CONTROL TECHNIQUES
FOR
SULFUR OXIDE AIR POLLUTANTS
U.S. DEPARTMENT OF HEALTH, EDUCATION, AND WELFARE
Public Health Service
Consumer Protection and Environmental Health Service
-------
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CONTROL TECHNIQUES
FOR
v SULFUR OXIDE AIR POLLUTANTS
j^vrv- •- "" AGENCY
Li
i •.
U.S. DEPARTMENT OF HEALTH, EDUCATION, AND WELFARE
Public Health Service
Consumer Protection and Environmental Health Service
National Air Pollution Control Administration
Washington, D.C.
January 1969
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National Air Pollution Control Administration Publication No. AP-52
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PREFACE
Throughout the development of Federal air pollution legislation, the
Congress has consistently found that the States and local governments have
the primary responsibility for preventing and controlling air pollution at its
source. Further, the Congress has consistently declared that it is the
responsibility of the Federal government to provide technical and financial
assistance to State and local governments so that they can undertake these
responsibilities.
These principles were reiterated in the Air Quality Act of 1967. A key
element of that Act directs the Secretary of Health, Education, and Welfare to
collect and make available information on all aspects of air pollution and its
control. Under the Act, the issuance of control techniques information is a
vital step in a program designed to assist the States in taking responsible
technological, social, and political action to protect the public from the
adverse effects of air pollution.
Briefly, the Act calls for the Secretary of Health, Education, and
Welfare to define the broad atmospheric areas of the Nation in which climate,
meteorology, and topography, all of which influence the capacity of air to
dilute and disperse pollution, are generally homogeneous.
-------
Further, the Act requires the Secretary to define those geographical
regions in the country where air pollution is a problem—whether interstate
or intrastate. These air quality control regions are designated on the basis
of meteorological, social, and political factors which suggest that a group
of communities should be treated as a unit for setting limitations on concen-
trations of atmospheric pollutants. Concurrently, the Secretary is required
to issue air quality criteria for those pollutants he believes may be harmful
to health or welfare, and to publish related information on the techniques
which can be employed to control the sources of those pollutants.
Once these steps have been taken for any region, and for any pollutant
or combination of pollutants, then the State or States responsible for the
designated region are on notice to develop ambient air quality standards
applicable to the region for the pollutants involved, and to develop plans of
action for meeting the standards.
The Department of Health, Education, and Welfare will review, eval-
uate, and approve these standards and plans and, once they are approved, the
States will be expected to take action to control pollution sources in the
manner outlined in their plans.
At the direction of the Secretary, the National Air Pollution Control
Administration has established appropriate programs to carry out the several
Federal responsibilities specified in the legislation.
11
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Control Techniques for Sulfur Oxide Air Pollutants is one of the first
of a series of documents to be produced under the program established to
carry out the responsibility for developing and distributing control technology
information. The document is the culmination of intensive and dedicated
effort on the part of many persons.
In accordance with the Air Quality Act, a National Air Pollution Control
Techniques Advisory Committee was established, having a membership
broadly representative of industry, universities, and all levels of govern-
ment. The committee, whose members are listed following this discussion,
provided invaluable advice in identifying the best possible methods for con-
trolling the sources of sulfur oxide air pollution, assisted in determining the
costs involved, and gave major assistance in drafting this document.
As further required by the Air Quality Act, appropriate Federal
departments and agencies, also listed on the following pages, were consulted
prior to issuance of this document. A Federal consultation committee, com-
prising members designated by the heads of 17 departments and agencies,
reviewed the document, and met with staff personnel of the National Air
Pollution Control Administration to discuss its contents.
During 1967, at the initiation of the Secretary of Health, Education,
and Welfare, several government-industry task groups were formed to
explore mutual problems relating to air pollution control. One of these, a
111
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task group on control technology research and development, looked into ways
that industry representatives could participate in the review of the control
techniques reports. Accordingly, several industrial representatives, listed
on the following pages, reviewed this document and provided helpful comments
and suggestions. In addition, certain consultants to the National Air Pollution
Control Administration also revised and assisted in preparing portions of this
document. (These also are listed on the following pages.)
The Administration is pleased to acknowledge the efforts of each of the
persons specifically named, as well as those of the many not so listed who
contributed to the publication of this volume. In the last analysis, however,
the National Air Pollution Control Administration is responsible for its
content.
The control of air pollutant emissions is a complex problem because
of the variety of sources and source characteristics. Technical factors
frequently make necessary the use of different control procedures for differ-
ent types of sources. Many techniques are still in the development, stage,
and prudent control strategy may call for the use of interim methods until
these techniques are perfected. Thus, we can expect that we will continue to
IV
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improve, refine, and periodically revise the control techniques information so
that it will continue to reflect the most up-to-date knowledge available.
John T. Middleton
Commissioner
National Air Pollution Control
Administration.
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NATIONAL AIR POLLUTION CONTEOL TECHNIQUES ADVISORY COMMITTEE
Mr. Louis D. Alpert, General Manager
Midwestern Department of the Federated
Metals Division
American Smelting & Refining Company
Whiting, Indiana
Professor James H. Black *
Department of Chemical Engineering
University of Alabama
University, Alabama
Mr. Robert L. Chass
Chief Deputy Air Pollution
Control Officer
Los Angeles County Air Pollution
Control District
Los Angeles, California
Mr. W. Donham Crawford
Administrative Vice President
Consolidated Edison Company of
New York, Inc.
New York, New York
Mr. Herbert J. Dunsmore
Assistant to Administrative
Vice President of Engineering
U. S. Steel Corporation
Pittsburgh, Pennsylvania
Mr. John L. Gilliland
Technical Director
Ideal Cement Company
Denver, Colorado
Mr. James L. Parsons
Consultant Manager
Environmental Engineering
Engineering Department
E. I. du Pont de Nemours & Co.,
Inc.
Wilmington, Delaware
Professor August T. Rossano
Department of Civil Engineering
Air Resource Program
University of Washington
Seattle, Washington
Mr. Jack A. Simon
Principal Geologist
Illinois State Geological Survey
Natural Resources Building
Urbana, Illinois
Mr. Victor H. Sussman, Director
Division of Air Pollution Control
Pennsylvania Department of Health
Harrisburg, Pennsylvania
Mr. Earl L. Wilson, Jr.,
Manager
Industrial Gas Cleaning
Department
Koppers Company, Inc.
Metal Products Division
Baltimore, Maryland
Dr. Harry J. White, Head
Department of Applied Science
Portland State College
Portland, Oregon
* Resigned September 16, 1968
VI
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FEDERAL AGENCY LIAISON REPRESENTATIVES
Department of Agriculture
Kenneth E. Grant
Associate Administrator
Soil Conservation Service
Department of Commerce
Paul T. O'Day
Staff Assistant to the Secretary
Department of Defense
Colonel Alvin F. Meyer, Jr.
Chairman
Environmental Pollution Control Committee
Department of Housing and Urban Development
Charles M. Haar
Assistant Secretary for Metropolitan Development
Department of the Interior
Harry Perry
Mineral Resources Research Advisor
Department of Justice
Walter Kiechel, Jr.
Assistant Chief
General Litigation Section
Land and Natural Resources Division
Department of Labor
Dr. Leonard R. Linsenmayer
Deputy Director
Bureau of Labor Standards
Department of Transportation
William H. Close
Assistant Director for Environmental Research
Office of Noise Abatement
Department of the Treasury
Gerard M. Brannon
Director
Office of Tax Analysis
VII
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Federal Power Commission
F. Stewart Brown
Chief
Bureau of Power
General Services Administration
Thomas E. Crocker
Director
Repair and Improvement Division
Public Buildings Service
National Aeronautics and Space Administration
Major General R. H. Curtin, USAF (Ret.)
Director of Facilities
National Science Foundation
Dr. Eugene W. Bierly
Program Director for Meteorology
Division of Environmental Sciences
Post Office Department
Louis B. Feldman
Chief
Transportation Equipment Branch
Bureau of Research and Engineering
Tennessee Valley Authority
Dr. F. E. Gartrell
Assistant Director of Health
U. S. Atomic Energy Commission
Dr. Martin B. Biles
Director
Division of Operational Safety
Veterans Administration
Gerald M. Hollander
Director of Architecture and Engineering
Office of Construction
Vlll
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CONTRIBUTORS
Mr. L. P. Augenbright, Assistant
Sales Manager
Western Knapp Engineering Division
Arthur G. McKee and Company
San Francisco, California
Dr. Allen D. Brandt, Manager
Environmental Quality Control
Bethlehem Steel Corporation
Bethlehem, Pennsylvania
Mr. William Bodle, Senior Advisor
Institute of Gas Technology
Chicago, Illinois
Dr. Donald A. Borum
Consulting Chemical Engineer
New York, New York
Mr. John D. Capian
Technical Director
Basic and Applied Sciences
Research Laboratories
General Motors Corporation
Warren, Michigan
Dr. R. R. Chambers, Vice President
Sinclair Oil Corporation
New York, New York
Mr. John M. Depp, Director
Central Engineering Department
Monsanto Company
St. Louis, Missouri
Mr. Harold F. Elkin
Sun Oil Company
Philadelphia, Pennsylvania
Mr. B. R. Gebhart
Vice President
Freeman Coal Mining Corporation
Chicago, Illinois
Mr. James R. Jones
Chief Combustion Engineer
Peabody Coal Company
Chicago, Illinois
Mr. Olaf Kayser
Vice President-Manufacturing
Lone Star Cement Corporation
New York, New York
Mr. David Lurie, Consultant
Wyckoff, New Jersey
Mr. Glenn A. Nesty
Vice President
Senior Technical Officer
Allied Chemical Corporation
New York, New York
Dr. Arthur L. Plumley
Senior Project Engineer
Kresinger Development Laboratory
Combustion Engineering, Inc.
Windsor, Connecticut
Mr. James H. Rook
Director of Environmental
Control Systems
American Cyanamid Company
Wayne, New Jersey
Mr. T. W. Schroeder
Manager of Power Supply
Illinois Power Company
Decatur, Illinois
Dr. Seymour C. Schuman
Private Consultant
Princeton, New Jersey
Mr. R. W. Scott
Coordinator for Conservation
Technology
Esso Research and Engineering
Company
Linden, New Jersey
IX
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Mr. David Swan
Vice President-Technology
Kennecott Copper Corporation
New York, New York
Mr. R. A. Walters, Project Director
of Smelter Studies
Western Knapp Engineering Division
Arthur G. McKee and Company
San Francisco, California
x
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CONTENTS
PREFACE
Contents xi
List of Figures xviii
List of Tables xxii
SUMMARY xxvii
1. INTRODUCTION 1-1
2. DEFINITIONS AND MEASUREMENTS OF SULFUR OXIDES 2-1
3. MAJOR SOURCES OF SULFUR OXIDES 3-1
3.1 COMBUSTION SOURCES 3-4
3. 2 INDUSTRIAL SOURCES 3-6
4. CONTROL TECHNIQUES FOR FUEL COMBUSTION PROCESSES . 4-1
4.1 ENERGY SOURCES, CONSUMPTION, AND USAGE TRENDS . . 4-1
4. 2 ENERGY AVAILABILITY 4-10
4. 2.1 Coal 4-10
4.2.2 Oil 4-16
4. 2. 2.1 Crude Oil 4-16
4. 2. 2. 2 Residual Fuel Oil 4-24
4. 2. 2. 3 Distillate Fuel Oils 4-29
4. 2. 3 Natural Gas 4-31
4. 2. 3.1 Other Sources of Natural Gas 4~35
4. 2. 3. 2 Natural-Gas Liquids 4-37
xi
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CONTENTS (Continued)
4. 2. 4 Hydroelectric Power 4-37
4. 2. 5 Nuclear Power 4-40
4. 2. 6 Other Energy Sources 4-43
4. 3 ENERGY SOURCE SUBSTITUTION 4-45
4. 3.1 Introduction 4-45
4. 3. 2 Methodology and Economics of Fuel Substitution . 4-53
4. 3. 3 Fuel Conversion Problems 4-57
4.4 FUEL DESULFURIZATION 4-64
4. 4. 1 Introduction 4-64
4. 4. 2 Coal 4-65
4. 4. 2,1 Introduction 4-65
4.4.2,2 Pyrite Removal: Coal Preparation 4-65
4.4.2,3 Pyrite Removal: Dry Processes 4-75
4. 4. 2. 4 Liquefaction 4-76
4. 4. 2. 5 Gasification 4-77
4. 4. 3 Oil 4-78
4. 4. 3.1 Introduction 4-78
4.4.3.2 Major Processes for Desulfurization 4-82
4. 4. 3. 3 Cost Studies 4-90
4.4.4 Gas 4-98
4. 5 FLUE GAS DESULFURIZATION 4-100
4. 5.1 Introduction 4-100
4. 5. 2 Alkalized Alumina Process 4-102
4. 5. 2.1 Introduction 4-102
xii
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CONTENTS (Continued)
4. 5. 2. 2 Process Description 4-103
4. 5. 2. 3 Cost 4-105
4. 5. 3 Limestone-Based Injection Process 4-106
4. 5. 3.1 Introduction 4-106
4. 5. 3. 2 Process Description 4-107
4. 5. 3.3 Process Cost 4-111
4. 5. 3. 4 Future Plans 4-112
4. 5.4 Catalytic Oxidation Process 4-112
4. 5. 4.1 Introduction 4-112
4. 5. 4. 2 Process Description 4-113
4. 5. 4. 3 Cost 4-117
4. 5. 5 Beckwell SO9 Recovery Process 4-117
£i
4. 5. 5.1 Introduction 4-117
4. 5. 5.2 Process Description 4-117
4. 5. 5. 3 Process Cost 4-118
4. 5. 6 Other Processes 4-118
4. 5. 6.1 Introduction 4-118
4. 5. 6. 2 Process Descriptions 4-118
4. 5. 7 Systems for Small Sources 4-123
4. 6 COMBUSTION PROCESS MODIFICATIONS 4-125
4. 6.1 Heat Recovery 4-125
4. 6. 2 Improving Generating System Efficiency 4-127
4. 6. 3 Newer Concepts of Central Station Power Generation . . 4-128
4. 6. 3.1 High Pressure Combustion 4-128
Xlll
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CONTENTS (Continued) „
v ' Page
4. 6. 3. 2 Two-Step Combustion 4-130
4.6.3.3 Magnetohydrodynamics 4-130
4. 6. 3. 4 Electrogasdynamics 4-131
5. INDUSTRIAL PROCESS SOURCES 5-1
5.1 NONFERROUS PRIMARY SMELTERS 5-1
5.1.1 Introduction 5-1
5.1. 2 Copper Smelter Emissions Control 5-3
5.1.3 Lead Smelter Emissions Control 5_g
5.1.4 Zinc Smelter Emissions Control 5-9
5. 2 PETROLEUM REFINERIES 5-12
5. 2.1 Introduction 5-12
5.2.2 Petroleum Refining Processes 5-12
5. 2. 2.1 Distillation 5_13
5. 2. 2. 2 Cracking or Pyrolysis 5-13
5. 2. 2.3 Hydrocracking 5-14
5. 2. 2. 4 Reforming 5_14
5.2.2.5 Polymerization and Alkylation 5-14
5. 2. 2. 6 Hydrogen Treating 5_15
5. 2. 2. 7 Hydrogen Production 5_15
5. 2. 3 Sulfur Dioxide Emissions 5-17
5. 2. 3.1 Heaters and Boilers 5_17
5. 2. 3. 2 Catalytic Regeneration 5-17
5. 2. 3. 3 Treating 5-18
5. 2. 3. 4 Acid Sludge Disposal 5-19
xiv
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CONTENTS (Continued)
5. 2. 3. 5 Flares 5-19
5. 2. 3. 6 Vacuum Jet Exhausters 5-19
5. 2. 3. 7 Asphalt Air Blowing 5-20
5.2.3.8 Miscellaneous Sources 5-20
5. 2. 4 Control of Sulfur Oxides 5-20
5. 2. 4.1 Heaters and Boilers 5-23
5.2.4.2 Catalytic Regeneration Gases 5-23
5.2.4.3 Treating 2-24
5. 2. 4.4 Air Blowing of Asphalt 5-26
5. 2. 4. 5 Sulfur Recovery Facilities 5-26
5. 2. 5 Sulfur Plant Costs 5-34
5. 3 SULFURIC ACID PLANTS 5-41
5. 3. 1 Introduction 5-41
5.3.2 Sulfuric Acid Manufacturing 5-41
5. 3. 3 Emissions 5-45
5.3.4 Control Methods for Sulfur Oxides 5-47
5.4 STEEL MANUFACTURING 5-51
5. 4. 1 Introduction 5-51
5. 4. 2 Sintering 5-51
5. 4. 3 Coke Ovens 5-53
5. 5 PULP AND PAPER MILLS 5-60
5. 5.1 Introduction 5-60
5. 5. 2 Sulfate (Kraft) Process SO2 Emissions and Control .... 5-62
5. 5. 3 Sulfite Process SO Emissions and Control 5-66
xv
331-543 O - 69 - 2
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CONTENTS (Continued)
Page
5. 5. 4 Neutral Sulfite Semi-Chemical SO2 Emissions — —
and Control 5-69
5. 5. 5 Steam and Power Boiler Atmospheric Emissions 5-69
5. 6 WASTE DISPOSAL 5_71
5. 6. 1 Coal Refuse 5.7^
5. 6.1.1 Introduction 5-71
5. 6.1. 2 Control Methods and Costs 5-72
5.6.1.3 Future Plans and Research 5_73
5. 6. 2 Incineration 5-75
5. 6. 3 Sewage Treatment 5-75
5. 7 MISCELLANEOUS SOURCES 5_77
5. 7.1 Introduction 5-77
5. 7. 2 Glass Manufacture 5_77
5. 7. 3 Corn Starch Production 5-77
5. 7. 4 Sugar Manufacture 5-73
5. 7. 5 Sulfur Fusion Processes 5-78
5. 7. 6 Liquid Sulfur Dioxide 5-78
5. 7. 7 Silicon Carbide 5_78
5. 7. 8 Titanium Dioxide 5-79
6. DISPERSION FROM STACKS 6-1
6.1 INTRODUCTION 6-1
6. 2 PLUME RISE 6-3
6. 3 DIFFUSION PROCESSES 6-4
6.4 USE OF MATHEMATICAL-METEOROLOGICAL MODELS . . .6-6
6. 5 METEOROLOGICAL ASPECTS OF SITE SELECTION 6-7
xvi
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CONTENTS (Continued)
6.6 FACTORS FOR SITE EVALUATION
6. 7 OTHER CONSIDERATIONS FOR SITE OR STACK
EVALUATION 6-11
6. 8 STATUS OF POWER PLANT PLUME DISPERSION AND
METEOROLOGICAL STUDIES 6-12
6.9 STACK COSTS 6-14
6.10 BIBLIOGRAPHY 6-15
6.10.1 Guide, Manuals, Workbooks 6-15
6.10.2 Textbooks 6-15
6.10.3 General 6-15
6.10.4 Plume Rise Calculations, Stack Height 6-17
6.10.5 Diffusion Calculations 6-18
6.10. 6 Mathematical Diffusion Models 6-20
6.10.7 Aerodynamics, Wind Tunnel Studies 6-21
6.10.8 Natural Removal Processes 6-21
6.10.9 Topographic and Urban Effects 6-22
6.10.10 Air Pollution Climatology 6-23
6.10.11 Costs 6-23
6.10.12 Aviation Regulations 6-23
7. EVALUATION OF SULFUR OXIDE EMISSIONS 7-1
7.1 COMPILATION OF SULFUR OXIDE EMISSION FACTORS- . 7-1
7.2 SOURCE TESTING FOR SULFUR OXIDES 7-6
APPENDIX CHEMICAL COAL PROCESSING A-l
AUTHOR INDEX A-21
SUBJECT INDEX A-33
xvn
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LIST OF FIGURES
Figure Page
3-1 Nationwide Sources of Sulfur Dioxide
Emissions, 1966 3-2
3-2 Estimated SO Emissions 3-3
Li
4-1 Trends in Energy Consumption by Source,
1850 - 1965 4-5
4-2 Future Energy Requirements and Fuel-use
Patterns for the Commercial Market 4-6
4-3 Future Fuel-use Patterns for Residential Home
Heating 4-7
4-4 Future Energy Requirements and Fuel-use Patterns
for Industrial Use (Except Electricity) 4-8
4-5 Trends in Electrical Power Generation 4-9
4-6 Coal Fields of the United States 4-13
4-7 Estimated Original and Remaining Coal Reserves,
by Rank, in United States, January 1, 1965 • • • 4-14
4-8 Estimate of U. S. Production of Crude Oil as of
December 31,1967 4-18
4-9 Natural Gas Fields of the United States 4-32
4-10 Principal Hydroelectric Projects Developed and
Under Construction January 1,1964 4-38
xviii
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LIST OF FIGURES (Continued)
Figure
4-11 Status of Nuclear Power Plants in the United
States as of December 31, 1967 4-42
4-12 Fuel Substitution Schemes for Reduction of
Sulfur Oxide Emissions 4-55
4-13 Coal Preparation (Simplified Flow Chart) 4-66
4-14 Flowsheet of a 500 Ton/hr Coal Preparation
Plant 4-71
4-15 Maximum Sulfur Content Versus Percent of
Mines Sampled 4-72
4-16 Proposed Coal Cleaning Plant (Simplified
Flow Chart) 4-74
4-17 H-Oil Desulfurization Process (Simplified
Flow Chart) 4-84
4-18 Hydrogen Treating (Simplified Flow Chart) .... 4-86
4-19 Delayed Coking (Simplified Flow Chart) 4-88
4-20 Propane Solvent De-Asphalting (Simplified
Flow Chart) 4-89
4-21 Incremental Desulfurization Costs - Per Barrel
Versus Constant Heating Value 4-94
4-22 Alkalized Alumina Process 4-104
4-23 Limestone Injection - Dry Process 4-108
4-24 Limestone Injection - Wet Scrubbing Process ... 4-110
4-25 Catalytic Oxidation Process 4-114
4-26 Comparison of Plant Size and Heat Rate 4-127
xix
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LIST OF FIGURES (Continued)
Figure
5-1 Copper Smelting with Sulfur Oxides Recovery
System 5-4
5-2 Flow Chart for H2S Removal by Amine Solutions . . 5-28
5-3 Sulfur Recovery Plant (Flow Chart) 5-31
5-4 Variation of H S to SO2 Ratio with Conversion and
Maximum Theoretical Conversion Possible at
Specified Ratio 5-33
5-5 Estimate of Investment Cost for Two-Stage Con-
verter Sulfur Plant „ 5-40
5-6 Flow Chart of a Typical Sulfur-Burning Contact
Sulfuric Acid Plant 5-44
5-7 Sulfur Dioxide Emissions from Contact Plants at
Various Conversion Efficiencies (Per Ton of
Equivalents 100% H2 SO4 Produced) 5-46
5-8 Concentration of SO in Exit Gas at Various Con-
version Efficiencies 5-46
5-9 Flow Chart for Sulfur-Burning Double-Contact
Plant with Intermediate SO« Adsorption 5-48
5-10 Typical Sulfate Pulping and Recovery Process .... 5-64
5-11 Typical Magnesium-Base Chemical Pulping
Recovery Process 5-68
5-12 Typical Recovery System for Neutral Sulfite-
Semichemical Liquor 5-70
6-1 Approximate Installed Costs of Stacks 6-14
A-l Solvent Refining (Simplified Flow Chart) A-2
xx
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LIST OF FIGURES (Continued)
Figure Page
A-2 COED Process (Simplified Flow Chart) A-5
A-3 Desulfurization of Coal Char (FMC Process) A-7
A-4 H-Coal Process (Simplified Flow Chart) A-9
A-5 CSF Process (Simplified Flow Chart) A-ll
A-6 Hydrogasification (Simplified Flow Chart) A-12
A-7 CO Acceptor (Simplified Flow Chart) A-15
^
A-8 Molten Salt (Simplified Flow Chart) A-17
A-9 Two-Stage, Super-Pressure Desulfurization
Process (Simplified Flow Chart) A-18
xxi
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LIST OF TABLES
Table
Summary of Methods For Controlling Sulphur
Oxide Emissions from Stationary Combustion
Sources
xxxiv
3-1 SO2 Emissions From Fuel Combustion in
1966 3-5
3-2 SO£ Emissions From Industrial Process
Sources in 1966 3-7
4-1 Consumption of Energy Resources by Major
Sources and Consuming Sectors 4-3
4-2 Estimated Remaining Coal Reserves of the
United States, By Rank, Sulfur Content, and
State, on January 1, 1965
(106 short tons) 4-11
4-3 United States Crude Oil Production by Area and
Sulfur Content Category - 1966 4-20
4-4 Foreign Crude Oil Production By Area and Sulfur
Content Category 4-22
4-5 Crude Oil Imported Into United States - 1966
(106 bbl) 4-23
4-6 Residual Fuel Oil Production From Domestic Crude
Oil In U.S. By Sulfur Content - 1965
(103 bbl) 4_26
4-7 Residual Fuel Oil Imports Into United States
1965-1966 4-27
4-8 Total U.S. Consumption of Residual Oil By
Major Consuming Group - 1963-1966 (103 bbl) . . . 4-23
4-9 Average Sulfur Content of Distillate Fuel Oils
for United States by Region - 1967 4-30
xxi i
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LIST OF TABLES (Continued)
Table
4-10 Estimated Proved Recoverable Reserves of
Natural Gas In United States
(106 ft 3 - 14. 73 psia, at 60°F) 4-34
4-11 Number of Customers and Volume of Natural Gas
Consumed By Principal Uses in United States . . . 4-36
4-12 Existing and Projected Hydroelectric Capacity
of United States To 1980 (106 kw) 4-39
4-13 Industrial Consumer Prices of Coal - 1967
(cents/106 Btu) 4-46
4-14 Industrial Consumer Prices of Fuel Oils -
1967 (cents/106 Btu) 4-48
4-15 Industrial Consumer Prices of Natural Gas -
1967 a (cents/106 Btu) 4-50
4-16 Sulfur Contents and Prices of Coals in 1966 By
Producing Districts 4-54
4-17 Cost and Engineering Data For Typical Fuel
Substitution Problem Analysis 4-58
4-18 Emission Control-Cost Effectiveness Ratio of
Fuel Alternatives 4-59
4-19 Convertibility of Industrial Heating Equipment . . . 4-61
4-20 Convertibility of Commercial Heating
Equipment 4-62
4-21 Convertibility of Domestic Heating
Equipment 4-63
4-22 Existing Mechanical Methods of Cleaning Coal. . . . 4-67
XXlll
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LIST OF TABLES (Continued)
Table Page
4-23 Cost Data For 500-Ton-Per-Hour Coal
Preparation Operation 4-69
4-24 Typical Sulfur Reductions Achieved in Various
High-Sulfur Coal Beds 4-70
4-25 Estimated Product Cost Utilizing Proposed
1000-Ton-Per-Hour Coal Preparation Plant .... 4-73
4-26 Typical Recent Petroleum Desulfurization
Activity 4-80
4-27 Process Sizes and Yields for 1967 Bechtel
Study 4-91
4-28 Heavy Fuel Oil Product Quality and Incremental
Cost 4-93
4-29 Production and Cost Data for Producing 1 Percent
Sulfur Residual Fuel Oil From Crude Oil in
Specified Districts at an Average Refinery 4-95
4-30 Production and Cost Data for Producing 0. 5
Percent Sulfur Residual Fuel Oil From Crude
Oil in Specified Districts at an Average
Refinery 4-96
4-31 Estimated Effect of Increased Generating
Efficiency On SO£ Emissions and Fuel Cost for
500-Megawatt Plant 4-129
5-1 Nonferrous Smelter Production and SO2 Emissions
in 1966 (Tons) 5-2
5-2 Sulfur Dioxide Concentrations From Zinc
Roasters 5-10
5-3 Capacity of the Components of a 95, 000-Barrel-
Per-Day Refinery 5-16
XXIV
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LIST OF TABLES (Continued)
Table
5-4 Sources of Sulfurous Emissions and Control
Methods 5-21
5-5 Desulfurization Methods and Their Effects on
Removal of Various Sulfur Compounds 5-25
5-6 Disposition of Sulfur in Net Products Consumed
in United States - 1962 (excluding Rocky
Mountain Region) 5-35
5-7 New Sulfur Plants Completed Or Under
Construction As Of February, 1968 5-36
5-8 Typical Two-Stage Sulfur Plant Costs 5-39
5-9 Sulfuric Acid Production (100% Basis)
(106 tons) 5-42
5-10 Distribution of Sulfur in Coke Oven Products • • • • 5-55
5-11 Pulp Mill Processes and Potential Atmospheric
Emissions in 1966 5-61
5-12 Ranges Of SO2 Concentrations in Stack Gas From
Two Kraft Mills 5-63
5-13 Effects of Furnace Secondary Air on SO2 and
Other Sulfur Compound Emissions 5-63
5-14 Effects of Turbulence on Furnace Gaseous
Emissions 5-65
5-15 Effects of Liquor Spray Pattern on Furnace
Gaseous Emissions 5-65
7-1 Emission Factors for Sulfur Compounds From
Fuel Combustion 7-2
xxv
-------
LIST OF TABLES (Continued)
Table Page
7-2 Emission Factors for Sulfur Compounds
From Solid Waste Disposal 7-3
7-3 Emission Factors for Sulfur Compounds
From Industrial Processes 7-4
A-l Solvent Refined Coal Product A-4
A-2 Typical Product Yields for Coed Process
(Based on Utah A Seam King Coal) A-4
A-3 Product Yield for H-Coal Process (Illinois
#6 Coal) A-8
XXVI
-------
SUMMARY
SOURCES OF SULFUR OXIDES
Approximately three-fourths of the 28. 6 million tons of sulfur oxides,
largely sulfur dioxide (SO0), emitted into the atmosphere of the United States
£t
in 1966 resulted from the combustion of sulfur-bearing fuels. Coal combustion
accounted for the largest part of this total. Industrial processes, mainly
smelting and petroleum refining, accounted for the remaining sulfur oxide
emissions. The quantity of sulfur oxides emitted varies widely from area to
area, depending on the type and quantity of fuel consumed and on the industrial
processes.
Combustion Processes
The rapid growth of the economy of this country has been due, in part, to
the ready supply of naturally occurring fossil fuels (coal, oil, and gas). These
fuels currently supply about 95 percent of the 57 quadrillion (57 x 10 ) Btu
consumed in the United States annually. Nuclear energy currently supplies only
a small fraction of total energy, but its contribution is expected to grow rapidly.
One of the best existing methods for reducing sulfur oxide emissions from
fuel combustion sources is the use of low-sulfur fuels, such as natural gas,
low-sulfur fuel oil, and low-sulfur coal; or by converting to another source of
power such as hydropower or nuclear energy. Many economic and social
factors would, however, be involved in any massive switch to low-sulfur fuels.
Careful planning which takes into consideration the cost and availability of these
xxvn
-------
fuels, as well as the levels and effects of emitted SO,,, can minimize these
£t
problems. Using low-sulfur fuels on a short-term basis during periods of
severe air pollution may also be feasible.
Coal is by far our mdst abundant fossil fuel. Low-sulfur supplies of this
fuel do exist, but they have not been fully developed nor are they very widely
distributed. It is estimated that over 40 percent of the high-rank coals found
east of the Mississippi River contain less than 1 percent sulfur (i. e., 95 billion
tons). Approximately 50 percent of this 95 billion tons of coal should be re-
coverable. A premium price is usually paid for high-rank, low-sulfur coal.
For areas not adjacent to low-sulfur coal supplies, additional transportation
costs will constitute an increasing part of the delivered price.
Coal cleaning processes are capable of removing some of the pyrite
sulfur in coal. Cleaning processes that include crushing to 1-1/2 inches or
less and flotation separation tend to remove more pyrite material. Because the
degree to which a particular coal can be cleaned varies widely and depends on
the amount and distribution of the pyrite sulfur in the coal, quantitative state-
ments about coal cleanibility, its cost, and the amount of cleanable coal avail-
able can not be made.
Though under active research, none of the more elaborate coal processing
schemes, such as gasification and liquefaction, are presently in full-scale
operation. The current state of development of these processes is described
in the Appendix.
Approximately 600 million barrels of residual fuel oil (grades 5 and 6)
are burned annually in the United States. More than 80 percent of this fuel con-
tains at least 2 percent sulfur. The east-coast regions burn about 50 percent
XXVlll
-------
of this fuel oil, most of which is imported from South America. Due to the
nature of petroleum refining processes, sulfur present in crude oil tends to be
concentrated in the residual oil fraction.
Lighter fuel oils (grades 1 and 2) are currently being consumed at a rate
of about 500 million barrels per year. The lighter oils generally contain
between 0. 04 and 0. 6 percent sulfur, and burning them does not produce as
much sulfur oxides as does burning residual oil. Because of the higher cost
of this fuel it is not generally burned by large consumers such as utilities and
large industrial plants.
Various refinery process schemes that can produce a residual fuel oil
with a sulfur content of 1.0 percent or less are currently being installed and
some are in operation. These schemes use delayed coking, solvent de-
asphalting, and hydrogen treating processes. Their principal product is low-
sulfur distillate oil, which is blended with heavy oil fractions to produce a
low-sulfur residual fuel oil. Desulfurizing to 1. 0 percent costs about $.25 to
$. 75 per barrel ($. 04 to $. 12 per million Btu); however, the price of 1. 0-
percent-sulfur-content residual fuel oil is influenced by many factors, and
prices to date have not in general increased greatly.
Desulfurizing to less than 1.0 percent will become more feasible as these
schemes are further improved. Costs for desulfurizing to less than 1.0 per-
cent cannot be accurately estimated now.
Natural gas is now available in all parts of the country, and production
has increased to about 18 trillion cubic feet per year. Sulfur compounds con-
tained in natural gas are for the most part removed before marketing. This
fuel, therefore, burns with negligible sulfur oxide emissions and is widely
xxix
-------
used. While new reserves of natural gas are being found, the domestic supply
of this fuel at current prices will probably become limited before the turn of
the century because of increased production costs.
Fuel costs vary widely and depend, among other things, on the con-
sumer's location and demand. Fuel-cost data are presented in this report for
industrial users in 50 Standard Metropolitan Statistical Areas for coal and oil
of various sulfur contents, and natural gas. When calculating the various
costs involved in fuel substitution schemes and the effect of the schemes on
sulfur oxide emissions, the following steps must be taken:
1. Determine heating requirements in Btu per hour, of unit in
question.
2. Select the various fuels that may be burned and determine their
costs.
3. For the various fuels determine the cost of boiler modifications
and operating expense.
4. Annualize the costs.
5. Determine the extent of sulfur dioxide emissions from com-
bustion of the alternative fuels.
In areas where the cost of low-sulfur fuels is high and the supply limited,
fuel substitution may not be an economically feasible method of reducing sulfur
oxide emissions. This is especially true in the case of large fuel consumers,
such as electrical generating stations. Increased attention has, therefore,
been recently focused on methods for removing sulfur oxides from the flue gas
before it enters the atmosphere. No flue gas desulfurization processes are
xxx
-------
presently in widespread use, but several methods such as alkalized alumina
sorption, limestone-dolomite injection, and catalytic oxidation are currently
under active investigation.
The limestone-dolomite injection process is the simplest method current-
ly being developed for the control of SCL emissions from large combustion
sources. In this process, limestone injected into the furnace reacts with the
sulfur oxides to form calcium sulfate, a solid, which is removed by dust-
collecting equipment. The degree of reaction can be increased by placing a
scrubber on the system, since the limestone, which calcines to quicklime in the
furnace, reacts fully in the scrubber due to increased contact and retention
time. Sulfur oxide removal efficiencies in excess of 80 percent are obtainable
when the scrubbing system is used. The primary disadvantage of this system
is the large amount of waste material (calcium sulfate and sulfite, unreacted
limestone, and fly ash) which must be disposed of. Flue gas reheating may be
required when the scrubber is used.
Estimated costs for an 800-megawatt, coal-fired power plant, operating
* '
at a load factor of 90 percent are tabulated below.
Operating cost, Percent SO2
Process Capital cost cents/kw-hr removal
Limestone injection $3,300,000 0.029 40-60
Limestone injection $4,650,000 0.035 80-90
followed by wet
scrubbing
xxxi
331-543 O - b9 - 3
-------
Three full-scale installations of the limestone-dolomite wet-scrubbing
process are presently under way on coal-burning power plants in the 170- to
420-megawatt range, and one of these is now in the preliminary steps of opera-
tion. Two TVA power plants are also currently being modified for the dry
limestone injection process.
The alkalized alumina process uses a dry sodium-aluminate metal oxide
to contact and react with the sulfur dioxide in a special reactor. The reacted
sorbent is then regenerated with a reducing gas and the sulfur reclaimed. This
process, though more complicated than the limestone injection process, does
produce a saleable by-product in the form of sulfur. Sulfur dioxide removal
efficiencies in excess of 90 percent have been obtained on pilot-scale plants.
Because of the large amount of equipment that must be installed for this
process, it appears to be more adaptable to new installations. The cost of
this system, although speculative at present, is estimated at $8.6 million
capital investment for an 800-megawatt plant. Operating costs vary with the
market for recovered sulfur.
Development of full-scale alkalized alumina process installations is de-
pendent on additional pilot-scale work.
The catalytic oxidation process converts sulfur oxides in the flue gas to
weak (75 to 80 percent) sulfuric acid by passing the gas stream through a vana-
dium pentoxide catalyst and a series of condensers. This process has advanced
through the pilot-plant stage and is available from the developer.
For a new 800-megawatt plant the catalytic oxidation system would re-
quire an investment of between $16 million and $24 million. Operating costs
xxxn
-------
would depend largely on the price obtained for sulfuric acid in that particular
area. Transportation of this weak acid over long distances would not be eco-
nomical.
Other flue-gas desulfurization processes are also being actively studied
both here and abroad. These include the Beckwell scrubbing system, char
sorption, and scrubbing with molten metallic salts.
The following table summarizes SO control techniques for combustion
^
processes.
xxxiii
-------
SUMMARY OF METHODS FOR CONTROLLING SULFUR OXIDE EMISSIONS
FROM STATIONARY COMBUSTION SOURCES
Method
1. Change fuel or energy source.
a. Switch to a fuel with lower
sulfur content
b. Switch to another energy
source such as hydro-
electric or nuclear energy.
2. Desulfurize fuel.
a. Coal
1.
2.
Remarks
a. Fuel switching is being ap-
plied to all sizes of combus-
tion units. Availability,
applicability, and cost of the
fuels with lower sulfur con-
tent are critical factors in
applying this method. Sulfur
oxide emission reduction is
directly proportional to re-
duction of sulfur in fuel.
b. Used currently by large elec-
tric generating stations only.
Causes no sulfur oxide emis-
sions.
a. Coal cleaning techniques,
which include crushing and
flotation, are already being
used to a limited extent.
Sulfur reduction depends on
xxxiv
-------
SUMMARY OF METHODS FOR CONTROLLING SULFUR OXIDE EMISSIONS
FROM STATIONARY COMBUSTION SOURCES (continued)
Method
b. Residual fuel oil
Remarks
the pyrite content of the coal.
Approximately 30 percent of
the sulfur can generally be
removed. Cleanability and
costs vary widely depending
on the type of coal. More
elaborate chemical proces-
sing of coal will yield low-
sulfur fuels, but economically
feasible techniques are still
in the development stage.
b. Catalytic treating with hy-
drogen removes sulfur from
oil. Blending of low-sulfur -
content distillate oils with
residual oil also yields a fuel
with a sulfur content of 1.0
percent or less. For a typi-
cal east coast imported re-
sidual fuel oil, a 60-percent
sulfur reduction can be
xxxv
-------
SUMMARY OF METHODS FOR CONTROLLING SULFUR OXIDE EMISSIONS
FROM STATIONARY COMBUSTION SOURCES (continued)
Method
3. Remove sulfur oxides from
flue gas
a. Limestone-dolomite in-
jection, dry process
3.
Remarks
readily achieved and greater
reductions are possible.
Costs vary widely, but are on
the order of $0. 25 to $0. 75
per barrel ($0. 04-$0.12 per
million Btu).
a. Calcined limestone reacts
with sulfur oxides and is
removed by fly ash control
equipment. A large-scale
prototype unit will be in
operation in 1969. SO0
^
removal efficiencies between
40 and 60 percent are
expected with operating costs
on the order of 0. 029 cents
per kw-hr ($0. OS/106 Btu).
XXXVI
-------
SUMMARY OF METHODS FOR CONTROLLING SULFUR OXIDE EMISSIONS
FROM STATIONARY COMBUSTION SOURCES (continued)
Method
b. Limestone-dolomite in-
jection, wet process
c. Alkalized alumina sorption
Remarks
b. Sulfur oxides react with the
calcined limestone before
entering a wet scrubber where
further removal is achieved.
This process is presently be-
ing installed on a number of
power plants in the 170 to 420
Mw size range. SOQ removal
Z
efficiencies between 80 and
90 percent may be obtained
with an operating cost of
about 0. 035 cents per kw-hr
£J
($0. 036/10 Btu) for an
existing plant.
c. Presently only in the pilot-
plant stage, this process re-
moves sulfur oxides by
sorption on the solid metal
oxide. The metal oxide is
then regenerated and sulfur
is recovered. Removal of at
xxxvii
-------
SUMMARY OF METHODS FOR CONTROLLING SULFUR OXIDE EMISSIONS
FROM STATIONARY COMBUSTION SOURCES (continued)
Method
d. Catalytic oxidation
e. Caustic scrubbing
4.
Increase combustion
efficiency
Remarks
least 90 percent of the sulfur
oxides is expected. Operating
costs may be partially re-
covered when the sulfur is
sold.
d. Sulfur dioxide is catalytically
oxidized to SOQ and recovered
o
as condensed sulfuric acid.
Removal of about 90 percent
of the sulfur oxides is possible.
Net operating costs will de-
pend on the scale of recovered
sulfuric acid.
e. In operation on a few small
combustion processes, costs
and removal efficiencies vary
widely depending on specific
operating conditions.
4. Increased combustion efficiencies
will reduce the amount of fuel
burned and, thereby, decrease
sulfur oxide emissions.
xxxviii
-------
Industrial Processes
Nonferrous primary smelting of sulfide-containing metallic ores such
as copper, zinc, and lead is the largest industrial-process emitter of sulfur
dioxide, and currently accounts for emissions of about 3. 5 million tons per
year. Large modern smelters reduce these emissions by passing the exit
gases through a sulfuric acid plant; they recover a valuable by-product in the
form of sulfuric acid. The sulfuric acid plants are of the contact type and
are adaptable to most smelter gases after the entrained solid matter has been
removed. Installation of a sulfuric acid plant will usually reduce emissions
by more than 90 percent. Smelter operating costs may be reduced by market-
ing the recovered sulfuric acid. About half the primary smelters in this
country presently use sulfuric acid recovery. These smelters use 42 percent
of all the ore concentrate produced in the country.
Petroleum refineries, because of their increasing capacities and con-
sumption of fuel, have become major sources of sulfur oxide emissions. Large
quantities of low-grade, sulfur-bearing gas and liquid fuels generated in the
refining processes, are used as fuel at the refinery. Removal of sulfur com-
pounds from these fuels and from the petroleum feedstock by hydrogen treating
and subsequent recovery of raw sulfur is possible and is practiced at many
large refineries.
