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.

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      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

-------
                          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

-------
                          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

-------
                           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

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                         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

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                                 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

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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

-------

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                            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

-------

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       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

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                  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

-------
  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


 "10,000
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 •s.
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 10
                                I	I
     1850   1870    1890   1910   1930    1950   1970

                      YEAR
                                 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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Figure 4-2.  Future   energy  requirements  and
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            market.1'
                       4-6

-------
                             100
                             80
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                      Figure 4-3.  Future  fuel-use patterns for  resi-
                                   dential home heating."11
                                           4-7
331-543 O - 69 - 5

-------
                             32.34
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                                   COAL
                                   PETROLEUM
                                   NATURAL
                                      GAS
                                    LIQUIDS
                                   NATURAL
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Figure 4-4.  Future energy requirements and fuel-
            use   patterns   for  industrial   use
            (except electricity).11
                     4-8

-------
•o
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                                   NUCLEAR
                                   HYDRO AND
                                     OTHER
 FOSSIL FUELS
(COAL, OIL, GAS)
            1966
                     1980       2000
                          YEAR
          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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-------
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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-------
      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

-------
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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)
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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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4-58

-------
















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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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331-543 O - 69 - 9

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       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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-------
      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

-------
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



  331-543 O - 69 - 10

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                                                                                     4-89

-------
(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

-------
           I-1
           It
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                    §
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                                   4-93

-------
1.10



1.00



0.90



0.80



0.70



0.60



0.50



0.40



0.30



0.20



0.10
0.00
        T
T
T
T
         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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4-96

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4-97

-------
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

-------
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

-------
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

-------
      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

-------
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

-------
      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

-------
                             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

-------
      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

-------
 $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

-------
                                          CO
                                          0>
                                          o
                                          o
                                          o
                                          0)
                                          o
                                          w
                                          co
                                          CM
                                          co
                                          3
                                          o>
4-108

-------
      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

-------
U
>-
                                      To:
                                      UJUJ
                                  UJZ«

tt



o
o
1—


ui
u
z
a:
                       <2
                         i
                                                               CO
                                                               CO
                                                               CD
                                                               u
                                                               o
                                                               u
                                                               CO
                            o
                            *-•
                            o
                                                               a>

                                                               o
                                                               to
                                                               a>
      L_
                                                              CM

                                                              4
                                                               O)
                           4-110

-------
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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           Zi/>

           3S
           (J
                       ^ce
                       SO

                       <*<
                       £z
                       CO-
                       CKS


                       §^
                       <
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   N 10



   If
   U
     (J
a:
uu
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UJ
X
UJ
 Q
 UJ
 CQ
 U
                                     O

                                     UJ
                     O

                     fN
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                                                  O
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«

"x
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                             05
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                      _i o:1^
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                      !-«=!
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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

-------
    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

-------
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

-------
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

-------
      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

-------
      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

-------
      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

-------
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

-------
 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

-------
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

-------
     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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-------
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                                   4-136

-------
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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

-------
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

-------
                                                     0)

                                                     w

                                                     V)

                                                     >.

                                                     <5

                                                     O
                                                     (0
                                                     a)
                                                     T3

                                                     X
                                                     O
                                                     (0
                                                     .c

                                                     'i
                                                     O)
                                                     O.
                                                     O
                                                     O
                                                     £
                                                     3
                                                     O>
                                                     \L
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

-------
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

-------
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

-------
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

-------
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

-------
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

-------
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

-------
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

-------
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

-------
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

-------
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

-------
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

-------
    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

-------
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
Largest %
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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

-------
                                6?

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                                          il
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

-------
free SO0 content of oleum, there is an increase in SO  emissions to the
       o                                          o


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

-------
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

-------
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

-------
      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

-------
                                                   u)
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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

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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

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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

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                        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

-------
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

-------
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

-------
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.
                                   5-84

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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

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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

-------
      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

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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

-------
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

-------
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

-------
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

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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

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              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

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       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

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  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

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        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

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  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.
                                    A-l

-------
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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

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                             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

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                       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

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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

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                        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

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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

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                       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

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                        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

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                       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

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                        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

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                        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

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                             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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