companion utility
boiler plant.
Thermal efficiency "
60-751
• Disposal of solid
wastes
Capital cost may be as
high as 60-75 percent of
the companion utility
boiler plant.
Thermal efficiency •
60-75*
*See Table 3.3-3, 3.3-4, and 3.3-5.
**Thermal Efficiency is defined as the energy content of all useful products expressed as a percentage of the energy content of the feed coal.
-------
this section. The information contained in this table is summarized in the
following text.
The SRC-I, SRC-II, H-Coal, and EDS systems are in an advanced stage
of development; however, there are a number of factors such as scale-up
difficulties, feedstock flexibility, product utilization, reactor complexity,
and cost which are still not well defined on a common basis for these four
systems.
Considerable background is available from liquefaction process research
programs as to performance of various bench and process development units.
The results have shown that yields, hydrogen consumption, and product
quality can be duplicated in equipment with a significant range in capacity.
Testing of large size pilot plants will further confirm scale-up parameters
beyond the smaller size reactor systems that have already been tested.
Pilot plants using larger reactor and commercial components and equipment
will resolve a number of general issues, in addition to scale-up parameters,
that relate to mechanical equipment and process integration. These issues
are considered to represent major technical problems to be solved prior to
construction of commercial plants.
The various hydrogenation-type coal liquefaction processes use common
components and subsystems. Design bases for these components are to be
obtained from their use in the larger pilot plants during 1979-1980. A
list of subsystems and components required for hydrogenation processes
that need further engineering development is given in Table 3.3-2 (Ref.
3-30).
The SRC-II, H-Coal, and EDS systems produce fuel oil-type liquid
products that can be used in conventional fuel oil-fired boilers. However,
the SRC-I process produces a solid fuel similar to low-sulfur coal except
for its low melting point (175°C to 205°C). Because of this, SRC-I is
not suitable for use as a fuel in stoker-type boilers. SRC-I is suitable
3-36
-------
TABLE 3.3-2.
HYDROGENATION SUBSYSTEMS AND COMPONENTS
REQUIRING ENGINEERING DEVELOPMENT
Unit Operation
Issues
Slurry mixing and pumping
Slurry preheating
Hydrogenation
Product heat exchange
Pressure letdown
Materials of construction
of system units
Fractionation
Hydrogen or fuel gas
generation, using pitch
containing ash
Operating procedures
Erosion and operation of multiple
reciprocating pumps
Design configuration, gel formation, heat
transfer, pressure drop, coking of tubes
Contacting of coal, solvent, hydrogen
exothermic reactions
Fouling of heat exchange surfaces, erosive
action of solids
Valve life, testing of valves for service
Long-term durability questionable for
service due to corrosion, erosion,
embrittlement, and chemical effects
Design of vacuum-still transfer lines,
heated pumps, solids carryover, transport
of streams with high solids concentration
at high temperatures
Feasibility of using gasification or
flexicoking for generating hydrogen or fuel
gas from vacuum-still bottoms
Solids withdrawal, startup, emergency
shutdown, recovery, and other factors
Source: Ref. 3-30
3-37
-------
though for use in a conventional pulverized coal boiler if certain
modifications are made (see discussion in Section 2.3.3.1). When commer-
cialized, coal liquefaction systems will be large facilities producing daily
the energy equivalent of about 1000 gigajoules of synthetic fuels. This is
much more energy than is needed by a single industrial boiler. Therefore,
a coal liquefaction plant will only be associated with an industrial boiler
as an off-site fuel source transporting a portion of its product to the
industrial boiler.
All hydrogenation processes will produce gaseous, liquid and solid
waste streams. Tables 3.3-3 through 3.3-5 summarize the sources and
characteristics of those streams. The amount and concentration of various
compounds present in those wastes will depend on coal characteristics,
operating conditions, and hydrogen consumption.
The hydrogen sulfide in the gaseous emissions is removed by an acid
gas removal process followed by a sulfur recovery process. Ammonia, formed
from coal nitrogen during the hydrogenation reaction step, is removed from
the process wastewater by steam stripping.
Phenols in the liquid effluents may be recovered from process wastewater
by extraction if their recovery and by-product value is significant. If
present in low concentrations they may be treated by biological oxidation
treatment. Auxiliary facilities such as raw and boiler water treatment,
cooling tower, and coal and product storage generate wastewater effluents
and can be treated by conventional methods. Tables 3.3-3, 3.3-4, and 3.3-5
show sources and characteristics of air emission, wastewater streams, and
solid waste discharges. Applicability of pollution control methods and
equipment will be confirmed by the operation of large-scale pilot and
demonstration plants.
For the production of lower sulfur and nitrogen fuels, an additional
hydrotreating step may be necessary. More hydrogen sulfide and ammonia is
3-38
-------
TABLE 3.3-3. SOURCES AND CHARACTERISTICS OF AIR EMISSIONS
Module
Source
Emission Characteristic
Coal preparation
Hydrogenation
Pyrolysis and hydro-
carbonization
Hydrotreating
Catalytic synthesis
Extraction
Phase separation
Fractionation
Gas cleaning module
Synthesis gas/hydrogen
generation
Auxiliary systems and
utilities
Grinding, pulver-
izing and drying
Preheater flue gas
Particulates, hydrocarbon
vapors
COX, NOX, H2S, NH3,
hydrocarbons
Preheater flue gas COX, NOX, SOX, hydrocarbons
Preheater flue gas
Catalyst removal
and replacement
Heater flue gas
None
Flash drum vapors
Uncondensed gases
from condenser
C02 gas stream
Synthesis gas
Driers flue gas
Cooling tower drift
Boiler combustion
gases
, NOX, SOx, hydrocarbons,
particulates, NHs, H2S
COX, NOX, SOX, hydrocarbons
None
Hydrocarbons, H2S, NH3, C02
H2S, C02
C02, H2S, hydrocarbons
C02, hydrocarbons, SOX, COX
NOX, hydrocarbons
Biocides, anticorrosive
agents, solids, NOX, COX,
SOX, hydrocarbons, fly ash
Source: Ref. 3-31
3-39
-------
TABLE 3.3-4. SOURCES AND CHARACTERISTICS OF WASTEWATER STREAMS
Module
Source Description
Wastewater Strea
Constituents
Coal preparation
Hydrogenatlon
Pyrolysls and
hydroc.irbonlzatlon
Hydrotreating
Synthesis gas
generation
Catalytic synthesis
Phase separation
Coal storage piles, crushing and
grinding operations
Cooling and quenching operation
Cooling and quenching operation
Condensing overhead vapors
Cooling and quenching operation
Shifting operation
Condensing overhead vapors
Two or three stage pressure
reduction
Storm water runoff
Foul water from
quench
Foul water from
quench
Condensate
Foul water from
quench
Condensed unreacted
water
Condensate
Condensate from
overhead condenser
U)
-o
0
Fractional Ion
Gas cleaning
Hydrogen generation
Supercritical gas
extraction
Auxiliary systems
and utilities
Cooling overhead vapors
Absorption and regeneration
operations
Cooling and quenching
operation
Shifting operation
Char quenching operation
Cooling towers and boiler
Plant yard area
Condensate
Purge flows
Foul water from
quench
Condensed unreacted
water
Foul water from
quench
Slowdown
Storm water runoff
Suspended particles, dissolved solids
Phenols, tars, ammonia, thiocyanates,
sulfldes and chlorides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, ammonia, si'lfidos
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, aomonla, sulftdes
Oils, light hydrocarbons, phenols,
ammonia, dissolved sulfides
Light hydrocarbons, dissolved salts
Dissolved sulfides in gas removal
solvent
Phenols, tars, ammonia, thiocyanates,
sulfides, and chlorides
Phenols, tars, ammonia, thiocyanates,
sulfides and chlorides
Phenols, tars, ammonia, thiocynnates,
sulfides and chlorides
Dissolved salts
Suspended particles, dissolved solids,
traces of phenols, oil and tars
Sourre: Ref. 3-31
-------
TABLE 3.3-5. MODULAR SOLID WASTE DISCHARGES
u>
,n Solid waste
a
O u M
u n u
0) rH 4J
0 2 R
rH M OC
3 U « nH
U «-< CD
•H 4-t Up
Module
Coal preparation
Hydrogenation
Pyroly sis/hydrocarbon izat ion
llydrotreatlng
Synthesis gas generation
Catalytic synthesis
*J C ~~- 01
t, S JC C
CO O. 01 -rl
0. W < 6
+ 00
0 + 0
+ 0 +
0 + 0
+ + +
0 + 0
a
u
0
0
+
0
+
0
3 l-i
M-i O
—< 10
3 -a
VI ft
U T3
(V CQ
a 3
en MI
0
0
0
0
0
+
u
•H 1
N TJ
— ' «H
tM
*J t-l
C 3
a> v>
Spent
Spent
Spent
Remarks
catalyst not continuously goneratod
catalyst particles in gas or liquid stream
catalyst not continuously generated
+ 0 + +
+ 0 + +
0000
Extraction (supercritical
gas extraction)
Phase separations
Fractionation
Gas cleaning (acid gas
removal)
Hydrogen generation
Auxiliary systems utilities
-I- denotes waste stream is generated in module.
0 denotes waste stream is not generated in module.
Source: Ref. 3-31
0
0
Small amounts of unreacted char/oil may I)
present
Solids from donor solvent processes only
Some systems use sulfur guard absorbents
Particulnte product losses during handling,
ash and participates from coal/clmr burning
hollers
-------
thereby generated from the process. While this may be an additional
environmental impact at the liquefaction plant site, combustion of the
hydrotreated liquid fuels will result in reduced environmental impact at the
combustion site.
Cost data for the candidate liquefaction processes are not extensive due
to the developing nature of these processes. However, for the SRC-II, EDS,
and H-Coal systems capital costs have been estimated at 60-75 percent of the
cost of a utility boiler using the liquefied coal products (Ref. 3-30, 3-32).
The capital cost of an SRC-I plant is estimated at 50 percent of the asso-
ciated boiler, but the cost of this boiler may only be 75 percent of the
cost of an equivalent conventional coal-fired boiler (Ref. 3-33, 3-34).
Estimates of the thermal efficiency of coal liquefaction plants
(defined as product energy content divided by coal feed energy content) are
in the 60-75 percent range (Ref. 3-32, 3-35, 3-36). The actual efficiency
will depend on factors such as coal characteristics, degree of processing,
and environmental requirements.
3.3.2 Selection of "Best Candidate" Coal Liquefaction Systems
Based on the information presented in Section 3.3.1, the SRC-I and
EDS systems were selected as the "best candidates" for detailed cost, energy,
and environmental analyses. The SRC-I system was chosen because it is the
most developed and potentially the most economical of the candidate systems.
However, a disadvantage of the SRC-I system which may restrict its use is
its inability to produce a very low sulfur fuel from a high sulfur coal
feedstock.
The other three liquefaction processes are very similar with respect
to status of development, environmental impacts, costs, and energy conversion
efficiency. The EDS system was selected because it is representative of the
three systems and the results of analyzing the EDS system should also apply
to the SRC-II and H-Coal systems.
3-42
-------
The sulfur, nitrogen and ash contents and higher heating value of the
fuels produced by the SRC-I and EDS systems are shown in Table 3.3-6. Also
shown on this table are the estimated emissions of S02, and particulates
resulting from combustion of those fuels. These emission values were
calculated from EPA emission factors (Ref. 3-29) for the combustion of fuel
oil and bituminous coal (except for the SRC-I 862 value which is based on
complete conversion of the fuel sulfur to SOa). The particulate emissions
for SRC-I assume that a particulate control device with at least an 80
percent removal efficiency is applied to the combustion gases. Values for
NOX are shown in parentheses on Table 3.3-6. These are based on EPA
emissions factors (Ref. 3-29) which may not be valid for coal derived fuels.
The emission control levels selected for combustion of coal liquefaction
fuels are shown below:
Moderate Intermediate Stringent
Level Level Level
S02, ng/J 520 260 86
NOx, ng (as N02)/J 300 220 86
Particulates, ng/J 13 13 13
In selecting liquefaction processes to meet these emission targets, control
of NOX emissions is not considered. This is because NOX emissions cannot be
estimated "a priori" for coal derived fuels and there is insufficient data
available to generalize NOX emissions from the combustion of these fuels.
The low sulfur coal derived SRC-I and EDS fuels can meet all three
target SOa and particulate emission levels. The high sulfur coal derived
SRC-I fuel can meet all the particulate control levels, but can only meet
the moderate S02 emission level. The high sulfur coal derived EDS fuel can
meet all three target emission levels, but for the stringent level, hydro-
processing is required to reduce the fuel sulfur content to 0.2 percent.
3-43
-------
TABLE 3.3-6. FUEL COMPOSITION AND COMBUSTION EMISSIONS FOR LIQUEFACTION FUELS
U)
SRC-I
Fuel Composition
%C
d
% N
% Ash
HHV
Emissions
S02, ng/J
NOx, ng N03/J
Particulates, ng/J
Low Sulfur
Coal
0.1
1.3
0.2
36.2 MJ/kg
55
(248)
13
Hi£h Sulfur
Coal
0.8
1.7
0.3
36.6 MJ/kg
440
(248)
13
Low Sulfur
Coal
0.2
0.2
-
41.4 GJ/m3
83
(115)
6
EDS
High Sulfur Coal
Raw
0.3
0.2
-
41.4
125
(115)
6
Hydr op recessed
0.2
0.2
-
41.4
83
(115)
6
* Assumes 80% efficient particulate control device on flue gas.
Numbers in parenthesis are merely estimates based on EPA emissions factors (Ref. 3-29). Actual
emissions are not known.
-------
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-------
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-------
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(Jefferson Chemical Co.) concerning performance of DGA Acid Gas Removal
Process. July 18, 1978.
3-28. Telephone communication between P.J. Murin (Radian Corp.) and Paul
Sigmund (Union Carbide) concerning performance of amine acid gas re-
moval processes. June 5, 1978.
3-29. Environmental Protection Agency. Compilation of Air Pollutant Emission
Factors, 2nd ed., with supplements. AP-42. Research Triangle Park,
NC, Feb. 1972, April 1973, July 1973, Sept. 1973, July 1974, Jan. 1975,
Dec. 1975, Feb. 1976, April 1977.
3-30. Spencer, D.V., S.B. Alpert and R.H. Wolk. Review of Alternative
Liquefaction Processes. EPRI: Electric Power Research Institute,
Palo Alto, California. 1978.
3-31. Hittman Associates, Inc. Environmental Assessment Data Base for Coal
Liquefaction Technology, Vol. I & II, Final Report. EPA-600/7-78-184a
& b, EPA Contract No. 68-02-2162. Columbia, MD. September 1978.
3-32. Fant, B.T. Exxon Donor Solvent Coal Liquefaction Commercial Plant
Study Design. Prepared for U.S. Energy Research and Development Admin-
istration by Exxon Research and Engineering Company: Florham, NJ.
January.
3-33. Spencer, Dwain and Oliver Gildersleeve. Market Potential for New Coal
Technologies. EPRI Journal, 3(4) 1978.
3-34. Alpert, S.B., et al. Review of Solvent-Refined Coal Technology. Elec-
tric Power Research Institute. Palo Alto, CA. March 1978.
3-35. Schmid, B.K. and D.M. Jackson. Recycle SRC Processing for Liquid and
Solid Fuels. In: Paper presented at the Fourth Annual International
Conference on Coal Gasification, Liquefaction and Conversion to Elec-
tricity. August 2-4, 1977. Pittsburgh, PA.
3-47
-------
3-36. "H-Coal Commercial Evaluation Case 1: Fuel Oil Made for 25,000 TPD
H-Coal Liquefaction Plant". Fluor Engineers and Constructors, Inc.
Prepared for ERDA. March 1976.
3-48
-------
SECTION IV
COST ANALYSIS OF SYNTHETIC FUELS FROM COAL SYSTEMS
Synthetic fuels from coal systems considered to be the "best candidates"
as emission control techniques for industrial boilers were selected in Sec-
tion III. Presented in this section are the results of cost analyses of those
systems. In developing the cost analyses, boilers with four heat input rates
were considered: 8.8, 22, 44, and 58.6 MW * (30, 75, 150 and 200 x 106 Btu/hr)
A limited number of cases using low-Btu gas in a 117 MW (400 x 106 Btu/hr)
boiler were also examined. These boiler sizes correspond to the coal-fired
standard boiler sizes being examined in other technology assessment reports
being prepared as part of the EPA's Industrial Boiler Program. Therefore,
synthetic fuels from coal technologies can be compared to other control tech-
niques for coal-fired industrial boilers. All costs in this report are ex-
pressed in terms of mid-1978 dollars.
Synthetic fuels from coal systems are precombustion emission control
techniques for industrial boilers, i.e., they supply a "clean" boiler fuel.
As such, the approach used for the cost analyses was:
• First develop costs for producing the synthetic fuels,
*Since Standard International units are being used in this report, megawatts
and kilowatts are used to denote both boiler capacity (thermal heat input)
and electrical requirements. To minimize potential confusion, MW and MW
will be used to distinguish between megawatts (thermal) and megawatts (elec-
trical), respectively. As an example, a boiler with a heat input capacity
of 30 x 106 Btu/hr will have an 8.8 MW heat input capacity.
4-1
-------
Then incorporate these fuel costs into the cost analyses
of the synthetic fuel-fired boilers, and
Finally compare the synfuel-fired boiler costs to coal-
fired boiler costs.
The medium-Btu coal gasification and coal liquefaction systems examined
are large capacity, off-site production facilities. They are also complex
and expensive installations. As such, it was beyond the scope of this study
to perform detailed cost analyses of these systems. Instead, costs were
obtained from design studies available in the open literature and adjusted,
as appropriate, to reflect differences between the design study bases and
the bases used in this study.
For the low-Btu gasification systems, costs for the most expensive
equipment items or processing units were obtained from process vendors. Costs
for typical and less expensive equipment were estimated from cost correlations
such as those presented by Guthrie (Ref. 4-1) and Peters and Timmerhaus
(Ref. 4-2).
Capital requirements for the synfuel-fired boilers were based on infor-
mation developed by PEDCo for the EPA Industrial Boiler Program (Ref. 4-3, 4-4)
The basis for the SRC-I-fired boiler and EDS liquids-fired boilers were PEDCo's
58.6 MWT (200 x 106 Btu/hr) pulverized coal and 44 MWT (150 x 106 Btu/hr)
residual fuel oil boilers respectively. The capital requirement for low and
medium Btu gas-fired boilers should be similar to those for natural gas-fired
boilers of comparable sizes. Capital requirements for gas-fired boilers were
obtained from PEDCo (Ref. 4-4).
A general discussion of the various components which are included in the
cost analyses are presented in Section 4.1. Also presented are the common
key assumptions and cost bases used. The results of the cost analyses, as-
sumptions and bases specific to each synfuel technology, and a discussion
of significant findings are presented in Sections 4.2 through 4.4 Section
4.2 addresses low-Btu gasification, while medium-Btu gasification is addressed
4-2
-------
in Section 4.3 and coal liquefaction in Section 4.4. Section 4.5 provides an
overall summary of the synfuel economics.
4.1 CONTRIBUTORS TO CONTROL COSTS AND COST BASES
Capital requirements and operating costs for the gasification and lique-
faction systems are presented in this section. Additionally, the capital
requirements are atmualized so that a synfuel cost (in $/GJ or $/106 Btu) can
be calculated. Finally the annualized costs of firing the synfuels in new
industrial boilers are developed so that comparisons to the costs for direct
firing of coal can be made. The bases for the economic evaluation are pre-
sented below.
4.1.1 Capital Requirement
The capital requirement for each synfuel system is presented with the
following components identified:
• Installed equipment costs (for each major processing area)
Indirect costs
- Engineering costs
- Construction and field expenses
- Contractor's fee
- Startup and performance tests
• Allowance for funds used during construction
• Contingency
• Total turnkey costs (the sum of the items above)
• Working Capital
4-3
-------
• Land
Total capital requirement (the sum of all items listed above)
The installed equipment costs include the cost of all equipment (process
and auxiliary) as well as the cost of installation. Indirect capital costs
are those costs not attributable to any specific piece of equipment and in-
clude the items listed above. Generally, the indirect cost items are taken
as a percentage of the installed equipment costs. Specific percentages used
in this study are indicated on the cost summary sheets in Sections 4.2 through
4.4 and in Appendices A, B, and C.
If the construction period is long (>1 year), interest during construction
on the capital spent in the early stages of construction can become signifi-
cant. Since a large synfuel plant will require a 3-4 year construction peri-
od, allowances must be made for the capital tied up during construction.
The synfuel facilities described in this report have not been built and
integrated with gas-fired boilers on a commercial scale. Therefore, economics
cannot be compared with or based on an existing facility. A large contingency
is, therefore, justified for these systems. A 20% contingency was applied to
the uncontrolled coal-fired boiler capital investments by PEDCo (Ref. 4-3,
4-4) . It is recommended that a 30% contingency factor be applied to the
synthetic fuels system capital investment.
The total turnkey cost (TTC) is the sum of the installed equipment cost,
indirect costs, contingencies, and interest during construction. The TTC is
also the depreciable investment. Working capital (taken as 25% of total
direct operating costs - to be defined in Section 4.1.2) and land are capital
requirements but cannot be depreciated for tax purposes.
4.1.2 Operating Costs
The operating costs associated with the synfuels plants are broken out
as follows:
4-4
-------
Direct Operating Costs
- Utilities
-Steam
-Electricity
-Cooling water
-Process water
- Raw Materials
-Coal
-Water
-Catalysts and chemicals
- Operating Labor
- Maintenance
- Supervision
- By-product credits
-Sulfur
-Hydrocarbons
-Ammonia
- Waste disposal
Indirect Operating Costs
- Plant overhead
- Payroll overhead
Unit prices for the various operating cost components are shown in Table
4.1-1.
4.1.3 Annualized Costs
Annualized costs are the sum of direct operating costs, indirect
operating costs, and capital-related costs. Included in the capital-related
costs in this study 'are:
• Local taxes
• Insurance
4-5
-------
TABLE 4.1-1. VALUES USED FOR ANNUAL COST ITEMS
Q
Item Cost
Operating Labor, $/man-hour 12.02
Supervision, $/man-hour 15.63
Maintenance Labor, $/man-hour 14.63
Steam, $/GJ ($/106 Btu) 5.00 ( 5.28)
Electricity, mills/kW-hr 25.8
Purchased Water, $/m3 ($/103 gal) 0.032 ( 0.12)
Process Water, $/m3 ($/103 gal) 0.04 ( 0.15)
Cooling Water, $/m3 ($/103 gal) 0.05 ( 0.18)
Coal, $/metric ton ($/short ton)
High Sulfur Eastern 18.72b (17.00)
Low Sulfur Western 8.88 ( 8.06)
Plant and Payroll Overhead0
Waste disposal , $/metric ton ($/short ton)
Low Btu gasification facilities 44 (40)
Medium Btu gasification facilities 11 (10)
Coal liquefaction facilities 11 (10)
By-product credits See section 4.3
Mid-1978 dollars.
b
These coal costs are representative of minemouth costs for the Eastern and
Western coals. The effect of higher coal costs (considering assumed coal
transportation costs) will be explored in a sensitivity analysis for each
synfuel technology.
c
For this study, plant overhead was taken as 26 percent of the annual labor
and maintenance costs. Payroll overhead was taken as 30 percent of the
annual operating labor costs.
Large gasification and liquefaction facilities will take advantage of large,
on-site waste disposal systems and hence have lower solids disposal costs.
Source: Ref. 4-5
4-6
-------
• General and administrative (G&A) costs
• Capital recovery
• Interest of working capital
Local taxes, insurance, and G&A are taken as four percent of total turnkey
costs (TTC).
The capital recovery factor (CRF) used in this study is based on the
equal payment annuity formula:
i (1 + i)"
(1 + i)n-l
where i = annual interest rate
n = economic life of equipment, in years.
For the EPA's Industrial Boiler Program, all contractors are using a 10 per-
cent interest rate which will yield the following CRF's:
Economic Life, Years CRF
20 0.1175
25 0.1102
30 0.1061
45 0.1014
The CRF is applied only to the depreciable investment (Total Turnkey Costs) .
Interest on working capital is calculated using a 10% interest rate.
4.2 LOW-BTU COAL GASIFICATION
Annualized costs for industrial steam generation facilities using low-
Btu Wellman-Galusha gasifiers and low-Btu gas-fired boilers are summarized
in Table 4.2-1. These gasification/steam generation facilities are alterna-
tives to direct coal-fired boilers, and are effective in reducing flue gas
4-7
-------
TABLE 4.2-1.
COST ANALYSIS OF "BEST CANDIDATE" LOW-BTU COAL GASIFICATION
SYSTEMS FOR INDUSTRIAL BOILERS3
Boiler heat
input, MW
(10* Btu/hrJ
8.8 (30)
8.8 (30)
8.8 (30)
22 (75)
22 (75)
22 (75)
44 (150)
44 (150)
44 (150)
58.6 (200)
58.6 (200)
58.6 (200)
117.2 (400)
117-2 (400)
Coal feed
to gasifier
Low-sulfur
High-sulfur
High-sulfur
Low-sulfur
High-sulfur
High- sulfur
Low-sulfur
High- sulfur
High-sulfur
Low- sulfur
High-sulfur
High-sulfur
Low— sulfur
High- sulfur
Sulfur control
technique and
level of control
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
MEA/A11 Levels
Stretford/Stringent
Stretford/Moderate
SO 2 control
efficiency,
Z
94. 2C
94. 2d
94.2-98.2*
94. 2C
94. 2d
94.2-98.2*
94. 2C
94. 2d
94.2-98.2*
94. 2C
94.2d
94.2-98.2*
94. 2C
94. 2d
Annualized Low-Btu
Gas-Fired Boiler Costs
$10' /yr
2100
2320
2540
2890
3380
3870
4450
5340
6050
5320
6530
7350
9340
11,810
per unit of heat
input. $/kW
($/10* Btu/fir)
239 (70,000)
264 (77,200)
289 (84,700)
131 (38,500)
154 (45,100)
176 (51,600)
101 (29,700)
121 (35,600)
138 (40,300)
91 (26,600)
111 (32,700)
125 (36,800)
80 (23,400)
101 (29,700)
Z increase
in costs
over uncon-
trolled coal-
fired.boiler
costs
115
144
168
54
83
110
42
73
97
21
54
74
18
53
aWellman-€alusha gaaifier; mid-1978 dollars; 60Z annual operating factor
Low-Btu gas-fired costs were conpared to uncontrolled coal-fired boiler costs for systems using the same coal feed-
stock and having identical boiler heat inputs.
CS02 emission level is 30 ng/J (0.07 lb/106 Btu)
dSOa emission level IB 140 ng/J (0.32 lb/106 Btu)
*SOz ealsaion levels are 140-43 ng/J (0.32-0.10 lb/10c Btu)
All system* have estimated NO and particulate emissions as follows:
M0x—50-100 ng/J (0.12-0.23 lb/101 Btu)
particulate*—<4 ng/J (<0.01 lb/10* Btu)
-------
emissions of S02, NO , and particulates compared to the coal-fired systems.
Because the removal of sulfur species is the most important and expensive gas
purification operation, the costs summary and subsequent figures and tables
report costs as a function of the degree of control of sulfur species. How-
ever, use of low-Btu gas also results in nominally 100 percent control of
particulate emissions. This is because essentially all particulates are re-
moved from the low-Btu gas (grain loading of 0.01 g/m3 which is equivalent to
2 ng/J in the combustion flue gases) during the operations needed for the re-
moval of sulfur species. NO emissions are similar to NO emissions from the
X X
combustion of natural gas—50-100 ng NO (as N02)/J. Details on the emissions
resulting from low-Btu gasification/steam generation facilities are presented
in Section 6.1.
Section 4.2 is organized as follows:
4.2.1 Costs Summary and Analysis
4.2.2 Cost Bases
4.2.3 Cost Sensitivity Analysis
4.2.4 Confidence Intervals for Annualized Costs
4.2.1 Costs Summary and Analysis
As described in Chapter 3.1, two processes have been selected for the
removal of sulfur species from low-Btu fuel gas. These processes are the
Stretford process and the monoethanolamine (MEA) process. The Stretford
process features the direct conversion of H2S to elemental sulfur; organic
sulfur compounds are not removed (Ref. 4-6). The MEA process features the
absorption of both HaS and organic sulfur compounds, with subsequent treat-
ment of an acid gas product stream requisite. In this report, subsequent
treatment of the acid gas occurs in Glaus and SCOT units.
The annualized costs for low-Btu gasification/steam generation facilities
have been compared to the annualized costs for coal-fired boilers (without
emission controls) that have been prepared by PEDCo (Ref. 4-3). These cost
4-9
-------
comparisons were made for steam boilers having identical heat input (not steam
output). The percentage increase in annualized costs for the low-Btu systems
compared to coal-fired systems is summarized in the final column of Table
4.2-1. The largest percentage increase occurs in the smaller systems. The
annualized uncontrolled coal-fired boiler costs used for the comparisons are
listed in Table 4.2-2.
A breakdown of the cost components for all of the low-Btu gasification/
steam generation facilities studied is provided in Appendix A. Tables 4.2-3
through 4.2-5 are examples of one set of tables contained in Appendix A.
Table 4.2-3 summarizes the capital requirements of the gasification systems,
while annualized operating costs for the gasification systems (60 percent
operating factor) are summarized in Table 4.2-4, along with the estimated
product gas cost. Table 4.2-5 presents the total annualized operating costs
for the low-Btu gas-fired boilers burning the low-Btu gas with economics
developed in Tables 4.2-3 and 4.2-4.
In order to facilitate the evaluation of the control costs associated
with low-Btu gasification, several figures were prepared.
Figure 4.2-1 presents the annualized boiler costs, in $/kW ,
as a function of S02 emission level. As shown in the figure,
the costs for the MEA system do not vary discernibly with vary-
ing S02 control efficiency.
• Figure 4.2-2 presents the incremental costs of emissions control
(by low-Btu gasification) as a function of boiler size. Because
of greater economies of scale in the low-Btu gasification/steam
generation systems (versus the direct coal-fired steam generation
systems), large boiler systems have markedly lower unit control costs,
Figure 4.2-3 grafically illustrates the cost effectiveness (incre-
mental annualized costs per kg S02 controlled) of low-Btu gasifi-
cation/steam generation systems in controlling S02 emissions.
4-10
-------
TABLE 4.2-2. ANNUALIZED COST FOR UNCONTROLLED COAL-FIRED INDUSTRIAL BOILERS
Input Heat Rate,
MW (106 Btu/hr)
8.8
8.8
22
22
44
44
58.6
58.6
117.2
117.2
Mid-1978
(30)
(30)
(75)
(75)
(150)
(150)
(200)
(200)
(400)
(400)
dollars.
Assumptions: 1)
2)
Industrial Boiler
Type
Underfeed Stoker
Underfeed Stoker
Chain-Grate-Stoker
Chain-Grate-Stoker
Spreader Stoker
Spreader Stoker
Pulverized Coal
Pulverized Coal
Pulverized Coal
Pulverized Coal
Annualized Costs
Coal Feed
High Sulfur Eastern
Low Sulfur Western
High Sulfur Eastern
Low Sulfur Western
High Sulfur Eastern
Low Sulfur Western
High Sulfur Eastern
Low Sulfur Western
High Sulfur Eastern
Low Sulfur Western
$103/yr
952
977
1,851
1,866
3,075
3,121
4,248
4,369
7,784
7,930
60% annual operating factor
W% interest rate and the following equipment lifetimes were
»/»,
108
111
84
85
70
71
72
75
66
68
used to
($/106 Btu/hr)
(31,700)
(32,600)
(24,700)
(24,900)
(20,500)
(20,800)
(21,200)
(21,800)
(19,500)
(19,800)
annualize
capital requirements
• 8.8 MW - 30 years
• 22, 44, 58.6, and 117.2 MWT - 45 years
Source: Ref. 4-3
-------
TABLE 4.2-3.
I
t-«
to
CAPITAL INVESTMENT REQUIREMENTS FOR LOW-BTU
WELLMAN-GALUSHA GASIFICATION SYSTEMS
Coal Feedstock -
Acid Gas Removal
SO 2 Control Level
INSTALLED EQUIPMENT COSTS
Coal Receiving and Storage
Gasification System
Gas Purification System
Blower /Compressor
Quench/Cooling Towers
Pwps (for cooling liquor)
Electrostatic Precipitator
Separator /Evaporator
H2S Removal Unit
Sulfur Recovery Unit
Building and Ductwork Not Coated
In Above Equipment Costs
/£• f.f ori\
VOA OI Bl*/
Total Installed Equipment (EC)
INDIRECT INSTALLATION COSTS
Engineering (10Z of EC)
Construction and Field
Expense (10T of EC)
Construction Fees (10Z of EC)
Startup (2Z of EC)
Total Indirect Costs (1C)
CONTINGENCIES (30Z of EC + 1C)
TOTAL TURNKEY COSTS (TTC)
WORKING CAPITAL (25Z of Total Direct
Operating Costs)
TOTAL CAPITAL INVESTMENT
8.8(30)
370
500
60
50
30
120
120
1,330
-
160
2,740
270
270
270
50
860
1,080
4,680
170
4,850
Low Sulfur Western
Unit - Stretford
- Stringent
System Capacity, MWT (106Btu/hr)
22(75)
390
1,000
70
80
40
220
190
1,380
-
220
3,590
360
360
360
70
1,150
1.420
6,160
270
6,430^
44(150)
440
2,000
100
120
70
290
240
1,800
-
320
5,380
540
540
540
110
1,730
2.130
9,240
440
9,680
58.6(200)
600
2,500
120
140
90
370
250
1,970
-
390
6,430
640
640
640
130
2,050
2.540
11,020
560
11,580
117.2(400)
790
5,000
240
280
170
740
500
2,300
-
640
10,660
1,070
1,070
1,070
210
3,420
4.220
18,300
1,020
19,320
JO1 mid-1978 dollars.
-------
TABLE 4.2-4.
ANNUALIZED COSTS FOR LOW-BTU WELLMAN-GALUSHA
GASIFICATION SYSTEMS
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Stretford
S02 Control Level - Stringent
Operating Factor - 60%
System Capacity, MW (106 Btu/hr)
DIRECT OPERATING COSTS
Operating Labor (@ $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance (6% of Total
Turnkey Costs x 0.8)
Replacement Parts (included
in maintenance)
Electricity (@ 25.8 mills/kW-hr)
Steam «? $5.00/GJ)
Cooling Water (@ $0.05/m3)
Process Water (@ $0.04/m3)
Coal (@ $8.88/ton)
Chemicals
Sulfur, Ash Disposal
(@ $44.00/ton)
Total Direct Operating Costs
OVERHEAD COSTS
Payroll (30% of operating labor)
Plant (26% of labor, parts and
maintenance)
Total Overhead Costs
CAPITAL CHARGES
G&A, Local Taxes and
Insurance (4% of Total
Turnkey Costs)
Capital Recovery (11.75% of
Total Turnkey Costs)
Interest on Working Capital
(@ 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS
Average Gas Cost^ $/GJ
8.8(30)
210
70
220
-
20
10
10
-
90
20
30
680
60
130
190
190
550
20
760
1630
9.80
22(75)
260
70
300
-
40
30
30
-
220
50
90
1090
80
160
240
250
720
30
1000
2330
5.60
44(150)
320
70
440
-
80
60
60
-
440
110
170
1750
100
220'
320
370
1090
40
1500
3570
4.30
58.6(200)
370
70
530
-
110
80
80
-
600
150
230
2220
110
250
360
440
1290
60
1190
4370
> 3.95
117.2(400)
580
140
880
-
210
160
170
-
1190
300
460
4090
170
420
590
730
2150
100
2980
7660
3.45
103 Mid-1978 dollars
-------
TABLE 4.2-5.
ANNUALIZED COSTS FOR LOW-BTU GAS-FIRED
INDUSTRIAL BOILERS
M
J>
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Stretford
SOz Control Level - Stringent
Operating Factor. - 60%
System Capacity, MW (10s Btu/hr)
CAPITAL INVESTMENT, 10J $
Total Turnkey Costs (TTC)
Land
Working Capital (25% of Total
Direct Operating Costs,
excluding fuel costs)
Total Capital Requirement
OPERATING COSTS, 10J $/yr
Direct Costs
Operating Labor (@ $12.02/hr)
Supervision (9 $15.63/hr)
Maintenance Labor (@ $14.63/hr)
Replacement Parts
Electricity (@ 25.8 mills/kw-hr)
Process Water (@ $0.04/m')
Fuel
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30% of operating labor)
Plant (26% of labor and parts)
Total Overhead Costs
Capital Charges
G&A, Local Taxes, and
Insurance (4% of TTC)
Capital Recovery Factor
(10.61% of TTC)
Interest on Working Capital
(0 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS, 103 $/yr
8.8(30)
640
<10
70
710
110
70
30
30
30
<10
1630
<10
1900
30
60
90
30
70
10
110
2100
22(75)
1110
<10
70
1180
110
70
30
40
40
<10
2330
<10
2620
30
70
100
40
120
10
170
2890
44(150)
1740
<10
120
1860
210
70
60
60
50
<10
3570
10
4030
60
100
160
70
180
10
260
4450
58.6(200)
2070
<10
120
2190
*
210
70
60
70
50
<10
4370
10
4840
60
110
170
80
220
10
310
5320
117.2(400)
4150
<10
200
4350
320
70
130
140
100
10
7660
10
8440
100
170
270
170
440
20
630
9340
Mid-1978 dollars
-------
-IS
I
4-1
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1
CO
aj
O
3
4J
PQ
1-5
0
CO
4J
CO
0
0
OJ
N
•H
rH
03
3
a
§
-------
180 4
4-1
o-
4-1
a)
0)
•c/>
A
CO
M
0)
f-l
•H
O
(-1
•H
(K
CO
cd
150 -4
M-l
O
co
4-1
co
O
O
•a
1
g
K
o
X High Sulfur Eastern Coal;
MEA
O High Sulfur Eastern Coal;
Stretford
• Low Sulfur Western Coal;
Stretford
120 J
90 -\
60 J
30 H
30
60
90
Boiler Heat Input, MW
120
Figure 4.2-2.
Incremental annualized costs of low-Btu gas-fired boilers
versus boiler input heat rate.
4-16
-------
14-
4J
d
o
o
CM
O
co
Jj
ca
o
o
a
0)
O
H
CO
(0
0)
a
-------
The following are concluded: 1) S02 removal from high sulfur
eastern coal using the Stretford unit is more cost effective than
using an MEA unit, and 2) S02 removal from high sulfur eastern
coal is more cost effective than from low sulfur western coal.
4.2.2 Cost Bases
Costs for the most expensive equipment in the gasification/steam genera-
tion facility, e.g., the Stretford unit and the gasifiers, were obtained from
process vendors. Gas-fired boiler capital costs were provided by PEDCo
(Ref. 4-4). Costs for typical and less expensive equipment, e.g., ductwork,
were estimated from cost correlations, such as those presented by Guthrie
(Ref. 4-1) and Peters and Timmerhaus (Ref. 4-2). Some costs were estimated
from those presented in PEDCo's report for uncontrolled coal- and gas-fired
boilers (Ref. 4-3). All costs have been indexed to mid-1978 dollars.