Recovery of hydrogen sulfide (H S) generated in the sulfur removal
Zi
processes is readily accomplished by scrubbing the HJ3 stream with
ethanolamine or a similar solution. In this process, the H0S is stripped from
^
the recovery solution by heating. The rich US gas is then converted to sulfur
XXXIX
-------
in a conventional Claus-type process. The cost of sulfur produced in a two-
stage Glaus-type recovery plant varies with plant size, but is much less than
the cost of sulfur produced by conventional methods.
Sulfuric acid plants, by the very nature of the process, are emitters of
SO9 and sulfuric acid mist. These emissions can be decreased through im-
^
proved plant design and operation. By increasing SO2 to S
-------
Dispersion
Dispersion of sulfur oxides by tall stacks can be a useful approach to-
ward reducing the frequency of high concentrations at ground level in some
areas. The usefulness of the approach is limited by local meteorological
and topographic conditions and by other sources of sulfur oxides in the area.
Data presented on the cost of tall stacks show, expenditures in excess of $2
million would be required for most large stacks over 900 feet tall. An
extensive bibliography on gas dispersion is included in this report.
xli
-------
-------
1. INTRODUCTION
Pursuant to authority delegated to the Commissioner of the National Air
Pollution Control Administration, Control Techniques for Sulfur Oxide Air
Pollutants is issued in accordance with Section 107c of the Clean Air Act
(42U.S.C. 1857c-2bl).
Sulfur oxides in the atmosphere are known to have many adverse effects
upon health and welfare, and reduction of emissions of this class of
pollutants is of prime importance to any effective air pollution abatement
program. Sulfur oxide pollutants originate from a variety of sources, and
the emissions vary widely in physical and chemical characteristics.
Similarly, the available control techniques vary in type, application,
effectiveness, and cost.
The control techniques described herein represent a broad spectrum of
information from many engineering and other technical fields. Many of the
devices, methods, and principles have been developed and used over many
years, and much experience has been gained in their application. They are
recommended as the techniques generally applicable to the broad range of
sulfur oxides emission control problems. A discussion of other methods,
still in various stages of research and development, serves to provide in-
formation about the latest concepts under consideration, even though they may
not, as yet, be available for general use.
1-1
-------
The proper choice of a method, or combination of methods, to be
applied to any specific source depends on many factors other than the
characteristics of the source itself. While a certain percentage of control,
for example, may be acceptable for a single source, a much higher degree
may be required for the same source when its emissions blend with those of
others. This document provides a comprehensive review of the approaches
commonly recommended for controlling the sources of sulfur oxides air
pollution. It does not review all possible combinations of control techniques
that might bring about more stringent control of each individual source.
The many commercial, domestic, industrial, and municipal processes
and activities that generate sulfur oxide air pollutants are described in-
dividually in this document. The various techniques that can be applied to
control emissions of sulfur oxides from these sources are reviewed and
compared. Consideration of the availability and potential use of different
fuels forms a major segment because, at the present time, means have not
yet been perfected for effectively removing sulfur oxides from the flue gases
of fuel-burning installations. Sections on source evaluation, equipment costs
and cost-effectiveness analysis, and current research and development also are
included. The bibliography comprises important reference articles, arranged
according to applicable processes.
While some data are presented on quantities of sulfur oxides emitted to
the atmosphere, the subject of the effects of sulfur oxides on health and wel-
fare are considered in a companion document, Air Quality Criteria for
Sulfur Oxides.
1-2
-------
The National Air Pollution Control Administration also is publishing a
document which discusses the philosophy underlying the issuance of air
quality criteria, and which suggests some general guidelines for utilizing the
criteria to develop air quality standards. This latter publication also
describes the factors that should be considered in developing and evaluating
States' air quality standards and implementation plans.
1-3
-------
-------
2. DEFINITIONS AND MEASUREMENTS OF SULFUR OXIDES
An oxide of sulfur is any chemical combination of sulfur and oxygen.
This report, however, deals with only two such oxides, sulfur dioxide (SOJ
and sulfur trioxide (SO0), which are the most common sulfur oxide pollutants.
o
Sulfur dioxide is an invisible, nonflammable, acidic gas. It oxidizes to SO
o
in the atmosphere at varying rates, depending on temperature and the
presence of other substances. Sulfur trioxide is a highly hygroscopic gas,
which combines with water in the atmosphere to form sulfuric acid mist
(H9SO.), or with other materials in the atmosphere to form sulfate compounds.
Lt 4
Atmospheric concentrations of SO0 may be determined by manual or
^
1 2
automatic methods. ' A commonly used manual method is the p-rosaniline
or West-Gaeke technique. Continuous monitoring instruments that sample,
analyze, and continually record atmospheric SO concentrations are com-
&
mercially available. Sulfation of exposed lead peroxide paste and the sulfate
content of atmospheric particulates are other indications of the presence of
sulfur oxides in the air.
REFERENCES FOR SECTION 2
1. "Methods of Measuring and Monitoring Atmospheric Sulfur Dioxide."
U. S. Dept. of Health, Education, and Welfare, National Center
for Air Pollution Control, PHS-Pub-999-AP-6, Aug. 1964.
2. American Society for Testing and Materials, Method D 1355-60.
2-1
331-543 O - 69 - 4
-------
-------
3. MAJOR SOURCES OF SULFUR OXIDES
Sulfur oxides, primarily SO , are generated during the combustion of any
i
sulfur-bearing fuel, and by many industrial processes that use sulfur-bearing
raw materials. In 1966, about 28. 6 million tons of SO was emitted in the
4U
United States. The various sources of SO are shown in Figure 3-1.
£
The distribution of emissions by source category in any particular city or
specific location may differ markedly from that shown.
Figure 3-2 shows the estimated increase in SO emissions with the passage
^
of time if no air pollution controls were to be applied. This increase is largely
due to the projected increase in fuel consumption by utility companies, which,
it is expected, will level off in 1990, as nuclear power stations replace more
fuel burning plants.
3-1
-------
OTHER FUEL COMBUSTION
9.1 MILLION TONS
INDUSTRIAL
PROCESSES
(EXCLUDING FUEL
COMBUSTION)
6.4 MILLION TONS
FUEL COMBUSTION BY
ELECTRICAL UTILITIES
13.1 MILLION TONS
Figure 3-1. Nationwide sources of sulfur dioxide
emissions, 1966.1>2
3-2
-------
o
o
Z
O
UJ
CN
O
70
60
50
40
30
20
10
""•s.
1960
1970
1980
YEAR
1990
2000
Figure 3-2. Estimated SO2 emissions.3
3-3
-------
3.1 COMBUSTION SOURCES
Combustion of fuels accounts for 77 percent of all SO2 emitted. This
is due to the relatively high sulfur content of some bituminous coals and
residual fuel oils, and to the very large amounts of these fuels consumed
in this country. Bituminous coal and residual fuel oil usually contain from
1 to 3 percent sulfur by weight. Combustion of these fuels produces about
2 pounds of SO0 and about 0. 03 pound of SOQ for each pound of sulfur in
4 o
the fuel.
Data on SO0 emissions from fuel combustion in 1966 are presented
^
in Table 3-1.
3-4
-------
Table 3-1. SO_ EMISSIONS FROM FUEL
Z
COMBUSTION IN 19662
Source SO0 emissions, tons
4
Utility coal . 11,925,000
Utility oil 1,218,000
Other coal 4,700,000
Other oil 4,386,000
Natural gasa 3,500
Total 22,232,500
Q
Not included in Reference 2.
3-5
-------
3.2 INDUSTRIAL PROCESS SOURCES
Smelting of metallic ores and oil refinery operations are the major
industrial process sources of SO emissions. Increased demand for sulfur and
LJ
sulfuric acid should result in a more profitable recovery market for these
emissions, tending to prevent any large, future increase of SO emissions from
&
these sources.
Sulfur dioxide emissions from industrial process sources in 1966 are
given in Table 3-2.
3-6
-------
Table 3-2. SO2 EMISSIONS FROM INDUSTRIAL PROCESS
SOURCES IN 19662
SO™ emissions, tons
Ore smelting 3,500,000
Petroleum 1,583,000
Sulfuric acid manufacturing 550, 000
Coke processing 500,000
Refuse burning 200,000
o
Miscellaneous 75,000
Total industrial process 6, 408, 000
Q
Includes chemical manufacturing, and pulp and paper production.
3-7
-------
REFERENCES FOR SECTION 3
1. Hangebrauck, R. P. and Spaite, P. W. "A Status Report on Controlling
the Oxides of Sulfur. " J. Air Pollution Control Assoc. , Vol. 18, pp. 5-8,
Jan. 1968.
2. Rohrman, F. A. and Ludwig, J. H. Unpublished data, U. S. Dept. of
Health, Education, and Welfare, National Center for Air Pollution Control.
3. Rohrman, F. A. and Ludwig, J. H. "SO2 Pollution: The Next 30 Years. "
Power, pp. 82-83, May 1967.
3-8
-------
4. CONTROL TECHNIQUES FOR FUEL COMBUSTION PROCESSES
4.1 ENERGY SOURCES, CONSUMPTION, AND USAGE TRENDS
The selection of an energy source depends upon the projected use, the
competitive ability of producers of the raw energy (including electricity) to
deliver the energy to the consumer, availability of the various raw energy
forms, and preference of the consumer. Another factor is the effect on
ambient air quality. Substitution of a low-air-pollution-potential energy
source for a high-potential one is an effective method of reducing emissions of
various air contaminants, including sulfur oxides.
As shown in the previous chapter, the combustion of coal and petroleum
products (not including natural gas) accounted for approximately 22, 229, 000
tons, or 77 percent, of the emissions of SO9 in the United States in 1966.
&
Combustion of fuel for utility power generation is the largest source category,
accounting for 45. 5 percent of the total emissions of SO0. In the Washington,
£
D. C. , metropolitan area, for example, the combustion of fuel for utility
power generation accounted for 63 percent of the area's total SO0 emissions.
^
In other areas, such as the Pacific Northwest, fuel combustion may account
for little or no sulfur oxide emissions. If projected fuel use trends prove
valid, and no changes in the sulfur content of fuels or in SO^ control
practices occur, then SO2 emissions will more than double by the year 2000.
4-1
-------
The United States consumes more energy than any other single nation.
The annual energy consumption has increased from 101. 3 million Btu per
2 3
capita in 1850 to 278 million Btu per capita in 1965. The corresponding
12
total energy consumption has increased from 2, 357 x 10 Btu per year in
18502 to 53, 785 x 1012 Btu per year in 1965. 3
Table 4-1 shows the consumption of energy by major sources and con-
suming sectors from 1947 through 1966. The data indicate that the long-
term consumption of coal has declined while consumption of petroleum, natural
gas, hydropower, and nuclear power all have increased. Trends in electrical
generation indicate that coal is the major fuel used and that its use has con-
tinued to increase in that category. Although electrical generation by
nuclear power was begun in 1956, it was 1960 before it accounted for 0.1
percent of the production.
Long-range forecasts of energy requirements and fuel-use patterns are
approximations. The forecasts include a wide range of assumptions and
judgments regarding population growth, per capita consumption, changes in
technology of use, economic developments, and availability of the several
fuels.
Before 1962, the projected total energy consumption for the year 1980
ranged from 60 x 10 5 to 145 x 1015 Btu (an average of 82 x 10 Btu).
Estimates for the year 2000 range from 105 x 10 to 280 x 10 Btu. More
15 15
recent estimates for 1980 range from 82 x 10 to slightly less than 100 x 10
4-2
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4-4
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Btu.
6-10
The total annual energy consumption per capita is predicted to
ft n Q
increase from 278 x 10 Btu in 1965 to 415 x 10 Btu in 1985.
The data in Figure 4-1 show that consumption of most energy sources
will continue to increase and that nuclear energy will have the greatest rate
of increase. In 1964, Landsberg predicted for the years 1980 and 2000 the
energy requirements and fuel-use patterns for commercial, residential, and
industrial markets in the United States. These predictions, which now seem
somewhat conservative, are presented in Figures 4-2 through 4-4. The
ioo,ooopr—|—i—i—i—i—i—i—i—i—i—r^3 electric generating capacities,
so.ooof- —\ by energy source for the year
1966, projected for the years 1980
3
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1850 1870 1890 1910 1930 1950 1970
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and 2000, are presented in
Figure 4-5. 6'12
Other, more recent
13
estimates predict that the 1980
nuclear capacity of electrical
utilities will be approximately
150,000 megawatts, or 25 percent
of the total electrical capacity.
It is estimated that by the year
2000, the nuclear capacity will
account for more than half of the
Nation's electrical generating
Figure 4-1. Trends in energy consumption by capacity.
source, 1850 - 1965.2,3
4-5
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4-6
-------
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dential home heating."11
4-7
331-543 O - 69 - 5
-------
32.34
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COAL
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use patterns for industrial use
(except electricity).11
4-8
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1980 2000
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Figure 4-5. Trends in electrical power
generation. 6'12'13
4-9
-------
4. 2 ENERGY AVAILABILITY
4.2.1 Coal
In the United States, estimated recoverable reserves of coal comprise
14
approximately 83 percent of all fossil fuels in terms of energy equivalents.
Figure 4-6 is a map showing the coal producing areas in the United States.
Figure 4-7 shows the estimated original and remaining coal reserves by rank
as of January 1, 1965.
The use of the term "coal reserve" has very little meaning unless it is
further described. "Estimated original coal reserve" is defined as the initial
coal reserve before any was ever produced. "Remaining coal reserve" means
the amount that is underground as of the date of the estimate. "Recoverable
coal reserve" is the amount of coal underground, as of the date of the estimate,
that can probably be mined in the future. These estimates include only that
coal which is in seams that are 14 inches thick or more and occurs at
depths of 3,000 feet or less. All of this recoverable coal may, however, not
be economically mineable. Bituminous coal is currently being recovered from
active mines at an efficiency of approximately 57 percent.
Sulfur content of remaining coal reserves is an important factor in air
pollution control. Table 4-2 shows the remaining reserves of coal of all ranks
as of January 1, 1965, by range of sulfur content and by State. These estimates
indicate that approximately two-thirds of the estimated reserve consists of low-
sulfur (1. 0 percent or less) coal; however, more than half is composed of
4-10
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4-14
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low-rank coals (subbituminous and lignite). Considering only high-rank coals
(bituminous and anthracite), the States east of the Mississippi River contain
9
slightly over 40 percent (95 X 10 tons) of the coals containing 1. 0 percent
sulfur or less. These data are based largely on the analysis of cleaned coals.
In dealing with fuel sulfur content, it is important to note that an average
sulfur content may be quite misleading in that it does not give any information
on the range of sulfur values actually encountered. A range of sulfur contents
or a maximum value should, therefore, be considered in specifying sulfur limits
for fuels.
Approximately 98 percent of the total lignite reserves, which are largely
low in sulfur, are located in North Dakota and Montana. Reserves of low-
sulfur subbituminous coal are also located in the Western States, with about
60 percent of the total occurring in Montana and Wyoming.
Extra-high-voltage transmission of electricity and developments in the
technology of using low-rank coal as a practical and economical fuel make it
possible to have large power generating stations burn subbituminous coal or
lignite. Until recently the problems with burning low-rank lignite have kept
interest in its use low; however, better firing technology and better equipment
18
have spurred lignite development. Reserves of peat, the first-stage
alteration of vegetable matter to coal, are approximately 14, 000 million air-
dried tons with a heating value of about 5800 to 7900 Btu per pound. Approxi-
mately 75 percent of this reserve occurs in Minnesota, Wisconsin, and
19
Michigan.
4-15
-------
Approximately two-thirds of the total bituminous reserve is located east
of the Mississippi. The economy of mining these reserves has, however, not
yet been determined nor is the amount of coal already under contract generally
known. The data presented in Table 4-2 indicate that the United States has an
abundant supply of coal for many years. However, the availability of low-
sulfur coal of high rank is somewhat limited.
4.2.2 Oil
4.2. 2.1 Crude Oil - Over the years many estimates have been made of the
world's oil reserves. These estimates are based on qualifying assumptions,
such as future recovery efficiency and the amount of oil underground still
to be found. In this report, the following definitions are used:
1. Ultimate resources of crude oil include the sum of past
discoveries and estimated reserves that will be discovered in the
future.
20
2. Proved reserves include estimated quantities of crude oil
that geological and engineering data demonstrate with reasonable
certainty to be recoverable in the future from known oil reservoirs
under existing economic and operating conditions.
3. Future recoverable oil reserves include that remaining portion
of the total recoverable reserves, not included in the proved
reserves and past production, that present and past production
experience suggests can actually be recovered in the future.
4. Total recoverable reserves include future recoverable reserves,
proved reserves, and past production.
4-16
-------
The history of the petroleum industry abounds with estimates of our
crude oil reserves. Current estimates of ultimate United States crude-oil
4.
reserves are in the range of 500 billion barrels. At the present recovery
efficiency, total recoverable reserves for the United States are about 175
billion barrels.
The proved reserves of the United States represent the working inventory
of the petroleum industry and have been kept at approximately 31 billion
barrels. About 3 billion barrels of domestic crude oil is now being produced
21
per year.
Future recoverable reserves are of major importance since they are
based on the present recovery efficiency (approximately one-third) and since
they represent the amount of crude oil potentially available in the future. If
the recover ability increases in the future, as petroleum authorities project,
future recoverable reserves will increase proportionally.
Since the occurrence of oil, whatever its magnitude, is ultimately finite,
exploitation should reach a peak - or perhaps several peaks or an extended
plateau - then subside and terminate. Assuming that the estimate of 175
billion barrels of recoverable crude oil for the U.S. is reasonable, the curve
in Figure 4-8 should represent the future oil production rate. Of this 175
billion barrels, 83 billion barrels has already been produced. Proved
reserves make up another 31 billion barrels, leaving about 61 billion barrels
as future recoverable reserves.
Relative price movements, government policy, and changes in the
technology of production and distribution have been the key factors in main-
taining the continuing upward trend in oil production.
4-17
-------
PROVED RESERVES
31 x 109 bbl
£
-Q
CUMULATIVE
PRODUCTION
83 x 109 bbl
•FUTURE RECOVERABLE
RESERVES
61 x 109 bbl
\
1850
1900
1950
2000
2050
YEAR
Figure 4-8. Estimate of U. S. production of crude oil as of December 31, 1967.22
The projected decline in production rate shows that in order to meet the
demand, the efficiency of recovery will have to increase, or other sources,
\
such as foreign imports and synthetic crude from oil shale, tar sands, and
coal, will eventually become the principal suppliers of crude oil in the United
States.'
Future additional sources of oil for the United States which appear
promising include the potential supplies in the oil shale formations of
Wyoming, Colorado, and Utah; the tar sands in Canada and the United States;
23
and the liquefaction of coal (Section 4. 4. 2. 4).
The oil shale formations in the western United States occupy about
16, 000 square miles of land. 24 It is estimated that 600 billion barrels of
crude oil is recoverable from deposits assaying more than 25 gallons
per ton of shale. Plans for the first large commercial plant for
4-18
-------
extracting and refining this shale into synthetic crude oil at the rate of 58, 000
barrels per day have been announced.
It has been known for many years that the Athabasca Tar Sands of
Canada are a potential source of oil, but until recently economic extraction
from the sand has not been feasible. The first commercially operated plant
was dedicated by Great Canadian Oil Sands, Ltd., on September 30, 1967, with
a capacity of approximately 45 thousand barrels of synthetic crude oil per
o/>
day. Most of this crude oil is refined into high-grade distillate products.
The ultimate reserves in Canada are estimated to be about 600 billion
27 26
barrels, 300 billion barrels of which is believed to be recoverable. It is
estimated that tar sands recently discovered in Utah contain 46 billion barrels
28
of crude oil in reservoirs favorable to thermal recovery, but the economics
of this recovery have not yet been determined.
The distribution of the total United States crude oil production according
to sulfur content in 1966 is illustrated in Table 4-3. Almost 80 percent of the
total has a sulfur content of 1 percent or less by weight.
Significant trends for the period 1956 through 1966 include the following:
1. In the Gulf Coast area a relative increase in production of
crude oil containing 0. 26 to 0. 50 percent sulfur.
2. In the Mid-Continent area a decrease in production of crude oil in
the 0. 26 to 0. 50 percent sulfur category.
3. In the Rocky Mountain area an increase in production of crude oil
in the 0. 00 to 0. 25 percent sulfur category.
4-19
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The distribution for 1966 of the foreign crude oil production within the
free world, excluding the United States, is shown by area and sulfur content
in Table 4-4. The percentage distribution in each sulfur content category is
included. Note that the majority of crude oil containing less than 1. 0 percent
sulfur is located in Africa and Canada.
Data on the crude oil imported into the United States in 1966 are sum-
marized in Table 4-5. The average sulfur content of these imports may be
approximated on the basis of the average sulfur contents shown in Table 4-4.
These imports account for about 15 percent of United States production.
The President of the United States, under section 232 of the Trade
Expansion Act of 1962, may make adjustments in the imports of crude oil,
unfinished oils, and finished products as necessary so that such imports do
not threaten our national security. For instance, Proclamation 3894 Federal
Register, Vol. 32, No. 138, July 19, 1967, in support of Federal, State, and
local rules and regulations for air pollution control, allowed the petroleum
industry to provide additional supplies of low-sulfur residual fuel oil to the
fuel combustion market.
All allocations or licenses to import crude oil, unfinished oils, or
finished products are granted according to regulations of the Oil Import Admin-
istration, Department of the Interior, under review of the Secretary. Such
allocations may become even more important in the future with the expected
increased demand for low-sulfur fuels.
4-21
-------
Table 4-4. FOREIGN CRUDE OIL PRODUCTION BY AREA
AND SULFUR CONTENT CATEGORY21
Area and
sulfur content range,
weight %
1966 production
10 bbl Percent
Africa:
0.00 -
0.26 -
0.51 -
1.01 -
>
Canada:
0.00 -
0.26 -
0.51 -
1.01 -
>
0.25
0.50
1.00
2.00
2.00
0.25
0.50
1.00
2.00
•2.00
637
144
216
-
3
112
18
107
40
40
63.7
14.4
21.6
-
0.3
35.4
5.7
33.7
12.6
12.6
Middle East:
0.00 - 0.25
0.26 - 0.50
0.51 - 1.00
1.01 - 2.00
>2. 00
-
-
-
1509
1862
-
-
-
44.8
55.2
South America:
0.00 - 0.25
0.26 - 0.50
0. 51 - 1. 00
1. 01 - 2. 00
>2. 00
24
19
52
225
1161
1.6
1.3
3.5
15.2
78.4
4-22
-------
Table 4-5. CRUDE OIL IMPORTED INTO UNITED STATES - 19663
(106 bbl)
Area Amount
North America 126. 7
South America 163.1
Middle East 107.6
Africa 31.5
o
Asiatic Areas 18. 2
Total 447.1
aSumatra crude oil imported into West Coast - sulfur content,
by weight, is 0.1 percent. ^9
4-23
331-543 O - 69 - £
-------
Regulations liberalizing the importation of low-sulfur crude oils to
permit production of low-sulfur fuel oils have already been established for the
West Coast by the Department of Interior, and similiar changes are being
considered for the East Coast.
4. 2. 2. 2 Residual Fuel Oil - Refining of crude oil produces various grades of
fuel oil in addition to other lighter petroleum products such as gasoline. Due
to the nature of the refining processes, and the characteristics of the sulfur
compounds in crude oil, the sulfur is concentrated in the heavier fractions,
30
which have higher boiling points.
ASTM (the American Society for Testing and Materials) in its publi-
cation "D396 - Standard Specifications for Fuel Oils," classifies fuel oils into
two main categories - distillates and residuals. These in turn are then sub-
divided into five grades, 1, 2, 4, 5, and 6. There are three commercial
grades of residual oil marketed in the United States - grades 4,* 5, and 6.
Grades 4 and 5 are produced either as straight-run fractions, or by blending
grades 6 and 2. They are used primarily for heating commercial and in-
dustrial buildings. Grade 6 is described as a heavy oil, and is used exten-
sively to fire large boilers in public utility, industrial, and commercial
installations; and as a fuel for large diesel engines, especially marine
31
engines. In marine applications, grade 6 is often referred to as bunker
fuel oil, or Bunker C. The average sulfur content of these three grades
ranges from 0. 5 to 5. 0 percent by weight with the majority in the range of
0. 75 to 2. 5 percent.
*Grade 4 is actually a blend of distillate and residual fuels, and is currently
classified as a residual fuel oil for import purposes.
4-24
-------
Currently, about 7 percent of domestic crude oil ends up as residual oil
A
fractions, compared to 14 percent in 1957. The distribution by region and by
sulfur content of residual oil from domestic crude is shown in Table 4-6. This
fuel is substantially all committed and delivered to specific markets, such as
the metal industry. This being the present trend, imported residual fuel oil,
higher in sulfur content, has become the principal source of other major con-
sumer groups. South American countries, due to factors such as water trans-
portation, have become the chief suppliers of this product (as indicated in
Table 4-7), supplying over 90 percent of the residual fuel oil imported during
the period 1964 through 1966. The average sulfur content of this South
American residual oil is 2. 25 percent by weight. The total 376, 795, 000
barrels of imported residual oil constitutes over 61 percent of the total domes-
tic consumption of this fuel in 1966. The other 39 percent originated from
foreign and domestic crudes refined in the United States.
The total consumption of residual oil by major consuming groups in the
United States is illustrated in Table 4-8 for the years 1963 through 1966. By
1966 the eastern States consumed about 420 million barrels, the western
States about 100 million barrels, and the gulf coast and inland States about
3
100 million barrels.
The sulfur oxide emissions that result from the combustion of this tre-
mendous volume of high-sulfur fuel have presented a problem for some large
cities. Air pollution control legislation now in force in some of these cities
limits the sulfur content of fuels burned, resulting in an increased demand for
low-sulfur fuel.
4-25
-------
Table 4-6. RESIDUAL FUEL OIL PRODUCTION FROM DOMESTIC CRUDE
OIL IN U. S. BY SULFUR CONTENT3" - 1965 32'33
Sulfur,
%
<0.7
0.7-1.0
1.0 - 1.5
1.5 - 2.0
2.0 - 3.0
>3.0
Regional total
Regional %
Average S %
do3
Gulf
East Coast States
3,310
930 4,728
15,472
2,200 4,000
15,650 9,360
2,200
18,780 39,070
10.6 22.0
2.44 1.61
bbl)
Central
States
8,750
12,920
19,250
200
25,518
2,110
68, 748
38.8
1.70
Pacific
Coast
1,975
8,138
5,186
24,575
6,600
4,300
50,774
28.6
1.72
Total
14,035
26,716
39,908
30,975
57,128
8,610
177,372
100
1.76
%of
total
7.9
15.0
22.5
17.5
32.0
4.9
100.0
o
99 percent of the operating refineries.
4-26
-------
Table 4-7. RESIDUAL FUEL OIL IMPORTS INTO UNITED STATES
0«3
1964-1966
Imports, 10
Country of origin
Venezuela
Netherland Antilles
(Aruba, Curacao)
British West Indies
(Trinidad and Tobago)
Mexico
Italy
Puerto Rico
Argentina
Colombia
England
Canada
Netherlands
Panama
Kuwait
Others
Totals
1964
142,256
95,182
36,527
6,684
12
4,787
1,290
1,485
-
1,826
117
1,541
-
4,184
295,891
1965
180,538
103,645
37,600
5,839
422
4,371
2,945
3,090
95
1,964
41
1,231
-
3,406
345,187
bbl
1966a
194,676
100,101
44,614
6,067
5,264
4,749
4,346
3,515
2,109
1,880
1,285
1,113
1,093
5,983
376,795
1966
average
sulfur, %
2.2
2.46
1.93
4.4
2.8
2.2
1.0
1.55
3.5
2.65
3.00b
2.00b
-
-
-
Preliminary.
'Estimated.
4-27
-------
Table 4-8. TOTAL U.S. CONSUMPTION OF RESIDUAL OIL BY MAJOR
CONSUMING GROUP - 1963-19663
(103 bbl)
Consuming group
Heating oils (apartments
and commercial)
Industrial (excluding
oil company fuel)
Oil company use (ex-
cluding heating oil)
Electric generation
utilities
Railroads
Bunkering of vessels
(excluding military)
Military use
Miscellaneous
Total
1963
125,248
149,269
46,976
91,615
5,342
76,502
36,444
7,126
538,522
1964
126,215
157,176
43, 098
97,595
5,350
83,024
35,568
8,606
556,632
1965
156,254
140,602
34,354
114,884
4,001
73,639
40,380
10,004
574,118
1966
167,471
141,050
35,177
140,642
3,792
73,641
41,861
10,338
613,972a
a376, 795, 000 barrels were imported.
4-28
-------
The Secretary of the Interior, in an attempt to help alleviate the problem
of importing high-sulfur residual oils, announced on July 17, 1967, a modifica-
tion of the oil import program. In essence, the definition of residual fuel oil
was broadened to include grade 4 fuel oil, which had previously been consid-
ered distillate. This fuel usually has a sulfur content of under 1.5 percent.
The definition of residual fuel oil also was expanded to include those low-sulfur
crude oils that may be burned directly as fuel oil without any processing. Thus,
low-sulfur fuel from two new sources now is available to users of residual
fuel oil.
4.2.2.3 Distillate Fuel Oils - Distillate fuel oils, grades 1 and 2, are prin-
cipally used for heating homes, domestic hot water, small apartment houses,
and in certain industrial processes where simplified burning apparatus is
required and the firing rate is usually not more than 20 to 25 gallons per
hour. These distillate oils normally have a heating value of 5.8 to 6 million
Btu per barrel. The average sulfur content of this fuel is between 0. 04 and
0.35 percent by weight. Table 4-9 gives a breakdown, by section of the
country, of the average sulfur content of grades 1 and 2. Because of the rela-
tively low sulfur content, distillate fuel oils can be burned without creating
large amounts of sulfur oxide emissions.
Quantities of distillate fuels for various user categories have been re-
ported and show that about 85 percent of all distillate fuels other than diesel
35
fuel and kerosene is used for space heating. In 1966, about 506 million
35
barrels of distillate fuel, excluding diesel fuel was consumed.
4-29
-------
Table 4-9. AVERAGE SULFUR CONTENT OF DISTILLATE FUEL
o OC
OILS FOR UNITED STATES BY REGION - 1967
Region
Eastern
Southern
Central
Rocky Mountains
Western
No. 1
0.060
0.040
0.089
0.105
0.124
Grade
No. 2
0.232
0.184
0.283
0.321
0.307
Q
Region boundaries defined in reference 36.
4-30
-------
4.2.3 Natural Gas
Natural gas is a mixture of low-molecular-weight hydrocarbons. Meth-
ane is almost always the major constituent. It ordinarily has a negligible
sulfur content; however, if the sulfur content is significant in its natural form
the gas must be processed to reduce the sulfur compounds before it can be
marketed. Natural gas occurs underground either dissolved in oil, in reser-
voirs of gas above pools of oil, or in gas fields unassociated with oil.
The allocation of this fuel and its cost when it is shipped interstate are
the responsibility of the Federal Power Commission. Such factors as poten-
tial supply, reserve-production ratio, present and future technologies available
to improve recovery and economic factors, and improvement in methods of
production of a comparable synthetic will influence these decisions.
Most of the gas produced in the United States has come from reservoirs
without oil, or in areas where the production of gas is not significantly affected
37
by the oil. Figure 4-9 outlines the location of these fields throughout the
United States. Authoritative annual estimates of proved reserves of natural
gas* in the United States and estimated yearly production figures have been
prepared since 1946 by the Committee on Natural Gas Reserves of the
American Gas Association.
*Proved reserves of natural gas, as used by the American Gas Association
Committee of Natural Gas Reserves, means the current estimated quantity of
natural gas and natural gas liquids which analysis of geologic and engineering
data demonstrates with reasonable certainty to be recoverable in the future
from known oil and gas reservoirs under existing economic and operating
conditions.
4-31
-------
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4-32
-------
Natural gas reserves in the United States will be covered under two
general headings - proved reserves and potential supply. The potential supply
is divided into three categories - probable, possible, and speculative. (See
reference 38, for definitions of these terms). Total recoverable reserves
include the total of proved reserves and potential supply of natural gas.
The proved recoverable reserves (at 14. 73 psia and 60 F) in the United
States as of December 31, 1967, were 292.9 trillion cubic feet, while the total
potential supply was estimated to be 690 trillion cubic feet, resulting in a
26 27
total recoverable reserve of about 983 trillion cubic feet. ' The proved
reserves by State are shown in Table 4-10. About 70 percent of the potential
supply of natural gas is located in the south-central and gulf coast States.
Proved reserves have continued to increase through 1967, although at a
slightly reduced rate. This reduction is attributed to the fact that the rate of
consumption has been increasing over the past few years while the rate of
development of new fields has remained relatively constant. Since 1946, when
the American Gas Association first initiated its annual proved reserves study,
about 146 trillion cubic feet of natural gas has been added to the proved re-
serves, while the actual annual production has increased from 4. 9 trillion
20
cubic feet in 1946 to 18.4 trillion cubic feet in 1967.
Within the next few years, production of natural gas for the first time
will probably exceed the new supply developed. If past trends continue,
total proved reserves may peak at approximately 300 trillion cubic feet in
1971 or 1972; and, if projections are right, reserves will decrease to about
41
273 trillion cubic feet by 1980. It is estimated that net production will rise
4-33
-------
Table 4-10. ESTIMATED PROVED RECOVERABLE RESERVES OF
NATURAL GAS IN UNITED STATES39'40
(106 ft3 - 14. 73 psia, at 60°F)
State
Alaska
Arkansas
California
Colorado
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Montana
Nebraska
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
Texas a
Utah
Virginia
West Virginia
Wyoming fe
Miscellaneous
Total United States
As of
December 31, 1966
2,946,862
2,599,629
8,474,393
1,651,406
236,493
71,207
15,923,275
1,017,007
83,684,092
773,131
1,668,863
620,350
72,757
14,753,142
120,871
1,024,509
755,215
20,122,191
1,350,576
123,609,326
1,372,225
37,586
2,622,237
3,594,046
231,416
289,332,805
As of
December 31, 1967
3,635,254
2,811,251
7,723,797
1,769,263
258,604
74,781
15,283,657
953, 983
86,290,009
760,912
1,597,007
837,718
63,792
15,092,465
121,086
882,132
762,731
19,403,806
1,392,170
125,415,064
1,226,517
37,798
2,579,986
3,685,459
238,461
292., 907, 703
Includes offshore reserves.
Includes Alabama, Arizona, Florida, Iowa, Maryland, Missouri, Tennessee,
and Washington.
4-34
-------
from 18. 4 trillion cubic feet in 1967 to 20. 5 trillion cubic feet in 1970, 24. 25
trillion cubic feet in 1975, and 27. 0 trillion cubic feet in 1980. Marginal
reservoirs of natural gas may become economically recoverable by such
42
treatments as the use of underground nuclear explosions.
There are three major classes of natural gas consumers: residential,
commercial, and industrial. Almost without exception, residential and com-
mercial customers are served by public utilities, whereas industrial custom-
ers are served by distributors and pipeline companies. Table 4-11 shows
natural gas consumption by principal use in the United States. Industrial
customers use about two-thirds of all natural gas in the United States, and
residential customers use about one-fourth.
Gas is supplied on either a continuous or an interruptible basis. Con-
tinuous service provides the consumer with gas according to his needs; inter-
ruptible service is provided only when the distribution system has sufficient
gas. Usually, residential and commercial service is on a continuous basis
but large users may be served on an interruptible basis. Thus, when there
is a heavy demand from the residential and commercial categories, it may be
necessary for large industries to switch to another fuel.
4.2.3.1 Other Sources of Natural Gas - Importation of natural gas at the
present time is limited to small shipments by pipeline from Canada and
Mexico. Net imports from Canada - less than 3 percent of United States con-
sumption - are expected to rise rapidly, from 482 billion cubic feet in 1967 to
41
1350 billion cubic feet in 1980. Net imports from Canada and Mexico should
rise to 3. 8 percent of the United States demand by 1970 and to as much as 5.1
41
percent in 1980.
4-35
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A third promising source of imports is shipment by tanker of natural
gas in liquid form from countries such as Venezuela. This source is tech-
nically feasible and the economics of importation is being studied at the
present time. The Philadelphia Gas Works is currently constructing a liqui-
fied natural gas plan to handle its peaking load and plans to start importing
liquified natural gas in 3 to 5 years.
4.2.3.2 Natural-Gas Liquids - Natural-gas liquids are by-products resulting
from production of natural gas. The ratio of natural gas to natural-gas liquids
is approximately 30, 000 cubic feet of gas per barrel of liquids. It is estimated
that total proved reserves of about 8.6 x 10 barrels of natural-gas liquids
39
exist in the United States.
The 1966 net production of natural-gas liquids was approximately 588 x
/^ O Q
10 barrels. Of this total, liquid-petroleum gases and ethane accounted for
about 61 percent, natural gasoline and isopentane for about 29 percent, other
3
products for about 8 percent, and finished gasoline and naphtha for 3 percent.
Combustion of these fuels produces very little sulfur oxide emission.
4.2.4 Hydroelectric Power
Hydroelectric power does not require,fuel for generation and, therefore,
does not create any sulfur oxides. Hydroelectric generation presently accounts
for 18 percent of the electrical energy produced in the United States, but it is
estimated that by 1980 only 13 percent of the total electrical energy will be
supplied by this source. Figure 4-10 and Table 4-12 show the locations and
trends for hydroelectric projects.
4-37
-------
(O
O)
ta
(0
c
o
(0
c
o
o
z
o
0
a:
LU
o
z
3
0
UJ
a.
o
n i
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UJ
o
>-
1-
(J
a.
<
u
a
•
1
o
in
s
D
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j
o
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D
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ct:
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s
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o
m
^
n
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a>
a.
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W
*-»
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o"
l_
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LL
4-38
-------
Table 4-12. EXISTING AND PROJECTED HYDROELECTRIC CAPACITY
OF UNITED STATES TO 198045
(106 kw)
Existing capacity 45.8
Capacity under construction 14. 6
Subtotal 1970 60.4
Estimated additions to 1980 17.6
Total 1980 78.0
4-39
331-543 O - 69 - 7
-------
4.2.5 Nuclear Power
Nuclear energy is our newest and most promising source of energy. The
use of nuclear energy has grown at a tremendous rate, as evidenced by the fact
that in September 1968, over 100 nuclear electric generating plants with a
total capacity of 72, 000 megawatts were in operation, under construction, or
46
planned. The primary reasons for this growth are significant reductions in
cost of nuclear power and increases in plant capacity. In most areas, the
cost of power generated in nuclear plants having a capacity greater than 500
megawatts is now competitive with that of fossil fuel plants. An important
feature of nuclear plants from an air pollution standpoint is that they emit no
sulfur oxides.
Nuclear energy has several advantages and several disadvantages. Some
of the advantages are: essential elimination of the need for stored fuel, elimi-
nation of vulnerability of fuel flow to strikes, relative economy where moderate
to high fossil fuel prices prevail, use of waste heat for processing sea water or
high-mineral-content inland water supplies to fresh water, and the absence of
sulfur oxides emissions.
The disadvantages include: lack of public acceptance in highly populated
areas, high initial plant costs, expensive liability insurance, increased
cooling-water needs, radioactive waste disposal, radiation hazards, and the
extensive safeguards required to protect public health. Because of the econo-
mic pressure of these disadvantages there is a tendency toward re-evaluation
47
of nuclear reactor sites. The potential of nuclear power plants to contamin-
ate the environment with radioactivity under accidental conditions is recognized,
4-40
-------
and surveillance programs are conducted to assure the continued protection of
48
the public health.
Because of their relative simplicity of construction and their reliability,
most reactors that have been installed in the United States are water-cooled,
either by boiling water (BWR type) or by pressurized water (PWR type).
Figure 4-11 is a map of the United States showing plants in operation,
being built, and planned. As of December 31, 1967, the nuclear plant capacity
in operation was 2, 810,100 kilowatts; the capacity of plants under construction
49
was 14,657,400 kilowatts. In order to meet the demand for more power
capacity, and because the unit cost of electricity decreases as generator size
increases, there has been a general trend toward bigger plants. Studies now
indicate that plants up to 3000 megawatts are technically feasible though there
may be engineering problems associated with the manufacture of pressure
vessels and single-shaft turbines for a plant this large.
The only materials that can sustain the fission reaction are U-233, U-235,
and Pu-239. U-235 occurs in nature, but the other two fuels must be produced
artificially. Because the light commercial water reactors now in use require
a U-235 content of 2 to 3 percent, the 0. 7 percent U-235 content of natural
uranium must be enriched or concentrated.
Opinions on the future adequacy of the nuclear fuel resources of the United
22 37 46 11 50 51
States are many and varied. ' ' ' ' ' The nuclear reserves are esti-
mated on the basis of cost of recovery at the time of the estimate. Several
estimates ' ' ' ' have been made in the past, but the most recent
4-41
-------
O)
(O
O)
I
0)
u
a>
O
co
CO
co
CO
T3
0)
c
CD
a>
I
CO
CD
o
co
3
O)
4-42
-------
estimates by the Atomic Energy Commission place the reserves at 148, 000
53
tons of U0O0 at a cost of $8 or less per pound.
o o
4.2.6 Other Energy Sources
Although it is expected that the United States will continue to derive the
major portion of its energy from fossil fuels, nuclear energy, and hydro-
electric power, there are several other energy sources worth mentioning
because they produce no SO2 emissions.
Solar energy is a continuous and inexhaustible source of power. The
total amount of power that the earth receives as radiation from the sun is ap-
17 54
proximately 5x10 Btu per hour, which far exceeds the amount of power
that can be generated from fossil fuels. The application of solar power in the
United States has been very limited, due largely to technical and economic
problems of conversion. This trend is not expected to change in the near
55
future.
Reservoirs of geothermal heat underlie the volcanic regions of the earth.
The heat can be withdrawn and used either in the form of hot water or steam
under pressure. In the United States, the Pacific Gas and Electric Company
has had geothermal plants in operation since 1959 and they will soon build a
55-megawatt unit. The availability of geothermal heat in the United States
is limited to the western part.
Heat-reclaim systems utilize the excess heat generated in one area to
heat another area which is deficient in heat. This type of system has been
utilized in some large buildings for several years. A recent announcement
says that school buildings will be heated by the excess heat generated by the
4-43
-------
1300 students (450 Btu per hour each) and by lighting, cooking, and other inci-
57
dental interior sources. The absence of additional fuel combustion for heat-
ing purposes results in a net reduction on emissions of sulfur dioxide from this
source.
Fuel cells are electrochemical devices that produce electricity through
direct conversion of chemical energy. Fuel cells differ from batteries in two
major respects: they operate continuously as long as fuel and oxidizer are
supplied from an external source, and the electrolyte remains chemically un-
changed, that is, it need not be recharged.
The application of fuel cells has to date been limited to space research
and military uses because of the high initial cost. Providing energy to trans-
portation vehicles is a possible future application. Widespread application
will, however, depend on technological advances sufficient to reduce initial
cost and permit the use of low-cost fuels. Some experts feel that sufficient
information is already available to design a large-scale power plant using a
p- o
high-temperature cell with coal as a fuel.
