vvEPA
          United States
          Environmental Protection
          Agency
Office of Air Quality
Planning and Standards
Research Triangle Park. NC 27711
- V2V-EOF

  AP-42
  Volume I
  Supplement F
  July 1993
         Air
             SUPPLEMENT F

                     TO

             COMPILATION
                     OF
             AIR POLLUTANT
           EMISSION FACTORS

                 VOLUME I:

              STATIONARY POINT
             AND AREA SOURCES

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VII

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 ^
         >,         UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
                                ! of Air Quality Planning and Standards
                          Research Triangle Park, North Carolina 27711


                                         NOTICE


    The Emission Inventory Branch  (EIB) has been working on this Supplement F to AP-42 for
several months.  It is a substantial part of  EPA's efforts to comply with Section 130 of the 1990
Clean Air Act Amendments, which require that the Agency review and revise its air pollutant emission
factors every three years.  Supplements D and E reflected the first parts of this effort.  Though the
Act requires this updating for ozone-related  pollutants only (total organic compounds, oxides of
nitrogen, and carbon monoxide), the effort has been expanded to include,  where data are available,
other criteria pollutants, hazardous pollutants, global warming gases and other speciation information.
More AP-42 sections are now under development and/or review, to result in the cover to cover update
of this important document series. This complete update has been a major technical undertaking, and
the efforts of the Emission Factor And Methodologies Section staff, and of the several contractors
who assisted, are hereby acknowledged.

     This supplement  and the subsequent updates  now under development represent  significant
improvements, but many data gaps and uncertainties still exist. AP-42 users can help alleviate this
situation by providing comments, emission test data,  and any other information which may be
evaluated and reflected in future updates.

    Those familiar with this document may notice that some factors published in the past now have
lower quality ratings, even though the factors are unchanged or are supported by newer and more
extensive data.  This is attributable to the adoption of more consistent and stringently applied rating
criteria.  The factors in this AP-42 update are believed to be more appropriate and to represent a
better estimate than in the past.  Of course, they remain for estimation purposes and should not be
considered substitutes for exact measurements taken at the source.

    Besides this print medium, the information in AP-42 is now available by several other routes.  The
Air CHIEF compact disc/read-only memory (CD/ROM) contains AP-42, as well as  about 30
hazardous air pollutant emission estimation reports and several data bases.  It can be purchased from
the Government Printing Office for about $15.00. Also, the CHIEF electronic bulletin board, via
PC/modem at (919) 541-5742, contains the latest versions of each section of AP-42, and many other
reports and tools.  In addition, individual sections of AP-42 can be obtained quickly and directly
through the facsimile service Fax CHIEF, at 919) 541-5626/0548.  These electronic on-line services
operate 24 hours per day and 7 days per week.  The CHIEF Newsletter, issued quarterly, contains
much useful information  on emission factors, inventories  and  related  matters, and anyone may
receive this newsletter by providing her/his name and address.  These various media are provided by
EIB's ClearingHouse For Inventories And Emission Factors (CHIEF).

    If you have questions or comments, on these or  any other emission  estimation topics, you may
call the Info CHIEF hot line at 919 541-5285, during Eastern Time office  hours, or write to:

                             Emission Inventory Branch (MD 14)
                                          US EPA
                             Research Triangle Park, NC  27711
                                                 Emission Factor And Methodologies Section
                                                 Emission Inventory Branch
                                                 Technical Support Division
                                                 Office Of Air Quality Planning And Standards
                                                 U. S. Environmental Protection Agency

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                                INSTRUCTIONS FOR INSERTING
                                       SUPPLEMENT F
                                  INTO VOLUME I OF AP-42

Pp. iii through vi (blank) replace Hi and iv. New "Publications In Series".
Pp. vii through x replace v through viii.  New "Contents".
Pp. xi through xviii replace ix through xvi. New "Key Word Index".
Pp. 1.1-1 through -38 (blank) replace all of previous Section  1.1. Major Revision.
Pp. 1.2-1 through -14 (blank) replace all previous. Major Revision.
Pp. 1.3-1 through -38 replace all previous. Major Revision.
Pp. 1.4-1 through -8 replace all previous.  Major Revision.
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Pp. 1.7-1 through -18 (blank) replace all previous. Major Revision.
Pp. 1.8-1 through -6 (blank) replace  all previous.  Major Revision.
Pp. 1.9-1 through -6 (blank) replace  all previous.  Major Revision.
Pp. 1.10-1 through -12 replace all previous. Major Revision.
Pp. 1.11-1 through-8 replace all previous. Major Revision.
Pp. 2.1-1 through -44 replace all previous. Major Revision.
Pp. 2.5-1 through -56 (blank) replace all previous. Major Revision.
Add pp. 2.6-1 through -30.  New Section.
Add pp. 2.7-1 through -14 (blank).  New Section.
Pp. 3.1-1 through -10 replace all previous. Minor Revision.
Pp. 3.2-1 through -10 (blank) replace all previous. Minor Revision.
Pp. 3.3-1 through -8 (blank) replace  all previous.  Minor Revision.
Pp. 3.4-1 through -10 (blank) replace all previous. Minor Revision.
Pp. 5.2-1 through -6 replace all previous.  Major Revision.
Pp. 5.5-1 through -6 replace all previous.  Major Revision.
Pp. 5.7-1 through -4 replace all previous.  Major Revision.
Pp. 5.8-1 through -6 replace all previous.  Major Revision.
Pp. 5.9-1 through -8 (blank) replace  all previous.  Major Revision.
Pp. 5.11-1 through -10 (blank) replace all previous.  Major Revision.
Pp. 5.15-1 through -8 (blank) replace all previous. Major Revision.
Pp. 5.16-1 through -8 replace all previous. Major Revision.
Pp. 5.17-1 through -10 (blank) replace all previous.  Major Revision.
Pp. 5.18-1 through -6 replace all previous. Major Revision.

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                       INSTRUCTIONS FOR INSERTING SUPPLEMENT F
                                           (CONT.)

Pp. 6.8-1 through -10 replace all previous.  Major Revision.
Add pp. 6.10-1 and -2 (blank). Editorial Change.
Pp. 6.10.1-1 through -4 replace all previous. Major Revision.
Pp. 6.10.2-1 through -6 (blank) replace all previous.  Major Revision.
Pp. 6.10.3-1 through -6 (blank) replace all previous.  Major Revision.
Pp. 6.14-1 through -8 replace all previous.  Major Revision.
Pp. 6.18-1 through -4 replace all previous.  Major Revision.
Pp. 7.7-1 through -8 replace all previous. Major Revision.
Pp. 7.14-1 through -10 replace all previous.  Major Revision.
Pp. 7.16-1 through -6 replace all previous.  Major Revision.
Pp. 8.8-1 through -4 replace all previous.  Editorial Change.
Pp. 8.10-1 through -6 (blank) replace all previous. Editorial Change.
Pp. 8.11-1 through -16 replace all previous. Editorial Change.
Pp. 8.14-1 through -10 replace all previous.  Major Revision.
Pp. 8.16-1 through -12 (blank) replace all previous.  Major Revision.
Pp. 8.17-1 through -6 (blank) replace all previous.  Major Revision.
Pp. 8.18-1 through -12 replace all previous.  Major Revision.
Pp. 8.23-1 through  -8 (blank) replace all previous.  Editorial  Change.
Add pp. 8.25-1 through -10.  New Section.
Section 8.26 is reserved.
Add pp. 8.27-1 through -4.  New Section.
Pp. 12-1 through -4 and -39 and -40 replace same. Minor Revision.
Pp. D-l through -12 (blank) replace all previous. Major Revision.
Pp. E-l through -8 (blank) replace all previous.  Major Revision.

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   SUPPLEMENT F

           TO

   COMPILATION
          OF
  AIR POLLUTANT
EMISSION FACTORS

       VOLUME I:

    STATIONARY POINT
   AND AREA SOURCES
   Office Of Air Quality Planning And Standards
       Office Of Air And Radiation
    U. S. Environmental Protection Agency
     Research Triangle Park, NC 27711

          July 1993
                              AP-42
                            Volume I
                           Supplement F

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This report has been reviewed  by the Office  Of Air Quality Planning And Standards,  U. S.
Environmental Protection Agency, and has been approved for publication.  Any mention of trade
names or commercial products is not intended to constitute endorsement or recommendation for use.
                                           AP-42
                                         Volume I
                                       Supplement F
                                             11

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                                PUBLICATIONS IN SERIES
    Issue

COMPILATION OF AIR POLLUTANT EMISSION FACTORS, FOURTH EDITION
SUPPLEMENT A
    Introduction
    Section  1.1
            1.2
            1.3
            1.4
            1.6
            1.7
            5.16
            7.1
            7.2
            7.3
            7.4
            7.5
            7.6
            7.7
            7.8
            7.10
            7.11
            8.1
            8.3
            8.6
            8.10
            8.13
            8.15
            8.19.2
            8.22
            8.24
            10.1
            11.2.6
    Appendix C.I

    Appendix C.2
                                                                Date

                                                                 9/85

                                                                10/86
Bituminous And Subbituminous Coal Combustion
Anthracite Coal Combustion
Fuel Oil Combustion
Natural Gas Combustion
Wood Waste Combustion In Boilers
Lignite Combustion
Sodium Carbonate
Primary Aluminum Production
Coke Production
Primary Copper Smelting
Ferroalloy Production
Iron And Steel Production
Primary Lead Smelting
Zinc Smelting
Secondary Aluminum Operations
Gray Iron Foundries
Secondary Lead Processing
Asphaltic Concrete Plants
Bricks  And Related Clay Products
Portland Cement Manufacturing
Concrete Batching
Glass Manufacturing
Lime Manufacturing
Crushed Stone Processing
Taconite Ore Processing
Western Surface Coal Mining
Chemical Wood Pulping
Industrial Paved Roads
Particle Size Distribution Data And Sized Emission Factors
  For Selected Sources
Generalized Particle Size Distributions
SUPPLEMENT B
   Section  1.1
            1.2
            1.10
            1.11
            2.1
            2.5
            4.2
            4.12
            5.15
            6.4
            8.15
            8.19.2
            11.1
            11.2.1
            11.2.3
            11.2.6
            11.2.7
   Appendix C.3
Bituminous And Subbituminous Coal Combustion
Anthracite Coal Combustion
Residential Wood Stoves
Waste Oil Combustion
Refuse Combustion
Sewage Sludge Incineration
Surface Coating
Polyester Resin Plastics Product Fabrication
Soap And Detergents
Grain Elevators And Processing Plants
Lime Manufacturing
Crushed Stone Processing
Wildfires And Prescribed Burning
Unpaved Roads
Aggregate Handling And Storage Piles
Industrial Paved Roads
Industrial Wind Erosion
Silt Analysis Procedures
                                                                9/88
                                           in

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                             PUBLICATIONS IN SERIES (Cont.)
   Issue

SUPPLEMENT C
   Section   1.10
            2.1
            2.5
            4.2.2.13
            4.2.2.14
            5.19
            7.6
            7.10
             10.1
             11.1
             11.2.6
             11.2.7
             11.3
   Appendix C.2
   Appendix D
   Appendix E
                                                                Date

                                                                 9/90
Residential Wood Stoves
Refuse Combustion
Sewage Sludge Incineration
Magnetic Tape Manufacturing Industry
Surface Coating Of Plastic Parts For Business Machines
Synthetic Fiber Manufacturing
Primary Lead Smelting
Gray Iron Foundries
Chemical Wood Pulping
Wildfires And Prescribed Burning
Industrial Payed Roads
Industrial Wind Erosion
Explosives Detonation
Generalized Particle Size Distributions
Procedures For Sampling Surface/Bulk Dust Loading
Procedures For Laboratory Analysis Of Surface/Bulk Dust Loading Samples
SUPPLEMENT D
    Section   1.4
             1.9
             1.10
            2.1
            4.2.1
            4.13
            5.13.1
            5.13.2
            5.13.3
            6.10.3
            8.6
            8.19.1
            8.24
             11.1
             11.4
             11.5
Natural Gas Combustion
Residential Fireplaces
Residential Wood Stoves
Refuse Combustion
Nonindustrial Surface Coating
Waste Water Collection, Treatment And Storage
Polyvinyl Chloride And Polypropylene
Poly(ethylene terephthalate)
Polystyrene
Ammonium Phosphates
Portland  Cement Manufacturing
Sand And Gravel Processing
Western Surface Coal Mining
Wildfires And Prescribed Burning
Wet Cooling Towers
Industrial Flares
                                                                 9/91
SUPPLEMENT E
    Section   1.2
             1.4
             1.5
             1.6
             1.8
             1.9
             1.10
             1.11
             2.2
             2.3
             2.4
             3.1
             3.2
             3.3
             3.4
             5.15
    Chapter  12
Anthracite Coal Combustion
Natural Gas Combustion
Liquified Petroleum Gas Combustion
Wood Waste Combustion In Boilers
Bagasse Combustion In Sugar Mills
Residential Fireplaces
Residential Wood Stoves
Waste Oil Combustion
Automobile Body Incineration
Conical Burners
Open Burning
Stationary Gas Turbines For Electricity Generation
Heavy Duty Natural Gas Fired Pipeline Compressor Engines
Gasoline And Diesel Industrial Engines
Large Stationary Diesel And All Stationary Dual Fuel Engines
Soap And Detergents
Storage Of Organic Liquids
                                                                 10/92
                                            IV

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                             PUBLICATIONS IN SERIES (Cont.)
SUPPLEMENT F
   Section  1.1
            1.2
            1.3
            1.4
            1.5
            1.6
            1.7
            1.8
            1.9
            1.10
            1.11
            2.1
            2.5
            2.6
            2.7
            3.1
            3.2
            3.3
            3.4
            5.2
            5.5
            5.7
            5.8
            5.9
            5.11
            5.15
            5.16
            5.17
            5.18
            6.8
            6.10.1
            6.10.2
            6.10.3
            6.14
            6.18
            7.7
            7.14
            7.16
            8.8
            8.10
            8.11
            8.14
            8.16
            8.17
            8.18
            8.23
            8.25
            8.27
   Chapter  12
   Appendix D
   Appendix E
Bituminous And Subbituminous Coal Combustion
Anthracite Coal Combustion
Fuel Oil Combustion
Natural Gas Combustion
Liquefied Petroleum Gas Combustion
Wood Waste Combustion In Boilers
Lignite Combustion
Bagasse Combustion In Sugar Mills
Residential Fireplaces
Residential Wood Stoves
Waste Oil Combustion
Refuse Combustion
Sewage Sludge Incineration
Medical Waste Incineration
Landfills
Stationary Gas Turbines For Electricity Generation
Heavy Duty Natural Gas Fired Pipeline Compressor Engines
Gasoline And Diesel Industrial Engines
Large Stationary Diesel And All Stationary Dual Fuel Engines
Synthetic Ammonia
Chlor-Alkali
Hydrochloric Acid
Hydrofluoric  Acid
Nitric Acid
Phosphoric Acid
Soap And  Detergents
Sodium  Carbonate
Sulfuric Acid
Sulfur Recovery
Ammonium Nitrate
Normal  Superphosphates
Triple Superphosphates
Ammonium Phosphate
Urea
Ammonium Sulfate
Zinc Smelting
Secondary Zinc Processing
Lead Oxide And Pigment Production
Clay And Fly Ash Sintering
Concrete Batching
Glass Fiber Manufacturing
Gypsum Processing
Mineral Wool Processing
Perlite Processing
Phosphate Rock Processing
Metallic Minerals Processing
Lightweight Aggregate Manufacturing
Feldspar Processing
Storage Of Organic Liquids
Procedures For Sampling Surface And Bulk Materials
Procedures For Analyzing Surface And Bulk Material Samples
                                                                 7/93

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                                      CONTENTS
                                                                                       Page

INTRODUCTION	...1
1.   EXTERNAL COMBUSTION SOURCES	1-1
     1.1      Bituminous And Subbituminous Coal Combustion	1.1-1
     1.2      Anthracite Coal Combustion  	1.2-1
     1.3      Fuel Oil Combustion	1.3-1
     1.4      Natural Gas Combustion	1.4-1
     1.5      Liquified Petroleum Gas Combustion	>	1.5-1
     1.6      Wood Waste Combustion In Boilers 	,	1.6-1
     1.7      Lignite Combustion	1.7-1
     1.8      Bagasse Combustion In Sugar Mills	1.8-1
     1.9      Residential Fireplaces	1.9-1
     1.10     Residential Wood Stoves 	..	1.10-1
     1.11     Waste  Oil Combustion	1.11-1

2.   SOLID WASTE DISPOSAL	2.0-1
     2.1      Refuse Combustion	2.1-1
     2.2      Automobile Body Incineration	...2.2-1
     2.3      Conical Burners	2.3-1
     2.4      Open Burning	2.4-1
     2.5      Sewage Sludge Incineration	2.5-1
     2.6      Medical Waste Incineration	2.6-1
     2.7      Landfills	2.7-1
3.   STATIONARY INTERNAL COMBUSTION SOURCES	3.0-1
              Glossary Of Terms 	Vol. II
              Highway Vehicles	Vol. II
              Off-highway Mobile Sources	Vol. II
     3.1      Stationary Gas  Turbines For Electricity Generation	3.1-1
     3.2      Heavy Duty Natural Gas Fired Pipeline Compressor Engines 	3.2-1
     3.3      Gasoline And Diesel Industrial Engines  	3.3-1
     3.4      Large Stationary Diesel And All Stationary Dual Fuel Engines 	3.4-1

4.   EVAPORATION LOSS SOURCES	4.1-1
     4.1      Dry Cleaning	4.1-1
     4.2      Surface Coating 	4.2-1
     4.2.1    Nonindustrial Surface Coating	4.2.1-1
     4.2.2    Industrial Surface Coating 	4.2.2.1-1
     4.2.2.1  General Industrial Surface Coating  	4.2.2.1-1
     4.2.2.2  Can Coating	....4.2.2.2-1
     4.2.2.3  Magnet Wire Coating	4.2.2.3-1
     4.2.2.4  Other Metal Coating 	4.2.2.4-1
     4.2.2.5  Flat Wood  Interior Panel Coating	4.2.2.5-1
     4.2.2.6  Paper Coating	4.2.2.6-1
     4.2.2.7  Fabric Coating	4.2.2.7-1
     4.2.2.8  Automobile And Light Duty Truck Surface Coating Operations 	4.2.2.8-1
     4.2.2.9  Pressure Sensitive Tapes And Labels	4.2.2.9-1
     4.2.2.10 Metal Coil Surface Coating	4.2.2.10-1
     4.2.2.11 Large  Appliance Surface Coating	4.2.2.11-1
     4.2.2.12 Metal Furniture Surface Coating	4.2.2.12-1
     4.2.2.13 Magnetic Tape Manufacturing 	4.2.2.13-1
     4.2.2.14 Surface Coating Of Plastic Parts For Business Machines	4.2.2.14-1
     4.3      [Reserved]
     4.4      Transportation  And Marketing  Of Petroleum Liquids 	4.4-1
     4.5      Cutback Asphalt, Emulsified Asphalt And Asphalt Cement  	4.5-1
     4.6      Solvent Degreasing	4.6-1
                                             Vll

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 5.
6.
7.
4.7 Waste Solvent Reclamation 	
4.8 Tank And Drum Cleaning 	
4.9 Graphic Arts 	
4.10 Commercial/Consumer Solvent Use 	
4.11 Textile Fabric Printing 	
4.12 Polyester Resin Plastics Product Fabrication 	
4.13 Waste Water Collection, Treatment And Storage 	
CHEMICAL PROCESS INDUSTRY 	 	
5.1 Adipic Acid 	
5.2 Synthetic Ammonia 	
5.3 Carbon Black 	
5.4 Charcoal 	
5.5 Chlor-Alkali 	
5.6 Explosives 	
5.7 Hydrochloric Acid 	
5.8 Hydrofluoric Acid 	
5.9 Nitric Acid 	
5.10 Paint And Varnish 	 	
5.11 Phosphoric Acid 	
5.12 Phthalic Anhydride 	
5.13.1 Polyvinyl Chloride And Polypropylene 	
5.13.2 Polyethylene terephthalate) 	
5.13.3 Polystyrene 	
5.14 Printing Ink 	 ; 	
5.15 Soap And Detergents 	
5.16 Sodium Carbonate 	
5.17 Sulfuric Acid 	 '. 	
5.18 Sulfur Recovery 	
5.19 Synthetic Fibers 	
5.20 Synthetic Rubber 	
5.21 Terephthalic Acid 	
5.22 Lead Alkyl 	
5.23 Pharmaceuticals Production 	
5.24 Maleic Anhydride 	
FOOD AND AGRICULTURAL INDUSTRY 	
6.1 Alfalfa Dehydrating 	
6.2 Coffee Roasting 	
6.3 Cotton Ginning 	
6.4 Grain Elevators And Processing Plants 	
6.5 Fermentation 	
6.6 Fish Processing 	
6.7 Meat Smokehouses 	
6.8 Ammonium Nitrate 	
6.9 Orchard Heaters 	
6.10 Phosphate Fertilizers 	
6.11 Starch Manufacturing 	
6.12 Sugar Cane Processing 	
6.13 Bread Baking 	 	
6.14 Urea 	 	
6. 15 Beef Cattle Feedlots 	
6.16 Defoliation And Harvesting Of Cotton 	
6.17 Harvesting Of Grain 	
6.18 Ammonium Sulfate 	
METALLURGICAL INDUSTRY 	
7.1 Primary Aluminum Production 	
7.2 Coke Production 	
	 	 	 4.7-1
	 4.8-1
	 4.9-1
	 4.10-1
	 .4.11-1
	 4.12-1
	 4.13-1
	 5.1-1
	 5.1-1
	 5.2-1
	 5.3-1
	 5.4-1
	 5.5-1
	 ..5.6-1
	 5.7-1
	 5.8-1
	 	 	 5.9-1
	 5.10-1
	 5.11-1
	 5.12-
	 5.13.1-
	 5.13.2-
	 5.13.3-
	 	 	 5.14-
	 5.15-
	 5.16-1
	 5.17-1
	 5.18-1
	 5.19-1
	 5.20-1
	 5.21-1
	 5.22-1
	 5.23-1
	 5.24-1
	 6.1-1
	 6.1-1
	 6.2-1
	 6.3-1
	 6.4-1
	 6.5-1
	 ......6.6-1
	 6.7-1
	 6.8-1
	 6.9-1
	 6.10-1
	 6.11-1
	 6.12-1
	 6.13-1
	 6.14-1
	 6.15-1
	 6.16-1
	 .6.17-1
	 6.18-1
	 7.1-1
	 7.1-1
	 7.2-1
                                                      Vlll

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     *7.3     Primary Copper Smelting	.....7.3-1
     7.4     Ferroalloy Production	7.4-1
     7.5     Iron And  Steel Production	.....7.5-1
     7.6     Primary Lead Smelting	7.6-1
     7.7     Zinc Smelting	.....7.7-1
     7.8     Secondary Aluminum Operations	.....7.8-1
     7.9     Secondary Copper Smelting And Alloying	7.9-1
     7.10    Gray Iron Foundries	7.10-1
     7.11    Secondary Lead Processing	7.11-1
     7.12    Secondary Magnesium Smelting	7.12-1
     7.13    Steel Foundries	7.13-1
     7.14    Secondary Zinc Processing 	7.14-1
     7.15    Storage Battery Production	7.15-1
     7.16    Lead Oxide And Pigment Production	7.16-1
     7.17    Miscellaneous Lead Products	7.17-1
     7.18    Leadbearing Ore Crushing And Grinding	7.18-1

8.    MINERAL PRODUCTS INDUSTRY	8.1-1
     8.1     Asphaltic Concrete Plants	..	,	8.1-1
     8.2     Asphalt Roofing	 8.2-1
     8.3     Bricks And Related Clay Products	8.3-1
     8.4     Calcium Carbide Manufacturing	 8.4-1
     8.5     Castable Refractories	8.5-1
     8.6     Portland Cement Manufacturing	8.6-1
     8.7     Ceramic Clay Manufacturing	 8.7-1
     8.8     Clay  And Fly Ash Sintering	8.8-1
     8.9     Coal  Cleaning	8.9-1
     8.10    Concrete Batching 	8.10-
     8.11    Glass Fiber Manufacturing 	8.11-
     8.12    Frit Manufacturing	....8.12-
     8.13    Glass Manufacturing 	8.13-
     8.14    Gypsum Manufacturing	8.14-
     8.15    Lime Manufacturing	8.15-1
     8.16    Mineral Wool  Manufacturing	8.16-1
     8.17    Perlite Manufacturing 	8.17-1
     8.18    Phosphate Rock Processing	8.18-1
     8.19    Construction Aggregate Processing	8.19-1
     8.20     [Reserved]
     8.21    Coal  Conversion 		8.21-1
     8.22    Taconite Ore Processing	8.22-1
     8.23    Metallic Minerals Processing	8.23-1
     8.24    Western Surface Coal Mining	...8.24-1
     8.25    Lightweight Aggregate Manufacturing	.8.25-1
     8.26     [Reserved]
     8.27    Feldspar Processing	...8.27-1

9.    PETROLEUM  INDUSTRY  	9.1-1
     9.1     Petroleum Refining	9.1-1
     9.2     Natural Gas Processing	9.2-1

10.  WOOD PRODUCTS INDUSTRY	10.1-1
     10.1    Chemical Wood Pulping	10.1-1
     10.2    Pulpboard 	10.2-1
     10.3    Plywood Veneer And Layout Operations 	10.3-1
     10.4    Woodworking Waste Collection Operations	10.4-1

11.  MISCELLANEOUS SOURCES 	11.1-1
     11.1     Wildfires And Prescribed Burning	..11.1-1
     11.2    Fugitive Dust Sources	11.2-1
                                            IX

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      11.3     Explosives Detonation 	11.3-1
      11.4     Wet Cooling Towers	11.4-1
      11.5     Industrial Flares	11.5-1
12.   STORAGE OF ORGANIC LIQUIDS	12-1

APPENDIX A
      Miscellaneous Data And Conversion Factors  	.A-l

APPENDIX B
      (Reserved For Future Use)

APPENDIX C.I
      Particle Size Distribution Data And Sized Emission Factors For Selected Sources	C.l-1

APPENDIX C.2
      Generalized Particle Size Distributions	C.2-1

APPENDIX C.3
      Silt Analysis Procedures 	C.3-1

APPENDIX D
     Procedures For Sampling Surface/Bulk Dust Loading	D-l

APPENDIX E
     Procedures For Laboratory Analysis Of Surface/Bulk Dust Loading Samples	E-l

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                                   KEY WORD INDEX


                                                                             CHAPTER/SECTION

Acid
  Adipic	5.1
  Hydrochloric  	5.7
  Hydrofluoric	5.8
  Phosphoric	.	5.11
  Sulfuric	5.17
  Terephthalic	.......5.21
Adipic Acid	.	5.1
Aggregate, Construction .-.	8.19
Aggregate, Lightweight	8.25
Aggregate Storage Piles
  Fugitive Dust	11.2
Agricultural Tilling
  Fugitive Dust	11.2
Alfalfa Dehydrating	6.1
Alkali,  Chlor-	5.5
Alloys
  Ferroalloy Production 	7.4
  Secondary Copper Smelting And Alloying	7.9
Aluminum
  Primary Production	7.1
  Secondary Operations 	7.8
Ammonia, Synthetic	5.2
Ammonium Nitrate	.	....6.8
Ammonium Phosphate	6.10.3
Anhydride, Phthalic	'.	5.12
Anthracite Coal Combustion	.'	1.2
Appliance Surface Coating	.4.2.2.11
Ash
  Fly Ash Sintering	8.8
Asphalt
  Cutback Asphalt, Emulsified Asphalt And Asphalt Cement	4.5
  Roofing	.8*2
Asphaltic Concrete Plants	8.1
Automobile Body Incineration 	2.2
Automobile Surface Coating	..4.2.2.8-1

Bagasse Combustion In Sugar Mills	1.8
Baking, Bread	6.13
Bark
  Wood Waste Combustion In Boilers	1.6
Batching, Concrete 	8.10
Battery
  Storage Battery Production	7.15
Beer Production
  Fermentation 	,	.6.5
Bituminous Coal Combustion	1.1
Bread Baking	6.13
Bricks  And Related Clay Products	8.3
Bulk Material Analysis Procedures	App. E
Bulk Material Sampling Procedures	,	App. D
Burners,  Conical (Teepee)	,	2.3


                                             xi

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 Burning, Open	2.4
 Business Machines, Plastic Parts Coating	4.2.2.14
 Calcium Carbide Manufacturing	8.4
 Can Coating	4.2.2.2
 Cane
  Sugar Cane Processing	6.12
 Carbon Black	5.3
 Carbonate
  Sodium Carbonate Manufacturing	5.16
 Castable Refractories	8.5
 Cattle
  Beef Cattle Feedlots	6.15
 Cement
  Asphalt	4.5
  Portland Cement Manufacturing	8.6
 Ceramic Clay Manufacturing	8.7
 Charcoal	5.4
 Chemical Wood Pulping	10. l
 Chlor-Alkali 	".....".....5.5
 day
  Bricks And Related Clay Products	8.3
  Ceramic  Clay Manufacturing	,"^.7
  Clay And Hy Ash Sintering	.8.8
 Cleaning
  Coal	8.9
  Dry Cleaning	4.1
  Tank And Drum	       48
 Coal
  Anthracite Coal Combustion	1.2
  Bituminous Coal Combustion  	1.1
  Cleaning	8.9
  Conversion	8.21
 Coating, Surface 	!.!..4.2
  Appliance, Large 	'".'"A.2'.2.il
  Automobile And Light Duty Truck 	!!!!!!!!!.!"!."....!!..4.2.2.8
  Can  	4.2.2.2
  Fabric	4.2.2.7
  Flat Wood Interior Panel	.....A.2.2.5
  Metal, General 	."'""'"'"''.4.2.2 A
  Magnet Wire	."I"""!!!!!!!!"!!	4223
  Magnetic Tape	.'.'.*.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.!'.'.!'.!!!!4.2.2.13
  Metal Coil Surface	4.2.2.10
  Metal Furniture 	"l^".'.".'.".^"A.2\2.\2
  Paper	.V^.".^V.\V"".".'.'.'.'.'.'.'.'."!!!..4.2.2.6
  Plastic Parts For Business Machines	"I"""."''"".'".4.2.2.i4
  Tapes And Label, Pressure Sensitive	.".'....4.2.2.9
Coffee Roasting	......!.....!6.2
Coke Manufacturing	'"""""'""".1.2
Combustion
  Anthracite Coal	1.2
  Bagasse, In Sugar Mill	""".'.'.'.'.'""".'.'.'.'."!!!l!8
  Bituminous Coal	                                         1 i
  Fuel oil	"ZZZ"ZZ""!"ZZ!.'"i!3
  Internal, Mobile	Vol. II
  Internal, Stationary  	!!!ZZZZZ3.0
  Lignite	ZZZ""!'.!""Z!!"i!7
  Liquified Petroleum Gas	Z"!l!s
  Natural Gas  	...........!.."..L4

                                            xii

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  Orchard Heater		....<5.P
  Residential Fireplace	.			....1.9
  WasteOil	'.-l-l-l-
  Wood Stove		,..,1,10
Concrete
  Asphaltic Concrete Plants	-	-8.1
  Concrete Batching		8.10
Conical (Teepee) Burners		2.3
Construction Aggregate			8.19
Construction Operations
  Fugitive Dust Sources	H-2
Conversion, Coal	8.21
Copper
  Primary  Smelting	,	........7.3
  Secondary Smelting And Alloying 	,	.			7-9
Cotton
  Defoliation And Harvesting	6.16
  Ginning				6.3
Dacron
  Synthetic Fibers	-			5.19
Defoliation, Cotton		6.16
Degreasing Solvent				4.6
Dehydrating, Alfalfa	.-6.1
Diesel Engines, Stationary	3.4
Detergents
  Soap And Detergents		5.15
Detonation, Explosives			H-3
Drum
  Tank And Drum Cleaning	...4.8
Dry Cleaning			4.1
Dual Fuel Engines, Stationary	3.4
Dust
  Fugitive Sources		H.2
Dust Loading Sampling Procedures	...App. D
Dust Loading Analysis 		App. E
Electric Utility Power Plants, Gas	.....3.1
Electricity Generators,  Stationary Gas Turbine	3.1
Elevators, Feed And Grain Mills		6.4
Explosives		5.6
Explosives Detonation	........11.3
Fabric Coating	'.	4.2.2.7
Feed
  Beef Cattle Feedlots	...6.15
  Feed And Grain Mills And Elevators	......6.4
Feldspar	........8.27
Fermentation	6.5
Fertilizers
  Ammonium Nitrate	6.8
  Phosphate	...6.10
Ferroalloy Production	7.4
Fiber
  Glass Fiber Manufacturing	8.11
Fiber, Synthetic	5.19
Fires
  Forest Wildfires And  Prescribed Burning	11.1
Fireplaces, Residential	1.9
                                                Xlll

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Fish Processing	"...	6.6
Flat Wood Interior Panel Coating	4.2.2.5
Fly Ash
  day And Fly Ash Sintering	8.8
Foundries
  Gray  Iron Foundries	.....7.10
  Steel Foundries	..7.13
Frit Manufacturing 	8.12
Fuel Oil Combustion	1.3
Fugitive Dust Sources 	11.2
Furniture Surface Coating, Metal	...4.2.2.12

Gas  Combustion, Liquified Petroleum	1.5
Gas, Natural
  Natural Gas Combustion	1.4
  Natural Gas Processing	9.2
  Turbines, Electricity-generating	3.1
Gasoline/Diesel Engines	..3.3
Ginning, Cotton	6.3
Glass Manufacturing	8.13
Glass Fiber Manufacturing	8.11
Grain
  Feed And Grain Mills And Elevators	6.4
  Harvesting Of Grain	6.17
Gravel
  Sand And Gravel Processing	8.19
Gray Iron Foundries	7.10
Gypsum Manufacturing	8.14
Harvesting
  Cotton 	6.16
  Grain	...6.17
Heaters, Orchard	6.9
Hydrochloric Acid 	..5.7
Hydrofluoric Acid	5.8
Highway Vehicles	Vol.  II
Incineration
  Automobile Body	2.2
  Conical (Teepee) 	2.3
  Landfills	2.7
  Medical Waste	2.6
  Open  Burning	....2.4
  Refuse	2.1
  Sewage  Sludge	2.5
Industrial Engines, Gasoline And Diesel	3.3
Industrial Flares	11.5
Industrial Surface Coating  	4.2.2
Ink, Printing 	5.14
Internal Combustion Engines
  Highway Vehicle 	Vol.  II
  Off-highway Mobile	Vol.  II
  Off-highway Stationary	3.0
Iron
  Ferroalloy Production 	7.4
  Gray Iron Foundries 	7.10
  Iron And Steel Mills 	7.5
  Taconite Ore Processing  	8.22
                                            XIV

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 Label Coating, Pressure Sensitive 	.....:4.2.2.9
 Landfills	,	2.7
 Large Bore Engines	3.4
 Lead
   Ore Crushing And Grinding	........7.18
   Miscellaneous Products	7.17
   Primary Lead Smelting	...	7.6
   Secondary  Smelting	;	7.11
 Lead Alkyl	....:	5.22
 Lead Oxide And Pigment Production  	......7.16
 Leadbearing Ore Crushing And Grinding	7.18
 Lightweight Aggregate Manufacturing	8.25
 Lignite Combustion	..1.7
 Lime Manufacturing	8.15
 Liquified Petroleum Gas Combustion	1.5

 Magnesium
   Secondary  Smelting 	................;.......	7.12
 Magnet Wire Coating	........4.2.2.3
 Magnetic Tape Manufacturing/Surface Coating	.4.2.2.13
 Maleic Anhydride	;......5.24
 Meat Smokehouses 	......6.7
 Metal Coil Surface Coating	4.2.2.10
 Medical Waste Incineration	,	2.6
 Metal Furniture Surface Coating	4.2.2.12
 Mineral Wool Manufacturing	8.16
 Mobile Sources
,v  Highway	.	Vol. II
   Off-highway	....Vol. II

 Natural Gas Combustion	1.4
 Natural Gas Fired Pipeline Compressors	3.2
^Natural Gas Processing	.	.9.2
 Nitric Acid Manufacturing 	.	,	5.9
 Nonindustrial Surface Coating	4.2.1
 Normal Superphosphates 	6.10.1

 Off-highway  Mobile Sources  	Vol. II
 Off-highway  Stationary Sources 	3.0
 Oil
   Fuel Oil Combustion	-	1.3
   Waste Oil  Combustion		1.11
 Open Burning	.............2.4
 Orchard Heaters	..6.9
 Ore Processing
   Leadbearing Ore Crushing  And Grinding	......	7.18
   Taconite	..	..........8.22
 Organic Liquid Storage	.	12.0

 Paint And Varnish Manufacturing	...5.10
 Panel Coating, Wood, Interior	...4.2.2.5-1
 Paper Coating	4.2.2.6-1
 Paved Roads
   Fugitive Dust	.....11.2
 Perlite Manufacturing	8.17
 Petroleum
   Liquified Petroleum Gas Combustion	1.5
   Refining	9.1
   Storage Of Organic Liquids	12.0
   Transportation And Marketing Of Petroleum Liquids	4.4

                                               xv

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Pharmaceutical Production 	5.23
Phosphate Fertilizers	6.10
Phosphate Rock Processing	8.18
Phosphoric Acid	....5.11
Phthalic Anhydride	......5.12
Pigment
  Lead Oxide And Pigment Production	,7.16
Pipeline Compressors, Natural Gas Fired	3.2
Plastic Part Surface Coating, Business Machine	4.2.2.14
Plastics	5.13
Plywood Veneer And Layout Operations	...10.3
Poly(ethylene terephthalate)	5.13.2
Polyester Resin Plastics Product Fabrication	4.12
Polypropylene	5.13.1
Polystyrene	5.13.3
Polyvinyl Chloride	5.13.1
Portland Cement Manufacturing	8.6
Prescribed Burning	4	...11.1
Printing Ink	.	5.14
Pulpboard  	10.2
Pulping Chemical Wood 	10.1
Reclamation, Waste Solvent	4.7
Recovery, Sulfur	.....5.18
Refractories, Castable	8.5
Residential Fireplaces	1.9
Roads, Paved
  Fugitive Dust	.11.2
Roads, Unpaved
  Fugitive Dust	11.2
Roasting Coffee	6.2
Rock
  Phosphate Rock Processing	8.18
Roofing, Asphalt	8.2
Rubber, Synthetic	5.20
Sampling Procedures, Surface And  Bulk Materials	.	App  D
Sand And Gravel Processing	8.19
Sewage Sludge Incineration	2.5
Sintering, Clay And Fly Ash	8.8
Smelting
  Primary Copper Smelting	7.3
  Primary Lead Smelting	7.6
  Secondary Copper Smelting And Alloying	7.9
  Secondary Lead Smelting	....7.11
  Secondary Magnesium Smelting  	7.12
  Zinc Smelting	7.7
Smokehouses, Meat 	6.7
Soap And Detergent Manufacturing	5.15
Sodium Carbonate Manufacturing	5.16
Solvent
  Commercial/Consumer Use	4.10
  Degreasing 	4.6
  Waste Reclamation	4.7
Starch Manufacturing	6.11
Stationary Gas Turbines 	3.1
Stationary Sources, Off-highway	3.0
Steel
  Iron And Steel Mills 	7.5
                                            XVI

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  Foundries	7.13
Storage Battery Production	.	7.15
Storage Of Organic Liquids	12.0
Sugar Cane Processing	6.12
Sugar Mills, Bagasse Combustion In	1.8
Sulfur Recovery	5.18
Sulfuric Acid	,	.....5.17
Surface Coating	4.2
Surface Material Analysis Procedures 	App. E
Surface Material Sampling Procedures	App. D
Synthetic Ammonia	5.2
Synthetic Fiber 	5.19
Synthetic Rubber	5.20
Taconite Ore Processing 	8.22
Tank And Dram Cleaning	.4.8
Tape, Magnetic, Manufacturing	4.2.2.13
Tape Coating, Pressure Sensitive	....4.2.2.9
Teepee (Conical) Burners	2.3
Terephthalic Acid	....5.21
Tilling, Agricultural
  Fugitive Dust	11.2
Transportation And Marketing Of Petroleum Liquids 	4.4
Triple  Superphosphates	6.10.2
Track Surface Coating, Light Duty	4.2.2.8
Turbines, Natural Gas Fired 	3.1

Unpaved Roads
  Fugitive Dust	.....11.2
Urea 	6.14

Varnish
  Paint And Varnish Manufacturing	5.10
Vehicles, Highway And Off-highway	Vol. II

Waste Solvent Reclamation	4.7
Waste Oil Combustion	1.11
Waste Water Collection, Treatment and Storage	4.13
Wet Cooling Towers	11.4
Whiskey Production
  Fermentation 	6.5
Wildfires, Forest	11.1
Wine Making
  Fermentation	6.5
Wire Coating, Magnet	4.2.2.3
Wood
  Pulping, Chemical	10.1
  Stoves	1.10
  Waste Combustion In Boilers	1.6
  Interior Panel Coating 	.4 .2.2.5
Woodworking Waste Collection Operations	10.4

Zinc
  Secondary Processing 	7.14
  Smelting	7.7
                                             xvn

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XV111

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1.1 BITUMINOUS AND SUBBETUMINOUS COAL COMBUSTION

1.1.1 General

       Coal is a complex combination of organic matter and inorganic ash formed over eons from
successive layers of fallen vegetation. Coal types are broadly classified as anthracite, bituminous,
subbituminous, or lignite.  These classifications are based on coal heating value together with relative
amounts of fixed carbon, volatile matter, ash, sulfur, and moisture.  Formulae and tables for classifying
coals are given in Reference 1.  See AP-42 Sections 1.2 and 1.7 for discussions of anthracite and
lignite combustion, respectively.

       There  are three major coal combustion techniques: suspension firing, grate firing, and
fluidized bed combustion. Suspension firing is the primary combustion mechanism in pulverized coal
and cyclone systems.  Grate firing is the primary mechanism in underfeed and overfeed stokers.  Both
mechanisms are employed in spreader stokers.  Fluidized bed combustion, while not constituting a
significant percentage of the total  boiler population, has nonetheless gamed popularity in the last
decade and today generates steam for industries, cogenerators, independent power producers, and
utilities.

       Pulverized coal furnaces are used primarily in utility and large industrial boilers.  In these
systems, the coal is pulverized in  a mill to the  consistency of talcum powder (i.e., at least 70 percent
of the particles will pass through a 200 mesh sieve).  The pulverized coal is generally entrained in
primary air before  being fed through burners to the furnace, where it is fired in suspension. Pulverized
coal furnaces are classified as either dry or wet bottom, depending on the ash removal technique. Dry
bottom furnaces fire coals with high ash fusion temperatures and use dry ash removal techniques. In
wet bottom (or slag tap) furnaces, coals with low ash fusion temperatures are combusted and molten
ash is drained  from the bottom of the furnace.  Pulverized coal furnaces are further classified by the
firing position of the burners, i.e., single (front or rear) wall, horizontally opposed, vertical, tangential
(or corner-fired). Wall-fired boilers can be either single wall-fired (with burners on only  one wall of
the furnace firing horizontally) or opposed wall-fired (with burners mounted on two opposing walls).
Tangentially-fired boilers have burners mounted in the corners of the furnace.  The fuel and air are
injected toward the center of the furnace to create a vortex that enhances air and fuel mixing.

       Cyclone furnaces bum low ash  fusion temperature coal which has been crushed to below 4
mesh particle size. The coal is fed tangentially in a stream of primary air to a horizontal cylindrical
furnace.  Within the furnace, small coal particles are burned in suspension while larger particles are
forced against  the outer wall. Because  of the high temperatures  developed in the relatively small
furnace volume, and because of the low fusion temperature of the coal ash, much of the ash forms  a
liquid slag on  the furnace walls. The slag drains from,the  walls to the bottom of the furnace where it
is removed through a slag tap opening.  Cyclone furnaces are used mostly in utility and large
industrial  applications.

       In spreader stokers, a flipping mechanism throws the coal into the furnace and onto a moving
fuel bed.  Combustion occurs partly in suspension and partly on the grate.  Because of significant
carbon content in the paniculate, fly ash reinjection from mechanical collectors is commonly employed
to improve boiler efficiency.  Ash residue from the fuel bed is deposited in a receiving pit at the end
of the grate.

       In overfeed stokers, coal is fed  onto a traveling or vibrating grate and burns on the fuel bed as
it progresses through the furnace.  Ash  particles fall into an ash pit at the rear of the stoker.  The term
"overfeed" applies because ttie coal is fed onto the moving grate under an adjustable gate. Conversely,


7/93                              External Combustion Sources                             1.1-1

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 in "underfeed" stokers, coal is fed into the firing zone from below by mechanical rams or screw
 conveyors.  The coal moves in a channel, known as a retort, from which it is forced upward, spilling
 over the top of each side to form and to feed the fuel bed.  Combustion is completed by the time the
 bed reaches the side dump grates, from which the ash is discharged into shallow pits. Underfeed
 stokers include single retort units and multiple retort units, the latter having several retorts side by
 side.

        Small hand-fired boilers and furnaces are sometimes found in small industrial, commercial,
 institutional, or residential applications.  In most hand-fired units, the fuel is primarily burned in layers
 on the bottom of the furnace or on a grate. From an emissions standpoint, hand-fired units generally
 have higher carbon monoxide (CO) and volatile organic compounds (VOC)  emissions than larger
 boilers because of then- lower combustion efficiencies.

        In a fluidized bed combustor (FBC), the coal is introduced to a bed  of either sorbent
 (limestone or dolomite) or inert material (usually sand) which is fluidized by an upward flow of air.
 Most of the combustion occurs within the bed, but some smaller particles burn  above the bed in the
 "freeboard"  space.  The two principal types of atmospheric FBC boilers are  bubbling bed and
 circulating bed. The fundamental distinguishing feature between these types is  the fluidization
 velocity.  In the bubbling bed design, the fluidization velocity is relatively low, ranging between 1.5
 and 4 m/sec (5 and 12 ft/sec), in order to minimize solids carryover or elutriation from the combustor.
 Circulating FBCs, however, employ fluidization velocities as high as 9 m/sec (30 ft/sec) to promote
 the carryover or circulation of solids.  High temperature cyclones are used in circulating FBCs and in
 some bubbling FBCs to capture the solid fuel and bed material for return to the primary combustion
 chamber.  The  circulating FBC maintains a continuous, high-volume recycle rate which increases the
 fuel residence time compared to the bubbling bed design. Because of this feature, circulating FBCs
 often achieve higher combustion efficiency and better sorbent utilization than bubbling bed units.3

 1.1.2 Emissions and Controls

       The major pollutants of concern from bituminous and subbituminous coal combustion are
 paniculate matter (PM), sulfur oxides (SOJ, and nitrogen oxides (NOJ. Emissions from coal
 combustion depend on the rank and composition of the fuel, the type and size of the boiler, firing
 conditions, load, type of control technologies, and the level of equipment maintenance.  Some unbumt
 combustibles, including numerous organic compounds and CO, are generally emitted even under
 proper boiler operating conditions.  Emission factors for major and minor pollutants are given in
 Tables 1.1-1 through 1.1-14.

       Particulate Matter2"5 - Paniculate matter composition and emission levels are a complex
 function of firing configuration, boiler operation, and coal properties.  In pulverized coal systems,
 combustion is almost complete, and thus emitted particulate is largely comprised of inorganic ash
 residues.  In wet bottom pulverized coal units and  cyclones, the quantity of ash leaving the boiler is
 lower than in dry bottom units, because some of the ash liquifies, collects  on the furnace walls, and
 drains from the furnace bottom as molten slag.  Particulate emission limits specified in applicable New
 Source Performance Standards (NSPS) are  summarized in Table 1.1-15.

       Because a mixture of fine and coarse coal particles is fired in spreader stokers, significant
unburnt carbon can be present in the particulate. To improve boiler efficiency,  fly ash from collection
devices (typically multiple cyclones) is sometimes  reinjected into spreader stoker furnaces. This
practice can dramatically increase the particulate loading at the boiler outlet  and, to a lesser extent,  at
the mechanical  collector outlet. Fly ash can also be reinjected from the boiler, air heater, and
economizer dust hoppers. Fly ash reinjection from these hoppers increases particulate loadings less


 1.1-2                               EMISSION FACTORS                                7/93

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than from multiple cyclones.

       Uncontrolled overfeed and underfeed stokers emit considerably less particulate than do
pulverized coal units and spreader stokers, since combustion takes place in a relatively quiescent fuel
bed. Fly ash reinjection is not practiced in these kinds of stokers.

       Variables other than firing configuration and fly ash reinjection can affect PM emissions from
stokers. Particulate loadings will often increase as load increases (especially as full load is
approached) and with sudden load changes.  Similarly, particulate can increase as the coal ash and
"fines" contents increase.  Fines,  in this context, are coal particles smaller than about 1.6 millimeters
(1/16 inch) in diameter. Conversely, particulate can be reduced significantly when overfire air
pressures are increased.

       FBCs may tax conventional particulate control systems. The particulate mass concentration
exiting FBCs is typically 2 to 4 times higher than that from pulverized coal boilers13. Fluidized bed
combustor particles are also, on average, smaller in size, irregularly shaped, and have higher surface
area and porosity relative to pulverized coal  ashes. Fluidized bed combustion ash is more difficult to
collect in electrostatic precipitators (ESPs) than pulverized coal ash because FBC ash has a higher
electrical resistivity.  In addition, the use of multiclones for fly ash recycling, inherent with FBC
processes, tends to reduce flue gas stream particulate size13.

       The primary kinds of PM control devices used for coal combustion include multiple cyclones,
ESPs, fabric filters (or baghouses), and scrubbers.  Some measure of control  will even result from fly
ash settling in boiler/air heater/economizer dust hoppers, large breeching, and chimney bases. The
effects of such settling are reflected in current emission factors.

       ESPs are the most common high-efficiency PM control device used on pulverized coal and
cyclone units; they are also being used increasingly on stokers.  Generally, ESP collection efficiencies
are a function of collection plate area per unit volumetric flow rate of flue gas through the device.
Particulate control efficiencies of 99.9 percent or above are obtainable with ESPs.  Electrostatic
precipitators located downstream of air preheaters (i.e., cold side precipitators) operate at significantly
reduced efficiencies when low sulfur coal is  fired.  Fabric filters have recently seen increased use in
both utility and industrial applications, generally achieving at least 99.8 percent efficiency.  An
advantage of fabric filters is that they are unaffected by the high fly ash resistivities associated with
low sulfur coals.  Scrubbers are also used to control particulate, although their primary use is to
control sulfur oxides.  One drawback of scrubbers is the high energy usage required to achieve control
efficiencies comparable to those  for ESPs and baghouses2.

       Mechanical collectors, generally multiple cyclones, are the primary means of PM control on
many stokers. They are sometimes installed upstream of high-efficiency control devices in order to
reduce the ash collection burden on these devices.  Cyclones are also an integral part of most FBC
designs.  Depending on application and design, multiple cyclone efficiencies  can vary widely.  Where
cyclone design flow rates are not attained (which is common with underfeed  and overfeed stokers),
these devices may be only marginally effective and may prove little  better hi reducing particulate than
a large breeching.  Conversely, well-designed multiple cyclones, operating at the required flow rates,
can achieve collection efficiencies on spreader stokers  and overfeed stokers of 90 to 95  percent.  Even
higher collection efficiencies are obtainable on spreader stokers with reinjected fly ash because of the
larger particle sizes and increased particulate loading reaching the controls5"6.

       Sulfur Oxides7"9 - Gaseous sulfur oxides (SOJ from coal combustion are primarily sulfur
dioxide (SO2), with a much lower quantity of sulfur trioxide (SO3) and gaseous sulfates. These


7/93                              External Combustion Sources                             1.1-3

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compounds fonn as the organic and pyritic sulfur in the coal is oxidized during the combustion
process. On average, about 95 percent of the sulfur present in bituminous coal will be emitted as
gaseous SOX, whereas somewhat less will be emitted when subbituminous coal is fired.  The more
alkaline nature of the ash in some subbituminous coals causes some of the sulfur to react in the
furnace to form various sulfate salts that are retained in the boiler or in the flyash.  In general, boiler
size, firing configuration and boiler operations have little effect on the percent conversion of fuel
sulfur to SOX. Sulfur dioxide emission limits specified in applicable NSPS are summarized in Table
1.1-15.

        Several techniques are used to reduce SOX emissions from coal combustion.  One way is to
switch to lower sulfur coals, since SOX emissions are proportional to the sulfur content of the coal..
This alternative may not be possible where lower sulfur coal is  not readily available or where a
different grade of coal cannot be satisfactorily fired. In some cases, various coal cleaning processes
may be employed to reduce the fuel sulfur content. Physical coal cleaning removes mineral sulfur
such as pyrite but is not effective in removing organic sulfur. Chemical cleaning and solvent refining
processes are being developed to remove organic sulfur.

        Many flue gas desulfurization (FGD) techniques can remove SO2 formed during combustion.
Flue gases  can be treated using wet, dry, or semi-dry desulfurization processes of either the throwaway
type (in which all waste streams are discarded) or the recovery/regenerable type  (in which the SO2
absorbent is regenerated and reused).  To date, wet systems are the most commonly applied.  Wet
systems generally use alkali slurries as the SO2 absorbent medium and can be designed to remove
greater than 90 percent of the incoming SO2.  Paniculate reduction of up to 99 percent is also possible
with wet scrubbers, but fly ash is often collected by upstream ESPs or baghouses, to avoid erosion of
the desulfurization equipment and possible interference with FGD process reactions7. Also, the
volume of scrubber sludge is reduced with separate fly ash removal and contamination of the  reagents
and byproducts is prevented.   Lime/limestone scrubbers, sodium scrubbers, and dual alkali scrubbing
are among the commercially proven wet FGD systems.  The effectiveness of these devices depends not
only on control device design but also operating variables.  A summary table of commercial post-
combustion SO2 controls is provided in Table 1.1-16.

        A number of dry and wet sorbent injection technologies are under development to capture SO2
in the furnace, the heat transfer sections, or ductwork downstream of the boiler.  These technologies
are generally designed for retrofit applications and are well-suited for coal combustion sources
requiring moderate SO2 reduction and which have a short remaining life.

        Nitrogen Oxides10"11 - Nitrogen oxides (NOX) emissions from coal combustion are primarily
nitrogen oxide (NO), with only a few volume percent as nitrogen dioxide (NOz).  Nitrous oxide (N2O)
is also emitted at ppm levels.  Nitrogen oxides formation results from thermal fixation of atmospheric
nitrogen in the combustion flame and from oxidation of nitrogen bound in the coal. Experimental
measurements of thermal NOX formation have shown that the NOX concentration is exponentially
dependent on temperature and is proportional to N2 concentration in the flame, the square root of
oxygen  (O^ concentration in the flame,  and the gas residence time22.  Typically, only 20 to  60 percent
of the fuel nitrogen is converted to NOX. Bituminous and subbituminous  coals usually contain from
0.5 to 2 weight percent nitrogen, mainly present in aromatic ring structures.  Fuel nitrogen can account
for up to 80 percent of total NOX from coal combustion. Nitrogen oxide emission limits in applicable
NSPS are summarized in Table 1.1-15.

       A number of combustion modifications have been used to reduce  NOX emissions from boilers.
A summary of currently utilized NOX control technology for stokers is  given in Table 1.1-17.  Low
excess air (LEA) firing is the most widespread combustion modification, because it can be practiced in


1.1-4                                EMISSION FACTORS                                7/93

-------
both old and new units and in all sizes of boilers,  Low excess air firing is easy to implement and has
the added advantage of increasing fuel use efficiency. Low excess air firing is generally effective only
above 20 percent excess air for pulverized coal units and above 30 percent excess air for stokers.
Below these levels, the NOX reduction from decreased O2 availability is offset by increased NOX
production due to higher flame temperatures.  Another NOX reduction technique is simply to switch to
a coal having a lower nitrogen content, although many boilers may not properly fire coals with
different properties.

       Off-stoichiometric (or staged)  combustion is also an effective means of controlling NOX
emissions from coal-fired equipment  This can be achieved by using overfire air or low-NOx burners
designed  to stage combustion in the flame /one. Other NOX reduction techniques include flue gas
recirculation, load reduction, and steam or water injection.  However, these techniques are not very
effective  for use on coal-fired equipment because of the fuel nitrogen effect. Ammonia injection is a
post-combustion technique which can  also be used, but it is costly relative to other methods.  For
cyclone boilers, the use of natural gas reburning for NOX emission control is under investigation on a
full-scale utility boiler.33  The net reduction of NOX from any of these techniques or combinations
thereof varies considerably with boiler type, coal properties, and boiler operating practices. Typical
reductions will range from  10 to 60 percent References 10 and 27 may be consulted for detailed
discussion of each of these NOX reduction techniques. To date, flue gas treatment has not been used
commercially to reduce NOX emissions from coal-fifed boilers because of its higher relative cost

       Carbon Monoxide - The rate of CO emissions from combustion sources depends on the fuel
oxidation efficiency of the source.  By controlling the combustion process carefully, CO emissions can
be minimized. Thus, if a unit is operated improperly or not well maintained, the resulting
concentrations of CO (as well as organic compounds) may increase by several orders of magnitude.
Smaller boilers, heaters, and furnaces ten to emit more CO and organics than larger combustors.  This
is because smaller units usually have less high-temperature residence time and, therefore, less time to
achieve complete combustion than  larger combustors. Various combustion modification techniques
used to reduce NOX can produce increased CO emissions.

       Organic Compounds - Small amounts  of organic compounds are emitted from coal
combustion. As with CO emissions, the rate at which organic compounds are emitted depends on the
combustion efficiency  of the boiler. Therefore, any combustion modification which reduces the
combustion efficiency  will most likely increase the concentrations of organic compounds in the flue
gases.

       Total organic compounds (TOC) include volatile organic compounds (VOCs), semi-volatile
organic compounds, and condensible organic compounds.  Emissions of VOCs are primarily
characterized by the criteria pollutant class of unburned vapor-phase hydrocarbons. Unburned
hydrocarbon emissions can include essentially all vapor phase organic compounds emitted from a
combustion source.  These are primarily emissions of aliphatic, oxygenated, and low molecular weight
aromatic  compounds which exist in the vapor phase at flue gas temperatures. These emissions include
alkanes, alkenes, aldehydes, carboxylic acids, and substituted benzenes (e.g., benzene, toluene, xylene,
and ethyl benzene.)17-18.

       The remaining organic emissions are composed largely of compounds emitted from
combustion sources in a condensed phase. These compounds can almost exclusively be classed  into a
group known as polycyclic organic matter (POM), and a subset of compounds called polynuclear
aromatic  hydrocarbons (PNA or PAH). There are also PAH-nitrogen analogs.  Polycyclic organic
matter can be especially prevalent  in the emissions from coal combustion, because a large fraction of
the volatile matter in coal exits as  POM19.
7/93                             External Combustion Sources                             1.1-5

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        Formaldehyde is formed and emitted during combustion of hydrocarbon-based fuels such as
 coal. Formaldehyde is present in the vapor phase of the flue gas.  Formaldehyde is subject to
 oxidation and decomposition at the high temperatures encountered during combustion Thus, larger
 units with efficient combustion (resulting from closely regulated air-fuel ratios, uniformly high
 combustion chamber temperatures, and relatively long gas residence times) have lower formaldehyde
 emission rates than do smaller, less efficient combustion units20-21.

        Trace elements - Trace elements are also emitted from the combustion of coal. For this update
 of AP-41, trace metals included in the list of 189 hazardous air pollutants under Title III  od the 1990
 Clean Air Act Amendments23 were considered.  The quantity of trace metals depends on  combustion
 temperature, fuel feed mechanism, and the composition of the fuel. The temperature determines the
 degree of volatilization of specific trace elements contained in the fuel. The fuel feed mechanism
 affects the partitioning of elements between bottom ash and fly ash. The quantity of any given metal
 emitted, in general, depends on:

               the physical and chemical properties of the element itself;

               its concentration in the fuel;

               the combustion conditions; and

               the type of participate control device used,  and its collection efficiency
               as  a function of particle  size.

        It has become widely recognized that some trace metals become concentrated in certain waste
 particle streams from a combustor (e.g.,  bottom ash, collector ash, and flue gas paniculate)  while
 others do not19.  Various classification schemes have been developed to describe this partitioning
 behavior.24"26  The classification scheme  used by Baig, et al.26 is as follows:

               Class 1: Elements which are approximately equally distributed between
               fly ash and bottom ash, or show little or no small particle enrichment.

               Class 2: Elements which are enriched in fly ash relative to bottom ash,
               or show increasing enrichment with decreasing particle size.

               Class 3: Elements which are intermediate between Class 1 and 2.

               Class 4: Elements which are emitted hi the gas phase.

       Fugitive Emissions - Fugitive emissions are defined as pollutants which escape from an
industrial process due to leakage, materials handling, inadequate operational control, transfer or
storage. The fly ash handling operations in most modern utility and industrial combustion sources
consist of pneumatic systems or enclosed and hooded systems which are vented through small fabric
filters or other dust control devices. The fugitive PM emissions from these systems are therefore
minimal. Fugitive paniculate emissions  can sometimes  occur during fly ash transfer operations from
silos to trucks or rail cars.

       Emission factors for SOX, NOX, and CO  are presented in Tables 1.1-1 and 1.1-2, along with
emission factor ratings.  Paniculate matter and PM-10 emission factors and ratings are given in Tables
 1.1-3 and  1.1-4.  Cumulative particle size distribution and paniculate size specific emission  factors are
given in Figures 1.1-1 through 1.1-6 and Tables 1.1-5 through 1.1-10, respectively.  Emission factors


 1.1-6                              EMISSION FACTORS                                7/93

-------
and ratings for speciated organics and N2O are given in Tables 1.1-11 and 1.1-12. Emission factors
and ratings for other non-criteria pollutants and lead are listed in Tables 1.1-13 and 1.1-14.

       In general, the baseline emissions of criteria and non- criteria pollutants are those from
uncontrolled combustion sources. Uncontrolled sources are those without add-on pollution control
(APC) equipment, low-NOx burners, or other modifications designed for emission control.  Baseline
emission for SO2 and PM can also be obtained from measurements taken upstream of APC equipment

       Because of the inherently low NOX emission characteristics of FBCs and the potential for in-
bed SO2 capture by calcium-based sorbents, uncontrolled emission factors for this source category
were not developed in the same sense as with the other source categories. For NOX emissions, the data
collected from test reports were considered to be baseline if no additional add-on NOX control system
(such as ammonia injection) was operated.  For SO2 emissions, a correlation was developed from
reported data on FBCs to relate SO2 emissions to the coal sulfur content and the calcium-to-sulfur ratio
in the bed.
7/93                              External Combustion Sources                             1.1-7

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   TABLE 1.1-1. (ENGLISH UNITS) EMISSION FACTORS FOR SULFUR OXIDES (SOJ.NITROGEN
 OXIDES (NOJ, AND CARBON MONOXIDE (CO) FROM BITUMINOUS AND SUBBITUMINOUS COAL
                                   COMBUSTION8
Rring Configuration
sec
SOX"
Emissio
n Factor
Ib/ton
Rating
NOX'
Emissio
n Factor
Ib/ton
Rating
CO"'4
Emissio
n Factor
Ib/ton
Rating
Pulverized coal fired, dry bottom, wall 101002-02/22 38S A 21.7 A 0.5 A
fired 102002-02/22 (35S)
103002-06/22
Pulverized coal fired, dry bottom,
tangentfally fired

Pulverized coal fired, wet bottom


Cyclone furnace


Spreader stoker


Spreader stoker, with multiple
cyclones, and reinjectSon

Spreader stoker, with multiple
cyclones, no relnjection

Overfeed stoker1


Overfeed stoker, with multiple
cyclones'

Underfeed stoker

Underfeed stoker, with multiple
cyclone
Hand-fed units
FluWlzed bed combustor, circulating
bed

FlukJlzed bed combustor, bubbling
bed

101002-12/26
102002-12/26
103002-16/26
101 002-1 2/21
102002-01/21
103002-05/21
101002-03/23
102002-03/23
103002-23/01
101002-04/24
102002-04/24
103002-09/24
101002-03/24
101002-04/24
103002-09/24
101002-04/24
101002-04/24
103002-09/24
101002-05/25
102002-05/10/25
103002-07/25
101002-05/25
102002-05/10/25
103-002-07/25
102002-06
103002-08
102002-06
103002-08
103002-14
101002-17
102002-17
103002-17
101002-17
102002-17
103002-17
a. Factors represent uncontrolled emissions
coal feed, as fired.
b. Expressed as SO2, inclu

38S
(35S)

38S
(35S)

38S
(35S)

38S
(35S)

388
(35S)

38S
(35S)

38S
(35S)

38S
(35S)

31S

31S

31S
g


g


unless

ding SO2, SO3, and gase
A


D


D


B


B


A


B


B


B

B

D
E


E


otherwise

14.4 A


34.0 C


33.8 C


13.7 A


13.7 A


13.7 A


7.5 A


7.5 A


9.5 A

9.5 A

9.1 E
3.9 E


15.2 D


specified and should

ous sulfates. Factors in parent
0.5 A


0.5 A


0.5 A


5 A


5 A


5 A


6 B


6 B


11 B

11 B

275 E
18 E


18 D


be applied to

heses should
      be used to estimate gaseous SOX emissions for subbituminous coal.  In all cases, S is weight
      % sulfur content of coal as fired.  Emission factor would be calculated by multiplying the weight
1.1-8
EMISSION FACTORS
7/93

-------
       percent sulfur in the coal by the numerical value preceding S. On average for bituminous coal,
       95% of fuel sulfur is emitted as SO2, and only about 0.7% of fuel sulfur is emitted as SO3 and
       gaseous sulfate. An equally small percent of fuel sulfur is emitted as particulate sulfate
       (References 9,13). Small quantities of sulfur are also retained in bottom ash. With
       subbituminous coal, about 10% more fuel sulfur is retained in the bottom ash and particulate
       because of the more alkaline nature of the coal ash.  Conversion to gaseous sulfate appears
       about the same as for bituminous coal.
c.     Expressed as NO2.  Generally, 95+ volume % of nitrogen oxides present in combustion exhaust
       will be in the form of NO, the rest NO2 (Reference 11).  To express factors as NO, multiply
       factors by 0.66.  All factors represent emission at baseline operation (i.e., 60 to 110% load and
       no NOX control  measures).
d.     Nominal values achievable under normal operating conditions.  Values are one or two orders of
       magnitude higher can occur when combustion is not complete.
e.     Emission factors for CO2 emissions from coal combustion should be calculated using COJton
       coal = 73.3C, where C is the weight percent carbon content of the coal.
f.      Includes traveling grate, vibrating grate and chain grate stokers.
g.     Sulfur dioxide emission factors for fluidized bed combustion are a function of fuel sulfur content
       and calcium-to-sulfur ratio.  For both bubbling bed and circulating bed design, use: Ib SO/ton
       coal = 39.6(S)(Ca/S)"1'9.  In this equation, S is the weight percent sulfur in the fuel and Ca/S is
       the molar calcium-to-sulfur ratio in the bed. This equation may be used when the Ca/S is
       between 1.5 and 7. When no calcium-based sorbents are used and the bed material is inert
       with respect to sulfur capture, the emission factor for underfeed stokers should be used to
       estimate the  FBC SO2 emissions. In this case,  the emission factor ratings are E for both
       bubbling and circulating units.
SCC = Source classification code.
7/93                              External Combustion Sources                              1.1-9

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   TABLE 1.1-2. (METRIC UNITS) EMISSION FACTORS FOR SULFUR OXIDES (SOJ.NITROGEN
 OXIDES (NOJ, AND CARBON MONOXIDE (CO) FROM BITUMINOUS AND SUBBITUMINOUS COAL
                                  COMBUSTION"
Bring Configuration
sec
SOX"
Emissio
n
Factor
kg/Mg
Rating
NOX
Emlsslo
n
Factor
kg/Mg
Rating
CO**
Emissio
n
Factor
kg/Mg
Rating
Pulverized coal fired, dry bottom, wall 101002-02/22 19S A 10.85 A .25 A
flred 102002-02/22 (17.5S)
103002-06/22
Pulverized coal fired, dry bottom,
tangenHally fired

Pulverized coal fired, wet bottom


Cyclone furnace


Spreader stoker


Spreader stoker, with multiple
cyckmes, and relnJecBon

Spreader stoker, with multiple
cyclones, no reinjecHon

Overfeed stoker*


Overfeed stoker, with multiple
cyclones'

Underfeed stoker

Underfeed stoker, with multiple
cyclone
Hand-fed units
Fluldized bed combustor, circulating
bed

Fiukiized bed combustor, bubbling
bed

101002-12/26
102002-12/26
103002-16/26
101002-12/21
102002-01/21
103002-05/21
101002-03/23
102002-03/23
103002-23/01
101002-04/24
102002-04/24
103002-09/24
101002-03/24
101002-04/24
103002-09/24
101002-04/24
101002-04/24
103002-09/24
101002-05/25
102002-05/10/25
103002-07/25
101002-05/25
102002-05/10/25
103-002/07/25
102002-06
103002-08
102002-06
103002-08
103002-14
101002-17
102002-17
103002-17
101002-17
102002-17
103002-17
a. Factors represent uncontrolled emissions
coal feed, as fired.
b. Expressed as SO2, inclu

19S
(17.5S)

19S
(17.5S)

19S
(17.5S)

19S
(17.5S)

19S
(17.5S)

19S
(17.5S)

19S
(17.5S)

19S
(17.5S)

15.5S

15.5S

15.5S
g


g


A


D


D


B


B


A


B


B


B

B

D
E


E


unless otherwise

ding SO2, SO3, and gaseou

7.2 A


17 C


16.9 C


6.85 A


6.85 A


6.85 A


3.75 A


3.75 A


4.75 A

4.75 A

4.55 E
1.95 E


7.6 D


specified and should

is sulfates. Factors in parent
.25 A


.25 A


.25 A


2.5 A


2.5 A


2.5 A


3 B


3 B


5.5 B

5.5 B

137.5 E
9 E


9 D


be applied to

heses should
      be used to estimate gaseous SOX emissions for subbituminous coal. In all cases, S is weight
1.1-10
EMISSION FACTORS
7/93

-------
       % sulfur content of coal as fired. Emission factor would be calculated by multiplying the weight
       percent sulfur in the coal by the numerical value preceding S. On average for bituminous coal,
       95% of fuel sulfur is emitted as SO2, and only about 0.7% of fuel sulfur is emitted as SO3 and
       gaseous sulfate. An equally small percent of fuel sulfur is emitted as particulate sulfate
       (References 9,13).  Small quantities of sulfur are also retained in bottom ash. With
       subbituminous coal, about 10%  more fuel sulfur is retained in the bottom ash and particulate
       because of the  more alkaline nature of the coal ash.  Conversion to gaseous sulfate appears
       about the same as for bituminous coal.
c.     Expressed as NO2.  Generally, 95+ volume % of nitrogen oxides present in combustion exhaust
       will be in the form of NO, the rest NO2 (Reference 11).  To express factors as NO, multiply
       factors by 0.66.  All factors represent emission at baseline operation  (i.e., 60 to  110% load and
       no NOX control measures).
d.     Nominal values achievable under normal operating conditions.  Values are one or two orders of
       magnitude higher can occur when combustion is not complete.
e.     Emission factors for CO2 emissions from coal combustion should be calculated using CO^Mg
       coal = 36.7C, where C  is the weight percent carbon content of the coal.
f.      Includes traveling grate, vibrating grate and chain grate stokers.
g.     Sulfur dioxide emission factors for fluidized bed combustion are a function of fuel sulfur content
       and calcium-to-sulfur ratio. For both bubbling bed and circulating bed design, use: kg SOg/Mg
       coal = 19.8(S)(Ca/S)~19. In this equation, S is the weight percent sulfur in the fuel and Ca/S is
       the molar calcium-to-sulfur ratio in the bed. This equation may be used when the Ca/S is
       between 1.5 and 7.  When no calcium-based sorbents are  used and  the bed material is inert
       with respect to sulfur capture, the emission factor for underfeed stokers should be used to
       estimate the  FBC SO2 emissions. In this case, the emission factor ratings are E for both
       bubbling and circulating units.
SCC = Source classification code.
7/93                              External Combustion Sources                            1.1-11

-------
 TABLE 1.1-3. (ENGLISH UNITS) EMISSION FACTORS FOR PARTICULATE MATTER (PM) AND PM
      LESS THAN 10 MICRONS (PM-10) FROM BITUMINOUS AND SUBBITUMINOUS COAL
                                  COMBUSTION3
Firing Configuration
Pulverized coal fired, dry bottom, wall fired
Pulverized coal fired, dry bottom, tangentially fired
Pulverized coal fired, wet bottom
Cyclone furnace
Spreader stoker
Spreader stoker, with multiple cyclones, and
relnJecUon
Spreader stoker, with multiple cyclones, no reinjection
Overfeed stoker*
Overfeed stoker, with multiple cyclones'
Underfeed stoker
Underfeed stoker, with multiple cyclone
Hand-fed units
Fluldlzed bed combustor, bubbling bed
Flutdlzed bed combustor, circulating bed
sec
101002-02/22
102002-02/22
103002-06/22
101002-12/26
102002-12/26
103002-16/26
101002-12/21
102002-01/21
103002-05/21
101002-03/23
102002-03/23
103002-23/01
101002-04/24
102002-04/24
103002-09/24
101002-03/24
101002-04/24
103002-09/24
101002-04/24
101002-04/24
103002-09/24
101002-05/25
102002-05/10/25
103002-07/25
101002-05/25
102002-05/10/25
103002-07/25
102002-06
103002-08
102002-06
103002-08
103002-14
101002-17
102002-17
103002-17
101002-17
102002-17
103002-17
Filterable PM"
Emission
Factor
Ib/ton Rati
10A A
10A B
7A" D
2A" E
66' B
17 B
12 A
16" C
16" C
15' D
11" D
15 E
12 E
17 E
PM-10
Emission
Factor
ig Ib/ton
2.3A
2.3AC
2.6A
0.26A
13.2
12.4
7.8
6.0
5.0
6.2
6.21
6.21
13.2"
13.2
Rating
E
E
E
E
E
E
E
E
E
E
E
E
E
E
a. Factors represent uncontrolled emissions unless otherwise specified and should be applied to
coal feed, as fired.
b. Based on EPA Method 5 (front half catch) as described in Reference 28. Where particulate is
      expressed in terms of coal ash content, A, factor is determined by multiplying weight % ash
      content of coal (as fired) by the numerical value preceding the A.  For example, if coal with 8%
1.1-12
EMISSION FACTORS
7/93

-------
        ash is fired in a pulverized coal fired, dry bottom unit, the PM emission factor would be 10 x 8,
        or 80 Ib/ton.  The "condensible" matter collected in back half catch of EPA Method 5 averages
        <5% of front half, or "filterable", catch for pulverized coal and cyclone furnaces; 10% for
        spreader stokers; 15% for other stokers; and 50% for handfired units (References 6, 29, 30).
 c.      No data found; use assume emission factor for pulverized coal-fired dry bottom boilers.
 d.      Uncontrolled particulate emissions, when no fly ash reinjection is employed.  When control
        device is installed, and collected fly ash is reinjected to boiler, particulate from boiler reaching
        control equipment can increase up to a factor of two.
 e.      Accounts for fly ash settling in an economizer, air heater or breaching upstream of control
        device or stack.  (Particulate directly at boiler outlet typically will be twice this level.)  Factor
        should be applied even when fly ash is reinjected to  boiler from air heater or economizer dust
        hoppers.
 f.      Includes traveling grate, vibrating grate and  chain grate stokers.
 g.      Accounts for fly ash settling in breaching or  stack base.   Particulate loadings directly at boiler
        outlet typically can be 50% higher.
 h.      See Reference 34 for discussion of apparently low multiple cyclone control efficiencies,
        regarding uncontrolled emissions.
 i.      Accounts for fly ash settling in breaching downstream of boiler outlet.
 j.      No data found; use emission factor for underfeed stoker.
 k.      No data found; use emissjon factor for spreader stoker.
 SCC = Source classification code'.
7/93                               External Combustion Sources                             1.1-13

