EPA-450/1-78-001
       CONTROL TECHNIQUES
FOR NITROGEN OXIDES EMISSIONS
   FROM STATIONARY SOURCES -
          SECOND EDITION
           Emission Standards and Engineering Division
        U.S. ENVIRONMENTAL PROTECTION AGENCY
           Office of Air and Waste Management
          Office of Air Quality Planning and Standards
          Research Triangle Park, North Carolina 27711

                 January 1978

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This report has been reviewed by the Emission Standards and Engineering Division, Office of Air Quality Planning
and  Standards, Office of Air and Waste Management, Environmental Protection Agency, and approved for
publication. Mention of trade names or commercial products does not constitute endorsement or recommendation
for use. Copies are available free of charge to Federal employees, current contractors and grantees, and nonprofit
organizations - as supplies permit - from the Office of Library Services, Environmental Protection Agency, Research
Triangle Park, North  Carolina 27711; or copies may be purchased from the Superintendent of Documents, U.S.
Government Printing Office, Washington, D.C. 20460.
                                    Publication No. EPA-450/1-78-001

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                                                 PREFACE

         This document is the second edition of the EPA document entitled:  Control Techniques for
  Nitrogen Oxides Emissions from Stationary Sources.  This document was first published in 1970 as
  National Air Pollution Control Administration Publication No. AP-67.  Some sections of the second
  edition have been substantially modified from the original, and others have required only minor up-
  dating.  For example, Section 6 on NOX control  of nitric acid plants has been extensively rewritten.
  Additionally,  Section 8 of the original  edition,  "Nitrogen Oxides Emission Factors" has been incor-
  porated into Section 2.  Section 9,  "Possible New Technology" has been included in Section 3.   This
  revision incorporates reviewers'  comments  from drafts  of the second edition and adds new material  on
  the  energy  and  environmental  impacts  of  the  control  techniques  as required by Section 108 (b)  (1)  of
  the  1977 Clean  Air Act.
        The Energy and Environmental Division of Acurex Corporation  has prepared  this  document for
 the Environmental Protection Agency.  The EPA Project Officer was G. H. Wood, who was assisted by M.
 Davenport.  The Acurex Program Manager was H. B. Mason and the Project Engineer was R. M. Evans;
 principal contributors were A. Balakrishnan,  C. Castaldini, R. Schreiber, W. Toy, and L. R. Waterland.
        This  document has been reviewed by the Environmental Protection Agency, the National Air Pollu-
 tion  Control  Techniques Advisory Committee (NAPTAC),  and  many individuals associated with other Federal
 agencies, State  and  local  governments, and private industry.   The members of NAPTAC are listed  on the
 following page.   In  addition,  Acurex  acknowledges  the valuable assistance provided by the following
 individuals  and  their organizations:   J.  Copeland,  G. Crane,  M.  Davenport,  K.  Durkee,  R.  Iversen, T.
 Lahre,  A.  Trenholm, R.  Walsh,  G.  Wood  and K.  Woodward of  the  Office  of  Air  Quality Planning and  Stan-
 dards;  J.  S.  Bowen, R.  E. Hall,  D.  G.  Lachapelle, W. S. Lanier,  G. B. Martin and  J.  Wasser of the
 Combustion Research Branch, Industrial Environmental Research  Laboratory  (IERL);  R.  D.  Stern  of  the
 Process Technology Branch, IERL; Don Carey of the Division of  Stationary Source Enforcement,  IERL;
 John Pierovich of the U. S. Forest Service; W. Skidmore of the U. S. Department of Commerce;  Wes
 Pepper and J. Mulloy of the Los Angeles Department of Water and Power; J. Peregoy  and W. Barr of the
Pacific Gas and Electric Co., R. E. Levine of Southern California Edision and J. Johnson of Babcock and
Wilcox Co.
                                                iii

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                                U.  S.  ENVIRONMENTAL PROTECTION AGENCY

                    NATIONAL AIR POLLUTION CONTROL TECHNIQUES ADVISORY COMMITTEE
Chairman and Executive Secretary

Mr. Don R. Goodwin, Director
Emission Standards and Engineering Division
Office of Air Quality Planning and Standards
U. S. Environmental Protection Agency
Research Triangle Park, North Carolina  27711
                                          COMMITTEE MEMBERS
Dr. Lucile F. Adamson
1344 Ingraham Street, N. VI.
Washington, D. C.  20011
(Howard University Professor,
(School of Human Ecology)

Mr. 0. B. Burns, Jr., Director-
Corporate Environmental Activities
Westvaco Corporation
Westvaco Building, 299  Park Avenue
New York, New York  10017

Mr. Donald C. Francois, Assistant Director
Division of Natural Resources Management
Department of Conservation and Cultural Affairs
Post Office Box  578
St. Thomas, Virgin Islands  00801

Mr. Waldron H. Giles, Manager
Advanced Material and Space Systems  Engineering
General Electric Company
Reentry and Environmental Systems Division
3198 Chestnut Street, Room 6839B
Philadelphia, Pennsylvania  19101

Mr. James  K.  Hambright, Director
Department of Environmental Resources
Bureau of  Air Quality and Noise Control
Post Office  Box  2063
Harrisburg,  Pennsylvania  17120

Mr. W. C.  Hoi brook,  Manager
Environmental and  Energy Affairs
B. F.  Goodrich  Chemical Company
6100 Oak Tree Boulevard
Cleveland,  Ohio  44131

Mr.  Lee  E.  Jager,  Chief
Air Pollution Control  Division
 Michigan Department of Natural  Resources
 Stevens  T.  Mason Building  (8th floor)
 Lansing,  Michigan   48926

 Dr.  Joseph T. Ling,  Vice  President
 Environmental Engineering  and Pollution Control
 3M Company
 Minnesota Mining & Manufacturing Company
 Box 33331, Building 42-5W
 St. Paul,  Minnesota  55133
Mr. Marcus R. McCrayen
Assistant Vice President
of Environmental Engineering
United Illuminating Company
80 Temple Street
New Haven, Connecticut  06506


Mrs.  Patricia F. McGuire
161 White Oak Drive
Pittsburgh, Pennsylvania  15237
(Member of the Allegheny County
Board of Health, Pennsylvania)

Dr. William J. Moroz
Professor of Mechanical Engineering
Center for Air Environment Studies
226 Chemical Engineering, Building II
Pennsylvania State University
University Park, Pennsylvania  16802


Mr. Hugh Mullen, Director
of Government and Industry Relations
I. U. Conversion Systems, Inc.
3624 Market Street
Philadelphia, Pennsylvania  19104

Mr. C. William Simmons
Air Pollution Control Officer
San Diego Air Pollution Control District
9150 Cheasapeake Drive
San Diego, California  92123

Mr. E. Bill Stewart, Deputy Director
Control and Prevention
Texas Air Control Boad
8520 Shoal Creek Boulevard
Austin, Texas  78758

Mr. Victor H. Sussman, Director
Stationary Source Environmental
 Control Office
Ford Motor Company
Parkland Towers West, Suite 628
Post Office Box 54
Dearborn, Michigan  48126
                                                   iv

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                                          TABLE OF CONTENTS

Section
                                                                                             Page
          LIST OF FIGURES .....                                                          ~^
                                        .........................      ix
          LIST OF TABLES  ....
                                      ..........................     xi1
          SUMMARY ...................
                                          .........................    xvi
   1       INTRODUCTION   .  .  .
                                ..............................    1-1
   2       CHARACTERIZATION OF NOY EMISSIONS  .  .
                                *                  .....................    2-1
          2.1  Definitions and Formation Theory
          2.2  Sampling and Analysis Methods   . .   ....................    ;'J
          2.3  Equipment Descriptions, Emissions Estimates! Emission "Factors ........
              and Fuel Usage by Application Sector ..........     .......      2_3

         2.3.1  Utility Boilers  .....
         2.3.2  Industrial Boilers ...... ......................   2'6
         2.3.3  Commercial and Residential Space Heating .' .' ! ..............   I'M
         2.3.4  Internal Combustion  ......... . .....'.'.'.' .........   ?~2?
                                                    Combust1on E"9ines ..........   2.22
                                                                 .............   2-25
         2.3.5  Industrial  Process Heating .  .
         2.3.6  Incineration	   2"2'
         2.3.7  Noncombustion Sources       	   2"31
         2.3.8  Other NOY  Emissions  ...'!.'	   2"31
                        x                         	   2-34
         2.4   Summary of 1974 NO   Emissions and  Fuel  Consumption  ....                      ? o,
         2.5   NOX  Emission  Trends  and  Projections   ............'.	   2 34

         REFERENCES FOR  SECTION 2
                                   	   2-48
 3       CONTROL TECHNIQUES   	
                                                                   *"*•*•••••••   ,j™ |
         3.1  Combustion Modifications 	
                                                               *"**••••••••••    ,3~ |
        3.1.1  Factors Affecting NOX Emissions from Combustion	    3_-,

        3.1.1.1  Thermal NO   ....
        3.1.1.2  Fuel NO   x  ....'.'.'.	    3'2
        3.1.1.3  Summary xof Process Modification'concepts' '  .' .' .' .' .* .' .' .' .' .' .' .' .' .' ;    3^5

        3.1.2  Modification of Operating Conditions ...                                    -> -,<-
                                                          	    J-lb
        3.1.2.1   Low  Excess Air Combustion      ....                                      , lc
        3.1.2.2  Off-Stoichiometric Combustion	'.    	    t ,q
        3.1.2.3  Flue Gas  Recirculation    	    	    ,1;:
        3.1.2.4  Reduced Air Preheat Operation   ...    	    0*07
        3.1.2.5   Load Reduction   	]	     '*'
        3.1.2.6   Steam and  Water  Injection  	  .    	    o"™
        3.1.2.7   Ammonia Injection	        	    ,f[j
        3.1.2.8   Combinations of Techniques	.'.".'."!.'.'.'.'!."!!.''"'"    3!34

        3.1.3   Equipment Design Modifications 	          3_34

        3.1.3.1  Burner  Configuration	                                            , -,.
        3.1.3.2  Burner  Spacing	"'.'.'.'  1  .'!.*.'.'!.'!!  I.'"''    ^37

        3.1.4  Fuel Modification	                                          0 00
                                                   	••	    o-oo
        3.1.4.1  Fuel  Switching 	                                                , „
        3.1.4.2  Fuel  Additives	     	    3"3°
        3.1.4.3  Fuel  Denitrification	.'	    ™

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                                   TABLE OF CONTENTS (Continued)


Section                                                                                     ^3^

          3.1.5  Alternate Processes 	     3-42

          3.1.5.1  Fluidized Bed Combustion  	     3-42
          3.1.5.2  Catalytic Combustion  	     3-44
          3.1.5.3  Repowering  	  	     3-45
          3.1.5.4  Combined Cycles	     3-46

          3.2  Combustion Flue Gas Treatment 	     3-47

          3.2.1  Dry Flue Gas Treatment	     3-47
          3.2.2  Wet Flue Gas Treatment	     3-49

          3.3  Noncombustion Gas Cleaning  	     3-51

          3.3.1  Plant Design for NOX Pollution Abatement at New Nitric Acid Plants  .  .  .     3-52

          3.3.1.1  Absorption Column Pressure Control  	     3-52
          3.3.1.2  Strong Acid Processes	 •  •     3-52

          3.3.2  Retrofit Design for N0y Pollution Abatement at New or Existing
                 Nitric Acid Plants  .	     3-53

          3.3.2.1  Chilled Absorption   	     3-54
          3.3.2.2  Extended Absorption  	     3-54
          3.3.2.3  Wet Chemical Scrubbing  	     3-54
          3.3.2.4  Catalytic Reduction  	     3-57
          3.3.2.5  Molecular Sieve Adsorption   	     3-59

          REFERENCES FOR SECTION 3	     3-59

   4      LARGE  FOSSIL FUEL COMBUSTION  PROCESSES    	  	     4-1

          4.1  Electrical Utility Boilers   	     4-1

          4.1.1  Control Techniques	     4-2

          4.1.1.1  Combustion Modification  	     4-2
          4.1.1.2  Flue Gas Treatment	     4-19
          4.1.1.3  Fuel Switching   	     4-23
          4.1.1.4  Fuel Additives   	     4-24

          4.1.2  Costs	     4-24

          4.1.2.1  Combustion Modification  	    4-25
          4.1.2.2  Fuel Gas Treatment	    4-33

          4.1.3  Energy and Environmental  Impact  	    4-33

          4.1.3.1  Energy  Impacts   	    4-35
          4.1.3.2  Environmental  Impact  	    4-36

          4.2   Industrial  Boilers   	    4-48

          4.2.1  Control Techniques  	    4-48
          4.2.2  Costs	    4-55
          4.2.3  Energy  and  Environmental  Impacts  	    4-55

          4.3   Prime Movers	    4-62

          4.3.1  Reciprocating Internal Combustion Engines 	    4-62
                                                  vi

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                                   TABLE OF CONTENTS (Continued)

Section
                                                                                               Page
          4.3.1.1   Control Techniques .
          4.3.1.2   Costs  ........."!.'.".".'.'	    4'62
          4.3.1.3   Energy and Environmental  impact	    4"70
                                                      	    4-76
          4.3.2 Gas Turbines ....
                                        "  '  '	    4-83
          4.3.2.1   Control  Techniques  .  .
          4.3.2.2   Costs  .  .  .	;  ."  .'	    4-88
          4.3.2.3   Energy and Environmental  impact'  .......'.'.'.',  '*	    ?"92
          4.4   Summary   ....
                                  	    4-98
          REFERENCES TO  SECTION 4  .
                                      	    4-101
  5       OTHER COMBUSTION PROCESSES   	
                                                                          "••••••••     0"|
          5.1  Space Heating   	
                                                                          **•••••••     0** I
          5.1.1  Control Techniques .   .
         5.1.2  Costs   . . .	.'.'.'.'."	     5'4
         5.1.3  Energy and Environmental impact  ........ 	     f"7
                                                         	     5-8
         5.1.3.1   Energy Impact  	
         5.1.3.2   Environmental  Impact .     	     5"8
                                           	     5-8
         5.2  Incineration and Open Burning
                                             	    5-10
         5.2.1  Municipal and Industrial  Incineration
                                                                       *"*•••••••    0" i \j
         5.2.1.1   Emissions   	
         5.2.1.2   Control  Techniques  	    5-1]
         5.2.1.3   Costs   .  .          	    5-11
                               	    5-14
         5.2.2  Open Burning  ....
                                   	    5-14
         5.2.2.1   Emissions   ....
         5.2.2.2   Control Techniques ..'.'.'!.*.'.'!.'	    5'14
                                            	    5-15
         5.3  Industrial  Process Heating 	
                                              	     5-18
         5.3.1  Petroleum and  Natural  Gas
                                            	     5-19
        5.3.1.1  Process Description  	
        5.3.1.2  Emissions and Control Techniques 	     5"19
                                                  	     5-20
        5.3.2  Metallurigical Process .
                                        	     5-25
        H'H  I?™"55 Description  and Control Techniques ...                             , «
        5.3.2.2  Emissions  . .                                  	     5-25
                                  ' "	     5-32
        5.3.3  Glass Manufacture  .
                                      	     5-34
        5.3.3.1  Process Description   .
        5.3.3.2 Emissions	.'      	     5-34
        5.3.3.3 Control Techniques .  '.	"	    5"38
                                          	    5-40
        5.3.4   Cement Manufacture  .  .  .
                                          	    5-40
        5.3.4.1  Process Description   .  .
        5.3.4.2 Emissions   ...            	    5-40
        5.3.4.3 Control  Techniques .....'.	    5'42
                                              	    5-43
        5.3.5   Coal  Preparation Plants   ...
                                                	     5-44
        REFERENCES  FOR SECTION 5
                                   	     5-46
                                              vi i

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                       TABLE OF CONTENTS (Concluded)


                                                                                   Page

NONCOMBUSTION PROCESSES 	 ,  	    6'1

6.1  Nitric Acid Manufacture	     6-2

6.1.1  Dilute Nitric Acid Manufacturing Processes   . . .	     6-2

6.1.1.1  Single Pressure Processes 	     6-4
6.1.1.2  Dual Pressure Processes   	     6-4
6.1.1.3  Nitric Acid Concentration 	     6-7
6.1.1.4  Direct Strong Nitric Acid Processes 	     6-7

6.1.2  Emissions	    6-10
6.1.3  Control Techniques for NOX Emissions from Nitric Acid Plants 	    6-11

6.1.3.1  Chilled Absorption  	    6-14
6.1.3.2  Extended Absorption   	    6-16
6.1.3.3  Wet Chemical Scrubbing   	    6-16
6.1.3.4  Catalytic Reduction	    6-25
6.1.3.5  Molecular Sieve Adsorption    	    6-29

6.1.4  Costs    	    6-33

6.2  Nitric Acid Uses	    6-36

6.2.1  Ammonium Nitrate Manufacture 	    6-36

6.2.1.1  Process Description   	    6-36
6.2.1.2  Emissions   	    6-38

6.2.2  Organic Oxidations    	    6-38

6.2.2.1  Process Description  	    6-38
6.2.2.2  Emissions   	    6-39
6.2.2.3  Control Techniques  	    6-39
6.2.2.4  Costs   	    6"40

6.2.3  Organic Nitrations  	    6-40

6.2.3.1  Process Description  	    6-40
6.2.3.2  Emissions	    6-46
6.2.3.3  Control Techniques  	    6-47
 6.2.3.4  Costs
                                                                                    6-49
 6.2.4  Explosives:   Manufacture and Use	     6-49

 6.2.4.1   Process  Description   	       6-49
 6.2.4.2  Emissions   	       6-50
 6.2.4.3  Controls   	       °'^
 6.2.4.4  Costs  	       6"5Z

 6.2.5  Fertilizer Manufacture 	     6-52
 6.2.6  Metals Pickling	     6-54

 REFERENCES FOR SECTION 6	     6-55

 APPENDIX A - SELECTED TABLES IN ENGLISH UNITS 	     A-l
 APPENDIX B - PREFIXES FOR SI UNITS	     B-'
 APPENDIX C - GLOSSARY	     --'
                                      VI11

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                                           LIST OF FIGURES
  Figure
                                                                                              Page
  2-1     Stationary sources of N0₯ emissions 	                                  „ „
                                  x                       	    t-4
  2-2     Summary of 1974 stationary source NO  emissions	                     9 -,7
                                              A                       *•••••••••«    t"~O/
  2-3     Nationwide annual  NOV emission trends 1940-1972 .                                     o /.n
                              *                               	    £-*tU
  2-4     Annual  stationary  source NOX  emission trends   	           2_41
  2-5     Annual  stationary  source NOX  emissions  projections  -  low nuclear                     2-46
  2-6     Annual  stationary  source NOX  emissions  projections  -  high  nuclear  	       2-47
  3-1      Kinetic  formation  of  nitric oxide for combustion of natural qas
          atmospheric pressure   .  .                                        	
                                        	     3-4
  3-2      Nitrogen and sulfur content of U.S. coal reserves	         3_10
  3-3      Percent conversion of fuel nitrogen to NO  in
          combustion  ....                      x
                             	     3-11
  3-4      Possible fate of fuel nitrogen contained in coal particles or oil
          droplets during combustion  	
 3-5     Conversion of nitrogen in coal to NO  	
                                             X                     •••«•••••••.    O "• I H
 3-6     Corner windbox showing overfire air system  	                3_21
 3-7     Two-stage combustion  	
                                                               """*••*•••••••     o™ L.C.
 3-8     N0x vs.  theoretical  air,  overfire air study ..............               3_23
 3-9     N0x vs.  tilt differential,  overfire air study ..............             3_23
 3-10     N0x vs.  theoretical  air,  biased  firing study,  maximum  load   ...........     3_24
 3-11     Effect of  FGR on NO  emissions    .....                                             0  or
                                                     ...................     o-£o
 3-12     Reduced  air  preheat  with  natural  gas  firing,  320 MW corner-fired unit  ......     3-28
 3-13     Correlation  of NOX emissions with water  injection rate for natural qas
         fired gas  turbine (Houston L&P Wharton No. 43  unit) ........    .....       3_31
 3-14     Comparison of NOX emissions with pulzerized coal firing, circular
         burner vs. dual register  burner  .......                                         ,  ,,
3-15    Extended absorption system on existing nitric acid plant  ............    3.55
4-1     NOX emissions from gas, tangenti ally-fired utility boilers  ...........    4_8
4-2     Effects of NOX control methods on a gas, wall-fired utility boiler ........    4_]0
4-3     NOX emissions from residual  oil, tangenti ally-fired utility boilers .......    4.12
                                               ix

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                                                                                            Page
        Effects of NOX controls  methods on  an  oil,  wall-fired  utility  boiler  	   4-13
        NOX emissions from tangential, coal-fired utility boilers    	   4-17
        Effect of burner stoichiometry on NOX  production in tangential,
        coal-fired boilers 	   4-18
4-7     1975 capital  cost of overfire air for  tangential, coal-fired boilers  	   4-26
4-8     S02 conversion vs. excess oxygen in coal-fired utility boilers 	   4-45
4-9     Effect of combustion modification methods on total  nitrogen oxides
        emissions and boiler efficiency  	   4-49
4-10    The influence of flue gas recirculation on NO  emissions from a  firetube
        boiler	4-51
4-11    The influence of flue gas recirculation on NO  emissions from a  watertube
        boiler	4-51
4-12    Effect of NO  controls on solid particulate emissions  from, industrial
        boilers  . .x	4-60
4-13    Effects of NO  controls  on particulate size distribution from oil-fired
        boilers  . .  ?	4-61
4-14    Effect of NOV emissions  level on fuel  penalty for light-duty trucks  	   4-77
                    A
4-15    Effect of derating on 1C engine HC emissions 	   4-80
4-16    Effect of retarding ignition on 1C engine HC emissions 	   4-80
4-17    Effect of air-to-fuel ratio on 1C engine HC emissions   .	4-81
4-18    Effect of decreased manifold air temperature on 1C engine HC emissions 	   4-82
4-19    Effect of water injection on 1C engine HC emissions  	   4-82
4-20    Smoke levels versus NOX level for large-bore diesel engines  	   4-84
4-21    NOV emissions from large gas turbines  without NOV controls 	   4-86
          X                                             X
4-22    NO  emissions from small gas turbines  without NO  controls 	   4-87
          X                                             **
4-23    NO  emissions from gas turbines having NO  controls and operating on
        liquid fuels	4-91
5-1     General trend of smoke, gaseous emissions, and efficiency versus
        stoichiometric ratio for residential heaters 	   5-3
5-2     Effect of excess air on NOX emissions  from a 45.3 Mg (50 ton) per day
        batch-feed incinerator 	   5-12
5-3     Effect of underfire air on NO  emissions from a 227 Mg (250 ton) per  day
        continuous-feed incinerator  	   5-13
5-4     Effect of process rate on NO  emissions from a process heater  	   5-22
5-5     NO emissions as a function of time for an open hearth furnace	5-36

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 Figure
                                                                                               Page
 5-6    The effect of cement kiln temperature on NO emissions 	        5_45
 6-1    Single pressure nitric acid manufacturing process
                                                                        ******•••••  D"0
 6-2    Dual pressure nitric acid plant flow diagram	            6_6
 6-3    Nitric acid concentrating unit  	
                                              	6-8
 6-4    Process flow diagram for direct production of highly concentrated nitric acid ....  6-9
 6-5    Schematic flow Sheet of the CDL/VITOK NOX removal  process 	  6_15
 6-6    TVA chilled absorption  process  ...                                                   ,  ,.,
                                              	6-17
 6-7    Grande  Pariosse  extended absorption  process  for  NO  abatement  	  6_18
 6-8    Flow diagram of  the  MASAR process
 6-9    Process  flow diagram for the Goodpasture  process   	       6_23
 6-10    Nonselective  catalytic  reduction system 	           6_26
 6-11   Molecular sieve  system   	                                                     c  ~n
                                               	o-ju
 6-12   Batch process for the manufacture of nitroglycerin (NG) 	           6-42
 6-13   Schmid-Meissner continuous-nitration plant   	                   6_43
6-14   Biazzi  continuous-nitration plant 	
6-15   Recovery of spent acid	                                                  c  ...
                                                 	o-4b
6-16   Trinitrotoluene (batch process) manufacturing diagram 	  6.51
                                                XI

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LIST OF TABLES
Table
2-1
2-2

2-3

2-4
2-5
2-6

2-7
2-8
2-9
2-10
2-11

2-12
2-13
2-14
2-15

2-16
2-17
2-18
2-19
2-20
2-21

2-22
2-23
2-24
2-25
2-26
2-27
2-28

Quality of Emission Factors for Oxides of Nitrogen . . 	
Emissions, Emission Factors, and. Fuel Usage for Steam
Generation, 1974 -Utility boilers . .t 	
Annual NO Emissions and Fuel Consumption Comparison for
Utility B8ilers, 1974 	 • • , 	
Annual Fuel Usage for Utility Boilers (EJ) 	
Annual NOX Emissions for Utility Boilers (Tg) 	 	
Emissions, Emission Factors, and Fuel Usage for Steam Generation,
1974 - Industrial Boilers 	
Annual Fuel Consumption for Industrial Boilers . 	
Annual NO Emissions from Industrial Boilers 	
Emissions, Emission Factors, and Fuel Usage for Commercial Boilers, 1974 ....
Emissions, Emission Factors, and Fuel Usage for Residential Space Heating, 1974.
Summary of Annual NO Emissions and Fuel Consumption for Commercial and
Residential Space Heating, 1974 	
Annual Fuel Usage for the Commercial/Residential Sector, (EJ) 	
Annual NOX Emissions from Commercial Boilers (Gg) 	
Annual NOX Emissions from Residential Space Heating (Gg) 	
Emissions, Emission Factors, and Fuel Usage by Equipment Category for
Internal Combustion Engines, 1974 	
Annual Fuel Consumption by Internal Combustion Engines (PJ) 	
Annual NO Emissions from Internal Combustion Engines (Gg) 	
Summary of Annual Emissions for Industrial Process Heating Equipment (Gg) . . .
Summary of Annual NO Emissions from Incineration . 	
Summary of Annual Emissions for Noncombustion Sources 	
Estimates of Annual NOW Emissions from Other Sources 	
X
Summary of Total Annual NOX Emissions from Fuel User Sources, 1974 	
Summary of Annual Fuel Usage, 1974 	
Comparisons of Annual NO Emissions Data 	
Annual Fuel Consumption Comparisons 	
Annual Nationwide NOX Emissions Projected to 2000 	
Estimated Future NSPS Controls 	
Annual Nationwide NO,, Emissions to 2000 	
Page
2-5

2-9

2-10
2-11
2-12

2-15
2-17
2-18
2-20
2-21

2-21
2-23
2-24
2-24

2-26
2-28
2-28
2-32
2-33
2-33
2-33

2-35
2-36
2-38
2-39
2-42
2-44
2-45
     xn

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 Table
                                                                                              Page
 3-1       Factors  Controlling  the  Formation  of Thermal  NO

 3-2       Analyses of Typical  U.S.  Fuel Oils  	
                                                           	   3-8
 3-3       Analyses of Typical  U.S.  Coals and  Lignite  	

 3-4       Summary  of  Combustion Process Modification Concepts
                                                                     ************   «3"" I /
 3-5       Summary  of  Results with Ammonia Injection

 3-6       NOX Formation Potential of Some Alternate Fuels

 4-1       Range of Uncontrolled Utility Boiler NO  Emissions

 4-2       Summary of Combustion Modification Techniques for Large Boilers  	      4.4

 4-3      Major Japanese Dry FGT Installations (Selective Catalytic Reduction) 	    4.2Q

4-4      Major Japanese Wet FGT Installations 	



                                                                                	    4-27


                                                                                	    4-29
                                                                                                3-33

                                                                                                3-40
         Los Angeles Department of Water and Power Estimated  Installed  1974 Capital
         Costs for NOX Reduction Techniques on Gas and Oil-Fired Utility Boilers
 4-7                                                           nsae        apta
                                                                                               4-30

 4-8      1975 Differential Operating Costs of Overfire Air on New and Existina
          Tangential Coal-Fired Utility Boilers  ............... \                4_31

 4-9      Impact of NOX Control Techniques on Major Utility Boiler Components  .......    4.32

 4-10     Cost Estimates for Combustion Flue Gas Treatment Processes ............    4.34

 4-11      Effects of Retrofit Combustion Modification NO  Controls on Utility
          Boilers Efficiency .............. x .........
 4-12     Representative Effects  of NOX  Controls  on  CO  Emissions  from Utility Boilers   .  .  .    4-38

 4-13     Effects  of NO  Controls on Particulate  Emissions  from Coal-Fired
          Utility  Boilers  	                                .

 4-14     Effects  of NO  Controls on Emitted  Particle Size  Distribution
          from  Coal-Firld Utility Boilers	                4_43

 4-15     SOX Emissions  Summary for Utility Boilers  	          4_46

 4-16     Summary  of POM Emission Tests  for a Coal-Fired Utility Boiler  	    4.47

 4-17     Effects  of NOX Controls  on  CO  Emissions from  Industrial Boilers  	    4.57

 4-18     Representative Effects  of  N0y  Controls on Vapor Phase Hydrocarbon
          Emissions  from Industrial  Boflers   	                  4_5g


 4~19     CoSJstion  EnSnesSSi°n  C°ntro1 Techniclues for Reciprocating Internal
                            	   4-63

 4-20     Effect of  N0x  Controls  on Large-Bore Internal  Combustion Engines 	   4.65


         1975 California 13.4 G/KWHR (l^G/HP-HR) combined  NOX and HC°Levels *° *?**.  .  .  .    4-67

4-22     1975 Vehicle Emission Limits .                                                        . cn
                                                	    H-DO
                                                xiii

-------
Table
4-23
4-24
4-25
4-26
4-27

4-28

4-29

4-30
4-31
4-32
4-33
4-34
4-35

4-36
5-1
5-2
5-3

5-4
5-5

5-6
5-7
5-8
5-9
5-10

6-1
6-2
6-3
6-4

6-5

Emission Control Techniques for Automotive Gasoline Engines 	
Emission Control Systems for Conventional Gasoline Internal Combustion Engines. .
Cost Impacts of NOX Controls for Large-Bore Engines 	
Typical Baseline Costs for Large (> 75 kW/cylinder) Engines 	
Typical Controls Costs for Diesel-Fueled Engines Used in Heavy-Duty Vehicles
(>2700 kg or 3 tons) 	
Estimates of Sticker Prices for Emissions Hardware from 1966 Uncontrolled
Vehicles to 1976 Dual-Catalyst Systems 	
Representative Effects of NOX Controls on CO Emissions from Internal
Combustion Engines 	
Relationship Between Smoke, EGR, and Retard 	
Gas Turbine - Summary of Existing Technology - Combustion Modifications 	
Impact of NOX Emission Control on the Installed Capital Cost of Gas Turbines. . .
Water Injection Costs, Mills/kWh 	
Representative Effects of NOX Controls on CO Emissions from Gas Turbines 	
Summary of the Effects of NO Controls on Vapor Phase Hydrocarbon
Emissions from Gas Turbines 	
Summary of NOV Controls Technology 	
X
Nationwide N0y Emissions from Space Heating Projected to 1990 	
Comparison of Mean Emissions for Cyclic Runs on Residential Oil-Fired Units . . .
Effect of Low-NO Operation on Incremental Emissions and System Performance
for Residential Warm Air Furnaces 	
Annual Emissions of Nitrogen Oxides from Open Burning 	
Effects of NOV Controls on NOV Emissions from Petroleum Process Heaters 	
X X
NOX Emissions from Petroleum Refinery CO Boilers 	
Estimated NO Emissions from Steel Mill Processes and Equipment 	
Effects of NOX Controls on Steel Industry NOX Emissions 	
NOX Emissions from Glass Melting Furnaces 	
Recommended Programs for Reducing Emissions and Energy Consumption in the
Glass Industry 	
NOX Abatement Methods on New or Existing Nitric Acid Plants 	
Performance of Hercules Purasiv N Unit During Three-Day Run 	
Performance of U.S. Army-Holston Purasiv N Unit During Three-Day Run 	
Capital and Operating Costs for Different NOX Abatement Systems in a 270 Mg/d
Nitric Acid Plant 	
Annual Energy Requirements (TJ) for NO Abatement Systems for a 270 Mg/d
Nitric Acid Plant 	 	
4-68
4-69
4-72
4-72

-73

4-74
470

4-85
4-89
4-93
4-94
4-97

4-97
4-99
5-2
5-5

5-9
5-15
5-21

5-24
5-33
5-35
5-39

5-41
6-12
6-31
6-32

6-34

6-35
                                                xiv

-------
Table
                                                                                              Page
6-6      Basis for Tables 6-4 and 6-5 	
                                              •••'«•'•  	     6-35
6-7      Annual Nitric Acid Consumption In the United States,  1974   	     6_37
6-8      Estimated NOX Emissions from Organic Nitrations 1n 1970  	     6_48
6-9      Emission Factors for Manufacture of Explosives 	             6_53
                                               xv

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                                               SUMMARY

       In this document, the term "nitrogen oxides" or "NO " refers to either or both of two gaseous
oxides of nitrogen, nitric oxide (NO), and nitrogen dioxide (NOo).  These substances are important
in air pollution control because they are involved in photochemical reactions in the atmosphere and
because, by themselves, they have harmful effects on public health and welfare.

CHARACTERIZATION OF NOX EMISSIONS
       Manmade oxides of nitrogen are currently emitted at a rate in excess of 20 Tg (22 million
tons/yr) in the United States.  Stationary sources account for approximately 60 percent of these
emissions, of which 98 percent are due to combustion sources.  Combustion generated NO  is derived
from two separate formative mechanisms, thermal NO  and fuel NO .  Thermal  NO  results from the
thermal fixation of molecular nitrogen and oxygen in the combustion air.   This is the dominant
mechanism with the firing of clean fuels such as natural gas and distillate oil.  Fuel NO  results
from the oxidation of organically bound fuel  nitrogen compounds.   This can be the dominant mechanism
with the firing of coal and high nitrogen residual oils.  The rate of formation of both thermal NO
and fuel NO  is strongly dependent on the combustion process conditions.   The emissions due to both
mechanisms are increased by intense combustion resulting from rapid mixing of the air and fuel
streams.  Additionally, the emissions due to thermal NOX are sharply increased by increased local
combustion temperatures.
       Since equipment process conditions and fuel type are so important  in determining NO  emissions,
the characterization of emissions and the evaluation of control potential requires detailed classi-
fication of stationary sources according to factors known to influence NO  formation.   Over 100
combinations of equipment type and fuel type are identified as having significantly different poten-
tial for NOX emissions and/or NOX control.  The emission compilation for  these sources for the year
1974 shows, however, that the 30 most significant equipment/fuel  combinations are responsible for
over 80 percent of stationary source emissions.
                                                xvi

-------
        The total nationwide emissions in 1974 for stationary sources,  grouped according  to applica-
 tion sector, are shown on Figure S-l.  On an uncontrolled basis,  utility boilers  accounted for over
 40 percent of stationary source emissions.   These boilers fired 61  percent coal,  18  percent oil,  and
 21 percent gas.  For all stationary sources, the firing of coal yielded  35 percent of  total  NO
 emissions while comprising only 28 percent  of stationary source fuel consumption.  Conversely,  natural
 gas comprised 42 percent of stationary source fuel  consumption, but generated only 34  percent  of  sta-
 tionary source NOX.   Although  some sectors  shown on the figure, such as  noncombustion  sources,  are
 small  on a nationwide scale, they may be crucial  in local  NO  abatement  programs.
 CONTROL TECHNIQUES
        Current  and  advanced methods  for  stationary  source  N0x control operate either through suppres-
 sion of NOX  formation  in  the  process  or  through  physical or chemical removal of NO  from the stack
 gases.   Suppression of NOX formation  is  most effective with combustion sources.  Candidate approaches
 include combustion  process modification  through  alteration of operating conditions on existing sys-
 tems or alternate design  of new units, fuel modification through fuel switching, fuel denitrifica-
 tion, or fuel additives,  and  use of alternate combustion concepts such as catalytic combustion and
 fluidized bed combustion.  Removal of N0x from stack gases is most effective with noncombustion
 sources  of NOX, chiefly chemical manufacturing.  Candidate approaches include catalytic reduction,
 with wet chemical scrubbing,  extended and chilled absorption, and adsorption with molecular sieves.
 A summary of general stationary source NOX control techniques is given on Table S-l.
       Combustion process modifications  have been extensively implemented on existing gas and oil
 fired utility boilers  to  comply with  local emission standards.  External  control techniques such
 as low excess air firing, biased burner  firing, overfire air and flue gas recirculation have
 yielded  emission reductions up to 60 percent of uncontrolled, baseline operation.   A summary of
 combustion modification concepts is given in Table S-2.
       With coal firing,  the most effective combustion modification technique for  utility boilers
 is a combination of low excess air firing and off-stoichiometric combustion through biased  firing,
 overfire  air, or use of delayed mixing burners.   Utility boiler manufacturers are  currently includ-
 ing these procedures in new unit designs to comply with  the Standard  of Performance for New Sta-
 tionary Sources of 301  ng/J (0.7 Ib N02/106  Btu).  Retrofit implementation of low  excess air and
 off-stoichiometric combustion has shown  that a  level  of  258 ng/J (0.6 Ib  N02/106 Btu)  is achievable
with some unit designs.  Emission levels  as  low as 189 ng/J (0.44 Ib  N02/106  Btu)  have  been  demon-
 strated on a  tangentially fired unit  equipped with factory  installed  overfire air.   Current
                                                 xvi i

-------
                                           Commercial/
                                           residential
                                       space heating
                                       9.0%
      Utility boilers
      41.9%
 Reciprocating 1C
 engines 19.8%
                       Industrial
                       boilers 18.2%
                                                     Incineration 0.3%

                                                     Gas turbines 2.0%

                                                     Others 3.6%

                                                     Noneombustion 1.7%

                                                     Industrial process
                                                     heating 3.5%
Source

Utility Boilers
Industrial Boilers
Reciprocating 1C Engines
Coranercial/Residential Heating
Industrial Process Heating
Noncombustion
Gas Turbines
Incineration
Other

TOTAL
   Estimated N0x Emissions

  Fg         106 Tons
   105
   218
   628
   444
 2.413
 1.090
 0.432
 0.203
 0.236
 0.039
 0.435

12.171
13.416
  Figure S-l.  Summary of 1974 stationary source N0₯ emissions.
                              xvili

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 developmental  activity is  focusing  on  identifying and,  if  required, correlating  operational  problems,
 such as  increased  waterwall  corrosion  with  boiler tubes of conventional chemical composition when
 exposed  to  the reducing conditions  at  the surface resulting from combustion modifications.
        Retrofit combustion process modifications have also been extensively applied to gas
 turbines.  Water injection has been successfully implemented to achieve emission levels of 75 ppm
 at 15 percent excess oxygen.  Current activity is  focusing on development of dry controls using
 premixing,  prevaporization and controlled mixing for application to new combustor can designs.
        There has been only limited field implementation of combustion process modification for other
 stationary  combustion equipment e.g.,  industrial and commercial  boilers,  residential  and commercial
 space heating equipment,  reciprocating internal  combustion engines and industrial  process furnaces.
 The following sequence is  being pursued for N0x  control  development for these sources:  control  from
 operational fine tuning (e.g.,  low excess air firing,  burner  tuning), minor retrofit  modifications
 (e.g.,  biased burner firing),  extensive hardware changes  (e.g.,  new burners)  and major  new equipment
 redesign (e.g.,  optimized  heat  transfer surfaces and burner aerodynamics).
        Fuel  switching for  N0x control  is not  currently  practiced due  to the supply  shortage  of
 clean fuels.   A  number of  alternate fuels such as methanol and low-heating-value gas  have low NO -
 forming  potential  and may  be utilized  in the  1980's.  The  economic  incentive  for alternate fuel use
 usually  depends  on factors other than  N0x control, e.g., desulfurization cost  tradeoffs,  system
 efficiency.
       Fuel oil  denitrification, usually as an adjunct to  oil desulfurization, shows  promise for re-
 ducing fuel N0x.  This concept may  be  effective for  augmenting combustion modifications for NO  con-
 trol  with the  firing  of residual oil.   Fuel  additives are  not directly effective for suppressing
 N0x emissions.  Their  use to suppress  fouling and smoke emissions, however, may  permit more exten-
 sive  use of combustion control  methods than would otherwise be practical.
       Alternate combustion concepts under development include catalytic combustion and fluidized
 bed combustion.  Lab-scale tests of catalytic combustion have demonstrated extremely low NO  emissions
with  clean fuels (1-5 ppm).  This concept may see application in  the 1980's to stationary gas tur-
bines and space heating systems.  Fluidized  bed combustion pilot  plants have demonstrated NO  emis-
sions of the same order as  conventional coal-fired  power plants  using process  modifications for  NO
control  (170 ng/J,  or, 0.4  Ib N02/106 Btu).   The  potential  for replacement  of  conventional utility
and industrial boilers by FBC depends on a number of  other factors  such as  S0x control cost tradeoffs
and operational flexibility,  e.g.,  load following.
                                                xxi

-------
       Stack gas treatment for NO  removal has been implemented 1n the U.S. only on noncombustlon
sources.  Here, an additional incentive is the recovery of NC^ as a feedstock material.  The most
widely tested technique is catalytic reduction with selective or nonselective reducing agents.  The
short supply of reducing agents (methane, ammonia) coupled with the loss of tail gas NCL as a poten-
tial feedstock is causing interest to shift to alternate processes such as molecular sieve absorp-
tion and extended absorption.
       Flue gas treatment (FGT) of combustion sources has been at a low level of development in the
U.S. due largely to the lack of regulatory incentive.  The developmental activity has recently ac-
celerated, however, as a result of increased emphasis on stationary source NO  controls in the na-
tional NO  abatement program.  Flue gas treatment could be effective in the 1980's to augment combus-
tion process modifications on large sources if stringent emission control  is required, for example, to
comply with a potential short-term N0£ air quality standard.  Current developmental activity includes
transferring FGT technology from Japan where stringent NO  controls are enforced.  Processes being
considered include selective catalytic reduction, selective homogeneous reduction and wet scrubbing.
The dry systems show most promise for NO  removal alone.  For simultaneous NO /SO  removal, several
wet and dry processes are effective but the cost tradeoffs have not been identified.
       A sunmary evaluation of NO  control techniques for combustion sources is given in Table S-3.
LARGE FOSSIL FUEL COMBUSTION PROCESSES
       The three largest stationary emitters of NOX are electric power plant boilers (42 percent of
the total), industrial boilers (18 percent) and prime movers, such as gas turbines and I.e. engines
(20 percent).  The most successful NOX reduction technique is modification of operating conditions.
For utility boilers, techniques such as lowering excess air, off-stoichiometric combustion, and, for
gas- ans oil-fired units, flue gas recirculation have resulted in NOX reductions of up to 60 percent
making it possible for them to meet emissions regulations at costs of $1 to $10 per kW (electric
output).  Ongoing performance tests are investigating potential side effects of the modifications,
such as increased corrosion and particulate emissions with coal firing.
sources are able to decrease NO  by up to 50 percent with no efficiency Impairment or increase in
particulate formation.  The most successful techniques are lowering excess air, staged combustion,
and flue gas recirculation.
       The energy impacts of applying combustion modification NOX controls to utility and industrial
boilers occur largely through the effects on unit fuel-to-steam efficiency.  This is usually

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expressed as an increase or decrease in fuel  consumption  for  a  constant  output.   Generally, flue gas
recirculation and off-stoichiometric combustion have very little effect  on  efficiency.   In  some cases,
taking burners  out of service may result in  reduced capacity.   Low excess  air and  reduced  air pre-
heat have a slight impact, usually less than  1.5 percent  increase in fuel use; although,  significant
reductions in air preheat (~ 150-200K)  can have a much greater  impact (~ 3-4  percent increase in fuel
use).  New designs should significantly reduce any adverse efficiency impacts.
       Emissions of other pollutants, CO, HC, particulates, sulfates, and organics, can be  altered
by the use of NO  control.  Generally,  these  changes have been  acceptable.   In some cases specific
consideration of other emissions has been given in the design or method  of  application of the NOX
control technique.
       Prime movers include stationary reciprocating internal combustion engines and gas turbines.
For the former, "dry" methods such as spark retard, air/fuel  ratio change,  and derating work  well,
providing NO  reductions of 10 to 40 percent  while fuel consumption increases 2  to  15 percent.
Water injection ("wet" control) is currently  the most effective technique for gas turbines, reducing
NO  up to 90 percent at costs of 0.4 to 14 mills/kWh, depending on the turbine's application.  "Dry"
control techniques show potential, but it will be a number of years before  their development  will  be
complete and they will be ready to be applied to large production turbines.
       The energy impacts of applying NO  control to internal combustion engines and gas turbines
are manifested almost exclusively through corresponding increases in fuel consumption.  Since both
types fire mainly clean fuels, the impact on  other emissions is confined primarily to HC, CO, and
particulates (smoke).
OTHER COMBUSTION PROCESSES
       Space heating, incineration and open burning, and industrial process heating are additional
combustion sources of NO  .  Residential and commercial space heating contributes 9 percent of the
nation's stationary NO  emissions.   Emissions of CO and smoke from the major equipment types,
residential and commercial warm air furnaces, can be controlled by burner maintenance, tuning, or
replacement.  These techniques are ineffective for NOX reduction, however.   The  most promising pros-
pect for NO  control in space heating systems is for new equipment applications.  New low NOV sys-
           X                                                                                X
terns are available at a cost of 10 percent or more above conventional systems.   These systems are
capable of reducing NO  emissions by more than 50 percent, while increasing operating efficiency
by more than 5 percent.
                                                xxvi

-------
       There has been negligible application of combustion modification to incineration and open
burning and to industrial process heatfng equipment.
NONCOMBUSTION PROCESSES

       Noncombustion-generated NOX, only 1.7 percent of stationary emissions, is produced mainly
during nitric acid manufacture.  NOX control methods include extended absorption, wet scrubbing,
and catalytic reduction.  Catalytic reduction was initially practiced but because of catalyst costs,
fuel costs and changes in the operating conditions of nitric acid plants, greater use of the extended
absorption and wet scrubbing processes have been employed more recently.  Other minor noncombustion
sources are mainly those that use nitric acid as a feedstock.  Control methods are similar to those
used for nitric acid manufacturing.   Table S-4 gives a summary of tail gas abatement processes and
applications.
                                               Xxvii

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                                                SECTION 1

                                              INTRODUCTION

        Manmade oxides of nitrogen (NOX) are currently emitted at a rate in excess of 20 Tg (22 mil-
  lion tons) per year in the United States.  Over 98 percent of manmade NOX emissions result from com-
  bustion with the majority due to stationary sources.  Combustion generated oxides of nitrogen are
  emitted predominantly as nitric oxide, NO, a relatively harmless gas, but one which is  rapidly con-
  verted in the atmosphere to the toxic nitrogen dioxide, N02>   Nitrogen dioxide is deleterious to
 human respiratory functions and, with sustained exposure,  can promote an increased incidence  of
 respiratory ailments.   Additionally,  N02 is an important constituent  in the chemistry of photochemi-
 cal  smog.   The N0/N02  conversion in  the atmosphere promotes the formation of the  oxidant ozone,  0,,
                                                                                                  0
 which subsequently combines with airborne hydrocarbons  to  form the irritant peroxyacetylnitrates
 (PAN).   Nitrogen  dioxide is also a precursor in the formation of nitrate aerosols  and nitrosamines,
 the  health effects of  which are  under study by the EPA.  Because of the quantity  generated and  their
 potential  for widespread adverse effects  on public health  and welfare,  nitrogen oxides are among  the
 atmospheric pollutants  for  which standards  and  regulatory  controls  have been established both by  the
 U.S.  Environmental  Protection Agency  (EPA)  and  by  State and local agencies.
       As  part of  the  regulatory control  program,  the U.S. Environmental Protection Agency (nee the
 National Air  Pollution Control Administration)  published "Control Techniques for Nitrogen Oxide
 Emissions  from Stationary Sources" (AP-67)  in March 1970, as one of a series of documents summariz-
 ing technology for the control of air pollutants.  Since the issuance of AP-67, there has been con-
 siderable activity in both regulatory control of NOX and development of emission control  techniques
 for stationary sources.  Under provisions of the 1970 Clean Air Act Amendments, the EPA  promulgated,
 in 1971, a National Ambient Air Quality Standard for N02 of 100 Mg/m8  annual average.  To achieve
and maintain this standand, a number  of State and local  agencies have  established  NOX  emission con-
trol  standards for new and existing  large stationary combustion sources and nitric acid plants.
Additionally, Standards of Performance for New Stationary Sources were promulgated by  the EPA  in
1971  for steam generators with thermal input greater than 73.2 MW (250 x 106  Btu/hr) and  nitric  acid
plants.   Standards of performance for stationary gas turbines  were proposed on  October 3,  1977.

-------
Standards for stationary large bore reciprocating engines are in preparation.   The standard for
large steam generators is under review to determine if additional  stringency is appropriate.

       The NO  control technology development to support the implementation of these standards has
shown widespread advancement since the publication of the AP-67 document.   Efforts have proceeded
on methods which suppress NO  formation, through combustion process modification,  and on methods
which remove NO  from the flue or tail gases, through stack gas treatment.

       Combustion process modification is the preferred method for control  of stationary combustion
sources accounting for 98 percent of stationary source NO .  Process modifications have been exten-
sively applied to retrofit of existing utility and industrial boilers and gas turbines firing gas
and oil.  The significant role of fuel bound nitrogen in NO  formation with the firing of coal and
                                                           X
heavy oils was shown early in the control development effort.  Current activity is concentrating on
refinement of fuel NO  control methods for application to advanced designs of coal-fired combustion
equipment.  Progress has also been made in the design of low-NO  residential and commercial space
                                                               A
heating systems.

       Stack gas treatment is the preferred method for control of NO  emissions from stationary non-
combustion sources.   These sources, primarily nitric acid plants,  contribute less  than 2 percent of
nationwide stationary sources NO  emissions, but can present a serious local hazard.  Several con-
trol techniques, including extended absorption, catalytic reduction, wet scrubbing, and molecular
sieve absorption, have been developed and implemented on existing and new equipment.  Reductions in
NO  in excess of 95 percent have been demonstrated.

       The purpose of this report is to update and revise the original AP-67 document by incorporat-
ing improved emissions estimates and NO  control technology developments since 1970.  Emphasis is
given to identifying the significant stationary sources of N0x emissions based on  the most recent
emission factors and fuel consumption data (Section 2), summarizing the developmental status of
candidate NOX control techniques (Section 3), and reviewing the effectiveness, cost and user
experience with the implementation of NOX controls on large combustion sources (Section 4), other
combustion sources (Section 5), and noncombustion sources (Section 6).  Also included in these
sections is information on the energy and environmental impacts of the various control techniques
as required by Section 108 (b)(l) of the 1977 Clean Air Act.

       This r  port is concerned only with quantifying and controlling stationary source NO  emis-
                                                                                          X
sions.  The effects upon health and welfare of nitrogen oxides and their secondary atmospheric reac-
tion products are considered in two related documents, AP-63, "Air Quality  Criteria for Photochemi-
cal Oxidants," and AP-84, "Air Quality Criteria for Nitrogen Oxides".   Both of these documents are
under revision by the Office of Air Quality Planning and Standards.
                                                 1-2

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                                                SECTION 2
                                    CHARACTERIZATION OF NOX EMISSIONS

          This section presents a nationwide inventory and projection to the year 2000 of stationary source
  emissions of oxides of nitrogen.  Section 2.1 defines NOX and summarizes the basis of its occurrence
  in stationary source combustion.  Section 2.2 describes  the standard EPA method for analysis of
  source and ambient NOX concentrations.   Specific stationary source equipment types are described in
  Section 2.3.   The NOX emission factors,  fuel  consumption rates and annual  N0x emissions for each of
  these source  types are also tabulated in Section 2.3.  A summary of nationwide NOX emissions and
  fuel  consumption  by equipment  application sector is given  in  Section  2.4.   Projections  of these
  emissions  to  the  year 2000  are given  in  Section  2.5.

  2.1      DEFINITIONS  AND FORMATION THEORY
          Seven oxides  of nitrogen are  known to occur:  NO, NO,,, N03> N20, N^, N^ and N^.  Of
  these, nitric oxide  (NO) and nitrogen dioxide (NO,,) are emitted in sufficient quantities  in fuel
  combustion and chemical manufacturing to be significant in atmospheric pollution.  In this document,
  "NO/ refers to either or both of' these two gaseous oxides of nitrogen.  Nitrogen dioxide is dele-  '
 terious to human respiratory functions and is  a  key participant in the formation of photochemical
 smog.   Nitric  oxide, taken  alone, is  relatively  less harmful  but is important as the main precursor
 to N02 formation in the atmosphere.
         Approximately 95 percent  of oxides of  nitrogen emanating from stationary combustion sources
 are emitted as  nitric oxide.  Two separate mechanisms, thermal  NOX  formation and  fuel  NOX  formation,
 have been identified  as generating N0x during  fossil fuel combustion.
        Thermal NOX results  from  the thermal fixation of molecular  nitrogen  and oxygen in  the  com-
 bustion air.  Its  rate of formation is extremely  sensitive to  local flame temperature and  somewhat
 less so to  local concentration of oxygen.  Virtually all  thermal N0x is formed at the region of the
 flame which is at the highest temperature.  The NO, concentration is subsequently "frozen" at the
 level prevailing in the high temperature region by the thermal  quenching of the combustion gases.
The flue gas NOX concentrations  are  therefore between the  equilibrium level  characteristic of the
                                                2-1

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peak flame temperature and the equilibrium level  at the  flue  gas  temperature.  This  kinetically con-
trolled behavior means that thermal  N0x emissions are dominated by  local  combustion  conditions.
        Fuel NO  derives from the oxidation of organically bound  nitrogen in  certain fuels  such as
coal and heavy oil.  Its formation rate is strongly affected  by the rate  of mixing of the  fuel and
airstream in general and by local oxygen concentration in particular.   The flue  gas  N0y concentra-
tion due to fuel nitrogen is typically only a fraction (e.g., 20  to 60 percent)  of the level  which
would result from complete oxidation of all nitrogen in the fuel.  Thus,  fuel NOX formation,  like
thermal NO  formation, is dominated by the local combustion conditions.  Additionally, fuel N0x
emissions are dependent on the nitrogen content of the fuel.   The NOX emissions  characterization
detailed in this section, therefore, takes account of variations  in equipment operating conditions
and in fuel type which influences the emissions as well as the potential  for control.  Additional
discussion on thermal and fuel NOX formation mechanisms is given in Section 3.1.
        Oxides of nitrogen emitted in the byproduct streams of chemical manufacturing (nitric acid,
explosives) are predominantly in the form of N02-  The N02 concentration in the flue gas is typi-
cally at the equilibrium  level characteristic of the chemical compositions and  temperatures required
in  the manufacturing  process.  The  NO   emissions  from noncombustion sources  are then much  less sen-
 sitive  to  minor process  modifications  than  are  combustion generated NOX  emissions.

2.2    SAMPLING AND  ANALYSIS METHODS
        The  standard  EPA  method  for compliance  testing  of Nt>x from stationary sources is the phenol-
disulfonic  acid (PDS)  method.  This method  was  developed  for the measurement of nitrate in solution
by  Chamot  around 1910 (Reference 2-1).  The specifications for the PDS method are given in
Reference  2-2.   Briefly,  the method requires  that a  grab  sample  be collected in an  evacuated flask
containing a  dilute sulfuric acid-hydrogen  peroxide  solution which absorbs the  nitrogen oxides,
except  nitrous  oxide  (N20).   The sample is  then processed following the  procedures  of Reference  2-2.
The absorbance  of  420 nm wavelength light by the treated  samples is then measured.   A calibrated
 relationship between  absorbance  and NOp concentration  is  used to relate  the  measurement to the sample
 NOp concentration.
         The advantages of the PDS method  include the wide concentration  range,  minimum  number of
 sample handling steps, and lack  of interference with sulfur  dioxide  in the flue gases.  The  disad-
 vantages are the long time elapsed between samples,  a possible  interference  from halides,  and the
 inherent problems  with grab sampling.
                                                  2-2

-------
          Chemiluminescence,  the  Federal  Reference Method  (Reference 2-3) for ambient NO  sampling, is
  also a  popular  source  testing technique.  Although it cannot be used for compliance testing, its
  continuous  electronic  measurement feature is advantageous for use in emissi'on control development
  programs.

  2-3     c2rinoENT DESCRIPTIONS> EMISSIONS ESTIMATES, EMISSION FACTORS, AND FUEL USAGE BY APPLICATION
         oLL1 UK
         The rate of emission of oxides of nitrogen from stationary combustion sources is dominated
  by equipment design characteristics (combustion intensity, fuel/air mixing pattern, combustion gas
  temperature history) and fuel characteristics (combustion temperature, fuel nitrogen content).   A
  previous NOX emissions inventory for 1972 (Reference 2-4) classified stationary combustion sources
  according to the design characteristics known to influence NOX  emissions.   A total  of 137  combina-
 tions of equipment type and fuel type were identified as  having significantly different  potential
 for NOX emissions and/or NOX control.   The emissions  data cited in  this  section  are an update,  to
 1974, of the 1972 inventory of Reference 2-4.
         An overview of stationary  sources of NOX emissions is provided  in  Figure 2-1.  The first
 division is  by application  and  the  second by use sector.   The six applications encompass all major
 sources  and  the  cited  sectors include  all  those  of  importance within each  sector.   Steam generation
 is  by far the  largest  application on a  capacity  basis for both  utility and  industrial equipment  while
 space heating  is  the largest application  by  number of installations.  Internal combustion  engines
 (both reciprocating and gas  turbines)  in  thi petroleum and related products industries have gener-
 ally  been  limited to pipeline pumping and gas compressor  applications.  Process  heating data are
 not as readily available, but the main sources appear to  be process heaters in petroleum refineries,
 the metallurgical industry and the drying and curing ovens in the broad-ranging ceramics  industry.
 Incineration by both the municipal  and industrial sectors is a small but noticeable source, pri-
 marily in urban areas.  Noncombustion sources are largely within the area of chemical manufacture,
 more  specifically nitric and  adipic acids and explosives.   The final description level in Figure 2-1
 is the important equipment types.  Although these equipment categories do not include all  the pos-
 sible variations or hybrid units, the bulk of the equipment is included in the breakdown.
        The emissions inventory from Reference 2-4 for the significant stationary source  equipment
 types was updated to 1974 using the most recent emission factors and fuel  consumption data.  These
emission factors were obtained from EPA publication  AP-42  (Reference 2-5),  its  three supplements
 (References 2-6,  2-7,  2-8) and recent field test  studies  (References  2-9  to 2-13).   A rating of  the
quality  and  general  applicability  of these emission  factors  for each  sector is given  in Table 2-1.
                                               2-3

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             APPLICATION
     SECTOR
                                                         EQUIPMENT TYPES
STATIONARY
SOURCES OF <
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                    Figure 2-1.  Stationary sources of NOX emissions.


                                       2-4

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       TABLE 2-1.  QUALITY OF EMISSION FACTORS FOR OXIDES OF NITROGEN,
Sector
Utility




Industrial


Reciprocating 1C
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Gas turbines

Residential

Commercial


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Quality3
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B
A
A
B
B
B
B

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A
A
A
B
A
A
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D
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B - average, based on limited number of field measurements
C - marginal, sparse data base
D - Inadequate data base
                               2-5

-------
A grading of "A" means the quality of the emission factor is  good,  i.e.,  based on  high  quality  field
measurements of a large number of sources.  "B" indicates average quality or based on a limited num-
ber of field measurements.  "C" refers to a sparse data base, or to data  which is  of marginal quality
and "D" indicates an inadequate data base.
        The emission factors cited herein are for the baseline operating  conditions without the use
of NO  controls.  "Baseline" refers to nominal settings of process variables such  as unit load,
excess air levels, and combustion air preheat as well as to the most representative design type with-
in a given equipment class.  It should be noted that stationary source NOX emissions are strongly
dependent on small variations in design types, fuel composition or process operating conditions.
Thus, for those equipment sectors given a rating other than "A" in Table 2-1, the  sparseness of the
available emission data may preclude the  specification of a true baseline emission factor for all
significant design types.

2.3.1   Utility Boilers
Emissions and  Fuel Use
        Utility boilers are field-erected watertube  boilers  ranging  in thermal capacity from 30 MW
 (100  x  106  Btu/hr)  to around  3000 MW.  This equipment category includes the large  majority of utility
and  industrial  electric power  generating  boilers.  Field-erected watertube  boilers  operate at  steam
 temperatures  up  to  840K  (1050  F)  and  steam  pressures up  to 26 MPa  (3800  psi).  Depending  upon  manu-
 facturer,  units  greater than  about  2250  MW  operate  at supercritical  steam  pressures above 24  MPa
 (3500 psi)  (Reference 2-14).   In  general, utility boilers  recover  up to  90  percent  of  the heat with
waterwalled combustion chambers  in  combination with  superheaters,  reheaters,  economizers  and air
 preheaters.   Approximately half  of  this  heat energy  is absorbed  by radiant  heat transfer  to the
 furnace walls.
         Although there are some  differences among utility  boiler designs in such  factors  as furnace
 volume, operating pressure,  and  configuration of internal  heat  transfer  surface,  the principle dis-
 tinction is firing mode.   This includes  the type of  firing equipment, the fuel  handling system, and
 the placement of the burners  on  the furnace walls.  The major firing modes  are:   single-  or opposed-
 wall fired, tangentially fired,  turbo fired, and cyclone fired.   Vertically fired units and  stoker
 units are used to a small extent in older steam generating stations.  All of the  major firing  types
 can be designed to burn the principle fossil fuels - gas,  oil and coal - either singly or in  com-
 bination.   However, the cyclone unit is primarily designed  to fire coal as the principal fuel.
                                                 2-6

-------
          In addition to differences in firing mode,  coal,  depending on its  ash characteristics,  is
  burned in either a dry-bottom or wet-bottom (slag tap)  furnace.   Dry-bottom units  operate  at tem-
  peratures below the ash-fusion temperature, and  ash is  removed  as a solid.   Wet-bottom furnaces
  melt the ash and remove slag  through  a  bottom tap.   Although wet  bottom  units were once used exten-
  sively in burning low ash-fusion temperature coals,  they  are no longer manufactured due to  opera-
  tional  problems  with low sulfur coals and  because their high combustion  temperatures promote NO
  formation.
          In  single-wall  firing  (front-wall  firing) burners are mounted normal  to a  single furnace
 wall.   Furnace wall  area  generally limits  the capacity  of these units to about 1200 MW.  When
 greater capacity is  required,  horizontally  opposed wall-firing furnaces are normally used.   In these
 units burners are mounted on opposite furnace walls.  Generally, capacities for these units exceed
 1200 MW  (Reference 2-14).  Burners on the single-wall and opposed-wall firing designs are usually
 register type where  fuel and combustion air are combined in the burner throat.
         Turbo-fired units are similar to the horizontally opposed-wall-fired units  except that
 burners are mounted on opposed, downward inclined furnace walls.   Fuel and  combustion air are intro-
 duced into the combustion zone where rapid  mixing occurs.
         In tangential firing,  arrays  of fuel and  air nozzles are located  at each  of the four corners
 of the combustion chamber.  Each nozzle  is  directed  tangentially to a small  firing  circle in the
 center of the chamber.  The resulting  spin  of the four "flames"  creates high turbulence and  thorough
 mixing of fuel  and air in the  combustion zone.
         In the cyclone furnace design  fuel  and air are introduced  circumferentially into a water-cooled,
 cylindrical  combustion chamber to produce a highly swirling, high  temperature  flame.  The cyclone
 was  originally developed as a  slagging furnace to  burn low ash-fusion  temperature coals,  but  has
 recently been used  successfully on  lignite.   Relatively  high levels  of thermal N0x  formation
 accompany  the high  temperatures  of slagging  operation.   Due  to the  inability of this design to
 readily  adapt to  low  NOX opeartion, this type of furnace is no longer being constructed.
        Vertical-firing  furnaces were developed for pulverized fuels prior to the advent of water-
walled combustion chambers.  These units provide a long-residence time combustion which efficiently
 burns low-volatile fuels such as anthracite. Vertical-fired boilers are no longer sold,  and rela-
tively few of these units are found in the field.
       Stoker-fired units are designed for solid fuel firing.  Unlike liquid, gaseous or pulverized
fuels which are burned in suspension,  the stoker employs  a  fuel  bed.  This bed is  either a station-
ary grate through which ash falls or a  moving grate which dumps  the ash into a hopper.   The  main
                                                2-7

-------
types of stokers are overfeed and underfeed designs.   Spreader stokers  are overfeed  designs  and  dis-
tribute fuel by projecting the fuel  evenly over the fuel  bed.   Other overfeed stokers  generally
deposit fuel on a continuously moving grate.  Underfeed designs introduce fuel  beneath the fuel  bed
as ash is pushed aside by the newly  introduced fuel.
        Tangential firing, single-wall and horizontally opposed-wall firing and turbofurnace firing
account for 40 and 36 and 14 percent of the fuel consumed by utility botlers (Reference 2-15).   In
terms of units, their distribution is 19, 59 and 8 percent, respectively.  Cyclone,  vertical and
stoker designs make up the remaining 14 percent.
        Recent trends indicate a continued strong movement toward pulverized coal-fired boilers.
Many previously ordered oil-fired units are being converted to coal firing during the design phase.
The trend of the last 10 years to increasing capacities appears to have slowed with many utilities
electing to install two small boilers rather than a single larger unit (Reference 2-14).  Industry
sales were  particularly depressed in 1976 and 1977.  Uncertainty about the nation's energy policy,
environmental regulations, mild summer load peaks, increased energy costs, and a 1975 reserve capa-
city of about 35 percent have combined to produce this situation.
        Estimates for the uncontrolled NOX emissions from utility boilers were derived from the
1974 utility fuel consumption compilation for coal, oil and natural gas published by  the Federal
Power Commission  (FPC) in Reference  2-16.  The  consumption rate of  each fuel type was prorated
according to firing type based on the procedures used  irwReference  2-4.   Emission factors for each
equipment type were obtained  from AP-42  (Reference 2-5), AP-42 Supplement No.  5  (Reference  2-7),
and  a field test  survey of utility boilers  (Reference  2-10).  These factors  were applied  to the
individual  fuel consumption  rates to arrive at  the annual NOX  figures  presented  in  Table  2-2.
The  nominal heating values of the fuels  were  as follows:  gas - 37.3 MJ/Nm3* (1000  Btu/scf), oil -
39 GJ/m3  (140,000 Btu/gal),  and  coal - 27.9 MJ/kg  (12,000 Btu/lb).
        A summary of  the  emissions and fuel usage with respect to  firing  type  is presented  in
Table 2-3.  The  resultant total  nationwide  annual  NOX  emissions by  utility  boilers  in 1974  is esti-
mated to  be 5.1 Tg  (5.63  million tons).   The  corresponding  total annual  fuel  consumption  for 1974
 is 16.3 EJ  (15.4  quadrillion Btu).
         Fuel  consumption  data from References 2-4,  2-15,  2-17,  and  2-18,  and the  present report  are
 compared  in Table 2-4.  The  corresponding NOX emissions  are compared in  Table  2-5.  The NOX emis-
 sions  for both oil  and  gas  firing compare very well  between the present  report and  the  recent study
 of Reference  2-15.   The discrepancy  in emissions  with coal  firing  is primarily due  to the use of
 more recent emission factors for lignite combustion  and for cyclones in  this report.
 * The symbol  Nm3 is used  to denote  cubic meters at standard temperature  and pressure.
                                                 2-8

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-------
 2.3.2   Industrial Boilers
 Equipment Description
         This equipment category is comprised of industrial  boilers ranging in capacity up to 73.2  MW
 (250 x 106 Btu/hr).   Industrial  boilers are either field-erected  or packaged  units.   The  field-erected
 units are only the very large capacity units and are-quite  similar in  design  to  utility boilers  (See
 Section 2.3.1).   Packaged boilers, which are equipped and shipped complete with  fuel  burning equip-
 ment, are mainly watertube and firetube designs.   Other designs such as  cast  iron, and shell  type  are
 also used.  Each of  these designs  has  a fairly  distinct capacity  range.   Packaged boilers far out-
 number field-erected units,  but  their  combined  fuel  consumption is slightly less than that of field-
 erected boilers.
         In watertube boilers,  hot  gases pass  over  tubes  which are water  or steam filled.   The tubes
 line the combustion  chamber  walls  and  gain  heat mainly  by radiative  heat transfer from the flame.
 Downstream the combustion chamber  heat is absorbed convectively with tubes  mounted across  the hot
 gas  flow.   Almost all  package  boilers  greater than about 8.8 MW (30  x  106  Btu/hr) are watertube  boilers
         Sales  statistics  for 1975  (Reference  2-19) indicate that  86  percent of the packaged water-
 tubes were burner-fired  (usually a  single burner)  and the remainder  were stoker-fired.  Of the burner-
 fired units, 50  percent fired  either residual or distillate fuel  oil,  40 percent have  dual fuel  (oil
-natural  gas) capability and  10 percent fire only natural gas.   In  general, natural  gas and  distil-
 late  oil firing  units  are more prevalent at the lower capacity ranges  of watertube boilers.
         In  firetube  boilers  hot gases  are directed from  the combustion chamber through tubes which
are submerged  in water.   Firetube boilers burn fuel oil  and natural  gas  because the design is parti-
cularly  sensitive to fouling with ash-containing fuels.  Residual  oil and natural gas are  the most
common fuels in the  larger firetubes and natural gas and distillate oil  are the main fuels for the
smaller  units.  Firing is by single burner.   Recent sales statistics indicate that the firetube has
diminished  in sales  in the past 5 years (Reference 2-20).
Emission and Fuel Use
        The 1974 NOX emissions from industrial boilers were  estimated by essentially the same proce-
dure as used for utility boilers.  The fuel  consumption data for the total industrial  boiler sector
were obtained from Reference 2-18.   These 1971 data were updated to 1974 by an annual  growth rate
estimate from Reference 2-21.  The process gas consumption data  were also obtained  from Reference
2-18.
                                                 2-13

-------
        The fuel usage for each specific equipment type  was derived from the total  fuel  consumption
data based on the procedures used in Reference 2-4.   The following were the basic  assumptions  made  in
that report in formulating the emission estimates:
        •   Field-erected watertube boilers larger than  29 MW (100 x 106 Btu/hr)  are indistinguish-
            able from utility boilers and have the same  firing distribution
        •   Field erected watertube boilers smaller than 29 MW (100 x 106 Btu/hr)  are single-wall-
            fired units
        •   Packaged watertube boilers are single-wall-fired units
        •   Packaged firetube boilers do not fire pulverized coal  in significant  quantities
        •   Alternate fuel usage (e.g., coal-derived gas) is negligible
        The emission factors were largely derived from a recent field test survey of industrial
boilers, Reference 2-9.  The test data were screened for application to a nominal  baseline operating
                                  i»
condition.  Where baseline data were available for more  than one unit of a specific design type, the
data were averaged.  When test data for a specific firing type/fuel wer .• unavailable, emission fac-
tors were estimated based on data for similar units.  The updated emission factors based on this
rdcent data are generally 15 to 30 percent lower for gas and oil-fired industrial  boilers than those
based on earlier data (Reference 2-5).  The resultant estimated 1974 NOX emissions from industrial
boilers are presented in Table 2-6.
        Comparisons of fuel consumption data and NO  emission estimates from recent emission inven-
tories for the industrial boiler sector are given in Tables 2-7 and 2-8, respectively.  There are
substantial differences in the fuel consumption data used in the previous inventories which cause
wide discrepancies in NO  emission estimates.  These could be due to the difficulty encountered in
separating the total fuel usage in the industrial sector into industrial boilers,  direct heat, feed
stock, internal combustion and other categories.  The data used for the current estimates are
regarded as the most extensive and reliable to date.
2.3.3   Commercial and Residential Space Heating
Equipment Description
        This category is made up of commercial and residential warm air furnaces  and boilers.  Warm
air furnaces are space heaters, where the unit is located in the room which it heats, or central
heaters which use ducts to transport and discharge warm air into the heated space.  Space heaters
comprise less than 10 percent of the nation's heaters.  Central heaters make up the remainder of the
                                                2-14

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warm air heater equipment sector.  Combustion chambers are cylindrical for distillate oil  firing or
sectional for natural gas firing.  Combustion products pass through flue gas passages of the heat
exchanger and exit through a flue to the atmosphere.  The commercial packaged boilers are very simi-
lar to industrial packaged boilers (See Section 2.3.2).  Boilers used for residential space heating
are generally cast iron designs.  Residential warm air furnaces and cast iron boilers are available
in sizes up to 0.12 MW (4 x 10s Btu/hr).  Larger units are mainly confined to the commercial and
institutional sector.
        Commercial and institutional systems are used for space heating and hot water generation.
The equipment consists mainly of oil-fired warm air furnaces and firetube boilers.  The rated heat
input, or fuel consumption, of this equipment ranges from 0.12 MW  (4  x 10s Btu/hr) to 3.6 MW  (12.5 x
106 Btu/hr).
        Fuels burned for  residential and commercial space heating  are residual and distillate oil,
natural gas and  occasionally coal.  Typically residual oil firing  is  limited to the  larger  commer-
cial or institutional boilers.
        Although there has  been  a continuing trend  in  the recent past toward space heating  equipment
which  uses natural gas, this trend  is  expected to reverse itself in the near future  (Reference  2-22).
'Furthermore,  the use of fossil fuels of all  types is  expected  to drop drastically by the year 2000.
Emissions and Fuel Use
        The fuel  consumption data for  commercial and  residential space  heating equipment were
obtained  from the National  Gas Survey  (Reference 2-23).  The fuel  consumption data were subdivided
by equipment  type based on  the procedures  of Reference 2-4.  The basic  assumptions made  in  that
study  were:
         •   Coal is  burned  in  commercial units  (stokers) but not in residential  systems
         t   No  pulverized coal  is burned in  commercial or  residential units
         •   Residual  oil  consumption  is negligible  in residential  units
         t   Commercial  fuel usage  is  directly  proportional  to  installed capacity
         •   LPG, wood,  or producer  gas have  negligible use in  space heating
 The emission factors used were obtained from AP-42  (Reference  2-5), AP-42 Supplement No.  6 (Refer-
 ence 2-8),  and Reference 2-24.
         The NO  emissions estimates by equipment type for the  commercial  and residential  sector are
 presented in Tables 2-9 and 2-10,  respectively.   A  summary of  these results by  sector is  given  is
 Table 2-11.
                                                 2-19

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                                                   2-21

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         Thirty percent of the total  fossil  fuel  used in the United States in stationary sources is
 consumed in space heating.  According to the 1970 United States Census, 57.7 percent of residential
 heating equipment was gas-fired, 28.3 percent was oil-fired, and the remaining 14 percent used other
 fuels such as propane, coal, and wood.   Fuel consumption data for the combined commercial/residen-
 tial sector obtained from several sources are compared in Table 2-12.  The fuel  usage used in this
 report compares very well  with those from the FEA for 1974.   The NOX emission estimates by fuel are
 compared with several  recent sources for the commercial  and residential sector in Tables 2-13 and
 2-14.  The estimates are in reasonable  agreement.