Although heat produced during the incineration of refuse is usually
wasted, it could be used to produce steam, which would have many applications.
The heating value of mixed refuse today averages about 4500 to 5000 Btu per
pound. This value can be expected to increase because the trend is toward
less garbage and more paper and plastics. The sulfur content of refuse is
approximately 0.1 percent, therefore, the emission of sulfur dioxide from
/? f\
refuse incineration is of minor importance.
4-44
-------
4. 3 ENERGY SOURCE SUBSTITUTION
4.3.1 Introduction
Substitution of energy sources with little or no potential sulfur oxide
emissions for high-sulfur sources is one of the best methods presently avail-
able for reducing sulfur oxide emissions. Thus, conversion to nuclear fuel or
hydropower for electrical generation, or substituting fuels low in sulfur such
as gas, or low-sulfur coal or oil for high-sulfur fuels can greatly reduce sul-
fur oxide emissions. Reduction of particulate emissions is another benefit to
be derived from using some low-sulfur fuels. Simultaneous reduction of two
pollutants (sulfur oxides and particulates) is a very desirable and important
feature of fuel substitution.
The major arguments against this means of control are that adequate
quantities of low-sulfur fuel are not available at an economical price, changing
the fuel-use patterns would disrupt the fuel market, and the transportation,
social, and economic balance of a fuel producing area. A drastic change in
fuel-use patterns could result in a shortage of low-sulfur fuels.
The fuel and transportation price structure in the United States is very
complex and there are many factors involved in determining the ultimate price
of a fuel. Fuel rates vary widely, depending on factors such as geographical
location, user category, and quantity required.
Costs, in 1967, of fossil fuels in various parts of the country are pre-
sented in Tables 4-13, 4-14, and 4-15. These are prices of fuels delivered
4-45
-------
Table 4-13. INDUSTRIAL CONSUMER PRICES OF COAL - 1967
(cents/106 Btu)
Destination
Hartford, Conn.
Boston, Mass.
Providence -Pawtucket -Warwick, R.I. - Mass.
Buffalo, N.Y.
New York, N.Y.
Syracuse, N.Y.
AUentown-Bethlehem-Easton, Pa. - N.J.
Philadelphia, Ra.
Pittsburgh, Pa.
Wilmington, Del. - N.J. - Md.
Washington, D.C. - Md. - Va.
Jacksonville, Fla.
Miami, Fla.
Atlanta, Ga.
Baltimore, Md.
Norfolk-Portsmouth, Va.
Charleston, W. Va.
Huntington, W. Va.
Chicago, ni.
Gary-Hammond - E. Chicago, Ind.
Indianapolis, Ind.
Detroit, Mich.
Flint, Mich.
Akron, Ohio
Cincinnati, Ohio-Ky. - fad.
Cleveland, Ohio
SteubenvlUe-Wierton, Ohio-W. Va.
Toledo, Ohio - Mich.
Milwaukee, Wise.
<0.7
45-48
48-49
45-48
41-43
40-42
--
41-43
41-43
39-41
41-43
38-47
42-45
47-50
41-44
40-43
37-39
30-31
32-33
40-43
40-43
38-40
38-41
39-42
38-40
33-36
38-40
38-40
38-38
42-45
Sulfur ranges, weight %
0.8-0.9 1.8-2.0
41-49 35-43
44-50 36-45
41-49 36-45
34-49 30-36
38-46 34-41
39-47 32-30
37-43 32-40
37-43 32-38
34-40 27-39
37-45 32-39
34-41 32-39
37-43
41-49
36-39
35-42 31-38
33-39
24-25
27-27
34-41
34-41
32-38
32-39
33-40
31-38
27-33 37-45
31-38
31-38
31-35
36-44
2.9 - 3.7
a
-
-
-
-
-
-
-
-
-
-
39-41
44-47
32-34
-
-
-
-
27-34
31-32
26-29
30-35
32-37
-
28-30
26-29
26-29
27-31
33-38
sh (-) indicates data on coal prices not available.
4-46
-------
Table 4-13 (continued). INDUSTRIAL CONSUMER PRICES OF COAL - 1967
(cents/106 Btu)
Destination
Birmingham, Ala.
Louisville, Ky. - Ind.
Chattanooga, Tenn. - Ga.
Memphis, Tenn. - Ark.
Davenport - Rock Island - Moline
Iowa - 111.
Kansas City, Mo. - Kan.
Minneapolis - St. Paul, Minn.
St. Louis, Mo. - 111.
Omaha, Nebr. - Iowa
Oklahoma City, Okla.
Denver, Colo.
Salt Lake City, Utah
Los Angeles-Long Beach, Calif.
San Francisco-Oakland, Calif.
Portland, Ore. - Wash.
Seattle, Wash.
<0.7
40-41
35-37
38-39
41-44
42-68
48-51
42-63
40-43
42-63
-
30-60
40-69
55-74
57-74
52-74
53-74
Sulfur ranges, weight %
0.8-0.9 1.8-2.0
34-40
29-33
.33-38
36-43
37-45
42-51
42-51
34-41
42-51
46-46
-
38-72
55-77
55-77
51-77
52-77
2.9 - 3.7
32-34
21-22
31-33
28-28
32-37
37-43
33-39
25-30
38-46
-
-
-
-
-
-
-
(-) Indicates data on coal prices not available.
4-47
-------
Table 4-14. INDUSTRIAL CONSUMER PRICES OF FUEL OILS - 1967
(cents/106 Btu)
SMSA
Standard Metropolitan
Statistical Area
Hartford, Conn.
Boston, Mass
Providence-Pawtucket Warwick,
R.I. - Mass.
Buffalo, N.Y.
New York, N.Y.
Syracuse
Allentown-Bethlehem-Easton,
Pa. -N.J.
Philadelphia, Pa.
Fuel oil category
No. 5 No. 5
No. 1 No. 2 No. 4 No S 1% S
guar guar
a
95 84 58 52
95 84 55 52
87 -- — 59
94 83 53 45
—
—
93 82 58 53
No. 6
No S
guar
43
37
38
50
37
—
45
37
No. 6
1% S
guar
—
--
—
54
48
—
56
49
Pittsburgh, Pa.
Wilmington, Del. - N.J. - Md.
Washington, D.C. - Md. - Va.
Jacksonville, Fla.
Miami, Fla.
Atlanta, Ga.
Baltimore, Md.
Norfolk-Portsmouth, Va.
Charleston, W. Va.
Huntington, W. Va. - Ashland, Ky.
Chicago, 111.
Gary-E. Chicago-Hammond, Ind.
Indianapolis, Ind.
Detroit, Mich.
Flint, Mich.
Akron, Ohio
Cincinnati, Ohio - Ky. - Ind.
Cleveland, Ohio
Steubenville, Wierton, Ohio-W. Va.
94
92
103
90
93
94
83
81
92
80
82
83
86
85
85
101
101
72
76
77
90
90
56
54
50
46
59 63
58 60
27
37
37
37
37
49
53
58
51
53
55
54
4-48
-------
Table 4-14 (continued). INDUSTRIAL CONSUMER PRICES OF FUEL OILS - 1967
(cents/106 Btu)
SMSA
Standard Metropolitan
Statistical Area
Toledo, Ohio-Mich.
Milwaukee, Wise.
Birmingham, Ala.
Louisville, Ky. - Ind.
Chattanooga, Term. - Ga.
Memphis, Tenn. - Ark.
Davenport-Rock Island-Moline,
Iowa - 111.
Kansas City, Mo. - Kan.
Minneapolis -St. Paul, Minn.
St. Louis, Mo. - 111.
Omaha, Nebr. - Iowa
New Orleans, La.
Oklahoma City, Okla.
El Paso, Texas
Houston, Texas
Phoenix, Ariz.
Denver, Colo.
Salt Lake City, Utah
Los Angeles-Long Beach, Calif.
San Francisco-Oakland, Calif.
Portland, Ore. - Wash.
Seattle-Everett, Wash.
Honolulu, Hawaii
Fuel oil category
No. 5 No. 5 No. 6 No. 6
No. 1 No. 2 No. 4 No S 1% S No S 1% S
guar guar guar guar
101 90 -- 61 -- 56
88 80
90 80
..
87 76
72 — 40 -- 37
—
87 76 — — — 34
89 80 -- 63 -- 56
85 74 -- -- -- 44 45
87 78
88 77 — 45 — 37
84 73 — — — 34
..
34
--
..
42
75 67 — 38 — 27
..
53 — 45
54 — 45
44
Dash (-) indicates data on oil'prices not available.
4-49
-------
Table 4-15. INDUSTRIAL CONSUMER PRICES OF NATURAL GAS - 1967'
(cents/106 Btu)
Standard Metropolitan
Statistical Area
Hartford, Conn.
Boston, Mass.
Providence-Pawtucket
Buffalo, N.Y.
New York, N.Y.
Syracuse, N.Y.
Allentown, Pa.
Philadelphia, Pa.
Pittsburgh, Pa.
Wilmington, Del.
Washington, D.C.
Jacksonville, Fla.
Miami, Fla.
Atlanta, Ga.
Baltimore, Md.
Norfolk, Va.
Charleston, W. Va.
Huntington, W. Va.
Chicago, 111.
Gary, Ind.
Indianapolis, Ind.
Detroit, Mich.
Flint, Mich.
Akron, Ohio
Cincinnati, Ohio
Cleveland, Ohio
Continuous
143
175
114
97
130
102
88
100
52
76
90
90
103
60
83
79
65
65
56
43
60
55
57
54
55
54
Natural gas
Q
Interruptible
54
36
-
-
44
68
48
33
-
37
60
40
41
30
50
45
42
43
28
29
40
43
41
-
42
-
4-50
-------
Table 4-15 (Continued). INDUSTRIAL CONSUMER PRICES OF NATURAL
GAS - 1967
a
(cents/10 Btu)
Standard Metropolitan
Statistical Area
Steubenville, Ohio
Toledo, Ohio
Milwaukee, Wise.
Birmingham, Ala.
Louisville, Ky.
Chattanooga, Tenn.
Memphis, Tenn.
Davenport, 111.
Kansas City, Kansas
Minneapolis, Minn.
St. Louis, Mo.
Omaha, Nebr.
New Orleans, La.
Oklahoma City, Okla.
El Paso, Texas
Houston, Texas
Phoenix, Ariz.
Denver, Colo.
Salt Lake City, Utah
Los Angeles, Calif.
San Francisco, Calif.
Natural
Continuous
49
55
87
35
60
64
33
54
-
75
55
48
23
18
44
25
49
-
37
54
55
gas
Q
Interruptible
-
-
49
31
46
37
23
26
24
37
33
28
-
15
-
-
-
24
26
32
38
4-51
-------
Table 4-15 (Continued). INDUSTRIAL CONSUMER PRICES OF NATURAL
GAS - 1967a
r*
(cents/10 Btu)
Standard Metropolit
Statistical Area
Portland, Ore.
Seattle, Wash.
Honolulu, Hawaii
:an Natural gas
Continuous
62
100
210
£>
Interruptible
36
35
-
a
Prices are estimated from one of the following:
A.G. A. Rate Service, Vols. I and II. American Gas Association, Inc.,
New York, March, 1968.
Brown's Directory of North American Gas Companies, 81st edition,
Moore Publishing Co., Duluth, Minnesota, 1967.
*A guaranteed supply 100 percent of the time. Prices represent an estimated rate
based on a descending scale rate for higher volume usage.
i
'Gas supplied during times of off-peak demand. Prices and schedules of
supply are sometimes negotiated; at other times the rates are already
established. Practice is dependent on the local gas utility.
4-52
-------
to Industrial consumers with heat input requirements greater than 5 billion Btu
per hour. These consumers receive fuel in bulk quantity, their fuel costs
reflecting bulk quantity delivery. Fuel costs for public utility steam-genera-
ting plants are contracted separately at each installation; these costs have been
fii
well documented and are, therefore, not included in this tabulation.
The prices in Table 4-13 are for coal from the nearest producing dis-
trict (f.o.b. mine price). In addition, prices of District 7 and 8 coals for
each Standard Metropolitan Statistical Area (SMSA) are determined. Coals
from Districts 7 and 8 are low-sulfur fuels, in the 0 to 0.7 percent and 0.8
to 1.4 percent sulfur range. Table 4-16 shows the producing districts and
mine prices.
4.3.2 Methodology and Economics of Fuel Substitution^
A number of alternatives are available for switching from high-sulfur
fuel to a low-sulfur fuel. Typical examples include switching from:
1. High-sulfur coal to low-sulfur coal.
2. High-sulfur coal to low-sulfur residual oil.
3. High-sulfur residual oil to low-sulfur residual oil.
4. Sulfur-bearing fuel to gas.
All the logical possibilities of fuel substitution to reduce sulfur emis-
sions are shown in Figure 4-12. Electric heating, although considered a
substitute energy in some circumstances, is generally only a relocation of
the sulfur oxide emissions and is not considered here. In some cases,
4-53
-------
Table 4-16. SULFUR CONTENTS AND PRICES OF COALS IN 1966
BY PRODUCING DISTRICTS, 14> 62~64
1.
2.
3 &
4.
5.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21
22.
23.
District No.
and name
Eastern Pennsylvania
Western Pennsylvania
6. West Virginia
Ohio
Michigan
Southern No. 1
(South W. Va. and
Western Va.)
Southern No. 2
(Eastern Kentucky)
Western Kentucky
Illinois
Indiana
Iowa
Southeastern (Alabama)
Arkansas -Oklahoma
Southwestern (Mo. ,
Kansas, Texas)
Northern Colorado
Southern Colorado
New Mexico (also
Arizona, Calif.)
Wyoming
Utah
North -South Dakota
Montana
Washington (also
Oregon)
Low
1.0
1.1
0.6
1.6
-
0.5
0.5
2.0
1.1
1.1
4.2
0.7
NA
3.0
0.3
0.5
NA
0.6
0.6
0.7
0.6
NA
Sulfur (dry basis),
weight %
Average
1.8
1.8
2.4
3.5
-
0.7
1.1
2.9
2.7
3.3
4.7
1.1
NA
3.9
0.5
0.7
1.0
0.9
0.7
0.8
0.7
NA
High
3.6
4.1
3.8
5.0
-
1.1
4.3
4.0
4.1
5.3
5.7
1.7
NA
6.0
0.7
0.9
NA
1.0
0.8
1.0
0.7
NA
Average coa.L price per ton
F.O.B. mine, $
4.33
5.97
4.65 & 4.28
3.79
-
6.14
4.44
3.45
3.85
3.92
3.69
6.76
7.30
4.29
4.20
5.35
2.52
3.23
5.77
1.98a
3.08
7.57
aLignite, 7,000 Btu/lb as received.
NA = not available.
4-54
-------
HIGH-SULFUR
COAL
HIGH-SULFUR
RESIDUAL OIL
LOW-SULFUR COAL
LOW-SULFUR RESIDUAL
DISTILLATE OIL
NATURAL GAS
LOW-SULFUR
RESIDUAL OIL
DISTILLATE OIL
Figure 4-12. Fuel substitution schemes for reduction of sulfur oxide emissions.
however, the electricity may be produced by a noncombustion process, thus
eliminating emissions.
A study of the economics of energy source substitution includes the in-
cremental fuel costs and capital investment requirements for boiler modifi-
cation to accept a fuel substitute. While not considered in the following cost
analysis because of their variability, plant down-time and loss of capacity
during boiler modification may be added cost items.
Capital investment is the cost of modifying a boiler unit to facilitate
the combustion of another fuel. These costs include replacement of burners,
4-55
331-543 O - 69 - 8
-------
fuel handling changes, and combustion chamber changes. Capital charges in
the following example were assumed to be 8 percent per year with straight-
line depreciation over a 25-year period. A longer depreciation period would,
of course, decrease the annual charges. Any credits associated with scrap-
ping of storage and handling equipment for the discontinued fuel are not in-
cluded in these evaluations, but could at times be valuable. Annualized costs
are calculated and determined on an equivalent energy input basis. These
annualized costs include capital charges, operation, maintenance, and fuel
costs.
The following procedure may be used to determine fuel substitution
costs in a specific area.
1. Select a source of sulfur dioxide emission, an industrial
boiler of given output rating in Ibs steam per hour. (Example: a
boiler with a capacity of 100,000 pounds of steam per hour, burn-
ing 3. 3-percent sulfur coal).
2. Select the possible fuel alternatives and from given boiler ef-
ficiencies determine energy input requirements in Btu per hour.
(1000 pounds of steam requires approximately one million Btu of
heat output.)
3. Obtain fuel costs (by sulfur content) for the area of interest.
Compute the required fuel cost per year. A sample calculation
4-56
-------
for Chicago, 111. , is shown in Table 4-17. Fuel costs and sulfur
contents are taken from Tables 4-13, 4-14, and 4-15.
4. For the corresponding fuel alternatives, determine the capital
investments for boiler modifications and operation costs. The
boiler modification cost may be obtained from the manufacturers
or from local fuel supplier.
5. Annualize fuel costs, capital charges, and operating and
maintenance costs.
6. For the fuels selected, determine the potential SO emissions
£
for the required equal energy output from the heat and sultur con-
tent of the fuels.
7. Using the original fuel (3.3-percent-sulfur coal) as a base line
for evaluating effectiveness, calculate the emissions for alterna-
tive fuels as illustrated in Table 4-18.
In this example, an SO reduction using one alternative, a switch to in-
L*
terruptible gas service, was accomplished for very little additional cost. Costs
will vary widely from area to area, and from one combustion unit to another.
4.3.3 Fuel Conversion Problems
The National Petroleum Council conducted a study of the extent to which
equipment designed to burn various types of fossil fuels could be converted from
65
one type of fuel to another. The Council limited the scope of the study to
physical facilities only, without regard to economics or the availability of
4-57
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4-59
-------
alternate sources of fuel. Tables 4-19, 4-20, and 4-21 show the convertibility
of domestic, commercial, and industrial heating equipment.
The substitution of one type of fuel for another can be an expensive step
if the fuel burning equipment cannot be easily converted. In some cases,
furnaces are designed to burn solid, liquid, or gaseous fuels; however, most
are designed for only one type. Changing from high-sulfur to low-sulfur coal
may present problems with ash fusion in wet-bottom furnaces, and may affect
the fly ash collection efficiency of electrostatic precipitators.
Changing from a solid to a liquid fuel requires entirely different storage
and handling equipment; however, changing from a solid or liquid to a gaseous
fuel would not present any storage problems since gas is not stored in large
quantities. Eliminating the storage problems by switching to a gaseous fuel
would actually reduce overall fuel handling costs. Additional cost benefits
may also be realized when factors such as ash handling and elimination of fly
ash collectors are taken into account.
4-60
-------
Table 4-19. CONVERTIBILITY OF INDUSTRIAL HEATING EQUIPMENT
Designed to burn Can be
Type of equipment Coal Oil Gas Coal
Incinerators A No
X No
Boilers XX NA
X X NA
XX No
X NA
X Perhaps
X Perhaps
Process heating XX NA
X X NA
XX No
NA
Perhaps
X Perhaps
Heat treating XX No
X No
X No
converted
Oil
NAb
Yes
NA
Yes
NA
Yes
NA
Yes
NA
Yes
NA
Yes
NA
Yes
NA
NA
Yes
to burn
Gas
Yes
NA
Yes
NA
NA
Yes
Yes
NA
Yes
NA
NA
Yes
Yes
NA
NA
Yes
NA
Designates the fuel that the equipment was designed to burn.
Not applicable.
4-61
-------
Table 4-20. CONVERTIBILITY OF COMMERCIAL HEATING EQUIPMENT
Designed to burn Can be
Type of equipment Coal Oil Gas Coal
Unit heaters X* No
X No
Incinerators X No
X No
Portable unvented
heaters (salamanders) X NA
X No
X No
Water heaters X NA
X No
X No
Warm -air furnaces X NA
X No
X No
Boilers - steam or
hot water X NA
X No
X No
XX No
converted
Oil
NAb
No
NA
Yes
No
NA
No
Yes
NA
Perhaps
Yes
NA
Perhaps
Yes
NA
Perhaps
NA
to burn
Gas
Yes
NA
Yes
NA
No
No
NA
Yes
Yes
NA
Yes
Yes
NA
Yes
Yes
NA
NA
Designates the fuel that the equipment was designed to burn.
Not applicable.
4-62
-------
Table 4-21. CONVERTIBILITY OF DOMESTIC HEATING EQUIPMENT
Designed to burn
Type of equipment Coal Oil Gas
Incinerators A
X
Unvented space heaters X
X
Vented space heaters X
X
X
Recessed wall heaters X
X
Water heaters X
X
X
Warm -air furnaces X
X
X
Boilers-steam or
hot water X
X
X
Can
Coal
No
No
No
No
NA
No
No
No
No
NA
No
No
NA
No
No
NA
No
No
be converted
Oil
NAb
Perhaps
NA
No
Difficult
NA
No
NA
No
Probably
NA
NO
Yes
NA
No
Yes
NA
Perhaps
to burn
Gas
Yes
NA
No
NA
Difficult
No
NA
Perhaps
NA
Probably
Perhaps
NA
Yes
Yes
NA
Yes
Yes
Na
Designates the fuel that the equipment was designed to burn.
Not applicable.
4-63
-------
4.4 FUEL DESULFURIZATION
4.4.1 Introduction
Fuel desulfurization, whether partial or complete, offers another way of
reducing S09 emissions. The economic and technical feasibility of fuel desul-
^
furization, however, varies widely, but this aspect of SO control sjhould al-
u
ways be examined before developing an S00 control program for a specific area.
Lt
Desulfurization of fuels is not new. Research into ways of removing sul-
fur from coal, oil, and gas has been going on for many years, and actual com-
mercial desulfurization operations exist. These installations, however,
operate only to increase profit or marketability of the fuel. For example,
some pyrite sulfur is removed in normal coal preparation operations that are
performed to remove clay, shale, and rocks from the coal, and pyrite has
been reduced in metallurgical-grade coals for many years. Research efforts
to transform coal into liquids and gases involve removal of sulfur, but their
primary purpose is the upgrading of coal to more valuable products. In re-
fining crude oils, hydrogen treatment is widely practiced on the distillate oils
to meet certain sulfur specifications. Natural gas containing sulfur compounds
is desulfurized to increase its marketability and meet specifications.
The impetus given this work by the concern over air pollution is a new
aspect. In effect, air pollution regulations that set stringent sulfur levels have
created a new market, which has led to greatly increased efforts to develop
low-sulfur fuels.
Sulfur can be partially removed from coal by means of coal preparation
techniques now available. Much coal is currently being cleaned, to improve its
4-64
-------
marketability; however, relatively few coals are cleaned extensively. Capa-
bility for sulfur reduction varies widely according to the specific coal type.
Liquefaction and gasification of coal may be practiced on a limited scale
in 5 to 10 years. However, even then, because of economic considerations,
these methods will account for only a small portion of coal used.
Processes for producing residual fuel oil with a sulfur content of 1.0 per-
cent or less are in operation, and numerous additional installations employing
processes of this type are in the construction or planning stage.
4.4.2 Coal
4.4.2.1 Introduction - Sulfur exists in coal in three forms; pyrites (FeS2),
organic compounds, and sulfates. The total sulfur content of coal ranges from
negligible amounts to about 7 percent by weight.
Sulfates, usually present only in very small quantities, are not considered
a problem. Organic sulfur is bound molecularly into coal and cannot be re-
moved without chemically changing the nature of the fuel by liquefaction or
gasification. Pyritic sulfur present as particles is removable by physical
techniques except when intimately mixed in the coal. The degree of sulfur re-
moval depends on the types of sulfur present in the coal and on the amount of
each type present.
This discussion considers only bituminous coal because anthracite coal,
which is inherently low in sulfur (0. 7 percent average), makes up less than 4
percent of coal consumed annually and is steadily decreasing in use.
4.4.2.2 Pyrite Bemoval: Coal Preparation - Coal preparation or cleaning is
the mechanical removal of impurities from coal. The extent and type of
4-65
-------
cleaning depend on the nature of the coal and on its projected use. Coal for
steam generation must meet specifications different from those for coal for
metallurgical coke production.
Mechanical cleaning of coal is possible because of the differences in
physical properties between coal and its impurities. Specific gravity is the
property most often exploited, normally by a water-washing process. Table
4-22 lists the chief cleaning methods utilized in the coal industry.6b
A typical coal preparation operation is diagrammed in Figure 4-13.
Selective mining is the first step
in production of coal of a consistent
RUN-OF-MINE COAL
1
FINE
COAL
f
CRUSHER
1
SCREENS
desired quality. Mechanically mined
COARSE
COAL .coal contains considerably more rock,
shale, and fine coal particles than
COARSE .
REJECTS manually mined coal, and may require
additional cleaning. This cleaning
I
SPECIFIC GRAVITY TYPE
CLEANING SYSTEM
FLOAT COAL
SINK
I COAL
HIGH-PYRITE
REJECTS
LOWER-SULFUR
COAL PRODUCT
Figure 4-13. Coal preparation (simplified flow
chart).
removing the larger particles of heavy
pyrite. The Brookdale, Pa., plant of
the Bethlehem Steel Corporation for
some time has been reducing sulfur
content of coal from 3.4 percent to 1.0
percent at a total product yield of 85
percent. An existing, fairly sophisti-
cated, 500-ton-per-hour coal-prepara-
tion plant is diagrammed in Figure
4-66
-------
Table 4-22. EXISTING MECHANICAL METHODS OF CLEANING COAL
Physical
property
Method
Size
treated
% of cleaned coal
utilizing method
Crushability and
size
Specific gravity
Surface effect
Crushing and
screening
Jig
Heavy medium
Table
Pneumatic
Cyclone
Launder
Froth
flotation
6 in. and up
6 mesh - 3 in.
6 mesh - 8 in.
100 mesh - 1/4 in.
Up to 1/4 in.
1/8 in - 1-1/2 in.
4 mesh - 3 in.
Up to 30 mesh
Initial step in
most cleaning
operations
47.8
27.2
13.2
6.9
2.2
1.9
4-67
-------
4-14 in order to show the complexity of such an operation. Costs of this opera-
tion are detailed in Table 4-23.
In 1964, the Paul Weir Company reported on a study entitled "The Eco-
nomic Feasibility of Coal Desulfurization." Sulfur reduction data from that
study are summarized in Table 4-24. Total sulfur, organic sulfur, and
cleaned-coal sulfur percentages vary widely within the individual States and
coal beds. Because of a lack of data on type and levels of sulfur in coal beds,
on the washability of the pyritic sulfur, and on capability of available cleaning
methods for pyrite separation, the study did not produce definitive results. In
1965, the Public Health Service funded a study by the Bureau of Mines to de-
termine the washability of pyritic sulfur in the major sources of fuel coals. In
1966, to accelerate this study, a contract was let to Commercial Testing and
Engineering Company to determine washability of pyritic sulfur in selected
areas believed to have washable coals. In this same year, a study was funded
with the Illinois Geological Survey to determine the important chemical and
physical properties of all coal beds actively mined in Illinois.
Figure 4-15 shows organic, pyritic, and total sulfur levels of coal based
on the cumulative data obtained in these studies to date. The small sulfate
fraction of the sulfur is included in the organic portion. This figure shows the
technical feasibility of reducing pyrite sulfur by presently employed washing
(float and sink) techniques. The upper portion of the pyrite sulfur in Figure
4-15 may be removed if the coal is crushed to 3/8 inch and floated in a liquid
of specific gravity 1.60, but the lower portion of the pyrite is too intimately
mixed to be removed by this treatment. Of the mines sampled, about 20
4-68
-------
Table 4-23. COST DATA FOR 500-TON-FEE-HOUR
COAL PREPARATION OPERATION67
Greene County, Pennsylvania - Pittsburgh bed
o
Coal crushed to 1-1/2 in.
Coal washed by 1.60 specific gravity separating medium
Costs
Mining costs per ton $3.60
at 90-% yield 4.00
(10 % list in cleaning process)
Process costs (per ton of product)
Operating $0.415
Depreciation (20 year) 0.117
Mining 4.000
Total $4. 532 per ton
Cost per 106 Btu (at 13,400 Btu/lb) $ 0.169
Total cleaning cost 0. 932 per ton
Sulfur content, %
Raw coal sulfur, 2.66
Post-wash sulfur, 2.03
Organic sulfur, 0.95
aCrushing to 3/8 inch would increase operating costs and de-
crease yield; however, the post-wash sulfur level would be
lower.
4-69
-------
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4-70
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331-543 O - 69 - 9
-------
percent produced coal that was washable to 1 percent sulfur or less, and 45
percent produced coal that was washable to 2 percent sulfur or less by crushing
to 3/8 inch and floating in a liquid of specific gravity 1.60. These percentages
represent a total of about 13.5 million and 29.6 million tons of coal annually.
The economic aspects of coal cleaning, by the best available techniques,
were explored by the Paul Weir Company under its 1964 contract. Cost data
were computed on the basis of a hypothetical 1000-ton-per-hour plant. This
proposed plant, diagrammed in Figure 4-16, reduces the coal to a final maxi-
mum size of 3/8 inch. The dried product is about 78 percent of the input mine
coal; the other 22 percent, rejected at various process points, is considered
nonrecoverable. Estimated costs per ton for products of this plant are shown
6-° I 1 ' I i i ffl
in Table 4-25. Sulfur contents are not
5.0
I I I
DATA FROM 113 MINES, ANNUAL
PRODUCTION OF 127.5 MILLION
TONS OF COAL.
INTIMATELY
MIXED PYRITE
- - , oN ORGANIC SULFURfW
x"-° -^ "5^
given since this would depend on the
specific type of coal.
The economic feasibility study
points out many knowledge gaps, such
as insufficient data on sulfur distribu-
tion and characteristics in a given coal
seam, the washability of a given coal
seam, and the capabilities of present
cleaning operations.
20 40 60 80
NUMBER OF MINES SAMPLED, *
Figure 4-15. Maximum sulfur content versus percent of
mines sampled.68
4-72
-------
Table 4-25. ESTIMATED PRODUCT COST UTILIZING PROPOSED
1000-TON-PER-HOUR COAL PREPARATION PLANT67
Capital costs (20-yr retirement) $ 0.117 per ton product
Direct operating costs (2,400, 000 tons/ 0-370 per ton product
yr)a
Coal costs; at 78-% yield 3.141 per ton product
Total $ 3. 628 per ton product
Total cost per 106 Btu at 12, 000 Btu/lbb $ 0.151
Do not include taxes.
Final sulfur content will depend on type of raw coal.
4-73
-------
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4-74
-------
The current fuel research program being funded by the National Air
Pollution Control Administration is to determine:
1. Efficiency and applicability of available coal cleaning
methods for pyrite separation.
2. Available sources of high-sulfur coals capable of being
desulfurized.
3. Costs and technical limitations of proven technology for
converting the refuse from coal cleaning into useful products.
A logical way to decrease the cost of desulfurization is to find suitable
uses for high-pyrite refuse material. Both iron oxides and sulfur can currently
be recovered, but the cost of this recovery is too high. At present, fluidized-
bed roasting of pyrite and subsequent sulfuric acid manufacture are in the
advanced stages of technological development. Design of prototype pyrite-use
processes will be initiated early in 1970, depending on performance of the
prototype coal-cleaning plant and on the results of pyrite-use studies.
4.4.2.3 Pyrite Removal: Dry Processes - Dry processes for the removal of
pyrites from coal are attractive because they can use fine coal and they do not
require water. These processes include air classification and electrostatic
and magnetic separation, none of which has reached the commercial stage.
For each of these processes, coal must be pulverized below 200-mesh size to
liberate the finely disseminated pyrite particles for removal. The most ad-
vanced of these processes is the two-stage air classification method used by
Bituminous Coal Research, Inc. (BCR).
4-75
-------
BCR, in cooperation with a group of interested utilities, has installed a
pilot plant at the Seward, Pennsylvania, power station of the Pennsylvania
Electric Company to study the process. The 3- to 4-ton-per-hour plant will
supply pulverized coal to one burner of a boiler. Coarse pyrite will be re-
moved by the tramp iron chute on the pulverizer; 20 to 30 percent of the pyrite
can be removed in this manner. Fine pyrite will be removed by an efficient
air classifier. Rejects from both the tramp iron chute and the classifier will
be further cleaned on a concentrating table. The table will produce clean
pyrite, mixed refuse, and clean coal. The clean coal will be returned to the
pulverizer, the refuse discarded, and the pyrite sold. Pyrite reduction in the
pulverized coal delivered to the consumer is expected to be 60 to 70 percent
based on the raw coal. Initially, central Pennsylvania coals, which are low in
organic sulfur and high in pyrite, will be used. Losses in the process are
expected to be between 10 and 15 percent since rejects are reprocessed. No
by-product credit is assumed.
Magnetic separation of pyrite from coal is being studied at the U. S.
Bureau of Mines and at West Virginia University. The work at the Bureau is
aimed at enhancing the weak magnetism of pyrite by means of microwave radia-
tion. West Virginia University is examining the use of superconducting magnets
to provide higher field intensities for pyrite separation. Both processes are
in the basic research stage, as is electrostatic separation of pyrite from coal,
which is being studied by the U.S. Bureau of Mines.
4.4.2.4 Liquefaction - Liquefaction is the conversion of coal into products of
which the major useful fraction is liquid. Some gaseous products always
4-76
-------
result, and the major product (up to 50 to 60 percent of yield) is relatively
high-sulfur char. Almost all liquefaction processes involve hydrogenation
and aim for maximum gasoline production; therefore very little heavy fuel is
produced. An exception is the solvent refining (Pemco) process, the end-
product of which is a low-ash, low-sulfur liquid or solid fuel.
Liquefaction is not a desulfurization process per se, because the sulfur
is not simply removed, but appears in the various end-products. Of major
interest in air pollution control is production of a low-sulfur fuel, either as a
primary product of the process or by desulfurization of the char.
Coal liquefaction has been a technical reality for decades. The economics
of this process in this country, however, have been unfavorable up to now.
Coal desulfurization by liquefaction is a possible long-term approach to pro-
69
viding low-sulfur fuels.
Four major liquefaction processes are described in the Appendix 1.
4.4.2.5 Gasification - Gasification is the process in which coal reacts with
oxygen, steam, hydrogen, carbon dioxide, or a mixture of these, to produce a
gaseous product suitable for pipeline transmission and subsequent use as a
fuel. Gasification is an effective method of desulfurization because sulfur is
readily removed and recovered as HgS. Coal gasification is not a new develop-
ment. Carbonization (Pyrolysis) of coal to coke yields a gas that was used as
early as 1792 for street lighting in cities throughout the world. This gas is
low in heat content because it contains only 15 to 30 percent of the input coal's
Btu content. In hydrogasification, the methane is directly produced from coal
and contains 57 to 71 percent of the coal's Btu content. The most promising
4-77
-------
approach is gasification followed by methane shift reaction, which produces a
gas having as much as 75 percent of the Btu content of the input coal.
The four major processes for obtaining from coal a gas with heat contents
of 900 to 1000 Btu per cubic foot use variations of gasification-methanation.
These processes are hydrogasification, CO acceptor, molten salt, and two-
^
stage superpressure. Much development is necessary if any of these four
processes is to become commercially feasible in the next decade. These
methods are also described in the Appendix 1.
The cost of obtaining pipeline-quality gas by these coal gasification
/>
techniques is estimated at from $.44 to $.54 per 10 Btu, which is within
the cost range of higher-cost natural gas. The future of gasification appears
to lie in providing not a replacement for natural gas, but a supplement, as the
cost of finding and using natural gas reserves increases. As a long-range,
supplementary source of low-sulfur fuel, this method has promise for the
future. Pipeline transmission of gas is generally more economical than
transmitting electricity, and the production of this sulfur-free fuel will allow
generation of electricity closer to the highly populated areas.
4.4.3 Oil
4.4.3.1 Introduction - All crude oil contains some sulfur. Refining processes
- including distillation and cracking, which separate the crude oil into various
petroleum products - cause the sulfur to become more concentrated in the
heavier fractions, which have higher boiling temperatures. It is the heaviest
fraction, petroleum residuum, from which residual fuel oils (primarily
Grade 6) are obtained.
4-78
-------
Production of residual fuel oil with a sulfur content of 1. 0 percent or
less is currently receiving much attention. Low-sulfur residual fuel oil can
be obtained by direct desulfurization of the high-sulfur residual oil, or in-
directly by blending heavy oil fractions with low-sulfur distillate oils. This
latter scheme is currently being used to produce most of the imported residual
fuel oil with a sulfur content of 1. 0 percent or less.
Direct desulfurization by hydrogen treatment of the lighter petroleum
products such as distillate fuel oils has been practiced for many years as part
of the normal refining process. The application of these methods directly to
heavy fuel oils is, however, relatively new. The petroleum industry has further
developed and applied these desulfurization schemes successfully as evidenced
by some of the new processes being installed , as shown in Table 4-26. A
30, 000-barrel-per-day desulfurizing unit has been in operation at Shell Oil
Company's refinery at Curacao, Netherlands Antilles, since late 1967. An
additional unit costing $35. 5 million is planned by Shell for Punta Cardon,
Venezuela. Standard Oil of New Jersey is planning to invest about $200 million
in desulfurizing processes at refineries in western Venezuela and in Aruba,
Netherlands Antilles. The installation at Amuay, Venezuela, will consist of
three desulfurization units with a total capacity of 159, 000 barrels per day of
low-sulfur fuel oils.
Many of these schemes upgrade the feed stream to low-sulfur distillate
products. These products may be marketed, or blended with heavy oil fractions
to yield a fuel oil meeting Grade 6 fuel specifications with a sulfur content of
1.0 percent or less. Under certain operating conditions, however, some of
these processes will directly yield a low-sulfur residual fuel oil.
4-79
-------
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Cost estimates for direct desulfurization of residual fuel oil may be
made if the sulfur and metallic content of the crude oil, the cost of hydrogen,
the plant size, desired sulfur level, and related factors are known. Costs of
reducing sulfur content of residual oil to 1. 0 percent range from $. 25 to $. 75
71
per barrel. Data obtained by the Bechtel Corporation for a typical
ft
Caribbean crude oil show an additional cost of $. 60 per barrel ($. 10 per 10
Btu) for desulfurizing residual fuel oil from 2. 6 to about 1. 0 percent, when a
72 73
5-year pay-out was assumed. ' Another recent cost estimate by
Arthur G. McKee and Company was based on domestic crude oils, and showed
a breakeven or slightly profitable operation for producing residual fuel oil
with a sulfur content of 0.5 percent.
The price of a barrel of residual fuel oil with a sulfur content of 1. 0
percent or less, however, cannot be so easily estimated since this price
depends on demand, investment payouts, desired profits, import duties, cost
of crude oil, value of other refinery products, and quantity purchased.
4.4.3.2 Major Processes for Desulfurization - Several schemes are available
for desulfurizing petroleum products. The particular scheme to be used in a
given situation will depend on such things as desired sulfur content, type of
feed stream and its metals content, and the desired product.
Hydrodesulfurization - Direct residual oil desulfurization processes use
a form of hydrocracking for sulfur removal (Section 5.2.2.3). Hydrocracking
processes were originally developed to reduce the yield of residual fuel oil;
however, by selecting the proper catalyst and operating conditions, residual
fuel oil yields can be maintained and sulfur removal achieved. In deep
4-82
-------
desulfurization (to below 0.5 percent), however, the yield of residual fuel oil
decreases, since the severe operating conditions that must be used tend to
upgrade part of the feed to lighter petroleum products.
The three most commercially advanced hydrocracking processes are the
H-Oil, ISOMAX, and Gulf-HDS processes. Developed by Hydrocarbon Research,
Inc., and Cities Service Oil Company, the H-Oil process has been in commer-
cial operation since late 1962 with a 2500-barrel-per-day installation at Lake
Charles, Louisiana, which converts residual oil to lighter products. This
process uses an ebullating catalyst system in which the reactor feed (gas and
liquid) passes upward through a bed of catalyst maintained in continuous random
motion by the upflow. A flow chart for this desulfurization process is shown in
Figure 4-17.
The ISOMAX hydrocracking process, developed by Chevron Research
Company and Universal Oil Products, Inc., has long been used for distillate-
gas oil conversion. Upgrading of low-value residual fractions and desulfur-
izing of fuel oil are relatively new uses for this process. By controlling the
severity of hydrocracking, a heavy, low-sulfur fuel-oil blend stock, as well
as minimal yields of synthetic naphtha and saleable gas, are produced. Mini-
mizing the cracking of low-boiling products saves hydrogen and produces a max-
imum yield of finished fuel oil. Hydrocarbon flows through the reactor once, and
hydrogen is recycled from the high-pressure separator. A product stripper is
used to remove ^S. This process is used in a new installation in Chiba, Japan.
The Gulf-HDS process, developed by Gulf Research and Development
Company, is also a fixed-catalyst-bed process used to upgrade or desulfurize
4-83
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4-84
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petroleum residues by catalytic hydrogenation. It produces refined heavy fuel
oil and high-quality catalytic-cracker charge stock.
Hydrogen treating - Hydrogen treating is an important adjunct to all
direct desulfurization operations and is essentially a mild form of hydro-
cracking. Hydrogen treating is used for hydrogen saturation of olefins and/or
aromatics and for removal of sulfur, nitrogen, and other impurities (Section
5.2.2.6). It is widely used in reformer and catalytic cracker feedstock pre-
paration, product upgrading, yield improvement, and sulfur recovery.
The general process flow is shown in Figure 4-18. Feedstock is mixed
with hydrogen, heated, and charged to a fixed-bed reactor containing a nickel
or cobalt-molybdate-alumina catalyst. The reactor effluent is cooled, separated
from recycle gas, and stripped of H0S and light ends. Operating costs are
Lt
74
$.10 to $. 20 per barrel. Capacity for hydrogen treating in the United States
is currently over 3.5 million barrels per day.
Distillation - For a relatively small sulfur reduction (2.6 to 2.0 percent),
distillation followed by hydrodesulfurization of the overhead stream may be
used. Usually, vacuum distillation is used, but in some cases atmospheric
distillation may be satisfactory. The advantage of distillation is that it is
relatively inexpensive and makes use of well known technology and existing
equipment. Vacuum distillation of the heavy fraction from an atmospheric dis-
tillation unit will increase the recovery of the lighter fractions suitable for
hydrodesulfurization.
Delayed Coking - Coking is a thermal process for decomposing, re-
arranging, or combining hydrocarbon molecules by applying heat without
4-85
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4-86
-------
catalysts. Delayed coking is a semicontinuous process for the conversion of
heavy low-grade oils such as reduced crude and tars into solid coke and lighter
products that can be used as catalytic cracking feedstock. This process is
important from a fuel desulfurization standpoint since the sulfur is concen-
trated in the petroleum coke. Disposal of this high-sulfur coke is a problem
and may be an economic debit.
Figure 4-19 is a flow chart of the delayed-coking process. Heated
charge is introduced into the fractionating tower. Heavy liquids from the tower
bottom are pumped through a heater to a coke drum. Vapor from the drum is
returned to the fractionating tower for separation into coke gas, gasoline, and
gas oil. When a coke drum is full, it is removed from the line and dumped
while the process flow is diverted to a clean drum.