4.2.2.1 Cost Basis for Low-Btu Gasification Systems
Costs for the Stretford process were provided by J.F. Pritchard and Co.
(Ref. 4-7) and quoted as turnkey costs. (The Stretford, in these instances,
produces a sulfur cake product that must be disposed of.) J.F. Pritchard
and Co. estimated the costs from cost curves based on their experience, and
reported the costs to be no better than preliminary estimates (Ref. 4-7).
For the smaller applications, no accurate cost data exist, and costs were
extrapolated from costs for larger systems. A ten percent engineering cost
and 30 percent contingency were added to J.F. Pritchard's costs to account
for overall contractor engineering costs and uncertainties in the cost esti-
mates. Operating costs for the Stretford process include cooling water,
chemicals, and electricity. For a system producing 8.8 MW of low-Btu gas
using high-sulfur coal, these cost items amount to 0.29 m3/min (77 gpm) of
cooling water, $210/d for chemicals, and 63 kWg (Ref. 4-8, 4-9).
Cost for the MEA absorption unit are based on data reported by Perry
Gas Company (Ref. 4-10, 4-11). Because systems of equal capacity but
4-18
-------
different removal requirements have about the same sorbent flow rate, the
same skid-mounted package unit can be used for each level of control. Operat-
ing costs include electricity and steam, as described in Chapter 5.1. These
amount to 0.9 kW£ electric power and 0.44 MW (1.5 x 106 Btu/hr) steam for a
system with a gas output of 8.8 MW and an SOa control efficiency of 94.2
percent.
Costs for the Glaus and SCOT units were obtained from data of Ralph M.
Parsons and Co. and Shell Oil (Ref. 4-12 through 4-16). As for the cost
estimates for the Stretford process, costs for the small units were extrapo-
lated off cost curves. Both the Glaus and SCOT units for the two smallest
boiler systems are smaller than those currently operating, and actually
resemble pilot-scale units. The accuracy of the cost data are thus somewhat
questionable. Although the acid gases from the MEA units differ slightly
(due to the differing levels of control), their impact on Claus/SCOT units
is negligible. Utilities for Claus/SCOT units are summarized in Chapter
5.1. For a gasification/steam generation system of 8.8 MW thermal input,
the utilities will amount to 7 kW electric power, 0.022 m3/min (6 gpm)
cooling water, 17 kW,_ (5.8 x 101* Btu/hr) fuel gas, and steam credit of
0.08 kg/s (630 Ib/hr).
Turnkey costs for Wellman-Galusha gasifiers, cyclones, and gasification
auxiliaries were obtained from McDowell-Wellman Co. (Ref. 4-17). As was done
for the Stretford unit costs, a ten percent engineering cost and 30 percent
contingency were added to McDowell-Wellman Go's, cost estimates. The smallest
facility in this study (30 MW ) requires one 3-^neter (10-foot) diameter
gasifier; the largest (117.2 MW_) needs ten gasifiers. Power requirements
for gasifier jacket water circulation and the gasifier inlet air blower
amount to about 38 kW for a gasifier/boiler using low-sulfur coal (8.8 MW
input to boiler).
Installed costs for ductwork and buildings and services were estimated
to be 6 percent of the installed equipment investment, based on factors re-
ported in Peters and Timmerhaus (Ref. 4-2).
4-19
-------
Costs for the coal receiving and storage system were estimated from costs
reported by PEDCo and EBECO (Ref. 4-4, 4-18).
Costs for the tar/oil electrostatic precipitators were obtained from
Research Cottrell, Inc. (Ref. 4-19). For a gasifier/boiler facility using
low-sulfur coal (8.8 MWT heat input to boiler), electric power requirements
amount to 6 kW (Ref. 4-19).
The gasification systems described in this report feature either a centri-
fugal blower or compressor downstream of the gas cooling equipment and upsteam
of the acid gas removal equipment. Those systems using the Stretford process
for HaS removal produce a gas that enters the Stretford process at a pressure
of about 110 kPa (16 psia). Those systems using the MEA process for the re-
moval of sulfur compounds produce a gas that enters the MEA process at about
275 kPa (40 psia). Thus, systems using the Stretford process use a blower
while systems using the MEA process use a compressor. The estimation of com-
pression power requirements (in kW ) is summarized in Chapter 5.1. Costs of
the blower were estimated from Peters and Timmerhaus (Ref. 4-2), while costs
for the compressor were estimated from Guthrie (Ref. 4-1).
Tars and heavy oils are separated from the cooling liquor in a tar/oil/
water separator. The separator provides for gravity settling of tars and oils,
and provides for their periodic removal and possible utilization. The separator
costs are relatively minor and are estimated from Ref. 4-20.
Excess process condensate is evaporated in multiple-effect evaporators
to reduce wastewater discharge. After calculating the area of the evaporator
costs were estimated by using factors from Guthrie (Ref. 4-1). The area was
calculated from
Area = steam usage
(overall heat transfer coefficient) (log mean temperature difference)
As an example, with a heat transfer coefficient of 300 Btu/hr'ft2«°F, a tem-
perature difference of 106°F, and a steam rate of 0.12 MWT (0.42 x 106 Btu/h),
4-20
-------
the area of each of three evaporators is calculated to be approximately 13
ft2, with an installed cost per evaporator of $26,000.
Costs for the cooling liquor circulation pumps were also estimated from
charts in Guthrie (Ref. 4-1). The charts use a capacity factor to determine
the equipment cost of pumps; the factor is expressed as gpm x psi. As an
example, a pump with a circulation of 230 gpm and a pressure drop of 100 psi
has a capacity factor of 23,000. Total direct and installation costs for pump
and driver amount to $13,000. For a dual set of pumps and drivers (one operat-
ing and one spare) the total installed equipment costs are $26,000. Electricity
requirements for the pump are estimated in Section 5.1.
Costs for the direct contact cooling towers were based on calculations
from Ref. 4-21 and 4-22, and costing charts from Guthrie (Ref. 4-1). The
area of the cooling towers was estimated from the maximum allowable vapor
velocity to avoid entrainment. The height of the towers was established
through heat transfer analysis described in Ref. 4-21 and 4-22. Most tar and
oil particles (>1 um) are removed in the spent cooling liquor.
Unit costs for the operating cost items identified above were presented
in Table 4.1-1. The cost of maintenance labor and supplies was calculated as
6 percent of the total turnkey costs and corrected by a factor of 0.80 to
account for the reduced operating factor of 60 percent (Ref. 4-2). Operating
labor, supervision, and maintenance labor for the various system are presented
in Table 4.2-6.
No credit or debit has been taken for tars and oils produced from the
gasifiers. This assumes that the value of these by-product hydrocarbons
will offset the cost of locating a buyer and transporting the liquids to that
buyer. Additionally, the by-product sulfur is not of high quality and is
disposed of as a solid waste.
4-21
-------
TABLE 4.2-6. LABOR REQUIREMENTS FOR LOW-BTU GASIFICATION/
STEAM GENERATION
Boiler Heat
Input , MWL
Gasification System
Operating Labor
, . a
Supervision
8.8
2
h
22
2%
h
44 58.6
3 3%
h h
117.2
5h
1
Maintenance Labor - - -
Gas-fired Boiler
Operating Labor3 1122 3
Supervision % % % % %
Maintenance \ % % hi.
values shown are number of persons required per 8-hr shift. Total labor costs
are based on 3 shifts per day.
Maintenance labor costs for gasification systems are not broken out separately
from the annual maintenance materials costs.
4-22
-------
4.2.2.2 Cost Basis for Low-Btu Gas-Fired Boilers—
Capital requirements for natural gas-fired boilers were provided by
PEDCo (Ref. 4-4). Boilers firing low-Btu gas should be very similar to those
firing natural gas, and as a result similar costs are expected. For the pur-
f
poses of this study, the costs of a low-Btu gas-fired boiler was assumed to
be identical to that of a natural gas-fired boiler. All boiler costs are
for single, package units except for the largest size, 117 MW (400 x 106
Btu/hr) thermal input. For this size, two 58.6 MW (200 x 106 Btu/hr) package
units were used to avoid the higher costs associated with a field erected unit
which would otherwise be required (Ref. 4-4). Labor requirements for the
low-Btu gas-fired boilers are presented in Table 4.2-6. Other operating costs
were based on information provided by PEDCo (Ref. 4-3, 4-4).
Annualized capital requirements for the low-Btu gas-fired boilers were
calculated using the equal payment annuity formula. The 0.1061 capital recovery
factor used was based on a 10 percent interest rate and 30-year equipment life-
time.
4.2.3 Cost Sensitivity Analysis
In this section, the major cost components of the low-Btu gas-fired
boiler annualized costs are identified. Specifically the effect of coal
costs on annualized costs is evaluated since the coal costs studied are
typical of minemouth coal costs and some degree of coal transportation and
handling is likely for most industrial applications.
A complete cost component breakdown of the annualized cost for low-Btu
gas-fired boilers is presented in Table 4.2-7.
Since the coal-to-gas conversion in the gasifier is less than unity, an
increase in coal cost will affect the annualized costs of a low-Btu gas-fired
boiler to a greater extent than the annualized costs of a coal-fired boiler.
Examples of the extent of this impact are presented in Table 4.2-8. For
4-23
-------
TABLE 4.2-7. SENSITIVITY ANALYSIS--LOW-BTU GAS-FIRED
BOILER ANNUALIZED COSTS
Coal
Boiler Input Heat Rate,
Labor and Maintenance
Utilities
Overhead
Capital Charges
Low Sulfur Western
8.8
11.4
1.4
4.3
5.2
58.6
Percent
7.7
1.1
3.2
5.8
High Sulfur
8.8
of Annualized Costs
10.3
1.3
3.9
4.7
Eastern
58.6
6.3
0.9
2.6
4.7
Fuel (Low-Btu gas)
Labor & Maintenance
Coal
Other Operating Costs
Overhead
Capital Charges
Total Fuel
Annualized Costs,
103$/year
23.8
4.3
4.3
9.0
36.2
77.6
18.2
11.3
12.2
6.8
33.6
82.1
22.4
6.9
6.9
8.6
34.9
79.7
15.6
16.5
16.8
5.8
30.6
85.3
2100
5320
2320
6530
Basis: 1) A Stretford is the acid gas removal system for all cases shown.
2) The first four items in the table above - labor and maintenance,
utilities, overhead, capital charges - refer to the gas-fired
boiler system. The fifth item - fuel - is low-Btu gas from the
Wellman-Galusha System. Percentages under fuel are the various
cost components of the gasification system.
4-24
-------
-C-
N>
Ui
TABLE 4.2-8. EFFECT OF COAL TRANSPORTATION COSTS ON ANNUALIZED LOW-BTU GAS-FIRED BOILER COSTS3
Input Heat Rate
to Boiler, MH
(10* Btu/hr)
Low Sulfur Western Coal
8.8 ( 30)
58.6 (200)
High Sulfur Eastern Coal
8.8 ( JO)
58.6 (200)
Coal Cost
Coal-fired Boiler
Annuallzed Costs,
$io'/yr
980
4370
950
4250
- Base Case Values
Lov-Btu Gas-fired
Boiler Annualized Costa,
$10»/yr
2100
5320
2320
6530
Coal Transportation Coses Addedc
Incremental
Costs,
$10'/yr
1120
950
1370
2280
Coal-fired Boiler
Annuallzed Costs,
$10'/yr
1140
5480
1040
4800
Low-Btu Gas-Fired
Boiler Annuallzed Costs,
$10»/yr
2330
6830
2430
7260
Incremental
Costs,
Sio'/yr
1190
1350
1390
2460
All gasification facilities use the Strecford process
bBase Case Values: Low Sulfur Western (LSW) - $0.40/CJ; High Sulfur Eastern (HSE) - S0.68/GJ
transportations Coats: LSW - Sl.OO/CJ; HSE - $0.50/GJ
-------
illustrative purposes coal transportation costs are taken as $1.00/GJ and
$0.50/GJ for low sulfur western and high sulfur eastern coal, respectively.
4.2.4 Confidence Interval for Low-Btu Gasification/Boiler Annualized Costs
In assessing the accuracy or confidence interval for the annualized low-
Btu gas-fired boiler costs presented in this section, two major items were
considered:
• capital investment requirements, and
• operating and maintenance requirements (including labor, maintenance,
utilities, raw materials, and waste disposal)
Additional factors impact the accuracy of the annualized costs, but those
factors were essentially assumptions or bases imposed on the economic evalua-
tion. Included in the assumptions and bases were:
• method of annualizing the capital investment requirements,
• method of calculating overhead costs, and
• unit costs for operating and maintenance (O&M) requirements
Annualized capital related charges and overhead costs can vary widely
depending upon individual company operations. In order to estimate these
charges in a manner consistent with the other control technologies being
examined in the EPA's Industry Boiler Program, the EPA stipulated the esti-
mating technique to be used. Also, unit costs for the O&M requirements were
provided by the EPA in order to maintain consistency in the Industry Boiler
Program. Since the above three items served as the bases for the economic
evaluation, they were not considered in assessing the accuracy of the annualized
cost estimates.
Assessing the accuracy of the capital investment and O&M requirements
is complicated by the fact that no low-Btu gasification system, integrated
with quenching/cooling and sulfur species removal units, has ever been built.
4-26
-------
Thus, there is no "yardstick" to compare the results of this study to. How-
ever, the process vendors who supplied the major equipment item cost estimates
(e.g., for the gasification system and Stretford process) indicated that the
estimates had an accuracy of about ±30%. A conservative approach was taken
in estimating the total turnkey costs of the gasification system by including
a 30% project contingency. As a result, the total capital investment require-
ment estimates are believed to be accurate within ±30%.
The operating and maintenance requirements for the gasification systems
(e.g., labor and utilities) were estimated based on vendor quotes, information
in the literature, and engineering calculations. As such, the accuracy of the
O&M requirements are believed to be within ±30%.
Thus, for the assumptions and bases used in this study (e.g., units costs
for coal, labor, utilities, and waste disposal), the annualized costs for the
low-Btu gas-fired boilers are estimated to be accurate to within ±30%.
4.3 MEDIUM-BTU COAL GASIFICATION
As described in Section 3.2, two processes have been selected in this
study for the removal of sulfur species from medium-Btu gas produced by a
Lurgi gasifier. These are the Stretford process and the Rectisol process.
Also, use of two coals—a high sulfur eastern and a low sulfur western (see
Section 3 for coal analyses)—are being examined. A large centralized gasi-
fication plant with a medium-Btu gas capacity of 3060 MW (250 x 109 Btu/SD)
was the only plant size investigated. Therefore, the medium-Btu gas cost
(in $/GJ) is constant for all of the medium-Btu gas-fired boilers examined
in this study. Thus, four coal gasification system scenarios are considered
and costs for four medium-Btu gas products were developed. The estimated
annualized operating costs for industrial boilers using these medium-Btu gases
as fuel are summarized in Table 4.3-1.
As discussed in Section 6.2 on environmental impacts, the levels of
particulate and N0x emissions from the medium-Btu gas-fired boilers are
4-27
-------
TABLE 4.3-1.
COST ANALYSIS OF "BEST CANDIDATE" MEDIUM-BTU COAL
GASIFICATION SYSTEMS FOR INDUSTRIAL BOILERS*
Boiler Heat
Input, MW_
(10* Btu/hr)
8.8 ( 30)
8.8 ( 30)
8.8 ( 30)
8.8 ( 30)
22 ( 75)
22 ( 75)
22 ( 75)
22 ( 75)
44 (150)
f 44 (150)
» 44 (150)
44 (150)
58.6(200)
58.6(200)
58.6(200)
58.6(200)
Coal Feed
to Gaslfier
Low- sulfur
Low-sulfur
High-sulfur
High-sulfur
Low-sulfur
Low-sulfur
High-sulfur
High-sulfur
Low-sulfur
Low-sulfur
High-sulfur
High-sulfur
Low-sulfur
Low-sulfur
High-sulfur
High-sulfur
Sulfur Control
Technique**
Stretford
Rectisol
Stretford
Rectisol
Stretford
Rectisol
Stretford
Rectisol
Stretford
Rectisol
Stretford
Rectisol
Stretford
Rectisol
Stretford
Rectlsol
SOz Control
Efficiency,
Z
93
99+
98
99+
93
99+
98
99+
93
99+
98
99+
93
99+
98
99+
Annualized Medlua-Btu
Gas-fired Boiler Costs
$10' /yr
1210
1320
1490
1650
2390
2690
3120
3500
4550
5150
6010
6770
5840
6630
7770
8790
Z Increase In
Annualized Costs
per unit heat input Over Uncontrolled
$/kWT ($/106 Btu/hr) Coal-Fired Boiler Costs
138
150
169
188
109
122
142
159
103
117
137
154
100
113
133
150
(40,400)
(43,900)
(49,500)
(55,100)
(31,900)
(35,700)
(41,600)
(46,600)
(30,200)
(34,300)
(40,100)
(45,100)
(29,300)
(33,100)
(39,000)
(43,900)
24
35
57
73
28
44
69
89
46
65
95
120
34
52
83
107
**
Lurgi gaaifler. 60Z annual operating factor for the boiler.
All cases have estimated NO and partlculate emissions of 50-100 ng NO /J (0.12-0.23 lb/106 Btu) and 4 ng
partlculates/J (0.01 lb/106 Btu).
SOz. emission levels (from the industrial boiler only) are as shown below:
Low sulfur western coal with Stretford - 37 ng S02/J (0.09 lb/106 Btu)
High sulfur eastern coal with Stretford - 60 ng SOj/J (0.14 lb/106 Btu)
All Rectisol case* - 2 ng SO,/J (0.004 lb/106 Btu)
-------
estimated to be similar to those for natural gas combustion—50-100 ng NO /J
(0.12-0.23 lb/106 Btu) and 4 ng particulates/J (0.01 lb/106 Btu). This is
esentially complete control of particulates and 60-85 percent control of NO
emissions from what would be expected from direct-firing of coal. Sulfur
dioxide emissions are also significantly reduced by firing medium-Btu gas
instead of coal, with reductions of 93 to 99+ percent being achieved. A more
detailed discussion of the environmental impact of using medium-Btu gasifica-
tion as an industrial boiler emission control technique is presented in
Section 6.2.
This section is organized as follows:
4.3.1 Costs Summary and Analysis
4.3.2 Cost Bases
4.3.3 Cost Sensitivity Analysis
4.3.1 Costs Summary and Analysis
In Table 4.3-1, the annualized costs for medium-Btu gasification/steam
generation facilities are compared to the annualized costs for uncontrolled
coal-fired boilers (See Table 4.2-2 for descriptive information on the coal-
fired boiler systems). Refer to Section 4.3.2 for the economic bases for
this evaluation. As indicated by the "percentage increase" data in Table
4.3-1, the medium-Btu gas-fired boilers are most nearly competitive with
uncontrolled coal-fired boilers at the small boiler capacities. This occurs
since the medium-Btu gas cost does not vary as a function of boiler capacity.
However, as will be shown in Figure 4.3-2, the incremental annualized costs
of the medium-Btu gas-fired boilers (versus coal-fired boilers) per kVL, of
design input heat to the boiler do not have a significant dependence on
boiler input heat rate.
In order to facilitate the evaluation of the emissions control costs
associated with medium-Btu gasification, Figures 4.3-1, 4.3-2, and 4.3-3 were
prepared.
4-29
-------
200-,
180-
• Low Sulfur Western Coal; Stretford
0 Low Sulfur Western Coal; Rectisol
X High Sulfur Eastern Coal; Stretford
(9) High Sulfur Eastern Coal; Rectisol
•CO-
•H
O
(0
cfl
O
U
oa
M
•2 120-1
4J
01
O
O
13
(I)
3
i-H
i
160-
140-
100-
—i 1 1 1—
10 20 30 40
Boiler Input Heat Rate, MW
—T
50
—?
60
Figure 4.3-1.
Annualized costs of medium-Btu gas-fired
industrial boilers.
4-30
-------
(g) High Sulfur Eastern Coal; Rectisol
X High Sulfur Eastern Coal; Stretford
O Low Sulfur Western Coal; Rectisol
« Low Sulfur Western Coal; Stretford
„ 100-
OJ
•rl
O
pa
"S 80-
M H
•H 3
to 5
1 —
co
O «
co
3 S 60-
PQ rH
1 -H
Q O
•H
0) 0)
0 1
4-1 CO
CO O
O 0
CJ
VI
"rt > 20-
4J O
c
01
§
M
CJ
c
M On
00
X
x x x
o
0 o o
£
A
*
I 1 1 1 1 1
0 10 20 30 40 50 60
Boiler Input Heat Rate, MW
Figure 4.3-2.
Incremental cost of medium-Btu
gas-fired industrial boilers
4-31
-------
5.On
/ n
0) H 4.0
0) H
§2
4J O
O O
01
E o 3.0
w w
w op
w .*^
o ^
2 3
*J C
C (U
o s
CM CJ
O 13
CO M
2.0-
1.0-
o
Q Low Sulfur Western Coal; Rectisol
» Low Sulfur Western Coal; Stretford
® High Sulfur Eastern Coal; Rectisol
\s High Sulfur Eastern Coal; Stretford
O
o
o
X
10
20
i
30
i
40
i
50
60
Boiler Input Heat Rate, MW
Figure 4.3-3.
Cost effectiveness of medium-Btu gasification/steam
generation system in controlling SOa emissions.
4-32
-------
Figure 4.3-1 presents the annualized medium-Btu gas-fired boiler
costs as a function of boiler capacity.
• Figure 4.3-2 illustrates the incremental costs of emissions
control (compared to uncontrolled coal-fired boilers) as a
function of boiler size.
Figure 4.3-3 graphically illustrates the cost effectiveness of
medium-Btu gasification in controlling S02 emission assuming all
costs of control are allocated to S02 emissions control.
Before discussing the bases used to calculate the cost data in Table
4.3-1 and Figures 4.3-1, 4.3-2, and 4.3-3, some comments are required concern-
ing the use of the cost data and the need to consider both coal and medium-BTU
gas transportation costs. First, the size and complexity of the medium-Btu
gasification facilities prohibited detailed cost estimating in this study.
The true costs for many of the pieces of equipment depend highly on factors
which are specific, and sometimes unique, for each application. Many assump-
tions had to be made to develop the design and operating parameters which were
required for the cost analyses. Thus, when using the cost estimates, one
should be aware of the assumptions and bases that went into their development.
The second item is a consideration of the impact transportation costs
have on the cost of the medium-Btu gas and hence on the annualized cost of
the boiler. The coal costs used in this study are minemouth costs, as pro-
vided by the EPA and PEDCo (Ref. 4-5). They do not include transportation
costs which can, in the case of western coals, increase delivered coal costs
to as high as 2 or 3 times the minemouth costs. For the western coal cases,
a $1.00/GJ or 250 percent increase in coal costs would increase the medium-
Btu gas costs by about $1.70/GJ. That translates into a 40 percent increase
in gas costs for the Stretford case and a 34 percent increase for the Rectisol
case. For the eastern coal cases, a $0.50/GJ or 74 percent increase in coal
costs would cause the medium-Btu gas price to increase by $0.98/G.]. That is
4-33
-------
a 16 percent increase in gas costs for the Stretford case and a 14 percent
increase for the Rectisol case.
The medium-Btu gasification plants in this study are also assumed to be
located away from, but within the general region of the industrial boiler.
The cost of transporting the medium-Btu gas from the gasification facility to
the boiler, however, has not been included in the cost analysis. This cost
will obviously depend on the distance between the two locations, the volume
of gas transmitted, and site specific factors such as the cost of procuring
right-of-way for the transmission pipeline.
4.3.2 Cost Bases
The cost data presented in Table 4.3-1 were developed by first estimat-
ing the annualized costs of producing medium-Btu gas, and from that, the unit
cost of the gas. The unit gas costs were used to calculate the annual fuel
costs for the four sizes of industrial boilers examined. These were then
incorporated into the annualized cost analysis of each boiler.
Estimates of the capital requirements and operating and maintenance costs
for the four gasification systems were developed from data presented in a
study by C. F. Braun for high-Btu gasification systems (Ref. 4-23). Adjust-
ments were made to the C. F. Braun study data to 1) reflect the differences
between high-Btu and medium-Btu gasification systems (deletion of the costs
for the shift conversion, methanation and product gas compression units) and
2) incorporate the use of different operating conditions (coal, oxygen and
steam flow rates) and acid gas/sulfur recovery processes. The size and cost
of the on-site coal-fired utility boilers were also adjusted to reflect
different steam and electric power requirements and to include the use of
limestone flue gas desulfurization (FGD) units to control 862 emissions from
the boiler.
The process areas for which capital requirements were estimated are shown
in Table 4.3-2, along with the operating parameter used to adjust the C. F.
4-34
-------
Braun data. For all adjustments except for the Rectisol costs for the high
sulfur coal case, a scale factor of 0.6 was used to reflect the influence of
economy of scale. As shown in Table 4.3-2, costs for several of the process
areas were not adjusted. This was because, either 1) their costs were rela-
tively minor and/or 2) sufficient detailed information was not available to
permit making adjustments.
TABLE 4.3-2. CAPITAL COST ITEMS FOR MEDIUM-BTU GASIFICATION SYSTEMS
Coal Handling and Reclaiming
Coal Preparation
Coal Feed, Gasification and
Raw Gas Quench
Acid Gas Removal
Product Gas Drying
Liquid Effluent Treatment
Sulfur Recovery
Solids Disposal
Steam and Utilities Systems
Plant Water Systems
Oxygen Plant
General Facilities
Adjustment Parameter for
C.F. Braun Costs
Coal Flow Rate
Coal Flow Rate
Not Adjusted
(1) (2)
Not Adjusted
Not Adjusted
(1)
Solids Flow Rate
Heat Duty and Electricity
Required (3)
Not Adjusted
Oxygen Flow Rate
Not Adjusted
(1) Costs for the Stretford process used for acid gas removal/sulfur
recovery and for just sulfur recovery were supplied by vendor quotes
(Ref. 4-8).
(2) Costs could not be obtained for the Rectisol process. At the
suggestion of Lurgi (Ref. 4-24), the licensor of the Rectisol process,
costs presented by C.F. Braun for the Selexol process were used for
the Rectisol costs in the low sulfur coal case. These costs were
ratioed by the quantity of acid gas removed to estimate costs for the
high sulfur eastern coal case (Ref. 4-25).
(3) Limestone FGD costs were estimated from Ref. 4-26 based on the quantities
of flue gas to be treated and SOa removed.
4-35
-------
The costs for the coal feed, gasification, raw gas quench and shift con-
version units of the C. F. Braun study were provided by Lurgi and reported as
a group. The cost of the shift conversion unit was estimated at $52 million
(January 1976 dollars) based on cost data for other systems presented in the
C. F. Braun study. Insufficient data were available to adjust the cost of
the coal feed, gasification, and raw gas quench units.
Cost estimates for the Stretford process were obtained from process
vendors (Ref. 4-8). Estimates for the Rectisol process could not be obtained.
Instead, at the suggestion of Lurgi (the licensor of the Rectisol process),
C. F. Braun's cost data for the Selexol process were used for the Rectisol
costs in the low sulfur coal case (Ref. 4-24). For the high sulfur coal case,
the Selexol costs were ratioed by the amount of acid gases removed. This is
a reasonable approach for situations where most of the acid gas is C02 as is
the case in this study (Ref. 4-25).
The costs of the limestone FGD unit for the utility boiler were estimated
from data presented in Ref. 4-26. These costs were adjusted according to
flue gas flow rate and quantity of S02 removed.
All estimates of capital requirements were indexed to mid-1978 dollars
using the CE Plant Cost Index (mid-1978 = 217.7). Tables 4.3-3 and 4.3-4
summarize the adjusted capital investment requirements for the four medium-
Btu gasification systems.
Operating costs for the gasification systems were also estimated based
on data presented in C. F. Braun's study (Ref. 4-23). Maintenance costs and
annualized operating costs for the four systems examined are summarized in
Appendix B. Tables 4.3-5 and 4.3-6 for the low-sulfur western coal case
using the Stretford process are shown here to indicate the cost approach
taken and the bases used. Unit costs for the direct operating costs, e.g.,
4-36
-------
TABLE 4.3-3. ESTIMATED INSTALLED EQUIPMENT COSTS FOR LURGI MEDIUM-BTU GASIFICATION SYSTEMS*
i
OJ
Low Sulfur Western Coal
Process Area
Coal Storage and Reclaiming
Coal Preparation
Coal Feed )
Gasification [
Raw Gas Quench )
Acid Gas Removal
Product Gas Drying
Sour Water Stripping, Ammonia
Recovery, and Bio-Oxidation
Sulfur Recovery
Solids Disposal
Steam and Utility Systems
Plant Water Systems
Oxygen Plant
General Facilities
TOTAL INSTALLED EQUIPMENT COSTS
Stretford
17
20
162
11
0.9
22
-
3.5
228
26
77
96
663.4
Rectisol
17
20
162
136
0.9
22
16
3.5
233
26
77
96
809.4
High Sulfur
Stretford
16
19
162
33
0.9
22
-
5.6
324
26
95
96
799.5
Eastern Coal
Rectisol
16
19
162
169
0.
22
40
5.
316
26
95
96
967.
9
5
4
a3060 MW (250 x 109 Btu/day) capacity (gas output); mid-1978 dollars; 106 dollars.
-------
TABLE 4.3-4. ESTIMATED TOTAL CAPITAL REQUIREMENTS FOR LURGI MEDIUM-BTU GASIFICATION SYSTEMS5
i
u>
00
Total Engineered Equipment Costs (EC)
(including direct installation costs)
Installation Costs, indirect
Engineering and Fee (10% of EC)
Construction and Field Expense
(included in Equipment Costs)
Contingencies (30% of EC)
Allowance for Funds Used During
Construction (EC x Average Spending
Period (1.75 yrs) x 10%)
Paid-up Royalties
Startup Costs (20% of total gross
annual operating costs)
Land
Working Capital (25% total direct
operating costs)
Total Capital Requirement
Low Sulfur
Stretford
663.4
66.3
218.9
116.1
1.1
23.1
0.9
26.0
1115.8
western coal
Rectisol
809.4
80.9
267.1
141.6
1.1
24.4
0.9
27.7
1353.1
High sulfur
Stretford
799.5
80.0
263.9
139.9
1.1
38.4
0.9
45.0
1368.7
eastern coal
Rectisol
967.4
96.7
319.2
169.3
1.1
40.8
0.9
47.3
1642.7
a3060 MWT (250 x 109 Btu/day) capacity (gas output); mid-1978 dollars; 106 dollars.
-------
TABLE 4.3-5. ESTIMATED MAINTENANCE COSTS FOR LURGI
MEDIUM-BTU GASIFICATION SYSTEM3
Coal Feedstock
Acid Gas Removal
Unit
Coal Handling and Reclaiming
Coal Preparation
Coal Feed
Gasification
Raw Gas Quench
Acid Gas Removal
Product Gas Drying
Liquid Effluent Treatment
Sulfur Recovery
Solids Disposal
Steam and Utilities Systems
Plant Water Systems
Oxygen Plant
General Facilities
TOTAL
Maintenance Labor
(@ 60% of Total Maintenance)
Maintenance Supplies
(@ 40% of Total Maintenance)
Unit
Unit
Cost
24
29
232
16
1
31
-
5
326
37
110
137
948
Low sulfur western
Stretford
Maintenance
Factor, %
6
6
5
3
3
3
3
3
1
3
3
1
Maintenance
Cost
1.4
1.7
11.6
0.5
0.03
0.9
-
0.2
3.3
1.1
3.3
1.4
25.4
15.2
10.8
13060 MW (250 x 109 Btu/day) gas output capacity; 106 mid-1978 dollars.
4-39
-------
TABLE 4.3-6. ANNUALIZED COSTS FOR LURGI MEDIUM-BTU
GASIFICATION SYSTEM3
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Stretford
Operating Factor - 90%
Direct Costs
Operating Labor (@ $12.02/hr) 6.3
Maintenance Labor (60% of Total Maintenance) 15.2
Supervision (20% of Operating and Maintenance Labor) 4.3
Maintenance Materials (40% of Total Maintenance 10.8
Replacement Parts (Included in Maintenance Materials)
Operating Supplies (30% of Operating Labor) 1.9
Purchased Water (@ $0.032/m3) 0.1
Coal (@ $8.88/ton) 58.3
Chemicals and Catalysts 2.3
Solids Disposal (@ $ll/ton) 4.7
Total Direct Coats 103.9
Overhead Costs
Payroll (30% of Operating Labor) 1.9
Plant (26% of Labor, Materials, and Maintenance) 9.5
Total Overhead Costs 11.4
By-Product Credits
Sulfur (@ $29/ton) 0.8
Ammonia (@ $110/ton) 5.2
Naphtha (@ $93/m3)
Phenols (@ $46/m3) 1.1
Tars (I? $46/m3) 8.7
Oils (@ $79/m3) 8.7
Total By-Product Credits (24.5)
Capital Related Charges
G&A, Local Taxes, and Insurance (4% of Total 42.6
Capital Requirement excluding Start-up Costs,
Land, and Working Capital)
Capital Recovery (11.752 of Total Capital Require- 127.9
ment excluding Land and Working Capital)
Interest on Working Capital (@ 10%) 2.6
Total Capital Related Charges 173.1
TOTAL ANNUALIZED COSTS 263.9
Average Gas Costs, $/GJ (S/106 Btu) 3.05 (3.20)
Average Gas Costs'5, $/GJ ($/106 Btu) 4.30 (4.55)
a3060 MW (250 x 109 Btu/day) output gas capacity; 105 mid-1978 dollars.
At 60% operating factor.
4-40
-------
coal costs, were those indicated in Table 4.1-1 (Ref. 4-5). The average gas
costs shown in Table 4.3-6 were calculated in a manner analogous to that
described previously for low-Btu gasification systems. The following assump-
tions were used:
20-year project life,
• 10 percent interest rate, and
60 and 90 percent operating factors.
The medium-Btu gas plant is designed to operate at a 90% operating fac-
tor. Average gas costs were calculated based on this operating factor. How-
ever, an industrial boiler with a 60% operating factor will have to pay more
for gas from this facility. There are various means available to permit the
centralized gas plant to operate at full capacity 90% of the time. They
include:
• Gas storage capability could be made available
• Backup fuels could be utilized by industrial boiler
operators during peak requirements.
These techniques were not evaluated because of the additional complexity
which would be added to the study. Therefore medium-Btu gas costs were also
evaluated using a 60% operating factor. The costs (at 60% operating factor)
were used in Table 4.3-1 in developing annualized medium-Btu gas-fired boiler
costs.
Annualized operating costs for the medium-Btu gas-fired boilers were
also estimated in a manner identical to that for the low-Btu gas-fired
boilers. Capital requirements and all direct operating costs except fuel
costs were assumed to be the same as for the same capacity low-Btu gas-fired
boiler. Annualized capital charges were calculated using a capital recovery
factor based on a 20-year boiler lifetime and interest at 10 percent.
Detailed summaries of the annualized costs of the 16 medium-Btu gas-fired
boilers examined are contained in Appendix B.
4-41
-------
4.3.3 Cost Sensitivity Analysis
In this section, the major cost components of the medium-Btu gas-fired
boiler annualized costs are identified. Specifically the effect of coal costs
on annualized boiler costs is evaluated since the base case coal costs are
typical of minemouth costs and some degree of coal handling and transporta-
tion is likely for most industrial application.
A complete breakdown of the annualized costs for medium-Btu gas-fired
boilers is presented in Table 4.3-7.
Since the coal-to-gas conversion efficiency is less than unity, an
increase in coal cost will increase the annualized costs of a medium-Btu
gas-fired boiler relative to those of an uncontrolled coal-fired boiler.
Examples are presented in Table 4.3-8. For illustrative purposes, coal
cost increases of $1.00/GJ and $0.50/GJ are examined for western and eastern
coal, respectively. These are representative of possible coal transportation
costs expected for coals in these regions.
4.4 COAL LIQUEFACTION
The SRC-I and Exxon Donor Solvent (EDS) processes were selected as the
"best candidate" coal liquefaction systems for controlling emissions from
industrial boilers. Capital requirements for constructing facilities using
these processes and annualized operating costs were estimated from available
literature data (Ref. 4-27, 4-28). The coal feedstocks considered in the
/
cost estimates were high sulfur bituminous coals. Insufficient information
was available to develop cost estimates for a low sulfur coal feedstock.
From the annualized cost estimates for the coal liquefaction facilities
unit fuel prices were calculated. These were incorporated into cost analyses
4-42
-------
TABLE 4.3-7.
SENSITIVITY ANALYSIS - MEDIUM-BTU GAS-FIRED
BOILER ANNUALIZED COSTS
Coal
Boiler Input Heat Rate,
MWT
Labor and Maintenance
Utilities
Overhead
Capital Charges
Fuel (Medium-Btu Gas)
Labor & Maintenance
Coal
Other Operating Costs
By Product Credits
Overhead
Capital Charges
Total Fuel
Annual ized Costs,
103$/yr
Low Sulfur Western
8.8
19.8
2.5
7.4
10.7
8.7
9.2
1.5
(3.9)
2.7
41.3
59.5
1210
58.6
Percent
7.0
1.0
2.9
7.4
12.0
12.7
2.1
(5.3)
3.8
56.5
81.7
5840
High Sulfur Eastern
8.8
of Annualized Costs
16.1
2.0
6.0
8.7
7.6
15.0
3.2
(1.9)
2.3
40.9
67.1
1490
58.6
5.3
0.6
2.2
6.2
9.7
19.2
4.1
(2.5)
3.0
52.1
85.6
7770
Basis: 1) Stretford is the acid gas removal unit for all cases shown
2) Operating factors - 60% for gasification plant
60% for boiler
3) The first four items in the table above - labor and maintenance,
utilities, overhead, capital charges - refer to the gas-fired
boiler system. The fifth item - fuel - is medium-Btu gas from
the gasification plant. Percentages under fuel are the various
components of the gas costs.
4-43
-------
TABLE 4.3-8. EFFECT OF COAL TRANSPORTATION COSTS ON ANNUALIZED MEDIUM-BTU GAS-FIRED BOILER COSTS
Low
High
Input Heat Rat*
to Boiler. MH_
(10* Btu/hr)
Sulfur Uestern Coal
8.8( 30)1
8.8( 30)"
58.6(200)'
58.6(200)°
Sulfur Eastern Coal
8.8( 30)'
8.8( 30)°
58.6(200)'
58.6(200)°
Coal-find Boiler
Annualized Costa,
ttO'/yr
977
977
4369
4369
952
952
4248
4248
Coal Coat • Baaa Case Valuaa*
MediuB-Btu gai-fir«d
Boiler Annualized Coata,
$10'/yr
1210
1320
5840
6630
1490
1650
7770
8790
Incremental
Costa,
$103/yr
230
340
1470
2260
540
700
3520
4540
Coal
Coal-fired Boiler
Annualized Coata,
$!0'/yr
1144
1144
5478
5478
1035
1035
4802
4802
Transportation Costa Added
Mediua-Btu gas-fired
Boiler Annualized Costs,
$10J/yr
1490
1600
7720
8520
1640
1800
8800
9820
b
Incremental
Costs,
$10}/yr
350
460
2240
3040
610
770
4000
5020
"Base Case Values: Low Sulfur Uestern (LSH) - W.40/CJ; High Sulfur Eastern (USE) - $0.68/CJ
bTransportation Coats: LSH - Sl.OO/GJ; HSB - S0.50/GJ
'Caslflcstlon Systea Uses Stretford Process
'ossification System Uses Rectlsol Process
-------
developed for several sizes of industrial boilers. For the EDS liquids, four
package, watertube boilers sizes were examined—8.8, 22, 44, and 58.6 MW
(30, 75, 150, and 200 x 106 Btu/hr) heat input. For SRC-1, the only boiler
considered was a 58.6 MW (200 x 106 Btu/hr), field-erected pulverized coal
type boiler. Smaller boilers were not examined because they generally would
be stoker types, and it is impractical to use SRC-I in a stoker type boiler
due to its low melting point.