 2.3.4   Internal  Combustion
 2.3.4.1    Stationary Reciprocating Internal  Combustion Engines
         Reciprocating  1C engines for stationary  applications range in capacity from  15  kW  (20 hp)  to
 37  MW (50,000 hp).   These  engines are either compression ignition (CI)  units  fueled  by  diesel  oil  or
 a combination of  natural  gas and diesel  oil  (dual),  or spark ignition (SI)  fueled by natural  gas  or
 gasoline.
         Stationary  reciprocating 1C  engines  use  two  methods  to ignite the  fuel-air mixture  in  the
 combustion  chamber.   In  CI  engines,  air  is first compression heated  in  the  cylinder,  and then  diesel
 fuel  is  injected  into  the  hot air where  ignition is  spontaneous.   In  SI engines,  combustion is  spark
 initiated with  the  natural  gas or gasoline being introduced  either by injection or premixed with
 the  combustion  air  in  a  carburetted  system.   EUher  2- or 4-stroke power cycle designs with various
 combinations  of fuel charging,  air charging,  and chamber design are available.
         Because reciprocating  1C  engine  installations characteristically have a low physical profile
 (low  buildings, short  stacks,  and little visible emissions), they are frequently  located in or adja-
 cent  to  urban centers where power demands are greatest and pollution problems most acute.  These
 units are used  in a variety of applications because of their relatively short construction and instal-
 lation time and the fact that they can be operated remotely.  Applications range from shaft power for
 large electrical generators to small  air compressors and welders.
         By capacity, 73 percent of the 1C engines are fueled by natural gas, 16 percent by diesel oil
 and 11 percent by gasoline.  In terms of installed capacity, the oil  and gas industry is the leading
 user of  stationary 1C engines for pipeline and production applications, followed  by general  industri-
al  users, electric power generation,  and agriculture.  In terms of annual  energy  consumption,  oil  and
gas  industry applications again come  first,  followed by general industrial  and electrical  generation
applications.
                                                2-22

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                                               2-23

-------
                                                                      a\  b
         TABLE 2-13.   ANNUAL NOY  EMISSIONS FROM COMMERCIAL  BOILERS  (Gga)
Fuel
Coal
Oil
Gas
Total
Source
Battell e
1971
(Reference 2-18)
119
134
23
276
MSST
1972
(Reference 2-4)
26
192
109
327
GCA
1973
(Reference 2-15)
27
570
100
697
Current
1974
49
457
203
709
aBy convention all NOX emissions are reported as equivalent NO;?.   Approximately
 95 percent of the NOX from stationary source combustion is emitted as NO.

n"his table is included in Appendix A in English units.
                                                                         a,b
     TABLE 2-14.  ANNUAL NOX EMISSIONS FROM RESIDENTIAL SPACE HEATING (Rga)
Fuel
Coal
Oil
Gas
Total
Source
Battell e
1971
(Reference 2-18)
-
153
162
315
MSST
1972
(Reference 2-4)
-
230
192
422
GCA
1973
(Reference 2-15)
11
89
190
290
Current
1974
-
183
197
380
aBy convention all NOX emissions are reported as equivalent NOg.  Approximately
 95 percent of the NO  from stationary source combustion is emitted as NO.

 This table is included in Appendix A in English units.
                                  2-24

-------
       The emissions estimates for reciprocating 1C engines, given in Table 2-15, were derived from
Reference 2-11.  This is the most recent and complete survey of emissions from reciprocating 1C
engines.  Since the horsepower, speed, cycle, fuel, air charging,  and fuel  charging combinations are
so numerous, emission estimates for each combination would be impossible considering the data avail-
able.  In view of this fact, the 1C engine emissions are categorized into spark-ignition (gas-fired),
and compression ignition (diesel or dual-fueled).  The fuel data of Reference 2-11 were updated to
1974 by the FPC data from Reference 2-16.

2.3.4.2   Gas Turbines
        Gas turbines are rotary internal combustion engines fueled by natural gas, diesel or distil-
late fuel oils, and occasionally residual or crude oils.  These units range in capacity from 30 kW
(40 hp) to over 74 MW (100,000 hp) and may be installed in groups for larger power output.  The basic
gas turbine consists of a compressor, combustion chambers, and a turbine.  The compressor delivers
pressurized combustion air to the combustors at compression ratios of up to 20 to 1.  Injectors
introduce fuel into the combustors and the mixture is burned with exit temperatures up to 1,370K
(2.000F).  The hot combustion gases are rapidly quenched by secondary dilution air and then expanded
through the turbine which drives the compressor and provides shaft power.  In some applications,
exhaust gases are also expanded through a power turbine.
        While simple-cycle gas turbines have only  the three components described above, regenerative-
cycle gas turbines also use hot exhaust gases (700K to 870K, 800F to 1.100F) to preheat the inlet air
between the compressor and the combustor.  This makes it possible to recover some of  the thermal
energy  in the exhaust gases and to increase  thermal efficiency.  A third type of turbine is the
combined-cycle gas turbine.  This  is basically  a simple-cycle unit which exhausts to  a waste heat
boiler  to recover thermal energy from  the exhaust  gases.   In some cases, this waste heat boiler is
also designed  to burn additional fuels  to supplement  steam production, a process which is referred
to  as supplementary  firing.
        Gas  turbines  have been  extremely  popular in the  past decade because of the relatively short
construction lead times, low cost, ease and  speed  of  installation, and low physical profile (low
buildings,  short stacks, little visible emissions, quiet operation).  In addition, features like
remote  operation, low maintenance, high  power-to-weight ratio, and short startup time have  added to
their popularity.  Primary applications  of  gas  turbines include electricity  generation (peaking and
baseload),  pumping,  gas compression,  standby electricity generation, and miscellaneous industrial
uses.
        The  fuel  data for gas  turbines  were  obtained from the Shell Report  (Reference  2-29)  and  updated
to  1974 by  data  from the same  FPC  source mentioned above.   Emission  factors  were obtained from AP-42
Supplement  No. 4  (Reference  2-6).  NOX emissions for  gas turbines are shown  in Table  2-15.
                                                 2-25

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-------
        Comparisons of fuel data and NOX emission estimates from several  recent surveys are given in
Tables 2-16 and 2-17, respectively.   The lower emissions from gas turbines from this report,  compared
to those from the earlier inventory, Reference 2-4, are mainly due to the smaller and more recent
emission factors obtained from AP-42 Supplement No. 4 mentioned previously.

2.3.5   Industrial Process Heating
        Significant quantities of fuel are consumed by industrial process heating equipment in a
wide variety of industries, including iron and steel production, glass manufacture, petroleum refin-
ing, cement manufacture, sulfuric acid manufacture, and brick and ceramics manufacture.  In addition,
there are dozens of industrial processes that burn smaller amounts of fuel, such as coffee roasting,
drum cleaning, paint curing ovens, and smelting of metal ores, to name only a few.  Brief process
descriptions for some of these are given below.

Iron and Steel Industry
        The iron and steel industry is one of the major contributors to combustion-related process
NO  emissions.  The most important combustion processes are sinter lines, coke ovens, open hearth
furnaces, soaking pits and reheat furnaces.  The remaining combustion-related processes (pelletiz-
ing, heat treating, and finishing) are less important because they use relatively small amounts of
fuel (Reference 2-9).
        Sintering machines are used to agglomerate ore fines, flue dust, and coke breeze for charg-
ing of a blast furnace.  The use of this operation is presently declining at the rate of about 3.4
percent annually because of its inability to accommodate rolling mill scale which is contaminated
with rolling oil.
        Coke ovens produce metallurgical coke from coal by the distillation of volatile matter pro-
ducing coke oven  gas.  The fuels commonly used in  this process are coke oven gas and blast furnace
gas.  Although NO  emissions  are minimized by slow mixing in  combustion chambers, they are nonethe-
less substantial  because of the very  large quantity  of fuel consumed  in this process.  Present pro-
jections show a  5.7  percent annual  increase in fuel  consumption  for coke ovens.
       Open hearth furnaces are now being replaced in the U.S. steel  industry by  the basic oxygen
furnace, but  are still  an  important source of NOX  emissions because of the very high combustion air
preheat temperature, high  operating temperatures,  and the practice of oxygen lancing.  Fuel consump-
tion  in open  hearth  furnaces  is presently decreasing about 8  percent  per year.
        Soaking  pits and reheat furnaces are used  to heat steel  billets and ingots  to  correct work-
ing temperatures prior  to  forming.  Current trends are  toward continuous  casting  of molten metal,
                                                  2-27

-------
              TABLE 2-16.  ANNUAL FUEL CONSUMPTION BY INTERNAL
                           COMBUSTION ENGINES  (PJ)a
Fuel
Oil and Dual
Gas
Source
Shell
1971
(Reference 2-29)
503
1579
MSST
1972
(Reference 2-4)
548
1716
Current
1974
569
1706
      This table is included in Appendix A in English units.
  TABLE  2-17.  ANNUAL  NOX  EMISSIONS  ROM  INTERNAL COMBUSTION ENGINES  (Gg3)1

Equipment
Reciprocating
Engines

Turbines


Fuel
Oil and
Dual
Gas
Oil
Gas
Total
Source
Shell
1971
(Reference 2-29)
360
1580
30
70
2040
MSST
1972
(Reference 2-4)
287
1697
108
156
2248
Current
1974
399
2014
109
127
2649
By convention all NOX emissions are reported as equivalent N02.   Approximately
95 percent of the NOX from stationary source combustion is emitted as  NO.

This table is included in Appendix A in English units.
                                   2-28

-------
and the need for these units 1s being eliminated.   At present,  however,  soaking  pits  and  reheating
furnaces still consume more fuel than any other single process  1n the steel  industry.   In spite  cf
the fact that soaking pits and reheat furnaces are being phased out,  consumption of process  fuel
continues to increase at an annual rate of about 2.8 percent in the Iron and steel  Industry  as a
whole.

Glass Industry
        In the glass industry, melting furnaces and annealing lehrs are the two fuel  combustion  pro-
cesses of greatest importance.  Melters in the glass industry are continuous reverbatory  furnaces
fueled by natural gas and oil.  Coal is not suitable for these furnaces because of its inherent
impurities.  Annealing lehrs control the cooling of the formed glass to prevent stains from occur-
ring.  Some lehrs are direct-fired by atmospheric, premix, or excess-air burners.  About 80 percent
of the total industry fuel consumption goes for melting, while annealing lehrs consume about 15
percent.  There is a current trend in the glass industry towards electric melters, or at least elec-
trically assisted conventional melters.  But until it becomes clearer which fuels are going to be
available in the future, no definite trends will emerge.  Present trends toward fuel  oil  in place
of natural gas have begun as a result of natural gas shortages and price increases.
Cement Industry
        Cement kilns are the major combustion processes in the cement industry.  These kilns are
rotary cylindrical devices up  to  230 m (750 feet) in length which contain a feedstock combination
of calcium, silicon, aluminum,  iron, and various other trace metals.  This mixture of elements  in
the  form of various combinations  of clay, shale, slate, blast furnace slag, iron ore, silica sand,
limestone, and chalk slowly moves through the kiln as products of fossil fuel combustion move in an
opposite direction.  Temperatures of the material during the process may reach  1.756K (2.700F).
        Coal, fuel oil, and natural gas are the main fuels used  in cement kilns.  Natural gas
accounts for 45 percent of the fuel consumed, coal for 40 percent, and  fuel oil  for 15 percent.   The
major effluent stream  for this process is the exhaust gas which  passes  through  the entire length of
the  kiln and may entrain additional particulate or trace metals  from the kiln feedstock.  Cement
industry figures show  that the industry has grown an average of  about  1.9 percent annually  over  the
past 20 years.   Industry projections,  however, predict a greater growth in  the  next few years of
between  2.6  to 4.1 percent per year (Reference 2-30).
                                                  2-29

-------
  Petroleum  Refineries
         A  wide variety of process combustion takes place in the petroleum refining industry, includ-
  ing catalyst regenerating in the catalytic cracker, catalytic reforming, delayed coking, and hydro-
  treating and flaring of waste gases.  Catalytic cracking is required for a large portion of gasoline
  production.  Fuel is consumed in this operation in the catalyst regeneration procedure which removes
  coke and tars from the catalyst surface.  Temperatures during this process are moderate, ranging
  from 840 to 922K (1,050 to 1.200F), but fuel  requirements are on the order of 829kJ/l (125,000 Btu/
  Bbl) feedstock.  Catalytic cracking capacity increased about 1.7 percent per year between 1960 and
  1973.  Future growth will depend on energy and environmental policy and particularly the demand for
  low sulfur fuel oil.   Present estimates of future growth are from 1 percent to 3.0 percent per year
  (Reference 2-30).
         Catalytic reforming,  where certain saturated ring hydrocarbons  are converted into aromatic
 compounds,  typically  utilizes oil,  gas,  or electricity as its  primary fuel.   Delayed coking is  an
 energy extensive  process  which uses  severe cracking to convert residual  pitch and tar to gas,  naptha,
 heating oil and other more  valuable  products.   Hydrotreating is  a  process  designed  to remove  impur-
 ities  such  as  sulfur,  nitrogen,  and  metals to  prepare  cracking or  reformer feedstock.
        Process  heating  fuels  used by the refinery  industry  are primarily natural  gas  and  refining
 gas,  along  with some  residual oils and petroleum coke.   Projections are for a 2.7 percent annual
 increase in process heating to 1980,  and 2.9 percent per year  to 1985 (Reference  2-30).   The fuel
 mix for the future is highly  dependent on  both  availability  and costs of the  preferred fuels, and
 is therefore very difficult to project until national energy priorities are established and the ques-
 tion of natural gas price regulations is  settled.
 Brick and Ceramic Kilns
        Brick and ceramic kilns for curing clay products are another major user of process heating
 fuels.  Products of these kilns include  structural bricks, structural and facing tile, vitrified
 clay pipe,  and other related items.  Typically a kiln is operated in conjunction with a drier which
 recovers part of the heat contained in the exhaust gases.  Kilns are fueled by coal, oil, or gas
 (depending on the  availability of fuel and the product being cured) for batch runs of 50  to 100
 hours at temperatures  around 1,367 K (2,000 F).   Combustion products are ducted from the  kiln  to a
drier, where wet clay  products undergo an initial  drying process.     Occasionally, when higher
temperatures are needed for  drying,  a secondary combustion process  is  used  in  the  drier itself.
                                               2-30

-------
Emissions
        Emissions from the industrial  process equipment sector are regarded as the most difficult to
quantify of all  stationary sources.   This is largely due to the extreme diversity of equipment types
in use and is compounded by the common practice of reporting industrial fuel  use by sector rather
than by equipment type.  The annual  nationwide NOX emissions estimates for the significant emitters
in the industrial process heating sector are given in Table 2-18.   A number of minor equipment types
are excluded from this table, as insignificant on a national scale, but could be important from the
standpoint of localized pollution potential.  The data sources used to generate Table 2-18 include
References 2-4 and 2-31 through 2-35.  The nationwide emissions for the industrial process sector are
estimated to be  432.2 Gg (0.476 x 106  tons) per year which comprises 3.5  percent of the nationwide
total from all stationary sources.  Table 2-18 also shows estimates for some process equipment types
from a recent output from the National Emissions Data System (NEDS) and from a recent IGT study
(Reference 2-36).  Major discrepancies exist in the estimate for glass melting furnaces and for
heating/annealing ovens.  Further study should therefore be made before these data are used to
evaluate the need for control measures for these sources.
2.3.6  Incineration
       NOX emissions estimates due to incineration are taken from the OAQPS survey, Reference 2-32.
NOX emissions from open or prescribed burning are not included in this category.  OAQPS reported a
total NOX production due to incineration of 37 Gg (41,000 tons).  The 1971 estimate was updated to
1974 using population growth and GNP data obtained from the Bureau of Census, Reference 2-35, and
is presented in Table 2-19.  The total NOX emissions from incineration are thus estimated to be
39 Gg (43,000 tons) per year and may be compared to the AP-115 (Reference 2-26) estimate for 1969
of 64 Gg (70,000 tons) NOX and the 1976 NEDS National Emissions Summary value of 42 Gg (46,000 tons)
NOX-  In view of the broad spectrum covered by the industrial incineration sector, these discrep-
ancies are not surprising.
2.3.7   Noncombustion Sources
        NOX emissions for the chemical industry dominate this category.  Again, OAQPS, Reference
2-32, data are used exclusively for nitric acid production, sulfuric acid production, and explosives
manufacture.  The emissions for these sources were updated to 1974 by production data obtained from
the  Bureau of Census, Reference 2-35, and are presented in Table 2-20.  Personal communication with
GCA  Corporation yielded emission estimates for adipic acid plants.  The total NO  emission from
these noncombustion sources amounts to 203 Gg (0.224 million tons) per year.  Nitric acid production
                                                 2-31

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                                              2-32

-------
   TABLE  2-19.   SUMMARY  OF  ANNUAL  NOX  EMISSIONS  FROM  INCINERATION1
Industry
Incineration
Total
Application
Industrial
Municipal

Total NO Emissions
Gg
21.8
17.2
39.0
          TABLE 2-20.  SUMMARY OF ANNUAL EMISSIONS FROM
                       NONCOMBUSTION SOURCES3
Industry
Acid


Explosives
Total
Application
Sulfuric
Nitric
Adi pic


NOX, Ggb
10.9
127.0
14.5
50.9
203.3
TABLE 2-21.  ESTIMATES OF ANNUAL NOX EMISSIONS FROM OTHER SOURCES
Source
Solid waste disposal
Forest wildfires
Prescribed burning
Agriculture burning
Coal refuse fires
Structural fires
Misc. (welding, grain silos, etc.)
Total
NO , Ggb
x y
150
138
30
13
53
6
45
435
  These tables are included  in Appendix A in English units.

  By convention all NOX emissions are reported as equivalent NO-.
  Approximately 95 percent of the N0x from stationary source combustion
  is emitted as NO.
                                2-33

-------
is by far the largest source of noncombustion NOX emissions,  contributing  nearly  62  percent  of  the
total.  Although NO  emissions from the manufacture of sulfuric acid  are a result of.combustion of
sulfur in the feedstock with gas or oil, this source is included here rather than with  the combus-
tion sources.
2.3.8   Other NOX Emissions
        Other sources of NO  emissions include forest fires,  prescribed burning,  and structural fires.
Estimates of emissions from these sources are very inconsistent.  A composite of  estimates and  data from
several sources (References 2-32, and 2-35, and the 1976 NEDS National Emission Report) is given in Table 2-21

2.4     SUMMARY OF 1974 NOX EMISSIONS AND FUEL CONSUMPTION
        This section presents a summary of the 1974 estimated NOX emissions and fuel consumption by
sector and fuel.  This will be followed -by comparisons with other sector inventories, primarily
References 2-4 and 2-15.
        A summary of total NO  emissions by fuel and sector compiled from the best available data is
presented in Table 2-22. Table 2-23 summarizes the 1974 fuel consumption by sector.  The NOX emissions
estimates are further  summarized in Figure 2-2.  Tables 2-24 and 2-25 compare these data with pre-
vious estimates:  MSST, Reference 2-4;  GCA, Reference  2-15; ESSO, Reference 2-31; AP-115, Reference
2-26; and OAPQS, Reference 2-32.  Exact comparison to  other sources  is  virtually  impossible since
each  chose to present  NO  sources grouped under  different headings.  These tables demonstrate  that
                        A
the  present  set of data, while based  on much more detailed breakdowns,  are in reasonable agreement
with  previous estimates.
2.5      NOX  EMISSION TRENDS AND  PROJECTIONS
         Nationwide NO   emission  trends  from  1940 to  1972 as compiled by the EPA  (Reference  2-37) are
illustrated  in  Figure  2-3.   In  general, stationary  sources comprise  between 60 and  70  percent  of the
total NOX production,  as  shown  in  the figure.   Figure  2-4 compares the  EPA  figures  with  the ESSO
 (Reference  2-31) estimates  published  in 1968.   The  slight downward trend  in  1971  of the  EPA data is
due  to revised  emission factors.   As  can  be  seen from the figure,  1972  emissions  have  already  attain-
ed the 1978  ESSO estimate.
         Projections  for nationwide NO  emissions from stationary sources  have  been  made  by  the
 National Academy of  Sciences  (Reference 2-37)  based on several  assumptions,  including  consideration
 for various  control  options.   These projections with extrapolation to the year 2000 are  presented  in
 Table 2-26.   Assumptions made for these projections are:
                                                 2-34

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                                                      2-35

-------
                   TABLE 2-23.   SUMMARY OF ANNUAL FUEL USAGE3, 1974
Sector
Utility Boilers
1C Engines
Reciprocating
Turbines
Industrial Boilers
Commercial Boilers
Residential Heating
TOTAL
Fuel Usage6 - EJ
(percentage of total)
Gas
3.376 ( 6.95)

1.063 ( 2.19)
0.642 ( 1.32)
7.230 (14.87)
2.387 ( 4.91)
5.597 (11.51)
20.295 (41.75)
Coal
9.935 (20.44)

-
-
3.294 ( 6.78)
0.282 ( 0.58)
-
13.511 (27.80)
Oil
2.998 ( 6.16)

0.268 ( 0.55)
0.301 ( 0.62)
4.208 ( 8.66)
3.620 ( 7.45)
3.406 ( 7.01)
14.801 (30.45)
Total
16.309 (33.55)

1.331 ( 2.74)
0.943 ( 1.94)
14.732 (30.31)
6.289 (12.94)
9.003 (18.52)
48.607 (100.0)
aThis table is included  in Appendix A in English units.




Excludes process fuel.
                                          2-36

-------
                      INCINERATION
                             GAS TURBINES
                              -i	 BOTHERS
                                         NONCOMBUSTION
                            12 O/ oc  /  Vv,-INDUSTRIAL PROCESS
                                                 HEATING
                                             9.0
                                        OMMERCIAL/
                                       RESIDENTIAL
                                      SPACE HEATING
                                RECIPROCATING 1C
                                  ENGINES
                                    ESTIMATED NOX EMISSIONS
SOURCE
UTILITY BOILERS
INDUSTRIAL BOILERS
RECIPROCATING 1C ENGINES
COMMERCIAL/RESIDENTIAL HEATING
INDUSTRIAL PROCESS HEATING
NONCOMBUSTION
GAS TURBINES
INCINERATION
OTHER
TOTAL
Tg
5.105
2.218
2.413
1.090
0.432
0.203
0.236
0.039
0.435
12.171
1fl6 tons
5.628
2.444
2.660
1.202
0.476
0.224
0.260
0.043
0.479
13.416
Figure 2-2.  Summary of 1974 stationary source NOX emissions.
(Pie chart units in percent).
                            2-37

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                                      O TOTAL EMISSIONS
                                      DSTATIONARY FUEL COMBUSTION
                                      AROAD VEHICLES
                                      • ELECTRICITY GENERATION
                                      • INDUSTRIAL FUEL COMBUSTION
                                      AINDUSTRIAL PROCESS LOSS
                                                                                 x
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1940
1950
                                               1960
                                     YEAR
1968  1970  1972
   1969
    Figure 2-3. Nationwide annual NOX emission trends 1940 - 1972 (Reference 2-37).
                                     2-40

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                Figure 2-4.  Annual stationary source NOX emission trends.
                                           2-41

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        •   Implementation of NSPS (1972) for utility boilers and nitric acid plants
        •   Electrical demand grows at about 6.5 percent per year
        •   No increase in oil consumption after 1975
        t   The 1940 to 1972 growth rate of NO  emissions from industrial,  commercial,  and
            institutional  sources will be reduced over the next 30 years to 2.63 percent
            per year due to a shift to electricity

       Two cases for electric power generation are considered.  One assumes that most new electric
power plants will be nuclear; the other assumes no new nuclear plants after 1975.  Neither of these
are realistic but were considered, at the time they were made, to bracket the possible cases.  The
uncertainty of projections of this nature is compounded by several emerging trends:

        t   There will be a significant increase in the utilization of coal in power  generation,
            leading to an intensified NO  problem unless stringent controls are adopted
        t   Industrial area sources may be switching from gas to oil or coal, resulting in
            larger potential NO  emissions
        •   The potential  application of alternate fuels is difficult to quantify at  this
            time (probably 10 years away)
        •   The recent emphasis on energy conservation has produced lower than expected energy
            growth rates in the industrial and utility sectors
       In view of these trends, the confidence level  of any speculations on growth  rates  of specific
       nt/fuel combina
include the following:
equipment/fuel  combinations 1s very low.   Other significant factors  affecting  future  NO  emissions
        0   Major technological  developments 1n equipment design,  fuels  and  fuel  treatment,  combus-
            tion control  and exhaust gas cleanup
        •   Uncertainty concerning the future of nuclear energy as a  major source of  electrical
            power
        •  The degree to which NOX emissions will be regulated by  both  local  and  federal  agencies
        More recent projections  of stationary source NOX emissions have  been made in  Reference  2-38.
Several growth and control  scenarios are considered.  The energy use  patterns are based primarily
on FEA (Reference 2-39) and ERDA (Reference 2-40) reports.   Emission  factors consider retirement
rates of old equipment and  various levels of NSPS (Including existing, proposed,  and  possible)  for
                                                2-43

-------
         TABLE 2-27.  ESTIMATED FUTURE NSPS CONTROLS (Reference 2-38)
NOX Source
Utility and Large
Industrial Boilers
(>73 MW)a Coal



Oil
Gas
Large Packaged Boilers
(>7.3 MW)a Coal


Oil
Gas
Small Packaged Boilers
£7.3 MW)a Coal
Oil
Gas
Small Commercial and
Residential Units
Oil
Gas
Gas Turbines

1C Engines Dist Oil

Nat Gas

Gasoline

Process Combustion

Date Implemented
1971

1977
1981
1985
1988
1971
1971

1979
1985
1990
1979
1979

1979
1979
1979


1983
1983
1977
1983
1972
1985
1979
1985
1979
1985
1981
1990
Standard (ng/J)
300

258
215
172
129
86
129

258
215
172
129
86

50% reduction
86
129


30
17
129
86
1390
1040
1240
930
950
710
20% reduction
40% reduction
aThermal input
                                      2-44

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                                    OTOTAL NOX - PRESENT CONTROLS
                                    D TOTAL NOX - NSPS CONTROLS
                                    AUTILITY BOILERS-PRESENT CONTROLS
                                    OUTILITY BOILERS - NSPS CONTROLS
   1974
                                                                      2000
 Figure 2-5. Annual stationary source NOX emissions projections - low nuclear
 (Reference 2-38).
                                    2-46

-------
15
                                      O TOTAL NOX - PRESENT CONTROLS
                                      D TOTAL NOX-NSPS CONTROLS     	
                                      AUTILITYBOILERS -PRESENT CONTROLS
                                      OUTILITY BOILERS - NSPS CONTROLS	
 1974
2000
   Figure 2-6. Annual stationary NOX emissions projections - high nuclear
   (Reference 2-38).
                                    2-47

-------
 new equipment.   The most stringent NSPS  considered  are  given  in Table  2-27.  Table 2-28 presents a
 breakdown by end use sector for two of the cases  considered in Reference  2-38.  The main assumptions
 are:
         •   NSPS as shown in Table 2-27
         •   Growth in electrical  demand  of 4.4  percent  per year
         •   Continuation of current consumption patterns

       The low nuclear case considers 35  percent of new electrical  capacity to  be  supplied  by nuclear
power and the remaining 65 percent by coal-fired boilers.   The high nuclear case reverses these  per-
centages.  Both of these cases are shown  graphically in Figures  2-5 and 2-6.  For  comparison  the same
growth cases with current control  levels  only are  also shown.  The  potential  reduction  through a
vigorous control  program is evident.  Comparison of  Figures  2-5 and 2-6 and Table  2-26  shows  a size-
able difference in projected emissions for the various assumptions.  A  large  part  of the difference
is due to a downward revision in the growth of electrical  demand in  Reference 2-38 to reflect recent
trends.   These results further illustrate the difficulty of projecting  emissions very far into the
future.

                                      REFERENCES FOR  SECTION 2

2-1      Chamot,  E.M., D.S.  Pratt,  and H.W. Redfield,  "Journal  of the American Chemical  Society,"
         33,  366,  1911.
2-2      Code of  Federal  Regulations, Title 40,  Part 60, Appendix A, Method 7.  See also:   Hami1, H.
         and  R. Thomas,  "Collaborative Study  of  Method for the Determination of Nitrogen Oxide
         Emissions  from  Stationary  Sources,"  SwRI-EPA  Contract 68-02-0626, May 8,  1974.
2-3      Federal  Register,  Vol.  41,  No. 232,  December  1, 1976.
2-4      Mason, H.B.  and  A.B.  Shimizu, "Definition of  the Maximum Stationary Source Technology (MSST)
         Systems  Program  for NOX,"  (Draft Report) Aerotherm Final  Report 74-123, Acurex Corporation,
         Aerotherm  Division, October 1974.
2-5      "Compilation of  Air Pollution Emission  Factors  (Second Edition)," Publication No.  AP-42,
         Environmental Protection Agency,  Research Triangle Park, North Carolina, April  1973.
2-6      Supplement No. 4 of Reference 2-5, January 1975.
2-7      Supplement No. 5 of Reference 2-5, December 1975.
2-8      Supplement No. 6 of Reference 2-5, April 1976.
2-9      Cato, G.A., H.J. Buening, C.C. DeVivo,  B.C.  Morton, and J.M. Robinson,  "Field Testing:
         Application of Combustion Modification  to Control  Pollutant Emissions from Industrial
         Boilers -  Phase  1," KVB Engineering  Inc.,  EPA-650/2-74-078a, Research Triangle  Park,  N..C.,
         October  1974.
2-10     Crawford, A.R.,  E.H. Manny, and W. Bartok, "Field Testing:   Application of Combustion Modi-
         fications  to Control NO  Emissions from Utility Boilers,"  Exxon Research and  Engineering
         Company, June 1974.
                                                                                          »
2-11     Offen, G.R., et  al.,  "Standard Support Document and Environmental  Impact Statement  - Sta-
         tionary Reciprocating Internal Combustion  Engines" (Draft  Report).  Acurex Corp./
         Aerotherm Division, Mountain View, California, Project 7152, March 1976.

                                                2-48

-------
2-12    Environmental  Protection  Agency,  "Standard  Support and Environmental Impact Statement for
        Standards of Performance:   Lignite-Fired  Steam  Generators," Final Draft, OAPQS, March 1975.

2-13    "Standard Support and Environmental  Impact  Statement, Vol  1:   Proposed Standards of Perfor-
        mance for Stationary Gas  Turbines,"  EPA-450/2-77-017a, September  1977.

2-14    Personal  communication with H.J.  Melosh  III,  Foster  Wheeler Corporation.

2-15    Surprenant, N.F.  et. al., "Preliminary Emissions  Assessment of Conventional Stationary Com-
        bustion Systems,"~GCA Corporation,  EPA Report No. 600/2-76-046b,  March 1976.

2-16    FPC News, Federal Power Commission,  Washington, D.C., June 6,  1975.

2-17    Dykema, O.W., and Kemp, V.E., "Inventory of Combustion Related Emissions from  Stationary
        Sources," (First Update).  Aerospace Corporation, EPA-600/2-77-066a, March  1977.

2-18    Putnam, A.A., Kropp, E.L., and Barrett,  R.E., "Evaluation of  National Boiler  Inventory,"
        Battelle Columbus Laboratories, October  1975.

2-19    Personal communication with R.R.  Vosper,  Coen Company, January 1977.

2-20    "Current Industrial Reports, Steel  Power Boilers,"  1968-1975, U.S.  Department  of Commerce,
        Bureau of the Census.

2-21    "Patterns of Energy Consumption in the United States,"  Stock  No.  4106-0034, Stanford  Research
        Institute, Menlo Park, California, January 1972.

2-22    Dupree, W.G., and J.S. Corsentino, "Energy Through  the Year  2000 (Revised),"  Bureau of Mines,
        December 1975.

2-23    "National Gas Survey," Preliminary Draft, Federal Power Commission, 1974.

2-24    Barrett, R.E., Miller, S.E., and Locklin, D.W., "Field Investigation of Emissions from Com-
        bustion  Equipment for  Space Heating," Report No.  EPA-R2-73-084a, Prepared by Battelle Memo-
        rial  Institute,  Columbus, Ohio, June 1973.

2-25    "Nationwide  Inventory  of Air Pollutant Emissions 1968,"  Pub.  No. AP-73,  Environmental Pro-
        tection Agency,  Research Triangle Park,  North Carolina,  July 1971.

2-26    Cavender, J.H.,  Kircher, D.S. and Hoffman, A.I., "Nationwide Air Pollutant Emission Trends
        1940-1970," Pub. No. AP-115, Environmental Protection Agency, Research Triangle Park, North
        Carolina, January 1973.

2-27    Crump, L.H. and  Reading, C.L., "Fuel and Energy Data -United States by States and Regions,
        1972,"  Information  Circular 8647, Bureau of Mines,  Department of Interior.

2-28    "Monthly Energy  Review," Federal Energy Administration, July 1976.

2-29    McGowin,  C.R., "Stationary  Internal Combustion Engines in the United States," Report No.
        EPA-R2-73-210, Prepared  by  Shell Development Company, Houston, Texas, April 1973.

2-30    Foley,  G.,  "Industrial Growth  Forecasts,"  Stanford  Research  Institute, Contract No. 68-02-
         1320, September  1974.

2-31    Bartok,  W.,  et.  al_., "Systems  Study of Nitrogen  Oxide Control Methods for  Stationary Sources -
        Vol. II," prepared  for National  Air Pollution  Control Administration, NTIS Report No. PB-192-
         789, Esso Research  and Engineering,  1969.

 2-32     "OAQPS Data File of Nationwide Emissions,  1971," Office  of Air Quality Planning and Standards,
         Environmental  Protection Agency, May  1973.

2-33     Goldish, J.  et.  al_., "Systems  Study of  Conventional Combustion Sources in  the  Iron and Steel
         Industry," Report No.  EPA R2-73-192,  Prepared  by Walden  Research Corporation,  Cambridge,
         Massachusetts,  April 1973.

 2-34     Oil and Gas Journal, Volume 73,  No.  12.   The Petroleum Publishing  Company, Tulsa, Oklahoma.

 2-35    "Annual Survey of Manufacturers  1974  -  Fuels and Electric Energy Consumed," U.S. Department
         of Commerce, Bureau of the Census.
                                                  2-49

-------
2-36   Ketels, P.A., J.D. Nesbitt, and R.D.  Oberle,  "A Survey of Emissions Control  and Combustion
       Equipment Data in Industrial Process  Heating," Institute of Gas Technology,  Final  Report
       8949, October 1976.


2-37   National Academy of Science, "Air Quality and Stationary Source Emission  Control,"  Prepared
       for the Committee on Public Works, United States Senate, Serial  No.  94-4, March 1975.

2-38   Salvesen, K.G.,  et ^1.,  "Emissions Characterization  of Stationary  NO  Sources," Aerotherm
       Draft Report, TR-77^72,  October 1977.                                x         '


2-39   "1976 National Energy Outlook," Federal  Energy Administration,  FEA/N-75/713,  February  1976.

2-40   "A National  Plan for Energy Research, Development &  Demonstration:   Creating  Energy Choices
       for the Future," ERDA-48,  Volume 2 of 2.
                                              2-50

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                                             SECTION 3
                                        CONTROL TECHNIQUES
       This section presents a survey of the general principles and developmental  status of poten-
tial techniques for NO  control for stationary sources.   It is intended to provide a broad perspec-
tive on the various suggested concepts for NO  control by combustion process modification and
flue gas treatment for combustion sources and by tail gas cleanup for noncombustion sources.  A
more detailed review of the effectiveness and cost of control implementation on specific equipment
types is given in Sections 4, 5, and 6.
3.1    COMBUSTION MODIFICATIONS
       Modifying the combustion process is the most widely used technique for reducing combustion
generated oxides of nitrogen.  This section describes the four most popular methods:  modification
of the operating conditions, equipment design modification, fuel modification, and use of alternate
combustion processes.  The section begins by describing the factors which affect the generation of
NO  during combustion.
3.1.1  Factors Affecting NOX Emissions from Combustion
       Oxides of nitrogen formed in combustion processes are usually due either to thermal fixation
of atmospheric nitrogen in the combustion air, leading to "thermal  NO ", or to the conversion of
                                                                     A
chemically bound nitrogen in the fuel, leading to "fuel NOX".  For natural gas and light distillate
oil firing, nearly all N0y emissions result from thermal fixation.  With residual oil, crude oil,
and coal, the contribution from fuel-bound nitrogen can be significant and, under certain operating
conditions, predominant.
       A third potential mechanism of  NO  formation arises in processes such as glass manufacturing,
where the raw materials in contact with the combustion products contain nitrogen compounds.  Little
is  known about the extent of conversion to NO  of these nitrogen compounds, or of the effects of
combustion modifications on this mechanism.
                                                 3-1

-------
 3.1.1.1   Thermal  NOX
        The detailed  chemical  mechanism by  which  molecular nitrogen  in  the  combustion  air  is  con-
 verted to nitric  oxide is  not fully  understood.   In  practical  combustion equipment, particularly
 for liquid or solid  fuels,  the kinetics of the N2-02 system  are  coupled to the  kinetics of hydro-
 carbon oxidation  and both  are influenced,  if  not dominated,  by effects of  turbulent mixing in  the
 flame  zone.   It is,  however,  generally accepted  that thermal NOX forms at  high  temperatures  in an
 excess of air.  The  usually stable oxygen  molecule dissociates to oxygen atoms  which  are  very
 reactive.   These  atoms react  with the  otherwise  stable nitrogen  molecule to form NO .
       The most widely accepted reactions  that describe  the  formation of thermal NO   are  those of
 the extended  form of the Zeldovich chain mechanism (Reference  3-1):
                                                  02  + M^O  +  0  + M                       (3-1)
                                                  N2  + 0 t NO + N                         (3-2)
                                                  N   +  OH 2  NO + H                        (3-3)
                                                  02  + N ^ NO + 0                         (3-4)
 Equation  (3-1) is considered  to be in  equilibrium, and M  is  a  "third body", normally  taken to  be
 molecular  nitrogen.   For thermal NOX,  reaction (3-2) is much slower than reaction (3-3) and, there-
 fore,  controls the rate of  NO formation.  The creation of an NO  molecule from reaction (3-2) is
 accompanied by the release  of an N atom, which rapidly forms another NO molecule from reaction
 (3-3)  and  (3-4).  Reactions (3-2) and  (3-4) are the chain-making  and chain-breaking mechanisms,
 and the oxygen atom  is the  chain carrier.
       Experimental measurements of NO formation  in heated mixtures of N2>  02 and Argon at
 atmospheric pressure  have been correlated with an equation of  the form (Reference 3-2):
                                       [NO]  =   k, e-k2/T [N2] [02]1/2 t                 (3-5)
Where:  [] = mole fraction
        T = absolute temperature
        t = residence time
     k,, k2 = constants
This expression reflects the strong dependence of NO formation on temperature.   It also shows that
NO concentration is directly proportional  to N2 concentration and to the residence time, and varies
                                                3-2

-------
with 02 to the one-half power.   A rate expression such as this one does not fully describe the
thermal NO  reaction mechanism, but it does give some valuable qualitative trends.
       The temperature and time dependencies of NO formation are illustrated in Figure 3-1 for
idealized conditions (References 3-3 and;3-4).   The results at 0.01 sec for three values of the
stoichiometric ratio (S.R.) show, as expected,  that NO formation is suppressed by reduced avail-
ability of oxygen.  In a practical combustor, departure from S.R. = 1  would result in reduced
temperatures which would further suppress NO formation.  It is precisely these factors of high
sensitivity to temperature, oxygen concentration level, and time of exposure which make the forma-
tion of thermal NO  susceptible to combustion modification.
       Ideally, then, the formation of thermal  NO  could be reduced by four tactics:   (1) reduce
nitrogen level at peak temperature, (2) reduce oxygen level at peak temperature, (3)  reduce peak
temperature, and (4) reduce time of exposure at peak temperature.  In typical hydrocarbon-air
flames, [N~] is of the order 0.7 and is relatively difficult to modify.  Therefore, field practice
has focused on reducing oxygen level, peak temperature, and time of exposure in the NO -producing
region of the combustor.   (Reference 3-5.)  These parameters are in turn dependent on secondary
combustion variables such as combustion intensity and internal mixing in the flame zone - effects
which are ultimately determined by primary equipment and fuel parameters over which the combustion
engineer has some control.  A hierarchy of effects leading to thermal  NO  formation is depicted
in Table 3-1.  Although causal relationships between the four categories shown in Table 3-1 are
not firmly established, combustion modification technology is, nevertheless, confronted with the
task of reducing thermal NO  through modification of equipment and fuel parameters.  This task
has been approached with efforts ranging from the short-term testing of equipment modifications
on commercial units, in order to determine the effect on NO  emissions, to long-term fundamental
studies and pilot testing directed at achieving a basic understanding of NO  formation.
       Combustion modification techniques such as lowered excess air and off stoichiometric or
staged combustion have been used to lower local 0? concentrations in boilers.  Also,  staged
combustion in the form of stratified charge cylinder design has been used successfully in 1C
engines.  Since gas turbines typically operate at excess air levels far greater than  stoichiometric,
lowering excess air levels in this equipment class does not control thermal NO .
       Flue gas recirculation and reduced air preheat have been used in boilers to control thermal
NO  by lowering peak flame temperatures.  Analogously, exhaust gas recirculation (EGR), reduced
manifold air temperature (1C engines) and reduced air preheat (regenerative gas turbines) have been
                                                 3-3

-------
   2800
6000
   3000
          TEMPERATURE, °F
    3200         3400
                                        3600
                                         3800
                                                                4000
              PRIMARY ZONE-ADIABATIC
              NO FORMATION
              2376 K (3800 °F)
              FOR 0.05 sec-^150 ppm
                                                                  ^•ADIABATIC
                                                                       TEMP.
     RECIRCULATION ZONE
     NO FORMATION
     1922 °K (3000 °F)
     FOR 2.0 sec-^-50 ppm
                                                     S.R. - STOICHIOMETRIC RATIO
 10
 1800
1900
2000
                                  2100       2200

                                 TEMPERATURE, °K
                                            2300
                                             2400
  Figure 3-1. Kinetic formation of nitric oxide from combustion of natural gas at
  atmospheric pressure (References 3-3 and 3-4).
                                      3-4

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applied to  1C engines and gas turbines.  Other techniques designed to lower peak temperatures in
prime movers include water injection and altered air/fuel ratios.
       Techniques which reduce residence time at peak temperature have been more easily applied to
prime mover equipment classes.  Although flue gas recirculation  (and EGR) reduces combustion gas
residence time, it acts as a thermal NO  control primarily through temperature reduction.  Tech-
niques which specifically reduce exposure time at high temperatures include ignition retard for 1C
engines and early quench with secondary air for gas turbines.
       It is important to recognize that the above-mentioned techniques for thermal NO  reduction
alter combustion conditions on a macroscopic scale.  Although these macroscopic techniques have all
been relatively successful in reducing thermal NO , local microscopic combustion conditions ulti-
mately determine the amount of thermal NO  formed.  For example, recent studies on the formation of
thermal NO  in gaseous flames have confirmed that internal mixing can have large effects on the total
amount of NO formed (References 3-6, 3-7).  Burner swirl, combustion air velocity, fuel injection
angle and velocity, burner divergent angle and confinement ratio all affect the mixing between fuel,
combustion air and recirculated products.  Mixing, in turn, alters the local temperatures and
species concentrations which control the rate of NO  formation.
                                                   x
       Unfortunately, generalizing these effects is difficult, because thp interactions are complex.
Increasing swirl, for example, may both increase entrainment of cooled combustion products (hence
lowering peak temperatures) and increase fuel/air mixing (raising local  combustion intensity).  The
net effect of increasing swirl can be to either raise or lower NO  emissions, depending on other
system parameters.
       In summary,a hierarchy of effects depicted in Table 3-1 produces  local  combustion conditions
which promote thermal NOX formation.  Although combustion modification technology seeks to affect
the fundamental  parameters of combustion, modifications must be made by  changing the primary equip-
ment and fuel  parameters.   Control  of thermal  NOX, which began by altering inlet conditions and
external  mass addition, has moved to more fundamental  changes in combustion equipment design.
3.1.1.2  Fuel  NOX
       The role of fuel-bound nitrogen as a source of NOX emissions from combustion sources has
been recognized since 1968 (Reference 3-8).   Although the relative contribution of fuel  and thermal
NOX to total NOX emissions from sources firing nitrogen-containing fuels has not been definitively
established, recent estimates indicate that fuel  NO  is significant and  may even predominate.   In
                                                   A
one recent study (Reference 3-9),  residual  oil  and pulverized coal  were  burned  in  an  argon/oxygen
                                                3-6

-------
mixture to eliminate thermal NOX effects.   Results show that fuel  NOX can account for over 50 per-



cent of total NO  production from residual  oil firing and approximately 80 percent of total NOX



from coal firing.  Therefore, as coal is increasingly used as a national energy source, the control



of fuel NO  will become more important.
          A


       Fuel-bound nitrogen occurs in coal  and petroleum  fuels.  The nitrogen containing compounds



in petroleum tend to concentrate in the heavy resin and asphalt fractions upon distillation (Refer-



ence 3-10).  Table 3-2 gives analyses of typical fuel oils.  Fuel  nitrogen is less than 0.01 per-



cent for distillate oils; however, it ranges from 0.1 to 0.5 for residual oils.



       The classes of nitrogen compounds in fuel oil include indoles, quinolines, pyradines, and



carbazoles.  Their quantities in the distilled fractions vary with the origin of the crude oil.



From one California crude,  pyradines dominated in the distillate fraction and carbazoles dominated



in residual oil  (Reference  3-11).



       Table 3-3 gives analyses of four ranks of U.S. coals.  Nitrogen content of most U.S. coals



lies in  the 0.5  to 2 percent range (Reference 3-12); anthracite coals contain the least and bitu-



minous coals the most nitrogen.  Although the structure of coal is not  known with certainty, it



is believed that coal-bound nitrogen occurs in aromatic ring structures  such as  pyridine,



picoline,  quinoline, and  nicotine  (Reference  3-10).  Figure 3-2 illustrates the  nitrogen content



of various U.S.  coals, expressed as  ng  N02 produced  per Joule  for 100 percent conversion of the



fuel nitrogen.   The figure  clearly shows that if  all coal-bound nitrogen were converted to NOX>



emissions  for  all coals would exceed New Source Performance Standards.   Fortunately, only  a frac-



tion of  the  fuel nitrogen is converted  to NOX for both oil and coal  firing, as shown in Figure 3-3.



Furthermore, the figure  indicates  that  fuel nitrogen conversion decreases as nitrogen  content



increases.   Thus, although  fuel  N0x  emissions undoubtedly  increase with increasing  fuel nitrogen



content, the emissions  increase is not  proportional.   In  fact, recent data  indicate only  a small



 increase in  NO  emissions as fuel  nitrogen  increases (Reference 3-14).   From observations  such as
               A


these,  the effectiveness  of partial  fuel denitrification  as  a  NOX control method seems doubtful.



        The precise  mechanism by which  fuel  nitrogen is converted  to  NOX is  not understood; however,



 certain aspects are clear,  particularly for  coal  combustion.   In  a  large,  pulverized coal  utility



 boiler,  the coal particles are  conveyed by  an airstream  into the  hot combustion  chamber,  where



 they are heated at  a  rate in excess  of 10"K/s.  Almost  immediately volatile  species, containing some



 of the coal-bound  nitrogen, vaporize and  burn homogeneously,  rapidly (-10  ms)  and probably detached



 from the original  coal  particle.  Combustion of the remaining solid  char is heterogeneous and  much



 slower (~300 ms).
                                                 3-7

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         3-10

-------
   100
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o •
 OMARTIN AND BERKAU
 DTURNER, ETAL.        ~
 ATURIMER ANDSIEGMUND
 OFENIMORE
 • HAZARD
 • MCCANN,ETAL.        ~
 APERSHING, ET AL.
 •FLAGAN AND APPLETON

NOTE: OIL FUEL UNLESS   _
      OTHERWISE INDICATED
                                                          COAL
     i
             0.2      0.4      0.6      0.8       1.0      1.2      1.4

                             NITROGEN IN FUEL BY WEIGHT, percent
         1.6
                                                          1.8
2.0
     Figure 3-3. Percent conversion of fuel nitrogen to NOX in laboratory scale combustion
     (Reference 3-13).
                                          3-11

-------
        Figure 3-4 summarizes what may happen to fuel  nitrogen during this process.   In general,
 nitrogen evolution parallels evolution of the total  volatiles, except during  the initial  10 to 15
 percent volatilization in which little nitrogen is released  (Reference 3-16).   Both total  mass
 volatilized and total  nitrogen volatilized increase  with  higher pryolysis temperature; the nitro-
 gen volatilization increases more rapidly than that  of the total  mass.   Total  mass  volatilized
 appears to  be a stronger  function of coal  composition than 1s  total  nitrogen volatilized  (Reference
 3-17).   This supports  the relatively small  dependence of  fuel  NOX on coal  composition  observed in
 small  scale testing (Reference 3-9).
        Although there  is  not absolute agreement on how the volatiles separate  into  species,  it
 appears that about half the  total  volatiles  and 85 percent of  the nitrogeneous  species do  not  evolve
 as  permanent light gases.  However,  prior  to oxidation, the devolatilized  nitrogen  may be  converted
 to  a small  number of common,  reduced  intermediates,  such  as HCN and  NHL,  in the fuel regions of the
 flame.   The existence  of  a set pf conmon  reduced  intermediates would explain the observations  that
 the form of the original  fuel  nitrogen compound does  not  influence its conversion to NO (e.g.,
 References  3-10,  3-18).   More  recent  experiments  suggest  that  HCN  is the predominant reduced inter-
 mediate (Reference 3-19).  The reduced intermediates  are  then  either oxidized to NO, or converted
 to  N2 in the post-combustion zone.  Although  the mechanism for these conversions is not presently
 known,  one  proposed mechanism  postulates a role for NCO (Reference 3-20).
        Nitrogen  retained  in  the char may also be oxidized  to NO, or  reduced to  N2 through hetero-
 geneous  reactions  occurring  in the post-combustion zone.   However, it is clear  that the conversion
 of  char  nitrogen  to NO proceeds much more slowly than the conversion of devolatilized nitrogen.
 In  fact, based on  a combination of experimental and empirical  modeling studies,  it is now believed
 that 60  to 80 percent of the fuel NOX results from volatile nitrogen oxidation  (References 3-16 and
 3-21).    Conversion of the char nitrogen to NO is in general lower, by factors of two to three,  than
 conversion of total coal  nitrogen.
       Regardless of the precise mechanism of fuel NOX formation, several general trends are evi-
dent, particularly for coal combustion.  As expected, fuel nitrogen conversion to NO is highly
dependent on the fuel/air ratio for the range existing in  typical combustion equipment, as shown
 in Figure 3-5.  Oxidation of the char nitrogen is relatively  insensitive to fuel/air changes, but
volatile NO formation is  strongly affected by fuel/air ratio  changes.
       In contrast to thermal NOX, fuel NOX production is  relatively insensitive to  small  changes
in combustion zone temperature (Reference 3-18).  Char nitrogen oxidation appears to be a  very
                                                3-12

-------
                           OIL DROPLET
                               OR
                          kCOAL PARTICLEj
                              + HEAT
           VOLATILE FRACTIONS
         (HYDROCARBONS, RN ETC.)
                /
              RN.
             x x
         PATH A  PATH B
            NO


TO FLUE GASES  RELEASE ZONE
                                         OXIDATION AT
                                       PARTICLE SURFACE

                                              1
                                              NO
                                          /\
                                  ESCAPE FROM    REDUCTION IN
                                BOUNDARY LAYER  BOUNDARY LAYER
Figure 3-4.  Possible fate of fuel nitrogen contained in coal particles
or oil  droplets during combustion (Reference 3-15).
                               3-13

-------
 X
o
100
 90
 80
 70
 60
 50
 40
 30
 20
 10
  0
                                               I
   WALL TEMP.  1500 °K
   FLAME TEMP. 1600 °K
O LIGNITE 75-90 jum
O LIGNITE 38-45 jum
A BITUMINOUS 3845 Aim
                                                                                 D
                   12345
                    FUEL EQUIVALENCE RATIO (INVERSE OF STOICHIOMETRIC RATIO)
          Figure 3-5. Conversion of nitrogen in coal to NOX (Reference 3-22).
                                           3-14

-------
 weak function of temperature, and although the amount of nitrogen volatiles appears to increase as
 temperature increases, this is believed to be partially offset by a decrease in percentage conver-
 sion.  Furthermore, operating restrictions severely limit the magnitude of actual  temperature
 changes attainable in current systems.
        As described above, fuel  NO emissions are a strong function of fuel/air mixing.  In general,
 any change which increases the mixing between the fuel  and air during coal devolatilization will
 dramatically increase volatile nitrogen conversion and  increase fuel  NO.  In contrast, char NO forma-
 tion is only weakly dependent on initial  mixing and therefore may represent a lower limit on the
 emission level which can be achieved through burner modifications.
        From the above modifications, it appears that, in principle, the best strategy for fuel  NO
 abatement combines low excess  air firing,  optimum burner design,  two-stage combustion and high  air
 preheat.   Assuming suitable stage separation,  low excess air  may  have little'effect on fuel  NO, but
 it increases system efficiency.   Before using  LEA firing,  the need to get  good  carbon burnout, and
 low CO  emissions must be considered.
        Optimum burner design ensures  locally fuel-rich  conditions  during devolatilization, which
 promotes  reduction  of devolatilized  nitrogen to N2-  Two-stage  combustion  produces  overall fuel-rich
 conditions  during  the first 1  to  2 seconds and  promotes  the reduction of NO  to  N« through reburning
 reactions.   High secondary  air preheat  also  appears desirable,  because  it  promotes  more complete
 nitrogen  devolatilization  in the  fuel-rich initial combustion stage.  This leaves less char nitrogen
 to  be subsequently  oxidized in the fuel-lean second stage.  Unfortunately, it also  tends to favor
 thermal NO  formation, and at present there is no  general agreement on which  effect  dominates.
 3.1.1.3   Summary of Process Modification Concepts
        In summary of the above discussion, both thermal  and fuel NOX are kinetically or aerodynami-
cally limited in that their emission rates are far below the levels which would prevail at equilib-
rium.  Thus, the rate of formation of both thermal and fuel NOX is dominated by combustion condi-
tions and is amenable to suppression through combustion  process modifications.  Although the
mechanisms are different, both thermal and fuel NOX are  promoted by rapid mixing of oxygen with the
fuel.  Additionally, thermal NOX is greatly increased by long  residence time at high temperature.
The modified combustion conditions and control  concepts  which  have been tried or suggested to combat
the formation mechanisms are as follows:
          Decrease  primary flame zone 02 level  by
          -  Decreased overall  02 level
          -  Controlled mixing of fuel  and air
          -  Use of fuel-rich primary flame zone
                                                3-15

-------
        •  Decrease  time  of  exposure  at  high  temperature  by
           -  Decreased peak temperature:
              -  Decreased adiabatic  flame  temperature  through dilution
              —  Decreased combustion Intensity
              -  Increased flame cooling
              -  Controlled  mixing  of fuel  and air  or use of  fuel-rich primary  flame  zone
           -  Decreased primary flame zone  residence time
        •  Chemically  reduce NOX in post-flame region by
           -  Injection of reducing agent
        Table  3-4 relates these control  concepts  to applicable combustion  process modifications and
 equipment  types.  The process modifications  are  further  categorized  according  to their  role  in the
 control  development sequence:  operational adjustments,  hardware modifications of existing equipment
 or  through factory  installed controls,  and,  major  redesigns  of new equipment.  The controls  for de-
 creased &2 are also generally effective for  peak temperature reduction but have not  been repeated.
 The following subsections review the status  of each of the applicable controls.

 3.1.2   Modification of Operating Conditions
        The modification  techniques described in  this subsection include low excess air, off  stoichi-
 ometric combustion, flue gas recirculation,  reduced air  preheat, load reduction, steam  or water
 injection,  and ammonia injection.
 3.1.2.1  Low  Excess Air Combustion
        Reducing  the total amount of  excess air supplied  for  combustion is an effective  demonstrated
 method  for  reducing NOX emissions  from  utility and industrial boilers, residential  and  commercial
 furnaces, warm air  furnaces, and process furnaces.   Low  excess air (LEA) firing reduces the local
 flame zone  concentration of oxygen,  thus reducing  both thermal  and fuel  NO  formation.  LEA firing
 is  furthermore easy to implement and increases efficiency (slight decrease in fuel  consumption).
 It  is,  therefore, used extensively in both new and retrofit applications,  either singly or in com-
 bination with  other control  measures.  The ultimate level of excess air  is generally limited  by
 the onset of  smoke or carbon monoxide emissions which occurs when excess air is reduced to levels
 far below the  design  conditions.   Fouling and slagging may also increase in heavy oil- or
 coal-fired applications  at very low levels of excess air, thus  limiting  the potential of this
 technique.
       Low excess air firing is the most widespread NOX control  technique  for utility boilers.   It
was initially  implemented to increase thermal efficiency and reduce stack  gas opacity due  to  acid
mist.  A number of studies  have shown LEA firing to be  effective  in reducing  NO  emissions without

                                                   3-16

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significantly increasing CO or smoke levels (References 3-14, 3-23 through 3-27).   NO  reductions
averaging between 16 and 20 percent are achieved on gas- and oil-fired boilers when the excess  air
is reduced to levels between 2 and 7 percent.   Low excess air firing below 5 percent is now standard
practice on most oil and gas utility boilers.   NOX reductions of 20 percent on the average are
achieved on coal-fired utility boilers when excess air is reduced to the 20 percent level  or lower.
However, the minimum excess air levels achievable with satisfactory performance are 8 to 12 percent.
In some existing units,  excess air levels  below 15 to  18 percent present operating problems
(Reference 3-25).
       The minimum practical level of excess air which can be achieved in existing boilers, without
encountering operational problems, depends upon factors in addition to the type of fuel fired.
These factors include low load operation,  nonuniformity of air/fuel ratio, fuel and air control lags
during load swings, use of upward burner tilt to increase steam superheat (for tangentially-fired
boilers), and coal quality variation and ash slagging potential (for coal-fired boilers).  They tend
to increase the minimum excess air level at which the boiler can operate safely.
       Other factors such as secondary air register settings and steam temperature control flexibil-
ity also affect the excess air levels.  The boiler combustion control system must be modified so
that the proportioning of fuel and air is  adequate under all operating conditions.  Uniform distri-
bution of fuel and air to all burners is increasingly important as excess air is lowered.  Excess
air levels are also affected if other NO  control techniques are employed.  Staging and operating
at reduced load increases the minimum excess air levels whereas switching from eastern to western
coals could decrease the levels (References 3-24, 3-28, and 3-29).
       LEA firing is a very effective method for controlling NO  in industrial boilers.  Although
it is not in widespread use as a NO  control technique for industrial boilers, LEA is generally con-
sidered as part of an energy conservation  program.  LEA is also a feasible NO  control technique for
residential and commercial furnaces; however, the trend in NO  control for these sources has been in
improved burner design in order to obtain  low excess air levels without extensive CO emissions.
       LEA is not a very promising technique for 1C engines and gas turbines.  When the air/fuel
ratio is reduced, CO and HC emissions increase sharply for 1C engines.  In gas turbines, the
overall air/fuel ratio cannot, be modified  to control NO , since the ratio is determined by the
turbine inlet temperature.
        In summary, changing the overall air/fuel ratio to control NO  emissions is a simple, feasi-
ble, and effective technique for stationary sources of combustion, with the exception of gas turbine
                                                 3-18

-------
 engines and 1C engines.   For certain  applications  such  as  utility  boilers,  LEA  firing  is presently
 considered a routine operating  procedure  and  is  incorporated  in  all  new  units.   Since  it is effi-
 cient and  easy to  implement, LEA  firing will  see increasingly widespread use,in other  applications.
 Most sources will  require additional  control  methods, in conjunction with LEA,  to  bring NO  emis-
 sions within statutory  limits.  In  such cases, the extent  to  which excess air can  be lowered will
 depend upon the other control techniques  employed.   However,  virtually all  developmental programs
 for  advanced NOX controls are placing maximum emphasis  on  operation  at minimum  levels  of excess air.
 LEA  will thus  be an  integral part of  nearly all  combustion modification  NO  controls,  both current
 and  emerging.
 3.1.2.2 Off-Stoichiometric  Combustion
        Off-stoichiometric combustion  (OSC) is a  NOX  control technique in  which  the mixing of fuel
 with the combustion  air is altered  so that substoichiometric  conditions  prevail  locally in the
 primary combustion zone.   Complete  combustion occurs downstream of the primary  zone.   OSC is effec-
 tive for retrofit  implementation on large boilers  having multiple  burners arranged in  rectangular
 matrices mounted either on one boiler wall (front-fired) or on opposite walls (horizontally
 opposed-fired).  This method can also be used on corner-fired boilers (tangentially fired), however
 in the  case  of  OSC with burners out of service these boilers  require that all four burners on any
 level  be "taken out"  simultaneously.  Front-wall and horizontally  opposed firing types are more
 flexible in  the location  and number of burners that can be set on  air only.   For new units, OSC is
 an attractive control technique to be included in the design of both single and multiple burner
 units of all design types.
       Off-stoichiometric combustion appears to be  an effective technique for control  of both
 thermal and fuel NOX due to its ability to control  the mixing of the fuel with the combustion air.
 The  resulting fuel-rich regions in the primary flame zone are cooled by flame radiation heat trans-
 fer  prior to completion of combustion with the remaining combustion air.   Thus,  although the overall
 air/fuel mixture is near-stoichiometric,  the primary N0x-forming region of the flame is operated at
 a substoichiometric,  low  NOX condition.  The NOX control effectiveness with OSC depends on burner or
 primary stage stoichiometry which  in turn  is limited by convective  section fouling, unburned
 hydrocarbon emissions or poor ignition characteristics which occur at excessively rich  operation.
An additional limitation of fireside corrosion may  arise with the firing of  some coals  and  heavy
oils.
        In off-stoichiometric firing, the flame is long,  yellow,  and smokey,  as opposed  to the  short
 and  intense flame observed on normal firing.   Fuel  combustion also  extends further into the  furnace,
                                                3-19

-------
sometimes causing excessive superheater (convective section) temperatures.   On some units, increased
operator vigilance is required to surmount decreased effectiveness of the flame detector system.
       In practice, OSC consists of operating some burners (usually the ones located in the lower
part of the pattern) fuel-rich while the burners in the upper part of the pattern operate on pure
air.  Off-stoichiometric combustion is a generic term and several modes of operation are asso-
ciated with it.
       "Two-stage" combustion is based on the same principles as off-stoichiometric combustion
except that the fuel-rich burner operation is achieved by diverting a portion of the toLu. required
air through separate ports located above the burner pattern.  This is also known as "overfire air/
NO  port" operation and is the method used for several new multiburner designs and for use on single
burner units such as industrial boilers.  Figure 3-6 shows the overfire air system on a corner
windbox of a tangentially fired boiler.  So-called "simulated overfire air" operation results when
the top row of burners operate on pure air.  In certain boilers, NO  reduction optimization requires
                                                                   A
that the burners operate either fuel- or air-rich in a staggered configuration.  This is sometimes
called "biased" firing or, in the extreme where some burners are operated on air only, "burners
out of service" (BOOS).
       The two-stage combustion technique is shown in Figure 3-7.  A vertical cross section of a
utility boiler burner is shown schematically.  Two-stage combustion of natural gas (methane) is
depicted, and a few of the global reaction mechanisms associated with the primary and secondary
combustion zones are identified.
       The effect of two-stage combustion on NO  emissions from three tangential coal-fired utility
boilers is shown in Figures 3-8, 3-9 and 3-10 (Reference 3-31).  In these tests, NOX diminished
steadily while first stage air (burner combustion air) was decreased and routed to the overfire air
ports.  Ninety percent of stoichiometric air supplied to the first stage resulted in a 58 percent
NO  reduction (Figure 3-8).  This reduction was obtained with overfire air ports tilted approxi-
mately 40 degrees away from the burners (Figure 3-9).  NO  emissions were reduced approximately 40
percent when two-stage combustion with burners out of service was applied on the same boilers
(Figure 3-10).
       On existing large boilers, a load reduction will  result with BOOS firing if the active fuel  burners
or pulverizers do not have the capacity to carry the fuel  required for full  load.   Most utility boilers
constructed after 1971 are, or have been, designed with overfire air ports  so that all fuel  burners
are active during off-stoichiometric operation.
                                                3-20

-------
        WINDBOX
      SECONDARY
     AIR DAMPERS
 SECONDARY AIR
DAMPER DRIVE UNIT
                                                       OVER-FIRE AIR
                                                          NOZZLES
SIDE IGNITOR
  NOZZLE


SECONDARY
AIR NOZZLES
                                                         COAL NOZZLES
                                                        OIL GUN
  Figure 3-6. Corner windbox showing over- fire air system (Reference 3-31
                                  3-21

-------
SECONDARY OXIDIZING
            ZONE -N

       CO + 0
                •C02 \

                -C02   |
   {    C  + 0
   \
    \                 /
     \--	--./
                    + 4H20

,'   CH4 + 202—>-C02 + 2H20

1    CH4 + 02—>»C   + 2H20

\     C + 02—>-CO  +0
\  02—M) + 0

 ^   N  + 02 -^-NO  + 0

  \   No + 0 	>-NO  + N
  \   L


  ^ PRIMARY REDUCING ZONE
                                                      (    NOZZLE
                           FURNACE
                             WALL
                                               AIR REGISTER
            Figure 3-7. Two-stage combustion (Reference 3-30).
                                 3-22

-------
       O ALABAMA POWER CO.
         BARRY #2
         3/4 LOAD
       D WISCONSIN POWER & LIGHT CO
         COLUMBIA #1
         FULL LOAD
       A UTAH POWER & LIGHT CO
         HUNTINGTON#2
         FULL LOAD
 100
                90          100          110           120
                 THEORETICAL AIR-TO FUEL FIRING ZONE, percent

  Figure 3-8.  NOX vs. theoretical air, overfire air study (Reference 3-31).
320


300

280

260


240


220


200


180


160

140
 120
        NSPS
   60
                     A
                     D
                              O ALABAMA POWER CO.
                                BARRY #2
                              D WISCONSIN POWER &
                                LIGHT CO.
                                COLUMBIA #1
                              A UTAH POWER & LIGHT CO.
                           A    HUNTINGTON#2
    40        20         0        20         40
       TOWARD                          AWAY
OFA REGISTER AND FUEL NOZZLE TILT DIFFERENTIAL, degrees
Figure 3-9.  NOX vs. tilt differential, overfire, air study (Reference 3-31).
                                3-23

-------
        O ALABAMA POWER CO.
          BARRY #2
        D WISCONSIN POWER & LIGHT CO
          COLUMBIA #1
        A UTAH POWER SLIGHT CO.
           HUNTINGTON#2
          95      100     105      110      115     120
               THEORETICAL AIR-TO-FUEL FIRING ZONE, percent

Figure 3-10. NOX vs. theoretical air, biased firing study, maximum load
(Reference 3-31).
                                3-24

-------
       With OSC, excess air cannot be generally maintained as low as with normal  firing.   This  is
because OSC does not achieve the intimate mixing of fuel  and air that is required for  low excess
air operation.
       In early work with OSC, fairly significant results had been obtained for gas-fired utility
boilers by Southern California Edison Company and Pacific Gas and Electric Company,  and from coal-
fired subscale combustion in tests performed by the U.S.  Bureau of Mines in 1966. This modifica-
tion technique has been more thoroughly investigated during the last several  years,  and subsequent
sections of the present document review the recent developments for specific equipment and fuel
types.
3.1.2.3  Flue Gas Recirculation
       A portion of the flue gas recycled back to the primary combustion zone reduces  thermal NO
formation by acting as a thermal ballast to dilute the reactants.  This reduces both the peak flame
temperature and the partial pressure of available oxygen at the burner inlet.
       Some large steam boilers are designed for recirculation of.a portion of the flue gases in
order to control superheat temperatures.  Normally, as boiler load decreases, steam temperatures
tend to drop unless some method of control is employed.  By recirculating an increasing portion
of the flue gas as the boiler load decreases, it is possible to maintain steam temperature at a
constant level over a wider load range.  .Where this type of control is used, the flue gases are
injected through the hopper bottom to reduce the effectiveness of the furnace heat absorption sur-
face without interfering with the combustion process.
       It has been concluded that recirculation for steam temperature control is relatively ineffec-
tive  in suppressing NO .  The flue gas must enter directly  into the combustion zone if it is to be
effective in lowering the flame temperature and reducing NOX formation.
       A typical performance of flue gas recirculation (FGR) is shown in Figure  3-11.   These results
were  obtained on three similar 320 MW tangential, gas-fired utility boilers at full  load.  The data
show  a substantial reduction in NO up to 20 percent recirculation and diminishing returns thereafter.
Similar results were obtained at reduced load operation  (Reference 3-32).
       Operational problems are sometimes associated with large rates of FGR.  Possible flame
instability, loss of heat exchanger efficiency, and, for packaged boilers, condensation on internal
heat  transfer surfaces,  limit the utility of FGR on some units.
                                                3-25

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                                                   DATA FROM DIFFERENT
                                                   UN ITS OF SAME TYPE
50
              Figure 3-11
       20              30
   RECIRCULATIONr wRG/Wf + wa, percent
   WHERE>  = MASSFLOWRATE
         RG= RECIRCULATEDGAS
         f   = FUEL
         a   = AIR

Effect of FGR on NO emissions (Reference 3-32),
                                        3-26

-------
       Although it has been concluded that FGR reduces thermal  NOX, recent experience has cast
doubts on its capability to reduce fuel  NOX.   This method will, therefore, probably be restricted
to low-nitrogen fuels, such as natural  gas,  distillate oil,  and low nitrogen residual oils.

       Flue gas recirculation requires  greater capital investment than LEA and OSC methods because
of the need for high temperature fans and ducts and large space requirements for the modifications.
However, for those boilers originally designed with FGR (for superheat control), costs of retro-
fitting are reasonable (Reference 3-30).