In 1964, the capacity of delayed-coking processes in the United States
and Canada was about 700, 000 barrels per day. For a 15, 000-barrel-per-day
74
plant, operating costs in 1962 were estimated at $. 30 per barrel.
Solvent De-Asphalting - Solvent de-asphalting is a physical process in
which a solvent is used to separate the various constituents of a petroleum
charge. In this process, sulfur and heavy metals are removed, color is im-
proved, and carbon residue and the tendency toward coke formation are re-
duced. Solvent de-asphalting is an alternate method for preparing feedstock
for catalytic cracking. It competes with vacuum distillation, coking, and
visbreaking.
The process flow is shown in Figure 4-20. The solvent, liquid propane,
is contacted counter-currently with descending heavy oil in the de-asphalting
4-87
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4-89
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(contacting) tower. The normal charge stock is vacuum-reduced crude of
various boiling ranges. The de-asphalted oil is separated from propane by
evaporation and steam stripping. The heavy asphalt-propane mixture is heated,
flashed, and stripped. Propane is recovered and compressed for re-use. Re-
sidual fuel oil with a sulfur content of 1 percent or less can be achieved by this
technique if the de-asphalted gas oil is hydrocracked and blended with high-
sulfur, bottom fractions. The process is licensed by M. W. Kellogg Company,
among others. Direct operating cost at a 5000-barrel-per-day plant is about
$.25 per barrel.74
4.4.3.3 Cost Studies - Cost estimates of fuel oil desulfurization were prepared
72
by Bechtel Corporation in 1964 for California crude and in 1967 for
73
Venezuelan crude, and by Arthur G. McKee and Company in early 1968, for
70
crudes processed in refineries in the United States. The 1964 study, now
largely outdated, is not discussed here.
In all processes involving hydrogen, a major cost item is the hydrogen.
Low-cost sources and maximum use of hydrogen are of utmost economic im-
portance. A cost estimate published in 1966 for a 50, 000-barrel-per-day re-
finery processing Venezuelan crude and desulfurizing from 2. 0 to 0. 5 percent
75
gave an operating cost of $. 284 per barrel. This was increased to $. 424
per barrel when a 5-year payout after taxes was used.
1967 Bechtel Study - The specifications for the selected base case
Caribbean refinery using Venezuelan crudes are given in Table 4-27.
A major assumption of the 1967 Bechtel report is that the product stream
obtained from the refinery is fixed. Although in actual practice a refinery
turns out those products that have maximum economic value, the Bechtel study,
4-90
-------
Table 4-27. PROCESS SIZES AND YIELDS FOR 1967 BECHTEL STUDY
.73
Process
Size, barrels per stream day
Crude distillation
Vacuum distillation
Catalytic cracking
Visbreaking
Alkylation
Lube plant
300,000 @ 23.6° API
48,000
23,000
72,000
2,000
2,000
Product yield
Volume, % of crude
Regular gasoline
Premium gasoline
JP-4
Jet A-l
Kerosine
No. 2 distillate fuel oil
Automotive diesel
Marine diesel
No. 6 fuel oil
Lube
Naphtha
Fuel and Loss
8.1
4.1
1.5
1.5
4.2
11.3
2.6
3.3
57.4
0.7
3.0
2.3
100.0
4-91
-------
as one of its constraints, maintained a fixed volume of lighter products. The
value of low-sulfur residual fuel oil will depend on the quantity and value of
other products produced. These points should be noted in any consideration of
the results of this study. Table 4-28 is a summary of residual-fuel-oil quality
and cost data for different processes at a typical Caribbean refinery.
Certain comments are in order regarding product and process capabili-
ties. When the sulfur content is reduced to about 1.0 percent, the viscosity of
the oil is reduced to the lowest limit of ASTM specifications for No. 6 fuel oil
(45 SSF at 122°F). When the sulfur content is reduced to 0.5 percent, the
viscosity reaches the lowest limit allowed by import regulations (145 SSU at
100°F). Residual fuel oils of relatively low sulfur content, down to about 0.87
percent, may be attained without charging the oil directly to a desulfurizer or
having coke as a product for disposal. Fuels with a sulfur content of about 0.5
percent may be produced by direct residual desulfurization or by delayed
coking and solvent de-asphalting followed by blending. Because of the high
metal content of this crude oil, process capabilities and costs are less reliable
for desulfurization below 0. 87 percent.
The volumetric value of fuel oil decreases with desulfurization. This is
illustrated in Figure 4-21, where degree of desulfurization is related to costs,
calculated on 5-year-payout basis.
70
1968 McKee Study -As the basis of the McKee study, an "average" re-
finery was selected for each of the five petroleum districts established in the
United States by the Bureau 01 Mines. The crude used in each refinery was
typical for its district, as reported by the Bureau of Mines. In the
4-92
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1.10
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T
T
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COST PER 6,300,000 Btu
determination of size for the average refinery, the many small refineries in
that district were neglected if they contributed only a small proportion of the
production.
This study assumes that hydro-
desulfurization will lead to an upgrad-
ing of products and that residual fuel oil
will be partly upgraded to distillate
fuel which can be sold. The major re-
sults when desulfurizing to 1.0 per-
cent and to 0.5 percent are shown in
Tables 4-29 and 4-30.
These data show the production
COST PER BARREL
0.0
0.5
1.0 1.5 2.0
% SULFUR IN FUEL OIL
2.5
of No. 6 fuel oil for the typical re-
Figure 4-21. Incremental desulfurization costs -
per barrel versus constant heating finery without hydrodesulfurization in
value.^3
each district. A decreased amount of
this fuel is produced when hydrodesulfurization is used, but some No. 2 fuel
oil is also produced. In addition, sulfur is produced in the sulfur recovery
plant. Operating costs include hydrogen production, H0S and sulfur removal,
i£J
and operation of the hydrodesulfurization unit itself. They do not include de-
preciation or charges on the capital investment* The decreased amount of No.
6 fuel oil produced is shown as a debit while the increased production of No. 2
fuel oil is credited to the operation as is the sulfur recovered.
The major conclusion to be drawn from this study is that, for a refinery
of reasonable size, production of low-sulfur residual fuel oil may yield a net
4-94
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4-97
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income on operation. The net profit, of course, would be larger if higher
prices for low-sulfur residual oil were assumed. Disposal of the large amount
of distillate fuel oil may be a problem in some districts, and this fuel may have
to be upgraded to meet specific requirements. This would affect the cost.
4.4.4 Gas
Many natural gases, as found, contain elemental sulfur and sulfur com-
pounds. The sulfurous constituents may range in concentration from undetect-
able amounts to over 10 percent.
It is usually necessary to remove the sulfurous materials when they occur
in other than trace concentrations. Elemental sulfur causes plugging of equip-
ment. Hydrogen sulfide is a highly toxic material, even in very low concen-
trations. It causes rapid corrosion in steel when moisture is present or at
elevated temperatures, and is very reactive with copper or copper-bearing
materials under all conditions. Organic sulfur compounds (mercaptans,
disulfides, carbonyl sulfide, thiophenes) are malodorous, corrosive, and gen-
erally undesirable in significant concentrations. Specifications for saleable
natural gas generally call for the concentration of hydrogen sulfide to be below
1/4 grain per 100 standard cubic feet of gas and total sulfur to be no more than
10 grains per 100 standard cubic feet.
Literally scores of methods are employed industrially to remove the
sulfur-bear ing materials from natural gas. The economical choice of process
depends on factors such as quantity, temperature, pressure, and relative
humidity of the gas; quantity and composition of sulfur; nature of other
4-98
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contaminants present; and desirability of recovering sulfur in elemental form
as a by-product of treating.
Wet scrubbing methods are categorized as to whether they depend on
chemical reaction of the treating agent with sulfur compounds or on selective
7fi
solubility of the sulfur compounds. Treating with dry materials can be
categorized as methods that depend on chemical reaction and methods that
depend on selective physical absorption.
Cost of desulfurizing natural gas depends on the many factors outlined
above in discussion of methods. In general, the cost will range from a fraction
of a cent to several cents per thousand standard cubic feet of gas.
4-99
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4. 5 FLUE GAS DESULFURIZATION
4.5.1 Introduction
Removing SO0 from the flue gases is an obvious way of reducing SO0
£i £,
emissions. Flue-gas-desulfurization processes may provide an alternative
method for large fuel consumers where a switch to a low-sulfur fuel may
present technical and economic problems.
It has been estimated that 28. 6 million tons of SO9 was emitted into
£t
the atmosphere in the continental United States in 1966. Of this total, about
13.1 million tons (45.5 percent) was the result of combustion of oil and coal
77
in electric power generating plants. Other combustion processes accounted
for approximately 9.1 million tons (31.5 percent). Because of the predom-
inance of fuel combustion as an SO0 source, primary research and develop-
z
ment emphasis has been placed on the development of processes and equipment
for controlling this source. Many flue gas desulfurization processes have
been proposed, and a number of them are currently being actively developed.
One of these processes, the limestone injection-wet scrubbing process, is
in full-scale preliminary operation, and other large-scale prototypes will be
in operation within the next 3 years.
Progress in developing suitable flue-gas-desulfurization processes has
been slow because of the magnitude and complexity of the problem. A modern
power plant of 1000-megawatt capacity, burning coal with a sulfur content
between 2. 5 and 3 percent, will emit 1. 7 million to 2 million cubic feet per
minute of flue gas with an SO0 concentration of between 0. 2 and 0. 3 percent
£t
by volume. Desulfurization of flue gas is further complicated by a wide
variation in the size of power plants.
4-100
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The technical and economic feasibility of most processes is closely
related to plant size.
It is unlikely that a single flue-gas-desulfurization method will be
developed that is capable of controlling effluents from all types of sources.
Each of the several techniques now being studied demonstrates varying
capabilities for controlling different aspects of the problem. The control
technique to be used will depend on factors such as boiler size and con-
figuration, age, load pattern, characteristics of the fuel, by-products, and
geographical area (particularly with respect to ability to consume by-products).
The most promising SO- removal processes currently under investiga-
z
tion in the United States are limestone-dolomite injection, catalytic oxidation,
and alkalized-alumina sorption. A potassium sulfite scrubbing system also
is receiving increased attention. The limestone injection process, which
appears to have potential for controlling emissions from both small and large
sources, is, with certain variations, currently being installed on a number
of boilers in the 125- to 700-megawatt range. The alkalized alumina and
catalytic oxidation processes seem to be more applicable to large new units,
since their integration into the power plant is required. Other "second
generation" processes that show potential for improved economics and con-
trol capabilities also are being actively developed for installation during the
years between 1975 and 1980. These systems may find application in the
future as replacement processes for those now being developed, or in special
circumstances where the economics of a particular system are justified.
4-101
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4.5.2 Alkalized Alumina Process
4.5.2.1 Introduction - The alkalized alumina process is one of a number of
flue-gas-desulfurization schemes that use a dry metal oxide to contact and
absorb the SO0 in a gas stream. Because the activated sodium aluminate
^
sorbent is expensive, a regenerative process is employed and the sorbent is
recycled. Sulfur is recovered in the regenerating process. Developers claim
90 percent recovery of SO2 from the gas stream.
The process, which was developed with financial assistance from the
Public Health Service, is patented by the Bureau of Mines, Department of the
Interior. Their studies have progressed from a 92-cfm-at-625°F pilot plant
erected in 1961 at the Pittsburgh Coal Research Center, Bruceton, Pennsylvania,
to a recently installed plant rated at 0. 2 megawatt or 920 cfm at 625 F. Both
installations have transport reactors and use furnaces fired with pulverized
coal to supply SO0-bearing gas streams. To fill in gap areas where further
£i
fundamental data were needed for design studies, the National Air Pollution
Control Administration (NAPCA) contracted with AVCO Space Systems
Division to do kinetics work on sorption and regeneration and incorporate
these data in mathematical process models for use in determining process
costs as a function of design. W.R. Grace Company was given a contract to
do extensive work to test the life of alkalized alumina, improve its physical
and chemical properties, and determine the optimum means for producing
a low-cost sorbent. Other studies were funded by the Bureau of Mines to do
sorbent development and kinetic studies on regeneration.
4-102
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The British have advanced the .process development under the auspices
78
of the Central Electricity Generating Board (CEGB). A fluidized, large-
diameter absorber-contactor is the foremost innovation of their "sodium
aluminate" process. CEGB is ready to design, construct, and evaluate a
50-megawatt prototype plant.
The M.W. Kellogg Company has been selected by NAPCA as the prime
contractor for process design and development, and will help determine
whether a large, advanced-prototype plant is necessary to achieve optimum
process efficiency and economics prior to incorporation of the process into
a full-scale plant.
4.5.2.2 Process Description - The raw sorbent solid in the form of 1/16-inch
spheres of dawsonite, NaAl(CO3) (OH)2, is activated at 1200°F to form high-
porosity, high-surface-area sodium aluminate, which reacts with SO2 in the
flue gas at 300 to 650 F. The sodium aluminate reacts with SO2 to form
sodium sulfate, which is then regenerated in the presence of a reducing gas
at 1200°F.
The basic steps in the process are shown in Figure 4-22. After leaving
the boiler, the gases enter a dust collector and then a reactor, which removes
the SO0 from the flue gas at 600 F. Gas from the absorber then passes through
Li
an air preheater, a high-efficiency dust collector, and the stack. The spent
sorbent is heated to between 1200 and 1300 F and enters the regenerator
where it contacts a reducing gas (primarily H0, CO, and CO0), which is in
z ^
the form of producer gas (gas from reforming of fuel oil or natural gas).
4-103
331-543 O - 69 - 11
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SORBENT MAKEUP
DUST
COLLECTOR
FLUE GAS
FROM BOILER
SORBENT
STORAGE
FINES
SEPARATOR
PURIFIED FLUE
GAS TO AIR PREHEATER
AND STACK
FL
UE GAS
REACTOR
REGEN-
ERATOR
\
GAS TO SULFUR
RECOVERY PLANT
REDUCING GAS
DUST
REMOVAL
Figure 4-22. Alkalized alumina process.
The sulfate-bearing pellet is regenerated to sodium aluminate and re-
cycled. Hydrogen sulfide is the primary desorbed sulfur compound formed
under reducing conditions in the regenerator. A conventional Glaus unit (see
section 5. 2) will be used to convert H?S in the regenerator effluent gas stream
to elemental sulfur.
The advantages of this process are:
1. It produces a highly desirable and valuable by-product, i. e.,
sulfur, which can be sold to offset process operating costs.
2. The stack gases are released at a high enough temperature
(250 to 300 F) to maintain buoyancy of the stack effluent.
4-104
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Some of the disadvantages associated with this process are:
79
1. Sorbent make-up costs are high because of attrition. Present
sorbent cost is also high, but considerable progress being made in
preparation techniques should reduce this cost. W. R. Grace's
preliminary sorbent preparation work for NAPCA indicates that the
CO -sodium aluminate process may be capable of producing
&
sorbent for $. 20 per pound versus the $. 25 per pound projected
earlier by the Bureau of Mines. Attrition is, however, a critical
problem that must be overcome, perhaps by improving the sorbent
or the design of the regenerating process.
Q A
2. The process is most applicable to new power stations. To
keep process costs at a reasonable level, lower SCL removal effici-
Li
ency may have to be accepted for installations in existing power
plants.
3. The overall process is large and complex, involving circulation
of large amounts of sorbent at high temperature through the sorption
and regeneration steps, production of reducing gas, and recovery of
81
sulfur in a Claus unit. This results in high capital charges for
this SO0 removal equipment.
Li
4.5.2.3 Cost - Costs for the alkalized alumina process are difficult to esti-
mate and are based on the assumption that a suitable sorbent will be available.
It has, however, been estimated that for an 800-megawatt coal-fired plant
incorporating a transport-dispersed-solids reactor, a capital cost of $10. 64
per kilowatt is required. The operating cost of such a unit would be about
4-105
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$1. 54 per ton of coal (60 mills per million Btu). These figures are based on
the assumption that coal with a sulfur content of 3 percent and a 90-percent
82
operating load factor will be used. No allowance is made for revenue from
by-product sale. If credit is taken for by-product sulfur, the operating costs
would be decreased. These figures are also based on 0.1-percent attrition of
the sorbent per cycle, which is considerably lower than the rates now experi-
enced in a transport-type, dispersed-solids reactor; thus in all probability the
actual operating costs would be higher.
On the other hand, use of a fluid-bed reactor may result in substantially
lower sorbent make-up costs. An economic compromise for application to
existing power plants might require acceptance of SO removal efficiencies in
Zj
the 50 to 80 percent range. Advances in regenerator design would result in
lower process costs.
4. 5. 3 Limestone-Based Injection Process
4.5.3.1 Introduction - Oxides of sulfur produced by burning coal arid oil can
be reacted with the calcined products of limestone or dolomite to produce
removable calcium-sulfur salts. Two basic limestone injection processes are
currently being investigated, (1) limestone injected directly into the high-
temperature zone of the boiler is calcined to lime and allowed to react with
SO? in the flue gas and (2) limestone injected into the boiler is calcined to lime
and subsequently becomes part of an aqueous SO? scrubbing solution in the
scrubber. In the second process, the alkaline, milk-of-lime scrubbing solu-
tion reacts with SO? to form calcium and magnesium sulfites and sulfates,
which can be collected for disposal. Both processes are of major interest
4-106
-------
because of their relatively low capital cost and because of their potential for
being adapted to large and small, existing and new power plants. Their appli-
cation will require little alteration of existing power plants. Because of these
characteristics, the limestone-based processes are regarded as among the
most promising SO2 control methods.
4. 5. 3. 2 Process Description
Dry Process - The first active program in the United States for the
development of a dry limestone-injection process to control SO0 from flue gas
z
was initiated in 1964 by the Process Control Engineering Program of the
NAPCA. Earlier work in Germany and Japan was inconclusive. A series of
in-house and contract research projects to identify the important kinetic and
process variables affecting the use of reactants and sulfur oxide removal
efficiency was started. Results from these studies were incorporated into a
conceptual design study of the dry-injection process conducted by the
Tennessee Valley Authority as part of the NAPCA program for development of
a large-scale prototype process. The flow chart for this prototype process,
which will be operational in the summer of 1969, is shown in Figure 4-23. In
this process limestone and/or dolomite is pulverized and fed into the high-
temperature combustion zone of the furnace where it is calcined to the active
Q O
oxide forms CaO and MgO. The reaction of the additive with SO0 and oxygen
L±
at temperatures above 1200 F forms gypsum (CaSO,). Sulfates, unreacted
lime, and fly ash are removed by conventional particulate collection equip-
ment. Additional electrostatic precipitator capacity may, however, be
required to maintain a given collection efficiency.
4-107
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4-108
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Wet Process - The principle of lime scrubbing was thoroughly studied in
three separate but related programs in England in the 1930's. The first of
these involved a 26, 000-scfm-pilot-scale study. This work led to the construc-
tion of the still active Battersea SO wet-scrubbing process in London. Sulfur
£
oxide removal efficiencies of over 90 percent were obtained. A second pilot
study was conducted at the Tir John Power Plant at Swansea, Wales, This
process was reported to have demonstrated high SO9 removal efficiency. This
L*
work led to the full-scale, cyclic lime process that was installed in the late
1930's on the Fulham power plant, where it operated successfully until it was
closed during World War II. These installations demonstrated the capability
of the lime scrubbing process for removing SO from flue gas. However, they
also spotlighted specific process problems such as high maintenance and
operating costs, low-temperature corrosion, solid wastes disposal, and loss
of plume buoyancy resulting in high localized ground-level concentrations of
SO0 and other emissions.
LA
Unlike the earlier work done in England, the current limestone-
injection lime-scrubbing process for SO control is actually a combination of
o
the two individual processes, (1) dry limestone injection directly into the
furnace where it is calcined to lime and (2) scrubbing of the combustion flue
gas by lime slurry for removal of SO». Figure 4-24 is a conceptual design
for this process.
In the limestone scrubbing process, limestone is injected into the com-
bustion zone of a boiler, where it is calcined to reactive lime. The lime and
fly ash are collected by the scrubber, where the calcined limestone forms a
4-109
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4-110
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slurry of reactive milk-of-lime, which reacts with the SO- in the flue gas to
form sulfite and sulfate salts. The spent scrubber liquor and reaction products
are allowed to settle. Ash and reacted lime are removed for disposal. Scrub-
ber liquor is recycled to reduce water requirements and avoid water pollution.
The limestone-injection wet-scrubbing process for SO0 control was first
Li
researched in the United States by Wisconsin Electric Company and Universal
88
Oil Products Company in 1963 and 1964. The Combustion Engineering
Company in cooperation with Detroit Edison Company recently conducted
research on a similar process, which involved injection of limestone and
dolomite into a full-scale 170-megawatt boiler followed by a 2500-cfm scrubber
processing about 1. 0 percent of the total boiler flue gas. This work resulted
in the purchase of the limestone-injection wet-scrubbing process for use on
three full-scale power plant boilers in the 125- to 420-megawatt range.
These installations have been sold with a guaranteed removal efficiency of
more than 80 percent of SO9 and 98 percent of particulates. One of these
<£j
systems is currently in preliminary operation at the Union Electric Company's
Meramec Plant in St. Louis.
4. 5. 3. 3 Process Cost - Conceptual design and economic studies conducted
by TVA under NAPCA contract indicate that the capital investment for the dry
limestone injection process for an 800-megawatt power plant would be about
$3 million and that the net operating cost when removing 40 to 60 percent of
85
the SO9 would be about $0. 73 per ton. These figures assume limestone
Zj
delivered at $2. 00 per ton, and 200 percent stoichiometric addition of lime-
stone. Similar estimates of the capital and operating costs of the limestone-
4-111
-------
scrubbing process indicate that capital costs would be $4 million and operating
o c
costs would be $0. 94 per ton of coal' fired. Operating cost estimates by the
vendor (Combustion Engineering Co.) range from $0. 35 to $0. 50 per ton of
coal ($0. 015 to $0. 02 per million Btu). 86
4.5.3.4 Future Plans - A full-scale boiler (240-Mw) of the TVA power gen-
erating system is being equipped for direct injection of limestone and dolomite.
This unit, at the Shawnee power plant, is expected to be placed on line in
mid-1969. It is the purpose of these prototype studies to demonstrate process
feasibility and generate economic and design data on the dry injection process.
Three large-scale limestone-scrubbing demonstration units have been
sold by Combustion Engineering Company for installation on full-scale boilers.
These units have been sold as guaranteed processes and are based on extra-
polation of data gathered from small-scale pilot studies conducted jointly by
Combustion Engineering and Detroit Edison.
An intermediate-scale applied research program will be initiated by
NAPCA to provide the needed intermediate-scale data on prototype equipment
to study engineering, kinetics, and economic problems associated with wet-
scrubbing processes. Three scrubbers, each capable of scrubbing approxi-
mately 100, 000 acfm, will be evaluated, and studies will be made of reaction
and process kinetics, and factors such as high- and low-temperature corro-
81
sion, solid waste disposal, water pollution potential, and plume reheating.
4. 5. 4 Catalytic Oxidation Process
4. 5. 4.1 Introduction - This process converts sulfur oxides to sulfuric acid by
passing the flue gases over a vanadium pentoxide catalyst, which oxidizes the
4-112
-------
SO0 to SOQ. The SOQ then combines with water vapor in the flue gas to form
Li O O
sulfuric acid. Subsequent cooling condenses the acid.
In 1961, Bituminous Coal Research Incorporated (BCR) and Penelec
(composed of Pennsylvania Electric Company, Monsanto Chemical Company,
Research-Cottrell Incorporated, and Air Preheater Company) proceeded,
independent of each other, to show the feasibility of sulfuric acid production
on pilot-plant scales using similar methods. The BCR investigations were
carried out at Monroeville, Pennsylvania, and the Penelec group worked at the
Seward, Pennsylvania, power plant. The Penelec group's investigations have
now advanced to an operating 12-megawatt prototype plant at Portland,
Pennsylvania, which appears to be the most promising system using this
process. This work has proved successful, and Monsanto has announced
plans to market the process.
In Japan the Kiyoura-TIT proc^ss, another variation of the catalytic
oxidation process, is being used; and a pilot-plant installation is operating in
Omuta, Japan. This process involves the injection of gaseous ammonia to
form the by-product, ammonium sulfate, (NH ) SO . While TVA conceptual
T: ^ *i
design studies considered using ammonium sulfate as an intermediate sub-
stance from which a phosphate fertilizer could be produced, current demand
for (NH. )2SO, from this source is limited in this country because ample
79
quantities are generated by the coke industry.
4.5.4.2 Process Description - The catalytic oxidation process, as shown in
Figure 4-25, is an adaptation of the contact catalytic process used in the
manufacture of sulfuric acid. Many of the details of the process are not
available because of the proprietary nature of this process.
4-113
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A high-efficiency electrostatic precipitator (99. 5%) is employed to
remove particulate matter before the gas enters the catalyst bed at elevated
temperatures of 800 to 850 F. Sulfur trioxide formed in the catalyst bed
reacts with water vapor in the flue gas to form sulfuric acid. In the BCR
method, vapor condensation was carried out by two air-cooled tubular heat
exchangers, which preheated the boiler combustion air and preheated boiler
feed water. BCR reported that through careful temperature control of this
81
arrangement higher acid concentrations are possible. Monsanto achieved a
reported 78 percent sulfuric acid strength by using a rotary air preheater.
Condensation occurred both in the acid condenser and mist eliminator sections.
Over 99 percent of the sulfuric acid formed is collected in these sections. The
gas is exhausted through the stack at approximately 220 F.
A fixed-bed catalyst achieved 90 percent conversion of SO0 to SOQ on the
£ tj
first pilot plant; however, a means for cleaning the bed must be provided for
use in a large plant to preserve the life of the catalyst and maintain high con-
87
version efficiencies. Even minute amounts of certain particulates, such as
selenium, arsenic, or chlorides, deactivate vanadium pentoxide.
Corrosion properties of sulfuric acid are minimized when the concentra-
tion is above 93 percent; however, the weak acid vapors are extremely cor-
rosive below their dew point, and special materials of construction are
required on the cooler portions (below 500 F) of the equipment.
The advantages of this process are:
1. The SO2 removal system is simple.
2. Recycling of catalyst is not required.
3. Effluent-stack-gas buoyancy is maintained.
4-115
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4. The by-product acid may prove profitable in some areas.
5. All raw materials are contained in the flue gas.
Some of the disadvantages of the catalytic oxidation process are:
I. The need for expensive corrosion-resistant materials of con-
struction in the cooler section.
2. Rearrangement of the gas stream through the boiler's economi-
zer section is necessary in order to supply the converter with
850 F flue gas. Provision must be made to route the gases back
to the economizer or place the economizer after the converter.
3. Marketability of 75 to 80 percent acid is questionable unless
such markets as the steel or fertilizer industries are reasonably
close to the supply of acid.
4. The process is difficult to apply to older plants because of the
problems of tapping existing flue gas streams at a point where
required temperatures exist.
4-116
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4.5.4.3 Cost - Estimated installation cost for this process is $20 to $30 per
kilowatt above that of a new conventional power station. The operating costs
for an 800-megawatt plant have been estimated to be $1. 75 per ton of coal
burned, without credit for the acid produced (0. 613 mill/kw-hr or 68.4 mill/
82
million Btu). If credit is taken for 78 percent acid by-product from a
3-percent coal, using a 90-percent recovery factor, $1.06 per ton of coal fired
might be realized ($10 per ton is the estimated market value of the acid). The
overall costs (or credits) associated with this process are dependent upon the
sales value of the acid.
4. 5. 5 Beckwell SO9 Recovery Process
&
4.5.5.1 Introduction - The Beckwell Process has been developed by the
Wellman-Lord Co., a division of the Bechtel Corp. This process uses a
potassium sulfite scrubbing solution and has been evaluated at the Gannon
Station of the Tampa Electric Co. This pilot-study has led to the construction
of a 56, 500-cfm pilot plant scheduled for operation in April 1969 at the Crane
Station of the Baltimore Gas & Electric Co.
4. 5. 5. 2 Process Description - SO9 is removed from the flue gas by scrubbing
' ' • • A
with a solution of potassium sulfite. The absorbed SCL forms potassium bi-
sulfite, which precipitates out of solution as potassium pyrosulfite. Heating
this potassium pyrosulfite converts it back to potassium sulfite, and a concen-
88
trated stream of SCL is recovered. This SO9 may be recovered in the
Lt &
anhydrous form.
4-117
-------
4. 5. 5. 3 Process Cost - For a 500-megawatt coal-fired power plant, it is
estimated that installed costs will be in the range of $5 to $6 million. Net
operating costs will depend largely on the price received for the recovered
88
SO ; however, a breakeven cost is envisioned.
4. 5. 6 Other Processes
4. 5. 6.1 Introduction - The four processes previously mentioned (alkalized-
alumina sorption, wet or dry limestone-dolomite injection, potassium sulfite
scrubbing, and catalytic oxidation) are the main processes developed to the
large pilot-plant stage, prototype scale-up, or full-scale plant installation in
the United States. There are between 60 and 70 other SO0 removal systems
z
that are in various stages of development.
4. 5. 6. 2 Process Descriptions - In inorganic-solids sorption systems (exclud-
ing metal oxides), the dry system approach is typified by the Reinluft
79
process. A small-scale pilot plant is being operated in Warren Spring,
England, by the Central Electricity Research Laboratory. Two larger-scale
coal-fired pilot plants (10 megawatt) are operating in the Ruhr Valley,
Germany. Available information indicates that carbon catalyst oxidation is
igniting char in the absorber. Evaluations must be held in abeyance, however,
because the owners of these German units have made process details
inaccessible.
Basically, flue gas containing SO2 is passed through a bed of activated
char at temperatures of 200° to 300°F. During adsorption, SO2 is oxidized to
SOr which reacts with flue gas moisture, yielding I^SO^. The char adsorbent
is removed to a regenerator and heated to 750°F, liberating SO2 and CO2>
4-118
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A conventional acid plant converts SO9 into concentrated acid. An efficiency
&
rate of 95 percent is claimed. It is estimated that, for the comparable 800-
megawatt power plant burning 3-percent-sulfur coal, a $14,217, 000 capital
investment is required. Operating cost, including 14 percent capital charge of
total investment for 90-percent load factor, is $5,431,000 per year (0.857 mill
82
per kilowatt-hour, or $2. 45 per ton of coal).
Some advantages of this system are: (1) production of a desirable con-
centrated acid, (2) adequate buoyancy of discharged stack gases, and (3) the
regenerator's self-activation of the charcoal. At present, however, the dis-
advantages seriously impair the system's promise. The disadvantages are:
(1) susceptibility to fires in the absorber, due in part to the fact that the char
becomes activated to a higher degree with each subsequent desorption;
(2) necessity for large amounts of char; and (3) high cost of materials and
recirculation.
The Lurgi process is a wet-char system that first cools the boiler gas
79
by contact with a weak solution of sulfuric acid. After adsorption of con-
verted SOQ by the char, water is intermittently sprayed into the gas stream to
o
remove acid. Some of the disadvantages of this process are: weak recovered
acid, cool effluent gases, and the need for corrosion-resistant materials of
construction. The process has been tested in conjunction with chemical plant
operations. Plans call for testing on a coal-fired power plant.
A similar wet-char process (removal of acid with wash water) is the
79
pilot-plant operation of Hitachi, Ltd., of Toyko. A 2-kilowatt plant has
operated at the Goi Power Plant, and a 50-kilowatt installation is being
4-119
331-543 O - 69 - 12
-------
planned. The Japanese government subsidizes this work. Gas contact with
carbon is done in a cyclic system employing six towers with alternating
schedules for 30-hour uncooled gas adsorption, 10-hour washing, and 20-hour
stack-gas drying periods. The product acid of 10 to 15 percent is obtained by
successively weaker washes of adsorption tower carbon. Increase in costs due
to a required damper system to change the flow from tower to tower is a
disadvantage.
Metal-oxide sorption systems - Besides the alkalized-alumina and
dolomite-injection systems, sorption with metal oxides is also being
investigated.
The Grillo Process uses a slurry of manganese and magnesium oxide as
79
an absorbent. There are two series reactors, the first at a temperature of
248° to 302°F and the second ranging from 104° to 176°F. The gas stream is
cooled by evaporation of absorbent slurry. After absorption, the regen-
eration of the absorbent is carried out by heating a mixture of MgSO. and
coke in a Herreshoff-type furnace at 1470 to 1560 F. Concentrated SO is
^j
evolved for sulfuric acid production. The ash and regenerated oxide are
separated, the oxide suspended, and the slurry recycled.
The advantages are the use of carbon steel construction, non-attrition of
absorbent, and rapid absorption. The disadvantages are some fly ash gener-
ation, cooling of discharge gases, and pressure drops through the reactors.
A small-scale pilot plant is operating. Costs have been estimated at $0. 75 to
$1. 20 per ton of fuel for a 300-megawatt plant.
4-120
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The Carl Still Process was developed by the Firma Carl Still and is
being currently tested on a 10-megawatt unit at the Herne Power Station,
79 o
Recklinghausen, Germany. A brown coal (lignite) ash is reacted at 300 F
after the SO -laden flue gas leaves the air preheater and before it reaches the
L±
control precipitator. The lime content of the lignite ash is 40 to 50 percent.
After reaction with the flue gases, the spent absorbent can be discarded or
the calcium sulfite can be heated to evolve a rich SO stream for sulfuric
acid production.
Three series reactors are used and the feed is recycled. The recycle-
to-feed ratio is about 2 or 3 to 1. The major obstacles to this process appear
to be that a suitable lignite is not widely available and formation of calcium
sulfate would interfere with the activity of the basic ash in recycle. Costs for
the process have not yet been determined.
Inorganic-liquid sorption systems - A molten-carbonate process is
being developed to scrub SO from the flue gas, using a eutectic mixture of
LJ
LiCO , Na CO , and K CO (with a melting point of 746°F) at about 800°F.
O Z O LA O
The mass transfer of a liquid-gas system should be excellent; and, with the
high temperatures obtained before the economizer, high reaction rates are
possible. Elemental sulfur is the by-product. Bench-scale studies have
shown that the carbonates are corrosive and that corrosion-resistant materials
of construction are required. Regeneration appears difficult since reduction
rates of sulfite and sulfate to sulfide are slow until temperatures of about
1150 F are reached. This accentuates the corrosion problem. In existing
plants, access to the flue gas at 800 F is often complicated.
4-121
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This system requires much less liquid compared to aqueous systems.
The process does not cool the gas stream or add water to it. There is also
some indication that the molten salt can control nitrogen oxides.
Aqueous-solutionsorption systems - Besides the alkali-solids injection
system with wet scrubbing, which was previously discussed, numerous pro-
cesses have been devised to remove SO0 from flue gases by scrubbing with
^j
water solutions. Prior to 1940, nonrecovery-type lime-water scrubbers were
installed in England.
In the Battersea-Bankside power plants, flue gases were scrubbed with
86
a solution formed by adding chalk to the alkaline Thames River water.
This process was developed in the 1930's by the British Electrical Authority.
The operating cost to attain 90 percent removal of SO was $1.15 per ton of
LJ
coal, or 12 percent of the delivered coal cost. Capital costs of up to $3
million for this system were estimated for a 120-megawatt power plant.
Also in the 1930's the Howden-ICI Process used lime or chalk in water
86
to scrub flue gases. Holdup tanks caused the calcium sulfate to accumulate
before the liquid was recycled. Operating costs were estimated in 1956 by the
U. S. Bureau of Mines to be $1. 25 to $1. 93 per ton of coal. One plant in
England and one in Wales had generating capacities of 120 megawatts each.
Chemico is also studying a variety of water-based alkali scrubbing
solutions for removing SO?. Pilot-scale tests are currently under way with
SO9 removal efficiencies in excess of 90 percent. A pressure drop of 5 to 6
^
inches of water occurs across the scrubber.
4-122
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Miscellaneous processes - Many other wet processes are being investi-
gated. Among the names and systems encountered are Mitsubishi Shipbuilding
Engineering Company, U. S. Stoneware Incorporated, the Cominco Ammonia
Processes, and the Ionics/Stone & Webster Caustic Scrubbing Process.
Despite the long history of wet scrubbing programs, many basic questions
remain unanswered, and modern technology is being applied to solve them.
The economics of these processes are being evaluated to determine by-
product and plume-reheating costs.
Reduction of SO0 to sulfur (the most marketable by-product) is another
u
desulfurization process under active investigation. Princeton Chemical
Research, Inc. , is performing bench-scale studies on the catalyzed reduction
of SO0 by H S produced from sulfur and methane. The use of organic sorbents,
z 2
both liquid and solid, is also under active investigation. Uniroyal is studying
fibers, which may be developed to the extent that they could be used in pro-
cesses capable of controlling SO and particulates. Physical methods of
o
separation are also under active investigation.
4. 5. 7 Systems for Small Sources. In a recent preliminary study a 600-gallon-
per-minute recycling scrubber system was used to remove SO0 from the flue
LA
89
gases of a 200, 000-pound-per-hour industrial boiler. The installation cost
for such a system was estimated at $125, 000. The scrubber's adsorbent
slurry might be composed of sea water, limestone, soda ash, or any combin-
ation of these. Efficiencies for SC- removal could range from 70 to 99 per-
&
cent. If such a system were adopted, the suggestion has been made that
perhaps as much as 25 percent of the flue gas stream should bypass the
4-123
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scrubber and be added to the treated gases after SO removal. This would
LJ
elevate the stack gas exhaust temperature to about 50 F above the dew point
to provide the buoyancy needed for dispersal and prevention of steaim plume
formation.
An installed cost of $750, 000 and an operating cost of 0. 3 mill/kw-hr
were recently estimated for the limestone/dolomite wet process for an exist-
90
ing 250, 000-pounds-of-steam-per-hour boiler.
Scrubbers attached to small municipal and industrial boilers in the past
have been used primarily to remove particulate matter. They have also been
used on boiler gases for the recovery of C02 for making liquid CO and
dry ice.
4-124
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4.6 COMBUSTION PROCESS MODIFICATIONS
4.6.1 Heat Recovery
One important means of reducing SO emissions from fuel combustion
^
systems is to increase the efficiency of the systems so that they use less fuel
to produce a given amount of energy. Process improvements usually result in
relatively small increases in efficiency; but when such improvements are
applied to a large plant, fuel savings become immediately apparent. Since
fuel combustion in power plants is the largest source of SO emissions, this
Li
discussion is restricted to power plants.
Over the years, generation of electricity in large central stations has
become steadily more efficient. Large modern steam-electric plants use
approximately 8500 Btu to produce one kilowatt-hour of electricity. Many
older, smaller plants still in operation require over 10,000 Btu to produce a
single kilowatt-hour of electricity.
Improvements in the operation of power plant components can reduce
the heat rate, or Btu/kilowatt-hour ratio, and thus save fuel and reduce SO
^
emissions. Small heat-rate reductions may result from:
1. Washing turbine blades.
2. Adjusting turbine control valves to insure proper lift.
3. Adjusting for maximum turbine throttle pressure.
4. Adjusting preheater seals and feedwater heaters.
4-125
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5. Periodic cleaning of condensers.
6. Periodic cleaning of secondary and reheat superheaters.
In a recently cited case, the net result of these operations was a reduction in
91
heat rate of about 45 Btu per kilowatt-hour.
Another consideration in process efficiency is the steam generator itself.
A reduction in heat rate results from increased boiler steam pressure and tem-
perature . The effect on efficiency can be gauged from the rule of thumb that
doubling the steam drum pressure produces a 7-percent decrease in heat rate.
At present, a maximum steam pressure of 5000 pounds per square inch (gauge)
is being achieved. Net heat rate has improved by 3 to 3. 5 percent as main
stream temperatures have risen from 900 to over 1000 F. Further gains
should accompany advances in the design and fabrication of critical heat-
absorbing surfaces such as firebox walls and convection zones. Modern fuel-
feed systems, which provide proper fuel size and distribution, also contribute
to overall efficiency.
Efficient boiler operation requires that the optimum air-to-fuel ratio be
maintained. Control of fuel and air is automatic on all large modern boilers.
Plant efficiency also improves with increasing unit size, as shown in Figure
92
4-26. Heat rates below 800 Btu per kilowatt-hour have, however, not yet
been sustained.
4-126
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10,000
4.6.2 Improving Generating System
Efficiency
Uniform electrical demand would
be ideal for power plant operations;
however, varying power demands call
for flexibility in power generation.
7500
100 200 300 400 500 600 700 800 900 1000 , , ,
Flexible electrical production systems
UNIT CAPACITY, Mw
-.. ,«„,> . , i * . . . x minimize the inefficient fuel use
Figure 4-26. Comparison of plant size and heat
rate.92
associated with startup, low-load, and
cyclic operations of large boilers and thereby decrease SO emissions.
Diesel and gas turbine generators are being installed at many generating
stations to meet peak demands. These units, available in many sizes up to
about 25 megawatts each, can reach full load very rapidly from a cold start.
They are especially useful in systems with rapid load fluctuations since they
can take up these fluctuations and allow the larger boilers to run at a constant,
efficient rate. Because such units burn light fuel oils or natural gas, they
do not emit large quantities of SO .
Another means of attaining system flexibility is the pumped-storage
technique. During periods of low power demand, excess generating capacity
is used to pump water to an elevated reservoir. Then, during peak demand
periods, the potential energy of the water can be converted to electricity by a
conventional hydroelectric plant. By this method, stored energy can be put on
4-127
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line in a few minutes. This method is practical only where terrain, water
supply, and market conditions are suitable. In addition, considerable energy
is lost in the pumping operation. In order to provide an overall SO reduction,
tL
the electricity used to pump water to the elevated reservoir must be provided
by a nuclear plant, or a thermal plant burning a low-sulfur fuel.
Extra-high-voltage transmission networks also provide system flexibility
by allowing utilities in one area to provide power to cities hundreds of
miles away.
4.6.3 Newer Concepts of Central Station Power Generation
Greater process efficiency also can be achieved by changes in the basic
techniques used to generate electricity. The following alternative methods of
power generation represent techniques that are still in the developmental
stage, but offer considerable potential advantages over present methods in that
they use less fuel for a given electrical output and thus emit less SO .
^
93 94
4.6.3.1 High-Pressure Combustion ' The design of a pressurized coal-
fired furnace requires a new method of fuel burning, such as a fluidized-bed
technique. In addition to providing for easier effluent removal, fluidized-bed
carbonization is a potentially low-cost method of processing coal to obtain a
gas stream capable of powering a high-temperature gas turbine. This high
temperature offers a modest but significant increase in overall efficiency,
which would produce a proportional reduction in SO emissions. As shown in
^
Table 4-31, for a 500-megawatt plant of this design, the expected increase in
4-128
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Table 4-31. ESTIMATED EFFECT OF INCREASED GENERATING
EFFICIENCY ON SO2 EMISSIONS AND FUEL COST
FOR 500-MEGAWATT PLANT
Combustion
concept
Conventional
One- step
pressurized
Two-step
MHD
EGD
Initial
capital cost,
dollars AW
112
NAC
135d
130d
91d
Overall
efficiency,
%
39
40
41
50
45
Potential SO2
reduction, a
tons/day %
-
6.0 2.5
12.5 5.0
55.0 22.0
33.5 13.0
Fuel savings,
dollars/yr"
-
196,600
393,000
1,730,000
1,050,000
aBased on use rate of 4200 tons of coal per day, 3 percent sulfur content,
12,500 Btu per pound.