The estimated annualized costs for industrial boilers firing EDS liquids
and SRC-I are summarized in Table 4.4-1. Also included in this table are the
percentage increases that these annualized costs represent over the costs of
direct coal-fired boilers (Ref. 4-3) .
Emissions from the combustion of SRC-I and EDS liquids are summarized
in Table 4.4-2. Also shown in this table are the target emission control
levels for combustion of coal-derived liquids. As indicated in this table,
SRC-I can only meet the moderate SOa emission control level, while raw EDS
liquids can meet the intermediate level, and if hydroprocessed, can meet the
stringent level. If a 80 percent efficient particulate control device is
used on the boiler flue gases, SRC-I combustion can meet the particulate
emission control target of 13 ng/J (0.03 lb/106 Btu). The EDS liquids can
meet the target control level without a post-combustion particulate control
device. NO emissions indicated in Table 4.4-2 are based on EPA emission
factors for coal and residual fuel (Ref. 4-29). Whether these factors are
appropriate for coal-derived fuels is not known. Combustion modification
potentially could reduce the levels of NO ' emissions. However, the extent
to which combustion modifications would be effective is not known.
4.4.1 Cost Bases
Annualized costs for the SRC-I and EDS facilities were developed from
available literature data (Ref. 4-27, 4-28). Capital requirements (indexed
to mid-1978 dollars using the M+S cost index) for the facilities are
4-45
-------
TABLE 4.4-1. COST ANALYSIS OF "BEST CANDIDATE" COAL LIQUEFACTION
SYSTEMS FOR INDUSTRIAL BOILERS
Boiler Heat
Input, HVL.
(106 Btu/hr)
•e>
1
8.8
22
44
5 t . 6
58.6
( 30)
( 75)
(150)
(200)
(200)
Coal Feed to
Liquefartion Process
High
High
High
High
High
Sulfur
Sulfur
Sulfur
Sulfur
Sulfur
Bituminous
Bituminous
Bituminous
Bituminous
Bituminous
Coal
Liquefaction
Process
EDS
EDS
EDS
EDS
SRC- 1
Annuallzed Coal Liquids-Fired
Emission Control Efficiency, X Boiler Costs
S02
95*
95*
95*
95*
83
Partlculates
99.4
99.4
99.8
99.8
99.6**
X Increase In Costs
Over Uncontrolled
10' $/yr $/kWT ($/10" Btu/hr) Coal-Fired Holler Costs
1,300
2,670
5,110
6,580
6,800
148
121
116
112
116
(43,000)
(36,000)
(34,000)
(33,000)
(34,000)
37
44
66
55
60
* Additional hydroprocesslng can Increase SOj control efficiency to 96.5X or greater.
** Assumes 80Z efficiency participate control device on boiler flue gases.
All costs are mid-1978 dollars.
-------
TABLE 4.4-2. EMISSIONS FROM COAL LIQUIDS COMBUSTION
SRC-I*
EDS Liquids*
Raw
Hydroprocessed
Target Control Levels
Moderate Control
Intermediate Control
Stringent Control
S02, ng/J
440
125
83
520
260
86
N0x, ng (as N02)/J
(248)
(115)
(115)
300
200
86
Participates, ng/J
13**
6
6
13
13
13
* Produced from high sulfur bituminous coal.
** Assumes 80% efficient particulate control device on flue gas.
Numbers in parentheses are merely estimates based on EPA emissions factors (Ref. 4-29). The validity
of applying those emission factors to coal liquids combustion is not known.
-------
presented in Tables 4.4-3 and 4.4-4. Annualized costs and average product
costs are presented in Tables 4.4-5 and 4.4-6. The following assumptions
were used to develop the cost estimates shown in these tables:
Labor, process water, catalyst, and chemical costs for
the SRC-I facility were assumed to be equal to those
for the EDS facility.
• Minemputh coal costs were used, i.e., costs for trans-
porting the coal feedstock from the mine to the
liquefaction facility were not included.
• A 20-year equipment life and 10 percent annual interest
rate were used to calculate the annualized capital charges.
• An 80 percent plant operating factor was used to calculate
the average product costs.
Annualized costs for the coal liquids-fired boilers were estimated
from data developed by PEDCo (Ref. 4-3) for a 58.6 MWT> pulverized low
sulfur eastern field-erected coal-fired boiler (for the SRC-I boiler) and
for a 44 MKL, residual fuel oil-fired package boiler (for the EDS liquids-
fired boilers). Capital requirements for the 8.8, 22, and 58.6 MWT EDS
liquids-fired boilers were estimated using the 44 MW_ boiler capital require-
ment. The assumptions used in developing the annualized boiler costs
included:
The cost of transporting the coal liquids from the coal
liquefaction plant to the industrial boiler were not
included.
A 45-year equipment life and 10 percent annual interest
rate were used to calculate the annualized capital
charges for the SRC-I-fired boiler.
A 20-year equipment life and 10 percent annual interest
rate were used to calculate the annualized capital
charges for the EDS liquids-fired boilers.
A 60 percent annual operating factor was assumed for all
of the boilers.
Detailed summaries of the capital requirements and annualized costs of the
SRC-I and EDS liquids-fired boilers are contained in Appendix C.
4-48
-------
TABLE 4.4-3. TOTAL CAPITAL REQUIREMENT FOR SRC-I PROCESS
Coal Feedstock High Sulfur Bituminous
Capacity 7050 MWT(577 x 109 Btu/day)
S02 Control Level Moderate
Installed Equipment Costs
Coal preparation 90
Hydrogenation and hydrogen recycle 221
Fractionation 27
Hydrogen plant 342
Filtration 192
Product solidification 28
Gas and secondary recovery 90
Offsites and wastewater treatment 110
General Facilities 86
Total Installed Equipment (EC) 1,186
Engineering and fee (included in direct costs)
Construction and field expense (included in
direct costs)
Contingencies (30% of EC) 356
Start-up Costs (20% of total gross annual
operating costs) 59
Allowance for funds used during construction
(EC x 1.75 x 0.10) 208
Land 2
Working capital (25% of total direct annual
operating costs) 73
Total Indirect Costs 698
TOTAL CAPITAL REQUIREMENT 1,884
106 mid-1978 dollars
4-49
-------
TABLE 4.4-4. TOTAL CAPITAL REQUIREMENTS FOR EXXON DONOR SOLVENT PROCESS
Coal Feedstock High Sulfur Bituminous
Capacity 4000 MW (328 x 109 Btu/day)
SOa Control Level Intermediate*
Installed Equipment Costs
Liquefaction 218
Solvent hydrogenation 74
Flexicoker 145
Hydrogen recovery and generation 218
Gas and wastewater treatment 44
Product recovery 7
Offsites 224
Total Equipment Costs (EC) 930
Engineering and fee (10% of EC) 93
Construction and field expense
(included in direct costs)
Contingencies (30% of EC + Engineering + Fee) 307
Start-up costs (20% of total gross annual
operating costs 53
Allowance for funds used during construction
(EC x 1.75 x 0.10) 163
Land 2
Working capital (25% of total direct annual
operating costs) 66
Total Indirect Costs 684
TOTAL CAPITAL REQUIREMENT 1,614
*Additional hydroprocessing will permit attainment of stringent control
levels. Additional costs incurred for hydroprocessing cannot be determined
and are assumed to be negligible.
106 mid-1978 dollars
4-50
-------
TABLE 4.4-5. ANNUALIZED COSTS FOR SRC-I PROCESS
Coal Feedstock
Capacity
S02 Control Level
Operating Factor
High Sulfur Bituminous
7050 MWT(577 x 109 Btu/day)
Moderate
80%
Direct Costs
Manpower
Repair materials and other
Electricity (@ 25.8 mills/kW-h)
Purchased water (@ $0.032/m3)
Catalysts and Chemicals
Coal (@ $18.72/ton)
Total Direct Costs
31
48
16
<1
6
163
264
Overhead
Payroll (30% of labor)
Plant (26% of labor, parts and maintenance)
Total Overhead Costs
General and Administrative Costs, Local Taxes
and Insurance (4% of total capital requirement
excluding land and working capital)
By-Product Credits
Capital Recovery Factor (11.75% of total
capital requirement excluding land and
working capital)
Interest on working capital
9
20
29
72
(9)
213
7
TOTAL ANNUALIZED COSTS
Average Product Cost, $/GJ
576
3.25
106 mid-1978 dollars
4-51
-------
TABLE 4.4-6. ANNUALIZED COSTS FOR EXXON DONOR SOLVENT PROCESS
Coal Feedstock High Sulfur Bituminous
Capacity 4000 MW (328 x 109 Btu/day)
S02 Control Level Intermediate*
Operating Factor
Direct Costs
Manpower 31
Repair materials and other 48
Electricity (@ 25.8 mills/kW-h) 32
Purchased water (@ $0.032/m3)
-------
4.4.2 Costs Summary and Analysis
The estimated annualized boiler costs listed in Table 4.4-1 are shown
graphically in Figure 4.4-1 as a function of boiler input heat rate. As
expected, the larger boilers have lower annualized costs per unit of capacity.
Also shown in Figure 4.4-1 are the incremental costs of the coal liquids-
fired boilers (in $/kW_, of design input heat rate) over direct coal-fired
boilers. As was true for the medium-Btu gas-fired boilers, the coal liquids-
fired boiler incremental costs do not have a significant dependence on
boiler input heat rate.
The 862 control cost effectiveness of the coal liquefaction systems as
emission controls is shown in Figure 4.4-2. The data in this figure are ex-
pressed as incremental costs per kg of S02 controlled as a function of boiler
size. This assumes that the total incremental cost of control for coal
liquefaction systems are allocated to S02 control only. The figure indicates
that the S02 control cost effectiveness does not have a significant dependence
on boiler capacity.
4.4.3 Cost Sensitivity Analysis
In Table 4.4-7 the individual components of the coal liquids-fired
boiler annualized costs are identified. This analysis is for the 58.6 MWT
SRC-I-fired boiler and the 8.8 and 58.6 MW EDS liquids-fired boilers.
The cost data presented for the coal liquefaction facilities and the
coal liquids-fired boilers do not include the cost of transporting coal from
the mine to the coal liquefaction facility or transporting the coal liquids
to the industrial boiler. In order to provide insight into the impact that
transportation costs could have, a rough cost sensitivity analysis was per-
formed. Two cases were examined for the 58.6 MW SRC-I-fired boiler and the
8.8 and 58.6 MWT EDS liquids-fired boilers:
4-53
-------
n
u
05
o
-------
£
o
4-1
O
O
-------
TABLE 4.4-7 COST SENSITIVITY - COAL LIQUIDS-FIRED BOILERS
Coal Liquefaction Process
Boiler Input Heat Rate, MWT
Labor and Maintenance
Utilities
Overhead
Capital Charges
Fuel
Labor & Maintenance
Coal
Other Operating Costs
Overhead
Capital Charges
Total Fuel
Total
8.8
18.0
2.4
7.1
9.1
10.1
15.1
2.8
3.7
31.7
63.4
100.0
EDS
58.6
Percent of Annualized
6.3
0.9
2.6
6.8
13.2
19.8
3.7
4.8
41.9
83.4
100.0
SRC-1
58.6
Costs
14.7
3.7
5.7
23.0
7.2
15.0
1.2
2.6
26.9
52.9
100.0
Total Annualized Boiler Costs,
103$/yr
1300
6580
6800
4-56
-------
1) Base case coal costs ($18.72/ton or $0.68/GJ) with
$0.50/GJ coal transportation costs added.
2) Minemouth coal costing $0.68/GJ with $0.50/GJ coal
transportation and liquefaction plant product trans-
portation of $0.50/GJ.
In order to make valid comparisons, annualized costs were also calculated
for direct coal-fired boilers using $1.18/GJ coal.
The results of the sensitivity analysis are presented in Table 4.4-8,
and illustrate the significant impact that transportation costs can have.
For example, the base case incremental costs for the 8.8 MW EDS liquids-fired
boiler ($18.72/ton coal, no transportation costs) are $40/kW_. However, for
the worst case examined, i.e., $1.18/GJ coal and $0.50/GJ product fuel trans-
portation costs, the incremental costs increase about 40 percent to $56/kW_,.
4.5 SUMMARY
Table 4.5-1 presents summary information concerning the three synfuel
technologies evaluated. All of the synfuel plant configurations are not
described. For example, the SRC-I-fired boiler data are not presented. Also,
only data for two boiler heat input rates (8.8 and 58.6 MW ) are presented.
The configurations presented are not intended to be "best cases" but rather
were selected for illustrative purposes.
In all of the systems studied, the capital-related charges and O&M
costs are the largest contributors to annualized costs. The coal cost is
the next largest contributor. Since a minemouth coal cost was used in the
study, the coal component could be much larger when a realistic delivered
cost (including coal transportation) is included in the analysis.
A brief characterization of each synfuel technology follows:
4-57
-------
TABLE 4.4-8.
EFFECT OF COAL AND PRODUCT TRANSPORTATION COST ON
ANNUALIZED COAL LIQUIDS-FIRED BOILER COSTS
•e^
i
Ui
00
Boiler
Heat
Input, ML
8.8
8.8
8.8
58. 6
58. 6
58.6
58.6
58. 6
S8.6
Process
EOS
EDS
EOS
EDS
EDS
EDS
SRC-1
SXC-1
SRC-1
Coel Cost
$/CJ
0.68
1.18
1.18
0.68
1.18
1.18
0.68
1.18
1.18
Coal Liquid
Cost, S/CJ
^.
5.
5.
4.
5.
5.
3.
3.
3.
95
82
82
95
82
82
25
93
93
Product Liquid*
Transportation Delivered Annualited Synfuel-Fired Anniullzed Coal-fired Incrnwntal Coet
Cost, S/GJ Cost, S/GJ Boiler Costs, 103$/ye«r Boiler Costs, 10]$/yr $/year $/KWT
». f*
— 5
0.50 6
— 4
__ 5
0.50 6
— 3
— ^ 1
0.50 4
.95
.82
.32
.95
.82
.32
.25
.93
,43
1300
1450
1530
6580
7550
8100
6800
7560
8110
950
1040
1040
4250
4S20
4820
4250
4820
4820
350
410
490
2330
2730
3280
2550
2740
3290
40
46
56
40
47
56
44
47
56
-------
TABLE 4.5-1. SYNFUEL ECONOMICS SUMMARY
I
ui
VD
Percent of Total Anmiallzed Boiler Costs3
Labor and
Maintenance15 lltilitiesc
Lou Sulfur Western C.o.il'1
Uncontrolled Coal-
Fired Boiler
8.8 MWT
58.6 MW?
Lou-Btu Gas-Fired
Boiler0
8.8 MW.r
58.6 MW.r
Medium-Bin (;as-Fired
Boilerf
8.8 MW.f
58.6 MWT
Hi£h_Suifur Eastern Coal^
Uncontrolled Conl-
Flred Boiler
8.8 MW
58.6 MW
Low-Btu Gas-Fired
Boiler0
8.8 MW
58.6 MWT
Mediim-Btu Gas-Fired
Boilcrf
8.8 MW.f
58.6 MWT
F.DS Liquids-Fired
Boiler
8.8 MU
58.6 MWT
53
34
15
10
27
9
52
33
14
8
22
7
25
8
.5
.9
.7
.9
.2
.9
.7
.9
.2
.9
.1
.5
.1
.9
6
8
1
1
2
1
6
7
1
0
2
0
2
0
.6
.6
.4
.1
.5
.0
.7
.7
.3
.9
.0
.6
.4
.9
Capital-
Related
Charges
33.1
46.4
5.
5.
10.
7.
28.
40.
4.
4.
8.
6.
9.
6.
,2
8
7
4
3
1
7
7
7
2
1
8
Fuel
Labor and
Maintenance1* Coal Other
6.8
10.1
32.8 4.
25.0 11.
11.4 9.
15.8 12.
12.
18.
31.0 6.
21.4 16.
9.9 15.
12.7 19.
13.8 15.
18.0 19.
,3 4.3
,3 12.2
2 (2.4)
7 (3.2)
3
3
9 6.9
5 16.8
0 1.3
2 1.6
1 2.8
8 3.7
Total
Capital- Annual i.'.ecl
Related Boiler Costs
rhargt'S 10' $/vear
980
4370
36.3 2100
33.6 5320
41.3 1210
56 . 5 5840
950
4250
34.9 2320
30.6 6530
40.9 1490
52.1 7770
31.7 1300
41.9 6580
Incremental Aiimi.'tl i zc
Boiler Costs (over
uncoil t ml 1 eO co.-il-fii
, boiler costs)
lO'" S/vnar $/kW
-
-
1120 127
950 if,
230 26
1470 25
-
-
1370 lr)f>
2280 39
540 61
3520 60
350 40
2330 40
rlTlie first three items refer to normalized cost associated with the
operation of the boiler only. The fuel item can be either coal or
synfuel and the various components are broken down accordingly.
Including overhead.
cIncludes utilities, solid waste disposal (where applicable),
watcr, chemicals.
Coal costs are $0.68/GJ and $0.40/GJ for high sulfur Eastern and low sulfur
Western, respectively. These are representative of minemouth costs.
Stret ford acid gas removal system.
Roctisol acid gas removal system.
-------
Low-Btu Gasification - This control technology is more cost effective
at the higher capacities evaluated. Higher coal costs (resulting from
including coal transportation costs) will tend to increase the incremental
annualized boiler costs (over uncontrolled coal-fired boiler costs).
Medium-Btu Gasification - This control technology exhibits fairly
constant incremental costs ($/kWT) as a function of boiler size. It should
be pointed out that coal and medium-Btu gas product transportation costs
have not been included in the evaluation and may significantly increase the
incremental costs.
Coal Liquefaction - This technology also exhibits fairly constant
incremental costs ($/kWT) as a function of boiler size. Again, coal and
liquids transportation costs have been excluded and could increase the
incremental costs substantially.
4-60
-------
References
4-1. Guthrie, Kenneth M. Process Plant Estimating Evaluation and Control.
Solana Beach, CA. Craftsman Book Co. 1974.
4-2. Peters, Max S., and Klause D. Timmerhaus. Plant Design and Economics
for Chemical Engineers. Second ed. New York, NY. McGraw-Hill. 1968.
4-3. Devitt, T., P. Spaite, and L. Gibbs. The Population and Characteris-
tics of Industrial/Commercial Boilers. EPA Contract No. 68-02-2603,
Task 19. Cincinnati, Ohio. PEDCo Environmental, Inc. May 1979.
4-4. Telephone communication between Radian Engineer W. C. Thomas and David
Noe of PEDCo Environmental, Inc. concerning various cost items for
gas- and coal-fired boilers. 31 May and 1 June 1979.
4-5. PEDCo Environmental Specialists, Inc. "Emission Control System
Economics." Section 3.0. Cincinnati, OH. October 1978.
4-6. Cavanaugh, E. C., W. E. Corbett and G. C. Page. Environmental Assess-
ment Data Base for Low/Medium-Btu Gasification Technology. Volumes I
& II. Final Report. EPA 600/7-77-125a and b, EPA Contract No. 68-02-
2147. Austin, TX. Radian Corporation. September 1977.
4-7 Telephone communication between Radian Engineer W. C. Thomas and Dale
Williams of J. F. Pritchard and Co. concerning costs for Stretford
Process. 30 May 1979.
4-8. Telephone communication between Radian Engineer P. J. Murin and Dale
Williams and Buzz Zey of J. F. Pritchard & Company concerning costs of
Stretford Systems. 30 October 1978.
4-9. Letter from Roger S. Leland of J. F. Pritchard & Company to Radian
Engineer T. G. Sipes concerning Stretford process. 25 July 1978.
4-10. Telephone communications between Radian Engineer P. J. Murin and Tom
Jones and "Hub" Wills of Perry Gas Company concerning costs of MEA acid
gas removal processes. 20 October 1978 through 2 November 1978.
4-11. Perry, Charles R. "Basic Design and Cost Data on MEA Treating Units."
In Proceedings of the 1967 Gas Conditioning Conference. University of
Oklahoma. Norman, OK.
4-12. Telephone communication between Ra'dian Engineer P. J. Murin and Ken
Braden of Ralph M. Parsons Company concerning costs for Glaus units
and tail gas treatment. 31 October 1978.
4-13. Telephone communication between Radian Engineer P. J. Murin and Jack
McNamera of Shell Development Company concerning costs for SCOT
process. 26 October 1978.
4-14. Dravo Corporation. Handbook of Gasifiers and Gas Treatment Systems.
Final Report. Task Assignment No. 4. Report No. FE-1772-11. ERDA
Contract No. E(49-18)-1772. Pittsburg, PA. Chemical Plants Division.
February 1976.
4-61
-------
4-15. Goar, Gene. "Impure Feeds Cause Glaus Plant Problems." In Hydrocarbon
Process. 53(7), 129-32. 1974.
4-16. Beavon, David K.., and Raoul P. Vaell. "The Beavon Sulfur Removal
Process for Purifying Glaus Plant Tail Gas." In American Petroleum
Institute Proceedings, Division of Refining, 1972. New York, NY.
p. 267. 1972.
4-17. Telephone communication between Radian Engineers W. C. Thomas and P. J.
Murin and Wallace Hamilton of McDowell Wellman concerning cost of the
Wellman-Galusha gasifier. 25 May 1979.
4-18. Telephone communication between Radian Engineer W. C. Thomas and Hugh
Campbell of EBECO Associates, Inc. concerning costs of coal handling
equipment for Wellman-Galusha gasifier. 29 May 1979
4-19. Telephone communication between Radian Engineer W. C. Thomas and Mike
Zolanzes of Research Cottrell concerning costs of detarrers. 30 May
1979.
4-20. Environmental Protection Agency. Process Design Manual for Suspended
Solids Removal. EPA 625/l-75-003a. January 1975.
4-21. Fair, James R. "Designing Direct-Contact Coolers/Condensers." In
Chem. Eng. 79(13), 91. 1972.
4-22. Fair, James R. "Process Heat Transfer by Direct Fluid-Phase Contact."
AIChE Symp. Ser. 68(118), 1-11. 1972.
4-23. Detman, Roger F. Factored Estimates for Western Coal Commercial
Concepts. Interim Report. Report No. FE-2240-5. Series No. IV: B-l.
ERDA Contract No. E(49-18)-2240. Alhambra, CA. C. F. Braun & Company.
October 1976.
4-24. Telephone communication between Radian Engineer P. J. Murin and Ted
Pollaert of American Lurgi Corporation concerning costs for Rectisol
process. 11 November 1978.
4-25. Telephone communication between Radian Engineer W. C. Thomas and Kim
Crawford of TRW concerning costs for Rectisol and Selexol processes.
13 November 1978.
4-26. Torstrick, R. L., L. J. Henson and S. V. Tomlinson. "Economic
Evaluation Techniques, Results, and Computer Modeling for Flue Gas
Desulfurization." Presented at the Flue Gas Desulfurization Symposium.
Hollywood, FL. November 1977.
4-27. Schmid, B. K., and D. M. Jackson, Gulf Mineral Resources Co. Recycle
SRC Processing for Liquid and Solid Fuels. Presented at the Fourth
Annual International Conference on Coal Gasification, Liquefaction and
Conversion to Electricity, University of Pittsburgh, Pittsburgh, PA.
August 2-4, 1977.
4-28. Exxon Research and Engineering Company. EDS Coal Liquefaction Process
Development, Phase III A. Interim Report. January 1978.
4-62
-------
4-29. Environmental Protection Agency. Compilation of Air Pollutant
Emission Factors, 2nd ed., with supplements. AP-42. Research
Triangle Park, NC. February 1972, April 1973, July 1974, January 1975,
December 1975, February 1976, April 1977.
4-63
-------
SECTION V
ENERGY IMPACTS OF SYNTHETIC FUELS FROM COAL SYSTEMS
"Best candidate" synthetic fuels from coal systems were selected in
Section 3 for detailed analysis of costs, energy, and environmental impacts.
The two low-Btu gasification systems selected were the Wellman-Galusha
gasifier with the Stretford and MEA acid gas removal (AGR) processes, while
the two medium-Btu systems were the Lurgi gasifier with the Stretford and
Rectisol AGR processes. The SRC-I and EDS systems were selected as the
"best candidate" coal liquefaction systems. The results of the cost impact
analyses were presented in Section 4.
Presented in this section are the energy impacts associated with using
the "best candidate" systems as precombustion emission controls for new
industrial boilers. Low-Btu coal gasification is addressed in Section 5.1
while Section 5.2 deals with medium-Btu gasification. Coal liquefaction is
addressed in Section 5.3.
The largest consumption of energy in the synthetic fuels from coal
processes is the inefficiency in the conversion process. Only 60-75 percent
of the energy content of the coal feed to the gasifier or liquefaction
reactor is converted into energy in the plant's major products.
In addition to the conversion inefficiency, the synthetic fuels
processes consume energy in the form of steam to drive pumps, compressors,
fans, etc. and to provide hydrogen for the liquefaction and gasification
5-1
-------
reactions. Electricity is also used to drive pumps, fans, agitators, etc.,
as well as to satisfy general lighting, cooling and heating needs. The
plant's steam and electricity requirements can be supplied by on-site
boilers or by importing these auxiliaries from an off-site source.
As mentioned previously, Standard International units are used in this
report. Therefore, megawatts and kilowatts are used for both thermal power
(denoted MWT or kVO and electrical power (denoted MW or kW ).
5.1 LOW-BTU COAL GASIFICATION
Energy consumption data for the low-Btu Wellman-Galusha gasifier and
its associated gas clean-up systems (see Figure 5.1-1) are given in Table
5.1-1. The energy consumed by a low-Btu gasification system is linearly
proportional to the plant's gas production rate. Therefore, in Table 5.1-1,
only a boiler heat input rate of 8.8 MW_ and the corresponding energy
consumption data for this boiler size are shown. Energy consumption data
for the other standard boiler capacities (22, 44, 58.6, and 117.2 MWT heat
input) can be calculated by multiplying the "% increase" value shown by
the desired boiler heat input rate. The results of these calculations
are shown in Figure 5.1-2.
For all of the cases examined, the estimated grain loading in the low-
Btu fuel gas is 0.01 g/m3 (4 grains/103 scf) (Ref. 5-1). This is equivalent
to around 2 ng/J (0.004 lb/106 Btu) in the combustion flue gases, which is
below the target particulate emission control level of 13 ng/J (0.03 lb/106
Btu). NOX emissions from combustion of low-Btu gas should be comparable
to those arising from combustion of natural gas - 50 to 100 ng NOX (as
N02)/J (0.12-0.23 lb/106 Btu). These emissions might be reduced to even
lower levels if combustion modifications are incorporated into the design
of the boiler. NOx emissions of 50 to 100 ng NOX/J represent a 55 to 87
percent reduction in the emissions from uncontrolled coal combustion
(230-400 ng/J). These levels are also in-line with the target NOX emission
5-2
-------
Ln
I
U)
Coal Feeder Vent Gases
Coal
Air and
Steam
Ash
Tar/Oil/Water
Separator
Tar/Oil
Low-Btu
Product Gas
Desulfurlzed Tall Ga
Elemental Sulfur
Excess Water to Disposal
Figure 5.1-1. Simplified flow diagram - Wellman-Galusha low-Btu gasification system.
-------
TABLE 5.1-1. ENERGY CONSUMPTION FOR WELLMAN-GALUSHA LOW-BTU GASIFICATION SYSTEMS
Input Heat Acid Gas S02 Emission Types
Rate to Boiler, Coal Removal Process and Control of Energy
MHT (10* Btu/hr)* Feed SO2 Control Level Efficiency, X Consumed
8.8 (10) Low Sulfur
8.8 (30) High Sulfur
8.8 (30) High Sulfur
*For other boiler heat rates, ei
Stretford
Stringent
Stretford
Moderate
MEA**
Moderate
Intermediate
Stringent
leriv consuned -
94.2
94.2
94.2
96.5
98.2
heat rate x X
Coal, Steam
Electricity
Coal, Steam
Electricity
("Coal, Elec-
jtrlcity. Steam
JLov-Btu Gas
X Increase In
Amount of Energy Energy Input to
Consulted Uncontrolled
HHT (10* Btu/hr) Coal-Fired Boiler
3.45
4.18
5.59
5.59
5.60
(11.8)
(U.3)
(19.1)
(19.1)
(19.1)
39.2
47.5
63.5
63.5
63.6
"Includes Claua to treat acid gag stream and SCOT to treat Glaus tall gas.
Stringent SO2 Control Level - 43 ng S02/J (0.1 lb/10' Btu)
Intermediate SOj Control Level - 86 ng S02/J (0.2 lb/105 Btu)
Moderate SO; Control Level - 150 ng SOj/J (0.35 lb/10* Btu)
All cases have estimated NO and particulate emissions of:
NO - 50-100 ng/J (0.12-0.23 lb/106 Btu)
Particulatea - <* ng/J (<0.01 lb/10c Btu)
-------
80-i
70-
60-
50-
a
o
S 40
o
60
c
30-
20-
10-
X High Sulfur Eastern Coal; MEA
0 High Sulfur Eastern Coal; Stretford
• Low Sulfur Western Coal; Stretford
0
30
60
90
Boiler Input Heat Rate, MW
120
Figure 5.1-2. Energy consumption of low-Btu gasification systems.
5-5
-------
control level (86 ng/J) (0.02 lb/106 Btu) being considered in this study
for the combustion of low-Btu gas in industrial boilers.
For the gasification of low sulfur coal, energy requirements were
calculated only for one SOa emission control level (corresponding to SOa
emissions slightly lower than the stringent control level of 43 ng SOa/J).
This emission level is achieved by using the Stretford process to remove
all but 10 ppmv of the HaS in the product gas. Because the HaS removal
reaction in the Stretford process is very fast, it may not be possible to
operate the process to achieve significantly less HaS removal (although
residuals of around 100 ppmv may be possible with a less efficient type of
contactor) (Ref. 5-2, 5-3).
For the high sulfur coal cases, the Wellman-Galusha gasifier with the
MEA acid gas removal process was examined for all three target SOa control
levels. However, the Wellman-Galusha/Stretford system was only examined
for the moderate control level. This is because of the high organic sulfur
content (predominantly COS) of the high sulfur coal-derived low-Btu gas.
Although the Stretford process is effective in removing HaS, it does not
remove COS (Ref. 5-4).
5.1.1 Comparison of Energy, Requirements
A more detailed breakdown of the gasification system energy consumption
data is shown in Table 5.1-2. A comparison of this information shows that
the inefficiency of the gasification system—conversion losses and energy
content of the by-product tars and oils—is the major energy consumption
in all of the systems. For the low and high sulfur coal cases using the
Stretford process, this represents almost 90 percent of the total energy
consumed. For the higher sulfur coal cases using the MEA process, conver-
sion inefficiency is still the major source (^65%) of energy consumption.
However, other major energy users are 1) the compressor used to compress
5-6
-------
TABLE 5.1-2.
DETAILED SUMMARY OF ENERGY CONSUMPTION FOR WELLMAN-GALUSHA
LOW-BTU GASIFICATION SYSTEMS
Ln
1
VJ
Source of
titiur^y Consumption
Conversion Losses
By-products
Uasii ier - Inlet Air
Blower and Jacket
Mater Pump
IJuench/Cooling
Fan
Pumps
Electrostatic Prccipitator
Condensate Evaporator
Acid Gas Removal
Gas Compressor
Steam
Electricity
Sulfur Recovery (Claus)
Electricity
Low Sulfur Coal
Stretford
High Sulfur Coal
Stretford MEA HEA MEA
(Moderate Control) (Moderate Control) (Stringent Control) (Intermediate
Type of 2 of Z of
Energy kW Product Cas kUT Product Gas kWT
Coal Feed 1020 U.6
Coal Feed 1960 22.3
Electricity* 110 1.2
Electricity* 130 1.5
Electricity* 60 0.7
Electricity* 20 0.2
Steam** 120 1.4
Electricity*
Steam**
Electricity* 30 0.3
Electricity*
Steam Steam**
Electricity Electricity*
Steam
Fuel Gas
TOTAL
Steau**
Fossil Fuel
3450 39.2
1970 22.4 1970
1690 19.2 1690
100 1.1 100
130 1.3 130
70 0.8 70
20 0.2 20
30 0.3 200
1080
430
170 2.0 <5
10
-180
10
40
20
4180 47.5 5590
Z of
Product Gas kH_
22.
19.
1.
1.
0.
0.
2.
12.
4.
<0.
0.
-2.
0.
0.
0.
63.
4
2
1
5
8
2
3
3
9
1
1
0
1
4
2
5
1970
1690
loo
130
70
20
200
1080
450
<5
10
-190
10
40
20
5600
Control)
Z of 2 of
Product Gas kW Product Gas
22.
19.
1.
1.
0.
0.
2.
12.
5.
<0.
0,
-2.
0.
0.
0.
63.
4
2
1
5
8
2
3
3
1
1
1
1
1
4
2
6
1970
1690
10O
130
70
20
200
1080
440
<5
10
-190
10
40
20
5590
22.
19.
1.
1.
0.
0.
2.
12.
5.
•-•o.
0.
-2.
0.
0.
4
2
1
5
6
2
3
3
0
1
1
1
1
4
0.2
63.
5
Basis: 8.8 MWT (30 x 106 Btu/hr) of low-Btu gas
* Electrical energy Is based on energy input to the generating source and an assuoed conversion efficiency to electricity of 34.1Z.
**Nt--t steam requirements are obtained from the Industrial boiler.
-------
the gas feed to the MEA unit to 0.28 MPa (40 psia) and 2) the steam used
to regenerate the MEA solution.
As indicated in Table 5.1-2, the Stretford process requires much less
energy than the MEA process. In fact, the quench/ cooling system requires
more energy than the Stretford process. Additional energy would be
consumed in the Stretford 'process if the sulfur were melted and purified,
but this would probably not be done for the small quantities of sulfur
recovered in the systems considered here. Additional energy would also be
required if a high temperature reduction process were used to treat the
Stretford liquor blowdown, but this also is not likely for the small sizes
considered in this study. Moreover, even with this increased energy
consumption, the gasification inefficiency would still by the major energy
consumer.
It should be noted that for the MEA cases the level of control of
emissions has a negligible impact on energy consumption. For both the
moderate and intermediate control levels, energy consumption equals 63.5
percent of the low-Btu gas energy. This increases to only 63.6 percent
for the stringent SOa control level.
5.1.2 Methods of Reducing Energy Consumption
Conversion losses and the energy content of the by-product tars and
oils represent by far the greatest energy losses in converting coal into
a low-Btu gaseous fuel. Thus, the greatest potential for reducing energy
consumption lies with these items. Conversion losses include:
Heat lost from the gasifier to the cooling jacket water
and the atmosphere,
Unreacted carbon in the gasifier ash,
• The sensible heat of the raw low-Btu gas, and
5-8
-------
The latent heat of the water vapor, tars, and oils in
the raw low-Btu gas.
Little can be done about heat lost to the cooling jacket water, but
fortunately this loss normally is very small.
The amount of unreacted carbon removed with the gasifier ash depends
on the operation of the gasifier and the coal feed characteristics.
Increasing the air flow to the gasifier helps to reduce the amount of carbon
in the ash by increasing the temperature of the fire zone. However, to
prevent slagging of the ash, the fire zone temperature must be kept below
the ash fusion temperature. The reactivity of the coal also influences the
amount of unreacted carbon in the ash. While gasifier ash from reactive
bituminous coals can contain as little as 10 percent carbon (Ref. 5-1),
gasifying unreactive anthracite coals can produce ashes containing over
30 percent carbon (Ref. 5-5). One means of reducing the amount of unreacted
carbon in the ash is to use a slagging gasifier.
The last two sources of conversion losses listed above deal with the
energy content of the gas that is lost as it is cooled prior to being
treated for sulfur removal. The conventional method of recovering this
type of energy is heat exchange to raise steam. However, this is normally
not practical unless there is a need for low pressure steam. The use of
waste heat boilers also encounters fouling problems from condensing tars
and oils. A potentially more promising alternative is to not cool the gas
at all, but to treat it for sulfur removal-at the temperature at which it
exists the gasifier. Unfortunately, acid gas removal processes capable of
this are not commercially available.
The second major source of energy consumption in low-Btu gasification
systems is the energy contained in the by-product tars and oils. As shown
in Table 5.1-2, this equals about 20 percent of the energy content of the
low-Btu product gas. While the tars and oils can be used as a fuel (Ref.
5-1), there are some practical considerations which may limit their use.
5-9
-------
First, the quantity of tars and oil produced is small. For an 8.8 MW,_
(30 x 106 Btu/hr) gasification facility using western coal, approximately
2000 kW (6.8 x 106 Btu/hr) of tars and oils are recovered. Site-specific
factors will determine whether this amount of fuel can be economically used.
Second, the tars and oils contain sulfur compounds which may restrict their
use as a combustion fuel. One analysis of the tars and oils produced by
gasifying a low sulfur bituminous coal indicated they contained 0.5 percent
sulfur (Ref. 5-1). Again, site-specific factors must be considered. In
order to illustrate the procedures used to calculate the energy impact data
shown in Table 5.1-2, an example calculation is presented in Appendix D.
5.2 MEDIUM-BTU COAL GASIFICATION
The medium-Btu coal gasification systems being considered in this study
as "best candidate" emission control systems for industrial boilers are the
Lurgi gasifier with the following acid gas removal/sulfur recovery processes.
1) Rectisol/Stretford,
2) Stretford (for both sulfur removal and recovery).
Energy consumption data for these systems are presented in Table 5.2-1. As
was true for low-Btu gasification, the energy consumed by a medium-Btu
gasification system is linearly proportional to the plant's gas production
rate. Therefore, in Table 5.2-1, only a standard boiler heat rate of 8.8
MW (30 x 106 Btu/hr) and the corresponding energy consumption data for this
boiler size are shown. Energy consumption data for the other standard boiler
heat rates, 22, 44, and 58.6 MW (75, 150, and 200 x 106 Btu/hr), or any
other boiler heat rate, can be calculated by multiplying the "percent
increase" value shown by the desired boiler heat rate. The results of these
calculations are plotted in Figure 5.2-1.
For both the low and high sulfur coal cases, energy requirements were
calculated for only one level of S02 emission control. For the Rectisol
case this corresponds to removal of H2S and COS to less than 10 ppmv.