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TABLE 1.1-4. (METRIC UNITS) EMISSION FACTORS FOR PARTICULATE MATTER (PM) AND PM
      LESS THAN 10 MICRONS (PM-10) FROM BITUMINOUS AND SUBBITUMINOUS COAL
                                  COMBUSTION8
Bring Configuration
Pulverized coal fired, dry bottom, wall fired
Pulverized coal fired, dry bottom, tangentially fired
Pulverized coal fired, wet bottom
Cyclone furnace
Spreader stoker
Spreader stoker, with multiple cyclones, and
rejection
Spreader stoker, with multiple cyclones, no reinjection
Overfeed stoker*
Overfeed stoker, with multiple cyclones'
Underfeed stoker
Underfeed stoker, with multiple cyclone
Hand-fed units
FIuHized bed combustor, bubbling bed
FluWlzed bed combustor, circulating bed
sec
101002-02/22
102002-02/22
103002-06/22
101 002-12/26
102002-12/26
103002-16/26
101002-12/21
102002-01/21
103002-05/21
101002-03/23
102002-03/23
103002-23/01
101002-04/24
102002-04/24
103002-09/24
101002-03/24
101002-04/24
103002-09/24
101002-04/24
101002-04/24
103002-09/24
101002-05/25
102002-05/10/25
103002-07/25
101002-05/25
102002-05/10/25
103-002-07/25
102002-06
103002-08
102002-06
103002-08
103002-14
101002-17
102002-17
103002-17
101002-17
102002-17
103002-17
Filterable PM"
Emission
Factor
kg/Mg Rating
5A A
5A B
3.5A" D
1A" E
33" B
8.5 B
6 A
8" C
4.5" C
7.51 D
5.5" D
7.5 E
6 E
8.5 E
PM-10
Emission
Factor
kg/Mg Rating
1.15A E
1.15A0 E
1.3A E
0.13A E
6.6 E
6.6 E
3.9 E
3.0 E
2.5 E
3.1 E
3.1' E
3.1" E
6.6" E
6.6 E
a. Factors represent uncontrolled emissions unless otherwise specified and should be applied to
coal feed, as fired.
b. Based on EPA Method 5 (front half catch) as described in Reference 28. Where particulate is
      expressed in terms of coal ash content, A, factor is determined by multiplying weight % ash
      content of coal (as fired) by the numerical value preceding the A.  For example, if coal with 8%
1.1-14
EMISSION FACTORS
7/93

-------
        ash is fired in a pulverized coal fired, dry bottom unit, the PM emission factor would be 5 x 8, or
        40  kg/Mg.  The "condensible" matter collected in back half catch of EPA Method 5 averages
        <5% of front  half, or "filterable", catch for pulverized coal and cyclone furnaces;  10% for
        spreader stokers; 15% for other stokers; and 50% for handfired units (References 6, 29,  30).
 c.      No data found; use assume emission factor for pulverized coal-fired dry bottom boilers.
 d.      Uncontrolled  paniculate emissions, when no fly ash reinjection is employed.  When control
        device is installed, and collected fly ash is reinjected to boiler, particulate from boiler reaching
        control equipment can increase up to a factor of two.
 e.      Accounts for  fly ash settling in an economizer, air heater or breaching  upstream of control
        device or stack. (Particulate directly at boiler outlet typically will be twice this level.) Factor
        should be applied even when fly ash is reinjected to boiler from air heater or economizer dust
        hoppers.
 f.      Includes traveling grate, vibrating grate and chain grate stokers.
 g.      Accounts for  fly ash settling in breaching or stack base.  Particulate loadings directly at boiler
        outlet typically can be 50% higher.
 h.      See Reference 34 for discussion of apparently low multiple cyclone control efficiencies,
        regarding uncontrolled emissions.
 i.      Accounts for  fly ash settling in breaching downstream of boiler outlet.
 j.      No  data found; use emission factor for underfeed stoker.
 k.      No  data found; use emission factor for spreader stoker.
 SCO = Source classification code.
7/93                               External Combustion Sources                             1.1-15

-------
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1.1-16
                                EMISSION FACTORS
                                                                              7/93

-------
          s
 2.0A
 1.8A
 1.6A
 1.4A
 1.2A
 l.QA
 0.8A
 0.6A
0.4A
0.2A
0
                                         Scrubber
                                 ESP
                           -I	1  I  It
                                                                   lUghouse
                                                          Uncontrolled
                                                         Multiple cyclone
                   .6   1     2     4    6  10
                          Particle dianeter (us)
                                                                                     l.OA
                                                                                     0.6A 1?
                                                                                          * k
                                                                                     0.4A 7
      iS   -
                                                                                     O.ZA  5
                                                                                          o. o
0.06A ,.
     o 
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                                                                    20
                                                                          40  60  100
                                                                                     0.01A      I
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 G.04A   *
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 0.01A  2J1
       -s
       ; u
0.006A  "
0.004A  SS
               0.002A I
                                                                                   0.001A
                                                                                         
     Figure 1.1-1. Cumulative size specific emission factors for dry bottom boilers burning pulverized
                                              bituminous coal.
               3.SA
                                                                                                 O.IA

                                                                                                 0.06A
                                                                                                      k.
                                                                                                      O
                                                                                                 0.04A ^_
                                                                                                 0.02A  u
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                                                                                                      E S
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                          .2
                                .4  .6   1
                                              246      10
                                           Particle diameter (inn)
                                                  20    40  60  100
                                                                                                0.002A
                                                                                                 O.U01A
Figure 1.1-2.  Cumulative specific emission factors for wet bottom boilers burning pulverized bituminous
                                                   coal.
7/93
                      External Combustion Sources
                1.1-17

-------
   TABLE 1.1-6.  CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
      FACTORS FOR WET BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS COAL8
                                  (Emission Factor Rating: E)
ParBcIe Size*
(jun)
Cumulative Mass % <_ stated size
Uncontrolled
Controlled
Multiple
cyclones
ESP
Cumulative Emission Factor0 [kg/Mg (Ib/ton) coal, as fired]
Uncontrolled
Controlled11
Multiple cyclones
ESP
     15
40
                              99
                      83
                    1.4A(2.8A)
               0.69A (1.38A)     0.023A (0.46A)
     10
37
                              93
                                        75
                    1.30A(2.6A)
               0.65A (1.3A)      0.021 A (0.42A)
                  33
            84
                                        63
                   1.16A(2.32A)
               0.59A (1.18A)     0.018A (0.36A)
     2.6
21
                              61
                                        40
                   0.74A(1.48A)
               0.43A (0.86A)     0.011A (0.022A)
     1.25
                              31
                                        17
                               0.21A (0.42A)
                                   0.22A (0.44A)     0.005A (0.01A)
     1.00
                               19
                               0.14A (0.28A)
                                   0.13A (0.26A)     0.002A (0.004A)
    0.625
                               0.07A (0.14A)
    TOTAL
100
100
                                        100
3.5A (7.0A)
0.7A (1.4A)
0.028A (0.056A)
a.     Reference 32. Applicable SCCs are 101002-12/21,102002-01/21, and 103002-05/21.
b.     Expressed as aerodynamic equivalent diameter.
c.     A = coal ash weight %, as fired.
d.     Estimated control efficiency for multiple cyclones is 94%; and for ESP, 99.2%.
e.     Insufficient data.
ESP 3 Electrostatic precip'rtator.
SCC B Source classification code.
1.1-18
                  EMISSION FACTORS
                                                           7/93

-------
 TABLE 1.1-7. CUMULATIVE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS FOR
                      CYCLONE FURNACES BURNING BITUMINOUS COAL"
                                   (Emission Factor Rating:  E)
Particle Size"
(urn)
Cumulative Mass %  stated size
Uncontrolled
Controlled
Multiple
cyclone
s
ESP
Cumulative Emission Factor0 [kg/Mg (Ib/ton) coal, as fired]

Uncontrolled
Controlled" ;
. Multiple cyclones
ESP
      15
                  33
                             95
                                      90
                             0.33A (0.66A)
                                                               0.057A (0.114A)    0.0064A (0.013A)
      10
                   13
           94       68       0.13A(0.26A)      0.056A (0.112A)     00054A (0.011 A)
                             93       56       0.08A(0.16A)      0.056A (0.112A)    0.0045A (0.009A)
     2.5
                             92       36           0           0.055A(0.11A)     0.0029A (0.006A)
     1.25
                             85
                                      22
                                                               0.051A (0.10A)     0.0018A (0.004A)
     1.00
                             82
                                      17
                                             0.049A (0.10A)     0.0014A (0.003A)
    0.625
    TOTAL
100
                             100
                   100
1A(2A)
0.06A (0.12A)
0.008A (0.016A)
a.      Reference 32. Applicable SCCs are 101002-03/23,102002-03/23, and 103002-23/01.
b.      Expressed as aerodynamic equivalent diameter.
c.      A = coal ash weight %, as fired.                              -
d.      Insufficient data.
e.      Estimated control efficiency for multiple cyclones is 94%; and for ESP, 99.2%.
ESP = Electrostatic precipitator.
SCC = Source classification code.
7/93
                External Combustion Sources
                                       1.1-19

-------
               E .
               ss
               ^ u
I.OA
0.9A
C.SA
0.7A
0.6A
O.SA
0.4A
0.3A
0.2A
0.1A
0
                        .1    .2    .4  .6   1     2      46    10
                                                Particle diameter (urn)
      0.10A
             u
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             c
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      0.04A   g,
      0.02A   *.
            o 
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      0.004A ^.
                                                                       Uncontrolled
                                                                           i   i t i i  i
      0.002A
      O.OOIA
                                                                                             i
                                                                       20
                                                                             40 60  100
  Figure 1.1-3.  Cumulative size specific emission factors for cyclone furnaces burning bituminous coal.
              10
               9
               G
               7
               6
               S
               4

               3
               2
               1
               0
            Multiple cyclone with
            flyash rcinjection
   Multiple cyclone without
   flyash reinjecfion
                         t   I   t  t I
                                           Baghouse
                                         Uncontrolled
                                              tSP
                                                                     i   i i  t i  i i
                  .1
          .4  .6   1     2     4   6    10
                     Particle diameter (urn)
                                                                       40  60  100
10.0
 6.C    -
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     * 2
 4.0  -i
     o **
      ; >"
 2.0

 1.0
 0.6
 0.4

 0.2  "Z*
     Z E
       01
 0.1
0.10
 0.06
 U.04

 0.02

 0.01
 0.006
 0.004

 0.002

 0.001
   Figure 1.1-4.  Cumulative size specific emission factors for spreader stokers burning bituminous coal.
1.1-20
                     EMISSION FACTORS
                      7/93

-------
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7/93
External Combustion Sources
1.1-21

-------
   TABLE 1.1-9. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
            FACTORS FOR OVERFEED STOKERS BURNING BITUMINOUS COAL3
Particle
Size"
(urn)
Cumulative Mass % < stated size
Uncontrolled
Multiple Cyclones
Controlled
Cumulative Emission Factor0 [kg/Mg (Ib/ton) coal, as fired]
Uncontrolled
Factor
Rating
Multiple Cyclones Controlled"
Factor
Rating
15
10
6
2.5
1.25
1.00
0.625
TOTAL
49
37
24
14
13
12
c
100
60
55
49
43
39
39
16
100
3.9 (7.8)
3.0 (6.0)
1.9(3.8)
1.1 (2.2)
1.0(2.0)
1.0(2.0)
C
8.0 (16.0)
C
C
C
C
C
C
C
C
2.7 (5.4)
2.5 (5.0)
2.2 (4.4)
1.9(3.8)
1.8(3.6)
1.8(3.6)
0.7(1.4)
4.5 (9.0)
E
E
E
E
E
E
E
E
a.      Reference 32. Applicable SCCs are 1001002-05/25, 102002-05/10/25, and 103002-07/25.
b.      Expressed as aerodynamic equivalent diameter.
       Insufficient data.
c.
d.      Estimated control efficiency for multiple cyclones is 80%.
SCC at Source classification code.
1.1-22
EMISSION FACTORS
7/93

-------
                    8

                    7.2

               S  6.4
               < -o
               V- t>
               15  5.6
               M VI
               42 -  4.8
                   3.2
               * 01
                    2.4

                    1.6
                    0.8 -
                      0
                       .1
                              Multiple
                              cyclone
                            J - 1
                                        i 1 1 1
                                                   -1
             4  .6    1     2     4    6  10    20
                      Particle  diameter (pa)
10

6.0
4.0

2.0

1.0
0.6
0.4

0.2  5


0.1
                                                                         40  60 100
   Figure 1.1-5.  Cumulative size specific emission factors for overfeed stokers burning bituminous coal.
                     ;
                       S  5
8^  2
     1 -
                                                                  Uncontrolled
                                                        ...I  I  ,1..
                                       4  -6    1     2     4   6   10    20    40  60 10
                                                 Particle diameter (tan)
    Figure 1.1-6.  Cumulative specific emission factors for underfeed stokers burning bituminous coal.
7/93
               External Combustion Sources
              1.1-23

-------
  TABLE 1.1-10. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
            FACTORS FOR UNDERFEED STOKERS BURNING BITUMINOUS COALa
Particle Size"
ftim)
Cumulative Mass %, ^stated size
Uncontrolled Cumulative
Emission Factor0 [kg/Mg (Ib/ton) coal,
Factor
as fired]
Rating
a.     Reference 32.  Applicable SCCs are 102002-06 and 103002-08.
b.     Expressed as aerodynamic equivalent diameter.
c.     May also be used for uncontrolled hand-fired units.
SCC = Source classification code.
15
10
6
2.5
1.25
1.00
0.625
TOTAL
50
41
32
25
22
21
18
100
3.8 (7.6)
3.1 (6.2)
2.4 (4.8)
1.9(3.8)
1.7(3.4)
1.6(3.2)
1.4(2.7)
7.5 (15.0)
C
C
C
C
C
C
C
C
1.1-24
EMISSION FACTORS
7/93

-------
  TABLE 1.1-11. (ENGLISH UNITS) EMISSION FACTORS FOR METHANE (CH4), NON-METHANE
 TOTAL ORGANIC COMPOUNDS (NMTOC), AND NITROUS OXIDE (N2O) FROM BITUMINOUS AND
                       SUBBITUMINOUS COAL COMBUSTION"
Firing Configuration
Pulverized coal fired, dry bottom,
wall fired
Pulverized coal fired, dry bottom,
tangenfially fired
Pulverized coal fired, wet bottom
Cyclone furnace
Spreader stoker
Spreader stoker, with multiple
cyclones, and reinjection
Spreader stoker, with multiple
cyclones, no reinjection
Overfeed stoker*
Overfeed stoker, with multiple
cyclones'
Underfeed stoker
Underfeed stoker, with multiple
cyclone
Hand-fed units
Fluidized bed combustor, bubbling
bed
Fluidized bed combustor, circulating
bed
sec
101002-02/22
102002-02/22
103002-06/22
101002-12/26
102002-12/26
103002-16/26
101002-12/21
102002-01/21
103002-05/21
101002-03/23
102002-03/23
103002-23
101002-04/24
102002-04/24
103002-09/24
101002-03/24
101002-04/24
103002-09/24
101002-04/24
101002-04/24
103002-09/24
101002-05/25
102002-05/10/25
103002-07/25
101002-05/25
102002-05/10/25
103002-07/25
102002-06
103002-08
102002-06
103002-08
103002-14
101002-17
102002-17
103002-17
101002-17
102002-17
103002-17
CH,"
Emission
Factor
Ib/ton
0.04
0.04
0.05
0.01
0.06
0.06
0.06
0.06
0.06
0.8
0.8
5
0.06
0.06
Rating
B
B
B
B
B
B
B
B
B
B
B
E
E
E
NMTOC"'C
Emission
Factor
Ib/ton Rati
0.06 B
0.06 B
0.04 B
0.11 B
0.05 B
0.05 B
0.05 B
0.05 B
0.05 B
1.3 B
1.3 B
10 E
0.05 E
0.05 E
N20
Emission
Factor
ng Ib/ton
.09
.03
.09s
.09'
.09s
.09"
.09
.09"
.09*
.09
.09
.09"
5.9'
5.5
Rating
D
D
E
E
E
E
E
E
E
E
E
E
E
E
a. Factors represent uncontrolled emissions unless otherwise specified and should be appl ed to
coal feed, as fired.
b. Nominal values achievable under normal operating conditions. Values one or two orders of
magnitude higher can occur when combustion is not complete.
c. Non-methane total organic compounds are expressed as C2 to C16 alkane equivalents
7/93
External Combustion Sources
1.1-25

-------
       (Reference 31). Because of limited data, the effects of firing configuration on NMTOC emission
       factors could not be distinguished.  As a result, all data were averaged collectively to develop a
       single average emission factor for pulverized coal units, cyclones, spreaders and overfeed
       stokers.
d.     Refer to EPA/OAQPS's SPECIATE and XATEF data bases for emission factors on speciated
       VCX5.
e.     No data found; use emission factor for pulverized coal-fired dry bottom boilers.
f.      Includes traveling grate, vibrating grate and chain grate stokers.
g.     No data found; use emission factor for circulating fluidized bed.
SCO SB Source classification code.
1.1-26                               EMISSION FACTORS                                7/93

-------
   TABLE 1.1-12. (METRIC UNITS) EMISSION FACTORS FOR METHANE (CHJ, NON-METHANE
 TOTAL ORGANIC COMPOUNDS (NMTOC), AND NITROUS OXIDE (N2O) FROM BITUMINOUS AND
                          SUBBITUMINOUS COAL COMBUSTION*                 ^
Firing Configuration
sec
CH4"
Emission
Factor
kg/Mg
Rating
, NMTQC"'0
Emission
Factor
'kg/Mg
Rating
N20
Emission
Factor
kg/Mg
Rating
Pulverized coal fired, dry bottom,
wall fired

Pulverized coal fired, dry bottom,
tangentially fired

Pulverized coal fired, wet bottom


Cyclone furnace


Spreader stoker


Spreader stoker, with multiple
cyclones, and reinjection

Spreader stoker, with multiple
cyclones, no reinjection

Overfeed stoker1


Overfeed stoker, with multiple
cyclones'

Underfeed stoker

Underfeed stoker, with multiple
cyclone
Hand-fed units
Fluidized bed combustor, bubbling
bed

Fluidized bed combustor, circulating
bed

101002-02/22 0.02 B 0.04 B .045
102002-02/22
103002-06/22
101002-12/26 0.02 B 0.04 B .015
102002-12/26
103002-16/26
101002-12/21 0.025 B 0.02 B .045
102002-01/21
103002-05/21
101002-03/23 0.005 B 0.055 B .045*
102002-03/23
103002-23
101002-04/24 0.03 B 0.025 B .045
102002-04/24
103002-09/24
101002-03/24 0.03 B 0.025 B .045
101002-04/24
103002-09/24
101002-04/24 0.03 B 0.025 B .045
101002-04/24
103002-09/24
101002-05/25 0.03 B 0.025 B .045
102002-05/10/25
103002-07/25
101002-05/25 0.03 B 0.025 B .045
102002-05/10/25
103002-07/25
102002-06 0.4 B .65 B .045
103002-08
102002-06 0.4 B .65 B .045
103002-08
103002-14 2.5 E 5 E .045
101002-17 0.03 E 0.025 E 2.75
102002-17
103002-17
101002-17 0.03 E 0.025 E 2.75
102002-17
103002-17
D ,


D


E


E


E


.E


E


E


E


E

E

E
E


E


a.      Factors represent uncontrolled emissions unless otherwise specified and should be applied to
       coal feed, as fired.
b.      Nominal values achievable under normal operating conditions. Values one or two orders of
       magnitude higher can occur when combustion is not complete.
c.      Non-methane total organic compounds are expressed as C2 to C16 alkane equivalents
7/93
External Combustion Sources
1.1-27

-------
       (Reference 31).  Because of limited data, the effects of firing configuration on NMTOC emission
       factors could not be distinguished. As a result, all data were averaged collectively to develop a
       single average emission factor for pulverized coal units, cyclones, spreaders and overfeed
       stokers.
d.     Refer to EPA/OAQPS's SPECIATE and XATEF data bases for emission factors on speciated
       VOC.
e.     No data found; use emission factor for pulverized coal-fired dry bottom boilers.
f.      includes traveling grate, vibrating grate and chain grate stokers.
g.     No data found; use emission factor for circulating fluidized bed.
SCC = Source classification code.
 1.1-28                               EMISSION FACTORS                                7/93

-------
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7/93
External Combustion Sources
1.1-29

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1.1-30
                                         EMISSION FACTORS
                                                                                                   7/93

-------
             TABLE 1.1-15.  NEW SOURCE PERFORMANCE STANDARDS FOR FOSSIL
                                         FUEL-FIRED BOILERS
Standard/
Boiler Types/
Applicability
Criteria
Subpart D
Boiler Size
MW
(Million Btu/hr)
>73
(>250)
Fuel
or
Boiler
Type
CSas
PM
ng/J
(Ib/MMBtu)
[% reduction]
43
(0.10)
SO2
ng/J
(Ib/MMBtu)
[% reduction]
NA
NO,
ng/J
(Ib/MMBtu)
[% reduction]
86
(0.20)
     Industrial-
       Utility

    Commence
  construction after
      8/17/71
                  Oil
               Bit/Subbit.
                 Coal
                43
               (0.10)

                43
               (0.10)
                  340
                  (0.80)

                  520
                  (1.20)
                   129
                  (0.30)

                   300
                  (0.70)
    Subpart Da

       Utility

    Commence
  construction after
      9/18/78
  >73
 (>250)
Gas
                  Oil
                                    Bit/Subbit.
                                       Coal
 13
(0.03
[NA]

 13
(0.03)
[70]

 13
(0.03)
[99]
 340
(0.80)
 [90]'

 340
(0.80)
 [90?

 520
(1.20)
 [90]
   86
  (020)
   [25]

   130
  (0.30)
   [30]

 260/210
(0.60/0.50)
  [65/65]
Subpart Db
>29
Gas
NA"
NA"
43'
(0.10)
     Industrial-
    Commercial-
    Institutional

    Commence
  construction after
     6/19/84"
    Subpart DC

  Small Industrial-
    Commercial-
    Institutional

    Commence
 construction after
       6/9/89
              Distillate Oil
              Residual Oil
                                    Pulverized
                                    Bit/Subbit.
                                       Coal

                                     Spreader
                                   Stoker & FBC
                                    Mass-Feed
                                      Stoker
                43
               (0.10)
            (Same as for
             distillate oil)

                22
               (0.05)
                                 22'
                                (0.05)
                                 22
                                (0.05)
                  340"
                 (0.80)
                  [90]

               (Same as for
               distillate oil)

                  520
                 (1.20)
                  [90]

                  520
                 (1.20)
                  [90]

                  520"
                 (1.20)
                  [90]
                   43'
                  (0.10)


                   130"
                  (0.30)

                   300
                  (0.70)
                                                   260
                                                   (0.60)
                                                   210
                                                   (0.50)
 2.9-29
(10 - 100)
Gas
                  Oil
              Bit & Subbit.
                 Coal
                -M.



                22"
               (0.05)
                  215
                 (0.50)

                  5201
                 (1.20
                  [90]
a.      Zero percent reduction when emissions are less than 86 ng/J (0.20 Ib/MMBtu).
b.      70 percent reduction when emissions are less than 260 ng/J (0.60 Ib/MMBtu).
c.      The first number applies to bituminous coal and the second to subbituminous coal.
7/93
                External Combustion Sources
                                                           1.1-31

-------
d.      Standard applies when gas is fired in combination with coal, see 40 CFR 60, Subpart Db.
e.      Standard is adjusted for fuel combinations and capacity factor limits, see 40 CFR 60, Subpart
        Db.
f.      For furnace heat release rates greater than 730,000 J/s-m3 (70,000 Btu/hr-ft3), the standard is
        86 ng/J (0.20 Ib/MMBtu).
g.      For furnace heat release rates greater than 730,000 J/s-m3 (70,000 Btu/hr-ft3), the standard is
        170 ng/J  (0.40 Ib/MMBtu).
h.      Standard applies when gas or oil is fired in combination with coal, see 40 CFR 60, Subpart DC.
i.      20 percent capacity limit applies for heat input capacities of 8.7 Mwt (30 MMBtu/hr) or greater.
j.      Standard is adjusted for fuel combinations and capacity factor limits, see 40 CFR 60, Subpart
        DC.
k.      Additional requirements apply to facilities which commenced construction, modification, or
        reconstruction after 6/19/84 but on or before 6/19/86 (see 40 Code of Federal Regulations Part
        60, Subpart Db).
I.      215 ng/J  (0.50 Ib/million Btu)  limit (but no percent reduction requirement) applies if facilities
        combust only very low sulfur oil (< 0.5 wt. % sulfur).
FBC s Fluidized bed combustion.
1.1-32                              EMISSION FACTORS                                 7/93

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     TABLE 1-16.  POST-COMBUSTION SO, CONTROLS FOR COAL COMBUSTION SOURCES
 Control Technology
Process
Typical Control Efficiencies    Remarks
 Wet scrubber
Lime/limestone
       80-95+%           Applicable to high sulfur
                          fuels,
                          Wet sludge product
                            Sodium carbonate
                                    80-98%
                          1-125 MW (5-430 million
                          Btu/hr) typical application
                          range,           ,
                          High reagent costs
                            Magnesium oxide/hydroxide
                                                               80-95+%
                                                      Can be regenerated
                            Dual alkali
                                                                90-96%
                                                      Uses lime to regenerate
                                                      sodium-based scrubbing
                                                      liquor
 Spray drying
Calcium hydroxide slurry,
vaporizes in spray vessel
                                                                70-90%
                          Applicable to low and
                          medium sulfur fuels,
                          Produces dry product
 Furnace injection
Dry calcium
carbonate/hydrate injection in
upper furnace cavity
                                                                25-50%
                          Commercialized in Europe,
                          Several U.S. demonstration
                          projects underway
 Duct injection
Dry sorbent injection into
duct, sometimes combined
with water spray
                                                               25-50+%
                          Several R&D and
                          demonstration projects
                          underway,
                          Not yet commercially
                          available in the U.S.
7/93
           External Combustion Sources
                                             1.1-33

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      TABLE 1-17.  COMBUSTION MODIFICATION NOX CONTROLS FOR STOKER COAL-FIRED INDUSTRIAL BOILERS
Control Technique
Low Excess Air
(LEA)
Description of
Technique
Reduction of air
flow under stoker
bed
Effectiveness of
Control
(% NOX reduction)
5-25
Range of
Application
Excess oxygen
limited to 5-6%
minimum
Commercial
Availability/R&D
Status
Available now but
need R&D on
lower limit of
excess air
Comments
Danger of
overheating grate,
clinker formation,
corrosion, and
high CO
emissions
  Staged             Reduction of
  combustion (LEA    undergrate air
  + OFA)             flow and increase
                     of overfire air flow
                         5-25
                   Excess oxygen
                   limited to 5%
                   minimum
                   Most stokers have
                   OFA ports as
                   smoke control
                   devices but may
                   need better sir
                   flow control
                   devices
                                                                            Need research to
                                                                            determined
                                                                            optimum location
                                                                            and orientation of
                                                                            OFA ports for NOX
                                                                            emission control.
                                                                            Overheating grate,
                                                                            corrosion, and
                                                                            high CO emission
                                                                            can occur if
                                                                            undergrate  airflow
                                                                            is reduced below
                                                                            acceptable  level
                                                                            as in LEA
                                                                                                                      o
                     Reduction of coal    Varies from 49%
  Load Reduction      and air feed to the   decrease to 25%
  (LR)                stoker             increase in NOX
                                       (average 15%
                                       decrease)
                                      Has been used
                                      down to 25% load
                                      Available
                                      Only stokers that
                                      can reduce load
                                      without increasing
                                      excess air. Not a
                                      desirable
                                      technique
                                      because of loss in
                                      boiler efficiency
  Reduced air
  prohoat (RAP)
Reduction of
combustion air
temperature
                   Combustion air
                   temperature
                   reduced from
                   473K to 453K
                   Available now if
                   boiler has
                   combustion air
                   heater
                   Not a desirable
                   technique
                   because of loss in
                   boiler efficiency
 Ammonia Injection
Injection of NH3 in
convective section
of boiler
40-40 (from gas-
and oil-fired boiler
experience)
Limited by furnace
geometry.
Feasible NH3
injection rate
limited to 1.5
NH./NO
Commercially
offered but not yet
demonstrated
Elaborate NH3
injection,
monitoring, and
control system
required.
Possible load
restrictions on
boiler and air
preheater fouling
by ammonium
bisulfate
1.1-34
                       EMISSION FACTORS
                                                                     7/93

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REFERENCES FOR SECTION 1.1

1.     Steam. 38th Edition, Babcock and Wilcox, New York, 1975.

2.     Control Techniques for Paniculate Emissions from Stationary Sources, Volume
       if EPA-450/3-81-005a, U.S. Environmental Protection Agency, Research
       Triangle Park, NC, April 1981.

3.     Ibidem. Volume n. EPA-450/3-81:005b.

4.     Electric Utility Steam Generating Units: Background Information for Proposed
       Particulate Matter Emission Standard. EPA-450/2-78-006a, U.S.  Environmental
       Protection Agency, Research Triangle Park, NC, July 1978

5.     Axtman, W. and H.A. Eleniewski, "Field Test Results of Eighteen Industrial
       Coal Stoker Fired Boilers for Emission Control and Improved Efficiency",
       Presented at the 74th Annual Meeting of the Air Pollution Control Association,
       Philadelphia, PA, June 1981.

6.     Field Tests of Industrial Stoker Coal Fired Boilers for Emission  Control and
       Efficiency Improvement - Sites LI-17. EPA-600/7-81-020a, U.S. Environmental
       Protection Agency, Washington D.C., February 1981.

7.     Control Techniques for Sulfur Dioxide Emissions from Stationary Sources. 2nd
       Edition. EPA-450/3-81-004, U.S. Environmental Protection Agency, Research
       Triangle Park, NC, April 1981.

8.     Electric Utility Steam Generating Units: Background Information for Proposed
       SO, Emission Standards. EPA-450/2-78-007a, U.S. Environmental Protection
       Agency, Research Triangle Park, NC, July 1978.

9.     Castaldini, Carlo and Meredith Angwin, Boiler Design and Operating Variables
       Affecting Uncontrolled  Sulfur Emissions from Pulverized Coal Fired Steam
       Generators. EPA-450/3-77-047, U.S. Environmental Protection Agency,
       Research Triangle Park, NC, December 1977.

10.    Control Techniques for Nitrogen Oxides Emissions from Stationary Sources,
       2nd Edition, EPA-450/1-78-001, U.S. environmental Protection Agency,
       Research Triangle Park, NC, January 1978.

11.    Review of MX Emission Factors for Stationary Fossil Fuel Combustion
       Sources. EPA-450/4-79-021, U.S. Environmental Protection Agency,  Research
       Triangle Park, NC, September 1979.

12.    Gaglia, B.N. and A. Hall, "Comparison of Bubbling and Circulating Fluidized
       Bed Industrial Steam Generation", Proceedings of 1987 International  Fluidized
       Bed Industrial Steam Conference, American Society of Mechanical Engineers,
       New York, 1987.

7/93                           External Combustion Sources                        1.1-35

-------
 13.    Gushing, K., Belba, V., and Chang, R., "Fabric Filtration Experience
       Downstream from Atmospheric Fluidized Bed Combustion Boilers", presented
       at the Ninth Particulate Control Symposium, October 1991.
 14.    Overview of thee Regulatory Baseline, Technical Basis, and Alternative Control
       Levels for Sulfur Dioxide (S(X) Emission Standards for Small Steam
       Generating Units, EPA-450/3-89-12, U.S. Environmental Protection Agency,
       Research Triangle Park, NC, May 1989.

 15.    Fossil Fuel Fired Industrial Boilers - Background Information - Volume I.
       EPA-450/3-82-006a, U.S. Environmental Protection Agency, Research Triangle
       Park, NC, March 1982.

 16.    EPA Industrial Boiler FGD Survey: First Quarter 1979. EPA-600/7-79-067b,
       U.S. Environmental Protection Agency, Research Triangle Park, NC, April
       1979.

 17.    Particulate Polycyclic  Organic Matter, National Academy of Sciences,
       Washington, DC, 1972

 18.    Vapor Phase Organic Pollutants - Volatile Hydrocarbons and Oxidation
       Products, National Academy of Sciences, Washington, DC, 1976.

 19.    Lim, K.J., et.al., Industrial Boiler Combustion Modification NO. Controls -
       Volume I Environmental Assessment, EPA-600/7-81-126a, U.S. Environmental
       Protection Agency, Washington, D.C., July 1981.

20.    Hagebruack, R.P., DJ. Von Lehmden, and J.E. Meeker, "Emissions and
       Polynuclear Hydrocarbons and Other Pollutants from Heat-Generation and
       Incineration Process",  Journal of the Air Pollution Control Assoction,  14:267-
       278, 1964.

21.    Rogozen, M.B., et al., Formaldehyde: A Survey of Airborne Concentration and
       Sources, California Air Resources Board, ARB  report no. ARB/R-84-231,
       1984.

22.    Lim, K.J., et al., Technology Assessment Report for Industrial Boiler
       Applications: NO. Combustion Modification. EPA-600/7-79-178f, U.S.
       Environmental Protection Agency, Research Triangle Park, NC, December
       1979.

23.    Clean Air Act Amendments of 1990, Conference Report to Accompany S.
       1603, Report 101-952, U.S. Government Printing  Office, Washington,  DC,
       October 26, 1990.

24.    Klein,  D.H., et al., "Pathways of Thirty-Seven Trace Elements Through Coal-
       Fired Power Plants", Environmental Science and Technology., 9: 973-979,
1.1-36                           EMISSION FACTORS                             7/93

-------
25.   Coles, D.G., et aL, "Chemical Studies of Stack Fly Ash from a Coal-Fired
      Power Plant", Environmental Science and Technology, 13: 455-459, 1979.

26.   Baig, S., et aL, Conventional Combustion Environmental Assessment, EPA
      Contract No. 68-02-3138, U.S. Environmental Protection Agency, Research
      Triangle Park, NC, 1981.

27.   Technology Assessment Report for Industrial Boiler Applications: NO.
      Combustion Modification, EPA-600/7-79-178f, U.S. Environmental Protection
      Agency, Washington, DC, December 1979.

28.   Standards of Performance for New Stationary Sources, 36 FR 24876, December
      23, 1971.

29.   Application of Combustion Modifications to Control Pollutant Emissions from
      Industrial Boilers - Phase I,  EPA-650/2-74-078a, U.S. Environmental Protection
      Agency, Washington, DC, October 1974.

30.   Source Sampling Residential Fireplaces for Emission Factor Development
      EPA-450/3-76-010, U.S. Environmental Protection Agency, Research Triangle
      Park, NC, November 1875.

31.   Emissions of Reactive Volatile Organic Compounds from Utility Boilers. EPA-
      600/7-80-111, U.S. Environmental Protection Agency, Washington DC, May
       1980.

32.   Inhalable Paniculate Source Category Report for External Combustion Sources,
      EPA Contract No. 68-02-3156, Acurex Corporation, Mountain View, CA,
      January  1985.

33.   Brown, S.W., et aL, "Gas Reburn System Operating Experience on a Cyclone Boiler,"
      presented at the  NOX Controls For Utility Boilers Conference, Cambridge, MA, July
       1992.

34.   Emission Factor Documentation For AP-42 Section 1.1 - Bituminous and
       Subbituminous Coal Combustion - Draft, U.S. Environmental Protection Agency,
      Research Triangle Park, NC, March 1993.
 7/93                          External Combustion Sources                         1.1-37

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-------
1.2 ANTHRACITE COAL COMBUSTION

1.2.1  General1"4

       Anthracite coal is a high-rank coal with more fixed carbon and less volatile matter than either
bituminous coal or lignite; anthracite also has higher ignition and ash fusion temperatures.  In the
United States, nearly all anthracite is mined in northeastern Pennsylvania and consumed in
Pennsylvania and its surrounding states. The largest use of anthracite is for space heating. Lesser
amounts are employed for steam/electric production; coke manufacturing, sintering and pelletizing; and
other industrial uses.  Anthracite currently is only a small fraction of the total quantity of coal
combusted in the United States.

        Another form of anthracite coal burned in boilers is anthracite refuse, commonly known as
culm. Culm was produced as breaker reject material from the mining/sizing of anthracite coal and was
typically dumped by miners on the ground near operating mines. It is estimated that mere are over 15
million Mg (16 million tons) of culm scattered in piles throughout northeastern Pennsylvania.  The
heating value of culm is typically in the 1,400 to 2,800 kcal/kg (2,500 to 5,000 Btu/lb) range,
compared to 6,700 to 7,800 kcal/kg (12,000 to 14,000 Btu/lb) for anthracite coal.

1.2.2 Firing Practices5"7

        Due to its low volatile matter content, and  non-clinkering characteristics, anthracite coal is
largely used in medium-sized industrial and institutional stoker boilers equipped with stationary or
traveling grates.  Anthracite coal is not used in spreader stokers because of its low volatile matter
content and relatively high ignition temperature.  This fuel may also be burned in pulverized coal-fired
(PC-fired) units, but due to ignition difficulties, this practice is limited to only a few plants in eastern
Pennsylvania.  Anthracite coal has also been widely used in hand-fired furnaces. Culm has been
combusted primarily in fluidized bed combustion (FBC) boilers because of its high ash content and
low heating value.

        Combustion of anthracite coal on a traveling grate is characterized by a coal bed of 8 to 13 cm
(3 to 5 inches) hi depth and a high blast of underfire air at the rear or dumping end of the grate.  This
high blast of air lifts incandescent fuel particles and combustion gases from the grate and  reflects the
particles against a long rear arch over the grate towards the front of the fuel bed where fresh or
 "green" fuel enters.  This special furnace arch design is required to assist in the ignition of the green
 fuel.

         A second type of stoker boiler used to burn anthracite coal is the underfeed stoker.  Various
 types of underfeed stokers are used in industrial boiler applications but the most common for
 anthracite coal firing is the single-retort side-dump stoker with stationary grates. In this unit, coal is
 fed intermittently to the fuel bed by a ram. In very small units the coal is fed continuously by a
 screw.  Feed coal is pushed through the  retort and upward towards the tuyere blocks.  Air is supplied
 through the tuyere blocks on each side of the retort and through openings  in the side grates.  Overfire
 air is commonly used with underfeed stokers to  provide combustion air and turbulence in the flame
 zone directly above the active fuel bed.


 7/93                             External  Combustion Sources                            1.2-1

-------
        In PC-fired boilers, the fuel is.pulverized to the consistency of powder and pneumatically
injected through burners into the furnace. Injected coal particles burn in suspension within the furnace
region of the boiler. Hot flue gases rise from the furnace and provide heat exchange with boiler tubes
in the walls and upper regions of the boiler.  In general, PC-fired boilers operate either in a wet-
bottom or dry bottom mode; because of its high ash fusion temperature, anthracite coal is burned in
dry-bottom furnaces.

        For anthracite culm, combustion in conventional boiler systems is difficult due to the fuel's
high ash content, high moisture content, and low heating value. However, the burning of culm in a
fluidized bed system was demonstrated at a steam generation plant in Pennsylvania.  A fluidized bed
consists of inert particles (e.g., rock and ash) through which air is blown so that the bed behaves as a
fluid.  Anthracite coal enters in the space above the bed and burns in the bed.  Fluidized beds can
handle fuels with moisture contents up to near 70 percent (total basis) because of the large thermal
mass represented by the hot inert bed particles.  Fluidized beds can also handle fuels with ash contents
as high as 75 percent. Heat released by combustion is transferred to in-bed steam-generating tubes.
Limestone may be added to the bed to capture sulfur dioxide formed by combustion of fuel sulfur.

1.2.3 Emissions And Controls4"6

        Particulate matter (PM) emissions from anthracite coal combustion are a function of furnace
firing configuration, firing practices (boiler load, quantity and location of underfire air, soot blowing,
flyash reinjection, etc.), and the ash content of the coal. Pulverized coal-fired boilers emit the highest
quantity of PM per unit of fuel because they fire the anthracite in suspension, which results in a high
percentage of ash carryover into exhaust gases.  Traveling grate stokers and hand fired units produce
less PM per unit of fuel fired, and coarser particulates, because combustion takes place in a quiescent
fuel bed without significant ash carryover into the exhaust gases.  In general, PM emissions from
traveling grate stokers will increase during soot blowing and flyash reinjection and with higher fuel
bed underfeed air flowrates. Smoke production during combustion is rarely a problem, because of
anthracite's low volatile matter content

        Limited data are available on the emission of gaseous pollutants from anthracite combustion.
It is assumed, based on bituminous coal combustion data, that a large fraction of the fuel sulfur is
emitted as sulfur oxides.  Also, because combustion equipment, excess air rates, combustion
temperatures, etc., are similar between anthracite and bituminous coal combustion, nitrogen oxide
emissions are also assumed to be similar. Nitrogen oxide emissions from FBC units burning culm are
typically lower than from other anthracite coal-burning boilers due to the lower operating temperatures
which characterize FBC beds.

        Carbon monoxide and total organic compound emissions are dependent on combustion
efficiency. Generally their emission rates, defined as  mass  of emissions per unit of heat input,
decrease with increasing boiler size.  Organic  compound emissions are expected to be lower for
pulverized coal units and higher for underfeed and overfeed stokers due to relative combustion
efficiency levels.

        Controls on anthracite emissions mainly have been  applied to PM.  The most efficient
paniculate controls, fabric filters, scrubbers, and electrostatic precipitators, have been installed on large
pulverized anthracite-fired boilers.  Fabric filters can achieve  collection efficiencies exceeding 99
percent  Electrostatic precipitators typically are only 90 to  97 percent efficient, because of the

1.2-2                                EMISSION FACTORS                                7/93

-------
characteristic high resistivity of low sulfur anthracite fly ash.  It is reported that higher efficiencies can
be achieved using larger precipitators and flue gas conditioning.  Mechanical collectors are frequently
employed upstream from these devices for large particle removal.

       Older traveling grate stokers are often uncontrolled.  Indeed, particulate control has often been
considered unnecessary, because of anthracite's low smoking tendencies and the fact that a significant
fraction of large size flyash from stokers is readily collected in flyash hoppers as well as in the
breeching and base of the stack.  Cyclone collectors have been employed on traveling grate stokers,
and limited information suggests these devices may be up to 75 percent efficient on particulate.
Flyash reinjection, frequently used in traveling grate stokers to enhance fuel use efficiency, tends to
increase PM emissions per unit of fuel combusted.  High-energy venturi scrubbers can generally
achieve PM collection efficiencies of 90 percent or greater.

        Emission factors and ratings for pollutants from anthracite coal combustion and anthracite
culm combustion are given in Tables 1.2-1 through 1.2-7. Cumulative size distribution data and size
specific emission factors and ratings for particulate emissions are summarized in Table 1.2-8.
Uncontrolled and controlled size specific emission factors are presented in Figure 1.2-1. Particle size
distribution data for bituminous coal combustion may be used for uncontrolled emissions from
pulverized anthracite-fired furnaces, and data for anthracite-fired traveling grate stokers may be used
for hand fired units.
  7/93                             External Combustion Sources                             1.2-3

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   Table 1.2-1. EMISSION FACTORS FOR SPECIATED METALS FROM ANTHRACITE COAL
                      COMBUSTION IN STOKER FIRED BOILERS*

                           EMISSION FACTOR RATING: E
Pollutant
Mercury
Arsenic
Antimony
Beryllium
Cadmium
Chromium
Manganese
Nickel
Selenium
Emission Factor Range
kg/Mg
4.4E-05 - 6.5E-05
BDLb - 1.2E-04
BDL
1.5E-05 - 2.7E-04
2.3E-05 - 5.5E-03
3.0E-03 - 2.5E-02
4.9E-04 - 2.7E-03
3.9E-03 - 1.8E-02
2.4E-04 - 1.1E-03
Ib/ton
8.7E-05 - 1.3E-04
BDL - 2.4E-04
BDL
3.0E-05 - 5.4E-04
4.5E-05 - 1.1E-04
5.9E-03 - 4.9E-02
9.8E-04 - 5.3E-03
7.8E-03 - 3.5E-02
4.7E-04 - 2.1E-03
Average Emission Factor
kg/Mg
6.5E-05
9.3E-05
BDL
1.5E-04
3.6E-05
1.4E-02
1.8E-03
1.3E-02
6.3E-04
Ib/ton
1.3E-04
1.9E-04
BDL
3.1E-04
7.1E-05
2.8E-02
3.6E-03
2.6E-02
1.3E-03
"Reference 9. Units are kg of rwllutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
 Source Classification Codes are 10100102,10200104, and 10300102.
      = Below detection limit
     Table 1.2-2. EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS (TOG) AND
              METHANE (CH^ FROM ANTHRACITE COAL COMBUSTORS8
Source Category
(SCC)b
TOG Emission Factor
kg/Mg
Ib/ton
Rating
CH4 Emission Factor
kg/Mg
Ib/ton
Rating
 Stoker fired boilers0        0.10      0.20
 (SCC 10100102,
 10200104, 10300102)

 Residential spaced          NDe      ND
 heaters
 (no SCC)
                        ND
                         4
ND
 Units are kg of pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
DSCC = Source Classification Code.
Reference 9.
Reference 14.
CND = No data.
1.2-4
EMISSION FACTORS
                                                                             7/93

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Table 1.2-3 (Metric Units). EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
                   FROM ANTHRACITE COAL COMBUSTORS*

                         EMISSION FACTOR RATING: E
Pollutant
Biphenyl
Phenanthrene
Naphthalene
Acenaphthene
Acenaphthalene
Fluorene
Anthracene
Fluorarithrene
Pyrene
Benzo(a)anthracene
Chrysene
Benzo(k)fluoranthrcne
Benzo(e)pyrene
Benzo(a)pyiene
Perylene
Indeno(123-cd) perylene
Benzo(gjh,i,) perylene
Anthanthrene
Coronene
Stoker Fired Boilersb
(SCC 10100102,
10200104, 10300102)
Emission Factor
1.2SE-02
3.4E-03
0.65E-01
NDd
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Residential Space Heaters"
(No SCC)
Emission Factor
Range
ND
4.6E-02 - 2.1E-02
4.5E-03 - 2.4E-02
7.0E-03 - 3.4E-01
7.0E-03 - 2.0E-02
4.5E-03 - 2.9E-02
4.5E-03 - 2.3E-02
4.8E-02 - 1.7E-01
2.7E-02 - 1.2E-01
7.0E-03 - l.OE-01
1.2E-02 - 1.1E-01
7.0E-03 - 3.1E-02
2.3E-03 - 7.3E-03
1.9E-03 - 4.5E-03
3.8E-04 - 1.2E-03
2.3E-03 - 7.0E-03
2.2E-03 - 6.0E-03
9.5E-05 - 5.5E-04
5.5E-04 - 4.0E-03
Emission Factor
ND
1.6E-01
1.5E-01
3.5E-01
2.5E-01
1.7E-02
1.6E-02
1.1E-01
7.9E-02
2.8E-01
5.3E-02
2.5E-01
4.2E-03
3.5E-03
8.5E-04
2.4E-01
2.1E-01
3.5E-03
1.2E-02
aUnits are kg of pollutant/Mg of anthracite coal burned.
Reference 9.
Reference 14.
dND = No data.
               SCC = Source Classification Code.
7/93
External Combustion Sources
                                                                           1.2-5

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 Table 1.2-4 (English Units). EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
                     FROM ANTHRACITE COAL COMBUSTORSa

                           EMISSION FACTOR RATING: E
Pollutant
Biphenyl
Phenanthrene
Naphthalene
Acenaphthene
Acenaphthalene
Fluorene
Anthracene
Fluoranthrene
Pyrene
Benzo(a)anthracene
Chrysene
Benzo(k)fluoranthrene
Benzo(e)pyrene
Benzo(a)pyiene
Perylene
Ihdeno(123-cd) perylene
Benzo(g4i4,) perylene
Anthanthrene
Coronene
Stoker Fired Boilersb
(SCC 10100102,
10200104,
10300102)
Emission Factor
2.5E-02
6.8E-03
1.3E-01
NDd
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Residential Space Heaters0
(No SCC)
Emission Factor
Range
ND
9.1E-02 - 4.3E-02
9.0E-03 - 4.8E-02
1.4E-02 - 6.7E-01
1.4E-02 - 3.0E-01
9.0E-03 - 5.8E-02
9.0E-03 - 4.5E-02
9.6E-02 - 3.3E-01
5.4E-02 - 2.4E-01
1.4E-02 - 2.0E-01
2.3E-02 - 2.2E-01
1.4E-02 - 6.3E-02
4.5E-03 - 1.5E-02
3.8E-03 - 9.0E-03
7.6E-04 - 2.3E-03
4.5E-03 - 1.4E-02
4.3E-03 - 1.2E-02
1.9E-04 - 1.1E-03
1.1E-03 - 8.0E-03
Emission Factor
ND
3.2E-01
3.0E-01
7.0E-01
4.9E-01
3.4E-02
3.3E-02
2.2E-01
1.6E-01
5.5E-01
1.1E-01
5.0E-01
8.4E-03
7.0E-03
1.7E-03
4.7E-01
4.2E-01
7.0E-03
2.4E-02
aUnits are Ibs. of pollutant/ton of anthracite coal burned.
^Reference 9.
"Reference 14.
dND = No data.
              SCC = Source Classification Code.
1.2-6
EMISSION FACTORS
                                                                            7/93

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di
        CU
           cu
          .
         o ^co
         SI
             '

                 3
                   CO
                   oo
                   co
                   O
1
                    O
oo
O
O
                    S
                    O
                    O
                 00
              
                              n
                     188  IB
                     2^0   S
7/93
                  External Combustion Sources
                                                                      1.2-7

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                       w
        1

CO
              CO
                       "
                             CO
            bO
               O
              CQ
        PH
        a
        g
                       oo
                             00
            00
               vo
                       0\
                       o
              O\
        a
        o
          o"
          O
        60

        !
coal boi
01, 1

                      
                      en
                      co

                      0\
                                     m
                                     CO
                                     5
                                     o
                                   3
22
08
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denti
SCC)
                                            a
                                              o
                   sS^&a
1.2-8
                EMISSION FACTORS
                                                                             7/93

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         Table 1.2-7. EMISSION FACTORS FOR CARBON MONOXIDE (CO) AND
          CARBON DIOXIDE (CO^ FROM ANTHRACITE COAL COMBUSTORS4
Source Category
(SCC)b
CO Emission Factor
kg/Mg
Ib/ton
Rating
CO2 Emission Factor
kg/Mg
Ib/ton
Rating
 Stoker fired boilers6        0.3
 (SCC 10100102,
 10200104, 10300102)

 FBC boilersd             0.15
 (no SCC)
      0.6
      0.3
B
E
2840
NDe
5680
 ND
aUnits are kg of pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
bSCC = Source Classification Code.
"References 10, 13.
Reference 15. FBC = Fluidized bed combustion; FBC boilers burning culm fuel; all other sources
 burning anthracite coal.
     = Nodata.
 7/93
External Combustion Sources
                                 1.2-9

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 Table 1.2-8.  CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
   FACTORS FOR DRY BOTTOM BOILERS BURNING PULVERIZED ANTHRACITE COAL8

                           EMISSION FACTOR RATING: D
Particle
Sizeb
(urn)
15
10
6
2.5
1.25
1.00
0.625
TOTAL
Cumulative Mass % < stated size
Uncontrolled
32
23
17
6
2
2
1
100
Controlled0
Multiple
Cyclone
63
55
46
24
13
10
7
100
Baghouse
79
67
51
32
21
18

100
Cumulative Emission Factor*1
kg/Mg (Ib/ton) coal, as fired
Uncontrolled
1.6A (3.2A)e
1.2A (2.3A)
0.9A (1.7A)
0.3A (0.6A)
0.1A (0.2A)
0.1 A (0.2A)
0.05A (0.1A)
5A (10A)
Controlled0
Multiple
Cyclone
0.63A
(1.26A)
0.55A
(1.10A)
0.46A
(0.92A)
0.24A
(0.48A)
0.13A
(0.26A)
0.10A
(0.20A)
0.07A
(0.14A)
1A (2A)
Baghouse
0.0079A
(0.016A)
0.0067A
(0.013A)
0.0051 A
(0.010A)
0.0032A
(0.006A)
0.0021A
(0.004A)
0.0018A
(0.004A)
f
0.01A
(0.02A)
Reference 8.  Source Classification Codes are 10100101, 10200101, and 10300101.
^Expressed as aerodynamic equivalent diameter.
Estimated control efficiency for multiple cyclone is 80%; for baghouse, 99.8%.
"Units are kg of pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
eA a coal ash weight %, as fired.
flnsufficient data.
1.2-10
EMISSION FACTORS
                                                                             7/93

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                                                                            l.OA
                                                  0.010A

                                                  0.009A

                                                  0.008A


                                                  0.007A

                                                  0.006A

                                                  0.005A

                                                  0.004A

                                                  0.003A

                                                   0.002A

                                                   0.001A

                                                   0
                                                                                              I- OJ
                                                                                              (A t.
                                                                                              V) -
                                      Particle diameter (pm)
  Figure 1.2-1.  Cumulative size specific emission factors for dry bottom boilers burning pulverized
                                            anthracite coal.
7/93
External Combustion Sources
1.2-11

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References For Section 1.2

1.  Minerals Yearbook, 1978-79, Bureau of Mines, U. S. Department of the Interior, Washington, DC
    1981.

2.  Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection Agency, Research
    Triangle Park, NC, April 1970.

3.  P. Bender, D. Samela, W. Smith, G. Tsoumpas, and J. Laukaitis, "Operating Experience at the
    Shamokin Culm Burning Steam Generation Plant", Presented at the 76th Annual Meeting of the
    Air Pollution Control Association, Atlanta, GA, June 1983.

4.  Chemical Engineers' Handbook, Fourth Edition, J. Perry, Editor, McGraw-Hill Book Company,
    New York, NY, 1963.

5.  Background Information Document For Industrial Boilers, EPA 450/3-82-006a, U. S.
    Environmental Protection Agency, Research Triangle Park, NC, March 1982.

6.  Steam: Its Generation and Use, Thirty-Seventh Edition, The Babcock & Wilcox Company, New
    York, NY, 1963.

7.  Emission Factor Documentation for AP-42 Section 12 - Anthracite Coal Combustion (Draft),
    Technical Support Division, Office of Air Quality Planning and Standards, U. S. Environmental
    Protection Agency, Research Triangle Park, NC, April 1993.

8.  Inhalable Particulate Source Category Report for External Combustion Sources, EPA Contract
    No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985.

9.  Emissions Assessment of Conventional Stationary Combustion Systems, EPA Contract No.
    68-02-2197, GCA Corp., Bedford, MA, October 1980.

10. Source Sampling of Anthracite Coal Fired Boilers, RCA-Electronic Components, Lancaster, PA,
    Final Report, Scott Environmental Technology, Inc., Plumsteadville, PA, April 1975.

11. Source Sampling of Anthracite Coal Fired Boilers, Shippensburg State College, Shippensburg, PA,
    Final Report, Scott Environmental Technology, hie, Plumsteadville, PA, May  1975.

12. Source Sampling of Anthracite Coal Fired Boilers, Pennhurst Center, Spring City, PA, Final
    Report, TRC Environmental Consultants,  Inc., Wethersfield, CT, January 23, 1980.

13. Source Sampling of Anthracite Coal Fired Boilers, West Chester State College, West Chester, PA>
    Pennsylvania Department of Environmental Resources, Harrisburg, PA 1980.

14. Characterization of Emissions ofPAHs From Residential Coal Fired Space Heaters, Vermont
    Agency of Environmental Conservation, 1983.
1.2-12                              EMISSION FACTORS                               7/93

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References For Section 1.2 (Continued)

15. Design, Construction, Operation, and Evaluation of a Prototype Culm Combustion Boiler/Heater
    Unit, Contract No. AC21-78ET12307, U. S. Dept of Energy, Morgantown Energy Technology
    Center, Morgantown, WV, October 1983.

16. Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection Agency, Research
    Triangle Park, NC, April 1970.

17. Source Test Data on Anthracite Fired Traveling Grate Stokers, Office of Air Quality Planning and
    Standards, U. S. Environmental Protection Agency, Research Triangle Park NC, 1975.

18. N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary Combustion Systems,
    Volume IV:  Commercial/Institutional Combustion Sources, EPA Contract No. 68-02-2197, GCA
    Corporation, Bedford, MA, October 1980.

19. R. W. Cass and R. W. Bradway, Fractional Efficiency of a Utility Boiler Baghouse: Sunbury
    Steam Electric Station, EPA-600/2-76-077a, U. S. Environmental Protection Agency, Washington,
    DC, March 1976.
 7/93                             External Combustion Sources                           1.2-13

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1.3 FUEL OIL COMBUSTION

1.3.1  General1'2'26

       Two major categories of fuel oil are burned by combustion sources:  distillate oils and residual
oils.  These oils are further distinguished by grade numbers, with Nos. 1 and 2 being distillate oils;
Nos. 5 and 6 being residual oils; and No. 4 either distillate oil or a mixture of distillate and residual
oils.  No. 6 fuel oil is sometimes referred to as Bunker C.  Distillate oils are more volatile and less
viscous than residual oils. They have negligible nitrogen and ash contents and usually contain less
than 0.3 percent sulfur (by weight).  Distillate oils are used mainly in domestic and small commercial
applications.  Being more viscous and less volatile than distillate oils, the heavier residual oils (Nos. 5
and 6) must be heated for ease of handling and to facilitate proper atomization.  Because residual oils
are produced from the residue remaining after the lighter fractions (gasoline, kerosene, and distillate
oils) have been removed from the crude oil, they contain significant quantities of ash, nitrogen, and
sulfur. Residual oils are used mainly in utility, industrial, and large commercial applications.
               ,27
1.3.2 Emissions

        Emissions from fuel oil combustion depend on the grade and composition of the fuel, the type
and size of the boiler, the firing and loading practices used,  and the level of equipment maintenance.
Because the combustion characteristics of distillate and residual oils are different, their combustion can
produce significantly different emissions. In general, the baseline emissions of criteria and non-criteria
pollutants are those from uncontrolled combustion sources.  Uncontrolled sources are those without
add-on air pollution control (APC) equipment or other combustion modifications designed for emission
control. Baseline emissions for sulfur dioxide (SOj) and paniculate matter (PM) can also be obtained
from measurements taken upstream of APC  equipment.

        In this section, point source emissions of nitrogen oxides (NOp, SO2, PM, and carbon
monoxide  (CO) are being evaluated as criteria pollutants (those emissions which have established
National Primary and Secondary Ambient Air Quality Standards. Paniculate matter emissions are
sometimes reported as total suspended particulate (TSP).  More recent data generally quantify the
portion of inhalable PM which is considered to  be less than 10 microns in aerodynamic diameter (PM-
 10).  In addition to the criteria pollutants, this section includes point source emissions of some non-
criteria pollutants, nitrous oxide (N2O), volatile  organic compounds (VOCs), and hazardous air
pollutants  (HAPs), as well as data on particle size distribution to support PM-10 emission inventory
efforts.  Emissions of carbon monoxide (COa) are also being considered because of its possible
participation in global climatic change and the corresponding interest in including this gas in emission
inventories.  Most of the carbon in fossil fuels is emitted as CO2 during combustion.  Minor amounts
of carbon  are emitted as CO, much of which ultimately oxidizes to CO2, or as carbon in the ash.
Finally, fugitive emissions associated with the use of oil at the combustion source are being included
 in this section.

         Tables 1.3-1 through 1.3-4 present emission factors for uncontrolled emissions of criteria
 pollutants from fuel oil combustion. A general discussion of emissions of criteria and non-criteria
 pollutants from coal combustion is given in the following paragraphs. Tables 1.3-5 through 1.3-8
 present cumulative size distribution data and size specific emission factors for particulate emissions
 from fuel  oil combustion.  Uncontrolled and controlled size specific emission factors are presented in
 Figures 1.3-1 through 1.3-4. Distillate and residual oil categories are given separately, because their
 combustion produces significantly different particulate, SO2, and NOX emissions.
 7/93                              External Combustion Sources                             1-3-1

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  Particulate Matter Emissions3-7-12-13-21-23"24

         Particulate matter emissions depend predominantly on the grade of fuel fired. Combustion of
  lighter distillate oils results in significantly lower PM formation than does combustion of heavier
  residual oils.  Among residual oils, firing of Nos. 4 or 5 oils usually produces less PM than does the
  firing of heavier No. 6 oil.

         In general, PM emissions depend on the completeness of combustion as well as on the oil ash
  content The PM emitted by distillate oil-fired boilers is primarily carbonaceous particles resulting
  from incomplete combustion of oil and is not correlated to the ash or sulfur content of the oil.
  However, PM emissions from residual oil burning is related to the oil sulfur content This is because
  low sulfur No. 6 oil, either refined from naturally low sulfur crude oil or desulfurized by one of
  several processes, exhibits substantially lower viscosity and reduced  asphaltene, ash, and sulfur
  contents, which results in better atomization and more complete combustion.

         Boiler load can also  affect paniculate emissions in units firing No. 6 oil. At low load
  conditions, particulate emissions from utility boilers may be lowered by 30 to 40 percent and by as
 much as 60 percent from small industrial and commercial units.  However, no significant particulate
 emissions reductions have been noted at low loads from boilers firing any of the lighter grades.  At
 very low load  conditions, proper combustion conditions may be difficult to maintain and particulate
 emissions may increase significantly.

 Sulfur Oxide Emissions1"6-22

        Sulfur oxide (SOX) emissions are generated during oil combustion from the oxidation of sulfur
 contained in the fuel. The emissions of SOX from conventional combustion systems are predominantly
 in the form of SO2.  Uncontrolled SOX emissions are almost entirely dependent on the sulfur content of
 the fuel and are not affected by boiler size, burner design, or grade of fuel being fired.  On average,
 more than 95 percent of the fuel sulfur is converted to SO2: about 1 to 5 percent is further oxidized to
 sulfur trioxide  (SOg); and about 1 to 3 percent is emitted as sulfate particulate. SO3 readily reacts with
 water vapor (both in the atmosphere and in flue gases) to form a sulfuric acid mist.

 Nitrogen Oxides Emissions1-11-14-15-20-24-25-28-29-41

        Oxides of nitrogen (NO^ formed in combustion processes are due either to thermal fixation of
 atmospheric nitrogen in the combustion air ("thermal NOX"), or to the conversion of chemically bound
 nitrogen in the  fuel ("fuel NOX"). The term NOX refers to the composite of nitric oxide (NO) and
 nitrogen dioxide (NOj). Nitrous  oxide is not included in NOX but has taken on recent interest because
 of atmospheric  effects. Test data have shown that for most external fossil fuel combustion systems,
 over 95 percent of the emitted NOX is in the form of NO.

       Experimental measurements of thermal NOX formation have shown that NOX concentration is
 exponentially dependent on temperature, and proportional to N2 concentration in the flame, the square
 root of O2 concentration in the flame, and the residence time.  Thus, the formation of thermal NOX is
 affected by four factors:  (1) peak temperature, (2) fuel nitrogen concentration, (3) oxygen
 concentration, and (4) time of exposure at peak temperature. The emission trends due to changes in
these factors are generally consistent for all types of boilers:  an increase in flame temperature, oxygen
availability, and/or residence time at high temperatures leads to an increase in NOX production.
1.3-2                               EMISSION FACTORS                                7/93

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       Fuel nitrogen conversion is the more important NOx-forming mechanism in residual oil boilers.
It can account for 50 percent of the total NOX emissions from residual oil firing. The percent
conversion of fuel nitrogen to NOX varies greatly, however, typically from 20 to 90 percent of nitrogen
in oil is converted to NOX. Except in certain large units having unusually high peak flame
temperatures, or in units firing a low nitrogen content residual oil, fuel NOX generally accounts for
over 50 percent of the total NOX generated. Thermal fixation, on the olher hand, is the dominant NOX
forming mechanism in units firing distillate oils, primarily because of the negligible nitrogen content in
these lighter oils.  Because distillate oil-fired boilers usually have lower heat release rates, the quantity
of thermal NOX formed in them is less than that of larger units.

       A number of variables influence how much NOX is formed by these two mechanisms.  One
important variable is firing configuration.  NOX emissions from tangentially (corner) fired boilers are,
on the average, less than those of horizontally opposed units.  Also important are the firing practices
employed during boiler operatioa Low excess air (LEA) firing, flue gas recirculation (FOR), staged
combustion (SC), reduced air preheat (RAP), low NOX burners (LNBs), or some combination thereof
may result in NOX reductions of 5 to 60 percent.  Load reduction (LR) can likewise decrease NOX
production.  Nitrogen oxides emissions may be reduced from 0.5 to 1 percent for each percentage
reduction in load from full load operation.  It should be noted that most  of these variables, with the
exception of excess air, influence the NOX emissions only of large oil fired boilers. Low excess air-
firing is possible in many small boilers, but the resulting NOX reductions are less significant

       Recent N2O emissions data indicate that direct N2O emissions from oil combustion units are
considerably below the measurements made prior to 1988.  Nevertheless, the N2O formation and
reaction mechanisms are still not well understood or well characterized.  Additional sampling and
research is needed to fully characterize N2O emissions and to understand the N2O  formation
mechanism. Emissions can vary  widely from unit to unit, or even from  rne same unit at different
operating conditions. It has been shown in some cases that N2O increases with decreasing boiler
temperature.  For this update, average emission factors based on reported test data have been
developed for conventional oil combustion systems. These factors are presented in Table 1.3-9.

        The new source performance standards (NSPS) for PM, SO2, and NOX emissions from residual
oil combustion in fossil fuel-fired boilers are shown in Table 1.3-10.

Carbon Monoxide Emissions16"19

        The rate of CO emissions from combustion sources depends on the oxidation efficiency of the
fuel. By controlling the combustion process carefully, CO emissions can be rninimized. Thus if a unit
is operated improperly or not well maintained, the resulting concentrations of CO  (as well as organic
compounds) may increase by several orders of magnitude.  Smaller boilers, heaters, and furnaces tend
to emit more of these pollutants than larger combustors.  This is because smaller units usually have  a
higher ratio of heat transfer surface area to flame volume leading to reduced flame temperature and
combustion intensity and, therefore, lower combustion efficiency than larger combustors.

        The presence of CO in the exhaust gases of combustion systems results principally from
incomplete fuel combustion. Several conditions can lead to incomplete  combustion,  including:

               insufficient oxygen (O^ availability;

               poor fuel/air mixing;
 7/93                             External Combustion Sources                             1.3-3

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               cold wall flame quenching;

               reduced combustion temperature;

               decreased combustion gas residence time; and

               load reduction (i.e., reduced combustion intensity).

 Since various combustion modifications for NOX reduction can produce one or more of the above
 conditions, the possibility of increased CO emissions is a concern for environmental, energy efficiency,
 and operational reasons.

 Organic Compound Emissions16"19-30"35-64

        Small amounts of organic compounds are emitted from combustion. As with CO emissions,
 the rate at which organic compounds are emitted depends, to some extent, on the combustion
 efficiency of the boiler. Therefore, any combustion modification which reduces the combustion
 efficiency will most likely increase the concentrations of organic compounds in the flue gases.

        Total organic compounds (TOCs) include VOCs, semi-volatile organic compounds, and
 condensible organic compounds.  Emissions of VOCs are primarily characterized by the criteria
 pollutant class of unburned vapor phase hydrocarbons.  Unburned hydrocarbon emissions can include
 essentially all vapor phase organic compounds emitted from a combustion source. These are primarily
 emissions of aliphatic, oxygenated, and low molecular  weight aromatic compounds which exist in the
 vapor phase at flue gas temperatures.  These emissions include all alkanes, alkenes, aldehydes,
 carboxylic acids, and substituted benzenes (e.g., benzene, toluene, xylene, and ethyl benzene).

        The remaining organic emissions are composed largely of compounds emitted from
 combustion sources in a condensed phase. These compounds can almost exclusively be classed into a
 group known as polycyclic organic matter (POM), and a subset of compounds called polynuclear
 aromatic hydrocarbons (PNA or PAH).  There are also PAH-nitrogen analogs.  Information available
 in the literature on POM compounds generally pertains to these PAH groups.

        Formaldehyde is formed and emitted during combustion of hydrocarbon-based fuels including
 coal and oil.  Formaldehyde is present hi the vapor phase of the flue gas.  Formaldehyde is subject to
 oxidation and decomposition at the high temperatures encountered during combustion.  Thus, larger
 units with efficient combustion (resulting from closely regulated air-fuel ratios, uniformly high
 combustion chamber temperatures, and relatively long gas retention times) have lower formaldehyde
 emission rates than do smaller, less efficient combustion units.  Average emission factors for POM and
 formaldehyde from fuel oil combustors are presented in Table 1.3-9,  together with N2O emissions data.

Trace Element Emissions16"19' 364

       Trace elements are also emitted from the combustion of oil.  For this update of AP-42, trace
metals included in the list of 189 hazardous air pollutants under Title ffl of the 1990 Clean Air Act
Amendments are considered.  The quantity of trace metals emitted depends on combustion
temperature, fuel feed mechanism, and the composition of the fuel. The temperature determines the
degree of volatilization of specific compounds contained in the fuel.  The fuel feed mechanism affects
the separation of emissions into bottom ash and fly ash.
1.3-4                              EMISSION FACTORS                               7/93

-------
       The quantity of any given metal emitted, in general, depends on:

              the physical and chemical properties of the element itself;

              its concentration in the fuel;

              the combustion conditions;  and

              the type of particulate control device used, and its collection efficiency as a function of
              particle size.

       It has become widely recognized that some trace metals concentrate in certain waste particle
streams from a combustor (bottom ash, collector ash, flue gas particulate), while others do not.
Various classification schemes have been developed to describe this partitioning have been developed.
The classification scheme used by Baig, et al. is as follows:

              Class 1: Elements which are approximately equally distributed between fly ash and
              bottom ash, or show little or no small particle enrichment.

              Class 2: Elements which are enriched in fly ash relative to bottom ash, or show
              increasing enrichment with decreasing particle size.

              Class 3: Elements which are intermediate between Classed 1 and 2.

              Class 4: Elements which are emitted in the gas phase.

       By understanding trace metal partitioning and concentration in fine particulate, it is possible to
postulate the effects of combustion controls on incremental trace metal emissions.  For example,
several NOX controls for boilers reduce peak flame temperatures (e.g., SC, FOR, RAP, and LR). If
combustion temperatures are reduced, fewer Class 2 metals will initially volatilize, and fewer will be
available for subsequent condensation and enrichment on fine PM. Therefore, for combustors with
particulate controls, lowered volatile metal emissions should result due to unproved particulate
removal.  Flue gas emissions of Class  1  metals (the non-segregating trace metals) should remain
relatively unchanged.

       Lower local O2 concentration are also expected to affect segregating metal emissions  from
boilers with particle controls. Lower O2 availability decreases the possibility of volatile metal
oxidation to less volatile oxides. Under these conditions, Class 2 metals should remain in the vapor
phase as they  enter the cooler sections of the boiler. More redistribution to small particles should
occur and emissions should increase. Again, Class 1  metal emissions should remain unchanged.

        Other combustion NOX controls which decrease local O2 concentrations (e.g., SC and FOR)
also reduce peak flame temperatures.  Under these conditions, the effect of reduced combustion
temperature is expected to be stronger than that of lower O2 concentrations. Available trace metals
emissions data for fuel oil combustion in boilers are summarized in Table 1.3-11.

 1.3.3  Controls

        The various control techniques and/or devices employed on oil combustion sources depend on
the source category and the pollutant being controlled. Only controls for criteria pollutants are


7/93                             External Combustion Sources                              1.3-5

-------
 discussed here because controls for non-criteria emissions have not been demonstrated or
 commercialized for oil combustion sources.

        Control techniques may be classified into three broad categories: fuel substitution, combustion
 modification, and post combustion control.  Fuel substitution involves using "cleaner" fuels to reduce
 emissions.  Combustion modification and post- combustion control are both applicable and widely
 commercialized for oil combustion sources. Combustion modification is applied primarily for NOX
 control purposes, although for small units, some reduction in PM emissions may be available through
 improved combustion practice. Post-combustion control is applied to emissions of paniculate matter,
 SO2, and, to some extent, NOX, from oil combustion.

 1.3.3.1 Fuel Substitution3-5-12-56

        Fuel substitution, or the firing of "cleaner" fuel oils, can substantially reduce emissions of a
 number of pollutants.  Lower sulfur oils, for instance, will reduce SOX emissions in all boilers,
 regardless of the size or type of boiler or grade of oil fired.  Particulates generally will be reduced
 when a lighter grade of oil is fired.  Nitrogen oxide emissions will be reduced by switching to either a
 distillate oil or a residual oil with less nitrogen.  The practice of fuel substitution, however, may be
 limited by the ability of a given operation to fire a better grade of oil and by the cost and availability
 of that fuel.

 1.3.3.2 Combustion Modification1"*-8-9-13-14-20

        Combustion modification includes any physical change in the boiler apparatus itself or in its
 operation. Regular maintenance of the burner system, for example, is important to assure proper
 atomization and subsequent minimization of any unburned combustibles. Periodic tuning is important
 in small units for maximum operating efficiency and emissions control, particularly for PM and CO
 emissions. Combustion modifications, such as LEA, FOR, SC, and reduced load operation, result in
 lowered NOX emissions in large facilities.

        Particulate Matter Control56

        Control of PM emissions from residential and commercial units is accomplished by improved
 burner servicing and by incorporating appropriate equipment design changes to improve oil
 atomization and combustion aerodynamics. Optimization of combustion aerodynamics using a flame
 retention device, swirl, and/or recirculation is considered to be the best approach toward achieving the
 triple goals of low PM emissions, low NOX emissions, and high thermal efficiency.

       Large industrial and utility boilers are generally well-designed and well-maintained so that soot
 and condensible organic compound emissions are minimized. Particulate matter emissions are more a
 result of entrained fly ash in such units.  Therefore, post- combustion controls are necessary to reduce
 PM emissions from these sources.

       NO. Control37-57-60

       In boilers fired on crude oil or residual oil, the control of fuel NOX is very important in
 achieving the desired degree of NOX reduction since, typically, fuel NOX  accounts for 60 to 80 percent
of the total NOX formed. Fuel nitrogen conversion to NOX is highly dependent on the fuel-to-air ratio
in the combustion zone and, in  contrast to thermal NOX formation, is relatively insensitive to small
changes in combustion zone temperature, hi general, increased mixing of fuel and air increases


 1.3-6                                EMISSION FACTORS                                 7/93

-------
nitrogen conversion which, in turn, increases fuel NOX. Thus, to reduce fuel NOX formation, the most
common combustion modification technique is to suppress combustion air levels below the theoretical
amount required for complete combustion.  The lack of oxygen creates reducing conditions that, given
sufficient time at high temperatures, cause volatile fuel nitrogen to convert to N2 rather than NO.

       In the formation of both thermal and fuel NOX, all of the above reactions and conversions do
not take place at the same time, temperature, or rate. The actual mechanisms for NOX formation in a
specific situation are dependent on the quantity of fuel bound nitrogen, if any, and me temperature and
stoichiometry of the flame zone.  Although the NOX formation mechanisms are different, both thermal
and fuel NOX are promoted by rapid mixing of fuel and combustion air.  This rate of mixing may itself
depend on fuel characteristics such as the atomization quality of liquid fuels.  Additionally, thermal
NOX is greatly increased by increased residence time at high temperatures, as mentioned above.  Thus,
primary combustion modification controls for both thermal and fuel NOX typically rely on the
following control approaches:

               decrease primary flame zone O2 level by:

                      decreasing overall O2 level;             :
                      controlling (delaying) mixing of fuel and air, and
                      use of fuel-rich primary flame zone.

               decrease residence time at high temperatures by:

                      decreasing adiabatic flame temperature through dilution;
                      decreasing combustion intensity;
                      increasing flame cooling; and
                      decreased primary flame zone residence time.

       Table 1.3-12 shows the relationship between these control strategies and the combustion
modification NOX control techniques currently in use on boilers  firing fuel oil.

1.3.3.3 Post Combustion Control54"56

       Post combustion control refers to removal of pollutants  from combustion flue  gases
downstream of the combustion zone of the boiler.  Flue gas cleaning is usually employed on large oil-
fired boilers.

        Paniculate Matter Control56

        Large industrial and utility boilers are generally, well-designed and well-maintained.  Hence,
particulate collectors are usually the only method of controlling PM emissions from these sources.
Use of such collectors is described below.

        Mechanical collectors, a prevalent type of control device, are primarily useful in controlling
particulates generated during soot blowing, during upset conditions, or when a very dirty heavy oil is
fired.  For these situations, high efficiency cyclonic collectors can achieve up to 85 percent control of
particulate. Under normal firing conditions, or when  a clean oil is combusted, cyclonic collectors are
not nearly so effective because of the high percentage of small particles  (less than 3 micrometers in
diameter) emitted.
 7/93                             External Combustion Sources                             1.3-7

-------
         Electrostatic precipitators (ESPs) are commonly used in oil-fired power plants.  Older
  precipitators, usually small, typically remove 40 to 60 percent of the emitted PM. Because of the low
  ash content of the oil, greater collection efficiency may not be required. Currently, new or rebuilt
  ESPs can achieve collection efficiencies of up to 90 percent

         Scrubbing systems have also been installed on oil fired boilers to control both sulfur oxides
  and particulate.  These systems can achieve SO2 removal efficiencies of 90 to 95 percent and
  paniculate control efficiencies of 50 to 60 percent.

         NO, Control61

         The variety of flue gas treatment NOX control technologies is nearly as great as combustion
 modification techniques.  Although these technologies differ greatly in cost, complexity, and
 effectiveness, they all involve the same basic chemical reaction: the combination of NOX with
 ammonia (NH3) to form nitrogen (Nj) and water
        In selective catalytic reduction (SCR), the reaction takes place in the presence of a catalyst,
 improving performance.  Non-catalytic systems rely on a direct reaction, usually at higher
 temperatures, to remove NOX.  Although removal efficiencies are lower, non-catalytic systems are
 typically less complex and often significantly less costly.  Table 1.3-13 presents various catalytic and
 non-catalytic NOx-reduction technologies.