Based on coal cost of $.25 per 10 Btu and 300 days of operation per year.
CNA - not available.
Cost presently speculative.
4-129
-------
efficiency would be about 1 percent, which would result in a reduction in SO
£
emissions of 6.0 tons per day. This 1 percent efficiency increase could save
about $196, 000 per year in fuel costs. Although there are still many technical
problems, the feasibility of fluidized-bed carbonization over a wide range of
coal ranks has been demonstrated.
4.6.3.2 Two-Step Combusion - This approach uses a two-stage process in
which a first gasification stage yields concentrated fuel gas containing H S.
/j
The H S can be easily removed and converted into elemental sulfur, and the
^j
resulting sulfur-free fuel gas burned in a second combustion step.
The object is to balance the higher capital cost of this station against the
lower operating cost which results from sulfur revenue and fuel savings. As
shown in Table 4-31, the probable capital cost for a 500-megawatt clean power
plant is about 20 percent more than for a conventional plant, or approximately
93
$135 per kilowatt. The expected 2-percent efficiency increase would mean
an annual fuel savings of about $393, 000. Sulfur dioxide emissions would be
reduced by about 12. 5 tons per day.
95
4.6.3.3 Magnetohydrodynamics Another new concept involves the use of a
magnetohydrodynamic (MHD) generator as the first step in power generation, or
an MHD "topping plant" combined with a conventional steam "bottoming plant."
Basically, MHD is a technique in which the thermal energy of a hot gas is con-
verted first to kinetic energy and then directly to electricity by the mass
4-130
-------
interaction of an electromagnetic field with the hot, rapidly moving, electrical-
ly conductive gas.
It is foreseeable that the thermodynamic efficiency of MHD conversion of
fuel to electrical energy will ultimately reach 50 percent or even higher. This
relatively high efficiency will allow much more effective use of fuel and, there-
fore, reduce SO0 emissions as shown in Table 4-31.
Li
Assessment of the capital costs of MHD steam power plants is difficult.
Present indications are that capital costs for an MHD plant will be about $130
per kilowatt. Further intensive development, however, may lead to reduced
capital costs.
Although direct conversion of thermal energy to electrical energy by MHD
is appealing, the physical problems are formidable. One must cope with gas
temperatures in the range of 4500 to 5500 F and with the slagging, corrosive,
and erosive effects of mineral matter in the fuel. If existing problems are
overcome, the MHD system, with its higher efficiencies, promises more
effective use of resources and an opportunity for better control of the effluent-
gas SO 2'
The first practical application of the MHD generator is being tested at the
Air Force's Arnold Engineering Development Center in Tennessee. This de-
vice, using a treated coal at present, has a maximum operating time of only
120 seconds. It also has a potential for high nitrogen oxide emissions.
4.6.3.4 Electrogasdynamics - Electrogasdynamics (EGD), like MHD, is a
direct energy conversion technique in which the kinetic energy of a flowing gas
is directly converted into low-amperage, high-voltage electricity. In this
4-131
-------
process, positive ions are formed on the particles in the coal combustion
gases by means of a corona discharge. These charged dust particles are
carried downstream to the collector electrodes, where they build up an elec-
trical charge, which flows through an external load. Current is forced
through the load resistance as the gas does work in pushing the charged elec-
96
trie field in the generator.
The primary advantages of an EGD coal-fired station are that it can
operate at high efficiency and can be built at a low capital cost. These advan-
tages result from the simplicity of the EGD system compared to conventional
stations.
Preliminary studies, while rather speculative, indicate, as shown in
Table 4-31, that EGD systems (approximately 500-Mw) can be built at a
capital cost of $91 per kilowatt and can operate at an efficiency of 45 percent
97
or higher. A substantial decrease in air pollution would be obtained because
the amount of effluent gas is reduced in direct proportion to the efficiency
increase. For a 500-megawatt plant, an increase in efficiency of 8 percent
(39 percent for a conventional plant - projected 45 percent for an EGD plant)
will result in an emission reduction of approximately 33. 5 tons of S(X> per day
and in fuel savings of about $1,050,000 per year, as shown in Table 4-31.
So far, no fundamental arguments against the feasibility of EGD coal-
fired plants have been raised. However, there still remain many difficult
engineering problems such as better ion sources, a better under standing of
the mobility of charged particles, and new ways to match load impedances of
the generator and the load. If all technical difficulties can be overcome, this
4-132
-------
process will have the potential of generating cheaper electricity at a smaller
capital cost, and with some reduction in SO2 emissions. At present, experi-
ments are being conducted under contract with the Office of Coal Research of
the Department of the Interior. A pilot-plant EGD power station is planned
for 1972 or 1973. As with the MHD technique, the EGD has a potential for
high nitrogen oxide emissions.
4-133
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4-136
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70. Sledjeski, E. W. and Maples, R. E. "How Residual Sulfur Limits
Affect Refining. " Oil Gas J. , £>6(18):55-63, April 29, 1968.
71. Schuman, C. S. "Desulfurization of Petroleum Stocks. " Preprint.
(Presented at Div. of Petroleum Chemistry, American Chemical Society,
Atlantic City, New Jersey, Sept. 13, 1968.)
72. "The Economics of Residual Fuel Oil Desulfurization. " Bechtel
Corporation, June 1964.
73. "Desulfurization Costs (for) Residual Fuel Oil - Typical Carribbean
Refinery - Venezuelan Crude Oil." Bechtel Corporation, Feb. 1967.
74. Bland, W. F. (ed.) "Petroleum Processing Handbook. " McGraw-Hill,
New York, 1967.
4-139
-------
75. Alpert, S. B. , Johnson, A. R., and Johnson, C. A. "How Feasible Is
Residual Oil Desulfurization Today." Oil Gas J. , 64(6):97-100, Feb. 7,
1966.
76. Shreve, R. N. (ed.) "Chemical Process Industries." 3rd edition,
McGraw-Hill, 1967, pp. 67-92.
77. Hangebrauck, R. P. and Spaite, P. W. "A Status Report on Controlling
the Oxides of Sulfur. " J. Air Pollution Control Assoc. , l_8(l):5-8,
Jan. 1968.
78. Frankenberg, T. T. "Sulfur Removal: for Air Pollution Control. "
Mech. Eng. , Vol. 87, pp. 36-51, Aug. 1965.
79. Slack, A. V. "Air Pollution: The Control of SO from Power Stacks.
Part III - Processes for Recovering SO2 from Power Stacks. " Chem.
Eng. , Vol. 74, pp. 188-196, Dec. 4, 1967.
80. Spaite, P. W. "Reduction of Ambient Air Concentrations of Sulfur Oxides •
Present and Future Prospects." In: Proceedings of the 3rd National
Conference on Air Pollution, Washington, D. C. , Dec. 12-14, 1966,
pp. 161-169.
81. Hughes, D. F. "Present Engineering and Economic Feasibility of Flue
Gas Treatment Process. " (A study by Bechtel Corporation for the
Potomac Electric Power Company, presented at the Federal Interstate
Air Pollution Abatement Conference, National Capital Metropolitan
Area, Dec. 1967.)
82. Katell, S. and Plants, K. D. "Here's What SO2 Removal Costs."
Hydrocarbon Processing, 46(7): 161-164, July 1967.
83. Harrington, R. E. , Borgwardt, R. H. , and Potter, A. E. "Reactivity
of Selected Limestones and Dolomites with Sulfur Dioxide. " American
Industrial Hygiene Association J. , 2_9(2): 152-158, March-April 1968.
84. Pollock, W. A., Tomany, J. P., and Frieling, G. "Flue Gas Scrubber. "
Mech. Eng. , Vol. 89, pp. 21-25, Aug. 1967.
85. Harrington, R. E. Private communication, Process Control Engineering
Program, National Air Pollution Control Administration, Cincinnati,
Ohio, Aug. 1968.
4-140
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86. Plumley, A. L. , Whiddon, O. D , Shutko, F. W. , and Jorakin, J.
"Removal of SO2 and Dust from Stack Gases. " Combustion, 40(l):16-23,
July 1968.
87. Bovier, R. F. "Sulfur-Smoke Removal System." Preprint. (Presented
at the 76th Annual American Power Conference, Chicago, Illinois,
April 16, 1964.)
88. Private communication, Wellman-Lord Corp., Lakeland, Florida.
89. Kopita, R. and Gleason, T. G. "Wet Scrubbing of Boiler Gases. " Chem.
Eng. Prog., 64(1):74-78, Jan. 1968.
90. Parsons, J. L. Private communication, E. I. DuPont de Nemours & Co.,
Wilmington, Delaware, June 12, 1968.
91. Moore, J. A. and Ferguson, H. "Squeezing,More Megawatts from Fewer
Btu's." Power, Vol. 112, pp. 76-98, Feb. 196S.
92. Evans, R. K. "The Spectacular Story of Size. " Power, 110(12):S2-S5,
Dec. 1966.
93. Squires, A. M. "Air Pollution: The Control of SO2 from the Power
Stacks." Chem. Eng., Vol. 74, pp. 101-109, Dec. 18, 1967.
94. Brown, F. H. S. "The Prospects for Alternative Methods of Generation
of Electric Power: A Comprehensive Review." Combustion, 38(ll):23-28,
May 1967.
95. "American Power Conference Abstracts. " Combustion, 39(2):19-29,
Aug. 1967.
96. Gourdine, M. "Electrogasdynamics, or EGD for Short. " Combustion,
39(7):13-16, Jan. 1968.
97. Gourdine, M. "Electrogasdynamics and the Coal Industry. " Preprint.
(Presented at the National Coal Association Technical Sales Conference,
Annual Meeting, Pittsburgh, Pennsylvania, Sept. 15, 1966.
4-141
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5. INDUSTRIAL PROCESS SOURCES
5.1 NONFERROUS PRIMARY SMELTERS
5.1.1 Introduction
Several important metallic ores are found as sulfides, and the smelting
of these ores produces SO_. These ores include the sulfides of copper, lead,
£
zinc, nickel, mercury, and molybdenum. In the United States, only the
sulfide ores of copper, lead, and zinc are mined in appreciable quantity.
Molybdenum also occurs as the disulfide, but current primary production of
this metal in the United States is less than 50, 000 tons per year, mostly from
Colorado.
In 1966, nonferrous smelters emitted about 12 percent of the total
estimated SO emissions in the United States. Production and SO emissions
£ £
data for that year are shown in Table 5-1.
Metal ores, as they occur in nature, are usually mixed with large
amounts of worthless rock, which must be removed from the desired minerals.
The nature of this preconcentration operation is defined by the characteristics
of each particular ore. Among the principles of separation commonly
employed are gravity separation, preferential wetting, flotation, and tabling.
These methods depend upon such factors as relative density and wettability of
mineral and rock. Because concentration produces a feed material of
5-1
-------
Table 5-1. NONFERROUS SMELTER PRODUCTION
AND SO. EMISSIONS IN 19661'2
Li
(TONS)
Metal Concentrate Metal production SO recovered SO emitted
£ &
Copper 6,008,000 1,581,000 996,000 2,830,000
Lead 790,000 441,000 11,700 146,000
Zinc 2,062,000 1,025,000 817,400 509,000
1,825,100 3,485,000
5-2
-------
relatively high sulfur content, SO concentrations from smelting operations
^
are relatively high compared with those from fuel combustion. Smelter gases
containing more than 3 percent SO by volume can usually be fed to sulfuric
acid manufacturing plants for conversion of the sulfur oxides into sulfuric
acid. Of the 35 sulfide ore smelters in the United States, 17 plants
(handling about 42 percent of the concentrate processed) are currently
recovering some sulfur as SO_ or sulfuric acid.
The costs of controlling SO0 emission from smelters is partly offset
/j
by the value of the sulfuric acid produced.
5.1.2 Copper Smelter Emissions Control
An important sulfide ore of copper is chalcopyrite (CuFeS ). Such an
£
ore is concentrated by suitable mechanical operations. Typically, the ore is
crushed, ground, and thickened. The thickener underflow is then sent to
water flotation cells, where frothing agents are added to produce foam and
where "collector" materials such as xanthates are added to aid in the separa-
tion of chalcopyrite from rock. The copper mineral, along with water and
other materials, forms a froth, which is drawn off and filtered.
The copper concentrate is then fed into a reverberatory furnace
(Figure 5-1). The furnace is also charged with slag from the copper converter
and with limestone and silicious fluxes. Hot combustion gases from the firing
of gas, oil, or powdered coal pass directly over the charge. Some oxides of
sulfur are emitted, but the principal products are copper matte: mainly
cuprous sulfide (CuS2), ferrous sulfide (FeS), and small amounts of other
sulfides.
5-3
-------
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5-4
-------
The purpose of the reverberatory furnace is to make copper matte and
to form a slag to remove part of the iron.
An alternative procedure is to roast the copper concentrates in a
vertical, multiple-hearth furnace before charging to the smelting furnaces.
Sulfur dioxide constitutes 12 to 14 percent by volume of the gaseous emissions.
The purpose of sulfur removal by roasting is to reduce the amount of sulfur
to that required for subsequent operations. Many smelters omit roasting now,
but it may return to general use as an air pollution reduction measure
because high SO concentrations favor the recovery of sulfur.
u
In addition to copper, the concentrate usually contains various other
minerals and metals. Slag formed in the reverberatory furnace removes part
of the iron. The matte dissolves precious metals and other metals such as
bismuth and nickel, most of which are recovered later in the refining process.
Part of the sulfur is driven off. Gases from the reverberatory furnace
contain 1 to 2 percent SO9 by volume and represent 25 to 40 percent of the
&
3
sulfur present in the raw ore.
The product of the reverberatory furnace is charged as a liquid to a
copper converter, which is a cylindrical, refractory-lined vessel (Figure 5-1)
containing numerous tuyeres. Air is blown through these tuyeres into the
copper matte, forming blister copper and liberating the sulfur as SO0.
£1
Cu0S + O0—»2Cu + SO0
Zi £ 2t
FeS + ~ O-—*FeO + SO.
A Li Li
A silicious flux is added to combine with the FeO to form a slag; this slag
contains so much copper that it is returned to the reverberatory furnace.
5-5
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The converter operations are not continuous, but consist of at least three
blows with interspersed additions and adjustments. The first and second
blows are for the purpose of slag formation and elimination of iron; the final
blow completes the reduction of copper to an impure blister copper, which
is refined elsewhere. Converter gases contain up to 6 percent SO0, and are
&
often fed to contact sulfuric acid plants. Sulfuric-acid-plant feeds from
nonmetallurgical sources normally range from 7 to 14 percent SO . The
^
metallurgical gases from smelters are more costly to treat because of the
dilute nature of the gas stream and the presence of such impurities as dust
and acid mist. These impurities must be removed with electrostatic
precipitators, cyclones, or scrubbers before the gas enters a contact sulfuric
acid plant. Each acid plant must be designed for the particular smelter-gas
feed used. Because of the dilute nature of smelter-plant feed gases,
80 percent removal of SO_ is considered a reasonable rate of recovery;**
therefore, exit concentrations may still be as high as 0. 8 percent, or
8000 ppm. More than 90 percent recovery of SO0 and exit concentrations as
z
low as 3000 ppm are obtained in some cases.
Reverberatory smelting usually dilutes the SO2 in the gas stream so
much that economic recovery as sulfuric acid is not feasible. Flash smelting
processes would avoid such dilution and allow a high degree of sulfur
recovery. There are three fundamental pyrometallurgical copper operations:
roasting, smelting, and converting. Flash smelting is a combination of
roasting and smelting. Ore concentrate and preheated air are mixed and
burned by being blown into the top of a vertical cylindrical furnace - the flash
smelting furnace. Beneath this furnace is a settler, which is similar to a
5-6
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reverberatory furnace and is well insulated to retain matte in a molten con-
dition. Combustion gas and roast blow down into the smelter from the flash
furnace. The gas stream turns 90 degrees, and the roast falls into the
molten pool of copper matte. The hot gases traverse the settler, move along
the surface of the matte, and then are cooled from about 2300 to 1600 F in
a waste heat boiler. The gases are then further cooled by heat exchange
against incoming smelting air and sent to a sulfuric acid plant. This process
saves fuel and operates continuously. An SO0 feed of constant concentration
z
as high as 12 to 14 percent SO can be sent to the sulfuric acid plant.
^j
Flash smelting is possible when there is a substantial amount of sulfur
in the concentrate above that actually required to form the copper matte.
Smelting with oxygen-enriched air is now practical because of the
r\
availability of bulk oxygen at reasonable prices. This process reduces the
amount of nitrogen involved in smelting, but has little effect on SCL emissions
£t
because it is used only in converting or flash smelting, both of which already
produce relatively concentrated SCL gas streams. Oxygen-enriched air is not
used in the reverberatory furnace, which produces dilute SO0 gas and is the
&
major source of SO emissions from copper smelters.
^
The range of SO2 emissions from individual smelters in the United States
7
during 1968 was 11,000 to 536, 000 tons per year. The smaller amounts were
emitted from smelters handling weathered copper ores (such as basic copper
carbonates) or native copper; the larger amounts were caused by roasting
ores high in sulfides or pyrites.
5-7
-------
5.1.3 Lead Smelter Emissions Control
The most important ore of lead is galena (PbS). The lead ore concentrate
is converted to oxide before reduction to metal. This is commonly done by
sintering, wherein the following reaction takes place:
2 PbS + 3 00 (air)—-2 PbO + 2 SO0
^j fj
Lead concentrates and lead-bearing residues and fluxes are spread over a
continuous belt of grated pallets and ignited as the mass moves over a windbox.
Oxidation of the sulfide furnishes the required roasting heat. Most of the
sulfur is removed. The thickness and composition of the charge must be
controlled so that it can be handled properly by the machine and will produce a
roast with the required physical characteristics. The oxide is reduced to
crude lead in a blast furnace, to which the sinter, together with coke, is
charged. The crude lead from this furnace requires extensive further refining
and silver, bismuth, and antimony are often important by-products.
Sintering steps produce appreciable sulfur oxide. The air aspirated
through the burning bed of galena concentrate has an exit SO0 content in the
j-i
Q
range of 1.5 to 5 percent by volume. These gases can be fed to a contact
sulfuric acid plant, after preliminary removal of dust and mists. If the SO
£t
feed concentration is too low, it can be raised by burning pyrites or sulfur.
Emissions from individual lead smelters in the United States during 1968
7
ranged from 2000 to 82, 000 tons of SO0 per year. No control cost data were
^
found in the published literature.
5-8
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5.1.4 Zinc Smelter Emissions Control
The metallurgy of zinc is unique among tonnage metals in that the boiling
point of zinc (907 C) is lower than the temperature of reduction to metal
(1100° to 1200°C). The product of the reduction is a metal vapor.
Zinc occurs in the United States mainly as sulfide ores, the most common
one being sphalerite (ZnS). This ore must be roasted and converted to an
oxide before reduction to metallic zinc.
ZnS + -| 02 (air)—-ZnO + SO2
The roasted and/or sintered charge is reduced with coke to zinc metal.
The metal is then purified in a high-temperature distilling tower. In this way,
cadmium with its lower boiling point, lead with its higher boiling point, and
other impurities are removed from the zinc. The reduction of sinter to metal
can be done in several ways, but little if any SO0 is emitted in the reducing
-------
Table 5-2. SULFUR DIOXIDE CONCENTRATIONS
FROM ZINC ROASTERS
Roasting furnace SO0 in exit gas, volume %
4J
Multiple hearth 5-7
Fluid bed 6-12
Flash 6-8
Sintering 4.5-7
5-10
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on sulfur burner gas, or with combinations of these gases. Dust in the roaster
gas amounts to about 15 percent of the roaster feed and is removed by a
cyclone, an electrostatic precipitator, and a scrubbing tower, followed by an
electrostatic mist precipitator and a sulfuric acid drying tower. All this
equipment is required to make the roaster gas suitable for feeding to the con-
tact sulfuric acid plant. The dust removed from the roaster gas is returned
to the zinc-ore-concentrate pelletizing system. The gaseous effluent from
the sulfuric acid plant contains less than 2000 parts per million of SO? by
volume.
The capital cost of a 200-ton-per-day sulfuric acid plant handling gases
from a zinc roaster plant, adjusted to 1968 costs, is over $1. 8 million. If
the SO2 is assigned no value, the total cost of the acid would be about $10.70
per ton. A comparison of total sulfuric acid costs from this zinc roaster gas
plant and a 200-ton-per-day, sulfur-burning acid plant suggests an
advantage of over $10 per ton for acid from the roaster gas plant, based on
1968 sulfur price levels.
These rough estimates are based on costs given in the reference and
cannot be used to generalize.
5-11
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5.2 PETROLEUM REFINERIES
5.2.1 Introduction
As of January 1968, there were 269 operating petroleum refineries in the
United States with capacities ranging from a few thousand to 430, 000 barrels
12
per day. In some urban areas of the United States there are several
refineries with a combined crude processing rate of over 800,000 barrels per
day. Refinery processing during 1966 resulted in SO0 emissions estimated at
t.t
1, 583, 000 tons, or approximately 5. 5 percent of total SCL emissions in the
United States.13
In some areas, considerable effort has been made to control SO
£
emissions. In many instances, modern refinery processes have, of necessity,
integrated air pollution control into their operations.
Sulfur removal from some refinery streams is a part of refining. It
would be desirable to remove all sulfur compounds before any processing of the
crude begins, but since this is impractical, sulfur is removed in subsequent
steps throughout refinery processing. There are several reasons, other than
air pollution control, for removing sulfur from intermediate fractions and
products of crude oil. Sulfur removal reduces corrosion, odor, number of
breakdowns, catalyst poisoning, and gum formation and improves octane
rating, color, and lube oil life.
5.2.2 Petroleum Refining Processes
Most oil refinery processing units are made up of at least five main types
of equipment: heaters, reactors, vessels, heat exchangers, and pumps. The
arrangement, type, and quantity of this equipment are set up to fit the
5-12
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particular function desired, such as separation, conversion, treating, or
blending. Separation is accomplished by distillation; conversion by cracking
and reforming; and treating by various methods, the most popular of which is
hydrogen treating.
5.2.2.1 Distillation - Separation of a mixture of light and heavy hydrocarbons
into various fractions is usually done by distillation. The first step in
refining crude oil to gasoline is atmospheric distillation, whereby crude oil is
separated into gas, naphtha, diesel oil, gas oil, and topped crude. Further
refining of fractions will again entail the use of distillation equipment. Almost
every major processing unit in the refinery has, as a part of its unit, a
distillation section.
5.2.2.2 Cracking or Pyrolysis - Conversion, by cracking large hydrocarbon
molecules into smaller ones, is done by the application of heat and/or
catalysts. At the same time some of the cracked molecules recombine
(polymerize) to form larger molecules; thus, a synthetic crude that can be
separated into gaseous hydrocarbons, gasoline, gas oil, and fuel is formed.
A large selection of materials ranging from ethane to heavy crude residuums
can be cracked.
The two kinds of cracking are thermal and catalytic. Thermal cracking,
using high temperature and pressure, is generally applied to the cracking of
distillates heavier than gasoline. Delayed coking, fluid coking, and visbreaking
are examples of thermal cracking processes. Catalytic cracking uses high
temperatures and chemical catalysts to crack the molecules into synthetic
crude. The result is a faster and more complete breakdown of heavy
5-13
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feed-stock than is accomplished by thermal cracking. There are only two
methods of catalytic cracking in general use: the more popular, fluidized-bed
method typified by a fluid catalytic cracking unit (F. C. C.) and the less
commonly used moving-bed method, as used by Thermofor catalytic cracking
units (T.C.C.).
5.2.2.3 Hydrocracking - The hydrocracker uses a fixed-bed catalytic
reactor, wherein cracking occurs in the presence of hydrogen, under
substantial pressure. The principal functions of the hydrogen are to suppress
the formation of heavy residual material and to increase the yield of gasoline
Ifi
by reacting with the cracked products. High-molecular-weight, sulfur-
bearing hydrocarbons are also cracked, and the sulfur combines with the
hydrogen to form hydrogen sulfide (ELS). Therefore, waste gas from the
hydrocracker contains large amounts of H S, which can be processed for
^
removal of sulfur.
5.2.2.4 Reforming - Catalytic reforming units are used to produce higher
octane gasoline by rearranging the molecular structure of straight run and
light naphtha feedstock. The reaction is achieved in a fixed-bed catalytic
reactor by reactions of the feedstock in the presence of hydrogen over a
platinum catalyst. Hydrogen, produced as a by-product, is partly recycled to
the reactor, with the excess used in hydrogen treating units for sulfur removal
and product improvement.
5.2.2.5 Polymerization and Alkylation - Gasoline is produced in polymeriza-
tion and alkylation units by combining gaseous hydrocarbons. Gaseous olefins
will combine to polymerize into high-octane gasoline. Alkylation combines
5-14
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olefins with isobutanes. These processes operate as closed systems and do not
cause a significant air pollution problem under normal operating conditions.
5.2.2.6 Hydrogen Treating - The hydrogen treating process consists of
bringing oil charge stock and hydrogen into a fixed-bed, catalytic reactor at
an elevated temperature and pressure. Under the influence of the catalyst,
hydrogen reacts with sulfur, nitrogen, oxygen, and olefinic hydrocarbons to
i fi
form removable H S, ammonia, saturated hydrocarbons, and water. In
£
addition, metals are reduced to elemental form. Large quantities of hydrogen
are required if any extensive use of hydrotreating and hydrocracking is done.
The process gas from this unit is rich in hydrogen, hydrocarbons, and
H9S. Hydrogen sulfide can be extracted from this stream and converted to
&
elemental sulfur or sulfuric acid.
5.2.2.7 Hydrogen Production - Hydrogen is now of extreme importance in
refining. For example, Kuwait National Petroleum is building what is
17
considered the first "all-hydrogen" refinery in the world. It includes
residuum hydrogenation and hydrotreating. Table 5-3 shows the components of
this 95, 000-barrel-per-day refinery.
The hydrogen manufactured by the hydrogen plant, plus whatever by-
product hydrogen is produced by the catalytic reformer, is used in the two
hydrocrackers, four desulfurizers, and the catalytic reformer, for the purpose
of product upgrading and feedstock preparation. In doing this, large amounts
of organic sulfur compounds are hydrogenated to H S and contained in the sour
Li
gas stream coming from these units. This H S is removed from the gas stream
Li
in an extraction system and then converted to elemental sulfur in the sulfur
5-15
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Table 5-3. CAPACITY OF THE COMPONENTS OF A 95, 000-BARREL-
PER-DAY REFINERY
Component
Capacity
Crude unit
Catalytic reformer
H-Oil unit (hydrocracker)
Isomax unit (hydrocracker)
Four unifiners (desulfurizers)
Hydrogen plant
Sulfur recovery unit
95, 000 bbl/day
15,820 bbl/day
23,460 bbl/day
14,400 bbl/day
80, 000 bbl/day
140 million cf/day
570 It/day
5-16
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recovery facility. Therefore, the importance of the extensive use of hydrogen
is not only reflected in product upgrading and feedstock preparation but also
in the production of a large amount of recovered sulfur from processing a
sour crude.
5.2.3 Sulfur Dioxide Emissions
If controls are not applied, emissions of SO from refinery operations
^
can be appreciable. For example, it has been shown that if all H S produced
£
in Los Angeles County from processing approximately 650, 000 barrels of
crude per day were burned instead of being controlled, 800 tons of SO would
u
be discharged into the atmosphere per day. Furthermore, 200 to 300 tons of
SO0 would be emitted per day by burning acid sludge that comes from sulfuric
Lt
acid treating.
5.2.3.1 Heaters and Boilers - In many instances refinery SO2 emissions
come from burning organic sulfur compounds contained in the fuel used as
energy sources for process heaters and refinery boilers. Almost every major
processing unit in an oil refinery includes one or more process heaters. Such
fuels as refinery gas, natural gas, heavy residual fuel oil, and coke are used.
Sulfur-dioxide flue-gas concentrations, ranging from 700 to 1000 parts per
18
million, resulting from burning heavy residual fuel oil have been measured.
The SO flue-gas concentration varies, depending mainly upon the sulfur
£
content of the fuel and, to a lesser extent, the operating conditions.
5.2.3.2 Catalytic Regeneration - A catalyst, after extended use, loses some
of its activity and requires regeneration. Regeneration is accomplished by
applying a controlled volume of air to burn off coke deposits at a controlled
5-17
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temperature, which in turn creates an effluent gas containing dust, carbon
monoxide, and SCL.
Catalyst can be regenerated continuously as in the Fluid Catalytic Cracker
(F.C.C) or the Thermofor Catalytic Cracker (T.C.C.), where the catalyst is
continuously removed from the reactor, regenerated in a large vessel, and
recycled to the reactor. The F. C. C. regenerator is one of the larger single
sources of SCL emissions in an oil refinery. Tests made in Los Angeles
County on six F. C. C. units with a combined fresh feed rate of 156, 000
barrels per day and nine T. C. C. units with a combined fresh feed rate of
69, 000 barrels per day showed emissions of 42 tons per day and 2 tons per
day, respectively. The SO concentration of the F. C. C. flue gas ranged
£
from 308 to 2190 parts per million. The SO0 concentration of the catalytic
A
cracking unit regenerator flue gases can vary over wide limits, depending on
the amount of sulfur in the feed stock and on operating conditions.
In a fixed-bed system, such as a reformer or hydrotreater, the reactor
is periodically taken off stream to regenerate the catalyst. The SO0 emission
^
from regeneration of a fixed-bed catalyst is not significant.
5.2.3.3 Treating - The quantity of sulfur emitted from treating operations
depends primarily on the methods used for handling spent acid and acid sludge,
and on recovery or disposal of H?S. Settling tank vents, surge tanks, water
treatment units, waste-water drains, valves, and pump seals in the treatment
area may be sources of trace quantities of malodorous substances such as
H S and mercaptans.
5-18
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Hydrogen treatment generates large quantities of H S. Unless available
methods are used to remove the H S, it is used as part of the fuel feed to
^
heaters or boilers, which results in the emission of large quantities of SO .
z»
5.2. 3.4 Acid Sludge Disposal - Sludge contains from 25 to 70 percent acid,
the remaining portion being mostly heavy hydrocarbons, alkyl sulfides, and
1 ft
thiophenes. This sludge may be disposed of by burning it as a fuel, and thus
creating large quantities of SO? emissions. There are other methods of
disposal, such as making by-products, processing for acid recovery, and
dumping in the ground or at sea.
5.2.3.5 Flares - Waste gas produced by a refinery can be handled by one or
more flare systems. The sulfur content of the waste gas to each flare system
depends on its source, since it can come from one or more refinery operating
units. The combustible composition of waste gas and the temperature in the
combustion zone determine whether sulfur compounds are sufficiently burned
to SO0 or released in a more odoriferous form. Sulfur dioxide and other
£
injurious substances in hydrocarbon waste gases should be removed by some
type of absorption system before going to a flare. Examples of flare preab-
sorption systems would be SO removal from an Edeleanu treating unit, HF
^
from an alkylation unit, and HC from an isomerization unit.
5.2.3.6 Vacuum Jet Exhausters - Vacuum jets are used to operate a process
vessel at less than atmospheric pressure, to remove hydrocarbon gases from
equipment during shutdowns, and to evacuate the gases from fixed-bed
reactors before regeneration. The steam jet exhauster on the crude-unit
vacuum tower, for example, continuously draws a vacuum on the tower in
5-19
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which the temperature of the heavy residuum may be high enough to cause some
cracking of the organic sulfur constituents into ELS. The H0S, in turn, is
£ £
exhausted by the steam jet exhauster and discharged with the uncondensed
gases. The volume of gas is not great, but it may contain as much as 25
percent KLS, by volume.
5.2.3. 7 Asphalt Air Blowing - Asphalt from the crude unit can be made into
roofing asphalt by subjecting it to air blowing at elevated temperatures. Air
is passed through the charge in the steam-blanketed still at an approximate
rate of 40 cubic feet per minute per ton of charge until the desired hardness
17
is achieved. In addition to sulfur compounds, the effluent gases contain
hydrocarbons and aerosols.
5.2.3.8 Miscellaneous Sources - There are several other refinery sources of
SO0 emissions, such as decoking, air blowing for brightening petroleum
£
distillates, and waste-water treatment.
5.2.4 Control of Sulfur Oxides
Table 5-4 is a compilation of typical refinery sources of sulfur compound
emissions. The specific unit, process gas source, waste gas source, usual
method of disposal, and recommended method of control are shown. Process
gas is defined as that gas produced in a processing unit. It comes from such
units as catalytic cracking units and reformers. Waste gas is the gas
emitted from processing units that cannot be used further. For instance,
crude vacuum tower exhaust gas, which has an insufficient heating value to be
used as a fuel, and emergency relief gas, which is beyond the normal
capacity of vapor recovery systems, are waste gases.
5-20
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5.2. 4.1 Heaters and Boilers - The concentration of SO emitted from heaters
— — ^
and boilers can be lowered by burning low-sulfur fuel oil, low-sulfur process
gas, or natural gas.
Since the demand is now becoming greater for low-sulfur fuel oil, U. S.
refineries may have difficulty selling high-sulfur fuel oil. Consequently,
refineries that make high-sulfur fuel oil in areas of the United States where
9
there are no restrictions limiting the amount of sulfur in the fuel oil will
probably use it in their process heaters and boilers, as a supplement to
burning process gas and natural gas. Some refineries, particularly on the
West Coast, make no heavy fuel oils. The general trend in refinery processing
in this country is toward more conversion of feed stock to distillate oils.
5.2.4.2 Catalytic Regeneration Gases - The removal of SO from the
L — i - i • £
regeneration gases of F. C. C. and T. C. C. units is not practiced at this time;
however, current studies being made on systems for the removal of SO0 from
^
combustion gases in power plants may find that, in the future, these systems
can be used on F.C.C. units because the SO0 concentrations in the F.C.C.
Lt
effluent gas are comparable to those of some power plants. An alternative
method would be to desulfurize the feedstock.
The removal of SO from the regeneration gases of a fixed-bed catalytic
Lt
reactor can be accomplished by caustic scrubbing. Since the volume of gas
during regeneration is limited, and regeneration is required infrequently
(in some instances once and other instances a few times per year, depending
on the type of unit and operations performed), the cost of sulfur removal
would not be high.
5-23
-------
5.2.4.3 Treating - Table 5-5 shows 12 of the many methods of desulfurizing
14
petroleum products and feedstocks. Method 1 shows one way of removing
H S; however, in order to prevent sulfurous emissions when this gas is later
&
burned, the H S in the stabilizer off-gas should be separated from the gaseous
^
hydrocarbon. This can be done by method 8, provided that elemental sulfur
recovery is desired, or by a caustic-wash scrubber. Similarly, Hr,S should
£i
be removed from the stabilizer off-gas resulting from the use of the hot clay
treating process (method 10). Sulfuric acid treatment (method 2) removes
most sulfur compounds, plus some hydrocarbons, to form an acid sludge.
This method is gradually being replaced by other methods. An acid recovery
system, replacing the burning of acid sludge, is one way to alleviate the
problem of large quantities of SCL emissions. Sweetening processes used for
light distillates (methods 3, 4, and 5), remove very little if any sulfur or
sulfurous compounds from the liquid product, but will convert them to a less
deleterious form. Caustic scrubbing, used alone (method 7) or with pro-
moters (method 8), removes mercaptans by chemical reaction. Some of these
caustic treating processes are regenerative. Spent caustic is sometimes sold
to chemical plants for conversion to chemicals. Because of excessive costs
and disposal problems, the use of caustic has been largely replaced by other
methods, except in the removal of trace amounts of acid gases. Hydrogen sul-
fide gene rated in hydrogen treating operations (method 11) should be removed
from the process gas by amine scrubbing or some similar operations. The
cleaned gas can then be used for refinery fuel and the removed H S can be further
£
processed into elemental sulfur or sulfuric acid. If the quantity of H0S is too
^
small to economically justify recovery, it should be caustic scrubbed, with the
5-24
-------
Polys
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5-25
331-543 O - I
-------
residual gas going to an elevated flare or boiler firebox. Considering the
added cost of caustic scrubbing, sulfur recovery seems to be the better choice.
5.2.4.4 Air Blowing of Asphalt - The effluent gas stream from an asphalt
still, containing sulfur compounds, hydrocarbons, odors, and aerosols, is
objectionable if discharged directly into the atmosphere. The effluent stream
may first be water scrubbed to remove some of the hydrocarbons and then
incinerated in a boiler, a heater firebox, or a specially built incinerator. The
combustion of sulfur-bearing gases yields SO .
£
5.2.4.5 Sulfur Recovery Facilities - Sulfur plants and sulfuric acid plants
associated with oil refineries are of considerable importance in the control of
SO emissions. Modern dry refinery methods have greatly increased the
£i
removal of sulfur from crude oil derivatives. Up to 85 percent of the sulfur
in crude oil can be converted to ELS by using modern refinery methods.
For example, in a 100, 000-barrel-per-day refinery processing a
31.2° API* crude oil with 2. 5 percent sulfur content, the total amount of
sulfur in the crude used each day is approximately 330 long tons. The use of
modern processes in such a refinery could result in the production of a fuel
oil containing 1.5 percent sulfur, and the recovery of 250 long tons of sulfur
per day. If a fuel oil of 0.5 percent sulfur were produced, the potential
19
sulfur production would be 285 long tons per day.
It can be seen by referring to Table 5-5 that only a few of the methods
will remove H S. However, if sulfur is to be made from H S, a regenerative
type of HQS removal process should first be used to remove the H S from the
Ll £
*°API - specific gravity scale established by the American Petroleum
Institute.
5-26
-------
sour gas stream. One of these, as shown in the table, is ethanolamine
absorption of ELS. In addition to ethanolamine, there are several other
^j
regenerative absorbents in use. The criteria for the selection of the ELS
removal process and the absorbent are: (1) type of impurities in the gas
stream such as ELS, CO0, RSH, COS, and CS0, (2) impurity concentration,
Lt £ Z
(3) amount of impurity removal desired, (4) acid-gas selectivity required,
23
(5) feed gas volume, and (6) temperature-pressure of feed gas.
In addition to the ethanolamine process, the following processes can
remove H S from gaseous hydrocarbons by a liquid absorption/desorption
u
method: (1) hot potassium carbonate, (2) water washing, (3) seaboard
and vacuum carbonate process, (4) tripotassium phosphate, (5) sodium
phenolate, (6) Giammarco-Vetrocoke process, (7) Catacarb process,
(8) Shell Sulfinol process, (9) Fluor solvent process, and (10) vacuum
u , 20
carbonate.
The use of ethanolamines is an established method for removing H S.
^
Figure 5-2 is a flow chart for such a process. Either monoethanolamine or
diethanolamine in aqueous solution can be used as the absorbent. Hydrogen
sulfide reacts with the amine to form a compound that can be decomposed
by heat.
The hydrocarbon gas (sour gas), rich in H S, enters the bottom of the
absorber. The lean amine solution contacts the gas counter-currently and
absorbs the ELS. The desulfurized gas leaves the top of the column, and the
rich amine solution leaves the bottom of the column and goes through the heat
exchanger into the regenerator column. In the regenerator, ELS is stripped
L4
5-27
-------
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from the rich amine solution by heat and passes out of the tower as a concen-
trated acid gas. The acid gas from the regenerator column is cooled and then
sent to the sulfur plant. The lean amine solution leaving the regenerator
reboiler is cooled and sent to the amine storage tank, from which it will be
pumped back to the absorber to repeat the cycle.
Upset conditions of this unit could result in releases of hydrocarbons and
H0S. The usual procedure in this case is to connect relief valves to a flare
Lt
system, allowing any release of hydrocarbons and H S to be incinerated by the
Zj
flare. Also, during malfunction of the sulfur plant the acid gas flow can be
diverted to the flare system. A well designed and properly maintained sulfur
plant will help to prevent frequent emergency releases of gas to the flare.
Hydrogen sulfide removal systems are most often located at several unit
areas within a refinery. Sometimes the regeneration part of the facility is
located in a chemical company near the refinery. The chemical company
pipes lean amine solution to one or more refinery units where H0S is removed,
^
and the rich amine is piped back to the chemical company. Acid gas is used
by the chemical company to manufacture sulfur.
The Claus process (developed about 1890) is the most widely used method
21
of producing sulfur from refinery H S. The modified Claus process
Zj
(developed about 1937) is based on producing elemental sulfur by first con-
verting one-third of the H S feed by precise combustion with air to achieve
^
the following reaction:
2 ELS + 3 CL -2 SO0 + 2 HQO
5-29
-------
The above products of combustion are then further reacted with the two-thirds
unreacted H_S feed in the presence of a suitable catalyst to form sulfur vapor:
2 H0S + S00 catalyst.aS0 + bSc + cS + 2 H0O
& Zt £ D O £
The letters a, b, and c represent the number of mols of the various possible
21
molecular forms of sulfur vapor.
Sulfur vapor is formed in both the combustion reaction and in the
catalytic conversion reaction; however, regardless of how much sulfur is
formed in the combustion reaction, it can be shown stoichiometrically that the
required amount of oxygen is that quantity which will react with one-third of
22
the H S in the acid gas feed and convert it to SO0. After each reaction, the
Z £
sulfur vapor is condensed to liquid sulfur and allowed to drain to sulfur
storage.
Figure 5-3 shows a typical process flow chart for one type of modified
Glaus sulfur plant. The total acid gas stream enters a waste heat and reaction
furnace where one-third of the acid gas is burned with a controlled amount of
air. The exothermic reaction in the waste heat and reaction furnace is used to
produce steam. Sulfur vapor formed in the primary reaction is condensed in
the No. 1 condenser and drained to liquid sulfur storage. The uncondensed
gases leaving the condenser go to the No. I converter where, with the use of a
catalyst at a controlled temperature, some of the HgS is converted to more
sulfur vapor. The temperature of the converter inlet gas stream is elevated
to the optimum conversion temperature (475 F) by combining with a slip
stream of about 900 F from the hot gas stream of the reaction furnace. The
sulfur vapor, formed by the No. 1 converter, is condensed by the No. 2
5-30
-------
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5-31
-------
condenser. Uncondensed vapors, before entering the No. 2 converter, mix
with a hot-gas slip stream from the reaction furnace. Converter No. 2 vapor
passes to No. 3 condenser and then enters a coalescer for the removal of any
entrained sulfur droplets. From the coalescer the gases go to an incinerator
where the residual tail gas, containing sulfur compounds, is converted to SCL
Li
and diluted with air before the effluent gases are discharged into the
atmosphere.
Several types of catalysts have been used, but bauxite appears to be the
21
most desirable because of low cost, durability, and high activity. The
catalyst-bed thickness is limited since the reaction is exothermic and low
temperatures favor the conversion. It has been shown that a one-stage plant
(one converter) with an excessively thick catalyst bed is not feasible for
23
guaranteed high conversion efficiencies. A one-stage converter plant can
operate with efficiencies up to 85 percent. With two stages, efficiencies have
been reported as high as 95 percent. From an air pollution point of view, it
is imperative that all plants be designed with at least two and possibly three
catalytic converter stages.