5-10
-------
TABLE 5.2-1. ENERGY CONSUMPTION FOR LURGI MEDIUM-BTU GASIFICATION SYSTEMS
t_n
I
Input Heat Acid Gas SO2 Emission Types Amount of Energy * Increase in Energy
Rate to Boiler, Coal Removal Process and Control of Energy Consumed, Input to Uncontrolled
MWT(106 Btu/hr)* Feed S02 Control Level Efficiency, % Consumed MWT(106 Btu/hr)* Coal-Fired Boiler
8.8 (30)
8.8 (30)
8.8 (30)
8.8 (30)
Low Sulfur Stretford 93 Coal 6-°7 &9'°
Stringent
Low Sulfur Rectisol 99+ Coal 6.18 70.3
Stringent
High Sulfur Stretford 98 Coal 8.51 96.7
Intermediate
High Sulfur Rectisol 99"*" Coal 8.40 95-4
Stringent
* For other boiler heat rates, energy consumed = heat rate x % increase in energy use x 0.01.
Notes: Stringent S02 Control Level - 43 ng S02/J (0.1 lb/10s Btu)
Intermediate S02 Control Level - 86 ng S02/J (0.2 lb/106 Btu)
Rectisol systems include Stretford process for sulfur recovery.
All systems result in NO emissions estimated at 50-100 ng/.J (0.12-0.23 lb/106 Btu) and particulate emissions of
4 ng/J (0.01 lb/106 Btu).
-------
a
o
CO
a
o
o
00
M
V
w
60-,
50 -
40 -
30 -
20 -
10 -
• Low Sulfur Western Coal; Stretford
Low Sulfur Western Coal; Rectisol
V High Sulfur Eastern Coal; Stretford
QHigh Sulfur Eastern Coal; Rectisol
10
20
30
40
50
60
Input Heat Rate to Boiler, MW_
Figure 5.2-1. Energy consumption of medium-Btu gasification systems.
5-12
-------
For the Stretford cases, COS is not removed, but H2S is reduced to less than
10 ppmv. This was done because the medium-Btu plants examined here are
assumed to be large capacity installations, 3060 MWT (250 x 109 Btu/day),
that supply gas to many users. In order to pipe medium-Btu gas and avoid
corrosion problems, the H2S concentration of the gas must be below
approximately 10 ppmv (Ref. 5-6).
At total sulfur levels of less than 10 ppmv, all of the systems using
the Rectisol gas removal process produce a gas that can easily meet a
stringent S02 emission control level of 43 ng S02/J (0.1 Ib S02/106 Btu).
For the low sulfur coal case which uses the Stretford process for acid gas
removal, approximately 160 ppmv of sulfur compounds remain in the product
gas. Since this gas has a heating value of 11.6 MJ/m3 (313 Btu/scf), its
combustion will result in SOz emissions of less than 39 ng S02/J (0.09 Ib
S02/106 Btu) which is slightly below the stringent S02 emission control
level. For the high sulfur coal case using the Stretford process, higher
levels of COS increase the minimum residual sulfur level to 240 ppmv.
Based on a gas heating value of 10.7 MJ/m3 (287 Btu/scf), S02 emissions are
estimated at 60 ng S02/J (0.14 Ib SOa/106 Btu). This is greater than the
stringent S02 emission control level, but is less than the intermediate
control level of 86 ng S02/J (0.2 Ib S02/106 Btu).
• Particulate and NOx emissions from the combustion of medium-Btu gas
should be similar to those arising from the combustion of natural gas -
4.3 ng particulates/J (0.01 lb/106 Btu) and 50-100 ng NOX (as N02)/J
(0.12-0.23 lb/106 Btu). These levels compare favorably with the stringent
target emission levels of 13 ng particulates/J (0.03 lb/106 Btu) and 86 ng
NOX/J (0.2 lb/106 Btu).
5.2.1 Basis for Energy Consumption Data
A simplified flow diagram of a Lurgi-based medium-Btu gasification
system is shown in Figure 5.2-2. Energy balances for the candidate
5-13
-------
I
H1
*-
Alt t ^
) *
J
r- 1 f »
Coal J *
Oxygen
Production
°2
J_
Lurgl
Gaslflers
t
Recycle
\ '
fc Quench / f
Cooling
I
Ash
Coal
Preparation
f-g
. t
Auxiliary
Boiler
Tar/OH
Quench Liquor
Acid Gas
Renewal ....
^ L w _ . , . k MoiHi
•••*• f * Dehydration * _ '
«• ' Produ
Recovery -+• Demilfurized T«11 R»
^ Elemental Sulfur
^ Phenol ^ Aimnnla ^ Hlnlno-1 ml ^
Separation Removal Recovery Treatment
1 I 1
Tar/011 Phenoli Ammonia
— ». Stean and
Power to
— *. Process Areas
n-Btu
Treated Water
To Plant Water
System
Ash Scrubber
Sludge
Figure 5.2-2. Simplified flow scheme - Lurgi medium-Btu coal gasification system.
-------
gasification systems using the process configuration shown in this figure
were calculated from information presented in a conceptual commercial
process design of a Lurgi-based high-Btu gasification plant (Ref. 5-7).
In this design, all internal energy needs, i.e., steam and electricity, are
supplied by an on-site coal-fired boiler.
The following adjustments were made to the high-Btu plant conceptual
design in order to estimate the energy requirements of the candidate
medium-Btu system:
1) The energy requirements and credits of the shift conversion,
methanation and product gas compression steps were subtracted
from the plant's auxiliary energy requirements.
2) The energy required by the QZ production unit was adjusted
(by linear ratioing) to reflect any difference in the Oz
requirements of the candidate systems vs the conceptual
design.
3) Likewise, the auxiliary boiler load was adjusted to reflect
any difference in the quantity of gasifier steam required and
to reflect the absence of the methanation waste heat boiler
which supplied part of the gasifier steam in the high-Btu
plant design.
4) The energy required by the acid gas removal and sulfur
recovery units was adjusted to reflect the use of different
processes (Stretford or Rectisol).
5) A limestone flue gas desulfurization unit was used to
control SOz emissions (90 percent control) from the coal-
fired auxiliary boiler.
Estimates of the energy required by the Rectisol acid gas removal
process were based on information available for a similar application in a
proposed gasification plant (Ref. 5-8). In this plant, removal of 4.53
kg-moles C02/s and 0.0503 kg-r.oies H;S/t> irom a stream containing 32.36
percent C02 and 0.34 percent H2S had th? following energy requirements:
5-15
-------
Electricity = 8830 kW£
High Pressure Steam = 28.39 kg/s (225,140 Ib/hr)
Low Pressure Steam = 26.88 kg/s (213,180 Ib/hr)
Since the composition of the inlet gas for this application is similar to
the compositions of the two inlet gases being examined in this study, the
above energy consumption data were divided by the quantity of acid gas
removed. The resulting factors were then applied to the study cases
considered here.
• 1927 kW per kg-mole acid gas removed per second,
• 6.194 kg high pressure steam per kg-mole acid gas removed, and
• 5.865 kg low pressure steam per kg-mole acid gas removed.
For the Stretford process, energy requirements were calculated from
the following factors (Ref. 5-9).
Electricity
For sulfur recovery for Rectisol cases—
1.1 kW per kg sulfur removed per hour
For direct sulfur removal/recovery—
3.0 kW per kg sulfur removed per hour
Low Pressure Steam = 2.57 kg per kg sulfur removed
per hour.
5.2.2 Comparison of Energy Consumption
A more detailed breakdown of the energy consumption data in Table
5.2-1 is presented in Table 5.2-2. For the low sulfur coal cases, the data
indicate that gasification inefficiency, i.e., conversion losses and the
energy content of the by-products, equals almost 35 percent of the medium-
Btu product gas energy content. Stated from another viewpoint, only 70-75
percent of the energy content of the coal fed to the gasifier is converted
5-16
-------
Ln
I
TABLE 5.2-2. DETAILED SUMMARY OF ENERGY CONSUMPTION FOR
LURGI MEDIUM-BTU GASIFICATION SYSTEMS
Low Sulfur Coal Feed
High Sulfur Coal Feed
Stretford Rectisol/Strptford Stretford Rertis
2 of '/. of
MW Product G
-------
to energy in the product gas. The other major sources of energy consumption
are the oxygen production unit and gasifier steam (^24 percent of the
product gas energy), and miscellaneous process needs (^9 percent). Only
a small portion (1.3-2.3 percent) of the total energy needs are for the
sulfur removal and recovery units which depend on the amount of HaS
removed from the gas.
The same general trends hold for the high sulfur coal cases as for the
low sulfur cases. Sulfur removal and recovery account for only a small
portion of the total energy consumed, while gasification inefficiency,
oxygen production, and gasifier steam are the large energy users. Thus,
the energy impact of utilizing medium-Btu coal gasification as an SOa
emission control technique for industrial boilers has little dependence
on the level of SOz emission reduction achieved.
5.2.3 Methods of Reducing Energy Requirements
The most significant potential for reducing the energy requirements
of the medium-Btu gasification systems is use of the energy content of the
by-product tars, oils, and naphtha. The by-products represent 15-25
percent of the total energy consumed by the system. Burning these by-
products in the auxiliary boiler would reduce the coal feed to the boiler
by 25-45 percent.
Another large energy requirement is steam for the gasifier. This is
especially true for the high sulfur coal cases which, because of the
relatively low reactivity of bituminous coals, require large amounts of
steam. Use of a slagging type gasifier for the high sulfur eastern
(bituminous) coal case would help reduce the gasifier steam requirements.
5-18
-------
5.3 COAL LIQUEFACTION
Liquefaction systems employ various operations which are very similar
to those used in the petroleum refining industry. Some of these include
slurry mixing and preheating, high pressure hydrogenation reaction, vacuum
distillation, and gas compression. Each of these operations is highly
energy intensive. Pumps employed in the liquefaction process use electric
energy whereas preheaters burn the process derived low-Btu fuel gas or light
hydrocarbons which ultimately come from coal energy. Steam used as a
heating source is also obtained by burning part of the low-Btu fuel gas or
the liquid product in auxiliary boilers.
Electric power is mainly consumed by pumps, compressors, forced and
induced draft fans, agitators, pressure filters, centrifuges, coal pulver-
izers, and lock hoppers. Table 5.3-1 shows a partial list of major
electric power consuming equipment along with specific equipment functions.
In most cases, all electric power will be purchased from a local utility
company and the distribution system will be designed for high reliability.
Fuel gas is required for the slurry furnace, solvent hydrogenation
furnace, steam reformer furnace (if steam reforming is used for hydrogen
production), sulfur tail gas burner, and the off-site steam boiler. Low-
Btu gas or light hydrocarbons produced within the system are used as the
fuel source, although natural gas can also be used.
High, medium, and low-pressure (A.I, 2.05, and 0.9 MPa) steam is
required in the liquefaction system. Steam is generally used as an
indirect heating source for various liquids. In the liquefaction system
extensive heat integration, where high-temperature process streams are
cooled by passing boiler feed water through heat exchangers thereby
generating steam, has resulted in sufficient on-site steam generation.
Basically, off-site steam is required for a startup and emergency or
non-normal operating mode situation. As a result a very low off-site
5-19
-------
TABLE 5.3-1. MAJOR EQUIPMENT CONSUMING ELECTRIC POWER IN
COAL LIQUEFACTION SYSTEMS
Equipment
Function
Coal-handling equipment -
crushers, pulverizers
Slurry feed pump (P - 2425)
Solvent hydrogenation feed
pump (P - 1675)
Wash water booster pump
(P - 1265)
Air fin exchangers
Gas compressors
(P = 6.9-15.3 MPa)
Slurry agitator
Slurry preheater-furnace
draft fan
Fractionation column reflux
pumps
Fractionation column product-
oil transfer pumps
Prepared coal to the acceptable feed size
Pumps the slurry from slurry-mixing tank
to the reactor via preheater
Pumps the solvent through fixed bed
hydrotreater
Pumps the water for scrubbing the gases
such as HaS and
Condenses the vapor in condenser and used
as product coolers
Compresses either treated gas or inert
gas to the required pressures
Mixes the coal with recycled solvent in
the tank
Induces the combustion gases to generate
convection flow in the furnace for
efficient heat transfer
Returns the condensate from the condensate
drum to the f ractionation column
Transfers the recovered oil from the
fractionation towers to the downstream
processing units
steam base load (boiler plant) is required. In coal liquefaction plants,
off-site package boilers will be provided and will use low-Btu gas from
the gasification or flexicoking operations. Coal-fired boilers are not
used due to the low steam demand of the liquefaction plant and high invest-
ment requirements for coal handling equipment and flue gas desulfurization.
5-20
-------
The overall thermal efficiency of four liquefaction systems is given
in Table 5.3-2. Thermal efficiency is defined as the gross heating value
of all products, divided by the gross heating value of the feed coal plus
the coal equivalent of electricity. The conceptual design for SRC systems
(Ref. 5-1.0) and the EDS system (Ref. 5-11) assume the electric power to be
purchased from an outside utility. The H-Coal design (Ref. 5-1.2) assumes
on-site power generation. The thermal efficiency is higher for the SRC-I
system, primarily because of mild hydrogenation conditions in the reactor.
In this case, less hydrogen is consumed in converting coal to solid fuel.
In the other three liquefaction systems, mild to severe hydrogenation condi-
tions are required. Since there is an efficiency loss in gasifying
residual hydrocarbons to produce hydrogen, a high hydrogen requirement
implies at least some decrease in thermal efficiency.
TABLE 5.3-2. THERMAL EFFICIENCIES OF COAL LIQUEFACTION SYSTEMS
H-Coal
SRC-I SRC-II (Fuel-Oil Mode) EDS
Input
Coal: T/D (metric) 27,270 27,270 22,730 21,800
Electric Power: MW 86 41 184 175
Output
Pipeline Gas
LPG : m 3/D
Light Oil: m3/D
Fuel Oil: m 3/D
Solid Fuel: T/D
(metric)
Thermal Efficiency: %
1
. 1,225
2,490 2,480
10,090
13,970
71.6 70.3
-
1,270
8,155 3,490
2,470 4,730
-
67.74 63.3
Source: Ref. 5-10, 5-11, 5-12
5-21
-------
5.3.1 Discussion of Energy Consumption
The coal liquefaction systems being considered in this study as "best
candidate" emission controls for industrial boilers are the SRC-I and EDS
systems. Energy consumption data for those systems are summarized in
Table 5.3-3 for a 58.6 MWT (200 x 106 Btu/hr) industrial boiler. Energy
requirements for other size boilers can be calculated by multiplying the
"percentage increase" data by the desired boiler heat rate. The results of
these calculations are shown in Figure 5.3-1.
A more detailed breakdown of the energy consumed in the various
modules of the EDS system is presented and discussed in the following text.'
The energy consumption for the EDS system is based upon estimates
considering 21,818 metric tons per stream day of clean Illinois No. 6 coal
being fed to a mine mouth coal conversion plant designed to produce 9,539
cubic meters per stream day of Ca+ coal liquids. The conceptual design for
this system was prepared by Exxon Research and Engineering Company (Ref.
5-11), Florham Park, New Jersey.
Electric power requirements in various modules of the process are
shown in Table 5.3-4. The coal-slurry feed pump and the coal-slurry
mixing tank agitator in the liquefaction module, respectively, consume
1,482 kW and 1,016 kW of electric power. The solvent hydrogenation
(hydrotreating) module contains a reactor product feed pump, wash water
booster pump, low-sulfur fuel oil-product pump, naphtha pump, sour water
pump, and solvent-stripper bottoms pump. The total electric power consumed
by these pumps is 10,940 kW . In the flexicoking module the gas compressors
and the gasifier air blower are the major power consumers. Compressors
are the main power consuming equipment in the hydrogen generation module.
These compressors are used for processing the steam-reformed gas through
the cryogenic units. In the gas and water treating module, solvent-charge
pumps, ammonia product compressor, and transfer pumps in the phenol
5-22
-------
TABLE 5.3-3. ENERGY CONSUMPTION FOR COAL LIQUEFACTION SYSTEMS
I
N>
[(eat Input Coal Liquefaction
eo Boiler, Coal System and SOj
MWT(106 Btu/hr}* Feed Control Level
58.6 (200) High Sulfur SRC- 1
Moderate
58.6 (200) High Sulfur EDS
Intermediate
Stringent**
SOz Emission Types of Amount of
Control Energy Energy Consumed
Efficiency, % Consumed MWT(106 Btu/hr)*
77.1 Coal and 30.8 (105)
Electricity
97.0 Coal and 37.5 (128)
Electricity
99.0 Coal and 37.5 (128)**
Electricity
% Increase in Energy
Input to Uncontrolled
Coal-fired Boiler
52.2
64.0
64.0
* For other boiler heat rates, energy consumed = heat rate jc Z increase in energy use x 0.01.
** Increased sulfur control will not significantly increase energy consumption. Actual increase
could not be estimated.
-------
40 n
30 -
20 -
g
•H
CO
g
0
t>0
I 10
w
• - SRC-I
X - EDS
10 20 30 40
Input Heat Rate to Boiler, MW
50
60
Figure 5.3-1. Energy consumption in coal liquefaction systems.
5-24
-------
TABLE 5.3-4. ELECTRIC POWER REQUIREMENTS FOR EDS SYSTEM
Module Normal Operating Load, kW
Liquefaction 24,474
Solvent Hydrogenation 11,760
Flexicoking 44,452
Hydrogen Generation (Steam reforming) 72,438
Gas and Water Treating 5,832
Product Recovery 145
Total On-Site Operating Load 159,101
Total Off-Site (Auxiliary) Operating Load 14,300
Total Plant Operating Load 173,401
= 175
extraction unit require a combined operating load of 4,942 kW . The pumps
to transfer products such as ethane and butane that are recovered from the
cryogenic units do not consume much power. The off-site or auxiliary
operations include steam generation, raw water treating, boiler-feed water
treating, cooling water system, wastewater treatment and reuse system,
solids-waste disposal system, and coal handling and storage system. Total
off-site operating load is 14,300 kW , which is about 9 percent of the total
on-site operating load.
Table 5.3-5 shows heat equivalent of fuel gas consumption for the EDS
system. Although the fuel gas requirements are met by internally generated
low-Btu gas, the data in Table 5.3-5 are presented to indicate the points
of energy consumption in the EDS system. Total heat consumption (from
low-Btu gas with HHV of 127 Btu/scf) is about 1230 MWT (4200 x 106 Btu/hr) .
If this fuel gas energy is converted to equivalent of coal energy by
5-25
-------
TABLE 5.3-5. FUEL GAS* CONSUMPTION FOR EDS SYSTEM
Equipment Consumption, MW_ (10 Btu/hr)
Slurry Furnace 410 (1-400)
Solvent Hydrogenation Furnace 50 ( 170)
Sulfur Plant Burners 20 ( 70)
Steam Reformer Furnace 610 (2080)
Off-Site Boilers 140 (480)
TOTAL 1230 (4200)
* High Heating Value of Fuel Gas =4.74 MJ/m3 (127 Btu/scf)
assuming the coal heating value to be 29.1 MJ/kg (12,000 Btu/lb), then
about 158 metric tons/hr of coal will be required to provide the necessary
heat in the furnaces, sulfur burners and off-site boilers.
The conceptual design for the EDS system (Ref. 5-11) uses high
pressure (4.1 MPa) and low pressure (0.9 MPa) steam in the process. Table
5.3-6 shows the steam production and consumption rates for different process
modules. As for fuel gas needs, the steam requirements are supplied by
internal means. This includes waste heat recovery from process streams or
firing internally generated low-Btu gas in an auxiliary boiler. The numbers
in parentheses in Table 5.3-6 are steam production rates. Hydrogen
generation and flexicoking modules produce high pressure steam at a rate
of 265,800 and 86,200 kg/hr. Atmospheric and vacuum distillation columns
utilize high pressure steam at a rate of 377,000 kg/hr. The balance,
11,400 kg/hr of high pressure steam, is produced in off-site boilers. Also,
as shown in the table, liquefaction and flexicoking modules produce a
large amount of low pressure steam and only 55,600 kg/hr of low pressure
steam is produced in the off-site boilers.
5-26
-------
TABLE 5.3-6. STEAM REQUIREMENTS FOR EDS SYSTEM
Module
Liquefaction
Solvent Hydrogenation
Flexicoking
Hydrogen Generation (Steam
Gas and Water Treating
Product Recovery
Total On-Site Requirements
Steam Requirements,
4.1 MPa Steam 0.
(600 psig)
130,500
0
(39,000)
Reforming) (120,400)
0
(40,300)
11,400
* Kg/hr
9 MPa Steam
(125 psig)
(22,900)
53,700
(158,500)
52,100
105,500
300
55,600
* Numbers in parentheses show steam production rates.
5.3.2 Methods of Reducing Energy Consumption
The coal liquefaction systems considered here are still in the
development stage. As such, estimations of energy requirements are based
on pilot and demonstration plant data and conceptual commercial size
designs. Because of this, it is extremely difficult to evaluate the
potential for energy savings in these systems. However, when commercializa-
tion of these systems is realized, the facility's steam and fuel gas systems
will undoubtedly be optimized in order to effect the most energy efficient
operation.
5.4 SUMMARY OF ENERGY IMPACTS
All of the synthetic fuels from coal systems examined in this study
incur significant adverse energy impacts. Expressed as a percent of the
energy input to an equivalent size, uncontrolled coal-fired industrial
boiler, the energy consumption figures range from 40% to almost 100%. The
low-Btu gasification systems generally have the lowest energy impacts, 40-
65%, while the medium-Btu gasification systems have the highest, 70-100%.
The energy impacts of the coal liquefaction systems range from 50-65%.
5-27
-------
In all cases, the major portion of the energy consumed is attributable to
conversion losses and energy contained in by-products.
5-28
-------
References
5-1. Page, Gordon C. Environmental Assessment: Source Test and Evaluation
Report—Chapman Low-Btu Gasification, Final Report. DCN 78-200-143-81.
EPA-600/7-78-202. Radian Corporation, Austin, Texas. October 1978.
5-2. Telephone communication between T.G. Sipes (Radian Corp.) and John
Hemmingway (Woodall-Duckham USA) concerning Stretford Process - efflu-
ent treatment and decreased H2S removal. 24 August 1978.
5-3. Telephone communication between T.G. Sipes (Radian Corp.) and Buz Zey
and Dale Williams (J.F. Pritchard and Co.) concerning cost estimates
for Stretford process. 1 August 1978.
5-4. Cavanaugh, E.G., W.E. Corbett and G.C. Page. Environmental Assessment
Data Base for Low/Medium-Btu Gasification Technology, Volumes 1 & II,
Final Report. EPA 600/7-77-125a and b. DCN 77-200-143-26, Radian
Corporation, Austin, Texas. November 1977.
5-5. Thomas, W.C., K.N. Trede, and G.C. Page. Environmental Assessment:
Source Test and Evaluation Report - Wellman-Galusha (Glen Gery)
Low-Btu Gasification. Final Report. EPA Report No. 600/7-79-185,
EPA Contract No. 68-02-2147. Austin, TX. Radian Corporation.
August, 1979.
5-6. Telephone communication between E.P. Hamilton (Radian Corp.) and Al
Schlemmer (Texas Eastern Transmission Corp.) concerning permissible
residual sulfur levels in gases entering transmission pipelines.
13 October 1978.
5-7. Detman, Roger F. Factored Estimates for Western Coal Commercial
Concepts, Technical Appendix II, Engineered Equipment Descriptions,
Interim Report. Alhambra, CA. C. F. Braun & Co. October 1976.
5-8. El Paso Natural Gas Co. Application of El Paso Natural Gas Co. for a
Certificate of Public Convenience and Necessity. El Paso, TX. 1973.
5-9. Telephone communication between P.J. Murin (Radian Corp.) and Dale
Williams and Buz Zey (J.F. Pritchard and Co.) concerning costs of
Stretford process. 30 October 1978.
5-10. Schmid, B.K. and D.M. Jackson. Recycle SRC Processing for Liquid and
Solid Fuels. In: Paper presented at the Fourth Annual International
Conference on Coal Gasification, Liquefaction and Conversion to Elec-
tricity. August 2-4, 1977. Pittsburgh, PA.
5-11. Fant, B.T. Exxon Donor Solvent Coal Liquefaction Commercial Plant
Study Design. Prepared for U.S. Energy Research and Development
Administration by Exxon Research and Engineering Company. Florham
Park, NJ. January.
5-29
-------
5-12. Flour Engineers and Constructors, Inc. H-Coal Commercial Evaluation
Conceptual Design and Economic Analysers for 25,000 Tons Per Day
H-Coal Liquefaction Plant. Prepared for the U.S. Energy Research
and Development Administration. Washington, D.C.
5-30
-------
SECTION VI
ENVIRONMENTAL IMPACTS OF SYNTHETIC FUELS FROM COAL SYSTEMS
In previous sections of this report, the population of synthetic fuels
from coal systems were identified, evaluated, and compared in order to
select several "best candidate" systems for detailed analysis of cost,
energy, and environmental impacts. Costs and energy impacts were addressed
in Sections 4 and 5 respectively. Presented in this section are the
environmental impacts associated with using synthetic fuels from coal systems
as emission controls for industrial boilers.
The following text summarizes briefly the environmental impacts of
synfuels processes. Detailed information is presented in Sections 6.1,
6.2, and 6.3 for the "best candidate" low-Btu gasification, medium-Btu
gasification, and liquefaction systems respectively.
The synthetic fuels from coal processes being considered in this study
produce both beneficial and adverse environmental impacts. Beneficial
impacts include significant reductions in the emissions of SOa and particu-
lates from the industrial boiler (versus those ^rom direct coal combustion)
as well as reductions in the emissions of NOx, CO and hydrocarbons.
However, the beneficial impacts realized at the boiler are offset somewhat
by adverse impacts (or potential impacts) associated with producing the
synthetic fuels.
3-1
-------
For the low-Btu gasification systems, the major adverse impacts are
incinerated coal feeding gases, process condensate, and gasifier ash. As
coal is fed to the gasifier, raw product gas leaks past the coal feeding
mechanism. Incineration of the coal feeder vent gases produces NOx emissions
as well as S02 emissions from the sulfur species contained in the gas.
Fortunately, the flow rate of this stream is very small. A potentially more
hazardous impact is the process condensate stream generated when the raw
low-Btu gas is cooled. This stream contains dissolved organics, trace
elements, NHs, HzS, HCN and other components present in the product gas.
This stream in all likelihood cannot be discharged without treatment for
removal of these pollutants. Ash removed from the gasifier contains trace
elements (often in significant concentrations) and small amounts of organics.
If this material is landfilled, it may be necessary to take steps to prevent
leaching of the trace elements and organics from contaminating water sources
near the landfill.
The medium-Btu gasification systems also produce coal feeding gases
and solid wastes similar in nature to those from low-Btu systems. Liquid
discharges are eliminated though by using evaporators for final treatment
of the process condensate stream. However, the major adverse environmental
impact from medium-Btu systems is the flue gas from the coal-fired auxiliary
boiler. While particulates and SOz emissions are controlled by electrostatic
precipitators (99 percent control) and limestone scrubbers (90 percent con-
trol) , respectively, this stream is still the major source of air emissions
from the gasification plant.
For the coal liquefaction systems, the major adverse environmental
impacts are flue gases from process heaters (SOa, NOx, CO and particulates)
and process wastewaters (oil, phenols, HaS, NHs and dissolved solids).
6-2
-------
6.1 LOW-BTU GASIFICATION
Two low-Btu gasification systems are being considered in this study as
precombustion emission controls for industrial boilers. For low sulfur
coal, the Wellman-Galusha gasifier with the Stretford process for sulfur
removal and recovery is being examined. For high sulfur coal, the systems
examined are the Wellman-Galusha gasifier with the Stretford process and
the Wellman-Galusha with the MEA acid gas removal process followed by the
Glaus and SCOT processes for sulfur recovery.
Detailed discussions of the multimedia environmental impacts associated
with the use of these systems are presented in the following sections.
6.1.1 Air Pollution
Air emissions from both the production and combustion of low-Btu gas
derived from coal are summarized in Table 6.1-1. Also shown in this table
are the estimated uncontrolled air emissions from direct combustion of coal
in industrial boilers (Ref. 6-1). The emissions in Table 6.1-1 are
expressed in terms of weight of pollutant per unit of energy input to the
boiler. These data, which really are emission factors, are the same for all
boiler sizes considered in this report (8.8, 22, 44, 58.6, and 117.2 MWT
heat input). This is because the actual emissions rates are linearly pro-
portional to the boiler heat input. Actual emissions rates can be calculated
by multiplying the emission factors from Table 6.1-1 by the desired boiler
heat input rate.
6.1.1.1 Air Pollutants in Boiler Combustion Gases—
Particulate and NOX emissions in the boiler combustion gases are
estimated to be the same for all of the low-Btu fuel gases examined.
Because low-Btu gas contains negligible amounts of particulates, particulate
emissions are expected to be equal to or less than those from the combustion
6-3
-------
TABLE 6.1-1. AIR POLLUTION IMPACTS FROM "BEST CANDIDATE" LOW-BTU GASIFICATION SYSTEMSa
ON
System*
Coal
Feed
Low
sulfur
Low
sulfur
High
sulfur
High
sulfur
SOz
Control Level
(X Reduction)
Direct coal
combust Ion
(uncontrolled)
Strlngent(94.2)
Direct coal
combustion
(uncontrolled)
Moderate (94. 2)
Hoderate(94.2)
Intermediate
(96. 5)
Strlngent(98.2)
Sulfur
Spec lea
Enisslon Removal
Source Process
Combustion
gas
Combustion Stretford
gas
Gasification
system0
Combustion
gas
Combustion Stretford
gas
Gasification
systea0
Combustion MEAe
gas
Gasification
system41
Combustion ME A6
gas
Gasification
systea''
Combustion MEAe
gas
Gasification
system*1
SO,
ng/J (lb/10'Btu)
520 (1.2)
30 (O.D7)
1.9 (0.005)
2400 (5.7)
140 (0.32)
9.0 (0.02)
140 (0.32)
13 (<0.03)
86 (0.2)
13 (<0.03)
43 (0.1)
13 (<0.03)
ng/J
340-400
50-100
<0.4
280-330
50-100
<0.4
50-100
<0.4
50-100
<0.4
50-100
<0.4
telssloos
NOx
(lb/10'Btu)
(0.76-0.94)
(0.12-0.23)
(<0.001)
(0.64-0.76)
(0.12-0.23)
(<0.001)
(0.12-0.23)
(<0.001)
(0.12-0.23)
(<0.001)
(0.12-0.23)
(<0.001)
Other
Partlculates
ng/J (lb/10'Btu) Pollutant
600-1900 (1.4-4.5)
<4 (<0.01) Organic a
CO
Trace ele
Small Organlcs
CO
MB,
HCN
HzS
COS
950-3100 (2.2-7.2)
<4 (<0.01) Same as
Small Same as
<4 (<0.01) Same as
Small Same as
<4 (<0.01) Same as
Small Sane as
<4 (<0.01) Same as
Small Same as
Pollutants
Change from.
Uncontrolled
•ents
+
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
low sulfur
fWellman-Calusha gaslfier with the Indicated sulfur control processes.
•H- Increase; + slight Increase; — decrease; - slight decrease.
Tiajor emissions of SO;, HOx cane from Incinerated coal-feeder vent. Other emission sources are Incinerated start-up gases, fugitives, and Stretford
.ttxidlzer vent.
Tiajor emissions of SO2, NOx caae from Incinerated coal-feeder vent, with smaller amounts fron SCOT tall gas. other emission sources are Incinerated
atart-up gases and fugitives.
Including Claus and SCOT for acid gas treatment.
-------
of natural gas (4 ng/J or 0.009 lb/106 Btu). This represents a reduction of
greater than 99 percent from uncontrolled coal-fired boiler emissions. NOX
emissions are also estimated to be similar to those from natural gas com-
bustion (Ref. 6-2). This represents a reduction of 65-85 percent of uncon-
trolled coal-fired boiler NOX emissions.
Sulfur dioxide emissions for the low sulfur coal cases are estimated at
30 ng S02/J (0.07 lb/106 Btu) based on the quantities of residual sulfur
species in the synthetic gas. This is slightly below the stringent target
SOa control level of 43 ng/J (0.1 lb/106 Btu). This level also represents
greater than a 94 percent reduction of uncontrolled SOa emissions from coal-
fired boilers. For the high sulfur coal cases, use of the Stretford system
should result in SOa emission in the boiler flue gas around 140 ng S02/J
(0.32 lb/105 Btu), which is less than the moderate target SOa control level
of 150 ng/J (0.35 lb/106 Btu). The MEA system can be designed to achieve
all three control levels. The moderate, intermediate and stringent control
levels represent 94.2, 96.5 and 98.2 percent reduction, respectively, of the
uncontrolled emissions from direct coal-fired boilers.
As indicated in Table 6.1-1, organic (hydrocarbon) emissions from
combusting low-Btu gas are significantly lower and CO emissions are somewhat
lower than would arise from direct coal combustion (Ref. 6-1). Also,
emissions of trace elements may be somewhat lower. This is because many of
the trace elements found in the coal feed to the gasifier appear to be
concentrated in the particulates entrained in the raw low-Btu gas (Ref. 6-3).
Since these particulates are removed from the g,as prior to combustion, fewer
should be released to the atmosphere when the low-Btu gas is combusted.
6.1.1.2 Air Pollutants from the Gasification System—
In addition to the air emissions from the combustion of low-Btu gas,
various pollutants are emitted from the coal preparation, gasification, and
gas purification operations of the gasification system. These emissions
include:
6-5
-------
Incinerated coal feeding gases,
Incinerated start-up gases,
Stretford oxidizer vent gases,
Tail gases from SCOT unit on MEA process,
• Fugitive emissions, and
• Evaporator emissions.
The coal feeder gas stream is mainly product gas, somewhat diluted by
air, that escapes when coal is fed to the gasifier (Ref. 6-4). In most
installations, this stream will probably be incinerated so that the major
emissions from it will be small quantities of S02 and NOx. An alternative
to incineration is to recycle this stream to the gasifier inlet air or to
combine it with the product gas. Since this stream accounts for most of
the air emissions from the gasification system, recycling it would eliminate
most of the air emissions.
Another emission source is the low-quality gas produced during start-
up, shutdown, or unexpected upsets. This stream will probably be incin-
erated, resulting in small, intermittant emissions of SOz and NOx. The
quantity of these emissions cannot be estimated since they depend on the
frequency of startups and upsets.
The Stretford process uses an air-blown oxidizer to convert reduced ADA
back to its oxidized form. A large excess of air is used in the oxidizer
and released in the oxidizer vent. The vent stream will contain primarily
oxygen and nitrogen, along with water picked up from the solution. It also
has the potential to contain small amounts of ammonia and hydrocarbons. If
these components are present in the inlet gas, some will be absorbed by the
Stretford solution and released in the oxidizer (Ref. 6-5, 6-6).
Tail gas from the SCOT unit will contain small quantities of SOz and
HzS, with concentrations of less than 250 ppm SOz and 10 ppm HzS. Total SQZ
emissions would probably be less than 4.3 ng SOz per Joule of product gas
(0.01 lb/106 Btu) (Ref. 6-7).
6-6
-------
A vent stream from the tar/oil/water separator is a potential emission
source, but is recycled to the product gas in this system and thus con-
tributes no emissions.
Fugitive emissions from the gasification system include dust from coal
handling and storage, gases discharged during ash removal and leaks around
the gasifier pokeholes.
Fugitive dust from coal handling and storage consists mainly of coal
dust emitted at transfer points in the handling and storage operation. This
potential emission is similar to that encountered at coal-fired boilers
although its magnitude would be larger due to higher coal feed rates to the
gasifier. Applicable methods of control include water sprays, polymer
coatings, and collection in baghouses (Ref. 6-4).
Fugitive emissions from the removal of accumulated gasifier ash are
relatively small. They contain mainly steam and air, with traces of
particulates and volatile matter from the ash. No special control is
required.
Pokeholes are located on top of the gasifier to permit insertion of
rods to monitor the depth of the ash and fire zones. This procedure occurs
approximately once every four hours, with the rods being left in the
pokeholes for 1-2 minutes (Ref. 6-3). During this time raw product gas leaks
past the poke rods. These emissions are reduced and sometimes eliminated by
decreasing the gasifier inlet air flow rate during the poking operation.
This causes the gasifier to operate at slightly below atmospheric pressure,
resulting in air leaking into the gasifier through the pokeholes instead
of product gas leaking out. During the four hours between poking operations,
the pokeholes are covered with a flat metal slide. Leaks around the
pokehole cover occur. However, the magnitude of the leaks is dependent on
site-specific factors such as the gasifier operating pressure and more
importantly the physical condition of the slide pokehole cover, i.e., the
Tiaintenance practices of the plant.
6-7
-------
In the low-Btu gasification systems considered in this study, excess
process condensate is sent to a multiple effect evaporator for disposal.
This treating step will result in the discharge of volatile components
present in the process condensate. The quantities of these pollutants will
depend on the amount of condensate treated and the concentration of pollu-
tants in the condensate. No data are available on the quantities of pollu-
tants which may be discharged from the evaporator. However, data on the
composition of the process condensate are presented in the next section.
6.1.2 Water Pollution
Potential water effluents from Wellman-Galusha low-Btu gasification
facilities include:
• Coal storage runoff,
• Ash sluicing water,
• Process condensate, and
• Stretford process blowdown.
Some of these potential effluents contain large quantities of specific
pollutants (e.g., phenols) and cannot be discharged under the most stringent
federal and state effluent standards. Controls are available, however, to
reduce or eliminate the impact of these effluents.
The type and quantity of potential effluents from low-Btu gasification
facilities are summarized in Table 6.1-2. Effluent rates are reported in
ng/J of heat input to the boiler (lb/106 Btu), since effluent rates on this
basis are the same for any size gasification facility. Estimated water
quality parameters and compositions of the process condensate and Stretford
process blowdown streams are shown in Tables 6.1-3 through 6.1-5. Coal
storage runoff and ash sluicing water effluents are not characterized in
Tables 6.1-2 through 6.1-5. However, these streams are essentially similar
to those liquid wastes potentially discharged from coal-fired boilers,
6-8
-------
TABLE 6.1-2. WATER POLLUTION IMPACTS FROM "BEST CANDIDATE" LOW-BTU GASIFICATION SYSTEMS3
Effluent Generated
Coal Feed
Sulfur Species
Removal Level" Removal Process
Type
Quantity, ng/J
(lb/106 Btu)
Low Sulfur
94.2%
Stretford
• coal pile runoff
• ash sluicing water
• process condensate
• Stretford blowdown
not quantified0
not quantified
5600 (13)e'f
300 (0.7)f'g
High Sulfur
94.2 98.2% Stretford or MEA
94.2%
94.2-98.2%
Stretford
MEA
• coal pile runoff
• ash sluicing water
• process condensate
• Stretford blowdown
• process condensate
not quantified0
not quantified
1400
610
9100
(3.4)
(1.4)J
(21)
e,f
e,f
Wellman-Galusha gasification system.
Effluents are the same for moderate, intermediate and stringent control levels.
The quantity of water runoff from coal storage piles is largely site dependent; where coal is
stored in small quantities, covered bins are usually employed, resulting in no water runoff from
coal storage.