        SO,  Control62"63

        Commercialized post-combustion flue gas desulfurization (FGD) processes use an alkaline
 reagent to absorb SO2 in the flue gas and produce a sodium or a calcium sulfate compound. These
 solid sulfate  compounds are then removed in downstream equipment Flue gas desulfurization
 technologies  are categorized as wet, semi-dry, or dry depending on the state of the reagent as it leaves
 the absorber  vessel.  These processes are either regenerable (such that the reagent material can be
 treated and reused) or are nonregenerable (in which case all waste streams are  de-watered and
 discarded).

        Wet regenerable FGD processes are attractive because they have the potential for better than
 95 percent sulfur removal efficiency, have minimal waste water discharges, and produce a saleable
 sulfur product Some of the current nonregenerable calcium-based processes can, however, produce a
 saleable gypsum product.

       To date, wet systems are the most commonly applied. Wet systems generally use alkali
 slurries as the SOX absorbent medium and can be designed to remove greater than 90 percent of the
 incoming SOX.  Lime/limestone scrubbers, sodium scrubbers,  and dual alkali scrubbing are among the
 commercially proven wet FGD systems.  Effectiveness of these devices depends not only on control
 device design but also operating variables.  Table 1.3-14 summarizes commercially available post
 combustion SO2 control technologies.
1-3-8                                EMISSION FACTORS                                7/93

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1.3-12
EMISSION FACTORS
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7/93
                External Combustion Sources
                                                                  1.3-13

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1.3-14
EMISSION FACTORS
7/93

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 TABLE 1.3-3 (METRIC UNITS). EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
                  (TOC), METHANE, AND NONMETHANE TOC (NMTOC)
                    FROM UNCONTROLLED FUEL OIL COMBUSTION
 Utility boilers

 No. 6 oil fired,
 normal firing
 (10100401)

 No. 6 oil fired,
 tangential firing
 (10100404)

 No. 5 oil fired,
 normal firing
 (10100405)

 No. 5 oil fired,
 tangential firing
 (10100406)

 No. 4 oil fired,
 normal firing
 (10100504)

 No. 4 oil fired,
 tangential firing
 (10100505)

 Industrial boilers

 No. 6 oil fired
 (102004-01/02/03)

 No. 5 oil fired
 (10200404)
Firing Configuration
(SCC)a
TOCb
Emission
Factor
kg/103 
Rating
Methaneb
Emission
Factor
kg/103 1
Raring
NMTOCb
Emission
Factor
kg/103 
Rating
                          0.125
                          0.125
                          0.125
                          0.125
                          0.125
                          0.125
                          0.154
                          0.154
                           0.030
Distillate oil fired
(102005-01/02/03)

No. 4 oil fired              0.030        A
(10200504)

Commercial/mstitutional/residential combustors
 No. 6 oil fired
 (103004-01/02/03)

 No. 5 oil fired
 (10300404)
                          0.193
                          0.193
0.034
0.034
0.034
0.034
0.034
0.034
 0.12


 0.12


0.006


0.006



0.057


0.057
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         0.091
         0.091
0.091
         0.091
         0.091
0.034


0.034


0.024


0.024



0.136


0.136
A


A


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A
7/93
                              External Combustion Sources
                                  1.3-15

-------
 TABLE 1.3-3 (METRIC UNITS).  EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
                 (TOG), METHANE, AND NONMETHANE TOG (NMTOC)
              FROM UNCONTROLLED FUEL OIL COMBUSTION (Continued)
Firing Configuration
(SCC)m
TOCb
Emission
Factor
kg/103 4
Rating
Methane1'
Emission
Factor
kg/103 C
Rating
NMTOC?
Emission
Factor
kg/103 fi
Rating
 Distillate oil fired
 (103005-01/02/03)
0.067
0.026
0.041
No. 4 oil fired
(10300504)
Residential furnace
(No SCC)
0.067

0.299

A

A

0.026

0.214

A

A

0.041

0.085

A

A

'SCC = Source Classification Code.
""References 16-19. Volatile organic compound emission can increase by several orders of magnitude
 if the boiler is improperly operated or is not well maintained.
1.3-16
      EMISSION FACTORS
                                 7/93

-------
TABLE 1.3-4 (ENGLISH UNITS). EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
                 (TOC), METHANE, AND NONMETHANE TOG (NMTOC)
                    FROM UNCONTROLLED FUEL OIL COMBUSTION
Firing
Configuration
(SCC)a
TOG"
Emission
Factor
lb/103 gal
Rating
Methaneb
Emission
Factor
lb/103 gal
Rating
NMTOC?
Emission
Factor
lb/103 gal
Rating
 Utility boilers

 No. 6 oil fired,           1.04         A
 normal firing
 (10100401)

 No. 6 oil fired,           1.04         A
 tangential firing
 (10100404)

 No. 5 oil fired,           1.04         A
 normal firing
 (10100405)

 No. 5 oil fired,           1.04         A
 tangential firing
 (10100406)

 No. 4 oil fired,           1.04         A
 normal firing
 (10100504)

 No. 4 oil fired,           1.04         A
 tangential firing
 (10100505)

 Industrial boilers

 No. 6 oil fired           1.28         A
 (102004-01/02/03)

 No. 5 oil fired           1.28         A
 (10200404)

 Distillate oil fired       0.252        A
 (102005-01/02/03)

 No. 4 oil fired          0.252        A
 (10200504)

 Commercial/institutional/residential coinbustors

                       1.605        A
No. 6 oil fired
(103004-01/02/03)

No. 5 oil fired
(10300404)
                                             0.28
                                             0.28
                                             0.28
                                             0.28
                                             0.28
                                             0.28
                        1.605
                                             0.052
                                             0.052
0.475
0.475
                       0.76
                       0.76
                       0.76
                       0.76
                       0.76
                       0.76
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7/93
                              External Combustion Sources
                                    1.3-17

-------
TABLE 1.3-4 (ENGLISH UNITS). EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
                (TOC), METHANE, AND NONMETHANE TOG (NMTOC)
              FROM UNCONTROLLED FUEL OIL COMBUSTION (Continued)
Firing
Configuration
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TOCb

Emission
Factor
lb/103 gal
Distillate oil fired 0.556
(103005-01/02/03)
No. 4 oil fired 0.556
(10300504)
Residential furnace 2.493
(No SCQ

Rating


Methane"

Emission
Factor
lb/103 gal
A 0.216

A 0.216

A 1.78


Rating


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Emission
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lb/103 gal
A 0.34

A 0.34

A 0.713


Rating


A

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'SCC = Source Classification Code.
References 16-19. Volatile organic compound emission can increase by several orders of magnitude
 if the boiler is improperly operated or is not well maintained.
1.3-18
EMISSION FACTORS
7/93

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1.3-20
         EMISSION FACTORS
                                             7/93

-------
     TABLE 1.3-7.  CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
           EMISSION FACTORS FOR UNCONTROLLED INDUSTRIAL BOILERS
                              FIRING DISTILLATE OIL8

                           EMISSION FACTOR RATING: E
Particle Sizeb (um)
15
10
6
2.5
1.25
1.00
0.625
TOTAL
Cumulative Mass % <
stated size
Uncontrolled
68
50
30
12
9
8
2
100
Cumulative Emission Factor,
[kg/103 1 (lb/103 gal)]
Uncontrolled
0.16 (1.33)
0.12 (1.00)
0.07 (0.58)
0.03 (0.25)
0.02 (0.17)
0.02 (0.17)
0.005 (0.04)
0.24 (2.00)
*Reference 29.  Source Classification Codes: 102005-01/02/03.
Expressed as aerodynamic equivalent diameter.
7/93
External Combustion Sources
1.3-21

-------
     TABLE 1.3-8. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC
     EMISSION FACTORS FOR UNCONTROLLED COMMERCIAL BOILERS BURNING
                           RESIDUAL AND DISTILLATE OIL8

                            EMISSION FACTOR RATING: D
Particle
Sizeb (um)
15
10
6
2.5
1.25
1.00
0.625
TOTAL
Cumulative Mass %
< stated size
Uncon-
trolled,
Residual
Oil
78
62
44
23
16
14
13
100
Uncon-
trolled,
Distillate
Oil
60
55
49
42
38
37
35
100
Cumulative Emission Factor,0
[kg/103 C (lb/103 gal)]
Uncontrolled,
Residual Oil
0.78A (6.50A)
0.62A (5.17A)
0.44A (3.67A)
0.23A (1.92A)
0.16A (1.33A)
0.14A (1.17A)
0.13A (1.08A)
1A (8.34A)
Uncontrolled,
Distillate Oil
0.14(1.17)
0.13 (1.08)
0.12 (1.00)
0.10 (0.83)
0.09 (0.75)
0.09 (0.75)
0.08 (0.67)
0.24 (2.00)
Reference 29. Source Classification Codes: 103004-01/02/03/04,103005-01/02/03/04.
'Expressed as aerodynamic equivalent diameter.
"Paniculate emission factors for residual oil combustion without emission controls are, on average, a
 function of fuel oil grade and sulfur content:
 No. 6 oil:    A = 1.12(S) + 0.37 kg/103 6 Where S is Ine weight % of sulfur in the oil,
 No. 5 oil:    A = 1.2 kg/103 H
 No. 4 oil:    A = 0.84 kg/103 C
 No. 2 oil:    A = 0.24 kg/103 H
 1.3-22
EMISSION FACTORS
7/93

-------
      It
      53
      g
l.OA
0.9A
0.8A
0.7A
0.6A
O.SA
0.4A
0.3A
0.2A
0.1A
0
                        J	1i  i  i i iir
                                            J
                                                JI  I  11 l
                   .1    .2     .4  .6   1     2     46   10
                                         Particle diameter (pm)
                                                                J	L
0.10A
0.09ft
0.08A
0.07A
0.06A
O.OSA
0.04A
0.03A
0.02A
0.01*
i
"^

II
8
0.01A
0.006A
0.004A

0.002A

0.001A
        E 2
                                                  20
                                                         40  60  100
       I
0.0006A I
0.0004A 
0.0002A 5jj

O.OfiOlA
       Figure 1.3-1.  Cumulative site specific emission factors for utility boilers firing residual oil.
                  l.OA
            I 2
            u
            
                                   .4  .6
                                          1     2     4   6    10    20
                                            Pirticle diameter (pa)
                                                             40  60  100
    Rgure 1.3-2.  Cumulative site specific emission factors for industrial boilers firing residual oil.
7/93                                 External Combustion Sources                               1.3-23

-------
  I
  u
  *

  g
                      0.25
                     0.20
                     0.15
                     o.io
                     0.05
                               J	1i  i  i^i 11
                                        -6    1    ~24  6   10     20     40  60   100
                                                Particle diameter (no)
    Figure 1.3-3.  Cumulative site specific emission factors for uncontrolled industrial boilers firing

                                              distillate oil.
       l.OOA

 >

 ;      0.90A
 1

 I      0.80A
 )


 I      0.70A



 '.    0.60k



 ' C   0.50A



       0.4QA



I      O.JOA
      O.iOA  -

      0

           .1
             g-
                                 Distillate oil
Ji;|  i ! 111	i    i
                                                          Residual oil
                                                               ,1
                                                                                     0.25
                                                                                     0.20 =
                                                                                     0.15
                                                                                    0.10
                                                                                    0.05
                                                                                          o 


                                                                                          1 'S
                              2      .6   1     2     4  6    10     20     40  60  100

                                              Particle diameter (urn)
  Figure 1.3-4.  Cumulative site specific emission factors for uncontrolled commercial boilers burning

                                        residual and distillate oil.
1.3-24
                           EMISSION FACTORS
                                                                  7/93

-------
     TABLE1.3-9. EMISSION FACTORS FOR NITROUS OXIDE (N2O), POLYCYCLIC
          ORGANIC MATTER (POM), AND FORMALDEHYDE (HCOH) FROM
                             FUEL OIL COMBUSTION

                          EMISSION FACTOR RATING: E
Firing Configuration
(SCC)a
Emission Factor, kg/103  (lb/103 gal) ,
N20b
POM6
HCpET
 UtJlitv/mdustrial/comrnercial boilers

          No. 6 oil fired            0.013 (0.11)    3.2-3.6 (7.4-8.4)d   69-174 (161-405)
           (101004-01
            10200401
            10300401)

         Distillate oil fired           0.013(0.11)       9.7 (22)e  ......  100-174(233-405)
            (10100501
            10200501
            10300501)

 Residential furnaces                 0.006 (0.05)         NA               NA
 (No SCC)	

"SCC = Source Classification Code.
References 28-29.
References 16-19.
dParticulate and gaseous POM.
Paniculate POM only.
NA = Not available.
7/93                           External Combustion Sources                         1.3-25

-------
       TABLE 1.3-10. NEW SOURCE PERFORMANCE STANDARDS FOR FOSSIL
                           FUEL FIRED BOILERS
Standard/
Boiler Types/
Applicability
Criteria
Subpart D

Industrial-
Utility

Commence
construction
after 8/17/71
Subpart Da

Utility
Commence
construction
after 9/18/78



Subpart Db

Industrial-
Commercial-
Institutional

Commence
construction
after 6/19/84









Boiler Size Fuel
MW or
(Million Boiler
Btu/hr) Type
>73 Gas
(>250)

Oil


Bit/SubbiL
Coal
>73 Gas
(>250)

Oil


BiL/SubbiL
Coal

>29 Gas
(>100)

Distillate Oil



Residual Oil

Pulverized
BiL/SubbiL
Coal

Spreader
Stoker & FBC

Mass-Feed
Stoker
PM
ng/J
(Ib/MMBtu)
[% reduction]
43
(0.10)

43
(0.10)

43
(0.10)
13
(0.03
[NA]
13
(0.03)
[70]
13
(0.03)
[99]
NAd


43
(0.10)


(Same as for
distillate oil)
22e
(0.05)

22e
(0.05)

22e
(0.05)

SO2
ng/J
(Ib/MMBtu)
[% reduction]
NA


340
(0.80)

520
(1.20)
340
(0.80)
[90]a
340
(0.80)
[90f
520
(1.20)
[90]b
NAd


340
(0.80)
[90]

(Same as for
distillate oil)
520e
(1.20)
[90]
520e
(1.20)
[90]
520e
(1.20)
[90]
NOX
ng/J
(Ib/MMBtu)
[% reduction]
6(3
(0.20)

129
(0.30)

300
(0.70)
86
(020)
[25]
130
(0.30)
[30]
260/210C
(0.60/0.50)
[65/65]
43f
(0.10)

43f
(0.10)


130*
(0.30)
300
(0.70)

260
(0.60)

210
(0.50)

1.3-26
EMISSION FACTORS
7/93

-------
         TABLE 1.3-10.  NEW SOURCE PERFORMANCE STANDARDS FOR FOSSIL
                             FUEL FIRED BOILERS (Continued)
Standard/
Boiler Types/
Applicability
Criteria
Subpart DC

Small
Ladustrial-
Commercial-
Institutional

Commence
construction
after
6/9/89
Boiler Size
MW
(Million
Btu/hr)
2.9 - 29
(10 - 100)









Fuel
or
Boiler
Type
Gas


Oil


Bit & Subbit
Coal



PM
ng/J
(Ib/MMBtu)
[% reduction]
_h


Jy


22j*
(0.05)



SO2
ng/J
(Ib/MMBtu)
[% reduction]
-


215
(0.50)

520k
(1.20
[90]


NO,
ng/J
(Ib/MMBtu)
[% reduction]
-


-


-




"Zero percent reduction when emissions are less than 86 ng/J (0.20 Ib/MMBtu).
70 percent reduction when emissions are less than 260 ng/J (0.60 Ib/MMBtu).
The first number applies to bituminous coal and me second to subbituminous coal.
Standard applies when gas is fired in combination with coal, see 40 CFR 60, Subpart Db.
'Standard is adjusted for fuel combinations and capacity factor limits, see 40 CFR 60, Subpart Db.
*For furnace heat release rates greater than 730,000 J/s-m3 (70,000 Btu/hr-ft3), the standard Is 86 ug/J
 (0.20 Ib/MMBtu).
Tor furnace heat release rates greater than 730,000 J/s-m3 (70,000 Btu/hr-ft3), the standard is 170 ng/J
 (0.40 Ib/MMBtu).
Standard applies when gas or oil is fired in combination with coal, see 40 CFR 60, Subpart DC.
J20 percent capacity limit applies for heat input capacities of 8.7 Mwt (30 MMBtu/hr) or greater.
kStandard is adjusted for fuel combinations and capacity factor limits, see 40 CFR 60, Subpart DC.
""Additional requirements apply to facilities  which commenced construction, modification, or
 reconstruction after 6/19/84 but on or before 6/19/86 (see 40 Code of Federal Regulations Part 60,
 Subpart Db).
"215 ng/J (0.50 Ib/million Btu) limit (but no percent reduction requirement) applies if facilities
 combust only very low sulfur oil (< 0.5 wL % sulfur).
 FBC = Fluidized bed combustion.
7/93
External Combustion Sources
1.3-27

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                                                                  8
1.3-30
                          EMISSION FACTORS
                                                                         7/93

-------
          TABLE 1.3-13. POST-COMBUSTION NOX REDUCTION TECHNOLOGIES
Technique
Description
Advantages
Disadvantages
1. Urea
injection
2. Ammonia
injection
(Thennal-
DeNO,)
3. Air Heater
(AH-)SCR
1
4. Duct SCR
5. Activated
Carbon
SCR
Injection of urea
into furnace to react
with NOX to form
N2 and H2O
Injection of
ammonia into
furnace to react
with NOX to form
NjandHjO
Air heater baskets
replaced with
catalyst coated
baskets. Catalyst
promotes reaction
of ammonia with
NOX.
A smaller version of
conventional SCR is
placed in existing
ductwork
Activate carbon
catalyst, installed
downstream of air
heater, promotes
reaction of
ammonia with NOX
at low temperature.
- Low capital cost
- Relatively simple system
- Moderate NOX removal (30-
60%)
- Non-toxic chemical
- Typically, low energy injection
sufficient
- Low operating cost
- Moderate NOX removal (30-
60%)
- Moderate NOX removal (40-65
%)
- Moderate capital cost
- No additional ductwork or
reactor required
- Low pressure drop
- Can use urea as ammonia
feedstock
- Rotating air heater assists
mixing, contact with catalyst
- Moderate capital cost
- Moderate NOX removal (30%)
- No additional ductwork
required
- Active at low temperature
- High surface area reduces
reactor size
- Low cost of catalyst
- Can use urea as ammonia
feedstock
- Activated carbon is non-
hazardous material
- Temperature dependent
- Design must consider boiler operating
conditions and design
- Reduction may decreased at lower
loads
- Moderately high capital cost
- Ammonia handling, storage,
vaporization and injection systems
required (Ammonia is a toxic
chemical)
- Design must address pressure drop,
maintain heat transfer
- Due to rotation of air heater, only
50% of catalyst is active at any time
- Duct location unit specific
temperature, access dependent
- Some pressure drop must be
accommodated
- High pressure drop
- Not a fully commercial technology
                               SOX removal as well as NOX
                               removal
 7/93
                External Combustion Sources
                                         1.3-31

-------
       TABLE 1.3-13.  POST-COMBUSTION NOX REDUCTION TECHNOLOGIES (Continued)
 Technique
    Description
         Advantages
          Disadvantages
LUrea
  injection
Injection of uiea
into furnace to react
with NOX to form
N2 and
- Low capital cost
- Relatively simple system
- Moderate NOX removal (30-
 60%)
- Non-toxic chemical
- Typically, low energy injection
 sufficient
6. Conven-
  tional SCR
Catalyst located in
flue gas stream
(usually upstream of
air heater) promotes
reaction of
ammonia with NOX.
- High NOX removal (90%)
Temperature dependent
Design must consider boiler operating
conditions and design
Reduction may decreased at lower
loads
Very high capital cost
High operating cost
Extensive ductwork to/from reactor
Large volume reacio* muci be d*ef
Increased pressure drop may require
ID fan or larger FD fan
Reduced efficiency
Ammonia sulfate removal equipment
for air heater
Water treatment of air heater wash
  1.3-32
                      EMISSION FACTORS
                                                    7/93

-------
           TABLE 1.3-14.  POST-COMBUSTION SO2 CONTROLS FOR FUEL OIL
                                 COMBUSTION SOURCES
 Control Technology     Process
                          Typical Control
                            Efficiencies
                Remarks
 Wet scrubber
Lime/limestone
80-95+%
Applicable to high
sulfur fuels,
Wet sludge product
                        Sodium carbonate
                             80-98%
                 1-125 MW (5-430
                 million Btu/hr) typical
                 application range,
                 High reagent costs
 Spray drying
                        Magnesium
                        oxide/hydroxide

                        Dual alkali
Calcium hydroxide
slurry, vaporizes in
spray vessel
                             80-95+%
                             90-96%
 70-90%
                Can be regenerated
                Uses lime to
                regenerate sodium-
                based scrubbing liquor
Applicable to low and
medium sulfur fuels,
Produces dry product
 Furnace injection
Dry calcium
carbonate/hydrate
injection in upper
furnace cavity
 25-50%
Commercialized in
Europe,
Several U.S.
demonstration projects
underway
 Duct injection
Dry sorbent injection
into duct, sometimes
combined with water
spray
25-50+%
Several R&D and
demonstration projects
underway,
Not yet commercially
available in the U.S.
7/93
        External Combustion Sources
                                1.3-33

-------
 References for Section 1.1

 1.      W.S. Smith, Atmospheric Emissions from Fuel Oil Combustion:  An Inventory Guide.
        999-AP-2, U.S. Environmental Protection Agency, Washington, DC, November 1962.

 2.      J.A. Danielson (ed.), Air Pollution Engineering Manual. Second Edition, AP-40, U.S.
        Environmental Protection Agency, Research Triangle Park, NC, 1973. Out of Print.

 3.      A. Levy, et al.. A Field Investigation of Emissions from Fuel Oil Combustion for Space
        Heating. API Bulletin 4099, Battelle Columbus Laboratories, Columbia, OH, November 1971.

 4.      RJB. Barrett, etal.. Field Investigation of Emissions from Combustion Equipment for Space
        Heating. EPA-R2-73-084a,  U.S. Environmental Protection Agency, Research Triangle Park,
        NC, June 1973.

 5.      G.A. Cato, etal.. Field Testing: Application of Combustion Modifications To Control
        Pollutant Emissions from Industrial Boilers - Phase I. EPA-650/2-74-078a, U.S. Environmental
        Protection Agency, Washington, DC, October 1974.

 6.      G.A. Cato, etal.. Field Testing: Application of Combustion Modifications To Control
        Pollutant Emissions ftom Industrial Boilers - Phase II. EPA-600/ 2-76-086a, U.S.
        Environmental Protection Agency, Washington, DC, April 1976.

 7.      Particulate Emission Control Systems for Oil Fired Boilers. EPA-450/3-74- 063, U.S.
        Environmental Protection Agency, Research Triangle Park, NC, December 1974.

 8.      W. Bartok, etal.. Systematic Field Study of NOx Emission Control Methods for Utility
        Boilers. APTD-1163, U.S. Environmental Protection Agency, Research Triangle Park, NC,
        December 1971.

 9.      A.R. Crawford, etal.. Field Testing: Application of Combustion Modifications To Control
        NOx Emissions from Utility Boilers. EPA-650/2-74-066, U.S. Environmental Protection
        Agency, Washington, DC, June 1974.

 10.    J.F. Deffner, etal.. Evaluation of Gulf Econojet Equipment with Respect to Air Conservation.
       Report No. 731RC044, Gulf Research and Development Company, Pittsburgh, PA, December
        18,1972.

 11.    CJ3. Blakeslee and H.E. Burbach, "Controlling NOx Emissions from Steam Generators,"
       Journal of the Air Pollution Control Association. 23:37-42, January 1973.

 12.    C.W. Siegmund, "Will Desulfurized Fuel Oils Help?," American Society of Heating.
       Refrigerating and Air Conditioning Engineers Journal. 11:29-33, April  1969.

 13.    F.A. Govan, et al., "Relationships of Particulate Emissions Versus Partial to Full Load
       Operations for Utility-sized  Boilers-," Proceedings of Third Annual Industrial Air Pollution
       Control Conference. Knoxville, TN, March 29-30, 1973.

14.    R.E.  Hall, et al.. A Study of Air Pollutant Emissions from Residential  Heating Systems.
       EPA-650/2-74-003, U.S. Environmental Protection Agency, Washington, DC, January 1974.


1.3-34                              EMISSION FACTORS                                7/93

-------
15.     RJ. Milligan, etal.. Review of. NOx Emission Factors- for Stationary Fossil Fuel Combustion
       Sources. EPA-450/4-79-021, U.S. Environmental Protection Agency, Research Triangle Paik,
       NC, September 1979.

16.     N.F. Suprenant, etal.. Emissions Assessment of Conventional Stationary Combustion Systems.
       Volume I:  Gas and Oil Fired Residential Heating Sources. EPA-600/7-79-029b, U.S.
       Environmental Protection Agency, Washington, DC, May 1979.

17.     C.C. Shin, et al.. Emissions Assessment of Conventional Stationary Combustion Systems.
       Volume HI: External Combustion Sources for Electricity Generation. EPA Contract No.
       68-02-2197, TRW, Inc., Redondo Beach, CA, November 1980.

18.     N.F. Suprenant, etal., Emissions Assessment of Conventional Stationary Combustion System.
       Volume IV: Commercial Institutional Combustion Sources. EPA Contract No. 68-02-2197,
       GCA Corporation, Bedford, MA,  October 1980.

19.     N.F. Suprenant, etal.. Emissions Assessment of Conventional Stationary Combustion Systems.
       Volume V:  Industrial Combustion Sources. EPA Contract No. 68-02-2197, GCA Corporation,
       Bedford, MA,  October 1980.

20.     K J. Lim, etal.. Technology Assessment Report for Industrial Boiler Applications: NOx
       Combustion Modification. EPA-600/7-79-178f, U.S. Environmental Protection Agency,
       Washington, DC, December 1979.

21.     Emission Test Reports, Docket No.  OAQPS-78-1, Category II-I-257 through 265, Office Of
       Air Quality Planning And Standards, U.S. Environmental Protection Agency, Research
       Triangle Park, NC, 1972 through 1974.

22.     Primary Sulfate Emissions from Coal and Oil Combustion. EPA Contract No. 68-02-3138,
       TRW, Inc., Redondo Beach, CA, February 1980.

23.     C. Leavitt, etal.. Environmental Assessment of an Oil Fired Controlled Utility Boiler.
       EPA-600/7-80-087, U.S. Environmental Protection Agency, Washington, DC, April 1980.

24.     W.A. Carter and RJ. Tidona, Thirty-day Field Tests of Industrial Boilers:  Site 2 -
       Residual-oil-fired Boiler. EPA-600/7-80-085b, U.S. Environmental Protection Agency,
       Washington, DC, April 1980.

25.     D.W. Pershing, etal.. Influence of Design Variables on the Production of Thermal and Fuel
       NO from Residual Oil and Coal Combustion. Air:  Control of NOx and SOx Emissions, New
       York, American Institute of Chemical Engineers, 1975.

26.     Fossil Fuel Fired Industrial Boilers  - Background Information: Volume 1. EPA-450/3-82-
       006a, U.S. Environmental Protection Agency, Research Triangle Park, NC, March 1982.

27.     U.S. Environmental Protection Agency, "National Primary and Secondary Ambient Air Quality
       Standards," Code of Federal Regulations, Title 40, Part 50, U.S. Government Printing Office,
       Washington DC, 1991.
7/93                            External Combustion Sources                          1.3-35

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 28.     R. Clayton, etal.. N,O Field Study. EPA-600/2-89-006, U.S. Environmental Protection
        Agency, Research Triangle Park, NC, February 1989.

 29.     Evaluation of Fuel-Based Additives for N,O and Air Toxic Control in Fluidized Bed
        Combustion Boilers. EPRI Contract No. RP3197-02, Acurex Report No. FR-91-101-/ESD,
        (Draft Report) Acurex Environmental, Mountain View, CA, June 17, 1991.

 30.     Particulate Polycyclic Organic Matter. Nation Academy of Sciences, Washington, DC, 1972.

 31.     Vapor Phase Organic Pollutants  Volatile Hydrocarbons and Oxidation Products. National
        Academy of Sciences, Washington, DC, 1976.

 32.     H. Knierien, A Theoretical Study of PCB Emissions from Stationary Sources. EPA-600/7-76-
        028, U.S.  Environmental Protection Agency, Research Triangle Park, NC, September 1976.

 33.     Estimating Air Toxics Emissions From Coal and Oil Combustion Sources. EPA-450/2-89-001,
        U.S. Environmental Protection Agency, Research Triangle Park, NC, April 1989.

 34.     R J?. Hagebrauck, D. J. Von Lehmden, and J.E. Meeker, "Emissions of Polynuclear
        Hydrocarbons and Other Pollutants from Heat-Generation and Incineration Process," J. Air
        Pollution Control Assoc. 14:267-278, 1964.

 35.     M.B. Rogozen, etal.. Formaldehyde:  A Survey of Airborne Concentration and Sources.
        California Air Resources Board, ARE report no. ARB/R-84-231, 1984.

 36.     Clean Air Act Amendments of 1990, Conference Report To Accompany S. 1603, Report 101-
        952, U.S. Government Printing Office, Washington, DC, October 26, 1990.

 37.     K. J. Lim, etal.. Industrial Boiler Combustion Modification NOx Controls - Volume I
        Environmental  Assessment EPA-600/7-81-126a, U.S. Environmental Protection Agency, July
        1981.

 38.     D.H. Klein, etal.. "Pathways of Thirty-Seven Trace Elements Through Coal-Fired Power
        Plants," Environ. Sci. Technol.. 9:973-979, 1975.

 39.     D.G. Coles, etal.. "Chemical Studies of Stack Fly Ash From a Coal-Fired Power Plant,"
        Environ. Sci. Technol.. 13:455-459, 1979.

 40.     S. Baig, etal.. Conventional Combustion Environmental Assessment. EPA Contract No. 68-02-
        3138, U.S. Environmental Protection Agency, Research Triangle Park, NC, 1981.

41.     Code of Federal Regulations. 40. Parts 53 to  60 . July 1, 1991.

42.    Environmental Assessment of Coal and Oil Firing hi a Controlled Industrial Boiler.  Volume I.
       PB 289942, U.S. Environmental  Protection Agency, August 1978.

43.    Environmental Assessment of Coal and Oil Firing in a Controlled Industrial Boiler.  Volume II.
       EPA-600/7-78-164b, U.S. Environmental Protection Agency, August 1978.
1.3-36                              EMISSION FACTORS                               7/93

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44.    Environmental Assessment of Coal and Oil Firing in a Controlled Industrial Boner. Volume
       HI, EPA-600/7-78-164c, U.S. Environmental Protection Agency, August 1978.

45     Emission Reduction on Two Industrial Boilers with Major Combustion Modifications. EPA-
       600/7-78-099a, U.S. Environmental Protection Agency, August 1978.

46.    Emission Reduction on Two Industrial Boilers with Major Combustion Modifications, Data
       Supplement EPA-600/7-78-099b, U.S. Environmental Protection Agency, August 1978.

47.    Industrial Boilers Emission Test Report. Boston Edison Company. Everett  Massachusetts,
       EMB Report 81-IBR-15, U.S. Environmental Protection Agency, Office of Air Quality
       Planning and Standards, October 1981.

48.    Residential Oil Furnace System Optimization, phase II. EPA-600/2-77-028, U.S.
       Environmental Protection Agency, January 1977.

49.    Characterization of Particulate Emissions from Refinery Process Heaters and Boilers, API
       Publication No. 4365, June 1983. U.S. Environmental Protection Agency, January 1977.

50.    James Ekmann, etal.. Comparison of Shale Oil and Residual Fuel Combustion in Symposium
       Papers New Fuels and Advances in Combustion Technologies Sponsored by Institute of Gas
       Technology. March 1979.

51.    Overview of the Regulatory Baseline. Technical Basis, and Alternative Control Levels for SO2
       Emission Standards for Small Steam Generating Units. EPA-450/3-89-012, U.S. Environmental
       Protection Agency, May 1989.

52.    Overview of the Regulatory Baseline. Technical Basis, and Alternative Control Levels for NOx
       Emission Standards for Small Steam Generating Units. EPA-450/3-89-013, U.S. Environmental
       Protection Agency, May 1989.

53.    Overview of the Regulatory Baseline. Technical Basis, and Alternative Control Levels for PM
       Emission Standards for Small Steam Generating Units. EPA-450/3-89-014, U.S. Environmental
       Protection Agency, May 1989.

54.    Flue Gas Desulfurization:  Installations and Operations. PB 257721, National Technical
       Information Service, Springfield, VA, September  1974.

55.    Proceedings:  Hue Gas Desulfurization Symposium - 1973. EPA-650/2-73-038, U.S.
       Environmental Protection Agency, Washington, DC, December 1973.

56.    G.R. Offen, etal.. Control of Particulate Matter from Oil Burners and Boilers.
       EPA-450/3-76-005, U.S. Environmental Protection Agency, Research Triangle Park, NC, April
       1976.

57.    J.H. Pohl and A.F. Sarofim, Devolatilization and  Oxidation of Coal Nitrogen (presented at the
       16th International Symposium on Combustion), August 1976.
 7/93                            External Combustion Sources                           1.3-37

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 58.     D.W. Pershing and J. Wendt, Relative Contribution of Volatile and Char Nitrogen to NOx
        Emissions From Pulverized Coal Flames. Industrial Engineering Chemical Proceedings, Design
        and Development, 1979.

 59.     D.W. Pershing, Nitrogen Oxide Formation in Pulverized Coal Flames. Ph.D. Dissertation,
        University of Arizona, 1976.

 60.     P.B. Nuteher, High Technology Low NOx Burner Systems for Fired Heaters and Steam
        Generators. Process Combustion Corp., Pittsburgh, PA, Presented at the Pacific Coast Oil
        Show and Conference, Los Angeles, CA, November 1982.

 61.     M.N. Mansour, etal.. Integrated NOx Reduction Plan to Meet Staged SCAOMD Requirements
        for Steam Electric Power Plants. Proceedings of the 53rd American Power Conference, 1991.

 62.     D.W. South, etal.. Technologies and Other Measures For Controlling Emissions:
        Performance. Costs, and Applicability. Acidic Deposition: State of Science  and Technology,
        Volume IV, Report 25, National Acid Precipitation Assessment Program, U.S. Government
        Printing Office, Washington, DC, December 1990.

 63.     EPA Industrial Boiler FGD Survey: First Quarter 1979. EPA-600/7-79-067b, U.S.
        Environmental Protection Agency, April 1979.
1.3-38                             EMISSION FACTORS                              7/93

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1.4 NATURAL GAS COMBUSTION

1.4.1  General1"2

       Natural gas is one of the major fuels used throughout the country. It is used mainly for
industrial process steam and heat production; for residential and commercial space heating; and for
electric power generation. Natural gas consists of a high percentage of methane (generally above 80
percent) and varying amounts of ethane, propane, butane, and inerts (typically nitrogen, carbon
dioxide, and helium). Gas processing plants are required for the recovery of liquefiable constituents
and removal of hydrogen sulfide before the gas is used (see Natural Gas Processing, Section 9.2).  The
average gross heating value of natural gas is approximately 8900 kilocalories per standard cubic meter
(1000 British thermal units per standard cubic foot), usually varying from 8000 to 9800 kcal/scm (900
to 1100 Btu/scf).

1.4.2 Emissions and Controls3"5

        Even though natural gas is considered to be a relatively clean-burning fuel, some emissions
can result from combustioa For example, improper operating conditions, including poor air/fuel
mixing, insufficient air, etc., may cause large amounts of smoke, carbon monoxide (CO), and organic
compound emissions.  Moreover, because a sulfur-containing mercaptan is added to natural gas to
permit leak detection, small amounts of sulfur oxides will be produced in the combustion process.

        Nitrogen oxides (NOX) are the major pollutants of concern when burning natural gas.  Nitrogen
oxide emissions depend primarily on the peak temperature within the combustion chamber as well as
the furnace-zone oxygen concentration, nitrogen concentration, and time of exposure at peak
temperatures.  Emission levels vary considerably with the type and size of combustor and with
operating conditions (particularly combustion air temperature, load, and excess air level in boilers).

        Currently, the two most prevalent NOX control techniques being applied to natural gas-fired
boilers (which result hi characteristic changes in emission rates) are low NOX burners and flue gas
recirculation.  Low NOX burners reduce NOX by accomplishing the combustion process in stages.
Staging partially delays the combustion process, resulting in a cooler flame which suppresses NOX
formation. The three most common types of low NOX burners being applied to natural gas-fired
boilers are staged air burners, staged  fuel burners, and radiant fiber burners. Nitrogen oxide emission
 reductions of 40 to 85  percent (relative to uncontrolled emission levels) have been observed with low
 NOX burners. Other combustion staging techniques which have been applied to natural gas-fired
 boilers include low excess air, reduced air preheat, and staged combustion (e.g., bumers-out-of-service
 and overfire air). The degree of staging is a key operating parameter influencing NOX emission rates
 for these systems.

        In a flue gas recirculation (FOR) system, a portion of the flue gas is recycled from the stack to
 the burner windbox. Upon entering the windbox, the gas is mixed with combustion air prior to being
 fed to the burner. The FOR system reduces NOX emissions by two mechanisms. The recycled flue
 gas in made up of combustion products which act as inerts during combustion of the fuel/air mixture.
 This additional mass is heated hi the combustion zone, thereby lowering  the peak flame temperature
 and reducing the amount of NOX formed.  To a lesser extent, FOR also reduces NOX formation by

 7/93                              External Combustion Sources                             1.4-1

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lowering the oxygen concentration in the primary flame zone.  The amount of flue gas recirculated is a
key operating parameter influencing NOX emission rates for these systems.  Hue gas recirculation is
normally used in combination with low NOX burners. When used in combination, these techniques are
capable of reducing uncontrolled NOX emissions by 60 to 90 percent

       Two post-combustion technologies that may be applied to natural gas-fired boilers to reduce
NOX emissions by further amounts are selective noncatalytic reduction and selective catalytic
reduction.  These systems inject ammonia (or urea) into combustion flue gases to reduce inlet NOX
emission rates by 40 to 70 percent

       Although not measured, all paniculate matter (PM) from natural gas combustion has been
estimated to be less than 1 micrometer in size. Paniculate matter is composed of filterable and
condensible fractions, based on the EPA sampling method.  Filterable and condensible emission rates
are of the same order of magnitude for boilers; for residential furnaces, most of the PM is hi the form
of condensible material.

       The rates of CO and trace organic emissions from boilers and furnaces depend on the
efficiency of natural gas combustion.  These emissions are minimized by combustion practices mat
promote high combustion temperatures, long residence times at those temperatures, and turbulent
mixing of fuel and combustion air.  In some cases, the addition of NOX control  systems such as FOR
and low NOX burners reduces combustion efficiency (due to lower combustion temperatures), resulting
in higher CO and organic emissions relative to uncontrolled boilers.

       Emission factors for natural gas combustion in boilers and furnaces are presented in Tables
1.4-1 through 1.4-3.  For the purposes  of developing emission factors, natural gas combustors have
been organized into four general categories:  utility/large industrial boilers, small industrial boilers,
commercial boilers, and residential furnaces.  Boilers and furnaces within these  categories share the
same general design and operating characteristics and hence have similar emission characteristics when
combusting natural gas. The primary factor used to demarcate the individual combustor categories is
heat input
                                                            O
1.4-2
EMISSION FACTORS
                                                                                       7/93

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              Figure 1.4-1.  Load reduction coefficient as a function of boiler load.
              (Used to determine NOX reductions at reduced loads in large boilers.)
7/93
External Combustion Sources
1.4-3

-------

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7/93
External Combustion Sources
1.4-5

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-------
References for Section 1.4

1.  Exhaust Gases From Combustion and Industrial Processes, EPA Contract No. EHSD 71-36,
    Engineering Science, Inc., Washington, DC, October 1971.

2.  Chemical Engineers' Handbook, Fourth Edition, J. H. Perry, Editor, McGraw-Hill Book
    Company, New York, NY, 1963.

3.  Background Information Document For Industrial Boilers, EPA-450/3-82-006a, U. S.
    Environmental Protection Agency, Research Triangle Park, NC, March 1982.

4.  Background Information Document For Small Steam Generating Units, EPA-450/3-87-000, U. S.
    Environmental Protection Agency, Research Triangle Park, NC, 1987.

5.  Fine P'articulate Emissions From Stationary and Miscellaneous Sources in the South Coast Air
    Basin, California Air Resources Board Contract No. A6-191-30, KVB, Inc., Tustin, CA, February
     1979.

6.  Emission Factor Documentation for AP-42 Section 1.4 - Natural Gas Combustion (Draft),
    Technical Support Division, Office of Air Quality Planning and Standards, U. S. Environmental
    Protection Agency, Research Triangle Park, NC, April 1993.

7.  Systematic Field Study ofNOx Emission Control Methods For Utility Boilers, APTD-1163, U. S.
    Environmental Protection Agency, Research Triangle Park, NC, December 1971.

8.   Compilation of Air Pollutant Emission Factors, Fourth Edition, AP-42, U. S. Environmental
     Protection Agency, Research Triangle Park, NC, September 1985.

9.   J. L. Muhlbaier, "Paniculate and Gaseous Emissions From Natural Gas Furnaces and Water
     Heaters", Journal of the Air Pollution Control Association, December 1981.

 10.  Field Investigation of Emissions From Combustion Equipment for Space Heating, EPA-R2-73-
     084a, U. S. Environmental Protection Agency,  Research Triangle Park, NC, June 1973.

 11.  N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary Combustion Systems,
     Volume  I:  Gas and Oil Fired Residential Heating Sources, EPA-600/7-79-029b, U. S.
     Environmental Protection Agency, Washington, DC, May 1979.

 12.  C. C. Shih, et al., Emissions Assessment of Conventional Stationary Combustion Systems, Volume
     HI: External Combustion Sources for Electricity Generation, EPA Contract No. 68-02-2197,
     TRW, Inc., Redondo Beach, CA, November 1980.

 13.  N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary Combustion Systems,
     Volume  IV:  Commercial/Institutional Combustion Sources, EPA Contract No. 68-02-2197, GCA
     Corporation, Bedford, MA, October 1980.
 7/93                            External Combustion Sources                            1.4-7

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References for Section 1.4 (Continued)

14. N. F. Suprenant, et al., Emissions Assessment of Conventional Stationary Combustion Systems,
    Volume V: Industrial Combustion Sources, EPA Contract No. 68-02-2197, GCA Corporation,
    Bedford, MA, October 1980.

15. Emissions Test on 200 HP Boiler at Kaiser Hospital in Woodland Hills, Energy Systems
    Associates, Tustin, CA, June 1986.

16. Results From Performance Tests: California Milk Producers Boiler No. 5, Energy Systems
    Associates, Tustin, CA, November 1984.

17. Source Test For Measurement of Nitrogen Oxides and Carbon Monoxide Emissions From Boiler
    Exhaust at GAP Building Materials, Pacific Environmental Services, Inc., Baldwin Park, CA,
    May 1991.

18. J. P. Kesselring and W. V. Krill, "A Low-NOx Burner For Gas-Fired Firetube Boilers",
    Proceedings: 1985 Symposium on Stationary Combustion NOX Control, Volume 2, EPRI CS-4360,
    Electric Power Research Institute, Palo Alto, CA, January 1986.

19. NOX Emission Control Technology Update, EPA Contract No. 68-01-6558,  Radian Corporation,
    Research Triangle Park, NC, January 1984.

20. Background Information Document For Small Steam Generating Units, EPA-450/3-87-000, U. S.
    Environmental Protection Agency, Research Triangle Park, NC, 1987.

21. Evaluation of the Pollutant Emissions From Gas-Fired Forced Air Furnaces: Research Report
    No. 1503, American Gas Association Laboratories, Cleveland, OH, May 1975.

22. Thirty-day Field Tests of Industrial Boilers:  Site 5 - Gas-fired Low-NOx Burner, EPA-600/7-81-
    095a, U. S. Environmental Protection Agency, Research Triangle Park, NC, May 1981.

23. Private communication from Kim Black (Industrial Combustion) to Ralph Harris (MRI),
    Independent Third Party Source Tests, February 7,1992.
1.4-8
EMISSION FACTORS
7/93

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1.5 LIQUEFIED PETROLEUM GAS COMBUSTION

1.5.1   General1

       Liquefied petroleum gas (LPG or LP-gas) consists of propane, propylene, butane, and
butylenes; the product used for domestic heating is substantially propane. This gas, obtained mostly
from gas wells (but also to a lesser extent as a refinery by-product) is stored as a liquid under
moderate pressures. There are three grades of LPG available as heating fuels:  commercial-grade
propane, engine fuel-grade propane (also known as HD-5 propane), and commercial-grade butane.  In
addition, there are high purity grades of LPG available for laboratory work and for use as aerosol
propellants.  Specifications for the various LPG grades are available from the American Society for
Testing and Materials and the Gas Processors Association.  A typical heating value for commercial-
grade propane and  HD-5 propane is 6,090 kcal/liter (91,500 Btu/gallon), after vaporization; for
commercial-grade butane, the value is 6,790 kcal/liter (102,000 Btu/gallon).

       The largest market for LPG is the domestic/commercial market, followed by the chemical
industry (where it is used as a petrochemical feedstock) and agriculture. Propane is also used as an
engine fuel as  an alternative to gasoline and as a stand-by fuel for facilities that have interruptible
natural gas service  contracts.

1.5.2   Emissions and Controls1"4

       Liquefied petroleum gas is considered a "clean" fuel because it does  not produce visible
emissions. However, gaseous pollutants such as carbon monoxide (CO), organic compounds, and
nitrogen oxides (NOX) do occur. The most significant factors affecting these emissions are burner
design, burner adjustment, and flue gas A'enting.  Improper design, blocking and clogging of the flue
vent, and insufficient combustion air result in improper combustion and the emissions of aldehydes,
CO, hydrocarbons, and other organics. Nitrogen oxide emissions are a function of a number of
variables, including temperature, excess ah-, fuel/air mixing, and residence time in the combustion
zone. The amount of sulfur dioxide (SOz) emitted  is directly proportional to the amount of sulfur in
the fuel. Emission factors for LPG combustion are presented in Tables 1.5-1 and 1.5-2.

        Nitrogen oxides are the only pollutant for which emission controls have been developed.
Propane and butane are being used in Southern California as backup fuel to natural gas, replacing
distillate oil hi this role pursuant to the phaseout of fuel oil in that region. Emission controls for NOX
have been developed for firetube and watertube boilers firing propane or butane.  Vendors are now
warranting retrofit systems to levels as low as 30 to 40 ppm (based on 3 percent oxygen).  These low-
NOX systems use a combination of low NOX burners and flue gas  recirculation. Some burner vendors
use water or steam injection into the flame zone for NOX reduction. This is a trimming technique
which may be necessary during backup fuel periods because LPG typically has a higher NOx-forming
potential than natural gas; conventional natural gas emission control systems may not be sufficient to
reduce LPG emissions to mandated levels.  Also, LPG burners are more prone to sooting under the
modified combustion conditions required for low NOX emissions.  The extent of allowable combustion
modifications for LPG may be more  limited than for natural gas.

        One NOX control system that has been demonstrated on small commercial boilers is flue  gas
recirculation (FOR).  Nitrogen oxide emissions from propane combustion can be reduced by as much
7/93                             External Combustion Sources                             1.5-1

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as 50 percent by reciiculating 16 percent of the flue gas. Nitrogen oxide emission reductions of over
60 percent have been achieved with FOR and low NOX burners used in combination.
1.5-2
EMISSION FACTORS
7/93

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             'TABLE 1.5-1. (ENGLISH UNITS) EMISSION FACTORS FOR LPG
                                     COMBUSTION8
                                (Source Classification Codes)

                             EMISSION FACTOR RATING: E
Pollutant
Butane Emission Factor
Ib/lOOOgal
Industrial
Boilersb
(10201001)
Filterable paniculate matter* 0.6
Sulfur oxides6 0.09S
Nitrogen oxidesf 21
Carbon dioxide 14,700
Carbon monoxide 3.6
Total organic compounds 0.6
Commercial
Boilers0
(10301001)
Propane Emission Factor
lb/1000 gal
Industrial
Boilersb
(10201002)
0.5 0.6
0.09S 0.10S
15 19
14,700 12,500
2.1 3.2
0.6 0.5
Commercial
Boilers0
(10301002)
0.4
0.10S
14
12,500
1.9
0.5
"Assumes emissions (except SOX and NOX) are the same, on a heat input basis, as for natural gas
 combustion. The NOX emission factors have been multiplied by a correction factor of 1.5 which is
 the approximate ratio of propane/butane NOX emissions to natural gas NOX emissions.
''Heat input capacities generally between 10 and 100 million Btu/hour.
Heat input capacities generally between 0.3 and 10 million Btu/hour.
dFilterable particulate matter (PM) is that PM collected on or prior to the filter of an EPA Method 5
 (or equivalent) sampling tram.
'Expressed as SO2. S equals the sulfur content expressed on gr/100 ft3 gas vapor. For example, if the
 butane sulfur content is 0.18 gr/100 ft3 emission factor would be (0.09 x 0.18=) 0.016 Ib of
 SOj/lOOO gal butane burned.
Expressed as NO2.
7/93
External Combustion Sources
1.5-3

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        TABLE 1.5-2. (METRIC UNITS) EMISSION FACTORS FOR LPG COMBUSTION8
                                (Source Classification Codes)

                              EMISSION FACTOR RATING: E
Pollutant
Butane Emission Factor
kg/1000 liters
Industrial
Boilersb
(10201001)
Filterable particulate matter4 0.07
Sulfur oxides6 0.01 IS
Nitrogen oxidesf 2.5
Carbon dioxide 1,760
Carbon monoxide 0.4
Total organic compounds 0.07
Commercial
Boilers0
(10301001)
Propane Emission Factor
kg/1000 liters
Industrial
Boilersb
(10201002)
0.06 0.07
0.011S 0.012S
1.8 2.3
1,760 1,500
0.3 0.4
0.07 0.06
Commercial
Boilers0
(10301002)
0.05
0.012S
1.7
1,500
0.2
0.06
Assumes emissions (except SOX and NO*) are the same, on a heat input basis, as for natural gas
 combustion.  The NOX emission factors have been multiplied by a correction factor of 1.5 which is
 the approximate ratio of propane/butane NOX emissions to natural gas NOX emissions.
'Heat input capacities generally between 3 and 29 MW.
"Heat input capacities generally between 0.1  and 3 MW.
"Filterable particulate matter (PM) is that PM collected on or prior to the filter of an EPA Method 5
 (or equivalent) sampling train.
Expressed as SO2. S equals the sulfur content expressed on gr/100 ft3 gas vapor. For example, if the
 butane sulfur content is 0.18 gr/100 ft3 emission factor would be (0.011 x 0.18) = 0.0020 kg of
 SO^IOOO liters butane burned.
Expressed as NO2.
1.5-4
EMISSION FACTORS
                                                                                    7/93

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References for Section 1.5

1.     Letter dated August 19, 1992.  From W. Butterbaugh of the National Propane Gas Association,
       Lisle, Illinois, to J. McSorley of the U.S. Environmental Protection Agency, Research Triangle
       Park, NC.

2.     Air Pollutant Emission Factors. Final Report. Contract No. CPA-22-69-119. Resources
       Research, Inc., Reston, VA, Durham, NC, April 1970.

3.     Nitrous Oxide Reduction with the Weishaupt Flue Gas Recirculation System. Weishaupt
       Research and Development Institute, January. 1987.

4.     Phone communication memorandum dated May 14,1992.  Conversation between B. Lusher of
       Acurex Environmental and D. Childress of Suburban/Petrolane, Durham, NC.
7/93                            External Combustion Sources                            1.5-5

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1.6 WOOD WASTE COMBUSTION IN BOILERS

1.6.1  General1'5

       The burning of wood waste in boilers is mostly confined to those industries where it is
available as a byproduct. It is burned both to obtain heat energy and to alleviate possible solid waste
disposal problems. In boilers, wood waste is normally burned in the form of hogged wood, sawdust,
shavings, chips, sanderdust, or wood trim.  Heating values for this waste range from about 2,200 to
2,700 kcal/kg (4,000 to 5,000 Btu/lb) of fuel on a wet, as-fired basis.  The moisture content of as-fired
wood is typically near 50, weight percent but may vary from 5 to 75 weight percent depending on the
waste type and storage operations.

       Generally, bark is the major type of waste burned in pulp mills; either a mixture of wood and
bark waste or wood waste alone is burned most frequently in the lumber, furniture, and plywood
industries.  As of 1980, there were approximately 1,600 wood-fired boilers operating in the U.S., with
a total capacity of over 30 GW (1.0 x 1011 Btu/hr).
1.6.2 Firing Practices"

       Various boiler firing configurations are used for burning wood waste. One common type of
boiler used in smaller operations is the Dutch oven. This unit is widely used because it can burn fuels
with very high moisture content. Fuel is fed into the oven through an opening in the top of a
refractory-lined furnace. The fuel accumulates in a cone-shaped pile on a flat or sloping grate.
Combustion is accomplished in two stages: (1) drying and gasification, and (2) combustion of gaseous
products. The first stage takes place in the primary furnace, which is separated from the secondary
furnace chamber by a bridge wall.  Combustion is completed in the secondary chamber before gases
enter the boiler section.  The large mass of refractory helps to stabilize combustion rates but also
causes a slow response to fluctuating steam demand.

       In another boiler type, the fuel cell oven, fuel is dropped onto suspended fixed grates and is
fired in a pile.  Unlike the Dutch oven, the refractory-lined fuel cell also uses combustion air
preheating and positioning of secondary and tertiary air injection ports to  improve boiler efficiency.
Because of their overall design and operating similarities, however, fuel cell and Dutch oven boilers
have comparable emission characteristics.

       The most common firing method employed for wood-fired boilers larger than 45,000 kg/hr
(100,000 Ib/hr)  steam generation rate is the spreader stoker.  With this boiler, wood enters the furnace
through a fuel chute and is spread either pneumatically or mechanically across the furnace, where
small pieces of the fuel burn while in suspension.  Simultaneously, larger pieces of fuel are spread in a
thin, even bed on a stationary or moving grate. The burning is accomplished in three stages hi a
single chamber:  (1) moisture evaporation; (2) distillation and burning of volatile matter,  and (3)
burning of fixed carbon. This type of operation has a fast response to load changes, has  improved
combustion control, and can be operated with multiple fuels.  Natural gas or oil is often fired in
spreader stoker boilers as auxiliary fuel. This is done to maintain constant steam when the wood
waste supply fluctuates and/or to provide more steam than can be generated from the waste supply


7/93                              External Combustion Sources                             1.6-1

-------
 alone. Although spreader stokers are the most common stokers among larger wood-fired boilers,
 overfeed and underfeed stokers are also utilized for smaller units.

        Another boiler type sometimes used for wood combustion is the suspension-firing boiler. This
 boiler differs from a spreader stoker in that small-sized fuel (normally less than 2 mm) is blown into
 the boiler and combusted by supporting it in air rather than on fixed grates.  Rapid changes hi
 combustion rate and, therefore, steam generation rate are possible because the finely divided fuel
 particles bum very quickly.

        A recent development in wood firing is the fluidized bed combustion (FBC) boiler.  A
 fluidized bed consists of inert particles through which air is blown so that the bed behaves as a fluid.
 Wood waste enters in the space above the bed and burns both in suspension and in the bed. Because
 of the large thermal mass represented by the hot inert bed particles, fluidized beds can handle fuels
 with moisture contents up to near 70 percent (total basis).  Fluidized beds can also handle dirty fuels
 (up to 30 percent inert material).  Wood fuel is pyrolyzed faster in a fluidized bed than on a grate due
 to its immediate contact with hot bed material.  As a result, combustion is rapid and results in nearly
 complete combustion of the organic matter, thereby minimizing emission of unbumed organic
 compounds.

 1.6.3 Emissions And Controls6"11

       The major emission of concern from wood boilers is paniculate matter (PM), although other
 pollutants, particularly carbon monoxide (CO) and organic compounds, may be emitted in significant
 quantities under poor operating conditions. These emissions depend on a number of variables,
 including (1) the composition of the waste fuel burned, (2) the degree of flyash reinjection employed
 and (3) furnace design and operating conditions.

       The composition of wood waste depends largely on the industry from which it originates.
 Pulping operations, for example, produce great quantities of bark that may contain more than 70
 weight percent moisture, sand, and other non-combustibles.  As a result, bark boilers in pulp mills may
 emit considerable amounts of particulate matter to the atmosphere unless they are well controlled.  On
 the other hand, some operations, such as furniture manufacturing, generate a clean, dry wood waste
 (e.g., 2 to 20 weight percent moisture) which produces relatively low particulate emission levels when
 properly burned. Still other operations,  such as sawmills, burn a varying mixture of bark and wood
 waste that results in PM emissions somewhere between these two extremes.

       Furnace design and operating conditions are particularly important when firing wood waste.
 For example, because of the high moisture content that may be present in wood waste, a larger than
 usual area of refractory surface is  often necessary to dry the fuel before combustion.  In addition,
 sufficient secondary air must be supplied over the fuel bed to burn the volatiles  that account for most
 of the combustible material in the waste. When proper drying conditions do not exist, or when
 secondary combustion is incomplete, the combustion temperature is lowered, and increased PM, CO,
 and organic compound emissions may result. Short term emissions can fluctuate with significant
variations in fuel moisture content

       Flyash reinjection, which is commonly used with larger boilers to improve fuel efficiency, has
a considerable effect on PM emissions.  Because a fraction of the collected flyash is reinjected into the
boiler, the dust loading from the furnace and, consequently, from the collection device increase

 1.6-2                               EMISSION FACTORS                                7/93

-------
significantly per unit of wood waste burned.  More recent boiler installations typically separate the
collected paniculate into large and small fractions in sand classifiers.  The larger particles, which are
mostly carbon, are reinjected into the furnace. The smaller particles, mostly inorganic ash and sand,
are sent to ash disposal.

       Currently, the four most common control devices used to reduce PM emissions from wood-
fired boilers are mechanical collectors, wet scrubbers, electrostatic precipitators (ESPs), and fabric
filters. The use of multitube cyclone (or multiclone) mechanical collectors provides particulate control
for many hogged boilers. Often, two multiclones are used in series, allowing the first collector to
remove the bulk of the dust and the second to remove smaller particles. The efficiency of this
arrangement is from 65 to 95 percent. The most widely used wet scrubbers for wood-fired boilers are
venturi scrubbers.  With gas-side pressure drops exceeding 4 kPa (15  inches of water), particulate
collection efficiencies of 90 percent or greater have been reported for venturi scrubbers operating on
wood-fired boilers.

       Fabric filters (i.e., baghouses) and ESPs are employed when collection efficiencies above 95
percent are required.  When applied to wood-fired boilers, ESPs are often used downstream of
mechanical collector precleaners which remove larger-sized particles.  Collection efficiencies of 93 to
99.8 percent for PM have been observed for ESPs operating on wood-fired boilers.

       A variation of the ESP is the electrostatic gravel bed filter. In this device, PM in flue gases is
removed by impaction with gravel media inside a packed bed; collection is augmented by an
electrically charged grid within the bed. Particulate collection efficiencies are typically near 95
percent.

       Fabric filters have had limited applications to wood-fired boilers.  The principal drawback to
fabric filtration, as perceived by potential users, is a fire danger arising from the collection of
combustible carbonaceous fly ash.  Steps can be taken to reduce this hazard, including the installation
of a mechanical collector upstream of the fabric filter to remove large burning particles of fly ash (i.e.,
"sparklers").  Despite complications, fabric filters are generally preferred for boilers firing salt-laden
wood. This fuel produces fine particulates with a high salt content. Fabric filters are capable of high
fine particle collection efficiencies; in addition, the salt content of the particles has a quenching effect,
thereby reducing fire hazards. In two tests of fabric filters operating  on salt-laden wood-fired boilers,
particulate collection efficiencies were above 98 percent

        Emissions of nitrogen oxides (NOJ from wood-fired boilers are lower than those from coal-
fired boilers due to the lower nitrogen content of wood and the lower combustion temperatures which
characterize wood-fired boilers. For stoker and FBC boilers, overfire air ports may be used to lower
NOX emissions by staging the combustion process.  In those areas of the U.S. where NOX emissions
must be reduced to their lowest levels,  the application of selective non-catalytic reduction (SNCR) and
selective catalytic reduction (SCR) to waste wood-fired boilers has either been accomplished (SNCR)
or is being contemplated (SCR). Both systems are post-combustion NOX reduction techniques in
which ammonia (or urea) is injected  into the flue gas to selectively reduce NOX to nitrogen and water.
In one application of SNCR to an industrial wood-fired boiler, NOX reduction efficiencies varied
between 35 and 75 percent as the ammonia:NOx ratio increased from 0.4 to 3.2.

        Emission factors and emission  factor ratings for wood waste boilers are summarized in Tables
 1.6-1 through 1.6-7.  Emission factors are for uncontrolled combustors, unless otherwise indicated.

 7/93                              External Combustion Sources                             1.6-3

-------
 Cumulative particle size distribution data and associated emission factors are presented in Tables 1.6-8
 and 1.6-9. Uncontrolled and controlled size-specific emission factors are plotted in Figures 1.6-1 and
 1.6-2.  All emission factors presented are based on the feed rate of wet, as-fired wood with average
 properties of 50 weight percent moisture and 2,500 kcal/kg (4,500 BtuAb) higher heating values.
1.6-4                                EMISSION FACTORS                                 7/93

-------
     > 01
     c ^t
                            Nu1t1pl cyclone
                            ftft flyash nt1njct1on
                                         2     4   6   10
                                     Particle dlamster (urn)
                              40  60  100
      Figure 1.6-1. Cumulative size specific emission factors for baric fired boilers.
                                                     2.0
                                                     1.8
                                                         fe
                                                     l.S o
                                                        >-
                                                     1.4 g.
                                                         M
                                                         s;
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                                                        o '
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                                                     .0
7/93
External Combustion Sources
1.6-5

-------
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1.6-6
EMISSION FACTORS
7/93

-------
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7/93
                                   External Combustion Sources
                           1.6-7

-------
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1.6-8
                   EMISSION FACTORS
                            7/93

-------
    TABLE 1.6-3 EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS (TOG) AND
              CARBON DIOXIDE (CO^ FROM WOOD WASTE COMBUSTION8
Source Category
(SCC)b
TOC
kg/Mg
Ib/ton
Rating
C02d
kg/Mg
Ib/ton
Rating
 Fuel cell/Dutch oven      0.09       0.18
 boilers
 (no SCC)

 Stoker boilers            0.11       0.22
 (no SCC)

 FBC boilers6             Ntf       ND
 (no SCC)
                          1100
                          1100
                          1100
2100
2100
2100
B
B
B
"Units are kg of pollutant/Mg of wood waste burned and Ibs. of pollutant/ton of wood waste burned.
 Emission factros are b ased on wet, as-fired wood waste with average properties of 50 weight percent
 moisture and 2500 kcal/kg (4500 Btu/lb) higher heating value.
bSCC = Source Classification Code.
"References 11,14-15,18.  Emissions measured as total hydrocarbons, converted to kg carbon/Mg fuel
 (Ib carbon/ton fuel).
"References 11, 14-15, 17, 27.
TBC = Fluidized bed combustion.
fND = No data.
7/93
External Combustion Sources
              1.6-9

-------
  Table 1.64 (Metric Units).  EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
                            FROM WOOD WASTE COMBUSTION"
Organic Compound11
Phenols
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benzo(a)anthracene
BenzoOH-k)fluoranthene
Benzo(a)pyrene
Benzo(g4i4)perylene
Chrysene
Indeno(l,23c,d)pyrene
Polychlorinated dibenzo-p-dioxins
Polychlorinated dibenzo-p-furans
Acenaphthylene
Pyrene
Methyl anthracene
Acrolein
Solicyladehyde
Benzaldehyde
Formaldehyde
Acetaldehyde
Benzene
Naphthalene
2,3,7,8-TetracMorodibenzo-p-dioxin
Emission Factor
Range0
kg/Mg
3.2E-05-6.0E-05
4.3E-08-2.1E-06
8.5E-08-1.4E-05
1.0E-06-9.0E-05
4.3E-08-1.7E-04
4.3E-08-4.3E-04
2.1E-07-2.9E-05
4.3E-08-3.2E-06
1.7E-07-9.5E-05
4.3E-08-1.5E-07
4.3E-08-1.7E-06
4.3E-08-1.5E-04
4.3E-08-3.0E-07
1.5E-09-1.7E-08
2.3E-09-3.6E-08
3.0E-07-3.4E-05





1-.2E-04-1.6E-02
3.0E-05-1.2E-02
4.3E-05-7.0E-03
2.5E-05-2.9E-03
1.1E-011-2.6E-011
Average Emission
Factor
kg/Mg
1.9E-04
1.7E-06
4.8E-06
2.8E-05
1.9E-05
4.5E-05
8.5E-06
9.0E-07
1.9E-05
9.5E-08
6.0E-07
2.1E-05
1.7E-07
e-OE-W*'
1.5E-08^
2.2E-05
4.5E-068
7.0E-058
2.0E-06e
1.1E-058
6.0E-068
3.3E-03
1.5E-03
1.8E-03
1.1E-03
1.8E-11
Emission
Factor
Rating
C
C
C
C
C
C
C
C
C
D
C
C
D
C
C
C
D
D
D
D
D
C
C
C
C
D
*Units are kg of pollutant/Mg of wood waste burned and Ibs. of pollutant/ton wood waste burned. Emission
 factors are based on wet, as-fired wood waste with average properties of 50 weight percent moisture and 2500
 kcal/kg higher heating value.  Source Classification Codes are 10100901/02/03,10200901/02/03/04/05/06/07,
 and 10300901/02/03.
Pollutants in this table represent organic species measured for wood waste combustors.  Other organic species
 may also have been emitted but were either not measured or were present at concentrations below analytical
 limits.
References 11-15,18,26-28.
Emission factors are for total dioxins and furans, not toxic equivalents.
Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor is 6.5E-07 kg/Mg
 with a D rating.
^Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor is 2.8E-07 kg/Mg
 with a D rating.
Based on data from one source test
1.6-10
EMISSION FACTORS
7/93

-------
  Table 1.6-5 (English Units). EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
                             FROM WOOD WASTE COMBUSTION8
Organic Compound1"
Phenols
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benzo(a)anthracene
Benzo(b+k)fluoranthene
Benzo(a)pyrene
Benzo(g,h4)perylene
Chrysene
Indeno(l,2,3,c,d)pyrene
Polychlorinated dibenzo-p-dioxins
Polychlorinated dibenzo-p-furans
Acenaphthylene
Pyrene
Methyl anthracene
Acrolein
Solicyladehyde
Benzaldehyde
Formaldehyde
Acetaldehyde
Benzene
Naphthalene
2,3,7,8-Tetrachlorodibenzo-p-dioxin
Emission Factor
Range0
Ib/ton
6.4E-05-1.2E-04
8.6E-08-4.3E-06
1.7E-07-2.8E-05
2.0E-06-1.8E-04
8.6E-08-3.5E-04
8.6E-08-8.6E-04
4.3E-07-5.9E-05
8.6E-08-6.4E-06
3.4E-07-1.9E-04
8.6E-08-3.0E-07
8.6E-08-3.5E-06
8.6E-08-3.0E-04
8.6E-08-6.0E-07
3.0E-09-3.3E-08
4.6E-09-7.2E-08
6.0E-07-6.8E-05





2.3E-04-3.3E-02
6.1E-05-2.4E-02
8.6E-05-1.4E-02
5.0E-05-5.8E-03
2.12E-011-5.11E-011
Average Emission
Factor
Ib/ton
3.9E-04
3.4E-06
9.6E-06
5.7E-05
3.8E-05
9.0E-05
1.7E-05
1.8E-06
2.9E-05
1.9E-07
1.2E-06
4.3E-05
3.4E-07
l^-OS1*
2.9E-08dlf
4.4E-05
9.0E-068
1.4E-04*
4.0E-068
2.3E-058
1.2E-058
6.6E-03
3.0E-03
3.6E-03
2.3E-03
3.6E-11
Emission
Factor
Rating
C
C
C
C
C
C
C
C
C
D
C
C
D
C
C
C
D
D
D
D
D
C
C
C
C
D
"Units are kg of pollutant/Mg of wood waste burned and Ibs. of pollutant/ton of wood waste burned.
 Emission factors are based on wet, as-fired wood waste with average properties of 50 weight percent moisture
 and 4500 Btu/lb higher heating value.  Source Classification Codes are 10100901/02/03,
 10200901/02/03/04/05/06/07, and 10300901/02/03.
'Pollutants in this table represent organic species measured for wood waste combustors.
 Other organic species may also have been emitted but were either not measured or were present at
 concentrations below analytical limits.
"References 11-15, 18, 26-28.
Emission factors are for total dioxins and furans, not toxic equivalents.
Excludes data from combustion of sauvladen wood. For salt-laden wood, emission factor is 1.3E-06 Ib/ton
 with a D rating.
Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor is 5.5E-07 Ib/ton
 with a D rating.
'Based on data from one source test.
7/93
External Combustion Sources
1.6-11

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         Table 1.6-6 (Metric Units).  EMISSION FACTORS FOR SPECIATED METALS
                            FROM WOOD WASTE COMBUSTION4
Trace Element* Emission Factor
Range*
kg/Mg
Chromium (VI) 1.5E-05-2.9E-05
Copper 7.0E-06-6.0E-04
Zinc 4.9E-05-1.1E-02
Barium
Potassium
Sodium
Iron 4.3E-04-3.3E-02
Lithium
Boron
Chlorine
Vanadium
Cobalt?"
Thorium
Tungsten
Dysprosium
Samarium
Neodymium
Praeseodymium
Iodine
Tin
Molybdenum
Niobium
Zirconium
Yttrium
Rubidium
Bromine
Germanium
Arsenic 7.0E-07-1.2E-04
Cadmium 1.3E-06-2.7E-04
Chromium (Total) 3.0E-06-2.3E-04
Manganese 1.5E-04-2.6E-02
Mercury 1.3E-06-1.0E-05
Nickel 1.7E-05-2.9E-03
Selenium 8.5E-06-9.0E-06
Average Emission Emission
Factor Factor
kg/Mg Rating
2.3E-05 D
9.5E-05 C
2.2E-03 C
2.2E-03d D
3.9E-01d D
9.0E-03d D
2.2E-02 D
3.5E-05d D
4.0E-04d D
3.9E-03d D
6.0E-05d D
6.5E-05d D
8.5E-06d D
5.5E-06d D
6.5E-06d D
1.0E-05d D
1.3E-05d D
1.5E-05d D
8.0E-06d D
1.5E-05d D
9.5E-05d D
1.7E-05d D
1.7E-04d D
2.8E-05d D
6.0E-04d D
1.8E-04d P
1.7E-06d D
4.4E-05 C
8.5E-06 C
6.5E-05 . C
4.4E-03 . C
3.7E-06 C
2.8E-04 C
8.8E-06 D
"Units are kg of pollutant/Mg of wood waste burned and Ibs. of pollutant/tori of wood waste burned.
 Emission factors are based on wet, as-fired wood waste with average properties of 50 weight percent moisture
 and 2500 kcal/kg higher heating value. Source Classification Codes are 10100901/02/03,
 10200901/02/03/04/05/06/07, and 10300901/02/03.
'Pollutants in this table represent metal species measured for wood waste combustors. Other metal species may
 also have been emitted but were either not measured or were present at concentrations below analytical limits.
References 11-15.
"Based on data from one source test.
1.6-12
EMISSION FACTORS
                                                                                            7/93

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              Table 1.6-7 (English Units).  EMISSION FACTORS FOR SPECIATED METALS
                                 FROM WOOD WASTE COMBUSTION8
Trace Element*" Emission Factor
Range0
Ib/ton
Chromium (VI) 3.1E-05-5.9E-05
Copper 1.4E-05-1J2E-03
Zinc 9.9E-05-2.3E-02
Barium
Potassium
Sodium
Iron 8.6E-04-8.7E-02
Lithium
Boron
Chlorine
Vanadium
Cobalt
Thorium
Tungsten
Dysprosium
Samarium
Neodymium
Praeseodymium
Iodine
Tin
Molybdenum
Niobium
Zirconium
Yttrium
Rubidium
Bromine
Germanium
Arsenic 1.4E-06-2.4E-04
Cadmium 2.7E-06-5.4E-04
Chromium (Total) 6.0E-06-4.6E-04
Manganese 3.0E-04-5.2E-02
Mercury 2.6E-06-2.1E-05
Nickel 3.4E-05-5.8E-03
Selenium 1.7E-05-1.8E-05
Average Emission Emission
Factor Factor
Ib/ton Rating
4.6E-05 . D
1.9E-04 C
4.4E-03 D
4.4E-03d D
7.8E-01d D
1.8E-02d D
4.4E-02 D
7.0E-05d D
8.0E-04d D
7.8E-03d D
1.2E-04d D
I.3E-04d D
1.7E-05d D
UE-05d D
1.3E-05d D
2.0E-05d D
2.6E-05d D
3.0E-05d D
1.8E-05d D
3.1E-05" D
1.9E-04d D
3.5E-05d D
3.5E-04d D
5.6E-05d D
1.2E-03d D
3.9E-04d D
2.5E-06d D
8.8E-05 C
1.7E-05 C
1.3E-04 C
8.9E-03 C
6.5E-06 C
5.6E-04 C
1.8E-05 D
"Units are kg of pollutant/Mg of wood waste burned and Ibs. of pollutant/ton of wood waste burned.
 Emission factors are based on wet, as-fired wood waste with average properties of 50 weight percent
 moisture and 4500 Btu/lb higher heating value.  Source Classification Codes are 10100901/02/03,
 10200901/02/03/04/05/06/07, and 10300901/02/03.
'Pollutants in this table represent metal species measured for wood waste combustors.  Other metal
 species may also have been emitted but were either not measured or were present at concentrations
 below analytical limits.
"References 11-15.
dBased on data from one source test
7/93
External Combustion Sources
1.6-13

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                                                            1.6-15

-------
References for Section 1.6

1.     Emission Factor Documentation for AP-42 Section 1.6-Wood Waste Combustion in Boilers,
       Technical Support Division, Office of Air Quality Planning and Standards, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, April 1993.

2.     Steam, 38th Edition, Babcock and Wilcox, New York, NY, 1972.

3.     Atmospheric Emissions From the Pulp and Paper Manufacturing Industry, EPA-450/1-73-002,
       U. S. Environmental Protection Agency, Research Triangle Park, NC, September 1973.

4.     C-E Bark Burning Boilers, C-E Industrial Boiler Operations, Combustion Engineering, Inc.,
       Windsor, CT, 1973.

5.     Nonfossil Fuel Fired Industrial Boilers - Background Information, EPA-450/3-82-007, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, March 1982.

6.     Control of Paniculate Emissions From Wood-Fired Boilers, EPA 340/1-77-026, U. S.
       Environmental Protection Agency, Washington, DC, 1977.

7.     Background Information Document For Industrial Boilers, EPA 450/3-82-006a, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, March 1982.

8.     E. F. Aul, Jr.  and K. W. Barnett, "Emission Control Technologies For Wood-Fired Boilers",
       Presented at the Wood Energy Conference, Raleigh, NC, October 1984.

9.     G. Moilanen,  K. Price, C. Smith, and A. Turchina, "Noncatalytic Ammonia Injection For NOX
       Reduction on a Waste Wood Fired Boiler", Presented at the 80th Annual Meeting of the Air
       Pollution Control Association, New York, NY, June 1987.

10.    "Information on the Sulfur Content of Bark and Its Contribution to SO2 Emissions When
       Burned  as a Fuel", H. Oglesby and R. Blosser, Journal of the Air Pollution Control Agency,
       30(7):769-772, July 1980.

11.    Written communication from G. Murray, California Forestry Association, Sacramento, CA to
       E. Aul,  Edward Aul & Associates, Inc., Chapel Hill, NC, Transmittal of Wood Fired Boiler
       Emission Test, April, 24, 1992.

12.    Hazardous Air Emissions Potential From a Wood-Fired Furnace (and Attachments), A. J.
       Hubbard, Wisconsin Department of Natural Resources, Madison, WI, July 1991.

13.    Environmental Assessment of a Wood-Waste-Fired Industrial Watertube Boiler, EPA Contract
       No. 68-02-3188, Acurex Corporation, Mountain View, CA, March 1984.

14.    Evaluation Test on a Wood Waste Fired Incinerator at Pacific Oroville Power Inc., Test
       Report No. C-88-050, California Air Resources Broad,  Sacramento, CA, May 1990.
 1.6-16                             EMISSION FACTORS                               7/93

-------
References for Section 1.6 (Continued)

15.    Evaluation Test on Twin Fluidized Bed Wood Waste Fueled Combustors Located in Central
       California, Test Report No. C-87-042, California Air Resources Board, Sacramento, CA,
       February,  1990.

16.    Inhalable Paniculate Source Category Report for External Combustion Sources, EPA Contract
       No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985.

17.    Emission Test Report, Owens-Illinois Forest Products Division, Big Island, Virginia, EMB
       Report 80-WFB-2, U. S. Environmental Protection Agency, Research Triangle Park, NC,
       February 1980.