For a minimum discharge of sulfur compounds to the atmosphere, and a
maximum conversion to sulfur, the initial ratio of H S to SO0 should be
j^ «£
maintained at the stoichiometric ratio of 2 mols of H S to 1 mol of SO . To
&4 £l
maintain this ratio, the correct amount of air must be metered into the
reaction furnace. Figure 5-4 shows what happens when the correct amount of
23
air is not supplied. For example, if the initial ratio of H S to SO is not at
Lt A
the desired ratio of 2 and is instead 1.3, then the initial ratio will become
5-32
-------
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5-33
-------
lower from point to point in the plant as the conversion increases until it
22
theoretically approaches zero at 84. 8 percent maximum conversion.
Eecently, there has been introduced on the market a costly and sophisti-
cated instrumentation system that will automatically adjust the flow of air to
maintain optimum operating conditions. For larger sulfur plants, it has been
stated that the amount of additional sulfur manufactured by the use of this
24
instrumentation will result in a payoff of the instrumentation in a few years.
A sulfur plant should be designed to prevent as many operating
difficulties and shutdowns as possible, and standby equipment should be
installed. For example, one refinery on the East Coast built a sulfur plant
with two reaction furnaces to provide for a range of practical operating flexi-
bility. This arrangement also allows periodic servicing of one reaction
furnace while the other unit remains in operation.
5.2.5 Sulfur Plant Costs
Large sulfur plants operate more economically than small ones.
Table 5-6 shows that there is a large potential source of sulfur, either from
desulfurizing the fuel oil or from converting it to distillate fuel oil.
Table 5-7 shows new construction in the United States and other areas to
25
recover this sulfur from oil refineries and natural gas producing areas.
Costs, as shown, do not indicate whether the H S removal facility iis included
^
with the sulfur recovery plant.
In the last 10 years, the recovery of sulfur in the United States has grown
very rapidly and has reached 25 percent of the free-world production.
5-34
-------
Table 5-6. DISPOSITION OF SULFUR IN NET PRODUCTS
CONSUMED IN UNITED STATES - 1962
(excluding Rocky Mountain Region)
Gasoline
Kerosine (including
commercial jet)
Military jet fuel
Distillate fuel oil
Residual fuel oil
Asphalt
All other
Totals
Net
product Sulfur
consumed, content, Sulfur,
1000 bbl % tons/day
4,166 0.043 228
439 0.079 49
291 0.067 27
1,909 0.213 599
1,456 1.428 3,625
297
793
9,356 4,528
Approximate
% total
sulfur
burned
5.0
1.16
0.6
13.2
80.1
100.0
5-35
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The smallest sulfur plant that is justified by the economics of sulfur re-
covery depends on a number of variables. Units have been built and operated
19
economically with as small a capacity as 4 tons per day. In areas where
local air pollution regulations limit the amount of sulfurous gas emissions to
the atmosphere, the least expensive air pollution control method may be a low-
capacity sulfur plant. Fortunately, even the smallest modern refineries are
capable of producing enough H0S to support an economically operated sulfur
Li
plant.
Typical sulfur plant costs are shown in Table 5-8 for 20- and 40-ton
plants. These estimates are not firm since costs vary with plant location and
existing facilities.
Table 5-8. TYPICAL TWO-STAGE SULFUR PLANT COSTS
Plant size:
Capacity, long tons/day
Production, long tons/yr
Investment:
Plant cost
Working capital , 15%
Total investments
Operating costs, $/long ton sulfur
Depreciation, 10% of cost
Taxes and insurance, 3.0%
Total fixed costs
Operating labor
Supervision and clerical
Maintenance
Supplies, estimated
20
6,570
$ 287,000
$ 43,000
$ 330,000
4.30
1.29
5.59
4.68
3.72
4.02
0.54
40
13,140
$ 330,000
$ 50,000
$ 380,000
2.52
0.75
3.27
3.08
2.16
2.86
0.54
5-39
-------
Table 5-8 (continued). TYPICAL TWO-STAGE SULFUR PLANT COSTS
Payroll, overhead
Water
Power and fuel
Total direct costs
Total cost at plant, $/long ton
Credit for steam, $/long ton
Net cost at plant, $/long ton of sulfur
1.56
0.42
0.75
15.69
21.28
1.00
20.28
1.02
0.42
0.75
10.83
14.00
1.00
13.00
The estimated costs of two-stage sulfur plants operated on an H S-
26
rich stream is indicated on the curve in Figure 5-5. A two-stage plant
is ordinarily capable of operating with an HS-to-sulfur conversion efficiency
Li
of 90 percent.
10.0
5.0
o
-o
1.0
8 0.5
10 50 100 500 1000
SULFUR, long tons/day
5000
Figure 5-5. Estimate of investment cost for two-
stage converter sulfur plant.
5-40
-------
5.3 SULFURIC ACID PLANTS
5.3.1 Introduc tion
Su If uric acid production has grown rapidly in the past few years, as
shown in Table 5-9. The 1967 production of over 28 million tons of sulfuric
acid (largest mineral acid industry in the United States) resulted in the atmos-
pheric emission of approximately 600, 000 tons of S0?.
Tight sulfur supply may, however, limit the production of sulfuric acid
in the future. The modern trend is toward construction of giant plants. A
2000-ton-per-day, single-train sulfuric acid plant has recently been built.
Several others, each of which will produce more than 1500 tons of acid per
day, are under construction.
5.3.2 Sulfuric Acid Manufacturing
The principal raw materials used for the manufacture of sulfuric acid
are elemental sulfur, sulfides (iron, copper, and zinc), H2S from sour gases,
and spent sulfuric acid from various chemical processes.4 Elemental sulfur
is the raw material from which about 70 percent of all sulfuric acid produced
in the United States is derived.
Two processes are currently used to produce sulfuric acid, the contact
process and the almost obsolete chamber process. Fundamentally, these
processes are similar: both initially burn sulfur, with a controlled amount of
excess air, producing S02 gas; both catalytically oxidize the S00 to SO • both
^ o
must control the heat balance of the reaction to secure the desired equilibirum;
and both use an absorber as the final step before the tail gases enter the
atmosphere. The chamber process produces weaker acid (77.7 percent) and
5-41
331-543 O - 69 - 16
-------
Table 5-9. SULFURIC ACID PRODUCTION (100% basis)
n
(10 tons)
1963 1964 1965 1966 1967 (estimated)
Contact process 19.4 21.4 23.5 27.5 27.3
Chamber process 1.5 1.5 1.3 1.2 o.9
Total 20.9 22.9 24.8 28.7 28.2
5-42
-------
uses nitrogen oxide gas as a catalyst; the contact process, which uses a va-
nadium pentoxide catalyst, produces 98 to 100 percent acid and various grades
of oleum.
Since the chamber process is obsolete, no plants of this type have been
built for many years. A flow chart of a typical sulfur-burning contact plant is
18
shown in Figure 5-6. Dry air is used to burn sulfur to SO with a control-
^
led amount of excess air. The SO , at a concentration of 7 to 10 percent,
Li
passes through a waste-heat boiler and gas filter before entering a four-stage
converter. Each stage of the converter consists of a fixed bed of pelletized
vanadium pentoxide catalyst. When the gas passes through this catalyst, SO
Li
reacts exothermically with excess air to form SO . Heat exchangers are
O
used to lower the temperature of the gas to its optimum conversion temper-
ature before the gas enters the outer catalyst stages. Rarely are more than
four stages used. Sulfur trioxide gas mixture leaving the fourth stage of the
converter is cooled to approximately 475 F and enters the absorber, where
the SO3 is almost all absorbed by counter-current contact with 98 to 99
percent sulfuric acid. Sulfur dioxide is not absorbed in this solution. The
tail gas from the absorber with unconverted SO , unabsorbed SO , and acid
Z o
mist is normally discharged directly into the atmosphere.
When oleum is produced, the converter gases containing 7-1/2 to 10-1/2
percent SO are absorbed in 98 percent sulfuric acid circulated through an
o
oleum tower until the desired acid strength is obtained. Because of the
5-43
-------
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5-44
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free SO0 content of oleum, there is an increase in SO emissions to the
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atmosphere when oleum is produced.
5.3.3 Emissions
The extent of SO emissions in large measure depends upon efficient
LA
operation and a plant design that ensures a high rate of conversion of SO to
ZA
SO and subsequent absorption. The heart of the contact plant is the converter,
o
where a number of factors determine the quantity and concentration of SO
LI
emissions. Some of these factors are: (1) concentration of the entering SO ,
LA
(2) ratio of oxygen to SO0, (3) number of catalyst converter stages, (4) arrange-
£
ment and volume of catalyst, (5) catalyst efficiency, (6) gas uniformity, (7)
4
impurities in the entering gas, and (8) temperature control. Normal oper-
ation will obtain an SO conversion efficiency of 96 to 98 percent in a well
LA
designed, modern, contact plant, and will result in emissions of from 25 to
40 pounds of SO per ton of acid produced, as shown in Figure 5-7. Exit gas
£
concentrations of SO in well operated plants vary from about 2000 to 3500
&
4
parts per million, as shown in Figure 5-8. Under certain operating condi-
tions, e.g. , during startups, when the catalyst has not been sufficiently pre-
heated, or under high-capacity operations or plant upsets, these concentrations
could exceed 5000 parts per million as shown in Figure 5-8. Emissions from
chamber plants vary from 25 to 30 pounds of SO2 per ton of acid produced.
Concentrations of sulfuric acid mist in the exit gas range from 3 to 15 milli-
grams per standard cubic foot for a contact plant, and 5 to 30 milligrams per
5-45
-------
DOUBLE
CONTACT
PROCESS
94 96 98 100
CONVERSION OF S02 TO S03, %
Figure 5-7. Sulfur dioxide emissions from con-
tact plants at various conversion
efficiencies (per ton of equivalent
100% H2S04 produced).
7.0 80 9.0 10.0 11.0 12.0
VOLUME % S02 ENTERING CONVERTER
Figure 5-8. Concentration of S02 in exit gas at
various conversion efficiencies.
5-46
-------
standard cubic foot for a chamber plant. The concentration of unabsorbed
SO3 in the exit gas from a contact plant varies substantially, but is usually
about 0. 5 milligram per standard cubic foot. Sulfur trioxide mist, upon
contact with atmospheric moisture, is hydrated and forms a visible, white,
acid-mist plume.
5.3.4 Control Methods for Sulfur Oxides
Any factor that increases the conversion of SO to SO will naturally
Z o
reduce SO emissions. Conversion efficiencies greater than 99.7 percent
u
28
have been claimed for the Bayer double-contact process. This process is
based on the principle that the conversion of SO to SO is improved if the
L* O
equilibrium is shifted by absorbing the SO formed in the early conversion
O
stages and subjecting the remaining SO -bearing gas to a final conversion. In
&
this process, the typical conversion system is modified by adding an inter-
mediate absorbing tower just ahead of the fourth catalyst conversion stage.
An additional heat exchanger also is required to cool the gases before they
enter the intermediate absorber. The overall degree of conversion is improved
because the remaining SO , freed from most of the SO , encounters a very
£ O
high degree of conversion when once more reacted in the final fourth stage.
28
Figure 5-9 is a flow chart of the double-contact process. Several
double-contact plants have been in operation in Europe since the first one was
5-47
-------
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5-48
-------
installed in 1964. The double-contact system could be adapted to an existing
contact plant; however, installation would be very expensive and has not yet
been done in this country.
A similar scheme, called the Burkhardt S.A. process, also employs
intermediate absorption. Burkhardt S.A. claims efficiencies of 99.0 to 99.6
29
percent in plants using brimstone sulfur as raw material. This efficiency
range will result in exit SO concentrations of 500 to 1000 parts per million,
^
No known installations of this process are presently in operation.
The advantage of the double contact and Burkhardt S.A. processes,
beyond the reduction of SO emissions, is that a greater conversion capacity
£i
can be obtained. This is accomplished not only by the higher conversion
efficiency but also by allowing a higher concentration of SO to enter the
Li
converter. The double-contact plants used in Europe, instead of operating
with 6.5 to 7 percent SO from pyrites, now operate with up to 10 percent
Zi
28
SO inlet concentrations.
^
Cost data show that the additional equipment investment is compensated
28
by smaller equipment and higher sulfuric acid yields. Additional capital
expenditure of 10 to 15 percent is required to increase conversion efficiency
from 98 percent in a typical new contact plant to 99.5 percent in the double-
30
contact plant. In evaluating the economics of a double-contact plant versus
a typical contact plant, it is generally estimated that the additional revenue
obtained from increased production achieved through higher yields will provide
5-49
-------
a payout period of about 5 years for the additional capital expenditure required
for a double-contact plant. The payout period would be further decreased if
a higher initial SO concentration were used. For instance, a 140,000-ton-
£t
per-year sulfuric acid plant operating at a conversion rate of 98 percent
would emit about 1750 tons of SO per year; with a double-contact conversion
£
of 99. 5 percent the plant would emit about 420 tons of SO2 per year and pro-
duce more than 2000 additional tons of sulfuric acid.
A number of gas scrubbing systems are also available for removing
SO . The ammonium sulfite-bisulfite scrubbing system pioneered years
L±
ago at Trail, British Columbia, has reduced SO in the tail gas from a high
/di
as 0.9 percent to 0.03 percent. Recently, Dutch State Mines has spent
$420,000 on a similar plant for the purification of tail gases resulting from
the production of sulfuric acid and oleum. The DSM control system consists
of passing the tail gases through an ammonia solution that retains 95 percent
of the SO . The resulting ammonium bisulfite solution is used for the pre-
Zj
31
paration of caprolactam. Scrubbing systems reduce plume bouya.ncy and may
cause a visible plume due to water vapor.
Sulfur trioxide, sulfuric acid mist, and spray in the exit gas can be
controlled by a number of devices of varying costs and efficiencies, Some of
these are wire-mesh mist eliminators, fiber mist eliminators, electrostatic
precipitators, and packed bed separators. For a description of mist
eliminators, refer to Control Techniques for Particulate Air Pollutants.
5-50
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5.4 STEEL MANUFACTURING
5.4.1 Introduction
An integrated steel plant has coke manufacturing, blast furnace, and
steel furnace facilities. Iron ore, which is received in the form of impure
iron oxide, is reduced in the blast furnace to form metallic iron. Combustion
of coke provides the reducing atmosphere in the furnace. The metallic iron
(pig iron) is further refined to steel by reducing the impurities and adjusting
the alloy content to specified levels. Pig iron is usually refined to steel in
open-hearth furnaces (oxygen lanced and non-oxygen lanced), basic oxygen
furnaces, and electric arc furnaces. In both blast furnaces and steel making
furnaces, a slag is formed which floats on the molten metal and removes the
impurities.
Sulfur dioxide emissions from steel plants are produced primarily from
sintering, coke manufacture, and combustion operations.
5.4.2. Sintering
Agglomerating processes are used on blast-furnace feed for beneficiating
ore and salvaging recovered dust. The primary purpose of agglomeration is
to improve the permeability of the blast-furnace burden, hence improving the
gas-solid contact and rate of reaction, and reducing the coke consumption. A
secondary purpose is to improve the movement of the burden in the blast
furnace as melting progresses and, thus, reduce the quantity of dust emitted
from the furnace. Sintering and pelletizing are the primary types of
5-51
-------
agglomerating processes used on iron ore. Sintered materials include iron
oxide fines from cyclones and electrostatic precipitators, mill scale from
metal working operations, metal turnings, and light scrap. Fluxes are some-
32
times added for better control of the properties of the sinter. Adding
limestone flux to the sinter increases hot metal production and decreases
coke consumption; raw limestone fed to the blast furnace is, of course,
correspondingly decreased.
Sintering is done on a belt of perforated pallets moved by sprockets
about 100 feet apart. Iron ore fines and coke breeze, or coal, are placed
on the pallets, and the charge is ignited as it passes through a short ignition
section of the furnace. Combustion air is pulled downward by a fan, through
the burning charge, through the perforations in the steel pallets, into the
windbox, and in most cases out the stack. The coke burns out of the charge,
and the hot clinker is removed from the belt and used for blast-furnace feed.
Sulfur emissions from sintering come from the iron ore and the coke.
Iron ores used in the United States are quite low in sulfur, usually under 0.03
percent. Coking coals usually contain less than 1 percent sulfur, about 30
percent of which is liberated by coking. The sintering operations may remove
35
as much as 70 percent of the sulfur in the total charge. Within limits
sintering is a good blast-furnace feed-desulfurizing procedure, especially
for high-sulfur charges. Most of the sulfur entering the blast furnace is
reduced to sulfide and combines with the slag. The blast furnace is operated
5-52
-------
to minimize the sulfur content of pig iron. Hydrogen sulfide is liberated from
the slag, and some of the slag sulfide content is gradually oxidized to SO by
ambient oxygen.
5.4.3 Coke Ovens
Iron and several other important metals are recovered from their ores
by high-temperature reduction. Wood charcoal was once used as the reducing
agent, but it has long since been replaced by coke, which is now the main
metallurgical reducing agent. Production of a ton of pig iron from a blast
36
furnace requires about 0.7 ton of coke. About 90 percent of the United
37
States coke output is used in metallurgical operations.
Coke is the solid material remaining after distillation of certain
bituminous coals in the absence of air. Because sulfur is very deleterious to
the quality of steel and is difficult to remove in blast furnace or refining
operations, low-sulfur coals are used whenever available and, indeed,
command a premium price for metallurgical purposes.
Conventional coking is done in long rows of slot-type coke ovens into
OQ
which coal is charged through holes in the top of the ovens. Coke oven gas
or other suitable fuel is burned in the flues surrounding the ovens, to furnish
heat for coking. Flue temperature is about 2600 F and the coking period
37
averages 17 to 18 hours. At the end of the coking period, incandescant
coke is pushed out of the furnace into quenching cars and carried to a quench-
ing station, where it is cooled with water sprays.
5-53
-------
Volatile matter from the distillation contains materials ranging from
hydrogen and methane to high-molecular-weight materials such as tars. In
addition to hydrocarbons, organic compounds of sulfur and nitrogen are
present. Because the coke oven environment contains strong reducing agents,
sulfur is present as H S and in other reduced forms, such as carbon disulfide.
£
Tars are separated from the hot coke-oven-gas stream by condensation. Am-
monia and organic gases are removed by water sprays and by absorption in
sulfuric acid. Benzene homologues are removed by absorption in straw oil.
After removal of by-products, the resulting coke-oven flue gas consists mainly
of hydrogen, methane, and carbon monoxide. Up to 50 percent of the sulfur in
the original coal is volatilized, and much of it remains in the coke-oven-flue
gas unless removed by special treatment.
The usual distribution of the sulfur from the original coal to coke oven
39
products is shown in Table 5-10: The debenzolized coke-gas may contain
as much as 0. 7 percent H S by volume, and this gas will generate S>O when
2 ^
used as fuel.
Pyritic sulfur in coal is reduced in the coke oven to form H S:
£1
heat
FeS + organic -FeS + H S
2 ^
Therefore, pyrite removal from coal is an aid to reduction in emissions of
sulfur oxides from subsequent combustion of coke-oven gas.
5-54
-------
36
Table 5-10. DISTRIBUTION OF SULFUR IN COKE OVEN PRODUCTS
% of original
Coke oven products sulfur in coal
Coke 50 - 65
Gas (as H S) 25 - 30
Ll
CS , thiophene, and other
£i
organic compounds 1 - 1.5
Tar and ammonia liquor 24 - 3.5
5-55
-------
In a coke plant, SO emissions originate from the fuels burned to heat
^
coke ovens (including coke-oven gas) and from leaks around the ovens. Oven
leaks release gases containing sulfur compounds. The leaking gases are at
high temperatures so that when they issue into the air, they burn immediately
to form SO from any sulfur compounds present. SO is also emitted when
Lt &
the incandescent coke is pushed from the oven and is transported to the quench-
ing tower. Most of the sulfur in the coke is released into the slag when the
coke is subsequently used in the blast furnace.
Escape of gas from coke ovens is caused by charging coal, removing
coke ("pushing"), and by leaks at many points around the ovens. Control of
gaseous emissions, therefore, depends upon speed, organization, and main-
tenance relative to oven operations, and coke-oven-gas treatment to remove
sulfur compounds before using the gas as fuel.
Coke oven gas contains 300 to 500 grains of sulfur per 100 cubic feet of
gas, or 0. 5 to 0.8 percent sulfur by volume, mainly as H S. Combustion of
Zt
this gas results in SO emissions. Various methods have been used to remove
£
H S from coke-oven gas. One method involves passing the coke-oven gas
^
40
through a sodium carbonate absorber. The resulting solution is regenerated
by passing through a heated vacuum tower. The sulfur content of the gas can
be reduced to about 50 grains per 100 standard cubic feet by this method if the
CO content for the coke-oven gas is relatively low. In the past, stripped H S
Lt £
was often vented, or burned to SO . Another method for disposing of the
5-56
-------
stripped H S is to utilize the burned gas for feed to a sulfuric acid plant, or to
£
41
add it to the main gas feed of a sulfuric acid plant. Preliminary treatment
is generally necessary to remove impurities such as hydrogen cycanide.
A second coke-oven-gas treating process removes H S by absorption in
£1
41
sodium thioarsenate. The rich thioarsenate solution is then heated and
sent to a second tower, where the solution is regenerated with air and ele-
mental sulfur is eliminated. Another process for H S removal involves
^
scrubbing the gas with an alkaline solution of anthraquinone and sodium
42
vanadate. The H S is oxidized to elemental sulfur, and the solution is
Li
regenerated by oxidation with air. No cost data were found pertaining to
coke-oven operation or gas cleaning.
Slot-type coke ovens currently being designed include the following
features designed to speed operations and minimize leaks:
1. Better designed and thinner-walled heating flues to improve
heat transfer and minimize cool spots and undercoking. This
results in a cleaner pushing operation.
2. Improved refractories with less spalling and cracking. These
refractory defects cause warping of metal furnace parts, gas leaks
into flue systems and chimneys, and voids, which fill with under-
coked coal and cause smoke during pushing.
5-57
331-543 O - 69 - 17
-------
3. Gas-tight, self-sealing oven doors, which no longer require
manual sealing with clay.
4. Mechanical cleaners or self-sealers for doors and for top-
charging hole covers. A few grains of sand on a metal seat can
cause appreciable leakage of hot gases.
5. Sealing sleeves for levelling bars. Levelling bars are used
to even out the oven charge to allow free passage of gas over the
charge into the gas collector main.
6. Mechanical removal of top coal-charging lids and means to
charge all three holes of an individual oven rapidly and sim-
ultaneously, with gas recovery mains in operation.
A method for enclosed pipeline charging of preheated coal is also being
developed. An enclosed system eliminates the possibility of emission during
charging.
It is evident that emissions from coke ovens can actually be reduced by
good organization and planning of operations, proper scheduling, careful
training of operators in battery cleanliness and attention to detail, and in-
centives for smokeless operation.
Efforts have been made to develop a satisfactory continuous coking
operation because continuous operations are inherently tighter and more
easily controlled. One process investigated is fluid-bed pyrolysis designed
43
to upgrade sub-bituminuous coals. The char produced might be briquetted
5-58
-------
for blast furnace feed. Continuous coking has been carried out to a limited
extent in a manner similar to belt sintering, in which the amount of air passed
through the coal is sufficient to cause combustion of the volatile matter with-
out undue combustion losses of coke. Currently, however, no practical
substitute for the slot coke oven exists.
Coke is still produced in beehive-type ovens in the United States on a
very limited scale. Because this obsolete process does not recover any of
the volatile gases generated in the coking process, it causes considerable air
pollution. The only practical control method is to replace the ovens with
well-designed slot-type ovens with by-product gas recovery systems.
5-59
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5. 5 PULP AND PAPER MILLS
5.5.1 Introduction
Pulp and paper production is one of the ten largest industries in our
country. Per capita demand for paper products is nearly 530 pounds per
year. 45 The manufacture of paper and related products can be divided into two
phases, pulping of wood and production of paper from pulp.
The manufacture of paper from pulp ordinarily results in only small
quantities of atmospheric pollutants.
In the pulping process, wood of various types is reduced to fiber, some-
times bleached, and then dried in preparation for making the final product at
the paper mill. Most pulp mill processes use some type of cooking liquor to
dissolve lignins in the wood and free the wood fibers. In many cases, to make
this process economical, spent cooking liquor is recovered, usually by some
process involving combustion. It is mainly in recovery processes that poten-
tial air pollutants are generated. The major pollutants from pulp mills are
participates, odorous sulfur compounds (HgS, methyl mercaptan, dimethyl
sulfide, dimethyl disulfide, and other organic-sulfur compounds), and SO2-
Which pollutants are emitted in significant amounts depends on the type of
recovery process employed and the degree to which control equipment is used.
There are three major pulping and recovery processes used in the United
States (sulfate, sulfite, and semichemical), and they account for nearly 80 per-
cent of the pulp produced in this country. The remaining 20 percent of the
pulp is produced by a number of small mills using various specialized processes.
Table 5-11 lists these processes, the quantity of pulp produced by each, and
their potential atmospheric emissions.
5-60
-------
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5-61
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The sulfate or kraft process has created the greatest pulp manufacturing
air pollution problem, mainly because of the large quantity of visible particu-
late and the highly odorous nature of the sulfur compounds emitted. Sulfur
dioxide emissions from the sulfate process are minor, but those from the
sulfite and semichemical processes are potentially major. Sulfur dioxide
emissions can be controlled and, in the case of the sulfite and semichemical
processes, provide an economic benefit from sulfur recovery.
5.5.2 Sulfate (Kraft) Process SO2 Emissions and Control
Sulfate pulping involves cooking wood chips in a caustic soda and sodium
sulfide solution. The process name comes from the fact that sodium sulfate
is used as the make-up chemical. A flow chart for a typical digestion and
46
chemical recovery process is shown in Figure 5-10.
Sulfur dioxide emissions from the sulfate recovery process are not great.
The significant sources of SC>2 are the recovery furnace, lime kiln, and smelt
dissolving tank. Table 5-12 shows the range of SO2 emissions encountered in
various sulfate mills.
Control devices specifically for SO2 are not used at sulfate mills because
of the relatively small SO2 concentrations and the greater need to control other
pollutants.
Sulfur dioxide emissions are, however, controlled as a secondary effect
of controlling odorous and particulate emissions. One recent study of recovery
furnace operation has shown that sufficient secondary air, turbulence in the
secondary zone, and liquor spray-pattern can substantially reduce emissions
AfJ
of odorous sulfur compounds and SO2. Tables 5-13 through 5-15 show the
5-62
-------
Table 5-12. RANGES OF SO0 CONCENTRATIONS IN STACK GAS
FROM TWO KRAFT MILLS
,46
Source
Recovery furnace
Lime kiln
Dissolving tank
SO2ppm
4-798
0-169
0.5-70
SO2 per ton of
air dried pulp, Ib
2.4 - 13.4
0.1- 0.3
0.0 - 0.14
Table 5-13. EFFECTS OF FURNACE SECONDARY AIR ON
AND OTHER SULFUR COMPOUND EMISSIONS 47
Secondary air, %
28.5
30.0
36.5
41.0
Excess
02,%
1.4
1.2
2.6
3.4
SO2, ppm ^S,
96.7 24.
53.0 12.
0.1 0.
0.2 0.
so2
ppm
6
6
007
012
5-63
-------
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5-64
-------
Table 5-14. EFFECTS OF TUBBULENCE ON FURNACE
GASEOUS EMISSIONS 47
Velocity at secondary
air port outlet, ft/sec
180
65
so2,
0.
47.
ppm
2
1
H2S,
0.
84.
ppm
012
5
Table 5-15. EFFECTS OF LIQUOR SPRAY PATTERN
ON FURNACE GASEOUS EMISSIONS 47
Type spray SO2
Coarse 0.08 0.0
Fine 9.8 0.37
5-65
-------
effects of operating variables on SC>2 emissions. Most recovery furnaces do
not, however, operate at optimum conditions from an air pollution standpoint,
and odorous emissions continue to be a problem at many mills.
Scrubbers are normally used on lime kilns and dissolving tanks to con-
trol particulate matter and some odorous emissions. These control devices
also reduce SC>2 emissions.
5.5.3 Sulfite Process SC>2 Emissions and Control
Sulfite pulping is an acid-base process for dissolving the lignin bonding
material from wood chips. The cooking liquor is produced by reacting SO0
z
with one of four bases (ammonium, calcium, magnesium, or sodium) in an
absorption device. The bisulfite solution that forms is used as cooking liquor
for wood chips in a digester.
A sulfur burner is the usual source of SOg for the calcium-, sodium-,
and ammonia-base sulfite processes. Methods for absorption of relatively
strong SO2 gas in the appropriate base are fairly well established. Sulfur
dioxide emissions from absorption systems can, however, be significant unless
proper process control and maintenance are practiced. It is imperative that
proper flow-rates, temperatures, and concentrations of the 869 gas and
absorption solution be maintained to minimize atmospheric emissions. Keep-
ing the absorption system operating at optimum conditions may require some
added expenditure in the form of extra operating and maintenance personnel.
Gases from the digester and blow tank are another source of SO,,. The
sulfur content of these gases can be controlled by passing them through condens-
ers and absorption towers or caustic scrubbers. One mill has reported a net
5-66
-------
savings of over $250, 000 per year from recovery of sulfur by installation of a
condenser and absorber to control SO2 emissions from blow tanks.
Much of the spent sulfite cooking liquor has been sewered in the past,
but greater emphasis is being placed on burning the liquor to reduce stream
pollution, recover chemicals, and generate steam. The spent sulfite cooking
liquor, being relatively high in organic sulfur compound, is potentially a large
combustion source of SC>2. Control of such emissions is possible and practical
since recovered SO2 in the form of HgSOn can be used as make-up chemical in
the process. The magnesium-base sulfite liquor is most suitable for burning
since the magnesium and SC^ can be efficiently recovered. Most new sulfite
mills in this country are of the magnesium-base type for this reason. Spent
ammonium-, calcium-, and sodium-base liquors can be burned, but only SOg can
be efficiently recovered, since the spent liquor is either destroyed or changed
in the combustion process.
Economical operation of the sulfite process requires efficient recovery
of SO 2 from the combustion gases, since concentrations of over 1 percent SO 2
(10, 000 parts per million) result from liquor combustion. With relatively
poor recovery (less than 90 percent), SOg emissions can be as high as 60 pounds
per ton of pulp. With 90 percent recovery, SOg emissions can be reduced to
49
approximately 1000 parts per million, or 20 pounds per ton of pulp. Another
study states that over 98 percent recovery is possible with three-stage venturi
absorption, resulting in stack emissions of about 300 parts per million SOg,
or 3 pounds per ton of pulp.
5-67
-------
Figure 5-11 shows a typical magnesium-base, chemical-digestion-and-
recovery system with air pollution control devices installed to control SC>2
and odorous sulfur compound emissions from the blow tank, multiple-effect
evaporators, and recovery furnace. Sulfur dioxide emissions from the com-
bustion process are recovered by efficient absorption in the scrubber and the
three absorption towers.
CHIPS
TO
ATMOSPHERE
BLOW GASES r
(S02). >
MgO SLURRY
JO ATMOSPHERE
(200 - 600 ppm SO2)
', Mg (HS03)2
COOKING LIQUOR
BLOW
SCRUBBER
DIGESTER
SCRUBBER TO ATMOSPHERE
PULP
MULTIPLE-
EFFECT
EVAPORAT
.«
i
3RS
MAKE-UP
SULFUR
MAGNESIA
MAKE-UP
WATER — »•
i
\
MgO
SLURRY
TANK
Figure 5-11 Typical magnesium-base chemical pulping recovery process.
5-68
-------
5.5.4 Neutral Sulfite Semichemical SC>2 Emissions and Control
The neutral-sulfite semichemical pulp process, the most widely used
semichemical process, normally uses sodium sulfite and sodium bicarbonate
as a cooking liquor. The spent cooking liquor can be burned with chemical
recovery.
Large quantities of SC>2 are generated in the combustion of the spent
liquor. Figure 5-12 shows how SO2 can be used to convert the smelt from the
combustion process to fresh cooking liquor. With the proper operation of this
system, little SC^ or E^S will be emitted to the atmosphere.
Small amounts of SC>2 and odorous sulfur compounds are released from
the digester blow gases and multiple-effect evaporators used to concentrate
spent liquor prior to burning. These emissions can be effectively controlled
by scrubbing.
5.5.5 Steam and Power Boiler Atmospheric Emissions
Many pulp and paper mills have auxiliary power boilers to produce
process steam. When these units are fired by coal or residual oil, SO2
emissions can be quite large, larger in fact than any SOo emissions from
chemical recovery processes.
One unique control method for SO2 emissions from boilers at a kraft
mill has been proposed.51 The method involves scrubbing power-boiler flue
gases with black liquor from the kraft process. The SO0 absorbed in the
£
liquor adds sulfur to the cooking liquor. Process make-up sulfur is reduced
and SO9 is removed from stack gases by a process that could provide an
^
economic return. A sodium carbonate scrubbing system has also been
proposed.52
5-69
-------
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5-70
-------
5,6 WASTE DISPOSAL
5.6.1 Coal Refuse
5.6.1.1 Introduction - Coal refuse is waste coal, rock, shale, culm, boney,
slate, clay, and related materials associated with a coal seam, whj.ch are
removed from the mine in the process of mining coal, or which are separated
from coal during cleaning and preparation. Coal refuse is often deposited in
large piles near mines and coal cleaning plants. These materials usually
contain large quantities of sulfur, in the form of "pyrites."53' 54
Coal refuse may be fired intentionally, accidentally, or by spontaneous
ignition. Ignition is more likely to occur if the waste pile contains extraneous
organic material like wood or garbage. Camp fires or brush fires often
furnish the ignition. Spontaneous firing occurs by slow oxidation of the coal.
Water may contribute to ignition by the heat of wetting, depending on the
physical nature of the coal and on humidity.
Sulfur dioxide is produced from the oxidation of pyrites in the coal:
FeS2 + 3O2 -FeSO4 + SO2.
The actual reactions going on in the pile are quite complex. Another reaction
is:
2FeS2 + 2H2O + 7O » 2FeSO4 + 2H2SO4-
The sulfuric acid produced may liberate HgS from the pyrites. This HgS may
further react:
2H2S + SO2 -~3S + 2H2O.
Sulfur is often observed on burning waste piles, and the odor of H2S is often
noticeable.
5-71
-------
Air samples taken in a community adjacent to a burning coal waste pile
showed average hourly SC>2 levels ranging from 0.4 to 3.0 parts per million
with peak levels from 0.6 to over 4. 5 parts per million, depending on meteoro-
53
logical conditions. Levels of I^S, measured at another time, varied from
0.1 to 0.4 part per million.
5.6.1.2 Control Methods and Costs - Methods of air pollution control for
coal waste piles consist of preventing or extinguishing fires. The method
used should be designed for the particular problem at hand and will vary from
one situation to another.
Among many methods investigated for extinguishing coal refuse fires are:
cooling and repiling the refuse; sealing with impervious material (such as a
blanket of well-compacted waste and a layer of clay); injecting a slurry of
limestone or other noncombustible; and sealing top and sides with coal cleaning
plant sludge. If the voids within the pile can be filled with inert materials,
combustion will cease.
Prevention of coal waste pile fires is fostered by proper site selection
and piling, and by ensuring the absence of wood, underbrush, paper, and other
such combustibles. Trespassers should be kept away from the piles.
Among methods for handling new waste and non-burning waste piles are:
c a
coal recovery (reducing the amount of combustibles) ; weathering for initial
oxidation followed by layering and compaction; and design of the waste piling
5-72
-------
to fit the topography and the material so that future ignition is minimized.
The following processes are examples of this last method:
1. Contouring the disposal valley and using earth to seal the
down-valley face of the deposited waste, °
2. Crushing large rocks, so that there will be the proper distribu-
tion of intermediate- and small-sized particles for compaction into
an impervious pile.
3. Terracing of waste piles and filling in the terraces with sealing
material such as clay to form a thick seal all around the pile. ^'
4. Contouring deep trenches around disposal hills in hilly terrain.
Waste is dumped and compacted by trucks operating on it. When the
first trench is filled, a second is superimposed by hill-side
excavation on a contour just above it, and so on. One variant of
this procedure uses excavated soil to cover the outside face of the
pile as the work progresses uphill.
Demonstration projects cosponsored by the National Air Pollution Control
Administration have indicated that costs of extinguishing coal waste pile fires
can be expected to range between $0.25 and $1.25 per cubic yard.53'58 Cost
of preventing these fires by compacting, layering, and contouring would be about
$1.00 per ton of refuse, based on the cost of sanitary landfills. A rough esti-
mate, based on the dimensions of burning coal-mine refuse banks, indicates
a total of over 1 billion cubic yards of such burning banks in the United States.
5.6.1.3 Future Plans and Research - The National Air Pollution Control Ad-
ministration has recently cosponsored 15 demonstration projects on extinguish-
ing culm-pile fires. Fourteen of these projects are State-sponsored, mostly
5-73
331-543 O - 69 - 18
-------
by Pennsylvania, and one project is sponsored by a non-profit corporation.
Seven projects are complete at this writing; however, a summary report must
await completion of the remaining projects. The U.S. Bureau of Mines is
expected to continue efforts in this field.
These demonstration projects have included, or will include;
1. Exclusion of air from a burning culm pile, using polyurethane
foam. After an apparently successful extinguishment, the burning
resumed. Cost was about $1.00 per cubic yard.
2. A project similar to the one described above, involving tests
with several kinds of plastic coatings to exclude air from the
pile, giving special attention to bitumastic coating.
3. Removal of culm bank material by drag line, dumping into a
lagoon, removal, repiling and compacting by bulldozers. Cost
was about $1.24 per cubic yard.
4. Treatment of a culm pile by injection of a slurry of vermiculite,
limestone, and sodium bicarbonate into drill holes sunk into the
pile. Results are not announced.
5. Injection of sludge resulting from neutralizing acid mine water
with limestone into a burning refuse bank. This treatment, it is,
hoped, will extinguish the fire and seal the bank.
6. Covering a pile with fine waste dust from cement plants. The
following part of the work will involve use of fine limestone dust on
the top of the pile.
5-74
-------
7. A huge water nozzle that breaks up and extinguishes a burning
culm bank. The waste was carried to a water pool and removed with
a clam shell for distribution and compaction by carry-alls and bull-
dozers. The cost was about $0.75 per cubic yard.
5.6.2 Incineration
The average sulfur content of municipal refuse has been found to be
about 0.1 percent.60 Tests made on incinerator stack gases showed SO2
a c\
concentrations generally in the 10- to 30-parts-per-million range.
Because of these fairly low values, SC>2 emissions from municipal refuse incinera-
tors are not a major problem and are not usually controlled. Incineration of some
high-sulfur chemical wastes are special problems that should be considered
for control along with other elements of the process involved.
5.6.3 Sewage Treatment
Many sewage treatment operations cause odors; however, there are only
two sources of SC>2 emissions, sludge-digester-gas combustion and sludge
incineration.
Sewage-sludge-digester gas, containing I^S, is corrosive, which limits
its use in internal combustion engines. Hydrogen sulfide concentration at
fi i
most treatment plants is not above 1 grain per cubic foot of gas, but
62
concentrations have been reported as high as 6 grains per cubic foot where
high-sulfate water has entered the sewers. Combustion of HoS produces
SOg emissions. Control technology concentrates on removing the H^S in order
to eliminate corrosion. Scrubbing with water or sewage effluent, augmented by
adding chlorine to the sewage gas, can reduce HkjS concentrations from over
a 1
2 grains per cubic foot to 0.5 grain or less per cubic foot of gas. Treatment
5-75
-------
of the resulting solution would usually be required before disposal. Another
method is the absorption of H2S on "iron sponge," a mixture of ferric oxide
61,62
and hardwood shavings. The iron sponge is regenerated by exposure to
air, releasing the sulfur as SO0. This has generally been emitted to the
z
atmosphere, but it could be absorbed by alkali solutions.
Sewage sludge is disposed of by various procedures, including lagooning,
land filling, using as a fertilizer or a fertilizer base, dumping into the sea,
and burning. Since dry digested sludge contains 1 percent sulfur, incineration
/J Q
may produce SC>2 emissions.
A wet oxidation method for sewage sludge, used on a large scale at
Chicago, develops SO2 control as in incidental benefit. In this process, a
3-percent aqueous suspension of ground sludge from the primary settlers is
pumped into a heated system where the pressure is about 1800 pounds per
square inch and the temperature is about 525 °F. Air is injected into the
aqueous sludge and "wet combustion" or oxidation occurs. Organics are
oxidized to CC>2 and water, or to low-molecular-weight acids such as acetic
acid. The sulfur compounds are oxidized to sulfates. Solid residue is about
90 percent inorganic and settles easily from the liquid portion. This liquid
portion, which maybe only about 1 percent of the total sewage flow, is recom-
bined with the main aqueous flow, and sent to secondary treatment. The heat
of oxidation of the sludge is sufficient to make the process thermally self-
supporting.
5-76
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5. 7 MISCELLANEOUS SOURCES
5.7.1 Introduction
There are several manufacturing operations, very limited in geo-
graphical distribution and scale of production, which are actual or potential
sources of SO9 emissions. There is little published information from which
&
to estimate quantitative emissions for these industries. In most cases, the
emissions are relatively minor; however, they may constitute local nuisances.
Sulfur oxide emissions discussed for the following miscellaneous sources
are in addition to emissions from fuel combustion.
5. 7. 2 Glass Manufacture65
The glass industry, though large and important, operates in relatively
few places.
Sulfur dioxide emissions may occur from the use of salt cake (NaJBO.)
in the glass tank charge. This material and powdered coal are among the
substances charged. The following reaction takes place:
Na9SO . + nSiO0 + C -Na,,O n SiO0 + SO0 + CO
Z 4 A / Z Z
No control of gaseous emissions is practiced.
5.7.3 Corn Starch Production
In a typical wet-milling process, corn kernels are steeped in water
containing 0. 2 percent SO at a temperature of 120 °F for 48 hours. This
^
steeping prepares the kernels for separation into starch, gluten, and fibers.
Sulfur dioxide is the most effective and most widely used reagent for this
purpose. No control of emissions is usually practiced.
5-77
-------
5.7.4 Sugar Manufacture
Lime is added to syrup during the sugar manufacturing process to
precipitate certain undesirable impurities. Calcium ions in the remaining
solution are precipitated by bubbling SO through the syrup to form calcium
LJ
sulfite. Minor emissions of SO can occur, depending on factors of design
£t
and plant operation.
5.7.5 Sulfur Fusion Processes
Processing of batches of sulfur by fusion can emit sulfur oxides at low
levels whenever the fusion vessel or kiln is opened. An example is the manu-
facture of ultramarine, which is made by fusing kaolin, charcoal, sodium
carbonate, sulfur, quartz, sodium sulfate, and resin. The melt is removed
from the kiln, cooled, ground, and washed. The insoluble compounds are
then heated with more sulfur to 950 F until the blue color develops.
5.7.6 Liquid Sulfur Dioxide
rt />
The national output of liquid SO in 1964 was 64,237 tons. The gas
^
is produced by burning sulfur or by roasting metal sulfides. The cooled
65
gases, containing up to 18 percent SO , are sent to a water absorber. The
£i
SO2 is stripped from the water, cooled, dried, compressed, and liquefied.