The quantity of water used for ash sluicing varies widely, depending on the practices of the indi-
vidual gasifier operators. The ash may be removed essentially dry, with the addition of little
water. As a worst case, 1 kg of water may be used per kg of ash removed. This results in ash
sluicing water of 3400-5600 ng/J (8-13 lb/106 Btu).
The quantities of process condensate depends on the water content of the coal feed, the desired
temperature of cooled product gas, and the pressure of the product gas. Systems featuring the MEA
process produce a gas at 280 kPa (40 psia). Values shown are the quantities of condensate sent to
on-site multiple effect evaporators. Residual wastes from the evaporators may be as little as 5%
of the values shown.
The estimated compositions of process condensate and Stretford blowdown are shown in Tables 6.1-3,
6.1-4, and 6.1-5.
Based on: complete conversion of HCN in feed gas to NaCNS; 2% conversion of H2S to
purge when salts concentration reaches 25% (Ref. 6-5, 6-8, 6-9).
-------
TABLE 6.1-3. WATER QUALITY PARAMETERS OF QUENCH LIQUOR FROM A CHAPMAN
FIXED-BED ATMOSPHERIC-PRESSURE GASIFIER3
Parameter
Value
Most Stringent Federal
or State Effluent
Standard0
Color (Pt-Co units)
Odor (Threshold No.)
PH
TDS (ppm)
TSS (ppm)
COD (ppm)
BOD (ppm)
DO (ppm)
Conductivity (umhos)
Alkalinity (as CaC03)(ppm)
Acidity
5,000
4,000
7.66
6,300
144*
5-10
15
125
30 mg/S,
a The process condensate from Wellman-Galusha gasification systems should
have water quality similar to that shown here for a Chapman-Wilputte
system.
k A water quality parameter is underlined once if it exceeds the most
stringent federal or state effluent standard by one order of magnitude or
less. A parameter underlined twice exceeds the standard by two or more
magnitudes.
In addition to water effluent standards, specific water quality criteria
apply to receiving waters. These include:
DO - - 5.0 mg/fc (probable average)
Odor Threshold Number - ^ 3.0 mg/& (probable average)
Alkalinity - 30-500 mg/£
Source: Ref. 6-10
6-10
-------
TABLE 6.1-4.
COMPOSITION OF QUENCH LIQUOR FROM A CHAPMAN
FIXED-BED ATMOSPHERIC-PRESSURE GASIFIER3
Estimated
Concentration
Constituent (mg/fc)
Aliphatic Hydrocarbons
Glycols, Epoxides
Carboxylic Acids and their
derivatives
Thiols
Phenols
Fused Aromatic Hydrocarbons and
their derivatives
Heterocyclic Nitrogen Compounds
Heterocyclic Sulfur Compounds
Antimony
Arsenic
Barium
Boron
Bromine (as Br~)
Cadmium
Cerium
Cesium
Calcium
Carbon
• carbonate
Chlorine
• chloride
Copper
Fluorine
• Fluoride
Iron
Iodine (as I~)
30
100
100
500
300b
100
500
50
0.07
0.8b
0.3
lb
0.3
0.005
0.003
0.001
20
2000
3000b
0.01
200b
J.
0.3
Most Stringent
Effluent Standards
(mg/i)
0.005
0.05
1.0
1.0
0.01
250
0.10
1
0.3
(Continued)
6-11
-------
TABLE 6.1-4. Continued
Constituent
Lanthanum
Lithium
Magnesium
Mercury
Nitrogen
• ammonia
• cyanide (alkali)
Niobium
Phosphorous
Potassium
Rubidium
Scandium
Selenium
Silicon
Silver
Strontium
Sulfur
• thiocyanate
• sulfide
• sulfate
Tin
Titanium
Tungsten
Yitrium
Zirconium
Estimated
Concentration
(mg/£)
0.007
0.003
2
' 0.0000003
jOOOb'c
j.OQOb>c
0.008
20
20
0.01
0.002
ib
2
0.002
0.08
<8
0.07
<10
1000b
0.03
0.1
0.02
0.005
0.01
Most Stringent
Effluent Standards
(mg/Jl)
0.002
2.5
0.02
1.0
0.01
0.05
600
a The process condensate from Wellman-Galusha gasification systems will have
composition similar to that shown here for a Chapman-Wilputte system. The
concentrations of sulfur species will be larger for systems using high-
sulfur coal feeds.
D A concentration is underlined once if it exceeds the most stringent federal
or state effluent standard by one order of magnitude or less. A concentra-
tion underlined twice exceeds the standard by two or more magnitudes.
c These concentrations include both free ions and complexes.
Source: Ref. 6-10
6-12
-------
TABLE 6.1-5. COMPOSITION OF SLOWDOWN FROM STRETFORD PROCESS3
Constituent ,
mg/&
NaHC03
Na2C03
NaV03
ADA
Iron
EDTA
Na2S203
NaCNS
Coal Feed
Low Sulfur
25,000
5,300
4,400
6,700
50b
2,700
45,000
173,000
High Sulfur
25,000
5,200
6,600
10,000
50b
2,700
120,000
90,000
a Based on: complete conversion of HCN in gas feed to NaCNS; 2% conversion
of H2S to Na2S203; and salts concentration of 25%. (Ref. 6-5, 6-8, 6-9).
Exceeds most stringent state or federal effluent standard.
-------
although the quantity of coal pile runoff could be larger due to the greater
coal feed requirements of gasification systems. The other streams are not
found at coal-fired boilers, and thus represent incremental discharge
potentially associated with low-Btu gasification facilities.
6.1.2.1 Coal Storage Runoff—
This potential effluent stream principally contains dissolved metals
and inorganics that have been leached from coal in uncovered storage piles
or bins. The quantity and composition of this stream are highly dependent
on the site of the gasification facility, and have not been estimated for
this study. A similar discharge stream exists at uncontrolled coal-fired
boilers.
Runoff from coal stored in uncovered bins can be eliminated by covering
the coal bins. Alternately, runoff from coal stored in uncovered bins or
in piles on the ground can be collected in ditches and subsequently used in
the gasification facility. Leaching of constituents from coal can be
reduced by coating the coal pile with a mixture of polymers (Ref. 6-4).
6.1.2.2 Ash Sluicing Water—
Ash sluice water is used to aid the removal of ash from the gasifier.
The quantity of water used for ash sluicing varies widely, depending on the
practices of individual gasifier operators. As a worst case, 1 kg of water
may be used per kg ash removed. If so, then the ash sluicing water would
amount to about 3400 ng/J (8 lb/106 Btu) for the low sulfur coal cases and
5600 ng/J (13 lb/106 Btu) for the high sulfur coal cases.
The ash sluice water principally contains dissolved metals and inor-
ganics that have been leached from the ash, but also contains some organic
compounds. The composition of the ash sluice water depends, of course, on
the characteristics of the gasifier ash. Important factors are the
6-14
-------
concentration of trace metals, unreacted coal, and the leachability of these
constituents. The only data presently available on ash sluice water compo-
sition are for gasifying anthracite coal. Those data indicate few compounds
are present in hazardous concentrations (Ref. 6-3). Generalizing these
results to other coal types is not warranted at this time.
If plant service water is used for ash sluicing, the sluice water may
be suitable for discharge into a public sewer. However, concentrations
of the various trace elements and other components (such as SCN~ and CN~)
in the sluice water may be too high to allow discharge to a sewer.
If the sluice water cannot be discharged, it can be drained from the
ash, collected, and recycled. The amount of sluice water that remains with
the disposed ash may provide a sufficient blowdown to prevent excessive
buildup of suspended or dissolved solids.
6.1.2.3 Process Condensate—
In cooling the raw low-Btu gas to the operating temperature and
pressures of the sulfur removal processes (44°C for both the MEA and
Stretford processes; essentially atmospheric pressure for the Stretford
process, 280 kPa for the MEA process), water is condensed and subsequently
removed from the gas quenching and cooling system. This condensate contains
many of the constituents of the low-Btu gas, including nitrogen species
i _
(such as NHif and CN ) , particulates (which are relatively rich in trace
elements), organics (including phenols,' thiols, and polynuclear aromatic
hydrocarbons), and dissolved gases. In tests conducted at a gasification
facility with a gas quench/cooling system similar to the one being examined
in this study, bioassay tests showed the process condensate to have a low
degree of hazard for health effects, and a high degree of hazard for
ecological effects (judged primarily from toxicity to aquatic life) (Ref.
6-10).
6-15
-------
The size of the process condensate waste stream depends on the
temperature and water content of the low-Btu gas, the temperature to which
the gas is to be cooled, and the operating pressure of the sulfur removal
process. The composition of the process condensate depends primarily on
the composition of the raw low-Btu gas.
Tables 6.1-3 and 6.1-4 contain data describing the quality and composi-
tion of process condensate from a gasification facility using a low-sulfur
coal feed. Higher concentrations of sulfur species would probably be found
in the condensate from a facility using high-sulfur coal. As shown in
these tables, the process condensate contains numerous constituents in
concentrations exceeding the most stringent federal and state standards for
effluent discharge. Those constituents include organics (such as phenols)
and inorganics (such as arsenic, boron, chloride, fluoride, iron, ammonia,
cyanide, phosphorous, selenium, and sulfate). The organic fraction contains
a relatively large amount of polycyclic aromatic hydrocarbons, many of which
are potential carcinogens.
Due to the high concentrations of organics and inorganics, this stream
cannot be discharged directly to a sewer or receiving water. No similar
type of potential waste stream exists at coal-fired boilers. Methods for
disposal of this waste principally include:
• Evaporation,
• Containment for treatment and ultimate disposal off-site, and
• Incineration.
The selection of disposal method depends on the size and location of the
gasification facility, and on the availability of waste treatment facilities
near the gasification plant. For small gasifiers, the quantity of process
condensate is too small to justify the construction of new on-site treatment
facilities. If the industrial complex in which the gasifier is located
already contains a central waste treatment plant, the process condensate
6-16
-------
could be treated there. Alternately, the condensate could be contained
on-site with subsequent shipment to a large hazardous waste treatment plant
located off-site. Treatment at off-site waste treatment facilities would
include destruction or recovery of organics and the neutralization or
recovery of inorganics. Ultimate disposal at the off-site facility would
include evaporation or incineration of aqueous wastes, and ponding of waste
sludges (Ref. 6-4).
Even in the larger plants considered in this study, the quantity of
waste generated probably does not justify the construction of complete
waste treatment facilities on-site. Again, the preferred disposal practice
depends on the availability of waste treatment facilities near the
gasification plant.
Evaporation and incineration control methods could be used for partial
treatment of the process condensate waste stream. However, each control
method has residual multimedia emissions. Evaporation effectively reduces
the size of the liquid waste stream but emissions will result from the
volatile components from the liquor. Non-volatile components remain with the
aqueous or solid residual and require treatment and/or ultimate disposal.
Incineration of the condensate waste stream, either in a process waste
incinerator or in a large boiler or heater located on-site, destroys the
hazardous organics contained in the waste. However, other hazardous com-
ponent? are volatilized and released with the incinerated gases. Residual
wastes require treatment and/or ultimate disposal. In this study, excess
process condensate is reduced to an estimated 5 percent of its original
volume by forced evaporation.
6.1.2.4 Stretford Process Slowdown—
The Stretford process blowdown is another waste stream not found at
coal-fired boilers. Its approximate compositions for the systems examined
in this study are shown in Table 6.1-5.
6-17
-------
The blowdown is required to remove nonregenerable compounds formed by
the reaction of HCN to form thiocyanates and by the oxidation of hydrogen
sulfide to thiosulfate. The major factors affecting the size of the blow-
down stream are the HCN concentration in the feed gas and the rate of
thiosulfate formation. Other factors include the degree of washing of the
by-product sulfur cake and the total salts concentration in the solution.
The Stretford processes operating with the gasification systems in this
study produce only a partially washed sulfur cake. This reduces the
blowdown rate somewhat, since some nonregenerable compounds exit the system
with the sulfur cake.
The principal pollutants found in the Stretford blowdown are thiosulfate
and thiocyanate. Specific standards for the discharge of these pollutants
do not exist.
In the past, the liquid blowdown from the Stretford process was
discharged directly to municipal sewers. Due to the high concentrations of
thiocyanate and thiosulfate ions, however, the stream probably cannot now be
discharged without treatment. Schemes proposed to treat Stretford blowdown
include:
• Treatment and discharge,
• Regeneration, and
Pretreatment to reduce size.
Processes involving treatment and discharge of the blowdown include biode-
gradation, evaporation, and combustion. These processes all require ultimate
disposal of a waste stream. They also decompose the absorbing solutions, so
that makeup chemicals must be added to the Stretford process.
In regeneration processes, blowdown is treated and returned to the
system. The requirement for ultimate disposal of a waste stream is
eliminated, and chemical makeup requirements are reduced.
6-18
-------
The blowdown stream can be reduced in size by removing HCN from the gas
before the Stretford absorber. Aqueous wastes from pretreatment contain
high concentrations of thiocyanate, sorbent, ammonia, and sulfur species
and require further treatment before discharge.
For small installations, the quantity of blowdown is of course very
small. For small quantities of waste, the preferred treatment option is to
send the blowdown to existing wastewater treatment facilities, if they are
available at the gasification site. Alternately, the blowdown can be
contained and subsequently shipped to large hazardous waste treatment plants
located off-site. The blowdown could also be disposed of with the gasifier
ash or sulfur cake; however, the subsequent potential for water pollution
from the disposal of ash or sulfur may be unacceptable. For large
installations, regeneration of the blowdown at high temperature may be the
most desirable treatment method.
6.1.3 Solid Waste
Solid wastes generated by the Wellman-Galusha gasification systems
include gasifier ash, cyclone dust, and sulfur cake from the Stretford
process and pure sulfur and MEA blowdown from the MEA process. Production
rates of these wastes are reported in Table 6.1-6. The production rates are
reported in ng/J (lb/106 Btu), since the rates on this basis are the same for
any size gasification facility. As shown in this table, the amount of
gasifier ash generated increases with increasing coal ash content, while
sulfur production increases with increasing coal sulfur content and with
increased sulfur removal efficiency.
Solid waste production is considerably higher for the gasification and
purification system than for an uncontrolled coal-fired boiler. The quantity
of gasifier ash produced is about 100 to 700 percent greater than the
bottom ash from a coal-fired boiler, mainly because of the higher coal
throughput required for the gasification system and also because some of the
6-19
-------
TABLE 6.1-6. SOLID WASTE IMPACTS FROM "BEST CANDIDATE" LOW-BTU GASIFICATION SYSTEMS
I
NO
Coal Feed
Low sulfur
Low sulfur
High sulfur
High sulfur
S02 Removal Level
(Control Efficiency, %)
Direct Coal Combustion
(Uncontrolled)
lb (94.2)
Direct Coal Combustion
(Uncontrolled)
Moderate {94.2)
Intermediate (96.5)
Stringent (98.2)
Moderate (94.2)
Solid Waste Generated
Acid das
Removal Process Type
Bottom ash
> 1
Stretford Gasifier ash
Cyclone dust
Sulfur cake
Bottom ash
MEAC Gasifier ash
Cyclone dust
Sulfur
MEA blowdown
c d
MEA Sulfur
MEA blowdown
MEAC Sulfur
MEA blowdown
Stretford Sulfur cake
ng/J (lb/106 Btu)
473-1810
3760
420
508
775-2880
6540
367
1650
116
1680
116
1690
116
3300
(1.1-4.2)
(8.73)
(.977)
(1.18)
(1.8-6.7)
(15.2)
(.853)
(3.83)
(0.27)
(3.90)
(0.27)
(3.93)
(0.27)
(7.67)
fWellman-Galusha gasification system.
The same system is used for moderate, intermediate, or stringent.
^Including Claus to treat acid gas; SCOT to treat tail gas.
Ash and dust are the same for all 3 control levels.
-------
coal ash evolves as fly ash during combustion, while most of it appears as
gasifier ash in gasification. Cyclone dust and sulfur cake are additional
solid waste products from the gasification system not produced from coal-
fired boilers.
With the exception of the sulfur produced from the MEA/Claus system,
all the solid wastes listed in Table 6.1-6 contain trace elements or other
possibly hazardous compounds that could be leachable. The gasifier ash
contains a variety of trace elements. Some of them, including Be, B, CO,
Cr, Cu, Ge, Mn, Mo, Ni, U, and V appear to be concentrated in the ash
compared to their concentrations in the coal, while other elements are
volatilized in the gasification process and thus are depleted in the
gasifier ash (Ref. 6-3). Tests conducted on ash from an anthracite-fired
gasifier have indicated low levels of trace elements in the leachate
(Ref. 6-3), but more data are required on leaching characteristics of ashes
produced from gasification of bituminous coals. Because of the presence of
trace elements and other possibly hazardous compounds, the gasifier ash
may be classified as a hazardous toxic waste according to the Resource
Conservation and Recovery Act (RCRA).
The cyclone dust is mostly carbon, but also contains various trace
elements that may be leachable. Leaching tests conducted on cyclone dust
from an anthracite-fired gasifier indicated fairly low levels of most trace
elements in the leachate, although levels of selenium and manganese may
exceed standards (Ref. 6-3). Like the ash, the cyclone dust may be classi-
fied as a hazardous toxic waste under RCRA. Because of its high carbon
content, it could also be classified as a hazardous "ignitable" waste.
6-21
-------
Sulfur recovered from the MEA tail gas by a Glaus unit is relatively
pure. It could possibly be marketed as a by-product, but marketing may be
difficult because of the small quantity produced. If not sold, the pure
sulfur could be disposed of by landfill. Sulfur produced by the Stretford
process is a wet cake containing about 50 percent water, with around 4
percent total dissolved solids (Ref. 6-5). This cake contains chemicals
from the Stretford solution that may be leachable from the sulfur cake. The
amount of these chemicals in the cake depends on the degree and effectiveness
of cake washing. This sulfur cake could be autoclaved and further purified
to produce pure molten sulfur suitable for sale, but the small quantities
produced in the systems considered in this study would probably make this
purification economically unattractive.
The MEA blowdown consists of various compounds resulting from degrada-
tion of the solution. These include dithiocarbamates, thioureas, salts of
thiosulfuric acid and formic acid, oxazolidone-2,l-(2-hydroxyethyl)
imidazolidone-2 and N-(2-hydroxyethyl)~ethylenediamine (Ref. 6-9). This
blowdown will probably be classified as toxic.
The gasifier ash and sulfur cake (and possibly the cyclone dust) can
be disposed of by landfill, with steps taken to prevent surface and ground
water contamination from water runoff and leachate. If these wastes are
declared to be toxic, practices for disposal of a toxic waste set forth in
the RCRA will have to be followed. The MEA blowdown can also be landfilled
following RCRA practices for disposal of a toxic waste. Methods that may
be used to prevent surface and ground water contamination include the use
of landfill sealants, or leachate collection systems, or interception of
subsurface flow by placement of grouted slurry-trench cutoffs and/or drains
upstream of the entire area of the landfill (Ref. 6-11).
6-22
-------
The gasifier ash which has undergone fixation with lime may be made
more structurally stable and resistant to leaching. Ashes with a sufficient
amount of calcium and alkalinity may self-stabilize into a structurally
sound, low permeability material. Ash from most bituminous coals (such as
the high sulfur coal) is generally low in calcium and alkalinity and does
not stabilize without lime addition. Ash from subbituminous coal generally
achieves marginal self-stabilization so that lime addition may not be
required for the ash from the low-sulfur coal. These generalizations,
however, are derived from characteristics of ash from direct coal combustion.
Gasifier ash has a higher organic content and possibly a different particle
size distribution than combustion ash, and may have different stabilization
characteristics.
The cyclone dust, as noted earlier, consists mostly of carbon. It can
be incinerated, rather than being landfilled. In fact, under the require-
ments of the RCRA, landfill of the dust may not be allowed if it is classi-
fied as a hazardous "ignitable" waste. Even if landfill is allowed,
burning the dust and taking advantage of its heating value would be more
environmentally acceptable.
As noted earlier, the sulfur cake from the Stretford process can be
autoclaved to produce a pure sulfur product. Although this may not be
economically attractive if only the potential value of the sulfur is
considered, it would at least produce a more environmentally acceptable
waste product.
6.1.4 Other Environmental Impacts
Other potential environmental impacts of low-Btu gasification systems
include noise, thermal pollution, electrical discharge, and radioactive
emissions. However, no data are available on these potential impacts.
6-23
-------
6.2 MEDIUM-BTU COAL GASIFICATION
The medium-Btu gasification systems being considered as precombustion
emission controls for industrial boilers are the Lurgi gasifier with the
Stretford or Rectisol acid gas removal process. Plants using these systems
are assumed to be centrally located in an industrial region and are capable
of producing the energy equivalent of 3060 MW™ (250 x 109 Btu/day) of
medium-Btu gas. Industrial boiler users would receive (via pipeline) only
a portion of the plant's output. Since the emissions from the gasification
plant can be prorated according to the plant output, the environmental
impact data presented in the following sections are expressed as weight .of
pollutant per unit of gas energy. Emissions associated with a given
industrial boiler can be calculated from the data by multiplying by the
boiler input heat rate.
6.2.1 Air Pollution
Air emissions generated during the production of medium-Btu gas are
summarized in Table 6.2-1 along with estimates of the emissions resulting
from combustion of the medium-Btu gas and from direct combustion of coal.
NOx and particulate emissions from the combustion of medium-Btu gas are
estimated to be similar to those from combustion of natural gas - 50-100 ng
NOx/J (0.12-0.23 lb/106 Btu) and 4 ng particulates/J (0.01 lb/106 Btu)
(Ref. 6-1, 6-2). This represents greater than 99 percent control of
particulate emissions and 60-85 percent control of NOx emissions (versus
those from direct coal combustion). Sulfur dioxide emissions are reduced
by greater than 99 percent (to 2 ng/J or 0.005 lb/106 Btu) by the Rectisol
process for both the low and high sulfur cases. For the Stretford systems,
93 percent (37 ng/J or 0.04 lb/106 Btu) and 98 percent (60 ng/J or 0.14
lb/106 Btu) S02 control are achieved for the low and high sulfur coal cases,
respectively.
6-24
-------
TABLE 6.2-1. SUMMARY OF AIR POLLUTION IMPACTS FOR LURGI MEDIUM-BTU GASIFICATION SYSTEMS
I
NJ
Ul
Coal
Feed
Low
sulfur
Low
sulfur
Low
sulfur
High
sulfur
High
sulfur
High
sulfur
S0j Control Level
(7. Reduction)
Direct coal
combustion
(uncontrolled)
Stringent
(93)
.
Stringent
(99+)
Direct coal
combustion
(uncontrolled)
Intermediate
(98)
Stringent
(99+)
Emission Source
Industrial
boiler flue gas
Industrial
boiler flue gas
Gasification
system
Auxiliary
boiler
Industrial
boiler flue gas
Gasification
system
Stretford
tall gas
Auxiliary
boiler
Industrial
boiler flue gas
Industrial
boiler flue gas
Gasification
system
Auxiliary
boiler
Industrial
boiler flue gas
Gasification
system
Stretford
tall gas
Auxiliary
boiler
Sulfur Species
Removal/Recovery
Process ng/J
520
Stretford 37
17
Rectlsol/ 2
Stretford
36
18
2450
Stretford 60
138
Rectlsol/ 2
Stretford
60
142
Emissions
S02 NOx Partlculates Other Pollutants
Change from
(lb/10s Btu) ng/J (lb/106 Btu) ng/J (lb/106 Btu) Pollutant uncontrolled*
(1.2) 340-400 (0.78-0.94) 600-1900 (1.4-4.5)
(0.09) 50-100 (0.12-0.23) 4 (0.01) Organics
CO
Trace elements
Organics +
CO +
(0.040) 137 (0.32) 6 (0.015) NHj +
HCN +
HzS +
COS +
(0.004) 50-100 (0.12-0.23) 4 (0.01) Same as Above
(0.083)
(0.043) 146 (0.34) 7 (0.016)
(5.7) 275-330 (0.64-0.76) 950-3100 (2.2-7.2)
(0.14) 50-100 (0.12-0.23) 4 (0.01)
Same as Above
(0.32) 180 (0.42) 17 (0.040)
(0.004) 50-100 (0.12-0.23) 4 (0.01)
Same as Above
(0.14)
(0.33) 194 (0.45) 18 (0.042)
* ++ increase; + slight Increase; — decrease; - slight decrease.
-------
The major sources of air pollution from the medium-Btu gasification
systems are the auxiliary boilers, plus for the Rectisol systems, the
incinerated sulfur recovery (Stretford) vent gases. The auxiliary boilers
are coal-fired, and include an electrostatic precipitator for control of
particulates (99 percent removal) and a limestone flue gas desulfurization
unit for control of SOa emissions (90 percent removal). Per unit of energy
input to the auxiliary boiler, the controlled boiler emissions are
(Ref. 6-1).
Low Sulfur High Sulfur
Coal Cases Coal Cases
S02, ng/J (lb/106 Btu) 52 (0.12) 245 (0.57)
Particulates, ng/J (lb/106 Btu) 19 (0.045) 31 (0.072)
NOx, ng/J (lb/106 Btu) 405 (0.94) 327 (0.76)
The emission rates shown in Table 6.2-1 were calculated by multiplying the
above data by the auxiliary boiler heat duties and dividing by the energy
content of the medium-Btu product gas. As shown in Table 6.2-1, emissions
from the Stretford systems are lower than those for the Rectisol systems.
This is a reflection of the lower auxiliary energy requirements of the
Stretford systems.
A second major source of air emissions from the systems using the
Rectisol acid gas removal process and the Stretford process for sulfur
recovery is the Stretford tail gas. The Stretford process can remove HaS
to below 10 ppmv; however, it is not effective in removing organic sulfur
compounds such as COS (Ref. 6-9). Thus, all of the COS removed by the
Rectisol process and sent to the Stretford process remains in the treated
•
gas. This vent stream is incinerated using a clean fuel (or alternately
it could be injected into the auxiliary boiler).
6-26
-------
Other air emissions from the Lurgi medium-Btu gasification systems
include:
• Hydrocarbons from the by-product storage tanks,
• Waste nitrogen from the oxygen production unit,
Cooling tower vapors,
Sulfur recovery (Stretford) oxidizer vent gases,
• Coal and ash hopper vent gases,
• Evaporator emissions, and
• Fugitive dust.
Table 6.2-2 summarizes the available information on the magnitude of these
emissions. A brief discussion of each of these minor emissions is presented
in the following text.
Emissions from the by-product storage tanks result from tank breathing,
leaks, spills, and venting of tanks during filling and emptying. If control
of these emissions is required to meet environmental requirements, vapor
recovery systems are available which can achieve greater than 90 percent
control (Ref. 6-13).
The waste nitrogen stream from the oxygen production unit will not
present any environmental problems, since it is predominantly NZ with only
a small amount of
The quantity of pollutants in the cooling tower vapors cannot be
quantified. However, since treated gas quench water is used as makeup to
the cooling tower, the potential exists for residual amounts of NHa , HaS,
and hydrocarbons contained in the makeup to be stripped out in the cooling
towers.
6-27
-------
TABLE 6.2-2. SUMMARY OF MINOR EMISSIONS FROM LURGI
MEDIUM-BTU GASIFICATION SYSTEMS3
Contaminant Emission
ng/J Product Gas
Source • Contaminants (lb/106 Btu)
By-Product Tank Vents Hydrocarbons 0.45 (0.001)
NH3 0.06 (0.0001)
Waste Nitrogen
Cooling Towers NHs, HaS trace
Hydrocarbons
Stretford Oxidizer Vent NH3, HCN, COS, not quantified
Hydrocarbons
Lock Hopper Vents H2S 0.45 (0.001)b
CO 26 (0.06)
Hydrocarbons 9 (0.02)
Evaporator H2S, NHs, not quantified
Hydrocarbons
Fugitive Dust Coal Dust 4 (0.01)
emissions are for all gasification systems considered and for both coal
.feeds.
Emissions are for a low sulfur coal feed; emissions will be higher for high
sulfur coal feeds.
Source: Ref. 6-5, 6-6, 6-12
6-28
-------
The Stretford oxidizer vent stream may contain ammonia and hydrocarbons.
If these components are present in the inlet gas to the Stretford unit, some
will be absorbed by the Stretford solution and subsequently be stripped out
in the oxidizer (Ref. 6-5, 6-6). Again, however, the amounts of these
pollutants cannot be quantified.
The Lurgi process uses lock hoppers for feeding coal into the pressured
gasifier. In this study, the lock hoppers are pressurized with cooled
product gas. After the coal charge is dropped into the gasifier, the hopper
is depressurized to slightly above atmospheric pressure. The gas released
during depressurization is collected in a lock gas holding vessel for
subsequent recycle. However, when a fresh charge of coal is added to the
lock hopper, it displaces the residual lock filling gases (Ref. 6-12).
An evaporator is included as a final treatment for the liquid wastes
generated in the Lurgi systems considered in this study. The feed to the
evaporator includes treated gas quench water which may contain residual
amounts of NHa, foS and hydrocarbons. While the amounts of these
pollutants which may be vaporized and discharged to the atmosphere cannot
be quantified, the potential does exist for their discharge.
Fugitive dust emissions arise from the coal crushing, grinding,
conveying, etc., steps in the coal preparation operation. These emissions
are controlled by installing water sprays with wetting agents at coal trans-
fer points. Additional control could be achieved, if necessary for health
or environmental reasons, by enclosing the dust sources and venting the
area to a particulate collection device (Ref. 6-12).
6.2.2 Water Pollution
The major liquid effluents from the medium-Btu gasification systems
considered here include:
6-29
-------
• Condensate removed from the raw medium-Btu gas in the
quench/cooling steps, and
• Blowdown from the plant's cooling water system.
However, in the conceptual commercial design upon which the systems in this
study were based, liquid effluents were eliminated by recycle and reuse with-
in the system and by use of evaporators for final treatment (Ref. 6-14).
This feature of the conceptual design was retained in the medium-Btu systems
in light of the requirements of the Water Pollution Control Act Amendments of
1972 which call for zero liquid discharge by 1985. Thus, there are no
liquid effluents from the medium-Btu gasification systems.
6.2.3 Solid Wastes
Solid wastes generated by the Lurgi medium-Btu gasification systems
include:
• Gasifier ash,
• Auxiliary boiler ash,
Sludge from the boiler FGD unit,
• Sludge from the biological oxidation pond,
• Concentrated wastes from the wastewater evaporators, and
• Water treatment sludge.
Production rates of these wastes are shown in Table 6.2-3, in terms of
weight of solid waste per Joule of product gas. By comparison, bottom ash
from an industrial boiler is approximately 10-40 percent of these values.
This is mainly because of the higher coal feed rates to the gasifier, the
extra coal required by the auxiliary boiler and the fact that some of the
ash content of the coal is released as fly ash during combustion while most
of it is removed as gasifier ash in gasification systems.
6-30
-------
TABLE 6.2-3. SUMMARY OF SOLID WASTES FROM LURGI MEDIUM-BTU GASIFICATION SYSTEMS
Sulfur Removal Unit
Solid Waste, kg/s
Gasifier Ash
Auxiliary Boiler Ash
FGD Sludge
Biopond Sludge
Wastewater Evaporator
Residue
Water Treatment Sludge
Total, kg/s
Total, yg/J Product Gas
Total Ash Input to Direct
Coal Fired Industrial
Boiler, yg/J
Low Sulfur
Stretford
10.4
2.5
3.2
0.4
0.2
<0.1
16.7
5.5
2.4
Coal Feed
Rectisol
10.4
2.5
3.5
0.4
0.2
<0.1
17.0
5.6
2.4
High Sulfur
Stretford
17.0
6.6
25.6
0.4
0.2
<0.1
49.8
16.3
3.8
Coal Feed
Rectisol
17.0
6.9
26.9
0.4
0.2
<0.1
51.4
16.8
3.8
Basis: 3060 MWT (250 x 109 Btu/day) medium-Btu gas.
Source: Engineering calculations, Ref. 6-1, 6-14
-------
All of the solid wastes contain trace elements, many of which may be
present in significant concentrations (Ref. 6-15, 6-16). In addition, the
gasifier ash contains approximately 5 percent unreacted coal (Ref. 6-17).
If these wastes are ponded or landfilled, as is current practice with many
solid wastes (Ref. 6-11), precautions may be necessary to prevent contami-
nation of both surface and ground waters from solid waste leachate (Ref.
6-11, 6-15). Methods currently available include use of landfill sealants,
leachate collection systems, or interception of subsurface flow by placement
of grouted slurry-trench cutoffs and/or drains upstream of the entire
landfill area (Ref. 6-11).
6.2.4 Other Environmental Impacts
Other potential environmental impacts of medium-Btu gasification systems
include noise, thermal pollution, electrical discharges and radioactive
emissions. However, no data are available on the levels of these potential
impacts.
6.3 COAL LIQUEFACTION
The environmental impacts of coal liquefaction facilities may be
generally classified into three problem areas: 1) pollutant releases; 2)
physical disturbances; and 3) plant construction, operation, and decommis-
sion. These problem areas are generally common to all four liquefaction
systems (SRC-I, SRC-II, H-Coal, EDS) discussed in previous sections.
6.3.1 Pollutant Releases
A generalized flow chart of pollutant releases is presented in Figure
6.3-1. The types of emissions can be divided into air or gaseous con-
taminants, aqueous contaminants, and solid wastes. Also, the emission
could be either continuous or intermittent. Continuous emissions are defined
as those released during normal on-stream operation, whereas intermittent
6-32
-------
REDUCED E
MISSIONS. SO , NO
& PARTICULARS
REDUCED
AMMONIA, FUGITIVE
HYDROCARBONS,
REDUCED CYANIDE,
SOX, NOX, C02
PARTICULATES
EMISSIONS
EMISSIONS
EMISSION
CONTROL
COAL
WATER
ENCRUSTING AGENTS,
Z)
o
cc. —
LU H-
>• ac.
ae <
O Q.
(COAL STORAGE
AND PREPARATION
WASH, PULVERIZE
SEPARATION,
_DRYJ_NG.
LANDFILL
COAL
\
SULFUR
FUGITIVE HYDROCARBONS
FROM PUMPS, FLANGES,
VALVES, LEAKS, VENTS
EMISSION
CONTROL
SULFUR
EMOVAL
UGE"!
SLUDGE",=
W™
COAL
DUST
H2 AGENT
SLUDGE
AND DUST
TO LANDFILL
VASTEUATER
LEACHATES'
icVcHATr
o—
ocz
o<
LIQUEFACTION
PROCESS AND
FUEL
PREPARATION
'REATMENT
DISCHARGE
THROUGH
OIFFUSER
ASH
LANDFILL
'-LEACHATES
GAS AND OIL PRODUCTS
(LAND AND WATER)
Figure 6.3-1. Pollutant releases from coal liquefaction system.
-------
emissions are defined as those released during startup, shutdown, operating
upsets, etc. The potential for release of hazardous chemicals, either
continuously or intermittently, is one of the major environmental and
safety considerations associated with coal liquefaction.
Expected rates and concentrations for air and water emissions along with
expected solid waste rates for a specific liquefaction system will depend
upon the size of the plant, the type of feed coal, and the final product
characteristics desired. The EDS system is considered here since the
conceptual environmental data for this system is readily available (Ref.
6-18), and it also represents a complex liquefaction system. The rates for
air and water emissions, and solid wastes as given in the following sections,
are based upon the EDS commercial plant study design for a plant producing
about 9,540 m3/SD of liquid products from 21,920 metric tons/SD of Illinois
No. 6 coal. Although no attempt was made to quantify emissions release
rates where insufficient process information was available, an attempt was
made to at least identify all probable emission sources. Additional emission
sources may be identified, however, as a result of further work and refine-
ment of the EDS process.
6.3.1.1 Air Pollution—
Gaseous contaminants produced in a coal liquefaction facility which
could have a detrimental impact on air quality include: hydrogen sulfide,
ammonia, particulate matter (e.g., coal dust and process fines), hydro-
carbons, sulfur dioxide, hydrogen cyanide, and small amounts of nitrogen
oxides, polycyclic hydrocarbons, and heavy metals. Air emissions from the
EDS process are summarized in Table 6.3-1. The greatest uncertainty with
regard to those emissions is in the coal receipt, storage, and preparation
area. The coal unloading, conveying, and crushing operations along with
the coal storage piles are all potential sources of fugitive dust. Although
6-34
-------
TABLE 6.3-1. ESTIMATED AIR EMISSIONS FROM THE EDS LIQUEFACTION PROCESS
Source of Emission
SO;
kg/hr (vppn)
EnUston Rates and Concentrations
CO
kg/hr (vppn)
NOy Hydrocarbon* Partlculatea
kg/hr (vppra) kg/hr kg/hr (vppm)
CONTINUOUS SQUKCES OF EMISSIONS
Coal storage •n
-------
the quantity of these fine particulate emissions is not known with
certainty, several steps were taken in the study design to minimize these
emissions. Water sprays were provided at the track hopper pit to suppress
the dusting resulting from bottom-dumping of coal from railroad cars. Water
sprays are also utilized at the outlets of the coal crushers. The inclined
conveyor belts from the crushers to the feed distributing bins are housed
in a completely enclosed gallery with emissions controlled by baghouse
filters. Each transfer point along the covered conveyor belts also has a
baghouse filter to remove particulates and dust.
The dry fines from the flexicoker are pneumatically conveyed to
off-site mixing tanks. These dry fines are removed in a venturi scrubber
prior to releasing the carrier air to the atmosphere. A very small but
undetermined amount of dry fines is emitted to the atmosphere along with
this air. It appears, however, that an improved processing scheme may be
possible in which all the ash fines are collected in a water slurry at the
flexicoker. Although not evaluated as part of the study design, this
scheme may eliminate the potential dry fines emissions from the venturi
scrubber while also reducing plant investment. Therefore, the emission of
dry fines to the atmosphere is not likely to be a problem.
Conventional pollution control systems are provided to remove sulfur
from the gas streams. An HzS removal unit removes HjS from the low-Btu
fuel gas coming from the flexicoker. The remaining gas streams are scrubbed
with DEA for HaS and COz removal. The rich DBA from on-site gas treating
is fed to DEA regeneration, where HzS and COa are stripped, combined with
the HaS and COz from sour water stripping, and fed to a sulfur plant. The
sulfur plant converts about 95 percent of the feed sulfur to elemental
sulfur. Tail gas from the sulfur plant is fed to a tail gas cleanup unit
which recovers additional sulfur product. This combination of units
provides for the recovery of 99.9 percent of the sulfur plant feed sulfur.
The tail gas cleanup unit reduces S02 emissions to about 100 vppm,
6-36
-------
equivalent to new source standards for sulfur plants. There are three 50
percent sulfur plants and two 50 percent tail gas cleanup units specified
in the study design. In the event that one of the tail gas cleanup units
is down, 50 percent of the sulfur plant tail gas is burned in its incinera-
tor, and the SOz emissions increase to about 8,000 vppm.