18.    National Dioxin Study Tier 4, Combustion Sources: Final Test Report, Site 7, Wood Fired
       Boiler WFB-A, EPA-450/4-84-014p, U. S. Environmental Protection Agency, Research
       Triangle Park, NC, April 1987.

19.    Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection Agency,
       Research Triangle Park, NC, April 1970.

20.    A Study of Nitrogen  Oxides Emissions From Wood Residue Boilers, Technical  Bulletin No.
       102, National Council of the Paper Industry for Air and Stream Improvement,  New York, NY,
       November 1979.

21.    R. A. Kester, Nitrogen Oxide Emissions From a Pilot Plant Spreader Stoker Bark Fired
       Boiler, Department of Civil Engineering, University of Washington, Seattle, WA, December
       1979.

22.    A. Nunn, NOX Emission Factors For Wood Fired Boilers, EPA-600/7-79-219, U. S.
       Environmental Protection Agency, September 1979.

23;    H. S. Oglesby and R. O. Blosser, "Information on the Sulfur Content of Bark and Its
       Contribution to SO2 Emissions When Burned as a Fuel", Journal of the Air Pollution Control
       Agency, 30(7):769-772, July 1980.

24.    Carbon Monoxide Emissions From Selected Combustion Sources Based on Short-Term
       Monitoring Records, Technical Bulletin No. 416, National Council of the Paper Industry For
       Air and Stream Improvement, New York, NY, January 1984.

25.    Volatile Organic Carbon Emissions From Wood Residue Fired Power Boilers in the Southeast,
       Technical  Bulletin No. 455, National Council of the Paper Industry For Air and Stream
       Improvement, New York, NY, April 1985.

26.    A Study of Formaldehyde Emissions From Wood Residue-Fired Boilers, Technical Bulletin No.
       622, National Council of the Paper Industry For Air and Stream Improvement, New York, NY,
       January 1992.
7/93                             External Combustion Sources                            1.6-17

-------
References for Section 1.6 (Continued)

27.    Emission Test Report, St. Joe Paper Company, Port St. Joe, Florida, EMB Report 80-WFB-5,
       U. S. Environmental Protection Agency, Research Triangle Park, NC, May 1980.

28.    A Polycyclic Organic Materials Study For Industrial Wood-Fired Boilers, Technical Bulletin
       No. 400, National Council of the Paper Industry For Air and Stream Improvement, New York,
       NY, May 1983.
1.6-18                             EMISSION FACTORS                               7/93

-------
i.7 LIGNITE COMBUSTION

1.7.1  General1-4

       Lignite is a coal in the early stages of coalification, with properties intermediate to those of
bituminous coal and peat.  The two geographical areas of the U.S. with extensive lignite deposits are
centered in the States of North Dakota and Texas.  The lignite in both areas has a high moisture
content (30 to 40 weight percent) and a low heating value, [1,400 to 1,900 kcal/kg (2,500 to 3,400
Btu/lb), on a wet basis]. Consequently, lignite is burned near where it is mined.  A small amount is
used in industrial and domestic situations, but lignite is mainly used for steam/electric production in
power plants.  Lignite combustion has advanced from small stokers and the first pulverized coal (PC)
and cyclone-fired units to large (greater than 800 MW) PC power plants.

       The major advantages of firing lignite are that it is relatively abundant (hi the North Dakota
and Texas regions), relatively low in cost, and low in sulfur content  The disadvantages are that more
fuel and larger facilities are necessary to generate a unit of power than is the case with bituminous
coal.  The reasons for this are: (1) lignite's higher moisture content means that more energy is lost in
evaporating water, which reduces boiler efficiency; (2) more energy is required to grind lignite to
combustion-specified size, especially in PC-fired units; (3) greater tube spacing and additional soot
blowing are required because of lignite's higher ash fouling tendencies; and (4) because of its lower
heating value, more lignite must be handled to produce a given amount of power. Lignite usually is
not cleaned or dried before combustion (except for incidental drying in the crusher or pulverizer and
during transport to the burner).  No major problems exist with the handling or combustion of lignite
when its unique characteristics are taken into account.

1.7.2 Emissions2'11'17

        The major pollutants generated from firing lignite, as with any coal, are paniculate matter
(PM), sulfur oxides (SOX), and nitrogen oxides (NOX). Emissions rates of organic compounds and
carbon monoxide (CO) are much lower than those for the major pollutants under normal operating
conditions.

        Emission levels for PM appear most dependent on the firing configuration of the boiler.
Pulverized coal-fired units and spreader stokers fire much or all of the lignite in suspension; they emit
a greater quantity of flyash per unit of fuel burned than do cyclones and other stokers.  Cyclone
furnaces collect much of the ash as molten slag in the furnace itself.  Stokers (other than spreader)
retain a large  fraction of the ash in the fuel bed and bottom ash.

        The NOX emissions  from lignite combustion are mainly a function of the boiler design, firing
configuration, and excess air level.  Stokers produce lower NOX levels than PC units and  cyclones,
mainly because most stokers are relatively small and  have lower peak flame temperatures. The boilers
constructed since implementation of the 1971 and 1979 new source performance standards (40 Code of
Federal Regulations, Part 60, Subparts D and Da respectively) have NOX controls integrated into the
boiler design and have comparable NOX emission levels to the small stokers.  In most boilers,
regardless of firing configuration, lower excess combustion air results in lower NOX emissions.


7/93                              External Combustion Sources                             1.7-1

-------
However, lowering the amount of excess air in a lignite-fired boiler can also affect the potential for
ash fouling.                                                          .                       ,,,

       The rate of SOX emissions from lignite combustion are a function of the alkali (especially
sodium) content of the ash. For combustion of most fossil fuels, over 90 percent of the fuel sulfur is
emitted as sulfur dioxide (SO2)  because of the low alkali content of the fuels.  By contrast, a
significant fraction of the sulfur in lignite reacts with alkaline ash components during  combustion and
is retained in the boiler bottom  ash and flyash.  Tests have shown that less than 50 percent of the
available sulfur may be emitted as SO2 when a high-sodium lignite is burned, whereas more than 90
percent may be emitted from a low-sodium lignite.  As an approximate average, about 75 percent of
the lignite sulfur will be emitted as SO2; the remainder will be retained in the ash as various sulfate
salts.

1.7.3 Controls2'11"17

       Most lignite-fired utility boilers are equipped with electrostatic precipitators (ESPs) with
collection efficiencies as high as 99.5 percent for total PM.  Older and smaller ESPs have lower
collection efficiencies of approximately 95 percent for total PM. Older industrial and commercial
units also may be equipped with cyclone collectors that normally achieve 60 to 80 percent collection
efficiency for total PM.

       Flue gas desulfurization (FGD) systems (comparable to those used on bituminous coal-fired
boilers) are in current operation on several lignite-fired utility boilers. Flue gases are treated through
wet or dry desulfurization processes of either the throwaway type (in which all waste streams are
discarded) or the recovery/regenerable type (in which the SOX absorbent is regenerated and reused).
Wet systems generally use alkali slurries as the SOX absorption medium and can reduce SOX emissions
by 90 percent or more. Spray dryers (or dry scrubbers) spray a solution or slurry of alkaline material
into a reaction vessel as a fine mist that mixes with the flue gas.  The SO2 reacts with the alkaline
mist to form salts.  The solids from the spray dryer and the salts formed are collected in a paniculate
control device.

        Over 50 percent reduction of NOX emissions can be achieved by  changing the burner
geometry, controlling air flow in the furnace, or making other changes in operating procedures.
Overfire air and low NOX burners are two demonstrated NOX control techniques for lignite
combustion.

        Baseline emission factors for NOX, SOX, and CO are presented in Tables 1.7-1 and 1.7-2.
Baseline emission factors for total PM and nitrous oxide (N2O) are given in Table  1.7-3.  Specific
emission factors for the cumulative particle size distributions are provided in Tables 1.7-4 and 1.7-5.
Uncontrolled and controlled size-specific emission factors are presented in Figures  1.7-1 and 1.7-2.
Lignite combustion and bituminous coal combustion are quite similar with respect to emissions of
carbon dioxide (CO^  and organic compounds.  As a result, the bituminous coal emission factors for
these pollutants presented in Section 1.1 of this document may also be used to estimate emissions from
lignite combustion.

        Emission factors for trace elements from uncontrolled lignite combustion are summarized in
Tables 1.7-6 and 1.7-7, based on currently available data.
 1.7-2                               EMISSION FACTORS                                 7/93

-------
       Controlled emission factors for NOX, CO, and PM are presented in Tables 1.7-8 and 1.7-9.
Controlled SO2 emissions will depend primarily of applicable regulations and FGD equipment
performance, if applicable.  Section 1.1 contains a discussion of FGD performance capabilities which
is also applicable to lignite-fired boilers. Controlled emission factors for selected hazardous air
pollutants are provided in Tables 1.7-10 and 1.7-11.
 7/93                              External Combustion Sources                             1.7-3

-------
       Table 1.7-1 (Metric Units).  EMISSION FACTORS FOR SULFUR OXIDES (SOX),
              NITROGEN OXIDES (NOX), AND CARBON MONOXIDE (CO)
                   FROM UNCONTROLLED LIGNITE COMBUSTION"
Firing Configuration
(SCQb
soxc
Emission
Factor
Rating
N0xd
Emission
Factor
Rating
C0e
Emission
Factor
Rating
Pulverized coal, dry 15Se
bottom, tangential
(SCC 10100302)
Pulverized coal, dry 15S
bottom, wall fired
(SCC 10100301)
Cyclone 15S
(SCC 10100303)
Spreader stoker 15S
(SCC 10100306)
Other stoker 15S
(SCC 10100304)e
Atmospheric fluidized bed 3S
(no SCC)
C
C
C
C
C
D
3.7
5.6
6.3
2.9
2.9
1.8
C
C 0.13
C
C
C
C 0.08

C



C
8Units are kg of pollutant/Mg of fuel burned.
bSCC= Source Classification Code.
Reference 2.
References 2-3, 7-8, 15-16.
References 7,16.
CS= Weight % sulfur content of lignite, wet basis.
  For high sodium ash (Na^ > 8%), use US.
  For low sodium ash (Na^ < 2%), use 17S.
  If ash sodium content is unknown, use 15S.
1.7-4
EMISSION FACTORS
7/93

-------
      Table 1.7-2 (English Units); EMISSION FACTORS FOR SULFUR OXIDES (SOX),
              NITROGEN OXIDES (NOX), AND CARBON MONOXIDE (CO)
                   FROM UNCONTROLLED LIGNITE COMBUSTION8
Firing Configuration
(SCQb
soxc
Emission
Factor
Rating
N0xd
Emission
Factor
Rating
C0e
Emission
Factor
Rating
Pulverized coal, dry
bottom, tangential
(SCC 10100302)
Pulverized coal, dry
bottom, wall fired
(SCC 10100301)
Cyclone
(SCC 10100303)
Spreader stoker
(SCC 10100306)
Other stoker
(SCC 10100304)f
Atmospheric fluidized bed
(no SCC)
30Se
30S
308
30S
30S
308
C
c
C
c
c
c
7.3
11.1
12.5
5.8
5.8
3.6
C
C 0.25
C
C
C
C 0.15

C



C
aUnits are Ib. of pollutant/ton of fuel burned.
bSCC= Source Classification Code.
Reference 2.
References 2-3, 7-8, 15-16.
"References 7, 16.
fS= Weight % sulfur content of lignite, wet basis.
  For high sodium ash (Na^ > 8%), use 228.
  For low sodium ash (Na^ < 2%), use 34S.
  If ash sodium content is unknown, use 308.
7/93
External Combustion Sources
1.7-5

-------
        Table 1.7-3.  EMISSION FACTORS FOR PARTICIPATE MATTER (PM) AND
                NITROUS OXIDE (N2O) FROM LIGNITE COMBUSTION8
Firing Ctonfiguration
(SCC)
Pulverized coal, dry
bottom, tangential
(SCC 10100302)
Pulverized coal, dry
bottom,
wall fired
(SCC 10100301)
Cyclone
(SCC 10100303)
Spreader stoker
(SCC 10100306)
Other stoker
(SCC 10100304)
Atmospheric fluidized bed
PMb
Emission Factor Rating
3.3A (6.5A) E
2.6A (5.1A) E
3.4A(6.7A) C
4.0A (8.0A) E
1.7A (3.4A) E

N2OC
Emission Factor Rating





1.2 (2.5) E
Units are kg of pollutant/Mg of fuel burned and Ib. of pollutant/ton of fuel burned.
  SCC= Source Classification Code.
References 5-6,12,14. A = weight % ash content of lignite, wet basis.
Reference 18.
 1.7-6
EMISSION FACTORS
7/93

-------

               
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                  Figure 1.7-1. Cumulative size specific emission factors for boilers
                                        firing pulverized lignite.
           l.OA
           0.9AH
     Sfe   0.8A
     ^51  0.7A
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                                          i i i
                                       .4  .6    1      2     4   6   10
                                                  Particle diameter (v)
                                 20
                                                                               40  M  100
                  Figure 1.7-2.  Cumulative size specific emission factors for lignite-
                                         fired spreader stokers.
1.7-8
EMISSION FACTORS
                                                                                       7/93

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                      External Combustion Sources
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1.7-10
EMISSION FACTORS
7/93

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1
1
f-5
References 19-21
7/93
External Combustion Sources
1.7-11

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                  Table 1.7-8. CONTROLLED EMISSION FACTORS FOR
               NITROGEN OXIDES (NOX) AND CARBON MONOXIDE (CO)
                     FROM CONTROLLED LIGNITE COMBUSTION*
Firing Configuration
(SCQ
N0xb
Emission Factor
kg/Mg (Ib/ton)
Rating
CO0
Emission Factor
kg/Mg Ob/ton)
Rating
 Pulverized coal, dry
 bottom, tangential
 overfire air
 (no SCQ

 Pulverized coal, dry
 bottom, tangential
 overfire air/low NOX
 burners
 (no SCC)
3.3 (6.6)
2.3 (4.6)
0.05 (0.10)
0.24 (0.48)
D
D
"Units are kg of pollutant/Mg of fuel burned and Ib. of pollutant/ton of fuel burned.
  SCC = Source Classification Code.
Reference 15,16.
References 15.
1.7-12
   EMISSION FACTORS
                    7/93

-------
    Table 1.7-9. EMISSION FACTORS FOR PARTICULATE MATTER (PM) EMISSIONS
                    FROM CONTROLLED LIGNITE COMBUSTION*
Firing Configuration
(SCC)
Control Device
PM
Emission Factor
Subpart D Betters, Baghouse 0.08A (0.16A)
Pulverized coal,
Tangential and wall-fired \yet scrubber 0.05A (0.10A)
(no SCC)

Rating
C
C
 Subpart Da Boilers,
 Pulverized coal,
 Tangential fired
 (no SCC)
Wet scrubber
0.01A (0.02A)
 Atmospheric fluidized bed
Limestone addition
0.03A (0.06A)
                                                                             D
Reference 15-16. A = weight % ash content of lignite, wet basis.
  Units are kg of pollutant/Mg of fuel burned and Ib. of pollutant/ton of fuel burned.
  SCC = Source Classification Code.
 7/93
  External Combustion Sources
                                                                                1.7-13

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                 Table 1.7-10 (Metric Units). EMISSION FACTORS FOR
            TRACE METALS AND POLYCYCLIC ORGANIC MATTER (POM)
                    FROM CONTROLLED LIGNITE COMBUSTION3

                           EMISSION FACTOR RATING:  E
Firing Configuration
(SCQ
Control Device
Emission Factor, pg/J
Cr | Mn
POM
 Pulverized coal
 (SCO 10100301)
Multi-cyclones
                          High efficiency cold-side
                          ESP
29-32
                                                 0.99
 Pulverized wet bottom
 (no SCQ
ESP
            15
Pulverized dry bottom
(no SCC)
Cyclone furnace
(SCC 10100303)
Stoker,
configuration unknown
(no SCC)
Spreader stoker
(SCC 10100306)
Multi-cyclones 0.78-7.9b
ESP 18 l.lb
ESP <3.3 57 0.05c-0.68b
Multi-cyclones 710
Multi-cyclones 13 47
ESP <2.3
Multi-cyclones 6.3
References 19-20. Units are picograms (10'12) of pollutant/Joule of fuel burned.
  SCC = Source Classification Code.
''Primarily trimethyl propenyl naphthalene.
Primarily biphenyl.
1.7-14
      EMISSION FACTORS
                                                                              7/93

-------
                Table 1.7-11 (English Units).  EMISSION FACTORS FOR
           TRACE METALS AND POLYCYCLIC ORGANIC MATTER (POM)
                   FROM CONTROLLED LIGNITE COMBUSTION*

                         EMISSION FACTOR RATING: E
Firing Configuration
(SCC)
Control Device
Emission Factor, lb/1012Btu
Cr
Mn
POM
Pulverized coal Multi-cyclones 67-74
(SCC 10100301) _OT ~ft
JtloJr *"J
                       High efficiency cold-side ESP
                                                  2.3
Pulverized wet bottom
(no SCC)
ESP
                                                                34
Pulverized dry bottom
(no SCC)
Cyclone furnace
(SCC 10100303)
Stoker,
configuration unknown
(no SCC)
Spreader stoker
(SCC 10100306)
Multi-cyclones
ESP
ESP
Multi-cyclones
Multi-cyclones
ESP
Multi-cyclones
1.8-18"
42 2.6b
<28 133 O.llc-1.6b
1700
30 110
<5.4
15C
References 19-20. Units are Ib. of pollutant/1012Btu of fuel burned.
  SCC = Source Classification Code.
bPrimarily trimethyl propenyl naphthalene.
cPrimarily biphenyl.
7/93
       External Combustion Sources
                                                                            1.7-15

-------
References for Section 1.7

1.     Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition, Volume 12, John Wiley
       and Sons, New York, NY, 1967.

2.     G. H. Gronhovd, et al., "Some Studies on Stack Emissions from Lignite Fired Powerplants",
       Presented at the 1973 Lignite Symposium, Grand Forks, ND, May 1973.

3.     Standards Support and Environmental Impact Statement: Promulgated Standards of
       Performance for Lignite Fired Steam Generators:  Volumes I and II, EPA-450/2-76-030a and
       030b, U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1976.

4.     7955 Keystone Coal Buyers Manual, McGraw-Hill, Inc., New York, NY, 1965.

5.     Source Test Data on Lignite-Fired Power Plants, North Dakota State Department of Health,
       Bismarck, ND, December 1973.

6.     G. H. Gronhovd, et al., "Comparison of Ash Fouling Tendencies of High and Low Sodium
       Lignite from a North Dakota Mine", Proceedings of the American Power Conference, Volume
       XXVm, 1966.

7.     A. R. Crawford, et al., Field Testing: Application of Combustion Modification to Control NOX
       Emissions from Utility Boilers, EPA-650/2-74-066, U. S. Environmental Protection Agency,
       Washington, DC, June 1974.

8.     Nitrogen Oxides Emission Measurements for Three Lignite Fired Power Plants, Contract No.
       68-02-1401 and 68-02-1404, Office Of Air Quality Planning And Standards, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, 1974.

9.     Coal Fired Power Plant Trace Element Study, A Three Station Comparison, U. S.
       Environmental Protection Agency, Denver, CO, September 1975.

10.    C. Castaldini, and M. Angwin, Boiler Design and Operating Variables Affecting Uncontrolled
       Sulfur Emissions from Pulverized Coal Fired Steam Generators, EPA-450/3-77-047, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, December 1977.

11.    C. C. Shih, et al., Emissions Assessment of Conventional Stationary Combustion Systems,
       Volume III:  External Combustion Sources for Electricity Generation, EPA Contract No.
       68-02-2197, TRW Inc., Redondo Beach, CA, November 1980.

12.    Source Test Data on Lignite-Fired Cyclone Boilers, North Dakota State Department of Health,
       Bismarck, ND, March 1982.

13.    Inhalable Particulate Source Category Report for External Combustion Sources, EPA Contract
       No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985.

14.    Personal communication dated September 18,1981, Letter from North Dakota Department of
       Health to Mr. Bill Lamson of the U. S. Environmental Protection Agency, Research Triangle
       Park, NC, conveying stoker data package.
1.7-16                             EMISSION FACTORS                               7/93

-------
References for Section 1.7 (Continued)

15.    Source Test Data on Lignite-Fired Power Plants, North Dakota State Department of Health,
       Bismarck, ND, April 1992.

16.    Source Test Data on Lignite-Fired Power Plants, Texas Air Control Board, Austin, TX, April
       1992.

17.    Honea, et al., "The Effects of Overfire Air and Low Excess Air on NOX Emissions and Ash
       Fouling Potential for a Lignite-Fired Boiler", Proceedings of the American Power Conference,
       Volume 40,  1978.

18.    M. D. Mann, et al., "Effect of Operating Parameters on N2O Emissions in a 1-MW CFBC,"
       Presented at the 8th Annual Pittsburgh Coal Conference, Pittsburgh, PA, October, 1991.

19.    G. W. Brooks, M. B. Stockton, K. Kuhn, and G. D. Rives, Radian Corporation, Locating and
       Estimating Air Emission from Source ofPolycyclic Organic Matter (POM), EPA-450/4-84-
       007p, U. S. Environmental Protection Agency, Research Triangle Park, NC, May 1988.

20.    J. C. Evans, et al., Characterization of Trace Constituents at Canadian Coal-Fired Plants,
       Phase I:  Final Report and Appendices, Report for the Canadian Electrical Association, R&D,
       Montreal, Quebec, Contract Number 001G194.
 7/93                             External Combustion Sources                           1.7-17

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1.8 BAGASSE COMBUSTION IN SUGAR MILLS

1.8.1  Process Description1"5

       Bagasse is the matted cellulose fiber residue from sugar cane that has been processed in a
sugar mill. Previously, bagasse was burned as means of solid waste disposal. However, as the cost of
fuel oil, natural gas, and electricity have increased, the definition of bagasse has changed from refuse
to a fuel.

       The U.S. sugar cane industry is located in the tropical and subtropical regions of Florida,
Texas, Louisiana, Hawaii, and Puerto Rico. Except for Hawaii, where sugar cane production takes
place year round, sugar mills operate seasonally from 2 to 5 months per year.

       Sugar cane is a large grass with a bamboo-like stalk that grows 8 to 15 feet tall. Only the
stalk contains sufficient sucrose for processing into sugar. All other parts of the sugar cane (i.e.,
leaves, top growth and roots) are termed "trash." The objective of harvesting is to deliver the sugar
cane to the mill with a minimum of trash or other extraneous material. The cane is normally burned
in the field to remove a major portion of the trash and to control insects and rodents. See Section
11.1 for methods to estimate these emissions. The three most common methods of harvesting are
hand  cutting, machine cutting, and mechanical raking. The cane that is delivered to a particular sugar
mill will vary in trash and dirt content depending on the harvesting method and weather conditions.
Inside the mill, cane preparation for extraction usually involves washing the cane to remove trash and
dirt, chopping, and then crushing.  Juice is extracted in the milling portion of the plant by passing the
chopped and crushed cane through a series of grooved rolls.  The cane remaining  after milling is
bagasse.

        Bagasse is a fuel of varying composition, consistency, and heating value.  These characteristics
depend on the climate, type of soil upon which  the cane is grown, variety of cane, harvesting method,
amount of cane washing, and the efficiency of the milling plant  In general, bagasse has a heating
value between 1,700 and 2,200 kcal/kg (3,000 and 4,000 Btu/lb) on a wet, as-fired basis. Most
bagasse has a moisture content between 45 and  55 percent by weight.

        Fuel cells, horseshoe boilers, and spreader stoker boilers are used to burn bagasse. Horseshoe
boilers and fuel cells differ in the shapes of their furnace  area but in other respects are similar in
design and operation. In these  boilers (most common among older plants), bagasse is gravity-fed
through chutes and piles onto a refractory hearth.  Primary and overfire combustion air flows through
ports in the furnace walls;  burning begins on the surface pile. Many of these units have dumping
hearths that permit ash removal while the unit is operating.

        In more-recently built sugar mills, bagasse is burned in spreader stoker boilers.  Bagasse feed
to these boilers enters the furnace through a fuel chute and is spread pneumatically or mechanically
across the furnace, where part of the fuel burns while in suspension.  Simultaneously, large pieces of
fuel are spread hi a thin, even bed on a stationary or moving grate. The flame over the grate radiates
heat back to the fuel to aid combustion.  The combustion area of the furnace is lined with heat
exchange tubes (waterwalls).


 7/93                              External Combustion Sources                              1.8-1

-------
 1.8.2  Emissions and Controls1'3

        The most significant pollutant emitted by bagasse-fired boilers is paniculate matter, caused by
 the turbulent movement of combustion gases with respect to the burning bagasse and resultant ash.
 Emissions of SO2 and NOX are lower than conventional fossil fuels due to the characteristically low
 levels of sulfur and nitrogen associated with bagasse.

        Auxiliary fuels  (typically fuel oil or natural gas) may be used during startup of the boiler or
 when the moisture content of the bagasse is too high to support combustion. If fuel oil is used during
 these periods, SO2 and NOX emissions will increase. Soil characteristics such as particle size can affect
 the magnitude of PM emissions from the boiler. Mill operations can also influence the bagasse ash
 content by not properly washing and preparing the cane. Upsets in combustion conditions can cause
 increased emissions of carbon monoxide (CO) and unburned organics, typically measured as volatile
 organic compounds (VOCs) and total organic  compounds (TOCs).

        Mechanical collectors and wet scrubbers are commonly used to control particulate emissions
 from bagasse-fired boilers. Mechanical collectors  may be installed in single cyclone, double cyclone,
 or multiple cyclone (i.e., multiclone) arrangements. The reported PM collection efficiency for
 mechanical collectors is 20 to 60 percent  Due to  the abrasive nature of bagasse fly ash, mechanical
 collector performance may deteriorate over time due to erosion if the system is not well maintained.

        The most widely used  wet scrubbers for bagasse-fired boilers are impingement and venturi
 scrubbers.  Impingement scrubbers normally operate at gas-side pressure drops of 5 to  15 inches of
 water; typical pressure drops for venturi scrubbers  are over 15 inches of water.  Impingement
 scrubbers are in greater use due to lower energy requirements and fewer operating and maintenance
 problems.  Reported PM collection efficiencies for both scrubber types are 90 percent or greater.

        Gaseous emissions (e.g., SO2, NOX, CO, and organics) may also be absorbed to a significant
 extent in a wet scrubber. Alkali compounds are sometimes utilized in the scrubber to prevent low pH
 conditions.  If CO2-generating compounds (such as sodium carbonate or calcium carbonate) are used,
 CO2 emissions will increase.

       Fabric filters and electrostatic precipitators have not been used to a significant extent for
 controlling PM from bagasse-fired boilers due to potential fire hazards (fabric filters) and relatively
 higher costs (both devices).

       Emission factors and emission factor ratings for bagasse-fired boilers are shown in Table 1.8-1
 (metric units) and Table 1.8-2 (English units).

       Fugitive dust may be generated by truck traffic and cane handling operations at the  sugar mill.
Particulate matter emissions from these sources may be estimated by consulting Section 11.2.
1.8-2                               EMISSION FACTORS                                7/93

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      Table 1.8-1 (Metric Units).  EMISSION FACTORS FOR BAGASSE-FIRED BOILERS8
Pollutant
Emission factor,
g/kg steamb
kg/Mg bagasse"
Rating
 Parn'culate matter*
     Uncontrolled
     Controlled
        Mechanical collector
        Wet scrubber
 PM-IO"
     Controlled
          3.9

          2.1
          0.4
7.8

4.2
0.8
D
B
Wet scrubber
Carbon dioxide
Uncontrolled6
Nitrogen oxides
Uncontrolledf
Polvcvclic organic matter
Uncontrolled8
0.34

390

0.3

2.5E-4
0.68

780

0.6

5.0E-4
D

A

C

D
aSource Classification Code is 10201101.
bUnits are gram of pollutant/kg of steam produced,
 where 1  kg of wet bagasse fired produces 2 kg of steam.
Units are kg of pollutant/Mg of wet, as-fired bagasse containing approximately 50 percent moisture,
 by weight
"References 2, 6-14. Includes only filterable PM (i.e., that paniculate collected on or prior to the filter
 of an EPA Method 5 (or equivalent) sampling train.
"References 6-14.  CO2 emissions will increase following a wet scrubber in which CO2-generating
 reagents (such as sodium carbonate or calcium carbonate) are used.
'References 13-14.
Reference 13. Based on measurements collected downstream of PM control devices which may have
 provided some removal of polycyclic organic matter (POM) condensed on PM.
7/93
External Combustion Sources
                      1.8-3

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       Table 1.8-2 (English Units). EMISSION FACTORS FOR BAGASSE-FIRED BOILERS3

Pollutant lb/l,(
Particulate matter3
Uncontrolled
Controlled
Mechanical collector
Wet scrubber
PM-IO*
Controlled
Wet scrubber
Carbon dioxide
Uncontrolled6
Nitrogen oxides
Uncontrolledf
Polycyclic organic matter
Uncontrolled8
Emission factor
300 Ib steamb Ib/ton bagasse"

3.9 15.6

2.1 8.4
0.4 1.6


0.34 1.36

390 1,560

0.3 1.2

2.5E-4 l.OE-3
Rating

C

D
B


D

A

C

D
"Source Classification Code is 10201101.
bUnits are Ibs. of pollutant/1,000 Ibs. of steam produced,
 where 1 Ib. of wet bagasse fired produces 2 Ibs. of steam.
Units are Ibs. of pollutant/ton of wet, as-fired bagasse containing approximately 50 percent moisture,
 by weight
References 2, 6-14. Includes only filterable PM (i.e., that particulate collected on or prior to the filter
 of an EPA Method 5 (or equivalent) sampling train.
"References 6-14.  CO2 emissions will increase following a wet scrubber hi which CO2-generating
 reagents (such as sodium carbonate or calcium carbonate) are used.
References 13-14.
Reference 13. Based on measurements collected downstream of PM control devices which may have
 provided some removal of polycyclic organic matter (POM) condensed on PM.
1.8-4
EMISSION FACTORS
7/93

-------
References for Section 1.8

1.  Potential Control Strategies for Bagasse Fired Boilers, EPA Contract No. 68-02-0627,
    Engineering-Science, Inc., Arcadia, CA, May 1978.

2.  Background Document: Bagasse Combustion in Sugar Mills, EPA-450/3-77-077, U. S.
    Environmental Protection Agency, Research Triangle Park, NC, January 1977.

3.  Nonfossil Fuel Fired Industrial Boilers - Background Information, EPA-450/3-82-007, U. S.
    Environmental Protection Agency, Research Triangle Park, NC, March 1982.

4.  A Technology Assessment of Solar Energy Systems:  Direct Combustion of Wood and Other
    Biomass in Industrial Boilers, ANL/EES-TM--189, Angonne National Laboratory, Argonne, IL,
    December 1981.

5.  Emission Factor Documentation for AP-42 Section 1.8 - Bagasse Combustion in Sugar Mills,
    Technical Support Division, Office of Air Quality Planning and Standards, U. S. Environmental
    Protection Agency, Research Triangle Park, NC, April 1993.

6.  Paniculate Emissions Test Report: Atlantic Sugar Association, Air Quality Consultants, Inc.,
    December 20, 1978.

7.  Compliance Stack Test: Gulf and Western Food Products: Report No. 238-S, South Florida
    Environmental Services, Inc., February 1980.

8.  Compliance Stack Test: Gulf and Western Food Products: Report No. 221 -S, South Florida
    Environmental Services, Inc., January 1980.

9.  Compliance Stack Test: United States Sugar Corporation: Report No. 250-5, South Florida
    Environmental Services, Inc., February 1980.

10. Compliance Stack Test: Osceola Farms Company:  Report No. 215-S, South Florida           ,
    Environmental Services, Inc., December 1979.

11. Source Emissions Survey ofDavies Hamakua Sugar Company:  Report No. 79-34, Mullins
    Environmental Testing Company, May 1979.

12. Source Emissions Survey: Honokaa Sugar Company, Kennedy Engineers, Inc., January, 19 1979.

13. Stationary Source  Testing of Bagasse Fired Boilers at the Hawaiian Commercial and Sugar
    Company:  Puunene, Maui, Hawaii, EPA Contract No. 68-02-1403, Midwest Research Institute,
    Kansas City, MO, February 1976.

14. Emission Test Report:  U. S. Sugar Company, Bryant Florida, EPA Contract No. 68-02-2818,
    Monsanto Research Corporation, Dayton, OH, May 1980.
7/93                             External Combustion Sources                            1.8-5

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1.9 RESIDENTIAL FIREPLACES

L9.1  General1-2

       Fireplaces are used primarily for aesthetic effects and secondarily as a supplemental heating
source in houses and other dwellings.  Wood is the most common fuel for fireplaces, but coal and
densified wood "logs" may also be burned.  The user intermittently adds fuel to the fire by hand.

       Fireplaces can be divided into two broad categories, 1) masonry (generally brick and/or stone,
assembled on site, and integral to a structure) and 2) prefabricated (usually metal, installed on site as a
package with appropriate duct work).

       Masonry fireplaces typically have large fixed openings to the fire bed and have dampers above
the combustion area in the chimney to limit room air and heat losses when the fireplace is not being
used.  Some masonry fireplaces are designed or retrofitted with doors and louvers to reduce the intake
of combustion air during use.

       Prefabricated fireplaces are commonly equipped with louvers and glass doors to reduce the
intake of combustion air, and some are surrounded by ducts through which floor level air is drawn by
natural convection, heated and returned to the room. Many varieties of prefabricated fireplaces are
now available on the market. One general class is the freestanding fireplace, the most common of
which consists of an inverted sheet metal funnel and stovepipe directly above the fire bed. Another
class is the "zero clearance"  fireplace, an iron or heavy gauge steel firebox lined inside with firebrick
and surrounded by multiple steel walls with spaces for air circulation. Some zero clearance fireplaces
can be inserted into existing masonry fireplace openings, and thus are sometimes called "inserts."
Some of these units are  equipped with close fitting doors and have operating and combustion
characteristics similar to wood stoves.  (See Section 1.10, Residential Wood Stoves.)

       Masonry fireplaces usually heat a room by radiation, with a significant fraction of the
combustion heat lost in the exhaust gases and through fireplace walls. Moreover, some of the radiant
heat entering the room goes  toward warming the air that is pulled into the residence to make up for
that drawn up the chimney.  The net effect is that masonry fireplaces ate usually inefficient heating
devices.  Indeed, in cases  where combustion is poor, where the outside air is cold, or where the fire is
allowed to smolder (thus drawing  air into a  residence without producing appreciable radiant heat
energy), a net heat loss may occur hi a residence using a fireplace. Fireplace heating  efficiency may
be improved by a number of measures that either reduce the excess air rate or transfer back into the
residence some of the heat that would normally be lost in the exhaust gases or through fireplace walls.
As noted above, such measures are commonly incorporated into prefabricated units. As a result, the
energy efficiencies of prefabricated fireplaces are slightly higher than those of masonry fireplaces.
               ,1-13
 1.9.2 Emissions

        The major pollutants of concern from fireplaces are unburnt combustibles, including carbon
 monoxide, gaseous organics and particulate matter (i.e., smoke).  Significant quantities of unburnt
 combustibles are produced because fireplaces are inefficient combustion devices, with high
 uncontrolled excess air rates and without any sort of secondary combustion. The latter is especially
 important in wood burning because of its high volatile matter content, typically 80 percent by dry

 7/93                              External Combustion Sources                             1.9-1

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 weight  In addition to unburnt combustibles, lesser amounts of nitrogen oxides and sulfur oxides are
 emitted.

        Hazardous Air Pollutants (HAPs) are a minor, but potentially important component of wood
 smoke.  A group of HAPs known as polycyclic organic matter (POM) includes potential carcinogens
 such as benzo(a)pyrene (BaP). POM results from the combination of free radical species formed in
 the flame zone, primarily as a consequence of incomplete combustion.  Under reducing conditions,
 radical chain propagation is enhanced, allowing the buildup of complex organic material such as POM.
 The POM is generally found in or on smoke particles, although some sublimation into the vapor phase
 is probable.

        Another important constituent of wood smoke is creosote.  This tar-like substance will burn if
 the fire is hot enough, but at insufficient temperatures, it may deposit on surfaces in the exhaust
 system.  Creosote deposits are a fire hazard hi the flue, but they can be reduced if the chimney is
 insulated to prevent creosote condensation or if the chimney is cleaned regularly to remove any
 buildup.

        Fireplace emissions are highly variable and are a function of many wood characteristics and
 operating practices. In general, conditions which promote a fast bum rate and a higher flame intensity
 enhance secondary combustion and thereby lower emissions.  Conversely, higher emissions will result
 from a slow burn rate and a lower flame intensity.  Such generalizations apply particularly to the
 earlier stages of the burning cycle, when significant quantities of combustible volatile matter are being
 driven out of the wood. Later in the burning cycle, when all volatile matter has been driven out of the
 wood, the charcoal that remains burns with relatively  few emissions.

       Emission factors and their ratings for wood combustion  in residential fireplaces are given  in
 Tables 1.9-1. and 1.9-2.
1.9-2                               EMISSION FACTORS                              7/93

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     Table 1.9-1. (ENGLISH UNITS) EMISSION FACTORS FOR WOOD COMBUSTION IN
                                RESIDENTIAL FIREPLACES
                           (Source Classification Code: 2104008001)
Device
Fireplace







Pollutant
PM-10"
Carbon Monoxide0
Sulfur Oxidesd
Nitrogen oxides6
Carbon Dioxidef
Total VOCs6
POM"
Aldehydesk
Emission Factor8
Ib/ton
34.6
252.6
0.4
2.6
3400
229.0
1.6E-3
2.4
Rating
B
B
A
C
C
D
EJ
E3
aUriits are in Ibs. of pollutant/ton of dry wood burned.
References 2, 5, 7,13; contains filterable and condensable particulate matter (PM); PM emissions are
considered to be 100% PM-10 (i.e., PM with an aerodynamic diameter of lOum or less).
"References 2, 4, 5, 9,  13.
""References 1, 8.
References 4, 9; expressed as NO2.
'References 5, 13
'References 4 -  5, 8. Data used to calculate the average emission factor were collected by various
methods. While the emission factor may be representative of the source population in general, factors
may not be accurate for individual sources.
Reference 2.
jData used to calculate the average emission factor were collected from a single fireplace and are not
representative of the general source population.
References 4, 11.
 7/93
External Combustion Sources
1.9-3

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       Table 1.9-2. (METRIC UNITS) EMISSION FACTORS FOR WOOD COMBUSTION IN
                                 RESIDENTIAL FIREPLACES
                            (Source Classification Code:  2104008001)
Device
Fireplace







Pollutant
PM-10b
Carbon Monoxide0
Sulfur Oxidesd
Nitrogen oxides6
Carbon Dioxidef
Total VOCsg
POMh
Aldehydes*
Emission Factor8
g/kg
17.3
126.3
0.2
1.3
1700
114.5
0.8E-3
1.2
Rating
B
B
A
C
C
D
Ej
Ej
 "Units are in grams of pollutant/kg of dry wood burned.
 'References 2, 5, 7,  13; contains filterable and condensable paniculate matter (PM); PM emissions are
 considered to be 100% PM-10 (i.e., PM with an aerodynamic diameter of lOum or less).
 'References 2, 4,5, 9,13.
 ""References 1, 8.
 References 4, 9; expressed as NO2.
 References 5, 13
 ^References 4 - 5, 8.  Data used to calculate the average emission factor were collected by various
 methods.  While the emission factor may be representative of the source population in general, factors
 may not be accurate for individual sources.
 ^Reference 2.
jData used to calculate the average emission factor were collected from a single fireplace and are not
 representative of the general source population.
 "References 4, 11.
1.9-4
EMISSION FACTORS
7/93

-------
References for Section 1.9
                                     .?        ',:;.

 1.    DeAngelis, D.G., et al., Source Assessment: Residential Combustion Of Wood, EPA-
      600/2-80-042b, U.S. Environmental Protection Agency, Cincinnati, OH, March 1980.

2.     Snowden, W.D., et al., Source Sampling Residential Fkeplaces For Emission Factor
      -Development EPA-450/3-76-010, U.S. Environmental Protection Agency, Research
      Triangle Park,  NC, November 1975.

3.     Shelton, J.W.,  and L. Gay, Colorado Fireplace Report. Colorado Air Pollution Control
      Division, Denver, CO, March 1987.

4.     Dasch, J.M., "Particulate And Gaseous Emissions From Wood-burning Fkeplaces,"
      Environmental Science And Technology, 16(10):643-67, October 1982.

5.     Source Testing For Fireplaces. Stoves. And Restaurant Grills In Vail, Colorado, EPA
      Contract No. 68-01-1999, Pedco Environmental, Inc., Cincinnati, OH, December 1977.

6.     Written communication from Robert C. McCrillis, U.S.  Environmental Protection
      Agency, Research Triangle Park, NC, to Neil Jacquay, U.S. Environmental Protection
      Agency, San Francisco, CA, November 19, 1985.

7.     Development Of AP-42 Emission Factors For Residential Fkeplaces, EPA Contract
      No. 68-D9-0155, Advanced Systems Technology, Inc., Atlanta, GA, January 11, 1990.

8.     DeAngelis, D.G., et al., Preliminary Characterization Of Emissions From Wood Fked
      Residential Combustion Equipment EPA-600/7-80-040, U.S. Envkonmental Protection
      Agency, Cincinnati, OH, March 1980.

9.     Kosel, P., et al., Emissions From Residential Fkeplaces, CARD Report C-80-027,
      California Ak  Resources Board, Sacramento,  CA, April 1980.

10.   Clayton, L., et al., Emissions From Residential Type Fkeplaces, Source Tests 24C67,
      26C, 29C67, 40C67, 41C67, 65C67 and 66C67, Bay Area Ak Pollution Control
      District, San Francisco, CA, January 31,  1968.

11.   Lipari, F., et al., Aldehyde Emissions From Wood-Burning Fkeplaces, Publication
      GMR-4377R, General Motors Research Laboratories, Warren, MI, March 1984.

12.   Hayden, A., C.S., and R.W. Braaten, "Performance Of Domestic Wood Fked
      Appliances," Presented at the 73rd Annual Meeting of the Ak Pollution Control
      Association, Montreal, Quebec, Canada, June 1980.

13.   Barnett, S.G.,  In-Home Evaluation of Emissions From Masonry Fkeplaces and
      Heaters, OMNI Envkonmental Services,  Inc., Beaverton, OR, September 1991.

7/93                          External Combustion Sources                          1.9-5

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1.10 RESIDENTIAL WOOD STOVES

1.10.1  General1-2

       Wood stoves are commonly used in residences as space heaters.  They are used both as the
primary source of residential heat and to supplement conventional heating systems.

       Five different categories should be considered when estimating emissions from wood burning
devices due to differences in both the magnitude and the composition of the emissions:

              the conventional wood stove,

              the noncatalytic wood stove,

              the catalytic wood stove,

              the pellet stove, and

              the masonry heater.

Among these categories, there are many variations in device design and operation characteristics.

       The conventional stove category comprises all stoves without catalytic combustors not included
in the other noncatalytic categories (i.e., noncatalytic and pellet). Conventional stoves do not have any
emission reduction technology or design features and, in most cases, were manufactured before July  1,
1986.  Stoves of many different airflow designs may be in this category, such as updraft, downdraft,
crossdraft and S-fiow.

       Noncatalytic wood stoves are those unite that do not employ catalysts but do have emission
reducing technology or features. Typical noncatalytic design includes baffles and secondary
combustion chambers.

       Catalytic stoves are equipped with a ceramic or metal honeycomb device, called a combustor
or converter,  that is coated with a noble metal such as platinum or palladium. The catalyst material
reduces the ignition temperature of the unburned volatile organic compounds (VOC) and carbon
monoxide (CO) in the exhaust gases, thus augmenting their ignition and combustion at normal stove
operating temperatures.  As these components of the gases burn, the temperature inside the  catalyst
increases to a point at which the ignition of the gases is essentially self sustaining.

       Pellet stoves are those fueled with pellets of sawdust, wood products, and other biomass
materials pressed into manageable shapes and sizes.  These stoves have active air flow systems and
unique grate design to accommodate this type of fuel.  Some pellet stove models are subject to the
1988 New Source Performance Standards (NSPS), while others are exempt due to a high air-to-fuel
ratio (i.e., greater than 35-to-l).

       Masonry heaters are large, enclosed chambers made of masonry products or a combination of
masonry products and ceramic materials. These devices are exempt from the 1988 NSPS due to their
weight (i.e., greater than 800 kg).  Masonry heaters are gaining popularity as a cleaner burning and

7/93                              External Combustion Sources                           1.10-1

-------
 heat efficient form of primary and supplemental heat, relative to some other types of wood heaters. In
 a masonry heater, a complete charge of wood is burned in a relatively short period of time.  The use
 of masonry materials promotes heat transfer.  Thus, radiant heat from the heater warms the
 surrounding area for many hours after the fire has burned out

 1.10.2   Emissions

        The combustion and pyrolysis of wood in wood stoves produce atmospheric emissions of
 particulate matter, carbon monoxide, nitrogen oxides, organic compounds, mineral residues, and to a
 lesser extent, sulfur oxides. The quantities and types of emissions are highly variable, depending on a
 number of factors, including stage of the  combustion cycle.  During initial burning stages, after a new
 wood charge is introduced, emissions (primarily VOCs) increase dramatically.  After the initial period
 of high burn rate, there is a charcoal stage of the burn cycle characterized by a slower burn rate and
 decreased emissions. Emission rates during this stage .are cyclical, characterized by relatively long
 periods of low emissions and shorter episodes of emission spikes.

        Particulate emissions are defined  in this discussion as the total catch measured by the EPA
 Method 5H (Oregon Method 7) sampling train.1 A small portion of wood stove particulate emissions
 includes "solid" particles of elemental carbon and wood.  The vast majority of particulate emissions is
 condensed organic products of incomplete combustion equal to or less than 10 micrometers hi
 aerodynamic diameter (PM-10).  Although reported particle size data are scarce, one reference states
 that 95  percent of the particles emitted from a wood  stove were less than 0.4 micrometers hi size.3

        Sulfur oxides (SO*) are formed by oxidation  of sulfur in the wood.  Nitrogen oxides  (NOJ are
 formed  by oxidation of fuel and atmospheric nitrogen.  Mineral constituents, such as potassium and
 sodium  compounds, are released from the wood matrix during combustion.

        The high levels of organic compound and CO emissions are results of incomplete combustion
 of the wood. Organic constituents of wood smoke vary considerably in both type and volatility.
 These constituents include simple hydrocarbons of carbon numbers 1 through 7 (Cl - C7) (which exist
 as gases or which volatilize at ambient conditions) and complex low volatility substances that
 condense at ambient conditions.  These low volatility condensible materials generally are considered to
 have boiling points below 300C (572F).

        Polycyclic organic matter (POM)  is an important component of the condensible fraction of
 wood smoke. POM contains a wide range of compounds, including organic compounds formed
 through incomplete combustion by the combination of free radical species hi the flame zone.  This
 group which is classified as a Hazardous Air Pollutant (HAP) under Title HI of the 1990 Clean Air
 Act Amendments contains the sub-group of hydrocarbons called Polycyclic Aromatic Hydrocarbons
 (PAH).

       Emission factors and their ratings for wood combustion in residential wood stoves, pellet
 stoves and masonry heaters are presented  hi Tables 1.10-1 through  1.10-8.  The analysis leading to the
 revision of these emission factors is contained in the emission factor documentation.29 These tables
 include emission factors for criteria pollutants (PM-10, CO, NOX, SOJ, CO2, Total Organic
 Compounds  (TOC), speciated organic compounds, PAH, and some  elements. The emission factors are
presented by wood heater type.  PM-10 and CO emission factors are further classified by stove
certification  category. Phase E stoves are those certified to meet the July 1,1990 EPA standards;

 1.10-2                              EMISSION FACTORS                               7/93

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                                                                                                           1
Phase I stoves meet only the July 1,1988 EPA standards; and Pre-Phase I stoves do not meet any of
the EPA standards but in most cases do necessarily meet the Oregon 1986 certification standards.1
The emission factors for PM and CO in Tables 1.10-1 and 1.10-2 are averages, derived entirely from
field test data obtained under actual operating conditions.  Still, there is a potential for higher
emissions from some wood stove, pellet stove  and masonry heater models.

       As mentioned, paniculate emissions are defined as the total emissions equivalent to that
collected by EPA Method 5H.  This method employs a heated filter followed by three impingers, an
unheated filter, and a final impinger. Paniculate emissions factors are presented as values equivalent
to that collected with Method 5H.  Conversions are employed, as appropriate, for data collected with
other methods.

       Table 1.10-7 shows net efficiency by device type, determined entirely from field test data. Net
or overall efficiency is the product of combustion efficiency multiplied by heat transfer efficiency.
Wood heater efficiency is an important parameter used, along with emission factors and percent
degradation, when calculating PM-10 emission reduction credits.  Percent degradation is related to the
loss in effectiveness of a wood stove control device or catalyst over a period of operation.  Control
degradation for any stove, including noncatalytic wood stoves, may also occur as a result of
deteriorated seals and gaskets, misaligned baffles and bypass mechanisms, broken refractories, or other
damaged functional components. The increase in emissions which can result from control degradation
has not been quantified.  However, recent wood stove testing in Colorado and Oregon should produce
results which allow estimation of emissions as a function of stove age.
7/93                              External Combustion Sources                            1.10-3

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-------
     TABLE 1.10-3.  (ENGLISH AND METRIC UNITS) ORGANIC COMPOUND EMISSION
                   FACTORS FOR RESIDENTIAL WOOD COMBUSTION3
                                (Source Classification Codes)

                            (EMISSION FACTOR RATING: E)b
Compounds



Ethane
Ethylene
Acetylene
Propane
Propene
i-Butane
n-Butane
Butenes"
Pentenesd
Benzene
Toluene
Furan
Methyl Ethyl Ketone
2-Methyl Furan
2,5-Dimethyl Furan
Furfural
O-Xylene
WOOD STOVE TYPE
Conventional
(SCC 2104008051)
Ib/ton g/kg
1.470 0.735
4.490 2.245
1.124 0.562
0.358 0.179
1.244 0.622
0.028 0.014
0.056 0.028
1.192 0.596
0.616 0.308
1.938 0.969
0.730 0.365
0.342 0.171
0.290 0.145
0.656 0.328
0.162 0.081
0.486 0.243
0.202 0.101
Catalytic
(SCC 2104008030)
Ib/ton g/kg
1.376 0.688
3.482 1.741
0.564 0.282
0.158 0.079
0.734 0.367
0.010 0.005
0.014 0.007
0.714 0.357
0.150 0.075
1.464 0.732
0.520 0.260
0.124 0.062
0.062 0.031
0.084 0.042
0.002 0.011
0.146 0.073
0.186 0.093
Reference 17.  Units are in Ibs. of pollutant/ton of dry wood burned and grams of pollutant/kg of dry
wood burned.
''Data show a high degree of variability within the source population.  Factors may not be accurate for
individual sources.
l-butene, i-butene, t-2-butene, c-2-butene, 2-me-l-butene, 2-me-butene are reported as butenes.
dl-pentene, t-2-pentene, and c-2-pentene are reported as pentenes.
1.10-6                             EMISSION FACTORS                              7/93

-------
    TABLE 1.10-4.  (ENGLISH UNITS) POLYGYCLIC AROMATIC HYDROCARBON (PAH)
              EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION"
                                (Source Classification Codes)

                             (EMISSION FACTOR RATING: E)b
Pollutant
STOVE TYPE
Conventional0
(SCC
2104008051)
Noncatalyticd
(SCC
2104008050)
Catalytic"
(SCC
2104008030)
Exempt Pellet'
(SCC
2104008053)
PAH
Acenaphthene
Acenaphthylene
Anthracene
Benzo(a)Anthracene
Benzo(b)Fluoranthene
Benzo(g,h4)Fluorantherae
Benzo(k)Fluoranthene
Benzo(g,h4)Perylene
Benzo(a)Pyrene
Benzo(e)Pyrene
Biphenyl
Chrysene
Dibenzo(a,h)Anthracene
7,12-Dimethylbenz(a)Anthracene
Fluoranthene
Fluorene
Indeno(l,2,3,cd)Pyrene
9-Methylanthracene
12-Methylbenz(a)Anthracene
3-Methylchlplanthrene
1-Methylphenanthrene
Naphthalene
Nitronaphthalene
Perylene
Phenanthrene
Phenanthrol
Phenol
Pyrene
PAH Total

0.010
0.212
0.014
0.020
0.006

0.002
0.004
0.004
0.012

0.012
0.000

0.020
0.024
0.000




0.288


0.078


0.024
0.730

0.010
0.032
0.009
<0.001
0.004
0.028
<0.001
0.020
0.006
0.002
0.022
0.010
0.004
0.004
0.008
0.014
0.020
0.004
0.002
<0.001
0.030
0.144
0.000
0.002
0.118
0.000
<0.001
0.008
0.500

0.006
0.068
0.008
0.024
0.004
0.006
0.002
0.002
0.004
0.004

0.010
0.002

0.012
0.014
0.004




0.186


0.489


0.010
0.414





2.60E-05






7.52E-05


5.48E-05









3.32E-05


4.84E-05

"Units ate in Ibs. of pollutant/ton of dry wood burned.
"Data show a high degree of variability within the source population and/or came from a small number of
sources.  Factors may not be accurate for individual sources.
Reference 17.
"References 15,18 - 20.
References 14 -18.
Reference 27. Exempt = Exempt from 1988 NSPS (Le., air : fuel >35:1).
7/93
External Combustion Sources
1.10-7

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     TABLE 1.10-5.  (METRIC UNITS) POLYCYCLIG AROMATIC HYDROCARBON (PAH)
               EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION"
                                   (Source Classification Codes)

                                   (Emission Factor Rating: E)b
Pollutant
STOVE TYPE
Conventional0
(SCC
2104008051)
Noncatalyticd
(SCC
2104008050)
Catalytic6
(SCC
2104008030)
Exempt Pellet1
(SCC
2104008053)
 PAH
 Acenaphthene                         0.005
 Acenaphthylene                       0.106
 Anthracene                           0.007
 Benzo(a)Anthracene                    0.010
 Benzo(b)Fluoranthene                  0.003
 Benzo(g,h4)Fluoranthene
 Benzo(k)Fluoranthene                  0.001
 Benzo(g,h4)Perylene                   0.002
 Benzo(a)Pyrene                       0.002
 Benzo(e)Pyrene                       0.006
 Biphenyl
 Chrysene                             0.006
 Dibenzo(a,h)Anthracene                0.000
 7,12-Dimethylbenz(a)Anthracene
 Fiuoranthene                          0.010
 Fluorene                             0.012
 Indeno(l,23,cd)Pyrene                 0.000
 9-Methylanthracene
 12-Methylbenz(a)Anthracene
 3-MethyIchlolanthrene
 1-Methylphenanthrene
 Naphthalene                          0.144
 Nitronaphthalene
 Perylene
 Phenanthrene                         0.039
 Phenanthrol
 Phenol
 Pyrene                               0.012

 PAH Total                           0.365
 0.005
 0.016
 0.004
<0.001
 0.002
 0.014
<0.001
 0.010
 0.003
 0.001
 0.011
 0.005
 0.002
 0.002
 0.004
 0.007
 0.010
 0.002
 0.001
<0.001
 0.015
 0.072
 0.000
 0.001
 0.059
 0.000
<0.001
 0.004

 0.250
0.003
0.034
0.004
0.012
0.002
0.003
0.001
0.001
0.002
0.002

0.005
0.001

0.006
0.007
0.002
0.093


0.024


0.005

0.207
1.30E-05
3.76E-05
2.74E-05
1.66E-05
2.42E-05
"Units ate in grams of pollutant/kg of dry wood burned.
"Data show a high degree of variability within the source population and/or came from a small number of
sources. Factors may not be accurate for individual sources.
Reference 17.
^References 15,18 - 20.
References 14 -18.
^Reference 27. Exempt = Exempt from 1988 NSPS (i.e., air : fuel >35:1).
1.10-8
                                      EMISSION FACTORS
                                       7/93

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   TABLE 1.10-6. (ENGLISH AND METRIC UNITS) TRACE ELEMENT EMISSION FACTORS
                        FOR RESIDENTIAL WOOD COMBUSTION"
                               (Source Classification Codes)

                            (EMISSION FACTOR RATING: E)b
Element
WOOD STOVE TYPE
Conventional
(SCC 2104008051)
Ib/fon g/kg
Noncatalytic
(SCC 2104008050)
Ib/ton g/kg
Catalytic
(SCC 2104008030)
Ib/ton g/kg
Cadmium (Cd)
Chromium (Cr)
Manganese (Mn)
Nickel (Ni)
2.2E-05
<1.0E-06
1.7E-04
1.4E-05
1.1E-05
<1.0E-06
8.7E-05
7.0E-06
2.0E-05
<1.0E-06
1.4E-04
2.0E-05
l.OE-05
<1.0E-05
7.0E-05
l.OE-05
4.6E-05
<1.0E-06
2.2E-04
2.2E-06
2.3E-05
<1.0-E06
1.1E-04
l.OE-06
"References 14,17.  Units are in Ibs. of pollutant/ton of dry wood burned and grams of pollutant/kg of
dry wood burned.
"The data used to develop these emission factors showed a high degree of variability within the source
population.  Factors may not be accurate for individual sources.
            TABLE 1.10-7. SUMMARY OF WOOD HEATER NET EFFICIENCIES8
Wood Heater
Type Source ]
Classification
Code
Wood Stoves
Conventional 2104008051
Noncatalytic 2104008050
Catalytic 2104008030
Pellet Stoves'5
Certified
Exempt
2104008053
Masonry Heaters
All 2104008055
Nfet Efficiency (%) Reference
54 26
68 9, 12, 26
68 6, 26
68 11
56 27
58 28
"Net efficiency is a function of both combustion efficiency and heat transfer efficiency.
 The percentages shown here are based on data collected from in-home testing.
"Certified = Certified pursuant to 1988 NSPS.
Exempt = Exempt from 1988 NSPS (i.e., air : fuel >35:1).
7/93
External Combustion Sources
                                                  1.10-9

-------
REFERENCES FOR SECTION 1.10
1.  Standards Of Performance For New Stationary Sources:  New Residential Wood Heaters. 53 FR
    5573, February 26, 1988.

2.  Gay, R., and J. Shah, Technical Support Document For Residential Wood Combustion. EPA-
    450/4-85-012, U.S. Environmental Protection Agency, Research Triangle Park, NC, February
    1986.

3.  Rau, J.A., and JJ. Huntzicker, Composition And Size Distribution Of Residential Wood Smoke
    Aerosols. Presented at the 21st Annual Meeting of the Air and Waste Management Association,
    Pacific Northwest International Section, Portland, OR, November 1984.

4.  Simons, C.A., et al., Whitehorse Efficient Woodheat Demonstration. The City of Whitehorse,
    Whitehorse, Yukon, Canada, September 1987.

5.  Simons, C.A., et al., Woodstove Emission Sampling Methods Comparability Analysis And Lti-situ
    Evaluation Of New Technology Woodstoves. EPA-600/7-89-002, U.S. Environmental Protection
    Agency, Cincinnati, OH, January 1989.

6.  Bamett, S.G., Field Performance Of Advanced Technology Woodstoves hi Glens Falls. N.Y.
    1988-1989.. Vol. 1, New York State Energy Research and Development Authority, Albany, NY,
    October 1989.

7.  Bumet, P.O., The Northeast Cooperative Woodstove Study. Volume 1, EPA-600/7-87-026a, U.S.
    Environmental Protection Agency, Cincinnati, OH, November 1987.

8.  Jaasma, D.R., and MJR. Champion, Field Performance Of Woodburning Stoves In Crested Butte
    During The 1989-90 Heating Season. Town of Crested Butte, Crested Butte, CO, September 1990.

9.  Derribach, S., Woodstove Field Performance In Klamatn Falls. OR. Wood Heating Alliance,
    Washington, DC, April 1990.

10. Simons, C.A., and S.K. Jones, Performance Evaluation Of The Best Existing Stove Technology
    (BEST) Hybrid Woodstove And Catalytic Retrofit Device. Oregon Department of Environmental
    Quality, Portland, OR, July 1989.

11. Bamett, S.G., and R.B. Roholt, In-home Performance Of Certified Pellet Stoves In Medford And
    Klamath Falls. OR. U.S. Department of Energy Report No. PS407-02, July 1990.

12. Bamett, S.G., In-Home Evaluation of Emission Characteristics of EPA-Certified High-Tech Non-
    Catalyn'c Woodstoves in Klamath Falls. OR, 1990. prepared for the Canada Center for Mineral
    and Energy Technology, Energy, Mines and Resources, Canada, DSS File No. 145Q, 23440-9-
    9230, June 1, 1990.
1.10-10
                                  EMISSION FACTORS
7/93

-------
REFERENCES FOR SECTION 1.10 (Continued)
 13. McCrillis, R.C., and R.G. Merrill, Emission Control Effectiveness Of A Woodstove Catalyst And
    Emission Measurement Methods Comparison. Presented at the 78th Annual Meeting of the Air
    And Waste Management Association, Detroit, MI, 1985.

 14. Leese, K.E., and S.M. Harkins, Effects Of Burn Rate, Wood Species, Moisture Content And
    Weight Of Wood Loaded On Woodstove Emissions. EPA 600/2-89-025, U.S. Environmental
    Protection Agency, Cincinnati, OH, May 1989.

 15. Allen, J.M.. and W.M. Cooke. Control Of Emissions From Residential Wood Burning By
    Combustion Modification. EPA-600/7-81-091, U.S. Environmental Protection Agency, Cincinnati,
    OH, May 1981.

 16. DeAngelis, D.G., et al., Preliminary Characterization Of Emissions From Wood-fired Residential
    Combustion Equipment. EPA-600/7-80-040, U.S. Environmental Protection Agency, Cincinnati,
    OH, March 1980.

 17. Burnet, P.O., et al., Effects of Appliance Type and Operating Variables on Woodstove Emissions.
    Vol. I., Report and Appendices 6-C, EPA-600/2-90-001a, U.S. Environmental Protection Agency,
    Research Triangle Park,  NC, January 1990.

 18. Cottone, L.E., and E. Mesner, Test Method Evaluations and Emissions Testing for Rating Wood
    Stoves. EPA-600/2-86-100, U.S. Environmental Protection Agency, Research Triangle Park, NC,
    October 1986.

 19. Residential Wood Heater Test Report. Phase H Testing, Vol. 1, TVA, Division of Energy,
    Construction and Rates,  Chattanooga, TN, August 1983.

20. Truesdale, R.S. and J.G. Cleland, Residential Stove Emissions from Coal and Other Alternative
    Fuels Combustion, in papers at the Specialty Conference on Residential Wood and Coal
    Combustion, Louisville,  KY, March 1982.

21. Barnett, S.G., In-Home Evaluation of Emissions From Masonry Fireplaces and Heaters. OMNI
    Environmental Services,  Inc., Beaverton, OR, September 1991.

22. Barnett, S.G., In-Home Evaluation of Emissions From a Grundofen Masonry Heater. OMNI
    Environmental Services,  Inc., Beaverton, OR, January 1992.

23. Barnett, S.G., In-Home Evaluation of Emissions From a Tulikivi KTU 2100 Masonry Heater.
    OMNI Environmental  Services, Inc., Beaverton, OR, March 1992.

24. Barnett, S.G., In-Home Evaluation of Emissions From a Royal Crown 2000 Masonry Heater,
    OMNI Environmental  Services, Inc., Beaverton, OR, March 1992.

25. Barnett, S.G., In-Home Evaluation of Emissions From a Bioflre 4x3 Masonry Heater. OMNI
    Environmental Services,  Inc., Beaverton, OR, March 1992.

7/93                            External Combustion Sources

-------
REFERENCES FOR SECTION 1.10 (Continued)


26. Bamett, S.G. and R.D. Bighouse, In-Home Demonstrations of the Reduction of Wbodstove
    Emissions from the use of Densified Logs. Oregon Department of Energy and U.S. Environmental
    Protection Agency, July 1992.

27. Bamett, S.G. and P.O. Fields, In-Home Performance of Exempt Pellet Stoves in Medford. Oregon.
    U. S. Department of Energy, Oregon Department of Energy, Tennessee Valley Authority, and
    Oregon Department of Environmental Quality, July 1991.

28. Bamett, S.G., Summary Report of the In-Home Emissions and Efficiency Performance of Five
    Commercially Available Masonry Heaters, the Masonry Heater Association, May 1992.

29. Emission Factor Documentation for AP-42 Section 1.10. Residential Wood Stoves, Office of Air
    Quality Planning and  Standards, U.S. Environmental Protection Agency, Research Triangle Park,
    NC, April 1993.
1.10-12                            EMISSION FACTORS                              7/93

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 1.11 WASTE OIL COMBUSTION

 1.11.1  General1

        Waste, or used oil can be burned in a variety of combustion systems including industrial
 boilers; commercial/institutional boilers; space heaters; asphalt plants; cement and lime kilns; other
 types of dryers and calciners; and steel production blast furnaces.  Boilers and space heaters consume
 the bulk of the waste oil burned. Space heaters are small combustion units [generally less than 0.1
 MW (250,000 Btu/hr input)] that are common in automobile service stations and automotive repair
 shops where supplies of waste crankcase oil are available.

        Boilers designed to burn No. 6 (residual) fuel oils or one of the distillate fuel oils can be used
 to burn waste oil, with or without modifications for optimizing combustion.  As an alternative to boiler
 modification, the properties of waste oil can be modified by blending it with fuel oil, to the extent
 required to achieve a clean-burning fuel mixture.

 1.11.2 Emissions and Controls1"3

        Waste oil includes used  crankcase oils from automobiles and trucks, used industrial lubricating
 oils  (such as metal working oils), and other used industrial oils (such as heat transfer fluids).  When
 discarded,  these oils become waste oils due to a breakdown of physical properties and to
 contamination by the materials they come in contact with. The different types of waste oils may be
 burned as mixtures or as single fuels where supplies allow; for example, some space heaters in
 automotive service stations burn waste crankcase oils.

        Contamination of the virgin oils with a variety of materials leads to an air pollution potential
 when these oils are burned. Potential pollutants include particulate matter (PM), small particles below
 10 micrometers in size (PM-10), toxic metals, organic compounds, carbon monoxide (CO), sulfur
 oxides (SOJ, nitrogen oxides (NO^, hydrogen chloride, and global warming gases (CO2, methane).

       Ash levels in waste oils  are normally much higher than ash levels in either distillate oils or
 residual oils. Waste oils have substantially higher concentrations of most of the trace elements
 reported relative to those concentrations found in virgin fuel oils. However, because of the shift to
 unleaded gasoline, the concentration of lead in waste crankcase oils has continued to decrease in recent
 years.  Without air pollution controls, higher concentrations of ash and trace metals in the waste fuel
 translate to higher emission levels of PM and trace metals than is the case for virgin fuel oils.

       Low efficiency pretreatment steps, such as large particle removal with screens or coarse filters,
 are common prefeed procedures  at oil-fired boilers.  Reductions in total PM emissions can be expected
 from these techniques but little or no effects have been noticed on the levels of (PM-10) emissions.

       Constituent chlorine in waste oils typically  exceeds the concentration of chlorine in virgin
distillate and residual oils.  High levels of halogenated solvents are often found in waste oil as a result
of inadvertent or deliberate additions of the contaminant solvents to the waste oils.  Many efficient
combustors can destroy more than 99.99 percent of the chlorinated solvents present in the fuel.
However, given the wide array of combustor types  which burn waste oils, the presence of these
compounds in the emission stream cannot be ruled  out.
7/93                              External Combustion Sources                            1.11-1

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       The flue gases from waste oil combustion often contain organic compounds other than
chlorinated solvents.  At ppmw levels, several hazardous organic compounds have been found in waste
oils. Benzene, toluene, polychlorinated biphenyls (PCBs) and polychlorinated dibenzo-d-dioxins are a
few of the hazardous compounds that have been detected in waste oil samples. Additionally, these
hazardous compounds may be formed in the combustion process as products of incomplete
combustion.

       Emission factors and emission factor ratings for waste oil combustion are shown in Tables
1.11-1 through 1.11-5.  Emission factors have been determined for emissions from uncontrolled small
boilers and space heaters combusting waste oil. The use of both blended and unblended fuels is
included in the mix of combustion operations.

       Emissions from waste oil used in batch asphalt plants may be estimated using the procedures
outlined in  Section 4.5.
 1.11-2
EMISSION FACTORS
7/93

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1.11-5

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     External Combustion Sources
                                                  1.11-7

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REFERENCES FOR SECTION 1.11

1.     Emission Factor Documentation for AP-42 Section 1.11, Waste Oil Combustion (Draft),
       Technical Support Division, Office of Air Quality Planning and Standards, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, April 1993.

2.     Environmental Characterization of Disposal of Waste Oils in Small Combustors,
       EPA-600/2-84-150, U.S. Environmental Protection Agency, Cincinnati, OH, September 1984.

3.     "Waste Oil Combustion at a Batch Asphalt Plant: Trial Burn Sampling and Analysis", Arthur
       D. Little, Inc, Cambridge, MA, Presented at the 76th Annual Meeting of the Air Pollution
       Control Association, June 1983.

4.     Used Oil Burned as a Fuel, EPA-SW-892, U. S. Environmental Protection Agency,
       Washington, DC, August 1980.

5.     "Waste Oil Combustion: an Environmental Case Study", Presented at the 75th Annual Meeting
       of the Air Pollution Control Association, June 1982.

6.     The Fate of Hazardous and Nonhazardous Wastes in Used Oil Disposal and Recycling,
       DOE/BC/10375-6, U. S. Department of Energy, Bartlesville,  OK, October 1983.

7.     "Comparisons of Air Pollutant Emissions from Vaporizing and Air Atomizing Waste Oil
       Heaters", Journal of the Air Pollution Control Association, 33(7), July 1983.

8.     Chemical Analysis of Waste Crankcase Oil Combustion Samples, EPA600/7-83-026, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, April 1983.

9.     R.L. Barbour and W.M. Cooke, Chemical Analysis of Waste  Crankcase Oil Combustion
       Samples, EPA-600/7-83-026, U.S. Environmental Protection Agency, Cincinnati, OH, April
       1983.
 1.11-8                             EMISSION FACTORS                               7/93

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2.1    REFUSE COMBUSTION

       Refuse combustion involves the burning of garbage and other nonhazardous solids, commonly
called municipal solid waste (MSW).  Types of combustion devices used to burn refuse include single
chamber units, multiple chamber units,  and trench incinerators.

2.1.1 General1'3

       As of January 1992, there were over 160  municipal waste combustor (MWC) plants operating
in the United States with capacities greater than 36 megagrams per day (Mg/day) [40 tons per day
(tpd)], with a total  capacity of approximately 100,000 Mg/day (110,000 tpd of MSW).1 It is
projected that by 1997, the total MWC capacity will approach 150,000 Mg/day (165,000 tpd), which
represents approximately 28 percent of the estimated total amount of MSW generated in the United
States by the year 2000.

       Federal regulations for MWCs are currently under three subparts of 40 CFR Part 60. Subpart
E covers MWC units that began construction after 1971 and have capacities to combust over
45 Mg/day (50 tpd) of MSW.  Subpart Ea establishes  new source performance standards (NSPS) for
MWC units which  began construction or modification after December 20,  1989 and have capacities
over 225 Mg/day (250 tpd).  An emission guideline (EG) was established under Subpart Ca covering
MWC units which  began construction or modification prior to December 20, 1989 and have capacities
of greater than 225 Mg/day (250 tpd).  The Subpart Ea and Ca regulations were promulgated on
February 11, 1991.

       Subpart E includes a standard for particulate matter (PM).  Subpart Ca and Ea currently
establish standards for PM, tetra- through octa- chlorinated dibenzo-p-dioxin/chlorinated
dibenzofurans (CDD/CDFs), hydrogen chloride (HC1), sulfur dioxide  (SO2), nitrogen oxides (NOX)
(Subpart Ea only),  and carbon monoxide (CO). Additionally, standards for mercury (Hg), lead (Pb),
cadmium (Cd),  and NOX (for Subpart Ca) are currently being considered for new and existing
facilities, as required by Section  129 of the Clean Air Act Amendments (CAAA) of  1990.

       In addition to requiring revisions of the Subpart Ca and Ea regulations to include these
additional pollutants, Section  129 also requires the EPA to review the standards and  guidelines for the
pollutants currently covered under these subparts. It is likely that the revised regulations will be more
stringent. The regulations are also being expanded to cover new and existing MWC facilities with
capacities of 225 Mg/day (250 tpd) or less. The  revised regulations will likely cover facilities with
capacities as low as 18 to 45 Mg/day (20 to 50 tpd).  These facilities are currently subject only to
State regulations.

2.1.1.1  Combustor Technology   There are three main  classes of technologies used to combust
MSW: mass burn, refuse-derived fuel (RDF),  and  modular combustors.  This section provides a
general description of these three classes of combustors.  Section 2.1.2 provides more details
regarding design and operation of each  combustor class.

       With mass burn units, the MSW is combusted without any preprocessing other than removal
of items too large to go through the feed system.  In a typical mass burn combustor,  refuse is placed
on a grate that moves through the combustor. Combustion air in excess of stoichiometric amounts is


7/93                                  Solid Waste Disposal                                2.1-1

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supplied both below (underfire air) and above (overfire air) the grate.  Mass burn combustors are
usually erected at the site (as opposed to being prefabricated at another location), and range in size
from 46 to 900 Mg/day (50 to 1,000 tpd) of MSW throughput per unit.  The mass burn combustor
category can be divided into mass burn/waterwall (MB/WW),  mass burn/rotary waterwall combustor
(MB/RQ, and mass burn refractory wall (MB/REF) designs.  Mass burn/waterwall designs have
water-filled tubes in the furnace walls that are used to recover heat for production of steam and/or
electricity. Mass burn/rotary waterwall combustors use a rotary combustion chamber constructed of
water-filled tubes followed by a waterwall furnace. Mass burn refractory designs are older and
typically do not include any heat recovery. Process diagrams for a typical MB/WW combustor, a
MB/RC combustor, and one type of MB/REF combustor are presented in Figures 2.1-1, 2.1-2 and
2.1-3, respectively.

       Refuse-derived fuel combustors burn processed waste that varies from shredded waste to
finely divided fuel suitable for co-firing with pulverized coal.  Combustor sizes range from 290 to
1,300 Mg/day (320 to 1,400 tpd).  A process diagram for a typical RDF combustor is shown in
Figure 2.1-4. Waste processing usually consists of removing noncombustibles and shredding, which
generally raises the heating value and provides a more uniform fuel.  The type of RDF used depends
on the boiler design. Most boilers designed to burn RDF use  spreader stokers and fire fluff RDF in a
semi-suspension mode.  A subset of the RDF technology is fluidized bed combustors (FBC).

       Modular combustors are similar to mass burn combustors in that they burn waste that has not
been pre-processed, but they are typically  shop fabricated and  generally range in size from 4 to
130 Mg/day (5 to 140 tpd) of MSW throughput. One of the most common types of modular
combustors is the starved air or controlled air type, which incorporates two combustion chambers. A
process diagram of a typical modular starved-air (MOD/SA) combustor is presented  in Figure 2.1-5.
Air is supplied to the primary chamber at  sub-stoichiometric levels. The incomplete combustion
products (CO and organic compounds) pass into the secondary combustion chamber where additional
air is added and combustion is completed. Another type of modular combustor design is the modular
excess air (MOD/EA) combustor which consists of two chambers as with MOD/SA units, but is
functionally similar to mass burn unit in that it uses excess air in the primary  chamber.

2.1.2  Process Description4

       Types of combustors described in  this section include:

             Mass burn waterwall,

             Mass burn rotary waterwall,

             Mass burn refractory wall,

             Refuse-derived fuel-fired,

             Fluidized bed,

             Modular starved air,  and

             Modular excess air.
2.1.2.1  Mass Burn Waterwall Combustors  The MB/WW design represents the predominant
technology in the existing population of large MWCs, and it is expected that over 50 percent of new


2.1-2                               EMISSION FACTORS                                7/93

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7/93
Figure 2.1-1. Typical mass burn waterwall combustor.



                Solid Waste Disposal
2.1-3

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    Figure 2.1-2. Simplified process flow diagram, gas cycle for a rotary waterwall combustor.



2.1-4                              EMISSION FACTORS                              7/93

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7/93
Figure 2.1-3.  Mass burn refractory-wall combustor with grate/rotary kiln.


                         Solid Waste Disposal
2.1-5

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2.1-6
Figure 2.1-4.  Typical RDF-fired spreader stoker boiler.



              EMISSION FACTORS
7/93

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                                                                                                               1
                             i
7/93
Figure 2.1-5.  Typical modular starved-air combustor with transfer rams.



                        Solid Waste Disposal
2.1-7

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units will be MB/WW designs. In MB/WW units, the combustor walls are constructed of metal tubes
that contain circulating pressurized water used to recover heat from the combustion chamber. In the
lower actively burning region of the chamber where corrosive conditions may exist, the walls are
generally lined with castable refractory.  Heat is also recovered in the convective sections (i.e.,
superheater, economizer) of the combustor.