About 0.02 percent of the total SO is lost into the atmosphere.
^
5.7.7 Silicon C arbide
Silicon carbide, an important abrasive, is made in an electric furnace
at temperatures of 2200 C using sand and coke as raw materials. The
5-78
-------
furnace has no top, and the walls are temporary so that they can be torn away
from the charge after completion of heating. Any gases generated go directly
to the atmosphere. The unreacted materials are later separated from the
product and recycled as fresh furnace charge.
Any SO evolved in this process will be from the oxidation of sulfur
Lt
contained in the coke. About 1.4 tons of coke is charged per ton of carbide
produced.
5.7.8 Titanium Dioxide
In the manufacture of titanium dioxide, sulfuric acid is added in batches
to titanium ore in a digester, yielding primarily titanium sulfate and ferrous
sulfate. The digester products are washed and separated, and the ferrous
sulfate goes to waste. The titanium compounds enter a calciner where they
are heated and converted to titanium dioxide. Sulfur trioxide and sulfuric
acid mist are emitted from the calciner. On the basis of field test date, it is
estimated that 40 pounds of SO are emitted per ton of titanium oxide
LJ
n ri
calcined. Caustic scrubbers could be used to decrease these emissions by
more than 50 percent.
5-79
-------
REFERENCES FOR SECTION 5
1. Rohrman, F. A. and Ludwig, J. H. "Sulfur Oxides Emissions by
Smelters - A Potential Chemical Engineering Problem and Industrial
Resource. " National Center for Air Pollution Control, Cincinnati, Ohio,
Jan. 1968.
2. "U.S. Dept. of Interior Minerals Yearbook 1966. " Bureau of Mines,
Washington, D. C.
3. Knudson, F. F. "The Control and Monitoring of Copper Smelter Smoke. "
Preprint. (Presented at the Air Pollution Control Association Meeting,
June 1964, Paper 64-59.)
4. "Atmospheric Emissions from Sulfuric Acid Manufacturing Processes."
U.S. Public Health Service, National Center for Air Pollution Control,
Washington, D. C., PHS-Pub-999-AP-13, 1965.
5. Bryk, P., Ryselin, J., Honkasalo, J., and Malmstrom, R. "Flash
Smelting Copper Concentrates. " J. Metals, Vol. 10, pp. 395-400,
June 1958.
6. Browning, J. E. "New Processes Focus Interest on Oxygen. " Chem.
Eng., ^5(5):88-92, Feb. 26, 1968.
7. Unpublished data. U.S. Public Health Service, National Air Pollution
Control Administration, Process Control Engineering Program, Cincin-
nati, Ohio.
8. "Restricting Dust and Sulfur Dioxide Emissions from Lead Smelters. "
Verein Deutscher Ingenieure, Clean Air Committee, Specification 2285,
Sept. 1961.
9. "Restricting Emissions of Dust and Sulphur Dioxide in Zinc Smelters."
Verein Deutscher Ingenieure, Clean Air Committee, Specification 2284,
Sept. 1961.
10. Hensinger, C. E., Wakefield, R. E. and Glaus, K. E. "New Roasters
Spur Production of Sulfuric Acid and Zinc Oxide Pellets. " Chem. Eng.,
7£( 12): 70-72, June 3, 1968.
11. Duecker, W. W. and West, J. R. "The Manufacture of Sulfuric Acid. "
American Chemical Society Monograph 144, Reinhold, 1959.
5-80
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12. Stormont, D. H. "Crude Capacity in U. S. Sets a Near-Record Pace for
1967." Oil and Gas J., 66(14): 126-157, April 1, 1968.
13. Rohrman, F. A. and Ludwig, J. H. "SO2 Emissions to the U.S. (1966)."
National Air Pollution Control Administration. (Unpublished.)
14. Sittig, M. and Unzelman, G. H. "Sulfur in Gasoline. " Petroleum
Processing, 11(8)-.75-95, Aug. 1956.
15. "Atmospheric Emissions from Petroleum Refineries. " U.S. Public
Health Service, PHS-Pub-763, 1960.
16. Hengstebeck, R. J. "Petroleum Processing, Principles and Application. "
McGraw-Hill, New York, 1959.
17. Hydrocarbon Processing, 46(5) :47, May 1967.
18. Danielson, J. A. "Air Pollution Engineering Manual. " U.S. Public
Health Service, PHS-Pub-999-AP-40, 1967.
19. Chute, A. E. "Sulfur Recovery for Profit and Air Pollution Abatement. "
Petro/Chem. Eng., J39(6):32-36, June 1967.
20. Maddox, R. N. and Burns, M. D. "How to Choose a Treating Process.
Oil and Gas J., Vol. 65, pp. 131-133, Aug. 14, 1967.
21. Gamson, B. W. and Elkins, R. H. "Sulfur from Hydrogen Sulfide. "
Chem. Eng. Progr., 49(4)-.203-215, 1953.
22. Mallette, F. S. "Problems and Control of Air Pollution. " Reinhold,
New York, 1955.
23. Valdes, A. R. "New Look at Sulfur Plants. " Hydrocarbon Processing,
43(3): 104-108, March 1964 and 43(4): 122-128, April 1964.
24. Carmassi, M. J. and Zwilling, J. P. "How S. N. P. A. Optimizes Sulfur
Plant." Hydrocarbon Processing, 46(4): 117-121, April 1967.
25. "HPI Construction Boxscore. " Hydrocarbon Processing, Section 2, Feb.
and June 1968.
26. Chute, A. E. Preprint. (Presented at Society of Mining Engineers,
Las Vegas, Nevada, Sept. 1967.)
5-81
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27. "Inorganic Chemicals Run Near Capacity. " Chem. Eng. News, 44(36):
72A-79A, Sept. 5, 1966.
28. Moeller, W. and Winkler, K. "The Double Contact Process for Sulfuric
Acid Production. " J. Air Pollution Control Assoc., l_8(5)324-25, May
1968.
29. "Air Pollution from Sulfuric Acid Production is Target of Conversion
Process." Chem. Eng. News, Vol. j>0, Jan. 25, 1965.
30. Depp, J. M. Private communication, Monsanto Co., May 17, 1968.
31. "Overseas Survey: Air Pollution." Mech. Eng. £9(7):60, July 1967.
32. "Mineral Facts and Problems. " 1965 edition, U.S. Bureau of Mines,
Bulletin 630.
33. Simons, R. A. and Felton, C. R., Jr. "Superfluxed Sinter Practice at
Bethlehem Steel Corporation's Lackawana Plant." J. Metals, pp. 70-73,
June 1967.
34. Schueneman, J. J., High, M. D., and Bye, W. E. "Air Pollution
Aspects of the Iron and Steel Industry. " U.S. Public Health Service,
National Center for Air Pollution Control, Cincinnati, Ohio, PHS-Pub-
999-AP-l, 1963.
35. Colclough, T. P. "The Role of Sulphur in Iron and Steel Making. "
American Society of Mechanical Engineers, Paper 55-APC-6, March
1965.
36. Brandt, A. D. Private communication, Bethlehem Steel Company,
Oct. 18, 1968.
37. Doherty, J. D. and DeCarlo, J. A. "Coking Practice in the United
States Compared with Some Western European Practices. " (Congres
International de Charleroi, Le Coke en Siderurgie), U. S. Bureau of
Mines, Washington, D. C., 1966.
38. Rueckel, W. C. "Modern Wilputte High Capacity Coke Ovens. "
J. Metals, 19(7):65-69, 1967.
39. Wilson, P. J. and Wells, J. H. "Coal, Coke, and Coal Chemicals."
McGraw-Hill, New York, 1950.
5-82
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40. Mallette, F. S. "Problems and Control of Air Pollution. " Reinhold,
New York, 1955, pp. 215-221.
41. Kohl, L. and Riesenfeld, F. C. "Today's Processes for Gas Purifica-
tion. " Chem. Eng., 66(12): 127-178, 1959.
42. Hydrocarbon Processing, 44(11):271, 1965.
43. Jones, J. F., Schmid, M. R., and Eddinger, R. T. "Fluidized-Bed
Pyrolyses of Coal. " Chem. Eng. Progr., 60(6):69-73, June 1964.
44. Nemerow, N. L. "Industrial Waste Treatment. " Addison-Wesley,
Reading, Massachusetts, 1963, 557 pp.
45. Private communication, Battelle Memorial Institute, Columbus, Ohio,
1967.
46. Harding, C. I. and Landry, J. T. "Future Trends in Air Pollution
Control in the Kraft Pulping Industry. " TAPPI, 4£(8):61A-67A, Aug.
1966.
47. Thoen, G. N., Dellass, C. C., Tallent, R. G., and Davis, A. S. "The
Effect of Combustion Variables on the Release of Odorous Sulfur Com-
pounds from a Kraft Recovery Unit. " Preprint. (Presented at the 1968
annual meeting of TAPPI), 7 pp.
48. Lea, N. S. and Cristoferson, E. A. "Save Money by Stopping Air
Pollution." Chem. Eng. Progr., 61(11):89-93, Nov. 1965.
49. Hanway, J. E., Henby, E. B., and Smithson, G. R., Jr. "Magnesium-
Base Cooking Liquor Preparation by Absorption of Dilute Sulfur Dioxide
in Flooded-Bed Towers. " Preprint. (Presented at the 1966 Alkaline
Pulping Conference, TAPPI, Richmond, Virginia, Sept. 13-16, 1966.)
50. Clement, J. L. "Magnesium Oxide Recovery Systems. " TAPPI, 49(8):
127A-134A, Aug. 1966.
51. Harding, C. I. and Galeano, S. F. "Utilization of Weak Black Liquor
for SOX Removal and Recovery. " Preprint. (Presented at the 52nd
Annual TAPPI Meeting, New York, Feb. 22, 1967.)
52. Galeano, S. F. and Harding, C. I. "Sulfur Dioxide Removal and Recovery
from Pulp Mill Power Plants. " J. Air Pollution Control Assoc., 17(8):
536-539, Aug. 1967.
5-83
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53. Sussman, V. H. and Mulhern, J. J. "Air Pollution from Coal Refuse
Disposal Areas. " J. Air Pollution Control Assoc., 14(7):279-284, 1964.
54. Hebley, H. F. "The Control of Gob Pile Fires. " J. Air Pollution Con-
trol Assoc., £(1):29-31, 51, 1956.
55. Letter to the editor. Fuel, 2!0(4):90-96, 1951.
56. "New Reclaim-Type Plant Produces Quality Coal, Provides Backfilling. "
Coal Age, pp. 118-122, April 1965.
57. Technical Coordinating Committee. "The Disposal of Coal Refuse - Coal
Report T-4." J. Air Pollution Control Assoc., ^(2): 105-110, 1965.
58. Hall, E. P. "Air Pollution from Coal Refuse Piles. " Mining Cong. J.,
Vol. 48, pp. 37-41, Dec. 1962.
59. Stahl, R. W. "Survey of Burning Coal-Mine Refuse Banks. " U.S. Bureau
of Mines, Circular 8209.
60. Kaiser, E. R. "The Sulfur Balance of Incinerators. " J. Air Pollution
Control Assoc., 18(3):171-174, 1968.
61. Norris, H. E. "Scrubbing Sewage Gas. " Water Works and Sewerage,
90(2):61, Feb. 1943.
62. Buswell, A. M. "Gas Scrubbing for H2S Removal and Methane Enrich-
ment. " Public Works, 92(3): 112-114, 198, March 1961.
63. Babbit, H. E. and Baumann, E. R. "Sewerage and Sewage Treatment. "
8th edition, John Wiley and Sons, New York, 1958.
64. Guccione, E. "Wet Combustion of Sewage Sludge Solves Disposal
Problems. " Chemical Engineering, Vol. 71, pp. 118-120, May 25, 1964.
65. Shreve, R. N. (ed.) "The Chemical Process Industries. " McGraw-Hill,
New York, 1956.
66. "Facts and Figures for the Chemical Process Industries: An Annual
C & E Feature. " Chemical Engineering News, Vol. 44, No. 36, Sept. 5,
1966.
67. Parsons, J. L. Private communication, E. I. DuPont de Nemours Co.,
Wilmington, Delaware, 1968.
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6. DISPERSION FROM STACKS
6.1 INTRODUCTION
This brief discussion of dispersion from stacks is followed by a bibliog-
raphy of selected references that provide more complete information.
In general, stacks are used to provide for a reduction of ground-level
concentration by giving natural atmospheric turbulence an opportunity to
dilute the pollutant before it reaches ground-level receptors. Along with con-
trol of emissions, it may be useful to use the natural dilution provided by
stacks to obtain desired air quality.
Assuming the same emission rate, ground-level concentration is less
with a tall stack than with a short one. Although a stack of any height usually
reduces the ground-level concentration, it does not provide a reduction in the
amount of material released into the atmosphere nor does it preclude signifi-
cant concentrations at ground level under all meteorological conditions.
An individual stack may be theoretically high enough to reduce ground-level
concentrations to a satisfactory level (if it were the only source); however,
it may add its emissions to those from other sources, resulting in undesirable
concentration levels. Because the contaminant emission is not reduced, all
6-1
-------
of it must eventually be removed through natural processes such as washout.
The effectiveness of stacks may in some instances be limited by unfavorable
terrain.
Current trends are toward larger power plants and higher stacks. These
higher stacks are designed to restrict ground-level concentrations to about the
same levels as those produced by smaller installations. The possibility of
overloading the atmosphere by the sheer size of the installation presents an
unanswered question as to the adequacy of even very tall stacks.
6-2
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6.2 PLUME RISE
In simplifying mathematical treatments of atmospheric dispersion, it is
realistic to assume that dispersion begins above the actual stack top at an
elevation called the "effective stack height. " A number of theoretical and
empirical equations have been developed to estimate the magnitude of the
plume rise. Since there is no one means of computation that has been generally
accepted for all circumstances, professional judgment and experience are
required to make the proper choice in a given situation.
When a stack plume is emitted in a disturbed air flow, caused by wind
blowing over structures or irregular terrain, standard plume rise and diffusion
equations may not apply. Wind tunnel studies with models of stacks, buildings,
and other objects are, therefore, used to estimate aerodynamic effects.
6-3
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6.3 DIFFUSION PROCESSES
For a given set of emission and meteorological conditions the expected
maximum ground-level concentrations can be estimated as a function of the
effective stack height. The important meteorological variables are atmospheric
stability and wind direction and speed.
An unstable atmospheric condition occurs when the temperature in the air
decreases rapidly with height, as would be expected to happen near the ground
during a cloudless day. Conversely, a stable condition exists within a
temperature inversion layer, where temperature increases with height.
Inversion layers at the ground are most likely to form in rural areas during a
night when the sky is clear and winds are light. Within such a layer there is
virtually no vertical stack plume diffusion. The effluent trail may be narrow,
widening gradually on a straight line from the stack, or it may resemble a
meandering river. Plumes from large modern power plants with high stacks
generally rise above surface inversion layers into a region of less stability.
Whenever the plume is trapped within the inversion layer, and depending
on the duration of the stable period and the wind speed at the effective stack
height, the effluent may travel aloft for many miles with relatively slow
dilution. However, during the following morning, after the ground has been
heated by the sun, air near the ground will be warmed and become turbulent
so that parts of the plume are often carried to the ground. This condition,
which occurs during the breakup of an inversion layer, is called "fumigation."
6-4
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Inversion-breakup fumigations are of particular interest with respect to
the tall stacks of modern power plants, the plumes of which may reach 1, 000
to 2, 000 feet. It is generally recognized that fumigation does occur, but its
magnitude, extent, and frequency are currently under investigation, and plants
generating over 1000 megawatts and utilizing tall stacks are individual cases
which require special study.
"The experience of the TVA with their many steam-generating plants
illustrates some of these situations. As plants of increasingly larger capacity
have been built, with correspondingly taller stacks, the maximum fumigations
have shifted from the high-wind type, with which many people are familiar, to
the light-wind type. Although tall stacks can be built to minimize the high-wind
and inversion-breakup fumigations, the total pollution discharge of the larger
plants becomes a problem when the limited capacity of the mixing layer prevents
adequate dilution. Thus, the other element that determines concentrations, the
pollutant source strength, may require control if such large plants are to be
built in parts of the country where this type of fumigation occurs with any
appreciable frequency. "*
*PHS Publication No. 999-AP-16, Potential dispersion of plumes from large
power plants.
6-5
331-543 O - 69 - 19
-------
6.4 USE OF MATHEMATICAL-METEOROLOGICAL MODELS
It is necessary to use electronic computers for the large number of
dispersion calculations required for estimating air pollution concentrations for
an area the size of a city or an air quality control region. In cases where the
impact of many sources on numerous receptors is being assessed, even though
the interest is primarily in a single source, the analysis is handled best
through the implementation of a validated mathematical-meteorological model.
By means of such a model, it is relatively easy to consider a change in source
conditions (that is, to assume a different sulfur content in fuel, a new stack
height, or a different location), and obtain an estimate of the effect. However,
the actual value of the result depends upon whether the model has been verified
by field observations of concentrations under conditions similar to those
assumed in the model.
6-6
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6. 5 METEOROLOGICAL ASPECTS OF SITE SELECTION
A meteorological analysis should be part of the preparation for site
selection for an emission source, or for an increase in emission at an established
site. The thoroughness of such analyses will vary widely depending on the
emission rate of the source and on the nature and number of potential receptors.
6-7
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6. 6 FACTORS FOR SITE EVALUATION
The following list of factors is usually considered when locating a large
potential source of air pollution that will use the stack as a means of dispersion.
1. Source Description
a. Elevation of stack base.
b. Stack height (physical and effective).
c. Inside diameter of stack at top.
d. Stack gas velocity (at top of stack) normally and during
slack periods of significant duration.
e. Stack gas temperature (at top of stack).
f. Peak, average, seasonal, and diurnal emission rates of SO
u
(grams per second).
2. Climatological Factors Affecting Plume Rise
a. Air temperature.
b. Air pressure (for effective stack height computations).
c. Wind speeds at effective stack height for stability conditions
of interest.
d. Stability conditions in the environment through which the
plume is rising. In some cases the frequency of occurrence
of each stability type may be required.
6-8
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3. Aerodynamic Considerations
a. Building shapes, dimensions, etc. at source.
b. Nearby large buildings and significant terrain features
affecting airflow.
c. Results of wind tunnel studies, if any.
4. Geography
a. Description of important terrain features affecting diffusion
(using maps, cross sections, etc.)
b. Locations of populations, present and future, with respect
to the source, considering particularly sensitive receptor
locations such as hospitals and schools.
c. Locations of sensitive vegetation or animals, if any.
d. Adjacent industries that could significantly affect, or be
affected by, the source or mutually add to the problems of
the area.
5. Other Climatological Factors Affecting Dispersion
a. Wind direction frequencies at effective stack heights, with
consideration of significant seasonal and diurnal variations.
b. Frequency and duration of light winds and calms.
c. Local wind circulations (valley winds, sea breezes, etc.)
6-9
-------
d. Stability conditions (frequency of occurrences of stability
categories). Consideration should be given to time of day,
seasons, and wind direction.
e. Occurrence of special weather phenomena such as fog.
f. Precipitation frequency and intensity.
g. Diurnal and seasonal variation in mixing layer depth,
especially in relation to effective stack height.
6. Potential for Increased Emissions
a. Possible future expansion of existing site.
b. Possible future construction of other sites.
c. Effect of expansion and new construction on total emissions.
6-10
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6.7 OTHER CONSIDERATIONS FOR SITE OR STACK EVALUATION
In some situations where representative meteorological observations are
lacking or questionable, a field-observation program may be conducted to obtain
on-site data, or to test the representativeness of observations from the nearest
weather station.
Effective stack height becomes lower as the wind speed increases, but
increased wind speed causes more dilution. Consequently, for a given stability
condition there is a critical wind speed for each emission condition at which
maximum ground-level concentrations occur. The determination of a critical
wind speed simplifies stack design and estimation of a maximum permissible
rate of emission, in simple situations where only the maximum concentrations
under certain stability conditions are desired.
However, this procedure, if applied alone, neglects the additive effect of
the source on the existing background or other emitters in the area. When it is
applied, allowance should be made for existing air quality and the possibility
of fumigation.
Meteorological assistance with respect to industrial site selection problems
may be obtained from professional meteorologists who advertise their services
in the Professional Directory section of the Bulletin of the American
Meteorological Society. The Executive Director of the Society, (45 Beacon
Street, Boston, Mass. 02108) can provide a current list of certified consulting
meteorologists.
6-11
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6. 8 STATUS OF POWER PLANT PLUME DISPERSION AND METEOROLOGICAL
STUDIES
In order to clarify questions on the dispersion of SO from stacks and
^
the resulting ground-level concentrations and effects, the National Air
Pollution Control Administration (NAPCA) is supporting five investigations, in
addition to conducting related research through its Meteorology Program.
1. The TVA has been conducting studies of plume rise, inversion
breakup, limited mixing layers, and primary and secondary emissions.
About 1700 plume rise observations have been taken at six steam plants
with stacks ranging from 170 to 800 feet. A tentative conclusion is that
with large units and high stacks, maximum ground-level concentration
occurs during fumigation associated with a limited mixing layer.
2. NAPCA investigators, in cooperation with the Pennsylvania Electric
Company and the Division of Air Pollution Control of the Pennsylvania
State Department of Health, are studying stack plume behavior, SO
i4
concentrations in the air and on the ground, and effects on flora in the
vincinity of three coal-burning electric power generating stations. The
first phase of the study is being conducted at the Keystone Power Station,
near Indiana, Pennsylvania; subsequent studies will involve the Homer
City Station, Homer City, Pennsylvania, and the Conemaugh Power
Station, northwest of Johnstown, Pennsylvania. The Keystone Station
6-12
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has twin 800-foot stacks and the Conemaugh Station will have 1000-foot
stacks. Observations are being made by means of portable stations,
instrumented helicopters, and a laser beam.
3. The GCA Corporation, in a joint study involving Bituminous Coal
Research Incorporated, the Edison Electric Institute, and American
Petroleum Institute, is investigating the reactions of sulfur compounds
in power plant plumes. Quantitative information on reaction rates and
products formed will allow the incorporation of SO decay rates into
L*
mathematical atmospheric diffusion models. Hopefully it will allow the
incorporation of the formation of sulfuric acid mist and inorganic sulfate
production into these models.
4. The Argonne National Laboratory, U.S. Atomic Energy Commission,
is developing a computer program that will predict the dispersion of
SO in the Chicago area. This study considers the requirements of a
u
pollution warning system, measures to be taken to minimize the severity
of pollution incidents, and long-range city planning.
5. The Brookhaven National Laboratory seeks to determine the
32 34
feasibility of using the S /S ratio of fossil fuels to identify individual
sources in urban areas, and determine the decay process of SO to the
Li
final end product.
6-13
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6.9 STACK COSTS
The cost of a stack depends on many factors including size, material and
labor costs, and the necessary foundations. Because these costs vary widely,
depending on the specific local conditions, only approximate costs can be
presented.
Figure 6-1 shows the estimated cost ranges for stacks of various sizes.
These data include only costs directly associated with the stack and not the
costs of fans, ducts, or dust collectors.
. 3000
8 2000
Q
UJ
«/> o 100C
Z T>
n
ll) o
I- —
Q.
Q.
300
INSIDE DIAMETER
AT TOP
* Includes foundations
I
I
I
300 400 500 600 700 800 900 1000
STACK HEIGHT, ft
Figure 6-1. Approximate installed costs of
stacks.
Operating costs of stacks of various sizes must also be considered. High
exit velocities will allow a smaller stack diameter, but also result in higher fan
power requirements. Tall stacks today are usually constructed of concrete with
low-alloy corrosion-resistant steel liners. This type of stack has proved
reliable to date, but long-range maintenance costs are not available, due to the
relative newness of these stacks.
6-14
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6. 10 BIBLIOGRAPHY
6.10.1 Guides, Manuals, Workbooks
"Recommended Guide for the Prediction of Dispersion of Airborne Effluents. "
American Society of Mechanical Engineers, United Engineering Center, New
York, 1968.
Slade, D. (ed.) "Meteorology and Atomic Energy, 1968." U.S. Atomic Energy
Commission, Div. of Technical Information, Oak Ridge, Tenn., 1968.
Munn, R. E.. "Annotated Bibliography for Air Pollution Meteorology." J. Air
Pollution Control Assoc., 11(10):449-453, 1968.
"Tall Stacks, Various Atmospheric Phenomena and Related Aspects, an
Annotated Bibliography." National Air Pollution Control Administration,
Office of Technical Information and Publications, Air Pollution Technical
Information Center, Arlington, Virginia, Aug. 1968.
Turner, D. B. "Workbook of Atmospheric Dispersion Estimates. " U.S.
Dept. of Health, Education, and Welfare, National Air Pollution Control
Administration, PHS-Pub-999-AP-26, 1967, pp. 31-34.
6.10.2 Text Books
McGill, P. L., Holden, F. R., and Ackley, C. (eds.) "Air Pollution Hand-
book." McGraw-Hill, New York, 1956.
Munn, R. E. "Descriptive Micrometeorology." Academic Press, New York,
1966, 241 pp.
Pasquill, F. "Atmospheric Diffusion. " D. Van Nostrand, New York, 1962,
297 pp.
Scorer, R. S. "Air Pollution." Pergamon, London, 1968, 151pp.
Scorer, R. S. "Natural Aerodynamics, " Pergamon, New York, 1958.
Stern, A. C. (ed.) "Air Pollution. Vol. 1, Air Pollution and Its Effects."
Academic Press, New York, 1968, 694 pp.
Sutton, O. G. "Micrometeorology." McGraw-Hill, New York, 1953, 333pp.
6-15
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6.10.3 General
Beers, N. R. "Stack Meteorology and Atmospheric Disposal of Radioactive
Waste." Nucleonics, Vol. 4, pp. 28-38, 1949.
Bierly, E. W. and Hewson, E. W. "Some Restrictive Meteorological Con-
ditions to Be Considered in the Design of Stacks. " J. Applied Meteorol., 1_
(3): 383-390, Sept. 1962.
Brink, J. A., Jr. and Crocker, B. B. "Practical Applications of Stacks to
Minimize Air Pollution Problems. " 57th National Meeting of the Air Pollution
Control Assoc., Houston, Texas, June 1965.
Church, P. E. "Dilution of Waste Stack Gases in the Atmosphere, " Ind. Eng.
Chem., 41.(12):2753-2756, 1949.
Davidson, W. F. "The Dispersion and Spreading of Gases and Dust from
Chimneys." Transactions of the Conference on Industrial Wastes, 14th
Annual Meeting, Industrial Hygiene Foundation of America, 1949, pp. 38-55.
Gartrell, F. E., et al. "Full-Scale Study of Dispersion of Stack Gases, a
Summary Report." Tennessee Valley Authority and Public Health Service,
Chattanooga, Tennessee, 1964, 93 pp.
Gartrell, F. E., Thomas, F. W., and Leavit, J. M. "Dispersion Character-
istics of Stack Emissions from Large Thermal Power Stations. " (Presented
at joint meeting of American Meteorology Society and American Geophysical
Union, Washington, D. C., April 19-22, 1966.)
Hewson, E. W. "Stack Heights Required to Minimize Ground Concentrations."
Transactions of American Society Mechanical Engineers, Oct. 1955.
Hewson, E. W. and Gill, G. C. "Meteorological Investigations in Columbia
River Valley near Trail, British Columbia. " In: Report Submitted to the Trail
Smelter Arbitral Tribunal, U. S. Bureau of Mines, Bulletin 453, 1944, pp. 23-
228.
Lowry, P. H. "Microclimate Factors in Smoke Pollution from Tall Stacks. "
Meteorological Monographs, £(4):24-29, 1951.
6-16
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Rummerfield, P. S., Cholak, J., and Kereiakes, J. "Estimation of Local
Diffusion of Pollutants from a Chimney: A Prototype Study of Employing an
Activated Tracer. " American Industrial Hygienic Assoc. J., pp. 366-371,
July-Aug. 1967.
Smith, M. E. "Reduction of Ambient Air Concentrations of Pollutants by
Dispersion from High Stacks. " U. S. Dept. of Health, Education, and Wel-
fare, Public Health Service, PHS-Pub-1649, pp. 151-160. (Proceedings:
Third National Conference on Air Pollution, Washington, D. C., Dec. 12-14,
1966.)
Sporn, P. and Frankenberg, T. T. "Pioneering Experience with High Stacks
on the Ohio Valley Electricity Corporation and the American Power System."
In: Proceedings: International Clean Air Congress, London, Oct. 1966.
(Expanded version of this paper appears in "The Tall Stack," a collection of
papers by Philip Sporn, Retired President, American Electric Power Company,
New York, 1967.)
Stone, G. N. and Clarke, A. J. "British Experience and Tall Stacks for Air
Pollution Control on Large Fossil-Fueled Power Plants." American Power
Conference, Illinois Institute of Technology, April 27, 1967.
Thomas, F. W., Carpenter, S. B., and Gartrell, F. E. "Stacks - How
High?" J. Air Pollution Control Assoc., 13_(5):189-204, May 1963.
6.10.4 Plume Rise Calculations, Stack Height
Bosanquet, C. H. "The Rise of a Hot Waste Gas Plume." J. Inst. Fuel,
3£(197):322-328, 1957.
Briggs, G. A. "A Plume Rise Model Compared with Observations. " J. Air
Pollution Control Assoc., lJ5(9):433-438, 1965.
Bryant, L. W. and Cowdrey, C. F. "The Effects of the Velocity and Temper-
ature of Discharge on the Shape of Smoke Plumes from a Funnel or Chimney:
Experiments in a Wind Tunnel. " Proceedings, Institute of Mechanical
Engineers (London), Vol. 169, pp. 371-400, 1955.
"The Calculation of Atmospheric Dispersion from a Stack. Report of CONCAWE
Working Group on Stack Height and Atmospheric Dispersion." CONCAWE,
Hague, The Netherlands, 1966, 57 pp.
6-17
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Holland, J. Z. "A Meteorological Survey of the Oak Ridge Area. " Atomic
Energy Comm., Washington, D. C., Report ORO-99, 1953, 584pp.
Landers, W. S. "Trends in Steam Station Design Affecting Air Pollution. "
American Society of Mechanical Engineers, Un. Engineering Center, New
York, 66-PWR-l, 1966.
Lucas, D. H. "Comment During Symposium on the Dispersion of Chimney
Gases Held on Dec. 7, 1961, Royal Meteorological Society," Int. J. Air
Water Pollution, Vol. 6, p. 94, 1962.
Moses, H. and Strom, G. H. "A Comparison of Observed Plume Rises with
Values Obtained from Well-Known Formulas." J. Air Pollution Control
Assoc., 11(10):455-466, Oct. 1961.
Moses, H., Strom, G. H., and Carson, J. E. "Effects of Meteorological
and Engineering Factors on Stack Plume Rise." Nuclear Safety, ^(1): 1-19,
1964.
"Round Table on Plume Rise and Atmospheric Dispersion. Atmospheric
Environment." Pergamon Press, New York, Vol. 2, 1968.
6.10. 5 Diffusion Calculations
Barad, M. L. "Diffusion of Stack Gases in Very Stable Atmosphere. "
Meteorological Monographs, 1_(4):9-19, 1958.
Bodurtha, F. T. "Discussion on ASME Standard APS-1. " Un. Engineering
Center, New York.
Bodurtha, F. T. "Background and Basis of ASME Standard. Recommended
Guide for the Control of Dust Emission - Combustion for Indirect Heat Ex-
changers." American Society of Mechanical Engineers, Un. Engineering
Center, New York, APS-1.
Bosanquet, C. H., Carey, W. F., and Halton, E. M. "Dust from Chimney
Stacks." Proceedings of the Institute of Mechanical Engineers, Vol. 162,
pp. 355-367, 1950
Bosanquet, C. H. and Pearson, J. L. "The Spread of Smoke and Gases from
Chimneys, Disperse Systems in Gases." Trans. Faraday Soc., Vol. 32,
pp. 1249-1264, 1936.
6-18
-------
Bowne, N. E. "Some Measurements of Diffusion Parameters from Smoke
Plumes. " Bulletin of the American Meteorological Society, 42_(2):101, 1961.
Calder, K. L. "Some Recent British Work on the Problem of Diffusion in the
Lower Atmosphere." In: Air Pollution, Proceedings of the U. S. Technical
Conference on Air Pollution, McGraw-Hill, New York, 1952, pp. 787-792.
Gifford, F. A. "Use of Routine Meteorological Observations for Estimating
Atmospheric Dispersion." Nuclear Safety, 2_(4):47-51, 1961.
Gifford, F. A. "Peak to Average Concentration Ratios According to a Fluctu-
ating Plume Dispersion Model." International J. of Air Pollution, 3>(4):253-260,
1960.
Hilst, G. R. "The Dispersion of Stack Gases in Stable Atmospheres." J. Air
Pollution Control Assoc., 7_(3):205-210, 1957.
Hilst, G. R. and Simpson, C. L. "Observations of Vertical Diffusion Rates in
Stable Atmospheres. " J. Meteorol. , j_5(l): 125-126, 1957.
Lowry, P. H., Mazzarella, D. A., and Smith, M. E. "Ground-Level
Measurements of Oil-Fog Emitted from a Hundred-Meter Chimney." Meteo-
rological Monographs, !L(4):30-35, 1951.
Pasquill, F. "The Estimation of Dispersion of Windborne Material. " Meteorol.
Mag., Vol. 90, pp. 33-49, 1961.
Peterson, K. R. "Continuous Point Source Plume Behavior Out to 160 Miles."
J. Applied Meteorol., Vol. 7, pp. 217-226, April 1968.
Pooler, F. "Potential Dispersion of Plumes from Large Power Plants. "
PHS-Pub-999-AP-16, 13 pp.
Priestly, C. H., McCormick, R. A., and Pasquill, F. "Turbulent Diffusion
in the Atmosphere." World Meteorological Organization, Geneva, Switzer-
land, Technical Note 24, WMO 77, TP 31, 1958.
Smith, M. E. and Singer, I. A. "An Improved Method of Estimating Concen-
trations and Related Phenomena from a Point Source Emission. " J. Applied
Meteorol., Vol. 5, pp. 631-639, Oct. 1966.
6-19
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6.10.6 Mathematical Diffusion Models
Clarke, J. F. "A Simple Diffusion Model for Calculating Point Concentrations
from Multiple Sources." J. Air Pollution Control Assoc., 4(9):347-352, Sept.
1964.
Davidson, B. "Summary of the New York Urban Air Pollution Dynamics
Research Program. " J. Air Pollution Control Assoc., 17(3):154-158>
March 1967.
Koogler, J. B., Sholtes, R. S., Danis, L., and Harding, C. I. "A Multi-
variant Model for Atmospheric Dispersion Predictions." J. Air Pollution
Control Assoc., 17_(4):211-214, April 1967.
Leavitt, J. M. "Meteorological Considerations in Air Quality Planning. "
J. Air Pollution Control Assoc., Vol. 10, pp. 246-250, June 1960.
Martin, D. O. and Tikvart, J. A. "A General Atmospheric Diffusion Model
for Estimating and Effects of One or More Sources on Air Quality." (Presented
at Annual Meeting of Air Pollution Control Assoc., St. Paul, Minnesota,
June 1968.)
Miller, M. E. and Holzworth, G. C. "An Atmospheric Diffusion Model for
Metropolitan Areas. " J. Air Pollution Control Assoc., 17_(1):46-50, Jan.
1957.
Pooler, F., Jr. "A Prediction Model of Mean Urban Pollution for Use with
Standard Wind Roses." Int. J. Air and Water Pollution, 4(3/4):199-211,
Sept. 1961.
Szepesi, D. J. "A Model for the Long Term Distribution of Pollutants
Around a Single Source." Idojaras (Budapest), Vol. 68, pp. 257-269, Sept.-
Oct. 1964.
Turner, D. B. "Relationships Between 24-Hour Mean Air Quality Measure-
ments and Meteorological Factors in Nashville, Tennessee." J. Air Pollution
Control Assoc., Il(10):483-489, 1961.
Turner, D. B. "A Diffusion Model for an Urban Area. " J. Applied Meteorol.,
3_(1):83-91, Feb. 1964.
6-20
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6.10.7 Aerodynamics, Wind Tunnel Studies
"Report of Government Committee on Air Pollution." Sir Hugh Beaver (Chair-
man), Her Majesty's Stationery Office, London, Cmd. 9322, 1954.
Halitsky, J. "Diffusion of Vented Gas Around Buildings." J. Air Pollution
Control Assoc., 12J2):74-80, 1962.
Halitsky, J. "Gas Diffusion Near Buildings, Theoretical Concepts and Wind
Tunnel Model Experiments with Prismatic Building Shapes." New York
University, Geophysical Sciences Lab., Report 63-3, 1963.
Scorer, R. S. "The Behavior of Plumes." Int. J. Air Pollution, Vol. 1,
pp. 198-220, 1959.
Sherlock, R. H. and Lesher, E. J. "Design of Chimneys to Control Down-
wash of Gases." Trans. Am. Soc. Mech. Engrs., Vol. 77, pp. 1-9.
Sherlock, R. H. and Lesher, E. J. "Role of Chimney Design in Dispersion
of Waste Gases. " Air Repair, 4(2): 1-10, 1954.
Strom, G. H. "Wind Tunnel Scale Model Studies of Air Pollution from Indus-
trial Plants." Industrial Wastes, Sept.-Oct., Nov.-Dec. 1955, Jan.-Feb.
1956.
Strom, G. H., Hackman, M. and Kaplin, E. J. "Atmospheric Dispersal of
Industrial Stack Gases Determined by Concentration Measurements in Scale
Model Wind Tunnel Experiments." J. Air Pollution Control Assoc., 7_(3):
198-203, 1957.
Sutton, O. G. "Discussion Before Institute of Fuels." J. Institute of Fuel, Vol
33, pp. 495, May 23, 1960.
6.10.8 Natural Removal Processes
Chamberlain, A. C. "Aspect of Travel and Deposition of Aerosol and Vapour
Clouds. " Atimic Energy Research Establishment, Harwell, England, HP/R,
1261, 1955, 35pp.
Coleman, R. "The Importance of Sulfur as a Plant Nutrient in World Crop
Production." Soil Science, 101(4):230-238, 1966.
6-21
331-543 O - 69 - 20
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Culkowski, W. M. "Calculations of the Deposition of Aerosols from Elevated
Sources." Oak Ridge Operations Office (AEC), Report ORO-171, 1958.
Culkowski, W. M. "Deposition and Washout Computations Based on the
Generalized Gaussian Plume Model." U. S. Weather Bureau, Oak Ridge,
Tennessee, USAEC Report ORO-599, 1963.
Engelmann, R. J., Perkins, R. W., Hage, D. I., and Haller, W. A. "Wash-
out Coefficients for Selected Gases and Particulates. " Preprint. (Presented
at the 59th Annual Meeting of the Air Pollution Control Assoc., San Francisco,
Calif., June 20-24, 1966.)
Gartrell, F. E., Thomas, F. W., and Carpenter, S. B. "Atmospheric
Oxidation of SO2 in Coal-Burning Power Plant Plumes. " Amer. Ind. Hyg.
Assoc. J., Vol. 24, pp. 113-120, March-April 1963.
Gifford, F. A. and Pack, D. H. "Surface Deposition of Airborne Material."
Nuclear Safety, 3_(4):76-80, 1962.
Junge, C. E. "Air Chemistry and Radioactivity. " Academic Press, New
York, 1963.
Singer, I. A. and Smith, M. E. "The Influence of Variable Meteorological
Parameters on Diffusion, Deposition, and Washout from Point Sources. "
Preprint. (Presented at the 58th Annual Conference, Air Pollution Control
Assoc., Toronto, Canada, June 1965.)
6.10.9 Topographic and Urban Effects
DeMarrais, G. A. "Vertical Temperature Difference Observed Over an
Urban Area. " Bulletin American Meteorological Society, Vol. 42, pp. 548-
556, 1961.
Landsberg, H. "Physical Climatology." Gray, Du Bois, Penn., 1966, p. 326.
Neiburger, M. "The Dispersion and Deposition of Air Pollutants over Cities."
Symposium: Air over Cities, Public Health Service, Cincinnati, Ohio, SEC
Technical Report A62-5, 1961, pp. 156-157.
"Symposium: Air over Cities." U. S. Public Health Service, R. A. Taft
Sanitary Engineering Center, Cincinnati, Ohio, SEC Technical Report A62-5,
1961, 290 pp.
6-22
-------
Smith, T. B. "Diffusion Study in Complex Mountainous Terrain. " Meteorology
Research, Inc., Report to Dugway Proving Ground, Army Chemical Corps.,
AD484087, 1965, pp. 106-110.
Van der Hoven, I. "Atmospheric Transport and Diffusion at Coastal Sites. "
Nuclear Safety, 8_(5)-.490-499, 1967.
6.10.10 Air Pollution Climatology
Dept. of Health, Education, and Welfare, "Air Pollution Prevention and Con-
trol, Definition of Atmospheric Areas." Federal Register, 33_(10), Jan 16,
1968.
Hosier, C. R. "Low-Level Inversion Frequency in the Contiguous United
States." Monthly Weather Review, Vol. 89, pp. 319-339, Sept. 1961.
Holzworth, G. C. "Estimates of Mean Maximum Mixing Depths in the Con-
tiguous United States." Monthly Weather Review, Vol. 92, pp. 235-242, 1964.
Holzworth, G. C. "Large-Scale Weather Influences on Air Pollution in the
United States." Preprint. (Presented at the 61st Annual Meeting of the Air
Pollution Control Assoc., St. Paul, Minnesota, June 1968.)
Korshover, J. "Climatology of Stagnating Anticyclones East of the Rocky
Mountains, 1936-1965." PHS-Pub-999-AP-34, 1967, 15pp.
6.10.11 Costs
Nelson, F. and Shenfeld, L. "Economics, Engineering, and Air Pollution in
the Design of Large Chimneys. " J. Air Pollution Control Assoc., 15(8):355-
361, Aug. 1965.
6.10.12 Aviation Regulations
"Federal Aviation Regulations, Part 77. " Dept of Transportation, Federal
Aviation Administration, Washington, D. C.
6-23
-------
-------
7. EVALUATION OF SULFUR OXIDE EMISSIONS
7.1 COMPILATION OF SULFUR OXIDE EMISSION FACTORS
To determine emission rates, a stack gas analysis of all sources of in-
terest would be necessary. This is, of course, impossible when an air pollu-
tion survey covers a large area that might contain many thousands of individual
sources. It is often necessary, therefore, to estimate emissions from sources
for which accurate stack gas analyses are unavailable. In some cases, the
proper use of a good emission factor will yield better results than those based
on a single series of stack gas tests. Emission factors are based on past
stack gas sampling data, material balances, and engineering estimates for
sources that are similar to those in question.
Tables 7-1 through 7-3 are compilations of available emission factors
for sulfur compounds from various types of sources. Most of the sulfur emitted
is in the form of SO2, but smaller quantities of SO3, sulfuric acid mist (usually
reported as particulate matter), hydrogen sulfide, and various other forms of
sulfur are also emitted. The emission factors listed are for uncontrolled
sources and are reported as SO2 unless otherwise noted. For a specific
source where control equipment is used the listed uncontrolled emission rates
must be multiplied by 1. 0 minus the fractional efficiency of the control equip-
ment. Unless otherwise stated, these factors are based on reference number 1.