       With moderate rates of recirculation ( 20 percent), FGR can generally be implemented without
significantly increasing emissions of CO or HC.  At high rates of recirculation (30 percent), how-
ever, flame instabilities accompanied by increased CO and HC emissions can result.  There is a
slight decrease in unit efficiency with FGR due to the recirculation power requirements.

3.1.2.4  Reduced Air Preheat Operation

       Reducing the amount of combustion air preheat lowers the primary combustion zone peak tempera-
ture, generally lowering thermal NO production as a result.   It has been used only sparingly because
of the energy penalty.  It is applicable to utility steam generators and large industrial boilers
which employ heaters to impart about 280K (500F) incremental heat to combustion air.  Figure
3-12 shows the NO reduction effect of reduced air preheat temperatures on 320 MW corner-fired
boiler burning natural gas.  NO emissions were reduced 15 percent at full load with a 45K (80F) re-
duction in combustion air temperature (Reference 3-32).

       With present boiler designs, reducing air preheat would cause significant reductions in
thermal efficiency and fuel penalties of up to 14 percent.  This technique would be feasible for
thermal NO  control if means other than air preheat were developed to recover heat from 423K to
          A
698K (300F to 800F) gases.  Reduced air preheat appears relatively ineffective in suppressing fuel
nitrogen conversion (References 3-30, 3-33).

       This technique is also applicable to turbocharged internal combustion engines and regenera-
tive gas turbines.  The turbocharged 1C engines have normally an intercooler to increase inlet
manifold air density permitting higher  mean flowrates, and consequently higher power output.  The
reduced air temperature also reduces NO  emissions.

       Regenerative gas turbines recover some of the thermal energy in the exhaust gas (tempera-
tures ranging from 700K (800F) to 867K (110F)) to preheat the combustion air.  Any reduction in
air preheat causes severe fuel penalties unless other means of recovering the heat in the exhaust
can be implemented.
                                                3-27

-------
400
                        AIR TEMPERATURE, °K

                      450               550
650
                        AIR TEMPERATURE, °F

Figure 3-12.  Reduced air preheat with natural gas, 320 MW corner-
fired unit (Reference 3-32}.
                             3-28

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3.1.2.5  Load Reduction
       The term "load" is defined as the percentage of the rated capacity at which the furnace  or
boiler is being operated.  Increasing boiler load causes an increase in primary combustion  zone
volumetric heat release rate which generally increases the temperature and rate of thermal  NOX
formation.  Reducing boiler load, or derating,  is accomplished by reducing the reactant flow
rate (fuel and oxidizer) into the furnace.   Both the heat release rate (also known as combustion
intensity) and peak flame temperature are lowered.
       Apart from the obvious drawback of limiting boiler capacity, load reduction can lead to
operational problems.  Higher levels of excess  air are typically required to suppress CO or smoke
emissions thus leading to an overall reduction  in efficiency.   The increased residence time of  the
combustion gases at the reduced load can cause  steam temperature imbalance in the convective sec-
tion.  Higher excess air or flue gas recirculation may be needed to maintain superheat temperatures.
Also, operation at greatly reduced load may exceed the practical turndown limit of the burners.
Some burners may need to be taken out of service to maintain good firebox mixing and steam tempera-
ture control.
       Most of the above problems can be avoided when the unit is designed to operate at low com-
bustion intensity.  Here, the use of enlarged fireboxes on new units produces NOX reductions simi-
lar to load reduction on existing units.  Some of the last gas- and oil-fired utility boilers sold
were equipped with enlarged fireboxes.  New coal-fired utility boilers use fireboxes typically 30
percent larger than was  the practice in the 1960's (Reference 3-34).  This practice is partly in
response  to the New Source Performance Standards set  in 1971 and partly to facilitate combustion
of lower  grade western coals.  With coal-firing, the NOX reduction due to an enlarged firebox is
largely indirect through the change in firebox aerodynamics.
       As mentioned  in Section 3.1.2.2 the retrofit of off-stoichiometric combustion to achieve
significant NO  reductions often  requires derating of the boiler.  Derating becomes necessary when
the desired first stage  burner stoichiometry cannot be obtained with the number of burners out of
service  (BOOS) at full load conditions.  The reduced  load, thus, permits additional burners
out of service and consequently  lowers first stage stoichiometries.  Load reduction is therefore
also effective in reducing fuel  NO  when this technique is implemented with staged combustion.
                                                3-29

-------
3.1.2.6  Steam and Water Injection
       Flame temperature,  as discussed above,  is  one of the important parameters  affecting  the
production of thermal  NO .   There are a number of possible ways  to  decrease  flame temperature via
thermal means.  For instance, steam or water injection, in quantities sufficient  to  lower flame
temperature to the required extent, may offer  a control solution.   Water injection has  been found
to be very effective in suppressing NO  emissions from internal  combustion engines and  gas  turbines.
Figure 3-13 shows NOX  emission reductions from a  gas turbine as  high as 80 percent (Reference 3-35).
       Since steam and water injection reduce  NO  by acting as a thermal ballast, it is important
that the ballast reach the primary flame zone.  Combustion equipment manufacturers vary in  their
methods of water or steam introduction.  The ballast may be injected into the fuel,  combustion air,
or directly into the combustion chamber.
       Water injection may be preferred over steam in many cases,  due not only to its availability
and lower cost, but also to its potentially greater thermal effect.  In gas- or coal-fired  boilers,
equipped for standby oil firing with steam atomization, the atomizer offers  a simple means  for  in-
jection.  Other installations will require special rigging so that a developmental program  may  be
necessary to determine the degree of atomization and mixing with the flame required, the optimum
point of injection and the quantities of water or steam necessary to achieve the desired effect.
       The use of water injection may entail some undesirable operating conditions,  such as de-
creased thermal efficiency due to the high heat capacity of water compared with that of flue gas
or other inert diluents, and increased equipment corrosion.  This technique  has the greatest
operating costs of all combustion modification schemes with a fuel  and efficiency penalty typically
of about 10 percent for utility boilers and about 1 percent for  gas turbines.  It is, therefore,
an unpopular NO  reduction technique for all combustion equipment except for stationary gas tur-
bines  (References 3-30 and 3-33) which, in addition to the lowest reduction  in efficiency,  showed
no major operational problems or reduced equipment life.  Water  injection for NO  reduction does
not appear to have a significant effect on  stack opacity and emissions of CO and HC.

3.1.2.7  Ammonia Injection
       The post-flame decomposition of NO by reducing agents has recently shown promise as  a
method for augmenting combustion modifications if stringent emission limits  are to be met.   Exxon
has patented a process for the homogeneous gas phase selective decomposition of NO by ammonia
(Reference 3-36).  The gas phase reaction in the temperature range of 978K (1,300F) to 1,368K
                                               3-30

-------
                 0.4           0.8            1.2            1.6
                     WATER INJECTED TO COMBUSTION AIR, percent
                                                                        2.0
Figure 3-13.  Correlation of NOX emissions with water injection rate for natural
gas fired gas turbine (Houston L&P Wharton No. 43 unit) (Reference 3-35).
                                     3-31

-------
  (2.000F)  converts  nitric oxide,  in  the presence of oxygen and ammonia,  into nitrogen and water
  (Reference  3-37).
        Results of  lab scale tests show that the level of NOX reduction depends on the combustion
  product temperature, initial NOX concentration, and quantity of ammonia injected (Reference 3-38).
  Based on  the available results, ammonia injection appears to be most effective between 978K
  (1.300F)  and 1.368K (2.000F), which corresponds to conditions in the convective section of large
  boilers.  Maximum NO reductions, as much as 90 percent,  were obtained at 1.233K (1.750F)  with
 molar ratios of ammonia to initial  nitric oxide ranging from 1.0 to 1.5.
        Field tests were conducted on a gas-fired furnace rated at 147 MW (500 x 106  Btu/hr) and on an
  oil-fired boiler rated at 41 MW (140 x 106 Btu/hr) with both the units retrofitted for NH, injection
                                                                                          O
  (Reference 3-37).  A reduction in NOX of nearly 70 percent was obtained with a NH3/initial  NOX ratio
 of 4.5.   Table 3-5 summarizes the available test results to date.
        Although ammonia  injection is a promising technique,  there  are a number of developmental
 questions  which must be  answered before its full  potential  can  be  assessed.   The  first  is  the
 applicability of ammonia  injection  to existing utility boilers and  to systems  other  than  steam
 generators.   Ammonia injection  appears to  have potential  for new utility boilers  and large  indus-
 trial  boilers since the  required temperature range is  compatible with current  convective  section
 design.  New units  could conceivably  be*designed to include  ammonia  injection  cavities  in the
 convective sections.  Applications to  existing units may  be  limited  by  the absence of the precise
 residence  time-temperature conditions  required for the process.  Additionally,  ammonia  injection
 seems  to be  limited  for other equipment types  such as  gas turbines and  1C engines because the  re-
 quired time-temperature constraint cannot  practically  be met.
       The second question concerns the ability to maintain  adequate convective section temperatures
 required for  selective reduction during boiler load changes.  Normally, during  load  reduction, the
 convective section temperature will  reduce substantially below the base load level.  The tempera-
 ture excursions during load reduction could easily move out of the range where ammonia injection is
 effective.   Load following capability may thus be a limitation on ammonia injection for nonbase-
 loaded units.
       The  third question concerns the effectiveness and  environmental impact of the process, par-
 ticularly with coal  firing.   The process has been demonstrated on oil- and  gas-fired  units but is
just starting to be studied  in coal-fired pilot scale  units.   Environmental  concerns  with  ammonia
 injection include the presence of ammonia as a  primary pollutant  in the stack gas  and potential
                                                3-32

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 reactions of ammonia with the fly ash  and  sulfur compounds  in  coal  firing.   Since low temperature
 stack gas reactions  are important here,  pilot  scale  tests will  be of limited use.'  Full  quantifica-
 tion of potential  adverse impacts of ammonia  injection  will  await full  scale demonstrations  with
 coal firing.
        In addition to the above  operational concern,  there  is  also  the  strategic  question  of whether
 sufficient ammonia would  be  available  in the 1980's  and 1990's  for  widespread application  in utility
 boilers (Reference 3-39).
        In  summary, ammonia injection has near-term application  for  NO   control  in gas- and oil-fired
 boilers;  also,  it  shows promise  for far-term applications to coal-fired boilers.
 3.1.2.8  Combinations  of  Techniques
        Since  1969, it  has  been demonstrated that  several of the previously discussed modification
 techniques  can  be  effectively utilized in combination since they  reduce NO   by  different mechanisms.
 Most often, off stoichiometric combustion is used with  low excess air, or  load reduction on  all
 fuel-boiler type configurations.   For oil and gas fired units flue  gas recirculation is used  in
 conjunction with the above techniques.   Flue gas recirculation and  load reduction lower peak
 combustion  temperatures, while off-stoichiometric operation reduces the amount  of fuel burned at
 peak temperature.  For the most part, combining control techniques  has been  shown to be comple-
 mentary but not additive for NOX  reduction (Reference 3-30).

 3.1.3   Equipment Design Modification

 3.1.3.1  Burner Configuration
       Burner or combustor modification for NOX control  is applicable to all  stationary combustion
 equipment categories.  The specific design  and configuration of a burner has  an important bearing
 on the amount of N0x formed.   Certain design types have been found to give greater emissions than
 others.  For example, the spud-type gas burner appears to give a higher emission rate than the
 radial spud type, which, in turn, produces  more NO  than the ring type.
       During the early 1970's specially designed "low-NOx"  burners were produced for thermal NO
control.  For the most part,  they are designed for utility and industrial  boilers and employ in-
flame LEA, OSC, or FGR principles.  The aim is  to strike a balance between minimum NO  formation
and acceptable combustion of  carbon and hydrogen in the fuel.
       There are currently several commercial  low-NO   gas and oil  burner designs in  operation and
development (References 3-40  through 3-44).   Full  scale  test results in  Japan show reduction  in
x
                                               3-34

-------
No  emissions from 40 to 60 percent with low-NO  gas burners.  Sub-scale tests with single burners of
the type normally used in utility boilers have indicated that simple changes in burner block and
nozzle geometry and in swirl vane angles can decrease NO  production by up to 55 percent  (References
3-41 and 3-45).  Some of the more innovative methods for oil burners include:  flame splitting
distributor tips which cause a flower petal flame arrangement, and atomizers with fuel injection
holes of different diameters which create fuel-rich and fuel-lean combustion zones (References 3-15,
3-40, 3-43).  Up to 55 percent reductions in NO  emissions are reported with the use of these nozzle
tips.  However, the change in flame shape may cause problems due to impingement on walls  and effectiveness
may be reduced as flames interact in multiburner furnaces.
       Other air-fuel modifications include a low-NO  burner (offered by at least one company in
the U.S.) for oil- and gas-fired package boilers.  This burner uses shaped fuel  injection ports
and controlled air-fuel  mixing to create a thin stubby ring-shaped flame (References 3-40, 3-42).
With this modification,  reductions in NOX from 20 to 50 percent are claimed.   The most extensive
air-fuel  modifications involve the self-recirculating and staged combustion chamber type of
burners,  used in industrial  process furnaces.   These burners are equipped with a prevaporization
or a precombustion chamber in the windbox.   In the chamber, the fuel is vaporized and premixed with
part of the combustion air,  or is allowed to undergo partial combustion under oxygen deficient
conditions before being  discharged into the furnace.  NO  reductions of about 55 percent are
typical  for these devices.
       Similar reductions are being demonstrated on prototype coal-fired units.   One major utility
boiler manufacturer has  recently fabricated and tested a dual register pulverized coal  burner,  de-
signed to produce a limited  turbulence,  controlled diffusion flame.   The manufacturer claims  NO
reductions of 50 percent (Reference 3-46).   Figure 3-14 shows field  test results  on  three  existing
boilers  equipped with the new low-NO  burners  (Reference 3-47).   Emissions  were  55 percent less NO
                                    *                                                             x
than identical  units  operating under similar conditions with old circular burners  (Reference  3-26).
       The new low-NOx burners are designed to attain controlled mixing of  fuel and  air  in a  pattern
that keeps the flame  temperature down and dissipates the heat quickly.   Burners can  be designed to
control  flame shape for  minimizing the reaction at peak temperature  between nitrogen  and oxygen.
Other designs internally recirculate part of the  combustion  gases or have fuel-rich and fuel-lean
regions  within a burner  to reduce flame  temperature  and oxygen availability.
                                                3-35

-------
    1.0


    0.9


    0.8


    0.7
"3 0.6
00
CO

5 0.5
 CM
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 X
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2 0.3
   0.2


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    0
CIRCULAR BURNER
DUAL REGISTER BURNER
                   90
                                             250

                                      UNIT CAPACITY, MW
                                                EPA NOX

                                            EMISSION LIMIT-
                                                             400
                                                                                       300
                                                             200 o
                                                                 X
                                                                o
                                                                                       100
                                             700
Figure 3-14. Comparison of NOX emissions with pulverized coal firing, circular burner vs  dual
register burner (Reference 3-47).
                                            3-36

-------
        Burner  design modifications  have the major advantages of not requiring redesign of boilers
 or combustion  chambers, not  necessitating  load reduction, and possible applicability to many types
 of boilers.  The disadvantages are  that some burners may have to be custom designed for specific
 fuels  and  that some burner designs  optimized for low-NO  may only be applicable to a limited number
 of boiler  configurations.  However, improved burner design may in the early 1980's be used in con-
 junction with  some already proven external combustion modification such as OSC.  This combination
 of low-NOx burners and OSC may lead to significantly lower N0x emissions.  It is also possible that
 with more  advanced burner designs currently under development, the external combustion modifica-
 tions  might be entirely replaced with the  low-NOx burners (References 3-33, 3-48).
 3.1.3.2  Burner Spacing
       The interaction between closely spaced burners, especially in the center of a multiple-
 burner installation, increases flame temperature at these locations.  There is a tendency toward
 greater NOX emissions with tighter  spacing and a decreased ability to radiate to cooling surfaces.
 This effect is  illustrated by the higher N0x emissions from larger boilers with greater multiples
 of  burners and  tigher spacing.  During a field test program conducted by KVB Inc.  two 215 MW units
 were tested for NOX reduction by combustion modification.  These two units are identical  in design
 except for burner spacing.  At reduced load operation the closeness of burner spacing for one of
 the units  resulted in higher NOX levels by as much as 25 percent (Reference 3-32).
       In most  new utility boiler designs, vertical  and horizontal  burner spacing  has been widened
 to  provide more cooling of the burner zone area.   In addition,  the furnace enclosures are built to
 allow  sufficient time for complete fuel  combustion from slower  and more  controlled  heat release
 rates, such as that associated with the off-stoichiometric  operating mode.   Furthermore,  furnace
 plan areas have been increased to allow for larger heat transfer to the  cooling  walls.   This  in-
 crease in the burner zone dimensions creates  more wall  area  thus  increasing the  distance  between
 evenly spaced burners.
       Horizontal  burner spacing is largest for tangentially fired  boilers  with  the  burners
 being located at each corner of the furnace.   Flames in a corner-fired unit interact  only  at  the
center of the furnace in the well  known  spiral  configuration.  As  a  result  the flames  radiate
widely to the surrounding  cooling surfaces before interacting with  one another.  Also,  the tangen-
 tial firing configuration  results in slow  mixing  of  fuel  with the  combustion air.  For  these
reasons, tangentially-fired  boilers  show baseline, uncontrolled  emissions  below  those  for  other
utility boilers firing  configurations.   It has  been  observed, however, that for  many  tangentially-
                                                3-37

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 fired  boilers, the NOX response to operating modifications has been less impressive than from
 boilers of other designs, even though the magnitude of the initial, uncontrolled emission level
 was  lower (References 3-27, 3-30).
 3.1.4  Fuel Modification

       Another alternative for controlling NOX through process alteration is through modification
 of the fuel.  Three candidate techniques are fuel switching, fuel additives, and fuel denitrification.
 3.1.4.1  Fuel Switching
       This method usually entails the conversion of the combustion system to the use of a fuel
 with a reduced nitrogen content (to suppress fuel NOX) or to one that burns at a lower temperature
 (to reduce thermal NOX).  Sulfur control is usually a dominant cost incentive for fuel switching.
 Natural gas firing is an attractive NO  control strategy because of the absence of fuel NO  in
                                      x                                                   x
 addition to the flexibility it provides for the implementation of combustion modification tech-
 niques.  Despite the superior cost-effectiveness of gas-fired NOX control, the economic considera-
 tions  in fuel selection are dominated by the current clean fuel shortage.  Indeed, the trend is
 toward the use of coal for electric power generation and larger industrial processes.  Fuel
 switching to natural  gas or distillate oil is not a promising option for widespread implementation
 (Reference 3-49).
       Western coals  constitute one abundant alternate source of potentially low-NOx fuels.   The
 direct combustion of western subbituminous coals in large steam generators generally produces lower
 NOX emissions than with combustion of eastern bituminous coals.  Three mechanisms are responsible
 for lower NOX emissions:  first, western coals in general contain less bound nitrogen than eastern
 coals on a unit heating value basis; second, the excess 02 in a steam generator burning western
 coal  can be maintained at very low levels; and third, the high moisture content of western coal
 produces lower flame  temperatures.
       The NO  emissions for a 59Mg (130,000 Ib) steam/hr industrial boiler firing pulverized western
 coal  at baseline conditions were 24 percent lower than for eastern coals (Reference 3-29);  NO,
emissions remained unchanged when firing western coal in stokers.   However,  the slope of the NO
vs.  excess 02 curve for a water-cooled vibrating grate stoker firing western coal  (Wyoming Bighorn)
was 12 ppm/percent excess 02,  compared to 35 ppm/percent excess 02 for eastern coal  (Kentucky
Vogue).
                                                3-38

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        Some specific  problems  associated  with  burning  low  sulfur, high moisture content coals  in
 combustion equipment  designed  for higher  quality  coals are listed below  (Reference  3-50):
        •  Poor ignition
        0  Reduced  boiler  load  capacity
        •  Increased carbon  loss
        •  Boiler fouling
        t  High superheat  steam temperature
        •  Flame instability
        t  Increased boiler  maintenance
        t  Reduced  boiler  efficiency
        •  Reduced  collection efficiency of electrostatic precipitator (ESP)
 However, most  of these operational problems can be solved  with current boilers specifically
 designed to  burn these lower grade coals.
       Formerly, a major incentive for switching to western coals was the low sulfur content of
these fuels.  Economic conditions made fuel  switching from high sulfur eastern bituminous coals to
low sulfur western subbituminous coal competitive with the cost of gas scrubbing for SCU removal.
Therefore, low sulfur, low nitrogen,  western coals represented a promising short-range option in
fuel switching for large industrial and utility boilers.  However, the 1977 Clean Air Act requires
that NSPS be based on a percentage reduction in the pollutant emissions which would have resulted
from the use of fuels which are not subject to treatment prior to combustion.  This deemphasizes
fuel switching.
       A promising long-range option  is the use of clean synthetic fuels derived from coal.   Candi-
date fuels include low to high Btu gas (3.7 to 30 MJ/Nm3, or 100 to 800 Btu/scf) and synthetic
liquids and solids.  Process and economic evaluations of the use of these fuels for power genera-
tion are being performed by, among others, the EPA, DOE, the American Gas Association, and the
Electric Power Research Institute (EPRI).   Two alternatives for utilizing low- and intermediate-Btu
                    O
gases (up to 26 MJ/m , or 700 Btu/scf) are firing in a conventional  boiler or in a combined  gas and
steam turbine power generation cycle.  For both systems, economic considerations favor placement of
both the gasifier and the power cycles at the coal minehead.  The most extensive use of these systems
would probably be for replacement of older conventional units upon their retirement (Reference 3-51).
       The NOX emissions from lower-Btu gas-fired units are expected to be low due to reduced flame
temperatures corresponding to the lower heating value of the fuel.   The effects on NO  formation of
                                                 3-39

-------
the molecular nitrogen and the intermediate fuel nitrogen compounds, such as ammonia,  in the lower-
Btu gas have not yet been fully determined and require further study.
       The synthetic fuel oils or solid solvent refined coal (SRC) may be expedted to be high in
fuel nitrogen content even though some denitrification may occur in the desulfurization process.
This high nitrogen, carried over from the parent coal, would promote high NO  emissions.  Other
potential alternate fuels that might be considered and their potential for fuel or thermal NO
are listed in Table 3-6.
                             TABLE 3-6.  NOX FORMATION POTENTIAL OF
                                         SOME ALTERNATE FUELS
FUEL
Shale oil '
Coal -oil mixture
Methanol
Water-oil emulsion
Hydrogen
THERMAL NOX
Low
Low
Low
Low
High
FUEL NOX
High
Moderate
Low
Unchanged
Low
       Shale oil ranks second to coal as the most abundant source of nonpetroleum fossil fuel in the
United States (Reference 3-52).   Even though there are six proven recovery processes, current shale
oil production is very limited.   The combustion of shale oil  will cause higher levels of fuel NO
because this fuel generally contains bound nitrogen in excess of 2 percent.  Distillation of shale
oil would reduce fuel nitrogen content, however.
       Coal-oil  mixtures have recently become of interest as  an alternate fuel which could stretch
the domestic oil supplies and reduce our dependence on foreign oil.   NO  from combustion of this
fuel will depend on the quantity of nitrogen present in the coal and oil and the percentages of
coal and oil used to make the mixture.  However,  NO  emissions are expected to be lower than
emissions obtained from combustion of coal only.
       Methanol  is currently produced from the synthesis of methane from natural gas.  However, due
to the shortage of natural  gas,  future production will have to come from synthetic gas generated
from coal and biomass.  Baseline NOX emissions from the combustion of methanol in an experimental
                                               3-40

-------
hot wall furnace system were reported at 50 to 70 ppm, compared to 240 to 300 ppm for distillate
oil.  With flue gas recirculation, the NOX emissions from methanol combustion were reduced to 10
ppm or 15 percent of the baseline level (Reference 3-53).
       In gas turbines 74 percent less NOX was produced using methanol, compared to distillate oil.
The hot wall experimental furnace showed a 20 percent increase in stack heat loss (SHL), compared
to SHL of 14 percent for distillate oil (based on 115 percent theoretical air at a 473K (390F) stack
temperature).  For natural gas, turbine efficiency levels increased by 6 percent due to higher inlet
temperatures.
       Since water-oil emulsions affect only thermal NOX these alternate fuels have a definite NOX
reduction potential when distillate oil is used (Reference 3-54).  NOX emission levels from emul-
sions with approximately 50 mass percent water in distillate oil approached the levels obtained
from methanol combustion  (Reference 3-55).
       Hydrogen as a fuel is used in high energy production concepts such as rocket engines.  The
high levels of thermal energy  released make this fuel attractive for other energy conversion sys-
tems.  Thermal NOX levels are, however, high when hydrogen meets with oxygen in the presence of
atmospheric nitrogen.  Water represents an abundant supply of hydrogen with the use of electrolysis.
       Low  NO  application  of  these fuels may require development of additional control technolo-
             A
gies.  Many of the current  combustion  control strategies may, however, be applicable, especially
for the  case of thermal  NOX<
       The  feasibility of synthetic fuel  firing as a  NOX control  option  is contingent on  the cost
tradeoff between  synthetic  fuel  production and the total control  costs for NOX, SOX, and  particu-
lates  in conventional coal  firing.   In the case of coal  derived  fuels, there  is preliminary
evidence that  gasification  may be more costly than flue  gas cleaning  of  conventional systems.
3.1.4.2   Fuel  Additives
        For  purposes  of  this document,  a fuel  additive is a substance  added to  any  fuel  to inhibit
formation of NOX  when  the fuel is burned.  The additive  can be  liquid, solid,  or  gas.   For liquid
fuels,  the  additive  should  preferably  be  a  liquid soluble  in  all  proportions  in  the  fuel, and  it
should be effective  in  very small concentrations.  The additive  should not in  itself create  an  air
pollution hazard  nor be  otherwise deleterious to  equipment and  surroundings.
        In 1971,  Martin,  et  al_.,  tested 206  fuel  additives  in  an  oil-fired experimental  furnace,
and four additives in  an oil-fired  packaged  boiler.   None  of  the additives tested  reduced NO
                                                 3-41

-------
       In general, NO  control in FBC is a matter of good management of the normal  process
variables.  If more stringent standards are enacted, conventional NO  controls, such as flue gas
recirculation and off-stoichiometric combustion, may be used.   Exploratory results  indicate that
two-stage combustion could be advantageous for;both NOX and SOX control.  The flexibility of the
FBC process is a technical and cost advantage to the implementation of new control  techniques.
       From a NOX control standpoint, fluidized bed combustion appears to be competitive with
control of conventional combustion methods.  At the present time, however, FBC must be viewed as
a medium risk concept.  The economics of the basic process have not yet been fully  established
relative to conventional boilers or low-Btu gas combined cycle units.  Also, the versatility of
the FBC concept to a wide variety of equipment applications needs to be shown.

3.1.5.2  Catalytic Combustion
       Catalytic combustion refers to combustion occurring in  close proximity to a  solid surface
which has a special (catalytic) coating.  A catalyst accelerates the rate of a chemical reaction,
so that substantial rates of burning should be achieved at low temperatures, avoiding the forma-
tion of NOX.   Moreover, the catalyst itself  serves  to sustain the overall combustion process,
thereby minimizing the stability problems (References 3-64 and 3-65).  However, the overall success
of a catalytic combustion system in reducing CO and UHC to low levels is a function of both hetero-
geneous and gas phase reactions; surface reactions alone appear to be unable to achieve the desired
low levels.
       Emissions from catalytic combustion experiments have typically been:  NO  <  2 ppm, UHC - 4 ppm,
and CO = 10 to 30 ppm.  Both gaseous and distillate fuels have been used and combustion efficiencies
above 95 percent have been obtained (Reference 3-65).
       The catalyst bed temperature must be held below 1,81 IK  (2.800F) to minimize  the formation of
NOX.  At high temperatures, above 1.273K (1,830F), catalyst degradation can be significant.  Excess
air can be used to lower the bed temperature; but except for gas turbines excess air is unattractive
since it also reduces thermal efficiency.   Further research is underway to consider other systems,
such as catalyst bed cooling, exhaust gas recirculation and staged combustion to maintain a low bed
temperature.
       Recent tests evaluated the applicability of catalytic combustors for gas turbines.   Test
fuels used were No. 2 distillate oil and low Btu synthetic coal  gas, for a range of pressure,
temperature,  and mass flow conditions.   Test results show that the catalyst bed temperature profile
at the bed exit was very uniform for low Btu gas, but  not as uniform for No.  2 oil.   Exceptionally
                                               3-44

-------
       A 30 MW AFBC pilot plant began operation in late 1976 (Reference 3-61).  Pressurized systems
are still being tested, with a pilot plant planned for the early 1980's.  Results of recent work in
FBC, the status of FBC development, and EPA, ERDA and EPRI FBC programs can be found in Reference
3-61.
       Suggested advantages for fluidized bed combustion compared to conventional boilers are:  (1)
compact size yielding low capital cost, modular Construction, factory assembly and low heat transfer
area,  (2) higher thermal efficiency yielding lower thermal pollution, (3) lower combustion tempera-
ture resulting in less fouling and corrosion and reduced NO  formation, (4) potentially efficient
sulfur oxides control by direct contact of coal with an SC^ acceptor, (5) fuel versatility, (6)
applicable to a wide range of low-grade fuels including char from synthetic fuels processes, and
(7) adaptable to a high efficiency gas-steam turbine combined power generation cycle.  The general
validity of these suggested advantages have yet to be demonstrated in field application.  The
principle disadvantages of FBC are:  (1) potential large amounts of solid waste (the sulfur acceptor
material) and (2) heavy particulate loading in the flue gas.
       The feasibility of the FBC for power generation and utility boilers depends in part on the
following:  (1) development of efficient methods for regeneration and recycling of the dolomite/
limestone materials used for sulfur absorption and removal, (2) obtaining complete combustion
through fly ash recycle or an effective carbon burnup cell, (3) development of a hot-gas particulate
removal process to permit use of the combustion products in a combined-cycle gas turbine without
excessive blade erosion.
       Oxides of nitrogen emissions from fluidized bed combustors have been shown to be predominately
fuel-derived.  Seven to ten percent of fuel nitrogen is converted to NO  (References 3-62 and 3-63).
Experiments with nitrogen-free fuels resulted in NOX concentrations in agreement with equilibrium
values at the bed temperature.  However, coal-fired experiments resulted in NO  concentrations in
excess of the equilibrium values.  Furthermore, experiments using nitrogen-free gases with coal
yield substantially similar NOX levels as combustion in air (Reference 3-62).
       NOX emissions have been found to be slightly dependent on coal  particle size, the type and
amount of sulfur acceptor, the amount of excess air and the design of the combustor  itself.   Emis-
sion levels from pressurized fluidized bed combustors are significantly less than from atmospheric
combustors.   This is probably a result of greatly increased NO  decomposition  rates  at elevated
pressures.   Even at 100 percent excess air, NOX emissions from a  PFBC are well  below the current
standards of 300 ng N02/J (0.7 lb/108  Btu).  Results of 160 ng/J (0.37 lb/106  Btu) have been
reported (Reference 3-61).
                                                3-43

-------
       References 3-67 and 3-68 describe in detail the application of repowering to boiler, gas
turbine, and steam generating plants; savings in capital and operating costs are anticipated.
Repowering of two steam turbine units in the City of Glendale, California increased power output
by 75 MW and reduced power cost to the consumer by 8 percent (Reference 3-69).  Under
contract from the Electric Power Research Institute, Westinghouse Electric Corporation is evaluat-
ing repowering conventional steam power plants without replacing the boiler.  Earlier pilot scale
work for EPRI by KVB Inc. shows a low NO  potential for repowering.  The boiler is fired fuel-rich
using approximately 85% of the NO  bearing gas turbine exhaust as the combustion air.  The remain-
ing gas turbine exhaust provides the boiler second stage air which is injected through overfire
air ports above the fuel-rich primary stage.  Up to 55% of the NO  in the gas turbine exhaust is
chemically reduced by the fuel rich primary stage of the boiler.  Also, the use of overfire air
reduces the NO  formed in the boiler by up to 50%.  The present use of repowering is very limited.
It may see extensive use in the 1980's if significant increases in generating capacity are needed.
3.1.5.4  Combined Cycles
       Combined cycles may, in the long term, reduce emissions of sulfur oxide, nitrogen oxide,
particulate matter, and waste heat while generating power at efficiencies higher than conventional
fossil- and nuclear-fueled steam stations (Reference 3-70).
       The combined gas and steam turbine system consists of a gas turbine using a coal-derived fuel,
which exhausts into an unfired waste-heat-recovery boiler.  At the gas turbine inlet, the most
economical large scale steam system would operate at 16.6 MPa (2,400 psig) with 811K (l.OOOF)
throttle steam and 81 IK reheat temperatures.  In this system, roughly 66 percent of the power
would be generated by the gas turbine; the remaining 34 percent would be generated by the steam
boiler system (Reference 3-71).
       Combined cycle efficiency improves significantly as the gas turbine inlet temperature is
increased.  At turbine inlet temperatures of 1,478K (2.200F), an efficiency improvement of 2 per-
centage points per 55K (100F) increase in turbine inlet temperature is found.
       The current status of combined cycles has been reviewed by Papamarcos (Reference 3-72) who
concludes that, before combined cycles are commercialized, efficient fuel conversion processes and
high temperature gas turbines that can use coal-derived fuels must be developed.  He estimates that
these developments will take place in some 15 to 20 years, and current DOE projections concur with
his estimate.
                                                3-46

-------
low emissions (2 to 3 ppm NO , 20 to 30 ppm CO) were achieved for both fuels, and unburned hydro-
carbons (UHC) were less than 1 ppm (Reference 3-66).  However, much additional work is needed
before catalytic combustion can be applied to gas turbines in the field.
       Catalytic combustion has been demonstrated to be effective in removing pollutants such as
N0x, CO, and UHC, but at present, catalytic combustors are limited by the catalyst bed temperature
capability.  Various government agencies and private industries are developing catalysts that will
withstand high temperatures, retain high catalyst activity, and last longer.  Catalytic combustion
systems are also under development; it appears that during the next 5 to 10 years, catalytic com-
bustion concepts may be incorporated into new gas turbine and residential, commercial, and indus-
trial heating designs.

3.1.5.3  Repowering
       Repowering adds a combustion turbine to an existing steam plant, providing additional capa-
city at lower initial costs and lower energy costs than other spare capacities available to a
utility.
       Repowering includes:  (1) steam turbine repowering, in which gas turbines and new heat re-
covery boilers are added to an existing steam electric generating plant; (2) boiler repowering in
which gas turbines are added to the existing steam generating facilities for power generation, re-
quiring the conversion of existing conventional boilers to heat recovery type boilers; and (3) gas
turbine repowering in which a steam generating plant is added to an existing gas turbine plant
(References 3-67 and 3-68).
       Depending on the system and power needs, repowering of existing facilities offers the
following advantages:
       •  There is no need to acquire  and develop a new plant site
       •  Repowering generally requires smaller increments of investment, saving on fixed charges
          since major investment on new plants is deferred
       •  Repowering improves heat rate, which lowers fuel consumption
       0  The environmental impact is  reduced, with improving schedules for environmental and site
          related approvals
       •  For boiler and steam turbine repowering, there is no increase in cooling water requirements
       0  Gas turbines may be operated independently as peaking units, which provides greater plant
          flexibility
                                                3-45

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       Each process developer utilizes different  catalysts,  catalyst  supports  and  bed  configura-
tions.  Also, differing applications require substantially different  catalysts^and operating  condi-
tions depending upon the S02 content and dust loading of the specific flue gas.  The  inlet  NOX
concentrations being treated in Japan range from  150 ppm to  250 ppm with NOX exit  concentrations
of 10 ppm to 50 ppm (Reference 3-74).
       Compared to the wet process, the dry process is simple,  requires less space, generates no
troublesome byproducts and requires no tail gas reheating.  However,  the dry process  has yet  to
prove itself on a dirty gas stream of commercial  scale.  If  the sulfur and particulate laden  flue
gas is scrubbed to remove S02 before FGT, it will have to be reheated from about 31 IK to 643K
(100F to 700F) (Reference 3-74).  If the S02 is not removed  from the  flue gas excess  ammonia  may
combine with S03/S02 and cause a visible plume.  This byproduct is also corrosive  to mild steel.
Large amounts of ammonia may be required which will cause an increased consumption of natural gas
currently used to produce the ammonia.  Ammonia requirements are proportional to the quantity of
NO  removed.  Thus, combustion modifications are  likely to be used to reduce NO  levels as  much as
  x                                                                            *
possible before treatment in FGT systems.
       A selective noble metal catalyst process using ammonia was recently explored on a pilot scale
by an EPA contractor.  The pilot plant, using natural gas, accumulated about 2000 hours of testing
and achieved NO  reductions of 90 percent with essentially no catalyst degradation.  Further tests
have  been conducted using fuel oil and/or sulfur-containing flue gases.  These tests indicate that
platinum is  not satisfactory for flue gases containing S02 (Reference 3-74).
       Another study for EPA has been conducted for the technical and economic assessment of various
catalytic processes for NO  control  (Reference 3-75).  Lab scale tests on simulated flue gas inves-
tigated several operating variables  and catalysts.  The major emphasis was on selective reduction
of NOX with  ammonia using nonnoble  metal catalyst  systems.   These parametric studies showed NO
reductions of 60 to 85 percent at  inlet concentrations of 250 to 1000 ppm.
       Although selective catalytic  reduction has  been the most widely used dry process, selective
noncatalytic NO  reduction  is under  investigation  in  both the U.S. and Japan.  The technique in-
volves the homogeneous decomposition of N0x  by injecting  a gaseous reducing agent  into  the post-
flame region.  Ammonia  is the most  common  reducing agent, although the two U.S. research firms in-
vestigating  this concept have considered    proprietary agents as well.   Injected  ammonia is most
effective  for NO   reduction when the combustion  products  are between 1.200K and 1.311K  (1,700F and
1.900F).   The concept  has been demonstrated  commercially  on a 41 MW  (140  x  l^Btu/hr) oil-fired
                                                 3-48

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  3.2    COMBUSTION FLUE GAS TREATMENT




         Combustion modification is a demonstrated and'effective method for achieving reduction of


  NOX from stationary sources.   It is, however,  somewhat limited both  in emission  reduction  efficiency


  and range of applicability,  particularly for coal-fired sources.   Removing the NOX  directly  from


  the flue gas  can  be used  in  addition to  combustion modification when  high  removal efficiencies

  are required.



         Flue  gas treatment (FGT)  processes  reduce  NOX emissions from combustion sources either by


  decomposing  N0x to  nitrogen and  water or oxygen,  or  by  removing NOX from the gas stream.   Work on


  these  systems  in  the United States  is being funded by EPA, but the major work is being conducted


  in  Japan (References 3-40 and  3-73).  At present, FGT  is commercially available  only  for oil  and


  natural  gas  firing.  For  S02 and particulate laden gas  streams, FGT for NO removal is still  in  the
                                                                            A
  developmental  stage.



        For convenience of discussion, the two FGT process routes can be categorized as dry pro-


 cesses (reduction) and wet processes (oxidation followed by scrubbing).  Dry systems are operated


 at about 644K (700F) and generally employ flue  gas additives and catalysts.  Wet  systems employ a


 wider variety of chemicals and  are operated at  313K to  323K (100F  to 120F), the same temperatures


 scrubbers use to remove SO,,.   These processes are described separately below.



 3.2.1  Dry Flue Gas Treatment




        Dry processes are  the  most fully  developed.  They are mainly applicable  to flue gas


 streams free  of S02  and  particulates; that  is,  gases  from the  burning  of gaseous  fuels or distil-


 late oils.  Large  dry FGT  systems have been in  operation since 1974  in Japan.  Some  systems applied


 to S02  and  particulate  laden gas  streams  have been piloted  successfully and several  prototype  plants


 are  now being  constructed  to treat gases from residual oil and  coal-fired boilers (References  3-40

 and  3-48).



        Although there are  many theoretical dry process variations (e.g. , nonselective  reduction,


 selective reduction using  NHg. and molecular sieves),  only selective catalytic reduction using


ammonia has achieved notable success  in treating combustion flue gases for  removal of NOX-   The


presence of oxygen in concentrations many times  greater than N0x in the flue gas precludes  consider-


ation of nonselective reduction.  However, selective reduction of NOX using ammonia  is readily


accomplished using any of a number of catalysts.
                                               3-47

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absorber may be so great as to preclude the use of liquid phase oxidation  processes  on  combustion
flue gases where large volumes of gas and low NO  concentrations are involved.
       The use of ozone or chlorine dioxide to oxidize NO in the gas stream prior to the  scrubber
appears to be the more successful approach.  Although the required scrubber is  still quite large,
substantial removal of NOX can be obtained in a scrubber designed for S02  removal.   Unfortunately,
chlorine dioxide is expensive and its use introduces the problem of disposing of chloride-
containing liquid discharges.  In addition, the production of ozone requires expensive  equipment
and a great deal of electrical energy.  For coal-fired flue gas with its higher NOX  concentrations,
the oxidant cost is very likely to be prohibitive.  Also, where ozone is utilized, additional
equipment may be required for removal of excess ozone from the final gas stream.
       Although wet NOX FGT systems may not see widespread use in this country, two  deserve addi-
tional mention because thej are relatively simple extensions of well established flue gas desulfuri-
zation (FGD) technology.  The Chiyoda 101 F6D process has been modified by the  inclusion  of an
ozone generator for NO oxidation.  The absorbed NO  is removed from the system  as a  dilute calcium
nitrate solution requiring disposal.  The process has been designated Chiyoda Thoroughbred 102.
This
yet.
This simultaneous SO /NO  process has been piloted in Japan but has not seen commercial  service as
       Mitsubishi Heavy Industries (MHI) also is developing a wet NO  FGT process which is a fairly
                                                                    A
simple extension of their limestone FGD process.  In this case, two additional pieces of equipment
are required:  one for ozone generation and injection into the flue gas, and one for treatment of
the tail gas to remove unreacted ozone prior to release to the atmosphere.  The MHI process differs
from most other wet FGT processes in that the captured nitrogen oxides are reduced to elemental
nitrogen by reaction with calcium sulfate in the circulating scrubber liquor.  A proprietary
catalyst present in the scrubber liquor promotes this reaction.  This simultaneous SO /NO  process
is presently in the pilot plant state in Japan.
       Both the Chiyoda and MHI processes are attractive from the standpoint of having simultaneous
SO /NO  control capability and from the developmental standpoint since they involve presently com-
mercial FGD technology.  However, the high energy consumption associated with the required production
of ozone is likely to render wet simultaneous SOX/NOX processes impractical.  For example, the oxida-
tion of NO to N02 by ozone for a 300 MW power plant is estimated to require 3 to 9 percent of the
plant power output (Reference  3-77).
       It appears that wet FGT systems cannot compete with dry selective catalytic reduction where
simple N0x control is involved.  For coal-fired applications where the dust loading and S02
                                                 3-50

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   boiler and  a 147  MW (500  x  10«  Btu/hr)  gas-fired  furnace.   Reductions of 70 percent were achieved
   with  a 1.5:1  molar  ratio  of ammonia  to  NO  (Reference 3-37).*
          Although selective noncatalytic  N0x reduction holds  promise, further tests and process
   studies are  needed  before its application in, the field.  The major requirements are:  (1) determina-
   tion  of its applicability to systems other than steam generators, such as gas turbines and combined
   cycles, (2) identification of reducing agent injection rate requirements for retrofit field appli-
   cations, (3) evaluation of techniques for maintaining adequate convective section temperatures
   required for selective reduction during  boiler load changes, (4)  assessment of possible  byproduct
  emissions,  and (5) assessment  of the impact on reducing agent markets  (References 3-37,  3-39, 3.75).
         Another dry FGT process  that  has  been  identified as  a possible  NOX control  technique  is
  molecular sieve adsorption.  In  general, this  is not applicable to  the water-containing  effluents
  from combustion sources  due  to  preferential absorption  of moisture  and resultant  loss of active
  sites.   It holds promise primarily for specialized  noncombustion applications where N02  concentra-
  tions  are high  (i.e.,  nitric acid plants).
         In general, the considerable experience in Japan qualifies N0x flue gas treatment  by selec-
  tive catalytic  reduction as commercially available for application to gas- and oil-fired  sources
  in the U.S.  from a technical  standpoint.   There are, however, several  factors and questions which
 must be considered in determining the potential for widespread use of this technology in  the U.S.
 Of particular importance is the applicability of this  technology to  coal-fired  sources.   EPA's
 research and  development program is aimed at resolving  these questions  (Reference  3-74).
 3.2.2  Wet Flue Gas Treatment

        The chemistry  and  process  steps involved  in wet processes are considerably more varied  than
 in dry  processes (Reference 3-74).  All Of those systems which have advanced beyond bench scale
 involve the use  of  a  strong oxidant such  as ozone or chlorine dioxide to convert the relatively
 inactive  NO in the  flue gas to N02 or  N20 for subsequent absorption.  Unfortunately, nearly all
 wet processes result  in a troublesome  byproduct which may be  little commercial value.  Some of
 these byproducts are  nitric acid, potassium nitrate, ammonium sulfate, calcium nitrate, and
 gypsum.

       The required oxidation  for wet  FGT  processes  can  take  place  either  in  the liquid or gas
Phase.  Those  processes that utilize liquid phase oxidation require extensive liquid/gas contact
in order to absorb the inactive  NO.  It appears  that  the  size and pressure drop  of  the NO

      *Amnonia injection  is  discussed in  more detail in  Section  3.1.2.7.
                                              3-49

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These designs will  be described in Section 3.3.1.   Techniques suitable for retrofit abatement for
older plants or add-on controls for plants built using old technology  include catalytic reduc-
tion, extended absorption with and without refrigeration,  wet chemical scrubbing,  and molecular
sieve adsorption.  These techniques will  be described in Section 3.3.2.  The techniques used for
other noncombustion sources, such as explosive plants and  adipic acid plants, are  basically the
same as those used for nitric acid plants, but vary with choice depending on economies of scale
and throughput.
3.3.1  Plant Design for N0y Pollution Abatement at New Nitric Acid Plants
       Nitric acid is manufactured in the United States by the catalytic oxidation of ammonia
over.a platinum or palladium catalyst with the subsequent absorption of the product gases, primarily
N0? and NO, by water to make nitric acid.  A more detailed discussion of the chemical process is
given in Section 6.  Each of these two catalytic processes have optimum conversions at different
operating conditions.  Moderate pressures of 300 to 500 kPa allow longer catalyst life by lowering
operating temperatures in the  initial oxidation reaction.  Higher  pressures in the range of 800 to
1100 kPa (116  to 160 psia) allow  higher absorption rates  in the absorption columns with smaller
equipment sizes and lower costs.  The higher conversions  of N02 to HN03 allow for smaller equipment
for  both the main  process plus any tail gas treatment required to meet emission standards.  Cur-
rently most existing plants operate at low or moderate pressures throughout the process.  Sections
3.3.1.1 and 3.3.1.2 will discuss  how the  design of new nitric acid plants has taken  these factors
into account to  increase conversion and decrease emission control costs.

3.3.1.1  Absorption Column  Pressure Control
       By designing a  new plant  so that the inlet  pressure at the absorption  is 800  to 1000 kPa
 (116 to  145 psia)> the efficiency of the  absorber  can be  increased so  that an effluent of less
than 200 ppm NO  is emitted.   A  high inlet gas  pressure at the absorber can be achieved either by
running the ammonia-oxygen  reaction at high pressure, or  by  running  the ammonia-oxygen  reaction
at low pressure, with  compression of the  gas stream  before introduction to the absorber.  Higher
absorption  pressures will increase the convertion  of NOp  to  nitric acid and minimize NOX emissions.
However, there are economic  penalties  in  the form  of increased equipment  cost, thicker  walls  and
compressors, and increased  maintenance costs.
3.3.1.2  Strong  Acid  Processes
       Nitric  acid is  usually produced at strengths  of 50 to 65 percent by weight  in water  due to
azeotrope  limitations.  Azeotropic conditions  result in a constant composition in  both  vapor  and
                                                3-52

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 concentrations are high, it is not clear whether dry FGT combined with conventional FGD processes
 will be cheaper than the wet simultaneous SOX/NOX systems such as Chiyoda 102 or MHI.  Dry simul-
 taneous S0x/N0x systems such as the Shell and the Sumitomo Shipbuilding processes may also prove
 to be cheaper than the wet simultaneous processes.  The Shell process is being commercially applied
 on a 40 MW* oil-fired boiler in Japan and is being applied in the U.S. on the flue gas streams from
 a 0.6 MW* coal-fired boiler.  The Sumitomo Shipbuilding process will be tested at the prototype
 level on an oil-fired boiler.
        In general, wet processes are less well developed and show higher projected costs than dry
 FGT processes.  Considering their cost and complexity,  it is doubtful that wet processes would be
 receiving any development attention in Japan were it not for the potential for simultaneous SO
 and NOX removal.   For both processes,  a number of important questions concerning NO  FGT costs,
 secondary effects, material use,  reliability, and waste disposal  remained to be answered.   EPA
 is proceeding with a  coordinated  program of experimental  work,  technology assessment,  and  engineer-
 ing studies  to answer these questions  (References 3-48,  3-74).
 3.3    Noncombustion  Gas Cleaning
        Emissions  from noncombustion sources as industrial  or chemical processes are small  relative
 to the total emissions from stationary sources (1.7  percent)'.  Nationwide NOX emissions  from nitric
 acid manufacturing are estimated,  for  the year 1974,  at 127 Gg  (140,000 tons) uncontrolled emissions,
 which is  about 1.0 percent of  the total  stationary source  emissions.   The Environmental  Protection
 Agency  issued  standards  (under  the  authority  of the Clean Air Act) that new  nitric acid  plants
 constructed  after  December  23,  1971, have  a maximum permitted nitrogen oxide  effluent of 1.5 kg
 (measured as N02)  per Mg of acid  (100 percent basis) produced (3 Ib/ton).  This  is equivalent to
 approximately  210  ppm NOX-  For existing plants the maximum nitrogen oxides permitted has been set
 at 2.75 kg/Mg  (5.5 Ib/ton)  of acid or approximately 400 ppm N0x in several states.  These standards
 were established in consideration of the then available technology, which was catalytic reduction
 of NOX to t\2 and water using methane or hydrogen.
       Several economic factors, discussed in Section 3.3.2.4 have stimulated development of
 Improved processes for tail gas cleaning and improvements in the nitric acid process itself.  One
of the major considerations is  that much of the residual oxides  of nitrogen formed in the manu-
facture of nitric  acid can be recovered and converted  into nitric  acid, thus increasing  the plant
yield.  Also, new plants can be designed to have low  NOX emissions without add-on control equipment.
       *electric output rating.
                                               3-51

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3.3.2.1   Chilled Absorption
       The basic principle involved is that the amount of NOX that can be removed from the process
gas by the absorber (water) increases as the water temperature decreases.  Therefore,  this method
of retrofit provides for chilling of the water prior to entry into the absorption tower or by direct
cooling of the absorption trays.   This method of NOX reduction has only provided marginal  results
and has had problems in continuously meeting the NSPS, especially in warm weather.  Refrigeration re-
quirements can prove costly, both in equipment and energy use.

3.3.2.2  Extended Absorption
       One of the most commonly used retrofit processes, which has been used effectively to meet
the NSPS, is extended absorption. Figure 3-15 shows the flow diagram of a nitric acid plant after
addition of the extended absorption system, which consists of an additional absorber and a pump.
This method is offered by several licensors both with and without other features such as compres-
sion of the tail gas before entry to the additional tower or a supply of chilled water to the
absorption column trays.  Because of the additional pressure loss in the second column an
inlet pressure of at least 700 kPa (101 psia) is preferred to make the economics of this method
attractive.

3.3.2.3  Wet Chemical Scrubbing
       Wet chemical scrubbing removes NOX from nitric acid plant tail gases by chemical reaction.
Liquids such as alkali hydroxide solutions, ammonia, urea, and potassium permanganate convert N02
to nitrates and/or nitrites.  These techniques produce a liquid effluent which needs disposal.
For three recent techniques — urea scrubbing, ammonia scrubbing and nitric acid scrubbing — the
effluent is a valuable byproduct which can be reclaimed and sold as fertilizer.
Caustic Scrubbing
       In this process, NO  in the tail gas reacts with sodium hydroxide, sodium carbonate, or
ammonium hydroxide to form nitrite and nitrate salts.  Although caustic scrubbing removes NO  from the
tail gas, it has not found extensive use in the industry because of the difficulties encountered in
disposing of the spent solution.   The alkali metal nitrite and nitrate salts contained in the spent
solution become a serious water pollutant if released as a liquid effluent, and their concentrations
are too dilute for economic recovery.
                                               3-54

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  liquid  phases.  With higher operating pressures nitric acid up to 68 percent can be obtained.
  Further concentration  is sometimes accomplished by dehydration of the acid or further distillation
  with sulfuric acid addition.
         However, nitric acid of high strength can be made directly from ammonia by the Direct Nitric
  Acid (DSNA) process.  Ammonia is burned with air near atmospheric pressure, and the nitrogen oxides
  are oxidized to nitrogen dioxide in a contact tower.  The nitrogen dioxide is then separated from
  the gas stream by physical  absorption in chilled high-concentrated nitric acid, stripped by distilla-
  tion and then liquified as  NpO..
        The liquid dinitrogen tetroxide is pumped to a reactor together with aqueous nitric acid.
 Pure oxygen is added and the dinitrogen tetroxide reacts  at a  pressure of approximately 5200 kPa
  (756 psig) directly to  highly concentrated nitric acid.   Variations  on the process  can  produce
 both strong (98  to 99 percent) nitric acid and weak (50 to  70  percent)  nitric acid  at the same
  plant (Reference 3-78).  Tail gas emissions from this process are within the 1.5 g/kg (3 Ib/ton)  NO
 regulation.  This occurs primarily by ensuring oxidation to N02 and physical absorption with the
 concentrated nitric acid at low temperature.
       Concentrated  nitric  acid has also  been made  by the SABAR (Strong Acid By Azeotropic Reacti-
 vication)  process.  Ammonia combustion occurs at near atmospheric pressure  and at 1.123K  (1.560F)
 with the usual waste-heat boiler, tail gas p'reheater, cooler/condenser effluent train.  By mixing
 the combustion gases with feed air and recycled nitrogen dioxide and compression nearly all the
 NO is converted to NO.,.   Chemical absorption with an azeotropic mixture of about 68 percent (by
weight)  nitric acid produces a superazeotropic mixture.   A 99 percent (by weight) overhead prod-
uct is produced by vacuum distillation.

3'3'2  Profit Design for NOX Pollution Abatement at New or Existing Nitric Acid Plants
       Most existing nitric  acid plants were not designed  with  the present NOX emission  standards
 in mind.  Abatement methods  for these plants are installed on a retrofit basis.  The available abate-
ment methods include chilled absorption, extended absorption, wet scrubbing, catalytic reduction,
and molecular sieve adsorption.  In this section, these  various control  techniques for NO  are
described.   These same procedures are also used on new nitric acid plants using the  earlier low  or
moderate operation pressure  design where the abatement facility is designed to process  the tail  gas
to meet the 1.5 g N02/kg of  acid product (3 Ib/ton) emission standard.
                                               3-53

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Urea Scrubbing
       Urea can be used to treat tail  gases for NOX control  since it reacts rapidly with nitrous
acid.  Nitrogen dioxide, N(L reacts with water to form both  nitric acid (HNOo) and nitrous acid
(HNOp) in equal proportions.  Nitrous  acid will rapidly decompose to form NO and NOo.   Urea
(CO (NHpJo) wnen contacted with the tail gas will absorb N0£ indirectly as nitrous acid to form
ammonium nitrate, NhLNO- and free nitrogen, N«.  By depleting the liquid phase of nitrous acid
the equilibrium conversion of nitric oxide, NO, to nitorgen  dioxide occurs to remove NO also.
The result is conversion of NOp to either free nitrogen which is vented to atmosphere or ammonium
nitrate which is sold as fertilizer.
Ammonia Scrubbing
       Ammonia, a weak base, can be used to scrub the oxides of nitrogen (weak acids) from the
nitric acid plant tail gas.   The- product of this scrubbing reaction is an ammonium nitrate solu-
tion (NH.NO.J which can be recovered and sold as fertilizer.  This process can be applied to tail
gas concentrations up to 10,000 ppm and requires 1 to 1.5 percent excess oxygen.
Nitric Acid Scrubbing
       Nitric acid scrubbing of tail gas has been commercially applied by one licensor.  The pro-
cess uses both physical absorption and stripping and chemical oxidation absorption.  The process
uses only water and nitric acid and coverts nitrogen oxides  in the tail gas to nitric acid at
concentrations which can be commercially utilized (Reference 3-79).
Potassium Permanganate Scrubbing
       A potassium permanganate scrubbing process has been used to reduce NO  emissions from
1800 ppm to 49 ppm at a nitric acid concentration plant in Japan.  The process reacts potassium
permanganate with nitrogen oxide and sodium hydroxide to form potassium sodium manganate, sodium
nitrite and potassium nitrite.  The potassium permanganate is regenerated by oxidizing the
potassium sodium manganate electrolytically (References 3-80 and 3-81).  However, the process
is presently considered to be too expensive to be competitive (Reference 3-82).  It has not
been tried on any plants in the United States, and is not presently offered by any licensor.
                                               3-56

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            Figure 3-15.  Extended absorption system on existing nitric acid plant.
                                          3-55

-------
       NO  abatement using nonselective catalyst is more difficult technically than  decolorization,
and commercial results have been less satisfactory.  Provisions must be made to control  the  heat
released in reacting all  the tailgas oxygen.   The thermal control  must  be done before extensive
NO reduction proceeds.
       In Section 6 the success of the various types of catalytic  abaters in coping  with the
problems of temperature rise and high space velocities will  be discussed.  In general, nonselective
catalytic reduction is not likely to be used in the future for NOX control.   The availability and
cost of natural gas, increasing catalyst cost and poor performance have led  to a decline in  inter-
est in this process.
Selective catalytic reduction
       In selective catalytic reduction, ammonia is reacted with the NOX to  form Ng.  The oxygen
in the tail gas does not react with the ammonia, so stoichiometric amounts of ammonia are used.
       In contrast to nonselective techniques, selective catalyst abatement  must be  carried  out
within the narrow temperature range of 483K to 544K (410F to 520F).  Within  these limits, ammonia
will reduce N02 and NO to molecular nitrogen, without simultaneously reacting with oxygen.  The
overall reactions are shown in the following equations:
                                      8NH3 + 6N02  +  7N2 + 12 H20                         (3-9)

                                      4NH3 + 6NO   -  5N2 + 6H20                           (3-10)
Above 544K, ammonia may oxidize to form NO ; below 483K, it may form ammonia nitrate.
       Selective oxidation with ammonia has several advantages over nonselective reduction:
       0  The reducing agent, ammonia is usually readily available since it  is consumed as
          feed stock in the nitric acid process
       •  Temperature rise through the reactor bed is only 20K to 30K (36F to 54F) so that
          energy recovery equipment, such as a waste heat boiler or high temperature gas
          turbine,  is not required
       •  Lower raw material costs since the amount of ammonia required is approximately
          equal to the molal equivalent amount of NO  abated
         Heterogeneous Catalysis
       One wet scrubber process uses heterogeneous catalysis in a packed column to oxidize NO to
N02 (References 3-83 and 3-84).  This system is currently in the development stage.
                                                3-58

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3.3.2.4  Catalytic Reduction
       There are three types of catalytic reduction processes used for NO  control:  nonselective
reduction, which removes both NO  and oxygen; selective reduction, which removes only NO  , and
                                x                                                       x
heterogeneous catalysis used in conjection with wet scrubbing.  Each of these will be discussed
in the following paragraphs.
Nonselective catalytic reduction
       The nonselective reduction process reacts NOX with H2 or CH4 to yield N2, C02 and H20.
The  process is called nonselective because the reactants first deplete all the oxygen present
in the tail gas, and then remove the NOX-  Prior to the large increases in natural gas prices the
excess fuel required to reduce the oxygen did not Impose a heavy economic penalty.  The reactions
were exothermic, and much of the heat could be recovered with a waste heat boiler.
       The nonselective reduction process is used for decolorization and energy recovery, as well
as for NOX abatement.  Decolorization and power recovery units reduce N02 to NO and react part
of the oxygen,  but their capacity to reduce NO to elemental nitrogen is limited.  The nonselective
abatement units carry the process through to NO reduction as well.  In nonselective reduction,
the tail  gases from the absorber are heated to the necessary catalyst ignition temperature, mixed
with a reducing agent, such as hydrogen or natural gas, and passed into the reactor and through
the catalyst.   The main chemical reactions that take place are:

                                   CH4 + 4N02  +  4NO + C02 + 2H20                         (3-6)

                                   CH4 + 202   +  C02 + 2H20                               (3-7)

                                   CH4 + 4NO   -»•  2N2 + C02 + 2H20                         (3-8)

       Similar equations can be written substituting hydrogen for methane, in which case two moles
of hydrogen are needed to replace one mole of methane.   The reaction kinetics are such that reduc-
tion reaction  (3-6) is faster than reduction reaction (3-7), but abatement reaction (3-8) is much
slower than reaction (3-7).   Thus, decolorization can be accomplished by adding just enough fuel for
partial  oxygen  burnout.   If NOX abatement is required,  however,  sufficient fuel must be added for
complete  oxygen burnout.
       Both catalyst and nitric acid manufacturers report satisfactory performance for decoloriza-
tion units.  The reduction of total  NO  is limited, but ground-level  NO, concentration in critical
                                      x                                c
areas near the  plant is  reduced substantially.
                                                3-57

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3-10   Sarofim, A.  F., ejt aJK, "Mechanisms and Kinetics of NO  Formation:  Recent Developments,"
       presented at 65th Annual AIChE Meeting, Chicago, November 1976.

3-11   Snyder, R.,  "Nitrogen and Oxygen Compound Types in Petroleum," Analytical Chemicstry 41:
       314-323, February 1969.

3-12   Martin, G. B.,  and E. E. Berkau, "An Investigation of the Conversion of Various Fuel Nitro-
       gen Compounds to Nitrogen Oxides in Oil Combustion," presented at AIChE meeting, August 30,
       1971, Atlantic  Civ--. August, 1971.

3-13   United States Senate, Committee on Public Works, "Air Quality and Stationary Source Emission
       Control," Serial No. 94-4, March 1975.

3-14   Habelt, W. W. and B. M. Howell, "Control of NO Formation in Tangentially Coal-Fired Steam
       Generators," in Proceedings of the NOX Control Technology Seminar, EPRI SR-39, February 1976.

3-15   Heap, M. P., elt al., "The Optimization of Burner Design Parameters to Control NOX Formation
       in Pulverized CoaT and Heavy Oil Flames," in Proceedings of the Stationary Source Combus-
       tion Symposium, EPA-600/2-76-152b,  June, 1976.

3-16   Pohl, J. H., and A. F.  Sarofim, "Devolatilization and Oxidation of Coal Nitrogen," presented
       at 16th International Symposium on Combustion, M.I.T., August 1976.

3-17   Blair, D. W., et al_., "Devolatilization and Pyrolysis of Fuel Nitrogen from Single Coal
       Particle Combustion," 16th Symposium (International) on Combustion, Cambridge, Mass., 1976.

3-18   Pershing, D. W., "Nitrogen Oxide Formation in Pulverized Coal Flames," PhD Dissertation,
       University of Arizona,  1976.

3-19   Axworthy, A. E., Jr., "Chemistry and Kinetics of Fuel Nitrogen Conversion to Nitric Oxide,"
       AIChE Symposium Series. No. 148, Vol. 71, 1975, pp. 43-50.

3-20   Axworthy, A. E., ejt al_., "Chemical  Reactions in the Conversion of Fuel Nitrogen to NOX," in
       Proceedings  of  the Stationary Source Combustion Symposium, Volume I, Fundamental Research,
       June 1976.

3-21   Pershing, D. W., and J. 0. L. Wendt, "The Effect of Coal Combustion on Thermal and Fuel
       NOX Production  from Pulverized Coal Combustion," presented at Central States Section,
       The Combustion  Institute, Columbus, Ohio, April 1976.
3-22   Pohl, J. H. and A. F. Sarofim, "Fate of Coal Nitrogen During Pyrolysis and Oxidation," In:
       Proceedings of the Stati
       EPA 600/2-76-152a, June
Proceedings of the Stationary Source Combustion Symposium. Volume I. Fundamental Research,
3-23   Barr, W. H., and D. E. James, "Nitric Oxide Control -A Program of Significant Accomplish-
       ments," ASME 72-WA/Pwr-13.

3-24   Barr, W. H., ejt al_., "Retrofit of Large Utility Boilers for Nitric Oxide Emissions Reduc-
       tion — Experience and Status Report."

3-25   Crawford, A. R., et al_.,  "Field Testing:  Application of Combustion Modifications to Control
       NOX Emissions from Utility Boilers," Exxon Research and Engineering Co., EPA-650/2-74-066,
       June 1974.

3-26   Crawford, A. R., e_t a_l_., "The Effect of Combustion Modification on Pollutants and Equipment
       Performance of Power Generation Equipment," Exxon Research and Engineering Co., EPA-600/2-
       76-152c, prepared for the Stationary Source Combustion Symposium, September 24-26, 1975.

3-27   Blakeslee, C. E., and H. E.  Burbach, "Controlling NOX Emissions from Steam Generators,"
       C.E. Inc., APCA 72-75, 65th Annual Meeting of Air Pollution Control Association, June 18-22,
       1972.

3-28   Hollinden, G. A., et al_. , "Evaluation of the Effects of Combustion Modifications in Con-
       trolling NOX Emissions at TVA's Widow's Creek Steam Plant," EPRI SR-39, February 1976.

3-29   Maloney, K. L., "Western Coal Use in Industrial Boilers," Western States Section/The
       Combustion Institute, April  19-20, 1976, Salt Lake City, Utah.
                                               3-60

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  3.3.2.5   Molecular  Sieve Adsorption
        One method of NOX control  involves the adsorption of N0x onto a solid followed by regenera-
  tion of  the adsorbent.  Materials such as silica gel, alumina, charcoal, and commercial zeolites
  or molecular sieves have been employed for this method.  Molecular sieves have been found to be
  the most effective  medium for this method of control, since they adsorb N02 selectively.
  Special  sieves have been developed which incorporate a catalyst to simultaneously convert NO to
  N02.  This process operates best only when low concentrations of oxygen are present, which is true
  of most tail  gas streams.   The abatement bed is usually provided with a dehydration section prior
  to contact with the abatement sieve to improve overall  performance.

        The adsorbent bed is  regenerated by thermally cycling  the bed  after  it  is  loaded  with NO .
 The required  regenerating  gas is obtained by using  a portion  of the  treated  tail  gas stream to
 desorb  the adsorbed  NO,, from the bed.   This  gas  stream  is  then recycled to the  nitric  acid  plant
 absorption tower.   No other  liquid,  solid or  gaseous effluents are produced  by  this  process.
        Two plants  using this system were  in operation and  had  experienced difficulties.  The  pro-
 cess has  become  unattractive for future  installations because  of the cost of the  catalyst bed,
 the energy cost  of thermal cycling, and  the operational difficulties of using a cycling  adsorption
 process with a steady state  nitric acid plant.

                                     REFERENCES FOR  SECTION 3

                                                 1n  CombuSt1on and Explosions," Acta Physiochim,
       MacKinnon, D. J   "Nitric Oxide Formation at  High Temperature," Journal  of the Air Pollution
       Control Association, Vol.  24, No. 3, March 1974.                                     niuciuri
 3-3    Rawdon, A. H.  , and R.  S.  Sadowski, "An Experimental  Correlation of Oxides of Nitroapn
                                    ***** '" ^ Data'"  ^ ASME °°Ur"a! " W»X for
 3-2
3-4

3-5
       Breen, B. P. ."Control of the Nitric Oxide Emissions from Fossil Fueled Boilers " The Fourth
       Westinghouse International School for Environmental Management, July 15-18, 1973.
       Bartz, D. R. , et ah , "Control of Oxides of Nitrogen from Stationary Sources in the South
       Coast Air Basin," California Air Resources Board Report No.  ARB 2-1471? Septeiber, 1974*
3"6    !Sf:hi;«PA; S£ — ' D"?Urn?r 5r1Jer?a for N0x Control» Volume I.  Influence of Burner
       Variables on NOX in Pulverized  Coal Flames," EPA 600/2-76-061 a, March 1976.
       Drtllll.  ...    ^-—.   „         of Interaction Between Fluid Dynamics on Chemistry of
       S^nn^m  v^   ? 'S ^^IT^ ™ Proceedings of the Stationary Source Combustion
       Symposium, Volume I. Fundamental Research. EPA 600/2-76-152a. .i..np iQ7fi	
3~8    nJScinJ:/*; !ud ?'  C' Ih°mas' "Oxides of Nitrogen in Relation to the Combustion of Coal,"
       presented at the Seventh International Conference on Coal  Science, Prague,  June, 1968
3"9    FuPlShNn9fr;mWRocTJ,,!T'A-iInf]UrnC? ?f ?esi?n Vari'ables  on the Production  of Thermal  and
       Fuel  NO from Resi^uaT Oil  and Coal Combustion,"  AIChE Symposium Series. No.  148,  Vol.  71,
       iy/0, pp.  iy-^9.
                                                3-59

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3-49   "Analysis of the Proposed National Energy Plan" - Office of Technology Assessment, Congress
       of the United States, August 1977.

3-50   Ctvrtnicek, T. E., e_t aj_., "Evolution of Low-Sulfur Western Coal Characteristics, Utiliza-
       tion and Combustion Experience," Monsanto Research Corp., EPA 650/2-75-046, May 1975.

3-51   Shimizu, A. B. , et al_. , "No  Combustion Control Methods and Costs for Stationary Sources,"
       Environmental Protection Technology Series, EPA-600/2-75-046, September 1975.

3-52   Bartick, H. A., ejt a_l_., "The Production and Refining of Crude Shale Oil into Military
       Fuels," Final Report by Applied Systems Group, submitted to Office of Naval Research,
       Arlington, Va., August 1975.

3-53   Martin, G. B., "Evaluation of NOX Emission Characteristics of Alcohol Fuels in Stationary
       Combustion Systems," presented at Joint Meeting, Western and Central States Sections,
       The Combustion Institute, April 21 and 22, 1975, San Antonio, Texas.

3-54   Hall, R. E., "The Effect of Water/Residual Oil Emulsions on Air Pollutant Emissions and
       Efficiency of Commercial Boilers," ASME 75-WA/APC-l, July 14, 1975.

3-55   Martin, G. B., "Environmental Considerations in the Use of Alternate Clean Fuels in
       Stationary Combustion Processes."

3-56   Martin, G. B., D. W. Pershing,E. E. Berkau, "Effects of Fuel Additives on Air Pollutant
       Emissions from Distillate Oil-Fired Furnaces," EPA, Office of Air Programs, AP-87, June 1971.

3-57   Shaw, H., "Reduction of Nitrogen Oxide Emissions from a Gas Turbine Combustor by Fuel Modi-
       fications," ASME Transactions, Journal of Engineering for Power, 95, 4, October 1973.

3-58   Altwicker, E. R., et al_., "Pollutants from Fuel Oil Combustion and the Effects of Additives,"
       Paper No. 71-14, 64th Annual APCA Meeting, Atlantic City, N. J., June 1971.

3-59   Barrett, R. E., e_t aj_., "Field Investigation of Emissions from Combustion Equipment for
       Space Heating," EPA R2-73-084a, June 1973.

3-60   Frey, D. J., "De-Ashed Coal Combustion Study," Combustion Engineering, Inc., October 1964.

3-61   Energy Research and Development Agency, "Proceedings of the Fourth International Conference
       on Fluidized Bed Combustion," McLean, Va., December 1975.

3-62   Jonke, A. A., et^ al_., "Pollution Control Capabilities of Fluidized-Bed Combustion," AIChE
       Symposium Series No. 126, Vol. 68, 1972.

3-63   Chronowski, R. A., and B.  Molayem, "NOX Emissions from Atmospheric Fluidized-Bed Boilers,"
       ASME 75-PWR-4, October 1975.

3-64   Pfefferle, W. C., el^ §J_.,  "CATATHERMAL Combustion:  A New Process for Low-Emissions Fuel
       Conversion," presented at the 1975 ASME Winter Annual Meeting, Houston, Texas, ASME
       Paper No. 75-WA/FU-l.