       With this type of system, unprocessed waste (after removal  of large, bulky items) is delivered
by an overhead crane to a feed hopper, which conveys the waste into the combustion chamber.
Earlier MB/WW designs utilized gravity feeders, but it is now more typical to feed by means of
single or dual  hydraulic rams.

       Nearly all modern MB/WW facilities utilize reciprocating grates or roller grates to move the
waste through the combustion  chamber.  The grates typically include three sections.  On  the initial
grate section, referred to as the drying grate, the moisture content of the waste is reduced prior  to
ignition.  The second grate section, referred to as the burning grate, is where the majority of active
burning takes place.  The third grate section, referred to as the burnout or finishing grate, is where
remaining combustibles  in the  waste are burned.  Smaller units may have only two individual grate
sections.  Bottom ash is discharged from the finishing grate into a water-filled ash quench pit or ram
discharger.  From there, the moist ash is discharged to  a conveyor system and transported to an ash
load-out or storage area prior to disposal.  Dry ash systems have been  used in some designs, but their
use is not widespread.

       Combustion air  is added from beneath the grate by way of underfire air plenums.  The
majority  of MB/WW systems supply underfire air to the individual  grate sections through multiple
plenums, which enhance the ability to control burning and heat release from the  waste bed.  Overfire
air is injected through rows of high-pressure nozzles located in the side walls of the combustor to
oxidize fuel-rich gases evolved from the bed and complete the combustion process.  Properly designed
and operated overfire air systems are essential for good mixing and burnout of organics in the flue
gas.  Typically, MB/WW MWCs are operated with 80 to 100 percent excess  air.

       The flue gas  exits the combustor and passes through additional heat recovery sections to one
or more air pollution control devices (APCD). The types of APCDs that may be used are discussed
in Section 2.1.4.

2.1.2.2 Mass Burn Rotary Waterwall Combustors - A more unique mass burn design is the MB/RC.
Plants of this design  range in size from 180 to 2,400 Mg/day (200 to 2,700 tpd), with typically  two
or three units per plant.  This  type of system uses a rotary combustion chamber. Following pre-
sorting of objects too large to  fit hi the combustor, the waste is ram fed to the inclined rotary
combustion chamber, which rotates slowly, causing the waste to advance and tumble as it burns.
Underfire air is injected through the waste bed, and overfire air is provided above the waste bed.
Bottom ash is  discharged from the rotary combustor to  an afterburner grate and then into a wet
quench pit.  From there, the moist ash is conveyed to an ash load-out or storage area prior to
disposal.

       Approximately 80 percent of the combustion air is provided along the rotary combustion
chamber  length, with most of the air provided in the first half of the chamber. The rest of the
combustion air is supplied to the afterburner grate and above the rotary combustor outlet in the  boiler.
The MB/RC operates at about  50 percent excess air, compared with 80 to 100 percent for typical
MB/WW firing systems. Water flowing through the tubes in the rotary chamber recovers heat from
2.1-8                                EMISSION FACTORS                                 7/93

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combustion.  Additional heat recovery occurs in the boiler waterwall, superheater, and economizer.
From the economizer, the flue gas is typically routed to APCDs.

2.1.2.3 Mass Burn Refractory Wall Combustors - Prior to 1970 there were numerous MB/REF
MWCs in operation. The purpose of these plants was to achieve waste reduction; energy recovery
was generally not incorporated in their design. Most of the roughly 25 MB/REF plants that still
operate or that were built in the 1970s and 1980s use electrostatic precipitators (ESPs) to reduce PM
emissions, and several have heat recovery boilers.  Most MB/REF combustors have unit sizes of 90
to 270 Mg/day (100 to 300 tpd).  It is not expected that additional plants of this design will be built in
the United States.

       The MB/REF combustors comprise several designs.  One design involves a batch-fed upright
combustor, which may be cylindrical or rectangular in shape. A second  design is based on a
rectangular combustion chamber with a traveling, rocking, or reciprocating grate.  This type of
combustor is continuously fed and operates in an excess air mode.  If the waste is moved on a
traveling grate, it is not sufficiently aerated as it advances through the combustor.  As a result,  waste
burnout or complete combustion is inhibited by fuel bed thickness,  and there is considerable potential
for unburned waste to be discharged into the bottom ash pit. Rocking and reciprocating grate systems
stir and aerate the waste bed as it advances through the combustion chamber, thereby improving
contact between the waste and combustion air and increasing the burnout of combustibles. The
system generally discharges the ash at the end of the grate to a water quench pit for collection and
disposal in a landfill.

       Because MB/REF combustors do not contain a heat transfer medium (such as the waterwalls
that are present in modern energy recovery units), they typically operate at higher excess air rates
(150 to 300 percent) than  MB/WW combustors (80 to 100 percent). The higher excess air levels  are
required to prevent excessive temperatures, which can result in refractory damage, slagging, fouling.,
and corrosion problems.  One adverse effect of higher excess air levels is the potential for increased
carryover of PM from the combustion chamber and, ultimately, increased stack emission rates.  High
PM carryover may also contribute to increased CDD/CDF emissions by  providing increased surface
area for downstream catalytic formation to take place.  A second problem is the potential for high
excess air levels to quench (cool) the combustion reactions, preventing thermal destruction of organic
species.

        An alternate, newer MB/REF combustor is the Volund design (Figure 2.1-3  presents this
MB/REF  design).   This design minimizes some of the problems of other MB/REF systems.  A
refractory arch is installed above the combustion zone to reduce radiant heat losses and improve solids
burnout.  The refractory arch also routes part of the rising gases from the drying and combustion
grates through a gas by-pass duct to the mixing chamber.  There the gas is mixed with gas from the
burnout grate or kiln.  Bottom ash is conveyed to an ash quench pit. Volund MB/REF combustors
operate with 80 to  120 percent excess air, which is more in line with excess air levels in the MB/WW
designs.  As a result, lower CO levels and better organics destruction are achievable, as compared to
other MB/REF combustors.

2.1.2.4 Refuse-derived Fuel Combustors  Refuse-derived fuel combustors burn MSW that has been
processed to varying degrees, from simple removal of bulky and noncombustible items accompanied
by shredding, to extensive processing to produce a finely divided fuel suitable for co-firing in
pulverized coal-fired boilers.  Processing MSW to RDF generally raises the heating  value of the waste
because many of the noncombustible items are removed.
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       A set of standards for classifying RDF types has been established by the American Society for
Testing and Materials. The type of RDF used is dependent on the boiler design. Boilers that are
designed to burn RDF as the primary fuel usually utilize spreader stokers and fire fluff RDF in a
semi-suspension mode.  This mode of feeding is accomplished by using an air swept distributor,
which allows a portion of the RDF to burn in suspension and the remainder to be burned out after
falling on a horizontal traveling grate. The number of RDF distributors in a single unit varies
directly with unit capacity.  The distributors are normally  adjustable so that the trajectory of the waste
feed can be varied.  Because the traveling grate moves from the rear to the front of the furnace,
distributor settings are adjusted so that most of the waste lands on the rear two-thirds of the grate.
This allows more tune for combustion to be completed on the grate. Bottom ash drops into a water-
filled quench chamber.  Some traveling grates operate at a single speed, but most can be manually
adjusted to accommodate variations in burning conditions.  Underfire air  is normally preheated and
introduced beneath the grate by a single plenum.  Overture air is injected  through rows of high-
pressure nozzles,  providing a zone for mixing and completion of the combustion process. These
combustors typically operate at 80 to 100 percent excess air.

       Due to the basic design of the semi-suspension feeding systems, PM  levels at the inlet to the
pollution control device are typically double those of mass burn systems and more than an order of
magnitude higher than MOD/SA combustors.  The higher paniculate loadings may contribute to the
catalytic formation of CDD/CDF. However, controlled Hg emissions from these plants are
considerably lower than from mass burn plants as a result of the higher levels of carbon present in the
PM carryover, as Hg adsorbs onto the carbon and can be subsequently captured by the PM control
device.

       Pulverized coal-(PQ fired boilers can co-fire fluff RDF or powdered RDF.   In a PC-fired
boiler that co-fires fluff with pulverized coal, the RDF is introduced into the combustor by air
transport injectors that are located above or even with the  coal nozzles. Due to its high moisture
content and large particle size,  RDF requires a longer burnout time than coal. A significant portion
of the larger, partially burned particles disengage from the gas flow and fall onto stationary drop
grates at the bottom of the furnace where combustion is completed. Ash  that accumulates on the
grate is periodically dumped into the ash hopper below the grate. Refuse-derived fuel can also be
co-fired with coal in stoker-fired boilers.

2.1.2.5 Fluidized Bed Combustors - In an FBC, fluff or  pelletized RDF is combusted on a turbulent
bed of noncombustible material such as limestone, sand, or silica.  In  its simplest form, an FBC
consists of a combustor vessel  equipped with a gas distribution plate and underfire air windbox at the
bottom. The combustion bed overlies the gas distribution plate.  The combustion bed is suspended or
"fluidized" through the introduction of underfire air at a high flow rate.  The RDF may be injected
into or above the bed through ports in the combustor wall. Other wastes and supplemental fuel may
be blended with the RDF outside the combustor  or added into the combustor through separate
openings.  Overture air is used to complete the combustion process.

       There are two basic types of FBC systems:  bubbling bed and circulating bed. With bubbling
bed combustors, most of the fluidized solids are maintained near the bottom of the combustor by
using relatively low ah- fluidization velocities. This helps  reduce the entrainment of solids from the
bed into the flue gas, minimizing recirculation or reinjection of bed particles. In contrast, circulating
bed combustors operate at relatively high fluidization velocities to promote carryover of solids into  the
upper section of the combustor. Combustion occurs in both the bed and upper section of the
combustor.  By design, a fraction of the bed material is entrained in the combustion gas and enters  a
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cyclone separator which recycles unburned waste and inert particles to the lower bed.  Some of the
ash is removed from the cyclone with the solids from the bed.

       Good mixing is inherent in the FBC design.  Fluidized bed combustors have very uniform gas
temperatures and mass compositions in both the bed  and in the upper region of the combustor.  This
allows the FBCs to operate at lower excess air and temperature levels than conventional combustion
systems. Waste-fired FBCs typically operate at excess air levels between 30 and 100 percent and at
bed temperatures around 815C (1,500F).  Low temperatures are necessary for waste-firing FBCs
because higher temperatures lead to bed agglomeration.

2.1.2.6 Modular Starved-air (Controlled-air) Combustors  In terms of number of facilities,
MOD/SA combustors represent a large segment of the existing MWC population.  However, because
of their small sizes, they account for only a small percent of the total capacity. The basic design of a
MOD/SA combustor consists of two separate combustion chambers, referred to as the "primary"  and
"secondary" chambers.  Waste is batch-fed to the primary chamber by a hydraulically activated ram.
The charging bin is filled by a front end loader or other means.  Waste is fed automatically on a set
frequency, with generally 6 to  10 minutes between charges.

        Waste is moved through the primary combustion chamber by either hydraulic transfer rams or
reciprocating grates. Combustors using transfer rams have individual hearths upon which combustion
takes  place.  Grate systems generally include two separate grate sections. In either case, waste
retention times in the primary chamber are long, lasting up to 12 hours.  Bottom ash is usually
discharged to a wet quench pit.

        The quantity of air introduced into the primary chamber  defines the rate at which waste burns.
Combustion air is introduced in the primary chamber at sub-stoichiometric levels, resulting in a flue
gas rich in unburned hydrocarbons. The combustion air flow rate to the primary chamber is
controlled to maintain an exhaust gas temperature set point, generally 650 to 980C (1,200 to
1,800F), which corresponds to about 40 to 60 percent theoretical air.

        As the hot,  fuel-rich flue gases flow to the secondary chamber, they are mixed with additional
air to complete the burning process. Because the temperature of the exhaust gases from the primary
chamber is above the autoignition point, completing  combustion is simply a matter of introducing air
into the fuel-rich gases. The amount of air added to the secondary chamber is controlled to maintain
a desired flue gas exit temperature, typically 980 to  1,200C (1,800 to 2,200F).  Approximately
80 percent of the total combustion  air is introduced as secondary air.  Typical excess air levels vary
from  80 to 150 percent.

        The walls of both combustion chambers are refractory lined. Early MOD/SA combustors did
not include energy recovery, but a waste heat boiler is common  in newer installations, with two or
more combustion modules manifolded to a single boiler. Combustors with energy recovery
capabilities also maintain dump stacks for use in an emergency,  or when the boiler and/or air
pollution control equipment are not in operation.

        Most MOD/SA MWCs are equipped with auxiliary fuel burners located in both the primary
and secondary combustion chambers.  Auxiliary fuel can be used during startup (many modular units
do not operate continuously) or when problems are experienced maintaining desired combustion
temperatures. In general, the combustion process is self-sustaining through control of air flow and
feed rate, so that continuous co-firing of auxiliary fuel is normally not necessary.
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       The high combustion temperatures and proper mixing of flue gas with air in the secondary
combustion chamber provide good combustion, resulting in relatively low CO and trace organic
emissions.  Because of the limited amount of combustion air introduced through the primary chamber,
gas velocities in the primary chamber and the amount of entrained PM are low. As a result, PM
emissions of air pollutants from MOD/SA MWCs are relatively low.  Many existing modular systems
do not have air pollution controls. This is especially true of the smaller starved-air facilities. A few
of the newer MOD/SA MWCs have acid gas/PM controls.

2.1.2.7  Modular Excess Air Combustors - There are fewer MOD/EA MWCs than MOD/SA
MWCs. The design of MOD/EA units is similar to that of MOD/SA units, including the presence of
primary and secondary combustion chambers. Waste is batch-fed to the primary chamber, which is
refractory-lined.  The waste is moved through the primary chamber by hydraulic transfer rams,
oscillating grates, or a revolving hearth. Bottom ash is discharged to a wet quench pit. Additional
flue gas residence time for fuel/carbon burnout is provided in the secondary chamber, which is also
refractory-lined.  Energy is typically recovered in a waste heat boiler.  Facilities with multiple
combustors may have a tertiary chamber where flue gases from each combustor are mixed prior to
entering the energy recovery boiler.

       Unlike the MOD/SA combustors but similar to MB/REF units, a MOD/EA combustor
typically operates at about 100 percent excess air in the primary chamber, but may vary between
50 and 250 percent excess air. The MOD/EA combustors also use recirculated flue gas for
combustion air to maintain desired temperatures  in the primary and secondary chambers. Due to
higher air velocities, PM emissions from MOD/EA combustors are higher than those from MOD/SA
combustors and are more similar in concentration to PM emissions from mass burn units. However,
NOX emissions from MOD/EA combustors appear to be lower than from either MOD/SA or mass
burn units.                                     (

2.1.3 Emissions4"7

       Depending on the characteristics of the MSW and combustion conditions in the MWC, the
following pollutants can be emitted:

             PM,

             Metals (in solid form on PM, except for Hg),

             Acid gases (HC1,  SO2),

             CO,

             NOX, and

             Toxic organics (most notably CDD/CDF).

A brief discussion on each of the pollutants is provided below, along with discussions on controls
used to reduce emissions of these pollutants to the atmosphere.

2.1.3.1  Paniculate Matter  The amount of PM exiting the furnace of an MWC depends on the
waste characteristics, the physical nature of the combustor design, and the combustor's operation.
Under normal combustion conditions, solid fly ash particulates formed from inorganic,


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noncombustible constituents in MSW are released into the flue gas.  Most of this paniculate is
captured by the facility's APCD and are not emitted to the atmosphere.

       Paniculate matter can vary greatly in size with diameters ranging from less than one
micrometer to hundreds of micrometers (>m).  Fine particulates, having diameters less than lOjim
(known as PM-10), are of increased concern because a greater potential for inhalation and passage
into the pulmonary region exists.  Further, acid gases, metals, and toxic organics may preferentially
adsorb onto particulates in this size range. The NSPS and EG for MWCs regulate total PM, while
PM-10 is of interest for State Implementation Plans and when dealing with ambient PM
concentrations.  In this chapter, "PM" refers to total PM as measured by EPA Reference Method 5.

       The level of PM emissions at the  inlet of the APCD will vary according the combustor
design, air distribution, and waste characteristics.  For example, facilities that operate with high
underfire/overfire air ratios or relatively high excess air levels may entrain greater quantities of PM
and have high PM levels  at the APCD inlet. For combustors with multiple-pass  boilers that change
the direction  of the flue gas flow, part of the PM may be removed prior to the APCD.  Lastly, the
physical properties of the waste being fed and the method of feeding influences PM  levels in the flue
gas.  Typically, RDF  units have higher PM carryover from the furnace due to the suspension-feeding
of the RDF.  However, controlled PM emissions from RDF plants do not vary substantially from
other MWCs (i.e., MB/WW), because the PM is efficiently collected in the APCD.

2.1.3.2 Metals ~ Metals are present in a variety of MSW streams,  including paper, newsprint, yard
wastes, wood, batteries, and metal cans.  The metals present in MSW are emitted from MWCs in
association with PM [e.g., arsenic (As), Cd, chromium (Cr), and Pb] and as vapors, such as Hg.
Due to the variability in MSW composition, metal concentrations are highly variable and are
essentially independent of combustor type.  If the vapor pressure of a metal is such  that condensation
onto particulates  in the flue gas is possible, the metal can be effectively removed by the PM control
device. With the exception of Hg, most metals have sufficiently low vapor pressures to result in
almost all of the  metals being condensed.  Therefore, removal in the PM control device for these
metals is generally greater than 98 percent. Mercury, on the other hand, has a high vapor pressure  at
typical APCD operating temperatures, and capture by the PM control device is highly variable. The
level of carbon in the fly ash appears to affect the level of Hg control.  A high level of carbon in the
fly ash can enhance Hg adsorption onto particles removed by the PM control device.

2.1.3.3  Acid Gases - The chief acid gases of concern from the combustion of MSW are HC1 and
SO2.  Hydrogen fluoride (HF), hydrogen bromide (HBr), and sulfur trioxide (SO3) are also generally
present, but  at much lower concentrations.  Concentrations of HC1 and  SO2 in MWC flue gases
directly relate to the chlorine and sulfur content in the waste. The chlorine and  sulfur contents vary
considerably based on seasonal and local waste variations. Emissions of SO2 and HC1 from MWCs
 depend on the  chemical form of sulfur and chlorine in the waste, the availability of alkali materials  in
 combustion-generated fly ash that act as sorbents, and the type of emission control system used.  Acid
 gas concentrations are considered to be independent of combustion conditions.  The major sources of
 chlorine in MSW are paper and plastics.  Sulfur is contained in many constituents of MSW, such as
 asphalt shingles, gypsum wallboard, and tires.  Because RDF processing does not generally impact
 the distribution of combustible materials  in the waste fuel, HC1 and SO2 concentrations for mass burn
 and RDF units are similar.

 2.1.3.4 Carbon Monoxide  Carbon monoxide emissions result when all of the carbon in the waste
 is not oxidized to carbon dioxide (CO2). High levels of CO indicate that the combustion gases were
 not held at a sufficiently high temperature  in the presence of oxygen (O2) for a long enough time to


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 convert CO to CO2. As waste burns in a fuel bed, it releases CO, hydrogen (H2), and unburaed
 hydrocarbons.  Additional air then reacts with the gases escaping from the fuel bed to convert CO and
 H2 to CO2 and H2O.  Adding too much air to the combustion zone will lower the local gas
 temperature and quench (retard) the oxidation reactions. If too little air is added, the probability of
 incomplete mixing increases, allowing greater quantities of unburned hydrocarbons to escape the
 furnace. Both of the conditions would result in increased emissions of CO.

        Because O2 levels and air distributions vary among combustor types, CO levels also vary
 among combustor types.  For example, semi-suspension-fired RDF units generally have higher CO
 levels than mass burn units, due to the effects of carryover of incompletely combusted materials into
 low temperature portions of the combustor, and, in some cases, due to instabilities that result from
 fuel feed characteristics.

        Carbon monoxide concentration is a good indicator of combustion efficiency, and is  an
 important criterion for indicating instabilities  and nonuniformities in the combustion process. It is
 during unstable combustion conditions that more carbonaceous material is available and higher
 CDD/CDF and organic hazardous air pollutant levels occur.  The relationship between emissions of
 CDD/CDF and CO indicates that high levels of CO (several hundred parts per million by volume
 [jppmv]), corresponding to poor combustion conditions, frequently correlate with high CDD/CDF
 emissions. When CO levels are low, however, correlations between CO and CDD/CDF are not well
 defined (due to the fact that many mechanisms may contribute to CDD/CDF formation), but
 CDD/CDF emissions are generally lower.

 2.1.3.5 Nitrogen Oxides - Nitrogen oxides are products of all fuel/air combustion processes. Nitric
 oxide (NO) is the primary component of NOX; however, nitrogen dioxide (NO^ and nitrous oxide
 (N2O) are also formed in smaller amounts. The combination of the compounds  is referred to as NOX.
 Nitrogen oxides are formed during combustion through (1) oxidation of nitrogen hi the waste, and (2)
 fixation of atmospheric nitrogen.  Conversion of nitrogen in the waste occurs at  relatively low
 temperatures  Bess than  1,090C (2,000F)], while fixation of atmospheric nitrogen occurs at higher
 temperatures.  Because of the relatively low temperatures at which MWC furnaces operate, 70 to
 80 percent of NOX formed in MWCs is associated with nitrogen in the waste.

 2.1.3.6 Organic Compounds  A variety of organic compounds,  including CDD/CDF,
 chlorobenzene (CB), polychlorinated biphenyls (PCBs), chlorophenols (CPs), and polyaromatic
 hydrocarbons (PAHs) are present in MSW or can be formed during the combustion and
 post-combination processes.  Organics in the flue gas can exist in the vapor phase or can be
 condensed or absorbed on fine particulates. Control of organics is accomplished through proper
 design and operation of both the combustor and the APCDs.

       Based on potential health  effects, CDD/CDF has been a focus of many research and
 regulatory activities. Due to toxicity levels, attention is most often placed on levels of CDD/CDF in
the tetra- through octa-homolog groups and specific isomers within those groups that have chlorine
substituted in the 2, 3, 7, and 8 positions.  As noted earlier, the NSPS and EG for MWCs regulate
the total tetra- through octa-CDD/CDF.

2.1.4  Controls8'10

       A wide variety of control technologies are used to control emissions from MWCs.  The
control of PM, along with metals that have adsorbed onto the PM, is most frequently accomplished
through the use of an ESP or fabric filter (FF).  Although other PM control technologies (e.g.,


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cyclones, electrified gravel beds, and venturi scrubbers) are available, they are seldom used on
existing systems, and it is anticipated that they will not be frequently used in future MWC systems.
The control of acid gas emissions (i.e., SO2 and HC1) is most frequently accomplished through the
application of acid gas  control technologies such as spray drying or dry sorbent injection, followed by
a high efficiency PM control device. Some facilities use a wet scrubber to control acid gases.  It is
anticipated that dry systems (spray drying and dry sorbent injection) will be more widely used than
wet scrubbers on future U. S.  MWC systems.  Each of these technologies is discussed in more detail
below.

2.1.4.1 Electrostatic Precipitators  Electrostatic precipitators consist of a series of high-voltage (20
to 100 kilovolts) discharge electrodes and grounded metal plates through which PM-laden flue gas
flows. Negatively charged ions formed by this high-voltage field (known as a "corona") attach to PM
in the flue gas, causing the charged particles to migrate toward, and be collected on, the grounded
plates. The most common types of ESPs used by MWCs are (1) plate wire units in which the
discharge electrode is a bottom weighted  or rigid wire, and (2) flat plate units which use flat plates
rather than wires as the discharge electrode.

       As a general rule, the  greater the amount of collection plate area, the greater the ESP's PM
collection efficiency. Once the charged particles are collected on the grounded plates, the resulting
dust layer is  removed from the plates by  rapping, washing, or some other method and collected in a
hopper.  When the dust layer is removed, some of the collected PM becomes re-entrained in the flue
gas.  To assure good PM collection efficiency during plate cleaning and electrical upsets, ESPs have
several fields located in series along the direction of flue gas flow that can be energized and cleaned
independently.  Particles re-entrained when the dust layer is removed from one field can be
recollected in a downstream field.  Because of this phenomena,  increasing the number of fields
generally improves PM removal efficiency.

       Small particles generally have lower migration velocities than large particles and are therefore
more difficult to collect.  This factor is especially important to MWCs because of the large  amount of
total fly ash smaller than 1 /on.  As compared to pulverized coal fired combustors, in which only 1 to
3 percent of the fly ash is generally smaller than 1 /*m, 20 to 70 percent of the fly ash at the inlet of
the PM control device  for MWCs  is reported to be smaller  than 1 jam.  As a result, effective
collection of PM from MWCs requires greater collection areas and lower flue gas velocities than
many other combustion types.

        As an approximate indicator of collection efficiency, the specific collection area (SCA) of an
ESP is frequently  used.  The SCA is calculated by dividing the collecting electrode plate area by the
flue gas flow rate  and  is  expressed as square feet of collecting area per 28 cubic meters per minute
(1000 cubic feet per minute) of flue gas.  In general, the higher the SCA, the higher the collection
efficiency. Most ESPs at newer MWCs have SCAs in the range of 400 to 600.  When estimating
emissions from ESP-equipped MWCs, the SCA of the ESP should be taken into consideration. Not
all ESPs are designed  equally and performance of different ESPs will vary.

2.1.4.2  Fabric Filters  Fabric filters are also used for PM and metals control, particularly in
combination with  acid gas control and flue gas cooling. Fabric filters (also known as "baghouses")
remove PM by passing flue gas through  a porous fabric that has been sewn into a cylindrical bag.
Multiple individual filter bags are mounted in an arranged compartment.  A complete FF, in turn,
consists of 4 to 16 individual  compartments that can be independently operated.
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       As the flue gas flows through the filter bags, particulate is collected on the filter surface,
mainly through inertial impaction.  The collected particulate builds up on the bag, forming a filter
cake. As the thickness of the filter cake increases, the pressure drop across the bag also increases.
Once pressure drop across the bags in a given compartment becomes excessive, that compartment is
generally taken off-line, mechanically cleaned,  and then placed back on-line.

       Fabric filters are generally differentiated by cleaning mechanisms.  Two main filter cleaning
mechanisms are used:  reverse-air and pulse-jet.  In a reverse-air FF, flue gas flows through
unsupported filter bags, leaving the particulate  on the inside of the bags.  The particulate builds up to
form a particulate filter cake. Once excessive pressure drop across the filter cake is reached, air is
blown through the filter in the opposite direction, the filter bag collapses, and the filter cake falls off
and is collected. In a pulse-jet FF, flue gas flows through supported filter bags leaving particulate on
the outside of the bags.  To remove the particulate filter cake, compressed air is pulsed through the
inside of the filter bag, the filter bag expands and collapses to its pre-pulsed shape, and the filter cake
falls off and is collected.

2.1.4.3   Spray Drying  Spray dryers (SD) are the most frequently used acid gas control technology
for MWCs in the United States.  When used in combination with an ESP or FF, the system can
control CDD/CDF, PM (and  metals), SO2, and HC1 emissions from MWCs.  Spray dryer/fabric filter
systems are more common than SD/ESP systems and are used mostly on new, large MWCs.  In the
spray drying process, lime slurry is injected  into the SD through either a rotary atomizer or dual-fluid
nozzles.  The water in the slurry evaporates to  cool the flue gas, and the lime reacts with acid gases
to form calcium salts that can be removed by a PM control device. The SD is designed to provide
sufficient contact and residence time to produce a dry product before leaving the SD adsorber vessel.
The  residence time in the adsorber vessel is typically 10 to 15 seconds.  The particulate leaving the
SD contains fly ash plus calcium salts,  water, and unreacted hydrated lime.

       The key design and operating parameters that significantly affect SD performance are SD
outlet temperature and lime-to-acid gas stoichiometric ratio. The SD outlet approach to saturation
temperature is controlled by the amount of water in the slurry. More effective acid gas removal
occurs at lower approach to saturation temperatures, but the temperature must be high enough to
ensure the slurry and reaction products are adequately dried prior to collection in the PM control
device.  For MWC flue gas containing  significant chlorine, a minimum SD outlet temperature of
around 115C (240F) is required to control agglomeration of PM and sorbent by calcium chloride.
Outlet gas temperature from the SD is usually around 140C (285F).

       The stoichiometric ratio is the molar ratio of calcium in the lime slurry fed to the SD divided
by the theoretical amount of calcium required to completely react with the inlet HC1 and SO2 in the
flue  gas.  At a ratio of 1.0, the moles of calcium are equal to the moles of  incoming HC1 and SO2.
However, because of mass transfer limitations, incomplete mixing, differing rates of reaction (SO2
reacts more slowly than HC1), more than the theoretical amount of lime is generally fed to the SD.
The  stoichiometric ratio used in SD systems  varies depending on the level of acid gas reduction
required, the temperature of the flue gas at the SD exit, and the type of PM control device used.
Lime is fed in quantities sufficient to react with the peak acid gas concentrations expected without
severely  decreasing performance. The lime content in the slurry is generally about 10 percent by
weight, but cannot exceed approximately  30  percent by weight without clogging of the lime slurry
feed system and spray nozzles.

2.1.4.4  Dry Sorbent Injection  This type of technology has been developed primarily to control
acid gas  emissions. However, when combined with flue gas cooling and either an ESP or FF,


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sorbent injection processes may also control CDD/CDF and PM emissions from MWCs.  Two
primary subsets of dry sorbent injection technologies exist.  The more widely used of these
approaches, referred to as duct sorbent injection (DSI), involves injecting dry alkali sorbents into flue
gas downstream of the combustor outlet and upstream of the PM control device.  The second
approach, referred to as furnace sorbent injection (FSI), injects sorbent directly into the combustor.

       In DSI, powdered sorbent is pneumatically injected into either a separate reaction vessel or a
section of flue gas duct located downstream of the combustor economizer or quench tower.  Alkali in
the sorbent (generally calcium or sodium) reacts with HC1, HF, and SO2 to form alkali salts [e.g.,
calcium chloride (CaCl2), calcium fluoride (CaF^, and calcium sulfite (CaSO3)].  By lowering the
acid content of the flue gas, downstream equipment can be operated at reduced temperatures while
minimizing the potential for acid corrosion of equipment. Solid reaction products, fly ash, and
unreacted sorbent are collected with either an ESP or FF.

       Acid gas removal efficiency with DSI depends on the method of sorbent injection, flue gas
temperature, sorbent type and feed rate, and the extent of sorbent mixing  with the flue gas.  Not all
DSI systems are of the same design, and performance of the systems will vary. Flue gas temperature
at the point of sorbent injection can range from about 150 to 320C (300  to 600F) depending on the
sorbent being used and the design of the process. Sorbents that have been successfully tested include
hydrated lime (Ca(OH)2), soda ash (Na2CO3), and sodium bicarbonate  (NaHCO3). Based on
published data for hydrated lime, some DSI systems can achieve removal efficiencies comparable to
SD systems; however, performance is generally lower.

       By combining flue gas cooling with DSI, it may  be possible to  increase CDD/CDF removal
through a combination of vapor condensation and adsorption onto the sorbent surface. Cooling may
also benefit PM control by decreasing the effective flue gas flow rate (i.e., cubic meters per minute)
and reducing the resistivity of individual particles.

       Furnace sorbent injection involves the injection of powdered alkali sorbent (either lime or
limestone) into the furnace section  of a combustor.  This can be accomplished by addition of sorbent
to the overture air, injection through separate ports, or mixing with the waste prior to feeding to the
combustor.  As with DSI, reaction products, fly ash, and unreacted sorbent are collected using an
ESP or FF.

       The basic chemistry of FSI is  similar to DSI. Both use a reaction of sorbent with acid gases
to form alkali salts. However, several key differences exist in these two  approaches.  First, by
injecting sorbent directly into the furnace [at temperatures of 870 to 1,200C (1,600 to 2,200F)]
limestone can be calcined in the combustor to form more reactive lime, thereby allowing use of less
expensive limestone as a sorbent.  Second, at these temperatures, SO2 and lime react in the
combustor, thus providing a mechanism for effective removal of SO2 at relatively low sorbent feed
rates.  Third, by injecting sorbent into the furnace rather than into a downstream duct, additional time
is available for mixing and reaction between the sorbent  and acid gases.  Fourth, if a significant
portion of the HC1 is removed before  the flue gas exits the combustor,  it may be possible to reduce
the formation of CDD/CDF in latter sections of the flue gas ducting. However,  HC1 and lime do not
react with each other at temperatures above 760C (1,400F).  This is  the flue gas temperature that
exists in the convective sections of the combustor.  Therefore, HC1 removal may be lower than with
DSI.  Potential disadvantages of FSI include fouling and erosion of convective heat transfer surfaces
by the injected sorbent.
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2.1.4.5 Wet Scrubbers  Many types of wet scrubbers have been used for controlling acid gas
emissions from MWCs.  These include spray towers, centrifugal scrubbers, and venturi scrubbers.
Wet scrubbing technology has primarily been used in Japan and Europe.  Currently, it is not
anticipated that many new MWCs being built in the United States will use this type of acid gas
control system. Wet scrubbing normally involves passing the flue gas through an ESP to reduce PM,
followed by a one- or two-stage absorber system.  With single-stage scrubbers, the flue gas reacts
with an alkaline scrubber liquid to simultaneously remove HC1 and  SO2.  With two-stage scrubbers, a
low-pH water scrubber for HC1 removal is installed upstream of the alkaline SO2 scrubber.  The
alkaline solution, typically containing calcium hydroxide [Ca(OH)2], reacts with the acid gas to form
salts, which are generally insoluble and may be removed by sequential clarifying, thickening, and
vacuum filtering.  The dewatered salts or sludges are then disposed.

2.1.4.6 Nitrogen Oxide Control Techniques  The control of NOX emissions can be accomplished
through either combustion controls or add-on controls.  Combustion controls include staged
combustion, low excess air (LEA),  and flue gas recirculation (FOR). Add-on controls which have
been tested on MWCs include selective noncatalytic reduction (SNCR), selective catalytic reduction
(SCR), and natural gas reburning.

        Combustion controls involve the control of temperature or O2 to reduce NOX formation.
With LEA, less air is supplied, which lowers the supply of O2 that  is available to react with N2 in the
combustion air.  In staged combustion, the amount of underfire air  is reduced, which generates a
starved-air region. In FOR,  cooled flue gas is mixed with combustion air, which reduces to O2
content of the combustion air supply. Due to the lower combustion temperatures present in MWCs,
most NOX is produced from the oxidation of nitrogen present in the fuel.  As a result,  combustion
modifications at MWCs have generally shown small to  moderate reductions in NOX emissions as
compared to higher temperature combustion devices (i.e., fossil fuel-fired  boilers).

        With SNCR, ammonia (NH3) or urea is injected into the furnace along with  chemical
additives to reduce NOX to N2 without the use of catalysts.  Based on analyses of data from U.S.
MWCs equipped with SNCR, NOX reductions of 45 percent are achievable.

        With SCR, NH3 is injected into the flue gas downstream of the boiler where it mixes with
NOX in the flue gas and  passes through a catalyst bed, where NOX is reduced to N2 by a reaction  with
NH3.  This technique has not been applied to U.S. MWCs, but has  been used on MWCs in Japan and
Germany. Reductions of up to 80 percent have been observed, but  problems with catalyst poisoning
and deactivation may reduce performance over time.

        Natural gas reburning involves limiting combustion air produce an LEA zone.  Recirculated
flue gas and natural gas  are then added to this LEA zone to produce a fuel-rich zone that inhibits NOX
formation and promotes  reduction of NOX to  N2.  Natural gas reburning has been evaluated on both
pilot- and full-scale applications and achieved NOX reductions of 50 to 60  percent.

2.1.5  Mercury Controls11'14

        Unlike other metals, Hg exists in vapor form at typical APCD operating temperatures.  As a
result, collection of Hg in the APCD is highly variable. Factors that affect Hg control are good PM
control, low temperatures in the APCD system, and a sufficient level of carbon in the fly ash.
Higher levels of carbon  in the fly ash enhance Hg adsoiption onto the PM, which is removed by the
PM control device.  To keep the Hg from volatilizing,  it is important to operate the control systems at
low temperatures, generally less than about 300 to 400F.


2.1-18                              EMISSION FACTORS                                7/93

-------
       Several mercury control technologies have been used on waste combustors in the
United States, Canada, Europe, and Japan.  These control technologies include the injection of
activated carbon or sodium sulfide (Na2S) into the flue gas prior to the DSI- or SD-based acid gas
control system, or the use of activated carbon filters.

       With activated carbon injection, Hg is adsorbed onto the carbon particle, which is then
captured in the PM control device.  Test programs using activated carbon injection on MWCs in the
United States have shown Hg removal efficiencies of 50 to over 95 percent, depending on the carbon
feed rate.

       Sodium sulfide injection involves spraying Na2S solution into cooled flue gas prior to the acid
gas control device.  Solid mercuric sulfide is precipitated from the reaction of Na2S  and Hg and can
be collected in the PM control device.  Results from tests on European and Canadian MWCs have
shown removal efficiencies of 50 to over 90 percent.  Testings on a U.S. MWC, however, raised
questions on the effectiveness of this technology due to possible oversights in the analytical procedure
used in Europe and Canada.

       Fixed bed activated carbon filters are another Hg control technology being used in Europe.
With this technology, the flue gas is passed through a fixed bed of granular activated carbon where
the Hg is adsorbed.  Segments of the bed are periodically replaced as system pressure drop increases.

2.1.6 Emissions15'121

       Tables 2.1-1 through 2.1-9 present emission factors for MWCs.  The tables  are for distinct
combustor types (i.e., MB/WW, RDF), and include emission factors for uncontrolled (prior to any
pollution control device) levels and for controlled levels based on various APCD types (i.e.,  ESP,
SD/FF). There are a large amount of data available for this source category, and as a result of this,
many of the emission factors have high quality ratings. However, for some categories there were
only limited data, and the ratings  are low.  In these cases,  one should  refer to the EPA  Background
Information Documents (BIDs) developed for the NSPS and EG, which more thoroughly analyze the
data than does AP-42, as well as discuss performance capabilities of the control technologies and
expected emission levels. Also, when  using the MWC emission factors, it should be kept in mind
that these are average values, and emissions from MWCs are greatly affected by the composition of
the waste and may vary for different facilities due to seasonal and regional differences.  The AP-42
background report for this section includes  data for  individual facilities that represent the range for a
combustor/control technology category.
 7/93                                 Solid Waste Disposal                                2.1-19

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2.1-20
                     EMISSION FACTORS
                         7/93

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7/93
          Solid Waste Disposal
                                                                  2.1-21

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7/93
Solid Waste Disposal
2.1-23

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2.1-24
EMISSION FACTORS
                       7/93

-------
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Table 2.1-6 (Metric and English Units). ORGANIC, NITROGEN OXIDE, AND CARBON MONOXIDE EMISSION FACTOI
MASS BURN/REFRACTORY WALL COMBUSTORSa>b
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value and dividing by 4,500 Btu/lb. SCC = Source Classification Code.
b Emission factors should be used for estimating long-term, not short-term, emission levels. This particularly
applies to pollutants measured with a continuous emission monitoring system (e.g., CO, NOx).
c ESP = Electrostatic Precipitator
d DSI/ESP = Duct Sorbent Injection/Electrostatic Precipitator
e CDD/CDF = total tetra-through octa-chlorinated dibenzo-p-dioxin/chlorinated dibenzofurans,
2,3,7,8-tetrachlorodibenzo-p-dioxin and dibenzofurans are Hazardous Air Pollutants listed in Title I of the
1990 Clean Air Act Amendments.
f Control of NOX and CO is not tied to traditional acid gas/PM control devices.
* = Same as "uncontrolled" for these pollutants.

7/93
Solid Waste Disposal
2.1-25

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7/93
              Solid Waste Disposal
                                                                 2.1-27

-------
              Table 2.1-9 (Metric and English Units). EMISSION FACTORS FOR
             MODULAR STARVED
                                   AIR COMBUSTORSab
                                 (SCCs 50100101, 50300114)
Pollutant
PMd
Ase
Cde
Cre
HgM
Nie
Pbe
S02
HCle
NOXS
cos
CDD/CDFh
Uncontrolled
kg/Mg
1.72E+00
3.34E-04
1.20E-03
1.65E-03
2.8 E-03
2.76E-03

1.61E+00
1.08E+00
1.58E+00
1.50E-01
1.47E-06
Ib/ton
3.43E+00
6.69E-04
2.41E-03
3.31E-03
5.6 E-03
5.52E-03

3.23E+00
2.15E+00
3.16E+00
2.99E-01
2.94E-06
Emission
Factor
Rating
B
C
D
C
A
D

E
D
B
B
D
ESPC
kg/Mg
1.74E-01
5.25E-05
2.30E-04
3.08E-04
2.8 E-03
5.04E-04
1.41E-03
*
*
*
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1.88E-06
Ib/ton
3.48E-01
1.05E-04
4.59E-04
6.16E-04
5.6 E-03
1.01E-03
2.82E-03
*
*
*
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D
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   Emission factors were calculated from concentrations using an F-factor of
   9,570 dscf/MBtu and a heating value of 4,500 Btu/lb.  Other heating values can
   be substituted by multiplying the emission factor by the new heating value and
   dividing by 4,500 Btu/lb. SCC = Source Classification Code.
   Emission factors should be used for estimating long-term, not short-term,
   emission levels.  This particularly applies to pollutants measured with  a
   continuous emission monitoring system (e.g., CO, NOx).
   ESP = Electrostatic Precipitator
   PM = total paniculate matter, as measured with EPA Reference Method 5.
   Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act
   Amendments.
   Mercury levels based on emission levels measured at mass burn, MOD/EA, and
   MOD/SA combustors.
   Control of NOX and CO is not tied to traditional acid gas/PM control devices.
   CDD/CDF = total tetra-through octa-chlorinated dibenzo-p-dioxin/chlorinated
   dibenzofurans, 2,3,7,8-tetrachlorodibenzo-p-dioxin and dibenzofurans are
   Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act
   Amendments.
 Same as "uncontrolled" for these pollutants.
- Not available
2.1-28
                 EMISSION FACTORS
7/93

-------
       Another point to keep in mind when using emission factors is that certain control
technologies, specifically ESPs and DSI systems, are not all designed with equal performance
capabilities. The ESP and DSI-based emission factors are based on data from a variety of facilities
and represent average emission levels for MWCs equipped with these control technologies.  To
estimate emissions for a specific ESP or  DSI system, refer to either the AP-42 background report for
this section or the NSPS and EG BIDs to obtain actual emissions data for these facilities. These
documents should also be used when conducting risk assessments, as well as for determining removal
efficiencies. Since the AP-42 emission factors represent averages from numerous facilities, the
uncontrolled and controlled levels  frequently  do not correspond to simultaneous testing and should not
be used to calculate removal efficiencies.

       Emission factors for MWCs were calculated from flue gas concentrations using an F-factor of
9,570 dry standard cubic feet per million British thermal unit (Btu) and an assumed heating value of
the waste  of 4,500 Btu per pound  (Btu/lb) for all combustors except RDF, for which a 5,500 Btu/lb
heating value was assumed.  These are average values for MWCs, however, a particular facility may
have a different heating value for the waste.  In such a case, the emission factors shown in the tables
can be adjusted by multiplying the emission factor by the actual facility heating value and dividing by
the assumed heating value (4,500 or 5,500 Btu/lb, depending on the combustor type).  Also,
conversion factors to obtain concentrations, which can be used for developing more specific emission
factors or make comparisons to regulatory  limits, are provided in Tables 2.1-10 and 2.1-11 for all
combustor types (except RDF) and RDF combustors, respectively.

       Also note that the values shown in the tables for PM are for total PM,  and the CDD/CDF
data represent total tetra- through octa-CDD/CDF.  For SO2, NOX, and CO, the data presented in  the
tables represent long-term  averages, and should not be used to estimate short-term emissions.  Refer
to the EPA BIDs which discuss achievable emission levels of SO2, NOX, and CO for different
averaging times based on analysis of continuous emission monitoring data.  Lastly, for PM and
metals, levels  for MB/WW, MB/RC, MB/REF, and MOD/EA were combined to determine the
emission factors, since these emissions should be the same for these types of combustors.  For
controlled levels, data were combined  within each control technology type (e.g., SD/FF data, ESP
data).  For Hg, MOD/SA data were also combined with the mass burn and MOD/EA data.

2.1.7  Other Types Of Combustors122-134

       Industrial/commercial Combustors  - The capacities of these units cover a wide range,
generally  between 23 and 1,800 kilograms (50 and 4,000 pounds) per hour.  Of either single- or
multiple-chamber design, these units are often manually charged and intermittently operated.  Some
industrial  combustors are similar to municipal combustors in size and design.  Emission control
systems include gas-fired afterburners, scrubbers, or both. Under Section 129 of the CAAA, these
types of combustors will be required to meet emission limits for the same list of pollutants as for
MWCs.  The EPA has not yet established these limits.

       Trench Combustors - Trench combustors, also called air curtain incinerators, forcefully
project a curtain of air across a pit in which open burning occurs.  The air curtain is intended to
increase combustion efficiency and reduce  smoke and PM emissions. Underfire air is also used to
increase combustion efficiency.
7/93                                  Solid Waste Disposal                               2.1-29

-------
         Table 2.1-10. CONVERSION FACTORS FOR ALL COMBUSTOR TYPES
                               EXCEPT RDF
   *at 7 percent 2-
Divide
For As, Cd, Cr, Hg, Ni, Pb, and CDD/CDF:
kg/Mg refuse
Ib/ton refuse
For PM:
kg/Mg refuse
Ib/ton refuse
For HC1:
kg/Mg refuse
Ib/ton refuse
For SO2:
kg/Mg refuse
Ib/ton refuse
For NOX:
kg/Mg refuse
Ib/ton refuse
For CO:
kg/Mg refuse
Ib/ton refuse
By
i
4.03 x lO-6
8.06 x 10-6
4.03 x 10"3
8.06 x 10'3
6.15 x 10-3
1.23x 10-2
1.07x lO-2
2.15x 10-2
7.70 x lO-3
1.54 x 10-2
4.69 x 10-3
9.4 x 10-3
To Obtain*
/ig/dscm
mg/dscm
ppmv
ppmv
ppmv
ppmv
2.1-30
EMISSION FACTORS
7/93

-------
            Table 2.1-11. CONVERSION FACTORS FOR REFUSE-DERIVED
                             FUEL COMBUSTORS
Divide
For As, Cd, Cr, Hg, Ni, Pb, and CDD/CDF:
kg/Mg refuse
Ib/ton refuse
For PM:
kg/Mg refuse
Ib/ton refuse
For HC1: :
kg/Mg refuse
Ib/ton refuse
For SO2:
kg/Mg refuse
Ib/ton refuse
For NOX:
kg/Mg refuse
Ib/ton refuse
For CO:
kg/Mg refuse
Ib/ton refuse
By
4.92 x ID"6
9.85 x ID"6
4.92 x 10'3
9.85 x lO'3
7.5 x ID"3
1.5 x ID"2
1.31 x ID'2
2.62 x ID"2
9.45 x ID"3
1.89 x ID"2
5.75 x 10-3
1.15x10-2
To Obtain*
/ig/dscm
mg/dscm
ppmv
ppmv
ppmv
ppmv
   "at 7 percent 02-
7/93
Solid Waste Disposal
2.1-31

-------
       Trench combustors can be built either above- or below-ground.  They have refractory walls
and floors and are normally 8-feet wide and 10-feet deep. Length varies from 8 to 16 feet. Some
units have mesh screens to contain larger particles of fly ash, but other add-on pollution controls are
normally not used.

       Trench combustors burning wood wastes, yard wastes, and clean lumber are exempt from
Section 129, provided they comply with opacity limitations established by the Administrator.  The
primary use of air curtain incinerators is the disposal of these types of wastes, however, some of
these combustors  are used to burn MSW or construction and demolition debris.

       In some states, trench combustors are often viewed as a version of open burning and the use
of these types of units has been discontinued  in some States.

       Domestic Combustors - This category includes combustors marketed for residential use.
These types of units are typically located at apartment complexes, residential buildings, or other
multiple family dwellings, and are generally found in urban areas. Fairly simple in design, they may
have single or multiple refractory-lined chambers and usually are equipped with an auxiliary burner to
aid combustion.  Due to their small size, these types of units are not currently covered by the MWC
regulations.

       Flue-fed Combustors - These units, commonly  found in large apartment houses or  other
multiple family dwellings, are characterized by the charging method of dropping refuse down the
combustor flue and into the combustion chamber.  Modified flue-fed incinerators utilize afterburners
and draft controls to improve combustion efficiency and reduce emissions.  Due to their small size,
these types of units are not currently covered by the MWC regulations.

       Emission  factors for industrial/commercial, trench, domestic, and flue fed combustors are
presented in Table 2.1-12.
2.1-32                               EMISSION FACTORS                                7/93

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                              Solid Waste Disposal
2.1-33

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References for Section 2.1

1.     Memorandum from D. A. Fenn, and K. L. Nebel, Radian Corporation, Research Triangle
       Park, NC, to W. H. Stevenson, U. S. Environmental Protection Agency, Research Triangle
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2.     J. Kiser, "The Future Role of Municipal Waste Combustion," Waste Age, November 1991,

3.     September 6,  1991.  Meeting Summary:  Appendix 1 (Docket No. A-90-45, Item Number II-
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4.     Municipal Waste Combustion Study: Combustion Control of Organic Emissions, EPA/530-
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5.     M. Clark, "Minimizing Emissions from Resource Recovery," Presented at the International
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6.     Municipal Waste Combustion Assessment: Combustion Control at Existing Facilities, ~
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7.     Municipal Waste Combustors - Background Information for Proposed Standards:  Control of
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8.     Municipal Waste Combustors - Background Information for Proposed Standards: Post
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9.     Municipal Waste Combustion Study - Flue Gas Cleaning Technology, EPA/530-SW-87-021c,
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10.    R. Bijetina, et al, "Field Evaluation of Methane de-NOx at Olmstead Waste-to-Energy
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11.    K. L. Nebel and D. M. White, A Summary of Mercury Emissions and Applicable Control
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12.    Emission Test Report: OMSS Field Test on Carbon Injection for Mercury Control,
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13.    J. D. Kilgroe, et al., "Camden Country MWC Carbon Injection Test Results," Presented at
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 14.    Meeting Summary:  Preliminary Mercury Testing Results for the Stanislaus County Municipal
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 2.1-34                             EMISSION FACTORS                               7/93

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15.    R. A. Zurlinden, et al., Environmental Test Report, Alexandria/Arlington Resources Recovery
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16.    R. A. Zurlinden, et al., Environmental Test Report, Alexandria/Arlington Resource Recovery
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21.    Memorandum.  J. Perez, AM/3, State of Wisconsin, to Files.  "Review of Stack Test
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23.    Municipal Waste Combustion, Multi-Pollutant Study. Emission Test Report.   Volume I,
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25.    Emission Source Test Report  Preliminary Test Report on Cattaraugus County, New York
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7/93                                 Solid Waste Disposal                               2.1-35

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28.    Entropy Environmentalists, Inc.  Stationary Source Sampling Report, Signal Environmental
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32.    Radian Corporation.  Preliminary Data from  October - November 1988 Testing at the
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33.    Telefax.  M. Hartman,  Combustion Engineering to D. White,  Radian Corporation.  Detroit
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34.    Interpoll Laboratories.  Results of the November 3-6, 1987 Performance Test on the No. 2
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35.    D. S. Beachler, (Westinghouse Electric Corporation) and ETS, Inc, Dutchess County
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36.    ETS, Inc.  Compliance Test Report for Dutchess County Resource Recovery Facility, May
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37.    Letter and  enclosures from W. Harold Snead, City of Galax, VA, to Jack  R. Farmer, U.S.
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38.    Cooper Engineers, Inc., Air Emissions Tests  of Solid Waste Combustion a  Rotary
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 39.    B. L. McDonald, et al., Air Emissions Tests at the Hampton Refuse-Fired Stream Generating
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 40.     Radian Corporation for American Ref-Fuel Company of Hempstead, Compliance Test Report
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 41.     J. Campbell, Chief, Air Engineering Section, Hillsborough County Environmental Protection
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 2.1-36                             EMISSION FACTORS                               7/93

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42.    Mitsubishi SCR System for Municipal Refuse Incinerator, Measuring Results at Tokyo-
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46.    Entropy Environmentalists, Inc. Stationary Source Sampling Report, Ogden Martin Systems of
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47.    Ethier, D.D., L.N. Hottenstein, and E.A. Pearson (TRC Environmental Consultants), Air
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48.    Letter from Rigo, H.G., Rigo & Rigo Associates, Inc., to Johnston, M., U. S. Environmental
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49.    Vancil, M.A. and C.L. Anderson (Radian Corporation), Summary Report CDD/CDF,  Metals,
       HCl,  SO2, NOX, CO and Particulate Testing, Marion County Solid Waste-to-Energy Facility,
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50.    Anderson, C.L., et al.  (Radian Corporation), Characterization Test Report, Marion County
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51.    Letter Report from M.A. Vancil, Radian Corporation,  to C.E. Riley, EMB Task Manager,
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52.    Anderson, C.L., K.L. Wertz, M.A. Vancil,  and J.W. Mayhew (Radian Corporation).
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53.    Clean Air Engineering, Inc., Report on Compliance Testing for Waste Management, Inc. at
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7/93                                 Solid Waste Disposal                              2.1-37

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54.    Alliance Technologies Corporation, Field Test Report - NITEP III.  Mid-Connecticut Facility,
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55.    Anderson, C.L. (Radian Corporation), CDD/CDF, Metals, and Particulate Emissions
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56.    Entropy Environmentalists, Inc., Municipal Waste Combustion Multi-Pollutant Study,
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57.    Entropy Environmentalists, Inc., Emissions Testing Report, Wheelabrator Millbury, Inc.
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58.    Entropy Environmentalists, Inc., Stationary Source Sampling Report, Wheelabrator Millbury,
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59.    Entropy Environmentalists, Inc., Emission Test Report, Municipal Waste Combustion
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60.    Entropy Environmentalist, Municipal Waste Combustion Multipollutant Study:  Emission Test
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61.    Entropy Environmentalists, Emission Test Report, Municipal Waste Combustion, Continuous
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62.    Entropy Environmentalists, Emissions Testing at Wheelabrator Millbury, Inc. Resource
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63.    Radian Corporation, Site-Specific  Test Plan and Quality Assurance Project Plan for the
       Screening and Parametric Programs at the Montgomery County Solid  Waste Management
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64.    Letter and enclosures from John W. Norton, County of Montgomery, OH, to Jack R.
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2.1-38                              EMISSION FACTORS                                7/93

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65.    Hahn, J.L., et al., (Cooper Engineers) and J.A. Finney, Jr. and B. Bahor (Belco Pollution
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66.    Clean Air Engineering, Results of Diagnostic and Compliance Testing at NSP French Island
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67.    Preliminary Report on Occidental Chemical Corporation EFW. New  York State Department of
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68.    H. J. Hall, Associates, Summary Analysis on Precipitator Tests and Performance Factors,
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69.    Anderson, C.L., et al. (Radian Corporation), Summary Report, CDD/CDF, Metals and
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70.    York Services Corporation, Final Report for a Test Program on the Municipal Incinerator
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71.    Radian Corporation, Results From the Analysis ofMSW Incinerator Testing at Oswego
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72.    Radian Corporation, Data Analysis Results for Testing at a Two-Stage Modular MSW
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73.    Fossa, A.J., et al., Phase I Resource Recovery Facility Emission Characterization Study,
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74.    Radian Corporation, Results from the Analysis of MSW Incinerator Testing at Peekskill,
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75.    Radian Corporation} Results from the Analysis of MSW Incinerator Testing at Peekskill, New
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76.    Ogden Martin Systems of Pennsauken, Inc., Pennsauken Resource Recovery Project, BACT
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7/93                                Solid Waste Disposal                               2.1-39

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77.    Roy F. Weston, Incorporated, Penobscot Energy Recovery Company Facility, Orrington,
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78.    Zaitlin, S., Air Emission License Finding of Fact and Order, Penobscot Energy Recovery
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79.    Neulicht, R. (Midwest Research Institute), Emissions Test Report:  City of Philadelphia
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80.    Letter with attachments from Gehring, Philip, Plant Manager (Pigeon Point Energy
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81.    Entropy Environmentalists, Inc., Stationary Source Sampling Report, Signal RESCO, Pinellas
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82.    Midwest Research Institute, Results of the Combustion and Emissions Research Project at the
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83.    Response to Clean Air Act Section 114 Information Questionnaire, Results of Non-Criteria
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84.    Engineering Science, Inc., A Report on Air Emission Compliance Testing at the Regional
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 2.1-40                              EMISSION FACTORS                                .7/93

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90.    Environment Canada, NITEP, Environmental Characterization of Mass Burning Incinerator
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7/93                                 Solid Waste Disposal                               2.1-41

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102.   Hahn, J.L. and D.S. Sofaer, "Air Emissions Test Results from the Stanislaus County,
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103.   Seelinger, R., et al. (Ogden Products, Inc.), Environmental Test Report, Walter B. Hall
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104.   PEI Associates, Inc, Method Development and Testing for Chromium, Municipal Refuse
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105.   Guest, T. and O. Knizek, "Mercury Control at Burnaby's Municipal Waste Incinerator",
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106.   Trip Report, Burnaby MWC, British Columbia, Canada.  White, D., Radian Corporation,
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107.   Entropy Environmentalists, Inc. for Babcock & Wilcox Co. North County Regional Resource
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108.   Maly, P.M., G.C.  England. W.R. Seeker, N.R. Soelberg, and D.G. Linz.  Results of the
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                                            ^
110.   Entropy  Environmentalists, Inc. for Westinghouse RESD, Metals Emission Testing Results,
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111.   Entropy  Environmentalists,  Inc. for Westinghouse RESD, Emissions Testing for: Hexavalent
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112.   Interpoll Laboratories,  Results of the July 1987 Emission Performance Tests of the
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 115.   Knisley, D.R., et al. (Radian Corporation), Emissions Test Report, Dioxin/Furan Emission
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2.1-42                             EMISSION FACTORS                               7/93

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116.   Entropy Environmentalists, Inc., Stationary Source Sampling Report, Ogden Martin Systems
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117.   Fossa, A.J.,  et al., Phase I Resource Recovery Facility Emission Characterization Study,
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118.   Telecon.  DeVan,  S.  Oneida ERF, with Vancil, M.A., Radian Corporation. April 4,  1988.
       Specific collecting area of ESP's.

119.   Higgins, G.M. An Evaluation of Trace Organic Emissions from Refuse Thermal Processing
       Facilities (North Little Rock, Arkansas; Mayport Naval Station, Florida; and Wright Patterson
       Air Force Base, Ohio), Prepared for U. S. Environmental Protection Agency/Office of Solid
       Waste by Systech Corporation, July 1982.

120.   Kerr, R., et al., Emission Source Test ReportSheridan Avenue RDF Plant, Answers (Albany,
       New York), Division of Air Resources, New York State Department of Environmental
       Conservation, August 1985.

121.   U. S. Environmental Protection Agency, Emission Factor Documentation for AP-42
       Section 2.1, Refuse Combustion, Research Triangle Park, NC, May 1993.

122.   Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection Agency,
       Research Triangle Park, NC, April 1970.

123.   Control Techniques For Carbon Monoxide Emissions From Stationary Sources,  AP-65, U. S.
       Environmental Protection Agency, Research Triangle Park, NC, March 1970.

124.   Air Pollution Engineering Manual, AP-40, U.S. Environmental Protection Agency, Research
       Triangle Park, NC, 1967.

125.   J. DeMarco.  et al., Incinerator Guidelines 1969, SW. 13TS, U. S. Environmental Protection
       Agency, Research Triangle Park, NC,  1969.

126.   Municipal  Waste Combustors - Background Information for Proposed Guidelines for Existing
       Facilities, U. S. Environmental Protection Agency, Research Triangle Park, NC,
       EPA-45Q/3-89-27e, August 1989.

127.   Municipal Waste Combustors - Background Information for Proposed Standards: Control of
       NOX Emissions U.S.  Environmental Protection Agency, Research Triangle Park, NC,
       EPA-450/3-89-27d, August 1989.

127.   J.O. Brukle, J.A. Dorsey, and B.T. Riley, "The Effects of Operating Variables and Refuse
       Types on Emissions from a Pilot-scale Trench Incinerator," Proceedings of the 1968
       Incinerator Conference, American Society of Mechanical Engineers, New York, NY,
       May 1968.

128.   Nessen, W.R., Systems Study of Air Pollution from Municipal Incineration, Arthur D. Little,
       Inc., Cambridge, MA, March 1970.


7/93                                Solid  Waste Disposal                               2.1-43

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130.   C.R. Brunner, Handbook of Incineration Systems, McGraw-Hill, Inc., pp. 10.3-10.4, 1991.

131.   Telecon Report, Personal communication between K. Quincey, Radian Corporation and
       E. Raulerson, Florida Department of Environmental Regulations, February 16, 1993.

132.   Telecon Report, Personal communications between K. Nebel and K. Quincey, Radian
       Corporation and M. McDonnold, Simonds Manufacturing, February 16, 1993.

133.   Telecon Report, Personal communications between K. Quincey,  Radian Corporation and
       R. Crochet, Crochet Equipment Company, February 16 and 26,  1993.

134.   Telecon Report, Personal communication between K. Quincey, Radian Corporation and
       T. Allen, NC Division of Environmental Management, February 16, 1993.
2.1-44
EMISSION FACTORS
7/93

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2.5 SEWAGE SLUDGE INCINERATION

       There are approximately 170 sewage sludge incineration (SSI) plants in operation in the
United States.  Three main types of incinerators are used:  multiple hearth, fluidized bed, and electric
infrared. Some sludge is co-fired with municipal  solid waste in combustors based on refuse
combustion technology (see Section 2.1).  Refuse  co-fired with sludge in combustors based on sludge
incinerating technology is limited to multiple hearth incinerators only.

       Over 80 percent of the identified operating sludge incinerators are  of the multiple hearth
design.  About 15 percent are fluidized bed combustors and 3 percent are electric.  The remaining
combustors co-fire refuse with sludge.  Most sludge incinerators are located in the Eastern
United States, though there are a significant number on the West Coast. New York has the largest
number of facilities with 33.  Pennsylvania and Michigan have the next-largest numbers of facilities
with 21 and 19 sites, respectively.

       Sewage sludge incinerator emissions are currently regulated under  40 CFR Part 60, Subpart 0
and 40 CFR Part 61, Subparts C and E. Subpart  0 in Part 60 establishes a New Source Performance
Standard for particulate matter. Subparts C and E of Part 61~National Emission Standards for
Hazardous Air Pollution  (NESHAP)establish emission limits for beryllium and mercury,
respectively.

       In 1989, technical standards for the use and disposal of sewage sludge were proposed as
40 CFR Part 503, under  authority of Section 405  of the Clean Water Act.  Subpart G of this
proposed Part 503 proposes to establish national emission limits for arsenic, beryllium, cadmium,
chromium,  lead, mercury, nickel, and total hydrocarbons from sewage sludge incinerators.  The
proposed limits for  mercury and beryllium are based on the assumptions used in developing the
NESHAP's for these pollutants, and no  additional controls were proposed  to be required. Carbon
monoxide emissions were examined, but no limit  was  proposed.

2.5.1  Process Description1'2

       Types of incineration described  in this section include:

              Multiple  hearth,

              Fluidized bed, and

              Electric.

       Single hearth cyclone, rotary kiln, and wet air oxidation are also briefly discussed.

2.5.1.1 Multiple Hearth Furnaces  The multiple hearth furnace was originally developed for
mineral ore roasting nearly a century ago.  The air-cooled variation has been used to incinerate
sewage sludge since the 1930s. A cross-sectional diagram of a typical multiple hearth furnace is
shown in Figure 2.5-1.  The basic multiple hearth furnace (MHF) is a vertically oriented  cylinder.
The outer shell is constructed of steel, lined with  refractory, and surrounds a series of horizontal
refractory hearths.  A hollow cast iron rotating shaft runs through the center of the hearths.  Cooling


7/93                                  Solid  Waste Disposal                                  2.5-1

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   Auxiliary
   Air Ports

   Rabble Arm
   2 or 4 Per
   Hearth
     Gas Flow
        Clinker
        Breaker
                         Cooling Air
                         Discharge
                                                     Sludge Cake.
                                                     Screenings.
                                                     and Grit
                                                                             Burners

                                                                             Supplemental
                                                                             Fuel
                                                                            Combustion Air

                                                                          Shaft Cooling
                                                                          Air Return

                                                                            Solids Flow
                                                         Drop Holes
                                    Shaft
                                    Cooling Air
2.5-2
Figure 2.5-1.  Cross Section of a Multiple Hearth Furnace

                EMISSION FACTORS
7/93

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 air is introduced into the shaft which extend above the hearths. Each rabble arm is equipped with a
 number of teeth, approximately 6 inches in length, and spaced about 10 inches apart.  The teeth are
 shaped to rake the sludge in a spiral motion,  alternating in direction from the outside in, to the inside
 out, between hearths.  Typically, the upper and lower hearths are fitted with four rabble arms, and
 the middle hearths are fitted with two.  Burners, providing auxiliary heat, are located in the sidewalls
 of the hearths.

        In most multiple hearth furnaces, partially dewatered sludge is fed onto the perimeter of the
 top hearth.  The rabble arms move the sludge through the incinerator by raking the sludge toward the
 center shaft where it drops through holes located at the center of the hearth. In the next hearth the
 sludge is raked in the opposite direction.  This process is repeated in all of the subsequent hearths.
 The effect of the rabble motion is to break up solid material to allow better surface contact with heat
 and oxygen. A sludge depth of about 1 inch is maintained in each hearth at the design sludge  flow
 rate.

        Scum may also be fed to one or more hearths of the incinerator. Scum is the material  that
 floats on wastewater.  It is generally composed of vegetable and mineral oils, grease, hair,  waxes,
 fats, and other materials that will float.   Scum may be removed from many treatment units including
 preaeration tanks, skimming tanks, and sedimentation tanks.  Quantities of scum are generally  small
 compared to those of other  wastewater solids.

        Ambient air is first ducted through the central shaft and its  associated rabble arms.   A
 portion, or all, of this air is then taken from  the top of the shaft and recirculated into the lowermost
 hearth as preheated combustion air. Shaft cooling air which  is not  circulated back into the furnace is
 ducted into the stack downstream of the air pollution control  devices.  The combustion air flows
 upward through the drop holes in the hearths, countercurrent to the flow of the sludge, before  being
 exhausted from the top hearth. Air enters the bottom to cool the ash.  Provisions are usually made to
 inject ambient air directly into on the middle hearths as well.

        From the standpoint of the overall incineration process, multiple hearth furnaces can be
 divided into three zones.  The upper hearths  comprise the drying zone where most of the moisture in
 the sludge is evaporated.  The temperature in the drying zone is typically between 425 and 760C
 (800 and 1400F).  Sludge combustion occurs in the middle hearths (second zone) as the temperature
 is increased to about 925C (1700F).  The combustion zone can be further subdivided into the
 upper-middle hearths where the volatile gases and solids are burned, and the lower-middle hearths
 where most of the fixed carbon is combusted.  The third zone, made up of the lowermost hearth(s), is
 the cooling zone. In this zone the ash is cooled as its heat is transferred to the incoming combustion
 air.

        Multiple hearth furnaces are sometimes operated with afterburners to further reduce odors and
 concentrations of unburned hydrocarbons. In afterburning, furnace exhaust gases are ducted to a
 chamber where they are mixed with supplemental fuel and air and completely combusted.  Some
.incinerators have the flexibility to allow sludge to be fed to a lower hearth, thus allowing the upper
 hearth(s) to function essentially as an afterburner.

        Under normal operating condition, 50 to 100 percent excess air must be added to a MHF in
 order to ensure complete combustion of the sludge.  Besides enhancing contact between fuel and
 oxygen in the furnace, these relatively high rates of excess air are necessary to compensate for normal
 variations in both the organic characteristics  of the sludge feed and the rate at which it enters the
 incinerator. When an inadequate amount of excess air is available, only partial oxidation of the


 7/93                                  Solid Waste Disposal                                2.5-3

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carbon will occur, with a resultant increase in emissions of carbon monoxide, soot, and hydrocarbons.
Too much excess air, on the other hand, can cause increased entrainment of paniculate and
unnecessarily high auxiliary fuel consumption.

       Multiple hearth furnace emissions are usually controlled by a venturi scrubber, an
impingement tray scrubber, or a combination of both.  Wet cyclones and dry cyclones are also used.
Wet electrostatic precipitators (ESPs) are being installed as retrofits where tighter limits on paniculate
matter and metals are required by State regulations.

2.5.1.2 Fluidized Bed Incinerators  Fluidized bed technology was first developed by the petroleum
industry to be used for catalyst regeneration. Figure 2.5-2 shows the cross section diagram of a
fluidized bed fiirnace.  Fluidized bed combustors (FBCs) consist of vertically oriented outer shell
constructed of steel and lined with refractory.  Tuyeres (nozzles designed to deliver blasts of air) are
located at the base of the furnace within a refractory-lined grid.  A bed of sand, approximately
0.75 meters (2.5 feet) thick, rests upon the grid. Two general configurations can be distinguished on
the basis of how the fluidizing air is injected into the furnace.  In the "hot windbox" design the
combustion air is first preheated by passing through a heat exchanger where heat is recovered from
the hot flue gases.  Alternatively, ambient air can be injected directly into the furnace from a cold
windbox.

       Partially dewatered sludge is fed into the lower portion of the furnace. Air injected through
the tuyeres, at pressure of from 20 to 35 kilopascals  (3 to 5  pounds per square inch grade),
simultaneously fluidizes the bed of hot sand and the incoming sludge. Temperatures of 750 to 925C
(1400 to 1700F) are maintained in the bed.  Residence times are typically 2 to 5 seconds. As the
sludge burns, fine ash particles are carried out the top of the furnace.  Some sand is also removed in
the air stream;  sand make-up requirements are on the order of 5 percent for every 300 hours of
operation.

       Combustion of the sludge occurs in two zones.  Within the bed itself (Zone 1) evaporation of
the water and pyrolysis of the organic materials occur nearly simultaneously as the temperature of the
sludge is rapidly raised. In the second zone, (freeboard area) the remaining free carbon and
combustible gases are burned.  The second zone functions essentially as an afterburner.

       Fluidization achieves nearly ideal mixing between the sludge and the combustion air and the
turbulence facilitates the transfer of heat from the hot sand to the sludge.  The most noticeable impact
of the better burning atmosphere provided by a fluidized bed incinerator is seen in the limited amount
of excess air required for complete combustion of the sludge.  Typically, FBCs can achieve complete
combustion with 20 to 50 percent excess air, about half the excess air required by multiple hearth
furnaces. As a consequence, FBC incinerators have generally lower fuel requirements compared to
MHF incinerators.

       Fluidized bed incinerators most often have venturi scrubbers or venturi/impingement tray
scrubber combinations for emissions control.

2.5.1.3  Electric Infrared Incinerators  The first electric infrared furnace was installed in 1975, and
their use is not common.  Electric infrared incinerators consist of a horizontally oriented, insulated
furnace.  A woven wire belt conveyor extends the length of the furnace and infrared heating elements
are located in the roof above the conveyor belt.  Combustion air is preheated by the flue gases and is
injected into the discharge  end of the furnace.  Electric infrared incinerators consist of a number of
2.5-4                                 EMISSION FACTORS                                 7/93

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                                                              Exhaust and Ash
                                                                   Pressure Tap
                                                                       Burner
         Thermocouple
&                                                                   Preheat
                                                                   Burner
                                                                   For Hot
                                                                   Windbox
7/93
Figure 2.5-2.  Cross Section of a Fluidized Bed Furnace

                Solid Waste Disposal
2.5-5

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 prefabricated modules, which can be linked together to provide the necessary furnace length.  A
cross section of an electric furnace is shown in Figure 2.5-3.

       The dewatered sludge cake is conveyed into one end of the incinerator.  An internal roller
mechanism levels the sludge into a continuous layer approximately one inch thick across the width of
the belt.  The sludge is sequentially dried and then burned as it moves beneath the infrared heating
elements. Ash is discharged into a hopper at the opposite end of the furnace.  The preheated
combustion air enters the furnace above the ash hopper and is further heated by the outgoing ash.
The direction of air flow is countercurrent to the movement  of the sludge along the conveyor.
Exhaust gases leave the furnace at the feed end.  Excess air rates vary from 20 to 70 percent.

       Compared to MHF and FBC technologies, the electric infrared furnace offers the advantage of
lower capital cost, especially for smaller systems.  However, electricity costs in some areas may make
an electric furnace infeasible.  One other concern is replacement of various components such as the
woven wire belt and infrared heaters, which have 3- to 5-year lifetimes.

       Electric infrared incinerator emissions are usually controlled with a venturi scrubber or some
other wet scrubber.

2.5.1.4  Other Technologies  A number of other technologies have been used for incineration of
sewage sludge, including cyclonic reactors, rotary kilns, and wet oxidation reactors. These processes
are not in widespread use in the United States and will be discussed only briefly.

       The cyclonic reactor is designed for small capacity applications.  It is constructed of a vertical
cylindrical chamber that is lined with refractory.  Preheated  combustion air is introduced into the
chamber tangentially at high velocities. The sludge is sprayed radially toward the hot refractory
walls. Combustion is rapid: The residence time of the sludge  in the chamber is on the order of
 10  seconds.  The ash is removed with the flue gases.

       Rotary kilns are also generally used for small capacity applications.  The kiln is inclined
slightly from the horizontal plane, with the upper end receiving both the sludge feed and the
combustion air. A burner is located at the lower end of the kiln. The circumference of the kiln
rotates at a speed of about 6 inches per second.  Ash is deposited into a hopper located below the
burner.

       The wet oxidation process is not strictly one of incineration; it instead utilizes oxidation at
elevated  temperature and pressure in the presence of water (flameless combustion). Thickened
sludge, at about 6 percent solids, is first ground and mixed with a stoichiometric amount of
compressed air. The slurry is then pressurized. The mixture is then circulated through a series of
heat exchangers before entering a pressurized reactor.  The temperature of the reactor is held between
 175 and  315C (350 and 600F).  The pressure is normally 7,000 to 12,500  kilopascals (1,000 to
 1,800 pounds per square inch grade).  Steam is usually used for auxiliary heat. The water and
remaining ash are circulated out the reactor and are finally separated in a tank or lagoon.  The liquid
phase is  recycled to  the treatment plant.  Off-gases must be treated to eliminate odors:  wet scrubbing,
 afterburning or carbon absorption may be used.
2.5-6
EMISSION FACTORS
7/93

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7/93
Solid Waste Disposal
2.5-7

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2.5.1.5 Co-Incineration and Co-Firing  Wastewater treatment plant sludge generally has a high
water content and in some cases, fairly high levels of inert materials. As a result, its net fuel value is
often low.  If sludge is combined with other combustible materials in a co-incineration scheme, a
furnace feed can be created that has both a low water concentration and a heat value high enough to
sustain combustion with little or no supplemental fuel.

       Virtually any material that can be burned can be combined with sludge in a co-incineration
process.  Common materials for co-combustion are coal, municipal solid waste (MSW), wood waste
and agriculture waste.  Thus, a municipal or industrial waste can be disposed of while providing an
autogenous (self-sustaining) sludge feed, thereby solving two disposal problems.

       There are two basic approaches to combusting sludge with MSW:  1) use of MSW
combustion technology by adding dewatered or dried sludge to the MSW combustion unit, and 2) use
of sludge combustion technology by adding processed MSW as a supplemental fuel to the sludge
furnace.  With the latter, MSW is processed by removing noncombustibles, shredding, air classifying,
and screening.  Waste that is more finely processed is less likely to cause problems such as severe
erosion of the hearths, poor temperature control, and refractory failures.

2.5.2 Emissions and Controls1"3

       Sewage sludge incinerators potentially emit significant quantities of pollutants. The major
pollutants emitted are:   1) paniculate matter, 2) metals, 3) carbon monoxide (CO), 4) nitrogen oxides
(NOX), 5) sulfur dioxide (SO^, and 6) unburned hydrocarbons. Partial combustion of sludge can
result in  emissions of intermediate products of incomplete combustion (PIC), including toxic organic
compounds.

       Uncontrolled paniculate emission rates vary widely depending on the type of incinerator, the
volatiles  and moisture content of the sludge, and the operating practices employed.  Generally,
uncontrolled paniculate emissions are highest from fluidized bed incinerators because suspension
burning results hi much of the ash being carried out of the incinerator with the flue gas.
Uncontrolled emissions from multiple hearth and fluidized bed incinerators are extremely variable,
however. Electric incinerators appear to have the lowest rates  of uncontrolled paniculate release of
the three major furnace types, possibly because the sludge is not disturbed during firing.  In general,
higher airflow rates increase the opportunity for paniculate matter to be entrained in the exhaust
gases. Sludge with low volatile content or high moisture content may compound this situation by
requiring more supplemental fuel to burn. As more fuel is consumed, the amount of air flowing
through the incinerator is also increased. However, no direct correlation has been established
between  air flow and paniculate emissions.

       Metals emissions are affected by metals content of the sludge,  fuel bed temperature, and the
level of paniculate matter control.   Since metals which are volatilized in the combustion zone
condense in the exhaust gas  stream, most metals (except mercury) are associated with fine paniculate
and are removed as the fine particulates are removed.