7-1
-------
Table 7-1. EMISSION FACTORS FOR SULFUR COMPOUNDS
FROM FUEL COMBUSTION
Source
Emission factor
Coal
Natural gas
38Sa
0.4
Ib of SOr
ton ^
Ib of SOC
106 CF
(assumes 5 percent of sulfur
remains in ash)
(assumes sulfur content of
grain_ of
Process gas
2.86Cb lb°fS°2
I0b CF
Fuel oil 158.8Sd
Diesel powered
engine
1000 gal
Wood
Gasoline powered 9
engine
Negligible
Ib of SOr
103 gal
40 lb°fS°2
10 gal
(includes SOg; based on fuel
density of 8.1 Ib/gal)
(assumed sulfur content of 0. 07
percent)
(assumed sulfur content of 0.3
percent)
Aircraft
Negligible
S = percent sulfur by weight.
DC = grains of sulfur/100 cubic feet of gas.
7-2
-------
Table 7-2. EMISSION FACTORS FOR SULFUR COMPOUNDS FROM
SOLID WASTE DISPOSAL
Emission factor,
Ib of SO2 per ton
Source of refuse charged
Open-burning dumps and
municipal incinerators 1.2-2.0
On-site commercial and industrial
multiple-chamber incinerators
On-site commercial and industrial
single-chamber incinerators
On-site residential single-chamber
incinerators 0.4
On-site residential flue-fed
incinerators 0.2
7-3
-------
Table 7-3. EMISSION FACTORS FOR SULFUR COMPOUNDS
FROM INDUSTRIAL PROCESSES3'4'5
Petroleum refineries
Catalyst regenerators:
Fluid
Thermofor
Sulfuric acid manufacture
Copper smelting - primary
Lead smelting - primary
Lead smelting - secondary
cupola
Lead smelting - secondary re-
verbatory and sweat furnaces
Zinc smelting - primary
Iron and steel mill sinter
machine
Ammonia purification at coking
plant
See reference 2
0.525 lb/bbla
0. 06 lb/bbla
Range: 20-70
Ib of SOf
1400
660
64
149
1090
0.3
8rt
. I
ton of 100% acid produced
Ib of S0«
ton of concentrated ore
Ib of SO2
ton of concentrated ore
Ib of sulfur compounds
ton of metal charged
Ib of sulfur compoundig
ton of metal charged
Ib of SO2
ton of concentrated ore
Ib of SO2 (assumes ore content
r 7 of 0. 01 percent with
ton of ore „, , f ,f
71 percent of sulfur
going up stack)
Ib of SOn
ton of NH,, solution
o
Based on data from Los Angeles. Could be considerably different in other
areas, depending on sulfur content of the feed stocks.
7-4
-------
Table 7-3 (continued). EMISSION FACTORS FOR SULFUR COMPOUNDS
FROM INDUSTRIAL PROCESSES3'4'5
Pulp and paper mills
Kraft type - recovery furnace
Calcium carbide manufacturing
main stack with impingement
scrubber
Coke dryer
2.4-13.4
Ib of SOr
Sulfite type - recovery furnace 40
ton of air dried pulp
Ib of SO,,
ton of air dried pulp (assumes
90-percent
recovery of
S02)
2.54 lb °f S°2 (includes S03)
ton of product
.
U.
Ib of SO0 (includes SO0)
Z O
ton of product
Based on data from Los Angeles. Could be considerably different in other
areas, depending on sulfur content of the feed stocks.
7-5
-------
7.2 SOURCE TESTING FOR SULFUR OXIDES
Emission factors or material balance calculations for sulfur oxides are
methods for estimating emissions. However, when it is necessary to quantify
the amount of sulfur oxides emitted from a particular source, it is often
necessary to perform stack gas sampling.
Many source tests are conducted to determine whether a particular
source is complying with emission regulations. Testing for compliance is
especially applicable where the theoretical source emission (calculated with
emission factors or by material balance) approximates the code limitation.
Source tests are also performed to determine the true efficiency of emission
control devices, especially where the theoretical collection efficiency would
result in a narrow margin of compliance. Where alterations in a process
design may be needed to correct pollution, source test results are often used
as a basis for suggesting changes and to identify those changes which will be
most effective. Another use of source test data would be in the determination
of how great a theoretical reduction in pollution could be expected from the
initiation of a proposed code.
The following methods are most commonly used in source testing:
/? n
1. Shell Development Company Method. '
Q
2. Los Angeles County Air Pollution Control District Method,
3. Total sulfur oxides, API Method 774-54. 9
4. Retch Test for sulfur dioxide.
7-6
-------
5. Bureau of Mines Method No. 4618 for sulfur dioxide and
sulfur trioxide.
6. Determination of sulfuric acid mist, sulfur dioxide, and
sulfur trioxide.
7-7
-------
REFERENCES FOR SECTION 7
1. Duprey, R. L. "Compilation of Emission Factors. " U.S. Public Health
Service, National Center for Air Pollution Control, Washington, D. C.,
PHS-Pub-999-AP-42, 1968.
2. "Atmospheric Emissions from Petroleum Refineries. " U.S. Public Health
Service, Washington, D. C., PHS-Pub-763, 1960, p. 56.
3. Unpublished data, National Air Pollution Control Administration, Process
Control Engineering Program, Cincinnati, Ohio.
4. Schueneman, J. J., High, M. D., and Bye, W. E. "Air Pollution
Aspects of the Iron and Steel Industry. " U.S. Public Health Service,
National Center for Air Pollution Control, Washington, D. C., PHS-Pub-
999-AP-l, June 1963.
5. Unpublished data, National Air Pollution Control Administration, Abate-
ment Program, Operations Section, Durham, N. C.
6. "Determination of Sulfur Dioxide and Sulfur Trioxide in Stack Gases."
Shell Development Company, Emeryville Analytical Dept., California,
Method Series 4S16/59a, 1959.
7. "Atmospheric Emissions from Sulfuric Acid Manufacturing Processes. "
U.S. Public Health Service, National Center for Air Pollution Control,
Washington, D. C., PHS-Pub-999-AP-13, 1965, p. 127.
8. Devorkin, H., Chass, R. L., Fudurich, A. P., and K ante r, C. V.
"Air Pollution Source Test Manual. " Los Angeles County Air Pollution
Control District, Los Angeles, California.
9. "Manual for Analytical Control of Liquids and Gaseous Effluents from
Petroleum Processing Plants. " American Petroleum Institute, Refiners'
Committee on Waste Disposal, New York, Revised June 30, 1950.
10. "Sulfur Dioxide Gas Test (Reich Test) for Sulfuric Acid Plants Either
Utilizing or Not Utilizing Air Quench. " Monsanto Chemical Co.,
Engineering Sales Dept., St. Louis, Missouri.
11. Berk, A. A. and Burdick, L. R. "A Method of Testing for SO2 and SO3
in Flue Gases." U. S. Dept. of Interior, Bureau of Mines R. I. 4618,
Jan. 1950, 9 pp.
7-8
-------
12. "Gas Analysis of Sulfuric Acid Plants. " Chemical Construction Corp.,
Technical Methods, Research and Development Laboratory, New York,
Aug. 1961.
7-9
-------
-------
APPENDIX - CHEMICAL COAL PROCESSING
1. INTRODUCTION
A brief summary of chemical coal processing was presented in
Section 4.4.1. This appendix presents more detailed information on these
processes.
2. LIQUEFACTION OF COAL
The Pemco Process of solvent refining of coal yields a low-sulfur,
low-ash fuel. At room temperature, the fuel is a shiny black solid which
is hard and brittle and can be readily ground into an extremely fine powder.
Since this fuel liquefies at approximately 430 F, it can be burned as either
a solid or a liquid.
The solvent refining process, while strictly speaking not a coal lique-
faction process, is shown in Figure A-l. In this process, finely ground coal
and anthracene oil are slurried, hydrogen is added to prevent repolymeriza-
tion, and the mixture is heated to 840 F. The dissolved coal is filtered to
remove the ash residue containing pyritic sulfur mixed with other separated
minerals. Unused hydrogen is recycled. The filtered coal solution is flash-
evaporated to remove the light fraction. This process allows the solvent to be
recovered after distillation and yields some light oil. The hot liquid residue
from the evaporator is discharged and cooled to yield a unique fuel product.
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Final product properties depend on the raw coal. Typical feed and
product yields are shown in Table A-l.
Coal containing predominantly pyritic sulfur can be converted by this
process to a refined fuel with a low sulfur content because the pyritic sulfur
is removed with the ash in the filtration step. Up to 70 percent of the organic
sulfur may be removed by hydrogenation to H^S in the dissolving step. More
solvent is generated than is used, so this step is economically attractive and
also adds flexibility to the final product by allowing admixture with the solvent.
Considerable market development is required to establish uses for this
fuel. Processing costs have been estimated at about 19 cents per million
Btu, and total cost at 27 to 32 cents per million Btu.
A 100-pound-per-hour pilot plant has been completed and a large instal-
lation is planned for Tacoma, Washington, for 1969.
FMC Corporation's Project COED (char-oil-energy development), the
Office of Coal Research's oldest coal liquefaction project, began work in May
1962. This process, which begins with a carbonization step, produces a
liquid, some gas, and char as shown in Table A-2.
In the COED process, diagramed in Figure A-2, crushed coal is heated
to progressively higher temperatures in a series of four fluidized bed reactors.
From 1 to 5 percent of the charge is volatilized in the first stage, and 50 per-
cent of the oil yield is derived from the second stage. Burning a portion of the
char with oxygen in the last stage supplies process heat. All the volatile
products from the coal produced by the last three stages exit from the second
stage to the product recovery system. The gas, containing 40 to 50 percent
A-3
331-543 O - 69 - 21
-------
Table A-l. SOLVENT REFINED COAL PRODUCT1
Raw coal
(Kentucky #11) Refined product
Ash, percent by weight 6.91 0.14
Sulfur, percent by weight 3.27 0.95
Heat content, Btu/lb 13,978 15,9156
Table A-2. TYPICAL PRODUCT YIELDS FOR COED PROCESS
(Based on Utah A Seam King Coal)
Product Weight %
Char 54.3
Oil 23.6
Gas 15.0
Tar liquor 7.0
A-4
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hydrogen, can be processed further to produce methane or hydrogen. Oil
processing yields conventional gasoline and fuel oil products.
Technology has progressed through the operation of a 100-pound-per-
hour process development unit. Design of a 36-ton-per-day prototype plant is
underway, and operation is scheduled for 1970.
Oil yields are relatively high, from 1 to 1.5 barrels per ton of coal.
The problem of effective use of the large amount of char has led FMC to de-
velop a process for removal of sulfur from the char so that it might be used as
a low-sulfur boiler fuel in power plants.
The essential elements of this desulfurization process are shown in
Figure A-3. The key part of the process is the use of calcined dolomite
(CaO + MgO) as an "acceptor" to absorb sulfur from the liberated H9S. Char
j6
and acceptor are easily separated because of the large particle size of the
acceptor. Sulfur is desorbed from the acceptor at 800 F by reaction with
steam and CO?:
(CaS + MgO) + HO + CO^ -(CaCOq + MgO) + H0S.
2 ^ *5 ^
Hydrogen sulfide is converted to elemental sulfur in a Glaus system, and the
acceptor regenerated by calcining at 1600 F.
FMC has estimated that the cost for reduction of sulfur level i n char from
3 percent to 0.3 percent is about 10 cents per ton of char, or about 0.4 cents
2
per million Btu. These figures allow substantial credit for sulfur recovery
(60 cents for each ton of char processed).
A-6
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The major disadvantage of the process is the present lack of use for the
char product. Considerable market development will be required to establish
its usefulness.
The H-Coal process, developed by Hydrocarbon Research, Inc., uses
hydrogenation to recover a light crude oil which can be conventionally refined
to gasoline. Coal conversion rate is higher than for other methods, as shown
in Table A-3 for Illinois #6 coal on a moisture- and ash-free basis.
Table A-3. PRODUCT YIELD FOR H-COAL PROCESS
(Illinois #6 coal)
Percent of original
Product coal by weight3-
Light gas 10.2
Liquid product 71.0
Char 10.7
H2S, NH3, H20 8.1
3.
Moisture and ash free basis.
This shows that about 90 percent by weight of the moisture- and ash-free
coal is converted in the reactor.
In the H-Coal process, diagrammed in Figure A-4, coal is dried, pulver-
ized, slurried with coal-derived oil, and charged continuously with hydrogen
to a reactor containing a bed of ebullating catalyst (fluidized bed where the
liquid is the fluidizing medium). The coal is hydrogenated and converted to
gaseous and liquid products: refinery gases, naphtha, middle distillate, and
heavy gas oil. The unconverted coal residue and the heavy liquid product are
sent to the carbonization section. Recovered heavy gas oil is catalytically
A-8
-------
hydrocracked to middle distillate, naphtha, and refinery gas. The naphtha is
further treated and reformed to gasoline.
CHAR
NO. 6 FUEL
OIL
NO. 2 FUEL
OIL
GASOLINE-*-
COAL
i
HYDROGEN
i
COAL HYDROGENATION
CARBONIZATION
HEAVY GAS OIL
HYDROGENATION
MIDDLE DISTILLATE
HYDROTREATING
MIDDLE DISTILLATE
HYDROCRACKING
SULFURIC ACID AND
AMMONIUM SULFATE
MANUFACTURE
PRODUCTS
NAPHTHA TREATING
AND REFORMING
Figure A-4. H-Coal process (simplified flow chart).
Ammonia, and a portion of the hydrogen sulfide produced in the
coal and heavy-gas-oil hydrogenation steps, are recovered as an aqueous
solution of ammonium sulfides. This solution, together with the H S
-------
acid. The ammonia is converted with a portion of the sulfuric acid to ammo-
nium sulfate.
Although this process does produce low-sulfur products, the economics
of the process are very sensitive to the price of light fuel oil and gasoline.
Eecent estimates place the cost of the oil between 12.1 and 14. 3 cents per gal-
r*
Ion, depending on the size of the plant.
Bench-scale work with a reactor processing 15 to 25 pounds per day of
coal has been completed. A 3-ton-of-coal-per-day pilot plant has been in
operation since February 1966, and the next step will be a demonstration unit,
using 250 to 500 tons of coal per day, located in a coal producing area.
The most extensive effort of the Office of Coal Research (OCR) to liquefy
coal is the Consol (CSF) process, developed by Consolidation Coal Company to
enable gasoline from coal to compete with its petroleum counterpart in coal
producing areas. In this process, diagramed in Figure A-5, coal is dissolved
in a process-generated liquid, and ash and other non-reactive parts are filtered
out. Solids go to a low-temperature carbonization step, which recovers sol-
vent and produces char. Liquids are first distilled to recover solvent, light
distillate, and a heavier fraction. The heavier fraction is hydrogenated and
distilled to form the major crude-oil portion. The crude oil is sent to the
gasoline-making step.
OCR feels that for a large commercial plant (30,000 to 100,000 barrels
of gasoline per day) a projected product cost of 11 cents per gallon is realis-
tic. Uses for the char and availability of low-cost hydrogen are major con-
siderations. These considerations make the building of such a gasoline plant
A-10
-------
SOL\
RECY
COAL
t
SOLVENT
RECYCLE
EXTRACTION
\
ENT
N
CLE 1 SOLIDS 1
1 I LIQUIDS
CARBONIZATION
SULFUR BEARING CHAR f
DISTILLATIO
CRUDE OIL TO GASOLINE MAKING
*
HYDROGENATION *H DISTILLATION
Figure A-5. CSF process (simplified flow chart).
next to a Consol coal-gasification plant attractive, because this would allow
some char use and provide a source of low-cost hydrogen.
The CSF process is the biggest OCR liquefaction process and the most
technologically advanced. A pilot plant, in operation since May 1967, at
Cresap, West Virginia, is capable of processing 1 ton of coal per hour, resulting
in a liquid output of 60 barrels daily. Design of a commercial plant may start
in the early 1970's if all goes well at Cresap.
GASIFICATION OF COAL
Hydrogasification, diagrammed in Figure A-6, is essentially a two-stage,
high-pressure, direct reaction of treated coal with hydrogen to form methane.
The coal is ground in a hammer mill before being partially oxidized. This
partial oxidation overcomes the tendency of the coal to agglomerate during
A-ll
-------
CRUSHED
COAL
HYDROGASIFIER
HYDROGEN
AND STEAM
PARTIAL
OXIDATION
PRETREATED
COAL
LOW
TEMPERATURE
HIGH
TEMPERATURE
1
CHAR
HYDROGEN
AND STEAM
PRODUCTION
GAS
STEPS
.
f
METHANATION
1
'
DRYING
f PIPE
ASH GAS
LINE
BY-PRODUCT
(SULFUR)
I i
Figure A-6. Hydrogasification (simplified flow chart).
hydrogasification. The high pressure (1100 psig) hydrogasification is divided
into two distinct reaction zones. The pretreated coal first enters a free-fall,
low-temperature (900 F to 1300 F) zone; then, by moving-bed, the unreacted
portion of the coal enters the high-temperature (1700 F) zone where further
gasification occurs. The lower temperature zone favors formation of methane
from the volatile portion of the coal, and the higher temperature zone favors
the formation of hydrogen and carbon monoxide.
A-12
-------
Gas produced in the low-temperature zone of the hydrogasifier passes
through purifying steps for removal of carbon dioxide, hydrogen sulfide, and
traces of organic sulfur. The purified gas is then enriched to pipeline quality
by methanation using carbon monoxide and hydrogen from the hydrogasifier.
After excess water vapor is removed, the resultant gas is ready for distribu-
tion to consumers.
The Institute of Gas Technology has carried out developmental work on
ct a
hydrogasification, and has completed a pilot-plant study. ' A prototype plant
is tentatively scheduled for completion in 1970, and a commercial plant by
1975. The work is supported by the American Gas Association (AGA) and the
U.S. Government Office of Coal Research (OCR).
Hydrogasification is perhaps the most promising method for obtaining
pipeline quality gas. Present cost estimates are based on an overall thermal
efficiency of about 75 percent. One of the major cost factors is the require-
ment for hydrogen. Current development by the Bureau of Mines of various
methods of using the spent char for hydrogen production could reduce overall
costs. Additional pilot-plant experience, and the recovery value of the sulfur
from gas purification, should also reduce overall costs in the future. Utli-
mately, OCR expects the gas to cost between 35 and 50 cents per million Btu.
Consolidation Coal Company (Consol) is advancing its CO0 acceptor
^
7 8
process to the pilot-plant stage. ' The Office of Coal Research has sponsored
the work since mid-1964. Consol has subcontracted with the M.W. Kellogg Co.
for design of the pilot plant to be built in Rapid City, South Dakota. Operations
should begin within 1-1/2 years, with an initial feed of lignite coal of 30 tons
per day.
A-13
-------
In the CCL acceptor process, diagrammed in Figure A-7, lignite coal is
crushed, dried, and preheated before entering a devolatilizer operated at about
1400 °F and 285 psig. The coal is devolatilized by contact with the gasifier
off-gases and is mixed with the calcined-dolomite CO0 acceptor. Superheated
z
steam carries the devolatilized char and dolomite to the gasifier, where 60
percent of the carbon in the char is gasified at 1600 Fo Heat required for this
gasification is supplied by the dolomite's acceptance of the CCL formed during
LA
gasification. The dolomite (now in the carbonate form) is returned to the re-
generator for calcining. Heat for regeneration of the dolomite is supplied by
combustion of compressed air with the residual char from the gassification
stage.
After the gas from the devolatilizer is purified, it requires some meth-
anation to bring it up to pipeline-gas quality. It should be noted that the reac-
tion of the lime with the CO0 makes gasification possible without the presence
&
of oxygen. The resulting gas stream is further concentrated by removal of the
co2.
This process produces not only high-Btu gas, but also low-sulfur fuel
(char) and low-cost, high-purity hydrogen. With nearby markets for the major
products, this process could be commercially feasible in a few years. It is
especially attractive when combined with a coal liquefaction plant requiring
9
low-cost, high-purity hydrogen.
The M. W. Kellogg Company has carried the molten salt process into
7
bench-scale experimentation under a contract with the Office of Coal Research.
A-14
-------
CRUSHED
COAL
FLASH
DRYER
BY-PRODUCT
(SULFUR)
DEVOLATILIZER
CHAR,
DOLOMITE
STEAM-
CALCINED
DOLOMITE
GASIFIER
OFF GASES
GASIFIER
ASH
DOLOMITE
REGEN-
ERATOR
CHAR
*—
ASH
CHAR AND DOLOMITE
GAS
PURIFYING
METHANATION
PIPELINE
GAS
Figure A-7. C02 acceptor (simplified flow chart).
Under a contract awarded in June 1964, Kellogg is making a concurrent
engineering-cost evaluation. No funds have been allocated in fiscal year 1968-
9
69 for this process.
Like the CO0 acceptor process, the molten salt process eliminates the
&
need for oxygen or air in the gasifier unit. Dilution of the raw gas by the non-
reactive portion of air is undesirable since this leads to costly purification.
A-15
-------
In this process, diagrammed in Figure A-8, a molten salt such as sodium car-
bonate supplies reaction heat and acts as a catalyst for the gasification reaction.
The gasifier, operated at 1000 F and 430 psig at the coal inlet and
1700 F and 400 psig at the gas outlet, is divided into two sections by a vertical
partition. The partition is perforated below the surface level of the molten salt
so that the salt can circulate but the gas evolved on one side cannot be carried
over to the other. The coal and steam enter on one side of the partition, and
preheated air enters on the other. The coal residue carried through the par-
tition by the molten salt is oxidized by the air to supply heat for the gasifi-
cation reaction taking place in the other half of the reaction vessel. The
gasification reaction is further enhanced by the catalytic properties of the mol-
ten salt, which lowers the required reaction temperature and optimizes methane
formation. Because of problems associated with the two-part gasifier, it has
been designed as two separate units, one for gasification and one for coal com-
bustion. In either design, the coal combustion gases and gasification gases are
separated, but heat transfer is allowed.
The relatively high temperature requires a system of heat recovery, as
shown in Figure A-8. Effective removal of coal ash from the molten salt re-
quires more development, as does most of this process. Work to date does
not provide a basis for estimation of the extent of gas purification and enriching
(further methanation) that will be required.
Although the CO~ acceptor and molten salt processes eliminate the need
for costly high-purity oxygen or hydrogen, the capital investment in either is
quite high. Systems for regeneration of the salt or dolomite and for required
auxiliary control need much refinement.
A-16
-------
RAW GAS
<_ K u on c v
COAL
1
FLUE GAS
TWO-PART
GASIFIER
•
STEAM
I
i
AIR
SALT
REGENERATOR
ASH
i
AIK
1 I
]
HEAT
'
RECOVERY
SYSTEM
FL
GA
UE
«
\J rt */
i
GAS
PURIFYING
1
liCTLJ AKJ ATIrtk.1
Me 1 n AIN A 1 IUN
I
PIPELINE
GAS
SULFUR
Figure A-8. Molten salt (simplified flow chart).
Bituminous Coal Research, Inc. {BCR) has been moving toward refine-
7 10
ment of the two-stage superpressure coal gasification process. ' BCR's
original contract with OCR, awarded in December 1963, was extended by 30
months in November 1966. The bench-scale work has been completed, and a
100-pounds-of-coal-per-hour process and equipment development plant is'under
construction.
The process, diagrammed in Figure A-9, is based on a high-pressure
two-stage gasifier in which most of the volatile portion of the coal is converted
A-17
-------
CRUSHED
COAL
RAW GAS
STEAM-
STEAM-
CYCLONE
STAGE
2
GASIFIER
STAGE
1
«*-
RECYCLE CHAR
GAS
PURIFYING
•OXYGEN
SLAG
SULFUR
METHANATION
PIPELINE
GAS
Figure A-9. Two-stage, super-pressure desulfurization process (simplified flow chart).
directly to methane and the residual char is reacted with oxygen and steam to
supply process heat. This gasification process may require less investment
in equipment than either the CO acceptor or molten salt processes and re-
quires less high-purity oxygen than hydrogasification.
A high-volatile bituminous coal is injected into stage 2 of the reactor
vessel and there heated rapidly to 1700 °F and 1050 psig. Methane formation
is rapid, and the nonvolatile portion of the coal is returned to stage 1, which
is essentially a slagging gasifier. High temperature and pressure optimize
A-18
-------
formation of methane (about 23 percent in the raw gas). The raw gas is cleaned
by passage through cyclones, and the entrained, low-volatile char is recycled
to stage 1 of the gasifier.
Since this process is in early stages of development, evaluation of its
feasibility is difficult. However, because of the temperature involved, a sys-
tem of heat recovery similar to that used in the molten salt process will prob-
ably be necessary. The main problem in the operation of this superpressure
process will be to keep the pressures and temperatures in various parts of the
gasifier at optimum operating values.
A-19
331-543 O - 69 - 22
-------
REFERENCES FOR APPENDIX
1. Jimeson, R. M. "Utilizing Solvent Refined Coal in Power Plants. "
Chem. Eng. Progr., 62(10):53-60, 1966.
2. Squires, A. M. "Air Pollution: The Control of SO2 from Power Stacks,
Part I - The Removal of Sulfur from Fuel. " Chem Eng., Nov. 6, 1967,
pp. 260-268.
3. "Commercial Process Evaluation of the H-Coal Hydrogenation Process. "
Office of Coal Research Contract 14-010001-477, Washington, D. C.
4. "OCR Points Liquid Coal to Market. " Coal Research, No. 24, Autumn
1966.
5. "Process Design and Cost Estimate for Production of 266 Million scf/day
of Pipeline Gas by the Hydrogasification of Bituminous Coal - Hydrogen
by the Steam-Iron Process. " Office of Coal Research Contract 14-01-
0001-381, Washington, D. C.
6. "Compilation of Interim Reports on Projects for the Production of Pipe-
line Quality Gas from Coal." Office of Coal Research, Washington, D. C.
7. "Pipeline Gas from Lignite Gasification - A Feasibility Study. " Office of
Coal Research Contract 14-01-0001-415, Washington, D. C.
8. Cochran, N. Private communication, April 1968.
9. "Laboratory-Scale Flow Reactor for Studying Gasification of Coal under
Conditions Simulating Stage 2 of the BCR Two-Stage Super-Pressure
Gasifier. " Preprint. (Presented at the American Institute of Chemical
Engineers Symposium, Carnegie Institute of Technology, Pittsburg, Pa.,
April 7, 1967.)
A-20
-------
AUTHOR INDEX
Abernethy, R. F.
Ackley, C.
Alpert, S. B.
Anderson, R. L.
Aresco, S. J.
Averitt, P.
Babbit, H. E.
Barad, M. L.
Baumann, E. R.
Beers, N. R.
Bell, D. D.
Bender, R. J.
Berk, A. A.
Bierly, E. W.
Bierman, Sheldon
Blade, O. C.
Bland, W. F.
Bodurtha, F. T.
Borgwardt, R. H.
Bosanquet, C. H.
Bovier, R. F.
Bowne, N. E.
Brandt, A. D.
Briggs, G. A.
Brink, J. A. , Jr.
Brown, F. H. S.
4-54
6-15
4-90
4-66, 4-74
4-54
4-13
5-76
6-18
5-76
6-16
4-41
4-40
7-7
6-16
4-37
4-30
4-85, 4-90
6-18
4-107
6-17, 6-18
4-115
6-18
5-53, 5-55
6-17
6-16
4-128
A-21
-------
AUTHOR INDEX (Continued)
Page
Browning, J. E. 5-7
Bryant, L. W. 6-17
Bryk, P. 5-6, 5-7
Burdick, L. R. 7-7
Burns, M. D. 5-27
Buswell, A. M. 5-75, 5-76
Bye, W. E. 5-52, 7-4, 7-5
Colder, K. L. 6-18
Carey, W. F. 6-18
Carmassi, M. J. 5-34
Carpenter, S. B. 6-17, 6-21
Carson, J. E. 6-18
Chamberlain, A. C. 6-21
Chass, R. L. 7-6
Cholak, J. 6-16
Christoferson, E. A. 5-67
Church, P. E. 6-16
Chute, A. E. 5-26, 5-39, 5-40
Clarke, A. J. 6-17
Clarke, J. F. 6-19
Glaus, K. E. 5-9
Clement, J. L. 5-67
Cochran, N. P. A-13, 4-44
Colclough, T. P. 5-52
Coleman, R. 6-21
Cowdrey, C. F. 6-17
A-22
-------
Crocker, B. B.
Culkowski, W. M.
Dana, G. F.
Danielson, J. A.
Danis, A. L.
Davidson, B.
Davidson, W. F.
Davis, A. S.
DeCarlo, J. A.
Dellass, C. C.
DeMarrais, G. A.
Depp, J. M.
Devorkin, H.
Dietrick, J. R.
Doherty, J. D.
Duecker, W. W.
Duprey, R. L.
Eddinger, R. T.
Elkins, R. H.
Engelmann, R. J.
Evans, R. K.
Felton, C. R., Jr.
Ferguson, H.
Foley, J. M.
AUTHOR INDEX (Continued)
Page
6-16
6-21
4-18
5-17, 5-43
6-20
6-20
6-16
4-62, 4-63, 4-65
4_10, 4-11, 4-12, 4-14, 4-54, 5-53
5-62, 5-63, 5-65
6-22
5-49
7-6
4-41
5-53
5-11
7-2, 7-3
5-58
5-29, 5-30, 5-32
6-21
4_126, 4-127
5-52
4-126
4-29
331-543 0-69-23
A-23
-------
AUTHOR INDEX (Continued)
Page
Frankenberg, T. T. 4-103, 6-17
Fudurich, A. P. 7-6
Galeano, S. F. 5-69
Gamson, B. W. 5-29, 5-30, 5-32
Gartrell, F. E. 6-16, 6-17, 6-21
Gifford, F. A. 6-19, 6-22
Gill, G. C. 6-16
Glaser, P. E. 4-43
Gleason, T. G. 4-123
Gourdine, M. 4-132
Guccione, E. 5-76
Hackman, M. 6-21
Hage, D. I. 6-21
Halitsky, J. 6-20
Hall, E. P. 5-73
Haller, C. P. 4-54
Haller, W. A. 6-21
Halton, E. M. 6-18
Hangebrauck, R. P. 3-2, 4-100
Hanway, John E. 5-67
Harding, C. I. 5-62, 5-63, 5-69, 6-20
Harrington, R. E. 4-107, 4-111, 4-112
Harward, E. D. 4-41
Hebley, H. F. 5-71, 5-73
Henby, E. B. 5-67
A-24
-------
Hengstebeck, R. J.
Hensinger, C. E.
Hewson, E. W.
High, M. D.
Hilst, G. R.
Holden, F. R.
Holland, J. Z.
Holzworth, G. C.
Honkasalo, J.
Hosier, C. R.
Hubbert, M. K.
Hughes, D. F.
Jimeson, R. M.
Johnson, A. R.
Johnson, C. A.
Jones, J. F.
Jorakin, J.
Junge, C. E.
Kaiser, E. R.
Kanter, C. V.
Kaplin, E. J.
Katell, S.
Kereiakes, J.
Kinney, G. T.
Knudson, J. F.
AUTHOR INDEX (Continued)
Page
5-14, 5-15, 5-19
5-9
6-16
5-52, 7-4, 7-5
6-19
6-15
6-17
6-20, 6-23
5-6, 5-7
6-22
4-18, 4-41
4-105, 4-112, 4-115
A-3, A-4, A-11
4-90
4-90
5-58
4-112, 4-122
6-22
4-44, 5-75
7-6
6-21
4-106, 4-117, 4-119
6-16
4-33, 4-35
5-5, 5-6
A-25
-------
AUTHOR INDEX (Continued)
Page
Kohl, Arthur L. 5-57
Koogler, J. B. 6-20
Kopita, R. 4-123
Korshover, J. 6-23
Landers, W. S. 6-17
Landry, J. T. 5-62, 5-63
Landsberg, H. H. 4-5, 4-6, 4-7, 4-8, 4-17, 4-41, 6-22
Lea, N. S. 5-67
Leavitt, J. M. 6-16, 6-20
Lesher, E. J. 6-21
Lowrie, R. L. 4-10
Lowry, P. H. 6-16, 6-19
Lucas, D. H. 6-18
Ludwig, J. H. 3-2, 3-3, 3-5, 3-7, 4-26, 4-27, 5-1,
5-2, 5-3, 5-6, 5-12
Maddox, R. N. 5-27
MaGill, P. L. 6-15
Mallette, F. S. 5-30, 5-34, 5-56
Malmstrom, R. 5-6, 5-7
Maples, R. E. 4-80, 4-81, 4-82, 4-90, 4-92, 4-95,
4-96, 4-97, 7-82
Marksley, G. F. 4-15
Martin, D. O. 6-20
Mazzarella, D. A. 6-19
McCormick, R. A. 6-19
McKinney, C. M. 4-17, 4-20, 4-22
A-26
-------
AUTHOR INDEX (Continued)
Miller, M. E.
Moeller, W.
Moore, J. A.
Moses, H.
Mulhern, J. J.
Munn, R. E.
Murphy, Z. E.
Neiburger, M.
Nelson, F.
Nemerow, N. L.
Netschert, B. C.
Norris, H. E.
Pack, D. H.
Parsons, J. L.
Pasquill, F.
Pearson, J. L.
Perkins, R. W.
Peterson, K. R.
Plants, K. D.
Plumley, A. L.
Pooler, F.
Potter, A. E.
Priestly, C. H.
Riesenfeld, Fred C.
Risser, H. E.
6-20
5-47, 5-49
4-126
6-18
5-71, 5-72, 5-73
6-15
4-10, 4-11, 4-12, 4-14, 4-54
6-22
6-23
5-60
4-2
5-71, 5-76
6-22
4-124, 5-79
6-15, 6-19
6-18
6-21
6-19
4-106, 4-117, 4-119
4-22, 4-112
6-19, 6-20
4-107
6-19
5-57
4-77
A-27
-------
AUTHOR INDEX (Continued)
je
Rohrnaan, F. A.
Rueckel, W. C.
Rummerfield, P. S.
Ryselin, J.
Saif-Ui-Rehman, N.
Schmid, M. R.
Schueneman, J. J.
Schuman, C. S.
Schurr, S. H.
Scorer, R. S.
Shaw, M.
Shelton, E. M.
Shenfeld, L.
Sheridan, E. T.
Sherlock, R. H.
Sholtes, R. S.
Shreve, R. N.
Shutko, F. W.
Simon, J. A.
Simons, R. A.
Simpson, C. L.
Singer, I. A.
Sittig, M.
Slack, A. V.
Slade, D.
3-2, 3-3, 3-5, 3-7, 4-26, 4-27, 5-1,
5-2, 5-3, 5-6, 5-12
5-53
6-16
5-6, 5-7
4-43
5-58
5-52, 7-4, 7-5
4-71, 4-82
4-2
6-15, 6-21
4-5, 4-9, 4-41
4-17, 4-20, 4-22
6-23
4-10, 4-11, 4-12, 4-14, 4-54
6-21
6-20
4-99, 5-77, 5-78
4-112, 4-122
4-11, 4-12
5-52
6-19
6-19, 6-22
4-24, 5-12, 5-24, 5-25
4-105, 4-113, 4-118, 4-119, 4-120,
4-121
6-15
A-28
-------
AUTHOR INDEX (Continued)
Page
Sledjeski, E. W. 4-80, 4-81, 4-82, 4-90, 4-92, 4-95,
4-96, 4-97, 7-82
Smith, J. W. 4-18
Smith, M. E. 6-17, 6-19, 6-22
Smith, T. B. 6-22
Smithson, G. R. , Jr. 5-67
Spaite, P. W. 3-2, 4-100, 4-105
Sporn, P. 6-17
Squires, A. M. 4-128, 4-130, A-6
Stahl, R. W. 5-73
Steigerwald, B. J. 3-3, 3-6, 4-26
Stern, A. C. 6-15
Stone, G. N. 6-17
Stormont, D. H. 5-12
Strom, G. H. 6-18, 6-21
Sullivan, F. P. 4-19, 4-33, 4-44
Sussman, V. H. 5-71, 5-72, 5-73
Sutton, O. G. 6-15, 6-21
Szepesi, D. J. 6-20
Tallent, R. G. 5-62, 5-63, 5-65
Thoen, G. N. 5-62, 5-63, 5-65
Thomas, F. W. 6-16, 6-17, 6-21
Tikvart, J. A. 6-20
Truedel, D. G. 4-18
Turner, D. B. 6-15, 6-20
Unzelman, G. H. 4-24, 5-12, 5-24, 5-25
A-29
-------
AUTHOR INDEX (Continued)
Page
Valdes, A. R. 5-27, 5-32
Van der Hoven, I. 6-22
Wakefield, R. E. 5-9
Weaver, C. L. 4-41
Wells, J. H. 5-54
West, J. R. 5-11
Whiddon, O. D. 4-112, 4-122
Whitman, M. 4-5, 4-9, 4-41
Wilson, P. J. 5-54
Winkler, K. 5-47, 5-49
Zwilling, J. P. 5-34
A-30
-------
SUBJECT INDEX
A
Absorption of SO2 4-102—4-105, 4-106—4-111,
4-112—4-116, 4-117, 4-118—4-122
Air blowing of asphalt 5-20
Air Quality Act of 1967
provisions of 1-1
Alkalized alumina process 4-102—4-106
Aqueous-solution sorption systems 4-122
B
Beckwell SO0 recovery process 4-117
^i
C
Carl still process 4-121
Catalytic oxidation process 4-112—4-117
Centralized powers production 4-128—4-133
COg acceptor process 4-78, A-13—A-19
Coal
cost of 4-46—4-47
desulfurization of 4-65—4-78, A-l—A-19
reserves and resources of 4-10—4-16
sulfur content 4-10—4-16, 4-65
Coal refuse burning 5-71—5-75
COED process A-3—A-8
Combustion of fuels
contribution to total SCv, emissions 3-1
Consol (CSF) process A-10—A-ll
Coke ovens 5-53—5-59
A-31
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Copper smelting
emission control from 5-1—5-7
Corn starch production
emissions from 5-77
Costs
alkalized alumina process 4-105—4-106
Beckwell SC^ recovery process 4-118
catalytic oxidation process 4-117
coal desulfurization 4-68—4-69, 4-72—4-73, 4-75
fuel oil desulfurization 4-82, 4-85, 4-87, 4-90, 4-93-4-98
limestone injection process 4-111—4-112
natural gas desulfurization 4-99
Crude oil (see Oil)
Culm-pile fires 5-73—5-75
Desulfurization of flue gas (see Flue gas)
Desulfurization of fuels (see specific fuel)
Dispersion of emissions (see Stacks)
Distillate fuel oils
general discussion of 4-16—4-30
Effective stack height 6-1—6-13
Electrogasdynamics (EGD) 4_i3i_4_i33
Emission factors of SC>2 7-1—7-5
Energy source substitution (see Fuel
substitution)
Energy sources producing no emissions 4-40—4-44
Flue gas desulfurization 4-100—4-124
Fuel cells 4-44
Fuel conversion problems 4-57—4-63
A-32
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Fuel oils
cost of 4-48—4-49
desulfurization of 4-78—4-98
Fuel substitution 4-45, 4-53—4-63
G
Gasification of coal 4-77—4-78, A-ll-A-19
Geothermal heat 4-43
Giammarco-Vetrocoke process 5-27
Glass manufacturing
emissions from 5-77
Grille process 4-120
Gulf-HDS hydrocracking process 4-83, 4-85
H
Heat reclaim systems 4-43—4-44
Heat recovery 4-125—4-126
High-pressure combustion 4-128—4-130
H-oil hydrocracking process 4-83—4-84
Hydrocracking 4-82—4-85, 5-14
Hydrodesulfurization of oil 4-82—4-85
Hydroelectric power production 4-37—4-39
Hydrogasification 4-77—4-78, A-ll—A-19
Hydrogen sulfide
combustion 5-75
production of in hydrogenation
of coal and oil A-6—A-7, A-9
I
Inorganic-liquid sorption systems 4-118—4-122
ISOMAX hydrocracking process 4-83
A-33
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Lead smelting
emission control from 5-8
Legislation affecting emission control 1-1, 4-25
Limestone-dolomite based injection
process 4-106—4-111
Liquefaction of coal 4-76—4-77, A-l-A-11
Liquid sulfur dioxide production
emissions from 5-78
Lurgi process 4-119
M
Magnetohydrodynamics (MHD) 4-130—4-131
Molten-carbonate process 4-121
Molten salt process A-14—A-19
Municipal incineration
sulfur content of 5-75
N
Natural gas
cost of 4-50—4-52
general discussion of 4-31—4-37
desulfurization of 4-98—4-99
reserves of 4-31—4-35
Natural-gas liquids
general discussion of 4-37
Nuclear power production 4-40—4-43
A-34
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o
Oil (see also Fuel oils)
reserves and resources of 4-16—4-21, 4-23, 4-27
sulfur content of 4-19—4-22, 4-24—4-26, 4-29—30
P
Paper manufacturing
general discussion of 5-60—5-70
emissions from 5-60—5-70
Petroleum refining
general discussion of 5-12
emissions from 5-17
control of SO 5-20—5-34
^
Plume rise
general considerations 6-3, 6-8—6-10
mathematical models of 6-6
field studies of 6-12—6-13
Power production
source of SO 3-1—3-7, 4-1—4-5
^
Projection of fuel usage 4-2—4-9
Pulp and paper mills 5-60—5-70
Pyrite sulfur removal 4-65—4-76
R
Reinluft process 4-118
Residual fuel oil
general discussion of 4-24—4-29
desulfurization of 4-78—4-90
A-35
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Sewage-sludge digester gas 5-75—5-76
Sewage sludge disposal
emissions from 5-75—5-76
Sewage treatment operations 5-75—5-76
Silicon carbide manufacturing
emissions from 5-78—5-79
Sintering 5-51-5-53
Site selection for emission sources
meteorological aspects of 6-7—6-10, 6-12—6-13
Smelters (see specific metal)
Solar energy production 4-43
Solvent refining process
description of A-l—A-3
Source testing of sulfur oxides 7-6—7-7
Sources of SO2
combustion 3-1, 3-4—3-5
industrial process 3-1, 3-6—3-7
Stacks
costs of 6-14
dispersion from 6-1—6-13
Sugar manufacturing
emissions from 5-78
Sulfate (Kraft) process
control methods for 5-62—5-66
emissions of SO2 5-62—5-66
Sulfite process
control methods for 5-66—5-68
emission of SO2 5-66—5-68
A-36
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Sulfur fusion processes
emissions from 5-78
Sulfur oxide
definition of 2-1
Sulfur plants
control of SC>2 from refineries 5-20—5-22
Sulfuric acid plants
control of SOg from refineries 5-20—5-22
general discussion of 5-41
emissions from 5-45—5-47
control methods 5-47—5-50
T
Tall stacks (see Stacks)
Titanium dioxide manufacturing
emissions from 5-79
Trend (see Projection)
Two-stage superpressure process 4-78, A-17—A-19
W
Waste disposal 5-71—5-76
Z
Zinc smelting
emission control from 5-9—5-11
A-37
U.S. GOVERNMENT PRINTING OFFICE • 1969 O - 331-543
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