3-65   Kesselring, J. P., et a]_.,  "Catalytic Oxidation of Fuels for NOX Control  from Area Sources,"
       EPA Report, EPA-600/2-76-037, February 1976.

3-66   DeCorso, S. M., et al.,   "Catalysts for Gas Turbine Combustors - Experimental  Test Results,"
       paper presented at A"SME Gas Turbine Conference and Products Show,  New Orelans, March 1976,
       ASME Paper #76-GT-4.

3-67   Gerstin, R. A., "A Technical and Economic Overview of the Benefits of Repowering," paper
       presented at the Gas Turbine Conference and Products Show,  Houston, Texas, March 2-6, 1975,
       ASME Paper #75-GT-16.

3-68   Ahuja, A., "Repowering Pays Off for Utility and Industrial  Plants," Power Engineering,
       pp.  50-54, July 1976.                                                	a	
                                               3r62

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 3-30   Brown, R. A., H.  B.  Mason, and R.  J.  Schreiber, "Systems Analysis Requirements for Nitrogen
        Oxide Control of Stationary Sources," Environmental  Protection Technology Series EPA-650/2-
        74-091, Sepgember 1974.

 3-31   Selker, A.  P., and R.  L.  Burnington,  "Overfire Air Technology for Tangentially Fired Utility
        Boilers Burning Western  U.S.  Coals,"  in  Proceedings  of the Second Stationary Source Combustion
        Symposium Vol II, Utility and Large Industrial  Boilers.  EPA-600/7-77-073b.  July 1Q77,	

 3-32   Bagwell,  F.  A., et. ah,  "Utility Boiler  Operating  Modes  for Reduced  Nitric  Oxide Emissions,"
        Presented at the  64th  Annual  Meeting  of  the Air Pollution Control  Association, June 1971.

 3-33   U.S.  Environmental  Protection Agency, "Draft - NOX SIP Preparation Manual Volume II -
        Support Sections," Office of  Air Quality Planning  and  Standards,  Research Triangle Park
        N.C.,  April, 1976.

 3-34   Copeland, J. 0.,  "Standards Support and  Environmental  Impact Statement:  An Investigation
        of the Best  Systems  of Emission  Reduction  for  Nitrogen Oxides from Large Coal-Fired Steam
        Generators," (Draft) EPA,  October  1976.

 3-35   Crawford, A.  R.,  E. H.  Manny  and W. Bartok,  "Field Testing:   Application of Combustion
        Modifications  to  Power Generating Combustion Sources," in  Proceedings of the Second  Stationary
        Source  Combustion Symposium,  Volume II.  Utility and Large  Industrial Boilers,  EPA-600/7-77-
        073b.

 3-36   Lyon,  R.  L., "Method for  the  Reduction of  the Concentration  of NO  in Combustion  Effluents
        Using  Ammonia," U. S.  Patent  No. 3,900,554,  assigned to  Exxon Research and  Engineering
        Company,  Linden,  New Jersey,  August 1975.

 3-37   Lyon,  R.  K.  and J. P.  Longwell,  "Selective,  Non-Catalytic  Reduction of NOX  by  NHa,"
        Proceedings  of the NOX Control Technology  Seminar, EPRI  SR-39,  February 1976.

 3-38   Muzio,  L. J.,  and T. K. Arand, "Homogeneous  Gas Phase  Decomposition of Oxides  of Nitrogen,"
        EPRI Report  FP-253, August  1976.

 3-39   Teixeira, D.  P.,  "Status of Utility Application of Homogeneous  NOX Reduction," Proceedings
        of the  NOX Control Technology Seminar, EPRI  SR-39, February  1976.

 3-40   Ando, J.  and T. Heiichiro,  "NOX Abatement  for Stationary Sources in Japan,"  Environmental
        Protection Technology Series, EPA-600/2-76-013b, January 1976.

 3-41    Shoffstall,  D. R., "Burner Design Criteria for Control  of  Pollutant Emissions from Natural
        Gas Flames,1   Institute of Gas Technology,  EPA-600/2-76-152b, June 1976.

 3-42    Koppang,  R.   R., "A Status Report on the Commercialization and Recent Development History
        of the TRW Low NOX Burner," TRW Energy Systems Group.

 3-43    Tsuji, S., et al_., "Control Technique for Nitric Oxide  - Development of New Combustion
        Methods," IHI Engineering Review, Vol. 6, No. 2.

 3-44   Ando, J., et aJL, "NOX  Abatement for Stationary Sources in Japan," August 1976 (Preliminary
        uraTt).

 3-45    Shoffstall,  D. R., "Burner Design Criteria for Control  of NOX from Natural  Gas Combustion,
        Volume  I,1 Institute of Gas Technology, EPA-600/2-76-098a, April 1976.

 3-46    Brackett, C.  E., and J. A. Barsin, "The Dual Register Pulverized Coal  Burner -a NOv
       Control Device," EPRI SR-39, February 1976.

 3-47   Campobenedetto, E. J.,  "The Dual  Register Pulverized Coal Burner - Field Test Results,"
       presented at Engineering  Foundation Conference on Clean Combustion of Coal,  Franklin Pierce
       College, New Hampshire, July 31-August 5, 1977.

3-48   Bowen, J.  S., D. G.  Lachapelle, and R. Stern, "Overview of EPA's NOX  Control Technology for
       Stationary Sources,"  presented at 67th Annual AIChE Meeting, December 1974.
                                               3-61

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3-69   Stambler, I., "Repowering Gives Glendale Extra 75 MW and Lower Rates,"  Gas  Turbine World,
       September 1977.

3-70   Robson, F.  L., and A.  J.  Giramonti, "The Use of Combined-Cycle Power Systems in Nonpolluting
       Central Stations," JAPCA, Vol.  22, pp.  177-180i 1972.

3-71   Amos, D. J., et al..,  "Energy Conversion Alternatives Study (EGAS), Westinghouse Phase I
       Final Report, Volume  V - Combined Gas Steam Turbine Cycles," NASA CR-134941, Volume V, 1976.

3-72   Papamarcos,  J., "Combined Cycles and Refined Coal," Power Engineering,  December 1976, pp.
       34-42.

3-73   Ando, J. and B.  A. Laseke, "S02 Abatement for Stationary Sources in Japan," EPA-600/7-77-
       103a, September 1977.

3-74   Stern, R.,  "The EPA Development Program for NOX Flue Gas Treatment," In:   Proceedings of the
       National Conference on Health,  Environmental Effects, and Control Technology of Energy Use,
       EPA Report 600/7-76-002,  February 1976.

3-75   Koutsoukos,  E. P., et al_., "Assessment of Catalysts for Control of NOX  from Stationary Power
       Plants, Phase I," Volume I, EPA-650/2-75-001-2, January 1975.

3-76   Muzio, L. L., J. K. Arand, and  D. P. Teixeira, "Gas Phase Decomposition of Nitric Oxide in
       Combustion Products," In:  Proceedings of the NOX Control Technology Seminar, EPRI Special
       Report SR-39, February 1976.

3-77   "Technology and Economics of Flue Gas NOX Oxidation by Ozone," EPA 600/7-76-003, December
       1976.

3-78   "Nitric Acid from Ammonia," Hoechst-Uhde Corp. brochure (FWC 11 619), Englewood Cliffs, N.J.

3-79   Mayland, B.  J., "The CDL/VITOK Nitrogen Oxides Abatement Process," Chenoweth Development
       Laboratory,  Louisville, Ky.

3-80   "New System Knocks NOX Out of Nitric," Chemical Week, September 3, 1975,  pp. 37-38.

3-81   "NOX Removal System Now Available," Wet Scrubber Newsletter, September  30, 1973, pp. 3-4.

3-82   Personal communication, Mr. Kenneth Ficek, Technical Service Manager, Carus Chemical,
       November 1977.

3-83   Mayland, B.  J., "Application of the CDL/VITOK Nitrogen Oxide Abatement  Process," presented at
       Sulfur and Nitrogen Symposium,  Salford, Lancashire, U.K., April 1976

3-84   Mayland, B.  J., and R. C. Heinze, "Continuous Catalytic Absorption for  NOX Emission Control,"
       Chemical Engineering Process, Vol. 6, May 1973, pp. 75-76.
                                                3-63

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         The  total  N0x  emitted  in  1974  by  the electric utility  industry was 5.1 Tg (5.6 x 106 tons)
  or 41.9 percent of  the  total  stationary  source emissions.  Coal-fired boilers accounted for approxi-
  mately  68 percent of  the  total utility emissions.  A more detailed emission breakdown is presented
  in Section  2.  For  reference, the ranges of uncontrolled NOX  emissions for three of the firing types
  are given in Table  4-1.   Cyclone-fired boilers typically have the largest uncontrolled emissions,
  and tangentially-fired  have the  lowest (Reference 4-1).
  4.1.1   Control Techniques
         The NOX control options for utility boilers include combustion modification, flue gas treat-
  ment, and fuel modification.  The former has been the most successful and widely used option,  and
  is described below for gas, oil,  and coal-fired units.   The other less popular and  less  developed
 options are discussed after combustion modification.
 4.1.1.1   Combustion  Modification
        The  general concept of  combustion  modifications  as  potential  NO  control  techniques  for sta-
 tionary sources was  discussed  in  Section  3.1.   These  techniques  have  been developed and  refined in
 numerous laboratory  test installations and  in  many successful  field  applications to commercial
 utility boilers.
        Utility  boilers,  due to their  importance as NOX  sources and their  control  flexibility,  are
 the most extensively modified  stationary  equipment type.  The  selection and implementation  of  effec-
 tive N0x controls  for  a  specific  utility  boiler is  uniquely dependent  on  the furnace characteristics
 (i.e., geometry and  operational flexibility),  fuel/air  handling  systems and automatic controls, and
 to  the potential for operational  problems which may result from  combustion modifications.  The
 following discussion is, therefore, not intended to provide application guidelines,  but rather to
 give  a broad overview  and  evaluation of tested procedures.
       Table 4-2 summarizes the status of combustion modification technology for NO   control in
 utility  boilers.  The  references  cited in the table are bases for the remainder of the discussion
 in  this  section.  The  table also  lists typical  values of controlled emissions  for the major modifi-
 cation techniques  and  two major firing types, tangential firing and wall  firing.
       Retrofit N0x control implementation by combustion modification usually  proceeds in several
 stages depending on the emission limits to be reached.   First,  fine tuning of  combustion  conditions
 by  lowering  excess  air and adjusting  the burner settings and air  distribution  is  employed.   If  NO
emission levels are still too high,  the minor modifications,  such as  biased firing or burners
out of service (BOOS) are implemented.   Increased  frequency  of  boiler  washing  increases flame heat
                                                4-2

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                                           SECTION 4
                             LARGE FOSSIL FUEL COMBUSTION PROCESSES
       Fossil  fuel  combustion in utility and industrial  boilers and internal  combustion (1C)
engines account for about 80 percent of NOX emissions from stationary sources (see Section 2).
The large boiler category encompasses application to utility power generation and industrial
process steam generators.  Large 1C engines are used predominantly for power  generation and
for pipeline pumping and encompass large bore reciprocating engines as well  as continuous
combustion gas turbine engines.   This section summarizes the effectiveness,  cost, user exper-
ience and energy and environmental impact of the implementation of NOX controls on these
equipment categories.
4.1    ELECTRICAL UTILITY BOILERS
       Most of the nation's electricity is generated in large fossil-fueled central station
power plants, which consist of high-pressure watertube boilers in the 100 to 1000 MW* range
serving turbine-generators.  Firing capacities of individual burners in utility boilers
commonly have thermal inputs as high as  58 MW  (200  x 106  Btu/hr).  A  1000 MW*  opposed
wall-fired unit may require as many as  60 separate  burners.
       Although there are some differences among utility  boiler designs in such factors as
furnace volume, operating pressure, and configuration of  internal heating transfer surface,
the principal distinction is firing mode.  This  includes  the type of firing equipment, the
fuel handling system, and the placement of the burners on the furnace walls  (see Section
2.3.1).
 *Electrical  utility boilers  are  commonly  described  in  terms of electrical output rating,
  This convention will  be  used  throughout  Section  4.1.
                                               4-1

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-------
 removal thereby decreasing thermal NOX (Reference 4-2).  If still  necessary, these minor modifications
 are followed by the major retrofits, including overfire air ports  (OFA), flue gas recirculation (FGR),
 and new burners.
        At present,  more of these  stages  of control  have  been  implemented  for  control  of  thermal  NO
 than for fuel  NOX control.   That  is,  FGR and  staging  are now  commonly  found in  gas  and oil-fired
 boilers, while coal-fired  units are only just now entering  the  second  stage of  control.
        The feasibility,  effectiveness, and application technique of the modifications within each
 stage of control depend  heavily on the fuel and firing type.  For example, testing  has shown that
 FGR  does not significantly  reduce fuel N0x, so this technique is usually  not  cost-effective for
 coal-fired units.   Also, such techniques  as BOOS or OFA  are implemented differently on wall-fired
 than  on tangentially-fired  units due  to  burner configuration and hardware differences.
        The practical limits on the modifications are based initially on three  subjective criteria:
 emission of other pollutants (i.e., CO,  smoke, and carbon in flyash), onset of  slagging or fouling
 and  incipience  of flame  instability at the burner.  When problems are encountered, implementation
 is halted  and  the situation reevaluated.   Stack gas sampling for NO , CO, and 0- is usually car-
                                                                    A           £
 ried  out concurrently during compliance  tests.  In the long term, the effects of the modification
 on such  factors as  burner condition, furnace slagging and corrosion, ability  to change fuels, and
 boiler  load are monitored to varying degrees.
       The  remainder of this section describes recent combustion modification experience on gas,
 oil and  coal-fired  boilers.

 Gas-Fired Boilers
       The highest degree of success  in reducing  N0x by the  application of combustion  modifications
 has been obtained on gas firing.   The  reason for  this  effectiveness  lies  in the  fact that all  of
 these techniques reduce thermal  NOX, which is  the  only NOX formation mechanism in  gas  combustion.
       Low excess air operation  has  been  shown to  be extremely effective  in lowering NO   emissions
from gas-fired  boilers.   An extensive  1971 study of  NOX  reduction  techniques applied to  six wall-
fired utility boilers showed reductions of 25  to 60  percent  at full  load.   The NO   reduction mag-
 nitude depends  not only on  final excess air level, but also  on furnace  design  and  firing  method
 (Reference 4-3).
x
                                                4-6

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 73    78    82  105  110   121    160     160     160  180
                         FURNACE SIZE (ELECTRICAL), MW
230
250
418   550
Figure 4-1.  NOX emissions from gas, tangentially-fired utility boilers (Reference 4-6).
                                       4-8

-------
        In  1972,  a  West Coast  utility obtained a 23 percent NOX reduction on a 750 MW* horizontally
 opposed unit  as  a  result of lowering excess air.  Off-stoichiometric firing and flue gas recircula-
 tion  were  subsequently implemented on this unit to achieve over 50 percent further reduction
 (Reference 4-4).   In other early work a 33 percent NOX reduction on a 250 MW* tangentially-fired
 utility boiler was obtained when the flue gas oxygen content was decreased from 3.9 percent to 0.6
 percent (Reference 4-5).  In  most cases, LEA was implemented without serious flame stability pro-
 blems,  and a  slight increase  in thermal efficiency was noted.
        From  both full and pilot scale results,  flue  gas  recirculation  (F6R) has been proven effec-
 tive  for lowering  NOX formation from gas combustion.   In  general, NOX  reduction figures range from
 20 to 60 percent for various  boiler designs and load conditions.  NOX  reductions are substantial up
 to 20 percent FGR; further recirculation yields only marginal additional reduction.  Subscale test-
 ing has shown that the magnitude of NOX reduction is mainly dependent on the amount of gas recircu-
 lated up to the  point of incipient flame instability and  other undesirable operating conditions.
 Some  references  which may be  scanned for further details  on FGR are References 4-3, 4-6, 4-7, and
 4-8.
        With gas  firing, off-stoichiometric combustion  (OSC) has been shown to be one of the most
 effective  means  of N0x control and also one of the easiest to implement.  Biased firing and burners
 out of  service (BOOS) are the most frequently used and most effective OSC methods.  Overfire air
 port  operation achieves less  reduction, particularly where biasing has already been implemented.
 N0y reduction figures of 25 to 58 percent were obtained on wall-fired utility boilers ranging from
 80  to 480  MW* when two-stage  combustion was applied (Reference 4-3).   Similar results were reported
 for gas-fired boilers in Southern California.   The effectiveness of off-stoichiometric combustion
 with gas firing  has been well  validated and documented (References 4-3, 4-6, and 4-9).
       The effectiveness of overfire air and flue gas recirculation on existing gas,  tangentially-
 fired boilers is shown graphically in  Figure 4-1.   The bar chart shows the variation  in uncontrolled
 emissions even among boilers of the same capacity and design.   Emissions from  five of the  boilers
 that exceeded the EPA's  standard of performance for new gas-fired sources,  86  ng N02/J  (0.2 lb/106Btu)
were reduced  below the standard by either overfire air or FGR.   The  data also  show a  trend toward
 higher emissions in larger units.   This  is  attributed to the  increase in thermal  NO  formation due
 to  the higher temperatures  resulting from the  higher volumetric  combustion  intensity  used  in  larger
boilers (Reference 4-6).
*
 electrical output rating
                                                 4-7

-------
  1600
   1400
  1200
oc
a
u
cc
   1000
   800
   600
   400
   200
O ORIGINAL FIRING METHOD
O REDUCED EXCESS AIR FIRING
A TWO STAGE COMBUSTION
OTWO STAGE COMBUSTION PLUS GAS
  RECIRCULATION THROUGH  BURNERS
                  200         400          600
                           LOAD (ELECTRICAL), MW
                                            800
1000
Figure 4-2.  Effects of NOX control methods on a gas, wall-fired utility boiler
(Reference 4-4).
                                   4-10

-------
       Figure 4-2 shows results from the modification of a 750 MW*, horizontally-opposed, wall-fired
unit firing gas.  At full load, a 90 percent NO  reduction was obtained using the combination of
staging and FGR.  These results also show that load reduction is effective for NO  control, but is
                                                                                 A
not favored because of economic considerations (Reference 4-4).  It should be noted that this 90
percent reduction is more a result of the extremely high uncontrolled NO  emissions (1400 ppm) for
this unit, than of any special control procedures used.  For units with more moderate uncontrolled
emissions, a 50 to 60 percent reduction is usually the upper limit.
       Water injection into gas-fired utility boilers has been tested to a limited extent.  A 50
percent maximum NOX reduction was demonstrated at full load for a 250 MW* tangentially-fired unit
when water was injected at a rate of 20 kg per GJ (45 lb/106 Btu) fired.  Boiler convective section
temperature increased by 139K (250F) and boiler efficiency dropped 5 percent.  The economic penal-
ties resulting from this method, as from reduced load or air preheat, make such techniques unattrac-
tive (Reference 4-5).
       A significant amount of work has been done on optimizing gas burner design for low NO  pro-
duction.   Of the three types of burners - spud, radial spud, and ring - the latter produce the
least NO , while the spud type yields the highest NO  formation.  In addition, burners which pro-
        /»                                           X
duce controlled, low turbulence, flames have been found to form lower quantities of NO .
       In summary, the effectiveness of NO  controls for gas-fired utility boilers has been ade-
quately explored.  Further investigation may not be warranted because the number of large gas-fired
utility and industrial boilers, small to begin with, is now declining rapidly due to the  present
natural gas supply shortage.  For example, several  West Coast utilities, the nation's largest users
of gas for this purpose, reduced from about 70 percent gas-firing in 1972 to less than 10 percent in
1974.  Low sulfur residual  oil is the predominant fuel to replace gas on the West Coast.
Oil-Fired Boilers
       Compared to gas-fired boilers, a generally poorer record of NO  reduction has been compiled
for oil-fired units.  This is due largely to reduced operating flexibility.   When firing  residual
oil, fuel NOX becomes an important contribution to the total NOX emission from a given unit, and the
individual  modifications are less effective and more complicated to implement.  Nevertheless, sub-
stantial  reductions have been achieved, in some instances as high as 60 percent on utility boilers.
       The most popular N0y reduction techniques for both new and existing oil-fired boilers include
overfire air ports, BOOS, flue gas recirculation, and combinations  of these  techniques.   Lowering
*
 electrical output rating
                                                  4-9

-------
   600
   500
   400
u
X
u
cc
C/5

00
cc
a
 X
o
300





230


200
   100
                                         NORMAL OPERATION

                                         OVERFIRE AIR


                                         GASRECIRCULATION


                                         GAS RECIRCULATION AND

                                         LOW EXCESS AIR

EPA STANDARD
   FOR NEW

  OIL-FIRED

   BOILERS
         71   78  79  84  84  89  160   160    160    180  230 289 300  378   380  400


                               FURNACE SIZE (ELECTRICAL), Mw


      Figure 4-3. NOX emissions from residual oil, tangentially-fired utility boilers
      (Reference 4-6).
                                           4-12

-------
excess air is now considered a routine operating procedure and is incorporated in all new units.
Overall response to the control techniques among boilers, even of the same size and design, can
differ significantly.
       For wall-fired units use of overfire air ports alone results in NO  reductions of about 15 to
20 percent.  For both wall- and tangentially-fired units, BOOS is implemented by removing from ser-
vice several burners in the upper part of the firing pattern.  This technique results in NO  reduc-
tions of 25 to 35 percent.  Flue gas recirculation, in which 15 to 25 percent of the combustion air
is recirculated flue gas, has given NOX reductions of 10 to 45 percent.  However, control effective-
ness is usually extended when F6R is combined with the other techniques.  BOOS and F6R give total
N0y reductions of 40 to 60 percent, although derating is sometimes necessary to reach these levels
(References 4-3 and 4-10).
       The combined use of overfire air and BOOS operation reduces NO  only marginally.   Smoke thres-
holds are higher and excess air levels must be slightly increased, which cancels the effects of the
overfire air.  However, if boiler load is reduced, lower first stage stoichiometries are permitted
and further N0x reductions are achieved with BOOS and OFA.
       The effectiveness of overfire air, flue gas recirculation, and their combination  on existing
oil, tangentially-fired boilers is shown graphically in Figure 4-3.   Emissions from four of the
boilers that exceeded the EPA's performance standard for new oil-fired sources, 129 ng N02/J,
(0.3 lb/106 Btu)  were reduced below the standard by use of either overfire air or FGR.
       Figure 4-3 also shows the influence of fuel NOV on the total  NO  production.   Unlike the data
                                                     *                x
for gas-fired units shown previously in Figure 4-1, there is no discernible trend toward higher
emissions from larger units.  Apparently, emissions are largely dependent on fuel  nitrogen content.
For example,  the  160 MW (electrical)  unit with an emission rate of 600 ppm was fired with a high
nitrogen (1 percent) California residual  oil,  while the other two 160 MW units used  oil  with a nitro-
gen content of only 0.3 percent.   The 45 percent difference in emissions can be attributed to higher
fuel NOX formation.   In addition,  the figure shows that FGR reduced  total  NO  from the oil-fired
boilers by only 30 percent, compared  to 70 percent from gas-fired units.   This is  because FGR
reduces thermal  NO  but is relatively ineffective on fuel  NO .
                  **                                         x
       Figure 4-4 shows results with  oil  firing from modifying the same wall-fired unit  depicted in
Figure 4-2.  The  combination of staging and FGR produced only a 50 percent NOX reduction, compared
to 90 percent on  gas.   Again,  this difference  is attributed mainly to the  influence  of fuel  NO
(Reference 4-4).
                                                4-11

-------
        Some experimental  work has been  performed  with  injecting  water  into  the  combustion  air  of  oil-
 fired boilers.   Spraying  water at a  rate of about 0.6  kg  per  kg  of oil  reduced  emissions about 40
 percent.   The effectiveness  of FGR is increased when combined with water  spraying,  but  the latter
 increases the minimum excess air  requirement while FGR alone  does  not.  In  addition,  the energy loss
 is significantly greater  for water injection as compared  to FGR  to obtain equal NO  reduction.  For
 these reasons,  water injection is not a  popular NOX control method.
        Operational  problems  associated with NOX control techniques on  some  oil-fired  boilers include
 degraded  flame  detection,  flame instability, boiler vibration, and limited  load capability.  Combin-
 ing FGR with BOOS has in  some cases  made existing flame scanning equipment  inadequate (Reference  4-6).
 BOOS and  FGR can also cause  flame instability.  Increasing the fuel flow  through the  burners left in
 service causes  significant changes in flame quality and stability.  Flame stability is  further  de-
 graded  by the increased burner throat velocities  resulting from  the addition of flue gas recircula-
 tion.   These factors  have  been  largely responsible  for flame  pulsations that cause boiler  vibration
 in some units using  large  rates of gas recirculation.
        Limited  load capability  can result from the  retrofit application of BOOS and FGR due to  the
 limited fuel/air handling  capacity of existing burners and distribution equipment.   Load reductions
 of 10 percent have been experienced with burner modifications.  Additional capacity requirements in
 the  form  of  a forced  draft fan  are also  imposed by FGR.
        There  are  several subtle factors that influence NOX emissions regulation compliance.  Among
 them are  operational  flexibility, fuel properties, and boiler cleanliness  (Reference 4-2).   Since
 boiler  operating  conditions are variable, the chosen low NOX operating mode must be flexible enough
 to allow  some latitude during periods of adverse operating conditions.   Equipment problems  may  occur
 somewhat  more frequently due the the fine tuning needed for NO  control (Reference  4-11).
       Variations in fuel  supply are the second important factor influencing regulation  compliance.
Residual oil fuel nitrogen content can vary between 0.2 and 1.0 percent.  Typically,  the conversion
of fuel nitrogen is  in the range of 20 to 40 ppm NOX per 0.1 percent fuel  nitrogen.  Other  fuel  oil
properties influence operating conditions such  as  smoke threshold,  atomization characteristics  and
excess air level for stable combustion.
       Boiler cleanliness appears  to be another important  factor  influencing  NO   emissions.   Indica-
tions are tha. up to a 50 ppm increase in NOX emissions  can  be  attributed  to  furnace  deposits  in  the
radiant section.   This is attributable to higher flame temperatures needed as a result of the  low
radiant heat transfer condition  incurred with deposits (Reference 4-2).
                                               4-14

-------
  400
  300
cc
a
r>g
o
o
oc
  100
           O ORIGINAL FIRING METHOD


           O TWO STAGE COMBUSTION


           A TWO STAGE COMBUSTION PLUS GAS

             RECIRCULATION THROUGH BURNERS
    200
400                 600


  LOAD (ELECTRICAL),MW
800
 Figure 4-4. Effects of NOX control methods on an oil, wall-fired utility

 boiler (Reference 4-4).
                                  4-13

-------
       In field tests, existing wall-fired boilers  under full  load  baseline operation  generally  pro-
duced NO  emissions that exceeded the NSPS for new  boilers.   However,  under modified operation using
low excess air and staged firing, NOX was reduced about 20 to 40 percent and the  boilers  were able
to meet the new unit standard.   Additional reductions were possible in some cases when the  load  was
reduced about 20 percent.  One  270 MW (electrical)  wall-fired boiler,  after being fitted  with a
specially-designed "low NOX"  burner,  obtained a NOX reduction of 35 percent (Reference 4-12).
       Flue gas recirculation has also been tested  on a wall-fired  boiler (Reference 4-13).  Apply-
ing 15 percent windbox FGR to a 560 MW (electrical) unit resulted in a 13 to 17 percent NOX reduc-
tion under normal, air-rich,  conditions.   When applied in conjunction  with OFA, FGR yielded a 7  per-
cent NO  reduction to augment the 33  percent reduction from OFA alone.  The reduction  obtained from
FGR alone is, however, less than half of  that normally obtained on  oil firing.  It appears  that,
due to the influence of fuel  NOX formation, FGR is  generally less effective for coal firing than
for gas and oil firing.  FGR may be justified if minor emission reductions (i.e., "trimming") are
necessary to achieve compliance with  a stringent emission standard  for existing units.
       Under baseline conditions, tangentially-fired boilers usually emit less NOX than wall-fired
boilers.  For example, of the 16 units shown in Figure 4-5,  10 meet the NSPS with no modifications.
For those that do not meet the regulation, overfire air, burner staging, and low  excess air tech-
niques can be used to reduce NOV by an average of 40 percent.
                               A
       A measure of the degree of control implemented with off-stoichiometric combustion  is given
by the value of the first stage burner stoichiometry.  Figure 4-6 shows the relationship  of NOX
reduction with stoichiometry to the active burners  for 13 tangential,  coal-fired  boilers  (References
4-3, 4-12, 4-14, 4-15, 4-16,  and 4-17).  The best-fit line illustrates that NOX emissions in general
are reduced approximately 140 ppm for each 10  percent reduction in burner stoichiometry.  It was
also discovered that an optimum burner tilt angle exists from a NOX formation standpoint.  Hori-
zontal burner operation reduced NO  emissions by 18 percent, while  lowering burner tilt to  -26
percent increased NO  emissions to 9  percent above  baseline  operation  (Reference  4-12).
       Several utility boiler tests have  been conducted using the combined firing of gas/coal and
oil/coal as a NOX reduction strategy.  Tests on the former mixture  were conducted on a 130  MW
(electrical) tangential unit.  Firing with 80 percent of the heat release from coal reduced NO   by
an average of 30 percent, while firing with 60 percent coal  and 40  percent gas resulted in  a 32
percent NOX reduction from 100 percent coal firing.  The data indicate that replacing  coal  with  gas
fuel lowers NO  in the direction of 100 percent gas firing,  but the relationship  is not linear.
                                                 4-16

-------
         In general, an estimate of the boiler's actual operating conditions should be made in order
  to assess all factors that may influence regulation compliance.  It is best to have at least a 25
  to 35 ppm margin under average conditions (References 4-2, 4-3, 4-4, and 4-10).
  Coal-Fired Boilers
         The retrofit implementation  of NOX controls  on coal-fired boilers is  currently  less wide-
  spread than  on gas- and  oil-fired units.   Due  to  the  continuing clean  fuels  supply  shortage,  however,
  the development  of control  for coal-fired units is  receiving  primary emphasis  in  the research  and
  development  programs  of  the Environmental  Protection  Agency's  Industrial  Environmental Research
  Laboratory at  Research Triangle Park.  Major developmental activity  to date  has been focused on
  achieving the  level of control for new units mandated by the Standards of Performance for New  Sta-
  tionary Sources -  300 ng N02/J (0.7 lb/10* Btu).  By contrast, the major  activity for gas and  oil-
  fired  units  has been on retrofit compliance with emission standards  for existing units in N0,,-sensi-
  tive Air Quality Control  Regions.   Nearly all new utility boilers currently being installed,  or on
  order, in the U.S.  are designed to use coal as the primary fuel.

        The combustion  characteristics  of  a solid fuel  such  as  coal  are  vastly different from  either
 gas or oil, and the NOX control  strategy  varies accordingly.   For the cleaner fuels,  thermal  NO
 formation  mechanism dominates;  certain sets of  combustion modification  methods  have  been  found  to  be
 well suited to  suppress this problem.   For coal, however, up to 80  percent of total  oxides of  nitro-
 gen comes  from  fuel-bound nitrogen.  Researchers have  found that  combustion modification  methods
 that were  effective on gas and  oil firing  either do  not work as well  or must  be applied differently
 on  coal-fired boilers.  In addition, operational problems associated  with  the modifications, such
 as  slagging,  fouling, and carbon burnout,  are more pronounced.
        The most extensive series of tests  performed  on coal-fired boilers  has been sponsored by the
 EPA and the Electric Power Research Institute.  The  combustion modification methods tested include
 lowering excess air, off-stoichiometric combustion,  biased firing, a  "low N0x" burner, and flue gas
 recirculation.  Coals tested include both Eastern and Western bituminous and Western sub-bituminous.
       The sequence of combustion modification implementation is similar to that for gas and oil
 firing.  First, the boiler is fine tuned by minimizing excess air to the threshold of excessive CO
 and unburned hydrocarbon formation.  If the NOX reduction obtained by such a  procedure is  inadequate,
off-stoichiometric techniques,  such as  biased  firing  and burners on air  only,  may  be  utilized.   The
hardware retrofit methods  are the last  to  be used.  These include overfire air ports  and "low  NO "
burners.
                                               4-15

-------
   700
   600
   500
CM
o
o
X
  400
o
cc
£2
CO
a  300

 x
o
   200
  100
     60
80              100              120              140


         STOICHIOMETRY TO ACTIVE BURNERS, percent
160
 Figure 4-6.  Effect of burner stoichiometry on NOX production in tangential, coal-fired boilers.
                                               4-18

-------
    II NORMAL OPERATION

        TOP ELEVATION NOT FIRING - NO OVERFIRE AIR

       TOP ELEVATION FIRING - OVERFIRE AIR
 EPA STANDARD
 FOR NEW COAL
 FIRED BOILERS
52
100   110 122    170    206
(80)*           (157)*
                                 215
                                (158)
250    250    265  370 375 378 426  485   565
                          FURNACE SIZE (ELECTRICAL), MW
                 *REDUCED RATING WHEN TOP ELEVATION NOT FIRING

  Figure 4-5.  NOX emissions from tangential, coal-fired utility boilers (Reference 4-6).
                                 4-17

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            TABLE 4-3.   MAJOR JAPANESE DRY FGT  INSTALLATIONS
                        (Selective Catalytic Reduction)  (Reference  4-21)
Process
Developer
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Sumitomo Chemical
Hitachi Shipbuilding
Hitachi Shipbuilding
Hitachi Shipbuilding
Tokyo Electric-
Mitsubishi H.I.
Kurabo
Kurabo
Kansai Electric-
Hitachi Ltd.
Chubu-IHI-Mitsui Toatsu
Chubu-MKK
Mitsubishi H.I.
Kobe Steel
Mitsui Toatsu
Mitsui Toatsu
Mitsui Toatsu
Mitsui Toatsu
Hitachi Ltd. -
Mitsubishi P.C.
Hitachi Ltd.
Ube Industries
Mitsui S.B. - M1tsu1 P.C.
Mitsui S.B. - Mitsui P.C.
MKK - Santetsu
MKK - Santetsu
MKK - Santetsu
Seltetsu Kagaku
Japan Gasoline
Japan Gasoline
Asahi Glass
Capacity
(Nm'/hr)
30,000
200,000*
250,000*
100,000*
200,000*
200,000*
250,000
300,000
5,000
350,000
440,000
10,000*
5,000
30,000
4,000

8,000
100
4,000
600
1 ,000*
3,000
4,000*
8.000*
150,000

350,000
10,000
200,000
240,000
1,500
1,000
15,000
15,000
50,000
70,000
70,000
Source of Effluent
011 -fired boiler
Heating furnace
Heating furnace
Gas-fired boiler
Gas-fired boiler
Heating furnace
Oil -fired boiler
Oil-fired boiler
Oil-fired boiler
CO-fired boiler
Oil-fired boiler
Gas -fired boiler
011 -fired boiler
Oil -fired boiler
Oil-fired boiler

Oil-fired boiler
011 -fired boiler
Oil-fired boiler
Sintering plant
Gas-fired boiler
Oil -fired boiler
Gas-fired boiler
Gas-fired boiler
Oil-fired boiler

Coke oven
Oil -fired boiler
011 -fired boiler
Oil -fired boiler
011 -fired boiler
Coke oven
011 -fired boiler
011 -fired boiler
Heating furnace
CO boiler
Glass furnace
Completion
Date
Jul 1973
May 1974
Mar 1975
Feb 1975
Feb 1975
Mar 1975
May 1976
May 1976
Nov 1973
Nov 1975
Nov 1975
Jan 1974
Nov 1973
Aug 1975
Jan 1975

Oct 1974
Oct 1974
Dec 1974
May 1974
Oct 1973
Oct 1974
Oct 1974
Jun 1974
Dec 1975

Oct 1976
Jan 1975
Sep 1975
Aug 1976
Dec 1974
Mar 1975
Jun 1976
Jun 1975
Nov 1975
Mar 1976
Apr 1976
*C1ean gas; others are for dirty gas
                                   4-20

-------
  Similar results were obtained with the oil/coal  mixed  fuel.   Further NOX  reductions  were  possible
  when mixed fuel firing was  combined with  techniques  such  as  lowering excess  air,  off-stoichiometric
  combustion,  and reduced load  (Reference 4-12).
         Throughout  the developmental  field  tests, attention was  given to the  potential side effects
  of low NOX operation.   Excessive smoke and CO levels generally  limit the  extent to which  the burners
  are fired  fuel-rich.   The fuel-rich  conditions can lead to flame instability, and the reducing atmos-
  phere in the primary  combustion zone can accelerate tube  corrosion and slagging (Reference 4-18).
  One utility  company reported experience with retrofit biased firing  on a  coal-fired boiler.  The
  problems included  increases in carbon  losses, decreases in boiler efficiency of about one percent-
  age  point at all load  levels, and increases in tube wastage on the sidewall near the biased burners
  (Reference 4-19).  The EPA is conducting long-term field tests to determine the extent to which OSC
  accelerates tube wastage.  Corrective measures to suppress tube wastage are also being examined.
 One  utility boiler manufacturer uses a "curtain  air"  oxidizing atmosphere  at the tube walls  to  sup-
 press wastage (Reference 4-20).
 4.1.1.2  Flue Gas Treatment
        The  major NOX  control  emphasis in the  United States has been  on process  modification  since
 it permits  the  construction  of new  equipment  that can meet existing  emission  standards.   Due mainly
 to economic penalties, a less  intensive effort has been  devoted  to removing nitrogen  oxides direct-
 ly from flue  gases.   However,  faced  with emission standards 20 to 40  percent  more  stringent than
 those in the  U.S.,  Japanese  industry  has been much more  interested in flue gas treatment  (FGT) and
 has several major pilot plants  and full-scale plants in  operation.  The major application  of flue
 gas treatment in Japan  has been to utility  boilers and the larger combustion  and noncombustion
 industrial  point sources of NOX.  More  inexpensive alternatives, such  as process modifications,
 will  continue to be used for smaller  combustion sources of NOX, although regulations could eventu-
 ally  require  the use of FGT as well.
       As described in  Section 3.2,  the two FGT process routes can be categorized as dry processes
 (reduction) and wet processes (oxidation followed by scrubbing).   In  Japan, dry processes are the
more  popular of  the two types, and these usually  involve the use of the selective catalytic reduc-
tion  process  (SCR).   Table 4-3 shows the SCR processes on conmercial  and pilot plants  in  operation
or under construction in Japan.
       Most of the larger installations treat  only "clean"  exhaust gas from the  combustion  of
gaseous fuels.  However, two  large plants being constructed by Sumitomo Chemical  and Hitachi
                                               4-19

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TABLE 4-4.  MAJOR JAPANESE WET FGT INSTALLATIONS  (Reference  4-21)
Process Developer
Sumitomo Metal
Fuji Kasul (Moretana)
Sumitomo Metal
Fuji Kasui (Moretana)
Sumitomo Metal
Fuji Kasui {Moretana)
Chiyoda
Osaka Soda
Shirogane
Mitsubishi H.I.
Ishikawajima H.I.
Tokyo Electric
Mitsubishi H.I.
Tokyo Electric
Mitsubishi H.I.
Kawasaki H.I.
Mitsubishi Metal
MKK, Nihon Chem.
Kobe Steel
Kobe Steel
Hissan Engineering
Hissan Engineering
Hodogaya
Chisso Corporation
M1tsu1 S.B.
Asa hi Chemical
Kureha Chemical
Type of Process
Redox
Redox
Redox
Redox (102 process)
Redox
Redox
Redox
Redox
Oxidation
absorption
Oxidation
absorption
Oxidation
absorption
Absorption
oxidation
Absorption
oxidation
Absorption
oxidation
Absorption
oxidation
Absorption
oxidation
Absorption
oxidation
Reduction
Reduction
Reduction
Reduction
Capacity,
NmVnr
62,000
100,000
39,000
1,000
60,000
48,000
2,000
5,000
2,000
100,000
5,000
4,000
1.000
50,000
1,800
3,000
4,000
300
150
600
5,000
Source of Effluent
011 -fired boiler
Metal heating furnace
01l-f1red boiler
01l-f1red boiler
Oil-fired boiler
Oil-fired boiler
Oil-fired boiler
Oil-fired boiler
Gas-fired boiler
Gas -fired boiler
Coal -fired boiler
Oil -fired boiler
Iron ore sintering furnace
Iron ore sintering furnace
Pickling
HNOa plant
Iron ore sintering furnace
011 -fired boiler
011 -fired boiler
011 -fired boiler
011 -fired boiler
Completion
Date
Dec 1973
Dec 1974
Dec 1974
1973
Mar 1976
Aug 1974
Dec 1974
Sep 1975
Dec 1973
Oct 1974
Dec 1975
Dec 1974
Dec 1973
Mar 1976
Jul 1973
Mar 1975
Oct 1975
1974
1974
1974
Apr 1975
By-product
NaN03, Nad
Na2S04
NaN03, NaCI
Na£S04
NaN03. NaCI
Na2S04
Gypsum,
Ca(N03)2
NaNOs, NaCI
Na2S04
Na2S04,
NaN03
Gypsum, N2
Gypsum, N2
HN03
HN03
Gypsum,
Ca(N03)2
KN03
Gypsum, N2
Gypsum, N2
NaN02
NaN03, NO
NaN03, NaCI
(NH4)2S04
H2S04, N2
Gypsum, N£
Na2S04, N2
                             4-22

-------
 Shipbuilding companies will treat "dirty" gas (containing S0x and participate)  from oil-fired  sources
 A pilot plant treating dirty gas (oil-fired) has been operated by Sumitomo for  over 4,000 hours
 reportedly without serious problems.   Electrostatic precipitators remove dust and  prevent contamina-
 tion of the catalyst.   More than 85 percent NOX removal  has  been achieved (Reference 4-21).
        Several  EPA contractors have investigated SCR on  both the lab  and pilot  scales.   Emphasis was
 on technical and economic assessment  of various catalytic processes,  using both noble and nonnoble
 catalyst systems.  These tests achieved NOX reduction of 60  to 95 percent at  inlet concentrations
 of 250 to 1000  ppm.  They also indicated that platinum is not a satisfactory  catalyst for flue gases
 containing SOp.
        Although  selective catalytic reduction has  been the most widely  used and investigated dry FGT
 process,  selective noncatalytic  reduction of NOX using ammonia has also  been  demonstrated commer-
 cially in Japan.   NOX  reductions  of 70  percent have  been  reported.  Investigation  of this  technique
 is underway in the U.S.  as  well.  Barriers  to its  use on  steam generator  exhaust include  reducing
 agent  injection  problems, load following, byproduct emissions,  and high reducing agent use and cost.
 The  attractiveness of  this  technique may  improve as more  accurate assessment of these problems are
 developed (References  4-22  and 4-23).
        Wet  systems generally have not been  as  popular as  dry processes.  Major disadvantages of wet
 systems are (1)  the need  for expensive  oxidizing agents and/or  energy input in proportion to the
 quantity  of N0x  removed',  (2) generation of  unmarketable byproducts, (3) waste water  production, and
 (4)  requirement  of prior  S02 removal to reduce the consumption  of N0x-removal  chemicals.  Its poten-
 tial major  advantage,  however, is simultaneous NOX and SO  removal.
       As with the dry process, most of the research, development and demonstration of wet pro-
 cesses has  been conducted in Japan  (Reference 4-21).  In  1975, there were 12 different wet pro-
 cesses being developed  in Japan at pilot plants and small commercial  plants (100 to 25,000 cubic
meters per  hour).  The  largest systems reportedly are treating 32,000 to 1,000,000  cubic meters
per hour of flue gas.   No firm data  are available as to NOX removal  efficiencies, but the range
appears to be from 60 to 90 percent.  Table 4-4 lists plants  in Japan  using wet  FGT systems.
       Two of these processes,  the Chiyoda 102 and the Mitsubishi Heavy  Industries  Systems, are
relatively simple extensions of well-established flue gas desulfurization (FGD)  technology.   Both
processes are attractive from the standpoint of simultaneously removing  SO  and  NO  .   However,  both
                                                                          X      X
require the use  of ozone.  Ozone production for application to coal-fired flue gas  is expected  to
require up to approximately 10  percent of the power plant electrical output.   When  added  to the
                                                4-21

-------
 the use of coal  as well.   Fuel  switching  to  natural  gas  or  low nitrogen oil  is, therefore, not a
 promising short-term option.
        A promising long-range option  is the  use of synthetic fuels derived from coal.  Candidate
 fuels  include  lower Btu gas  (3.7  to 30 MJ/Nm3, or 100 to 900 Btu/scf) and synthetic liquids or
 solids.   Although  these fuels would have  all the emission control advantages of conventional clean
 fuels,  there are several disadvantages associated with them.  First, economic considerations favor
 the placement  of both  the  gasifier and the power cycle at the coal minehead.  This fact eliminates
 existing utility boilers without  an onsite coal supply as users of lower-Btu gas.  Second, the cost
 of  required equipment  modification to lower-Btu gas  is high, ranging from $5 to $15/kW*.  Third,
 although synthetic  oil can be transported like conventional oil, the coal conversion process is
 highly,  and perhaps  prohibitively, expensive (Reference  4-24, 4-25).
        In  general,  the feasibility of coal-derived fuel  switching is dependent on the cost tradeoff
 between  the coal conversion route and more conventional  means of controlling the criteria pollu-
 tants  (i.e., gas cleaning).  The  economics of the former alternative are not well defined at pre-
 sent and will  not  be clear until  the ongoing studies and pilot projects are completed (Reference
 4-26).

 4.1.1.4  Fuel Additives
       The basis of this control technique was covered previously in Section 3.1.4.  In general, fuel
 additives are not effective.   Most of the additives that have been tested do not decrease NO
 emissions, and some  that contain  nitrogen actually increase NOX formation.  Several additives con-
 taining  metallic compounds were found to promote the catalytic decomposition of NO and N2.  However,
 serious  operational difficulties, high cost, and the presence of the additive as a pollutant in the
 exhaust  made these additives unattractive (Reference 4-27,  2-28).
       Other fuel additives investigated recently are intended to prevent boiler tube fouling.   Use
 of  these additives could conceivably allow a further decrease in excess  air which would reduce  NO
 formation.  However, the emission reduction from this method is quite limited and the cost-effec-
 tiveness is likely to be poor (Reference 4-29).
 4.1.2  Costs
       The cost of implementing  the preceding NOX  reduction  techniques  is  basically the sum  of  the
 initial capital cost and annual  operating  cost  (which includes  any cost  savings).   The  following
*
 electrical output
                                               4-24

-------
 power requirement  of  the  FGD  portion of  these processes, this energy consumption may render wet simul-
 taneous  SO  /NO   processes impractical  for commercial  use.
       In general, therefore, wet NOX  FGT systems cannot compete with dry selective catalytic reduc-
 tion  where  simple  NOX control is involved.  For coal-fired applications where high dust loadings
 and S02  removal  are involved, it is not  as yet clear whether dry FGT combined with conventional FGD
 processes will be  cheaper than wet simultaneous SO/NOv systems.  Other dry simultaneous SO /NO
                                                  AX                                    XX
 systems, such as the  Shell and the Sumitomo Shipbuilding processes, may also prove to be cheaper
 than  the wet simultaneous processes.  At present, the Shell process is being commercially applied
 on a  40  MW  (electrical) oil-fired boiler in Japan and is being piloted in the U.S. on a 0.6 MW
 (electrical) flue  gas stream  from a coal-fired boiler.  The Sumitomo Shipbuilding process is being
 tested on an oil-fired boiler in Japan.
       In summary, wet FGT processes are more expensive and less well developed than dry processes.
 Considering their  cost and complexity, it is doubtful that wet processes would be receiving any
 development attention in  Japan were it not for the potential for simultaneous SO  and NO  removal
 (Reference 4-65).
 4.1.1.3  Fuel Switching
       The aim of this technique is to switch the combustion system to a fuel  with a reduced nitro-
 gen content (to suppress  fuel  NOX)  or to one that burns at a lower temperature (to reduce thermal
 N0x).   Switching decisions are based on the knowledge that solid fuels generally contain more organ-
 ically-bound nitrogen than liquid fuels, and gaseous fuels are usually nitrogen-free.   Coal-fired
 utility boilers, unless they already have a dual  fuel capability, can be converted either to oil  or
 gas.   Likewise,  oil-fired boilers can be switched to gas fuel.   Due to design  limitations,  however,
 the reverse order of  these conversions is generally not practical.
       During the 1960's and early  1970's many Eastern and Midwestern U.S.  coal-fired  utility
 boilers were converted to oil  and/or gas in response to tightened particulate  and S02  emission
 standards.   This trend was attractive from a NOX  control standpoint for two reasons.   First,  liquid
and gaseous fuel  firing provides more flexibility for implementing  combustion  modification  techniques.
Second, fuels containing less  sulfur generally contain less nitrogen also,  which serves  to  reduce
fuel  NOX.
       Despite the superiority of oil-  and gas-fired NOX control, the economic  considerations  in
fuel  selection are dominated by the current clean fuel  shortage.  Existing  utility  boilers are cur-
rently returning to coal,  and  the trend for new utility and industrial  boilers  is strongly toward
                                               4-23

-------
   1.00
   0.75
 10.50
 CO
 o
 o
  1.50
  1.25
  1.00
  0.75
CO
O
CJ
                                                               A. NEW BOILER INSTALLATION
4WINDBOX FURNACES
                                                                8WINDBOX FURNACES
              200
              400                 600

                  UNIT SIZE (ELECTRICAL), MW
                                                                        800
1000
  0.50
  0.25
                                                          B. EXISTING BOILER MODIFICATION
                                400                 600

                                     UNIT SIZE (ELECTRICAL), MW
                                                                       1000
 Figure 4-7. 1975 capital cost of overfire air for tangential, coal-fired boilers (Reference 4-27).
                                                 4-26

-------
 discussion will center on  the costs of reducing NOX from utility boilers by combustion modification
 and  flue  gas  treatment.  In several cases the costs presented are for combined "NOX controls.  Gener-
 ally,  the effectiveness of combined NOX controls is not equal to the sum of the individual effects
 of each control.  Likewise the cost of combined controls is not the sum of the costs of single con-
 trols.  The cost of fuel additives is not discussed due to its status as an unattractive option and
 to a general  lack of cost  data.  Fuel switching economics are similarly not treated in this dis-
 cussion.
 4.1.2.1   Combustion Modification
       Much of the pioneering work on evaluating the cost effectiveness of combustion modification
 in full-scale combustion equipment has been performed on utility boilers.  Correspondingly, the
 related costs of these modifications have been fairly well documented compared to other source types.
 One  of the earliest efforts of this kind was attempted by Esso Research Labs in 1969 (Reference
 4-30).  Based on estimates for the capital, annual, and operating costs, the Esso report presented
 the  results of a cost effectiveness study performed for NO  control on utility boilers by means of
 combustion modification.  Since 1969, however, it has been revealed that a wide variation in the
 effectiveness of the control techniques among boilers exists.   This problem will require that con-
 tinuing cost-effectiveness evaluations be done on an individual boiler basis.
 Data from Combustion Engineering
       The most recent cost data were published in Reference 4-31  for new and existing tangential,
 coal-fired utility boilers.  These data are summarized in Figures  4 - 7a and b.  The cost range curves
were derived from estimates developed under an EPA-sponsored contract involving the reduction of NO
 from both new and existing tangential  coal-fired utility boilers.   The costs are for the com-
bined use of overfire air ports  and low excess air firing,  as  this is the preferred control  system
for tangential,coal-fired boilers.   Capital  costs  were projected over a unit size  range of 25 to
 1000 MW*.   The corresponding annual operating costs for 500 MW* units was 0.006 mills/kWh for a new
unit and 0.021 mills/kWh for existing units.   Figure 4-7a applies to new unit designs  with heating
surfaces adjusted to compensate  for the resultant  changes in heat  transfer distribution and  rates.
Figure 4-7b applies to existing units with no change in heating surface, as these changes must be
calculated on an individual unit basis.
*
 electrical output rating
                                               4-25

-------
 Data from the Pacific Gas and Electric Company
         As an example of the manner 1n which the costs  for combustion  modification may  vary  among
 individual existing units, several  case studies are presented  in  Table 4-6.   The  numbers  shown  are
 the costs incurred by the Pacific Gas and Electric Company during a  program  to  bring  six  units  into
 compliance with local NO  emission regulations.  For the most  part,  the conversions involved the
 combination of windbox flue gas recirculation and overfire air ports.   The average cost of the  modi-
 fications is about $10/kW* (Reference 4-32).
Data from the Los Angeles Department of Water and Power
        Another West Coast electric utility company, the Los Angeles Department of Water and Power
(LADWP), has had extensive experience in implementing NOX control techniques on its gas- and oil-fired
boilers.  The techniques currently utilized by the Department include burners out of service (BOOS),
overfire air ports, and low excess air.  Although the units are operated with the lowest excess air
possible, it has been found that when LEA is combined with other reduction methods, excess air levels
must be increased beyond those normally required.
        The Department's data indicate a unit efficiency decrease of approximately one percent attri-
butable to BOOS operation.  As has been found by other operators, LEA tended to increase efficiency
slightly: a one percent decrease in excess oxygen increased efficiency by about 0.25 percent.   Pro-
perly retrofitted, overfire air had no effect on efficiency.
        The NOX control  costs incurred by LADWP are shown in Table 4-7 for four different units.   The
figures for the BOOS techniques reflect the R&D costs that necessarily precede the retrofit.   All
costs include the labor required to implement the control methods, and are, therefore,  installed  equip-
ment costs.   The very low expense associated with overfire air on the B&W 235 MW*  unit  is due  to  the
base year of the estimate (1964 to 1965)  and to the fact that this modification was included  in the
original boiler design.
        The overfire air costs for the B&W 235 MW* unit lie in the low range of the appropriate band
of costs in Figure 4-7b. The LADWP boilers were, for the most part, modified without much difficulty,
and the associated costs probably represent the lower limits of the costs for the  three NO reduc-
tion techniques implemented (Reference 4-33).
 electrical  output  rating
                                                 4-28

-------
        It is readily observed that the cost ranges for existing units vary more widely than for new
units.  This is due to the variations in unit design and construction which can either hinder or aid
the installation of a given NO  control system.
       Above approximately 600 MW*. single cell-fired boilers exceed a practical size limit and
divided furnace designs are utilized.  Since a divided tangentially-fired furnace has double the
firing corners of a single cell furnace, the costs increase significantly.
       It should be kept in mind that although these cost data for utility boilers were developed
for tangentially coal-fired boilers, it is felt that the range of costs presented should also be
applicable to wall-fired boilers burning coal.  Additionally, the cost for similar combustion modi-
fication on gas and oil-fired utility boilers should be no higher than for the coal-fired units.
       The cost of reducing low excess air was not investigated since there is generally no signi-
ficant additional cost for modern units or units in good condition.  However, some older units may
require modifications such as altering the windbox by addition of division plates, separate dampers
and operators,  fuel valving, air register operators, instrumentation for fuel and air flow and
automatic combustion controls.
Data from EPA
       Table 4-5 shows estimated investment costs for low excess air (LEA) firing on utility boilers
requiring modifications (Reference 4-1).   These costs can vary depending on the actual  extent of the
required modification and are only provided as guidelines.   As unit size increases, the cost per kW
decreases since the larger units typically have inherently greater flexibility and may require less
extensive modification.
       The use  of low excess air firing reportedly increases boiler efficiency by 0.5 to 5 percent.
Additional savings may result from decreased maintenance and operating costs.  Consequently, invest-
ment costs may  be offset in fuel  and operating expenses.

                  TABLE 4-5.  1974 ESTIMATED INVESTMENT COSTS FOR LOW EXCESS AIR
                              FIRING ON EXISTING BOILERS NEEDING MODIFICATIONS

Unit Size
(MW*)
1000
750
500
250
120
Investment Cost
($/kW*)
Gas and Oil
0.12
0.16
0.21
0.33
0.53
Coal
0.48
0.51
0.55
0.64
0.73
                   electrical  output  rating
                                               4-27

-------
             TABLE 4-7.  LOS ANGELES DEPARTMENT OF WATER AND POWER ESTIMATED INSTALLED  1974
                         CAPITAL COSTS FOR NOX REDUCTION TECHNIQUES ON GAS-  AND OIL-FIRED
                         UTILITY BOILERS (Reference 4-33)
Unit
Capacity
(MW)
180
235
235
350
Unit
Type
C.E.
wall -fired
C.E.
wall -fired
B&W Opposed-
fired
B&W Opposed-
fired
NOX Reduction
Technique
BOOS
LEA
BOOS
LEA
BOOS
Overfire air
LEA
BOOS
Overfire air
LEA
Implementation
Method
Retrofit
Retrofit
Retrofit
Retrofit
Retrof i t
Original Design
Retrofit
Retrofit
Retrofit
Retrofit
Estimated
Cost
($)
67,400
28,900
75,200
28,900
75,000
14,000a
28,900
266,000
100,600
28,900
$/kW
0.38
0.16
0.32
0.12
0.32
0.06
0.12
0.76
0.29
0.08
       1964-65 base year
Operating Cost Data
       In addition to the increased capital  costs from including a NO  reduction system in  new or
existing units, the increased unit operating costs may be considered.  These differential operating
costs were defined for 500 MW (electrical)  new and existing units and are shown in  Table 4-8
(Reference 4-31).  The costs are given in 1975 dollars, and the equipment costs shown  are determined
from Figures 4-7a and b.   To put these operating costs in perspective, they can be compared to the
percent increase in generating costs shown  at the bottom of Table 4-8.   Except  for  the case of older
units, the difference in operating cost is  below 0.1  percent of annual  cost.
      Table 4-9 shows the impact on major system components,  efficiency,  and capacity when  employing
the major combustion modification NOX control  techniques.   The relative changes  in unit design  or
efficiency are shown to increase (or require addition) by a plus sign (+) or decrease by a  minus  sign
(-).  If the item is unchanged, or is altered to a negligible extent, it is indicated by a  zero (0).
Heat transfer surfaces remain unchanged in all cases (Reference 4-1).
        The following are the major economic considerations that the boiler operator or designer  may
face:
            The lowest cost method for reducing N0y emission levels on new and existing units  is
            the incorporation of low excess air firing.   Minimal  additional costs  are involved.
            For most utility boilers, the second lowest  cost NOX  control  method appears to  be  staged
            combustion by biased firing, "burners out of service" (BOOS)  or addition of an  overfire
            air system.  Although lowering excess air (LEA)  alone is less expensive than off-stoi-
            chiometric combustion, one utility company has found  that when LEA is  implemented  con-
            currently with other control techniques, the excess air levels must be increased be-
            yond those normally required.
                                                4-30

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       •   Gas recirculation 1s significantly more costly to implement than overflre air  and
           requires additional fan power.   In existing units, the necessity t'o reduce unit
           capacity to maintain acceptable gas velocities through the boiler conventive
           sections may impose an additional  penalty.
       t   For coal-fired units, gas recirculation to  the coal  pulverizers  would  cost approxi-
           mately 15 percent less than windbox FGR; however, this may require increased excess
           air to maintain adequate combustion.  In any case FGR is not particularly effective
           in reducing total NOX emissions from coal-fired systems.
       t   Water injection involves moderate  initial equipment costs, but due to  high operating
           costs resulting from losses in  unit efficiencies, it is the least desirable of the
           NO  reduction techniques evaluated.
       •   In general, the cost of applying any of the control  methods to an existing unit  will
           be approximately two to three times that of a new unit design.
       •   Attention must be given to the  base year in which control cqst estimates were  made.
           Figures on comparative electric power equipment costs from the most recent Marshall
           and Swift Equipment Cost Index  (1974) indicate that such costs have increased  19
           percent from 1972 and 16 percent from 1973.  It is safe to assume that costs will  be
           correspondingly higher in subsequent years.

4.1.2.2   Flue Gas Treatment
       The flue gas treatment methods described in Section 3.2  included wet (oxidation followed  by
scrubbing) and dry (reduction) methods. Since most of these processes are  still  in the early
stages of development, definite costs are, for the most part, not yet available.   However,  preli-
minary cost estimates have been made and are  presented in Table 4-10.  These estimates indicate
that the capital and operating costs for some of these processes are comparable to existing flue
gas desulfurization (FGD) systems.

4.1.3  Energy and Environmental Impact
       In addition to affecting the cost of operating  electrical generating combustion equipment,
implementing NOX control techniques can also  impact overall plant efficiency and  emissions  levels
of pollutants other than NOX.  These energy and environmental impacts are discussed below.  The
discussion emphasizes potential Impacts due to applying combustion modification controls  as these
have been the most extensively studied and offer the greatest potential  for widespread use  in the
                                                4-33

-------
             TABLE  4-11.   EFFECTS  OF  RETROFIT COMBUSTION MODIFICATION NOV CONTROLS ON
                          UTILITY  BOILER  EFFICIENCY  (Reference 4-34)    x
             Control
                                       Effect on Efficiency
                                                                             Comment
         Low  Excess Air
         Flue Gas  Recirculation
         Off-Stoichiometric
           Combustion
        Water  Injection
        Reduced Air Preheat
Up to 1.5% increase
Insignificant
Little effect with oil/
gas firing
Possible 1% decrease with
coal firing
About 10% decrease
About 1% efficiency loss
per 30K decrease in air
preheat temperatures
Reduced stack gas heat
loss
Small increase due to
fan requirement
Possible increase in
overall excess air
needed for earlier
burnout
Heat of vaporization of
injected water lost
Increased stack gas
heat loss
       The situation with flue gas treatment is likely to be different; however, data are insuffi-
cient to allow any quantitative assessment of the potential penalties.  For the case of oxidation/
absorption wet processes it has been estimated that generation of the oxidizing agent (ozone) will
require approximately 10 percent of the power plant electrical output (Reference 4-35).  When this
is added to the reheat requirements associated with all flue gas wet scrubbers, energy impacts may
be quite significant.

4.1.3.2   Environmental Impact
       Modification of the combustion process in utility boilers for NO  control reduces the ambient
levels of NOg, which is both a toxic substance and a precursor for nitrate aerosols, nitrosamines,
and photochemical smog.  These modifications can also cause changes in emissions of other combustion
generated pollutants.  If unchecked, these changes, referred to here as incremental  emissions, may
have an adverse effect on the environment, in addition to effects on overall  system performance.   How-
ever, since the incremental  emissions are sensitive to the same combustion conditions as NOX,  they may,
with proper engineering, also be held to acceptable levels during control  development so that  the  net
environmental  benefit is maximized.  In fact, control  of incremental emissions  of carbon monoxide,  hydro-
carbons and particulate has  been a key part of all  past NOX control  development programs.   In  addition,
recent control development has been giving increased attention to other potential  pollutants such  as
sulfates, organics,  and trace metals.
                                                4-36

-------
near term.  Due to a virtual lack of data, the potential effects of flue gas treatment techniques are
only briefly mentioned.  For the same reason, fuel switching and fuel additive effects are not treat-
ed at all.

4.1.3.1   Energy Impacts
       The energy impacts of applying combustion modification NOX controls to utility boilers occur
largely through effects on unit fuel-to-steam efficiency.  Although applying flue gas recirculation
requires additional forced draft fan capacity, the additional energy penalties imposed to drive the
fan are generally insignificant.  Thus, effects on unit efficiency tend to dominate energy effects.
       The efficiency effects of the combustion modifications for retrofit application are listed in
Table 4-11.  As the table shows, applying low excess air firing results in unit efficiency gains.
For this reason the technique is gaining acceptance and becoming more a standard operating procedure
than a specific NOX control method in both old and new units.
       The other commonly applied combustion modifications, F6R and off-stoichiometric firing,
generally have little energy impact on utility boiler operation.  In certain instances, higher over-
all excess air levels are required when using these techniques (especially for coal-firing) to pre-
vent combustible losses.  However, adverse effects are generally small.
       A special point of concern relates to taking burners out of service on coal-fired boilers.
Since, in a typical installation, each coal mill supplies a given set (generally a row or an eleva-
tion) of burners, applying BOOS generally involves removing a mill from service.  However, the
remaining mill capacity is usually insufficient to allow overfiring the remaining burners to main-
tain rated load.  Thus implementing BOOS in a coal-fired unit may require derating the unit 10 to
20 percent.  Of course, such derating represents a capacity loss, not an efficiency loss.  But it is
an energy related adverse impact nonetheless.
       The remaining combustion modification techniques listed in Table 4-11, water injection and
reduced air preheat, can impose quite significant energy penalties on utility boiler operation.   As
a consequence, these techniques are quite unpopular, and have found little acceptance.
       Table 4-11  applies only to retrofit application of the cornnon NOX combustion controls.   These
same combustion modifications (LEA, FGR, off-stoichiometric combustion), in addition to low-NO
burners, almost never adversely affect unit efficiency when designed in as part of a new unit.  This
illustrates that with suitable care during engineering and development, combustion modification NO
controls can be incorporated into new unit designs with no adverse energy impacts.
                                                 4-35

-------
     TABLE 4-12.  REPRESENTATIVE EFFECTS OF NOx CONTROLS ON CO
                  EMISSIONS FROM UTILITY BOILERS
                  (References 4-12, 4-16, 4-19)
NOX Control

Low Excess Air













Staged Combustion











Flue Gas Recirculation

Fuel

Natural Gas




Oil



Coal




Natural Gas



Oil



Coal



Natural Gas
Oil
CO Emissions (ppm)a

Baseline
14
86
12
8
14
19
85
15
19
42
20
24
27
27
14
86
12
14
19
85
15
28
24
27
17
31
175
21

NOX Control
68
74
61
8
34
42
53
20
19
93
60
283
81
225
16
67
13
14
21
85
21
37
20
26
40
45
65
9
{3% 02, dry basis.
                                 4-38

-------
        This section presents data obtained to date on the demonstrated effects  of combustion modi-
 fication NOX controls on incremental  emissions from utility boilers.   Attention is focused on flue
 gas emissions as no data exist on incremental effects on liquid and solid effluents.   Emphasis is
 placed on incremental CO, vapor phase hydrocarbon, and particulate emissions; although incremental
 sulfate and condensed phase organic emissions are briefly discussed.   Lack of data precludes any dis-
 cussion on the incremental  effects  of flue gas treatment, fuel  switching,  or fuel  additive approa-
 ches to NO  control.

 Carbon Monoxide Emissions
        Since large  quantities  of  CO in the flue gas  of utility  boilers mean decreased  efficiency,
 these boilers  are operated  to  keep  CO emissions at a  minimum.   Furthermore, if  flue gas CO  levels
 reach concentrations  in  excess  of 2,000 ppm,  severe  equipment damage can result from explosions
 in  flue gas  exit passages.   Thus, the degree  to which a  NOX  reduction  technique is allowed  to
 increase CO  is  limited by other than  environmental concerns.  In general,  a NO  control method is
 applied until  flue  gas CO reaches about 200 ppm.   Further application  is then curtailed.
        NOX control  effects  on CO  emissions are  highly dependent on  the equipment type  and the  fuel
 fired.   In utility  boilers  of newer design, it  is  generally  possible to achieve good NO  reduction
 without causing significant  CO  production.  This  is possible because newer burner and furnace designs
 allow for better combustion  air control and longer combustion gas residence time.   In addition, oil
 and  coal-fired boilers usually emit very low CO levels during low NOX combustion because smoke and
 soot  production generally occurs with these fuels before  significant CO levels are attained.  Since
 boiler  operators strive to keep combustible losses to a minimum, conditions which result in soot
 formation are avoided, resulting in correspondingly low CO levels.   A summary of the field data on
 the effects of the more extensively implemented modifications on CO emissions are shown in Table
 4-12.  These data are discussed below for each combustion NO  control.
       As the data in Table 4-12 illustrate, lower excess air levels in utility boilers can have pro-
found effects on CO emissions.  In virtually all instances CO emissions increased significantly
when excess 02 levels were reduced 30 to 60 percent.   Gas-fired boilers showed emission increases
up to 400 percent when excess 02 was lowered over this range, while oil-fired boilers were less
sensitive, and showed CO emission increases from 0 to 120 percent.   However,  coal-fired boilers
were the most sensitive to excess air reductions.  Reducing excess  02 by 40 to 60 percent  gave  100
to 1,000 percent increases in CO emissions.
                                                4-37

-------
operating efficiency, and NOX controls which significantly decrease efficiency have  found  little
acceptance.
Particulate Emissions
       Although gas-fired units produce negligible amounts of particulate, oil- and coal-fired
utility boilers currently emit approximately 38 percent of the nationwide particulate and smoke
(Reference 4-34).  Potential adverse effects on these particulate emissions from NO  combustion con-
trols could therefore have significant environmental impact.  Unfortunately the optimum conditions
for reducing particulate formation (intense, high temperature flames as produced by high turbulence
and rapid fuel/air mixing), are not the conditions for suppressing NO  formation.  Therefore, most
attempts to produce low NO  combustion designs have been compromised by the need to limit forma-
tion of particulates.  This compromise has generally produced designs which maintain a well con-
trolled, cool flame, while still providing sufficient gas residence time to completely burn carbon
containing particles.
       The NOX combustion controls currently receiving Lhe mos. widespread application in utility
boilers are low excess air, off stoichiometric combustion, and flue gas recirculation (for gas and
oil).  The altered combustion conditions resulting from these modifications can be expected to
influence emitted particulate load and size distribution.  For example, smoke and particulate emis-
sions tend to increase as available oxygen is reduced (soot emissions increase and ash particles
contain more carbon).  Thus the degree to which excess air can be lowered to control NO  is usually
limited by the appearance of smoke, especially in oil-fired units.   Of course, the extent to which
excess air can be limited depends on equipment types and design.   Many modern burners can operate
on as little as 3 to 5  percent excess air.
       Similarly, the degree to which staged combustion can be employed is frequently limited by
the degree to which the primary flame zone can be stably operated fuel-rich, how well the second
stage air mixes with primary stage combustion products, and the residence time for combustion in
the second stage.  Soot and carbon particles formed in the fuel-rich primary stage tend to resist
complete combustion downstream of that stage.
       On the other hand, flue gas recirculation on oil-fired units can serve to decrease particu-
late emissions by providing more intimate mixing.   Kamo,  et al.  (Reference 4-36)  have demonstrated
that recirculation rates of 40 to 50 percent on a  heater-sized oil-fired furnace reduced  the smoke
number significantly.
                                                4-40

-------
       Off-stoichiometric, or staged combustion has proven to be a very effective NO  reduction
 technique for  large steam generators.  It can be implemented in a variety of ways including burners
 out of service, overfire air ports, and biased firing.  In all cases, the effectiveness of staged
 combustion  in  reducing NO  emissions depends in large part on the fraction of total combustion air
                         A
 that can be introduced into the second combustion stage.  It is in this second stage that complete
 combustion of  the fuel is achieved.  CO emissions arise when this second stage combustion does not
 go to completion prior to quenching in the convective section.  This is caused by a combination of
 the first stage being too fuel rich and the mixing of second stage air being too slow for the resi-
 dence time  provided.  During development of retrofit or new design controls, these parameters are
 usually selected so that CO emissions are acceptable.
       The effectiveness of staged combustion in reducing NO  formation while keeping CO emissions
 low is highly  dependent on specific equipment type.  New utility boilers with multiburner furnaces
 are especially amenable to this technique because it is generally not difficult to adequately dis-
 tribute secondary air and assure complete combustion in these sources.   Consequently, implementing
 staged combustion in utility boilers is expected to elicit little effect on incremental  CO emissions,
 This conclusion is certainly borne out by the representative data presented in Table 4-12.
       The use of flue gas recirculation (FGR)  for NOX control  has, in  practice, been restricted
 to gas- and oil-fired units.   This technique is ineffective in reducing fuel NO  production,  the
 predominant source of NO  in coal  firing.   When FGR is implemented, 10  to 30 percent of the total
 burner gas flow is recycled flue gas from the boiler exhaust.  Further  FGR increases can cause
 flame instability due to reduced flame temperatures and oxygen availability.  Theoretically,  FGR
 can lead to increased CO emissions, but unacceptable flame instabilities usually occur before the
 onset of CO or smoke production.   Thus, as Table 4-12 shows, the use of FGR has not caused increased
 CO emissions.   On the contrary, CO emissions have generally decreased.
 Hydrocarbon Emissions
       Field test programs studying the effectiveness of NOX controls often monitor flue gas  HC
 emissions  as a supplementary measure of boiler  efficiency.   Therefore,  some data on the  effect of
 these controls on HC emissions are available.   Two recent test programs on utility boilers rou-
 tinely measured flue gas HC (Reference 4-12 and 4-16).   However,  in virtually all  tests, both base-
 line and low NOX emissions were less than  1  ppm (or below the detection limit of the available
monitoring instrument).   Thus, it  was  concluded that HC emissions  are relatively unaffected by
 imposing preferred NOX combustion  controls on large utility boilers.  However,  this conclusion is
 not altogether unexpected.   The presence of unburned HC in  flue gases implies poor boiler
                                                4-39

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       Published data on the effects of NO  reduction techniques on particulate emissions from
                                          A
utility boilers are scattered and insufficient for indepth analysis.""  Table 4-13 summarizes the
particulate emissions data obtained during two recent field test programs which studied coal-fired
utility boilers (References 4-12 and 4-16).  During the studies, particulate measurments were re-
corded under baseline and low NOV conditions.  Since these NCL conditions were generally produced
                                A                            A
by a combination of low excess air and staged combustion, the individual effect of each technique
on particulate emissions cannot be determined.  Nevertheless, the data do show that particulate
emissions are relatively unaffected by low NOX firing in front wall- and horizontally opposed-fired
boilers.  Tangentially-fired boilers, on the other hand, exhibit slightly increased particulate
emissions under low NO  conditions.
                      A
       The effects of low NOX firing on carbon (or combustible) content of the particulate are also
shown in Table 4-13.  Although the data are quite scattered, it appears that carbon losses increase
for front wall- and horizontally opposed-firing under low NOX conditions, but decrease slightly for
tangential firing.  However, the changes are small and may not be significant.