       Carbon monoxide is formed when available oxygen is insufficient for  complete combustion or
when excess air levels are too high, resulting in lower combustion temperatures.

       Nitrogen and sulfur oxide emissions are primarily the result of oxidation of nitrogen and
sulfur in the sludge. Therefore, these emissions can vary greatly based on local and seasonal sewage
characteristics.
2.5-8                                EMISSION FACTORS                                 7/93

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       Emissions of volatile organic compounds also vary greatly with incinerator type and
operation.  Incinerators with countercurrent air flow such as multiple hearth designs provide the
greatest opportunity for unburned hydrocarbons to be emitted.  In the MHF, hot air and wet sludge
feed are contacted at the top of the furnace. Any compounds distilled from the solids are immediately
vented from the furnace at temperatures too low to completely destruct them.

       Paniculate emissions from sewage sludge incinerators have historically been controlled by wet
scrubbers, since the associated sewage treatment plant provides both a convenient source and a good
disposal option for the scrubber water.  The types of existing sewage sludge incinerator controls range
from low pressure drop spray towers and wet cyclones to higher pressure drop venturi scrubbers and
venturi/impingement tray  scrubber combinations.  Electrostatic precipitators and baghouses are
employed, primarily where sludge is co-fired with municipal solid waste. The most widely used
control device applied to a multiple hearth incinerator is the impingement tray scrubber.  Older units
use the tray scrubber alone while combination venturi/impingement tray scrubbers are widely applied
to newer multiple hearth incinerators and to fluidized bed incinerators.  Most electric incinerators and
many fluidized bed incinerators use venturi scrubbers only.

       In a typical combination venturi/impingement tray scrubber, hot gas exits the incinerator and
enters  the preceding or quench section of the scrubber.  Spray nozzles  in the quench section cool the
incoming gas and the quenched gas then enters the venturi section of the control device.  Venturi
water is usually pumped into an inlet weir above the quencher. The venturi water enters the scrubber
above  the throat and floods the throat completely. This eliminates build-up of solids and reduces
abrasion.  Turbulence created by high  gas velocity in the converging throat section deflects some of
the water traveling down  the throat into the gas stream.  Particulate matter carried along with the gas
stream impacts on these water particles and on the water wall.  As the scrubber water and flue gas
leave the venturi section,  they pass into a flooded elbow where the stream velocity decreases,
allowing the water and gas to separate. Most venturi sections come equipped with variable throats.
By restricting the throat area within the venturi, the linear gas velocity  is increased and the pressure
drop is subsequently increased.  Up to a certain point, increasing the venturi pressure drop increases
the removal efficiency. Venturi scrubbers typically  maintain 60 to 99 percent removal efficiency for
particulate matter, depending on pressure drop and particle size distribution.

        At the base of the flooded elbow, the gas stream passes through a connecting duct to the base
of the impingement tray tower.  Gas velocity is further reduced upon entry to the tower as the gas
stream passes upward through the perforated impingement trays.  Water usually enters the trays from
inlet ports on opposite sides and flows across the tray.  As gas passes through each perforation in the
tray, it creates a jet which bubbles up  the water and further entrains solid particles.  At the top of the
tower  is a mist eliminator to reduce the carryover of water droplets in the stack effluent gas.  The
impingement section can  contain from one to four trays, but most systems for which data are
available have two or three trays.

        Emission factors  and emission factor ratings for multiple hearth sewage sludge incinerators
are shown in Tables 2.5-1 through 2.5-5.  Tables 2.5-6 through 2.5-8 present emission factors for
fluidized bed sewage sludge incinerators.  Table 2.5-9 presents the available emission factors for
electric infrared incinerators.  Tables 2.5-10 and 2.5-11 present the cumulative particle size
distribution and size specific emission factors for sewage sludge incinerators.  Figures 2.5-4, 2.5-5,
and 2.5-6 present cumulative particle size distribution and size-specific emission factors for multiple-
hearth, fluidized-bed, and electric infrared incinerators, respectively.
 7/93                                  Solid Waste Disposal                                 2.5-9

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Solid Waste Disposal
2.5-21

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7/93

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2.5-23

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EMISSION FACTORS
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2,5-37

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2.5-41

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EMISSION FACTORS
                                                                                7/93

-------
   Table 2.5-10 (Metric and English Units).  CUMULATIVE PARTICLE SIZE DISTRIBUTION
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                           EMISSION FACTOR RATING: E
Particle
Size,
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7/93
Solid Waste Disposal
2.5-45

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2.5-46
EMISSION FACTORS
7/93

-------
                     Figure 2.5-4.  Cumulative Particle Size Distribution and
                                Size-Specific Emission Factors for
                                  Multiple-Health Incinerators
                     Figure 2.5-5.  Cumulative Particle Size Distribution and
                  Size-Specific Emission Factors for Fluidized-Bed Incinerators
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7/93
Solid Waste Disposal
2.5-47

-------
                    Figure 2.5-6. Cumulative Particle Size Distribution and

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2.5-48
EMISSION FACTORS
7/93

-------
References for Section 2.5

1.     Second Review of Standards of Performance for Sewage Sludge Incinerators, EPA-450/3-84-
       010, U. S. Environmental Protection Agency, Research Triangle Park, North Carolina,
       March 1984.

2.     Process Design Manual for Sludge Treatment and Disposal, EPA-625/1-79-011, U.S.
       Environmental Protection Agency, Cincinnati, Ohio, September 1979.

3.     Control Techniques for Paniculate Emissions From Stationary Sources - Volume 1,
       EPA-450/3-81-005a, U. S. Environmental Protection Agency, Research Triangle Park,
       North Carolina, September 1982.

4.     Final Draft Test Report-Site 01 Sewage Sludge Incinerator SSI-A, National Dioxin Study.
       Tier 4:  Combustion Sources.  EPA Contract No. 68-03-3148, U. S. Environmental
       Protection Agency, Research Triangle Park, North Carolina, July 1986.

5.     Final Draft Test Report-Site 03 Sewage Sludge Incinerator SSI-B, National Dioxin Study.
       Tier 4:  Combustion Sources.  EPA Contract No. 68-03-3148, U. S. Environmental
       Protection Agency, Research Triangle Park, North Carolina, July 1986.

6.     Draft Test Report-Site 12 Sewage Sludge Incinerator SSI-C, EPA Contract No. 68-03-3138,
       U. S. Environmental Protection Agency, Research Triangle Park, North Carolina, April
       1986.

7.     M. Trichon and R. T. Dewling,  The Fate of Trace Metals in a Fluidized-Bed Sewage Sludge
       Incinerator, (Port Washington).  (GCA).

8.     Engineering-Science, Inc., Particulate and Gaseous Emission Tests at Municipal Sludge
       Incinerator Plants "O", "P", "Q", and "R" (4 tests), EPA Contract No. 68-02-2815,
       U. S. Environmental Protection Agency, McLean, Virginia, February 1980.

9.     Organics Screening Study Test Report.  Sewage Sludge Incinerator No. 13, Detroit Water and
       Sewer Department, Detroit, Michigan, EPA Contract No. 68-02-3849, PEI Associates, Inc.,
       Cincinnati, Ohio, August 1986.

10.    Chromium Screening Study Test Report. Sewage Sludge Incinerator No. 13, Detroit Water
       and Sewer Department, Detroit Michigan, EPA Contract No. 68-02-3849, PEI Associates,
       Inc., Cincinnati, Ohio, August 1986.

11.    Results of the October 24, 1980, Particulate Compliance Test on the No. 1 Sludge Incinerator
       Wet Scrubber Stack, MWCC St. Paul Wastewater Treatment Plant in St. Paul, Minnesota,
       [STAPPA/ALAPCO/05/27/86-No. 02], Interpoll Inc.,  Circle Pines, Minnesota, November
       1980.

12.    Results of the June ti,  1983, Emission Compliance Test on the No. 10 Incinerator System in
       the F&I 2 Building, MWCC Metro Plant, St. Paul, Minnesota, [STAPPA/ALAPCO/05/27/86-
       No. 02], Interpoll Inc., Circle Pines, Minnesota, June  1983.
 7/93                                 Solid Waste Disposal                               2.5-49

-------
13.    Results of the May 23, 1983, Emission Compliance Test on the No. 9 Incinerator System in
       the F&I 2 Building, MWCC Metro Plant, St. Paul, Minnesota, [STAPPA/ALAPCO/05/27/86-
       No. 02], Interpoll Inc., Circle Pines, Minnesota, May 1983.

14.    Results of the November 25,1980, Paniculate Emission Compliance Test on the No. 4 Sludge
       Incinerator Wet Scrubber Stack, MWCC St. Paul Wastewater Treatment Plant, St. Paul,
       Minnesota, [STAPPA/ALAPCO/05/27/86-No. 02], Interpoll Inc., Circle Pines, Minnesota,
       December, 1980.

15.    Results of the March 28, 1983, Particulate Emission Compliance Test on the No. 8
       Incinerator, MWCC Metro Plant, St. Paul, Minnesota, [STAPPA/ALAPCO/05/28/86-
       No. 06], Interpoll Inc., Circle Pines, Minnesota, April 1983.

16.    Particulate Emission Test Report for a Sewage Sludge Incinerator, City of Shelby Wastewater
       Treatment Plant, [STAPPA/ALAPCO/07/28/86-No. 06], North Carolina Department of
       Natural Resources, February 1979.

17.    Source Sampling Evaluation for Rocky River Wastewater Treatment Plant, Concord,
       North Carolina,  [STAPPA/ALAPCO/05/28/86-No. 06], Mogul Corp., Charlotte,
       North Carolina, July 1982.

18.    Performance Test Report:  Rocky Mount Wastewater Treatment Facility,
       [STAPPA/ALAPCO/07/28/86-No. 06], Envirotech, Belmont, California, July 1983.

19.    Performance Test Report for the Incineration System at the Honolulu Wastewater Treatment
       Plant, Honolulu, Oahu, Hawaii, [STAPPA/ALAPCO/05/22/86-No. 11], Zimpro, Rothschild,
       Wisconsin, January 1984.

20.    (Test Results) Honolulu Wastewater Treatment Plant, Ewa, Hawaii, [STAPPA/ALAPCO/05/
       22/86-No. 11], Zimpro, Rothschild, Wisconsin, November 1983.

21.    Air Pollution Source Test.  Sampling and Analysis of Air Pollutant Effluent from Wastewater
       Treatment Facility-Sand Island Wastewater Treatment Plant in Honolulu, Hawaii,  [STAPPA/
       ALAPCO/05/22/86-No. 11], Ultrachem, Walnut Creek, California, December 1978.

22.    Air Pollution Source Test.  Sampling and Analysis of Air Pollutant Effluent From Wastewater
       Treatment FacilitySand Island Wastewater Treatment Plant in Honolulu, HawaiiPhase II,
       [STAPPA/ALAPCO/05/22/86-No. 11], Ultrachem, Walnut Creek, California, December
       1979.

23.    Stationary Source Sampling Report, EEI Reference No. 2988, at the Osborne Wastewater
       Treatment Plant, Greensboro, North Carolina,  [STAPPA/ALAPCO/07/28/86-No. 06],
       Particulate Emissions and Particle Size Distribution Testing.  Sludge Incinerator Scrubber
       Inlet and  Scrubber Stack, Entropy, Research Triangle Park, North Carolina, October 1985.

24.    Metropolitan Sewer District-Little Miami Treatment Plant (three tests: August 9, 1985,
       September 16,1980, and September 30, 1980) and Mill Creek Treatment Plant (one test:
       January 9, 1986), [STAPPA/ALAPCO/05/28/86-No. 14], Southwestern Ohio Air Pollution
       Control Agency.
2.5-50                             EMISSION FACTORS                               7/93

-------
25.    P'articulate Emissions Compliance Testing, at the City of Milwaukee South Shore Treatment
       Plant, Milwaukee, Wisconsin, [STAPPA/ALAPCO/06/12/86-No. 19], Entropy, Research
       Triangle Park, North Carolina, December 1980.

26.    Particulate Emissions Compliance Testing, at the City of Milwaukee South Shore Treatment
       Plant, Milwaukee, Wisconsin, [STAPPA/ALAPCO/06/12/86-No. 19], Entropy, Research
       Triangle Park, North Carolina, November 1980.

27.    Stack Test Report-Bay shore Regional Sewage Authority, in Union Beach, New Jersey,
       [STAPPA/ALAPCO/05/22/86-No. 12], New Jersey State Department of Environmental
       Protection, Trenton, New Jersey, March  1982.

28.    Stack Test ReportJersey City Sewage Authority, in Jersey City, New Jersey,
       [STAPPA/ALAPCO/05/22/86-No. 12], New Jersey State Department of Environmental
       Protection, Trenton, New Jersey, December 1980.

29.    Stack Test ReportNorthwest Bergen County Sewer Authority, in Waldwick, New Jersey,
       [STAPPA/ALAPCO/05/22/86-No. 12], New Jersey State Department of Environmental
       Protection, Trenton, New Jersey, March  1982.

30.    Stack Test ReportPequannock, Lincoln Park, and Fairfleld Sewerage Authority, in Lincoln
       Park, New Jersey, [STAPPA/ALAPCO/05/22/86-No. 12], New Jersey State Department of
       Environmental Protection, Trenton, New Jersey, December 1975.

31.    Atmospheric Emission Evaluation, of the Anchorage Water and Wastewater Utility Sewage
       Sludge Incinerator, ASA, Bellevue, Washington,  April 1984.

32.    Stack Sampling Report for Municipal Sewage Sludge Incinerator No. 1, Scrubber Outlet
       (Stack), Providence, Rhode Island, Recon Systems, Inc., Three Bridges, New Jersey,
       November 1980.

33.    Stack Sampling Report, Compliance  Test  No. 3, at the Attleboro Advanced Wastewater
       Treatment Facility, in Attleboro, Massachusetts, David Gordon Associates, Inc., Newton
       Upper Falls, Massachusetts, May 1983.

34.    Source Emission Survey, at the Rowlett Creek Plant, North Texas Municipal Water District,
       Piano, Texas, Shirco, Inc., Dallas, Texas, November 1978.

35.    Emissions Data for Infrared Municipal Sewage Sludge Incinerators (Five tests), Shirco, Inc.,
       Dallas, Texas, January 1980.

37.    Electrostatic Precipitator Efficiency on a  Multiple Hearth Incinerator Burning Sewage Sludge,
       Contract No. 68-03-3148,  U.  S. Environmental Protection Agency, Research Triangle Park,
       North Carolina, August 1986.

38.    Baghouse Efficiency on a Multiple Hearth Incinerator Burning Sewage Sludge, Contract
       No. 68-03-3148, U. S. Environmental Protection Agency, Research Triangle Park, North
       Carolina, August 1986.
7/93                                Solid Waste Disposal                              2.5-51

-------
39.    J.B. Farrell and H. Wall, Air Pollution Discharges from Ten Sewage Sludge Incinerators,
       U. S. Environmental Protection Agency, Cincinnati, Ohio, August 1985.

40.    Emission Test Report. Sewage Sludge Incinerator, at the Davenport Wastewater Treatment
       Plant, Davenport, Iowa, [STAPPA/ALAPCO/ll/04/86-No. 119], PEDCo Environmental,
       Cincinnati, Ohio, October 1977.

41.    Sludge Incinerator Emission Testing.  Unit No.  1 for City of Omaha, Papillion Creek Water
       Pollution Control Plant, [STAPPA/ALAPCO/10/28/86-No. 100], Particle Data Labs, Ltd.,
       Elmhurst, Illinois, September 1978.

42.    Sludge Incinerator Emission Testing.  Unit No.  2 for City of Omaha, Papillion Creek Water
       Pollution Control Plant, [STAPPA/ALAPCO/10/28/86-No. 100], Particle Data Labs, Ltd.,
       Elmhurst, Illinois, May 1980.

43.    Paniculate and Sulfur Dioxide Emissions Test Report for Zimpro on the Sewage Sludge
       Incinerator Stack at the Cedar Rapids Water Pollution Control Facility, [STAPPA/ALAPCO/
       11/04/86-No. 119], Serco, Cedar Falls, Iowa, September 1980.

44.    Newport Wastewater Treatment Plant, Newport, Tennessee.  (Nichols; December 1979).
       [STAPPA/ALAPCO/lO/27/86-No. 21].

45.    Maryville Wastewater Treatment Plant Sewage  Sludge Incinerator Emission Test Report,
       [STAPPA/ALAPCO/lO/27/86-No. 21], Enviro-measure, Inc., Knoxville, Tennessee, August
       1984.

46.    Maryville Wastewater Treatment Plant Sewage  Sludge Incinerator Emission Test Report,
       [STAPPA/ALAPCO/lO/27/86-No. 21], Enviro-measure, Inc., Knoxville, Tennessee, October
       1982.

47.    Southerly Wastewater Treatment Plant, Cleveland, Ohio, Incinerator No. 3, [STAPPA/
       ALAPCO/ll/12/86-No. 124], Envisage Environmental, Inc., Richfield, Ohio, May 1985.

48.    Southerly Wastewater Treatment Plant, Cleveland, Ohio. Incinerator No. 1, [STAPPA/
       ALAPCO/ll/12/86-No. 124], Envisage Environmental, Inc., Richfield, Ohio, August 1985.

49.    Final Report for an Emission Compliance Test Program (July 1, 1982), at the City of
       Waterbury Wastewater Treatment Plant Sludge Incinerator, Waterbury, Connecticut,
       [STAPPA/ALAPCO/12/17/86-No.  136], York Services Corp, July 1982.

50.    Incinerator Compliance Test, at the City of Stratford Sewage Treatment Plant, Stratford,
       Connecticut, [STAPPA/ALAPCO/12/17/86-No. 136], Emission Testing Labs, September
        1974.

51.    Emission Compliance Tests at the Norwalk Wastewater Treatment Plant in South Smith Street,
       Norwalk, Connecticut, [STAPPA/ALAPCO/12/17/86-No. 136], York Research Corp,
       Stamford, Connecticut, February 1975.
 2.5-52                             EMISSION FACTORS                              7/93

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52.    Final ReportEmission Compliance Test Program at the East Shore Wastewater Treatment
       Plant in New Haven, Connecticut, [STAPPA/ALAPCO/12/17/86-No. 136], York Services
       Corp., Stamford, Connecticut, September 1982.

53.    Incinerator Compliance Test at the Enfleld Sewage Treatment Plant in Enfleld, Connecticut,
       [STAPPA/ALAPCO/12/17/86-No. 136], York Research Corp., Stamford, Connecticut, July
       1973.

54.    Incinerator Compliance Test at The Glastonbury Sewage Treatment Plant in Glastonbury,
       Connecticut, [STAPPA/ALAPCO/12/17/86-No. 136], York Research Corp., Stamford,
       Connecticut, August 1973.

55.    Results of the May 5,1981, Paniculate Emission Measurements of the Sludge Incinerator, at
       the Metropolitan District Commission Incinerator Plant, [STAPPA/ALAPCO/12/17/86-
       No. 136], Henry Souther Laboratories, Hartford, Connecticut.

56.    Official Air Pollution Tests Conducted on the Nichols Engineering and Research Corporation
       Sludge Incinerator at the Wastewater Treatment Plant in Middletown, Connecticut,
       [STAPPA/ALAPCO/12/17/86-No. 136], Rossnagel and Associates, Cherry Hill, New Jersey,
       November 1976.

57.    Measured Emissions From the West Nichols-Neptune Multiple Hearth Sludge Incinerator at the
       Naugatuck Treatment Company in Naugatuck, Connecticut, [STAPPA/ALAPCO/12/17/86-
       No. 136], The Research Corp., East Hartford, Connecticut, April 1985.

58.    Compliance Test Report-fAugust 27,1986), at the Mattabasset District Pollution Control
       Plant Main Incinerator in Cromwell, Connecticut,  [STAPPA/ALAPCO/12/17/86-No. 136],
       ROJAC Environmental Services, Inc., West Hartford, Connecticut, September 1986.

59.    Stack Sampling Report (May 21, 1986) City of New London No. 2 Sludge Incinerator Outlet
       Stack Compliance Test, [STAPPA/ALAPCO/12/17/86-No. 136], Recon Systems, Inc., Three
       Bridges, New Jersey, June 1986.

60.    Particulate Emission Tests, at the Town of Vemon Municipal Sludge Incinerator in Vernon,
       Connecticut, [STAPPA/ALAPCO/12/17/86-No. 136], The Research Corp., Wethersfield,
       Connecticut, March 1981.

61.    Non-Criteria Emissions Monitoring Program for the Envirotech Nine- Hearth Sewage Sludge
       Incinerator, at the Metropolitan Wastewater Treatment Facility in St. Paul, Minnesota, ERT
       Document No. P-E081-500, October 1986.

62.    D.R. Knisley, et al., Site 1 Revised Draft Emission Test Report, Sewage Sludge Test Program,
       U. S. Environmental Protection Agency, Water Engineering Research Laboratory, Cincinnati,
       Ohio, February 9,  1989.

63.    D.R. Knisley, et al., Site 2 Final Emission Test Report, Sewage Sludge Test Program, U. S.
       Environmental Protection Agency, Water Engineering Research Laboratory, Cincinnati, Ohio,
       October 19, 1987.
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64.    D.R. Knisley, et al., Site 3 Draft Emission Test Report and Addendum, Sewage Sludge Test
       Program.  Volume 1: Emission Test Results, U. S. Environmental Protection Agency, Water
       Engineering Research Laboratory, Cincinnati, Ohio, October 1, 1987.

65.    D.R. Knisley, et al., Site 4 Final Emission Test Report, Sewage Sludge Test Program, U.S.
       Environmental Protection Agency, Water Engineering Research Laboratory, Cincinnati, Ohio,
       May 9, 1988.

66.    R.C. Adams, et al., Organic Emissions from the Exhaust Stack of a Multiple Hearth Furnace
       Burning Sewage Sludge, U.S. Environmental Protection Agency, Water Engineering
       Research Laboratory, Cincinnati, Ohio, September 30, 1985.

67.    R.C. Adams, et al., Paniculate Removal Evaluation of an Electrostatic Precipitator Dust
       Removal System Installed on a Multiple Hearth Incinerator Burning Sewage Sludge, U. S.
       Environmental Protection Agency, Water Engineering Research Laboratory, Cincinnati, Ohio,
       September 30, 1985.

68.    R.C. Adams, et al., Paniculate Removal Capability of a Baghouse Filter on the Exhaust of a
       Multiple Heanh Furnace Burning Sewage Sludge,  U. S. Environmental Protection Agency,
       Water Engineering Research Laboratory, Cincinnati, Ohio, September 30,  1985.

69.    R.G. Mclnnes, et al., Sampling and Analysis Program at the New Bedford Municipal Sewage
       Sludge Incinerator, GCA Corporation/Technology Division. U. S. Environmental Protection
       Agency, Research Triangle Park, North Carolina,  November 1984.

70.    R.T. Dewling, et al., "Fate and Behavior of Selected Heavy Metals in Incinerated Sludge."
       Journal of the Water Pollution Control Federation, Vol. 52, No. 10,  October 1980.

71.    R.L. Bennet, et al., Chemical and Physical Characterization of Municipal Sludge Incinerator
       Emissions, Report No. EPA 600/3-84-047, NTIS No. PB 84-169325, U. S. Environmental
       Protection Agency, Environmental Sciences Research Laboratory, Research Triangle Park,
       North Carolina, March 1984.

72.    Acurex Corporation. 1990 Source Test Data for the Sewage Sludge Incinerator,
       Project 6595, Mountain View, California, April 15, 1991.

73.    Emissions of Metals, Chromium, and Nickel Species, and Organicsfrom Municipal
       Wastewater Sludge Incinerators, Volume I: Summary Report, U.S. Environmental  Protection
       Agency, Cincinnati, Ohio,  1992.

74.    L.T. Hentz, et al., Air Emission Studies of Sewage Sludge, Incinerators at the Western Branch
       Wastewater Treatment Plan, Water Environmental Research, Vol. 64, No. 2, March/April,
       1992.

75.    Source Emissions Testing of the Incinerator #2 Exhaust Stack at the Central Costa Sanitary
       District Municipal Wastewater Treatment Plan, Mortmez, California,  Galson Technical
       Services, Berkeley,  California,  October,  1990.
2.5-54                              EMISSION FACTORS                               7/93

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76.    R.R. Segal, et al., Emissions of Metals, Chromium and Nickel Species, and Organics from
       Municipal Wastewater Sludge Incinerators, Volume II: Site 5 Test Report - Hexavalent
       Chromium Method Evaluation, EPA 600/R-92/003a, March 1992.

77.    R.R. Segal, et al, Emissions of Metals, Chromium and Nickel Species, and Organics from
       Municipal Wastewater Sludge Incinerators, Volume III: Site 6 Test Report,
       EPA 600/R-92/003a, March 1992.

78.    A.L. Cone et al., Emissions of Metals, Chromium, Nickel Species, and Organics from
       Municipal Wastewater Sludge Incinerators.  Volume 5: Site  7 Test Report CEMS, Entropy
       Environmentalists, Inc., Research Triangle Park, North Carolina, March 1992.

79.    R.R. Segal, et al., Emissions of Metals, Chromium and Nickel Species, and Organics from
       Municipal Wastewater Sludge Incinerators, Volume VI: Site 8 Test Report,
       EPA 600/R-92/003a, March 1992.

80.    R.R. Segal, et al, Emissions of Metals, Chromium and Nickel Species, and Organics from
       Municipal Wastewater Sludge Incinerators, Volume VII:  Site 9 Test Report,
       EPA 600/R-92/003a, March 1992.

81.    Stack Sampling for THC and Specific Organic Pollutants at MWCC Incinerators.  Prepared
       for the Metropolitan Waste Control Commission, Mears Park Centre,  St.  Paul, Minnesota,
       July 11,  1991, QC-91-217.
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2.6 MEDICAL WASTE INCINERATION

       Medical waste incineration involves the burning of wastes produced by hospitals, veterinary
facilities, and medical research facilities.  These wastes include both infectious ("red bag") medical
wastes as well as non-infectious, general housekeeping wastes.  The emission factors presented here
represent emissions when both types of these wastes are combusted rather than just infectious wastes.

       Three main types of incinerators are used: controlled air, excess air, and rotary kiln. Of the
incinerators identified in this study, the majority (>95 percent) are controlled air units.  A small
percentage (<2 percent) are excess air.  Less than one percent were identified as rotary kiln.  The
rotary kiln units tend to be larger, and typically are equipped with air pollution control devices.
Approximately 2 percent of the total population identified in this study were found to be equipped
with air pollution control devices.

2.6.1  Process Description1"6

       Types of incineration described in this section include:

              Controlled air,

               Excess air, and

               Rotary kiln.

2.6.1.1 Controlled-Air Incinerators -- Controlled-air incineration is the most widely used medical
waste incinerator (MWI) technology, and now dominates the market for new systems at hospitals and
similar medical facilities.  This technology is also known as starved-air incineration, two-stage
incineration, or modular combustion.  Figure 2.6-1 presents a typical schematic diagram of a
controlled air unit.

        Combustion of waste in controlled air incinerators occurs in two stages.  In the first stage,
waste is fed into the primary, or lower, combustion chamber, which is operated with less than the
stoichiometric amount of air required for combustion.  Combustion air enters the primary chamber
from beneath the incinerator hearth (below the burning bed  of waste).  This air is called primary or
underfire air. In the primary (starved-air) chamber, the low air-to-fuel ratio dries and facilitates
volatilization of the waste, and most  of the residual carbon  in the ash burns.  At these conditions,
combustion gas temperatures  are relatively low [760 to 980C (1,400 to 1,800F)].

        In the second stage, excess air  is added to the volatile gases formed in the primary chamber  to
complete combustion. Secondary chamber temperatures are higher than primary chamber
temperatures-typically 980 to 1,095C (1,800 to  2,000F). Depending on the heating value and
moisture  content of the waste, additional heat may be needed.  This can be provided by auxiliary
burners located at the entrance to the secondary (upper) chamber to maintain desired temperatures.

        Waste feed capacities for controlled air incinerators range from about 0.6 to 50 kg/min  (75 to
 6,500 Ib/hr) [at an assumed fuel heating value of  19,700 kJ/kg (8,500 Btu/lb)].  Waste feed and ash
 removal can be manual or automatic, depending on the unit size and options purchased. Throughput


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                                                         Carbon Dioxide,
                                                         Water Vapor
                                                         Oxygen and Nitrogen
                                                         and Excess
                                                         to Atmosphere
                        Air
                                Air
 Main Burner for
 Minimum Combustion
 Temperature
         Starved-AIr
         Condition in
         Lower Chamber
       Controlled
       UnderfireAir
       for Burning
       Down Waste
                                 Volatile Content
                                  is Burned In
                                  Upper Chamber

                                 Excess Air
                                 Condition
2.6-2
Figure 2.6-1. Controlled Air Incinerator


       EMISSION FACTORS
7/93

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capacities for lower heating value wastes may be higher, since feed capacities are limited by primary
chamber heat release rates. Heat release rates for controlled air incinerators typically range from
about 430,000 to 710,000 kJ/hr-m3 (15,000 to 25,000 Btu/hr-ft3).

        Because of the low air addition rates in the primary chamber, and corresponding low flue gas
velocities (and turbulence), the amount of solids entrained in the gases leaving the primary chamber is
low.  Therefore, the majority of controlled air incinerators do not have add-on gas cleaning devices.

2.6.1.2  Excess Air Incinerators  Excess air incinerators are typically small modular units.  They
are also referred to as batch incinerators, multiple chamber incinerators, or "retort" incinerators.
Excess  air incinerators are typically a compact cube with a series of internal chambers and baffles.
Although they can be operated continuously, they are usually operated in a batch mode.

        Figure 2.6-2 presents a schematic for an excess air unit. Typically, waste is manually fed
into the combustion chamber.  The charging door is then closed, and an afterburner is ignited to bring
the secondary chamber to a target temperature [typically 870 to 980C (1600 to 1800F)].  When the
target temperature is reached,  the..primary chamber burner ignites. The waste is dried, ignited, and
combusted by heat provided by the primary chamber burner, as well as by radiant heat from the
chamber walls.  Moisture and volatile components in the waste are vaporized, and pass (along with
combustion gases) out of the primary chamber and through a flame port which connects the primary
chamber to  the secondary or mixing chamber. Secondary air is added through the flame port and is
mixed with the volatile components in the secondary chamber.  Burners are also installed in the
secondary chamber to maintain adequate temperatures for combustion of volatile gases.  Gases exiting
the secondary chamber are directed to the incinerator stack or to an air pollution-control device.
When the waste is consumed,  the primary burner shuts off.  Typically, the afterburner shuts off after
a set  time.  Once the chamber cools, ash is manually removed from the primary chamber floor and a
new charge of waste can be added.

        Incinerators designed to burn general hospital waste operate at excess air levels of up to
300 percent.  If only pathological wastes are combusted, excess air levels near 100 percent are more
common. The lower excess air helps maintain higher chamber temperature when burning high
moisture waste. Waste feed capacities for excess air incinerators are usually 3.8 kg/min (500 Ib/hr)
or less.

2.6.1.3 Rotary Kiln Incinerators - Rotary kiln incinerators, like the other types, are designed with a
primary chamber, where the waste is heated and volatilized, and a secondary chamber, where
combustion of the volatile fraction is completed.  The primary chamber consists of a slightly inclined,
rotating kiln in which waste materials migrate from the feed end to the ash discharge end.  The waste
throughput rate is controlled by adjusting the rate of kiln rotation and the  angle of inclination.
Combustion air enters the primary chamber through a port. An auxiliary  burner is generally used to
start combustion and maintain desired combustion temperatures.  Both the primary and secondary
chambers are usually lined with acid-resistant refractory brick, as shown in the schematic  drawing,
Figure 2.6-3.
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                                Rame Port
       Charging
         Door
      Ignition
     Chamber
                           Stack
                                 Secondary
                                 Air Ports
                                                                Secondary
                                                             X"" Burner Port
                                    Mixing
                                    Chamber
                                                              First
                                                              Underneath Port
               Hearth
    Side View
                   Secondary
                  Combustion
                   Chamber
         Mixing
        Chamber    Flame
                         Cleanout
                           Doors
                                                                  Charging Door


                                                                  Hearth
                                   Primary
                                   Burner Port
                           Secondary
                           Underneath Port
                           Figure 2.6-2. Excess Air Incinerator
2.6-4
EMISSION FACTORS
7/93

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                                                                                       cc
                                                                                       I
                                Figure 2.6-3. Rotary Kiln Incinerator
7/93
Solid Waste Disposal
2.6-5

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       Volatiles and combustion gases pass from the primary chamber to the secondary chamber.
The secondary chamber operates at excess air.  Combustion of the volatiles is completed in the
secondary chamber.  Due to the turbulent motion of the waste in the primary chamber,  solids burnout
rates and paniculate entrainment in the flue gas are higher for rotary kiln incinerators than for other
incinerator designs. As a result, rotary kiln incinerators generally have add-on gas cleaning devices.

2.6.2 Emissions and Controls2'4'7"43

       Medical waste incinerators can emit significant quantities of pollutants to the atmosphere.
These pollutants include:  1) paniculate matter (PM), 2) metals, 3) acid gases, 4) oxides of nitrogen
(NOX), 5) carbon monoxide (CO), 6) organics, and 7) various other materials present in medical
wastes, such as pathogens, cytotoxins, and radioactive diagnostic materials.

       Paniculate matter is emitted as a result of incomplete combustion of organics (i.e., soot) and
by the entrainment of noncombustible  ash due to the turbulent movement of combustion gases.
Paniculate matter may exit as a solid or an aerosol, and may  contain heavy metals, acids, and/or trace
organics.

       Uncontrolled paniculate emission rates vary widely, depending on the type of incinerator,
composition of the waste, and the operating practices employed.  Entrainment of PM in the
incinerator exhaust is primarily a function of the gas velocity within the combustion chamber
containing the solid waste.  Controlled air incinerators have the lowest turbulence  and, consequently,
lowest PM emissions; rotary kiln incinerators have highly turbulent combustion, and thus have the
highest PM emissions.

       The type and amount of trace metals  in the flue gas are directly related to the metals
contained hi the waste.  Metals emissions are affected by the level of PM control and the flue gas
temperature.  Most metals (except mercury) exhibit fine-particle enrichment and are removed by
maximizing small particle collection.  Mercury, due to its high vapor pressure, does not show
significant particle enrichment, and removal is not a function of small  particle collection in gas
streams at temperatures greater than 150C (300F).

       Acid gas concentrations of hydrogen  chloride (HC1) and sulfur dioxide (SO^ in MWI flue
gases are directly related to the chlorine and sulfur content  of the  waste. Most of the chlorine, which
is chemically bound within the waste hi the form of polyvinyl chloride (PVC) and other chlorinated
compounds, will be converted to HC1. Sulfur is also chemically bound within the materials making
up medical waste and is oxidized during combustion to form SO2.

       Oxides of nitrogen (NOX) represent a mixture of mainly nitric  oxide (NO) and nitrogen
dioxide (NO^.  They are formed during combustion by: 1) oxidation of nitrogen chemically bound
in the waste, and 2) reaction between molecular nitrogen and oxygen in the combustion air.  The
formation of NOX is dependent on the  quantity of fuel-bound nitrogen  compounds, flame temperature,
and air/fuel ratio.

       Carbon monoxide is a product of incomplete combustion.  Its presence can be related to
insufficient oxygen, combustion (residence) time, temperature, and turbulence (fuel/air mixing) in the
combustion zone.

       Failure to achieve complete combustion of organic materials evolved from the waste can result
in emissions of a variety of organic compounds. The products of incomplete combustion  (PICs) range


2.6-6                               EMISSION FACTORS                                7/93

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from low molecular weight hydrocarbon (e.g., methane or ethane) to high molecular weight
compounds [e.g., polychlorinated dibenzo-p-dioxins and dibenzofurans (CDD/CDF)].  In general,
combustion conditions required for control of CO (i.e., adequate oxygen, temperature, residence
time, and turbulence) will also minimize emissions  of most organics.

       Emissions of CDD/CDF from MWIs may occur as either a vapor or as a fine paniculate.
Many factors are believed to be involved in the formation of CDD/CDF and many theories exist
concerning the formation of these compounds.  In brief, the best supported theories involve four
mechanisms of formation.2 The first theory states that trace quantities of CDD/CDF present in the
refuse feed are carried over, unburned, to the exhaust.  The second theory involves formation of
CDD/CDF from chlorinated precursors with similar structures. Conversion of precursor material to
CDD/CDF can potentially occur either in the combustor at relatively high temperatures or at lower
temperatures such as are present in wet scrubbing systems.  The third theory involves synthesis of
CDD/CDF compounds from a variety of organics and a chlorine donor. The fourth mechanism
involves catalyzed reactions on fly ash particles at low temperatures.

       To date, most MWIs have operated without add-on air pollution control devices  (APCDs).  A
small percentage (approximately 2 percent) of MWIs do use APCDs.  The most frequently used
control devices are wet scrubbers and fabric filters  (FFs).  Fabric filters provide mainly  PM control.
Other PM control technologies include venturi scrubbers and electrostatic precipitators (ESPs).  In
addition to wet scrubbing, dry sorbent injection (DSI)  and spray dryer absorbers have also been used
for acid gas control.

       Wet scrubbers use gas-liquid absorption to  transfer pollutants from a gas to a liquid stream.
Scrubber design and the type of liquid solution used largely determine contaminant removal
efficiencies.  With plain water, removal efficiencies for acid gases could be as high as 70 percent for
HC1 and 30 percent for SO2.  Addition of an alkaline reagent to the scrubber liquor for acid
neutralization has been shown  to result in removal  efficiencies of 93 to 96 percent.

       Wet scrubbers are generally classified according to the energy  required to overcome the
pressure drop through the system.  Low-energy scrubbers (spray towers) are primarily used for acid
gas control only, and are usually circular in cross-section. The liquid  is sprayed down the tower
through the rising gas.  Acid gases are absorbed/neutralized by the scrubbing liquid. Low energy
scrubbers mainly remove particles larger than 5-10 micrometers (jim) in diameter.

       Medium-energy scrubbers can be used for paniculate matter and/or acid gas control.  Medium
energy devices rely mostly on impingement to facilitate removal of PM. This can be accomplished
through a variety of configurations, such as packed columns, baffle plates, and liquid impingement
scrubbers.

       Venturi  scrubbers are  high-energy systems  that are used primarily for PM control. A typical
venturi scrubber consists of a  converging and a diverging section connected by a throat section.  A
liquid (usually water) is introduced into the gas stream upstream of the throat.  The flue gas impinges
on the liquid stream in the converging section. As the gas passes through the throat, the shearing
action atomizes  the liquid into fine droplets. The gas  then decelerates through the diverging section,
resulting in further contact between particles and liquid droplets.   The droplets are then  removed from
the gas stream by a cyclone, demister or swirl vanes.

        A fabric filtration system (baghouse) consists of a number of filtering elements (bags) along
with a bag cleaning system contained in a main shell  structure with dust hoppers.  Particulate-laden


7/93                                  Solid Waste Disposal                                 2.6-7

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gas passes through the bags so that the particles are retained on the upstream side of the fabric, thus
cleaning the gas. A FF is typically divided into several compartments or sections.  In a FF, both the
collection efficiency and the pressure drop across the bag surface increase as the dust layer on the bag
builds up.  Since the system cannot continue to operate with an increasing pressure drop, the bags are
cleaned periodically.  The cleaning processes include reverse flow with bag collapse, pulse jet
cleaning, and mechanical shaking. When reverse flow and mechanical shaking are used, the
particulate matter is collected on the inside of the bag; particulate matter is collected on the outside of
the bag in pulse jet systems.  Generally, reverse flow FFs operate with lower gas flow per unit area
of bag surface (air-to-cloth ratio) than pulse jet systems and, thus, are larger and more costly for a
given gas flow-rate or application. Fabric filters can achieve very high (>99.9 percent) PM  removal
efficiencies. These systems are also very effective in controlling fine particulate matter, which results
in good control of metals and organics entrained on fine particulate.

        Particulate collection in an ESP occurs  in three steps:  (1) suspended particles are given an
electrical charge; (2) the charged particles migrate to a collecting electrode of opposite polarity; and  .
(3) the collected PM is dislodged  from the collecting electrodes and collected in hoppers for disposal.

        Charging of the particles is usually caused by ions produced in high voltage corona.  The
electric fields and the corona necessary for particle charging are provided by converting alternating
current to direct current using high voltage transformers and rectifiers.  Removal of the collected
particulate matter is accomplished mechanically by rapping or vibrating the collecting electrode plates.
ESPs have been used in many applications due  to their high reliability and efficiency in controlling
total PM emissions.  Except for very large and carefully designed ESPs, however, they are less
efficient than FFs at control of fine particulates and metals.

        Dry sorbent injection (DSI) is another method for controlling acid gases.  In the DSI  process,
a dry alkaline material is injected into the flue gas into a dry venturi within the ducting or into the
duct ahead of a particulate control device.  The alkaline material reacts with and neutralizes acids in
the flue gas.  Fabric filters are employed downstream of DSI to: 1) control the PM generated by the
incinerator, 2) capture the DSI reaction products and unreacted sorbent,  and 3) increase sorbent/acid
gas contact time, thus enhancing acid gas removal efficiency and sorbent utilization. Fabric filters are
commonly used with DSI because they provide high sorbent/acid gas contact.  Fabric filters are less
sensitive to PM loading changes or combustion upsets than other PM control devices since they
operate with nearly constant efficiency.  A potential disadvantage of ESPs used in conjunction with
DSI is that the sorbent increases the  electrical resistivity of the PM being collected. This
phenomenon makes the PM more difficult to charge and, therefore, to collect. High resistivity can be
compensated for by flue gas conditioning or by increasing the plate area and size of the ESP.

        The major factors affecting DSI performance are flue gas temperature, acid gas dew point
(temperature at which the acid gases condense), and  sorbent-to-acid gas ratio.  DSI performance
improves as the difference between flue gas and acid dew point temperatures decreases and the
sorbent-to-acid  gas ratio increases.  Acid gas removal efficiency with DSI also depends on sorbent
type and the extent  of sorbent mixing with the flue gas. Sorbents that have been successfully applied
include hydrated lime [Ca(OH)2], sodium hydroxide (NaOH),  and sodium bicarbonate (NaHCO3).
For hydrated lime, DSI can achieve  80 to 95 percent of HC1 removal and 40 to 70 percent removal of
SO2 under proper operating conditions.

        The primary advantage of DSI  compared to wet scrubbers is the relative simplicity of the
sorbent preparation, handling, and injection systems as well as the easier handling and disposal of dry
2.6-8                                EMISSION FACTORS                                 7/93

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solid process wastes.  The primary disadvantages are its lower sorbent utilization rate and
correspondingly higher sorbent and waste disposal rates.

       In the spray drying process, lime slurry is injected into the SD through either a rotary
atomizer or dual-fluid nozzles.  The water in the slurry evaporates to cool the flue gas, and the lime
reacts with acid gases to form calcium salts that can be removed by a PM control device.  The SD is
designed to provide sufficient contact and residence time to produce  a dry product before leaving the
SD adsorber vessel.  The  residence time in the adsorber vessel  is typically 10 to 15 seconds. The
particulates leaving the SD (fly ash, calcium salts, and unreacted hydrated lime) are collected by a FF
or ESP.

       Emission factors and emission factor ratings for controlled air incinerators are presented in
Tables 2.6-1 through 2.6-15. For emissions controlled with wet scrubbers, emission factors are
presented separately for low, medium, and high energy wet scrubbers.  Particle size distribution data
for controlled air incinerators are presented in Table 2.6-15 for uncontrolled emissions and controlled
emissions following a medium-energy wet scrubber/FF and a low-energy wet scrubber. Emission
factors and emission factor ratings for rotary kiln incinerators are presented in Tables 2.6-16
through 2.6-18. Emissions data are not available for pathogens because there is not an accepted
methodology for measurement of these emissions. Refer to References 8, 9,  11, 12, and 19 for more
information.
 7/93                                  Solid Waste Disposal                                 2.6-9

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-------
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Solid Waste Disposal
2.6-17

-------
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-------





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Solid Waste Disposal
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2.6-21

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                         Solid Waste Disposal
                                                            2.6-23

-------
                 Table 2.6-15. PARTICLE SIZE DISTRIBUTION FOR
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                      PARTICULATE MATTER EMISSIONS*
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2.6-24
EMISSION FACTORS
7/93

-------
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2.6-25

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7/93
                     Solid Waste Disposal
                                                                                2.6-27

-------
References for Section 2.6
1.     Locating and Estimating Air Toxic Emissions from Medical Waste Incinerators, U. S.
       Environmental Protection Agency, Rochester,  New York, September 1991.

2.     Hospital Waste Combustion Study: Data Gathering Phase, EPA-450/3-88-017, U. S.
       Environmental Protection Agency, Research Triangle Park, North Carolina, December 1988.

3.     C.R. Brunner, "Biomedical Waste Incineration", presented at the 80th Annual Meeting of the
       Air Pollution Control Association, New York, New York, June 21-26, 1987.  p. 10.

4.     Flue Gas Cleaning Technologies for Medical Waste Combustors, Final Report, U. S.
       Environmental Protection Agency, Research Triangle Park, North Carolina, June 1990.

5.     Municipal Waste Combustion Study; Recycling of Solid Waste, U. S. Environmental Protection
       Agency, EPA Contract 68-02-433, pp.5-6.

6.     S. Black and J. Netherton, Disinfection, Sterilization, and Preservation.  Second Edition,
       1977, p.729.

7.     J. McCormack, et al., Evaluation Test on a Small Hospital Refuse Incinerator at Saint
       Bemardine's Hospital in San Bernardino, California, California Air Resources Board, July
       1989.

8.     Medical Waste Incineration Emission  Test Report, Cape Fear Memorial Hospital,  Wilmington,
       North Carolina, U. S. Environmental Protection Agency, December 1991.

9.     Medical Waste Incineration Emission  Test Report, Jordan Hospital, Plymouth, Massachusetts,
       U. S. Environmental Protection Agency, February 1992.

10.    J.E. McCormack, Evaluation Test of the Kaiser Permanente Hospital Waste Incinerator in
       San Diego, California Air Resources Board, March  1990.

11.    Medical Waste Incineration Emission  Test Report, Lenoir Memorial Hospital, Kinston,
       North Carolina, U. S. Environmental Protection Agency, August 12, 1991.

12.    Medical Waste Incineration Emission  Test Report, AMI Central Carolina Hospital, Sanford,
       North Carolina, U. S. Environmental Protection Agency, December 1991.

13.    A. Jenkins, Evaluation Test on a Hospital Refuse Incinerator at Cedars Sinai Medical Center,
       Los Angeles, California, California Air Resources Board, April  1987.

14.    A. Jenkins, Evaluation Test on a Hospital Refuse Incinerator at Saint Agnes Medical Center,
       Fresno, California, California Air Resources Board,  April 1987.

15.    A. Jenkins, et al., Evaluation Retest on a Hospital Refuse Incinerator at Sutler General
       Hospital, Sacramento, California, California Air Resources Board, April 1988.
2.6-28                              EMISSION FACTORS                                7/93

-------
16.     Test Report for Swedish American Hospital Consumat Incinerator, Beling Consultants,
       Rockford, Illinois, December 1986.

17.     J.E. McCormack, ARE Evaluation Test Conducted on a Hospital Waste Incinerator at Los
       Angeles County-USC Medical Center, Los Angeles, California, California Air Resources
       Board, January 1990.

18:     MJ. Bumbaco, Report on a Stack Sampling Program to Measure the Emissions of Selected
       Trace Organic Compounds, Particulates, Heavy Metals, and HCljrom the Royal Jubilee
       Hospital Incinerator, Victoria, British Columbia, Environmental Protection Programs
       Directorate, April 1983.

19.     Medical Waste Incineration Emission Test Report, Borgess Medical Center, Kalamazoo,
       Michigan, EMB Report 91-MWI-9, U.  S. Environmental  Protection Agency,  Office of Air
       Quality Planning and Standards, December 1991.

20.     Medical Waste Incineration Emission Test Report, Morristown Memorial Hospital,
       Morristown, New Jersey, EMB Report 91-MWI-8, U. S. Environmental Protection  Agency,
       Office of Air Quality Planning and Standards, December  1991.

21.     Report of Emission Tests, Burlington County Memorial Hospital, Mount Holly, New Jersey,
       New Jersey State Department of Environmental Protection,  November 28, 1989.

22.     Results of the November 4 and 11, 1988 Paniculate and Chloride Emission Compliance Test
       on the Morse Boulger Incinerator at the Mayo Foundation Institute Hills Research Facility
       Located in Rochester, Minnesota, HDR Techserv, Inc., November 39, 1988.

23.     Source Emission Tests at ERA Tech, North Jackson, Ohio, Custom Stack Analysis
       Engineering Report, CSA Company, December 28, 1988.

24.     Memo to Data File, Hershey Medical Center, Derry Township, Pennsylvania, from Thomas
       P. Bianca, Environmental Resources, Commonwealth of Pennsylvania, May 9, 1990.

25.     Stack Emission Testing, Erlanger Medical Center, Chattanooga, Tennessee, Report 1-6299-2,
       Campbell & Associates, May 6,  1988.

26.     Emission Compliance Test Program, Nazareth Hospital, Philadelphia, Pennsylvania, Ralph
       Manco, Nazareth Hospital, September 1989.

27.     Report of Emission Tests, Hamilton Hospital, Hamilton, New Jersey, New Jersey State
       Department of Environmental Protection, December 19, 1989.

28.     Report of Emission Tests, Raritan Bay Health Services Corporation, Perth Amboy,
       New Jersey, New Jersey  State Department of Environmental Protection, December  13,  1989.

29.    K.A. Hansen, Source Emission Evaluation on a Rotary Atomizing Scrubber at Klamath  Falls,
       Oregon, AM Test, Inc., July 19, 1989.

30.    A.A. Wilder, Final Report for Air Emission Measurements from a Hospital Waste Incinerator,
       Safeway Disposal Systems,  Inc., Middletown, Connecticut.


7/93                                 Solid Waste Disposal                               2.6-29

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31.    Stack Emission Testing, Erlanger Medical Center, Chattanooga, Tennessee, Report 1-6299,
       Campbell & Associates, April 13,  1988.

32,    Compliance Emission Testing for Memorial Hospital, Chattanooga, Tennessee, Air Systems
       Testing, Inc., July 29, 1988.

33.    Source Emission Tests at ERA  Tech, Northwood, Ohio, Custom Stack Analysis Engineering
       Report, CSA Company, July 27, 1989.

34.    Compliance Testing for Southland Exchange Joint Venture, Hampton, South Carolina, ETS,
       Inc., July 1989.

35.    Source Test Report, MEGA of Kentucky, Louisville, Kentucky, August, 1988.

36.    Report on Paniculate and HCL Emission Tests on Therm-Tec Incinerator Stack, Elyra, Ohio,
       Maurice L. Kelsey & Associates, Inc., January 24,  1989.

37.    Compliance Emission Testing for Paniculate and Hydrogen Chloride at Bio-Medical Service
       Corporation, Lake City, Georgia, Air Techniques Inc., May 8, 1989.

38.    Particulate and Chloride Emission Compliance Test on the Environmental Control Incinerator
       at the Mayo Foundation Institute Hills Research Facility, Rochester, Minnesota, HDR
       Techserv, Inc., November 30, 1988.

39.    Repon on Paniculate and HCL Emission Tests on Therm-Tec Incinerator Stack, Cincinnati,
       Ohio, Maurice L.  Kelsey & Associates, Inc., May 22,  1989.

40.    Repon on Compliance Testing, Hamot Medical Center, Erie, Pennsylvania, Hamot Medical
       Center, July 19, 1990.

41.    Compliance Emission Testing for HCA North Park Hospital, Hixson, Tennessee, Air Systems
       Testing, Inc., February 16,  1988.

42.    Compliance Paniculate Emission Testing on the Pathological Waste Incinerator, Humana
       Hospital-East Ridge, Chattanooga, Tennessee, Air Techniques, Inc., November 12, 1987.

43.    Repon of Emission Tests, Helene Fuld Medical Center, Trenton, New Jersey, New Jersey
       State Department of Environmental Protection, December  1, 1989.
2.6-30
EMISSION FACTORS
7/93

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2.7    MUNICIPAL SOLID WASTE LANDFILLS

2.7.1 General1"4

       A municipal solid waste (MSW) landfill unit is a discrete area of land or an excavation that
receives household waste, and that is not a land application unit, surface impoundment, injection well,
or waste pile.  An MSW landfill unit may also receive other types of wastes, such as commercial
solid waste, nonhazardous sludge, and industrial solid waste.  The municipal solid waste types
potentially accepted by MSW landfills include:

             MSW,
             Household hazardous waste,
             Municipal sludge,
             Municipal waste combustion ash,
             Infectious waste,
             Waste tires,
             Industrial non-hazardous waste,
             Conditionally exempt small quantity generator (CESQG) hazardous waste,
             Construction and demolition waste,
             Agricultural wastes,
             Oil and gas wastes, and
             Mining wastes.

       Municipal solid waste management in the United States  is dominated by disposal in landfills.
Approximately 67 percent of solid waste is landfilled, 16 percent is incinerated, and 17 percent is
recycled or composted.  There were an estimated 5,345 active MSW landfills in the United States in
1992. In  1990, active landfills were receiving an estimated 118 million megagrams (Mg) (130 million
tons) of waste annually, with 55 to 60 percent reported as household waste, and 35 to 45 percent
reported as commercial waste.

2.7.2 Process Description2'5

       There are three major designs for municipal landfills. These are the area, trench, and ramp
methods.  AH of these methods utilize a three step process, which includes spreading the waste,
compacting the waste, and covering  the waste with soil.  The trench and ramp methods are not
commonly used, and are not the preferred methods when liners  and leachate collection systems  are
utilized or required by law.   The area fill method involves placing waste on the ground surface or
landfill liner, spreading it in layers,  and compacting with heavy equipment.  A daily soil cover is
spread over the compacted waste.  The  trench method entails  excavating trenches designed to receive
a day's worth of waste.  The soil from the excavation is often used for cover material and wind
breaks.  The ramp method is typically employed on sloping land, where waste is spread and
compacted similar to the area method, however, the cover material obtained is generally from the
front of the working face of the filling operation.

       Modern landfill design often incorporates liners constructed of soil (e.g., recompacted clay),
or synthetics (e.g., high density polyethylene),  or both to provide an impermeable barrier to leachate
(i.e., water that has passed through the  landfill) and gas migration from the landfill.


7/93                                 Solid Waste Disposal                                2.7-1

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2.7.3 Control Technology1'2'6

       The Resource Conservation and Recovery Act (RCRA) Subtitle D regulations promulgated on
October 9, 1991 require that the concentration of methane generated by MSW landfills not exceed
25 percent of the lower explosive limit (LEL) in on-site structures, such as scale houses, or the LEL
at the facility property boundary.

       Proposed New Source Performance Standards (NSPS) and emission guidelines for air
emissions from MSW landfills for certain new and existing landfills were published in the Federal
Register on May 30, 1991. The regulation, if adopted, will require that Best Demonstrated
Technology (BDT) be used to reduce MSW landfill emissions from affected new and existing MSW
landfills emitting greater than or equal to 150 Mg/yr (165 tons/yr)  of non-methanogenic organic
compounds (NMOCs). The MSW landfills that would be affected by the proposed NSPS would be
each new MSW landfill, and each existing MSW landfill that has accepted waste since November 8,
1987, or that has capacity available for future use.  Control systems would require: (1) a well-
designed and well-operated gas collection system, and (2) a control device capable of reducing
NMOCs in the collected gas by 98 weight-percent.

       Landfill gas collection systems are either active or passive  systems.  Active collection systems
provide a pressure gradient in order to extract landfill by use of mechanical blowers or compressors.
Passive systems allow the natural pressure gradient created by the increase in landfill pressure from
landfill gas generation to mobilize the gas for collection.

       Landfill gas control and treatment options include (1) combustion of the landfill gas, and (2)
purification of the landfill gas.  Combustion techniques include techniques that do not recover energy
(i.e., flares and thermal incinerators), and techniques that recover energy (i.e., gas turbines and
internal combustion engines)  and generate electricity from the combustion of the landfill gas. Boilers
can also be employed to recover energy from landfill gas in the form of steam.  Flares involve an
open combustion process that requires oxygen for combustion,  and can be open or enclosed.  Thermal
incinerators heat an organic chemical to a high enough temperature in the presence of sufficient
oxygen to oxidize the chemical to carbon dioxide (CO2)  and water. Purification techniques can also
be used to process raw landfill gas to pipeline quality natural gas by using adsorption, absorption, and
membranes.

2.7.4 Emissions2'7

        Methane (CH^ and CO2 are the primary constituents of landfill gas, and are produced by
microorganisms within the landfill under anaerobic conditions.  Transformations of  CH4 and CO2 are
mediated by microbial populations that are adapted to the cycling of materials in anaerobic
environments. Landfill gas generation,  including rate and composition, proceeds through four phases.
The first phase is aerobic [e.g., with oxygen (O^ available] and the primary gas produced is CO2.
The second phase is characterized by O2 depletion, resulting in an anaerobic environment, where
 large amounts of CO2 and some hydrogen (H2) are produced.   In the third phase, CH4 production
 begins, with an accompanying reduction in the amount of CO2 produced.  Nitrogen (N^ content is
 initially high  in landfill gas in the first phase, and declines sharply as the landfill proceeds through the
 second and third phases.  In the fourth phase, gas production of CH4, CO2, and N2 becomes fairly
 steady.  The total time and phase duration of gas generation varies with landfill conditions (e.g.,
 waste composition, design management, and anaerobic state).
 2.7-2                               EMISSION FACTORS                                 7/93

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       The rate of emissions from a landfill is governed by gas production and transport
mechanisms. Production mechanisms involve the production of the emission constituent in its vapor
phase through vaporization, biological decomposition, or chemical reaction.  Transport mechanisms
involve the transportation of a volatile constituent in its vapor phase to the surface of the landfill,
through the air boundary layer above the landfill, and into the atmosphere. The three major transport
mechanisms that enable transport of a volatile constituent hi its vapor phase are diffusion, convection,
and displacement.

2.7.4.1 Uncontrolled Emissions  To estimate uncontrolled emissions of the various compounds
present in landfill gas, total landfill gas emissions must first be estimated.  Uncontrolled CH4
emissions may be estimated for individual  landfills by using a theoretical first-order kinetic model of
methane production developed by the EPA.2 This model is known as the Landfill Air Emissions
Estimation model,  and can be accessed from the EPA's Control Technology Center bulletin board.
The Landfill Air Emissions Estimation model equation is as follows:

              QCH4  =L0 R(e-kc_e-kt)

       where:

           QCH4   =  Methane generation rate at time t, m3/yr;
            L0     =  Methane generation potential, m3 CH4/Mg refuse;
               R  =  Average annual refuse acceptance rate during active life, Mg/yr;
               e   =  Base log, unitless;
               k   =  Methane generation rate constant, yr"1;
               c   =  Time since landfill closure, yrs (c = 0 for active landfills); and
               t   =  Time since the initial refuse placement, yrs.

       Site-specific landfill information is generally available for variables R, c, and t.  When refuse
acceptance rate information is scant or unknown, R can be determined by dividing the refuse in place
by the age of the landfill.  Also, nondegradable refuse should be subtracted from the mass of
acceptance rate to prevent overestimation of CH4 generation.  The average annual acceptance  rate
should only be estimated by this method when there is inadequate information available on the actual
average acceptance rate.

       Values for variables L0  and k must be estimated.  Estimation  of the potential CH4 generation
capacity of refuse (L0) is generally treated  as a function of the moisture and organic content of the
refuse. Estimation of the CH4 generation constant (k) is a function of a variety of factors, including
moisture,  pH, temperature, and other environmental factors, and landfill operating conditions.
Specific CH4 generation constants can be computed by use of the EPA Method 2E.

       The Landfill Air Emission Estimation model uses the proposed  regulatory default values for
L0 and k. However, the defaults were developed for  regulatory compliance purposes.  As a result, it
contains conservative L0 and k default values in order to protect human health, to encompass a wide
range of landfills, and to encourage the use of site-specific data. Therefore, different L0 and k values
may be appropriate in estimating landfill emissions for particular landfills and for use in an emissions
inventory.
7/93                                  Solid Waste Disposal                                 2.7-3

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       A k value of 0.04/yr is appropriate for areas with normal or above normal precipitation rather
than the default value of 0.02/yr. For landfills with drier waste, a k value of 0.02/yr is more
appropriate. An L0 value of 125 m3/Mg (4,411 ft'/Mg) refuse is appropriate for most landfills.  It
should be emphasized that in order to comply with the NSPS, the model defaults for k and L0 must
be applied as specified in the final rule.

       Landfill gas consists of approximately 50 percent by volume CO2, 50 percent CH4, and trace
amounts of NMOCs when gas generation reaches steady state conditions.  Therefore, the estimate
derived for CH4 generation using the Landfill Air Emissions Estimation model can also be used to
represent CO2 generation. Addition of the CH4 and CO2 emissions will yield an estimate of total
landfill gas emissions.  If site specific information is available to suggest that the CH4 content of
landfill gas is not 50 percent, then the site specific information should be used, and the CO2 emission
estimate should be adjusted accordingly.

       Emissions of NMOCs result from NMOCs contained in the landfilled waste, and from their
creation from biological processes and chemical reactions within the landfill cell.  The Landfill Air
Emissions Estimation model contains a proposed regulatory default value for total NMOCs of
8000 ppmv, expressed as hexane. However, there is a wide range for total NMOC  values from
landfills. The proposed regulatory default value for NMOC concentration was developed for
regulatory compliance and to provide the most cost-effective default values on a national basis. For
emissions inventory purposes, it would be preferable that site-specific information be taken into
account when determining the total NMOC concentration.  A value of 4,400 ppmv as hexane is
preferable for landfills known to have co-disposal of MSW and commercial/industrial organic wastes.
If the landfill is known to contain only MSW or have very little organic commercial/industrial wastes,
then a total NMOC value of 1,170 ppmv as hexane should be used.

       If a site-specific total NMOC concentration is available (i.e.,  as measured by EPA Reference
Method 25C), it must be corrected for air infiltration into  the collected landfill gas before it can be
combined with the estimated landfill gas emissions to estimate total NMOC emissions.  The total
NMOC concentration is adjusted for air infiltration by assuming that CO2 and CH4  are the primary
(100 percent) constituents of landfill gas, and the following equation is used:

                              as hexane)  (1 x 106)   =   CNMOC PPmv ^ hexane
                              	          (corrected for air
                 CcO2 (PPmv) + CCH4 (PPmv)                 infiltration)
        where:
                       = Tota* NMOC concentration in landfill gas, ppmv as hexane;
                CCO2  = CO2 concentration in landfill gas, ppmv;

                 CCH  = CH4 Concentration in landfill gas, ppmv;  and
              1 x 106   = Constant used to correct NMOC concentration to units of ppmv.
 Values for CCQ  and CQJ  can t>e usually be found in the source test report for the particular
 landfill along with the total NMOC concentration data.
 2.7-4
EMISSION FACTORS
                                                                                          7/93

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       To estimate total NMOC emissions, the following equation should be used:
                           QNMOC = 2 QcH4 * CNMOC/CI x io6)
       where:
            QNMOC  = NMOC emission rate, m3/yr;
               QCH4   CH4 generation rate, m3/yr (from the Landfill Air Emissions Esthnation
                         model);
                      = Total NMOC concentration in landfill gas, ppmv as hexane; and
                   2  = Multiplication factor (assumes that approximately 50 percent of landfill
                         gas is
The mass emissions per year of total NMOCs (as hexane) can be estimated by the following equation:

                             A/i-o         f  1050.2 "1
                             MNMOC - VNMOC *    (273 +T)

where:
             MNMOC = NMOC (total) mass emissions (Mg/yr);
             QNMOC =  NMOC emission rate (m3/yr); and
                   T=  Temperature of landfill gas (C).

This equation assumes that the operating pressure of the system is approximately 1 atmosphere, and
represents total NMOC based on the molecular weight of hexane.  If the temperature of the landfill
gas is not known, a temperature of 25C (75F) is recommended.

       Uncontrolled emission concentrations of individual NMOCs along with some inorganic
compounds are presented in Table 2.7-1. These individual NMOC and inorganic concentrations have
already been corrected for ah* infiltration and can be used as input parameters in the Landfill Air
Emission Estimation model for estimating individual NMOC emissions from landfills when site-
specific data are not available. An analysis of the data based on the co-disposal history (with
hazardous wastes) of the individual landfills from which the concentration data were derived indicates
that for benzene and toluene, there is a difference in the uncontrolled concentration. Table 2.7-2
presents the corrected concentrations for benzene and toluene to use based on the site's co-disposal
history.

       Similar to the estimation of total NMOC emissions, individual NMOC emissions can be
estimated by the following equation:

                          QNMOC = 2 QcH4 * cNMoc/(i x io6)

       where:
            QNMOC  = NMOC emission rate, m3/yr;
               QCH4  = CH4 generation rate,  m3/yr  (from the Landfill Air Emission Estimation
                         model);
                      = NMOC concentration hi landfill gas,  ppmv; and
                   2  = Multiplication factor (assumes that approximately 50 percent of landfill
                         gas is
7/93                                Solid Waste Disposal                                2.7-5

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        Table 2.7-1. UNCONTROLLED LANDFILL GAS CONCENTRATIONS*




                             (SCC 50200602)
Compound
1,1,1-Trichloroethane (methyl chloroform)*
1 , 1 ,2,2-Tetrachloroethane*
1 , 1 ,2-Trichloroethane*
1,1-Dichloroethane (ethylidene dichloride)*
1,1-Dichloroethene (vinylidene chloride)*
1,2-Dichloroethane (ethylene dichloride)*
1,2-Dichloropropane (propylene dichloride)*
Acetone
Acrylonitrile*
Bromodichloromethane
Butane
Carbon disulfide*
Carbon monoxide
Carbon tetrachloride*
Carbonyl sulfide*
Chlorobenzene*
Chlorodiflouromethane
Chloroethane (ethyl chloride)*
Chloroform*
Chloromethane
Dichlorodifluoromethane
Dichlorofluoromethane
Dichloromethane (methylene chloride)*
Dimethyl sulfide
Ethane
Ethyl mercaptan
Ethylbenzene*
Fluorotrichloromethane
Hexane*
Hydrogen sulfide
Methyl ethyl ketone
Methyl isobutyl ketone*
Methyl mercaptan
Median
ppmv
0.27
0.20
0.10
2.07
0.22
0.79
0.17
8.89
7.56
2.06
3.83
1.00
309.32
0.00
24.00
0.20
1.22
1.17
0.27
1.14
12.17
4.37
14.30
76.16
227.65
0.86
4.49
0.73
6.64
36.51
6.13
1.22
10.43
Emission
Factor
Rating
B
C
E
B
B
B
C
B
D
C
B
E
C
B
E
D
B
B
B
B
B
C
C
B
D
C
B
B
B
B
B
B
B
2.7-6
EMISSION FACTORS
7/93

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                                  Table 2.7-1. (Cont).
Compound
NMOC (as hexane)
Pentane
Perchloroethylene (tetrachloroethene) *
Propane
Trichloroethene*
t- 1 ,2-dichloroethene
Vinyl chloride*
Xylene*
Median
ppmv
1170
3.32
3.44
10.60
2.08
4.01
7.37
12.25
Emission
Factor
Rating
D
B
B
B
B
B
B
B
            a References 9-35.  SCC = Source Classification Code
            * =  Hazardous Air Pollutants listed in Title I of the 1990 Clean Air
                 Act Amendments.
      Table 2.7-2.    UNCONTROLLED CONCENTRATIONS OF BENZENE AND TOLUENE
                     BASED ON HAZARDOUS WASTE DISPOSAL HISTORY4

                                    (SCC 50200602)



Benzene*
Co-disposal
Unknown
No co-disposal
Toluene* 
Co-disposal
Unknown
No co-disposal

Concentration
ppmv

24.99
2.25
0.37

102.62
31.63
8.93
Emission
Factor
Rating

D
B
D

D
B
D
               a References 9-35. SCC = Source Classification Code.
               * =  Hazardous Air Pollutants listed in Title I of the 1990
                    Clean Air Act Amendments.
       The mass emissions per year of each individual landfill gas compound can be estimated by the
following equation:
7/93
Solid Waste Disposal
2.7-7

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                     QNMOC   *	(Molecular weight of compound)	
                                      (8.205xl(T5 m3-atm/mol-K) (1000 g)(273 + T)
where:

                      =   Individual NMOC mass emissions (Mg/yr);
                      =   NMOC emission rate (m3/yr); and
                    T =  Temperature of landfill gas fC).

2.7,4.2 Controlled Emissions  Emissions from landfills are typically controlled by installing a gas
collection system, and destroying the collected gas through the use of internal combustion engines,
flares, or turbines. Gas collection systems are not 100 percent efficient in collecting landfill gas, so
emissions of CH4 and NMOCs at a landfill with a gas recovery system still occur.  To estimate
controlled emissions of CH4, NMOCs, and other constituents in landfill gas,  the collection efficiency
of the system must first be estimated. Reported collection efficiencies typically range  from 60 to
85 percent, with an average of 75 percent most commonly assumed. If site-specific collection
efficiencies are available, they should be used instead of the 75 percent average.

       Uncollected CH4, CO2, and NMOCs can be calculated with the following equation:

                                   .  _ Collection Efficiency
                                     ~          100

       Controlled emission estimates also need to take into account the control efficiency of the
control device. Control efficiencies of CH4 and NMOCs with differing control devices are presented
in Table 2.7-3. Emissions from the control devices need to be added to the uncollected emissions to
estimate total controlled emissions.

       Emission factors for secondary compounds (CO2, CO, and  NOX) exiting the control device
are presented in Tables 2.7-4 and 2.7-5.

       The reader is referred to Sections 11.2-1 (Unpaved Roads, SCC 50100401), and 11-2.4
(Heavy Construction Operations) of Volume I,  and Section H-7 (Heavy-duty Construction Equipment)
of Volume II, of the AP-42 document for determination  of associated dust and exhaust emissions from
these emission sources at MSW landfills.
2.7-8                                EMISSION FACTORS                                7/93

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      Table 2.7-3.  CONTROL EFFICIENCIES FOR LANDFILL GAS CONSTITUENTS*
Control
Device
1C Engine
(no SCC)






Turbine
(no SCC)



Flare
(50200601)
(50300601)










Compound
Benzene
Trichloroethylene
Perchloroethylene
NMOCs (as hexane)
1,1,1 -Trichloroethane
Chloroform
Toluene
Carbon tetrachloride
Perchloroethylene
Toluene
1,1,1 -Trichloroethane
Trichloroethylene
Vinyl chloride
Chloroform
Perchloroethylene
Toluene
Xylene
1,1,1 -Trichloroethane
1 ,2-Dichloroethane
Benzene
Carbon tetrachloride
Methylene chloride
NMOCs (as hexane)
Trichloroethylene
t-1 ,2-dichloroethene
Vinyl chloride
Average
Control
Efficiency
83.83
89.60
89.41
79.75
92.47
99.00
79.71
98.50
99.97
99.91
95.18
99.92
98.00
93.04
85.02
93.55
99.28
85.24
88.68
89.50
95.05
97.60
83.16
96.20
99.59
97.61
Emission
Factor
Rating
E
E
E
E
E
E
E
E
E
E
E
E
E
D
C
C
E
C
E
C
D
E
E
C
E
C
          a References 9-35. Source Classification Codes in parenthesis.
7/93
Solid Waste Disposal
2.7-9

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     Table 2.7-4. (Metric Units) EMISSION RATES FOR SECONDARY COMPOUNDS
                         EXITING CONTROL DEVICES*
Average Rate,
kg/hr/dscmm
Control Device Compound Uncontrolled Methane
Flare
(50200601)
(50300601)




ICE
(no SCC)

Turbine
(no SCC)



Carbon dioxide
Carbon monoxide
Nitrogen dioxide
Methane
Sulfur dioxide

Carbon dioxide
Nitrogen dioxide

Carbon dioxide
Carbon monoxide


135.4
0.80
0.11
1.60
0.03

182.37
0.80

49.36
0.32
Emission
Factor
Rating


B
B
C
C
E

E
E

E
E
      * Source Classification Codes in parenthesis.
      Table 2.7-5. (English Units) EMISSION RATES FOR SECONDARY COMPOUNDS
                          EXITING CONTROL DEVICES*
Control Device
Flare
(50200601)
(50300601)




1C Engine
(no SCC)

Turbine
(no SCC)

Compound


Carbon dioxide
Carbon monoxide
Nitrogen dioxide
Methane
Sulfur dioxide

Carbon dioxide
Nitrogen dioxide

Carbon dioxide
Carbon monoxide
Average Rate,
Ib/hr/dscftn
Uncontrolled Methane


8.450
0.050
0.007
0.105
0.002

11.380
0.050

3.080
0.021
Emission
Factor
Rating


B
B
C
C
E

E
E

D
E
       * Source Classification Codes in parenthesis.
2.7-10
EMISSION FACTORS
7/93

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References for Section 2.7

1.     Criteria for Municipal Solid Waste Landfills,  40 CFR Part 258, Volume 56, No.  196.
       October 9, 1991.

2.     Air Emissions from Municipal Solid Waste Landfills - Background Information for Proposed
       Standards and Guidelines.  Office of Air Quality Planning and Standards, U. S.
       Environmental Protection Agency.  Research Triangle Park, North Carolina.
       EPA-450/3-90-011a. Chapters 3 and 4.  March 1991.

3.     Characterization of Municipal Solid Waste in the United States:  1992 Update. Office of
       Solid Waste,  U.  S. Environmental Protection Agency, Washington, D.C.
       EPA-530-R-92-019.  NTIS No. PB92-207-166. July 1992.

4.     Eastern Research Group, Inc., List of Municipal Solid Waste Landfills. Prepared for the
       U.S. Environmental Protection Agency, Office of Solid Waste,  Municipal and Industrial
       Solid Waste Division, Washington, D.C. September 1992.

5.     Suggested Control Measures for Landfill Gas Emissions. State of California Air Resources
       Board, Stationary Source Division, Sacramento, California.  August 1990.

6.     Standards of Performance for New Stationary Sources and Guidelines for Control of Existing
       Sources:  Municipal Solid Waste Landfills; Proposed Rule, Guideline,  and Notice of Public
       Hearing.   40  CFR Parts 51, 52, and 60.  Vol.  56, No.  104. May 30, 1991.

7.     S.W. Zison, Landfill Gas Production Curves.  "Myth Versus Reality." Pacific Energy, City
       of Commerce, California.  [Unpublished]

8.     R.L. Peer, et al., Development of an Empirical Model of Methane Emissions from Landfills.
       U.S. Environmental Protection Agency, Office of Research and Development.
       EPA-600/R-92-037.  1992.

9.     A.R.  Chowdhury, Emissions from a Landfill Gas-Fired Turbine/Generator Set. Source Test
       Report C-84-33.  Los Angeles County Sanitation District, South Coast Air Quality
       Management District, June 28, 1984.

10.    Engineering-Science, Inc., Report of Stack Testing at County Sanitation District Los Angeles
       Puente Hills Landfill.  Los Angeles County Sanitation District, August 15, 1984.

11.    J.R. Manker,  Vinyl Chloride (and Other Organic Compounds) Content of Landfill Gas Vented
       to an Inoperative Flare, Source Test Report 84-496. David Price Company, South Coast Air
       Quality Management District, November 30, 1984.

12.    S. Mainoff, Landfill Gas Composition,  Source  Test Report 85-102.  Bradley Pit Landfill,
       South Coast Air  Quality Management District,  May 22, 1985.
7/93                                 Solid Waste Disposal                               2.7-11

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13.    J. Littman, Vinyl Chloride and Other Selected Compounds Present in A Landfill Gas
       Collection System Prior to and after Flaring, Source Test Report 85-369. Los Angeles
       County Sanitation District, South Coast Air Quality Management District, October 9, 1985.

14.    W. A. Nakagawa, Emissions from a Landfill Exhausting Through a Flare System, Source Test
       Report 85-461.  Operating Industries, South Coast Air Quality Management District,
       October 14, 1985.

15.    S. Marinoff, Emissions from a Landfill Gas Collection System, Source Test Report 85-511.
       Sheldon Street Landfill, South Coast Air Quality Management District, December 9,  1985.

16.    W.A. Nakagawa, Vinyl Chloride and Other Selected Compounds Present in a Landfill Gas
       Collection System Prior to and after Flaring, Source Test Report 85-592. Mission Canyon
       Landfill, Los Angeles County Sanitation District, South Coast Air Quality Management
       District, January 16,  1986.

17.    California Air Resources Board, Evaluation Test on a Landfill Gas-Fired Flare at the BBK
       Landfill Facility. West Covina,  California, ARB-SS-87-09, July  1986.

18.    S. Marinoff, Gaseous Composition from a Landfill Gas Collection System and Flare,  Source
       Test Report 86-0342.  Syufy Enterprises,  South Coast Air Quality Management District,
       August 21, 1986.

19.    Analytical Laboratory Report for Source Test. Azusa Land Reclamation, June 30, 1983,
       South Coast Air Quality Management District.