Continuous sulfur degasification facilities were included with the
sulfur plant sulfur pits. The gases evolving from the molten sulfur, mostly
HzS, are purged with nitrogen and sent to the sulfur plant tail gas
incinerator for combustion. This results in SOa emissions of about 1,000
vppm. However, this concentration represents an S02 emission rate of less
than 13.6 kg/hr, which is about 1.5 percent of the total plant 862
emissions. The purpose of degasifying the sulfur product is to reduce the
H2S emissions during loading operations and thus reduce the risk of health
hazards to personnel and odor nuisance. As an alternative to combusting the
sulfur pit purge gas, it may be possible to compress it and send it to the
tail gas cleanup unit for disposal. However, the scope of the work done in
the study design did not permit a detailed study of this alternative. It is
expected that this or some other alternative will be available as routine
practice in sulfur plants in the mid-1980's.
The off-site steam boilers were designed to fire low-Btu gas as a base
fuel and low sulfur fuel oil (LSFO) as a supplemental fuel when required.
If the firing of LSFO in these boilers proves to be unacceptable from an
SOa and NOy emissions standpoint, Cs LPG can be substituted as the supple-
mentary fuel.
6.3.1.2 Water Pollution—
Aqueous contaminants in the waste effluents which have broad temperature
and pH ranges may include materials such as suspended particulates, ammonia,
hydrogen sulfide, toxic trace metals, phenols, aromatic hydrocarbons,
6-37
-------
thiophenes, aromatic amines, and other organic compounds. A diagram of the
wastewater treatment system for the EDS liquefaction plant is shown in
Figure 6.3-2. A summary of the aqueous wastes from this plant is given in
Tables 6.3-2 and 6.3-3. Also shown are the miscellaneous waste streams and
applicable disposition methods.
The wastewaters from the EDS process include sour and non-sour phenolic
streams. Sour water from the various EDS process blocks is combined and
fed to the sour water stripping unit. The HaS and C02 are stripped from the
sour water and sent to the sulfur plant. Ammonia is recovered as a product
in the anhydrous form. The stripped water from sour water treating is
combined with the non-sour phenolic water stream coming from the slurry
drier and is sent to the phenol extraction plant. This unit extracts and
recovers crude phonols as a product. The effluent water along with water
from the API separator is sent to the off-site wastewater equalization tank.
The equalization tank serves to dampen fluctuations in wastewater composi-
tion. The API separator handles the HaS removal unit solution purge, C02
removal unit solution losses, and various non-sour water streams. The
total plant wastewater is drawn from the equalization tank and treated via
dissolved air flotation, biological oxidation, filtration, and activated
carbon. Treatment with activated carbon was included in the study design
based on the assumption that the technology required to apply it will be
fully available at the time it is needed for the design of a commercial EDS
plant. About 15 percent of the treated wastewater is reused as cooling
tower makeup, with the remainder being discharged.
The H2S removal unit solution purge stream may present some water
treating problems due to the chemical nature of this solution which contains
vanadium, thiosulfates, and anthraquinone disulfonic acid (ADA). Separate
treatment of this solution may be required to reduce the effluent chemical
oxygen demand (COD) due to thiosulfate. Although thiosulfate is readily
oxidized in a biological treatment unit, the optimum reaction occurs at low
6-38
-------
(jJ
VO
SOllOT *f*RI«C, wMI"
f ONSITE WASTC "J
1 mJLTIW UMirt j * "
'o SW* UATEM STMIPfEIIS j
•
;;"• . ui. «T£« '•"
POTAILE .J« TMUAC, '*•"** autKIIOH
""" "^ DHAyOFF ""j
I'" K' I '°-*U 1 API CCOALI-.
• • UPAM.I1>> ' • mi°" '
INTCWIITTEHT
J COOLIHC WAttH SrSTEH '
fUArouniw 1 '•» COOLINt • SIDE ST«Ah [ If
AND WINOACE ' , ™«« '"•"« ' J
L - 10 _ _i
COOL IHC TOUCH j J MUSED UASTEVAIEI
•Lduoom ^ 8
}.l HILE* ILOWOUI
AAV }},( SOrTEHINC '*•* OCN'MEMi- tl.fc |
1.H 1 ' ).1* | i l.ll
.)«
.-.H 101IM •"
DEROIIU
NOTES;
t FLOWS AtC III •'/"!«
1 SOLIDS HEHOVAl EQUIPHENT
| 0 SLIMir DKUnS *»D PunPS
' 0 SLUHIH 'IPELINE TO IACOO
I" WASTE TKEAT SOLIDS "\
1 CONCCNTMTlNt '
1 0 THICIUMEII 1
j a cuvirr »SLI FILTH J
L 1
«'•' "•'. „„, _'•« r,lT..T.». »-«. f"'"1"
190
WO.TAHINATEO CHEticAl
KIN UATEA T«AT
j.e
LOSSES
1 1 t
..T(VB . STCAH ^ COMSUHCH^
*"M1 CEMIATIM ^^ iu-»un.
'
"\ SLUR It
(. | HATE.
fl
1 SOLIDS DISPOSAL
1 TD LAGOON
'— HtAK MHC
0* HEAnar
THEATFO
ItUKf
I PLANI 1
~~TEFTLUEKT|
i.it
Figure 6.3-2. EDS commercial plant study design water systems coordination flow plan.
-------
TABLE 6.3-2. AQUEOUS WASTES FROM OFF-SITE WASTEWATER TREATING FACILITIES
OF THE COMMERCIAL EDS LIQUEFACTION PLANT
Facilities
Contaminants
Effluent
Cone., ppm
Contaminant Rates
cr>
J.
o
API Separator Total plant effluent
water rate » 26.5
Equalization unit m3/min (average,
including estimated
Neutralization unit rainwater and a
capacity contingency)
Dissolved air
flotation
Biological
oxidation
Filtration
Activated carbon
Sludge treatment
Oil 5
Phenols 1
Hydrogen sulfide 1
Ammonia 10
BOD . 10
COD 50-100
Suspended solids 10
Dissolved solids 3200
Biological sludge
9.1 kg/hr (0.57 ng/J)
1.8 kg/hr (0.096 ng/J)
1.8 kg/hr (0.096 ng/J)
" 16 kg/hr (0.95' ng/J)
16 kg/hr (0.95 ng/J)
121.5 T/D (303 ng/J)
7.2 T/D (18 ng/J)
-------
TABLE 6.3-3. AQUEOUS WASTES FROM MISCELLANEOUS WASTE STREAMS
OF THE COMMERCIAL EDS LIQUEFACTION PLANT
Waste Stream
Rate
or Quantity
Frequency
Disposition
Spent caustic
Sour water treating
LPG prewash tower
Extraction/
regeneration
HaS removal unit
solution purge
Disulfide Oil
CO2 removal unit
solution losses
0.015 m3/min Continuous
11.3 m3/min
33.9 m3/min
Once per week
Once every 3
months
0.015 tn3/min Continuous
0.001 mVmin Continuous
0.001 m3/min Continuous
Wastewater treating following
neutralization/sour water stripping/
phenol extraction
Wastewater treating (API separator)
Flexicoker reactor
Wastewater treating (API separator)
DEA system purge
378 m3
Once per year Scavenger/contract hauler
-------
pH. Since the biox unit must be operated at a pH of 7 to 9 to remove
organic compounds, thiosulfate may not be readily removed. If separate
HaS removal unit solution treatment is required, this may be done via
acidification with sulfuric acid which converts the sodium thiosulfate to
sulfate and allows for the recovery of ADA and vanadium.
6.3.1.3 Solid Wastes—
Solid wastes generated by coal liquefaction systems consist primarily
of ash and refuse removed from coal and sludges, and solids recovered from
waste treatment processes. Spent catalysts produced intermittently may be
regenerated on-site, which could generate secondary air pollutants. Also,
the disposal of solid wastes may produce fugitive dusts or leachates
resulting from reaction of trace elements and ground water.
Solid wastes from the EDS process include digested biological sludge
from the biological oxidation unit, oily sludge from the API separator and
dissolved air flotation unit, ash from the flexicoker, and solids removed
from the boiler feedwater cold lime-treating-unit blowdown. In addition,
spent catalysts are disposed of on an intermittent basis. The rates of
solid wastes including the catalysts to be disposed of are shown in Table
6.3-4.
Sludges from the wastewater treating facilities (API and DAF units)
are thickened and then concentrated in a gravity belt filter. The sludge
is then loaded onto trucks and disposed of in a land farming operation
outside the plant limits. The digested biological sludge should be
suitable for use in revegetating the mine tailings area and should not
create any odor problems.
6-42
-------
TABLE 6.3-4. SOLID WASTES FROM EDS SYSTEM
Continuous Source Emission
Solids from Flexicoker
Solvent hydrogenation reactors - catalyst
Solvent hydrogenation feed filters gravel
Hz plant hydro treaters - catalyst
Ha plant zinc oxide reactors - catalyst
Hz plant steam reformers - catalyst
Hz plant high temperature shift reactors -
catalyst
Hz plant low temperature shift reactors -
catalyst
Hz plant methanator reactors - catalyst
Hz plant carbon treater - activated carbon
Sulfur plant converters - catalyst
Tail gas cleanup hydrogenation reactors -
Solid Waste,
Metric Tons/Day
2500a
b
135
86
216
135
144
270
126
7
162
22
Expected Frequency
Variable
Once every 4 years
Once every 2 years
Once every 4 years
Once every 2 years
Once every 2 years
Once every 4 years
Once every 3 months
Once every 2 years
Once every 2 years
catalyst
Alumina driers
Off-site steam boilers (0.2 GJ/hr)
Wastewater treating facilities -
activated carbon
Liquefaction slurry preheat furnace -
decoking
Sulfur plant incinerator:
Fuel gas combustion
Tail gas combustion
Flare, safety valve discharges
Process vents
14
68
Once every 2 years
When Flexicoker is down
Once every 3 months
When one tail gas
cleanup unit is down
Variable
Variable
Flexicoker solids are sent to a settling pond which has a 5-year capacity.
It is anticipated that the catalyst from solvent hydrogenation and activated carbon
from the wastewater treating facilities may be returned to the manufacturer for
regeneration. If either is regenerated on-site, this would represent an additional
source of emissions to the atmosphere.
6-43
-------
The ash removed from the flexicoker low-Btu product gas is slurried
with water and pumped to an above-ground lagoon for disposal. This lagoon
is located about one-half mile from the plant site and has about a 5-year
capacity. The lagoon will eventually be covered and vegetated. The
blowdown from the cold lime-treating unit is thickened and disposed of with
the ash from the flexicoker. A diagram of the ash handling system is shown
in Figure 6.3-3. In an actual commercial EDS plant there may be an incentive
to combine ash disposal with mine tailings disposal or to dispose of the ash
in the worked out portions of the mine.
The spent catalysts from the EDS process may be disposed of in several
ways. These include burial or landfill, in situ or ex situ regeneration
followed by reuse, or metals reclamation.
6.3.1.4 Trace Elements—
The coal fed to the EDS process contains many trace elements which may
have an impact on the environment. The fate of these trace elements in
the process and their potential toxicity if released to the environment
need to be identified. Data are needed to give accurate and complete
material balances on all trace elements. These balances will make it
possible to identify potential problem areas and to design effective pollu-
tion control and disposal facilities for trace elements.
6.3.2 Physical Disturbances
The physical disturbances resulting from coal liquefaction plant
construction and operation are similar to those of a coal-fired power plant.
In most instances the physical disturbances are related to site-specific
characteristics; however, a general inventory can be compiled and includes:
• Changes in topography due to site preparation,
• Changes in water body flow characteristics due to
cooling water intake and consumptive water use,
6-44
-------
DRY ASH FINES
FROM FLEXICOKER
ASH FILTER CAKE.
FROM FLEXICOKER
BELT CONVEYOR
ATM
1
LI HE SLURRY
FROM COLD LIHE
SOFTENING
VENTURl
SCRUBBER
DRY ASH FINES
FROM FLEXICOKER-
oo
MIXING TANK
W/ MECHANICAL
AGITATORS
-VARIABLE H20 MAKEUP
(FROM WASTE WATER TREATING)
LIME SLURRY
FROM COLD LIME
SOFTENING ATM
ASH FILTER CAKE
FROM FLEXICOKER
RECYCLED
WATER FROM
CLARIFIED .
WATER POND
BELT CONVEYOR
CL
OO
MIXING TANK
W/ MECHANICAL
AG I TATORS
^(SIPHON)
• 50$ SLURRY PUMPS
VARIABLE H20 MAKEUP
"(FROM WASTE WATER
TREATING)
SETTLING POND
3 - 50% FLOATING BARGE PUMPS
16'
CLARIFIED WATER POND
Figure 6.3-3. EDS commercial plant study design ash handling system flow plan.
-------
Alterations of terrestrial and aquatic ecological
regimes due to construction and operation,
• Aesthetic and scenic alterations,
• Minor microclimatic changes,
• Changes in the character of aquatic communities due to
heated water and treated effluent discharges,
• Accumulation of solid wastes.
6.3.3 Plant Construction, Operation and Decommission
The overall effect of development of a given liquefaction system is a
function not only of its physical operation but also of the socioeconomic
cycle involved in construction, operation, and termination of operation of
the facility. The effect would be similar to construction of a large-
size power plant or a refinery plant. Throughout the entire facility life
cycle, established water and land use patterns may be disrupted.
6.3.4 Other Impacts
Besides the impact on air quality and water quality created by
pollutant releases as discussed earlier, other adverse impacts have been
identified. Many of the compounds known to be present in coal liquefaction
products are suspected of being carcinogens. Preliminary studies indicate
that the products of hydrogenated and higher-boiling distillates, centrifuged
oils, char, residues, and the recycled solvent oil contain potentially
hazardous materials. Chronic effects of the release of low levels of these
compounds and pollutant-derived atmospheric/aquatic food chain transformation
products are the principal concerns for areas outside the faclities.
Higher-concentration exposures and accidental discharges are the main
industrial health concerns within the plant. EPA has developed a list of
priority pollutants, some of which are carcinogenic. A study needs to be
done to quantify the carcinogenic pollutants.
6-46
-------
A commercial coal liquefaction facility may affect both terrestrial and
aquatic indigenous plant and animal species at all levels of community
organization. In most respects these impacts will be similar to coal-fired
power plants.
A commercial-size coal liquefaction facility may require about 102 to
163 hectares of land. Also, disposal of solid wastes will require large
areas of land. The solid wastes, depending upon the size of the plant and
ash content of the coal, will vary from 1,200 to 2,800 metric tons per day.
(Most of these wastes will be in the form of ash.) Over a 20-year period
the solid wastes form the liquefaction plant will cover 122 to 283 hectares
to a depth of about three meters. The land-use impacts and land disturbances
resulting from the liquefaction facility will vary with siting requirements
such as topography and access to coal supply, land area needed for the
process equipment and support facilities, and secondary growth.
When coal is liquefied, hazardous compounds such as polycyclic aromatic
hydrocarbons, phenols, thiophenols, aromatic amines, etc., are produced.
Product streams, plant fugitive losses, and leaks may result in concentra-
tions of toxic materials which may pose acute or chronic occupational
hazards requiring specialized, strictly-controlled operating procedures and
industrial hygiene and safety programs. Table 6.3-5 shows occupational
safety and health hazards and control measures associated with a coal
liquefaction plant. The SRC-I system is considered in the table; but
similar impacts are expected from the SRC-II, H-Coal and EDS systems.
6-47
-------
TABLE 6.3-5. OCCUPATIONAL AND HEALTH HAZARDS OF LIQUEFACTION SYSTEMS
Procaaa Operation
Coal storage, preparation
Occupational Safety
and Health llaaards Mature of Hasard
Unloading Coal dust
Haxard Control Measures
Water spray, filter masks
Liquefaction
Solvent extractloo
Direct hydroganation
Pyrolysis
Indirect liquefaction
Product aeparation
(distillation)
Hydrogen production
By-product recovery
•/power generation
Cooling tower
Water treatment
Uaatevater
and pond*
Solid waste disposal
Fuel gas sulfur removal
Gasification
Acid gas removal
Storage of raw coal
Waahlng
Drying
Crushing and pulverization
Slurry preparation and pumping
Prcheater (solvent extraction)
Reactor
Flash system
Preheater (direct liquid)
Catalytic reactor
EbuHated reactor
Carbonization (pyrolysls)
Hydroganation
Reactor
Centrifuge
Stripper
Distillation
Pressurised filter housings
Lines and valves
Gaslf ier
Steam reforming
Gas separator
Handling and storage of Pumps
products/by-products Storage tanks
Transfer lines
Valves
Centrifuge
Caa separator
Solids rnaval
Distillation
Coking/flexIcoking
Decanter
Flexicokiog
Hj production
Condenser, heat exchanger
Gas separation
Shift converter
Decanter
Centrifuge
Pyrolyier
Fluldized bed combustor
Flexicoking
Hydrocarbonixation
Water, dust, fire
Water, solids, soluble organic*
Water, dust, organic vapors
Water, dust, noise
Organic vapors including carcinogens
Leakage/expioaion of volatile
organic* and gases under heat
Inhalation and akin contact w/coal
tar volatile* from leaks, vents,
•pills
Contact w/spent catalyst containing
toxic or carcinogenic coal tars
Maintenance and repair of vessels
Water spray, sprinklers, alarms
Containment, water treatment
Spray, ventilation* waste containment
Spray, waate containment, barriers
Waste containment, ventilation, contact avoidance
Scrubbing or incineration of vent effluent
Leak detection and alarm
Ieolation of equipment
Impervious clothing and eye protection
Local ventilation
Air supply during vessel entry
Blast protection and fire suppression
Rotating machinery Safety systems, enclosure design
Ignition from electrical and friction Design
sources Grounding
Same as liquefaction
Same aa liquefaction Same as liquefaction
Disposal of filtrate containing coal Waate handling practices Including containment
tar carcinogens and toxic material and monitoring programs
Explosion and fire from hydrogen
leak
Leaks and explosions
Inhalation/skin contact
Noise
Rotating machinery and ignition
Leaks and explosions of pressurised
gases and vapors
Inhalation of toxic and carcinogenic
coal tars
Skin contact v/spilled residue
Leak detection
Alarm system
Ventilation
Pressure monitors
Leak detection
Explosive atmosphere detection
Roiae monitoring
Impervious clothing aad aye protection
Air monitoring
Leak detection
Explosive atmosphere detection
Noise monitoring
Impervious clothing and eye protection
Air monitoring
Pressure monitoring
Relief venting
Noise monitoring
Noise suppression
Air monitoring
Leak detection
Water monitoring
Drift eliminator design and maintenance
Equipment reliability
Skin contact w/water containing toxic Water monitoring
and carcinogenic coal tars Impervious clothing and tye protection
Inhalation of volatile coal tar Work practices and procedures
products
Combustion products
Heat
Noise
Contaminated drift and blowdown
Cooling tower maintenance
Rotating machinery
Pressure vessels Whlgh temperature
gases and vapor*
Inhalation and skin contact of coal
tars
Safety systems/enclosures
Landfill procedures
Incineration of wastes
Impervious clothing and eye protection
6-48
-------
References
6-1. Environmental Protection Agency. Compilation of Air Pollutant
Emission Factors. 2nd ed. with supplements. AP-42. Research
Triangle Park, NC. 1973.
6-2. Rawdon, A. H., R. A. Lisaukas and S. A. Johnson. "NOy Formation in
Low- and Intermediate-Btu Coal Gas Turbulent-Diffusion Flames."
Presented at the NOX Control Technology Seminar, sponsored by Electric
Power Research Institute, San Francisco, CA. 5-6 February 1976.
6-3. Thomas, W. C., K. N. Trede, and G. C. Page. Environmental Assessment:
Source Test, and Evaluation Report - Wellman-Galusha (Glen Gery)
Low-Btu Gasification. Final Report. EPA Report No. 600/7-79-185,
EPA Contract No. 68-02-2147. Austin, TX. Radian Corporation.
August, 1979.
6-4. Cavanaugh, E. C., W. E. Corbett and G. C. Page. Environmental
Assessment Data Base for Low/Medium-Btu Gasification Technology.
Volumes I & II. Final Report. EPA 600/7-77-125a, b. Radian
Corporation. Austin, TX. November 1977.
6-5. Nicklin, T., and B. H. Roland. "Removal of Hydrogen Sulfide from
Coke-Oven Gas by the Stretford Process." DECHEMA Monogr. 48(835-
358), 243071 (1963).
6-6. Kleeberg, Ulrich. "Removal of Hydrogen Sulfide from Gases Using the
Stretford Process." Presented at the Fifth International Conference
on Coal Gasification, Liquefaction and Conversion to Electricity.
Pittsburgh, PA. 8-10 August 1978.
6-7. Environmental Protection Agency. Standards Support and Environmental
Impact Statement Volume I: Proposed Standards of Performance for
Petroleum Refinery Sulfur Recovery Plants. Research Triangle Park,
NC. Emission Standards and Engineering Division. September 1976.
6-8. Moyes, A. J., and J. S. Wilkinson. "Development of the Holmes-
Stretford Process." Chem. Eng. (London) 282, 84-90 (1974).
6-9. Riesenfeld, F. C., and A. C. Kohl. Gas Purification. Second edition.
Gulf Publishing Company. Houston, TX. 1974.
6-10. Page, Gordon C. Environmental Assessment: Source Test and Evaluation
Report—Chapman Low-Btu Gasification. Final Report. EPA-600/7-78-
202. EPA Contract No. 68-02-2147. Radian Corporation. Austin, TX.
October 1978.
6-11. Meserole, N. P. Review and Assessment of the Existing Data Base
Regarding Flue Gas Cleaning Wastes. Radian Corporation. Austin, TX.
In press.
6-49
-------
6-12. Sinor, J. E., ed. Evaluation of Background Data Relating to New
Source Performance Standards for Lurgi Gasification. Final Report.
EPA-600/7-77-057. Cameron Engineers Inc. Denver, CO. June 1977.
6-13. Thomas, William C. Summary Report for a Screening Study to Determine
the Emission Reduction Potential NSPS Would Have on Transfer Opera-
tions Involving Crude Oil, Jet Fuels and Aviation Gasoline. Final
Report. Radian Corporation. Austin, TX. June 1976.
6-14. Detman, Roger F. Factored Estimates for Western Coal Commercial
Concepts, Technical Appendix II, Engineered Equipment Descriptions.
Interim Report. C. F. Braun & Company. Alhambra, CA. October 1976.
6-15. Holland, W. F., et al. Environmental Effects of Trace Elements from
Ponded Ash and Scrubber Sludge. Final Report. Radian Corporation.
Austin, TX. September 1975.
6-16. Radian Corporation. Coal-Fired Power Plant Trace Element Study,
4 vols. Radian Corporation. Austin, TX. September 1975.
6-17. El Paso Natural Gas Company. Application of El Paso Natural Gas
Company for a Certificate of Public Convenience and Necessity.
Docket No. CP73-131. El Paso, TX. 1973.
6-18. Fant, B. T. Exxon Donor Solvent Coal Liquefaction Commercial Plant
Study Design. Prepared for U.S. Energy Research and Development
Administration. Exxon Research and Engineering Company. Florham, NJ.
January 1978.
6-50
-------
SECTION 7
EMISSION SOURCE TEST DATA
Very little data exists on the levels of pollutants resulting from
combustion of coal derived synthetic fuels in industrial boilers. Two
series of tests were performed with low- and medium-Btu gas in small test
furnaces. For coal-derived liquids, eight combustion tests have been
conducted. The input heat rate of the coal-derived liquids test facilities
varied considerably. The largest was a commercial utility boiler rated at
22.5 MWe output or an approximate heat input of 66 MW (220 x 106 Btu/hr).
Two tests were run on a steam boiler with an input heat rate of 14 MW
(48 x 106 Btu/hr). The other tests were conducted on very small boilers or
laboratory combustors with input heat rates of 80-800 kW (0.3-3.0 x 106
Btu/hr).
The following sections give further details on the synfuels combustion
tests. Included are the pollutants analyzed and the analytical methods
used. Section 7.1 discusses the gaseous synfuels tests, while Section 7.2
discusses the eight coal liquids combustion tests.
7.1 LOW- AND MEDIUM-BTU GAS EMISSION TEST DATA
The Riley Stoker Corporation has conducted process development work
for the Riley coal gasifier. At their test facility in Worchester,
Massachusetts, they also have a small refractory lined test furnace. As
part of their development and marketing of the Riley gasifier, they
conducted a series of coal gas combustion tests. The results of the tests
were presented (Ref. 7-1) at the EPRI sponsored NO Control Technology Seminar
7-1
-------
held in San Francisco, CA on February 5-6, 1976, and are summarized in
Section 7.1.1.
Under a contract to the EPA, the Institute of Gas Technology has also
conducted combustion tests of low- and medium-Btu gas in a small furnace.
The results of those tests are summarized in Section 7.1.2.
7.1.1 Riley Morgan Combustion Tests
The internal dimensions of the test furnace used in the Riley tests
were 0.91 x 0.68 x 1.6 m (36 x 27 x 62 in). The burner was a scaled
register-type burner similar to those used in utility and industrial
boilers. Table 7.1-1 lists the gaseous species analyzed for during the
tests and the analytical methods used. As shown in this table, both NOX
and SOz were measured in the combustion gases. However, the major purpose
of the Riley paper was to discuss NOX emissions, and more specifically NOX
formation from fuel-bound nitrogen compounds (predominantly NHs). Because
of this emphasis, 862 emission data were not presented.
Most of the Riley data was for combustion of low-Btu gas (5.2-6.3
MJ/m3) with ammonia concentrations of 280-670 ppmv. However, one test was
conducted using medium-Btu gas (10 MJ/m3) containing 1170 ppmv ammonia.
The results of these tests are shown in Figures 7.1-1 and 7.1-2.
NOx can be formed from both fuel bound nitrogen compounds and by
thermal fixation of molecular nitrogen. In order to identify the quantity
of NOx attributable to thermal fixation, tests were also conducted using
fuel gases with low ammonia (11-43 ppmv) concentrations. The low NHa
concentrations were obtained by scrubbing the fuel gases with a sulfuric
acid solution. The results of these tests are also shown on Figure 7.1-2.
At 6 percent excess oxygen, thermal NOx emissions were around 1.0 ppmv
7-2
-------
TABLE 7.1-1. ANALYTICAL PARAMETERS AND ANALYSIS METHODS
FOR RILEY SYNGAS COMBUSTION TESTS
Analytical Parameter
Test Method*
Product Gas Constituents
CO
CO 2
H2
H2S
NH3
Particulates
and aerosols
Combustion Gas Constituents
NOX
S02
02
CO
Infrared analyzer
Infrared analyzer
Infrared analyzer
Thermal conductivity analyzer
Collection in NaOH followed by standard
iodine titration
Collection in HaSOit followed by gas
detecting ammonia electrode
Isokinetic sampling and collection on
absolute membrane filter
Electrochemical cell sensors
Electrochemical cell sensors
Electrochemical cell sensors
Infrared analyzer
*A11 analytical parameters except H2S and NHa were analyzed continuously.
Source: Ref. 7-1
7-3
-------
Used with permission of Riley Stoker Corporation from "NOX Forma-
tion in Low- and Intermediate-Btu Coal Gas Turbulent-Diffusion
Flames." February 1976.
,,
O
40.0
fO
<§>
>300|-
o
s
Q.
0.
•-200
z
o
55
CO
^100
o
z
-I
465 BTU/HR
WITH TAR
» « 430 M BTU/HR.TAR.HIGH NH3
O = 350-400 M BTU/HR, NO TAR
Q > 560 M BTU/HR, NO TAR
370 M BTU/HR
NO TAR
O = 430 M BTU/HR, NO TAR
V = 460-470 M BTU/HR, TAR
A = 330-380 M BTU/HR, NO TAR
02 BLOWN
0
1.0 2.0 3.0 4.0 5.0
FURNACE EXCESS OXYGEN,VOLUME %
6.0
70
Figure 7.1-1. NO emission data for coal derived syngas combustion.
Source: Ref. 7-1
7-4
-------
Used with permission of Riley Stoker Corporation from "NOX Formation in
Low- and Intarmediate-Btu Coal Gas Turbulent-Diffusion Flames."
February 1976.
CM
O
#
ro
CC.
o
2"
0.
Q.
CC
I
1.0
.8
CC
O
.6
iu 4
X
O
O
Ul
N 2
LEGEND
0 = 280-670PPM NH3,NO TAR
n = ||-43 PPM NH3,NO TAR
®=UNKNOWN NH3,NO TAR
A = 1940PPM NH3,WITH TAR
V = 620 PPM NH3, WITH TAR
O = II50PPMNH3,NOTAR,
02 BLOWN
1940 PPM NH3
(WITH TAR)
280-670 PPM NH3l-
(NO TAR)
\.
-o- *-
I-43PPMNH3,(NOTAR)
1.0 2.0 3O 4.0 5.0 6.0
FURNACE EXCESS OXYGEN.VOLUME %
7.0
8.0
"Figure 7.1-2. N0x emission data (normalized with respect to furnace
heat input) for coal derived syngas combustion.
Source: Ref. 7-1
7-5
-------
(dry, at 3 percent 02) per kW input to the test furnace. At 4 percent
excess oxygen, thermal N0x was only 0.85 ppmv (dry, at 3 percent 02) per
kW input. To convert these values to ng NO per J input to the furnace,
the following factors were used:
furnace input heat rates ranged from 101 to 173 kW
flue gas flow rate is estimated at 16 g-moles per
megajoule of heat input.
The resulting estimated thermal NO emissions are 63-120 ng NO (as N02)/J
X X
(0.15-0.28 lb/106 Btu). These emissions are comparable to and support the
target N0x emission control level of 86 ng/J (0.20 lb/106 Btu) being examined
in this technology assessment report for syngas combustion.
By subtracting the thermal NOx from the total NOX emissions, Riley
estimated the fuel-bound nitrogen NOy emissions. These were correlated with
ammonia content in the fuel gas as shown in Figures 7.1-3 and 7.1-4.
Information was not provided in the Riley paper concerning the
accuracy of the reported data. Also, the rationale was not given for using
electrochemical cell sensors instead of the EPA Method 7 for NOy determina-
tions. However, a probable reason is that using electrochemical cell
sensors provided continuous data while if the EPA method was used, several
hours are required to collect and analyze a single sample.
7.1.2 Institute of Gas Technology Combustion Tests
The pilot-scale furnace used by IGT was 4.3 m (14 ft) long and had a
cross-sectional area of 1.98 m2 (21.3 ft2). Combustion tests were conducted
using both a ported baffle burner and fuel momentum controller burner. The
input heat rate for all tests was nominally 1 MW (3.5 x 106 Btu/hr). The
low- and medium-Btu gases tested were blended to have compositions typical
of gas produced from Wellman-Galusha gasifiers. Table 7.1-2 lists the
analytical instruments used during the tests.
7-6
-------
Used with permission of Riley Stoker Corporation from "NO Formation in
Low- and Intermediate-Btu Coal Gas Turbulent-Diffusion Flames."
February 1976.
180
FLUE GAS 02= 4.0-5.0%
0 O2 .04 O6 J08 .10 .12 .14 .16 .18 .20
AMMONIA CONTENT OF FUEL GAS, VOLUME %
Figure 7.1-3. Fuel NO emissions for coal derived syngas combustion.
Source: Ref. 7-1
7-7
-------
Used with permission of Riley Stoker Corporation from "NO Formation in
Low- and Intermediate-Btu Coal Gas Turbulent-Diffusion Flames."
February 1976.
IOO
90
80
70
60
en
CE
50
40
30
20-
10,
FLUE GAS 0- = 4.0-5.0%
0 .02 .04 .06 .08 JO .12 .14 .16 .18 .20
AMMONIA CONTENT OF FUEL GAS, VOLUME %
Figure 7.1-4. Conversion of NHa to NO in coal derived syngas combustion.
Source: Ref. 7-1
7-8
-------
TABLE 7.1-2. ANALYTIC INSTRUMENTATION EQUIPMENT USED FOR IGT COMBUSTION TESTS
Beckman 742 Polarographic Oxygen (02)
Beckman Paramagnetic Oxygen (Oa)
Beckman NDIR Methane (CHi»)
Beckman NDIR Carbon Monoxide (CO)
Beckman NDIR Carbon Dioxide (COa)
Varian 1200 Flame lonization Chromatograph (Total CH and Ca to C9)
Beckman NDIR Nitric Oxide (NO)
Beckman UV Nitrogen Dioxide (N02)
Thermo Electron Pulsed Flourescent Sulfur Dioxide (S02)
Hewlett-Packard Thermoconductivity Chromatography, Hydrogen (H),
Nitrogen (N2), Argone (A2), CO, C02, Ci to C5, Oxygen (02)
Beckman Chemiluminescent N0-N02
Source: Ref. 7-2
The main purpose of the IGT tests was to examine the combustion of
"dirty" syngas and specifically the formation of NOX> However, they did per-
form baseline tests on both clean syngas and natural gas. The results of
their baseline tests are summarized in Table 7.1-3. As indicated in this
table, NO emissions from combustion of medium-Btu gas are only 30-50 percent
of those from natural gas combustion. For low-Btu gas combustion, N0x emis-
sions range from 13 to 34 percent of those for natural gas. These test
results support the target NO emission control level which was based on the
X
level of NO emissions from natural gas combustion.
X
A second part of IGT's test work involved doping the clean gases with
NH3. The results of these tests, in terms of percent conversion of NH3 to
NO are shown in Figures 7.1-5 and 7.1-6.
7-9
-------
60
50
o 40-
G
O
•H
CO
30H
20-
10-
X 20% Excess Combustion Air
O10% Excess Combustion Air
0.2 0.4 0.6 0.8 1.0 1.2
Percent NH3 in Medium-Btu Fuel Gas
Figure 7.1-5. Conversion of NH3 to NOX for medium-Btu gas combustion
using baffle burner.
Source: Ref. 7-2
7-10
-------
60-
50-
40-
a
.3
CO
Cl
O
30-
20-
10-
X 20% Excess Combustion Air
O 10% Excess Combustion Air
0.2 0.4 0.6 0.8 1.0-
Percent NHa in Medium-Btu Fuel Gas
1.2
Figure 7.1-6. Conversion of NHs to NO for medium-Btu gas
combustion using kiln burner.
Source: Ref. 7-2
7-11
-------
TABLE 7.1-3. SUMMARY OF IGT BASELINE COMBUSTION TESTS*
Burner Used
Baffle Type
Kiln Type
Fuel
Natural Gas
Medium-Btu Gas
Medium-Btu Gas
Low-Btu Gas
Low-Btu Gas
Natural Gas
Medium-Btu Gas
Medium-Btu Gas
Low-Btu Gas
Low-Btu Gas
Fuel Temperature, °C(°F)
25 ( 77)
49 (120)
427 (800)
49 (120)
427 (800)
25 ( 77)
49 (120)
427 (800)
49 (120)
427 (800)
NO Emissions, **
ng/J (lb/106 Btu)
34 (0.078)
22 (0.051)
16 (0.037)
11 (0.025)
15 (0.035)
21 (0.049)
18 (0.043)
13 (0.030)
17 (0.039)
13 (0.030)
* Approximate input heat rate of 1 MWT (3.5 x 106 Btu/hr) with 10% excess air.
**NO plus N02 (Dry, corrected to 0% excess air).
Source: Ref. 7-2
7.2 COAL LIQUIDS EMISSION SOURCE TEST DATA
This section describes eight fuel firing tests conducted to determine
the combustion and emissions characteristics of coal-derived liquid fuels.
The eight tests are identified as follows:
Test Facility Fuel
II Pulverized Coal-Fired B&W Utility Boiler (at Plant SRC-I
Mitchell)
#2 Cleaver-Brooks Package Boiler EDS
#3 Scotch Laboratory Boiler SRC-II
#4 Modified Stirling Boiler (at Alliance Research Center) SRC-I
#5 Modified Stirling Boiler SRC-I
#6 Solid Fuel Burning Test Facility (Combustion Engineering) SRC-I
#7 Small Scale Laboratory Gas Turbine Combustor SRC-II
#8 Small Scale Laboratory Gas Turbine Combustor H-Coal
7-12
-------
While the specific objectives of these tests varied somewhat, they
all were concerned with determining the effect of different combustion
parameters on air pollution emissions. Stack gas emission NOx was
monitored in all eight tests, since this is a primary concern in combusting
coal-derived liquid fuels. Three of the tests (#1, #3, and #5) monitored
S02 emissions, and five (#1, #2, #3, M, and #5) monitored particulate
concentrations in the stack gas. Table 7.2-1 summarizes the reported
emissions test data. The following section provides a general description
of the combustion test facilities and the emission monitoring methods
used for each test.
7.2.1 Combustion Facilities and Emission Monitoring
Test #1 was conducted by Southern Company Services, Inc. to demonstrate
the feasibility of burning SRC-I in a commercial utility steam boiler and
to determine what modifications must be made to the boiler and auxiliary
equipment to burn SRC-I fuel (Ref. 7-3, 7-4, 7-5).
This test was run on Boiler Unit No. 1 at the Georgia Power Company's
Plant Mitchell, near Albany, Georgia. This is a 22.5 MWp (rated output)
Babcock & Wilcox natural circulation, pulverized coal-fired boiler. The
unit is rated at 104,320 Kg of steam per hour at 6.1 MPa and 480°C (steam
pressure of 900 psi and steam temperature of 900°F). It is equipped with
Babcock & Wilcox E-35 pulverizers and Research Cottrell perforated-plate
electrostatic precipitators.
The burners were replaced with a dual register type and minor
modifications were made to the pulverizers. These modifications were
required for preparation and burning of SRC-I fuel.
Emissions were measured while the unit was operating at the following
output loads:
7-13
-------
TABLE 7.2-1. EMISSIONS SOURCE TEST DATA FOR COAL DERIVED LIQUIDS
I
I-1
•c-
Test Boiler
* Site
1
2
}
4
5
6
7
8
22.5 MW«
electrical
output
490 kW-
thermai output
(SO hp)
780 kW_
thenal output
(80 bp)
14 Ml. Input
(47x10* Btu/hr)
14 Ml. Input
(47x10* Btu/hr)
0.8 HW Input
(3xlO10* Btu/hr)
0.08 HW- Input
(0.3x10* Btu/hr)
Number or
Fuel Duration
Characteristics of T««ta
SRC-I: 11 runs,
35.5 MJ/kf 18 daye .
0.71X sulfur total
0.57X ash
1.6Z nitrogen
EDS: DMA
38.4 MJ/kg
0.8Z sulfur
l.OX nitrogen
SRC-II: 47 run*
38.3 Hi/kg
0.17Z sulfur
0.19X ash
1.08Z nitrogen
SRC-It 17 runs
36.3 Hi/kg
0.8Z sulfur
0.29Z ash
1.7Z nitrogen
SRC-I: 5 runs
36.3 HI /kg
0.7X lulfur
0.4Z ash
1.9Z nitrogen
SRC-I: 6 runs,
34.9 MJ/kg 100 hours
0.7Z sulfur duration
<0.1Z ash
1.9Z nitrogen
SRC-II: 4 runs.
38.9 Hi/kg longest!
0.37Z sulfur 3 hrs
H-Coal: 3 runs
41.4 MJ/kg
<0.002Z sulfur
Emissions, ng/J
(lb/10* Btu)
NOx:
SOi:
Parti
NO*:
Parts
"Ox!