       The effects of low NOX conditions on emitted particle size distribution have also been
investigated to a limited extent (Reference 4-12).  The data from a study of particle size distri-
bution in three boilers are summarized in Table 4-14.   As the table shows, no significant changes
were noted in two of the boilers, both of which were tangentially fired.   In the third, a hori-
zontally opposed boiler^ a distinct shift to smaller particles was noted, but the author reported
problems with the sampling and particle sizing equipment in this test, so the data may not be
significant.

Sulfate Emissions

       Ambient sulfate levels have recently become a matter of increasing concern in regions  with
large numbers of combustion sources, notably boilers,  firing sulfur-bearing coal  and oil.   Although
the direct health effects of high ambient sulfate levels are currently unclear (References 4-37 and
4-38), recent thought suggests that  sulfates may be more hazardous than S02.   For  this  reason,  con-
trol  of primary sulfate emissions is becoming a concern even though primary sulfates (directly
emitted)  comprise only 5 to 20 percent of ambient sulfate on a regional basis (Reference 4-38).

       Since approximately 98 percent of the sulfur introduced into a utility boiler appears  in flue
gas as an oxide, applying NOX controls would have essentially no effect on total SOX emissions.  How-
ever, effects on the emitted (S03 + particulate sulfate)/S02 ratio can be significant.  Specifically,
combustion conditions which limit local oxygen concentrations would be expected to decrease the
                                                4-41

-------
 extent of S02  to  S03  oxidation.  Thus applying  low excess air firing and off-stoichiometric combus-
 tion  to control NOX should also  lower S03/sulfate emissions.
        Confirming data,  though sparse, do exist.  Recent measurements have demonstrated the expected
 dependence of  sulfate emissions  on boiler excess air levels.  Bennett and Knapp  (Reference 4-39) have
 shown that particulate sulfate emissions increase with increasing boiler excess  0~ in oil-fired
 power plants.  Homolya,  et al. (Reference 4-40) report a similar increase in sulfate emissions as a
 percentage of  total sulfur emissions with increasing excess 02 in coal-fired boilers.  Their data,
 shown in  Figure 4-8,  show a linear relationship between the sulfate fraction of  emitted sulfur and
 boiler excess  02.  Other data (Reference 4-41), shown in Table 4-15, also show that SO., emissions
 decrease  when  staged  combustion  is used to control NO .

 Organic Emissions
       The  term organic  emissions as used here  is defined to mean those organic  compounds which exist
 as  a  condensed phase  at  ambient  temperature.  Thus they are organics which are either emitted as "car-
 bon on  particulate" or condense  onto emitted particulate in the near-plume of a  stack gas.  These com-
 pounds, with few  exceptions, can be classified  into a group known variously as polycyclic organic
 matter  (POM) or polynuclear aromatic hydrocarbons (PNA).
       POM  production is generally only a minor concern in gas-fired systems, of some concern in
 oil-fired sources, and of greater concern in coal-fired equipment.   Like CO and HC emissions,  POM
 emissions are the result of incomplete combustion.  Since NOV combustion controls can lead to inef-
                                                            A
 ficient combustion, if not carefully applied (especially  low excess  air and off-stoichiometric  com-
 bustion), applying these controls can potentially lead  to increased  POM production.
       Supporting data,  However,  are very limited, largely because  of the difficulty  of sampling
 flue gas streams  for POM and of accurately  assaying samples  for  individual  POM  species.   Thompson
 et al., recently  reported the effects of staged combustion and flue  gas  recirculation on  POM  emis-
 sions from a coal-fired  utility boiler (Reference 4-13).   Their  data,  shown  in  Table  4-16,  seem to
 indicate that POM emissions  do increase  with two-stage  combustion.   However,  they state  that  the
 sampling and laboratory  analysis  procedures  used in obtaining the data  varied over the  sample set.
Thus,  they conclude that POM emissions are not significantly affected  by firing mode.   In  another
study, Bennett and Knapp (Reference 4-39) attempted  to  investigate the  effects  of boiler excess 0?
on POM emissions  from  an oil-fired  utility boiler.   They  found that  particulate carbon content
increased with decreasing excess  02.   However,  because POM assay data varied  widely,  even  for base-
line condition analyses,  no  conclusion regarding POM emissions was possible.
                                                4-44

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                                                  4-45

-------
4.2    INDUSTRIAL BOILERS
       Industrial boilers range in capacity from 3  to  73  MW*,  (10  to  250  million  Btu/hr),  and  com-
prise a wide diversity of firing types and fuels.   In  1974,  industrial  boilers  consumed  about  30
percent of the fossil  fuel used by stationary sources. The  industrial  boiler capacity distribution
was approximately 49 percent gas-fired, 29 percent  oil-fired and 22 percent coal-fired.   About a
third of the industrial units are small packaged boilers.  Fifty-three  percent  are- in the 5 to 30
MW  (17 to 100 x 106 Btu/hr) range and are primarily packaged watertube units.   A more complete des-
cription of this equipment category is given in Section 2.3.2.
       NO  emissions from industrial-size boilers amounted to 2.2 Tg per year (2.44 x 106 tons) in
1974, or 18.2 percent  of the nationwide stationary source emissions.
       The following discussion of NO  control  techniques centers on the most promising method, com-
bustion modifications.
4.2.1  Control  Techniques
       The data on  applied  combustion  modification  technology for  industrial boilers are  limited.
The most extensive  results  were derived from a  recent EPA-sponsored  study  (Reference 4-49,  4-50).
This  study  involved the  field  testing  of  a  representative sample of  industrial boilers  to determine
their NO  reduction potential.  Ten different combustion modification  techniques were implemented.
       The  effects  of  these techniques on NOX emissions  and  boiler efficiency  are  summarized  in
 Figure 4-9  for  73  separate  boiler tests.   The ten  techniques  are  listed  at the top of the figure.
The graph  is  divided  into quadrants.   The criterion for  the  best quadrant  is that  the modification
 technique  should simultaneously reduce NOX and  increase  efficiency.  In  general,  the study showed that
 total NO   emission  reductions  of  up to 47 percent  were possible by using one or  a  combination of six
 different methods.  These were:   excess air reduction, burner-out-of-service (BOOS),  flue gas recir-
 culation  (FGR), overfire air addition, burner register adjustment, and reduced air preheat.  Only
 with the  first three  methods was  boiler efficiency generally unimpaired.
        Of these three, lowering excess air was  the preferred method because boiler efficiency was
 usually maintained or improved, and  particulate emissions  did not increase, as they do  with most of
 the other techniques.   FGR is the next most promising technique, since particulate emissions
  Approximately 1 percent of the industrial boilers are greater than the 73 MW (250 x 10  Btu/hr)
  classification for which new source performance standards have been established (Reference 4-42).
  These  boilers are essentially the same as utility boilers.
                                                 4-48

-------
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increased only five percent.   Staged  air addition  and  BOOS  show  some  potential, but difficulties



exist in distributing the air to avoid  an increase in  particulate  emissions.




       The remainder of this  subsection is devoted to  a  discussion of combustion  modification



experience on gas, oil, and coal-fired  boilers.  This  information  is  derived  mainly from References




4-49 and 4-50.





Gas-Fired Boilers




       NO  emissions under base load  conditions  for gas-fired units varied from 26 to 190 ng/J



(50 to 375 ppm) (Reference 4-51).  The level was most strongly dependent on combustion air tempera-



ture since NO  from gas firing is predominantly  thermally produced.  For example, emissions from



base loaded watertube boilers varied  from 37 to  60 ng/J  (70 to 116 ppm) when operated on ambient air.



NO  emissions from watertube boilers  with preheated combustion air varied from 47 to  190 ng/J  (90



to 375 ppm).




       Boiler NO  emissions with gas  firing generally decreased with decreases in excess air level



although  significant exceptions were noted.  The decrease in NOX emissions with low excess air fir-



ing was  generally more pronounced when preheated combustion air was utilized.




       Off-stoichiometric  combustion was  demonstrated to be successful for NOX control in multi-



burner,  gas-fired boilers.  NOX  reductions  of 12  to 40 percent were achieved by terminating the



fuel flow to  an individyal burner and  using that  burner port as an air injection port.  Simultaneous



limiting of excess  air also showed a 24  percent reduction  in NOX  emission  in one instance.  In the



tests  where these  combustion modifications  were utilized,  the percentage of units with emissions



less than 86  ng/J  (0.2 Ib  N02/106 Btu) was  increased  from  75 percent to 82 percent.




        Cichanowicz  et  al.  (Reference 4-52)  have compared the influence of  FGR for both watertube



and  firetube  boilers for natural gas at  constant  excess air.  These  results are shown in Figures



4-10 and 4-11.  Forty  percent  FGR reduced NOX emission by  approximately 70 percent for both these



boilers. Flue gas  recirculation  per  se was found  to have minimal  effects on gas fueled boiler effi-



ciency (Reference 4-50).




        Reducing  firing rate,  in general, does not have  a strong effect on  NOX emissions.   The N0y



 reduction achieved with  lower load was nullified  by  the  increase  in  excess air at the reduced load



 that was required for  adequate boiler  performance.   This resulted in an  insignificant NOX  decrease



 or even an increase at the lower firing rate.   Watertube gas-fired boilers were  relatively insensi-



 tive to load changes unless  they were  equipped  with  preheaters.   In  this  case, NOX reductions of
                                                  4-50

-------
   +7
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              WORST QUADRANT
           COMBUSTION MODIFICATION METHOD
                O FLUE GAS RECIRC.
                O AIR REGISTER ADJ.
                A OIL VISCOSITY
                O BURNERTUNEUP
                V ATOMIZATION PRESSURE	
                • ATOMIZATION METHOD
                • REDUCED EXCESS AIR
                AOVERFIREAIR
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                V BURNER-OUT-OF-SERVICE
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                                             BEST QUADRANT
                                                           -
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                  -5
                                               +5
                                                            +10
                        CHANGE IN EFFICIENCY, percent
  Figure 4-9. Effect of combustion modification methods on total nitrogen oxides
  emissions and boiler efficiency (Reference 4-50).
                                 4-49

-------
about 20 percent were obtained as the firing rate was  dropped  from 100 percent to  50  percent  of



name plate capacity.





Oil-Fired Boilers



       Base load NO  emissions for these boilers ranged from 36 to 101 ng/J (65 to 180 ppm) with



No. 2 oil, 112 to 347 ng/J (200 to 619 ppm) for No.  5  oil, and 107 to 196 ng/J (190 to 350 ppm)  for



No. 6 oil.  The influence of fuel nitrogen was clearly shown by the variation from 50 ng/J (90 ppm)



for 0.045 percent nitrogen oils to about 180 ng/J (325 ppm) for 0.5 percent nitrogen fuel  oils.




       The oil-fired firetube boilers showed little dependence of NO  emissions on excess air or
                                                                    A


load.  The watertube boilers were more sensitive, showing decreasing NOX with decreased excess air.



There was also a stronger effect of excess air when the heavier oils were fired.




       Off-stoichiometric combustion on a multiburner oil-fired boiler produced NOX reductions of



17 to 49 percent.  These reductions were achieved by stopping fuel flow to selected burners and



using the burner port as an air injection port.  It was also shown that using upper burners as air



injection ports gave better results than using lower burners.   This is not a general recommendation,



because this  kind of result is highly dependent on the individual internal flow patterns of a parti-



cular boiler.



       Emissions of NO  were  found to be relatively independent of the fuel oil atomization method,



but dependent on the characteristics of the individual burner.  For a given oil burner, the atomiza-



tion method that produced the lowest nitrogen oxide emissions also generally produced the greatest



quantity  of particulate.  Boiler efficiency was essentially unaffected by atomization method.





        Atomization pressure, however, did effect NO  emissions to a slight extent.  In one series



 of tests, an increase in steam atomization pressure increased NO  by 6 percent.




        In most tests, NO  emissions decreased as the excess air was reduced.  An average change in



 NO  of about 11 ng/J (20 ppm) for a one percent change of excess oxygen level was observed for
   A


 watertube boilers.  Firetube boilers averaged about 3 ng/J (6 ppm) for each one percent change in



 oxygen.  Emissions of NO  for No. 2 oil were less affected by excess oxygen level than were  those



 for Nos. 5 and 6 oil.  For all oils, the sensitivity of NO  to excess oxygen was small when  the total



 NO  concentration was less than 100 ng/J (180 ppm).




        Reducing air  preheat temperature on No.  6  oil  firing did  not  have  as  large  an  effect on  N0y



 emissions as  it did  on  gas  firing.   This  technique  primarily  affects  thermal  NOX  formation; the con-



 tribution of  fuel  NO  in residual  oil  firing  is  considerable.  Reducing  air  preheat  resulted  in an
                                                 4-52

-------
                                               LOAD-2.72Mg/h STEAM
                                                     (6000 Ib/hr)
                                               FUEL -NATURAL GAS
                                               02    -3.9 PERCENT
                         20         30         40

                      FLUE GAS RECIRCULATION, mass percent

Figure 4-10.  Influence of flue gas recirculation on NOX emissions from a
firetube boiler (Reference 4-52).
                                              LO AD-3.12Mg/h STEAM
                                                     (6900 Ib/hr)
                                              FUEL -NATURAL GAS
                                              0?   -3.5 PERCENT
                             20            30            40

                      FLUE GAS RECIRCULATION, mass percent

Figure 4-11. Influence of flue gas recirculation on NOX emissions from a
watertube boiler (Reference 4-52).
                                  4-51

-------
       Reducing excess oxygen in coal-fired boilers  was  found  to  be  more  effective  in  reducing N0x



than in either oil  or gas-fired boilers.   Each one percent  change in excess  oxygen  resulted  in



approximately a 37 ng/J (60 ppm) change in N0x emission, regardless  of air  preheat  temperature.



This strong, consistent,  decrease in N0x with  decreasing excess air  was unique to coal; the  N0x



occasionally increased when excess oxygen was  decreased  on  oil  and gas firing.   Also,  the  average



amount of excess air fired for coal averaged 8.7 percent, which was  significantly higher  than  for



oil or gas.



       The overfire air concept was tested on  several  stoker fired boilers,  and  the results  were



disappointing.  The above-grate air injection  ports (conventional equipment on  all  stokers)  re-



duced NO  by only 8 percent.  It was concluded that the  ports  were located  too  far  from the  pri-
        X

mary flame zone or that the overfire air system lacked the  capacity to alter the air/fuel  ratio



sufficiently for NO  reduction.





       The effect of firing rate was investigated by varying the  boiler load about  the base  load



point of 80 percent of nameplate capacity.  Generally, coal-fired watertube boilers showed an



increase in NO  when operating below 60 percent capacity.  This increase  usually coincided with  an



excess air increase.





       Another EPA-sponsored study is assessing the potential  of substituting western  U.S. sub-



bituminous coals for eastern bituminous coals  as an industrial boiler fuel  (Reference  4-53).  The



results of the program are significant from a  NO  control standpoint since  switching to this more
                                                A


abundant coal may become widespread in the near future.   The western coals  were found  to be com-



patible with the industrial boilers of current design, although two units of older  design (underfed



and traveling grate stokers) had some combustion difficulties.  The coals were superior to eastern



coals in terms of lower NO  , SO  , particulate, and unburned hydrocarbon emissions.   In addition,



they could be fired at lower excess air than eastern coal,  and produced much lower  combustible



losses.



       To  summarize,  it appears  that significant  NOX emission reduction can be obtained in most indus-



 trial  boilers  with  minor  modifications  in  operating conditions.  Additional emission  reductions are



 possible with  boiler  redesign  which would  permit  cost-effective  implementation of off-stoichiometric



 or staged-combustion  in units  burning  heavy fuel  oils or coal.   Very  few existing units possess the



 necessary  flexibility for this  type of major  retrofit.   Problems which must be considered in the



 design of  new units,  and  particularly  in  the  modification of  existing units, include  corrosion and



 deposits on boiler  tubes,  flame instability,  and  combustion noise.  The  level of NOX  reduction that
                                                4-54

-------
 efficiency decrease of about  2.5  percent  per  50K  increase  in  stack  temperature.  For general appli-
 cation,  this technique would  require  an increase  in economizer area to maintaia overall efficiency.

        Flue gas recirculation was implemented on a watertube boiler firing a No.  6 oil.   At a mini-
 mum excess oxygen level of 2 percent, adding 20 percent FGR to a steam-atomized flame  lowered NO
                                                                                                 x
 by 50 percent.  For an air-atomized burner, less  dramatic  N0x reduction  effects were experienced
 at both nominal and minimum excess oxygen levels.  For oil firing in  general,  FGR  rates  greater
 than 27 percent caused flame  instability  and  blowout.
        The effect on N0x emissions of tuning  the  burner was also determined.  Tuning involved  nozzle
 examination, spray angle adjustment,  and  flame  length  adjustment.   The chief effect of burner  modi-
 fication was a reduction in carbon monoxide rather than N0x>   Particulate  generally increased  after
 tuneup.    The most effective  method of reducing N0x by tuning was to  reduce  excess oxygen and  accept
 some increase in CO emissions.

 Coal-Fired Boilers
        The baseline N0x emissions from coal-fired boilers  were generally higher than those  from gas
 and oil-fired units.  Emissions ranged from 100  to 550 ng/J (165 to 900  ppm).  Although  the fuel
 nitrogen contents  of the test coals were  high,  ranging from 0.8  to  1.5 percent by weight, the  field
 studies  indicated  no strong dependence of N0x emissions upon  fuel nitrogen content.  Other  factors
 are apparently more important in  determining  N0x  production,  such as  furnace geometry, excess  air,
 firing rate, burner type,  and other fuel  properties.
        It  was  found  that  pulverized and spreader  stoker-type  boilers  produced the highest - 550  ng/J -
 baseline N0x emissions.   Chain  grate  and  underfed  stokers  had the lowest - 100 ng/J - emissions.  In
 these  latter units,  the combustion air fed  up through  the  grating is  insufficient for complete oxida-
 tion,  so additional  air must  be introduced  above the grating through overfire air ports.   The combus-
 tion is, therefore,  effectively staged, and the N0x emissions were quite low (100  ng/J  or 165 ppm).
       Spreader  stokers, in which the fuel  is introduced with the air  flow above the grate,  had
 intermediate emission characteristics.  Some of the fuel is burned in  suspension,  and the remainder
 is combusted on the  grate as  in the underfeed stoker.   The  resultant combustion  is  only partially
 staged.  The combustion intensities are also higher than for underfed  stokers,  possibly increasing
thermal NO  formation.
       The pulverized coal  units,  especially the cyclone-fired  types,  produced  the  highest  baseline
emissions due mainly to the very high combustion intensity.
                                                4-53

-------
boilers to date (References 4-49 and 4-50)  were presented  in  Figure 4-9.   As  the  figure  indicated,
only with low-excess air, BOOS, and FGR was boiler efficiency generally unimpaired.   For low  excess
air firing, efficiency gains of from 1  to 3 percent were typical.   Taking burners out of service  and
FGR generally did not affect efficiency.  On the other hand,  other tested controls generally  imposed
efficiency penalties.  Both overfire air and reduced air preheat gave efficiency  losses  of 1  to 2
percent.
       The effects of NOX combustion modification controls on incremental pollutant emissions from
industrial boilers should also be analogous to those described previously in Section 4.1.3.2  for
utility boilers.  Unfortunately, the only currently circulated data are on incremental flue gas
CO, HC, and particulate effects.
Carbon Monoxide Emissions
       The bulk of the data on incremental CO emissions due to NOX controls applied to industrial
boilers was obtained in the two previously cited field test programs (Reference 4-49 and 4-50).   In
these studies, CO emissions were reported for both baseline and for low NOX firing.  Baseline emis-
sions were recorded with the boiler operating at 80 percent of rated capacity under normal (or as-
found) conditions.  Low NO  testing was implemented until CO emission levels reached 100 to 200 ppm,
then it was curtailed.
       The data obtained during these studies are summarized in Table 4-17.  As indicated in the
table, baseline CO emissions for industrial boilers are generally  insignificant.   However, the applv
cation of NO   combustion controls  in most cases adversely affected CO levels because each control
was  implemented until CO levels became  unacceptable.
       As noted for  utility boilers, CO emissions from  industrial  boilers are also adversely
affected by  lowering excess air levels.  As observed  in the  field  study  and shown in Table 4-17,
CO emissions  from gas- and oil-fired boilers can be significantly  increased when excess oxygen is
reduced  20 to 50 percent.  Coal-fired boilers  showed  lower residual CO emission  increases.
       Two methods were  used in the  industrial  boiler study  to effect staged combustion:  overfire
air  and  burners out  of service.  In  these  tests baseline CO  emissions were always low.  Combustion
staging  by both methods  generally  resulted  in  unchanged to slightly  increased CO emissions.
       The data  in Table 4-17  show that FGR has little  effect on CO emissions.  This conclusion
substantiates what was noted in the  utility boiler  testing discussed in  Section  4.1.3.1.  In addi-
tion,  the  data in Table  4-17 illustrate that varying  combustion air  temperature  has  almost no
                                                4-56

-------
 is  achievable on  industrial boilers is close to, but generally not as great as, that attainable
 with  utility boilers.  The  Industrial Environmental Research Laboratory -RTF of the EPA is continuing
 to  develop cost-effective NOX reduction methods for industrial boilers.
4.2.2  Costs
       Cost data  for combustion modifications on industrial boilers are virtually nonexistent.  Only
 the most broadly  based estimates are available to the boiler owner and operator at the present time.
The most recent information of this kind was published in Reference 4-5Q.  In that industrial boiler
field study, a 5.1 MW (17.5 x 103 Ib steam/hr)  D-type watertube boiler was modified by adding staged
air and flue gas  recirculation capability.  The windbox depth was increased and a second set of
registers to control the recirculating flue gas was installed inside the extension.  The cost of
these modifications was estimated at $5000.  (The current cost of new boilers of this type is about
$60,000.)  The cost of a similar modification on other modern D-type boilers could be as high as
$7500 if the existing burner registers cannot be used.
       Manufacturers of industrial boilers in the 90 MW (300 x 103 Ib steam/hr) size range and one
million dollar cost category estimated that a staged air installation in general would add 2 to 4
percent to the boiler's cost.  Specifically for A-type boilers, the incremental cost would be about
2 percent, and for D-type about 3 percent.  Another booster air fan, if required, would increase
the modification  cost by about one percent (Reference 4-50).
       In a recent study, costs for retrofitting an existing unit to accept flue gas recirculation
were estimated (Reference 4-54).   Approximate costs, which include design, installation and equip-
ment costs associated with the retrofit of FGR  systems  were, in 1975 dollars, $20,340 for a 3.51 MW
firetube boiler and $21,190 for a 3.51 MW watertube boiler.   However, these costs would be consid-
erably less for a new boiler.  Reference 4-54 estimates that for a new boiler of the size mentioned
above, the cost of including an FGR system will  be about $6,900.
       Research and development,  including field testing and application of NO  control  methods to
this equipment category, is still in its early  stages.   More accurate cost estimates for these
techniques are being developed as part of ongoing and planned EPA studies.

4.2.3  Energy and Environmental Impact
       As was the case for utility boilers, the energy impacts of applying combustion modification
NOX controls to industrial boilers occur almost exclusively through effects on boiler efficiency.
Data on these efficiency effects  of NOX control  from the most extensive field study of industrial
                                                 4-55

-------
effect on CO emissions.   These observations  suggest that effects  of  peak  flame  temperature  on CO
emissions were also insignificant.

Hydrocarbon Emissions
       The field test program investigating  NOX controls applied  to  industrial  boilers  also reported
data on incremental HC emissions.   These data are summarized  in Table 4-18  and show that the use
of NOX combustion controls generally do not  affect flue gas HC  levels.  Some tests  show a slight
increase in HC emissions, yet others indicate slight reductions.   Based on these data,  it seems
fair to conclude that HC emissions  from boilers are unaffected  when  implementing NOX combustion
controls.

Particulate Emissions
       In addition to the above data, the industrial boiler test  program  reported some  particulate
emissions and size distribution data showing the effects of several  N0y combustion controls. These
particulate emissions data from several oil- and coal-fired boilers  are   summarized in  Figure 4-12.
The figure shows changes in particulate emissions versus changes  in  NOX emissions from  baseline  con-
ditions as a function of the applied NOX control.
       As Figure 4-12 shows, the effects of NOX controls on particulate emissions are mixed. For
example, both forms of staged combustion tested increased particulate emissions by 15 to 90 percent,
while flue gas recirculation increased emissions by 10 percent.  In  contrast, reducing  air  preheat
decreased particulate emissions by 45 percent.  Furthermore,  low  excess air firing generally lowered
particle emissions 25 to 60 percent.
       These observations are in general agreement with those of  Heap, et al. (Reference 4-54) who
studied FGR and staged combustion applied to two oil-fired packaged  boilers.  They found that
smoke emissions increased slightly when both FGR and staged combustion were applied.
       Cato, et al. (Reference 4-50) also reported some very limited particle size distribution
data, shown in Figure 4-13.  This figure shows that, in a distillate oil-fired boiler,  as  excess
air levels are lowered, the emitted particle size distribution shifts slightly to larger sizes.   A
more pronounced shift to larger particle sizes was observed with  reduced  load in a residual oil-
fired boiler.  However, these data are much too limited to allow any definite conclusions  to be
made regarding the effects of combustion modifications on flue gas particle size distribution.
                                                4-58

-------
TABLE 4-17.  EFFECTS OF NOx CONTROLS ON CO EMISSIONS
             FROM INDUSTRIAL BOILERS
             (References 4-49 and 4-50)
NOX Control
Low Excess Air
Staged Combustion
t Overfire Air
• Burners Out of
Service
Flue Gas Recirculation
Variable Air Preheat


Fuel
Natural Gas
Distillate Oil
Residual Oil
Coal
Natural Gas
Distillate Oil
Residual Oil
Coal
Natural Gas
Residual Oil
Natural Gas
Residual Oil
Natural Gas
Residual Oil
Coal
CO Emissions (ppm)a
Baseline
10
0
0
0
50
47
90
0
0
0
0
0
0
25
70
0
0
25
10
10
0
0
0
0
0
10
0
0
10
0
0
10
10
0
0
10
0
322
0
0
0
NOX Control
10
0
11
900
129
485
150
17
45
100
9
28
205
20
60
0
22
25
10
20
0
0
30
80
49
10
0
43
20
0
10
0
75
0
0
0
30
320
0
0
10
a3% 02, dry basis.
                         4-57

-------
  +50
  +40
  +30
^+20
CO
LLJ
S+10
x
o
CO
C9
2
X,
   -10
   -20
  -30
  -40
  -50
         COMBUSTION MODIFICATION METHOD
            O AIR TEMP. REDUCTION
            D REDUCED FIRING RATE
            A FLUE GAS RECIRC.
            O REDUCED EXCESS AIR
            • STAGED AIR
            • BURNERTUNEUP
            A BURNER-OUT-OF-SERVICE
                              O

                 BEST QUADRANT
                                                     WORST QUADRANT
b
    -200
                      •100                 0
                            CHANGE IN PARTICULATES, percent
                +100
+200
  Figure 4-12. Effect of NOX controls on solid paniculate emissions from industrial
  boilers (Reference 4-50).
                                        4-60

-------
      TABLE 4-18.   REPRESENTATIVE EFFECTS OF NOX CONTROLS ON VAPOR
                   PHASE HYDROCARBON EMISSIONS FROM INDUSTRIAL
                   BOILERS (References 4-49 and 4-50)
NOX Control
Low Excess Air
Staged Combustion
t Overfire Air
• Burners Out of
Service
Flue Gas Recirculation
Variable Air Preheat
Fuel
Natural Gas
Distillate Oil
Residual Oil
Coal
Natural Gas
Distillate Oil
Residual Oil
Natural Gas
Residual Oil
Residual Oil
Natural Gas
Residual Oil
HC Emissions (ppm)a
Baseline
42
10
17
7
3
8
35
11
21
5
0
0
0
12
35
0
10
15
35
NOX Control
34
0
13
8
9
13
25
18
7
0
0
0
0
14
15
0
0
13
25
13%  02,  dry basis,
                                  4-59

-------
4.3    PRIME MOVERS
4.3.1  Reciprocating Internal  Combustion Engines
       Stationary reciprocating engines account for nearly 20 percent of the NOX from stationary
sources, or 2.4 Tg per year (2.66 x 106 tons).   There are presently no Federal  regulations  for gase-
ous emissions from these engines.  Some local  areas, such as the South Coast Air Pollution  Control
District of Southern California, have set standards for internal combustion engines.
       A 1973 study by McGowin (Reference 4-55) provides a good overview of emissions from  station-
ary engines, particularly the large bore engines used in the oil and gas industry and for electric
power generation.  An EPA-sponsored Standards  Support and Environmental Impact Study (SSEIS) for
these engines (Reference 4-56) will be completed in 1978 and will be the most comprehensive study of
stationary reciprocating engines to date.
4.3.1.1   Control Techniques
       The NO  control techniques for 1C engines must be effective in reducing emissions over a broad
range of operating conditions — from continuous operation at rated load to lower utilization appli-
cations at variable load.  In general, large natural gas spark ignition engines running at  rated
loads have the highest NOX emission factors.  Gasoline engines, in contrast, frequently operate at
lower loads (less than 50 percent of rated) and produce substantially higher levels of CO and HC.  The
NO  control techniques for these engines often involve HC and CO control since these emissions fre-
quently increase as NO  is reduced.  Divided chamber diesel-fueled engines produce low levels of
NO   (accompanied by greater fuel consumption than open chamber designs).  In general, all diesel-
fueled engines have relatively small HC and CO emissions (less than 4 g/kWh*).
       The following paragraphs will discuss NO  control techniques in general followed by  a tabula-
tion of specific NOX reductions, by engine group.  A lack of emission data precludes any discussion
of natural gas engines less than 75 kW/cylinder (100 hp/cylinder).
       Table 4-19 summarizes the principal combustion control techniques for reciprocating  engines.
These methods may require adjustment of the engine operating conditions, addition of hardware, or a
combination of both.  Retard, air-to-fuel ratio change, derating, decreased inlet air temperature,
or combinations of these controls appear to be the most viable control techniques in the near term.
Nevertheless, there is some uncertainty regarding maintenance and durability of these techniques
because,  in the absence of regulation, very little data exists for controlled engines outside of
laboratory studies, particularly for large stationary engines.   In general, increases in fuel
consumption, as much as 10 percent, are the most immediate  consequence of the application of these
*
 shaft output
                                                 4-62

-------
       .  BASELINE
       LOW EXCESS
          AIR
                               AERODYNAMIC DIAMETER,jum

Figure 4-13. Effects of NOX controls on particulate size distribution fromioil-fired
industrial boilers (Reference 4 50).
                                        4-61

-------
 techniques (excluding inlet air cooling).  All control  techniques involve only operational  adjust-
 ments with the exception of (1) derating which may require additional  installed capacity to compen-
 sate for the decreased rating, (2) inlet manifold air cooling which involves the addition of a heat
 exchanger and a pump, and (3).catalytic conversion,  which requires adding a catalytic reactor.
        While exhaust gas recirculation (EGR)  yields  effective reduction of NO , this technique
 requires additional  development to overcome fouling  of  flow passages and increased smoke levels.   In
 general, recirculated exhaust  is cooled in order to  be  effective.   This practice promotes fouling.
 EGR has not been field tested  for large engines, and has  been rejected  by one manufacturer  of heavy-
 duty diesel truck engines and  limited  by another manufacturer.   EGR has potential  application in
 naturally aspirated  engines if full  load EGR  cutoff  is  provided to prevent excessive smoke  (<10
 percent opacity).  EGR,  however,  has been applied successfully  in  combination with other techniques,
 such as retard,  in gasoline-fueled automobile engines (References  4-56, 4-57).
        Water  injection,  similarly, has  serious maintenance and  durability problems associated with
 mineral  deposit  buildup  and oil  degradations.   Despite  use of demineralized  water  and increased
 oil  changes,  the control  problems associated  with engine  startup and shutdown  persist.   This
 factor,  coupled  with the need  for a  water source, has led  manufacturers  to  reject  this technique
 (Reference  4-56).
        Combustion  chamber modifications  such  as  precombustion and  stratified  chambers  have  demon-
 strated  large  NOX  reductions,  but  also  produce substantial  fuel consumption  increases  (5  to 8  per-
 cent more than open  chamber designs).  With the  rapid increases in  the  price of diesel fuel and
 gasoline, manufacturers  have been  reluctant to implement  this technique.   In fact, one manufacturer
 of divided  chamber engines  is vigorously  pursuing development of low emission open chamber engines
 (Reference  4-56).
       Table 4-20 summarizes emission reductions  achieved with large bore engines  by use of retard,
 air/fuel ratio changes, derating,  and reduced  inlet manifold air temperature (MAT).  This table
 includes only those techniques from Table 4-19 which could be readily applied by the user.  The
 cited emission reductions are based on results obtained from engines tested in manufacturers'
 laboratories.  Therefore, some uncertainty exists concerning durability  and maintenance over longer
periods of operation.  In general, the  greatest NOX reductions are accompanied by the larger
increases in fuel consumption.   This is a direct result  of reducing peak combustion temperatures
and,  thus, decreasing thermal  efficiency.
                                                4-64

-------
                 TABLE 4-19.   SUMMARY OF NOX  EMISSION  CONTROL TECHNIQUES  FOR
                                 RECIPROCATING  INTERNAL COMBUSTION  ENGINES
CONTROL
RETARD
Injection (CI)a
Ignition (SI)b
CHANGE AIR-TO-FUEL (A/F)
RATIO
DERATE
INCREASE SPEED
DECREASE INLET MANIFOLD
AIR TEMPERATURE
EXHAUST GAS RECIRCULATION
(tGR)
External
Internal
valve over! ap
or retard
exhaust back
pressure
CHAMBER MODIFICATION
Precombustion (CI)
Stratified charge (SI)
WATER INDUCTION
CATALYTIC CONVERSION
PRINCIPLE OF REDUCTION
Reduces peak temperature
by delaying start of
combustion during the
combustion stroke.
Peak combustion tempera-
ture is reduced by off-
stoichiometric operation.
Reduces cylinder pres-
sures and temperatures.
Decreases residence time
of gases at elevated
temperature and pressure.
Reduces peak temperature.
Dilution of incoming com-
bustion charge with inert
gases. Reduce excess
oxygen and lower peak
combustion temperature.
Cooling by increased
scavaging, richer
trapped air-to-fuel
ratio.
Richer trapped air-to-
fuel ratio.
Combustion in ante-
chamber permits lean
combustion in main cham-
ber (cylinder) with less
available oxygen.
Reduces peak combustion
temperature.
Catalytic reduction of
NO to Ng.
APPLICATION
An operational adjustment. Delay
cam or injection pump timing (CI);
delay ignition spark (SI).
An operational adjustment. In-
crease or decrease to operate on
off-stoichiometric mixture. Reset
throttle or increase air rate.
An operational adjustment, limits
maximum bmepc (governor setting).
Operational adjustment or design
change.
Hardware addition to increase
aftercooling or add aftercooling
(larger heat exchanger, coolant
pump).
Hardware addition; plumbing to shunt
exhaust to intake; cooling may be
required to be effective; controls
to vary rate with load.
Operational hardware modification:
adjustment of valve cam timing.
Throttling exhaust flow.
Hardware modification; requires
different cylinder head.
Hardware addition: inject water into
Inlet manifold or cylinder directly;
effective at water-to-fuel ratio *
1 (kg H20/kg fuel).
Hardware addition: catalytic con-
verter installed in exhaust plumbing
or reducing agent (e.g. ammonia)
injected into exhaust stream.
BSFCd
INCREASE
Yes
Yes
Yes
Yes
No
No if EGR
rates not
excessive
Yes
Yes
Yes
No
No
COMMENTS — LIMITATIONS
Particularly effective with moderate amount
of retard; further retard causes high exhaust
temperature with possible valve damage and
substantial BSFC increase with smaller NOX
reductions per successive degree of retard.
Particularly effective on gas or dual -fuel
engines. Lean A/F effective but limited by
misfiring and poor load response. Rich A/F
effective but substantial BSFC, HC, and CO
increase. A/F less effective for diesel-
fueled engines.
Substantial increase in BSFC with additional
units required to compensate for less power.
HC and CO emission increase also.
Practically equivalent to derating because
bmep is lowered for given power requirements.
Compressor applications constrained by vibra-
tion considerations. Not a feasible tech-
nique for existing and most new facilities.
Ambient temperatures limit maximum reduction.
Raw water supply may be unavailable.
Substantial fouling of heat exchanger and flow
passages; anticipate increased maintenance.
May cause fouling in turbocharged, aftercooled
engine. Substantial increases in CO and smoke
emissions. Maximum recirculation limited by
smoke at near rated load, particularly for
naturally aspirated engines.
Not applicable on natural gas engine due to
potential gas leakage during shutdown.
Limited for turbocharged engines due to
choking of turbocompressor.
5 to 10 percent increase in BSFC over open-
chamber designs. Higher heat loss implies
greater cooling capacity. Major design
development.
Deposit buildup (requiring demineralization) ;
degradation of lube oil, cycling control
problems.
Catalytic reduction of NO is difficult in
oxygen-rich environment. Cost of catalyst
or reducing agent high. Little research
applied to large-bore 1C engines.
'compression ignition
 Spark ignition
cbmep -- brake mean effective pressure
dBSFC -- brake specific fuel consumption
                                                     4-63

-------
        Numerous investigators have studied  control  techniques  to  reduce  NO   in  diesel-fueled auto-
 motive truck applications.   Many of these studies  are  summarized  in  Reference 4-57.   Retard, turbo-
 charging,  aftercooling,  derating and combinations  of these  controls  are  techniques  that are current-
 ly utilized by manufacturers to  meet California  heavy-duty  vehicle  (>2700 kg, or 6000 Ib) emission
 limits for diesel-fueled engines.
        Table 4-21  lists  five samples of  NOX  control  techniques currently implemented  by truck
 manufacturers to meet  the 1975 California 13.4 g/kWh*  (10 g/hp-hr) combined NO  and HC emission level
 Manufacturers indicate that greater reductions will  require (1)  increasing  degrees  of application
 of these controls  (and incurring additional  fuel penalties)  or,  (2)  application of  techniques  that
 need further development to overcome maintenance,  control,  and durability problems.   Controls  in
 this second category  include EGR,  water  injection,  and NO   reduction catalysts.
        Gasoline engine manufacturers,  in response  to Federal and  State regulations, have also  con-
 ducted considerable research of  emission control techniques  to reduce NO ,  as well  as  HC and CO,
                                                                        X
 levels.   Efforts in this area  have been  directed at  reducing emissions to meet  (1)  Federal and
 California heavy-duty  vehicle limits,  and (2) Federal  and California passenger  car  emissions limits.
 Table 4-22 lists Federal  and State emission  limits,  and Table 4-23 lists the various  controls  that
 are used  in several combinations by manufactures to  meet these limits.  Table 4-24  gives specific
 examples of control techniques recently  applied to meet Federal light duty  vehicle  emission limits.

        Based on the preceding discussion, potential N0x emissions reductions for stationary recipro-
 cating engines can be summarized  as follows:

        t    Controls such as retard, air-to-fuel  ratio change,  turbocharging, inlet air cooling (or
             increased after cooling), derating and combinations of these controls  have been  demon-
             strated to be effective and could be  applied with no  required lead  time for development.
             Fuel penalities, however, accompany  these techniques  and may exceed  5  percent  of the
             uncontrolled consumption.

        •   Exhaust gas recirculation, water injection, catalytic  conversion and precombustion  or
            stratified  charge techniques  involve  some lead time to develop as well  as  time to address
            maintenance and  control problems.
*
 rated shaft output
                                                4-66

-------
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-------
                  TABLE'4-22.   1975 VEHICLE EMISSION LIMITS

Passenger Car,
g/kWh (g/mi)a
California
Federal
Light duty truck^
g/kWh (g/mi)
California
Federal
Heavy duty vehicles,
g/kWh
California
Federal
NOX

6 (2.0)
9 (3.1)

6 (2.0)
9 (3.1)
HC

3 (0.9)
4 (1.5)

6 (2.0)
6 (2.0)

13
21
CO

26 ( 9)
44 (15)

59 (20)
59 (20)

40
53
Emissions limits are estimated in g/kWh from g/mi  assuming an average of 38.4
km/hr requiring 8195 W (11  bhp)  for the 7-mode composite cycle.
 TABLE 4-23.   EMISSION CONTROL TECHNIQUES FOR AUTOMOTIVE  GASOLINE  ENGINES
Control
NOX:
Rich or lean A/F ratio
Ignition timing retard
Exhaust gas recirculation
(5 to 10 percent)
Catalytic converters
(reduction)
Increased exhaust back pressure
Stratified combustion
HC, CO:
Thermal reactor
Catalytic converter (oxidation)
Exhaust manifold air injection
Positive crankcase ventilation
Comment
Increased bsfc, HC, and CO
Increased bsfc, HC, and CO, amount
of control limited by potential
exhaust valve damage
Increase bsfc and maintenance
related to fouling, smoking limits
degree of control
In developmental stage
Increase bsfc
Requires different cylinder head,
increased bsfc
Very effective in reducing HC, CO
Requires periodic catalyst element
replacement
Increased bsfc to power air pump
Reduces HC evaporative losses
                                    4-68

-------
TABLE 4-21.  CONTROL TECHNIQUES FOR TRUCK SIZE
             DIESEL ENGINES [<375 kW (500 HP)]
             TO MEET 1975 CALIFORNIA  13.4 G/KWHR  .
              10 G/HP-HR) COMBINED NOY AND HC LEVEL1
           Control
   Percent
bsfc^ Increase
  Retard, modify fuel
  system and turbocharger

  Retard, modify fuel
  system and turbocharger,
  add aftercooler

  Add turbocharger and
  aftercooler0

  Retard0 (naturally
  aspirated version)

  Precombustion chamber
      3


      3


    5 - 8
   lBased on Federal 13 mode composite cycle

   'bsfc = brake specific fuel consumption

   'Stationary versions of this engine would
   require a cylinder head with four exhaust
   valves rather than existing two valves.
                       4-67

-------
        •   NO  control  technology  for automotive  applications  can  be  adapted  to  stationary engines;
            however,  NO   reductions and attendant  fuel  penalties  for automotive applications are
            closely related  to  the  load cycle,  which  in some  cases  may differ  from  stationary
            applications
        •   Viable  control techniques  may  involve  an  operational  adjustment, hardware addition, or
            a  combination of both
        0   Additional research is  necessary  to
            —   Establish controlled levels for gaseous-fueled  engines (<75 kW/cylinder, or
                100 hp/cylinder)
            -   Establish controlled levels for medium-powered  diesel  and  gasoline  engines based
                on  stationary application  load  cycles
            -   Supplement the  limited emissions data available for large  bore engines

4.3.1.2   Costs
       As discussed earlier, stationary engines are unregulated for gaseous pollutants.  Consequently,
few data are available for field-tested controlled engines,  particularly  for large  (>375 kW or  500
hp) engines.  Sufficient data exist, however, to give order  or  magnitude  NOX control  costs for  the
following engine categories:
        •   Natural gas-, dual-, and diesel-fueled engines above  75 kW/cylinder
            (100 hp/cylinder)
        •   Small  to medium  (<75 kW/cylinder) diesel-fueled  engines
        •   Gasoline-fueled  engines (10 kW to 375  kW)
        Costs  for large  stationary  engines can  be  estimated  based on Reference 4-58 and information
 supplied by Reference 4-56.  These costs, however,  relate to emission reduction  achieved by engines
 tested in laboratories  rather  than to field  installations.   Reference 4-59 indicates, nevertheless,
 that these data are representative.
        In contrast to the large stationary engines,  more published cost  data  exists  for smaller
 (<375 kW, 500 hp)  gasoline  and diesel engines  which  must meet  State (California) and Federal
 emission limits for mobile  applications.   Stationary engines in  this  size range  are  versions of  these
 mobile engines.  Therefore, costs  can be  estimated based on  a  technology  transfer  from mobile  appli-
 cations to stationary service, keeping in mind that  in some  cases  mobile-duty cycles (variable
                                                4-70

-------




















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- ra «+-
3 T3 0
J
J CO C
3 C O
O -r-
•r- 4-)
r co ra
3 co i-
- •,- 0
J E -r-
J CU i-
3 CU
cnoE *-> ce. 
-------
    TABLE 4-25.  COST IMPACTS OF NOX CONTROLS FOR LARGE-BORE ENGINES
                                       Cost Impact
Retard


Air-to-fuel changes


Derate


Manifold air cooling



Combinations of above

Control techniques
Increased fuel consumption, more frequent
maintenance of valves

Increased fuel consumption, more frequent
maintenance of turbocharger

Fuel penalty, additional hardware, and increased
maintenance associated with additional units

Increased cost to enlarge cooling system, and
increased maintenance for cooling tower water
treatment

Initial, fuel, and maintenance

Increases as appropriate
            TABLE 4-26.   TYPICAL BASELINE COSTS FOR LARGE
                         (>75 kW CYLINDER) ENGINES3
Costs
1. Initial,6 $/kW
2. Maintenance,
$/kWh
3. Fuel and lube,
$/kWh
Total Operating,
2 + 3
Gas
174
4 x 10'3
10 x TO'3
14 x 10'3
Dual Fuel
174
4 x 10~3
10 x 10-3
14 x TO'3
Diesel
174
4 x 10-3
23 x 10"3
27 x 10'3
           Based on Reference 4-58 and information supplied to
           Reference 4-56 by manufacturers.

           Includes basic engine and cooling system.
                                 4-72

-------
 load)  can  differ  from stationary-duty cycles  (rated load).  Hence, costs (e.g., fuel penalties)



 associated with a control technique used in a stationary application may vary from the mobile case.




        Control costs for the three categories discussed above may include:




        •   Initial  cost increases for control hardware and/or equipment associated with a particular



           control  (e.g., larger radiator  for manifold air cooling or more engines as a result of



           derating)




        •   Operating cost increases which  consist of either increased fuel consumption and/or in-



           creased  maintenance associated  with NO   control system




        •   Combinations of  initial and operating cost increases





 Control Costs  for Large Bore Engines




        Table 4-25 lists cost impacts for control techniques available to users of large stationary



 engines.   These cost impacts may be related to actual installations using baseline data presented



 in  Table 4-26.  In  practice, these figures vary depending on the application, but, in general,



they are representative  of  the  majority  of  applications.   Basically, these controls involve  an operat-



ing  adjustment  with  the  exception  of derating  and manifold air cooling, which would require  hardware



additions.   Derating is  not  a viable technique for  existing  installations unless additional  units



can  be added  to satisfy  total power  requirements.




       The  impact  of the above  control  costs may vary  considerably given  the  following considera-



tions:




       •   Standby (<200hr/yr)  application  control  costs  are primarily a  result  of  initial



           cost increases  due  to  the emission  control, whereas continuous  service  (>6000  hr/yr)



           control  costs are largely a  function of  fuel  consumption  penalties




       •   Controls  which  require  additional  hardware  with no  associated  fuel penalty (e.g.,



           manifold  air-cooling)  may be more  cost effective  in continuous  service  (>6000  hr/yr)



           than operating adjustments which impose  a fuel  penalty  (e.g.,  retard, or air-to-



           fuel change)




       •   The  price of fuel can  affect the impact  of a  control  which  incurs  a  fuel penalty.



           For  example,  a control  which imposes a fuel  penalty of  5  percent  for  both  gas  and



           diesel  engines has  more impact on  the diesel  fueled engine  because diesel  oil  costs



           about 40 percent more per Joule  than natural  gas.   This  impact will  diminish  if gas



           prices increase more rapidly than  oil  prices.
                                                 4-71

-------
TABLE 4-28.   ESTIMATES OF STICKER PRICES FOR EMISSIONS  HARDWARE  FROM 1966  UNCONTROLLED
             VEHICLES TO 1976 DUAL-CATALYST SYSTEMS (Reference 4-57)
Model
Year
1966
1968
1970




1971-
1972




1973






Configuration
PCV-Crank Case
Fuel Evaporation
System
Carburetor Air/Fuel Ratio
Compression Ratio
Ignition Timing
Transmission Control
Sys tern
Total 1970
Anti-Dieseling
Solenoid
Thermo Air Valve
Choke Heat Bypass
Assembly Line Tests,
Calif (1/10 vol)
Total 1971-1972
OSAC (Spark Advance
Control)
Transmission Changes
(some models)
Induction Hardened Valve
Seats (4 and 6 cyl )
EGR (11 - 14%)
Exhaust Recirculation
Air Pump — Air
Injection System
Quality Audit, Assembly
Line (1/10 vol)
Total 1973
Typical Hardware
Value
Added
1.90
9.07
0.61
1.24
0.61
2.49

3.07
2.49
2.74
0.18

' 0.48
0.63
0.72
5.48
27.16
0.23

Price
2.85
14.25
0.95
1.90
0.95
3.80

4.75
3.80
4.18
0.57

0.95
0.95
1.90
9.50
43.32
0.38

Excise
Tax
0.15
0.75
0.05
0.10
0.05
0.20

0.25
0.20
0.22
0.03

0.05
0.05
0.10
0.50
2.28
0.02

Sticker
Price
3.00
15.00
1.00
2.00
1.00
4.00
8.00
5.00
4.00
4.40
0.60
14.00
1.00
1.00
2.00
10.00
45.60
0.40
60.00
                                        4-74

-------
Control Costs for Small  and Medium Gasoline- and Diesel-Fueled Engines
       Control costs for these engines can be characterized by analogy to those incurred to meet
State and Federal emission limits for automotive vehicles.   Again, these costs consist of initial
purchase price increases for control  hardware and increased operating costs (fuel and maintenance
cost increases).
       Table 4-27 lists  typical costs for techniques implemented for 1975 diesel-fueled truck
engines.  These costs are presented to indicate order of magnitude effects.  More research is
required to relate specific emission  control reductions to  initial and operating cost increases for
stationary engine applications.
       Table 4-28 gives  control hardware costs to meet gasoline-fueled passenger vehicle emission
limits through 1976.  Note that cost  increases correspond to increasingly more complex controls to
meet more stringent emission limits.
           TABLE 4-27.  TYPICAL CONTROL COSTS FOR DIESEL-FUELED  ENGINES USED  IN HEAVY-DUTY
                        VEHICLES  (>2700 kg OR 3 tons)
      Vehicles'
              Initial
                   baseline
                             engine
                             cooling system
                      turbocharger
                      aftercooler
                      EGR
                             $40-$67/kW ($30-$50/hp)
                             8X-14X engine
                             $4/kW ($3/hp)
                             6%-10% engine
                             $3-$4/kW ($2-$3/hp)
             Operating
                  Fuel:
                  Maintenance:
Fuel penalties range from 3 to 8 percent for various techniques.
Typical present fuel cost:  $0.095/1iter ($0.36/gallon) #2 diesel
or $2.13-$2.37/GJ ($2.25-$2.50/106 Btu).
EGR system will require periodic cleaning.   Note that turbo-
charged, aftercooled engines require additional maintenance for
the turbocharger and aftercooler compared to a similarly rated
naturally aspirated version.
     Based on  information supplied to Reference 4-56 by manufacturers.
                                                 4-73

-------
       Figure4-14 illustrates the effect of various control techniques on fuel economy.  Fuel
cost increases can be easily derived from typical gasoline costs, presently $0.55-0.75/gallon.
In addition to this operating expense, control techniques utilizing catalysts and EGR require peri-
odic maintenance.
       Manufacturers, in addition, incur certification costs for gasoline and diesel-fueled engines
which must meet State and Federal regulations.  These costs are passed on to the user in the form
of increased initial costs.  Manufacturers of diesel-fueled engines report these costs range from
$50,000 to $100,000 for a particular engine family.  This can result in a $125 cost per engine
based on a low sales volume family.

4.3.1.3   Energy and Environmental Impact
       The energy impacts of applying NO  controls to stationary reciprocating 1C engines are mani-
fested almost exclusively through corresponding increases in fuel consumption (bsfc).   Typical
percentage increases as a function of applied control were discussed in detail previously in
Sections 4.3.1.1 and 4.3.1.2.
       Potential adverse environmental impacts occur through increases in emissions of combustion-
generated pollutants other than NO  attendant to applying a NOX control.  Since 1C engines emit
only an exhaust gas effluent stream, impacts through liquid and solid effluents need not be con-
sidered.  In addition, since 1C engines fire "clean" fuels (natural gas and distillate oil) incre-
mental effects on the emissions of such pollutants as SO  and trace metals are relatively unimpor-
tant.  Thus, the following discussion will focus on the measured effects of specific NOX control
techniques on incremental emission of CO, HC, and particulate (smoke).   Again, all  available data
were obtained in tests on laboratory engines.  Nevertheless, such data  should be representative.
Carbon Monoxide
       As discussed in Section 4.3.1.1, the most common NOX reduction techniques applied to 1C
engines include derating, ignition retard, altering air/fuel  (A/F)  ratios,  reducing manifold air
temperatures (MAT), and water injection.   The effects of each of these  N0y  controls on engine CO
emission levels are summarized in Table 4-29.
       As indicated,  baseline CO emissions from two-cycle engines  are generally  lower than  those
from four-cycle engines.   However, derating two-cycle engines increases  CO  emissions  50 to  100 per-
cent, while  derating four-cycle engines actually gives  a 60 to 100  percent  decrease in CO levels.
                                               4-76

-------
TABLE 4-28.   ESTIMATES OF STICKER PRICES FOR EMISSIONS HARDWARE FROM 1966 UNCONTROLLED
             VEHICLES TO 1976 DUAL-CATALYST SYSTEMS (Reference 4-57) (Concluded)
Model
Year
1974





1975














1976



Configuration
Induction Hardened
Valve Seat V-8
Some Proportional EGR
(1/10 vol at $52)
Precision Cams, Bores,
and Pistons
Pretest Engines -
Emissions
Calif. Catalytic Con-
verter System (1/10 vol
at $64)
Total 1974
Proportional EGR
(acceleration-
deceleration)
New Design Carburetor
with Altitude
Compensation
Hot Spot Intake Manifold
Electric Choke (element)
Electronic Distributor
(pointless)
New Timing Control
Catalytic - Oxidizing-
Converter
Pellet Charge (6 Ib at
$2/lb)
Cooling System Changes
Underhood Temperature
Materials
Body Revisions
Welding Presses
Assembly Line Changes
End of Line Test Go/No-Go
Quality Emission Test
Total 1975
2 N0x Catalytic Converters*
Electronic Control3
Sensors9
Total 1976
Typical Hardware
Added
0.72
3.21
2.44
1.80
4.02

20.07
7.52
2.87
2.67
4.35
1.40
18.86
12.00
1.17
0.63
0.67
0.13
1.85
1.22

22.00
28.00
3.00

List
Price
1.90
4.94
3.80
2.85
6.08

30.02
14.25
4.75
4.75
9.50
2.85
34.20
20.52
1.90
0.95
1.90
0.95
2.85
1.90

37.05
47.50
5.70

Excise
Tax
0.10
0.26
0.20
0.15
0.32

1.58
0.75
0.25
0.25
0.50
0.15
1.80
1.08
0.10
0.05
0.10
0.05
0.15
0.10

1.95
2.50
0.30

Sticker
Price
2.00
5.20
4.00
3.00
6.40
20.60
31.60
15.00
5.00
5.00
10.00
3.00
36.00
21.60
2.00
1.00
2.00
1.00
3.00
2.00
138.20
39.00
50.00
6.00
134.00
      1976 most common  configuration
                                        4-75

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-------
   1.5
   1.0
   0.5
                                                  VARYING EGR AND
                                                SECONDARY AIR RATES
                           10                     20
              INCREASE IN BSFC, percent (OVER UNCONTROLLED VEHICLE)
                                                                        3.0
                                                                        2.5
                                                                        2.0
                                                                           cc
                                                                           =)
                                                                           Q
                                                                           LLJ

                                                                        1.5"

                                                                           cc
                                                                           D_
                                                                           C/J

                                                                           C)

                                                                            X

                                                                        1.0°
                                                                        0.5
30
 X
o
                                 GENERAL CORRELATION               	

                                 ESTIMATED FOR ADDITION OF NOX CATALYST
                                 BED AT 75 PERCENT EFFICIENCY

                                 VARYING DRIVING CYCLES

                                 AND CONTROL TECHNIQUES            	
                                     1	1
                5         10         15         20         25
              INCREASE IN BSFC, percent (OVER UNCONTROLLED VEHICLE)
     cc
     =3
     a
     LU
     o
     o
     cc
                                                                          00
                                                                          >
                                                                          o
                                                                           x
                                                                          O
30
 Figure 4-14. Effect of NOX emissions level on fuel penalty for light duty trucks
 (Reference 4-59].
                                   4-77

-------
                                                      O 2 CYCLE, BLOWER SCAVENGED
                                                      D 2 CYCLE, TURBOCHARGED
                                                      A 4 CYCLE, NATURALLY ASPIRATED
                                                      O4CYCLE, TURBOCHARGED
                                                     G  NATURAL GAS
                                                     DF DUAL FUEL               	
                                                     0  DIESEL
                                   20               30
                                   POWER DERATE, percent
           Figure 4-15. Effect of derating on 1C engine HC emissions (Reference 4-56).
1000
                                        O 2 CYCLE, BLOWER SCAVENGED
                                        D2CYCLE.TURBOCHARGEO
                                          4 CYCLE NATURALLY ASPIRATED
                                        <>4 CYCLE,TURBOCHARGED
                                       G  NATURAL GAS
                                       DF  DUAL FUEL
                                       D  DIESEL
  20
                                   4               6
                                  TIMING RETARD, degrees
 Figure 4-16.  Effect of retarding ignition timing on 1C engine HC emissions (Reference 4-56).
                                        4-80

-------
         Retarding  ignition  generally  causes  increased CO output for all engines.  This is somewhat
  expected,  though,  since  retarding  ignition  decreases both peak combustion temperature and combustion
  gas  residence  time, which  can  lead to  incomplete combustion.  Both increasing A/F ratios and reduc-
  ing  manifold air  temperature (MAT) has little effect on CO levels.  However, decreasing A/F causes
  50 to  100  percent  increases in CO emissions.  Water injection seems not to affect CO emissions from
  gas  and dual fuel  engines, but increases diesel engine CO emissions by 60 to 130 percent.
  Hydrocarbons
        The use of  N0y combustion controls on 1C engines can also have significant effects on HC
  emissions, with different N0x reduction techniques eliciting different effects.
        As shown in Figure 4-15, derating causes HC emissions to increase,  with the increase becom-
  ing more pronounced as load is  further reduced.   As the figure illustrates,  derating can cause a 20
  to 130 percent increase in HC emissions.   Figure 4-16  shows  the effect of  ignition retard on incre-
 mental  HC emissions.   In  contrast to  the effects of engine derating,  ignition retard tends  to
 decrease slightly  or not  affect emissions of HC.  However,  in  cases where  retarding  ignition initi-
 ally  reduces  HC emissions,  increasing the degree of ignition retard seems  to have little further
 effect.  The  data  in  the  figure indicate  that HC emissions decrease on the average of 30 percent
 when  ignition  is retarded 3 to  8  degrees.
        Changing the air-to-fuel  (A/F) ratio,  decreasing manifold air temperature  (MAT) and water
 injection  can all  result  in increased HC  emissions.  As shown  in Figure 4-17, both increasing and
 decreasing  the  A/F  ratio  by 10  percent  increases HC  levels 20  to 65 percent.  Larger  percentage
 increases occur in  engines  with high baseline emissions.  Figure 4-18  shows analogous effects when
 MAT is  decreased.   Decreasing 10  to 20  K  (20 to  40 F) increases HC emissions 5 to 50  percent.  HC
 levels  increase as  MAT is further reduced.  Turbocharged engines exhibit the largest  percentage
 emissions increases.  Water injection also increases HC emissions from 1C engines regardless of the
 baseline HC level,  as shown in Figure 4-19.  Average increases  of 16 to 25 percent have been experi-
 enced for water/fuel (W/F) ratios of 0.1 to 0.25.
 Particulates
       Virtually no data are available specifically on  particulate emission rates from stationary
 1C engines because  it is difficult,  time consuming,  and  expensive to measure  particulate  emissions
from these engines  directly.  Instead, exhaust gas opacity  readings have been used as a substitute
measure of particulate emissions.  These readings effectively measure  particulate since a relation-
ship between visible smoke and particulate mass  emissions has been  established  for medium power
                                                4-79

-------
1000
                                     ODF
 O 2 CYCLE, BLOWER SCAVENGED
 D 2CYCLE.TURBOCHARGED
 O4CYCLE.TURBOCHARGED
G  NATURAL GAS
OF DUAL FUEL            	
D  DIESEL
                                     MAT DECREASE. UK
  Figure 4-18. Effect of decreased manifold air temperature (MAT) on 1C engine HC emissions
  (Reference 4-56).
1000
                                                        O 2 CYCLE, BLOWER SCAVENGED
                                                        O4CYCLE.TURBOCHARGED
                                                       G  NATURAL GAS
                                                       DF DUAL FUEL
                                                       D  DIESEL
                                    0.4              0.6
                                          W/F RATIO
     Figure 4-19. Effect of water injection on 1C engine HC emissions (Reference 4-56).
                                           4-82

-------
1000
                                                      O 2 CYCLE, BLOWER SCAVENGED
                                                      CD 2CYCLE,TURBOCHARGED
                                                      O4CYCLE,TURBOCHARGED
                                                     G   NATURAL GAS
                                                     DF  DUAL FUEL
                                                     D   DIESEL
                            -10             0            10
                                 CHANGE IN A/F RATIO, percent
    Figure 4-17. Effect of air-to-fuel ratio on 1C engine HC emissions (Reference 4-56).
                                         4-81

-------
                                      NOX LEVEL, g/kWh
                                    12            16
                                                                20
        24
OQ
s
x
cj
<
QC
CO
ec
o
CO
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OQ
                            CONTROL CODE
             AIR-TO-FUEL RATIO     I
             REDUCE COMP. RATIO   M
             DERATE              R
             EXTERNAL EGR
                 INDUCTION        S
                                      INTERNALEGR
                                      MANIFOLD AIR TEMP.
                                      RETARD IGNITION
                                      TIMING
                                      INCREASE SPEED
                                         R     #5   I
*^\FUEL
TYPE^\^
2 STROKE
BLOWER
SCAVENGED
2 STROKE
TURBO-
CHARGED
4 STROKE
NORMALLY
ASPIRATED
4 STROKE
TURBO-
CHARGED
DIESEL
0
D
A
•
DUAl
FUEL



O
                                             3.
                                             4.
                                               ENGINE CODE NUMBER (#) DENOTES INITIAL POINT.
                                               CONTROL CODE DENOTES LEVEL AFTER CONTROL.
                                               BACHARACH AND BOSCH METERS ARE FILTER-TYPE
                                               INSTRUMENTS.
                                               SMOKE LEVELS FOR ENGINES #8-12 WERE MEASURED
                                               WITH A BOSCH METER.
                                               FINAL SMOKE LEVEL IS AT END OF LINE HAVING
                                               CONTROL CODE.
 s 10
0.
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<
a.
O
         #34
                                            #12
                                           CR#8 #9
                                         10       12
                                       NOX LEVEL, g/hp-hr
                                                            14
16
18
20
               Figure 4-20. Smoke levels versus NOX levels for large bore diesel engines.
                                               4-84

-------
 diesel engines (Reference 4-60 and 4-61).  Therefore, 1C engine smoke emissions are generally re-
 ported as percent plume opacity, or as Bosch or Bacharach smoke spot numbers.
        The plumes from most large-bore engines are nearly invisible when the engine is operating
 at steady-state.   However, applying NOX combustion controls can significantly  affect smoke emissions.
 Figure 4-20 shows the relationship between smoke emissions and NO  reduction as a function of NO
                                                                  x                              x
 control for those engines where data were reported on both pollutants.   As the figure shows,  NO
 controls, other than derating, generally increase smoke emissions, while derating decreases smoke
 levels.  Ignition retard and exhaust gas recirculation (EGR)  cause the  most significant increases
 in smoke level.
        Since N0y  controls which caused smoke levels to exceed 10 percent opacity were considered
 unacceptable in the  tests summarized in Figure 4-20,  none of  the data points for controlled engines
 are above this value.   However, the effect of progressively applying  ignition  retard  and  EGR  on
 smoke emissions is best demonstrated by data which include higher smoke levels.   Such data  are  pre-
 sented in Table 4-30 for two-cycle  diesel  engines,  and clearly  show that smoke  emissions  increase
 progressively as  percentage  EGR or  degree  of retard  is increased.
        In summary, experimental  data  have  shown  that  applying conventional  combustion modification
 NOX controls to 1C engines can  cause  increases  in  CO,  HC,  and particulate  (smoke) emissions.  This
 is  so because the combustion conditions  required to prevent NOX  formation  generally lead  to less
 complete  combustion.

 4.3.2  Gas Turbines
        Gas turbines  contributed only  2  percent of the annual stationary source NO  emissions in
 1974,  or  236 Gg (2.6 x  10s tons).  They do,  however, comprise a very rapidly growing  source with
 increasing application  in intermediate and base load power generation, pipeline pumping, natural gas
 compression, and onsite electrical generation.  The increasing application of gas turbines carries
with  it the potential for increasing the N0y emission contribution from these sources.  In response
to this, the frequency of control technique demonstration and implementation has increased in  the
past several years.
       Uncontrolled  NOX emissions are a function of turbine size (or efficiency) and fuel  type.   In-
creasing the turbine  size (or efficiency) increases the N0y concentrations primarily due to higher
combustion temperatures and to increased residence time at high  temperatures.  Oil-fired turbines
generally have higher NOX concentrations than gas-fired units.   Typical  uncontrolled NO  emissions
from gas turbines  are illustrated in Figures 4-21  and 4-22 for large and small  units,  respectively.
                                                 4-83

-------
  250
   200
CM
o
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QC
   150
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h-
Z
LU
U
z
o
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 X
o
   100
    50
                              O GAS-FIRED UNITS

                              D OIL-FIRED UNITS

                         NOTE:  DATA NOT ADJUSTED FOR
                                GAS TURBINE EFFICIENCY
                                       D
                                                      D
                                   D
                                   O
       PROPOSED NSPS
                   10
                                15            20

                                         TURBINE SIZE, MW
                                                            25
30
                                                                                        35
   Figure 4-21.  NOX emissions from large gas turbines without NOX controls!Reference 4-62).
                                              4-86

-------
             TABLE 4-30.  RELATIONSHIP BETWEEN SMOKE,
                          EGR, AND RETARD
                          (Reference 4-56).
Engine Type
2-cycle, Blower
Scavenged Diesel






2-cycle,
Turbocharged Diesel



Control a

None
10% EGR
20% EGR
39% EGR
4° advanceb
None
4° retard

None
4.9% EGR
8.4% EGR
12.1% EGR
Opacity, %

4.7
12
27.5
59
2.7
4.6
10

7.5
10.0
11.5
14.8
All EGR data based on hot EGR.

Injection advance is not a control; data included to show trend
                             4-85

-------
Imposed on these figures is the proposed NSPS  of 75  ppm for  these  sources.   Very  few  units meet these
standards in the uncontrolled state.
4.3.2.1   Control Techniques
       Combustion modification techniques for  gas turbines differ  from those of boilers  since  turbines
operate at a lean air/fuel  ratio with the stoichiometry determined primarily by the allowable  turbine
inlet air temperature.   The turbine combustion zone  is  nearly adiabatic and  flame cooling for  NOX
control is achieved through dilution  rather than radiant cooling.   The majority of NOX formation in
gas turbines is believed to occur in  the primary mixing zone, where locally  hot stoichiometric flame
conditions exist.  The  strategy for NO  control  in gas  turbines  is to  eliminate the high temperature
stoichiometric regions  through water  injection,  premixing, improved'primary  zone  mixing, and down-
streamed dilution.
       Combustion modifications for ^as turbines are classified  into wet and dry  techniques.   Wet
methods, such as water  and  steam injection, presently provide substantial  reductions.  As yet, no
combination of dry methods  has been successful on field units in reducing emissions below a  typical
standard of 75 ppm NO  at 15 percent  oxygen.  Presently available  wet  and dry methods for NO  reduc-
                     "                                                                       X
tion are aimed at either reducing peak flame temperature, reducing residence time at  peak flame
temperature, or both.  These techniques, along with  their reduction potential  and future prospects,
are shown in Table 4-31.
       Wet techniques are the most effective methods yet implemented with reduction potentials as
high as 90 percent for  gas  and 70 percent for  oil fuels.   With wet control,  water or  steam is  intro-
duced into the primary  zone either by premixing with the fuel prior to injection  into the combustion
zone, by injection into the primary airstream, or by direct  injection  into the primary zone.   The
effectiveness of each method is strongly dependent on atomization  efficiency and  primary zone  resi-
dence time.  In the case of water injection, peak flame temperatures are reduced  further through
vaporization of the water.
       Although NOX reduction is quite effective, numerous difficulties offer incentive  to the
development of dry controls.  If dry  controls  are developed  as expected, the long-term future  of
wet control does not appear promising based on the following inherent  problems of wet controls:
       0   Requirements for "clean" water or high-pressure steam
       •   Hardware requirements which increase plant size
       t   Delivery system  hardware which results in increased failure potential  and  overhaul/
           maintenance  time
                                                 4-88

-------
  200
  150
CJ
oc
   100
o
o
 X
o
                                O GAS-FIRED UNITS

                                D OIL-FIRED UNITS

                            NOTE: DATA NOT ADJUSTED FOR
                                  GAS TURBINE EFFICIENCY
                                                            D
                                                                          D
                                                                          D
      PROPOSED NSPS
50P_


  P
      D
     0
               0.5
                                1.0
2.0
                                                                          2.5
                                            1.5

                                      TURBINE SIZE, MW


Figure 4-22. NOX emissions from small gas turbines without NOX controls (Reference 4-62).
                                                                                    3.0
                                           4-87

-------
        •    Uncertainty  regarding  long-term control effects on turbine components.
        Although  few combinations  of presently available dry controls have the NO  reduction poten-
 tial of the wet  methods, many dry techniques are used in conjunction with water or steam injection,
 particularly on  larger  units.  On the smaller units, dry controls may be sufficient to meet stan-
 dards.  The dry  controls now available are:
        •    Lean  out primary zone - Reduces NOX  levels up to 20 percent by lowering peak flame
            temperatures.  This option allows less control over flame stabilization and reduces
            power output but is an attractive control to be built into future low NO  combustors.
        •    Increase mass flowrates — Possible NO  reductions up to 15 percent by reducing
            residence time at peak flame temperature.  This control essentially increases
            the turbine speed at constant torque and is not feasible in many applications.
        t    Earlier quench with secondary air - This is a minor combustor modification which
            entails upstream movement of the dilution holes to reduce residence time at peak
            temperatures.  This is a promising control  which is generally employed in advanced
            combustor research.
        •    Reduce inlet air preheat -A control  applicable only to regenerative cycle units.
            It is not attractive due to reduction in efficiency.
        t   Air blast and air assists atomization - Use of high-pressure air to improve atomiza-
            tion and mixing requires replacement of injectors and addition of high-pressure air
           equipment.   This control  is considered an excellent candidate for incorporation into
            new low NO  design combustors.
        •    Exhaust gas recirculation - Possible NOX reduction of 30 percent.   A candidate dry
           control  for future design, though it has limited application in some online units.
           EGR requires extensive retrofit relative to other dry controls and also  requires a
           distinct set of controls  for the EGR  system.
       Other minor combustor modifications are  generally  aimed  at  providing  favorable  interval  flow
patterns in the primary zone and  fuel/air  premixing.   The  bulk of  these  modifications  are combus-
tor-specific and are being investigated by the manufacturer.   In general,  dry controls  available
for immediate implementation have not exceeded 40 percent  NOX  reduction  and as  such may be  insuffi-
cient controls  for the larger  units  at present.   Since dry techniques approach  NO   reduction dif-
ferently than do wet controls,  their effects  are complementary and, consequently, can  be  used  toge-
ther.  Figure 4-23 illustrates  the effect  of  dry and wet controls  used separately and  in  combination
                                                4-90

-------
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-------
for liquid fuels (Reference 4-62).  The figures show dry controls to be not sufficiently developed
to meet the standards, whereas wet controls are sufficient.
       Future NOX control in gas turbines is directed toward dry techniques with emphasis on com-
bustor design.  Medium term (1979-1985) combustor designs incorporate improved atomization methods
or prevaporization and a premixing chamber prior to ignition.  These developmental  combustors are
projected to attain emission levels of 20 ppm NO  at 15 percent oxygen.  A possible long term option
is catalytically supported combustion.  Laboratory tests have given NOX reductions  of up to 98 per-
cent while maintaining stable, complete combustion.  This concept - described in Section 3.1.5.2 of
this report -will  probably require a new combustor design to accomodate it (Reference 4-57 and
4-62).