20.    J.R. Manker, Source Test Report C-84-202.  Bradley Pit Landfill, South Coast Air Quality
       Management District, May 25,1984.

21.    S. Marinoff, Source Test Report 84:315.  Puente Hills Landfill, South Coast Air Quality
       Management District, February 6, 1985.

22.    P.P. Chavez, Source Test Report 84-596.  Bradley Pit Landfill, South Coast Air Quality
       Management District, March 11, 1985.

23.    S. Marinoff, Source Test Report 84-373.  Los Angeles By-Products, South Coast air  Quality
       Management District, March 27, 1985.

24.    J. Littman, Source Test Report 85-403..  Palos Verdes Landfill, South Coast Air Quality
       Management District, September 25,  1985.

25.    S. Marinoff, Source Test Report 86-0234. Pacific Lighting Energy Systems, South Coast Air
       Quality Management District, July 16, 1986.

26.    South Coast Air Quality Management District, Evaluation Test on a Landfill Gas-Fired Flare
       at the Los Angeles County Sanitation District's Puente Hills Landfill Facility.
        [ARB/SS-87-06], Sacramento, California, July 1986.
 2.7-12                             EMISSION FACTORS                               7/93

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27.    D.L. Campbell, et al., Analysis of Factors Affecting Methane Gas Recovery from Six
       Landfills.  Air and Energy Engineering Research Laboratory, U.S. Environmental Protection
       Agency, Research Triangle Park, North Carolina.  EPA-600/2-91-055. September 1991.

28.    Browning-Ferris Industries, Source Test Report.  Lyon Development Landfill, August 21,
       1990.

29.    X.V. Via, Source Test Report.  Browning-Ferris Industries. Azusa Landfill.

30.    M. Nourot, Gaseous Composition from a Landfill Gas Collection System and Flare Outlet.
       Laidlaw Gas Recovery Systems, to J.R. Farmer, OAQPSrESD, December 8, 1987.

31.    D.A. Stringham and W.H. Wolfe, Waste Management of North America, Inc., to J. R.
       Farmer, OAQPS:ESD, January 29, 1988, Response to Section 114 questionnaire.

32.    V. Espinosa, Source Test Report 87-0318.  Los Angeles County Sanitation District Calabasas
       Landfill, South Coast Air  Quality Management District, December 16, 1987.

33.    C.S. Bhatt, Source Test Report 87-0329. Los Angeles County Sanitation District, Scholl
       Canyon Landfill, South Coast Air Quality Management District, December 4, 1987.

34.    V. Espinosa, Source Test Report 87-0391.  Puente Hills Landfill, South Coast Air Quality
       Management District, February 5, 1988.

35.    V. Espinosa, Source Test Report 87-0376.  Palos Verdes Landfill, South Coast Air Quality
       Management District, February 9, 1987.
7/93                                Solid Waste Disposal                              2.7-13

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3.1 STATIONARY GAS TURBINES FOR ELECTRICITY GENERATION

3.1.1  General

       Stationary gas turbines are applied in electric power generators, in gas pipeline pump and
compressor drives, and in various process industries. Gas turbines (greater than 3 MW(e)) are used in
electrical generation for continuous, peaking, or standby power. The primary fuels used are natural
gas and distillate (No. 2) fuel oil, although residual fuel oil is used in a few applications.

3.1.2  Emissions

       Emission control technologies for gas turbines have advanced to a point where all new and
most existing units are complying with various levels of specified emission limits.  For these sources,
the emission factors become an operational  specification rattier than  a parameter to be quantified by
testing. This section treats uncontrolled (i.e., baseline) emissions and controlled emissions with specific
control technologies.

       The emission factors presented are for simple cycle gas turbines.  These factors also apply to
cogeneration/combined cycle gas turbines. In general, if the heat recovery steam generator (HRSG) is
not supplementary fired, the simple cycle input specific emission factors (Ib/MMBtu) will apply to
cogeneration/combined cycle systems. The output specific emissions (g/hp-hr) will decrease  according
to the ratio of simple cycle to  combined cycle power output  If the  HRSG is supplementary  fired, the
emissions and fuel usage must be considered to  estimate stack emissions. Nitrogen Oxide (NOX)
emissions from regenerative cycle turbines (which account for only a small percentage of turbines in
use) are greater than emissions from simple cycle turbines because of the increased combustion air
temperature entering the turbine. The carbon monoxide (CO) and hydrocarbon (HC) emissions may be
lower with the regenerative system for a comparable design. More power is produced from the same
energy input, so the input specific emissions factor will be affected by changes in emissions, while
output specific emissions will  reflect the increased power output.

       Water/steam injection  is the most prevalent NOX control for  cogeneration/combined cycle gas
turbines. The water or steam is  injected with the air and fuel into the turbine combustion can in order
to lower the peak temperatures which, in turn, decreases the thermal NOX produced. The lower
average temperature within the combustor can may produce higher levels of CO and HC  as a result of
incomplete combustion.

       Selective catalytic reduction (SCR) is a post-combustion control which selectively reduces NOX
by reaction of ammonia and NO on a catalytic surface to form N2 and H2O. Although SCR systems
can be used alone, all  existing applications of SCR have been used in conjunction with water/steam
injection controls. For optimum SCR operation, the flue gas must be within a temperature range of
600-800F with the precise limits dependent on  the catalyst. Some SCR systems also utilize a CO
catalyst to give simultaneous catalytic CO/NOX control.

       Advanced combustor can designs are currently being phased into production turbines. These
dry techniques decrease turbine emissions by modifying the combustion mixing, air staging, and flame
stabilization to allow operation at a much leaner air/fuel ratio relative to normal operation. Operating
at leaner conditions will lower peak temperatures within the primary flame zone of the combustor.
The lower temperatures may also increase CO and HC emissions.

7/93                         Stationary Internal Combustion  Sources                        3.1-1

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        With the proliferation and advancement of NOX control technologies for gas turbines during
the past 15 years, the emission factors for the installed gas turbine population are quite different than
uncontrolled turbines.  However, uncontrolled turbine emissions have not changed significantly.
Therefore a careful review of specific turbine details should be performed before applying uncontrolled
emission factors. Today most gas turbines are controlled to meet local, state, and/or federal
regulations.

        The average gaseous emission factors for uncontrolled gas turbines  (firing natural gas and fuel
oil) are presented in Tables 3.1-1 and 3.1-2.  There is some variation hi emissions over the population
of large uncontrolled gas turbines because of the diversity of engine designs and models. Tables 3.1-3
and 3.1-4 present emission factors for gas turbines controlled for NOX using water injection, steam
injection or SCR. Tables 3.1-5 and 3.1-6 present emission factors for large distillate oil-fired turbines
controlled for NOX using water injection.

        Gas turbines firing distillate or residual oil may emit trace metals carried over from the metals
content of the fuel. If the fuel analysis is known, the metals content of the fuel should be used for
flue gas emission factors assuming all metals pass through the turbine. If the fuel analysis is not
known, Table 3.1-7 provides order of magnitude levels of trace elements for turbines fired with
distillate oil.
3.1-2
                                      EMISSION FACTORS
7/93

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                                  TABLE 3.1-1. (ENGLISH UNITS)
                EMISSION FACTORS FOR LARGE UNCONTROLLED GAS TURBINES"
                                     (Source Classification Codes)
Pollutant
Emission
Factor
Rating*
Natural Gas
(SCC 20100201)
[grams/hr-hp]c [Ib/MMBtu]
(power output) (fuel input)
Fuel Oil (i.e. Distillate)
(SCC 20100101)
[grams/hp-hr]c [Ib/MMBtu]
(power output) (fuel input)
NO,
CO
C02a
TOC(as
methane)
SO* (as SO,)"
PM (solids)
PM
(condensables)
PM Sizing %
< .05 microns
< .10 microns
< .15 microns
< .20 microns
< .25 microns
< 1 micron
C 1.6
D .39
B 407
D .087
B 3.41S
E .070
E .082

D
D
D
D
D
D
0.44
.11
112
.024
.948
.0193
.0226

15%
40%
63%
78%
89%
100%
2.54
.174
596
.062
3.67S
.138
.084







.698
.048
164
.017
1.01S
.038
.023

16%
48%
72%
85%
93%
100%
"References 1-8.
b"D" and "E" rated emission factors are due to limited data and/or a lack of documentation of test results,
  may not be suitable for specific facilities or populations and should be used with care.
'Calculated from Ib/MMBtu assuming an average heat rate of 8,000 Btu/hp-hr (x 3.632).
*Based on  100 percent conversion of the fuel carbon to CO2.  CO2 [Ib/MMBtu] = 3.67*C/E,
  where C  = carbon content of fuel by weight (0.7), and E = energy content of fuel, (0.0023  MMBtu/lb).
  The uncontrolled CO2 emission factors are also applicable to controlled gas  turbines.
"All sulfur in the fuel is converted to SO2.  S = percent sulfur in fuel.
7/93
Stationary Internal Combustion Sources
3.1-3

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                                 TABLE 3.1-2.  (METRIC UNITS)
               EMISSION FACTORS FOR LARGE UNCONTROLLED GAS TURBINES"
                                    (Source Classification Codes)
Pollutant
NO,
CO
CO2d
TOC (as methane)
SO, (as SO*)0
PM (solids)
PM (condensables)
PM Sizing %
< .05 microns
< .10 microns
< .15 microns
< .20 microns
< 25 microns
< 1 micron
Emission
factor
Rating1"
C
D
B
D
B
E
E
D
D
D
D
D
D
Natural Gas
(SCC 20100201)
[grams/kW-hr0 [ngfl]
(power output) (fuel input)
2.15 190
.52 46
546 48160
.117 10.32
4.57S 404S
.094 8.30
.11 9.72
15%
40%
63%
78%
89%
100%
Fuel Oil (i.e. Distillate)
(SCC 20100101)
[grams/kW-hr]c [ng/J]
(power output) (fuel input)
3.41 300
.233 20.6
799 70520
.083 7.31
4.92S 434.3S
.185 16.3
.113 9.89
16%
48%
72%
85%
93%
100%
References 1-8.
bHDM and "E" rated emission factors are due to limited data and/or a lack of documentation of test results,
 may not be suitable for specific facilities or populations and should be used with care.
Calculated from ng/J assuming an average heat rate of 11,318 kJ/kW-hr.
dBased on  100 percent conversion of the fuel carbon to CO2.  CO2 Ub/MMBtu] = 3.67*C/E,
 where C  = ratio of carbon in the fuel by weight, and E = energy content of fuel, MMBtu/lb.
 The uncontrolled CO2 emission factors are also applicable to controlled gas turbines.
'All sulfur in the fuel is assumed to be converted to SO2.
3.1-4
                                     EMISSION FACTORS
7/93

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                               TABLE 3.1-3. (ENGLISH UNITS)
           EMISSION FACTORS FOR LARGE GAS-FIRED CONTROLLED GAS TURBINES"
                             (Source Classification Code:  20100201)

                               EMISSION FACTOR RATING: C
Pollutant
Water Injection
(.8 water/fuel ratio)
[grams/hr-hp] [Ib/MMBtu]
(power (fuel
output) input)
Steam Injection
(1.2 water/fuel ratio)
[grams/hr-hp] [Ib/MMBtu]
(power (fuel
output) input)
NOX .50 .14 .44 .12
CO .94 .28 .53 .16
TOC (as methane)
NH3
NMHC
Formaldehyde
Selective
Catalytic
Reduction (with
water injection)
[Ib/MMBtu]
(fuel
input)
.03"
.0084
.014
.0065
.0032
.0027
"References 3, 10 - 15.  All data are averages of a limited number of tests and may not be typical of
 those reductions which can be achieved at a specific location.
""Average of 78 percent reduction of NOX through the SCR catalyst.
7/93
Stationary Internal Combustion Sources
3.1-5

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                               TABLE 3.1-4. (METRIC UNITS)
           EMISSION FACTORS FOR LARGE GAS-FIRED CONTROLLED GAS TURBINES8
                             (Source Classification Code: 20100201)

                               EMISSION FACTOR RATING: C
Pollutant
Water Injection
(0.8 water/fuel ratio)
[grams/kW-hr]
(power output)
NOX .66
CO 1.3
TOC (as methane)
NH3
NMHC
Formaldehyde
[ngfl]
(fuel input)
Steam Injection
(1.2 water/fuel ratio)
[grams/kW-hr]
(power output)
61 .59
120 .71




[ng/T]
(fuel input)
52
69




Selective
Catalytic
Reduction (with
water injection)
[ng/F]
(fuel input)
3.78b
3.61
6.02
2.80
1.38
1.16
References 3,10 - 15. All data are averages of a limited number of tests and may not be typical of
 those reductions which can be achieved at a specific location.
"Average of 78 percent reduction of NOX through the SCR catalyst.
3.1-6
EMISSION FACTORS
7/93

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                TABLE 3.1-5.  (ENGLISH UNITS) EMISSION FACTORS FOR LARGE
                     DISTILLATE OIL-FIRED CONTROLLED GAS TURBINES"
                              (Source Classification Code:  20100101)
Pollutant
NOX
CO
TOC (as methane)
SOx
PM
Emission Factor Rating
Water Injection
(.8 water/fuel ratio)
[grams/hr-hp]b
(power output)
E 1.05
E .067
E .017
B
E .135
[Ib/MMBtu]
(fuel input)
.290
.0192
.0048
C
.0372
"Reference 16.
""Calculated from fuel input assuming an average heat rate of 8,000 Btu/hp-hr (x 3.632).
CA11 sulfur in the fuel is assumed to be converted to SOX.
                TABLE 3.1-6. (METRIC UNITS) EMISSION FACTORS FOR LARGE
                     DISTILLATE OIL-FIRED CONTROLLED GAS TURBINES"
                              (Source Classification Code: 20100101)
Pollutant
NO,
CO
TOC (as methane)
so,
PM
Emission Factor Rating
Water Injection
(.8 water/fuel ratio)
[grams^cW-hr]b
(power output)
E 1.41
E .090
' E .023
B
E .181
[ng#I
(fuel input)
125
8.26
2.06
C
16.00
"Reference 16.
""Calculated from fuel input assuming an average heat rate of 8,000 Btu/hp-hr (x 3.632).
A11 sulfur in the fuel is assumed to be converted to SOX.
7/93
Stationary Internal Combustion Sources
3.1-7

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 TABLE 3.1-7.  TRACE ELEMENT EMISSION FACTORS FOR DISTILLATE OIL-FIRED GAS TURBINES8
                                (Source Classification Code: 20100101)
                                 EMISSION FACTOR RATING:  Eb
  Trace Element
                                       Ib/MMBtu
  Aluminum
  Antimony
  Arsenic
  Barium
  Beryllium
  Boron
  Bromine
  Cadmium
  Calcium
  Chromium
  Cobalt
  Copper
  Iron
  Lead
  Magnesium
  Manganese
  Mercury
  Molybdenum
  Nickel
  Phosphorus
  Potassium
  Selenium
  Silicon
  Sodium
  Tin
  Vanadium
  Zinc
          64
          9.4
          2.1
          8.4
          .14
          28
          1.8
          1.8
          330
          20
          3.9
          578
          256
          25
          100
          145
          .39
          3.6
          526
          127
          185
          2.3
          575
          590
          35
          1.9
          294
 1.5 E-04
 2.2 E-05
 4.9 E-06
 2.0 E-05
 3.3 E-07
 6.5 E-05
 4.2 E-06
 4.2 E-06
 7.7 E-04
 4.7 E-05
 9.1 E-06
 1.3 E-03
 6.0 E-04
 5.8 E-05
 2.3 E-04
 3.4 E-04
 9.1 E-07
 8.4 E-06
 1.2 E-03
 3.0 E-04
4.3 E-04
 5.3 E-06
 1.3 E-03
 1.4 E-03
8.1 E-05
4.4 E-06
6.8 E-04
'Reference 1.
^Emission factor rating of "E" indicates that the data are from a limited data
 set and may not be representative of a specific source or population of sources.
3.1-8
EMISSION FACTORS
               7/93

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REFERENCES FOR SECTION 3.1


1.     Shih, C.C., J.W. Hamersma, and D.G. Ackerman, R.G. Beimer, M.L. Kraft, and M.M.
       Yamada, Emissions Assessment of Conventional Stationary Combustion Systems: Vol. II
       Internal  Combustion Sources. Industrial Environmental Research Laboratory,
       EPA-600/7-79-029c, U.S. Environmental Protection Agency, Research Triangle Park, NC,
       February 1979.

2.     Final Report - Gas Turbine Emission Measurement Program, prepared by General Applied
       Science  Laboratories for Empire State Electric Energy Research Corp., August 1974, GASL
       TR787.

3.     Malte, P.C, S., Bernstein, F. Bahlmann, and J. Doelman, NO. Exhaust Emissions for Gas-Fired
       Turbine  Engines. ASME 90-GT-392, June 1990.

4.     Standards Support and Environmental Impact Statement; Volume 1: Proposed Standards of
       Performance for Stationary Gas Turbines. EPA-450/2-77-017a, September 1977.

5.     Hare, C.T. and K.J. Springer, Exhaust Emissions from Uncontrolled Vehicles and Related
       Equipment using Internal Combustion Engines: Part - 6 Gas Turbines. Electric Utility Power
       Plant, SWRI for EPA report APTD-1495, U.S. Environmental Protection Agency, Research
       Triangle Park, NC, NTIS PB-235751.

6.     Lieferstein, M., Summary of Emissions from Consolidated Edison Gas Turbine, prepared by
       the Department of Air Resources, City of New York, November 5, 1975.

7.     Hurley,  J.F. and S. Hersh, Effect of Smoke and Corrosion Suppressant Additives on Paniculate
       and Gaseous Emissions from Utility Gas Turbine:  prepared by KVB Inc.,  for Electric Power
       Research Institute, EPRI FP-398, March 1977.

8.     Crawford, A.R., E.H.  Mannym M.W. Gregory and W. Bartok, The Effect of Combustion
       Modification on Pollutants and Equipment Performance of Power Generation Equipment." in
       Proceedings of the Stationary Source Combustion Symposium Vol. Ill - Field Testing and
       Surveys. U.S. EPA-600/2-76-152c, NTIS PB-257 146, June 1976.

9.     Carl, D.E., E.S. Obidinski, and C.A.  Jersey, Exhaust Emissions from a 25-MW Gas Turbine
       Firing Heavy and Light Distillate Fuel Oils and Natural Gas, paper presented at the Gas
       Turbine Conference and Products Show, Houston, Texas, March 2-6, 1975.

10.    Shareef, G.S. and D.K. Stone, Evaluation of SCR NO. Controls for Small Natural Gas-Fueled
       Prime Movers - Phase I. prepared by Radian Corp. (DCN No.:  90-209-028-11) for the Gas
       Research Institute, GRI-90/0138, July 1990.

11.    Pease, R.R., SCAQMD Engineering Division Report - Status Report on SCR for Gas Turbines
       South Coast Air Quality Management District, July 1984.
 7/93                        Stationary Internal Combustion Sources                       3.1-9

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 REFERENCES FOR SECTION 3.1 (concluded)

 12.    GEMS Certification and Compliance Testing at Chevron USA. Inc.'s Gaviota Gas Plant
        Report PS-89-1837/Project G569-89, Chevron USA, Inc., Goleta, CA, 93117, June 21, 1989.

 13.    Emission Testing at the Bonneville Pacific Cogeneration Plant. Report PS-92-2702/Project
        7141-92, Bonneville Pacific Corporation, Santa Maria, CA, 95434, March 1992.

 14.    Compliance test report on a production gas-fired 1C engine, ESA, 19770-462, Proctor and
        Gamble, Sacramento,  CA, December 1986.

 15.    Compliance test report on a cogeneration facility, CR 75600-2160, Proctor and Gamble,
        Sacramento, CA, May, 1990.

 16.    Larkin, R. and E.B. Higginbotham, Combustion Modification Controls For Stationary Gas
        Turbines Vol. P.. Utility Unit Field Test EPA 600/7-81-122, U.S. Environmental Protection
        Agency, Research Triangle Park, NC, July 1981.
3.1-10
EMISSION FACTORS
7/93

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3.2 HEAVY DUTY NATURAL GAS FIRED PIPELINE COMPRESSOR ENGINES

3.2.1   General                     ,                                       :

       Engines in the natural gas industry are used primarily to power compressors used for pipeline
transportation, field gathering (collecting gas from wells), underground storage, and gas processing
plant applications, i.e. prime movers. Pipeline engines are concentrated hi the major gas producing
states (such as those along the Gulf Coast) and along the major gas pipelines. Gas turbines emit
considerably smaller amounts of pollutants than do reciprocating engines; however, reciprocating
engines are generally more efficient in their use of fuel.

       Reciprocating engines are separated into three design classes: 2-stroke lean burn, 4-stroke lean
burn and 4-stroke rich burn.  Each of these have design differences which affect both baseline
emissions as well as the potential for emissions control. Two-stroke engines complete  the power cycle
in a single engine revolution compared to two revolutions for 4-stroke engines. With the two-stroke
engine, the fuel/air charge is injected with the piston near the bottom of the power stroke. The valves
are all covered or closed and the piston moves to the top of the cylinder compressing the charge.
Following ignition and combustion, the power stroke starts with he downward movement of the piston.
Exhaust ports or valves are then uncovered to remove the combustion products, and a new fuel/air
charge is ingested. Two stroke  engines may be turbocharged using an exhaust powered turbine to
pressurize the charge for injection into the cylinder. Non-turbocharged engines may  be either blower
scavenged or piston scavenged to improve removal of combustion products.

       Four stroke engines use a separate engine revolution for the intake/compression stroke and the
power/exhaust stroke. These engines may be either naturally aspirated, using the suction from the
piston to entrain the air charge,  or turbocharged, using a turbine to pressurize the charge.
Turbocharged units produce  a higher power output for a given engine displacement, whereas naturally
aspirated units have lower initial cost and maintenance. Rich burn engines operate near the  fuel-air
stoichiometric limit with exhaust excess oxygen levels less than 4 percent. Lean burn engines may
operate up to the lean flame extinction limit, with exhaust oxygen levels of 12 percent  or greater.
Pipeline population statistics show a nearly equal installed capacity of turbines and reciprocating
engines.  For reciprocating engines, two stroke designs contribute  approximately two-thirds of installed
capacity.

3.2.2   Emissions and Controls

       The primary pollutant of concern is NOX, which readily forms in the high temperature,
pressure, and excess air environment found in natural gas fired compressor engines.  Lesser  amounts
of carbon monoxide and hydrocarbons are emitted, although for each unit of natural  gas burned,
compressor engines (particularly reciprocating engines) emit significantly more of these pollutants than
do external combustion boilers.  Sulfur oxides emissions are proportional to the sulfur content of the
fuel and will usually be quite low because of the negligible sulfur content of most pipeline gas. This
section will also discuss the  major variables affecting NOX emissions and the various control
technologies that will reduce uncontrolled NOX emissions.

       The major variables  affecting NOX emissions from compressor engines include  the air fuel
ratio, engine load (defined as the ratio of the operating horsepower to the rated horsepower), intake
(manifold) air temperature and absolute humidity,  hi general, NOX emissions increase with increasing

7/93                          Stationary Internal Combustion Sources                         3.2-1

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 load and intake air temperature and decrease with increasing absolute humidity and air fuel ratio. (The
 latter already being, in most compressor engines, on the "lean" side of that air fuel ratio at which
 maximum NOX formation occurs).  Quantitative estimates of the effects of these variables are presented
 in Reference 10.

        Because NOX is the primary pollutant of significance emitted from pipeline compressor
 engines, control measures to date have been directed mainly at limiting NOX emissions.  Reference 11
 summarizes control techniques and emission reduction efficiencies. For gas turbines, the early control
 applications used water or steam injection. New applications of dry low NOX combustor can designs
 and selective catalytic reduction are appearing.  Water injection has achieved reductions of 70 to 80
 percent with utility gas turbines. Efficiency penalties of 2 to 3 percent are typical due to the added
 heat load of the water.  Turbine power outputs typically increase, however. Steam injection may also
 be used, but the resulting NOX reductions may not be as great as with water injection, and it has the
 added disadvantage that a supply of steam must be readily available.  Water injection has not been
 applied to pipeline compressor engines because of the lack of water availability.

        The efficiency penalty and operational impacts associated with water injection have led
 manufacturers to develop dry low NOX combustor can designs based on lean burn and/or staging to
 suppress NOX formation. These are entering the  market in the early 1990's.  Stringent gas turbine NOX
 limits have been achieved in California in the late 1980's with selective  catalytic reduction.  This is an
 ammonia based post-combustion technology which can achieve in excess of 80 percent NOX
 reductions.  Water or  steam injection is frequently used in combination with selective catalytic
 reduction (SCR) to minimize ammonia costs.

        For reciprocating engines, both combustion controls and post-combustion catalytic reduction
 have been developed.  Controlled rich bum engines have mostly been equipped with non-selective
 catalytic reduction which uses unreacted hydrocarbons and CO to reduce NOX by 80  to 90 percent.
 Some rich-burn engines can be equipped with prestratified charge which reduces the  peak flame
 temperature in the NOX forming regions.  Lean burn engines have mostly met NOX reduction
 requirements with lean combustion controls using torch ignition or chamber redesign to enhance flame
 stability. NOX reductions of 70 to 80 percent are typical for numerous engines with retrofit or new
 unit controls. Lean bum engines may also be controlled with selective catalytic reductions (SCR), but
 the operational problems associated with engine control under low NOX operation have been a
 deterrent

       Emission factors for natural gas fired pipeline compressor engines are presented in Tables 3.2-
 1 and 3.2-2 for baseline operation and in 3.2-4 through 3.2-7 for controlled operation. The factors for
 controlled operation are taken from a single source test.  Table 3.2-3 lists non-criteria (organic)
 emission factors.
3.2-2                               EMISSION FACTORS                                7/93

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    TABLE 3.2-3. (ENGLISH AND METRIC UNITS) NON-CRITERIA EMISSION FACTORS
                FOR UNCONTROLLED NATURAL GAS PRIME MOVERS"
                          (Source Classification Code: 20200202)
                            EMISSION FACTOR RATING: Eb
 Pollutant
2-Cycle Lean Bum
                                              [grams/kW-hr]
                  tng/J]
 Formaldehyde                                     1.78                    140
 Benzene                                         2.2E-3                  0.17
 Toluene                                         2.2E-3                  0.17
 Ethylbenzene                                     1.1E-3                  0.086
 Xylenes	3.3E-3                  0.26
"Reference 1.
bAll emission factor qualities are "E" are due to a very limited data set  "E" rated emission
 factors may not be applicable to specific facilities or populations.
7/93                       Stationary Internal Combustion Sources                      3.2-5

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Stationary Internal Combustion Sources
3.2-7

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-------
References for Section 3.2

1.     Engines, Turbines, and Compressors Directory, American Gas Association, Catalog #XF0488.

2.     Martin, N.L. and R.H. Thring, Computer Database of Emissions Data for Stationary
       Reciprocating Natural Gas Engines and Gas Turbines in use by the Gas Pipeline Transmission
       Industry Users Manual (Electronic Database Included), prepared by SoufliWest Research
       Institute for the Gas Research Institute, GRI-89/0041.

3.     Air Pollution Source Testing for California AB2588 on an Oil Platform Operated by Chevron
       USA. Inc. Platform Hope, California. Chevron USA, Lie'., Ventura, CA, August 29, 1990.

4.     Air Pollution Source Testing for California AB2588 of Engines at the Chevron USA, Inc.
       Carpinteria Facility, Chevron USA, Inc., Ventura, CA, August 30, 1990.

5.     Pooled Source Emission Test Report:  Gas Fired 1C Engines in Santa Barbara County. ARCO,
       Bakersfield, CA, July, 1990.

6.     Castaldini, C., Environmental Assessment of NCX Control on a Spark-Ignited Large Bore
       Reciprocating Internal Combustion Engine, U.S. Environmental Protection Agency, Research
       Triangle Park, NC, April 1984.
    )  -  '
7.     Castaldini, C. and L.R. Waterland, Environmental Assessment of a Reciprocating Engine
       Retrofitted with Nonselective Catalytic Reduction, EPA-600/7-84-073B, U.S. Environmental
       Protection Agency, Research Triangle Park, NC, June 1984.              ,

8.     Castaldini, C. and L.R. Waterland, Environmental Assessment of a Reciprocating Engine
       Retrofitted with Selective Catalytic Reduction, EPA Contract No. 68-02-3188, U.S.
       Environmental Protection Agency, Research Triangle Park, NC, December 1984.

9.     Fanick, R.E., H.E. Dietzmann, and C.M. Urban, Emissions Data for Stationary Reciprocating
       Engines and Gas Turbines in Use by the Gas Pipeline Transmission Industry - Phase I&II,
       prepared by SouthWest Research Institute for the Pipeline Research Committee of the
       American Gas Association, April 1988, Project PR-15-613.

10.    Standards Support and Environmental Impact Statement, Volume I: Stationary Internal
       Combustion Engines, EPA-450/2-78-125a, U.S. Environmental Protection Agency, Office of
       Air Quality Planning  and Standards, Research Triangle Park, NC, July 1979.

11.    Castaldini, C.. NO, Reduction Technologies for Natural Gas Industry Prime Movers, prepared
       by Acurex Corp., for the Gas Research Institute, GRI-90/0215, August 1990.
7/93                         Stationary Internal Combustion Sources                        3.2-9

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3.3 GASOLINE AND DIESEL INDUSTRIAL ENGINES

3.3.1  General

       The engine category addressed by this section covers a wide variety of industrial applications
of both gasoline and diesel internal combustion engines such as, aerial lifts, fork lifts, mobile
refrigeration units, generators, pumps, industrial sweepers/scrubbers, material handling equipment (such
as conveyors), and portable well-drilling equipment.  The rated power of these engines covers a rather
substantial range; up to  186 kW (250 hp) for gasoline engines and up to 447 kW (600 hp) for diesel
engines.  (Diesel engines greater than 600 hp are covered in Section 3.4:  Large Stationary Diesel and
All Stationary Dual Fuel Engines).  Understandably, substantial differences in engine duty cycles exist
It was necessary, therefore, to make reasonable assumptions concerning usage in order to formulate
some of the emission factors.

3.3.2  Process Description

       All reciprocating internal combustion (1C) engines operate by the same basic process.  A
combustible mixture is first compressed in a small volume between the head of a piston and its
surrounding cylinder. The mixture is then ignited, and the resulting high pressure products of
combustion push the piston through the cylinder.  This movement is converted from linear to rotary
motion by a crankshaft.  The piston returns, pushing out exhaust gases, and the cycle is repeated.

       There are two methods used for stationary reciprocating 1C engines:  compression ignition (CI)
and spark ignition (SI).  Section 3.3 deals with both types of reciprocating internal combustion
engines.

       In compression  ignition engines, combustion  air is first compression heated in the cylinder,
and diesel fuel oil is then injected into the hot air. Ignition is spontaneous as the air is above the auto-
ignition temperature of the fuel. Spark ignition engines initiate combustion by the spark of an
electrical discharge.  Usually the fuel is mixed with the air in a carburetor (for gasoline) or at the
intake valve (for natural gas), but occasionally the fuel is injected into the compressed air in the
cylinder.  All diesel fueled engines are compression ignited and all gasoline fueled engines  are spark
ignited.

       CI engines usually operate at a higher compression ratio (ratio of cylinder volume when the
piston is at the bottom of its  stroke to the volume when it is at the top) than SI engines because fuel is
not present during compression; hence there is no danger of premature auto-ignition. Since engine
thermal efficiency rises with  increasing pressure ratio (and pressure ratio varies directly with
compression ratio), CI engines  are more efficient than SI engines. This increased efficiency is gained
at the expense of poorer response to load changes and a heavier structure to withstand the higher
pressures.

3.3.3  Emissions and Controls

       The best method for  calculating emissions is  on the basis  of "brake specific" emission factors
(g/hp-hr or g/kW-hr). Emissions are calculated by taking the product of the brake specific emission
factor, the usage in hours (that is, hours per year or hours per day), the power available (rated power),
and the load factor (the power actually used divided by the power available).

7/93                          Stationary Internal Combustion Sources                          3.3-1

-------
        Once reasonable usage and duty cycles for this category were ascertained, emission values
 were aggregated to arrive at the factors presented in Tables 3.3-1 (English units) and 3.3-2 (Metric
 units) for criteria and organic pollutants.  Emissions data for a specific design type were weighted
 according to estimated material share for industrial engines.  The emission factors in this table are
 most appropriately applied to a population of industrial engines rather than to an individual power
 plant because of their aggregate nature.  Table 3.3-3 shows unweighted speciated organic compound
 and air toxic emissions factors based upon only two engines.  Their inclusion in this section is
 intended  only for rough order of magnitude estimates.

        Table 3.3-4 shows a summary of various diesel emission reduction technologies (some which
 may be applicable to gasoline engines).  These technologies are categorized into fuel modifications,
 engine modifications, and exhaust after treatments.  'Current data are insufficient to quantify the results
 of the modifications. Table  3.3-4 provides general  information on the trends of changes on selected
 parameters.
3.3-2
EMISSION FACTORS
7/93

-------
  TABLE 3.3-1. (ENGLISH UNITS) EMISSION FACTORS FOR UNCONTROLLED GASOLINE
                          AND DIESEL INDUSTRIAL ENGINES3
                                (Source Classification Codes)
Pollutant
[Rating]"
NOX [D]
CO [D]
SOX [D]
Particulate [D]
CO2 [B]
Aldehydes [D]
Hydrocarbons
Exhaust [D]
Evaporative [E]
Crankcase [E]
Refueling [E]
Gasoline Fuel
(SCC 20200301, 20300301)
[grams/hp-hr]
(power output)
5.16
199
0.268
0.327
493
0.22

6.68
0.30
2.20
0.49
[Ib/MMBtu]
(fuel input)
1.63
62.7
0.084
0.10
155
0.07

2.10
0.09
0.69
0.15
Diesel Fuel
(SCC 20200102, 20300101)
[grams/hp-hr]
(power output)
14.0
3.03
0.931
1.00
525
0.21

1.12
0.00
0.02
0.00
[Ib/MMBtu]
(fuel input)
4.41
0.95
0.29
0.31
165
0.07

0.35
0.00
0.01
0.00
"Data based on uncontrolled levels for each fuel from References 1, 3 and 6.
 When necessary, the average brake specific fuel consumption (BSFQ value was
 used to convert from g/hp-hr to Ib/MMBtu was 7000 Btu/hp-hr.
b"D" and "E" rated emission factors are most appropriate when applied to a
 population of industrial engines rather than to an individual power plant, due
 to the aggregate nature of the emissions data.
"Based on assumed 100 percent conversion of carbon in fuel to CO2 with 87 weight
 percent carbon in diesel, 86 weight percent carbon in gasoline,  average brake
 specific fuel consumption of 7000 Btu/hp-hr, diesel heating value of 19300 Btu/lb,
 and gasoline heating value of 20300 Btu/lb.
7/93
Stationary Internal Combustion Sources
3.3-3

-------
   TABLE 3.3-2. (METRIC UNITS) EMISSION FACTORS FOR UNCONTROLLED GASOLINE
                           AND DIESEL INDUSTRIAL ENGINESa
                                 (Source Classification Codes)
Pollutant
[Rating]"
NOX [D]
com
SOX [D]
Particulate [D]
C02 [B]
Aldehydes [D]
Hydrocarbons
Exhaust [D]
Evaporative [E]
Crankcase [E]
Refueling [E]
Gasoline Fuel
(SCC 20200301, 20300301)
[grams/kW-hr]
(power output)
6.92
267
0.359
0.439
661
0.30

8.96
0.40
2.95
0.66
[ng/J]
(fuel input)
699
26,947
36
44
66,787
29

905
41
298
66
Diesel Fuel
(SCC 20200102, 20300101)
[grams/kW-hr]
(power output)
18.8
4.06
1.25
1.34
704
0.28

1.50
0.00
0.03
0.00
[ng/J]
(fuel input)
1,896
410
126
135
71,065
28

152
0.00
2.71
0.00
'Data based on uncontrolled levels for each fuel from References 1, 3 and 6.
b"D" and "E" rated emission factors are most appropriate when applied to a
  population of industrial engines rather than to an individual power plant,
  due to the aggregate nature of the emissions data.
"Based on assumed 100 percent conversion of carbon in fuel to CO2 with 87 weight
  percent carbon in diesel, 86 weight percent carbon in gasoline, average brake
  specific fuel consumption of 7000 Btu/hp-hr, diesel heating value of 19300 Btu/lb,
  and gasoline heating value of 20300 Btu/lb.
3.3-4
EMISSION FACTORS
7/93

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TABLE 3 3-3.  (ENGLISH AND METRIC UNITS) SPECIATED ORGANIC COMPOUNDS AND
        AIR TOXIC EMISSION FACTORS FOR UNCONTROLLED DIESEL ENGINES'1
                      (Source Classification Codes:  20200102, 20300101)

                       (ALL EMISSION FACTORS ARE RATED:  E)b
Pollutant
Benzene
Toluene
Xylenes
Propylene
1,3 Butadiene*
Formaldehyde
Acetaldehyde
Acrolein
Polycyclic Aromatic Hydrocarbons (PAH)
Naphthalene
Acenaphthylene
Acenaphthene
Fluorene
Phenanmrene
Anthracene
Fluoranthene
Pyrene
Benz(a)anthracene
Chrysene
Benzo(b)fluorantliene
Benzo(k)fluoranthene
Benzo(a)pyrene
Indeno(l,2,3-cd)pyrene
Dibenz(a,h)anthracene
Benzo(g,h,l)perylene
Total PAH
[Ib/MMBtu]
(fuel input)
9.33 E-04
4.09 E-04
2.85 E-04
2.58 E-03
< 3.91 E-05
1.18 E-03
7.67 E-04
< 9.25 E-05

8.48 E-05
< 5.06 E-06
< 1.42 E-06
2.92 E-05
2.94 E-05
1.87 E-06
7.61 E-06
4.78 E-06
1.68 E-06
3.53 E-07
< 9.91 E-08
< 1.55 E-07
< 1.88 E-07
< 3.75 E-07
< 5.83 E-07
< 4.89 E-07
1.68 E-04
[ng/J]
(fuel input)
0.401
0.176
0.122
1.109
< 0.017
0.509
0.330
< 0.040

3.64 E-02
< 2.17 E-03
< 6.11 E-04
1.26 E-02
1.26 E-02
8.02 E-04
3.27 E-03
2.06 E-03
7.21 E-04
1.52 E-04
< 4.26 E-05
< 6.67 E-05
< 8.07 E-05
< 1.61 E-04
< 2.50 E-04
< 2.10 E-04
7.22 E-02
"Data are based on the uncontrolled levels of two diesel engines from References 6 and 7.
b"E" rated emission factors are due to limited data sets, inherent variability in the
 population and/or a lack of documentation of test results. "E" rated emission factors
 may not be suitable for specific facilities or populations and should be used with care.
"Data are based on one engine.
7/93
Stationary Internal Combustion Sources
3.3-5

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               TABLE 3.3-4.  DIESEL EMISSION CONTROL TECHNOLOGIES3
Technology
Affected Parameter*5
Increase
Decrease
  Fuel Modifications
         Sulfur Content Increase
         Aromatic Content Increase
         Cetane Number
         10 percent and 90 percent Boiling Point
         Fuel Additives
         Water/Fuel Emulsions
  Engine Modifications
         Injection Timing

         Fuel Injection Pressure
         Injection Rate Control
         Rapid Spill Nozzles
         Electronic Timing & Metering
         Injector Nozzle Geometry
         Combustion Chamber Modifications
         Turbocharging
         Charge Cooling
         Exhaust Gas Recirculation
         Oil Consumption Control
 Exhaust After Treatment
         Particulate Traps
         Selective Catalytic Reduction
         Oxidation Catalysts
             PM, Wear
             PM, NOX
             NOX, PM, BSFC,
             Power
             PM, NOX
             PM, Power
             PM, Power, Wear
 PM, NOX
 PM
 PM, NOX
 NOX

 NO,
NOX, PM
PM
NOX, PM
PM
NOX, PM
NOX
NOX
NOX
PM, Wear

PM
NOX
HC, CO, PM
"Reference 4.
'NO, = Nitrogen oxides; PM = Particulate matter, HC =
 CO = Carbon monoxide; BSFC = Brake specific fuel
             = Hydrocarbons;
             consumption.
3.3-6
EMISSION FACTORS
                7/93

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References for Section 3.3

1.     Hare, C.T. and K.J. Springer, Exhaust Emissions from Uncontrolled Vehicles and Related
       Equipment using Internal Combustion Engines, Part 5: Farm, Construction, and Industrial
       Engines, U.S. Environmental Protection Agency, Research Triangle Park, NC, Publication
       APTD-1494, October 1973, pp. 96-101.

2.     Lips, H.I., J.A. Gotterba, and K.J. Lim, Environmental Assessment of Combustion
       Modification Controls for Stationary Internal Combustion Engines. EPA-600/7-81-127,
       Industrial Environmental Research Laboratory, Office of Environmental Engineering and
       Technology, Office of Air Quality Planning and Standards, U.S. Environmental Protection
       Agency, Research Triangle Park, NC, July 1981.

3.     Standards Support and Environmental Impact Statement, Volume I:  Stationary Internal
       Combustion Engines, EPA-450/2-78-125a, Emission Standards and Engineering Division,
       Office of Air, Noise, and Radiation, Office of Air Quality Planning and Standards, U.S.
       Environmental Protection Agency, Research Triangle Park, NC, July 1979.

4.     Technical Feasibility of Reducing NO,, and Particulate Emissions from Heavy-Duty Engines.
       Draft Report by Acurex Environmental Corporation for the California Air Resources Board,
       Sacramento, CA, March 1992, CARB Contract A132-085.

5.     Nonroad Engine and Vehicle Emission Study-Report. EPA-460/3-91-02,  Certification Division,
       Office of Mobile Sources, Office of Air & Radiation, U.S. Environmental Protection Agency,
       Research Triangle Park, NC, November 1991.

6.     Pooled Source Emission Test Report:  Oil and Gas Production Combustion Sources. Fresno
       and Ventura Counties. California, Report prepared by ENSR Consulting  and Engineering for
       Western States Petroleum Association (WSPA), Bakersfield, CA, December 1990, ENSR
       7230-007-700.

7.     Osborn, W.E., and M.D. McDannel, Emissions of Air Toxic Species: Test Conducted Under
       AB2588 for the Western States Petroleum Association. Report prepared by Carnot for Western
       States Petroleum Association (WSPA), Glendale, CA, May 1990, CR 72600-2061.
7/93                        Stationary Internal Combustion Sources                        3.3.7

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3.4 LARGE STATIONARY DIESEL AND ALL STATIONARY DUAL FUEL ENGINES

3.4.1  General

       The primary domestic use of large stationary diesel engines (greater than 600 hp) is in oil and
gas exploration and production. These engines, in groups of three to five, supply mechanical power to
operate drilling (rotary table), mud pumping and hoisting equipment, and may also operate pumps or
auxiliary power generators. Another frequent application of large stationary diesels is electricity
generation for both base and standby service. Smaller uses include irrigation, hoisting and nuclear
power plant emergency cooling water pump operation.

       Dual fuel engines were developed to obtain compression ignition performance and the
economy of natural gas, using  a minimum of 5 to 6 percent diesel fuel to ignite the natural gas.  Large
dual fuel engines have been used almost exclusively for prime electric power generation. This section
includes all dual fuel engines.

3.4.2   Process Description

       All reciprocating internal combustion (1C) engines operate by the same basic process.  A
combustible mixture is first compressed in a small volume between the head of a piston and its
surrounding cylinder.  The mixture is then ignited, and the resulting high pressure products of
combustion push the piston through the cylinder.  This movement is converted from linear to rotary
motion by a crankshaft.  The piston returns, pushing out exhaust gases, and the cycle is repeated.

       There  are two methods used for stationary reciprocating 1C engines:  compression ignition (CI)
and spark ignition (SI).  Section 3.4 deals only with compression ignition engines.

       In compression ignition engines, combustion air is first compression heated in the cylinder,
and diesel fuel oil is then injected into the hot air.  Ignition is spontaneous as the air is above the auto-
ignition temperature of the fuel.  Spark ignition engines initiate combustion by the spark of an
electrical discharge. Usually the fuel is mixed with the air in a carburetor (for gasoline) or at the
intake valve (for natural gas), but occasionally the  fuel is injected into the compressed air hi the
cylinder. Although all diesel fueled engines are compression ignited and all gasoline and gas fueled
engines are spark ignited, gas can be used in a compression ignition engine if a small amount of diesel
fuel is injected into the compressed gas/air mixture to burn any mixture ratio of gas and diesel oil
(hence the name dual  fuel), from 6- to 100-percent diesel oil.

       CI engines usually operate at a higher compression ratio  (ratio of cylinder volume when the
piston is at the bottom of its stroke to the volume when it is at the top) than SI engines because fuel is
not present during compression; hence there is no danger of premature auto-ignition. Since engine
thermal efficiency rises with increasing pressure ratio  (and pressure ratio varies directly with
compression ratio), CI engines are more  efficient than SI engines. This increased efficiency is gained
at the expense of poorer response to load changes and a heavier structure to withstand the higher
pressures.
7/93                         Stationary Internal Combustion Sources                         3.4-1

-------
 3.4.3 Emissions and Controls

        Most of the pollutants from 1C engines are emitted through the exhaust  However, some
 hydrocarbons escape from the crankcase as a result of blowby (gases which are vented from the oil
 pan after they have escaped from the cylinder past the piston rings) and from the fuel tank and
 carburetor because of evaporation.  Nearly all of the hydrocarbons from diesel  compression ignition
 (CI) engines enter the atmosphere from the exhaust Crankcase blowby is minor because hydrocarbons
 arc not present during compression of the charge. Evaporative losses are insignificant in diesel
 engines due to the low volatility of diesel fuels. In general, evaporative losses are also negligible in
 engines using gaseous fuels because these engines receive their fuel continuously from a pipe rather
 than via a fuel storage tank and fuel pump.

        The primary pollutants from internal combustion engines are oxides of nitrogen (NCy, organic
 compounds (hydrocarbons), carbon monoxide (CO), and particulates, which include both visible
 (smoke) and nonvisible emissions.  The other pollutants are primarily the result of incomplete
 combustion. Ash and metallic additives in the fuel also contribute to the paniculate content of the
 exhaust Oxides of sulfur (SOJ also appears in the exhaust from 1C engines.

        The primary pollutant of concern from large stationary diesel and all stationary dual fuel
 engines is NOX, which readily forms in the high temperature, pressure, nitrogen content of the fuel,
 and excess air environment found in these engines. Lesser amounts of CO and organic compounds are
 emitted. The sulfur compounds, mainly SO2, are directly related to the sulfur content of the fuel.  SOX
 emissions will usually be quite low because of the negligible sulfur content of diesel fuels and natural
 gas.

        Tables 3.4-1 (English units) and 3.4-2 (Metric units) contain gaseous emission factors.

        Table 3.4-3 shows the speciated organic compound emission factors and Table 3.4-4 shows the
 emission factors for polycyclic aromatic hydrocarbons (PAH).  These tables do not provide a complete -
 speciated organic compound and PAH listing since they are based only on a single engine test; they
 are to be used for rough order of magnitude comparisons.

        Table 3.4-5 shows the paniculate and particle sizing emission factors.

        Control measures to date have been directed mainly at limiting NOX emissions because NOX is
the primary pollutant from diesel and dual fuel engines. Table 3.4-6 shows the NOX reduction and fuel
consumption penalties for diesel and dual fueled engines based on some of the  available control
techniques. All of these controls are engine control techniques except for the selective catalytic
reduction (SCR) technique, which is a post-combustion control. The emission reductions shown are
those which have been demonstrated. The effectiveness of controls on an particular engine will
depend  on the specific design of each engine and the effectiveness of each technique could vary
considerably. Other NOX control techniques exist but are not included in Table 3.4-6. These
techniques include internal/external exhaust gas recirculation (EGR), combustion chamber
modification, manifold air cooling, and turbocharging.
3.4-2                               EMISSION FACTORS                                7/93

-------
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52-

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[Ib/MMBtu]
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4/93
Stationary Internal Combustion Sources
                      3.4-3

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Diesel Fuel
(SCC 20200401)
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3.4-4
EMISSION FACTORS
                          4/93

-------
     TABLE 3.4-3. (ENGLISH AND METRIC UNITS) SPECIATED ORGANIC COMPOUND
            EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES3
                            (Source Classification Code:  20200401)

                                 (Emission Factor Rating:  E)b
Pollutant
Benzene
Toluene
Xylenes
Propylene
Formaldehyde
Acetaldehyde
Acrolein
[Ib/MMBtu]
(fuel input)
7.76 E-04
2.81 E-04
1.93 E-04
2.79 E-03
7.89 E-05
2.52 E-05
7.88 E-06
[ng/J]
(fuel input)
3.34 E-01
1.21 E-01
8.30 E-02
1.20 E-00
3.39 E-02
1.08 E-02
3.39 E-03
"Data based on the uncontrolled levels of one diesel engine from reference 5. There was enough
 information to compute the input specific emission factors of Ib/MMBtu, but not enough to calculate
 the output specific emission factor of g/hp-hr.  There was enough information to compute the input
 specific emission factors of ng/J, but not enough to calculate the output specific emission factor of
 g/kW-hr.
b"E"  rating for emission factors are due to limited data sets, inherent variability in the population
  and/or a  lack of documentation of test results.  "E" rated emission factors may not be suitable for
  specific facilities or populations and should be used with care.
7/93                        Stationary Internal Combustion Sources                        3.4.5

-------
 TABLE 3.4-4.  (ENGLISH AND METRIC UNITS) POLYCYCLIC AROMATIC HYDROCARBON
         (PAH) EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES3
                           (Source Classification Code:  20200401)

                                (Emission Factor Rating: E)b
Pollutant
Polycyclic Aromatic Hydrocarbons (PAH)
Naphthalene
Acenaphthylene
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benz(a)anthracene
Chrysene
Benzo(b)fluoranthene
Benzo(k)fluoranthene
Benzo(a)pyrene
Indeno(l ,2,3-cd)pyrene
Dibenz(a,h)anthracene
Benzo(g,h,l)perylene
Total PAH
[Ib/MMBtu]
(fuel input)

1.30 E-04
9.23 E-06
4.68 E-06
1.28 E-05
4.08 E-05
1.23 E-06
4.03 E-06
3.71 E-06
6.22 E-07
1.53 E-06
1.11 E-06
< 2.18 E-07
< 2.57 E-07
< 4.14 E-07
< 3.46 E-07
< 5.56 E-07
2.12 E-04
[ng/J]
(fuel input)
..
5.59 E-02
3.97 E-03
2.01 E-03
5.50 E-03
1.75 E-02
5.29 E-04
1.73 E-03
1.60 E-03
2.67 E-04
6.58 E-04
4.77 E-04
<~9.37 E-05
< 1.10 E-04
< 1.78 E-04
< 1.49 E-04
< 2.39 E-04
9.09 E-02
*Data are based on the uncontrolled levels of one diesel engine from reference 5.  There was enough
  information to compute the input specific emission factors of Ib/MMBtu and ng/J but not enough to
  calculate the output specific emission factor of g/hp-hr and g/kW-hr.
b"E" rating for emission factors is due to limited data sets, inherent variability in the population and/or
 a lack of documentation of test results. "E" rated emission factors may not be suitable for specific
 facilities or populations and should be used with care.
3.4-6
EMISSION FACTORS
7/93

-------
   TABLE 3.4-5.  (ENGLISH AND METRIC UNITS) PARTICIPATE AND PARTICLE SIZING
            EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES8
                           (Source Classification Code:  20200401)

                                 (Emission Factor Rating: E)b
Pollutant
Particulate Size Distribution
<1 urn
1-3 um
3-10 um
>10um
Total PM-10 (<10 um)
TOTAL
Paniculate Emissions
Solids
Condensables
TOTAL
Power Output
[grams/hp-hr] [grams/kW-hr]

0.1520 0.2038
0.0004 0.0005
0.0054 0.0072
0.0394 0.0528
0.1578 0.2116
0.1972 0.2644

0.2181 0.2925
0.0245 0.0329
0.2426 0.3253
Fuel Input
[Ib/MMBtu] [ng/J]

0.0478 20.56
0.0001 0.05
0.0017 0.73
0.0124 5.33
0.0496 21.34
0.0620 26.67

0.0686 29.49
0.0077 3.31
0.0763 32.81
"Data are based on the uncontrolled levels of one diesel engine from reference 6.  The data for the
  paniculate emissions were collected using Method 5 and the particle size distributions were
  collected using a Source Assessment Sampling System (SASS).
b"E" rating for emission factors is due to limited data sets, inherent variability in the population and/or
  a lack of documentation of test results. "E" rated emission factors may not be suitable for specific
  facilities or populations and should be used with care.
7/93
Stationary Internal Combustion Sources
3.4-7

-------
        TABLE 3.4-6.  NOX REDUCTION AND FUEL CONSUMPTION PENALTIES FOR
                LARGE STATIONARY DIESEL AND DUAL FUEL ENGINES3
                              (Source Classification Codes)
Control Approach
Diesel
(SCC 20200401)
Percent NOX
Reduction
ABSFC,"
Percent
Dual Fuel
(SCC 20200402)
Percent
NOX
Reduction
ABSFC,"
Percent
Derate


Retard


Air-to-Fue!

Water Injection (B^O/fuel ratio)
Selective Catalytic Reduction (SCR)
10%
20%
25%
2
4
8
3%
10%
50%


<20
5-23
<20
<40
28-45

7-8
25-35
80-95

4
1-5
4
4
2-8

3
2-4
0
<20

1-33
<20
<40
50-73
<20
25-40

80-95
4

1-7
3
1
3-5
0
1-3

0
*Data are based on references 1, 2, and 3.  The reductions shown are typical and will vary depending
on the engine and duty cycle.
""BSFC = Brake Specific Fuel Consumption.
3.4-8
EMISSION FACTORS
7/93

-------
References for Section 3.4

1.     Lips, H.I., J.A. Gotterba, and K.J. Lim, Environmental Assessment of Combustion Modification
       Controls for Stationary Internal Combustion Engines, EPA-600/7-81-127, Industrial Environmental
       Research Laboratory, Office of Environmental Engineering and Technology, Office of Air Quality
       Planning  and Standards, U.S. Environmental Protection Agency, Research Triangle Park, NC, July
       1981,

2.     Campbell, L.M., D.K. Stone, and G.S. Shareef, Sourcebook:  MX Control Technology Data.
       Control Technology Center, EPA-600/2-91-029, Emission Standards Division, Office of Air
       Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park,
       NC, July 1991.

3.     Catalysts for Air Pollution Control, brochure by the Manufacturers of Emission Controls
       Association (MECA), Washington, DC, March 1992.

4.     Standards Support and Environmental Impact Statement. Volume I:  Stationary Internal
       Combustion Engines, EPA-450/2-78-125a, Emission Standards and Engineering Division, Office of
       Air, Noise, and Radiation, Office of Air Quality Planning and Standards, U.S. Environmental
       Protection Agency, Research Triangle Park, NC, July 1979.

5.     Pooled Source Emission Test Report:  Oil and Gas Production Combustion Sources, Fresno and
       Ventura Counties,  California. Report prepared by ENSR Consulting and Engineering for Western
       States Petroleum Association (WSPA), Bakersfield, CA, December 1990, ENSR # 7230-007-700.

6.     Castaldini, C, Environmental Assessment of NO, Control on a Compression Ignition Large Bore
       Reciprocating Internal Combustion Engine, Volume I: Technical Results, EPA-600/7-86/001a,
       Combustion Research Branch of the Energy Assessment and Control Division, Industrial
       Environmental Research Laboratory, Office of Research and Development, U.S.  Environmental
       Protection Agency, Washington, DC, April 1984.
7/93                        Stationary Internal Combustion Sources                           3.4-9

-------

-------
5.2   SYNTHETIC AMMONIA

5.2.1 General1'2

      Synthetic ammonia (NH3) refers to ammonia that has been synthesized (SIC 2873) from natural
gas.  Natural gas molecules are reduced to carbon and hydrogen. The hydrogen is then purified and
reacted with nitrogen to produce ammonia. Approximately 75 percent of the ammonia produced is
used as fertilizer,  either directly as ammonia or indirectly after  synthesis as urea, ammonium nitrate,
and monoammonium or diammonium phosphates. The remaining is used as raw material in the
manufacture of polymeric resins, explosives, nitric acid, and other products.

      Synthetic ammonia plants are located throughout the U. S. and Canada. Synthetic ammonia is
produced in 25 states by 60 plants which have an estimated combined annual production capacity of
15.9 million megagrams (17.5 million tons) hi 1991.  Ammonia plants are concentrated in areas with
abundant supplies of natural gas. Seventy percent of U. S.  capacity  is located in Louisiana, Texas,
Oklahoma, Iowa and Nebraska.

5.2.2 Process Description1'3"4

      Anhydrous  ammonia is synthesized by reacting hydrogen with nitrogen at a molar ratio of 3 to
1, then compressing the gas and cooling it to -33C (-27F).  Nitrogen is obtained from the air, while
hydrogen is obtained from either the catalytic steam reforming of natural gas (methane) or naphtha, or
the electrolysis of brine at chlorine plants. In the U.  S., about  98 percent of synthetic ammonia is
produced by catalytic steam reforming of natural gas.  Figure 5.2-1  shows a general process flow
diagram of a typical ammonia plant.

      Six process steps are required to produce synthetic ammonia using the catalytic steam reforming
method: 1) natural gas  desulfurization, 2) catalytic steam reforming, 3) carbon monoxide shift, 4)
carbon dioxide removal, 5) methanation  and 6) ammonia synthesis.  The first, third, fourth, and fifth
steps remove impurities such as sulfur, CO, CO2 and water from the feedstock, hydrogen and
synthesis gas streams.  In the second step, hydrogen is manufactured and nitrogen (air) is introduced
into  this two stage process.  The sixth step produces anhydrous ammonia from the synthetic gas.
While all ammonia plants use this basic process, details such as operating pressures, temperatures,
and quantities of feedstock vary from plant to plant.

5.2.2.1 Natural Gas Desulfurization

      In this step, the sulfur content (as  H2S) in natural gas is reduced to below 280  micrograms per
cubic meter to prevent  poisoning of the nickel catalyst in the primary reformer. Desulfurization can
be accomplished by using either activated carbon or zinc oxide.  Over 95 percent of the ammonia
plants in the U. S. use  activated carbon fortified with metallic oxide additives for feedstock
desulfurization. The remaining plants use a tank filled with zinc oxide for desulfurization.  Heavy
hydrocarbons can decrease the effectiveness of an activated carbon bed.  This carbon bed also has
another disadvantage in that it cannot remove carbonyl sulfide.  Regeneration of carbon is
accomplished by passing superheated steam through the carbon bed. A zinc oxide bed offers several
advantages over the activated carbon bed.  Steam regeneration to use as energy is not required when
using a zinc oxide bed. No air emissions are created by the zinc oxide bed, and the higher


7/93                               Chemical Process Industry                              5.2-1

-------
                                                                     EMISSIONS DURING
                                                                      REGENERATION

NATURAL GAS *


FUEL

STEAM *


AIR *

EMISSIONS
3-01-003-09
i PROCESS ^ 	
CONDENSATE
1 r

STEAM
CTDIDDCD
olnlrren
t
i
STEAM





FEEDSTOCK
DESULFURIZATION
!'


PRIMARY REFORMER

i r
SECONDARY
REFORMER
*
HIGH TEMPERATURE
SHIFT
LOW TEMPERATURE
SHIFT
1

CO2 ABSORBER

V
METHANATION
^
V

AMMONIA SYNTHESIS
t
NH3
3-01-003-05 jf
Cl ICI /tOtlDI IOTir\M
PUcL UUMBUo 1 IUN
EMISSIONS
i
t
3-01-003-06 (natural gas)
3-01-003-07 (oil fired)




EMISSIONS
3-01-003-008
i
.
'I
 COj> SOLUTION
^ REGENERATION

t
STEAM


PURGE GAS VENTED TO
* PRIMARY REFORMER
FOR FUEL
r
                 Figure 5.2-1 General flow diagram of a typical ammonia plant.
molecular weight hydrocarbons are not removed.  Therefore, the heating value of the natural gas is
not reduced.

5.2.2.2 Catalytic steam reforming

      Natural gas leaving the desulfurization tank is mixed with process steam and preheated to
540C (1004F). The mixture of steam and gas enters the primary reformer (natural gas fired
primary reformer and oil fired primary reformer tubes, which are filled with a nickel-based reforming
5.2-2
EMISSION FACTORS
7/93

-------
catalyst.  Approximately 70 percent of the methane (CH^) is converted to hydrogen and carbon   
dioxide (CO2).  An additional amount of CH4 is converted to CO. This process gas is then sent to
the secondary reformer, where it is mixed with compressed air that has been preheated to about
540C (1004F).  Sufficient air is added to produce a final synthesis gas having a hydrogen-to-
nitrogen mole ratio of 3 to 1:  The gas leaving the secondary reformer is then cooled to 360 C
(680F) in a waste heat boiler.

5.2.2.3 Carbon monoxide shift

      After cooling, the secondary reformer effluent gas enters a high temperature CO shift converter
which is filled with chromium oxide initiator and iron oxide catalyst.  The following reaction takes
place in the carbon monoxide converter:

                                  CO + H2O  -* CO2 +  H2                               (1)

The exit gas is then cooled in a heat  exchanger. In some plants, the gas is passed through a bed of
zinc oxide to remove any residual  sulfur contaminants that would poison the low temperature shift
catalyst.  In other plants, excess low temperature shift catalyst is added to ensure that the unit will
operate as expected.  The low temperature shift converter is filled with a copper oxide/zinc oxide
catalyst.  Final shift gas from this  converter is cooled from 210 to 110C (410 to 230F) and enters
the bottom of the carbon dioxide absorption system.  Unreacted steam is condensed and separated
from the gas in a knockout drum.  This condensed steam (process condensate) contains ammonium
.carbonate  ([(NH4)2 CO3  H2O]) from the high temperature shift converter, methanol (CH3OH) from
the low temperature shift converter, and small amounts  of sodium, iron, copper, zinc, aluminum and
calcium.

      Process condensate is sent to the stripper to remove volatile gases such as ammonia, methanol,
and carbon dioxide. Trace metals remaining in the process condensate are removed by the ion
exchange unit.

5.2.2.4 Carbon dioxide removal

      In this step, CO2 in the final shift gas is removed. CO2 removal can be done by using two
methods: mohoethanolamine (C2H4NH2OH) scrubbing and hot potassium scrubbing.  Approximately
80 percent of the  ammonia plants use monoethanolamine (MEA) to aid in removing CO2. The CO2
gas is passed upward through an adsorption tower countercurrent to a 15 to 30 percent solution of
MEA in water fortified with effective corrosion inhibitors. After absorbing the CO2, the amine
solution is preheated and regenerated (carbon dioxide regenerator) in a reactivating tower. This
reacting tower removes CO2 by steam stripping and then by heating. The CO2 gas (98.5 percent CO2)
is either vented to the atmosphere  or used for chemical feedstock in other parts of the plant complex.
The regenerated MEA is pumped back to the absorber tower after being cooled in a heat exchanger
and solution cooler.

5.2.2.5 Methanation

      Residual CO2 in the synthesis  gas is removed by catalytic methanation which is conducted over
a nickel catalyst at temperatures of 400 to 600C (752 to 1112F) and pressures up to 3,000 kPa (435
psia) according to the following reactions:


                                 CO  +  3H2  -   CH4 + H2O                              (2)


7/93                              Chemical Process Industry                              5.2-3

-------
                                 CO2 + H2  -* CO  + H2O                              (3)
                                CO2 + 4H2 -  CH4 + 2H2O                             (4)


Exit gas from the methanator, which has a 3:1 mole ratio of hydrogen and nitrogen, is then cooled to
38C (100F).

5.2.2.6 Ammonia Synthesis

      In the synthesis step, the synthesis gas from the methanator is compressed at pressures ranging
from  13,800 to 34,500 kPa (2000 to 5000 psia), mixed with recycled synthesis gas, and cooled to
0C (32F). Condensed ammonia is separated from the unconverted synthesis gas in a liquid-vapor
separator and sent to a let-down separator.  The unconverted synthesis is compressed and preheated to
180C (356F) before entering the synthesis converter which contains iron oxide catalyst.  Ammonia
from the exit gas is condensed and separated, then sent to the let-down separator. A small portion of
the overhead gas is purged to prevent the buildup of inert gases such as argon in the circulating gas
system.

      Ammonia in the let-down separator is flashed to 100 kPa (14.5 psia) at -33C (-27F) to
remove impurities from the liquid.  The flash vapor is condensed in the let-down chiller where
anhydrous ammonia is drawn off and stored at low temperature.

5.2.3 Emissions And Controls1'3

      Pollutants from the manufacture of synthetic anhydrous ammonia are emitted from four process
steps: 1) regeneration of the desulfurization bed, 2) heating of the catalytic steam, 3) regeneration of
carbon dioxide scrubbing solution, and 4) steam stripping of process condensate.
                                            /
      More than 95 percent of the ammonia plants in the U. S. use activated carbon fortified with
metallic oxide additives for feedstock desulfurization. The desulfurization bed must be regenerated
about once every 30  days for an average period of 8 to 10 hours. Vented regeneration steam contains
sulfur oxides (SOX) and hydrogen sulfide (H2S), depending on the amount of oxygen in the steam.
Regeneration also emits hydrocarbons and carbon monoxide (CO).  The reformer, heated with natural
gas or fuel oil, emits combustion products such as NOX,  CO, SOX, hydrocarbons, and particulates.

      Carbon dioxide (CO^ is removed from the synthesis gas by scrubbing with MEA or hot
potassium carbonate solution.  Regeneration of this CO2 scrubbing solution with steam produces
emission of water, NH3, CO, CO2 and monoethanolamine.

      Cooling the synthesis gas after low temperature shift conversion forms a condensate containing
NH3, CO2, methanol (CH3OH), and trace metals.  Condensate steam strippers are used to remove
NH3  and methanol from the water, and steam from this is vented to the atmosphere, emitting NH3,
CO2, and methanol.

      Some processes have been modified to reduce emissions  and to improve utility  of raw materials
and energy. One such technique is the injection of the overheads into the reformer stack along with
the combustion gases to eliminate emissions from the condensate steam stripper.
 5.2-4                               EMISSION FACTORS                                7/93

-------
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7/93
      Chemical Process Industry
                                                                             5.2-5

-------
References for Section 5.2

1.    Source Category Survey: Ammonia Manufacturing Industry, EPA-450/3-80-014, U.S.
      Environmental Protection Agency, Research Triangle Park, NC, August 1980.

2.    North American Fertilizer Capacity Data, Tennessee Valley Authority, Muscle Shoals, AL,
      December 1991.

3.    G.D. Rawlings and R.B. Reznik, Source Assessment: Synthetic Ammonia Production, EPA-
      600/2-77-107m, U. S. Environmental Protection Agency, Research Triangle Park, NC,
      November 1977.

4.    AIRS Facility Subsystem Source Classification Codes and Emission Factor Listing For Criteria
      Pollutants. EPA-450/4-90-003, U. S. Environmental Protection Agency, Research Triangle
      Park, NC 27711, March 1990.
 5.2-6
EMISSION FACTORS
7/93

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5.5       CHLOR-ALKALI

5.5.1     General1"2

      The chlor-alkali electrolysis process is used in the manufacture of chlorine, hydrogen and
sodium hydroxide (caustic) solution. Of these three, the primary product is chlorine.

      Chlorine is one of the more abundant chemicals produced by industry and has a wide variety of
industrial uses. Chlorine was first used to produce bleaching agents for the textile and paper industries
and for general cleaning and disinfecting. Since 1950, chlorine has become increasingly important as
a raw material for synthetic organic chemistry. Chlorine is an essential component of construction
materials, solvents,  and insecticides. Annual production from U.  S. facilities was 9.9 million
megagrams (10.9 million tons) in 1990 after peaking at 10.4 million megagrams (11.4 million tons) in
1989.

5.5.2     Process Description1"3

      There are three types of electrolytic processes used in the production of chlorine: 1) the
diaphragm cell process, 2) the mercury cell process, and 3) the membrane cell process. In each
process, a salt solution is electrolyzed by the action of direct electric current which converts chloride
ions to elemental  chlorine.  The overall process reaction is:

                           2NaCl + 2H2O -*  C12 + H2 + 2NaOH                          (1)


In all three methods the chlorine (Clj) is  produced at the positive electrode (anode) and the caustic
soda (NaOH) and hydrogen (H^ are produced, directly or indirectly, at the negative electrode
(cathode). The three processes differ in the method by which the anode products are kept separate
from the cathode  products.

      Of the chlorine produced in the U. S.  in 1989, 94 percent was produced either by the
diaphragm cell or mercury cell process. Therefore, these will be the only two processes discussed in
this section.

5.5.2.1   Diaphragm Cell

      Figure 5.5-1  shows a simplified block diagram of the diaphragm cell process. Water and
sodium chloride (Nad) are combined to  create the starting brine solution. The brine undergoes
precipitation and  filtration to remove impurities.  Heat is applied and more salt is added. Then the
nearly saturated,  purified brine is heated  again before direct electric current is applied. The anode is
separated from the cathode by a permeable asbestos-based diaphragm to prevent the caustic  soda from
reacting with the  chlorine. The chlorine produced at the anode is removed, and the saturated brine
flows through the diaphragm to the cathode chamber.  The chlorine is then purified by liquefaction and
evaporation to yield a pure liquified product.

      The caustic brine produced at the cathode is separated from salt and concentrated in an
elaborate evaporative process to produce  commercial caustic soda. The salt is recycled to saturate the
dilute brine. The  hydrogen removed in the cathode chamber is cooled and purified by removal of


7/93                                Chemical Process Industry                               5.5-1

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oxygen, then used in other plant processes or sold.

5.5.2.2   Mercury Cell

      Figure 5.5-2 shows a simplified block diagram for the mercury cell process. The recycled brine
from the electrolysis process (anolyte) is dechlorinated and purified by a precipitation-filtration
process. The liquid mercury cathode and the brine enter the cell flowing concurrently. The
electrolysis process creates chlorine at the anode and elemental  sodium at the cathode. The chlorine is
removed from the anode, cooled, dried, and compressed. The sodium combines with mercury to form
a sodium amalgam. The amalgam is further reacted with water  in a separate reactor  called the
decomposer to produce hydrogen gas and caustic soda solution. The caustic and hydrogen are then
separately cooled and the mercury removed before proceeding to storage, sales or other processes.

5.5.3     Emissions And Controls4

      Table 5.5-1 is  a summary of chlorine emission factors for chlor-alkali plants.  Emissions from
diaphragm and mercury cell plants include chlorine gas, carbon dioxide (CO2), carbon monoxide
(CO), and hydrogen. Gaseous chlorine is present in the blow gas from liquefaction,  from vents in
tank cars and tank containers during loading and unloading, and from storage tanks  and process
transfer tanks. Carbon dioxide emissions result from the decomposition of carbonates in the brine feed
when contacted with acid. Carbon monoxide and hydrogen are created by side reactions within the
production cell. Other emissions include mercury vapor from mercury cathode cells  and chlorine from
compressor seals, header seals, and the air blowing of depleted brine in mercury-cell plants.
Emissions from these locations are, for the most part, controlled through the use of  the gas in other
parts of the plant, neutralization in alkaline scrubbers, or recovery of the chlorine from effluent gas
streams.

      Table 5.5-2 presents mercury emission factors based on two source tests used to substantiate  the
mercury national emission standard for hazardous air pollutants (NESHAP). Due to  insufficient data,
emission factors for CO, CO2, and hydrogen are not presented  here.
5.5-2                                EMISSION FACTORS                                7/93

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              WATER
          SALT
                     SALT
                   (BRINE)
                          SEINE
                       SATURATION
                                RAV BRINE
                      PRECIPITATION
                       .FILTRATION
                                PURIFIED BRINE
         CHLORINE
                           HEAT
                         EXCHANGE
             SALT
           SALT
                          BKINE
                       SATURATION
                           HEAT
                        EXCHANGE
                 HYDROGEN
                      ELECTROLYSIS
                      CONCENTRATION
                         COOLING
                         STORAGE

                    SODIUM     '   HYDROXIDE
                                                   HYDROGEN
                                 OXYGEH
                                SEKOVAL
                                                           HYDROGEN
                                                                          PRECIPITANTS
                                                                             RESIDUE
                                                                          CHLORINE GAS
                                                            DRYING
                                                                             COMPRESSION
                                                                            LIQUEFACTION
                                                                             EVAPORATION
                                                                                      CHLORINE
7/93
Figure 5.5-1  Simplified diagram of the diaphragm cell process
                  Chemical Process Industry
5.5-3

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                                        SALT
               DILUTED BRINE
      CAUSTIC
      SOLUTION
                                    BRINE
                                 SATURATION
                                        RAW BRINE
                                PRECIPITATION
        DECHLORINATION
       HYDRO-
       CHLORIC
       ACID
                                    PRECIPITANTS
                                 FILTRATION
                                                   RESIDUE
                   COOLING
                   ANOLYTE
                                                   HYDROCHLORIC ACID
                                ELECTROLYSIS
                     AMALGAM
                   CAUSTIC
                   SOLUTION
                                                  CHLORINE GAS
                                              MERCURY
                                  AMALGAM
                                DECOMPOSITION
            COOLING
                         HYDROGEN
                                  COOLING
                                         COOLING
            MERCURY
            REMOVAL
                  MERCURY
                  REMOVAL
            STORAGE
        SODIUM HYDROXIDE
DRYING
                                       COMPRESSION
                  HYDROGEN
                                                         CHLORINE
5.5-4
Figure 5.5-2  Simplified diagram of the mercury cell process

              EMISSION FACTORS
                 7/93

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                               Table 5.5-1 (Metric Units).
          EMISSION FACTORS FOR CHLORINE FROM CHLOR-ALKALI PLANTS*
                       Source  (SCC)
                                                                  Chlorine Gas
                               kg/Mg
                             of Chlorine
                             Produced
 Liquefaction blow gases
   Diaphragm cell (SCC 3-01-008-01)
   Mercury cell  (SCC 3-01-008-02)
   Water absorberb  (SCC 3-01-008-99)
   Caustic scrubber8 (SCC 3-01-008-99)
 Chlorine Loading
   Returned tank car vents  (SCC 3-01-008-03)
   Shipping container vents  (SCC 3-01-008-04)
 Mercury Cell Brine Air Blowing   (SCC 3-01-008-05)
Emission
 Factor
 Rating
                              10 to 50
                              20 to 80
                               0.830
                               0.006

                                4.1
                                8.7
                                2.7
   E
   E
   E
   E

   E
   E
   E
Reference 4.  SCC = Source Classification Code.
bControl devices.
                               Table 5.5-1 (English Units).
          EMISSION FACTORS FOR CHLORINE FROM CHLOR-ALKALI PLANTS*





Source (SCC) kj
of C
Pr<
Chlorine Gas
5/Mg Emission
Morine Factor
)duced Rating
Liquefaction blow gases
Diaphragm cell (SCC 3-01-008-01) 20
Mercury cell (SCC 3-01-008-02) 40
Water absorber*5
Caustic scrubber1*
Chlorine Loading
Returned tank car
(SCC 3-01-008-99)
(SCC 3-01-008-99) 0

vents (SCC 3-01-008-03)
to 100 E
to 160 E
1.66 E
.012 E

8.2 E
Shipping container vents (SCC 3-01-008-04) 17.3 E
Mercury Cell Brine Air Blowing (SCC 3-01-008-05)


5.4 E
aReference 4.  Units are Ib of pollutant/ton .
bControl devices.
7/93
Chemical Process Industry
      5.5-5

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                           Table 5.5-2 (Metric and English Units).
 EMISSION FACTORS FOR MERCURY FROM MERCURY CELL CHLOR-ALKALI PLANTS"
Type of Source (SCC)
Mercury Gas
kg/Mg
of Clorine
Produced
Hydrogen Vent (SCC 3-01-008-02)
Uncontrolled 0.0017
Controlled 0.0006
End Box (SCC 3-01-008-02) 0.005
Ib/ton
of Clorine
Produced

0.0033
0.0012
0.010
Emission
Factor
Rating

E
E
E
* SCC = Source Classification Code



References for Section 5.5

1.    Ullmann's Encyclopedia of Industrial Chemistry, VCH Publishers, New York, 1989.

2.    The Chlorine Institute, Inc., Washington, DC, January 1991.

3.    1991 Directory Of Chemical Producers, Menlo Park, California: Chemical Information
      Services, Stanford Research Institute, Stanford, CA, 1991.

4.    Atmospheric Emissions from Chlor-Alkali Manufacture, AP-80, U. S. EPA, Office of Air
      Quality Planning and Standards, Research Triangle Park, NC, January 1971.

5.    B. F. Goodrich Chemical Company Chlor-Alkali Plant Source Tests, Calvert City, Kentucky,
      EPA Contract No. CPA 70-132, Roy F. Weston, Inc., May 1972.