S0»:
Parts
MOWS
Parts
NO*:
SOis
SOii
Parts
"V
NOx:
NO*:
180-200
(0.42-0.46)
400-460
(0.93-1.07)
17 (0.04)
350-420
(0.81-0.98)
10-12
(0.02-0.03)
130-170
(0.30-0.40)
160 (0.37)
150 (0.34)
170-240
(0.40-0.56)
250-1300
(0.59-3.0)
220-270
(0.51-0.63)
600-700
(1.4-1.6)
4 (0.01)
•»-900 (2)
260-340
(0.60-0.79)
140 (0.32)
100-130
(0.23-0.30)
X Control Vs.
Direct Coal
C embus t loo
NCy:
SOi:
Psrt:
NOxS
Part:
NOxs
SOis
Part!
NCt,:
Part:
NOx:
SOU
Parts
"°x!
HOxS
NO*:
•>-45
•v<85
DBA
(-5)-
(-55)
DMA
M35-60)
DNA
DNA
M10-50)
M65-90)
M20-35)
M65-70)
MO
,
•VQ
•<.(40-60)
M50-70)
Control
Levels
Supported *
NOxl
SOj:
Part:
MOx:
Part:
NOx:
SOj!
Part:
NOx:
Parts
»0x«
Parts
80t>
HCvS
"Ox!
HOxS
Mod.
Int.
Mod.
Hone
None
All
Mod.
Int.
Mod.
Int.
Done
Mod.
Int.
None
Nod.
None
None
Mod.
Mod.
Int.
Mod.
Int.
Esilsslon Monitoring
Methods
NOx:
SO,!
Part:
NOx:
Fart:
NOx!
SO,:
Part:
NOx:
Pert:
NO*:
SO,:
SOji
Part:
NOX:
HOX:
NOx:
EPA Method 7 and
Client luminescence
EPA Method 6 and
Pulsed Fluorescence
EPA Method 5
Chemilunlnescence
EPA Method 5
Chenilunlnescence
Flame Photonetrlc
Detector
EPA Method 5
CheBlluolnescence
EPA Method 5
Chenlluninescence
and Nondisperslve
Infrared
Modified Reich
Method
EPA Method 8
EPA Method 5
Electrochemical
Cell
ChemlluBinescence
and Electrochemical
Cell
Chemiluainescence
and Electrochemical
Cell
Remarke
ESP design
efficiency: 90X
Average efficiency
during test: 55Z
**
No post combustion
partlculate control
device
SO, emissions
reported are
greater than the
theoretical naxinun
possible based on
fuel characteristics
**
Source: Ref. 7-3 through 7-11.
* Mod. - Moderate control level; Int. - Intermediate control level; Str. - Stringent control level.
** Due to high excess air during combustion, NOx values are questionable.
DMA - Data Rot Available).
-------
Full load (22 MW ).
c
• Medium load (14 MW ), and
Low load (7.5 MW0).
Air pollutants were monitored by several methods. The following EPA
Reference Methods were used for manual testing:
• Method 5 - For determination of particulate emissions from
stationary sources,
Method 6 - For determination of SOz emissions from stationary
sources,
• Method 7 - For determination of nitrogen oxide emissions
from stationary sources.
Nitrogen oxides were also monitored continuously and analyzed by
chemiluminescence. Sulfur dioxide was also monitored by the pulsed
fluorescent analysis method. In addition, grab samples were collected and
analyzed by gas chromatography for the following components: CO, COz ,
S02, NZ , Oz, and Ci through Ce hydrocarbons.
Test #2 was conducted by the Exxon Research and Development Company
(Ref. 7-6) to investigate the combustion properties of liquid fuel produced
by the Exxon Donor Solvent Process. The test was run on a 0.49 MWT (50 hp
Cleaver-Brooks firetube package boiler which had a nominal firing rate of
57 liters/hr (15 gal/hr).
Stack particulates were measured by EPA Reference Method No. 5,
while chemiluminescence was used to measure nitrogen oxide emissions.
Test #3 was conducted by KVB, Inc. (Ref. 7-7) to determine the degree
to which NOX emissions from high nitrogen coal-derived liquid fuels could be
controlled by varying certain combustion parameters. The test was run on
a laboratory boiler with a 0.78 MWT (80 ph) Scotch dry-back type shell
7-15
-------
which was fired at 0.88 MW (3 million Btu/hr). The combustion unit had
air preheat, forced air combustion, and mechanical fuel atomization.
In this test nitrogen oxides were measured by chemiluminescence,
was monitored using a photometric analyzer, and particulate emissions were
determined by EPA Reference Method No. 5. Other emission test methods
used were: oxygen electrolytic analysis for 02, nondispersive infrared
analysis for CO, and Bachardach Smoke Tester for smoke.
Tests #4 and #5 were conducted by the Babcock & Wilcox Company (Ref.
7-8, 7-9) to characterize certain handling, pulverization, and combustion
properties of solvent refined coal (SRC-I). The tests were designed to
provide information that will aid in future boiler design and retrofitting
existing boilers to burn SRC-I.
These tests were run on a four-drum Stirling boiler at the B&W
Alliance Research Center. This unit has a rated output of 18,000 Kg/hr
(40,000 Ib/hr) steam at 1.0 MPa (150 psig), which corresponds to a fuel
input of about 14 MWT (47 x 106 Btu/hr) or up to 1400 Kg/hr (3100 Ib/hr)
of solvent refined coal. Several modifications were made to the dual
register burner, particularly the coal nozzle, of this boiler.
In Test #4, nitrogen oxide emissions were continuously monitored by
chemiluminescence and particulate emissions were measured by EPA Reference
Method 5. Stack opacity was measured by an optical transmissometer. Carbon
monoxide was monitored using an infrared analyzer, and Oa emissions were
determined by a paramagnetic analyzer.
In Test #5, S02 and SOs emissions were also measured using EPA
Reference Methods 6 and 8.
Test #6 was conducted by the CE Power Systems Division of Combustion
Engineering, Inc. (Ref. 7-10) to determine if the combustion characteristics
7-16
-------
of SRC-I permit its use as a fuel in utility steam boilers. The test was
run on the CE Power System's Solid Fuel Burning Test Facility, which has a
rated fuel input ranging between 0.6 MWT and 0.9 MWT (2 and 3 x 106 Btu/hr).
This test facility is used to simulate the combustion performance of
commercial coal-fired steam boilers manufactured by CE Power Systems.
The only air pollutant monitored in Test #6 was nitrogen oxides, which
was measured by the electrochemical cell method.
Tests #7 and #8 were conducted by the Westinghouse Research Laboratory
(Ref. 7-11) to evaluate the use of heavy distillate coal liquids from the SRC
and H-Coal processes for use in heavy duty utility turbines. The combustion
test facility used was a 10 cm (4 inch) diameter scaled down combustion
chamber used to simulate commercial gas turbine performance. The combustor
had a fuel rate of 6.08 liters/hr (1.6 gal/hr) with a combustion air flow
rate of 0.045 Kg/sec (0.1 Ib/sec) at a pressure of 0.3 MPa (3 atm.). The
fuel nozzle used in this test facility was of the conventional air assist
atomizing type generally used with No. 2 fuels.
Test #7 was conducted to evaluate SRC-II fuels at several levels of
hydroprocessing (7.4 wt percent, 10.3 wt percent and 11 wt percent
hydrogen).
Test #8 was conducted to evaluate H-Coal which had been hydroprocessed
at three levels (9.1 wt percent, 10.5 wt percent, and 11.7 wt percent
hydrogen).
The following air pollutants were monitored in Tests #7 and #8:
nitrogen oxides, carbon monoxide, carbon dioxide, unburned hydrocarbons,
and smoke. Nitrogen oxides were measured both by a chemiluminescence
analyzer and the electrochemical cell method. Carbon monoxide was measured
by a nondispersive infrared analyzer. Unburned hydrocarbons were monitored
by a flame ionization detector.
7-17
-------
7.2.2 Comparison of Emissions
Also shown in Table 7.1-1 are comparisons of the various target
emission levels to the reported emissions test data. The target control
levels are summarized below:
Target Emission Control ng/J
Levels for Coal-Derived Liquids Particulates SOz NOX (as
Moderate Control 13 520 300
Intermediate Control 13 260 220
Stringent Control 13 86 86
Particulate emissions from the EDS fuels and Test #1 for SRC-I
nominally meet the stringent target emission level. However, for the other
SRC-I tests (#'s 5 and 6) and the SRC-II tests, the particulate emissions
are much greater than the target control levels. This is because no
particulate control device was employed during these tests.
The SRC-II test data were below both the moderate and intermediate
control levels for SOa emissions, but were greater than the stringent
control level. S02 emissions data for SRC-I combustion were below the
moderate control level in one test (#1) but above it in the other (#5).
However, there is some question as to the validity of the data from Test #5
since the reported S02 emissions are above the theoretical maximum based
on the heating value and sulfur content of the SRC-I used.
The SRC-I data were below both the moderate and intermediate control
level for NOx emissions in two of the four tests (#1 and /M). In the other
two tests (#5 and #6) the range of NCy emissions was generally only below
the moderate control level. EDS combustion produced NOX emissions which
exceeded even the moderate control level. SRC-II combustion generated
lower NOx emissions than SRC-I or EDS. The test data indicate that SRC-II
can meet both the moderate and intermediate control levels.
7-18
-------
7.2.3 Discussion of Emissions Monitoring Methods
This section discusses the selection of stack monitoring methods for
the three principle pollutants monitored during the combustion tests:
nitrogen oxides, sulfur dioxide, and particulates. It also addresses the
relative merits of the EPA Reference Method for NOX and the other nitrogen
oxide emission monitoring methods used. In the five tests in which particu-
late emissions were measured, the EPA Reference Method No. 5, Determination
of Particulate Emissions from Stationary Sources, was used.
Sulfur dioxide emissions were monitored in three tests (#1, #3, and
#5). The EPA Reference Method No. 6, a titration technique which uses
barium thorin as the indicator, was used in Test #1. Test #3 used a flame
photometric detector analyzer for SOa measurement. This technique measures
SOa by introducing a gas sample into a hydrogen-rich flame and measuring the
3940 A 82 band with a narrow band optical filter. Its primary drawback is
susceptibility to interference from other sulfur compounds. The photometric
method was selected over the EPA Reference Method because the photometric
method gives a continuous read-out. The EPA Reference Method, which
necessitates accumulating the sample for several hours, is not suitable for
a combustion test where a relatively small quantity of fuel is available.
Test #5 used a Whittaker SS330 Analyzer which employs a modified Reich
method for SOz determination. This method was chosen over the EPA Reference
Method for the same reason as in Test #3.
Nitrogen oxide emissions were measured in all eight tests. However,
only Test #1 used the EPA Reference Method No. 7. Six other tests used the
chemiluminescence method, and three (Tests #6, #7, and #8) used the
Electrochemical Cell method for NOx detections.
The chemiluminescence method measures the quantity of radiant energy
emitted when NO reacts with ozone to produce NCh . This radiant energy,
measured by a photomultiplier tube, is proportional to the original quantity
7-19
-------
of NO in the sample gas. Chemiluminescence analyzers can also measure
by first converting it to NO in a heated stainless steel tube and comparing
the measured NO before and after conversion.
The EPA Reference Method #7 for determining NOx is a colorimetric
technique, the phenoldisulfonic acid procedure (PSD). This procedure
requires that the stack gas be absorbed for several hours to collect a
sufficient quantity for measurement. The Chemiluminescence method was
selected because it gives a continuous read-out.
Several studies have compared the Chemiluminescence and colorimetric
methods of NOx determination (Ref. 7-12, 7-13, 7-14). Monteriolo and
Bertolaccini (Ref. 7-12) found that the colorimetric, Chemiluminescence, and
electrochemical methods are equally valid in response linearity, sensitivity,
and concentration limit. Bergquist (Ref. 7-13) reported that the Chemilumi-
nescence method is generally most suitable. Bourbon et al. (Ref. 7-14)
found that Chemiluminescence yielded theoretical results of NOa and NO con-
centrations below 1 ppm, which were more accurate than results produced by
colorimetric methods.
7-20
-------
References
7-1. Rawdon, A. H., R. A. Lisauskas and S. A. Johnson, NO Formation in Low
and Intermediate Btu Coal Gas Turbulent-Diffusion Flames. Presented
at the NO Control Technology Seminar, sponsored by Electric Power
Research Inst. San Francisco, CA, 5-6 February 1976.
7-2. Waibel, R. T., E. S. Fleming, and D. H. Larson, Pollutant Emissions
from "Dirty" Low- and Medium-Btu Gases. EPA-600/7-78-191. October
1978.
7-3. The Southern Company Services, Solvent Refined Coal Burn Test. April
1978.
7-4. Nichols, Grady B. and William J. Barrett, Evaluation of Electrostatic
Precipitator During SRC Combustion Tests, EPA-600/7-78-129. July 1978.
7-5. Budden, Kenneth G., and Subhash S. Patel. Air Emissions from Combus-
tion of Solvent Refined Coal. Final Report. Report No. EPA-600/7-79-
004, EPA Contract No. 68-02-2162. Columbia, MD. Hittman Associates,
Inc. January 1979.
7-6. Quinlan, C. W. and C. W. Siegmund, Combustion Properties of Coal
Liquids from the Exxon Donor Solvent Process, Exxon Research and
Engineering Company. Presented at American Chemical Society Symposium.
Anaheim, California, March 14, 1978.
7-7. Arand, J. K., and L. J. Myzio, Combustion and Emission Evaluation of
SRC Fuel Oil, A Synthetic Liquid Fuel From Coal, KVB 19900-733. Prepared
for Gulf Mineral Resources by KVB, Inc. Tustin, CA, December 1977.
7-8. Babcock and Wilcox Company, Characteristics of Solvent Refined Coal:
Dual Register Burner Tests. Prepared for the Electric Power Research
Institute, FP-628, Research Project 1235-5, January 1978.
7-9. Babcock and Wilcox Company, Investigating Storage, Handling, and
Combustion Characteristics of Solvent Refined Coal Prepared for
Electric Power Research Institute, Research Project 1235-4, July 1976.
7-10. Combustion Engineering, Inc., Solvent Refined Coal Evaluation:
Pulverization, Storage, and Combustion. Prepared for Electric Power
•Research Institute, Research Project 1235-2b, June 1976.
7-11. Cabal, A. V., M. J. Dabkowski, R. H. Heck and T. R. Stein, Utilization
of Coal-Derived Liquid Fuels in a Combustion Turbine Engine. Mobile
Research and Development, in American Chemical Society, preprints of
papers presented at Anaheim, California, March 12-17, 1978.
7-12. Monteriolo, S. C. and M. A. Bertolaccini, Measurement of Nitrogen
Dioxide in the Atmosphere. Ann. Inst. Auper. Sanita, Rome. 1973
(APTIC No. 78660).
7-21
-------
7-13. Bergquist, K., Methods of Analysis of Nitric Oxide and Nitrogen
Dioxide in the Atmosphere and in Exhaust Gases: A Literature Search.
Research Institute of National Defense Report (Sweden) October 1972
(APTIC No. 79029).
7-14. Bourbon, P., J. Alary and J. C. Lepert, Determination of N02 and NO
at Various Concentrations Using Colorimetry and Chemiluminescence.
Analysis, April 1975 (APTIC No. 78217).
7-22
-------
APPENDIX A
CAPITAL INVESTMENT REQUIREMENTS
AND ANNUALIZED COSTS
FOR LOW-BTU COAL GASIFICATION SYSTEMS
AND LOW-BTU GAS-FIRED INDUSTRIAL BOILERS
A-l
-------
TABLE A-l. CAPITAL INVESTMENT REQUIREMENTS FOR LOW-BTU
WELLMAN-GALUSHA GASIFICATION SYSTEMS
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Stretford
S02 Control Level - Stringent
System Capacity, MW (106 Btn/tir)
INSTALLED EQUIPMENT COSTS
Coal Receiving and Storage
Gasification System
Gas Purification System
Blower /Compressor
Quench/Cooling Towers
Pumps (for cooling liquor)
Electrostatic Precipitator
Separator/Evaporator
I1;S Removal Unit
Sulfur Recovery Unit
Building and Ductwork Not Costed
in Above Equipment Costs
(6% of EC)
Total Installed Equipment (EC)
INDIRECT INSTALLATION COSTS
Engineering (10% of EC)
Construction and Field
Expense (JO/? of EC)
Construction Fees (10% of EC)
Startup (2% of EC)
Total Indirect Costs (1C)
CONTINGENCIES (30% of EC + 1C)
TOTAL TURNKEY COSTS (TTC)
WORKING CAPITAL (25% of Total Direct
Operating Costs)
TOTAL CAPITAL INVESTMENT
8.8(30)
370
500
60
50
30
120
120
1,330
-
160
2,740
270
270
270
50
860
1,080
4,680
170
~4,850
22(75)
390
1,000
70
80
40
220
190
1,380
-
220
3,590
360
360
360
70
1,150
1,420
6,160
270
67430"
44(150)
440
2,000
100
120
70
290
240
1,800
-
320
5,380
540
540
540
110
1,730
2,130
9,240
440
9,680
58.6(200)
600
2,500 ,
120
140
90
370
250
1,970
-
390
6,430
640
640
640
130
2,050
2.540
11,020
560
11,580
117.2(400)
790
5,000
240
280
170
740
500
2,300
—
640
10,660
1,070
1,070
1,070
210
3,420
4,220
18,300
1,020
19,32?
1C3 mid-1978 dollars.
-------
TABLE A-2, ANNUALIZED COSTS FOR LOW-BTU WELLMAN-GALUSHA
GASIFICATION SYSTEMS
>
u>
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Stretford
SO2 Control Level - Stringent
Operating Factor - 60%
System Capacity, MW
DIRECT OPERATING COSTS
Operating Labor (@ $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance (6% of Total
Turnkey Costs x 0.8)
Replacement Parts (included
in maintenance)
Electricity (@ 25.8 mills/kW-hr)
Steam (@ $5.00/GJ)
Cooling Hater (@ $0.05/m3)
Process Water (@ $0.04/m3)
Coal (@ $8.88/ton)
Chemicals
Sulfur, Ash Disposal
(@ $44.00/ton)
Total Direct-Operating Costs
OVERHEAD COSTS
Payroll (30£ of operating labor)
Plant (26% of labor, parts and
maintenance)
Total Overhead Costs
CAPITAL CHARGES
G&A, Local Taxes and
Insurance (4% of Total
Turnkey Costs)
Capital Recovery (11.7")% of
Total Turnkey Costs)
Interest on Working Capital
(@ 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS
Average Gas Cost, $/GJ
8.8(30)
210
70
220
-
20
10
10
-
90
20
30
680
60
130
190
190
550
20
760
1630
9.80
22(75)
260
70
300
-
40
30
30
-
220
50
90
1090
80
160
240
250
720
30
1000
2330
5.60
44(150)
320
70
440
-
80
60
60
-
440
110
170
1750
100
220
320
370
1090
40
1500
3570
4.30
(106 Btu/hr)
58.6(200)
370
70
530
-
110
80
80
-
600
150
230
2220
110
250
360
440
1290
60
1790
4370
3.95
117.2(400)
580
140
880
-
210
160
170
-
1190
300
460
4090
170
420
590
730
2150
100
2980
76ftO
3.43
103 Mid-1978 dollars
-------
TABLE A-3. ANNUALIZED COSTS FOR LOW-BTU GAS-FIRED
INDUSTRIAL BOILERS
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Stretford
SOj Control Level - Stringent
Operating Factor - 60%
System Capacity, MWT (106 Btu/hr)
CAPITAL INVESTMENT, 103 $
Total Turnkey Costs (TTC)
Land
Working Capital (25X of Total
Direct Operating Costs,
excluding fuel costs)
Total Capital Requirement
OPERATING COSTS, 10s $/yr
Direct Costs
Ooerating Labor (3 $12.02/hr)
Supervision (9 $15.63/hr)
Maintenance Labor (@ $14.63/hr)
Replacement Parts
Electricity (9 25.8 mills/kW-hr)
Process Water «? $0.04/m3)
Fuel
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30Z of operating labor)
Plant (26Z of labor and parts)
Total Overhead Costs
Capital Charges
G&A, Local Taxes, and
Insurance (4Z of TTC)
Capital Recovery Factor
(10.61Z of TTC)
Interest on Working Capital
(0 10Z)
Total Capital Charges
TOTAL ANNUALIZED COSTS, 103 $/yr
8.8(30)
640
<10
70
710
110
70
30
30
30
<10
1630
<10
1900
30
60
90
30
70
10
110
2100
22(75)
1110
<10
70
1180
110
70
30
40
40
<10
2330
<10
2620
30
70
100
40
120
10
170
2890
44(150)
1740
<10
120
1860
210
70
60
60
50
<10
3570
10
4030
60
100
160
70
180
10
260
4450
58.6(200)
2070
<10
120
2190
210 -
70
60
70
50
<10
4370
10
4840
60
110
170
80
220
10
310
5320
117.2(400)
4150
<10
200
4350
320
70
130
140
100
10
7660
10
8440
100
170
270
170
440
20
630
9340
Mid-1978 dollars
-------
TABLE A-4. CAPITAL INVESTMENT REQUIREMENTS FOR LOW-BTU
WELLMAN-GALUSHA GASIFICATION SYSTEMS
>
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - Stretford
S02 Control Level - Moderate
System Capacity, MVJ (106 Btn/hr)
INSTALLED EQUIPMENT COSTS
Coal Receiving and Storage
Gasification System
Gas Purification System
Blower/Compressor
Quench/Cooling Towers
Pumps (for cooling liquor)
Electrostatic Precipitator
Separator /Evaporator
H2S Removal Unit
Sulfur Recovery
Building and Ductwork Not Costed
in Above Equipment Costs
(6% of EC)
Total Installed Equipment (EC)
INDIRECT INSTALLATION COSTS
Engineering (10Z of EC)
Construction and Field
Expense (10% of EC)
Construction Fees (10% of EC)
Startup (2Z of EC)
Total Indirect Costs (1C)
CONTINGENCIES (302 of EC + 1C)
TOTAL TURNKEY COSTS (TTC)
WORKING CAPITAL (25% of Total Direct
Operating Costs)
TOTAL CAPITAL INVESTMENT
8.8(30)
370
500
60
50
30
100
90
1,540
170
2,910
290
290
290
60
930
1,150
4,990
210
5,200
22(75)
390
1,000
70
80
40
180
150
1,710
230
3,850
390
390
390
80
1,250
1,530
6,630
370
7,000
44(150)
440
2,000
100
120
70
240
170
2,330
350
5,820
580
580
580
120
1,860
2,300
9,980
630
10,610
58.6C?00)
600
2,500
120
140
90
310
200
2,710
430
7,100
710
710
710
140
2,270
2,810
12,180
800
12,980
117.2(400)
790
5,000
240
280
170
620
400
3,940
730
12,170
1,220
1,220
1,220
240
3,900
4,820
20,890
1,520
22,410
103 mid-1978 dollars
-------
TABLE A-5. ANNUALIZED COSTS FOR LOW-BTU WELLMAN-GALUSHA
GASIFICATION SYSTEMS
r
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - Stretford
S02 Control Level - Moderate
Operating Factor - 60%
System Capacity, MWT (106 Btu/hr)
DIRECT OPERATING COSTS
Operating Labor (@ $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance (6% of Total
Turnkey Costs x 0.8)
Replacement Farts (included
in maintenance)
Electricity «? 25.8 mills/kW-hr)
Steam (9 S5.00/GJ)
Cooling Water (@ $0.05/m3)
Process Water (@ $0.04/m3)
Coal Ǥ $18.72/ton)
Cliemlcals
Sulfur, Ash Disposal
«a $44.00/ton)
Total Direct Operating Costs
OVERHEAD COSTS
Payroll (30% of operating labor)
Plant (26% of labor, parts and
maintenance)
Total Overhead Costs
CAPITAL CHARGES
G&A, Local Taxes, and
Insurance (4% of Total
Turnkey Costs)
Capital Recovery (11.75% of
Total Turnkey Costs)
Interest on Working Capital
(? 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS
Average Gas Cost, $/GJ
8.8(30)
210
70
240
-
20
<10
20
-
160
50
70
840
60
140
200
200
590
20
_810
1850
11.10
22(75)
260
70
320
-
60
10
40
_
410
120
190
1480
80
170
250
270
780
40
1090
2820
6.75
44(150)
320
70
480
-
110
20
90
-
810
230
370
2500
100
230
330
400
1170
60
1.630
4460
5.35
58.6(200)
370
70
580
-
150
20
120
_
1080
310
500
3200
110
270
380
490
1430
80
2000
5580
5.05
117.2(400)
580
140
1000
_
300
40
230
_
2150
630
1000
6070
170
450
620
840
2450
150
3440
10,130
4.55
103 Mid-1978 dollars
-------
TABLE A-6. ANNUALIZED COSTS FOR LOW-BTU GAS-FIRED
INDUSTRIAL BOILERS
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - S tret ford
S02 Control Level - Moderate
Operating Factor - 60%
System Capacity, MW (106 Btu/hr)
CAPITAL INVESTMENT, 10 '$
Total Turnkey Costs (TTC)
Lnnd
Working Capital (25% of Total
Direct Operating Costs,
excluding fuel costs)
Total Capital. Requirement
OPERATING COSTS, io3 $/yr
Direct Costs
Operating Labor (@ $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance Labor (@ $14.63/hr)
Replacement Parts
F,lectrici"ty (@ 25.8 ratlls/kW-hr)
Process Water (? $0.04/m3)
Fuel
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30% of operating labor)
Plant (26% of labor and parts)
Total Overhead Costs
Capital Charges
G&A, Local Taxes, and
Insurance (4% of TTC)
Capital Recovery Factor
(10. 6U of TTC)
Interest on Working Capital
(1? 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS, 10 3 $/yj-
8.8(30)
640
<10
70
710
110
70
30
30
30
<10
1850
<10
2120
30
—IP-
go
30
70
10
no
2320
22(75)
1110
<10
70
1180
110
70
30
40
40
<10
2820
<10
3110
30
70
100
40
120
10
170
3380
44(150)
1740
<10
120
1860
210
70
60
60
50
<10
4460
10
4920
60
-li".0-
160
70
180
10
_26£
5340
58.6(?00)
2070
<10
120
2190
210
70
60
70
50
'10
5580
to
6050
60
JML()
170
80
220
10
_JLL°-
6530
117.2(400)
4150
<10
200
4350
320
70
130
14 (t
100
10
10,130
in
10,9 in
I0f>
170
270
] 70
440
20
610
1 1 ,R|0
Mid-1978 dollnrs
-------
TABLE A-7. CAPITAL INVESTMENT REQUIREMENTS FOR LOW-BTU
WELLMAN-GALUSHA GASIFICATION SYSTEMS
00
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - MEA
SO 2 Control Level - Moderate, Intermediate or Stringent
System Capacity, MWT (10s Btu/hr)
INSTALLED EQUIPMENT COSTS
Coal Receiving and Storage
Gasification System
Gaa Purification System
Blower/Compressor
Quench/Cooling Towers
Pumps (for cooling liquor)
Electrostatic Precipitator
Separator/Evaporator
H2S Removal Unit
Sulfur Recovery Unit
Building and Ductwork Not Coated
in Above Equipment Costs
(6% of EC)
Total Installed Equipment (EC)
INDIRECT INSTALLATION COSTS
Engineering (10Z of EC)
Construction and Field
Expense (10Z of EC)
Construction Fees (10Z of EC)
Startup (2Z of EC)
Total Indirect Costs (1C)
CONTINGENCIES (30Z of EC + 1C)
TOTAL TURNKEY COSTS (TTC)
WORKING CAPITAL (25Z of Total Direct
Operating Costs)
TOTAL CAPITAL INVESTMENT
8.8(30)
370
500
240
50
30
100
120
140
1,640
200
3,390
340
340
340
70
1,090
1.340
5,820
230
6,050
22(75)
390
1,000
290
80
40
180
190
300
2,170
300
4,940
490
490
490
100
1,570
1,950
8,460
420
6,880
44(150)
440
2,000
380
120
70
240
250
490
2,710
430
7,130
710
710
710
140
2,270
2.820
12,220
700
12,920
58.6(200)
600
2,500
530
140
90
310
280
560
3,000
510
8,520
850
850
850
170
2,720
3.370
14,610
990
15,600
103 mid-1978 dollars
-------
>
TABLE A-8. ANNUALIZED COSTS FOR LOW-BTU WELLMAN-GALUSHA
GASIFICATION SYSTEMS
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - HEA
SOz Control Level - Moderate, Intermediate or Stringent
Operating Factor - 60%
System Capacity. NW (106 Btu/hr)
DIRECT OPERATING COSTS
Operating Labor (@ $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance (6% of Total
Turnkey Costs x 0.8)
Replacement Parts (included
in maintenance)
Electricity (@ 25.8 mills/kW-hr)
Steam (@ $5.00/GJ)
Cooling Water (@ $0.05/m3)
Process Water (@ $0.04/m3)
Coal (0 $18.72/ton)
Chemicals
Sulfur, Ash Disposal
(@ $44.00/ton)
Total Direct Operating Costs
OVERHEAD COSTS
Payroll (30% of operating labor)
Plant (26% of labor, parts and
maintenance)
Total Overhead Costs
CAPITAL CHARGES
G&A, Local Taxes, and
Insurance (4% of Total
Turnkey Costs)
Capital Recovery (11.75% of
Total Turnkey Costs)
Interest on Working Capital
(@ 10%)
Tot.il Capital Charges
1'OTAI, ANNUALIZED COSTS
Average Gag Cost, S/GJ
8.8(30)
210
70
280
70
50
20
160
10
60
930
60
150
210
230
680
20
_9.3P.
2070
12.45
22(75)
260
70
410
160
120
50
410
30
160
1670
80
190
270
340
990
40
1170
3310
7.95
44(150)
320
70
590
330
230
90
810
60
320
2820
100
250
350
490
1440
70
2000
5170
6.20
58.6(2(
370
70
700
440
310
120
1080
80
420
3590
110
300
410
580
1720
100
2400
6400
5.75
103 mid-1978 dollars
-------
TABLE A-9. ANNUALIZED COSTS FOR LOW-BTU GAS-FIRED
INDUSTRIAL BOILERS
I
M
o
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - MEA
SOj Control Level - Moderate, Intermediate or Stringent
Operating Factor - 60%
System Capacity, MW (106 Btu/hr)
CAPITAL INVESTMENT, 10 ' $
Total Turnkey Costs (TTC)
Land
Working Capital (25% of Total
Direct Operating Costs,
excluding fuel costs)
Total Capital Requirement
OPERATING COSTS, 10 3 $/yr
Direct Costs
Operating Labor (@ $12.02/hr)
Supervision (9 515.63/hr)
Maintenance Labor (@ $14.63/hr)
Replacement Parts
Electricity (@ 25.8 mills/kW-hr)
Process Water (@ $0.04/m3)
Fuel
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30% of operating labor)
Plant (26% of labor and parts)
Total Overhead Costs
Capital Charges
G&A, Local Taxes, and
Insurance (4% of TTC)
Capital Recovery Factor
(10.61% of TTC)
Interest on Working Capital
«? 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS, 10s $/yr
8.8(30)
640
<10
70
750
110
70
30
30
30
<10
2,070
<10
2,340
30
60
90
30
70
10
110
2,540
22(75)
1,110
<10
70
1,180
110
70
30
40
40
<10
3,310
<10
3,600
30
70
100
40
120
10
170
3,870
44(150)
1,740
<10
170
1,860
210
70
60
60
50
<10
5,170
10
5,630
60
100
160
70
180
10
260
6,050
58.6(200)
2,070
<10
120
2,190
210
70
60
70
50
<10
6,400
10
6,870
60
110
170
80
220
10
310
7,350
Mid-1978 dollars
-------
APPENDIX B
CAPITAL INVESTMENT REQUIREMENTS
AND ANNUALIZED COSTS
FOR MEDIUM-BTU COAL GASIFICATION SYSTEMS
AND MEDIUM-BTU GAS-FIRED INDUSTRIAL BOILERS
B-l
-------
TABLE B-l. ESTIMATED INSTALLED EQUIPMENT COSTS FOR LURGI MEDIUM-BTU GASIFICATION SYSTEMS*
1"
Low Sulfur Western Coal
Process Area
Coal Storage and Reclaiming
Coal Preparation
Coal Feed 1
Gasification [
Raw Gas Quench )
Acid Gas Removal
Product Gas Drying
Sour Water Stripping, Ammonia
Recovery, and Bio-Oxidation
Sulfur Recovery
Solids Disposal
Steam and Utility Systems
Plant Water Systems
Oxygen Plant
General Facilities
TOTAL INSTALLED EQUIPMENT COSTS
Stretford
17
20
162
11
0.9
22
-
3.5
228
26
77
96
663.4
Rectisol
17
20
162
136
0,9
22
16
3.5
233
26
77
96
809.4
High Sulfur Eastern Coal
Stretford
16
19
162
33
0.9
22
-
5.6
324
26
95
96
799.5
Rectisol
16
19
162
169
0.9
22
40
5.5
316
26
95
96
967.4
a3060 MW (250 x 109 Btu/day) capacity (gas output); mid-1978 dollars; 106 dollars.
-------
TABLE B-2. ESTIMATED TOTAL CAPITAL REQUIREMENTS FOR LURGI MEDIUM-BTU GASIFICATION SYSTEMS*
DO
I
u>
Low Sulfur western coal
Total Engineered Equipment Costs (EC)
(including direct installation costs)
Installation Costs, indirect
Engineering and Fee (10% of EC)
Construction and Field Expense
(included in Equipment Costs)
Contingencies (30% of EC)
Allowance for Funds Used During
Construction (EC x Average Spending
Period (1.75 yrs) x 10%)
Paid-up Royalties
Startup Costs (20% of total gross
annual operating costs)
Land
Working Capital (25% total direct
operating costs)
Total Capital Requirement
Stretford
663.4
66.3
218.9
116.1
1.1
23.1
0.9
26.0
1115.8
Rectisol
809.4
80.9
267.1
141.6
1.1
24.4
0.9
27.7
1353.1
High sulfur eastern coal
Stretford
799.5
80.0
263.9
139.9
1.1
38.4
0.9
45.0
1368.7
Rectisol
967.4
96.7
319.2
169.3
1.1
40.8
0.9
47.3
1642.7
*3060 MW (250 x 109 Btu/day) capacity (gas output); mid-1978 dollars; 106 dollars.
-------
TABLE B-3. ESTIMATED MAINTENANCE COSTS FOR LURGI
MEDIUM-BTU GASIFICATION SYSTEM3
Coal Feedstock
Acid Gas Removal Unit
Unit
Unit Cost
Coal Handling and Reclaiming 24
Coal Preparation 29
Coal Feed
Gasification 232
Raw Gas Quench
Acid Gas Removal 16
Product Gas Drying 1
Liquid Effluent Treatment 31
Sulfur Recovery
Solids Disposal 5
Steam and Utilities Systems 326
Plant Water Systems 37
Oxygen Plant 110
General Facilities 137
TOTAL 948
Maintenance Labor
Ǥ 60% of Total Maintenance)
Maintenance Supplies
(@ 40% of Total Maintenance)
Low sulfur western
Stretford
Maintenance
Factor, %
6
6
3
3
3
3
3
1
3
3
1
Maintenance
Cost
1.4
1.7
11.6
0.5
0.03
0.9
0.2
3.3
1.1
3.3
1.4
25.4
15.2
10.8
a3060 MWT (250 x 109 Btu/day) gas output capacity; 106 mid-1978 dollars.
B-4
-------
TABLE B-4. ANNUALIZED COSTS FOR LURGI MEDIUM-BTU
GASIFICATION SYSTEM3
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Stretford
Operating Factor - 902
Direct Costs
Operating Labor (I? $12.02/hr) 6.3
Maintenance Labor (60Z of Total Maintenance) 15.2
Supervision (20Z of Operating and Maintenance Labor) 4.3
Maintenance Materials (40* of Total Maintenance) 10.8
Replacement Parts (Included in Maintenance Materials)
Operating Supplies (302 of Operating Labor) 1.9
Purchased Water (@ $0.032/m3) o.l
Coal (@ $8.88/ton) 58.3
Chemicals and Catalysts 2.3
Solids Disposal «? $11/ton) 4.7
Total Direct Costs . 103.9
Overhead Costs
Payroll (30* of Operating Labor) 1.9
Plant (26Z of Labor, Materials, and Maintenance) 9.5
Total Overhead Costs 11.4
By-Product Credits
Sulfur Ǥ $29/ton) 0.8
Ammonia (9 $110/ton) 5.2
Naphtha «? $93/m3)
Phenols (@ $46/m3) 1.1
Tars (9 $46/n3) 8.7
Oils (@ $79/mJ) 8.7
Total By-Product Credits (24.5)
Capital Related Charges
G&A, Local Taxes, and Insurance (4Z of Total 42.6
Capital Requirement Excluding Start-up Costs,
Land, and Working Capital)
Capital Recovery (11.75* of Total Capital 127.9
Requirement Excluding Land and Working Capital)
Interest on Working Capital (@ 10Z) 2.6
Total Capital Related Charges 173.1
TOTAL ANNUALIZED COSTS 263.9
Average Gas Costs, $/GJ ($/10* Btu) 3.05 (3.20)
Average Gas Costsb, $/GJ $/106 Btu) 4.30 (4.55)
*3060 MW_ (250 x 109 Btu/day) output gas capacity; 10s mid-1978 dollars.
^ A
At 60X operating factor.
B-5
-------
TABLE B-5. ESTIMATED MAINTENANCE COSTS FOR LURGI
MEDIUM-BTU GASIFICATION SYSTEM3
Coal Feedstock
Acid Gas Removal
Unit
Coal Handling and Reclaiming
Coal Preparation
Coal Feed
Gasification
Raw Gas Quench
Acid Gas Removal
Product Gas Drying
Liquid Effluent Treatment
Sulfur Recovery
Solids Disposal
Steam and Utilities Systems
Plant Water Systems
Oxygen Plant
General Facilities
TOTAL
Maintenance Labor
(@ 60% of Total Maintenance)
Maintenance Supplies
(@ 40% of Total Maintenance)
Unit
Unit
Cost
24
29
232
194
1
31
23
5
333
37
110
137
1156
Low sulfur western
Rectisol
Maintenance
Factor, %
6
6
5
3
3
3
3
3
1
3
3
1
Maintenance
Cost
1.4
1.7
11.6
5.8
0.03
0.9
0.7
0.2
3.3
1.1
3.3
1.4
31.4
18.8
12.6
13060 MW (250 x 109 Btu/day) gas output capacity; 106 mid-1978 dollars.
B-6
-------
TABLE B-6. ANNUALIZED COSTS FOR LURGI MEDIUM-BTU
GASIFICATION SYSTEM3
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Rectisol
Operating Factor - 902
Direct Costs
Operating Labor (3 $12.02/hr) 6.3
Maintenance Labor (602 of Total Maintenance) 18.8
Supervision (201 of Operating and Maintenance Labor) 5.0
Maintenance Materials (401 of Total Maintenance) 12.6
Replacement Farts (Included in Maintenance Materials)
Operating Supplies (30Z of Operating Labor) 1.9
Purchased Water (@ $0.032/m3) 0.1
Coal «? $8.88/ton) 58.9
Chemicals and Catalysts 2.3
Solids Disposal (@ $ll/ton) 4.8 .