4.3.2.2   Costs
       The most recent cost study of N0x controls for gas turbines has been performed by the EPA
(Reference 4-62).  Based on information presented in this study, the best available system of emis-
sion reduction considering costs are the wet systems.  Wet systems can be applied to turbines imme-
diately and their cost impact is minimal.  Although dry control techniques may be preferable
because of their minimal impact on efficiency,  their complete development and application to large
production turbines is still several years away.   Cost considerations for dry methods are,  therefore,
not discussed.
       Table 4-32,  derived from Reference 4-62, shows the expected increase in installed turbine cost
that will  result from using water injection to  control NOX to the proposed standard of 75 ppm.   The
impact varies from  0.8 percent in the case of the 820 kW (1100 hp) standby unit to  7.1  percent for
the unit requiring  extensive water treatment equipment.
       Table 4-33 presents a summary of the costs in mills/kWh which would be incurred  for 11
simple cycle turbine plants to meet the 75 ppm  standard.  This analysis was part of a cost model
developed  in an EPA report (Reference 4-62).  The results for each case are explained below.
Standby Units
       The first two cases, S-l and S-2, differ only in the number of hours operated annually.   Unit
S-l operates 80 hours and S-2 200 hours per year.  These units show the highest percentage impact in
terms of the incremental costs per net kWh of power generation.  The low number of  hours operated
each year  tends to  increase the cost of producing power because fixed costs are spread  over a  rela-
tively small  base.   The estimated impact in both  cases was roughly 2.4 percent.
                                                4-92

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                                          4-93

-------
        In summary, the resulting estimates showed that, except for standby units, the total  change
 in costs will probably fall in the range of 0.4 to 1.5 mills per kWh for turbines used in industrial
 and utility applications.  This cost is equivalent to about a 2 percent increase in operating costs.
 Control costs for standby units were much higher, ranging from 2 to 14 mills per kWh.  This  is pri-
 marily due to their low use factor.  This cost is equivalent to approximately a 2.5 percent  increase
 in operating costs.

 4.3.2.3   Energy and Environmental Impact
       As was the case for reciprocating 1C engines, the energy impacts of applying NO  controls to
 gas turbines occur almost solely through effects on unit fuel consumption, which were noted  in the
 foregoing discussion.  Dry controls, except for reduced air preheat applied to regenerative  cycle
 turbines, have insignificant effects on unit efficiency.  On the contrary, wet controls can  impose
energy penalties.  Water injection at the rate of 1 kg H20/Kg fuel  reduces turbine efficiency by
 about 1 percent.  If waste steam is available, steam injection can  increase turbine efficiency by
 increasing turbine power output at constant fuel input.  But, if a  fuel debit is taken for heat
 needed to raise injection steam, overall plant efficiency losses comparable to those experienced
with water injection will occur.
       Again, as with 1C engines, gas turbines emit only an exhaust gas effluent stream and  fire
 "clean" fuels.  Thus the potential environmental impacts of NO  controls applied to gas turbines
will  occur through incremental  effects on emissions levels of exhaust  gas CO, HC, and particulate
 (smoke).  Effects through liquid and solid effluents need not be considered, and incremental
impacts on SOX, trace metal, and, to some extent, higher molecular  weight organic emissions  are
 insignificant.
       The effects of some commonly applied NOX control techniques  on  CO emissions from gas  turbines
are summarized in Table 4-34.   From the table, it is apparent that  dry controls, notably leaning
the primary zone and air blast  (or air-assist atomization) reduce CO levels.  This is expected  since
the additional air introduced  into the combustor when applying these techniques allows more  complete
fuel  combustion.   On the other  hand,  wet control techniques,  such as water injection, tend to quench
combustion and give lower combustor temperatures.   This leads to incomplete combustion and increased
CO levels as  shown in Table 4-34.
       The very limited data on incremental  hydrocarbon emissions due  to NOX combustion controls
applied to stationary gas turbines are summarized  in  Table 4-35.  As the table  shows,  the  effects
of dry NOX controls are mixed.   Air blast tends  to increase HC emissions while  leaning the primary
zone  tends to decrease HC levels.   Increased  combustion efficiency  due  to higher combustion
                                                4-96

-------
       Cases S-3 and S-4 are 820 kW (1100 hp)  units  operating the  same  number  of hours,  respectively,
as the smaller 260 kW units.  These units can  use exactly the same water purification  system  as  the
smaller units.  Since the costs of producing power independent of  the water injection  system  (the
baseline cost) are identical  between cases S-l  and  S-3 and S-2 and S-4, the percentage  impact of
NOX control is decreased to less than one percent.

Industrial Units
       Case 1-1 represents a normal, single shaft gas turbine application.   The unit is  operated
2000 hours per year and is slightly oversized.  This negates any benefits that might be  derived  from
improved unit output.  For Case 1-2, also a baseload turbine, a credit  was taken for the improved
capacity of the unit.
       The highest cost impact was recorded in Case 1-3, which represents a remote turbine applica-
tion in an arid climate in which water must be transported fifty miles  at a cost of 2tf per gallon.
The impact in such cases, including water storage facilities, is approximately a 3.7 percent  in-
crease in the average cost of generating power.   Since water injection  results in a slight increase
in the power output capacity of the unit, a credit of 0.05 mills per kWh was taken for the output
enhancement.

Utility Applications
       The first unit operated 200 hours, the second 500 hours, the third 2000 hours, and the fourth
8000 hours annually.  A credit for enhanced output was taken in the last case, since the unit is
baseloaded.   In all four cases, the impact is  less than 2 percent.

Offshore Drilling Platform
       Initially, it was thought that this case would evidence the highest cost impact.   The  unit
was assumed to use sea water to fuel the water purification system, resulting in a substantial
increase in the capital and operating cost of the system.  The installed cost of the water treat-
ment equipment was $27,000, compared to $14,000 for an onshore application.  Despite these higher
costs, the availability of water offset the costs associated with transporting water to the remote
gas compressing station application  (1-3).  The total cost of water injection for the offshore plat-
form was 0.92 mills/kWh compared to  1.21 mills/kWh for the remote site.
       In  the EPA cost model, no attempt was made to provide detailed estimates of the control costs
for regenerative and combined cycle  gas turbines.  The cost impacts, in absolute terms, are not
expected to be much  greater than for simple cycles.  Indeed, the percentage impacts will be less,
given  the  higher cost per kW of generating capacity of these units.
                                                4-95

-------
 temperatures tends to support this latter observation.   The  effects  of applying wet controls are
 also mixed.  As indicated in the table,  with water injection at  a water-to-fuel (W/F) weight ratio
 of 0.5, HC emissions increased for turbines  having high  baseline HC  emissions, but decreased for
 turbines which emitted low baseline HC  levels.
        The data on particulate emissions from gas  turbines resulting from applied NO  controls are
 also very limited and are as inconclusive regarding the  increment in particulate emissions from
 NOX controls as those for incremental CO and hydrocarbon emissions.  For example, the effect of
 water injection on particle emissions seems  to  be  related to the specific injection method used
 (Reference 4-62).   Some tests show smoke level  reduction of  1.5  to 1.75 smoke spot numbers when
 water injection is used.   Other tests, however,  indicate increased particulate emissions with water
 injection at peak load.
        In summary,  the limited  data  available on the incremental effects of NO  controls on CO, HC,
 and particulate emissions  suggest  that the control  techniques do not significantly affect these
 emissions.   While  dry techniques appear  to decrease CO emissions and wet controls seem to increase
 CO  levels,  even these data,  as  well  as those on effects  on HC and particulate levels, are inconclu-
 sive.

 4.4    SUMMARY
        Table 4-36  summarizes  current and emerging NOX control technology for the major source cate-
 gories.   These  results show  that current technology is dominated by  combustion process modifica-
 tion.   Emerging  technology is also centered around combustion modifications.  Other approaches,
 such as  flue gas treatment, may be used  in the 1980's to augment combustion modification if
 required  by  stringent emission  standards.
       The level of combustion modification control available for a  given source depends on the
 importance of that source in regulatory programs.  Utility boilers  have been the most extensively
 regulated and accordingly, the technology is the most advanced.   Available  technology ranges  from
 operational adjustments such as low excess air and biased burner firing to  inclusion  of  overfire
 air ports or low NOX  burners in new units.   Some adverse operational impacts  have  been  experienced
with the use of combustion modification  on existing equipment.  In general  these have  been  solved
 through combustion engineering or by limiting the degree  of  control application.  With factory-
 installed controls on new equipment, operational  problems have been minimal.
       The technology for other sources  is less  well developed.   Control techniques shown effective
for utility boilers are being demonstrated on existing  industrial boilers.   Here, as for utility
                                                 4-98

-------
TABLE 4-34.  REPRESENTATIVE EFFECTS OF NOX CONTROLS ON CO EMISSIONS FROM GAS TURBINES (Reference 4-62)
NOX Control
Lean Primary Zone
Air Blast/
Piloted Air Blast
Water Injection
Fuel
Natural Gas
Kerosene
Diesel
Kerosene
Diesel
Natural Gas
Diesel
CO Emissions (ppm)a
Baseline
102
102
53
195
969
53
147
252
99
135
93
NOX Control
51
96
99
59
110
36
1134
1512
144
162
30
               13% 02, dry basis.   Emissions  levels at full  load.
            TABLE 4-35.  SUMMARY OF THE EFFECTS OF NOX CONTROLS ON VAPOR PHASE HYDROCARBON
                         EMISSIONS FROM GAS TURBINES (Reference 4-62)
NOX Control
Air Blast
Lean Primary Zone
Water Injection
Fuel
Jet-A
Natural Gas
Diesel Fuel
Kerosene
Natural Gas
Diesel Fuel
HC Emissions (ppm)a
Baseline
18
9
33
30
3
27
234
141
36
24
N0x Control
41
11
9 - 12
12
7
12
372
246
27
12
Comment
Idle
Full load
Full load
/ W/F = 0.5
               3% 02, dry basis.
                                                4-97

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                                                              4-99

-------
4-16   Crawford, A. R., e_t aJL,  "Field Testing:  Application of Combustion Modifications to Control
       NOX Emissions from Utility Boilers," EPA-650/2-74-066, June 1974.

4-17   Selker, A. P. and R. L. Burrington, "Overfire Air Technology for Tangentially Fired Utility
       Boilers Burning Western U.S. Coal", Proceedings of the Second Stationary Source Combustion
       Symposium. Vol. II. Utility and Large Industrial Boilers, EPA 600/7-77-0735, July 1977.

4-18   Jain, L. K., et al.,  "State of the Art for Controlling NOX Emissions, Part I:  Utility
       Boilers," EPA-R2^72-072a, September 1972.

4-19   Hollinden, G. A.", et al_., "Evaluation of the Effects of Combustion Modifications in Controlling
       NOX Emissions at TVA's Widow's Creek Steam Plant," EPRI SR-39, February 1976.

4-20   Friedrich, J. L., e_t al_., "Nitrogen Oxides Reduction," Foster Wheeler Energy Corporation,
       EPRI SR-39, February 1976.

4-21   Ando, J., and H.  Tohata,  "NOX Abatement for Stationary Sources in Japan," Environmental Pro-
       tection Technology Series, EPA-600/2-76-013, January 1976.

4-22   Lyon, R. K., and J.  P. Longwell, "Selective, Noncatalytic Reduction of NOX with Ammonia,"
       In:  Proceedings of the NOX Control Technology Seminar, EPRI Special Report SR-39, February
       1976.               ~             '

4-23   Muzio, L. J., J.  K.  Arand, and D.  P. Teixeira, "Gas Phase Decomposition of Nitric Oxide in
       Combustion Products," In:  Proceedings of the NQV Control Technology Seminar.  EPRI Special
       Report SR-39, February 1976.

4-24   Schreiber, R. J., e_t a\_.,  "Boiler Modification Cost Survey for Sulfur Oxides  Control by
       Fuel Substitution," Environmental  Protection Technology Series, EPA-650/2-74-123, November
       1974.

4-25   Frendburg, A., "Performance Characteristics of Existing Utility Boilers When Fired with
       Low-Btu Gas," EPRI Conference Proceedings, Power Generation, Clean Fuels Today, April 1974.

4-26   Agosta, J. e_t al_., "Status of Low Btu Gas as a Strategy for Power Station Emission Control,"
       presented at the 65th Annual Meeting of the American Institute of Chemical  Engineering,
       November 1972.

4-27   Martin, G. B., D. W. Pershing, and E.  E. Berkau, "Effects of Fuel Additives on Air Pollutant
       Emissions from Distillate Oil-Fired Furnaces," EPA, Office of Air Programs AP-87, June 1971.

4-28   Shaw, H., "Reductions of Nitrogen Oxide Emissions from a Gas Turbine Combustor by Fuel
       Modification," ASME Trans., Journal of Engineering for Power,  Vol.  95, No.  4,  October 1973.

4-29   Kukin, I., "Additives Can Clean Up Oil-Fired Furnaces," Environmental Science  and Technology,
       Vol. 2, No.  7, July 1973.

4-30   Bartok, W., e_t aj_.,  "Systems Study of Nitrogen Oxide Control Methods for Stationary Sources -
       Vol. II," prepared for National Air Pollution Control  Administration, NTIS Report No.
       PB-192-789, Esso Research and Engineering, 1969.
4-31
Blakeslee, C. E., and A. P. Selker, "Program for the Reduction of NOX from Tangential Coal-
Fired Boilers, Phase I," Environmental Protection Technology Series, EPA-650/2-73-005,
August 1973.
4-32   Kelley, D.  V., data submitted at the EPRI NOX Control  Technology Seminar, San Francisco,
       by Pacific  Gas and Electric Company, February 1976.

4-33   Letter from the Los Angeles Department of Water and  Power to Acurex Corporation, May 5,
       1975.
                                                  4-102

-------
  boilers,  the emphasis  in emerging  technology is  on  development of  controls  applicable  to  new unit

  design.   Advanced  low  NOX burners  and/or advanced off-stoichiometric  combustion  techniques  are  the

  most promising concepts.   This  holds  true for the other  source categories as  well.   The R&D emphasis

  for gas  turbines and reciprocating 1C engines is on developing optimized combustion  chamber designs

  matched  to  the burner  or fuel/air  delivery system.
                                       REFERENCES  TO  SECTION  4


 4-1     Lachapelle,  D.  G.,  J.  S.  Bowen,  and  R.  D.  Stern,  "Overview  of  the  Environmental  Protection
        Agency's  NOX Control  Technology  for  Stationary  Combustion Sources,"  presented  at the  67th
        AIChE Annual  Meeting,  December  1974.

 4-2     Teixeria,  D.  P.,  R.  E. Thompson,  "Utility  Boiler  Operating  Modes for Reduced Nitric Oxide
        Emissions  with  Oil  Fuel  Firing,"  presented  at the 66th Annual  Meeting of the Air Pollution
        Control Association,  Chicago, June 1973.

 4-3     Bartok, W.,  e_t  aj.,  "Systematic  Field  Study of  NOX Emission Control  Methods for  Utility
        Boilers,"  Esso  R  &  E,  Report GRU.4GNOS.71,  December 31,  1971.

 4-4     Barr,  W. H.,  "Nitric  Oxide Control -A  Program  of Significant  Accomplishments,"  ASME  Paper
        72-WA/PWR-13, 1972.                                                                    M

4-5     Blakeslee, C. E., "Reduction of NOX Emissions by  Combustion Modifications to a Gas-Fired
        250-MW Tangential Fired Utility Boiler," presented at Conference on  Natural Gas  Research
        and Technology, Atlanta, Georgia, June 5-7, 1972.

4-6     Blakeslee, C. E.  and  H.  E. Burbach,  "Controlling  NOX  Emissions from  Steam Generation,"
        JAPCA, Volume 23, No.  1, January  1973.

4-7     Halstead, C. J.,  et al_.,  "Nitrogen Oxides Control  in  Gas-Fired Systems Using Flue Gas Recircu-
        lation and Water.Injection," IGT/AGA Conference on Natural  Gas Research and Technology,
        Atlanta, Ga., June  1972.

4-8     Bagwell, F. A., et aj_.,  "Utility  Boiler Operating Modes  for Reduced  Nitric Oxide  Emissions,"
        JAPCA, Volume 21, No. 11, November 1971.

4-9     Habelt, W. W., and A. P. Selker,  "Operating Procedures and  Prediction for NOx Control in
        Steam Power Plants," presented at Central States  Section of the Combustion Institute, Spring
        Meeting, March 1974.

4-10    Norton, D. M., K. A. Krumwiede, C. E. Blakeslee,  and  B.  P. Breen,  "Status of Oil-Fired NOX
        Control Technology," In:  The Proceedings of  the  NQ₯  Control Technology Seminar, EPRI
        Special Report, SR-39, February 1976.

4-11     Barr, W. H., F.  W. Strehlitz, and S.  M. Dalton,  "Retrofit of Large Utility Boilers for
        Nitric Oxide Emission Reduction - Experience and  Status  Report," presented at AIChE 69th
        Annual Meeting, November 1976.

4-12    Crawford,  A. R., et a].. "The Effect of Combustion Modification on Pollutants and Equipment
        Performance of Power Generation Equipment," In:    Proceedings of the Stationary Source Combus-
        tion Symposium,  EPA-600/2-76-152c, June 1976.	

4-13   Thompson,  R. E., M.  W. McElroy,  and R.  C. Carr,  "Effectiveness of Gas Recirculation and Staged
        Combustion in Reducing NOX on a  560 MW Coal-Fired Boiler," In:   Proceedings of the NOX Control
       Technology Seminar,  EPRI Special Report SR-39, February 1976.             	'

4-14   Selker, A. P., "Program for Reduction of NOX from Tangential Coal-Fired Boilers,  Phase II  and
        I la," EPA 650/2-73-005a and b,  June 1975.

4-15    Hollinden,  G. A.,  "NOX Control  at TVA Coal-Fired Steam Plants," Proceedings of Third National
       Symposium,  ASME Air  Pollution Control Division,  April  24, 1973.
                                                4-101

-------
 4-54    Heap,  M.  P.,  ejt  al_.,  "Reduction  of  NO  emissions  from  Package  Boilers,"  Revised  Draft  Final
        Report by Ultra  Systems,  Inc.,  Irvine, California.

 4-55    McGowin,  C. R.,  "Stationary  Internal Combustion  Engines  in  the  United States,"  EPA-R2-73-210,
        April  1973.

 4-56    "Standard Support  and  Environmental  Impact  Statement  — Stationary  Reciprocating Internal  Com-
        bustion Engines,"  (Draft  Report).   Acurex Corp./Aerotherm Division,  Mountain  View,  California,
        Project 7152,  March  1976.


 4-57    Aerospace Corporation, "Assessment  of the Applicability  of  Automotive Emission  Control Tech-
        nology  to Stationary Engines," EPA-650/2-74-051, July  1974.

 4-58    The American Society of Mechanical  Engineers  (ASME),  "Power Costs, 1974 Report  on Diesel  and
        Gas Engines," March 1974.

 4-59    Calspan Corporation, "Technical  Evaluation  of Emission Control  Approaches and Economics of
        Emission  Reduction Requirements  for Vehicles  Between  6000 and 14000  Pounds GVW," EPA-460/73-
        005, November 1973.

 4-60    Bascom, R. C., et al., "Design Factors that Affect Diesel Emissions," SAE Paper 710484, July
        1971.

 4-61    Hills,  F.  J., et a]_.,  "CRC Correlation of Diesel Smokemeter Measurements," SAE  Paper  690493,
        May 1969.

 4-62    "Standards Support and Environmental Impact Statement, Volume I:   Proposed Standards  of
        Performance for Stationary Gas Turbines," EPA-450/2-77-017a, September  1977.

4-63   Shaw,  H., "The Effects of Water,  Pressure and Equivalence Ratio on Nitric Oxide Production
       in Gas Turbines," ASME Paper 73-WA/GT-l.

4-64   Hilt,  M. B. and Johnson,  R.  H., "Nitric Oxide Abatement in  Heavy Duty Gas Turbine Combustion
       by Means of Aerodynamic and  Water Injection," ASME  Paper 72-GT-53.

4-65   Stern, R.  D.,  "The EPA Development Program for NOX  Flue Gas  Treatment,"  In:   Proceedings  of
       the National  Conference on Health, Environmental  Effects, and  Control Technology of Energy
       Use,  EPA 600/7/76-002,  February 1976.            "               ~	~~	"	
                                                 4-104

-------
4-34   "Preliminary Environmental Assessment of Combustion Modification Techniques," Vol. II,
       EPA 600/7-77-1196, February 1977.

4-35   "Technology and Economics of Flue Gas NOX Oxidation by Ozone," EPA 600/7-76-033, December
       1976.

4-36   Kamo, R., e_t aJL , "The Effect of Air-Fuel Mixing on Recirculation in Combustion," Paper CP-
       62-12, API Research Conference on Distillate Fuel Consumption, June 1962.

4-37   Hegg, D. A., ejt aj_., "Reactions of Nitrogen Oxides, Ozone, and Sulfur in Power Plant Plumes,"
       EPRI EA-270, September 1976.

4-38   Richards, J. and R. Gerstle, "Stationary Source Control Aspects of Ambient Sulfates:   A
       Data Base Assessment," Pedco Final Report, EPA Contract No. 68-02-1321, Task 34, Pedco
       Environmental, Cincinnati, OH, February 1976.

4-39   Bennett, R.  L., and K.  T. Knapp, "Chemical Characterization of Particulate Emissions  from
       Oil-Fired Power Plants," presented at the 4th National Conference on Energy and the Environ-
       ment, Cincinnati, OH, October 1976.

4-40   Homolya, J.  B., ejt al., "A Characterization of the Gaseous Sulfur Emissions from Coal and
       Coal-Fired Boilers,^presented at the 4th National Conference on Energy and the Environment,
       Cincinnati,  OH, October 1976.

4-41   Hall, R. E., CRB, IERL, U.S. EPA, personal communication.

4-42   Locklin, D.  W. , et^ aj_. , "Design Trends and Operating Problems in Combustion Modifications
       of Industrial  Boilers," NTIS PB235-712/AS, 1974.

4-43   Krippene, B. C., "Burner and Boiler Alterations for NOX Control," Central States Section,
       The Combustion Institute, Madison, Wisconsin, March 1974.

4-44   Heap, M. P., e_t al_., "Burner Design Principles for Minimum NOX Emissions," EPA Coal Combus-
       tion Seminar,  Research Triangle Park, North Carolina, EPA 650/273-021, June 1973.

4-45   Lyon, R. K., "Method for the Reduction of the Concentration of NO in Combustion Effluents
       Using Ammonia," LL. S. Parent No. 3,900,554, assigned to Exxon Research and Engineering
       Company, Linden, New Jersey, August 1975.

4-46   Lyon, R. K.  and J. P. Longwell, "Selective, Non-Catalytic Reduction of NOX by NH3," Proceed-
       ings of the NOX Control Technology Seminar, EPRI SR-39, February 1976.

4-47   Campobenedetto, E. J., "The Dual Register Pulverized Coal Burner -Field Test Results,"
       presented at Engineering Foundation Conference on Clean Combustion of Coal, Franklin Pierce
       College, New Hampshire, July 31-August 5, 1977.

4-48   Teixeria, D. P., "Status of Utility Application of Homogeneous NOX Reduction," Proceedings of
       the NOX Control Technology Seminar, EPRI SR-39, February 1976.

4-49   Cato, G. A., et^ al_.,  "Field Testing:  Applications of Combustion Modification to Control
       Pollutant Emissions from Industrial Boilers — Phase 1," Environmental Protection Technology
       Series, EPA-650/2-74-078-a,

4-50   Cato, G. A., e_t al_.,  "Field Testing:  Application of Combustion Modification to Control
       Pollutant Emissions from Industrial Boilers — Phase 2," Environmental Protection Technology
       Series, EPA-600/2-76-086a, April 1976.

4-51   Heap, M. P., et_ al_.,  "Application of NOX Control Techniques to Industrial Boilers," Ultra-
       systems, Inc., presented at the 69th Annual Meeting of the AIChE, Nov. 28 to Dec. 2, 1976.

4-52   Cichanowicz, J. E., et_ aj_., "Pollutant Control Techniques for Package Boilers, Phase I
       Hardware Modifications and Alternate Fuels," (Draft Report) Ultrasystems and Foster Wheeler,
       November 1976.

4-53   Maloney, K.  L., "Western Coal Use in Industrial Boilers," Presented at the Meeting of the
       Western States Section of the Combustion  Institute, Salt Lake City, Utah, April 1976.
                                                4-103

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                                              SECTION  5




                                      OTHER  COMBUSTION  PROCESSES




        Significant amounts of the total fuels burned  and NO  emissions  released  in the United


 States  are associated with small-scale combustion processes.  These  include  important nonindustrial


 uses  in domestic and commercial heating,  hot water supply, a wide variety of  incinerators, and open


 burning of solid wastes.  The contribution to ambient N02 can be significant, particularly in local-


 ized, residential areas.  Control techniques, costs,  and energy and environmental impacts are dis-


 cussed  for those systems where .data are available.




 5.1     SPACE HEATING




        Residential and commercial space heating generated about 1.1 Tg  (1.2 x 106 tons) of NO


 during  1974, which accounts for approximately 9.0 percent of the total  national  stationary source


 N0x emissions (see Section 2).  Projections for nationwide emissions due to space heating have


 been made by the National Academy of Sciences (Reference 5-1).  These projections, shown in Table


 5-1, assume that approximately half of new housing units will use electricity for space heating.


 This assumption may be somewhat optimistic, from the  standpoint of NO , due to the recent high
                                                                     A

 rate of increase in the cost of electrical heat compared to oil  or gas firing.  The decline over


 the past 30 years in residential combustion, due to increased use of electrical  heat, may reverse


 if electrical heating costs continue to increase faster than fuel  costs.



       Hall,  et al_.  (Reference 5-2)  studied the factors that affect emission levels from residential


 heaters.  This project, which concentrated on an oil-fired warm air furnace, showed that excess air,


 residence time,  flame retention devices,  and maintenance are major factors in the control  of


emissions.



       As shown  in Figure 5-1, emissions  of CO,  HC,  smoke,  and  particulates pass through a minimum


as excess air is increased from stoichiometric conditions.   By contrast, both thermal efficiency and


NO emissions  pass through maximum points  as excess air is increased.   The experimental  results  showed


that increased residence time of the combustion  products reduces  emissions  of CO, caseous  HC, and


smoke but has no effect on NOX emissions.   Combustion  chamber material  was  found  to affect  all
                                                5-1

-------
emissions.   Furnaces with steel-lined chambers required higher excess air levels to reach Optimum



emission levels, thus reducing efficiency.   The shape of the combustion chamber had little effect



on pollutant generation.



       A specially designed flame retention device meant to decrease particulate emissions was



found to increase NO  emissions, but such a device also increased furnace efficiency.   Poor furnace



condition also yielded higher NO  emissions.





5.1.1  Control Techniques




       In a recent study of space heating equipment (Reference 5-3), emission levels were found to



be dependent upon boiler size, design, burner type, burner age, and operating conditions.  The



type of fuel used in the combustion equipment for space heating is important since 40 to 60 percent



of the fuel nitrogen present was converted to NOX-




       Currently available emission reduction techniques for space heating units are:   (1) tuning:



the best adjustment in terms of the smoke-CO^ relationship that can be achieved by normal cleanup,



nozzle replacement, simple scaling and adjustment with the benefit of field instruments, (2) unit



replacement:  installation of a new, advanced low-NO  unit, and (3) burner replacement:  installation



of a new low-emission burner.




       Reference 5-3 indicates that tuning has a beneficial effect on all pollutants with the excep-



tion of NO  .  In the field program, oil-fired units considered in "poor" condition were replaced and
          A


all others were tuned, resulting in reductions in smoke, CO, HC, and filterable particulate by 59,



81, 90, and 24 percent respectively, with no  significant change in NO  levels.




       Hall, e_t a]_.  (Reference 5-4) determined that gas-fired units exhibit emission levels similar



to an equivalent size high-pressure atomizing gun oil burner.  Table 5-2 shows mean emission levels



prior to and after  replacement or tuning.  Although tuning or replacement has been shown to have



little effect on NO  levels, yearly  inspection accompanied by one of these techniques is highly



recommended since other  pollutant levels are  so greatly reduced.




       Significant  emission  reduction can be  achieved by burner retrofit replacement.  Reference



5-3  found this  procedure to  produce  significantly lower levels of CO and filterable particulate.



In general, recently developed  burners have not demonstrated the ability to consistently reduce



NO   levels  while many, in  improving  combustion efficiency and reducing emissions of other pollutants,



actually increase NO  emission  over  the  standard burner.
                                                 5-4

-------
                              \OPTIMUM SETTING FOR MINIMUM
                                 EMISSIONS AND MAXIMUM
                          SMOKE       EFFICIENCY
                           (10TH
                                                                                        X


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                                   STOICHIOMETRIC RATIO


Figure 5-1. General trend of smoke, gaseous emissions, and efficiency versus stoichiometric ratio
for residential heaters (Reference 5-4).
                                             5-3

-------
       A number of commercially available burners were tested by Hall  (Reference 5-2)  wherein pol-



lutant levels were determined under typical  operation conditions.   Combustion-improving devices



yielded higher NO  levels than the standard  burner, but demonstrated a potential for reducing



levels of one or more pollutants and improving combustion efficiency.   Flame retention burners were



shown to be capable of operating at low excess air levels, resulting in increased combustion effi-



ciency with accompanied reduction in emission levels with the exception of N0x-




       An advanced residential warm air oil  furnace has been developed in an EPA-funded program



(References 5-5 and 5-6).  The furnace is said to increase the fuel utilization efficiency by up



to 10 percent.  In addition, a 65 percent reduction in NO  emission levels was realized.




       The advanced oil furnace design consists of an optimized oil burner and firebox combination.



The system has completed a 500 hour laboratory performance test.  The tests evaluated the effects



of combustion air swirl angle, nozzle spray angle, and axial injector placement on NO  emissions



levels for various oil flowrates and overall excess air combinations.   The optimum burner was a



nonretention gun-type with six swirl vanes set at a 26-degree angle.  The firebox design selected



was a cylindrical fin cooled firebox.  The optimum burner/firebox combination yielded emissions of



0.6 g NO/kg of fuel (1.2 Ib/ton) at 10 percent excess air compared to 2-3 g/kg (4-6 Ib/ton)  for the



baseline conmercial burners.  Operation at these low excess air levels combined with use of outside



air for combustion produced up to 10 percent increase in system efficiency (Reference 5-6).




       In a related study, Combs and Okuda (Reference 5-7) investigated the commercial feasibility



of an optimum low-NO  distillate oil burner head.  They reported that sheet metal stamping was the



best fabrication method for commercial production of the burner head.   They also investigated retrofit



possibilities and found that the optimum burner heads were operationally satisfactory and had long



life potential.




       Emissions of NO  from natural gas-fired furnaces were measured by the American Gas Associa-
                      A


tion Laboratories (Reference 5-8).  Measurements indicated that water-backed heat transfer systems



emitted higher levels of NO  compared to gas-to-air systems.  Also, multiport burners emitted



higher NO  levels than single port burners.   In another test, it was found that addition of a



radiant screen placed above a water heater burner resulted in a net reduction of NO  by about 55



percent.




       Another advanced burner/furnace design is the "Blueray" system (Reference 5-9).  This system



consists of a "blue flame" oil burner integrated with the firebox of a warm air furnace package.



Two sizes are currently available:  0.63 cm3 oil/sec (0.6 gph), and 0.789 cm3  oil/sec (0.75 gph).



The efficiency of the burner is reported to be about 84 percent and the NO  emission level is
                                                5-6

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discussed in Section 3.5,  offers the potential  for extremely low levels  of N0x (1-10 ppm)  when  firing
natural  gas or distillate oils.   Catalytic combustion is still  in the exploratory stage of develop-
ment and no reliable cost estimates are available for residential heating systems.
       The prospects for cost-effective NOX control in existing space heating units are not promis-
ing.  Furnace tuning and, if required, burner head replacement are strongly reconmended for reduc-
tion of carbon monoxide and smoke and for improving unit efficiency.  The impact on NOX is negli-
gible,  however.  Furnace tuning (cleaning, leak detection, sealing and burner adjustment) costs a
minimum of  $40 for  the average residential unit.  Burner head retrofit replacement costs an addi-
tional  $25  less installation.  These are usually cost effective  in view of the fuel savings and
increased  safety derived from the maintenance.
5.1.3   Energy and Environmental Impact

5.1.3.1   Energy Impact
        All  three NO  emission reduction  techniques  (tuning,  unit replacement  and burner replacement)
result  in  improved  system  efficiencies and,  consequently,  reduced fuel  consumption.   The  exact
amount  of improvement varies widely depending  on the type  of equipment.   The  most  promising method,
unit replacement,  appears  to offer in excess of 5 percent  fuel  savings.   On  a national  basis,  this
represents a potential  savings  of 0.6 percent  of annual fuel consumption if  all  space heating  equip-
ment were replaced  with'new designs.
 5.1.3.2  Environmental  Impact
        The effect of lower excess air on CO, HC, and particulate emissions was discussed  previously
 and is illustrated in Figure 5-1.  By constraining incremental emissions during control  development,
 however, it has been possible  to achieve low-NOx combustion conditions without adverse incremental
 emissions  (Reference 5-6).  Table 5-3 shows a comparison of typical uncontrolled units and a proto-
 type unit with an  optimized burner/firebox.   Incremental emissions were held constant or reduced
 at  the low-NO , high efficiency condition.  Table 5-3  also  shows incremental emissions with a com-
 mercially  available oil emulsifier  burner.  Again,  low N0y  operation was achieved with no adverse
 effects on  incremental emissions  (Reference 5-13).
        Over 90 percent of  residential and commercial warm air  furnaces fire  either natural  gas or
 distillate oil.  Emissions of  sulfates  and  trace metals from these units are thus of minor concern
 compared  to coal-fired boilers.   About  3 percent  of U.S. warm  air furnaces still  fire coal.   For
 these,  sulfates, trace metals  and  especially  ROM's  could cause severe  localized environmental
                                                  5-8

-------








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problems.   However, it is doubtful  that NOX controls,  except for fuel  switching,  will  be developed



and implemented for these sources,  and they will  not be considered further here^.




       An  additional  factor in evaluating incremental  emissions for warm air furnaces  is the cyclic



nature of  operation.   Warm air furnaces typically undergo two to five  on/off cycles per hour.   Studies



of emissions without  NO  controls show that the starting and stopping  transients  have  a strong,



sometimes  dominant, effect on total emissions of CO, HC and particulate (smoke) (References 5-2 and



5-3).  The effect of NO  controls on transient emissions is presently  unknown.  Incremental steady-



state emissions must eventually be weighed against the transient emissions for this significance



to be shown.




       Data on warm air furnace POM emissions under low-NOx operation  are apparently nonexistent.



Data on both transient and steady operation with and without NOX controls are needed to form a



general conclusion on the total incremental impact of N0x controls.  Additionally, it should be



emphasized that the incremental emissions data shown in Table 5-3 are for well maintained laboratory



operation.  Data are needed on long-term field operation with NOX controls.





5.2    INCINERATION AND OPEN BURNING





5.2.1  Municipal and Industrial Incineration










       According to a Public Health Service survey conducted in  1968  (Reference  5-14),  an average



of 2.5 kg  (5.5  pounds) of refuse and  garbage  is  collected  per capita  per  day  in  the United  States.



An additional  2  kg (4.5  pounds) per capita  per day are  generated  by incineration  of industrial



wastes, wastes  burned  in commercial and  apartment house  incinerators, and backyard burning.  The



total  per  capita waste generation  rate  is  conservatively estimated at about 4.5  kg (10  pounds)  per



day  (Reference  5-14).




        Incineration  is economically advantageous only  if land  is  unavailable  for  sanitary  landfill.



 Incineration  requires  a  large  capital  investment, and  operating  costs are higher  than for  sanitary



 landfill.




       The most common types  of  incinerators  use a  refractory-lined chamber with  a grate upon which



 refuse is  burned.  Combustion  products  are formed by  contact between  underfire air and  waste on the



 grates in  the primary  chamber.   Additional  air is admitted above the  burning  waste to  promote  burn-



 out  of the primary combustion  products.
                                                 5-10

-------
         Incinerators are used in a variety of applications.  The main ones are municipal and indus-
  trial solid waste management.  Municipal incinerators consist of multiple chamber units that have
  capacities ranging from 23 kg (50 pounds) to 1,800 kg (4,000 pounds).
  5.2.1.1  Emissions
         Nationwide N0x emissions  from incineration in 1974 amounted  to  39 Gg per year (43,400 tons
  per year)  which is 0.3 percent of the total  N0x  emissions from stationary sources.   Fifty-five
  percent of these emissions  result from industrial  incineration with  the  remainder due  to municipal
  incineration.   A number of other multimedia effluents from incineration  may be  of greater concern
  than NOX.   These include metallic  compounds  in the  particulate flyash  and  hopper ash and chlorinated
  organic and  inorganic  gaseous compounds.   Incinerator effluent rates are strongly dependent  on the
  composition  of  the  solid waste, the  incinerator design and specific operating variables such as
  excess air and  firing  rate.  The effluent rates can  vary  considerably from day  to day because of
  variations in refuse composition.  An  average emission factor  for incineration  of 1.5 g N02/ kg
  refuse (3 Ib/ton) was  reported by Niessen (Reference 5-15).  AP-42 (Reference 5-16) specifies the
  same value for multichamber industrial and municipal incinerators.  For  single chamber industrial
  incinerators, a  lower factor of 1 g N02/ kg refuse (2 Ib/ton) is specified.
        Stenberg, et a].., conducted field tests to ^tudy the effects  of  excess combustion air on  NO
                                                                                                   x
 emissions  from municioal incinerators (Reference  5ll7).   The  nitrogen oxide emissions ranged from
 0.7 g/kg (1.4 Ib/ton) to 1.65 g/kg (3.3 Ib/ton) of refuse charged for a 45.3 Mg  (50  ton)  per day
 batch-feed  incinerator and  a 227  Mg (250 ton)  per day continuous-feed incinerator.   As  shown in
 Figure 5-2,  NOX emissions  increase with increasing amounts of excess  air.  The amount of underfire
 air also has a significant  effect  on  N0x production and is shown in  Figure 5-3.
        In general,  nitrogen  oxide  emissions from  incineration  are not a primary  source of air pollu-
 tion; however,  particulate  emissions  are significant.   It  is   for this  reason that incinerator air
 pollution control  equipment  is adopted  to  the removal of particulate matter rather than NO
                                                                                          x'
 Activity in pollution abatement for incinerators to date has focused on particulate control  rather
than N0x.
5.2.1.2  Control Techniques
       The use of waste disposal methods other than combustion may be the most likely means for
reducing N0x emissions, since the methods normally used for control  of other emissions from inciner-
ation, such as particulate matter, organics,  and carbon monoxide,  tend to increase emissions of
                                                5-11

-------
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                                                   OFURNACE - BEFORE SCRUBBER
                                                       NOX = 0.081 + 0.00144 (PERCENT EXCESS)

                                                  DSTACK   -AFTER SCRUBBER


                                                       NOX = 0.093 + 0.00156 (PERCENT EXCESS)
                                 100
                                                             200
                                                                                          300
                                         EXCESS AIR, percent


  Figure 5-2. Effect of excess air on NOX emissions from a 45.3 Mg (50 ton)  per day batch-feed

  incinerator (Reference 5-17).
                                              5-12

-------
                                            NOX = 0.365 - 0.00183 (PERCENT UNDERFIRE AIR)
                                       UNDERFIRE AIR, percent

Figure 5-3. Effect of underfire air on NOX emissions from a 227 Mg (250 ton) per day continuous-
feed incinerator (Reference 5-17).
                                             5-13

-------
NO .   Other disposal  methods include dumping,  sanitary landfill,  composting,  burial  at sea,  disposal
  A

in sewers and hog feeding.


       One of the first refuse disposal  methods used was open dumping of refuse on land.   This


method is obviously very inexpensive, but extremely objectionable and offensive in and near popu-


lated areas.


       Sanitary land fills are good alternatives, to the extent that land usable for this purpose


is available.  Approximately 1233m3 (1  acre-foot) of land is required per 1000 persons per year


of operation for a waste production of 2 kg (4.5 pounds) per day per capita (Reference 5-18).  In


addition, cover material approximating 20 percent by volume of the compacted waste is required;


the availability of cover material may limit the use of sanitary landfill.



5.2.1.3  Costs


       At present, gaseous emission controls are not applied to incinerators.  As described earlier,


only  particulate emission controls  are employed.  Reference 5-19 presents estimated construction


costs  in 1966 and operating costs for particulate pollution control.



5.2.2  Open Burning



       Open burning  includes  forest wildfires,  prescribed  burning,  coal  refuse  fires, agricultural


burning,  and structural  fires.  Open  burning for solid  waste management  is usually  done  in  large


drums or  baskets,  in  large-scale  open dumps or pits  and on open  fields.   Commonly,  municipal  waste,


landscape  refuse,  agricultural  field  refuse, wood  refuse,  and  bulky industrial  refuse are disposed


of by open  burning.


 5.2.2.1   Emissions


        Emissions from open  burning are  affected by many variables  including  wind, ambient  tempera-


 ture, composition and moisture content  of the  debris burned,  and compactness of the pile.   Nitrogen

 oxides emissions depend mainly upon the nitrogen content of  the refuse.   Generally, due  to  the low


 temperatures associated with open burning, nitrogen oxides emissions are low.


        Annual emissions from open burning vary from year to  year,  and the data for the  various


 sources are not entirely consistent.  Table 5-4 shows the estimated NOX emissions from open burning
                                                  5-14

-------
 sources for 1971  as reported in Reference 5-20.   More recent estimates from the 1976 NEDS data file
 and Reference 5-21  are also given in Table 5-4.   Increasing awareness of air pollution problems
 has contributed to  a general decline in the quantity burned (and thus the emissions) from those
 categories which  can be controlled.   For example, despite the continuing growth in crop harvest,
 NOX emissions from  agricultural open burning has declined from an estimated 29 Gg (32,000 tons) in
 1969 to 13 Gg (14,300 tons) for 1973 (Reference  5-21).


                   TABLE 5-4.  ANNUAL EMISSIONS OF NITROGEN OXIDES FROM OPEN BURNING

Source

Solid Waste Disposal
Forest Wildfires
Prescribed Burning
Agricultural Burning
Coal Refuse Fires
Structural Fires
NOX Emissions
1971,
Reference 5-20
Gg
150
138
19
29
31
6
103 Tons
165
152
21
32
34
7
1976 NEDS
Gg
95
48
30
13a
53
5
103 Tons
105
53
33
14a
58
6
                         1973  estimate  from Reference  5-21.
5.2.2.2  Control Techniques
Solid Waste Disposal
       From the standpoint of air pollution, sanitary landfills are good alternatives to open burn-
ing.  In addition to the land necessary for sanitary landfill, cover material approximating 20
percent by volume of the compact waste is required.  The availability of cover material may limit
the use of the sanitary landfill method.
       Unusual local community factors may lead to unique approaches to the landfill  site problem.
For example, Reference 5-22 reports that in a pilot project the refuse is shredded and baled for
loading on rail cars for shipment to abandoned strip mine landfill sites.
       Other noncombustion alternatives may have application in some localities.   Composting is
now being tested on a practical  scale (Reference 5-23).   Hog feeding has been used for disposal
of garbage.  Dumping at sea has  been practiced by some seacoast cities, but is now extensively regulated,
                                                 5-15

-------
       Elsewhere, refuse has been ground and compressed into bales, which are then wrapped in chicken
wire and coated with asphalt.  The high-density bales sink to the bottom in the deeper ocean areas
and remain intact.  The practice of grinding garbage in kitchen units and flushing it down the sewer
has been increasing.  This in turn increases the load of sewage disposal plants and the amount of
sewage sludge (Reference 5-24).
Forest Wildfires
                                                                    122
       In the United States, forests comprise approximately 3.2 x 10  m  (786 million acres), or
34.4 percent, of the land area.  Seasonal forest fires are quite prevalent in dry western regions.
Considerable activity has been and is being directed toward reducing the frequency of occurrence
and the severity of these fires.  These activities include publishing and advertising information
on fire prevention and control, surveillance of forest areas where fires are likely to occur, and
various firefighting and control activities.  Additionally, prescribed burning is being used to
reduce the loading of combustible underbrush and thereby decrease the fire hazard and potential
fire spread rate.
                                                       10  2
       The U.S.  Forest Service estimated that 2.06 x 10   m  (5.11 million acres) of land were burned
in 1976 (the World Almanac, 1978).  A similar estimate for 1971 (Reference 5-20) was 1.73 x 1010 m2
(4.28 million acres) burned, producing 138 Gg (152,000 tons) of nitric oxides emissions.  Emissions
from forest fires are dependent on the local combustion intensity, the overall scale of the fire,
and, to some extent, the nitrogen content of the fuel.  These in turn are related to the topography
of the forest, the composition and dryness of the underbrush, the local meteorological conditions,
and the elapsed  time since a previous fire.  The topography of the forest, the composition and dry-
ness of the underbrush, the elapsed time since a previous fire and the meteorological condition are
all interrelated and dictate the burn rate and spread, intensity of the burn, and the size of the burn.
Prescribed Burning
       Prescribed burning is the use of controlled fires in forests and on ranges to reduce the pos-
sibility of wildfire and for other land management goals.  Four classes of open burning operations
are traditionally practiced by the Forest Service (Reference 5-25):
         •  Slash disposal resulting from forest harvesting operations
         •  Forest management operations for forest floor fuel  reduction, seedbed preparation, pest
            control, forest thinning and undergrowth control
         t  Public works construction operations to clear reservoir and dam-sites, utility and high-
            way  rights-of-way and building and structure site areas
                                                 5-16

-------
           t  Public works maintenance operations for the disposal  of reservoir driftwood and of
              rights of way and storm damage debris
  In addition, controlled burning is used to reduce unwanted quantities of waste and to improve land
  utilization.
           Because collection and incineration of these materials would tend to increase NO  emissions,
  the only current way to control emissions is to avoid combustion.   In the future it may be possible
  to develop incineration processes  that can  control  N0x and other emissions such as  particulate
  matter,  organics,  odorous  compounds,  and carbon monoxide;  or it may be possible to  develop equipment
  that can burn these materials  as substitutes for fossil  fuels.
           Other alternatives to incineration are abandonment or  burying at the site,  transport  to  and
  disposal in remote areas,  and  utilization.   Abandonment  or burning  at the site is practical  in cases
  where no other harmful  effects will ensue.   Abandoned or buried vegetation can have  harmful  effects
  upon plant life by hosting harmful  insects  or organisms, for example.   Agricultural  agencies such as
  the U.S.  Department of  Agriculture, or state and local agencies should be consulted  before  these
  techniques are employed.
  Agricultural  Burning
        Agricultural burning  includes the burning of residues  of field  crops,  row crops, and fruit
  and  nut  copes  for  at least one  of the  following  reasons  (Reference 5-21):
        t   Removal and disposal of residue at low cost
        •   Preparation of farmlands for cultivation
        •   Clearing to facilitate harvest
        t   Control of disease, weeds,   insects, or rodents
       Mitigation of the environmental   impact of agricultural open burning  is possible by proper
fire  and  fuel management (for example,   single-line backfiring), meteorologically scheduled burning
to optimize dispersion, or by the substitution of other alternatives, such as mobile  incineration,
incorporation into the soil, and mechanical removal.   Care must be exercised in the choice of alter-
nate methods of disposal  since a change in method may have significant adverse effects.   For ex-
ample, in. situ burning can provide thermal treatment to the  soil  which raises the production yield
substantially, incorporation of the residue into  the soil  may restrict rapid replanting, and residue
decomposition may deplete the soil nitrogen.
Coal  Refuse Fires
         An estimated 53 Gg (58,000 tons) of NOX  is emitted each year from burning coal  refuse.
Extinguishing and preventing these fires are the  techniques  used for eliminating these emissions.
                                                 5-17

-------
These techniques involve cooling and repiling the refuse, sealing refuse with impervious material, in-



jecting slurries of noncombustibles into the refuse, minimizing the quantity of combustibles in refuse,



and preventing ignition of refuse.   The NO  emissions from coal refuse fires are highly dependent on
                                          A


the nitrogen content of the coal.




Structural Fires




       There were almost one million buildings attacked by fire during 1971  with losses estimated at



$2.21 billion (Reference 5-20).   An estimated 6.3 Gg (7,000 tons) of NOX were emitted during 1971.



Prevention is the best control technique to reduce these emissions.  Use of fireproof construction,



proper handling, storage, and packaging of flammable materials, and publishing and advertising infor-



mation on fire prevention are some of the techniques used to prevent structural fires.




       Fire control techniques include the various methods for promptly extinguishing fires:  use of



sprinkler, foam, and inert gas systems; provision of adequate firefighting facilities and personnel;



provision of adequate alarm systems.  Information on these and other techniques for prevention and



control are available from agencies such as local fire departments, National Fire Protection Asso-



ciation, National Safety Council, and insurance companies.





5.3    INDUSTRIAL PROCESS HEATING





       Fossil fuel derived heat for industrial processes is supplied in two ways:  (1) by direct



contact of the raw process material to flames or combustion products in furnaces or specially-



designed vessels, and (2) by heat transfer media (e.g., steam, glycol or hot water) from boilers and



I.C. engines.  NO  emissions and control techniques for the latter equipment types have been de-
                 A


scribed in previous sections of this document.  The former equipment types are described in the



present section.  Industries covered include petroleum and natural gas, metallurgical, glass, cement,



and coal preparation plants.  Much of this section is taken directly from a recent study of indus-



trial process heating performed by the Institute of Gas Technology (Reference 5-28).




       There is currently very little application of NO  control to industrial process heating equip-



ment.  Consequently there are very few data on MO  control costs or energy and environmental impact,



and separate sections for these topics will not be included.  EPA's Industrial Environmental Research



Laboratory (RTP) is sponsoring a field test program to identify the potential for NO  control in a



diversity of process furnaces, ovens, kilns, and heaters.  Partial results from that study are given



in Reference 5-26 and are discussed, as appropriate, in the following subsections.  The complete



results of that program (scheduled for 1978) will provide a broad data base on which to evaluate



alternate control options.
                                                 5-18

-------
 5.3.1  Petroleum and Natural Gas
 5.3.1.1  Process Description
        Oil and gas production, gas plants, and pipeline stations are usually located in remote areas
 far from population centers.  Emissions do not, therefore, contribute substantially to ambient N0?
 levels in populous areas.  Petroleum refineries, however, are often located in or near densely popu-
 lated areas.
        Petroleum refining is the process of converting crude oil into salable products.  Crude oil
 is charged to an atmospheric pipestill  where light products are separated and taken overhead and
 light catalytic reforming feed,  raw gasoline, kerosene,  middle distillate, and heavy gas  oil are
 taken as sidestream products.   The reduced crude is charged to a vacuum pipestill  where heavy gas
 oil, lube stocks,  and residuum are cut.
        Atmospheric and vacuum  gas  oils  are charged to catalytic cracking units,  which provide light
 ends,  cracked gasoline,  and  fractions for blending distillate and residual  fuels.   Reduced  crude is
 used in making asphalt or residual  fuels, and is often fed to coking  units  to  increase  the  yield of
 distillate  products.   Catalytic  cracking and  coking produce propylene and butylene,  which are often
 alkylated with isobutane to  make alkylate.   Sometimes the  olefins are polymerized  for gasoline or
 chemical  production.   Catalytic  reforming increases the  octane number of naphtha by  converting
 naphthenes  (saturated  cyclic hydrocarbons)  and  paraffins to aromatics.   Hydrogen treating is used
 to reduce sulfur content,  increase  stability, and  improve  burning  characteristics  of kerosenes  and
 middle  distillates.
        The relative volumes of gasoline,  kerosene,  middle  distillate,  heavy fuel oil, etc.,  can  be
 adjusted  by diverting  heavy gasoline fractions  from gasoline  to middle distillate and cat-cracking
 feed, by  diverting coker feed to heavy fuel, and by other  changes.
       A  fluid-bed catalytic-cracking unit is often the heart of a modern refinery.  Preheated gas
 oil  is charged to a moving stream of hot regenerated catalyst while it is being transferred from
 the  regenerator to the reactor.  The gas oil is cracked in the reactor or the tube inlets to the
 reactor;  the  products then pass through cyclone separators for removal of entrained catalyst and are
 cut  into  products in a fractionator.  Coke forms on the catalyst during the reaction.
       Spent catalyst is withdrawn  from the bottom of the reactor and transferred to the regenerator
where coke is burned off.  The regenerator flue gas passes through cyclone separators for catalyst
removal  and is discharged through the stack.  The hot, regenerated catalyst flows back to  the
reactor, supplying  heat and catalyzing  the cracking reaction.
                                                5-19

-------
       The regenerator flue gas contains about 10 percent carbon monoxide.   This  gas  is  sometimes
fed to a CO boiler where it is burned in preheated air to generate steam.   Auxiliary  fuel  is
required to maintain satisfactory combustion conditions.
       Typical  refinery process heaters are the cabin-type furnace,  used for heat release  rates
above 44 MW (150 x 106  Btu/hr), and the vertical  cylindrical  furnace,  used  for heat duties below
23 MW (80 x 106 Btu/hr).   Either type may be used in the 23 to 44 MW (80 to 150 x 106 Btu/hr)
range.  Combustion boxes are lined with refractory.   Fuels may be liquid,  gas, or a combination of
both.  Gas burners operate with 10 to 40 percent excess air,  liquid  burners with  20 to 80  percent.
Stack temperatures are 478K to 756K (400F to 900F).

5.3.1.2  Emissions and Control Techniques
Process Heaters
       Oxides of nitrogen emissions in the petroleum and natural gas industries result from the com-
bustion of fuel in process heaters and boilers, and from internal combustion engines  used  to drive
compressors and electric generators.  Annual NOX emissions for 1974 from petroleum process heaters
are estimated to be 147 Gg (162,000 tons).  N0x control techniques for these sources  are described
in Section 4.2.1 of this report.
       Recent test data (Reference 5-26) on NO  emissions from both natural draft and mechanical
draft heaters are summarized  in Table 5-5.  Five vertically fired natural  draft heaters ranging in
size from 11 to 26 MW  (36 to 87 x 106 Btu/hr) were tested.  These units had 10 to 32 burners sized
about 940 ± 140 kW.  Baseline  NO  emission factors, which were in agreement with the findings of
Bartz (Reference 5-27), ranged from 39 to 52 ng/J (90  to  120 lb/109 Btu), considerably lower than the
EPA  emission factor for this  category of 95 ng/J  (220  lb/109 Btu).  Combustion modifications for  these
tests included  fuel heat content  variation, load  variation, burner air  register adjustment  and BOOS.
        Prior work by Bartz (Reference 5-27) had attributed large changes in NOX emissions to fluc-
tuations  in fuel gas composition.  However, the tests  reported in Reference 5-26 indicate that NOX
does  increase with increased  fuel heating value, although not to a significant degree.  The results
are  not conclusive, and more  tests with  different heaters and a wider variation in heating  value
are  needed.
        Two of the natural draft heaters  were tested during process rate changes of ±20 percent.
Figure  5-4 shows the observed  decrease  in NO  emissions as the load is  increased.  The probable
cause for  the  NO  reduction is  that  excess air was reduced as the load was  increased.
                                                 5-20

-------
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                                                 5-21

-------
   120
         1.50
PROCESS RATE, 1000 m3/d

         1.75
  2.00
   100
QC
a
o
QC
 X
o
    80
    60
    40
          REFINERY GAS FUEL
                 10
            12
                          PROCESS RATE, X 103 BARRELS/d
14
 Figure 5-4. Effect of process rate on NOX emissions from a process heater
 [Reference 5-26).
                                     5-22

-------
       Staged combustion for NO  control  was attempted by adjusting the air registers and taking
burners out of service.  Although NO  emissions were reduced (see Table 5-5),  the natural draft
heaters did not respond to burner adjustments as well  as expected, based on previous results with
other types of boilers.  There are three primary reasons for this.  First, in  most cases the burner
removal patterns resulted in increased excess air which could not be lowered to baseline levels be-
cause of furnace pressure limits.  Secondly, the design of natural draft burners utilizes the fuel
flow as an aid to induce combustion air.   This acts to defeat the attempt to achieve staged com-
bustion.  Finally, the in-line vertically-fired burner arrangement used for most heaters does not
provide much inter-burner mixing, a necessary feature of staged combustion.
       Two mechanical draft heaters, one with air preheat, were tested while firing either process
gas or Number 6 fuel oil.  Both were vertical cylindrical types and had only one burner; therefore,
the only possible combustion modification was variation of excess air.  As shown in Table 5-5, the
unit with air preheat and higher emissions for both oil and gas firing.  For both units, changes in
excess air had little effect on NO  emissions when firing oil.   For the unit without air preheat,
reductions in NO  from 64 ng/J to 36 ng/J were achieved in one test with refinery gas when the
excess oxygen was reduced from 5 percent to 2 percent.
Catalytic Crackers and CO Boilers
       NOX is also released from the catalytic-cracking regenerator and from CO boilers, which are
fired by the catalytic cracker off gas.   Emission testing in CO boiler stacks, summarized in Table
5-6, has shown results ranging from 100 ppm to 230 ppm of NO .    Hunter (Reference 5-26) reported
testing one CO boiler that was equipped with staged air ports.   Baseline emissions were 126 ppm.
Lowering excess oxygen from 2.1 to 1.8 percent reduced NOX by 8 percent.  Adjustment of the air ports
and BOOS had negligible effect on NOX emissions.  CO emissions, however, were  very sensitive to
excess air and increased rapidly below about 2 percent excess oxygen.   The lack of response of NOX  to
combustion modifications is attributed to NO  that is formed from ammonia in the CO gas feed acting
similarly to fuel nitrogen in oil or coal.
       The average emission factor for NO  from fluid catalytic cracking units is estimated in
Reference 5-16 as 0.24 kg N02/liter feed (84.0 lb/103  bbl feed).   The total nationwide annual
emissions from fluid bed and thermal cat crackers is estimated in Section 2 to be 45 Gg (50,000 tons)
in 1974.  If the regenerator exhaust is burned in a CO boiler,  the resulting NO  emissions can pre-
sumably be controlled by the classical methods discussed in Section 4.2.1 of this report.
                                                 5-23

-------
   TABLE 5-6.   NOX EMISSIONS FROM PETROLEUM
               REFINERY CO BOILERS (REFERENCE 5-28)
          Investigator
       NOX
(ppm as measured)
Schulz, et. al., (Reference 5-29)
Schulz, et. al., (Reference 5-30)
Shea (Reference 5-33)
Shea (Reference 5-31)
Cowherd (Reference 5-32)
     104-116
  (average  106)

      70-89
  (average 78)

      96-233
  (average  163)

     101-159
  (average  135)

     108-162
  (average  129)
                         5-24

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5.3.2  Metallurgical Processes





5.3.2.1  Process Description and Control  Techniques




       The iron and steel industry is the predominant source of NOX emissions derived from metallur-



gical processes.  Other industries, such  as aluminum production, extensively use electric melting



furnaces or operate the process equipment at temperatures below the minimum required for formation



of significant quantities of NO .   Copper, lead, and zinc smelting require combustion operation in



the reverberatory furnaces and converters (copper) and in sintering machines (lead and zinc).   These



combustion emissions are deemed insignificant relative to the emissions from the iron and steel



industry.  Emissions from these other industries may become significant as a result of the trend



toward higher melting rates in new equipment designs.  This section reviews the equipment types and



available NO  control technology for the  major sources of NO  within the iron and steel industry.



Section 5.3.2.2 summarizes NO  emission factors for these equipment types.  Major portions of this
                             A


section are taken from a 1976 IGT study (Reference 5-28) which uses 1971 steel industry data as a



source for fuel consumption and NO  emissions estimates.




Pelletizing




       Pelletizing of extremely fine low  grade iron ore occurs in a specially designed furnace at



or near the iron mine.  The cost of shipping the unbeneficiated ore would be almost double that of



the pelletized product.




       Previous studies by the Institute  of Gas Technology have shown that pelletized ore production



will be about 54 Tg per year (60 million  tons/yr) by 1985.  The fuel consumed by the pelletizing



furnaces has remained about constant at 0.7 MJ/kg (600,000 Btu/ton).  This indicates that annual NO



emissions from pelletizing furnaces will  reach about 7.65 Gg (8,500 tons) by 1985.  The steel  industry



and equipment builders are considering coal firing the pelletizing furnace combustion chambers.  If



this is done, it will probably bring about an increase of about 50 percent in NO  emissions.  There



is no information available concerning NO  control techniques for pelletizing furnaces (Reference 5-28)




Sintering




       Some of the iron ore and flue dusts are available in particle sizes too small to be charged



directly to the blast furnace.  These particles are mixed with flux and coke breeze and loaded onto a



traveling grate-sintering machine.  An auxiliary fuel such as natural gas, coke oven gas, or oil is



used to initiate combustion on the surface of the mixture and is referred to as ignition fuel.  Com-



bustion is continued over the length of travel by forcing air through the mixture on the grates.
                                                 5-25

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The mixture is heated to a fusion temperature,  which causes  agglomeration  of  the  iron-bearing  par-
ticles.  The discharged sinter is cooled,  crushed,  and screened prior  to transfer to  the  blast fur-
nace charging oven.
       The major source of energy used in the production of  sinter is  the  carbon  content  of coke
breeze and flue dust.  The amount of ignition fuel  required  is about 140 J/g  (0.12 million Btu per
ton) of sinter.  The total fuel requirement, including coke  breeze, is about  1.74 kJ/g (1.5 million
Btu per ton) of sinter.
       The use of sinter machines to agglomerate ore fines,  flue dust, and coke breeze has been
declining  since 1966 and amounted to 39 Tg  (43 x 10s tons) in 1971.  If the present rate of decline
continues, the 1985  production of sinter would be about 24.3 Tg (27 x 106  tons).   The attitude of
the steel  industry is mixed because many steel plants are phasing out sinter lines, while at least
one major  producer has  replaced  several small  sinter lines with a large machine designed to meet
pollution  control regulations.   On the other hand,  the use of sintering for recycling iron has
simultaneously been  increasing.  Therefore, the projected decrease  in the number of sinter machines
may not occur.  In any  case,  the IGT estimates (Reference 5-28) show that NOX will continue to be a
major  pollutant.  There  is no  information available concerning NOX emission control techniques for
these  furnaces.
Blast  Furnace
        The blast  furnace is the  central  unit  in which  iron  ore  is  reduced, in  the  presence of coke
and limestone,  for the production  of  pig  iron. The blast furnace  itself  is  normally  a closed unit
and therefore has no atmospheric emission.   A  preheated  air blast  is  supplied  to the  furnace  from
 the blast furnace stove, through nozzle-like openings  called tuyeres.  The subsequent reactions in
 the blast furnace are not pertinent to this discussion.   Excellent descriptions  are  available, how-
 ever,  such as the complete discussion of the process of changing  raw  ore  to  finished  steel  published
 by the United States Steel Corporation (Reference  5-34).
        The hot blast reacts with the coke to produce heat and more carbon monoxide than  is needed  to
 reduce the ore.   The excess CO leaves the top of  the blast  furnace with other  gaseous products and
 particulates and is  known as  blast furnace gas.   This gas is cleaned  to remove the particulates, which
 could later cause plugging.  It is then available  for heating purposes.   Blast furnace  gas contains
 about one percent hydrogen and 27 percent carbon  monoxide;  it has a heating  value of approximately
 3600  kJ/Nm3, or, 92 Btu/ft3   (Reference 5-34).
                                                  5-26

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 Coke Ovens
        Coke is an essential component in making pig iron and steel; coke ovens are generally an
 integral part of the steel plant complex.  One-sixth of the total bituminous coal produced is charged
 to coke ovens.  On the average, 1.4 kg of coal is required for each kilogram of coke produced.
        Conventional coking is done in long rows of slot-type ovens into which coal is charged
 through holes in the top of the ovens.  The sidewalls, or liners, are built of silica brick, and the
 spaces between the chambers are flues in which fuel gas burns to supply the required heat.  Each
 kilogram of coal carbonized requires 480 to 550 kJ (450 to 520 Btu).   Flue temperatures are as high
 as 1.753K or 2,700F (Reference 5-35).  Much of the remaining heat in  the partially spent combustion
 gases is accumulated in a brick checkerwork, which releases it to preheat the combustion air when
 the cycle is reversed.  This is a typical regenerative cycle to conserve fuel and give a higher flame
 temperature.
        The coal  in the coking  chambers undergoes  destructive distillation during  a heating period of
 about 16 hours.   The  noncondensable gaseous  product is  known as  coke oven gas and  on  a  dry basis
 has  a heating  value of about 22 MJ/Nn3  (570  Btu/ft3).   Approximately 35  percent of the  coke oven  gas
 produced  is  used  in heating  the oven.
        The major  sources  of emissions  from coke ovens are  the rapid evolution of  steam  and  other
 gases when moist  coal  is  charged, the  discharge of  gases and  particulates  from the  charging openings
 during  charging,  and the  emissions  during the  coke  push and  subsequent quencing.   Recent coke-oven
 battery designs have reduced the emissions from charging and pushing by using advanced  engineering
 features and improved operating procedures.  During the coking process, leakage from the push side
 and coke side door seals  can account for most  of the emissions during the coking process itself.
 Improved door sealing techniques reduce door leakage substantially.
       Although the current practice of firing coke ovens with a mixture of blast furnace gas and
 coke-oven gas and slow mixing in the combustion chambers should tend to minimize NO  production,
 the estimated total is substantial because of the large quantity of fuel  consumed.
       The reduction in the coke required per kilogram of hot metal achieved during the 1960's will
continue, but steel mills are currently installing new coke ovens because of the  increased  need  for
hot metal due to the high BOF*hot metal-scrap ratio.  It is believed that the decline  in coke rate
may have been stopped  by the increased cost  of fossil  fuels used as injectants.  The 1985 projection
for coke-oven underfiring fuel  is 485 PJ (458 trillion  Btu).   If the NOX  concentration remains  con-
stant, the resulting  total emissions of NOX  will  reach  57.8 Gg (64,120  tons)  per year.
 Basic Oxygen Furnace
                                                5-27

-------
       Although it may be reasonable to assume that substitution of form coke may result in a sub-
 stantial reduction in NOX production, the general opinion in the steel industry,is that form coke
 will not be a significant factor in 1985 (Reference 5-28).
 Blast Furnace Stove
       Between 2.2 and 3.5 kg of blast furnace gas is generated for each kilogram of pig iron pro-
 duced.  Some 18 to 24 percent of this gas is used as fuel to heat the three stoves which are usually
 associated with each blast furnace.  Two are generally on heat while the third is on blast.
       The blast furnace stove is a structure about 8 to 8.5 m (26 to 28 feet) in diameter and
 about 36 m (120 feet) high.  A roughly cylindrical combustion chamber extends to the top of the
 structure and the hot combustion gases pass through a brick checkerwork to the bottom by reverse
 flow and then to the stack.  The checkerwork usually contains 25,500 m2 (275,000 ft2) of heating
 surface and has about 85 percent thermal efficiency.  Unlike the conventional regenerators, which
 extract heat from the waste combustion gases, the blast furnace stove is heated by burning fuel.
 The stored heat is then used to preheat air for the combustion of fuel in the furnace to be served.
       As in the case of coke oven underfiring, the blast stoves require very large quantities of
 fuel for heating.   However, since the stoves are heated primarily with blast-furnace gas (3.0 to
 3.5 MJ/Mn3, or 80 to 95 Btu/ft3) the NOX concentration is lower due to the presence of diluents and
 a low flame temperature.
       The projected need for hot metal  in 1985 is 112 Tg (124 million tons).   This amount of hot
metal will  require 295 PJ (280 trillion Btu) for blast-stove heating.   Assuming no reduction in NO
 stack-gas concentration,  the NOX emission in 1985 will  be 17.7 Gg/yr (19,600 tons/yr).   Because of
the low estimated  NOX concentration and the presence of inerts in the  fuel  gas, equivalent to flue-
gas recirculation, the potential  for NOX reduction is  probably small  (Reference 5-28).

 Open Hearth Furnace
       Steel making by the open hearth process has been decreasing since it reached a peak in 1956,
 when it represented 90 percent, or 92.7 Tg (103 million tons), of the  total production.   The use of
 open hearth furnaces is expected to continue to decline and will  probably amount to about 10 percent
 of total steel production by 1985.   Regardless of this dramatic decline due to the inroads of the
 basic oxygen furnace (BOF)  and electric arc furnace steelmaking processes,  its NOX emission poten-
 tial deserves consideration.
       The open hearth furnace is both reverberatory and regenerative, like the glass melting fur-
 naces.   It is reverberatory in that the charge is melted in a shallow  hearth by heat from a flame
                                                5-28

-------
  passing over the charge and by radiation from the heated dome.  It is regenerative in that the
  remaining heat in the partially spent combustion gases from the reverberatory chamber is accumulated
  in a brick filled chamber, or "checker", and released to preheat the incoming combustion air when
  the cycle is reversed.   Fuel  of low calorific value such as blast furnace gas as  well  as the com-
  bustion air may be preheated  by the checkers in order to obtain the high  temperatures  required.
         Hot metal  from the  blast furnace,  pig iron,  scrap iron,  and lime are  the usual  materials
  charged to an  open hearth  furnace.   These are heated  over a period averaging  10 hours, at  a  tempera-
  ture as high as  the refractories will  permit.   Fuel oil  is  the  preferred  fuel  and  is burned  with
  excess  air to  provide an oxidizing  influence on  the charge.
         NOX emissions  from  open  hearth  furnaces are very  high because of the high combustion  air pre-
  heat temperature,  high operating temperature, and the  use of oxygen lances to  increase production
  rates.  The  data available indicate  that  NOX  concentrations will be in the 1000 to 2000-ppm  range.
  Although many open hearths are being phased  out because of emission control difficulties and better
  economics  of steel production with the BOF process, several steel mills are modernizing open hearth
  shops,  including pollution control  equipment to provide flexibility in the hot metal-scrap ratio,
  particularly those mills with a hot-metal deficiency.   Therefore, predictions that the open hearths
 will be phased  on entirely by 1985  are unrealistic,  and it is anticipated  that about  13.5 Pg (15
 million tons) will  still  be made by the open hearth process in 1985.  Fuel consumption  has  been
 decreasing and  may reach  2.9  MJ/kg  (2.5 million Btu/ton)  in 1985.   This will  require  a  fuel  con-
 sumption of 40  PJ (37.5  trillion Btu) for open hearth  steel  production and result  in  an NOX emis-
 sion level  of 14  Gg (15,750 tons) (Reference  5-28).