Total Direct Costs 110.7
Overhead Costs
Payroll (30Z of Operating Labor) 1.9
Plant (26X of Labor, Materials, and Maintenance) 9.4
Total Overhead Costs 11.3
By-Product Credits
Sulfur (9 $29/ton) 0.8
Ammonia (9 $110/ton) 5.2
Naphtha (@ $93/m3) 6.6
Phenols (@ $46/m3) 1.1
Tars (@ $46/m3) 8.7
Oils (8 $79/mJ) 8.7
Total By-Product Credits (31.1)
Capital Related Charges
G&A, Local Taxes and Insurance (4Z of Total Capital 52.0
Requirement Excluding Start-up Costs, Land, and
Working Capital)
Capital Recovery (11.75Z of Total Capital Require- 155.6
ment Excluding Land and Working Capital)
Interest on Working Capital Ǥ 10Z) 2.8
Total Capital Related Charges 210.4
TOTAL ANNUALIZED COSTS . 301.3
Average Gas Costs, $/GJ ($/10' Btu) 3.45 (3.65)
Average Gas Costs1", $/GJ ($/106 Btu) 5.00 (5.30)
*3060 MW (250 x 109 Btu/day) output gas capacity; 10s mid-1978 dollars.
u
At 60Z operating factor.
B-7
-------
TABLE B-7. ESTIMATED MAINTENANCE COSTS FOR LURGI
MEDIUM-BTU GASIFICATION SYSTEM3
Coal Feedstock
Acid Gas Removal
Unit
Coal Handling and Reclaiming
Coal Preparation
Coal Feed
Gasification
Raw Gas Quench
Acid Gas Removal
Product Gas Drying
Liquid Effluent Treatment
Sulfur Recovery
Solids Disposal
Steam and Utilities Systems
Plant Water Systems
Oxygen Plant
General Facilities
TOTAL
Maintenance Labor
(@ 60% of Total Maintenance)
Maintenance Supplies
(@ 40% of Total Maintenance)
Unit
Unit
Cost
23
27
232
47
1
31
-
8
463
37
136
137
1142
High sulfur eastern
Stretford
Maintenance
Factor, %
6
6
5
3
3
3
3
3
1
3
3
1
Maintenance
Cost
1.4
1.6
11.6
1.4
0.03
0.9
-
0.2
4.6
1.1
4.1
1.4
28.3
17.0
11.3
13060 MW (250 x 109 Btu/day) gas ouput capacity; 106 mid-1978 dollars.
B-8
-------
TABLE B-8. ANNUALIZED COSTS FOR LURGI MEDIUM-BTU
GASIFICATION SYSTEM3
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - Stretford
Operating Factor - 90%
Direct Costs
Operating Labor «? $12.02/hr) 6.3
Maintenance Labor (60% of Total Maintenance) 17.0
Supervision (20% of Operating and Maintenance Labor) 4.7
Maintenance Materials (40% of Total Maintenance) 11.3
Replacement Parts (Included in Maintenance Materials) -
Operating Supplies (30% of Operating Labor) 1.9
Purchased Water (@ $0.032/m3) 0.1
Coal (@ $18.72/ton) 116.6
Chemicals and Catalysts 6.4
Solids Disposal (@ $ll/ton) . 15.6
Total Direct Costs 179.9
Overhead Costs
Payroll (30% of Operating Labor) 1.9
Plant (26% of Labor, Materials, and Maintenance) 10.2
Total Overhead Costs 12.1
By-Product Credits
Sulfur (@ $29/ton) 4.3
Ammonia (@ $110/ton) 3.3
Naphtha (@ $93/m3)
Phenols (3 $46/m3) 0.7
Tars (@ $46/m3) 5.8
Oils (@ $79/m3) 1.2
Total By-Product Credits (15.3)
Capital Related Charges
G&A, Local Taxes and Insurance (4Z of Total 51.4
Capital Requirement Excluding Start-up Costs,
Land, and Working Capital)
Capital Recovery (11.75% of Total Capital Require- 155.4
ment Excluding Land and Working Capital)
Interest on Working Capital (@ 10%) 4.5
Total Capital Related Charges 211.3
TOTAL ANNUALIZED COSTS 388.0
Average Gas Costs, $/GJ ($/106 Btu) 4.45 (4.70)
Average Gas Costsb, $/GJ (?/106 Btu) 6.00 (6.35)
33060 MW (250 x 109 Btu/day) output gas capacity; 106 mid-1978 dollars.
U ^
At 60% operating factor.
B-9
-------
TABLE B-9. ESTIMATED MAINTENANCE COSTS FOR LURGI
MEDIUM-BTU GASIFICATION SYSTEM3
Coal Feedstock
Acid Gas Removal
Unit
Coal Handling and Reclaiming
Coal Preparation
Coal Feed
Gasification
Raw Gas Quench
Acid Gas Removal
Product Gas Drying
Liquid Effluent Treatment
Sulfur Recovery
Solids Disposal
Steam and Utilities Systems
Plant Water Systems
Oxygen Plant
General Facilities
TOTAL
Maintenance Labor
(@ 60% of Total Maintenance)
Maintenance Supplies
(@ 40% of Total Maintenance)
Unit
Unit
Cost
23
27
232
242
1
31
57
8
452
37
136
137
1383
High sulfur eastern
Rectisol
Maintenance
Factor, %
6
6
5
3
3
3
3
3
1
3
3
1
Maintenance
Cost
1.4
1.6
11.6
7.3
0.03
0.9
1.7
0.2
4.5
1.1
4.1
1.4
35.8
21.5
14.3
*3060 MW (250 x 109 Btu/day) gas output capacity; 106 mid-1978 dollars.
B-10
-------
TABLE B-10. ANNUALIZED COSTS FOR LURGI MEDIUM-BTU
GASIFICATION SYSTEM3
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - Rectisol
Operating Factor - 90%
Direct Costs
Operating Labor (9 $12.02/hr) 6.3
Maintenance Labor (60% of Total Maintenance) 21.5
Supervision (20% of Operating and Maintenance Labor) 6.6
Maintenance Materials (40% of Total Maintenance) 14.3
Replacement Parts (Included in Maintenance Materials)
Operating Supplies (30% of Operating Labor) 1.9
Purchased Water (@ ?0.032/m5) 0.1
Coal (@ $18.72/ton) 116.0
Chemicals and Catalysts 6.4
Solids Disposal (@ $ll/ton) 16.1
Total Direct Costs 189.2
Overhead Costs
Payroll (30% of Operating Labor) 1.9
Plant (26% of Labor, Materials, and Maintenance) 12.7
Total Overhead Costs 14.6
By-Product Credits
Sulfur Ǥ $29/ton) " 4.3
Ammonia (i? $110/ton) 3.3
Naphtha (@ $93/m3) 4.4
Phenols (@ $46/m3) 0.7
Tars (@ $46/m3) 5.8
Oils ((§ $79/m3) 1.2
Total By-Product Credits (19.7)
Capital Related Charges
G&A, Local Taxes and Insurance (4% of Total Capital 62.1
Requirement Excluding Start-up Costs, Land,
and Working Capital)
Capital Recovery (11.75% of Total Capital Require- 187.4
ment Excluding Land and Working Capital)
Interest on Working Capital (@ 10%) 4.7
Total Capital Related Charges 254.2
TOTAL ANNUALIZED COSTS 438.3
Average Gas Costs, $/GJ ($/106 Btu) 5.05 (5.35)
Average Gas Costs'3, 5/GJ ($/106 Btu) 6.90 (7.30)
a3060 MWT (250 x 109 Btu/day) output gas capacity; 10s mid-1978 dollars.
At 60% operating factor.
B-ll
-------
TABLE B-ll. ANNUALIZED COSTS FOR MEDIUM-BTU
GAS-FIRED INDUSTRIAL BOILERS
Coal Feedstock -
Acid Gas Removal
SOa Control Level
Operating
8
CAPITAL INVESTMENT, 10 3 $
Total Turnkey Costs (TTC)
Land
Working Capital (257, of Total
Direct Operating Costs)
Total Capital Requirement
OPERATING COSTS, 10 3 $/yr
Direct Costs
Operating Labor (@ $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance Labor (0 $14.63/hr)
Replacement Parts
Electricity (@ 25.8 mills/kW-hr)
Process Water (@ $0.04/m3)
Fuel (@ $4.30/GJ)
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30% of operating labor)
Plant (26% of labor and parts)
Total Overhead Costs
Capital Charges
GJ.A, Local Taxes, and
Insurance (4% of TTC)
Capital Recovery Factor
(10.61% of TTC)
Interest on Working Capital
//a irw*\
^l? LU/o)
Total Capital Charges
TOTAL AKOJALIZED COSTS, 10 3 S/yr
Factor
.3(30)
640
<10
250
890
110
70
30
30
30
<10
720
<10
990
30
60
90
30
70
30
130
1,210
Low Sulfur Western
Unit - Stretford
- Stringent
- 60%
System Capacity
. MWT
22(75) 44(150)
110 1
<10
520 1
630 2
110
70
30
40
40
<10
1,790 3,
<10
2,080 "77
30
70
100
40
120
50
210
2,390 4,
,740
<10
,010
,750
210
70
60
60
50
<10
580
10
040
60
100
160
70
180
100
350
550
(106Btu/hr)
58.6(200)
2,070
<10
1,310
3,380
210
70
60
70
50
<10
4,770
10
5,240
60
110
170
80
220
130
430
5,840
Mid-1978 dollars.
B-12
-------
TABLE B-12. ANNUALIZED COSTS FOR MEDIUM-BTU
GAS-FIRED INDUSTRIAL BOILERS
Coal Feedstock - Low Sulfur Western
Acid Gas Removal Unit - Rectisol
S02 Control Level - Stringent
Operating Factor - 60S
System Capacity, MW (10°Btu/hr)
CAPITAL INVESTMENT, 10 3 S
Total Turnkey Costs (TTC)
Land
Working Capital (25% of Total
Direct Operating Costs)
Total Capital Requirement
OPERATING COSTS, 10 3 $/yr
Direct Costs
Operating Labor (@ $12.02/hr)
Supervision (? $15.63/hr)
Maintenance Labor (@ $14.63/hr)
Replacement Parts
Electricity (@ 25.8 mills/kW-hr)
Process Water (@ $0.04/m3)
Fuel (@ $5.00/GJ)
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30% of operating labor)
Plant (26% of labor and parts)
Total Overhead Costs
Capital Charges
G&A, Local Taxes, and
Insurance (4% of TTC)
Capital Recovery Factor
(10.61% of TTC)
Interest on Working Capital
(@ 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS, 10 3 $/yr
8.8(30)
640
<10
280
920
110
70
30
30
30
<10
830
<10
1,100
30
60
90
30
70
30
130
1,320
22(75)
1,110
<10
590 •
1,700
110
70
30
40
40
<10
2,080
<10
2,370
30
70
100
40
120
•
60
220
2,690
44(150)
1,740
<10
1,160
2,900
210
70
60
60
50
<10
4,160
10
4,620
60
100
160
70
180
120
370
5,150
58.6(200)
2,070
<10
1,500
3,570
210
70
60
70
50
5,540
10
6,010
60
110
170
80
220
150
450
6,630
Mid-1978 dollars.
B-13
-------
TABLE B-13.
ANNUALIZED COSTS FOR MEDIUM-BTU
GAS -FIRED INDUSTRIAL BOILERS
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - Stretford
SC>2 Control Level - Intermediate
Operating Factor - 60%
System Capacity, MW (106Btu/hr)
CAPITAL INVESTMENT, 10 3 $
Total Turnkey Costs (TTC)
Land
Working Capital (25% of Total
Direct Operating Costs)
Total Capital Requirement
OPERATING COSTS, 10 3 $/yr
Direct Costs
Operating Labor (@ $12.02/hr)
Supervision ((? $15.63/hr)
Maintenance Labor (@ $14.63/hr)
Replacement Parts
Electricity (@ 25.8 mills/kW-hr)
Process Water (@ $0.04/m3)
Fuel (@ $6.00/GJ)
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30% of operating labor)
Plant (26% of labor and parts)
Total Overhead Costs
Capital Charges
G&A, Local Taxes, and
Insurance (4X of TTC)
Capital Recovery Factor
(10.61% of TTC)
Interest on Working Capital
(@ 10%)
Total Capital Charges
TOTAL ANNUALIZED COSTS, 10 3 $/yr
8.8(30)
640
<10
320
960
110
70
30
30
30
<10
1,000
<10
1,270
30
60
90
30
70
30
130
1,490
22(75)
1,110
<10
700
1,810
110
70
30
40
40
<10
2,500
<10
2,790
30
70
100
40
120
70
230
3,120
44(150)
1,740
<10
1,370
3,100
210
70
60
60
50
<10
5,000
10
5,460
60
100
160
70
180
140
390
6,010
58.6(200)
2,070
<10
1,780
3,850
210
70
60
70
50
<10
6,650
10
7,120
60
110
170
80
220
180
480
7,770
Mid-1978 dollars.
B-14
-------
TABLE B-14.
ANNUALIZED COSTS FOR MEDIUM-BTU
GAS-FIRED INDUSTRIAL BOILERS
Coal Feedstock - High Sulfur Eastern
Acid Gas Removal Unit - Rectisol
SOj Control Level - Stringent
Operating Factor - 60%
System Capacity, MW (106Btu/hr)
CAPITAL INVESTMENT, 10 3 $
Total Turnkey Costs (TTC)
Land
Working Capital (252 of Total
Direct Operating Costs)
Total Capital Requirement
OPERATING COSTS, 10 3 $/yr
Direct Costs
Operating Labor (@ $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance Labor «? $14.63/hr)
Replacement Parts
Electricity (@ 25.8 mills/kW-hr)
Process Water (@ $0.04/m3)
Fuel «? $6.90/GJ)
Chemicals
Total Direct Operating Costs
Overhead
Payroll (30% of operating labor)
Plant (26% of labor and parts)
Total Overhead Costs
Capital Charges
G&A, Local Taxes, and
Insurance (4% of TTC)
Capital Recovery Factor
(10.61% of TTC)
Interest on Working Capital
in , r\"/\
(I? lux;
Total Capital Charges
TOTAL ANNUALIZED COSTS, 10 3 $/yr
8.8(30)
640
<10
360
1,000
110
70
30
30
30
<10
1,150
<10
~1,420
30
60
90
30
70
40
140
1,650
22(75)
1,110
<10
790
1,900
110
70
30
40
40
<10
2,870
<10
3,160
30
70
100
40
120
80
240
3,500
44(150)
1,740
<10
1,550
3,290
210
70
60
60
50
<10
5,740
10
6,200
60
100
160
70
180
160
410
6,770
58.6(200)
2,070
<10
2,030
4,100
210
70
60
70
50
<10
7,650
10
8,120
60
110
170
80
220
200
500
8,790
Mid-1978 dollars.
B-15
-------
APPENDIX C
CAPITAL INVESTMENT REQUIREMENTS
AND ANNUALIZED COSTS FOR
COAL LIQUEFACTION SYSTEMS AND
COAL LIQUIDS-FIRED INDUSTRIAL BOILERS
C-l
-------
TABLE C-l. TOTAL CAPITAL REQUIREMENT FOR SRC-I PROCESS
Coal Feedstock High Sulfur Bituminous
Capacity 7050 MWT(577 x 109 Btu/day)
SC-2 Control Level Moderate
Installed Equipment Costs
Coal preparation 90
Hydrogenation and hydrogen recycle 221
Fractionation 27
Hydrogen plant 342
Filtration ' 192
Product solidification 28
Gas and secondary recovery 90
Offsites and wastewater treatment 110
General Facilities 86
Total Installed Equipment (EC) 1,186
Engineering and fee (included in direct costs)
Construction and field expense (included in
direct costs)
Contingencies (30% of EC) 356
Start-up Costs (20% of total gross annual
operating costs) 59
Allowance for funds used during construction
(EC x 1.75 x 0.10) 208
Land 2
Working capital (25% of total direct annual
operating costs) 73
Total Indirect Costs 698
TOTAL CAPITAL REQUIREMENT 1,884
106 mid-1978 dollars
C-2
-------
TABLE C-2. ANNUALIZED COSTS FOR SRC-I PROCESS
Coal Feedstock
Capacity
SOa Control Level
Operating Factor
High Sulfur Bituminous
7050 MWT(577 x 109 Btu/day)
Moderate
80%
Direct Costs
Manpower
Repair materials and other
Electricity (@ 25.8 mills/kW-h)
Purchased water (@ $0.032/m3)
Catalysts and Chemicals
Coal «? $18.72/ton)
Total Direct Costs
31
48
16
<1
6
163
264
Overhead
Payroll (30% of labor)
Plant (26% of labor, parts and maintenance)
Total Overhead Costs
General and Administrative Costs, Local Taxes
and Insurance (4% of total capital requirement
excluding land and working capital)
By-Product Credits
Capital Recovery Factor (11.75% of total
capital requirement excluding land and
working capital)
Interest on working capital
9
20
29
72
(9)
213
7
TOTAL ANNUALIZED COSTS
Average Product Cost, $/GJ
576
3.25
106 mid-1978 dollars
C-3
-------
TABLE C-3. ANNUALIZED COSTS FOR SRC (SOLID)-FIRED INDUSTRIAL BOILER
Boiler Size
Coal Feedstock
SOa Control Level
Operating Factor
58.6 MWT (200 x 106 Btu/hr)
High sulfur bituminous
Moderate
CAPITAL INVESTMENT, 10*$
Total Turnkey Costs (TTC) 10,199
Land 2
Working capital (25% of total 1,213
direct operating costs)
Total Capital Requirement 11,414
OPERATING COSTS, 103$/yr
Direct Costs
Direct labor Ǥ $12.02/hr) 421
Supervision (@ $15.63/hr) 137
Maintenance labor (@ $14.63/hr) 192
Replacement parts 250
Electricity (@ 25.8 mills/kWhr) 238
Process water (@ $0.04/m3) 3
Fuel Ǥ $3. 25/GJ) 3,604
Chemicals 8
Total Direct Operating Costs
Overhead
Payroll (30% of labor) 226
Plant (26% of labor and parts) 260
Total Overhead Costs
Capital Charges
G&A, local taxes, and insurance 408
(4% of TTC)
Capital recovery factor 1,034
(10.14% of TTC)
Interest on working capital 121
«a 10%)
Total Capital Charges
4,853
486
1,563
TOTAL ANNUALIZED COSTS, 103$/yr
6,802
Mid-1978 dollars.
C-4
-------
TABLE C-4. TOTAL CAPITAL REQUIREMENTS FOR EXXON DONOR SOLVENT PROCESS
Coal Feedstock High Sulfur Bituminous
Capacity 4000 MW (328 x 109 Btu/day)
S02 Control Level Intermediate*
Installed Equipment Costs
Liquefaction 218
Solvent hydrogenation 74
Flexicoker 145
Hydrogen recovery and generation 218
Gas and wastewater treatment 44
Product recovery 7
Offsites 224
Total Equipment Costs (EC) 930
Engineering and fee (10% of EC) 93
Construction and field expense
(included in direct costs)
Contingencies (30% of EC + Engineering + Fee) 307
Start-up costs (20% of total gross annual
operating costs 53
Allowance for funds used during construction
(EC x 1.75 x 0.10) 163
Land 2
Working capital (25% of total direct annual
operating costs) 66
Total Indirect Costs 684
TOTAL CAPITAL REQUIREMENT 1,614
*Additional hydroprocessing will permit attainment of stringent control
levels. Additional costs incurred for hydroprocessing cannot be determined
and are assumed to be negligible.
106 mid-1978 dollars
C-5
-------
TABLE C-5. ANNUALIZED COSTS FOR EXXON DONOR SOLVENT PROCESS
Coal Feedstock High Sulfur Bituminous
Capacity 4000 MW (328 x 109 Btu/day)
SOz Control Level Intermediate*
Operating Factor 80%
Direct Costs
Manpower 31
Repair materials and other 48
Electricity (@ 25.8 mills/kW-h) 32
Purchased water (@ $0.032/m3) <1
Catalysts and Chemicals - 6
Coal (@ $18.72/ton) 119
Total Direct Costs 236
Overhead
Payroll (30% of labor) 9
Plant (26% of labor, parts and maintenance) 20
Total Overhead Costs 29
General and Administrative Costs, Local
Taxes and Insurance (4% of total capital
requirements excluding land and working
capital) 62
By-Product Credits (16)
Capital Recovery Factor (11.75% of total
capital requirement excluding land and
working capital) 213
Interest on working capital 7
TOTAL ANNUALIZED COSTS 576
Average Product Cost, $/GJ 4.95
*Additional hydroprocessing will permit attainment of stringent control levels.
Additional costs incurred for hydroprocessing cannot be determined and are
assumed to be negligible.
106 mid-1978 dollars
C-6
-------
TABLE C-6. ANNUALIZED COSTS FOR EDS LIQUIDS-FIRED INDUSTRIAL BOILE1
o
Coal Feedstock - High Sulfur Eastern
SO 2 Control Level - Stringent
Operating, Factor - 60Z
System
CAPITAL INVESTMENT, 103 $
Total Turnkey Costs (TTC)
Land
Working Capital (25Z of Total Direct
Operating Costs
Total Capital Requirement
OPERATING COSTS, 10 ' $/yr
Direct Costs
Operating Labor (9 $12.02/hr)
Supervision (@ $15.63/hr)
Maintenance Labor (@ $14.63/hr)
Replacement Parts
Electricity (g 25.8 mills/kW-hr)
Process Water (9 $0.04/m3)
Fuel (0 $4.95/GJ)
Chemicals
Total Direct Operating Coats
Overhead
Payroll (30Z of operating labor)
Plant (261 of labor and parts)
Total Overhead Coats
Capital Charges
G&A, Local Taxes, and Insurance
(4Z of TTC)
Capital Recovery Factor
(10.611 of TTC)
Interest on Working Capital
(e ioz)
Total Capital Charges
TOTAL ANNUALIZED COSTS, 10 3 $/yr
8.8(30)
636
2
273
911
105
68
32
30
29
<1
824
2
1,090
32
61
93
25
67
27
119
1,302
Capacity, ]
22(75)
1,102
2
587
1,691
105
68
32
40
40
1
2,060
3
2,349
32
64
96
44
117
59
220
2.665
ns»T (io*
44(150)
1,729
2
1,145
2,876
210
68
64
60
47
2
4,121
6
4,578
63
104
167
69
183
115
.367
5,112
Btu/hr)
58.6(200)
2,055
2
1,490
3,547
210
68
64
71
50
3
5,489
7
5,962
63
107
170
82
218
149
449
6.581
Mid-1978 dollars
-------
APPENDIX D
ENERGY REQUIREMENTS FOR LOW-BTU
GASIFICATION SYSTEMS -
EXAMPLE CALCULATION
D-l
-------
APPENDIX D
ENERGY REQUIREMENTS FOR LOW-BTU GASIFICATION SYSTEMS - EXAMPLE CALCULATION
In order to illustrate the procedures used to calculate the low-Btu
gasification energy impact data contained in Table 5.1-2, an example calcu-
lation is presented below. The case considered in the example is gasifica-
tion of low sulfur western coal and use of the Stretford process for H2S
removal. Also included as an example is the calculation of the energy
requirements for the acid gas removal (MEA process) and sulfur recovery
(Claus/SCOT processes) units for the high sulfur coal cases.
D.I LOW SULFUR COAL CASE - EXAMPLE CALCULATION
The basis for this example calculation is a plant producing 8.79 MWT
(30 x 106 Btu/hr) of low-Btu gas from low sulfur western coal. Based on
the desired plant output and raw gas heating value, the gas flow rate
from the gasifier is calculated to be 1.60 m3/s. To produce this gas
requires a coal feed rate of 0.528 kg/s. Since the coal has a higher
heating value of 22.3 MJ/kg, the energy lost to conversion inefficiencies
is approximately
22.3 x 0.528 - 8.79 - 2.98 MWT
Tar and oil formation is assumed to be 10 percent of the coal feed.
Therefore, about 0.053 kg/s of tars and oils are produced. At 99.5 percent
D-2
-------
recovery of these by-products and an estimated higher heating value of 37.2
MJ/kg, the energy content of the by-products recovered is
0.053 x 0.995 x 37.2 = 1.96 MbL.
The rest of the gasification inefficiencies are attributable to conversion
losses and are calculated to be
2.98 - 1.96 = 1.02
Electricity is required for the gasifier inlet air blower and the pumps
that circulate the gasifier cooling jacket water. These electricity
requirements are estimated at 71.4 kJ/kg coal fed to the gasifier (Ref.
D-l) . Multiplying this factor times the coal feed rate yields
71.4 x 0.528 = 38 kWQ of electricity.
The pressure of the low-Btu gas decreases as it passes through the
quench/ cooling and gas clean-up system. A fan is used to overcome this
pressure drop — estimated at 4.98 kPa — and to provide art estimated 7.47 kPa
of pressure for distribution of the gas. The energy required by the fan
to overcome this pressure drop was calculated by the following equation
(Ref. D-2):
where k =1.4
pi = inlet pressure, lbf/ft2
pa = outlet pressure, lbf/ft2
q = gas flow rate, acfm
EB = efficiency of blower = 60 percent
En = efficiency of Driver = 90 percent
D-3
-------
For the low sulfur coal case,
pi = 2020 lbf/ft2
p2 = 2300 lbf/ft2
q = 3979 acfm
and the electricity requirements for the fan are calculated at
44 kWffi of electricity.
Electricity is also required to recirculate quench water to the in-line
quench, tray scrubber, and spray scrubber. For the low sulfur coal case,
the raw gas is cooled from 250°C (480°F) to 44°C (110°F), and 9.81 kg-moles/
hr (21.6 Ib-moles/hr) of water are condensed.
In the in-line quench, the gas is saturated and cooled to 64°C (146°F).
Cooling duty for the gas is estimated as
0.678 kg-moles .... ,..0o 0.031 MW-s n _01 __.
5J x (250 - 64) C x kg_mole*c = 0.391 M*,.
This is supplied by evaporation of the 601 kg/hr of water which staurates
the gas as it cools.
The enthalpy of the tars was calculated from the following equation
(Ref. D-3):
1
H = 1 35 (t302 T + -000328 T -
where H = enthalpy of tar, Btu/lb
T = temperature, °F
D-4
-------
Cooling the 420 Ib/hr (0.053 kg/s) of tars from 480°F (110°C) to 146°F
(64°C) requires
420 — x (149 - 24) — x MW"hr 0 015 MW
^zu hr x u^y M) lb x 3>41 x 106 Btu u.uia MWT.
This is supplied by 1930 kg/hr of quench water which is heated from 55°C
(130°F) to 64°C (146°F). Thus, the total quench water to the in-line quench
is
1930 + 601 - 2530 kg/hr.
In the plate scrubber, the gas is cooled from 64°C (146°F) to 55°C
(130°F). At 55°C, the gas contains 15.13 mole percent water, or 38.1 kg-
moles/hr (83.9 Ib-moles/hr) water. At 64°C, the gas contains 63.5 kg-moles/
hr (140 Ib-moles/hr) water. The cooling duty for the water that condenses
is therefore
hr oc . kg-mole 18 kg 2.38 MW-s n -no
x 25.4 -"r x -. °— x : = 0.302
hr kg-mole kg
Cooling duty for the sensible heat of the gas is estimated at
0.0699 kg-moles ( _ „ 0.0305 MW-s = Q Q g
AVJJ*T_/.^y\^A * i O /-t v * VA -^ A A«»TI •
s v ' kg-mole C i
Thus, the total cooling duty for the plate scrubber is
0.019 + 0.302 = 0.321 MWT-
Quench water is available at 46° C (115 °F), and heats to 57° C (135° F)
Therefore, the quench water rate to the plate scrubber is
°'321 m X O.OQ^MW-s X (57-46)*C X TT = 25'000
D-5
-------
In the spray scrubber, gas Is cooled from 55°C (130°F) to 43° C (110°F).
At 43°C, the gas contains 8.67 mole percent HaO, or 20.3 kg-moles/hr
(44.7 Ib-moles/hr) water. Thus, 17.8 kg-moles/hr (39.2 Ib-moles/hr) water
are condensed. Cooling duty for condensation is
hr 17.8 kg-moles ^8Jcg_ 2.41 MW-s =
3600 s hr kg-mole kg T
Cooling duty for the sensible heat of the gas is
0.0650 kg-moles x (55_43)0(] x 0 0305 MW-s , ^
s kg—mole C T
Thus, the total cooling duty for the tray scrubber is
0.214 + 0.024 - 0.238 MM,,.
Quench water enters at 35°C (95°F) and exists at 46°C (115°F). Therefore,
the quench water rate is
\fo°r 1 3600 tj
°'238 ™ X 0.00418 MW-s X (46-35)°C X ~^~ = 18'600 k8/hr-
From the above calculations, the total quench water circulated to the
quench/cooling system is
2,530
25,000
18,600
46,100 kg/hr (102,000 Ib/hr).
Assuming a liquid head of 0.68 MPa (100 psi), pump efficiency of 55 percent,
and driver efficiency of 80 percent, the electricity requirements for the
quench liquor pump are calculated as follows:
D-6
-------
46,100 £j x ,,^ o x 0.68 MPa x J^!* x . . * „ = 20 kWP electricity.
Electricity is required to operate the electrostatic precipitator
used for final clean-up of tars, oils, and particulates. The requirements
were estimated from Ref. D-4 at:
6 kWp of electricity.
Energy requirements for the Stretford process were estimated at 1.07
kW or" electricity per kg of sulfur recovered per hour (Ref. D-5) . For the
low sulfur coal case, 8.17 kg/hr of sulfur are recovered. Therefore,
electricity required by the Stretford process is
1.07 x 8.17 = 9 kWg of electricity.
Triple effect evaporators are used to evaporate excess process con-
densate. For this example, 177 kg/hr (390 Ib/hr) of water are evaporated,
and the steam requirements are estimated at
0.12
The results of the calculations just presented are summarized in Table
D-l. For the electricity needs, the "real" energy consumed is the thermal
energy required to generate the electricity. These values are shown in
Table D-l and were calculated based on an assumed electricity production
efficiency of 34.1 percent.
D-7
-------
TABLE D-l. SUMMARY OF ENERGY CONSUMPTION - LOW SULFUR COAT
Source of Energy
Consumption
Conversion Losses
By-Product Tars
Inlet Air Blower and
Cooling Jacket Pump
Quench VJater Pumps
Product Gas Fan
Electrostatic Precipitator
Stretford Pumps and Fans
Process Condensate Evaporators
Total
Type of Energy
Consumed
Coal Feed
Coal Feed
Electricity
Electricity
Electricity
Electricity
Electricity
Steam
Energy Consumption,
MWT
1.02
1.96
0.11*
0.06*
0.13*
0.02*
0.03*
0.12
3.45
* Electrical energy is based on energy input to the generating source and
an assumed conversion efficiency of 34.1 percent.
D.2 HIGH SULFUR COAL/MEA SYSTEMS - EXAMPLE CALCULATION
As mentioned previously, the procedures for calculating energy
consumption are the same for all cases examined through the quench/cooling
section. Those procedures, as well as the method used for calculating the
Stretford process energy requirement were just presented. In the following
text, an example calculation is shown for the MEA/Claus/SCOT sulfur
removal/recovery system for the high sulfur coal cases.
Energy consumption calculations for the MEA system were based on
information from References D-6, D-7, D-8, and D-9. A 20 percent MEA
solution was assumed. HaS sorption was assumed to be the equilibrium
value, and COz sorption to be 75 percent of the equilibrium value. Energy
requirements for regeneration were assumed to be 310 MJ/m of solution
regenerated. Electricity requirements of 630 kW per m3 per second of
solution were assumed. A gas pressure of 0.27 MPa psia was used. A
D-8
-------
residual of 30 ppmv COS remains in the gas, and eighty percent of the COS
removed is hydrolyzed to H2S.
A basis of 8.8 MW of gas production was assumed. The compositions of
the inlet gas, the outlet gas cleaned to meet the moderate control level,
and the acid gas are given in Table D-2. The heating value of the product
gas is 6.07 MJ/m3 . Thus, 86.8 m3/min of gas give 8.8 MWT. For this gas flow
rate, the electricity requirements of the fan required to compress the gas
to 0.27 MPa are calculated from Eq. D-l as
370
of electricity.
The MEA solution flow rate is calculated by multiplying the design liquid
to gas flow rate of 0.979 ra3/1000 m3 by the gas flow rate:
0.979m3 86.8m3 min nnm/o 3,
x : x ——- = 0.00142 m /s.
1000
min
60 s
TABLE D-2. GAS COMPOSITIONS FOR MEA SYSTEM, MODERATE CONTROL LEVEL
C02
CO
ciu
H2
H20
N2
H2S
COS
Inlet Gas
Vol. %
3.27
27.58
2.75
13.65
3.19
48.79
7424 ppmv
297 ppmv
Product Gas
Vol. %
1.46
28.37
2.64
14.04
3.28
50.2
290 ppmv
30 ppmv
Acid Gas
Vol. %
66.9
-
6.5
-
-
-
26.6
-
% of Inlet Flow Rate
100%
97.2%
2.77%
D-9
-------
Regeneration steam requirements are then equal to
„ ™-|/0 m " A // MTT
0.00142 — x - r - = 0.44 MW,p .
-
m
Finally, electricity requirements are
630 Mz£ x 0.00142 — = 0.9 kWp of electricity.
m3 s
The acid gas stream is 2.77 percent of the inlet gas, or 2.4 m3/min.
It contains 1.7 kg-moles/hr of HzS. Energy requirements for the Claus
plant were estimated from data reported for a system treating a gas stream
consisting of 40 percent HaS and 60 percent COa (Ref. D-l, D-10) . (The
acid gas stream in this example is slightly greater than 26 percent HzS) .
The energy requirements are as follows:
Power =2.8 kWh/kg-mole H2S.
Steam Credit = 194 kg steam/kg-mole HzS.
For this example:
Power requirements = 4 kWg of electricity.
Steam credit =180 kWT (assuming 0.3 MPa steam).
Energy requirements for the SCOT process were estimated by engineering
calculations based on data reported in References D-l and D-ll. They are
as follows:
Low Pressure Steam = 11.4 kg/kg sulfur (Ref. D-l)
Power = 0.16 kWh/lb sulfur (Ref. D-ll)
Fuel Gas = 5.12 x 10 3 Btu/lb sulfur (theoretical
calculation; somewhat greater than
reported in Ref . D-l) .
D-10
-------
For this example, the Glaus plant is assumed to achieve 90 percent sulfur
recovery. Sulfur recovery in the SCOT is thus 5.22 kg/hr, and energy
requirements are:
35 kWT of steam,
2 kW of electricity, and
17 kWrj, of fuel gas (low-Btu product gas) .
Total energy required for the MEA/Claus/SCOT system is 1100 kW of
electricity (at an assumed electrical generation efficiency of 34.1 percent),
475 kWm of steam and 20 kW^-, of fuel gas minus 180 kW~ of steam credit from
the Claus, or a total of 1390 kWT (4.74 x 106 Btu/hr).
D-ll
-------
References
D-l. Dravo Corporation. Handbook of Gasifiers and Gas Treatment Systems,
Final Report. Task Assignment No. 4. Pittsburgh, PA. Chemical Plants
Division. February 1976.
D-2. Peters, Max S., and Klaus D. Timmerhaus. Plant Design and Economics
for Chemical Engineers, second ed. New York. McGraw-Hill. 1968.
D-3. Lowry, H. H. ed. Chemistry of Coal Utilization. Volumes I, II, &
Supplementary Volume, New York. Wiley. 1945. 1963. (Supplementary
Volume).
D-4. Heinrich, R. F. and J. R. Anderson. Electro-Precipitators. Chemical
Engineering Practice, Volume III. H. W. Cremer, ed. New York.
Academic. 1975. pp. 484-534.
D-5. Telephone communication between P.J. Murin (Radian Corp.) and Dale
Williams and Buz Zey (J.F. Pritchard and Co.) concerning costs of
Stretford process. 30 October 1978.
D-6. Maddox, R. N. Gas and Liquid Sweetening. Norman, OK. John M.
Campbell Co. 1974.
D-7. Riesenfeld, F. C. and A. C. Kohl. Gas Purification, Second Edition.
Houston, Texas. Gulf Publishing Co. 1974.
D-8. Perry, Charles, R. "Basic Design and Cost Data on MEA Treating Units".
In Proceedings of the 1967 Gas Conditioning Conference. University of
Oklahoma. Norman, OK.
D-9. Kent, Raymond L., and Benjamin Eisenberg. "Better Data for Amine
Treating." Hydrocarbon Process. 55(2). 87-90. 1976.
D-10. Goar, Gene. "Impure Feeds Cause Glaus Plant Problems." Hydrocarbon
Process. 53(7). 129-32. 1974.
D-ll. Naber, J. E., J. A. Wesslingh and W. Groenendaal. "New Shell Process
Treats Glaus Off-Gas." Chemical Engineering Progr. 69(12). 29-34.
1973.
D-12
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1 REPORT NO
EPA-600/7-79-178d
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
5. REPORT DATE
Technology Assessment Report for Industrial Boiler
Applications: Synthetic Fuels
November 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
William C. Thomas
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78766
10. PROGRAM ELEMENT NO.
INE825
11. CONTRACT/GRANT NO.
68-02-2608, Task 49
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 6/78-6/79
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES
919/541-2851.
IERL-RTP project officer is William J. Rhodes, Mail Drop 61,
16. ABSTRACT
repOrt ? part of a series to aid in determining the technological basis
for New Source Performance Standards for Industrial Boilers , addresses the use of
synthetic fuels produced from coal as a precombustion emission control for new in-
dustrial boilers. The synthetic fuels technologies considered include coal gasifica-
tion and liquefaction. Examining the reduction of SOx, NOx, and particulate emis-
sions in industrial boiler flue gases is emphasized. Two low-Btu gasification systems
(the Wellman-Galusha gasifier with either the Stretford (W-G/S) or monoethanolamine
(W-G/MEA) acid gas removal process) were selected for the detailed analyses , which
involved two coal feedstocks (low-sulfur western and high-sulfur eastern) and five
boiler capacities (8.8, 22, 44, 58.6, and 117 MWT heat input). The low-Btu gasifica-
tion systems met the most stringent target NOx and particulate emissions control
levels that were considered. For SO2 emissions, the W-G/S systems using low-sul-
fur coal achieved a stringent target emission control level of 43 ng SO2/J heat level.
Using high-sulfur coal, the W-G/S system achieved a moderate target control level
of 150 ng SO2/J heat input. For regulatory purposes , this assessment must be viewed
as preliminary, pending results of the more extensive examination of impacts called
for under Section 111 of the Clean Air Act.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Group
Pollution
Boilers
Assessments
Coal
Coal Gasification
Liquefaction
Sulfur Oxides
Nitrogen Oxides
Dust
Aerosols
Pollution Control
Stationary Sources
Industrial Boilers
Synthetic Fuels
Particulate
13B 07B
13A
14B 11G
08G,21D 07D
13H
07D
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
377
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
D-13
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