 Basic  Oxygen  Furnace
        In the basic  oxygen  furnace  (BOF),  oxygen  is blown  downward  through a water-cooled lance into
 a bath containing scrap and hot metal.  Heat  produced by oxidation  of carbon, silicon, manganese,  and
 phosphorous  is sufficient to bring the metal  to pouring temperature and auxiliary fuel is not required,
 The  furnace  is an open top, tiltable, refractory-lined vessel shaped somewhat like the old-fashioned
 glass milk  bottle.  Furnace capacities range up to 309 Mg  (340 tons).  The time required per cycle  is
 very short -  from 45 to 60 minutes.
       The BOF has displaced the open hearth as the major steel  production  process,  but  is much less
flexible because of the inherent limitation of 25 percent to 30 percent  scrap  in the charge.   The
                                                5-29

-------
amount of BOF capacity in an integrated steel plant is, therefore, closely associated with hot metal
availability.  Additional flexibility in scrap use can be obtained by preheating the scrap with an
oxygen-fuel burner.  In many steel plants, the open hearth shop is modernized and equipped with
appropriate pollution control equipment so that it can be used in conjunction with BOF shops to
provide the required flexibility to accommodate variations in hot metal-scrap ratio.  A combination
of BOF shops and electric furnace shops provides the maximum in flexibility and may represent the
makeup of future steelmaking facilities.
       Excluding fuel use for scrap preheating, other uses are for refractory dryout and to keep
the BOF vessel from cooling between heats.  Their uses amount to about 232 kg  per kg (200,000 Btu
per ton) of steel produced.
       Decarburization of the iron charged to the BOF produces about 467 kJ of carbon monixide per
kilogram of steel (400,000 Btu/ton).  The off-gases also contain large amounts of particulates,
which must be removed before discharge into the atmosphere.  Typical American practice is to burn
the combustible gases in water-cooled hoods mounted above the BOF vessel, cool with excess air or
water sprays, and pass the cooled gases through high-energy scrubbers or electrostatic precipitators.
In most cases, the BOF vessels are equipped with open hoods that admit air for combustion of carbon
monoxide on a relatively uncontrolled basis.  If additional steam can be used in the plant, the
combustion hood can be used as a steam generation device, although the steam production will only
be cyclic.  Some new plants use suppressed combustion hoods which do not inspire air and burn off-
gases.  New BOF capacity is expected to continue this trend, which may cause a decrease in total
NO  emissions.
       During the combustion of the waste gas, the potential for NO  production exists.   One steel
manufacturer gives a range of values of from 30 to 80 ppm, or 180 to 500 ng NO  per kg (0.36 to 1.0
Ib NOX per ton) of steel  produced.  There is no information available on NOX control techniques for
the basic oxygen furnace (Reference 5-28).
Soaking Pits and Reheat Furnaces
       These are large furnaces with fuel  inputs ranging from 1.17 to 4.12 MJ/kg (1.0 to 3.5 x 106
Btu/ton) heated.  Fuel  efficiency is affected by many factors such as furnace size, design, combus-
tion controls, combustion air temperature, furnace scheduling, and downtime.   Improved efficiency
measures, which do not increase flame temperature, will, in general, reduce NO  emissions in propor-
tion to the reduction in fuel usage.
                                                5-30

-------
        Existing fuel  conservation measures  in soaking-pit heating  include improved  scheduling  so  as
 to charge at a higher ingot temperature,  programmed  input control,  improved  burner  designs,  air/
 fuel  ratio control  responsive  to stack-gas  oxygen  content,  addition of recuperators to  existing
 cold  combustion air installations,  and  use  of recuperators  designed to give  higher  preheat tempera-
 ture.   Of these,  the  use  of high-mixing-rate  burners  and  an increase in combustion  air  preheat are
 likely  to increase  the  N0x  emission  level.  At the present  time, only  experimental  information is
 available concerning  the  effect  of  these  parameters on  NO  levels.
                                                          A
        Soaking-pit  and  reheat-furnace operating  temperatures are such  that the estimated NO  levels
 should  fall  in the  250  to 350-ppm range.  However, the  very large amounts of fuel used  result  in a
 total NOX output  estimated  at  97  Gg  (107,000  tons) in 1971.
        A  major factor that  will  reduce  consumption of purchased and  in-plant fuels  and  thereby de-
 crease  NOX  output is the trend toward use of  continuous casting to  replace some ingot casting.  In
 this process,  billets and slabs which are hot-rolled prior  to cooling  are produced  from molten
 steel,  thus  eliminating soaking-pits and most  of the reheat requirement.  About 20  percent of  total
 steel production, or 36 Tg  (40 x  106 tons), is estimated  to be produced by continuous casting  in
 1985.   In  spite of  this, soaking-pit and reheating furnace  steel capacity will  have to be increased
 during  the  1975 to  1985 period to provide for  the expected growth in steel production and for  the
 steel which  for process reasons will have to be cast in ingots.  According to the IGT projection,
 conventional steel  processing will account for 144 Tg (160 x 106 tons)  in 1985.  At present fuel
 consumption  of 5.4 MJ/kg (4.7 x 106  Btu/ton),   the total  fuel consumed for soaking-pits and reheat
 furnaces  in  1985 will  be 795 PJ (750 x 1012  Btu).  This  fuel consumption will result in estimated
 NOX emissions of 143 Gg (157,900  tons).
 Heat Treating  and Finishing Operation
       This category includes annealing, hardening, carburizing and normalizing of some of the
 steel  industry cold-rolled products, as  well as production of coated products.   Fuel consumption
 in 1971  was about 632  PJ (600 x 1012  Btu)  for  the production of cold-rolled products (about 25
 percent of total steel  production).   NOX emission levels are assumed to be in the  150 to 250-ppm
 range.   On this basis,  total NOX  emission  in 1971 for this category will be about  7.6 Gg (8,400
tons).   Assuming that  production  of cold-rolled products remains at about 25  percent of total steel
production, the 1985 N0x emission will amount  to 10 Gg (11,200  tons) per year.   There is no informa-
tion available concerning  NOX control  techniques for  these sources  (Reference 5-28).
                                                5-31

-------
 Electric Furnaces
        Production of steel in electric-arc furnaces has grown rapidly since World War II and is
 currently estimated to be about 20 percent of total steel  production.  Because of the phase out of
 open hearth steelmaking, the increase in BOF steel  production, and the associated scrap-use limita-
 tion, the amount of steel produced in electric-arc  furnaces is expected to increase even more.
        The combustion of fossil fuels currently plays a very small role in electric steelmaking.
 This may change in the future as advances in technology permit the increased use of scrap preheating.
 Most authorities agree that scrap preheating will be accomplished outside the electric-arc furnace
 in a specially designed charging bucket, probably equipped for bottom discharge.   Many of the designs
 use excess air burners to limit flame temperature and minimize oxidation  of the scrap.   Associated
 air-pollution problems include particulates  from dirty scrap,  iron oxide, and oil  vapors.   The
 requirement for both incineration at  or  above 1,033K (1.400F)  and particulate removal  has  caused
 shutdown of several  scrap preheating  installations  because of  economic  considerations.
        The use of electricity for heat in steel  productljn transfers  the  NO  emissions  to  the
 utility plant where  the problem is  easier to control.   Electric  furnaces  are,  in any  case,  a  very
 minor source of NOX  from the  steel  industry  (Reference 5-28).
 5.3.2.2  Emissions
        Emissions  in  the steel  industry and its related  processing  have  historically consisted of
 fumes,  smoke,  and dust  or  particulates.   The  gases  usually  considered obnoxious have been SO  , CO,
 and  odors.   The  presence of oxides  of nitrogen has  been obscured by the heavy emission of particu-
 lates and a  resulting  lack of physical evidence.  The  NOX  emissions observed can be traced  largely
 to the  combustion of fuel oils  and  gas and,  in part, to the burning of carbon monoxide, which is a
 product of  the  processing operations.
        The  emission of  nitrogen oxides from iron and steelmaking and processing equipment does not
 appear  to have been extensively investigated.  However, reasonable estimates can be made by assuming
 a relationship between  known operating temperatures  and N0x concentrations in stack gases (Reference
 5-28).  This relationship is affected  by  other variables, such as combustion air preheat temperature
 and oxygen enrichment of combustion air.
       Table 5-7 shows the estimated N0x  concentrations for the major energy-intensive processes
and the resulting total annual combustion-related NOX production based on  1971  steel  production
energy consumption data (Reference 5-28).
                                                 5-32

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        Other test results  provided  by the  American  Iron  and  Steel  Institute  (Reference 5-36) indi-
 cate different emission factors  as  shown in  parentheses  in Table 5-7.  The emission levels for the
 coke ovens are the result  of three  separate  tests  (10, 186,  and 485 ppm).  There was some concern
 about the experimental  procedures,  and new tests are  planned  for 1978.
        Results of recent tests reported by Hunter,  et al_. (Reference 5-26) are summarized in Table
 5-8.  The open hearth  furnace was tested while operating on  natural gas and  Number 6 fuel oil
 (60/40).   The wide fluctuations  in  N0x and CO observed as various  operations were performed are
 shown in  Figure 5-5.   Large  changes  in excess air occurred as the  operators  opened doors to look at
 the steel  and to add material or adjust fuel flow to  change heating rate.  NO  emissions varied
 from 100  to  3500 ppm and averaged about 1800 ppm or about 950 ng/J (2.2 Ib/MMBtu).  NO  increased
 somewhat  linearly  with  excess 02-  Particulate emissions  were 2200 ng/J (5.02 IbMMBtu), measured
 upstream  of  the precipitator.  Following baseline tests the furnace was overhauled to repair refrac-
 tory and  fix  leaks.  A  second test cycle was observed on the repaired furnace and the average NO
 was  1094  ng/J  (1250 ppm), a  reduction  of about 40 percent.   During baseline tests, NO  frequently
                                                                                     A
 exceeded  2000  ppm  but with the excess  air controlled, excursions over 2000 ppm occurred only twice.
       One steel billet  reheat furnace was  tested while firing natural  gas at heat rates  between 13
 and  30 MW.  Baseline NOX emissions at  24 MW (82 million Btu/hr)  were 56 ng/J (110 ppm)  and particu-
 lates were 17  ng/J (0.04 Ib/MMBtu).   This furnace had two heating zones with 13 and 14  burners,
 respectively.  The row with  13 burners released about 80  percent of the heat input.   Combustion
 modifications  included reduced excess air,  resulting in a 24  percent NOX reduction,  and burners  out
 of service which produced a 43 percent NOX  reduction with three  burners out of service  in the  row
 of 13 burners.
       One steel ingot soaking pit was tested (site  16/2) while  firing  natural  gas  at about  2.9  MW
 (10 MMBtu/hr) through  a single burner.  Baseline  NOX emissions at 2 MW  were  52  ng/J  (101  ppm).
Reduction  of excess air reduced NOX  by 69 percent with no adverse effect on  the steel.
5.3.3   Glass Manufacture
5.3.3.1    Process Description
       The glass manufacturing industry is  made up of  several  basically different types of opera-
tions.  They are:
                                               5-34

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4000
3500
          BASELINE TEST
      NO. 6 OIL AND GAS FUEL
  1200        1300       1400       1500       1600        1700

                                       TIMEOFDAY.hr
1800
1900
                     2000
Figure 5-5. NO emissions as a function of time for an open hearth furnace (Reference 5-26).
                                            5-36

-------
         1.  Glass  container manufacture
         2.  Fiberglass manufacture
         3.  Flat glass manufacture
         4.  Specialty glass manufacture
 The largest type  is the glass container industry, which produces about 45 percent of the total
 amount  of glass (by weight) produced by the entire industry.
         While the specific processes used within each segment of the industry vary according to the
 product being manufactured, glass manufacturing involves three major energy-consuming processes:
 melting the raw materials, refining the molten glass, and finishing the formed products.   Typically,
 about 80 percent of the energy consumed by the glass industry is for melting and refining,  15 per-
 cent is for finishing,  and 5  percent is for mechanical  drives and conveyors.   The primary differ-
 ences in processes used among the various  segments  occur in the refining  and  finishing  operations.
        The raw materials used in  glass  manufacture  consist primarily of silica sand,  soda ash, lime-
 stone,  and cullet  (crushed waste  glass).   In the  production of window and plate glass,  for  example,
 temperatures  in the range  of  1,783K to  1,838K (2.750F to 2.850F)  may be required to melt  these raw
 materials  into a viscous liquid.
        The furnaces used are  of the pot  type if only  a  few tons  of  a specialty glass  are  to be pro-
 duced,  or  of  the continuous tank  type for  larger  quantities.   By  far the  larger amount  of glass  is
 melted  in  furnaces,  and  only  these  will  be  considered in connection with  NO   control.
        Continuous  reverberatory furnaces have  a holding  capacity  of up  to  1.27  Gg  (1,400  tons) and a
 daily output of as  much  as 270 Mg  (300 tons).   Reverberatory  furnaces  in  this  industry  are broken
 into two classifications according  to the firing arrangement  used:   end-port and side-port melters.
 In the operation of a side-port-fired furnace, the preheated combustion air mixes with the fuel in
 the port,  resulting in a flame that burns over the glass surface.  The products of combustion exit
 via the  opposite port, down through the checkerbricks, and out through the reversing valve to the
 exhaust  stack.  Typically, there are several ports situated along each side of the furnace.   In
 contrast, there are only two ports in an end-port-fired furnace, located on the rear wall  of the
 furnace.  The flame is ignited in  one port, travels  out over the glass toward the bridgewall,  and
 "horseshoes" back to the exit  port - the other port  in the rear of the furnace.  In both types of
furnaces, the firing pattern is reversed every 20  to 30 minutes, depending upon the specific  furnace.
During this reversal period, the flame is extinguished,  the furnace  is purged  of combustion  gases by
reversing the flow  of combustion air and exhaust gases passing through the reversal  valve, and
                                                5-37

-------
combustion is then reestablished in what was previously the exhaust port.  Both types of melters are
operated continuously throughout a campaign that normally lasts 4 to 5 years, at sustained tempera-
tures up to 1.867K (2,900F).
        In addition to the reverberatory-t.ype melters, day tanks, unit melters, and pot melters are
used, mostly in the pressed and blown glass industry.  Many of these melters are batch-type, as
opposed to continuous, resulting in a substantial reduction in fuel-utilization efficiency.  Much
of the  fuel that is wasted is due to the antiquated methods of operation and associated equipment
used with these melters (Reference 5-28).
       The combustion gases, on leaving the melting zone, retain a considerable amount of heat.  This
is reclaimed in a regenerator or brickchecker chamber.  When the firing cycle is reversed, combus-
tion air is preheated by being passed through the brick work.  Preheating saves fuel but increases
the flame temperature which promotes NO  formation.
       Coal is not used in glass melting.  Since molten glass is conductive, electrical heating is
used as a booster to supplement fuel firing whenever technically and economically practical.  Gas
and, to a lesser extent, fuel oil are the preferred fuels.

5.3.3.2  Emissions
       The flue gas from glass-melting furnaces is the major source of NO  emission in the glass
industry.   The operation of these furnaces is similar to that of open hearth furnaces used in steel -
making; regenerative checkerwork sets absorb heat from the combustion gases for subsequent release
to the incoming combustion air.   This is accomplished by a reversing valve which puts each checker-
work set through its heating and cooling cycle in turn.  The sequence of intense high-temperature
combustion and quenching in the checkerwork sometimes raises NO  emissions to levels higher than
those experienced in a steam boiler of equivalent heat release.   For example, during a recently
completed experimental program,  NOX emissions were measured during a complete firing cycle of a
glass melter.   NOX emissions were highest at the beginning of the firing cycle and  then,  as  the
cycle continued, decreased by about 30 percent.   At the beginning of the firing cycle, the combus-
tion air is preheated to a higher temperature, which results in a hotter flame than at the end  of
the cycle when the checkerbrick  and hence the air have cooled considerably.   Other  major  factors in
NOX formation  in a glass melter,  such as flame velocity and recirculation patterns  of flue gases,
are being studied.
       Table 5-9 summarizes  the  emissions from several  glass melters  as  measured  by a number of
investigators.
                                                 5-38

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5.3.3.3  Control  Techniques
        According to representatives  of the glass  industry,  the efforts  of  the  industry  to  reduce
air pollutant emissions are severely  hampered by the variations in  regulations  that  exist from
state to state.   This lack of uniformity requires  that different solutions  to the  problem be  sought,
depending on the location of the specific plant.  This, in turn, adds  substantially^ the  cost  of
pollution control.  In addition, not  only are the regulations variable from one location to another,
but these regulations are constantly  changing.   As a result, very few  air pollution  control equip-
ment installations have been made on  glass furnaces, and there is very little data available  on
the effectiveness and cost of these devices.
        In general, SO , NO , and particulates are the primary air pollutants from the glass  manu-
                      A    A
facturing processes.  The concern is  primarily  with  the melting process  because this  is  the largest
energy consumer and the major contributor to air pollutant emissions.   The  major pollution  problem in
the combustion process is NO  emissions.

        While the formation of NO  in the combustion process is not entirely understood, it is clear
that the goals of reducing NO  emissions and reducing energy consumption are seemingly at  odds.   N0x
                             A
formation is a temperature-related phenomenon; as temperature increases, NOX emissions  increase.
On  the  other hand,  increasing available  heat to a process may result in  increases in efficiency and
in  temperature,  which  in  turn increase N0x emissions.  Analysis of the process modifications  under
consideration in the  glass  industry  shows that  there  is a possibility of increasing N0x emissions.
If  the  implementation  is  carried out properly,  however, this need not occur.
        Six recommended modification programs are listed  in Table 5-10.   The order of listing  is
according to programs  that  afford  the greatest  potential  for solving the problems in the shortest
period  of time.   The  table  also  presents  estimates  of improvements that  may be obtained, where  such
estimates can reasonably  be made  (Reference 5-28).  Cost  data for these  programs are not available
at  this time.  Two  of the six recommendations  are currently  being pursued  by EPA/IERL-Cincinnati.

5.3.4   Cement Manufacture

5.3.4.1  Process Description
        The  cement industry includes  all  establishments engaged  in  the manufacture of hydraulic  cement
 (generic  name:   portland cement),  masonry,  natural, and  pozzuolana cements.  This discussion  is
 limited to  the  production of portland  cement because  it  accounts for  95  percent of  the  total
                                                  5-40

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cement manufactured in the United States,  with the remaining  5 percent split among the other



types.




       Raw materials used in the manufacture of port!and  cement  consist  of limestone,  chalk  or marl,



and seashells.   These are combined with either clay,  shale,  slate,  blast furnace  slag, iron  ore,



or silica sand.   The end product is a chemical combination of calcium,  silicon, aluminum,  iron,



and other trace materials.  The raw materials are first ground and  blended together.   Depending



upon which of the two processes is used, water may be added  during  blending (the  wet  process) or



the ingredients can be mixed on a dry basis (the dry  process).   In  general, the moisture content



of the raw materials determines the process used.  If the moisture  content is  greater than 18 per-



cent, by weight, the wet process will be used.  If the moisture  content  is less than  18 percent,



the dry process will be used.   The next step is the calcining or burning of the mixed raw  material



in a rotary kiln.  During this step, the material is  heated  to approximately 1,755K (2.700F) and



transformed into clinker, which has different chemical and physical  properties than the raw



materials had initially.  The clinker is discharged from the  kiln and cooled.  The last step is  to



grind the clinker to the desired fineness  and add gypsum to  control  the  setting time  of the  concrete



(Reference 5-28).





5.3.4.2  Emissions




       The major air pollutant emission problem in the manufacture  of portland cement is particu-



lates, which occur in all phases of cement manufacturing from crushing  and raw material storage  to



clinker production, clinker grinding, storage, and packaging. However,  emissions also include the



products of combustion of the fuel used in the rotary kilns  and  drying  operations; these emissions



are typically NO  and small amounts of SO .  For both the wet and dry kiln processes,  the  limited
                A                        A


data shows that nitrogen oxides are emitted at a rate of about 1.3  g  per kg (2.6 Ib  per ton) of



cement produced.




       The largest source of emissions in cement plants is the kiln operation.  At present,  about



56 percent of the cement kilns in operation use the wet  process, and 44 percent  use  the dry process.



Based on this information, estimates of total NOX emissions  from cement  plants in 1972 are 42.7 Gg



(4.7 x 104 tons) for the dry process and 54.5 Gg (6 x 10*  tons)  for the  wet process.   These  estimates,



because of a lack of data, assume the use of no controls  by  the  industry.   Without an inventory of



control equipment in use, they cannot be refined.




       Future efficiency-improving process modifications  that increase  flame temperature without



improving heat transfer to the process load will almost certainly result in increased  NO   emissions.
                                                5-42

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    Converse^, adequate removal of the additional heat resulting from the applicable process  modifica-
    tions should maintain NOX emissions at their current Level.
          Of the process modifications deemed to be near-term,  only  the  use of oxygen,nHchment has
   any great potential of Increasing  air pollutant emissions, pr^rlly  NO,.  ,„ SOTO applicat10ns ,„
   other industries,  for example,  glass  melting,  oxygen enrichment can be used without Increasing NO
   -i»1«,.   However,  due  to  the different  type of load ,„ the cement  Industry and the different  *
   patterns  of  heat transfer, 1t 1s suspected that NO, would Increase with the Imputation of oxygen
   enrichment (Reference 5-28).
   5.3.4.3   Control Techniques

         There 1s very little Information In the literature regarding co^erclal Installation of equip-
  ment for  removing NOX from kiln  waste gas or of edifications to Mln  operations to reduce NO
  production.   Water  scrubbing  1s  sometimes used for partlculate rental from waste  gas fro. Ill
  kiln,.   In this operation, the gas  contacts a  slurry of calcium hydroxide, which should remove a
  50/50 mixture of NO and NO, and  reduce  NO, up  to 20 percent.  Flue gas regulation, which Is used
  to contro! temperature  1n  some 1,.  kilns, should reduce NO, emissions by lowering „« temperature.
        Reference 5-26 reports NO, emission test results for both a  dry process  Kiln and  a  wet  pro-
  cess  Kiln.  The dry process kiln was tested at full  capacity while  firing a  68/32 mixture  of coke
  and natural gas.  Data for the same Mln firing natural  gas and oil  separately were also available
  for comparison.  Emissions of NO, while firing natural  gas were  1,050 to  1,800 ng/J (1680  to 2900 ppm)
 Operation on oil resulted  In a 60 percent reduction  (400-710 ng/J).   Operation on combined coke
 and natural gas produced emissions of 655 to  710 ng/J, a 50 percent  reduction.
        Lower NO, emissions  on  solid  and  liquid  fuels compared  to gas are attributed to the highly
 ad,abat1c nature of  the  process.  Many cement Mln, are currently being converted  from gas to solid
 fuels.  This conversion W1,l be beneficial In reducing NO, and could be pursued  as  an NO   control
 method  that Is consistent with the reduction of  Industrial  gas consumption.
       The  wet process cement kiln was tested only while firing natural  gas and  had  baseline
 emissions of 1319 ng/J (2250 pp.,.  c^bustlon modifications Investigated  Included variation of
 combustion air Inlet temperature and  excess oxygen,   tncrease of  combustion ,1r temperature from
 644K (700F,  to  767K (920F,  Increased  NO emissions to 15,8 ng/J, and ,5 percent Increase.   Reduction
 of excess  oxygen at baseline a,r temperature  reduced NO, to 846 ng/J, ,  36 percent  reduction   The
 independent  reductions of either excess  air or air temperature caused unacceptable  reduction of
kiln temperature  that can result In a  process upset.  The NO .missions were found to  be a  strong
                                                5-43

-------
function of kiln temperature,  as shown in Figure 5-6.   It was  found that simultaneous  reduction  of
excess air and increase in air temperature could produce a reduction in NO of about 14 percent while
maintaining kiln temperature.
       Electric heating eliminates all the pollutants  associated with combustion sources,  but its use
in kiln operation is very limited.  Another means of emission  control in kiln operation is the choice
of kiln type.  Some NO  reduction in limestone calcining is obtained by usipg a vertical instead of
a rotary kiln.  The mechanism of operation is such that heat transfer to the load is very high,  and
peak temperatures are lower than required to obtain the formation of N0x in large amounts.
5.3.5  Coal Preparation Plants
       Coal in its natural state contains impurities such as sulfur, clay, rock, shale, and other
inorganic materials, generally called ash.  Coal mining adds more impurities.  Coal preparation plants
serve to remove these impurities.  Coal cleaning processes utilized by coal preparation plants may be
wet, dry, or a combination of both.  Wet processes are a minor source of oxides of nitrogen.
       After the coal is wetted by the cleaning process, primary drying is done mechanically by
dewatering screens followed by centrifugal driers.  When lower surface moisture is desired (3 to 6
percent) with finer coal sizes, secondary drying is required.  Such low moisture levels can best be
accomplished by thermal drying.   It appears that new coal preparation plants that  install thermal
dryers will  use a fluidized-bed type.
        In  the fluidized bed drier, hot combustion gases  from a coal-fired  furnace  are  passed upward
through  a  moving bed of finely-divided wet coal.  As the bed fluidizes, the coal is dried as the
fine  particles  come into  intimate contact with  the  hot  gases.
        The major pollutant evolved from  the  thermal dryer  is particulate.  Well-controlled thermal
driers  emit  only minor quantities of  NOX-  Concentrations  of 40  to  70 ppm  (0.16 to 0.28 kg/MJ,  or
0.39  to  0.68 lb/106 Btu)  have  been measured  (Reference  5-43).  These  emission  rates are below the
NSPS  of 300  ng/J  (0.7  lb/106  Btu) for large  steam generators.   In  any case,  no N0x standards have yet
been  proposed  since the  thermal  dryer capacities are generally  less than  the  smallest  power  plants
required to  control NO   emissions:  73.2 MW,  or 250 x  106  Btu/hr (Reference 5-43).
                                                 5-44

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  1422
3000
1500
KILN TEMPERATURE, °K

  1600               170Q
                                                      1800
                                                                 1867
                        SHADED AREA SHOWS EFFECT OF INLET AIR TEMPERATURE VARIATIONS

                        NUMBERS REPRESENT EXIT 02 CONCENTRATIONS IN PERCENT
                        ROTARY CEMENT KILN, WET PROCESS
                     2300
                                         2500

                                   KILN TEMPERATURE °F
                                            2700
                                                                2900
     Figure 5-6.  The effect of cement kiln temperature on NO emissions (Reference 5-26).
                                        5-45

-------
                                    REFERENCES FOR SECTION 5
5-1   National  Academy of Sciences,  "Air Quality and  Stationary  Source  Emission Control," Prepared
      for the Committee on Public Works, United  States  Senate, Serial No.  94-4, March  1975.

5-2   Hall,  R.  E., J.  H.  Wasser,  and E.  E.  Berkau,  "A Study  of Air  Pollutant  Emissions from Resi-
      dential Heating  Systems,"  EPA  650/2-74-003, January 1974.

5-3   Barrett,  E.  R.,  S.  E.  Miller,  and  D.  W.  Locklin,  "Field Investigation of Emissions  from
      Combustion Equipment for Space Heating," Battelle-Columbus Laboratories, EPA R2-73-084a,
      June 1973.

5-4   Hall,  R.  E., et_ al_., "Status of EPA's Combustion  Research  Program for Residential Heating
      Equipment,"  presented  at the 67th  APCA Annual Meeting, June 1974.

5-5   Dickerson, R.  A., and  A.  S.  Okuda, "Design of an  Optimum Distillate  Oil  Burner for  Control
      of Pollutant Emissions," EPA-640/2-74-047, June 1974.

5-6   Combs,  L.  P.,  and A. S.  Okuda, "Residential Oil Furnace System Optimization  -Phase I,"
      Rocketdyne Division, Rockwell  International,  EPA-600/2-76-038, February 1976.

5-7   Combs,  L.  P.,  and A. S.^Okuda, "Commercial Feasibility of  an  Optimum Distillate  Oil Burner
      Head,"  Final Draft  Report,  Rocketdyne Division, Rockwell International,  Prepared for U.S.
      Environmental  Protection Agency, 1975.

5-8   Belles, F. E., R. L. Himmel  and D. W.  DeWerth,  "Measurement and Reduction of NO  Emissions  from
      Natural Gas  Fired Appliances," APCA Paper  No. 75-09.1. Presented at the 68th Annual Meeting  of
      the Air Pollution Control Association, June 15-20,  1975.

5-9   National  Petroleum  News, January 1975, pp.  34-35.

5_10  Lenney, R. J., Blueray Systems Inc.,  Weston, Massachusetts, Personal Communication, September
      1975.

5_H  Locklin,  D.  W.,  and  R. E. Barrett, "Guidelines  for  Residential  Oil Burner Adjustments,"
      EPA-600/2-75-069-a,  October  1975.

5_12  Locklin,  D.  W.,  and  R. E. Barrett, "Guidelines  for  Burner  Adjustments of Commercial Oil-
      Fired Boilers,"  EPA-600/2-76-088,  March  1976.

5-13  Hall,  R.  E., "The Effect of Water/Distillate  Oil  Emulsions on Pollutants and Efficiency of
      Residential  and  Commercial  Heating Systems,"  Air  Pollution Control Association Paper 75-09.4,
      June 1975

5-14  Black,  R.  J.,  H.  L.  Hickman, Jr.,  A.  J.  Muchick,  and R. D.  Vaughan,  "The National   Solid
      Wastes  Survey: An Interim Report," Public  Health  Service,  Environmental  Control Administra-
      tion, Rockville,  Maryland,  1968.

5-15  Niessen,  W.  R.,  et_ al_.,  Systems Study of Air  Pollution from Municipal Incineration, Report
      to NAPCA  under contract  CPA 22-69-23, Arthur  D. Little, Inc.,  Cambridge, Mass., 1970.

5-16  McGraw, J. J.  and R. L.  Duprey, Compliation of  Air  Pollutant  Emission Factors (Revised),
      AP-42,  EPA,  February 1972.

5-17  Stenburg,  R. L.,  et^ al_.,  "Field Evaluation of Combustion Air  Effects on  Atmospheric Emissions
      from Municipal  Incinerators,"  J. Air  Pollution  Control Assoc., Vol.  12,  pp.  83-89,  February
      1962.

5-18  Kirsh,  J.  B.,  "Sanitary  Landfill," In:   Elements  of Solid  Waste Management Training Course Manual
      Public  Health  Service, Cincinnati, Ohio, 1968,  p. 1-4.

5-19  Fife, J.  A., and R.  H. Boyer,  Jr., "What Price  Incineration Air Pollution Control?,"
      Proceedings  of 1966 National Incinerator Conference, American  Society of Mechanical Engi-
      neers,  New York.  1966.
                                                5-46

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  5~21    Chi,  C.  T. ,  and  D.  L.  Zanders, "Source Assessment: Agricultural Open Burning, State-of-the-Art,"
  5-23   Wiley, J. S. et al_. , "Composting Developments in the U.S.," Combust.  Sci.  6(2):5-9,  1965.


  5"24   72U"keFebrSary"fe96d9U?in9 Emi'SSi°nS ^ RefUS6 DisP°sal>" J'  Al> Pollution Control  Assoc.,  19:  69-


                                    %% L  C°°k'  °ffiCe °f F6deral  Activities»  U'  S.  Environmental
 5-26   Hunter, S.  C. ,  et al_. ,  "Application  of Combustion  Modifications  to  Industrial  Combustion
        Equipment,  "Proceedings of the Second Stationary Source  Combustion  Symposium   Vol   III
        EPA-600/7-77-0736, July 1977.                   - ~ - ~ - ! - : - '


 5-27   Bartz, D.  R. ,  et al_. ,  "Control  of Oxides  of  Nitrogen  from  Stationary Sources in the South
        Coast Air  Basin of California,"  PB 237 688/7WP, September,  1974.
 5"28   Fnn?IS: E'nV  •'  ?•  Ne?b1«.  «nd  R-  D- Oberle,  "A Survey of Emissions Control and Combustion

                                                     1
 5-29   Schultz,  E   J.,  L.  J.  Hellenbrand, and R. B. Engdahl , "Source Sampling of Fluid Catalytic
        Jul   1972         standard Oil of California, Richmond, California," Battelle-Columbus Labs,
 5"3°    SlrMn1  ErnJn'-^ J' "ei!enbrand' and R- B- Engdahl, "Source Sampling of Fluid Catalytic
        Cracking   CO Boiler and Electrostatic Precipitators at the Atlantic Richfield Company,
        Houston,  Texas," Battelle-Columbus Labs, July 1972.

 5-31    Shea,  E   P   "Source Testing, Standard Oil Company, Richmond, California," Midwest Research
        Institute,  Kansas City, Missouri, 1972.

 5-32    Cowherd   C., "Source Testing, Standard Oil of California Company, El  Segundo, California,"
        Midwest Research Institute, Kansas City, Missouri, 1972.

 5-33    Shea,  E   P. , "Source Testing, Atlantic Richfield Company, Wilmington,  California," Midwest
        Research  Institute, Kansas City, Missouri, January 1972.

 5-34    McGannon, H  E., The Making. Shaping and Treating of stPPl .  8th ed.,  Pittsburgh,  United
        States Steel Co., 1964.


 5"35   SH^VI V  ^ar5°nifIativn>,"   In:   Kl>k-0thmer Encyclopedia  of Chemical Technology. Standen. A.
       (ed.),  Vol.  4,  2d ed. ,  New York,  Interscience Publishers,  Inc.,,  1964,  p. 400-423. —

 5-36   Personal  communication,  Dr. Walter Jackson,  u.  S. Steel, November, 1977.

 5-37   Personal  Communication,  Mr. Andrew Trenholm  of  the Office of Air Quality Planning  and  Standards
       U. S.  Environmental  Protection Agency, Durham,  North  Carolina,  May 1976;   anmng  ana  btandards>
5"38   mPPHnrAf^ho'l-"^6!?0?051^'0" °f 51ass  Furnace  Emission."  presented at  the 63rd Annual
       meeting of the Air Pollution Control  Association, St.  Louis, June  1970.
5"39          JA:c~*St-; HEm1«1?n?  ;f°x1des  of Nit^gen  from  Stationary Sources in Los Angeles
                         N^rpgen Emitted  by  Medium and  Large  Sources," Joint District, Federal, State,
       Repor                                                                  ' L°S
5'40   Air Pollution Engineering  Mflmml.  Danielson, J. A.  (ed.).  National Center for Air Pollution
       Control,  Cincinnati,  Ohio,  PHS  Publication  Number 999-AP-40.
                                                5-47

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5-41   Nesbitt,  J.  D.,  D.  H.  Larson,  and M.  Fejer,  "Improving Natural  Gas Utilization in a Continu-
       ous End Port Glass-Melting Furnace,"  In:   Proceedings of the Second Conference on Natural
       Gas Research and Technology.  Session  IV.  Paper 9,  Chicago,  1972.

5-42   Ryder, R.  J., and J.  J.  McMackin, "Some Factors Affecting Stack Emissions from a Glass Con-
       tainer Furnace," Glass Ind.,  50,  June-July,  1969.

5-43   "Background  Information  for Standards of  Performance:  Coal  Preparation Plants; Volume 1:
       Proposed  Standards,"  EPA 450/2-74-021a, October 1974.
                                                 5-48

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                                              SECTION 6
                                       NONCOMBUSTION PROCESSES

       The problem of NOX emissions has been researched in the chemical industry more intensively
than anywhere else because it may represent the loss of a valuable raw material.  The following sec-
tions of this report discuss commercial processes developed for NO  control in the manufacture and
uses of nitric acid.
       The NOX released in vent gases from the manufacture and industrial  uses of nitric acid, dif-
fers markedly from that emitted from a combustion flue gas in concentration, total amount, and the
ratio of N09 and NO present.  The NO -containing chemical gas is commonly a process stream which
           t                        A                                 '
must be recycled with maximum N0x recovery in order to have an economical  process.  Vent gas is re-
leased only because it is too impure to recycle or too low in concentration for economic recovery.
The economic limit with a pure gas, as in nitric acid manufacture, is about 0.1 to 0.3 percent NO ,
                                                                                                 X
or 1,000 to 3,000 ppm.  The limit is higher in organic nitrations, such as the manufacture of nitro-
glycerine, where NOX content of the vent gas may approach 1  percent NO , or 10,000 ppm.
       The total amount of NOX emitted from all chemical  manufacturing is  about 1.7 percent
(203 Gg or 2.2 x 105 tons/yr) of all NOX from manmade sources in the United States.  These pro
cesses present problems only in special local areas.  The problems have been most serious in military
ordance works, which manufacture large volumes of nitric acid and use it in organic nitrations.  A
single plant like the Volunteer Ordance Works has produced, for example, emissions of NO  equal to
all nonmilitary uses of nitric acid in the United States.
       A high ratio of N02/N0 at high concentrations causes  the gases to be visible as a brownish
plume.  The visibility limit depends on the total  amount  of N02 present in the gas volume or layer
observed.   A convenient rule of thumb is that a stack plume or air layer will  have a visible brown
color when the N0« concentration exceeds 6,100 ppm divided by the stack  diameter in centimeters (Ref-
erence 6-1).  This means that the threshold of visibility for a 5 cm-diameter stack is about 1,200 ppm
of N02 and for a 30 cm-diameter stack, 200 ppm of N02 (or 2,000 ppm of NO   at a 1:10 ratio of NO?:NO).
                                                 6-1

-------
       The distinction between N0? concentrations and total  amount can be quite important in chemi-
cal vent gases, since a short burst of NOp at 10,000 ppm may be visible but less hazardous than
many times as much NO  emitted from a large stack at a lower concentration.  The total  amount in a
short, concentrated emission may be too small to have a detectable effect on NO  levels in ambient
air.
       A large amount of research with varying degrees of success has been carried out on the devel-
opment of processes for the removal of NO  from the off-gas  resulting from the manufacture and uses
of nitric acid.  The abatement processes are discussed in detail in Section 6.1.3.

6.1    NITRIC ACID MANUFACTURE
       Nitric acid plants are divided into two types:  those that make dilute nitric acid (50-68 per-
cent nitric acid) and those that make strong nitric acid (over 95 percent nitric). Nitric acid and water
form an azeotropic (constant-boiling) mixture at about 58 percent nitric acid content; this is the limiting
factor in the nitric acid concentration available through distillation and absorption methods.
The acid is concentrated to 98 percent in an acid concentration unit using extractive distillation.
The direct process for making strong nitric acid usually depends on direct formation of nitric acid
in an autoclave where nitrogen oxides react with oxygen and  water to form nitric acid.   Most (> 95
percent) nitric acid plants presently in operation are of the first kind.
6.1.1  Dilute Nitric Acid Manufacturing Processes
       Nitric acid in the United States is made by the catalytic oxidation of ammonia.   Air and
ammonia are preheated, mixed, and passed over a catalyst, usually a platinum-rhodium complex.  The
following exothermic reaction occurs:

                              4NH3  +  502  -»•  4NO  +  6H20
                                                                                            (6-1)
                                      (AH   = -906 J/mole)
The stream is cooled to 31 IK (100F) or less, and the NO then reacts with oxygen to form nitrogen
dioxide and its liquid dimer, nitrogen tetroxide.
                              2NO  +  02   +  2 N02 *  N204
                                                                                            (6-2)
                                      (AH   = -113 J/mole)
       The liquid and gas then enter an absorption tower. Air is directed to the bottom of the
tower and water to the top.  The NOo (or NpO.) reacts with water to form nitric acid and NO, as
follows:
                                                 6-2

-------
                                3N02   +   H20  +  2HN03   +  NO
                                                                                              (6-3)
                                        (AH    =  -135 J/mole)

  The  formation  of  1 mole  of  NO  for each  2 moles  of HN03  makes  it necessary  to reoxidize NO after each
  absorption  stage  since the  gas rises up the  absorber and  limits the  level  of recovery that can be
  economically achieved.
        Acid product is withdrawn from the bottom of the tower in concentrations of 55 to 65 percent.
  The air entering  the bottom of the tower serves to strip N02 from the product and to supply oxygen
  for reoxidizing the NO formed in making nitric acid (Equation 6-3).
        The oxidation and absorption operations can be carried out at low pressure (~ 100 kPa, 1  atm),
  at medium pressure (400 to 800 kPa or 58 to 116 psia) or at high pressure  (1000 to 1200 kPa or 145 to
  174 psia).  Both operations ma^ be at the same pressure or at different pressures.
        Before corrosion-resistant materials were developed, the armonia oxidation and absorption
 operations were carried out at essentially atmospheric  pressure.   This  also had advantages  compared
 to the higher pressure processes  of longer catalyst  life (about 6  months),  and  increased  efficiency
 of ammonia combustion.   However,  because of the  low  absorption and NO oxidation rates, much more
 absorption volume  is  required,  and  several  large towers  are placed in series.   Some  of these  low
 pressure  units  are still  in  operation,  but  they  represent  less  than  5 percent of the  current  U.S.
 nitric acid  capacity.
        Combination pressure plants carry out  the ammonia  oxidation process at  low or medium pres-
 sure  and  the  absorption step at medium or high pressure.   The  higher  combustion  temperature and gas
 velocity at an  increased  pressure for the oxidation reaction shortens catalyst's  lifetime (1  to 2
 months) through  increased erosion and lowers the anmonia oxidation conversion efficiency  (Reference
 6-2).  Thus lower  pressures in the oxidation process are preferred.  On the other hand, higher pres-
 sures  in the absorption tower increase the absorption efficiency and reduce N0x levels in the tail
 gas.   Of course  these advantages must be weighed against the cost of pressure vessels and compressors.
       The choice  of which combination of pressures to use is very site  specific and is governed  by
 the economic trade-offs between the costs of raw materials, energy and equipment, and process  effi-
 ciency; and local emissions limits.   In the 1960's.  combination low pressure oxidation/medium  pressure
absorption and single pressure (400 to 800 kPa) plants were preferred.  Since  the early 1970's, the
trend has  been toward medium pressure  oxidation/high  pressure absorption plants  in Europe  and  single
pressure plants  (400 to 800 kPa) in  the  United States.
                                                 6-3

-------
6.1.1.1   Single Pressure Processes
       In the single pressure process,  both the oxidation and absorption processes are carried out
at the same pressure - either low pressure (100 kPa or ~ 1 atm.) or medium pressure (400 to 800 kPa).
Single pressure plants are the most common type.  Figure 6-1  is a simplified flow diagram of a
single pressure process (Reference 6-3).   A medium pressure process will be described below.
       Air is compressed, filtered, and preheated to about 573K by passing through a heat exchanger.
The air is then mixed with anhydrous ammonia, previously vaporized in a continuous-stream evaporator.
The resulting mixture, containing about 10 percent ammonia by volume, is passed through the reactor,
which contains a platinum-rhodium  (2 to 10 percent rhodium) wire-gauze catalyst (for example, 80-mesh
and 75-ym diameter wire, packed in layers of 10 to 30 sheets so that the gas travels downward through
the gauze sheets).  Catalyst operating temperature is about 1,023K.  Contact time with the  catalyst
is about 3 x 10"  sec.
       The hot nitrogen oxides and excess air  mixture  (about  10 percent nitrogen  oxides)  from the reac-
tor are  partially cooled in  a heat exchanger and  further cooled in a water  cooler.   The  cooled  gas is
introduced into  a stainless-steel  absorption tower with  additional air  for  the further oxidation of
nitrous  oxide  to nitrogen  dioxide.   Small quantitites  of water  are added to hydrate  the  nitrogen
dioxide  and  also to scrub  the gases.   The overhead gas  from  the tower  is reheated by feed/effluent
heat  exchangers  and then expanded through a  power recovery turbine/compressor used  to  supply  the
reaction air.   The  tail  gas  is then  treated  by the  tail-gas  treater  for NOX abatement.   The bottom
of the  tower yields nitric acid  of 55  to  65  percent  strength.
 6.1.1.2  Dual Pressure Processes
        In order to obtain the benefits of increased absorption and reduced NOX emissions from high-
 pressure absorption, dual-pressure plants are installed.  Recent trends favor moderate-pressure
 oxidation and high-pressure absorption.
        A process flow diagram for a dual-pressure plant by Uhde is shown in Figure 6-2.  Liquid
 ammonia is vaporized by steam, heated and filtered before being mixed with air from the air/nitrous
 oxide compressor at from 300-500 kPa (44 to 72 psia).  The ammonia/air mixture is catalytically
 burned in the reactor with heat recovery by an Integral waste heat boiler to generate steam for use
 in  the turbine driven compressor.  The combustion gases are further cooled by tail gas heat exchange
 and water cooling  before compression to the absorber pressure of 800-1400 kPa (116 to 203 psia).  The
                                                   6-4

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                                                             WASTE GASES TO
                                                            POWER RECOVERY
                                                              AND TAIL GAS
                                                               TREATMENT
                                                             NITRIC ACID

Figure 6-1. Single pressure nitric acid manufacturing process (Reference 6-3).
                           6-5

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-------
absorption tower is internally water cooled to increase absorption by water.  Nitric acid up to 70
percent concentration is withdrawn from the bottom of the column and degassed with the air feed to
remove unconverted NO before being sent to storage.  The air/NO mixture is combined with reactor
effluent to form the absorber feed.  High yields of up to 96 percent conversion and tail-gas emissions
as low as 200 ppm N02 can be obtained by this process.

6.1.1.3  Nitric Acid Concentration
       Figure 6-3 illustrates a nitric acid concentration unit using extractive distillation with
sulfuric acid.  A mixture of strong sulfuric acid and 55 to 65 percent nitric acid is introduced at
the top of a packed column, and flows down the column counter-current to the ascending vapors.
Nitric acid leaves the top as a 98 percent nitric acid vapor containing small amounts of NO  and
oxygen, which result from the dissociation of nitric acid.   The vapors pass to a bleacher and a
condenser to condense nitric acid and separate NO  and oxygen, which pass to an absorber column for
conversion to, and recovery of, nitric acid.  Air is admitted to the bottom of the absorber.  Dilute
sulfuric acid is withdrawn from the bottom of the dehydrating tower and is sent to be concentrated
further to be used for other purposes.  The system usually operates at essentially atmospheric
pressure.
6.1.1.4  Direct Strong Nitric Acid Processes
       Nitric acid of high strength can be made directly from ammonia in direct strong nitric acid
processes.  These processes depend upon the formation of nitric acid by reaction of N02 or N20^ with
oxygen and water forming 95 percent to 99 percent nitric acid.  In this direct process, the composition
of the product nitric acid is not restricted by the azeotropic limit.
       The principal licensors of these direct processes are Uhde and Davy Powergas.  Uhde has built
two plants in this country using their direct strong nitric acid process.  The Uhde process will be
described in detail below.  Davy Powergas has two direct strong nitric acid processes; the CONIA
process and the SABAR process.  Davy has not built any plants utilizing these processes in the
United States, but there is a CONIA plant recently constructed in Sweden and a SABAR plant recently
constructed in Spain.  How these processes differ from the Uhde process will also be described below.
       Figure 6-4 shows a process flow diagram for a direct strong nitric acid plant.  Air and
gaseous ammonia are mixed and reacted where steam is generated in a combination burner/waste heat
boiler by the heat of reaction.  The reaction products are cooled, and a weak nitric acid condensate
removed.  The remaining gases are put through two oxidation columns where the NO is converted to N0.
                                                 6-7

-------
 VAPOR
98%HN03
FEED
93%
H2S04
60%
HN03*
      DEHYDRATING
        COLUMN
                                                                   TAIL GAS TO
                                                              ATMOSPHERE (VOLUME %)
                                         COUNTERCURRENT
                                           CONDENSER
                                     VAPORi
i
                             •*
                             CONDENSATE
                        BLEACHER
                       95-99% HN03
                  TO COOLER AND STORAGE
                                                                    74.3 N2
                                                                    20.402
                  VAPOR
           LIQUID
     STEAM
      COIL
JN-
NSABLE
5ES

ABSORPTION
COLUMN
                                                                                AIR
                         BOILER
                                            TO COOLER
                                                                    55% HNO3
                         Figure 6-3. Nitric acid concentrating unit.
                                          6-8

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 The overhead vapors are compressed to a pressure that allows the equilibrium di-nitrogen tetroxide
 (N204) to be liquefied with the use of cooling water alone.  The liquid Np04  is converted to nitric
 acid of about 95 to 99 percent by reacting the N204 with oxygen at a pressure of 5000 kPa (50 atm).
 The conversion reaction is:  2N204  +  2H20  -»•  4HN03>  Tail gases from the absorption column are
 scrubbed with water and condensed N204 in a tail-gas scrubber before being released.   The liquid
 from the tail-gas scrubber is mixed with the concentrated acid from the absorption column, which
 has been bleached and liquefied.   The combined product liquid (containing N204 as well as HNOJ  is
 reacted with oxygen in the reactor vessel, cooled,  and bleached to produce the concentrated nitric
 acid.
        Both Uhde plants using this process were built in 1973 for the U.S.  Government:  one in
 Joliet, Illinois makes 236 Gg/d (260,000 tons/day)  of 98.5 percent nitric acid; the second in
 Chattanooga, Tennessee, makes 313 Gg/d (345,000 tons/day) of 98 percent nitric acid.   Neither are
 in operation at present, although, both were designed to meet the New Source Performance Standards.
        In  the  Davy  Powergas SABAR  process  (Reference  6-4),  like  the  Uhde  process,  ammonia  and  air
 are reacted  at  atmospheric pressure,  and a 2-3  percent nitric acid is  condensed and removed  as a
 byproduct.   Davy Powergas  estimates 0.3  kg of  this weak  acid  byproduct is  produced per kg  of con-
 centrated  acid.   As  in the Uhde process, N02  is  then  produced from the product  gases and absorbed
 in concentrated  nitric acid.   However, whereas  Uhde  forms N204 from  this  liquid,  and reacts  the  N 0
 with oxygen, the  SABAR process takes  the concentrated  HN03  to a  vacuum rectification column, where
 concentrated HN03 comes  off overhead  and azeotropic nitric  acid  is collected at  the bottom.  Atmos-
 pheric  emissions  are less  than 500 ppm nitric oxides,  which would not  meet  the  new source  standards
 in the  United States without further  treatment.
        Davy Powergas developed the CONIA process to meet  the  more stringent environmental  regulations
 for its site in Sweden.  The CONIA process also depends on the ammonia-air reaction, followed by re-
 moval of the water which is generated.  The plant produces both 99.5 percent nitric acid and 54 per-
 cent nitric acid, with less than 200 ppm NOX in the stack gases, and no other solid or liquid waste
 streams.  However, Davy Powergas considers this particular plant design to be over-designed and hence
 too costly for most applications unless lower emissions limits must be met (Reference  6-5).
 6.1.2  Emissions

       Absorber tail gas is the principal  source of NOX emissions from nitric acid manufacturing.
Minor sources include nitric acid  concentrators and  the filling of storage tanks and shipping con-
tainers.  Nitrogen oxide emissions  from nitric acid  manufacturing are estimated at 127  Gg
                                                 6-10

-------
 (140,000 tons) during 1974, which is about 1.0 percent of the NO  emissions from stationary sources.
 It is estimated that 7.4 Tg (8.2 million tons) of nitric acid (100 percent) were produced in 1974
 (Reference 6-6).  AP-42 (Reference 6-7) cites an average emission factor for uncontrolled plants of
 25 to 27.5 kg/Mg of acid.  Typical uncontrolled tail-gas concentrations are on the order of 3000 ppm
 of NO  with equal amounts of NO and N02 (Reference 6-8).  Unde cites emission levels in excess of 800
 ppm for low-pressure plants, 400 to 800 ppm for medium-pressure plants, and less than 200 ppm for high-
 pressure plants (Reference 6-2).  The extent of control for these plants' is not known, although, Uhde
'did state that all three processes could be designed in such a way as to meet State and Federal emis-
 sion limits.
       In any nitric acid plant, the NO  content of tail gas is affected by several variables.  Abnormally
 high levels may be caused by insufficient air supply, high temperature in the absorber tower, low-
 pressure, production of acid at strengths above design, and internal leaks, allowing gases with
 high nitrogen oxide content to enter the tail-gas streams.  Careful control and good maintenance are
 required to hold tail-gas nitrogen oxide content to a minimum.
 6.1.3  Control Techniques for NOX Emissions from Nitric Acid Plants

       Nitric acid plants can be designed for low NO  emission levels without any add-on processes.
 Such plants are usually designed for high absorber efficiency; high inlet gas pressures and effec-
 tive absorber cooling can lead to low NO  emissions.  However, many new plants, and all existing
 plants, are not designed for NO  emission levels low enough to meet present standards.  For these
 plants, add-on abatement methods are necessary.
       The available abatement methods suitable for retrofit include chilled absorption, extended
 absorption, wet chemical scrubbing, catalytic reduction, and molecular sieve adsorption.  In this
 section, these various control techniques for NOV are described.  These techniques may also be
                                                .A
 appropriate for retrofit of explosive and adipic acid plants.
       Many of the retrofit processes are offered by more than one licensor, and many licensors
 (such as Uhde) offer more than one process.  Table 6-1 lists the major processes, the types of
 plants for which the processes are most suitable, and examples of nitric acid plants where the
 processes have been applied.  (The examples of nitric acid plants are not meant to be inclusive.)
       The selection of a control method depends on such things as the degree of control required,
 the operating pressure of the plant, and the cost and availability of fuel.  For example catalytic
 reduction was used to establish the NSPS originally.  Since that time fuel  costs have risen to the
 point where catalytic abatement is not economically attractive for new nitric acid plants but can
 be used as an effective secondary treatment to meet the NSPS.

                                               6-11

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       The  inlet  pressure at the absorber is an important factor in the selection of NO  control
 equipment.   In general, extended absorption equipment cannot be economically installed where the
 equipment will have inlet pressures of less than 758 kPa  (110 psia).  Consequently, extended adsorp-
 tion  is not usually chosen for older, low pressure nitric acid plants.  Wet scrubbing and molecular
 sieve absorption  are also not as effecive at low pressures.  Catalytic reduction, however, does not
 require high pressures.
 6.1.3.1  Chilled  Absorption
       This method is used primarily for retrofit of existing plants.  Chilling the water used in
 a  nitric acid absorption tower leads to higher yields of nitric acid and lower NO  concentrations
 in the tail gas.  Both water and brine solutions have been used in a closed loop system to provide
 local  cooling to  the liquid on the trays of the absorption tower.  Absorption may be further en-
 hanced by heterogeneous catalytic oxidation of NO to N0« upstream of the absorption tower.
 CDL/VITOK Process
       Figure 6-5 shows a CDL/VITOK process flow diagram.  Tail  gas enters the absorber, where the
 gases  are contacted with a nitric acid solution to both chemically oxidize and physically absorb
 nitrous oxides.   The reaction of NO to N02 may be catalyzed in the main absorber.  The upper portion
 of the absorber is water cooled to improve absorption.  The nitric acid solution from the absorber
 is sent to  a bleacher where air removes entrained gases and further oxidation occurs.  The bleached
 nitric acid solution is then either sent to storage or recirculated to the absorber after the addi-
 tion  of make-up water.  The process employes a closed loop system to chill the recirculated acid
 solution and tower cooling water by ammonia evaporation.
       One  variation in this system proposed by CDL/VITOK includes the addition of an auxilliary
 bleacher operating in parallel with the primary unit.  Another variation uses a secondary absorber
 with  its own bleacher.
       At the Nitram, Tampa, Florida location two 318 Mg/d plants were fitted with the CDL/VITOK
 process.  NOX tail gas concentrations were reduced from 1500 to  1800 ppm to 600 to 800 ppm.   With
 the addition of a gulf catalytic abatement system the plant meets local  regulations.   A second  plant
 at Nitram fitted with the process showed promise but was shut down and replaced with a new nitric
acid plant.
 TVA Process
       The  Tennessee  Valley  Authority,  at  their nitric  acid  plant in  Muscle Shoals, Alabama,  designed
 and installed  refrigeration  for NOX abatement  pruposes  in 1972,  in  order  to meet  State  standards  of 2.75

                                                6-14

-------
   PURIFIED
   TAIL GAS
  COOLING
  WATER
  RETURN
 FEED GAS/
  LIQUID
FROM HEAT
  EXCH.
          ABSORBER
       BREACH AIR
      RECOVERED
                                                        COOLING
                                                         WATER
                                                                •MAKE-UP WATER
                                           PUMP
     Figure 6-5. Schematic diagram of the CDL/VITOK NOX removal process (Reference 6-8).
                                         6-15

-------
 kg/Mg of nitric acid (5.5 Ibs/ton).   A flow diagram of their abatement  equipment is  shown  in  Figure
 6-6 (Reference 6-10).   It consists of a cooler  attached to  the  nitric acid  absorption  tower,  and  a
 bleacher from which any effluent  gases are  recycled to the  absorption tower.   As a  result  of  adding
 the NOX control  process the  concentration of the  product acid dropped from  65  percent  to 51 to  57
 percent.

 6.1.3.2  Extended  Absorption
        The  extended absorption  process basically  consists of a  second absorption column to which  the
 tail  gas  from the  nitric  acid plant  is sent.  The NOX  is absorbed  by water  and forms nitric acid,
 which  increases  the acid  yield.   Extended absorption can be  added  in conjunction with  pressurizing
 the tail  gas  upstream of  the tower or chilling  the  absorbent in  the tower.  However, neither  of these
 options is  a  necessary  part  of  the absorption process.
        This process is  offered  by several licensors, including J.  F. Pritchard (Grande Paroisse
 process), D.  M.  Weatherly, Chemico,  Uhde and C  and  I Gridler (CoFaz process).    The economics of  the
 process generally  require the inlet  pressure at the absorber to  be at least 758  kPa (110 psia).  Also,
 cooling is usually  required  if  the inlet N0x concentration is above 3000 ppm (Reference 6-6).   There is no
 liquid  or solid  effluent  from extended  absorption;  the weak  acid from the secondary absorber  is
 recycled to the  first absorber, increasing  the yield of  nitric acid.  In some  cases, extended absorp-
 tion can be used in  conjunction with  catalytic  tail gas  treatment  (see Section 6.1.3.4).
        Figure 6-7  shows a process flow  diagram  for  the Grande Paroisse process, which is representa-
 tive of extended absorption  processes.  Off-gas from the existing absorber flows  into the secondary,
 or  Grande Paroisse  absorber.   The tail  gas  from the secondary absorber goes to an existing tail-gas
 heater before being vented to the atmosphere or passing  through a catalytic reduction unit.  The
 liquid effluent is  returned to the primary absorber to become part of the acid product.
       More than 15 extended  absorption plants (by various licensors)  are operating in  the  United
States.  In cases where the off-gas must be  compressed before going to the secondary absorber, or
where refrigeration is  used,  maintenance requirements are increased.   Power recovery by an  air
compressor/tail-gas expander  is  usually employed when a pressurized absorber is used.

 6.1.3.3  Wet Chemical Scrubbing
       Wet chemical scrubbing uses liquids,  such as alkali hydroxides,  ammonia, urea and potassium
permanganate to convert N02 to nitrates and/or nitrites by chemical reaction.   Also,  scrubbing may
be done with water or with nitric acid.  Several of these processes are  described below.
                                                6-16

-------
                        ABSORPTION TOWER AND BLEACHER
                                   DETAIL
 COILS SUBMERGED -v ACID FLOW
IN ACID FOR COOLING
   OR HEATING c
                   -v
                   G }
                             GAS'FLOW
     STEAM
WATER
                        EXHAUST GASES-
                                              WATER
                   BLEACHER
                     AIR
                     NEW
                  \IITRICACIE
                   BLEACHER
            COMPRESSED
                AIR
                           WATER
                   PRODUCT
                  NITRIC ACID
                  TO COOLER
                                   T
                                   COOLING
                                    WATER
ABSORPTION
  TOWER
                                        SEAL PLATE

                                        TNTE~FWAL~
                                         BLEACHER
                                          SECTION
  *
REFRIG-
ERATED
COOLING
WATER
 (50 °F)
                                                              WATER
                                                                   \
                                                                     COOLING
                                                                   WATER HEADER
                                                                                   7
                                                                  COOLER CONDENSER
                                           NITRIC ACID   GAS FROM AMMONIA
                                                I
                                                         OXIDIZER
                 Figure 6-6.  TV A, chilled absorption process (Reference 6-10).
                                          6-17

-------
                                     TO EXISTING
                                  TAIL GAS PREHEATER
1 "•
r »_L_ n !
1 EXISTING I— ,,
ABSORBER P*] j 	
1 1 i
i
1 1
I 1
NITROUS j
GAS ^ | 1
1
, -i-
"L

LEVEL
CONTROL
7 K /r
• [ r^v.
i. _. i

	
-n— __j_ _,___
— 	 > 	 ^
	
SECONDARY
ABSORBER
TOWER





_ NITRIC ACID ! RE.C.?^E.?ED

AC
ACID TRANSFER
PUMPS
(ONE SPARE)
^T^ C^r
\y ^J
ID
















I {-&*








FLOW
CONTROL
/
-------
CO(NH2)2 + N2
+ HN02 t N2
+ •*- H
H2o + H + NH]
+ HNCO
+ co2 -
i-

 Urea Scrubbing
        This process is offered by two licensors:   MASAR,  Inc.  and Norsk Hydro.   The mechanisms
 given below have been proposed for this  process  (Reference 6-11).

                                                                     2H20                    (6-4)

                                                                    20                       (6-5)

                               HNCO  + H20  + HT +  NH4   + C02                              (6-6)

 When the  concentration of  nitric  acid is  low,  reaction (6-6) predominates  so  that  the overall
 reaction  is
                     HN02   +  CO(NH2)2 +  HN03   +  N£  +   C02  +   NH4N03  +  H20            (6-7)

 As  shown  in  reaction  (6-7), half  the  nitrogen  in the reaction will  form  NH4N03,  a  valuable by-
 product,  and half will  form N2, a  nonpolluting species.
       The MASAR process is shown  in  Figure 6-8.   A  three-stage absorption column  is used with gas
 and  liquid chillers on  the feed gas and recirculated solvents.  The process as described by MASAR,
 Inc.,  (Reference 6-12)  is  given below.
       The MASAR process,  as applied  to nitric acid plants, takes the tail gas from the exit of the
 absorption tower and  passes it to  a gas chiller where it is cooled.  During this cooling operation,
 condensation occurs with the formation of nitric acid.  This chilled gas and condensate passes into
 Section A of the MASAR  absorber.   Meanwhile, the normal feedwater used in the nitric acid plant
 absorption tower is chilled in Section C of the MASAR absorber and is then fed to Section A of the
 MASAR absorber, where it flows down through the packing countercurrent to the incoming chilled tail
 gas  to scrub additional NOX from the tail gas.   This scrubbing water is recirculated through a
 chiller to remove reaction heat and then this weak nitric acid stream is fed to the nitric acid
 plant absorber to serve as its feedwater.
       The tail gas then passes into Section B  of the MASAR absorber where it is  scrubbed with a
circulating urea-containing solution.  A urea/water solution is made up in a storage tank and
metered into the recirculating system at a rate necessary to maintain a specified minimum urea
residual  content.  As the solution scrubs the tail  gases,  both  nitric acid and nitrous  acids  are
formed, and the urea in the solution reacts  with  the nitrous acid  to form CO(C02),  N?,  and H90.   As
the solution is circulated, the nitric acid  content rises  and  some of the urea present  hydrolyzes
and forms some ammonium nitrate.   To maintain the system  in balance, some of the  circulated  solution
is withdrawn.  The recirculated solution  is  also  pumped through a  chiller to  remove the  heat  of
reactions and to maintain the  desired process temperature  in Section B.

                                               6-19

-------
                                       FEED WATER
                      SPENT MASAR
                     —SOLUTION—
                      (BLOW DOWN)
        LIQUID
       CHILLER
CONCENTRATED MASAR
     SOLUTION	
PUMP
                             TAIL GASES
                             FROM PLANT
        LIQUID
        CHILLER
                               TAIL GAS
                               CHILLER
I	^
 '             PUMP
                                                              SECTION
                                                               /r>
                                                               SECTION
                                                                 A
                             FEED WATER
                          TO NITRIC ACID PLANT
                           ABSORBER COLUMN
               MASAR
              ABSORBER
          Figure 6-8.  Flow diagram of the MASAR process (Reference 6-12).
                                        6-20

-------
       The tail gases then pass into Section C where they are again scrubbed by the feedwater
stream that is used, ultimately, as the nitric acid plant absorption tower feedwater.  The tail
gases then leave the MASAR absorber and pass on to the normally existing mist eliminator and heat
exchanger train of the nitric acid plant.  The cooling medium used in the gas chiller can be liquid
ammonia.  The vaporized ammonia is subsequently used as the feed to the plant ammonium nitrate
neutralizes  For non-ammonia nitrate producers, mechanical refrigeration could be used or the
ammonia vapor can be used in the nitric acid converter directly.
       The MASAR process has been reported to reduce NO  emissions from 4000 ppm to 100 ppm.  The
process could technically be designed for no liquid effluent.  In practice, however, liquid blowdown
of 16 kg/h (35 Ib/hr) of urea nitrate in 180 kg/h (396 Ib/hr) of water is estimated for a 320 Mg of
acid/day (350 tons/day) plant (Reference 6-12).
       A MASAR unit installed in 1974 for Illinois Nitrogen Corporation on a 320 Mg/d plant regu-
larly operates with between 100 and 200 ppm of NO  in the tail gas.  According to the Illinois Nitro-
gen plant manager (Reference 6-13), inlet NO  concentrations to the MASAR unit are approximately 3500
ppm and outlet concentrations are between 200 and 400 ppm.   The Illinois Environmental  Protection
Agency has tested this unit, using Method 7, with reproducible results of 57 ppm average emissions.
The unit is reported to operate with good reliability and has increased the net product recovered.
       The Norsk Hydro process was developed by Norsk Hydro A/S, the Norwegian state-owned power
generating authority and fertilizer and chemical manufacturer, to reduce NO  emissions  from 1525 ppm
to 850 ppm.  The modifications were made to an older, atmospheric pressure plant and two more recent
medium-pressure plants (300 and 500 kPa) (44 to 72 psia).  Basically, the last absorption towers in the
process streams of the older plant were modified to contact the tail gases from all  three plants with urea
solution and nitric acid.   The result was a net 44 percent  reduction in NO  emissions,  as given
above.  On a plant-wide basis, 10.4 kg of ammonium nitrate  are produced per Mg of nitric acid (20.8 Ib/ton)
(Reference 6-11).
       Norsk Hydro has also used urea addition on three plants producing a total  of 5 Gg/d (5500 tons/
day)  of prilled NPK fertilizers.  This method was used to control NO  emissions for lower-grade phosphate
rock.  Nitrous oxide is evolved when nitric and nitrous acid oxidizes impurities  in the rock such
as sulphides and organic material.  The addition of urea to the phosphate rock digester tends to
reduce N0x emissions to 2.5 kg/Mg (5 Ib/ton) phosphate from levels as high as 40  kg NO   per Mg phosphate
(80 Ib/ton) by adding 5 to 10 kg urea per Mg phosphate rock (10 to 20 Ib/ton) (Reference 6-11).
                                               6-21

-------
 Ammonia Scrubbing (Goodpasture Process)
        Goodpasture,  Inc.  of Brownfield,  Texas  is  the  licensor of a  process  developed  in  1973  in
 order for its  Western  Ammonia  Corporation  nitrogen  complex  in Dimitt,  Texas to  meet a 600  ppm
 maximum NOX effluent imposed by the  Texas  Air  Control  Board.   The process which was developed is
 suitable to retrofit existing  plants for reduction  of an  inlet concentration of 10,000 ppm to
 within the 1.5 kg N02/Mg  acid  (^210  ppm) standards  set for  new nitric  acid  plants.
        The process flow diagram for  this process  is shown in  Figure 6-9.  Feed  makeup streams to
 this  process are  ammonia  and water with  ammonium  nitrate  produced as a byproduct.  The total  process
 is  conducted in a single  packed contact  absorption  tower  with three sections operated in a co-
 current flow.  Goodpasture  states that the key to successful  operation is the process' capability
 to  minimize the formation of ammonium nitrite  and to  oxidize  the ammonium nitrite which does  form to
 ammonium nitrate.
        The Goodpasture process  consists  of three  distinct sections.  The first  is a gas absorption
 and reaction section operating  on the acidic side,  the second  is  a  gas  absorption and reaction
 section  operating on the ammoniacal  side,  and  the third is principally  a mist collection and  ammonia
 recovery step.
        In  the  first section, a  significant  portion  of the oxides  of  nitrogen  react to  form  nitric
 acid which  maintains the acidic  condition  in this section.  The  nitric  acid  formed reacts with the
 free ammonia content of the  solution  from  the  ammoniacal section  to  form ammonium nitrate - ^ portion
 reacting  in  the acidic section,  and a portion  reacting in the ammoniacal section.  The feed solution
 to the acidic  section is the product  solution  from  the ammoniacal section.   The ammonium nitrite
 content  of  this solution is oxidized  to  ammonium nitrate by the acidic  conditions existing  in this
 first section.   The product solution  from the Goodpasture process is withdrawn from this acidic
 section.
       In the  second, or ammoniacal  contacting, section the  remainder of the oxides of nitrogen react
 to form ammonium nitrate and ammonium nitrite;  the proportion of each being  dependent  on  the oxida-
 tion state of  the oxides of nitrogen in the gas phase.  Ammonia is added to  the  circulating solution
within this section to  maintain the  pH at a level  of 8.0 to  8.3.  The liquid feeds  to  this  section
are the product solution from the mist collection  section, and a portion of  the  acidic solution from
the first section.
       The third section is  incorporated  principally to collect the  mist, and any ammonium  nitrate
or ammonium nitrite aerosols which form in  the  first two sections.  In  addition, any free ammonia
                                                6-22

-------
   TAIL
   GAS IN*
  RECORD.
 CONTROL.
TREATED
TAIL GAS
  OUT
       LEVEL
                 AMMONIACAL
                  SECTION
                                             CONTROL.
                                AMMONIA--
                                   LEVEL
                                  CONTROL
HYDRAULIC
 CONTROL
  VALVE

   pH
 RECORD.
 CONTROL,
   STEAM
 CONDENSATE
                                                                      PRODUCT
                                                                    AMMONIUM
                                                                       NITRATE
                                                                     SOLUTION
   Figure 6-9. Process flow diagram for the Goodpasture process (Reference 6-14).
                                     6-23

-------
stripped from the solution in the ammoniacal  section is also recovered in this third section.
Process water or steam condensate is fed to this section in quantities sufficient to maintain  the
product ammonium nitrate solution in the 30 to 50 percent concentration range.  A small amount
of the acidic solution is also fed to this section in order to control the pH to approximately 7.0.
       The product solution from the abatement process is withdrawn at about 35 to 40 percent
ammonium nitrate concentration, and contains  approximately 0.05 percent ammonium nitrite.   At  the
Dimmitt plant, this solution is heated to 390K (240F), which completes the removal of the  ammonium
nitrite, before further processing.  Other users have discovered that if the solution sits for a
day in a day-tank, without heating, the ammonium nitrite is removed.
       The Goodpasture process has been installed at CF Industries' Fremont, Nebraska plant and
Chevron Chemical's Richmond, California plant.  In addition, American Cyanamid Company is  installing
the process at one high-pressure and six low-pressure plants in Canada.  Existing systems  have
given reliable operation and have met the emissions requirements for which they were designed.
       One particular advantage of this process is that the pressure losses in the process are only
6.8 to 13.0 kPa (1-2 psi) which allows its application to low-pressure plants.  One older, 340 kPa
(49 psia) plant has consistently met its required 400 ppm outlet concentration.  Another advantage
of the low-pressure drop is that reheat and power recovery of the effluent train in moderate-
pressure plants is usually economical.  However, special precautions must be taken to eliminate
deposition of ammonium nitrate on the turbine blades.
       Energy requirements of the process have been less than expected.  The original design speci-
fied heating the ammonium nitrate scrubbing solution to facilitate oxidation of ammonium nitrite
to nitrate.  However, it has been found that this reaction occurs spontaneously if the solution
is allowed to stand for a day in a holding tank.
       The retrofit of a Goodpasture unit may require some additional process modifications beyond
the abatement equipment.  For example, modern fertilizer plants use ammonium nitrate solutions in
excess of 85 percent.  The Goodpasture byproduct solution is only 35 to 55 percent ammonium nitrate;
therefore, additional evaporators may be needed to concentrate the Goodpasture effluent.   Chevron;
however, reports significant overall steam savings without additional evaporators.
Caustic scrubbing
       Sodium hydroxide, sodium carbonate and other strong bases have been used for nitric acid
scrubbing.  Typical reactions for this process are:
                                               6-24

-------
                                   2NaOH  +  3N02   5  2NaN03  +  NO  +  H20                  (6-8)
                             2NaOH  +  NO  +  N02   *  2NaN02  +  H20                         (6-9)

         A caustic scrubbing system was installed at a  Canadian nitric acid  plant  in  the  late  1950's
  (Reference 6-15).   However,  disposal  of the spent  solution  is a  serious  water  pollution problem,
  and the concentrations  of the salts are too low for economic  recovery.   There  have  been no recent
  installations  of this process.
  Potassium Permanganate  Scrubbing
         Another potential  chemical  for scrubbing  solutions is  potassium permanganate.  The Carus
  Chemical  Company  (a large  producer  of potassium  permanganate)  has developed a process for potassium
  permanganate solution scrubbing  of  NCy  However,  in the process, permanganate is reduced to manganate,
  which must be  electrolytically oxidized.  The cost for the electrolysis, as well  as the permanganate
 make up cost,  makes the process  uneconomical.  This process has not been installed at any nitric acid
  plant in  this  country.  Two plants are in operation in Japan, but no cost or user information is
  available.

  6.1.3.4  Catalytic Reduction
        This section describes two different catalytic  reduction processes.   They  are nonselective
 catalytic reduction and  selective catalytic reduction.
 Nonselective Catalytic Reduction
        In nonselective catalytic  absorption, methane or hydrogen  reacts  with the  NO   and oxygen  in
                                                                                   A
 the tail gas to form N2. H20,  and C02.  A schematic of  a  typical  catalytic  reduction unit is  shown
 in Figure 6-10.  The reactions (given  in Section 3.3.2.4)  in the  abater are exothermic;  and careful
 temperature control  is necessary  for effective operation.  The controls needed for operation  as
 a decolorizer are  much less stringent.
       Catalytic  reduction  units  for decolorization and power  recovery are  used in about  50 nitric
 acid plants  in  the United  States.  Many plants use  natural gas  for the reducing agent because of its
 easy availability  and low cost.*  Some  plants use  hydrogen.  When natural gas is used, the tail gas
 must be  preheated  to about  753K (900F)  to ensure  ignition.  A preheat temperature as low as 423K
 (300F) is  sufficient to  ignite hydrogen.
       Catalytic reduction  is highly exothermic.   The temperature rise for the reaction with methane
 is about 128K (230F) for each percent oxygen burnout; with hydrogen it is about 150K (270F).   For

*                          £.£" trU6i hOWeVer' the  •»—<« °f «'"«  "tur.1  gas have greatly

                                               6-25

-------
                             TAIL GAS PREHEATER
             TAIL GAS
           FROM ABSORBER
       REGENGAS
          OUT
                                        CH4/02
                                     CONTROLLER
                                   SET POINT
                                 CH4 OFF WHEN
                               NH3 TO CONVERTER
                                    IS OFF
                                                     I     ON-OFF
                                                     j  SET POINT-OPEN
                                                    A    HIGH 02
                  -C*3	1

          T' — t
          IOLLER  I
          (	f—	
          IV   I   I   I
                                               MIXER
                            ON-OFF
                          HIGH TEMP.
                           SET POINT
         TEMP.
       RECORDER
 LJ	:_
   MOLECULAR SIEVE
    DESULFURIZER
   TEMP.
 RECORDER/
CONTROLLER
                                              ABATER
POWER RECOVERY
   TURBINE
                                                                         02
                                                                     ANALYZER
                                                                     CONTROLLER
                                                                        CH4
                                                                     ANALYZER
                                                                     CONTROLLER
                           PROCESS
                            AIR
         Figure 6-10. Nonselective catalytic reduction system (Reference 6-16).
                                       6-26

-------
 decolorization, the outlet temperature is ordinarily limited to 923K (1.200F), the maximum tempera-
 ture limit of turboexpanders with current technology.  Increased power recovery may justify adding
 sufficient methane to reach the temperature limit of the turbine.
        The tail gas must be preheated to 753K (90QF) to insure ignition when methane is used as the
 reducing agent.  Outlet temperatures would reach 1.088K and 1.138K (1.500F and 1,590F) for 2 and 3
 percent oxygen burnout, respectively.  These temperatures compare to the 923K (1,200F) maximum
 temperature limit for single-stage operation.   The oxygen in the tail gas cannot exceed 2.8 percent
 to remain within the temperature limit of the catalyst.  Cooling must therefore be provided to meet
 the turboexpander limit.  Older turbines may have even lower temperature limitations.
        A somewhat cheaper but less successful  alternative is two-stage reduction for abatement.
 One system involves two reactor stages with interstage heat removal  (Reference 6-17).   Another
 two-stage system for abatement involves preheating 70 percent of the  feed to 753K (900F), adding fuel,
 and passing the mixture over  the first-stage catalyst.  The fuel  addition to the first stage  is
 adjusted to obtain  the  desired outlet temperature.   The remaining 30  percent of the  tail  gas,  pre-
 heated  to only  393K (250F), is used  to quench  the first stage effluent.   The two streams  plus  the
 fuel  for complete reduction are mixed and  passed  over the second-stage  catalyst;  the effluent
 passes  directly  to  the  turboexpander.   This  system avoids high  temperatures  and  the use of  coolers
 and waste  heat  boilers  (References 6-18, 6-19, and  6-20).
        Honeycomb ceramic  catalysts have been employed  in two-stage abatement,  with hourly gas-space
 velocities  of about  100,000 volumes  per hour per  volume in  each stage  (Reference  6-21).
        Nonselective catalyst systems  are offered  by  D. M. Weatherly, C &  I Girdler and Chemico.
 These systems are not as  popular as  NOX control methods because of rising fuel costs.
        Two or three plants are  known  to have installed single-stage nonselective abaters.  They are
 believed to have been designed  for natural gas.  As noted above, oxygen concentration cannot exceed
 about 2.8 percent.  The reactors must be designed to withstand 1,088K to 1.118K (1.500F to 1,550F)
 at  790  to 930 kPa, which requires costly refractories or alloys.  Ceramic spheres are used as cata-
 lyst supports, at hourly gas space velocities up to 30,000 volumes per hour per volume.  One company
 reports that they have been able to maintain NOX levels of 500 ppm or less over an extended period of
 time.   Operation close to 300  ppm might be attainable.  On a plant scale, the effluent  gas must be
 cooled by heat exchange  or quenched to meet the temperature  limitation of the turbine.   It may be
practical to use a waste heat  boiler  to generate steam.
       Commercial  experience with single-stage  catalytic abaters has  been modestly satisfactory,
but two-stage units  operating  on natural  gas have  not been as successful.   Two-stage  units  designed
                                               6-27

-------
for abatement have frequently achieved abatement for periods of only a few weeks,  at which  point
declining catalyst activity results in increasing NO levels.  Recent data indicate that successful
abatement can be maintained for somewhat longer periods.   Units that no longer abate NOX emissions
can, however, continue to serve for energy recovery and decolorization.
       The success of single-stage abaters compared to the limited success of two-stage units may
result from the following factors:  the catalyst is in a reducing atmosphere, the temperatures are
higher, and spherical rather than honeycomb catalyst supports are used.  It has not been practical to
change catalyst type in two-stage units because the reactors designed for a space velocity of
100,000 volumes per hour per volume would be too small to accommodate a spherical catalyst, which
effectively removes NO  at a space velocity of about 30,000.  The failure of the honeycomb catalyst
in NO  reduction compared to its success in decolorization may reflect that reaction kinetics make
it much more difficult to reduce NO than N02-
       Fuel requirements for nonselective abatement with methane are typically 10 to 20 percent
over stoichiometric.  Some hydrocarbons and CO appear in the treated tail gas.  Furthermore, not
all methane is converted in decolorization reduction units.  Less surplus fuel is required when
hydrogen is used.
Selective Catalytic Reduction
       In selective catalytic reduction, ammonia is reacted with the NOX to form N2-  No large
temperature rise occurs for ordinary operating conditions,  so no waste heat or steam is generated.
The catalyst used  in selective abatement units is platinum  on a honeycomb support.  Many catalytic
systems are installed between the expander and the economizer heat exchanger, and operate at
ambient pressure.   This lack of pressure sensitivity  is an  advantage for retrofitting older low-
pressure nitric acid plants.  It  is important to control the temperature between 483K and 543K
 (410F and  518F) because above 543K, ammonia may oxidize to  form N0x; below 483K, it may form ammonium
nitrate.
       Gulf Oil Chemicals  is the  main  licensor of  selective catalytic  abaters in North America.
They  have  eight systems onstream,  and  two more  planned.   Of these  systems, nine  operate at
ambient  pressure,  and one  operates  at  590 kPa  (86  psia).  Many of  these  catalyst beds also use  a
molecular  sieve for N02 adsorption  to  promote  the  reaction  with ammonia.
       Uhde  licenses  the BASF selective catalyst process  and recommends  it for tail  gas treatment
of 600 kPa  (87 psig)  nitric  acid  plants.
       User  experience with  these processes  has  been  good.   Catalyst  lifetimes of over 2 years  have
 been  reported, and expected  lifetime  is 5 to  10 years.  Catalytic  processes  have also been used to
 supplement chilled absorption  units when they  have  failed to meet  emission limits.
                                                 6-28

-------
  6.1.3.5  Molecular Sieve Adsorption
         The main equipment in a molecular sieve adsorption system is in the form of a two-section
  packed bed.   The first section is  packed with a desiccant, since the NOX adsorption sieve material
  works  best on a dry gas.   The second  section  contains  the material  which acts as nitrous oxide
  oxidation catalyst and NO  adsorber.
         Figure 6-11  is  a  schematic  of  a molecular sieve  system added to an existing nitric acid
  Plant.   N0x  removal  is accomplished in a  fixed  bed adsorption/catalyst system.   The water-saturated
  nitric  acid  plant  absorption  tower overheat stream is chilled to  283K  (50F),  the exact  temperature
  level being  a function of the  NOX  concentration  in the  tail-gas stream.   It is  then passed through
  a mist  eliminator  to remove entrained water and  acid mist.  The condensed water,  which  absorbs
  some of the  NO,,  in  the tail gas to form a weak acid, is collected in the  mist eliminator  and either
  recycled  to  the absorption tower or sent to storage.   The tail gas  then passes  through  a  molecular
  sieve bed where the special properties of the NOX removal  bed material results  in  the catalytic
 conversion of nitric oxide (NO) to nitrogen dioxide (N02).  This occurs in the presence of the low
 concentrations of oxygen typically present in the tail-gas stream.  Nitrogen dioxide is then selec-
 tively adsorbed.
        Regeneration is  accomplished by thermally cycling (or swinging)  the adsorbent/catalyst bed
 after it completes  its  adsorption  step and while it contains a high  adsorption loading of N02.   An
 oil-fired heater is used  to provide heat  for  regeneration.   The required regenerator gas is  obtained
 by using a portion  of the treated  tail-gas  stream for desorption  of  the NO,,.   This N02-loaded gas
 is recycled to the  nitric  acid  plant absorption  tower.   The  pressure drop  in the molecular sieve
 averages 34 kPa (5  psi) and N0x outlet  concentration averages  50 ppm (Reference  6-22).
       This process  has been applied to three  plants in  the  United States  (Reference 6-6).  Tables
 6-2 and  6-3 show  the performance of the system at two installations.  The  commercial  name  for
 the process  is the Purasiv  N process.  The unit at the 50 Mg/d (55 tons/day) acid plant of
Hercules,  Inc.  started up  in 1974.   Abatement ranged from 95.9 to 98.7 percent averaged over indivi-
dual cycles and was highest at the beginning of a cycle (Reference 6-23).  The U.S. Army Holston
Purasiv  N unit was started up in August 1974,  but has  been  inoperable for several years.
       Both plants have dual-unit NOX adsorbers, operating  on a 4 hour adsorption, 4 hour regenera-
tion cycle  (Reference 6-22).  Initial  reports  on the operation were very favorable; the effluent
standards were met,  and the sieve showed no noticeable  deterioration  after 6 months.  One sieve was
damaged by accidental acid back-up,  however, and did not  achieve the  expected 50  ppm outlet concen-
tration.
                                               6-29

-------




ABSORBER
(EXISTING)


TAIL GAS
CONTAINING NOX
1 ^
1
i
	 | 	
1
i
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AND N02-H20
ADSORPTION

REGENERATION


1
X.
/

^
/

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\^J
-^- 1 HEAT
j EXCHANGER
! (EXISTING)
	 4 	 '


                                                          POWER
                                                         RECOVERY
                                                         (EXISTING)
                                                   HOT GAS
Figure 6-11. Molecular sieve system (Reference 6-22).
                       6-30

-------

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                              6-32

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       The process has been successful in meeting emission standards.  The principal criticisms
have been high capital and energy costs, and the problems of coupling a cyclic system to a continu-
ous acid plant operation.  Furthermore, molecular sieves are not considered as state-of-the-art
technology.
6.1.4  Costs
       The most recent cost and energy utilization comparisons of the various abatement processes
are given in Tables 6-4 and 6-5 (Reference 6-6).  Direct comparison of these data is rather difficult
since not all the side effects, such as changes in plant yield, and the degree of abatement, are
described.
Chilled Absorption
       The cost figures in Table'6-4 for the CDL/VITOK process are in agreement with data provided by
Reference 6-25.   According to Reference 6-10, the bottom line costs for the chilled absorption process
used by the TVA is $2.09/Mg ($1.90/ton) of acid, which includes $0.14/Mg ($0.13/ton) credit for additional
product, 8 kWh and 85 kg steam per Mg acid (170 Ib/ton).  This cost is higher than the $1.74 Mg ($1.58/ton)
given in Table 6-4 and does not include the reduction in capacity caused by the reduction in the nitric
acid concentration.
Extended Absorption
        The Grande Paroisse process is capital  intensive; therefore,  costs may be dominated by the
assumptions made to  calculate return on investment and depreciation.   The figures in Table 6-4 reflect
a 20 percent return  on capital.   The Grande Paroisse literature shows cost of $0.98 to $1.13 per Mg
($0.89 to $1.03/ton)  but does not consider a return on investment cost.
       Even with high capital cost and unfavorable cost of capital, extended absorption is competi-
tive with other processes.  It has low maintenance costs and low energy requirements.
Wet Chemical Scrubbing
       The economics and energy use of two wet scrubbing processes, MASAR, urea scrubbing, and Good-
pasture, ammonia scrubbing, are given in Tables 6-4 and 6-5.  Costs for the Norsk Hydro process would
be similar if applied to a new plant.  Capital  cost for the Goodpasture process are estimated as
$425,000 for a 270 Mg/d (300 tons/day) plant (Reference 6-26).  No costs estimates are available for
potassium permanganate and caustic scrubbing since they are not in general use.
                                                6-33

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                                                            6-34

-------
                TABLE 6-5.  ANNUAL ENERGY REQUIREMENTS (TJ) FOR NOX ABATEMENT SYSTEMS
                     FOR A 270 Mg/d NITRIC ACID PLANT (Reference 6-6 and 6-26)*

Steam (Credit)
Electrical
Natural Gas
Oil
Basic Nitric
Acid Plant
(75.2)
—
172.0
-
96.8
Catalyst
Reduction
(136.18)
11.56
245.12
-
108.94
Molecular
Sieve
2.15
29.08
-
17.20
48.43
Grande
Paroisse
-
8.13
-
-
8.13
CDL/
Vitok
6.14
23.94
-
-
30.08
Masar
11.27
1.80-
-
-
13.07
Goodpasture
-
1.38
-
-
1.38
  This table is given in Appendix A in English units.
                    TABLE 6-6.  BASIS FOR TABLES 6-4 AND 6-5 (Reference 6-6)'

                                (Plant Capacity 270 Mg/day and 92 Gg/yr)
                                (March 1975 Dollars, ENR Index = 2.126)
             1.    Operating Labor
             2.    Maintenance Labor
             3.    Overhead

             4.    Cooling Water
             5.    Boiler Feedwater
             6.    Natural Gas
             7.    Oil
             8.    Depreciation
             9.    Return on Investment
            10.    Taxes and Insurance
            11.    Nitric Acid
            12.    Urea
            13.    Ammonium Nitrate
            14.    1  kWh = 11.07 MJ
            15.    Electricity
            16.    Ammonia
(3 $6.1/hr
(3 $7.0/hr
(3 100% of labor  (including fringe
  benefits  and supervision)
(3 $0.008/1000 1
(3 $0.20/1000 1
(3 $1.90/GJ
(3 $1.90/GJ
@ 11 yr straight line
@ 20% of capital cost
(3  2% of capital cost
(3 $ 99/Mg
(3 $176/Mg
(3 $110/Mg

(3 $0.02/kWh
(3 $173/Mg
JThis  table  is  given  in  Appendix  A  in  English  units.
                                               6-35

-------
       Capital and operating costs for these processes are very low and are aided by credit for the
byproducts  (ammonium nitrate).  In the Goodpasture process approximately 75 percent of the ammonia
is reclaimed as ammonium nitrate.
Catalytic Reduction
       The cost and energy data given in Tables 6-4 and 6-5 are for a natural gas fired nonselective
catalytic reduction unit.  The process is considerably more expensive than the other processes.  Not
only does a catalytic combustor have a high capital cost, but fuel costs are large (and will probably
increase).
       Costs for selective catalytic reduction are not included in Table 6-4.  Capital costs are
estimated as $100,000 to $125,000 for a 270 Mg per day unit by Gulf (Reference 6-27).  Operating
and maintenance costs are expected to be low except possibly for catalyst replacement.  The major
operating expense is the cost of ammonia for reaction with NO .
Molecular Sieve
       Both capital and operating costs for the molecular sieve process are high.  Fuel for the
regeneration phase, high maintenance costs, and catalyst replacement are the primary contributors to the
operating costs.  Not included in the cost figures are any extra costs which may result from upsets or
process alterations in the nitric acid plant as a result of the cyclic operation of the abatement unit.
6.2    NITRIC ACID USES

       Important uses of nitric acid and the estimated quantities consumed in each are listed in
Table 6-7.  Approximately 65 percent of the nitric acid produced in the United States is consumed
in making ammonium nitrate, of which approximately 80 percent is used for fertilizer manufacturing.
Adipic acid manufacture, the second largest use,  consumes only about 7 percent.   Other uses include
metal pickling and etching, nitrations and oxidations of organic compounds, and  production of
metallic nitrates.

6.2.1  Ammonium Nitrate Manufacture
6.2.1.1  Process Description
       Ammonium nitrate is produced by the direct neutralization of nitric acids with ammonia:
                              NH3  +  HN03  -  NH4N03                                       (6-10)
                                                6-36

-------
TABLE 6-7.  ANNUAL NITRIC ACID CONSUMPTION IN THE UNITED STATES,  1974
            (Reference 6-3 and 6-6)
Product
Ammonium Nitrate
Adi pic Acid
Nitrobenzene
Potassium Nitrate
Miscellaneous Fertilizers
Military, other than
NH4N03
Isocynates
Steel Pickling
Other
Total Nitric Acid
Production
Quantity of HNO, used in manufacture
Gg
4830
520
74
37
371
258
in
37
1193
7431
103 tons
5324
573
82
40
409
286
122
41
1315
8192
                               6-37

-------
About 735 kg (1600 Ib) of nitric acid (100 percent equivalent)  and 190 to 205 kg (420 to 450 Ib)  of
anhydrous ammonia are required to make 909 kg (1  ton)  of ammonium nitrate.   In actual practice,  100
percent nitric acid is not used, and typical  feed acid contains 55 to 60 percent HN03-   The product
is an aqueous solution of ammonium nitrate, which may  be used as liquid fertilizer or converted
into a solid product.  The heat of reaction is usually used to  evaporate part of the water, giving
typically a solution of 83 to 86 percent ammonium nitrate.   Further evaporation to a solid may be
accomplished in a falling-film evaporator (Reference 6-28),  in a disk-spraying plant (Reference
6-29), or by evaporation to dryness in a raked shallow open pan (graining).   The graining process
is no longer used due to hazardous conditions.
       A majority of the solid ammonium nitrate produced in the United States is formed by "prilling",
a process in which molten ammonium nitrate flows  in droplets from the top of a tower countercurrent
to a rising stream of air, which cools and solidifies  the melt to produce pellets or prills (Refer-
ence 6-3).
6.2.1.2  Emissions
       No significant amount of NOX is produced in this process; the most likely source of nitric
acid emissions would be the neutralizer.  The vapor pressure of ammonia, however, is much higher
than the vapor pressure of nitric acid, and the release of nitric acid fumes or NO  is believed  to
be negligible (Reference 6-30), especially since  a slight excess of NH^ is used to reduce product
decomposition.

6.2.2  Organic Oxidations
6.2.2.1  Process Description
       Nitric acid is used as an oxidizing agent  in the commercial preparation of adipic acid,
terephthalic acid, and other organic compounds containing oxygen.  The effective reagent is probably
NOp, which has very strong oxidizing power.
       Adipic acid (COOH-(CH2).-COOH) is a di-basic acid used in the manufacture of synthetic fibers.
It is an odorless white crystalline powder which  is manufactured by the catalytic oxidation of cyclo-
hexane, with cyclohexanone and cyclohexanol as intermediates.  About 618 Gg (681,000 tons) of adipic
acid were manufactured in 1975  (Reference 6-31).   Approximately 90 percent of adipic acid is consumed
in the manufacture of nylon 6/6.
       In the United States, adipic acid is made  in a  two-step  operation.  The first step is the
catalytic oxidation of cyclohexane by air to a mixture of cyclohexanol and cyclohexanone.  In the
                                                 6-38

-------
second step, adipic acid is made by the catalytic oxidation of the cyclohexanol/cyclohexanone mix-
ture using 45 to 55 percent nitric acid.   The product is purified by crystallization (Reference 6-32).
The whole operation is continuous.  The chemistry of the reactions in the two steps  is:
                        cyclohexanone + nitric acid •*•  adipic acid  +  NO   +  HLO         (6-11)
                        cyclohexanol  + nitric acid -»•  adipic acid  +  N02  +  H20         (6-12)
       The main nitrogen compounds formed in the above reactions are NO, NO,,, and N,,0.  The dissolved
oxides are stripped from the adipic acid/nitric acid solution with air and steam.   The NO and NOp
are recovered by absorption in nitric acid.   The off-gas from the NOX absorber is  the major contri-
butor to NOX emissions from the adipic acid  manufacturing process.
       Nitric acid is used for the oxidation of other organic compounds in addition to the adipic
acid, but none approaches the adipic acid product volume.
       Terephthalic acid is an intermediate  in the production of polyethylene terephthalate,  which
is used in polyester, films, and other miscellaneous products.  Terephthalic acid  can be produced
in various ways, one of which is by the oxidation of paraxylene by nitric acid (Reference 6-33).
In 1970, the process was used for about a third of terephthalic acid production and accounted for
approximately 20 percent of NO  emissions from nitration processes.  Since 1975, however, the use
of nitric acid as a feedstock in the production of terephthalic acid has been discontinued (Reference
6-34).  No NO  is now generated in terephthalic acid plants.
6.2.2.2  Emissions
       The off-gases leaving the adipic acid reactor after nitric acid oxidation of organic materi-
als may contain as much as 30 percent NO  before processing for acid recovery (Reference 6-35).
One of the principal compounds of the off gas, N20, is not counted as NOX, since it is not oxidized
to NO  in the atmosphere and is considered harmless.  The seven adipic acid manufacturing plants  in
the United States generated about 14.5 Gg (16,100 tons) of NOX in 1975 (Reference  6-31)  from a total
acid  production of  618  Gg  (681,000  tons).   This  gives  an  average  emission  factor  of 23.7 kg  N02/Mg
(47.4 Ib N02/ton) compared  to the nominal value  6  kg N02/Mg  (12.0 Ib N02/ton)  specified  by AP-42
(Reference 6-36).

6.2.2.3  Control Techniques
       In commercial operations, economy requires the recovery of NO  as nitric acid.  It is  recov-
ered  by mixing the off-gas with air and sending the stream to an absorbing tower,  where nitric acid
is recovered as the stream descends and unrecoverable N20 and nitrogen pass off overhead.
                                               6-39

-------
        If the resulting emission rates are too high,  further reduction could  be attempted  by  stan-
 dard techniques such as extended absorption or wet chemical  scrubbing.  These techniques are
 described in Section 6.1.3.   A potential,  long-range  control  for eliminating  NO  from  organic oxi-
 dation processing is the replacement of nitric acid as  an  oxidant by  catalytic processes using air
 oxygen.   The laboratory catalytic oxidation of cyclohexanol  and  cyclohexanone by air to  adipic acid
 has also been reported, but  no commercial  process  is  known (Reference 6-37).
 6.2.2.4    Costs
        Economy requires that nitric  acid be recovered from reactor off-gas  in large-scale  organic
 oxidations using  nitric acid as  the  oxidizing  agent.  For  example, the incentive for acid  recovery
 for a  270 Mg/d (300  tons/day)  adipic  acid  plant would be about $2.48  x 106  per year.   This figure is
 based  on  recovering  0.3 kg of  HN03 per kg  of adipic acid at a nitric  acid cost of $8.6 per 100 kg (Ref-
 erence 6-38).   The optimum economic  recovery level  depends upon  economic factors at each installation.
 6.2.3    Organic Nitrations
 6.2.3.1    Process Description
       Nitration  is  the treating  of  organic compounds with nitric  acid  (or  N02)  to produce nitro
 compounds  or  nitrates.   The  following  equations illustrate the two most common types of  reaction:
                           RH + HON02 -> RN02 + H20                                (6-13)
                           ROM +  HON02 + RON02 + H20                              (6-14)
 Examples of products of  the  first reaction  (C-nitration) are compounds such as nitrobenzene, nitro-
 toluenes, and  nitromethane.  Nitroglycerin  (or glycerin trinitrate) and nitrocellulose are examples
 of  compounds produced by the second reaction (0-nitration).
       Nitrating agents  used commercially include nitric acid, mixed nitric and sulfuric acids
 (mixed acids), and N02-  Mixed nitric and sulfuric acid is  most frequently used.  The sulfuric acid
 functions to promote formation of N02 ions and to absorb the water produced in the reaction.
       Nitrations are carried out in either batch or continuous processes.   The trend is  toward
 continuous processes, since control is more easily maintained, equipment is smaller,  system holdup
 is smaller, and hazards are reduced.   A multiplicity of specialty products  such as dyes and drugs,
which are produced in small  volumes,  will  continue, however,  to be manufactured by small  batch
nitrations.
                                               6-40

-------
       Batch nitration reactors are usually covered vessels provided with stirring facilities and
cooling coils or jackets.  The reactor bottom is sloped, and product is-»withdrawn from the lowest
point.  When products are potentially explosive, a large tank containing water (drowning tank) is
provided so that the reactor contents can be discharged promptly and "drowned" in case of abnormal
conditions.
       When the reaction is completed, the reactor contents are transferred to a separator, where
the product is separated from the spent acid.  The product is washed, neutralized, and purified;
spent acids are processed for recovery.  Figure 6-12 illustrates a batch nitration process for
manufacturing nitroglycerin (Reference 6-39).
       Continuous nitration for nitroglycerin is carried out in many types of equipment.  Two widely
employed processes are the Schmid-Meissner process (illustrated in Figure 6-13) and the Biazzi pro-
cess (illustrated in Figure 6-14).  Both processes provide for continuous reaction, separation,
water washing, neutralization, and purification.  The Biazzi process makes greater use of impellers
for contacting than the Schmid-Meissner, which uses compressed air to provide agitation during
washing and neutralizing.  Both types of equipment can be used for nitrating in general.
       When mixed acid is used, the spent acid is recovered in a system similar to that shown in
Figure 6-15.  The mixed acid enters the top of the denitrating tower.  Superheated steam is admitted
at the bottom to drive off the spent nitric acid and NOX overhead.  The gases are passed through a
condenser to liquefy nitric acid,  which is withdrawn to storage; the uncondensed gases are then
sent to an absorption tower.  Weak sulfuric acid is withdrawn from the bottom of the denitrator
tower and concentrated or disposed of by some convenient arrangement.
       When nitric acid alone is used for nitration, the weak spent acid is normally recovered by
sending it to an absorption tower, where it replaces some of the water normally fed as absorbent.
       Nitrobenzene and dinitrotoluenes are produced in large volumes as chemical  intermediates.
Explosives such as TNT, nitroglycerin, and nitrocellulose are produced in significant but lesser
volumes.
       Nitrobenzene is manufactured in both continuous and batch nitration plants.   Mixed acids
containing 53 to 60 percent H2S04, 32 to 39 percent HN03, and 8 percent water are  used in batch
operations, which may process 3.785 m3  (1000 gallons)  to 5.678 m3  (1500 gallons)  of benzene in 2 to
4 hours.   Continuous plants, as typified by the  Biazzi  units (Figure 6-14) also use mixed acids.
       The major use of nitrobenzene is in the manufacture of aniline.   It is also  used as  a  solvent.
Nitrobenzene production in 1970 was an estimated 188 Gg (207,500 tons).   Nitric acid requirements
                                                6-41

-------
                                               r
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         Figure 6-12. Batch process for the manufacture of nitroglycerin (NG) (Reference 6-39).
                                            6-42

-------
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                                          6-43

-------
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              Figure 6-14.  Biazzi continuous-nitration plant (Reference 6-39).
                                   6-44

-------
AIR
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                 Figure 6-15.  Recovery of spent acid (Reference 6-39).
                                    6-45

-------
are approximately 0.54 kg per kg of nitrobenzene (Reference 6-39).  On this basis, nitric acid used
in nitrobenzene synthesis was estimated at 126 Gg (139,000 tons) for 1970.
       Dinitrotoluene is manufactured in two stages in both continuous and batch units.  The first
stage  is the nitration of toluene to mononitrotoluene, which is nitrated to dinitrotoluene in the
second stage.  For making mononitrotoluene in the batch process, mixed acid consisting of 28 to 32
percent HNOg, 52 to 56 percent H2S04> and 12 to 20 percent water is used in equipment sized to
handle up to 11.4 m3 (3000 gallons).  Operating temperature ranges from 298K (77F) to 313K (104F).
Mononitrotoluene yields of 96 percent are typical (Reference 6-40).  The second step, the production
of dinitrotoluene, is carried out separately because it requires more severe conditions.
       Dinitrotoluene is made from mononitrotoluene using stronger mixed acid containing 28 to 32
percent HN03, 60 to 64 percent H,,S04, and 5 to 8 percent water.  Temperatures are increased to 363K
(194F) after all the acid has been added.  Dinitrotoluene yields are about 96 percent of theoretical
(Reference 6-41).
       The principal use of dinitrotoluene is as intermediate in making toluene diisocyanate (TDI)
for use in polyurethane plastics.  It is usually supplied as mixtures of the 2,4 and 2,6 isomers.
6.2.3.2   Emissions
       Relatively large NOX emissions may originate in nitration reactors and in the denitration of
the spent acid.   NOX is also released in auxiliary equipment such as nitric acid concentrators,
nitric acid plants, and nitric acid storage tanks.
       Nitration reactions per se do not generate NO  emissions.  NOV is formed in side reactions
                                                    A               X
involving the oxidation of organic materials.   Relatively  little oxidation and NO  formation occur
when easily nitratable compounds, such as toluene,  are processed.   Much more severe conditions  are
required in processing compounds that are difficult to nitrate, such as dinitrotoluene;  more  oxida-
tion takes place and,  thus, more NO  is formed.
       Limtied data are available on actual  NOX  emissions from nitrations.   For continuous  nitra-
tions, one company has  reported  emissions of 0.06 to 0.12 kg N02 per Mg of nitric  acid  (0.12  to 0.24
Ib/ton), with a  mean of 0.09 kg  N02/Mg (0.18 Ib/ton) at a single location (Reference 6-40).   At the
same location, emissions  averaging 7 kg of N02 per  Mg of acid were reported in  manufacturing  specialty
products in small  batch-type operations.   According  to Reference 6-42,  0.25 kg  of  N02 per Mg  of nitric
acid (0.5 Ib/ton)  are  generated  in the production of nitrobenzene.   In  the manufacture  of dinitrotol-
uence, 0.135 kg  of N02  is  estimated to be generated  for every Mg of nitric acid used (0.27  Ib/ton).
                                               6-46

-------
       Using the Reference 6-42 emission factors as a lower limit, and 7 kg NOX per Mg HNO-, (14 Ib/ton),
 (Reference 6-40) as upper limits for nitrations, the NOV emissions in 1970 would have the range indi-
                                                       x                  •»
 cated  in Table 6-8.  Even using the upper limit, NO  emissions from nitrobenzene and dinitrotoluene
 synthesis are relatively small but may present local nuisance problems.  Since the upper limit
 represents specialty batch operations on a small scale, the emissions are probably much higher than
 would  be encountered in large volume production of these products in either batch or continuous
 equipment.
 6.2.3.3   Control Techniques
       In large batch or continuous nitrations, operations are carried out in closed reactors.
 Fumes  are conducted from the reactor, air is added, and the mixture enters an absorption tower for
 recovery of nitric acid.  If too much N02 remains in the residual gas from the absorber, it may be
 further reduced by techniques such as wet chemical scrubbing.  Details of the control techniques
 are discussed in Section 6.1.3.
       Noncondensable gas from acid denitration is treated in the same manner as reactor gas.   A
 common absorber is sometimes employed.
       Small batch nitrators used in manufacturing specialties such as drugs and dyes are small-
 volume, high-intensity NOX emitters.  In one plant, reaction times ranged from 3 to 12 hours,  depend-
 ing on the product made.  From 3 to 850 batches of each product were made each year.  Emissions
 ranged from 0.7 to 130 kg of N0x per Mg of nitric acid (0.14 to 260 Ib/ton) with a median of 21 kg per
 Mg of  nitric acid (21 Ib/ton).  The median emission was 7 kg per Mg (14 Ib/ton) when one product was
 excluded from the calculations.  The emissions, which are vented in individual stacks, are brown in
 color  for a few hours per batch.
       Caustic scrubbing and NO  incineration are regarded as the most plausible controls for
                               A
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impurities in the gas.   Neither control  is considered highly efficient in this application.
       The intermittent character of emissions makes them difficult to control and contributes to
very high pollution abatement costs per ton of nitric acid consumed.   According to DuPont,  operating
costs for such equipment would render approximately half of the small  batch nitrations so unecono-
mical that the manufacture of these products would be terminated (Reference 6-40).   Large batches
may be suitable for conversion to continuous operating,  but small  batches are not.
                                                6-47

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6.2.3.4   Costs
       Fume incinerator investments are quoted at $10,000 to $20,000 by one source (Reference 6-43),
Another suggests that investments of $75,000 to $150,000 are necessary for flame abatement facili-
ties for existing small batch nitrators and $75,000 to $250,000 for existing large nitrators.
Annual operating costs were estimated at $25,000 to $85,000 per product for small batch nitrators
and $25,000 to $40,000 for continuous nitrators (Reference 6-40).
6.2.4   Explosives:  Manufacture and Use
6.2.4.1   Process Description
       An explosive is a material that, under the influence of thermal or mechanical  shock, decom-
poses rapidly and spontaneously with the evolution of large amounts of heat and gas.   Explosives
fall into two major categories:  high (industrial) explosives and low explosives.
       Industrial explosives in the United States consist of over 80 percent by weight of ammonium
nitrate and some 10 percent of nitro organic compounds.  During 1975, an estimated 1.4 Tg (3.1  x
109 pounds) of industrial explosives were manufactured, which is about 13 percent higher than the
1974 productions (Reference 6-44).  High explosives are less sensitive to mechanical  or thermal
shock, but explode with great violence when set off by an initiating explosive (Reference 6-45).
Low explosives, such as nitrocellulose, undergo relatively slow autocombustion when set off and
evolve large volumes of gas in a definite and controllable manner.
       Production and consumption data for military explosives are classified.   Some  of the more
important ingredients in military explosives are known, however:  trinitrotoluene (TNT), penter-
ythritol  tetranitrate (PETN), cyclotrimethylene-tri-nitramine (RDX), and trinitrophenyl methyl -
nitramine (Tetryl).   Nitration is an essential  step in the manufacture of each of these.
       PETN is most commonly used in conjunction with TNT in the form of pentolites,  made by incor-
porating  PETN into molten TNT.  RDX is used in  admixture with TNT, or compounded with mineral jelly
to form a useful  plastic explosive.   Tetryl is  most often used as a primer for other  less sensitive
explosives.
       TNT (symmetrical  trinitrotoluene) may be prepared by either a continuous process  or a batch,
three-stage nitration process using toluene, nitric acid, and sulfuric acid as  raw materials.  In
the batch process, a mixture of oleum (fuming sulfuric acid) and nitric acid that has been concen-
trated to a 97 percent solution is used as the  nitrating agent.   The overall  reaction may be
expressed as:                                  ru
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                                              NO
                                                2
                                               6-49

-------
       Spent acid from the nitration vessels is fortified with makeup 60 percent nitric acid before
entering the next nitrator.  Fumes from the nitration vessels are collected and removed from the
exhaust by an oxidation-absorption system.  Spent acid from the primary nitrator is sent to the acid
recovery system in which the sulfuric and nitric acid are separated.  The nitric acid is recovered
as a 60 percent solution, which is used for refortification of spent acid from the second and third
nitrators.  Sulfuric acid is concentrated in a drum concentrator by boiling water out of the dilute
acid.  The product from the third nitration vessel is sent to the wash house at which point asym-
metrical isomers and incompletely nitrated compounds are removed by washing with a solution of
sodium sulfite and sodium hydrogen sulfite (Sellite).  The wash waste (commonly called red water)
from the purification process is discharged directly as a liquid waste stream, is collected and sold,
or is concentrated to a slurry and incinerated in rotary kilns.  The purified TNT is solidified,
granulated, and moved to the packing house for shipment or storage.  A schematic diagram of TNT pro-
duction by the batch process is shown in Figure 6-16.
       Nitrocellulose is prepared by the batch-type "mechanical dipper" process.  Cellulose, in the
form of cotton linters, or specially prepared wood pulp, is purified, bleached, dried, and sent to
a reactor (niter pot) containing a mixture of concentrated nitric acid and a dehydrating agent such
as sulfuric acid,  phosphoric acid, or magnesium nitrate.  The overall reaction may be expressed as:
                 C6H?02(OH)3 + 3HON02 + H2S04 -» CgH^ONO^ + 3 H20 + H2$04           (6-16)
When nitration is  complete, the reaction mixtures are centrifuged to remove most of the spent acid.
The spent acid is  fortified and reused or otherwise disposed.  The centrifuged nitrocellulose under-
goes a series of water washings and boiling treatments for purification of the final  product.
6.2.4.2   Emissions
       The major emissions from the manufacture of explosives are nitrogen oxides  and nitric acid
mists.   Emissions  of nitrated organic compounds may also occur from many of the TNT process  units.
In the manufacture of TNT, vents from the fume recovery system, and nitric acid concentrators  are
the principal  sources of emissions.   Emissions may also result from the production  of Sellite
solution and the incineration of "red water".   Many plants now sell  the red water  to  the paper
industry where it  is of economic importance.
       Principal  sources of emissions from nitrocellulose manufacture are  from the  reactor pots  and
centrifuges, spent acid concentrators,  and boiling tubs used  for purification.
       The most important factor affecting emissions  from explosives  manufacture is the  type and
efficiency of the  manufacturing process.   The efficiency of the acid  and fume  recovery systems for
                                               6-50

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 TNT manufacture will directly affect the atmospheric emissions.  In addition, the degree to which
 acids are exposed to the atmosphere during the manufacturing process affects the NO  emissions.   For
 nitrocellulose production, emissions are influenced by the nitrogen content and the desired quality
 of the final product.  Operating conditions will  also affect emissions.   Both TNT and nitrocellulose
 are produced in batch processes.  Consequently, the processes may never  reach steady state and emis-
 sion concentrations may vary considerably with time.   Such fluctuations  in emissions will  influence
 the efficiency of control  methods.   Table 6-9 presents the emission factors for the manufacture  of
 explosives and the effects of various control devices upon emissions (Reference 6-45).   Although the
 manufacture of explosives  is a very small  source  of NOX emissions nationwide, explosions could be an
 intense source in confined underground spaces.  Precautions should be taken to avoid chronic exposure.
 6.2.4.3   Controls
        Explosives manufactured by  the commercial  industry  use ammonium nitrate extensively as  the
 base material.   The ammonium nitrate production process is reviewed in Section 6.2.1.  Nearly  half
 the plants use the catalytic reduction technique  for  control  of NO  emissions.
        The military explosives which are produced  in  large amounts  include  nitroglycerin,  nitrocellu-
 lose, TNT,  and  RDX.   The molecular  sieve abatement  system  is  used  at  Holston  Army Ammunition Plant
 in  Kingsport, Tennessee.   Another Army Ammunition Plant at Radford, Virginia,  is constructing  two
 molecular  sieve  units to treat vent  gas streams from  their nitrocellulose plant.  The description
 of  the  molecular  sieve control  technique is included  in Section 6.1.3.5.
 6.2.4.4    Costs
        Costs for  controlling NOX from explosives manufacture  by tail gas  treatment process were
 covered in Section 6.1.4.

 6.2.5    Fertilizer Manufacture
       Sulfuric and phosphoric acids are the principal acids used, in the United States,  in acidu-
 lating phosphate rock.  A few manufacturers produce "nitric phosphate" fertilizers by acidulating
 phosphate rock with nitric  acid to form phosphoric acid and calcium nitrate.  In subsequent steps,
 ammonia is added with either carbon dioxide or sulfuric or  phosphoric acid,  and "nitric  phosphates"
 are formed.  Dibasic calcium phosphate and ammonium nitrate are the useful  compounds produced
 (Reference 6-48).
       U.S. Department of Agriculture statistics do not segregate  nitric  phosphate  fertilizers  made
by acidulation of phosphoric rock;  but private sources indicate that nitric  phosphate fertilizer
                                                6-52

-------
             TABLE  6-9.   EMISSION  FACTORS  FOR MANUFACTURE
                         OF EXPLOSIVES  (REFERENCE  6-45)%
Type of process
TNT - batch process
Nitration reactors
Fume recovery
Acid recovery
Nitric acid concentrators
Red water incinerator
Uncontrolled0
Wet scrubber
Sellite exhaust
TNT — continuous process6
Nitration reactors
Fume recovery
Acid recovery
Red water incinerator
Nitrocellulose6
Nitration reactors
Nitric acid concentrator
Nitrogen oxides3
(N02)
kg/Mg


12.5(3-19)
27.5(0.5-68)
18.5(8-36)

13(0.75-50)
2.5
—


4(3.35-5)
1.5(0.5-2.25)
3.5(3-4.2)

7(1.85-17)
7(5-9)
Ib/ton


25(6-38)
55(1-136)
37(16-72)

26(1.5-101)
5
—


8(6.7-10)
3(1-4.5)
7(6.1-8.4)

14(3.7-34)
14(10-18)
 For some  processes considerable  variations in emissions have been reported
 The average of  the values  reported  is shown first, with the ranges given
 in  parentheses.  Where only one  number is given, only one source test was
 available.

Reference 6-46
^
'Use low end of  range  for modern, efficient units and high end of range for
 older, less efficient units.

 Apparent  reductions in NOX and particulate after control may not be sig-
 nificant  because these values are based on only one test result.
Reference 6-47

 For product with low  nitrogen content (12 percent), use high end of range.
 For products with higher nitrogen content, use lower end of range.
                                 6-53

-------
made  in  this manner was estimated at 450 Gg (500,000 tons) in 1967, and nitric acid consumptions
at  135 Gg  (150,000 tons)  (Reference 6-49).
       NO  emissions are  dependent on the quantity of carbonaceous material in the rock, since NO
         *                                                                                       x
is  formed as nitric acid  oxidizes the carbonaceous matter.  The use of calcined rock avoids the
production of NO  .
       Air pollution abatement by fertilizer manufacturers' efforts has centered on reducing particu-
lates and fluorides emissions, which are severe problems.  The water scrubbing used to.reduce these
pollutants would be expected to reduce NO  emissions to only a minor degree.  Although no measure-
ments of NO  emissions are available, brown plumes are said to occur.
           X
       One company has found that the addition of urea to the acidulation mixture reduces NO  emis-
sions and eliminates the  brown plume (Reference 6-49).  Urea, as discussed  in Section  6.1.3.3
reacts with nitric and nitrous acids to form N2-

6.2.6   Metals Pickling
       The principal use  of nitric acid in metals pickling is in treating stainless steel.   Mill
scales on stainless steels are hard and are difficult to remove.  Pickling procedures vary; some-
times a 10 percent sulfuric acid bath at 333K (140F) to 344K (160F) is followed by a bath at 328K
(130F) to 339K (150F) with 10 percent nitric acid and 4 percent hydrofluoric acid.  The first bath
loosens the scale, and the second removes it.   A continuous system for stainless steel  strip con-
sists of two tanks containing 15 percent hydrochloric acid, followed by a tank containing 4 percent
hydrofluoric and 10 percent nitric acid at 339K (150F) to 350K (170F).  One effective method is the
use of molten salts of sodium hydroxide to which is added some agent such as sodium hydride.  This
may be followed by a dilute nitric acid wash (Reference 6-50).
       No measurements were found of emission  rates from nitric acid pickling of stainless  steel.
Treating equipment should be properly hooded and ventilated and the fumes scrubbed to protect
workers.   Urea would probably control  the NO  emissions.
       Nitric acid is also used in the chemical  milling of copper or iron from metals that  are not
chemically attacked by nitric acid,  and for bright-dipping copper.   In the latter operation, a cold
solution of nitric and sulfuric acid has been  customarily used.   It has been reported that  copper
can be bright-dipped on cold nitric  acid alone when urea  is added.   A highly acceptable finish is
obtained, and NOX fumes are eliminated.
                                               6-54

-------
       Sulfuric acid should not be used with the nitric acid-urea mixture since nitrourea,  an  explo-
sive, can form.  Not more than 62 ml of urea per liter should be added,  and satisfactory operation
can be obtained with only 15 ml per liter.
       In chemical milling, the addition of 46 to 62 ml of urea per liter of 40 percent nitric acid
will reduce NC^ emissions from 8,000 ppm to levels below 10 ppm, provided a bubble  disperser is
used (Reference 6-51).
       A small, but intense, source of NOX occurs in the manufacture of  tungsten filaments  for
lightbulbs.  Tungsten filaments are wound on molybdenum cores, and after heat-treating, the cores
are dissolved in nitric acid.
       Reference 6-43 describes air pollution equipment for reducing the dense N02  fumes given off
periodically when trays of the filaments are dissolved.  The fumes pass  over a charcoal adsorber
bed, which adsorbs NOX as fumes are generated and desorbs when no fumes  are being generated.   This
smooths out peaks and valleys'in NOX content in off-gases, which are then heated and combined  with
carbon monoxide and hydrogen from a rich combustion flame.  The mixture  is then passed  through a
bed of noble metal catalyst.  A colorless gas is released from the equipment.
                                     REFERENCES FOR SECTION 6
6-1    Manney, E.H. and S. Skopp, "Potential Control of Nitrogen Oxide Emissions from Stationary
       Sources," Presented at 62nd Annual Meeting of the Air Pollution Control Association,
       New York.  June 22-26, 1969.
6-2    Freithe, W. and M. W. Packbier, "Nitric Acid:  Recent Developments in the Energy and Environ-
       mental Area," presented at AICHE Symposium, Denver, Colorado, August 28, 1977.
6-3    Lowenheim, F.A.  and M.K. Morgan, ed., Faith, Keyes. and Clark's Industrial Chemicals.  4th
       edition.  New York, Wiley Interscience Publication, 1975.
6-4    "Strong Nitric Acid Process Features Low Utility Cost," Chemical  Engineering, December  8,
       1975, p. 98-99.
6-5    Personal communication.  Mr. Dave Kirkbe, Davy Powergas, Houston, Texas, November 1977.
6-6    "Environmental Considerations of Selected Energy Conserving Manufacturing Process Options,
       Volume XV, Fertilizer Industry Report," EPA-600/7-76-0340, December  1976.
6-7    "Compilation of Air Pollution Emission Factors (Second Edition)," Publication No. AP-42,
       Environmental Protection Agency, Research Triangle Park, North Carolina, April 1973.
6-8    Gerstle, R.W. and R.F. Peterson, "Atmospheric Emissions from Nitric Acid Manufacturing
       Processes," National Center for Air Pollution Control, Cincinnati, Ohio, PHS Publication
       Number 999-AP-27, 1966.
6-9    Mayland, B.J., "Application of the CDL/VITOK Nitrogen Oxide Abatement Process,"  Presented
       to Sulfur and Nitrogen Symposium, Salford, Lancashire, U.K.  April 1976.
6-10   Barber, J.C. and N.L. Faucett, "Control of Nitrogen Oxide Emissions from Nitric  Acid Plants,"
       Third Annual Air Pollution Control Conference, March 1973.
6-11   "NOX Abatement in Nitric Acid and Nitric Phosphate Plants," Nitrogen, No.  93,  Jan/Feb 1975.
6-12   "MASAR Process for Recovery of Nitrogen Oxides," Company brochure, MASAR,  Inc.
                                                 6-55

-------
6-13   Personal  communication,  Mr.  Feaser,  Plant  manager,  Illinois  Nitrogen  Plant, Marseilles, 111.
       November 1977.

6-14   Service,  W.J.,  R.T.  Schneider,  and  D.  Ethington,  "The  Goodpasture  Process for Chemical Abate-
       ment and Recovery of NO  ," Conference  on Gaseous  Sulfur  and  Nitrogen  Compound Emissions,
       Salford,  England, Aprilx1976.

6-15   Streight, H.R.L., "Reduction of Oxides of  Nitrogen  in  Vent Gases,"  Chem. Eng., Vol. 36, 1958.

6-16   Gillespie, G.R., A.A.  Boyum, and M.F.  Collins,  "Nitric Acid:   Catalytic  Purification of Tail
       Gas," Chemical  Engineering Progress, Vol.  68,  1972.,

6-17   Decker, L, "Incineration Technique  for Controlling  Nitrogen  Oxides  Emissions," Presented at
       the 60th Annual Meeting  of the  Air  Pollution Control Association,  Cleveland, Ohio, June 1967.

6-18   Andersen, H.C., W.J. Green,  and D.R. Steele, "Catalytic  Treatment  of  Nitric Acid Tail Gas,"
       Ind. Eng. Chem., 53:199-204, March  1961.

6-19   Anderson, G.C.  and W.J.  Green,  "Method of  Purifying Gases Containing  Oxygen and Oxides of
       Nitrogen (Englehard Industries, Inc.,  U.S.  Patent No.  2, 970,  034), Official Gazette U.S.
       Patent Office,  762(5):969, January  31, 1961.

6-20   Newman, D.J.  and L.A.  Klein, "Apparatus for Exothermic Catalytic Reactions," (Chemical Con-
       struction Corp., U.S.  Patent No. 3,  443, 910),  Official  Gazette U.S.  Patent Office, 862
       (2):514,  May 1969.

6-21   Andersen, H.C., P.L. Romeo,  and W.J. Green, "New  Family  of Catalysts  for Nitric Acid Tail
       Gases," Nitrogen 50:33-36, November-December 1967.

6-22   Rosenberg, H.S., "Molecular Sieve NO  Control  Process  in Nitric Acid  Plants," Environmental
       Protection Technology Series, EPA-600/2-76-015, January  1976.

6-23   Chehaske, J.I.  and J.S.  Greenberg,  "Molecular  Sieve Tests for  Control  of NO  Emissions from
       a Nitric Acid Plant,"  Volume 1, EPA-600/2-76-048a,  March 1971.             x

6-24   Rosenburg, H.S., "Molecular Sieve NO  Control  Process  in Nitric Acid  Plants," EPA-600/2-76-
       015, January 1976.                  x

6-25   Mayland,  B.J. , The CDL/VITOK Nitrogen Oxides  Abatement  Process,"  Chenoweth Development
       Laboratory, Louisville,  Ky.

6-26   Personal  communication,  Mr.  Don Ethington,  Goodpasture,  Inc.,  Brownfield, Texas, November 1977,
       and February, 1978,  and  D. F. Carey, EPA-IERL,  February  1978.

6-27   "New Unit for Nitric Plants Knocks  Out NOX," Chemical  Week,  July 28,  1976.

6-28   "Ammonium Nitrate," Hydrocarbon Process.   46:149, November  1967.

6-29   Miles, F.D., Nitric Acid - Manufacture and Uses,  London, Oxford University Press,  1961.

6-30   Private communication with Esso Research and Engineering Co.

6-31   Durocher, D.F., P.O. Spawn, and R.C. Galkiewicz,  "Screening  Study  to  Determine Need for
       Standards of Performance for New Adipic Acid Plants,"  draft  report GCA-TR-76-16-G  GCA Cor-
       poration, Bedford, Massachusetts, June 1976.

6-32   Goldbeck, M., Jr., and F.C.  Johnson, "Process  for Separating Adipic Acid Precursors," (E.I.
       DuPont de Nemours and Co., U.S. Patent No.  2,  703,  331). Official  Gazette U.S. Patent
       Office.  692(1):110, March 1, 1955.

6-33   Burrows, L.A., R.M. Cavanaugh,  and  W.M. Nagle, "Oxidation Process  for Preparations of
       Terephthalic Acid," (E.I. DuPont de Nemours and Co., U.S. Patent No.  2,  636, 99).  Official
       Gazette U.S. Patent Office.   669(4):1209,  April 28, 1953.
                                                6-56

-------
6-34   Durocher, D.F.  et^ ^1_.,  "Screening  Study  to  Determine  Needs  for  Standards of Performance for
       New Sources of  Dimethyl  Terephthalate  and Terephthalic Acid Manufacturing" Draft Final Report,
       GCA-TR-76-17-G.   Submitted  to  EPA/OAQPS  by  GCA  Corp., Bedford,  Massachusetts, June  1976.

6-35   Lindsay,  A.F.,  "Nitric  Acid Oxidation  Design  in the Manufacture of Adipic Acid from Cyclohex-
       anol  and  Cyclohexanone," Special Suppl.  to  Chem.  Eng. Sci.  3:78-93,  1954.

6-36   Compilation of  Air Pollutant Emission  Factors,  Environmental  Protection Agency, AP-42,
       February  1972.

6-37   "Process  for Oxidation  of Cyclohexane  and for the Production  of Adipic Acid (British  Patent
       No. 956,  779) and Production of Adipic Acid," (British Patent No. 956, 780).  Great Britain
       Office. J. No.  3918:814, March 19, 1964.

6-38   Oil,  Paint, and Drug Reptr. 195(6):l-48, April  21,  1969.

6-39   Crater, W. deC.  Nitration.   In:  Kirk-Othmer  Encyclopedia of  Chemical Technology, Standen,
       A.  (ed.).  Vol.  9.  New York,  Interscience  Publishers, 1952.

6-40   Private communication with  E.I.  DuPont de Nemours and Co.,  March 1969.

6-41   Urbanski, T., "Chemistry and Technology  of  Explosives," Jeczalikowa,  I. and S. Laverton,
       (Trs.). Vol.  I.   New York,  MacMillan Co., 1964.

6-42   Processes Research,  Inc., "Air Pollution from Nitration Processes,"  Cincinnati, Ohio.
       APTD-1071, 1972.

6-43   Decker, L., "Incineration Technique for  Controlling Nitrogen  Oxides  Emissions," Presented
       at the 60th Annual Meeting  of the  Air  Pollution Control Association,  Cleveland.  June 11-16,
       1967.

6-44   Nelson, T.P., and Pyle,  R.E.,  "Screening Study  to Determine the Need  for New Source Perfor-
       mance  Standards in the  Explosives  Manufacturing Industry,"  Draft Report, Radian Corporation,
       Austin, Texas,  July  1976.

6-45   EPA,  Compilation of Air Pollutant  Emission  Factors, AP-42,  Supplement No. 5, December 1975.

6-46   Air Pollution Engineering Source Sampling Surveys,  Radford  Army Ammunition Plant. U.S.
       Army Environment Hygiene Agency, Edgewood Arsenal,  Md.

6-47   Air Pollution Engineering Source Sampling Surveys,  Volunteer  Army Ammunition Plant  and Joliet
       Army Ammunition Plant.   U.S. Army  Environmental  Hygiene Agency, Edgewood Arsenal, Md.

6-48   McVickar, M.H.  et aj_.,  "Fertilizer Technology and Usage," Madison, Wisconsin, Soil  Science
       Society of America,  1963.

6-49   Consumption of  Commercial Fertilizers, U.S. Dept.  of  Agriculture.  Statistical Reporting
       Service.

6-50   McGannon, H.E.,  The  Making, Shaping and  Treating of Steel,  8th  ed. Pittsburgh, United States
       Steel  Co., 1964.

6-51   Kerns, B.A.,  "Chemical  Suppression of  Nitrogen  Oxides,"  Ind.  Eng. Chem. Process Design  Develop.
       Vol.  4,  pp. 263-265, 1965.
                                                6-57

-------

-------
                                             APPENDIX A

                                  SELECTED TABLES IN ENGLISH UNITS

       This appendix contains the English engineering unit version of most of the large tables pre-
sented 1n the text.   The tables are arranged sequentially 1n the order 1n which they appear in the
text and have the same table number except for the prefix "A".
                                                A-l

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    TABLE A2-13.  ANNUAL NOX EMISSIONS FROM COMMERCIAL BOILERS  (10s  tons)
Fuel
Coal
Oil
Gas
Total
Source
Battell e
1971
(Reference 2-18)
0.131
0.148
0.025
0.304
MSST
1972
(Reference 2-4)
0.029
0.212
0.120
0.361
GCA
1973
(Reference 2-15)
0.030
0.63
0.110
0.77
Current
1974
0.0543
0.5044
0.2241
0. 7828
TABLE A2-14.  ANNUAL NOX EMISSIONS FROM RESIDENTIAL SPACE HEATING (106 tons)
Fuel
Coal
Oil
Gas
Total

Battelle
1971
(Reference 2-18)
-
0.1682
0.1785
0.3467
Source
MSST
1972
(Reference 2-4)
-
0.254
0.212
0.466
GCA
1973
(Reference 2-15)
0.012
0.098
0.210
0.320
Current
1974
-
0.2021
0.2175
0.4196
                                   A-13

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           TABLE A2-16.  ANNUAL FUEL CONSUMPTION BY INTERNAL
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Fuel
on
Gas
Source
Shell
1971
(Reference 2-29)
477
1497
MSST
1972
(Reference 2-4)
519
1627
Current
1974
540
1617
TABLE A2-17.  ANNUAL NOX EMISSIONS FROM INTERNAL COMBUSTION ENGINES (106 tons)
Equipment
Reciprocating
Engines

Turbl nes

Fuel
011 and
Dual
Gas
on
Gas
Total
Source
Shell
1971
(Reference 2-29)
0.40
1.74
0.03
0.08
2.25
MSST
1972
(Reference 2-4)
0.316
1.871
0.119
0.172
2.48
Current
1974
0.44
2.22
0.12
0.14
2.92
                                 A-15

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TABLE A2-20.  SUMMARY OF ANNUAL EMISSIONS FOR
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Industry
Acid


Explosive
Total
Application
Sulfuric
Nitric
Adi pic


NO , 106 tons
^
0.012
0.140
0.016
0.056
0.224
  TABLE A2-21.  ESTIMATE OF ANNUAL NOX EMISSIONS
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Source
Solid waste disposal
Forest wildfires
Prescribed burning
Agriculture burning
Coal refuse fires
Structural fires
Misc. (welding, grain silos, etc.,
Total
NOY 103 tons
/\
165
152
33
14
58
7
50
479
                       A-18

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                                                 A-22

-------
         TABLE A2-26.  ANNUAL NATIONWIDE NOY EMISSIONS PROJECTED TO 2000
                       (Reference 2-37)    A
Source Category
Stationary Fuel Combustion

Electric Generation

Industrial
Commercial -Institutional
Residential
Industrial Process Losses*5
Solid Waste Disposal
Miscellaneous
TOTAL

NOX Emissions (106 tons)
1972
12.27

5.94

5.39
0.65
0.29
0.70
0.18
0.59
13.74

1980
15.96
(17.12)a
8.16
(9.32)
6.73
0.76
0.31
0.95
0.22
0.74
17.87
(19.03)
1985
16.82
(21.43)
8.20
(12.81)
7.46
0.84
0.32
1.14
0.25
0.87
19.08
(23.69)
1990
18.46
(27.14)
8.88
(17.56)
8.31
0.93
0.34
1.38
0.28
1.02
21.14
(29.82)
2000
21.74
(44.46)
10.24
(32.96)
10.01
1.11
0.38
1.85
0.34
1.32
25.25
(47.97)
N0x emissions for no new nuclear power plants after 1975 are given in parentheses.

Industrial  process losses corrected for 1972 reporting error in Reference 2-36.
                                        A-23

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                   TABLE A2-27.  ESTIMATED FUTURE NSPS CONTROLS
                                 (Reference 2-38)
NOX Source
Utility and Large
Industrial Boilers
(<73 MW)a Coal



Oil
Gas
Large Packaged Boilers
(<7.3 MW)a Coal


Oil
Gas
Small Packaged Boilers
(>7.3 MW)a Coal
Oil
Gas
Small Commercial and
Residential Units
Oil
Gas
Gas Turbines

1C Engines Dist Oil

Nat Gas

Gasoline

Process Combustion

Date Implemented
1971
1977
1981
1985
1988
1971
1971
1979
1985
1990
1979
1979
1979
1979
1979

1983
1983
1977
1983
1972
1985
1979
1985
1979
1985
1981
1990
Standard (lb/106 Btu)
0.7
0.6
0.5
0.4
0.3
0.3
0.2
0.6
0.5
0.4
0.2
0.3
50% reduction
0.2
0.3

0.07
0.04
0.3
0.2
3.2
2.4
2.9
2.1
2.2
1.6
20% reduction
40/K reduction
aThermal Input
                                           A-24

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                         A-27

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                   TABLE A6-4.   CAPITAL  AND  OPERATING  COSTS  FOR  DIFFERENT NOx ABATEMENT SYS-
                                TEMS  IN  A 300  TPD  NITRIC ACID  PLANT  (Reference 6-6 and 6-26)

Capital Investment, ($)
Royalty
Operating Labor, (hr/yr)
($/yr)
Maintenance Labor,
($/yr)
Labor Overhead (incl. fringe
benefits & supervision, $/yr)
Catalyst or Molecular Sieve
Cooling Water, (gpm)
($/yr)
Steam, (Ib/yr)
($/yr credit)
Electricity, (kW)
($/yr)
Boiler Feed Water, (gpm)
($/yr)
Fuel, (106 Btu/hr)
($/yr)
Nitric Acid, (tpd)
($/yr)
Urea, tpd
($/yr)
Ammonium Nitrate, (tpd)
($/yr)
Depreciation (11-yr life)
Return on Investment (@ 20%)
Taxes & Insurance, (@ 2%)
Total Annual Cost, ($/yr)
Annual Cost, ($/ton)
Catalyst
Reduction
1,384,000
—
360
2,200
315
2,200
4,400

77,800
—
~ " . p
(15,833)
(387,590)
- 128
20,890
35
12,850
28.5
465,120
—
—




125,900
276,800
27,700
628,270
6.16
Molecular
Sieve
1,200,000
—
360
2,200
315
2,200
4,400

45,600
500
7,330
250
6,120
322
52,550
—
—
2.0
32,640
(6.6)
(112,200)




109,090
240,000
24,000
413,930
4.06
Grande
Paroisse
1,000,000
included
360
2,200
315
2,200
4,400

—
300
4,420
—
—
90
14,690
--
—
—
—
(6.0)
(102,000)




90,910
200,000
20,000
236,780
2.32
CDL/
Vitok
575,000
none
360
2,200
315
2,200
4,400

—
1,020
14,980
715
17,500
265
43,250
—
—
—
—
(6.0)
(102,000)




52,300
115,000
11,500
161,330
1.58
Masar
663,000
fee
360
2,200
540
3,775
5,975

—
—
--
1,310
32,070
20
3,260
—
—
—
—
(5.28)
(89,760)
1.37b
74,528
1.25
(42,500)
60,300
132,600
13,260
195,708
1.92
Goodpasture
425,000
51 ,000
360
2,200
315
2,200
4,400
—
30
440
--
—
45
7340
—
—
--
--
—
—
—
—
—
(13.0)
(422,000)
38,640
85,000
8,500
( 42,290)
(0.42)
 Investment estimates exclude interest during construction, owners expenses, and land costs.

Includes  credit for 0.0017 tons of urea/ton or nitric acid produced present in the spent
 solution  (D.SITPD).

'Parenthesis  indicate credit taken.
                                                    A-28

-------
 TABLE A6-5.  ANNUAL ENERGY REQUIREMENTS (109 Btu) FOR NOX ABATEMENT SYS-
              TEMS FOR A 300 TPD NITRIC ACID PLANT (Reference 6-6 and 6-26)

Steam (Credit)
Electrical
Natural Gas
Oil
Basic Nitric
Acid Plant
(71.4)
-
163.2
-
91.8
Catalytic
Reduction
(129.20)
10.97
232.56
-
114.33
Molecular
Sieve
2.04
27.59
-
16.32
45.95
Grande
Paroisse
-
7.71
-
-
7.71
CDL/
Vitok
5.83
22.71
-
-
28.54
Masar
10.69
1.71
-
-
12.40
Goodpasture
-
1.38
-
-
1»38
 TABLE A6-6.   BASIS FOR TABLES A6-4 AND A6-5 (Reference 6-6)
     (Plant Capacity @ 300 tpd and 102,000 tons/yr)
     (March 1975 Dollars, ENR Index = 2.126)
 1.    Operating Labor
 2.    Maintenance Labor
 3.    Overhead

 4.    Cooling Water
 5.    Boiler Feedwater
 6.    Natural Gas
 7.    Oil
 8.    Depreciation
 9.    Return on Investment
10.    Taxes and Insurance
11.    Nitric Acid
12.    Urea
13.    Ammonium Nitrate
14.    1  kWh = 10,500 Btu
15.    Electricity
16.    Ammonia
@ $6.1/hr
(3 $7.0/hr
@ 100% of labor (including fringe benefits
  and supervision)
(3 $0.03  1,000 gal
(3 $0.75  1,000 gal
(3 $2.00/1O6  Btu
(3 $2.00/1O6  Btu
@ 11 yr straight line
@ 20% of capital cost
@  2% of capital cost
0 $90/ton
(3 $160/ton
0 $TOO/ton

(3 $0.02/kWh
@ $157/ton
                                 A-29

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-------
                                             APPENDIX  B
                                        PREFIXES FOR SI  UNITS
       The names of multiples and submultiples of SI units may be formed by application  of these
prefixes:
1 UV- \*\J i uj «M i **• *
Unit is Multiplied
1018
1015
1012
109
106
103
102
10
lo-1
10'2
io-3
io-6
io-9
io-12
io-15
io-18
Prefix
exa
peta
tera
giga
mega
kilo
hecto
deka
deci
centi
mi 1 1 i
micro
nano
pi co
femto
atto
Symbol
E
P
T
G
M
k
h
da
d
c
m
y
n
P
f
a
                                                 B-l

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                                             APPENDIX C
                                              GLOSSARY

Biased Firing - An off-stoichiometric combustion technique in which  the  burners  of a  wall-fired
utility boiler are operated either fuel- or air-rich in  a staggered  configuration.
Boiler Efficiency -       Heat Output  x 100.
                          Heat Input
The overall figure reflects combustion efficiency,  radiation and convection  losses from the  boiler,
and heat lost in exhaust gases.
Burners Out Of Service (BOOS) - An off-stoichiometric combustion technique in which some burners
are operated on air only.
Combustion Modification -An alteration of the normal burner/firebox configuration or operation
employed for the purpose of reducing the formation  of nitrogen oxides.
Derating — Reducing the heat input and power or steam output of a boiler below the level for which
it was designed.
Excess Air - Any increment of air greater than the  stoichiometric fuel  requirement.  With gas-,  oil-
and coal-fired boilers, some excess air is used to  assure optimum combustion.
Field-Erected Boiler - All components of a boiler are delivered to the site and assembled in the
field.  Mainly pertains to utility and large industrial  boilers.
Firetube Boiler - Steam or hot water generator with heat transfer surface consisting of steel tubes
surrounded by water and carrying hot combustion gases.
Flue  Gas Recirculation (FGR) -A combustion modification in which a portion of the boiler exhaust
gases are  recirculated to the burners to inhibit NO formation.
Flue  Gas Treatment - A process which treats tail gases chemically to remove N0x before release to
the atmosphere.
Fuel  Nitrogen - Nitrogen that is chemically bound in the fuel.
Heat  Input - The product of  the fuel feedrate and the higher heating value, e.g., 10 Mg per hour
of coal with a  higher heating value of 29 MJ/kg provides a heat input of 80.5 MW (290GJ/h).
                                                C-l

-------
 Heat Release Rate - The rate  of combustion  per unit volume of firebox, typically 1n terms of MH/m3.
 Higher or Gross  Heating Value (HHV) -The heat generated by complete combustion of a fuel, always
 referenced to baseline  temperature, e.g., 16°C.  Heat available at the reference temperature 1s
 Included  1n the  higher  heating  value even 1f 1t  1s not practically available, I.e.* heat of con-*
 denslng water vapor.
 Low  Excess A1r - A combustion modification  1n which NOX formation Is Inhibited by reducing the excess
 air  to less than normal  ratios.
 Lower or  Net Heating Value  (LHV) -The heat that 1s practically available from a fuel to generate
 steam or  otherwise raise the  temperature of the media receiving energy.  The net heating value assumes
 complete  combustion.  It differs from the higher heating value 1n that heat of vaporizing water of
 combustion 1s  considered a  recoverable loss.
 Off-Stoich1ometr1c Combustion (OSC) -A combustion modification technique 1n which burner stolchl-
 ometry 1s  altered  to Inhibit  NOX formation.   Types of OSC Include biased firing, burners out of
 service,  and two-stage  combustion.
 Packaged  Boilers - These are  usually boilers that are smaller and more economically assembled at
 the  plant, then  shipped to  the  boiler  site  as  one integral unit ready for operation after  connection
 to water,  stream,  and power.
 Polycyclic  Organic Matter (POM) - Organic compounds which exists in condensed phase at  ambient tem-
 perature and are emitted as either "carbon on particulate" or condensed onto emitted partlculate.
 Polynuclear Aromatic Hydrocarbons (PNA) - Same  as POM.
 Stoichiometric Air - That quantity of air which supplies  only enough  oxygen to react with the  com-
 bustible portion of the fuel.
Two-Stage  Combustion - A type of off-stoichiometr1c combustion 1n  which the burners  are operated
 fuel-rich  and the remainder of the required  combustion  air is  Introduced  through separate ducts
 located above the burner.  This is also called  "overfire  air"  or "NOX port operation.
Matertube  Boiler - A steam generator with heat  transfer surface  consisting of steel  tubes carrying
water that are exposed to hot combustion gases.
                                                 C-2

-------
                                  TECHNICAL REPORT DATA
                           (Please read Instructions on the reverse before completing)
1. REPORT NO.
  EPA-450/1-78-001
                                                           3. RECIPIENT'S ACCESSI Of* NO.
4. TITLE AND SUBTITLE
  Control  Techniques for Nitrogen  Oxides  Emissions from
  Stationary Sources - Second Edition
             5. REPORT DATE
               January, 1978
             6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
  R.M.  Evans, R.J. Schreiber,  H.B.  Mason, W.M. Toy
  L.R.  Waterland, and C. Castaldini
                                                          8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
                                                           10. PROGRAM ELEMENT NO.
  Acurex Corporation/Energy  &  Environmental Division
  485  Clyde Avenue
  Mountain View, California  94042
             11. CONTRACT/GRANT NO.
               Contract No. 68-02-2611
               Task No. 12
12. SPONSORING AGENCY NAME AND ADDRESS
                                                           13. TYPE OF REPORT AND PERIOD COVERED
  United States Environmental  Protection Agency
  Office of Air Quality Planning  and Standards
  Research Triangle Park,  North Carolina  27711
               Final
             14. SPONSORING AGENCY CODE
                                                                  200/04
15. SUPPLEMENTARY NOTES
  Acurex Project Engineer:   Michael  Evans
  EPA Project Officers:  Gilbert  Wood and Michael Davenport
16. ABSTRACT
       This second edition  of  Control  Techniques for Nitrogen  Oxides Emissions
  from Stationary Sources  (AP-67)  presents recent developments of nitrogen oxides
  (NOx)  control techniques  which  have  become available  since  preparation of the
  first edition (published,  March  1970).  As required by  Section  108 of the Clean
  Air Act, this second edition compiles the best available  information on NOx
  emissions; achievable control  levels and alternative  methods of prevention and
  control  of NOx emissions;  alternative fuels, processes, and  operating methods
  which reduce NOx emissions;  cost of  NOx control methods,  installation, and
  operation; and the energy  requirements and environmental  impacts of the NOx
  emission control technology.
       Each stationary source  of  NOx emissions is discussed  along with the various
  control  techniques and process  modifications available  to  reduce NOx emissions.
  Various  combinations of  equipment process conditions  and  fuel  types are
  identified and evaluated  for NOx emission control.
17.
                               KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                              b.IDENTIFIERS/OPEN ENDED TERMS
                          c.  COS AT I Field/Group
  Nitroqen Oxides Emissions
  Control Techniques
  Fossil  Fuel Combustion
  Nitric Acid Manufacturing
  Costs
  Photochemical Oxidants
13. DISTRIBUTION STATEMENT


  Release Unlimited
19. SECURITY CLASS (This Report)
   Unclassified
21. NO. OF PAGES

     4QQ
                                              20. SECURITY CLASS (This page)

                                                Unclassified
                                                                        22. PRICE
EPA Form 2220-1 (9-73)
                                           C-3

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