6.    Diamond Shamrock Corporation Chlor-Alkali Plant Source Tests, Delaware City, Delaware,
      EPA Contract No. CPA 70-132, Roy F. Weston, Inc., June 1972.
 5.5-6
EMISSION FACTORS
                                                                                    7/93

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5.7       Hydrochloric Acid

5.7.1     General1

      Hydrochloric acid (HC1) is listed as a Title III Hazardous Air Pollutant (HAP). Hydrochloric
acid is a versatile chemical used in a variety of chemical processes, including hydrometallurgical
processing (e.g., production of alumina and/or titanium dioxide), chlorine dioxide synthesis, hydrogen
production, activation of petroleum wells, and miscellaneous cleaning/etching operations including
metal cleaning (e.g., steel pickling). Also known as muriatic acid, HC1 is used by masons to clean
finished brick work, is also a common ingredient hi many reactions, and is the preferred acid for
catalyzing organic processes. One example is a carbohydrate reaction promoted by hydrochloric acid,
analogous to those in the digestive tracts of mammals.

      Hydrochloric acid may be manufactured by several different processes, although over 90
percent of the HC1 produced in the U.S. is a byproduct of the chlorination reaction. Currently, U.S.
facilities produce approximately 2.3 million megagrams (2.5 million tons) of HC1 annually, a slight
decrease from the 2.5 million megagrams (2.8 million tons) produced in 1985.

5.7.2     Process Description1"4

      Hydrochloric acid can be produced by one of the five following processes:

      1)  Synthesis from elements:

                                     H2 + C12  -  2HC1                                   (1)


      2)  Reaction of metallic chlorides, particularly sodium chloride (NaCl), with sulfuric acid
          (H2SO4) or a hydrogen sulfate:

                             NaCl + H2SO4  ->  NaHSO4 + HC1                           (2)

                             NaCl + NaHSO4  -*  Na^C^  + HC1                           (3)
                             2NaCl + H2SO4  -*  N^SO^ + 2HC1                          (4)
      3)  As a byproduct of chlorination, e.g. in the production of dichloromethane,
          trichloroethylene, perchloroethylene, or vinyl chloride:
                                           C12  -  C2H4C12                                (5)

                                           -*  C2H3C1  + HC1                               (6)


      4)  By thermal decomposition of the hydrated heavy-metal chlorides from spent pickle liquor
          in metal treatment:

                          2FeCl3 + 6H2O -*  Fe^  + 3H2O + 6HC1                       (7)
7/93                               Chemical Process Industry                              5.7-1

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     5)   From incineration of chlorinated organic waste:

                         C4H6C12  + 5O2  ->  4CO2 + 2H2O + 2HC1
                                                    (8)
Figure 5.7-1 is a simplified diagram of the steps used for the production of byproduct HC1 from the
chlorination process.
                                CHLORINATION GASES
                                                                    VENT  GAS
                                                                         -  HCI
                                                                         -  CHLORINE
                                           t
     CHLORINATION
        PROCESS
       HCI
  ABSORPTION
                                      t
SCRUBBER
                                   CONCENTRATED
                                     LIQUID  HCI
                                 DILUTE  HCI
                     Figure 5.7-1 HCI production from chlorination process
      After leaving the chlorination process, the HCl-containing gas stream proceeds to the absorption
column, where concentrated liquid HCI is produced by absorption of HCI vapors into a weak solution
of hydrochloric acid. The HCl-free chlorination gases are removed for further processing. The liquid
acid is then either sold or used elsewhere in the plant. The final gas stream is sent to a scrubber to
remove the remaining HCI prior to venting.

5.7.3      Emissions4'5

      According to a 1985 emission inventory, over 89 percent of all HCI emitted to the atmosphere
resulted from the combustion of coal. Less than one percent of the HCI emissions came from the
direct production of HCI. Emissions from HCI production result primarily from gas exiting the HCI
purification system.  The contaminants are HCI gas, chlorine and chlorinated organic compounds.
Emissions  data are only available for HCI gas. Table 5.7-1 lists estimated emission factors for
systems with and without final scrubbers.
 5.7-2
EMISSION FACTORS
                                                                                       7/93

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                        TABLE 5.7-1 (METRIC UNITS)
         EMISSION FACTORS FOR HYDROCHLORIC ACID MANUFACTURE5
Type of Process
(SCC)
HC1 Emissions
kg/Mg
HC1
Produced
Byproduct hydrochloric acid
With final scrubber (3-011-01-99) 0.08
Without final scrubber (3-011-01-99) 0.90
Emission
Factor
Rating

E
E
                       TABLE 5.7-1 (ENGLISH UNITS)
         EMISSION FACTORS FOR HYDROCHLORIC ACID MANUFACTURE5
Type of Process
(SCC)
HC1 Emissions
Ib/ton HC1
Produced
Emission
Factor
Rating
Byproduct hydrochloric acid
With final scrubber (3-011-01-99) 0.15 E
Without final scrubber (3-011-01-99) 1.8 E
7/93
Chemical Process Industry
5.7-3

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References for Section 5.7

I.   Encyclopedia of Chemical Technology, Third Edition, Volume 12, John Wiley and Sons, New
     York, 1978.

2.   Ullmam's Encyclopedia of Industrial Chemistry, Volume A, VCH Publishers, New York,
     1989.

3.   Encyclopedia of Chemical Processing and Design, Marcel Dekker, Inc., New York,  1987.

4.   Hydrogen Chloride and Hydrogen Fluoride Emission Factors for the NAPAP (National Acid
     Precipitation Assessment Program) Emission Inventory, U.S. EPA, PB86-134040. October
     1985.

5.   Atmospheric Emissions from Hydrochloric Acid Manufacturing Processes. U.S. DHEW, PHS,
     CPEHS, National Air Polluting Control Administration.  Durham, N.C. Publication Number
     AP-54. September 1969.
5.7-4                              EMISSION FACTORS                               7/93

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5.8   HYDROFLUORIC ACID

5.8.1 General5'6                                                          ,             .

      Hydrogen fluoride (HF) is listed as a Title III Hazardous Air Pollutant (HAP). Hydrogen
fluoride is produced in two forms, as anhydrous hydrogen fluoride and as aqueous hydrofluoric acid.
The predominate form manufactured is hydrogen fluoride, a colorless liquid or gas which fumes on
contact with air and is water soluble.

      Traditionally, hydrofluoric acid has been used to etch and polish glass. Currently, the largest
use for HF is in aluminum production. Other HF uses include uranium processing, petroleum
alkylation, and stainless steel pickling. Hydrofluoric acid  is also used to produce fluorocarbons used
in aerosol sprays and  in refrigerants. Although fluorocarbons are heavily regulated due to
environmental concerns, other applications for fluorocarbons include manufacturing of resins,
solvents, stain removers, surfactants, and Pharmaceuticals.

5.8.2 Process Description1"3'6

      Hydrofluoric acid is manufactured by the reaction of acid-grade fluorspar (CaF2) with sulfuric
acid (H2SO4) as shown below:

                         CaF2 +  H2SO4   ->  CaSO4 + 2HF                                  (1)

      A typical HF plant is shown schematically in Figure 5.8-1. The endothermic reaction requires
30 to 60 minutes in horizontal rotary kilns externally heated to 200 to 250C (390 to 480F). Dry
fluorspar ("spar") and a slight excess of sulfuric acid are fed continuously to the front end of a
stationary prereactor or directly to the kiln by a screw conveyor. The prereactor mixes the
components prior to charging to the rotary kiln. Calcium  sulfate (CaSO4) is removed through an air
lock at the opposite end of the kiln.  The gaseous reaction productshydrogen fluoride and  excess
H2SO4 from the primary reaction, silicon tetrafluoride (SiF4), sulfur dioxide (SO2), carbon dioxide
(CO^, and water produced in secondary reactionsare removed from the front end of the kiln along
with entrained paniculate. The particulates are removed from the gas stream by a dust separator and
returned to the kiln. Sulfuric acid and water are removed  by  a precondenser. Hydrogen fluoride
vapors are then condensed in refrigerant condensers forming "crude HF", which is removed to
intermediate storage tanks. The remaining gas stream passes through a sulfuric acid absorption tower
or acid scrubber, removing most of the remaining hydrogen fluoride and some residual sulfuric acid,
which are also placed in intermediate storage. The gases exiting the scrubber then pass through water
scrubbers, where the SiF4 and remaining HF are recovered as fluosilicic acid (H2SiF6). The water
scrubber tailgases are passed through a caustic scrubber before being released to the atmosphere. The
hydrogen fluoride and sulfuric acid  are delivered from intermediate storage tanks to distillation
columns, where the hydrofluoric acid is extracted at 99.98 percent purity. Weaker concentrations
(typically 70 to 80 percent) are prepared by dilution with  water.

5.8.3 Emissions And Controls1"2'4

      Emission factors for various HF process operations are shown in Table 5.8-1. Emissions  are
suppressed to a great  extent by the condensing, scrubbing, and absorption equipment used in the
recovery and purification of the hydrofluoric and fluosilicic acid products. Particulate in the gas


7/93                               Chemical Process Industry                              5.8-1

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5.8-2
Figure 5.8-1. Hydrofluoric acid process flow diagram.




              EMISSION FACTORS
7/93

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 stream is controlled by a dust separator near the outlet of the kiln and is recycled to the kiln for
 further processing. The precondenser removes water vapor and sulfuric acid mist, and the condensers,
 acid scrubber and water scrubbers remove all but small amounts of HF, SiF4, SO2, and CO2 from the
' tailgas. A caustic scrubber is employed to further reduce the levels of these pollutants in the tailgas.

       Particulates are emitted during handling and drying of the fluorspar. They are controlled with
 bag filters at the spar silos and drying kilns. Fugitive dust emissions from spar handling and  storage
 are controlled with flexible coverings and chemical additives.

       Hydrogen fluoride emissions are minimized by maintaining a slight negative pressure in the kiln
 during normal operations. Under upset conditions, a standby caustic scrubber or a bypass to the tail
 caustic scrubber are used to control HF emissions from the kiln.
  7/93                                Chemical Process Industry                              5.8-3

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                                  Table 5.8-1 (Metric Units).
            EMISSION FACTORS FOR HYDROFLUORIC ACID MANUFACTURE3
          Operation And Controls
                                          Control
                                         efficiency
                                                                  Emissions
                                                          Gases
                  kg/Mg
                  Acid
                Produced
           Emission
            Factor
            Rating
                                      Paniculate (Spar)
       kg/Mg
       Fluorspar
       Produced
Emission
 Factor
 Rating
 Spar Dryingb (SCC 3-01-012-03)
    Uncontrolled
    Fabric filter

 Spar Handling Silos0 (SCC 3-01-012-04)
    Uncontrolled
    Fabric filter

 Transfer Operations (SCC 3-01-012-05)
    Uncontrolled
    Covers, additives
 Tail Gas0  (SCC 3-01-012-06)
    Uncontrolled
          0
         99

          0
         99
         0
         80
                       37.5
                       0.4


                       30.0
                       0.3
                       3.0
                       0.6
                    E
                    E


                    E
                    E
                    E
                    E
                12.5 (HF)
                15.0
    Caustic Scrubber
         99
22.5
(S02)

0.1 (HF)
0.2 (SiF4)
0.3 (SOj)
              E
              E
              E
E
E
E
*SCC = Source Classification Code.
bReference 1. Averaged from information provided by 4 plants. Hourly fluorspar input calculated
 from reported 1975 year capacity, assuming stoichiometric amount of calcium fluoride and 97.5%
 content in fluorspar. Hourly emission rates calculated from reported baghouse controlled rates.
 Values averaged are as follows:

                    Plant    1975 Capacity   Emissions fluorspar fcg/Mgl

                       1      13,600 MgHF              53
                      2      18,100 MgHF              65
                      3      45,400 Mg HF              21
                      4      10,000 MgHF              15
Reference 1. Four plants averaged for silo emissions, 2 plants for transfer operations emissions.
^Three plants averaged from Reference 1. Hydrogen fluoride and SiF4 factors from Reference 4.
5.8-4
EMISSION FACTORS
                                                                                      7/93

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                                 Table 5.8-1 (English Units).
            EMISSION FACTORS FOR HYDROFLUORIC ACID MANUFACTURE*
        Operation And Control
                                        Control
                                       efficiency
                                                                 Emissions
                                                         Gases
                                 Ib/ton
                                 Acid
                               Produced
                   Emission
                    Factor
                    Rating
                                                     Paniculate (Spar)
        Ib/ton
       Fluorspar
       Produced
Emission
 Factor
 Rating
 Spar Dryingb  (SCC 3-01-012-03)
   Uncontrolled
   Fabric filter
 Spar handling silos0
   Uncontrolled
   Fabric Filter
(SCC 3-01-012-04)
 Transfer operations (SCC 3-01-012-05)
   Uncontrolled
   Covers, additives

 Tail Gasd  (SCC 3-01-012-06)
   Uncontrolled
   Caustic Scrubber
0
99

0
99
                       0
                       80

                       0
                       99
         75.0
          0.8


         60.0
          0.6
                                6.0
                                1.2
   E
   E


   E
   E
                     E
                     E
        25.0 (HF)
        30.0
                                                  0.3
                                                  0.5
        45.0 (SOj)

        0.2 (HF)
            (SiF4)
            (S02)
E
E
E


E
E
E
aSCC = Source Classification Code
bReference 1. Averaged from information provided by 4 plants. Hourly fluorspar input calculated
 from reported 1975 year capacity, assuming stoichiometric amount of calcium fluoride and 97.5%
 content in fluorspar. Hourly emission rates calculated from reported baghouse controlled rates.
 Values averaged are as follows:

                     Plant    1975 Capacity   Emissions fluorspar fib/tori)
                        1      15,000 ton HF
                        2      20,000 ton HF
                        3      50,000 ton HF
                        4      11,000 ton HF
                                     106
                                     130
                                     42
                                     30
"Reference 1. Four plants averaged for silo emissions, 2 plants for transfer operations emissions.
dThree plants averaged from Reference 1. Hydrogen fluoride and SiF4 factors from Reference 4.
7/93
              Chemical Process Industry
                                            5.8-5

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References for Section 5.8

1.    Screening Study On Feasibility Of Standards Of Performance For Hydrofluoric Acid
      Manufacture, EPA-450/3-78-109, U. S. Environmental Protection Agency, Research Triangle
      Park, NC, October 1978.

2.    "Hydrofluoric Acid", Kirk-Othmer Encyclopedia Of Chemical Technology, Interscience
      Publishers, New York, NY, 1965.

3.    W. R. Rogers and K. Muller, "Hydrofluoric Acid Manufacture", Chemical Engineering
      Progress, 59(5): 85-8, May 1963.

4.    J. M. Robinson, et al., Engineering And Cost Effectiveness Study Of Fluoride Emissions
      Control, Vol. 1, PB 207 506, National Technical Information Service, Springfield,  VA, 1972.

5.    "Fluorine", Encyclopedia Of Chemical Processing And Design, Marcel Dekker,  Inc., New
      York, NY, 1985.

6.    "Fluorine Compounds,  Inorganic", Kirk-Othmer Encyclopedia Of Chemical Technology, John
      Wiley & Sons, New York, NY, 1980.
5.8-6                              EMISSION FACTORS                                7/93

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.5.9    NITRIC ACID

 5.9.1   General1"2

        In 1991, there were approximately 65 nitric acid (HNO3) manufacturing plants in the
 U. S. with a total capacity of 10 million megagrams (11 million tons) of acid per year.  The
 plants range in size from 5,400 to 635,000 megagrams (6,000 to 700,000 tons) per year.
 About 70 percent of the nitric acid produced is consumed as an intermediate in the
 manufacture of ammonium nitrate (NH4NO3), which in turn is used in fertilizers.  The
 majority of the nitric  acid plants are located in  agricultural regions such as the Midwest,
 South Central, and Gulf States in order to accommodate the high concentration of fertilizer
 use. Another five to ten percent of the nitric acid produced is used for organic oxidation in
 adipic acid manufacturing. Nitric acid is also used in organic oxidation to manufacture
 terephthalic acid and other organic compounds. Explosive manufacturing utilizes nitric acid
 for organic nitrations. Nitric acid nitrations are used in producing nitrobenzene,
 dinitrotoluenes, and other chemical intermediates.1 Other end uses of nitric acid are gold and
 silver separation, military munitions,  steel  and brass pickling, photoengraving, and acidulation
 of phosphate rock.

 5.9.2   Process Description1'3"4

         Nitric acid is produced by two methods.  The first method utilizes oxidation,
 condensation, and absorption to produce a weak nitric acid. Weak nitric acid can have
 concentrations ranging from  30 to 70 percent nitric acid.  The second method combines
 dehydrating, bleaching, condensing, and absorption to produce a high strength nitric acid
 from a weak nitric acid. High strength nitric acid generally contains more than 90 percent
 nitric acid. The following text provides more  specific details for each of these processes.

 5.9.2.1  Weak Nitric Acid Production1'3'4

         Nearly all the nitric acid produced in the U.S. is manufactured by the high
 temperature catalytic oxidation of ammonia as shown schematically hi Figure 5.9-1. This
 process typically consists of three steps:  1) ammonia oxidation, 2) nitric oxide oxidation, 3)
 absorption. Each step corresponds to a distinct chemical reaction.

         Ammonia Oxidation - First, a 1:9 ammonia/air mixture is oxidized at a temperature
 of 750 to 800C (1380 to 1470F) as it passes through a catalytic converter, according to the
 following reaction:
                               4NH3  + 5O2  -*  4NO +  6H2O                          (1)

  The most commonly used catalyst is made of 90 percent platinum and 10 percent rhodium
  gauze constructed from squares of fine wire.   Under these conditions the oxidation of
  ammonia to nitric oxide proceeds in  an exothermic reaction with a range of 93 to 98 percent
  yield.  Oxidation temperatures can vary from 750 to 900C (1380 to 1650F).  Higher
  catalyst temperatures increase reaction selectivity toward nitric  oxide (NO) production.
  Lower catalyst temperatures tend to be more selective toward less useful products; nitrogen
       and nitrous oxide (N2O).  Nitric oxide is considered to be a criteria pollutant and nitrous

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                             EMISSION
                              POINT
                                       3-01-013-02
 COMPRESSOR
  EXPANDER
                       .-NOV EMISSIONS	.
                       i       XCONTROL
                         CATALYTIC REDUCTION
                               ^UNITS
                             2
                                                                         ENTRAINED
                                                                            MIST
                                                                         SEPERATOR
                  PLATINUM
                  FILTER
NITROGEN
DIOXIDE
                                          I
                  SECONDARY AIR
            C

AIR



LING
PER


)

)










^





Rxn3


ABSORPTION
TOWER





__ __ ___ ___ ^ _ .

                                          COOLER
                                         CONDENSER
                        N02
                                                                     PRODUCT
                                                                     (50-70%
                                                                     HN00
                  Figure 5.9-1.  Flow diagram of typical nitric acid plant
             using single-pressure process (high-strength acid unit not shown).
5.9-2
EMISSION FACTORS
7/93

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oxide is known to be a global warming gas.  The nitrogen dioxide/dimer mixture then passes
through a waste heat boiler and a platinum filter.

       Nitric Oxide Oxidation - The nitric oxide formed during the ammonia oxidation must
be oxidized.  The process stream is passed through a cooler/condenser and cooled to 38C
(100F) or less at pressures up to 800 kPa (116 psia). The nitric oxide reacts noncatalytically
with residual oxygen to form nitrogen dioxide and its liquid dimer, nitrogen tetroxide:

                           2NO  + O2  -*   2NO2  *?  N2O4                          (2)

This slow, homogeneous reaction is highly temperature and pressure dependent.  Operating at
low temperatures and high pressures promote maximum production
of NO2 within a minimum reaction time.

        Absorption - The final step introduces the nitrogen dioxide/dimer mixture into an
absorption process after being cooled.  The mixture is pumped into the bottom of the
absorption tower, while liquid dinitrogen tetroxide is added at a higher point. Deionized
process water enters the top of the column.  Both liquids flow countercurrent to the
dioxide/dimer gas mixture.  Oxidation takes place in the free space between the trays, while
absorption occurs on the trays. The absorption trays are usually sieve or bubble cap trays.
The exothermic reaction occurs as follows:

                             3N02 + H20  -* 2HN03 + NO                         (3)

        A secondary air stream is introduced into the column to re-oxidize the NO which is
formed in Reaction 3. This secondary air also removes NO2 from the product acid. An
aqueous solution of 55 to 65 percent (typically) nitric acid is withdrawn from the bottom of
the tower. The acid concentration can vary  from 30 to 70 percent nitric acid.  The acid
concentration depends upon the temperature, pressure, number of absorption stages, and
concentration of nitrogen oxides entering the absorber.

        There are two basic types of systems used to produce weak nitric acid: 1) single-stage
pressure process, and 2) dual-stage pressure process. In the past, nitric acid plants have been
operated at a single pressure, ranging from atmospheric pressure to 1400 kPa (14.7 to 203
psia). However, since Reaction 1 is favored by low pressures and Reactions 2 and 3 are
favored by higher pressures, newer plants tend to operate a dual-stage pressure system,
incorporating a compressor between the ammonia oxidizer and the condenser. The oxidation
reaction is carried out at pressures from slightly negative to about 400 kPa (58 psia), and the
absorption reactions are carried out at 800 to 1,400 kPa (116 to 203 psia).

        In the dual-stage pressure system, the nitric acid formed in the absorber (bottoms) is
usually sent  to an external bleacher where air is used to remove (bleach) any dissolved oxides
of nitrogen.  The bleacher gases are then compressed and passed through the absorber.  The
absorber tail gas (distillate) is sent to an entrainment separator for acid mist removal.  Next,
the tail gas is reheated in the ammonia oxidation heat exchanger to approximately 200 C
 (392F). The final step expands the gas in the power-recovery turbine. The thermal  energy
produced in  this  turbine can be used to drive the compressor.

5.9.2.2 High Strength Acid Nitric Production1'3

        A high-strength nitric acid (98 to 99 percent concentration) can be obtained by
 concentrating the weak nitric acid (30 to 70 percent concentration) using extractive

 7/93                            Chemical Process Industry                           5.9-3

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distillation.  The weak nitric acid cannot be concentrated by simple fractional distillation. The
distillation must be carried out hi the presence of a dehydrating agent. Concentrated sulfuric
acid (typically 60 percent sulfuric acid) is most commonly used for this purpose. The nitric
acid concentration process consists of feeding strong sulfuric acid and 55 to 65 percent nitric
acid to the top of a packed dehydrating column at approximately atmospheric pressure. The
acid mixture flows downward, countercurrent to ascending vapors. Concentrated nitric acid
leaves the top of the column as 99 percent vapor, containing a small amount of NO2 and O2
resulting from dissociation of  nitric acid.  The concentrated acid vapor leaves the column and
goes to a bleacher and a countercurrent condenser system to effect the condensation of strong
nitric acid and the separation of oxygen and nitrogen oxide by-products. These byproducts
then flow to an absorption column where the nitric oxide mixes with auxiliary air to form
NO2, which is recovered as weak nitric acid. Inert and unreacted gases are vented to the
atmosphere from the top of the absorption column. Emissions from this process are relatively
minor. A small absorber can be used to recover NO2. Figure 5.9-2 presents a flow diagram
of high-strength nitric acid production from weak nitric acid.
   50-70%
   HNO,
HNOg,N02.02
                                            COOLING
                                            WATER
                                                      INERT,
                                                      UNREACTED
                                                      GASES

BLEACHER

	 w
1 CONDENS

)
(
)
( ^
'
STRONG
NITRIC ACII
DR
AIR
03, NO
)
ABSORPTION
COLUMN
                                                                            WEAK
                                                                            NITRIC ACID
             Figure 5.9-2.  Flow diagram of high-strength nitric acid production
                                  from weak nitric acid.
5.9.3   Emissions And Controls3"5

        Emissions from nitric acid manufacture consist primarily of NO, NO2 (which account
for visible emissions) and trace amounts of HNO3 mist and NH3. By far, the major source of
nitrogen oxides is the tail gas from the acid absorption tower. In general, the quantity of NOX
emissions are directly related to the kinetics of the nitric acid formation reaction and
absorption tower design. NOX emissions can increase when there is (1) insuffficient air supply
to the oxidizer and absorber, (2) low pressure, especially in the absorber, (3) high
temperatures in the cooler-condenser and absorber, (4) production of an excessively high-
strength product acid,  (5) operation at high throughput rates, and (6) faulty equipment such as
compressors or pumps which lead to lower pressures and leaks and decrease plant efficiency.

        The two most common techniques used to control absorption tower tail gas emissions
are extended absorption and catalytic reduction. Extended absorption reduces nitrogen oxide
emissions by increasing the efficiency of the existing process absorption tower or
incorporating an additional absorption tower. An efficiency increase is achieved by increasing
5.9-4
              EMISSION FACTORS
7/93

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the number of absorber trays, operating the absorber at higher pressures, or cooling the weak
acid liquid in the absorber. The existing tower can also be replaced with a single tower of a   :
larger diameter and/or additional trays. See Reference 5 for the relevant equations.

       In the catalytic reduction process (often termed catalytic oxidation or incineration), tail
gases from the absorption tower are heated to ignition temperature, mixed with fuel (natural
gas, hydrogen, propane, butane, naphtha, carbon monoxide, or ammonia) and passed over a
catalyst bed. In the presence of the catalyst, the fuels are oxidized and the nitrogen oxides are
reduced to N2. The extent of reduction of NO2 and NO to N2 is a  function of plant design,
fuel type operating temperature and pressure, space velocity through the reduction catalytic
reactor, type of catalyst and reactant concentration. Catalytic reduction can be used in
conjunction with  other NOX emission controls. Other advantages include the capability to
operate at any pressure and the option of heat recovery to provide energy for process
compression as well as extra steam. Catalytic reduction can achieve greater NOX reduction
than extended absorption. However,  high fuel costs have caused a decline in its use.

       Two seldom used alternative control devices for absorber tail gas are molecular sieves
and wet scrubbers. In the molecular sieve adsorption technique, tail gas is contacted with an
active molecular  sieve which catalytically oxidizes NO to NO2 and selectively adsorbs the
NO2. The NO2 is then thermally stripped from the molecular sieve and returned to the
absorber. Molecular sieve adsorption has successfully controlled NOX emissions in existing
plants. However, many new plants do not install this method of control. Its implementation
incurs high capital and energy costs. Molecular sieve adsorption is a cyclic system, whereas
most new nitric acid plants are continuous systems. Sieve bed fouling can also cause
problems.

        Wet scrubbers use an aqueous solution of alkali hydroxides or carbonates, ammonia,
urea, potassium permanganate, or caustic chemicals to "scrub" NOX from the absorber tail
gas. The NO and NO2 are absorbed and recovered as nitrate or nitrate salts. When caustic
chemicals are used, the wet scrubber is referred to as a caustic scrubber. Some of the caustic
chemicals used are solutions of sodium hydroxide, sodium carbonate, or other strong bases
that will absorb NOX in the form of nitrate or nitrate salts. Although caustic scrubbing can be
an effective control device, it is often not used due to its incurred high costs and the necessity
to treat its spent  scrubbing solution.

        Comparatively small amounts of nitrogen oxides are also lost from acid concentrating
plants. These losses (mostly NO^ are from the condenser system, but the emissions are small
enough to be controlled easily by  inexpensive absorbers.

        Acid mist emissions do not occur from the tail gas of a properly operated plant: The
small amounts that may be present in the absorber exit gas streams are removed by a
separator or collector  prior to entering the catalytic reduction unit or expander.

        The acid production system  and storage tanks are the only significant sources of
visible emissions at most nitric acid plants. Emissions from acid storage tanks may occur
during tank filling.

        Nitrogen oxide emission factors shown in Table 5.9-1 vary considerably with the type
of control employed and  with process conditions.  For comparison purposes, the New Source
Performance Standard on nitrogen emission expressed as NO2 for both new and modified


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plants is 1.5 kilograms of NO2 emitted per megagram (3.0 Ib/ton) of 100 percent nitric acid
produced.
                             Table 5.9-1 (Metric and English Units).
              NITROGEN OXIDE EMISSIONS FROM NITRIC ACID PLANTS*


Control k
Source Efficiency Nit
% Pr
Weak Acid Plant Tailgas
Uncontrolled1*'0 0
Catalytic reduction0
Natural gasd 99.1
Hydrogen6 97-98.5
Natural gas/hydrogen (25%/75%)f 98-98.5
NOX
g/Mg Ib/ton Emission
ric Acid Nitric Acid Factor
oduced Produced Rating
28 57 E
0.2 0.4 E
0.4 0.8 E
0.5 0.9 E
Extended absorption 95.8
Single-Stage Process8 0.95 1.9 E
Dual-Stage Process11 1.1 2.1 E
Chilled Absorption and Caustic Scrubbed N/A
High Strength Acid Plant^ N/A
1.1 2.2 E
5 10 E
'Assumes 100% acid. Production rates are in terms of total weight of product (water and acid). A plant producing
 454 Mg (500 tons) per day of 55 weight % nitric acid is calculated as producing 250 Mg (275 tons)/day of 100%
 acid. NA - Not available.
bReference 6. Based on a study of 12 plants, with average production rate of 207 Mg (100% HNO3)/day (range
 50 - 680) at average rated capacity of 97% (range 72 - 100%).
0 Single-stage Pressure Process.
dReference 4. Fuel is assumed to be natural gas. Based on data from 7 plants, with average production rate of
 309 Mg (100% HN03)/day (range 50 - 977 Mg).
'Reference 6. Based on data from 2 plants, with average production rate of 145 Mg (100% HNO3)/day (range
 109 - 190 Mg) at average rated capacity  of 98% (range 95 - 100%).  Average absorber exit temperature is 29 C
 (85 op) {range 25 - 32C (78 - 90F)}, and the average exit pressure is 586 kPa (85 psig) {range 552 - 648 kPa
 (80-94psig)}.
'Reference 6. Based on data from 2 plants, with average production rate of 208 Mg (100%  HNO3)/day (range
168 - 249 Mg) at average rated capacity of 110% (range 100 - 119%).  Average absorber exit temperature is 33C
(91 oF) {range 28 - 37C (83 - 98oF)>, and average exit pressure is 545 kPa (79 psig) {range 545 - 552 kPa
(79 - 80 psig)}.
^Reference 4. Based on data from 5 plants, with average production rate of 492 Mg (100% HNO3)/day
 (range 190 - 952 Mg).
hReference 4. Based of data from 3 plants, with average production rate of 532 Mg (100% HNO3)/day (range
286 - 850 Mg).
^Reference 4. Based of data from 1 plant, with a production rate of 628 Mg (100% HNO3)/day.
^Reference 2. Based on data from 1 plant, with a production rate of 1.4 Mg (100% HNO3)/hour at 100%
 rated capacity, of 98% nitric acid.
5.9-6
EMISSION FACTORS
7/93

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References for Section 5.9

1.    Alternative Control Techniques Document: Nitric And Adipic Acid Manufacturing
     Plants, EPA-450/3-91-026, U. S. Environmental Protection Agency, OAQPS, Research
     Triangle Park, NC, December 1991.

2.    North American Fertilizer Capacity Data, Tennessee Valley Authority, Muscle Shoals,
     AL, December 1991.

3.    Standards of Performance for Nitric Acid Plants, 40 CFR 60 Subpart G.

4.    Marvin Drabkin, A Review Of Standards Of Performance For New Stationary
     Sources  Nitric Acid Plants, EPA-450/3-79-013, U. S. Environmental Protection
     Agency, Research Triangle Park, NC, March 1979.

5.     Unit  Operations Of Chemical Engineering, 3rd Edition, McGraw-Hill, Inc. 1976.

6.    Atmospheric Emissions From Nitric Acid Manufacturing Processes, 999-AP-27,
     U. S. Department of Health, Education, and Welfare, Cincinnati, OH,
     December  1966.
 7/93                          Chemical Process Industry                         5.9-7

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5.11      PHOSPHORIC ACID

5.11.1    General1'2

      Phosphoric acid (H3PO4) is produced by two commercial methods: wet process and thermal
process. Wet process phosphoric acid is used in fertilizer production. Thermal process phosphoric
acid is of a much higher purity and is used in the manufacture of high grade chemicals,
pharmaceutical, detergents, food products, beverages and other nonfertilizer products. In 1987 over 9
million megagrams (9 million tons) of wet process phosphoric acid was produced in the form of
phosphorus pentoxide (P2O5). Only about 363,000 megagram (400,000 tons)  of P2O5 was produced
from the thermal process. Demand for phosphoric acid has increased approximately 2.3  to 2.5 percent
per year.

      The production of wet process phosphoric acid generates a considerable quantity of acidic
cooling water with high concentrations  of phosphorus and fluoride. This excess water is collected in
cooling ponds which are used to temporarily store excess precipitation for subsequent evaporation and
to allow recirculation of the process water to the plant for re-use. Leachate seeping is therefore a
potential source of ground water contamination. Excess rainfall also  results in water overflows from
settling ponds. However, cooling water can be treated to an acceptable level of phosphorus and
fluoride if discharge is necessary.


5.11.2    Process Description3"5

5.11.2.1  Wet Process Acid Production

      In a wet process facility (see Figures 5. 11-1 A and 5.11-1B), phosphoric acid is produced by
reacting sulfuric acid (H2SO4) with naturally occurring phosphate rock. The phosphate rock is dried,
crushed and then continuously fed into the reactor along with sulfuric acid. The reaction combines
calcium from the phosphate rock with sulfate, forming calcium sulfate (CaSO4), commonly referred
to as gypsum. Gypsum is separated from the reaction solution by filtration. Facilities in the U. S.
generally use a dihydrate process that produces gypsum in the form  of calcium sulfate with two
molecules of water (CaSO4  2 H2O or calcium sulfate dihydrate). Japanese facilities use a
hemihydrate process which produces calcium sulfate with a half molecule of water (CaSO4  %
H2O). This  one-step hemihydrate process has the advantage of producing wet process phosphoric acid
with a higher P2O5 concentration and less impurities than the dihydrate process. Due to these
advantages, some U. S. companies have recently converted to the hemihydrate process.  However,
since most wet process phosphoric acid is still produced by the dihydrate process, the hemihydrate
process will not be discussed in detail here.  A simplified reaction for the dihydrate process is as
follow:
                            3H2SO4 + 6H2O -  2H3PO4 + 3[CaSO4  2H2O]i             (1)

       In order to make the strongest phosphoric acid possible and to decrease evaporation costs, 93
 percent sulfuric acid is normally used. Because the proper ratio of acid to rock in the reactor is
 critical, precise automatic process control equipment is employed in the regulation of these two feed
 streams.
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5.11-2
Figure 5.11-1 A. Flow diagram of a wet process phosphoric acid plant.



                     EMISSION FACTORS
                                                                                     7/93

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                                                   - VACUUM
                                                      TO VACUUM*
                                                      AND HOT WELL
                      TO ACID PLANT ,
                                     HYDROFLUOSIUC ACID
           Figure 5.11-1B. Flow diagram of a wet process phosphoric acid plant (cont.).

      During the reaction, gypsum crystals are precipitated and separated from the acid by filtration.
The separated crystals must be washed thoroughly to yield at least a 99 percent recovery of the
filtered phosphoric acid. After washing, the slurried gypsum is pumped into a gypsum pond for
storage. Water is syphoned off and recycled through a surge cooling pond to the phosphoric acid
process. Approximately 0.7 acres of cooling and settling pond area is required for every ton of daily
P2O5 capacity.

      Considerable heat is generated in the reactor. In older plants, this heat was removed by blowing
air over the hot slurry surface. Modern plants vacuum flash cool a portion of the slurry, and then
recycle it back into the reactor.

      Wet process phosphoric acid normally contains 26 to 30 percent P2O5. In most cases, the acid
must be further concentrated to meet phosphate feed material specifications for fertilizer production.
Depending on the types of fertilizer to be produced, phosphoric acid is  usually concentrated to 40 to
55 percent P2O5 by using two or three vacuum evaporators.

5.11.2.2   Thermal Process Acid Production

      Raw materials for the production of phosphoric acid by the thermal process are elemental
(yellow) phosphorus,  air and water. Thermal process phosphoric acid manufacture, as  shown
schematically in Figure 5.11-2, involves three major steps: 1) combustion, 2) hydration, and 3)
demisting.

      In combustion, the liquid elemental phosphorus is burned (oxidized) in ambient  air in a
combustion chamber  at temperatures of 1650 to 2760C (3000 to 5000F) to form phosphorus
pentoxide (Reaction 2). The phosphorus pentoxide is then hydrated with dilute phosphoric acid
(H3PC>4) or water to produce strong phosphoric acid liquid (Reaction 3). Demisting, the final step,
removes the phosphoric acid mist from the combustion gas stream before release to the atmosphere.
 7/93
Chemical Process Industry
5.11-3

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                                                                IP
                                                                sis
5.11-4
Figure 5.11-2.  Flow diagram of a thermal process phosphoric acid plant.


                    EMISSION FACTORS
                                                                             7/93

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This is usually done with high-pressure drop demistors.

                                     P4 + 502  -  2P205                                  (2)

                                 2P2O5 + 6H2O  -  4H3PO4                               (3)


      Concentration of phosphoric acid (H3PO4) produced from thermal process normally ranges
from 75 to 85 percent. This high concentration is required for high grade chemical production and
other nonfertilizer product manufacturing. Efficient plants recover about 99.9 percent of the elemental
phosphorus burned  as phosphoric acid.

5.11.3     Emissions And Controls 3'6

      Emission factors for controlled and uncontrolled wet phosphoric acid production are shown in
Tables 5.11-1 and 5.11-2, respectively. Emission factors for controlled thermal phosphoric acid
production are shown in Table 5.11-3.

5.11.3.1   Wet Process

      Major emissions from wet process acid production includes gaseous fluorides, mostly silicon
tetrafluoride (SiF^  and hydrogen fluoride (HF).  Phosphate rock contains  3.5 to 4.0 percent fluorine.
In general, part of the fluorine from the rock is precipitated out with the gypsum, another part is
leached out with the phosphoric acid product, and the remaining portion is vaporized in the reactor or
evaporator. The relative quantities of fluorides in the filter acid and gypsum depend on the type  of
rock and the operating conditions. Final disposition of the volatilized fluorine depends on the design
and operation of the plant.

      Scrubbers may be used to control fluorine emissions. Scrubbing systems used in phosphoric
acid plants include  venturi, wet cyclonic and semi-cross flow scrubbers. The leachate portion of the
fluorine may be deposited in settling ponds.  If the pond water becomes saturated with fluorides,
fluorine gas  may  be emitted to the atmosphere.

      The reactor in which phosphate rock is reacted with sulfuric acid is the main source of
emissions. Fluoride emissions accompany the air used to cool the reactor slurry. Vacuum flash
cooling has replaced the air cooling method  to a large extent, since emissions are minimized in the
closed system.

      Acid concentration by evaporation is another source of fluoride emissions. Approximately 20 to
40 percent of the fluorine originally present in the rock vaporizes in this operation.

      Total particulate emissions from process equipment were measured for one digester and for one
filter. As much as 5.5 kilograms of particulate per megagram (11 pounds per ton) of P2O5 were
produced by the digester, and approximately 0.1 kilograms per megagram (.2 pounds per ton) of
P2O5 were released by the filter. Of this particulate, three to six percent were fluorides.

      Particulate emissions occurring from phosphate rock handling are discussed in Section 8.18,
 Phosphate Rock Processing.
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5.11.3.2  Thermal Process

      The major source of emissions from the thermal process is phosphoric acid mist
contained in the gas stream from the hydrator. The particle size of the acid mist ranges from 1.4 to
2.6 micrometers  (ftm). It is not uncommon for as much as half of the total phosphorus pentoxide
(P2O5) to be present as liquid phosphoric acid particles suspended in the gas stream. Efficient plants
are economically motivated to control this potential loss with various control equipment. Control
equipment commonly used hi thermal process phosphoric acid plants includes venturi scrubbers,
cyclonic separators with wire mesh mist eliminators, fiber mist eliminators, high energy wire mesh
contractors, and electrostatic precipitators.
                           Table 5.11-1. (Metric and English Units).
     CONTROLLED EMISSION FACTORS FOR WET PHOSPHORIC ACID PRODUCTION*
                  Source  (SCC Code)
                                                                     Fluorine
                       kg/Mg
                        P205
                      Produced
  Ib/ton
  P205
Produced
Emission
 Factor
 Rating
 Reactorb  (SCC 3-01-016-01)

 Evaporator0   (SCC 3-01-016-99)

 Belt Filter6  (SCC 3-01-016-99)

 Belt Filter Vacuum Pump0  (SCC 3-01-016-99)

 Gypsum settling and cooling pondsde (SCC 3-01-016-02)
                      1.9 x 10'3     3.8 x 10-3      A

                    0.022 x 10'3  0.044 x 10'3     B

                     0.32 x  10'3    0.64 x 10"3      B

                    0.073 x 10'3   0.15 x 10'3      B

                    Site specific  Site specific
  SCC = Source Classification Code
 b Reference 8-13
 0 Reference 13
 d Reference 18.  Site specific. Acres of cooling pond required: ranges from 0.10 acre per daily ton
  P2O5 produced in the summer in the southeastern United States to zero in the colder locations in
  the winter months when the cooling ponds are frozen.
 * Reference 19 states "Based on our findings concerning the emissions of fluoride from gypsum
  ponds, it was concluded than no investigator had as yet established experimentally the fluoride
  emission from gypsum ponds."
5.11-6
EMISSION FACTORS
                7/93

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                         Table 5.11-2. (Metric and English Units).
  UNCONTROLLED EMISSION FACTORS FOR WET PHOSPHORIC ACID PRODUCTION*
Source (SCC Code)
Nominal
Percent
Control
Efficiency

kg/Mg
P205
Produced
Reactorb (SCC 3-01-016-01) 99 , 0.19
Evaporator0 (SCC 3-01-016-99) 99 0.00217
Belt Filter0 (SCC 3-01-016-99) 99 0.032
Belt Filter Vacuum Pump0 (SCC 3-01-016-99)
99 0.0073
Gypsum settling and cooling pondsd'e (SCC 3-01-016-02) N/A Site
specific
Fluoride
Ib/ton
P2<>5
Produced
0.38
0.0044
0.064
0.015
Site
specific

Emission
Factor
Rating
B
C
C
C

  a SCC = Source Classification Code.
  b Reference 8-13
  c Reference 13
  d Reference 18. Site specific. Acres of cooling pond required: ranges from 0.04 hectare per daily
     Mg (0.10 acre per daily ton) P2O5 produced in the summer in the southeastern U. S. to zero in
     the colder locations in the winter months when the cooling ponds are frozen.
  e Reference 19 states "Based on our findings concerning the emissions of fluoride from gypsum
     ponds, it was concluded than no investigator had as yet established experimentally the fluoride
     emission from gypsum ponds."
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Chemical Process Industry
5.11-7

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                           Table 5.11-3. (Metric and English Units).
  CONTROLLED EMISSION FACTORS FOR THERMAL PHOSPHORIC ACID PRODUCTION8
Source (SCC Code)
Nominal
Percent
Control
Efficiency
Particulateb
kg/Mg
P205
Produced
Packed tower (SCC 3-01-017-03) 95.5 1.07
Venturi scrubber (SCC3-01-017-04) 97.5 1.27
Glass fiber mist eliminator (SCC 3-01-017-05) 96-99.9 0.35
Wire mesh mist eliminator (SCC 3-01-017-06) 95 2.73
High pressure drop mist (SCC 3-01-017-07) 99.9 0.06
Electrostatic precipitator (3-01-017-08) 98-99 0.83
Ib/ton
P205
Produced
2.14
2.53
0.69
5.46
0.11
1.66
Emission
Factor
Rating
E
E
E
E
E
E
 * SCC = Source Classification Code.
 b Reference 6.
References for Section 5.11

1.    "Phosphoric Acid", Chemical and Engineering News. March 2, 1987.

2.    Suljuric/Phosphoric Acid Plant Operation, American Institute Of Chemical Engineers, New
      York,  1982.

3.    P. Becker, Phosphates And Phosphoric Acid, Raw Materials, Technology, And Economics Of
      The Wet Process, 2nd Edition, Marcel Dekker, Inc., New York, 1989.

4.    Atmospheric Emissions from Wet Process Phosphoric Acid Manufacture, AP-57, U. S.
      Environmental Protection Agency, Research Triangle Park, NC, April  1970.

5.    Atmospheric Emissions From Thermal Process Phosphoric Acid Manufacture, AP-48, U. S.
      Environmental Protection Agency, Research Triangle Park, NC, October 1968.

6.    Control Techniques For Fluoride Emissions, Unpublished, U. S. Public Health Service,
      Research Triangle Park, NC, September 1970.

7.    Final Guideline Document: Control Of Fluoride Emissions From Existing Phosphate Fertilizer
      Plants, EPA-450/2-77-005, U. S. Environmental Protection Agency, Research Triangle Park,
      NC, March 1977.

8.    Summary Of Emission Measurements - East Phos Acid, International Minerals And Chemical
      Corporation, Polk County, FL, August 1990.
5.11-8
EMISSION FACTORS
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9.    Summary Of Emission Measurements -East Phos Add, International Minerals And Chemical
      Corporation, Polk County, FL, February 1991.

10.   Summary Of Emission Measurements - East Phos Acid, International Minerals And Chemical
      Corporation, Polk County, FL, August 1991.

11.   Source Test Report, Seminole Fertilizer Corporation, Bartow, FL, September 1990.

12.   Source Test Report, Seminole Fertilizer Corporation, Bartow, FL, May 1991.

13.   Stationary Source Sampling Report, Texasgulf Chemicals Company, Aurora, NC, Entropy
      Environmentalists, Inc., Research Triangle Park, NC, December 1987.

14.   Stationary Source Sampling Report, Texasgulf Chemicals Company, Aurora, NC, Entropy
      Environmentalists, Inc., Research Triangle Park, NC. March 1987.

15.   Sulfur Dioxide Emissions Test. Phosphoric Acid Plant, Texasgulf Chemicals Company,
      Aurora,  NC, Entropy Environmentalists, Inc., Research Triangle Park, NC, August 1988.

16.   Stationary Source Sampling Report, Texasgulf Chemicals Company, Aurora, NC, Entropy
      Environmentalists, Inc., Research Triangle Park, NC, August 1987.

17.   Source Test Report, FMC Corporation, Carteret, NJ, Princeton Testing Laboratory,
      Princeton, NJ, March 1991.

18.   A. J. Buonicore and W. T. Davis, eds., Air Pollution Engineering Manual, Van Nostrand
      Reinhold, New York, NY, 1992.

19.   Evaluation  Of Emissions And Control Techniques For Reducing Fluoride Emission From
      Gypsum Ponds In The Phosphoric Acid Industry, EPA-600/2-78-124, U. S. Environmental
      Protection Agency, Research Triangle Park, NC, 1978.
 7/93                              Chemical Process Industry                            5.11-9

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5.15       SOAP AND DETERGENTS

5.15.1     General

5.15.1.1   Soap Manufacturing1'3'6

      The term "soap" refers to a particular type of detergent in which the water-solubilized group is
carboxylate and the positive ion is usually sodium or potassium. The largest soap market is bar soap
used for personal bathing. Synthetic detergents replaced soap powders for home laundering in the late
1940s, because the carboxylate ions of the soap react with the calcium and magnesium ions in the
natural hard water to form insoluble materials called lime soap. Some commercial laundries that have
soft water continue to use soap powders. Metallic soaps are alkali-earth or heavy-metal long-chain
carboxylates which are insoluble in water but soluble in nonaqueous solvents. They are used as
additives in lubricating oils, greases, rust inhibitors, and jellied fuels.

5.15.1.2   Detergent Manufacturing1'3'6'8

      The term "synthetic detergent products" applies broadly to cleaning and laundering compounds
containing surface-active (surfactant) compounds along with other ingredients. Heavy-duty powders
and liquids for home and commercial  laundry detergent comprise 60 to 65 percent of the U. S. soap
and detergent market and were estimated at 2.6 megagrams (2.86 million tons) in 1990.

      Until the early 1970s, almost all laundry detergents sold in the U. S. were heavy-duty powders.
Liquid detergents were introduced that utilized sodium citrate and sodium silicate. The liquids offered
superior performance and solubility at a slightly increased cost. Heavy-duty liquids now account for
40 percent of the laundry detergents sold in the U. S.,  up from 15 percent in 1978. As a result, 50
percent of the spray drying facilities for laundry granule production have closed since 1970. Some
current trends, including the introduction of superconcentrated powder detergents, will probably lead
to an increase in spray drying operations at some facilities. Manufacturers are also developing more
biodegradable surfactants from natural oils.

5.15.2     Process Descriptions

5.15.2.1   Soap l*>6

      From American colonial days to the early 1940s, soap was manufactured by an alkaline
hydrolysis  reaction called saponification. Soap was made in huge kettles into which fats, oils, and
caustic  soda were piped and heated to a brisk boil. After cooling for several days, salt was added,
causing the mixture to separate into two layers with the "neat" soap on top and spent lye and water on
the bottom. The soap was pumped to  a closed mixing.tank called a crutcher where builders,
perfumes, and other ingredients were added. Builders are alkaline compounds which improve the
cleaning performance of the soap. Finally, the soap was rolled into flakes, cast or milled into bars, or
spray-dried into soap powder.

      An important modern process (post 1940s) for making soap is the direct hydrolysis of fats by
water at high temperatures.  This permits fractionation of the fatty acids, which are neutralized  to soap


7/93                                Chemical Process Industry                            5.15-1

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in a continuous process as shown in Figure 5.15-1. Advantages for this process include close control
of the soap concentration, the preparation of soaps of certain chain lengths for specific purposes, and
easy recovery of glycerin, a byproduct. After the soap is recovered, it is pumped to the crutcher and
treated the same as the product from the kettle process.

5.15.2.2  Detergent1'3'6'8

      The manufacture of spray-dried detergent has three main processing steps: 1) slurry
preparation, 2) spray drying and 3) granule handling. The three major components of detergent are
surfactants (to remove dirt and  other unwanted materials), builders (to treat the water to improve
surfactant performance) and additives to improve cleaning performance. Additives may include
bleaches, bleach activators, antistatic agents, fabric softeners, optical brighteners, antiredeposition
agents, and fillers.

      The formulation of slurry for detergent granules requires the intimate mixing of various liquid,
powdered, and granulated materials. Detergent slurry is produced by blending liquid surfactant with
powdered and liquid materials (builders and other additives) in a closed mixing tank called a soap
crutcher. Premixing  of various  minor ingredients is performed in a variety of equipment prior to
charging to the crutcher or final mixer. Figure 5.15-2 illustrates the various operations. Liquid
surfactant used in making the detergent slurry is produced by the sulfonation of either a linear alkylate
or a fatly acid, which is then neutralized with a caustic solution containing sodium hydroxide
(NaOH). The blended slurry is  held hi a surge vessel for continuous pumping to a spray dryer. The
slurry is atomized  by spraying through nozzles rather than by centrifugal action. The slurry is sprayed
at pressures of 4.100 to 6.900 kPa (600 to 1000 pounds per square inch)  in single-fluid nozzles and at
pressures of 340 to 690 kPa (50 to 100 psi)  in two-fluid nozzles. Steam or air is used as the atomizing
fluid in the two-fluid nozzles. The slurry is sprayed at high pressure into a vertical drying tower
having a stream of hot air of from 315 to 400C (600 to 750F). All spray drying equipment
designed for detergent granule production incorporates the following components: spray drying tower,
air heating and supply system, slurry atomizing and pumping equipment, product cooling equipment,
and conveying equipment. Most towers designed for detergent production are countercurrent, with
slurry introduced at the top and heated air introduced at the bottom. The towers are cylindrical with
cone bottoms and range in size from 4 to 7 meters (12 to 24 feet) in diameter and 12 to 38 meters (40
to 125 feet) in height. The detergent granules are conveyed mechanically  or by air from the tower to
a mixer to incorporate additional dry or liquid ingredients,  and finally to  packaging and storage.

5.15.3    Emissions And Controls

5.15.3.1  Soap1'3'6

      The main atmospheric pollution problem  in soap manufacturing is odor. The storage and
handling of liquid  ingredients (including sulfonic acids and salts) and sulfates are some of the sources
of this odor. Vent  lines, vacuum exhausts, raw material and product storage,  and waste streams are
all potential odor sources. Control of these odors may be achieved by scrubbing exhaust fumes and, if
necessary, incinerating the remaining VOCs. Odors emanating from the spray dryer may be
controlled by scrubbing with an acid solution.  Blending, mixing, drying, packaging and other
physical operations may all involve
dust emissions. The  production of soap powder by spray drying is the single largest source of dust in
the manufacture of synthetic detergents. Dust emissions from other finishing operations can be
controlled by dry filters such as baghouses.  The large sizes of the paniculate from synthetic detergent
drying means that  high efficiency cyclones installed in series can achieve satisfactory control.


5.15-2                                EMISSION FACTORS                                 7/93

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7/93
Figure 5.15-1.  Continuous process for fatty acids and soaps.



                Chemical Process Industry
5.15-3

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Currently, no emission factors are available for soap manufacturing. No information on hazardous air
pollutants (HAPs), volatile organic compounds (VOCs), ozone depleters, or heavy metal emissions
information were found for soap manufacturing.

5.15.3.2  Detergent1'3'4'6'8

      The exhaust air from detergent spray drying towers contains two types of air contaminants: 1)
fine detergent particles and 2) organics vaporized in the higher temperature zones of the tower.
Emission factors for particulates from spray drying operations are shown in Table 5.15-1.

      Dust emissions are generated at scale hoppers, mixers, and crutchers during the batching and
mixing of fine dry ingredients to form slurry. Conveying, mixing, and packaging of detergent
granules can also cause dust emissions. Pneumatic conveying of fine-materials causes dust emissions
when conveying air is separated from bulk solids. For this process, fabric filters are generally used,
not only to reduce or to eliminate dust emissions, but also to recover raw materials. The dust
emissions principally consist of detergent compounds,  although some of the particles are uncombined
phosphates, sulfates, and other mineral compounds.

      Dry cyclones and cyclonic impingement scrubbers are the primary collection equipment
employed to capture the detergent dust in the spray dryer exhaust for return to processing. Dry
cyclones are used in parallel or in series to  collect this particulate and recycle it back to the crutcher.
The dry cyclone separators can remove 90 percent or more by weight of the detergent product fines
from the exhaust air. Cyclonic impinged scrubbers are used in parallel to collect the particulate from
a scrubbing slurry and to recycle it to the crutcher.

      Secondary collection equipment is used to collect fine particulates that escape from primary
devices. For example, cyclonic impingement scrubbers are often followed by mist eliminators, and
dry cyclones are followed  by fabric filters or scrubber/electrostatic precipitator units. Several types of
scrubbers can be used following the cyclone collectors. Venturi scrubbers have been used but are
being replaced with packed bed scrubbers. Packed bed scrubbers are usually followed by wet-pipe-
type electrostatic precipitators built immediately above the packed bed in the same vessel. Fabric
filters have been used after cyclones but have limited applicability, especially on efficient spray
dryers, due to condensing water vapor and organic aerosols binding the fabric filter.

      In addition to particulate emissions, volatile organics may be emitted when the slurry contains
organic materials with low vapor pressures. The VOCs originate primarily from the surfactants
included in the slurry. The amount vaporized depends  on many variables such as tower temperature^
and the volatility of organics used in the slurry. These vaporized organic materials condense in the
tower exhaust airstream into droplets or particles. Paraffin alcohols and amides in the exhaust stream
can result in a highly visible plume that persists after the condensed water vapor plume has dissipated.

      Opacity and the organics emissions are influenced by granule temperature and moisture at the
end of drying, temperature profiles in the dryer, and formulation of the slurry. A method for
controlling visible emissions would be to remove offending organic compounds (i. e., by substitution)
from the slurry.  Otherwise, tower production rate may be reduced thereby reducing air inlet
temperatures and exhaust temperatures. Lowering production rate will also reduce organic emissions.

      Some of the hazardous air pollutants  (HAPs) and volatile organic compounds (VOCs) identified
from the VOC/PM Speciate Database Management System (SPECIATE) are: hexane, methyl alcohol,
1,1,1-trichloroethane, perchloroethylene, benzene, and toluene. Lead was  identified from SPECIATE


5.15-4                               EMISSION FACTORS                                 7/93

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7/93
Figure 5.15-2.  Manufacture of spray-dried detergents.



             Chemical Process Industry
5.15-5

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data as the only heavy metal constituent. No numerical data are presented for lead, HAP, or VOC
emissions due to the lack of sufficient supporting documentation.
                          Table 5.15-1. (English and Metric Units).
         PARTICULATE EMISSION FACTORS FOR DETERGENT SPRAY DRYING"

Control Device Effic
(9
Uncontrolled
Particulate
iency kg/Mg.
) of Product
45
Cyclone 85 7
Cyclone with:

Spray chamber 92 3.5
Packed scrubber 95 2.5
Venturi scrubber 97 1.5
Wet scrubber 99 0.544
Wet scrubber/ESP 99.9 0.023
Packed bed/ESP 99 0.47
Fabric filter 99 0.54
Ib/ton
of Product
90
. 14

7
5
3
1.09
0.046
0.94
1.1
Emission
Factor
Rating

Eb
Eb

^
^
Eb
Eb
Eb
Ec
Eb
"Some type of primary collector, such as a cyclone, is considered integral to a spray drying system.
 ESP = Electrostatic Precipitator.
bEmission Factors are estimations and are not supported by current test data.
cEmission factor has been calculated from a single source test. An efficiency of 99% has been
 estimated.
 5.15-6
EMISSION FACTORS
7/93

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References for Section 5.15

1.    Source Category Survey: Detergent Industry. EPA Contract No. 68-02-3059, June 1980.

2.    A. H. Phelps, "Air Pollution Aspects Of Soap And Detergent Manufacture", APCA Journal,
      17, (8): 505-507. August 1967.

3.    R. N. Shreve, Third Edition: Chemical Process Industries, McGraw-Hill Book Company, New
      York, NY.          .

4.    J. H. Perry, Fourth Edition: Chemical Engineers Handbook, McGraw-Hill Book Company,
      New  York, NY.

5.    Soap And Detergent Manufacturing: Point Source Category, EPA-440/l-74-018-a, U. S.
      Environmental Protection Agency, Research Triangle Park, NC, April 1974.

6.    J. A. Danielson, Air Pollution Engineering Manual (2nd Edition), AP-40, U. S. Environmental
      Protection Agency, Research Triangle Park, NC. May 1973.  Out of Print.

7.    A. Lanteri, "Sulfonation And Sulfation Technology". Journal Of The American Oil Chemists
      Society, 55, 128-132, January 1978.

8.    A. J. Buonicore and W. T. Davis, eds., Air Pollution Engineering Manual, Van Nostrand
      Reinhold, New York, NY, 1992.

9.    Emission  Test Report, Procter And Gamble, Augusta, GA, Georgia Department Of Natural
      Resources, Atlanta, GA, July 1988.

10.   Emission  Test Report, Time Products, Atlanta, GA, Georgia Department Of Natural Resources,
      Atlanta, GA, November 1988.

11.   AIRS Facility  Subsystem Source Classification Codes And Emission Factor Listing For Criteria
      Air Pollutants, U. S. Environmental Protection Agency, Research Triangle Park, NC,
      EPA-450/4-90-003, March 1990.
 7/93                             Chemical Process Industry                            5.15-7

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5.16      SODIUM CARBONATE

5.16.1    General
      Sodium carbonate (N^COj), commonly referred to as soda ash, is one of the largest-volume
mineral products in the U.S., with 1991 production of over 9 million Mg (10.2 million tons). Over
85 percent of this soda ash originates in Wyoming, with the remainder coming from Searles Valley,
California. Soda ash is used primarily in the production of glass, chemicals, soaps and detergents, and
by consumers. Demand depends to great extent upon the price of, and environmental issues
surrounding, caustic soda, which is interchangeable with soda ash in many uses and is widely co-
produced with chlorine (see section 5.5 Chlor-Alkali).
5.16.2    Process Description

      Soda ash may be manufactured synthetically or from naturally occurring raw materials such as
ore. Only one U.S. facility recovers small quantities of Na2CO3 synthetically as a byproduct of
cresylic acid production. Other synthetic processes include the Solvay process, which involves
saturation of brine with ammonia (NH^ and carbon dioxide (CO2) gas, and the Japanese ammonium
chloride (NH4C1) coproduction process. Both of these synthetic processes result in ammonia
emissions. Natural processes include the calcination of sodium bicarbonate (NaHCO3), or nahcolite, a
naturally-occurring ore found in vast quantities in Colorado.

      The two processes presently used to produce natural soda ash differ only in the recovery and
primary treatment of the raw material used. The raw material for Wyoming soda ash is mined trona
ore, while California soda ash is derived from sodium carbonate-rich brine extracted from Searles
Lake.

      There are four distinct methods used to mine the Wyoming trona ore:  1) solution mining, 2)
room-and-pillar, 3) longwall,  and 4) shortwall. In solution mining, dilute sodium hydroxide (NaOH),
commonly called caustic soda, is injected into the trona to dissolve it. This solution  is treated with
carbon dioxide gas in carbonation towers to convert the sodium carbonate (Na2CO3) in solution to
sodium bicarbonate (NaHCO3), which precipitates and is filtered out.  The crystals are again dissolved
in water, precipitated with carbon dioxide, and filtered. The product is calcined to produce dense soda
ash. Brine extracted from below Searles Lake in California is treated similarly.

      For the room-and-pillar, longwall,  and shortwall methods, the conventional blasting agent is
prilled ammonium nitrate (NH4NO3) and fuel oil, or ANFO (see section 11.3 "Explosives
Detonation").  Beneficiation is accomplished with either of two methods called the sesquicarbonate and
the monohydrate processes. In the sesquicarbonate process, shown schematically in Figure 5.16-1,
trona ore is first dissolved hi water and then treated as brine. The liquid is filtered to remove
insoluble impurities before the sodium sesquicarbonate (Na^COj  NaHCO3 '2H2O) is precipitated out
using vacuum crystallizers. The result is centrifuged to remove remaining water, and can be sold as a
finished product or further calcined to yield soda ash of light to intermediate density. In the
monohydrate process, shown schematically in Figure 5.16-2, the crushed trona is calcined hi a rotary
kiln, yielding dense soda ash and carbon dioxide and water as by-products. The calcined material is
combined with water to allow settling out or filtering of impurities such as shale, and is then


7/93                               Chemical Process Industry                              5.16-1

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                   CONTROL
                    DEVICE
                               CONTROL
                                DEVICE
        TOONA.
         ORE
1

CRUSHERS
AND
SCREENS



DISSOLVER



VACUUM
CRYSTALLIZES



CENTRIRJQE


i

CALCINER
                                             DRY
                                            SODIUM
                                           CARBONATE
           Figure 5.16-1 Flow diagram for sesquicarbonate sodium carbonate processing
            Figure 5.16-2  Flow diagram for monohydrate sodium carbonate processing
concentrated by triple-effect evaporators and/or mechanical vapor recompression crystallizers to
precipitate sodium carbonate monohydrate (Na2CO3 -H2O). Impurities such as sodium chloride
(NaCl) and sodium sulfate (Na^O^remain in solution. The crystals and liquor are centrifuged, and
the recovered crystals are calcined again to remove remaining water. The product must then be
cooled, screened, and possibly bagged before shipping.

5.16.3    Emissions and Controls

      The principal air emissions from the sodium carbonate production methods presently used in the
U.S. are paniculate emissions from the ore calciners; soda ash coolers and dryers; ore crushing,
screening, and transporting operations; and product handling and shipping operations. Emissions of
products of combustion, such as carbon monoxide, nitrogen oxides, sulfur dioxide, and carbon
dioxide occur from direct-fired process heating units such as ore calcining kilns and soda ash dryers.
With the exception of carbon dioxide, which is suspected of contributing to global climate change,
insufficient data are available to  quantify these emissions with a reasonable level of confidence, but
similar processes are addressed in various sections of Chapter 8 of AP-42 (Mineral Products
Industries).  Emissions  of filterable  and total particulate matter from individual processes and process
5.16-2
EMISSION FACTORS
7/93

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components are quantified in Table 5.16-1 on a controlled (as-measured) basis. Emissions of total
particulate matter from these same processes are quantified in Table 5.16-2 on an uncontrolled basis.
No data quantifying emissions of organic condensible particulate matter from sodium carbonate
manufacturing processes are available, but this portion of the particulate matter can be assumed to be
negligible. Emissions of carbon dioxide from selected processes are quantified in Table 5.16-3.
Emissions from combustion sources such as boilers, and from evaporation of hydrocarbon fuels used
to fire these combustion sources, are covered in other chapters of AP-42.

      Particulate emissions from calciners and dryers are typically controlled by venturi scrubbers,
electrostatic precipitators, and/or cyclones. Baghouse filters are not well suited to applications such as
these, due to the high moisture content of the effluent gas. Particulate emissions from the ore and
product handling operations are typically controlled by either venturi scrubbers or baghouse filters.
These control devices are an integral part of the manufacturing process,  capturing raw materials and
product for economic reasons. Due to  a lack of suitable emissions data for uncontrolled processes,
controlled emission factors are presented for this industry in addition to  uncontrolled emission factors.
The uncontrolled emission factors have been calculated by applying nominal control efficiencies to the
controlled emission factors.
 7/93                                Chemical Process Industry                             5.16-3

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                                    Table 5.16-1 (Metric Units)
                        PARTICULATE MATTER: CONTROLLED BASIS

Filterable
kg/Mg Em
of F
Process (SCC Code) Product R
Ore mining0 (3-01-023-99)
0.0016
Ore crushing and screening0 (3-01-023-99) 0.0010
Ore transfer0 (3-01-023-99)
0.00008
Monohydrate process: rotary ore calciner
(3-01-023-04/05) 0.091
Sesquicarbonate process: rotary calciner
(3-01-023-99) 0.36
Sesquicarbonate process: fluid-bed
(3-01-023-99)
calciner
0.021
Rotary soda ash dryers (3-01-023-06) 0.25
Fluid-bed soda ash dryers/coolers
Soda ash screening (3-01-023-99)
(3-O1-023-07) 0.015
0.0097
Soda ash storage/loading and unloading0
(3-01-023-99) 0.0021
1 Totalb
lission kg/Mg Emission
actor of Factor
ating Product Rating
C N/Ad N/Ad
D 0.0018 C
E 0.0001 E
A 0.12 B
B 0.36 C
C N/Ad N/Ad
C 0.25 D
C 0.019 D
E 0.013 E
E 0.0026 E
      * Filterable particulate matter is that material collected in the probe and filter of a method 5 or Method
       17 sampler
      b Total particulate matter includes filterable participate and inorganic condensible particulate.
      c For ambient temperature processes, all particulate matter emissions can be assumed to be filterable at
       ambient conditions; however, particulate sampling according to EPA Reference Method 5 involves the
       heating of the front half of the sampling train to temperatures that may vaporize some portion of this
       particulate matter, which will then recondense in the back half of the sampling train. For consistency,
       particulate matter measured as condensible according to Method 5 is reported as such.
       N/A = data not available.
5.16-4
EMISSION FACTORS
7/93

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                                   Table 5.16-1 (English Units)
                        PARTICULATE MATTER: CONTROLLED BASIS

Ib
Process (SCC Code) Pr<
Filterable*
/ton Emission
of Factor
iduct Rating
Ore mining0 (3-01-023-99) 0.0033 C
Ore crushing and screening0 (3-01-023-99) 0.0021 D
Ore transfer0 (3-01-023-99) 0.0002 E
Monohydrate process: rotary ore calciner 0
; (3-01-023-04/05)
Sesquicarbonate process: rotary calciner 0
(3-01-023-99)
.18 A
.72 B
Sesquicarbonate process: fluid-bed calciner 0.043 ,C
(3-01-023-99)
Rotary soda ash dryers (3-01-023-06) 0
Fluid-bed soda ash dryers/coolers (3-01-023-07) 0.
Soda ash screening (3-01-023-99) 0.
.50 C
030 C
019 E
Soda ash storage/loading and unloading0 0.0041 E
(3-01-023-99)
Totalb
Ib/ton
of
Product
N/Ad
0.0035
0.0002
0.23
0.73
N/Ad
0.52
0.39
0.026
0.0051
Emission
Factor
Rating
N/Ad
C
E
B
C ,
N/Ad
D
D
E
E
      a Filterable particulate matter is that material collected in the probe and filter of a method 5 or Method
       17 sampler
      b Total particulate matter includes filterable particulate and inorganic condensible particulate.
      0 For ambient temperature processes, all particulate matter emissions can be assumed to be filterable at
       ambient conditions; however, particulate sampling according to EPA Reference Method 5 involves the
       heating of the front half of the sampling train to temperatures that may vaporize some portion of this
       particulate matter, which will then recondense in the back half of the sampling train. For consistency,
       particulate matter measured as condensible according to Method 5 is reported as such.
      d N/A = data not available.
7/93
Chemical Process Industry
5.16-5

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                                        TABLE 5.16-2
                     PARTICULATE MATTER: UNCONTROLLED BASIS
Process (SCC
Ore mining (3-01-023-99)
Nominal -
Control I
Efficiency
Code) (percent) ]

Ore crushing and screening (3-01-023-99)
Ore transfer (3-01-023-99)

Monohydrate process: rotary ore calciner (3-01-023-04/05) 99.9
Sesquicarfaonate process: rotary calciner (3-01-023-99)
Sesquicarfaonate process: fluid-bed
calciner (3-01-023-99)
Rotary soda ash dryers (3-01-023-06)
Fluid-bed soda ash dryers/coolers
Soda ash screening (3-01-023-99)
(3-01-023-07) 99

Soda ash storage/loading and unloading (3-01-023-99) gg g
Total8
cg/Mg Ib/ton Emission
of of Factor
'roduct Product Rating
1.6 3.3 D
1.7 3.5 E
0.1 0.2 E
90 180 B
36 72 D
2.1 4.3 D
25 50 E
1.5 3.0 E
10 19 E
2.6 5.2 E
      * Values for total particulate matter on an uncontrolled basis can be assumed to include filterable
       particulate and both organic and inorganic condensible particulate. For processes operating at
       significantly greater than ambient temperatures, these factors have been calculated by applying the
       nominal control efficiency to the controlled (as-measured) filterable particulate emission factors above.
                               TABLE 5.16-3 (METRIC UNITS)
                                     CARBON DIOXIDEa
Process
(SCC Code)
Monohydrate process: rotary ore calciner
Sesquicarbonate
Sesquicarbonate
Rotary soda ash
process:
process:
dryers
rotary calciner
Carbon Dioxide
kg/Mg
of
Product
(3-01-023-04/05) 200
(3-01-023-99) 150
fluid-bed calciner (3-01-023-99) 90
(3-01-023-06)
63
Ib/ton
of
Product
400
310
180
130
Emission
Factor
Rating
E
E
E
E
       a  Emission factors for carbon dioxide are derived from ORSAT analyses during emission
          tests for criteria pollutants, rather than from fuel analyses and material balances.
5.16-6
EMISSION FACTORS
7/93

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References for Section 5.16

1.   D.S. Kostick, "Soda Ash," Mineral Commodity Summaries 1992, pp. 162-163, U.S Department
     of the Interior, Bureau of Mines, 1992.

2.   D.S. Kostick, "Soda Ash," Minerals Yearbook 1989, Volume I: Metals and Minerals, pp. 951-
     968, U.S Department of the Interior, Bureau of Mines, 1990.

3.   SRI International, 1990 Directory of Chemical Producers: United States.

4.   L. Gribovicz, Wyoming Department of Environmental Quality, Air Quality Division, "FY 91
     Annual Inspection Report: FMC-Wyoming Corporation, Westvaco Soda Ash Refinery," 11
     June 1991.

5.   L. Gribovicz, Wyoming Department of Environmental Quality, Air Quality Division, "FY 92
     Annual Inspection Report: General Chemical Partners, Green River Works," 16 September
      1991.

6.   L. Gribovicz, Wyoming Department of Environmental Quality, Air Quality Division, "FY 92
     Annual Inspection Report: Rhdne-Poulenc Chemical Company, Big Island Mine and Refinery,"
      17 December 1991.

7.   L. Gribovicz, Wyoming Department of Environmental Quality, Air Quality Division, "FY 91
     Annual Inspection Report: Texasgulf Chemical Company, Granger Trona Mine & Soda Ash
     Refinery," 15 July 1991.

8.    "Stack Emissions Survey: General  Chemical, Soda Ash Plant,  Green River, Wyoming,"
      Western Environmental Services and Testing, Inc., Casper, WY, February 1988.

9.    "Stack Emissions Survey: General  Chemical, Soda Ash Plant,  Green River, Wyoming,"
      Western Environmental Services and Testing, Inc., Casper, WY, November 1989.

10.   "Rhone-Poulenc Wyoming Co. Particulate Emission Compliance Program," TRC
      Environmental Measurements Division, Englewood, CO,  21 May 1990.

11.   "Rhdne-Poulenc Wyoming Co. Particulate Emission Compliance Program," TRC
      Environmental Measurements Division, Englewood, CO,  6 July 1990.

12.   "Stack Emissions Survey: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, October 1990.

13.   "Stack Emissions Survey: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, February 1991.

14.   "Stack Emissions Survey: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, January 1991.

15.   "Stack Emissions Survey: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, October 1990.
 7/93                              Chemical Process Industry                            5.16-7

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16.   "Compliance Test Report: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, 6 June 1988.

17.   "Compliance Test Report: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, 24 May 1988.

18.   "Compliance Test Report: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, 28 August 1985.

19.   "Stack Emissions Survey: FMC-Wyoming Corporation, Green River, Wyoming," FMC-
      Wyoming Corporation, Green River, WY, December 1990.

20.   "Emission Measurement Test Report of GR3A Crusher," The Emission Measurement People,
      Inc.," Canon City, CO,  16 October 1990.

21.   "Stack Emissions Survey: TG Soda Ash, Inc., Granger, Wyoming," Western Environmental
      Services and Testing, Inc., Casper, WY, August 1989.

22.   "Compliance Test Reports," Tenneco Minerals, Green River, WY, 30 November 1983.

23.   "Compliance Test Reports," Tenneco Minerals, Green River, WY, 8 November 1983.

24.   "Paniculate Stack Sampling Reports," Texasgulf, Inc., Granger, WY, October 1977-September
      1978.

25.   "Fluid Bed Dryer Emissions Certification Report," Texasgulf Chemicals Co., Granger, WY, 18
      February 1985.

26.   "Stack Emissions Survey: General Chemical, Soda Ash Plant, Green River, Wyoming,"
      Western Environmental Services and Testing, Inc., Casper, WY, May 1987.
5.16-8                            EMISSION FACTORS                              7/93

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5.17       SULFURIC ACID

5.17.1     General1'2
      Sulfuric acid (F^SO^ is a basic raw material used in a wide range of industrial processes and
manufacturing operations. Almost 70 percent of sulfuric acid manufactured is used in the production
of phosphate fertilizers. Other uses include copper leaching, inorganic pigment production, petroleum
refining, paper production, and industrial organic chemical production.

      Sulfuric acid may be manufactured commercially by either the lead chamber process or the
contact process.  Because of economics, all of the sulfuric acid produced in the U. S. is now produced
by the contact process. U. S. facilities produce approximately 42 million megagrams (46.2 million
tons) of H2SO4 annually. Growth in demand was about 1 percent per year from 1981 to 1991 and is
projected to continue to increase at about 0.5 percent per year.

5.17.2     Process Description3"5

      Since the contact process is the only process currently used,  it will be the only one discussed in
this section.  Contact plants are classified  according to the raw materials charged to them: elemental
sulfur burning, spent sulfuric acid and hydrogen sulfide burning, and metal sulfide ores and smelter
gas burning. The contributions from these plants to the total acid production are 81, 8 and 11 percent,
respectively.

      The contact process incorporates three basic operations, each of which corresponds to a distinct
chemical reaction. First, the sulfur in the feedstock is oxidized (burned) to sulfur dioxide:

                                        S  +  O2  -> SO2                                     (1)


The resulting sulfur dioxide is fed to a process unit called a converter,  where it is catalytically
oxidized to sulfur trioxide:

                                     2SO2 + O2  -  2SO3                                   (2)


Finally, the sulfur trioxide is absorbed in  a strong sulfuric acid (98 percent) solution:


                                    SO3  + H2O  ->   H2SO4                                 (3)


5.17.2.1   Elemental Sulfur Burning Plants

      Figure 5.17-1 is a schematic diagram of a dual absorption contact process sulfuric acid plant
that burns elemental sulfur. In the Frasch process, elemental  sulfur is melted, filtered to remove ash,
and  sprayed under pressure into a combustion chamber. The  sulfur is burned in clean air that has
been dried by scrubbing with 93 to 99 percent  sulfuric acid. The gases from the combustion chamber
cool by passing through a waste heat boiler  and then enter the catalyst  (vanadium pentoxide)
converter. Usually, 95 to 98 percent of the sulfur dioxide from the combustion chamber is converted
to sulfur trioxide, with an accompanying large evolution of heat. After being cooled, again by

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              8
        Figure 5.17-1.  Typical contact process sulfuric acid plant burning elemental sulfur.



5.17-2                             EMISSION FACTORS
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generating steam, the converter exit gas enters an absorption tower. The absorption tower is a packed
column where acid is sprayed in the top and where the sulfur trioxide enters from the bottom. The
sulfur trioxide is absorbed in the 98 to 99 percent sulfuric acid. The sulfur trioxide combines with the
water in the acid and forms more sulfuric acid.

      If oleum (a solution of uncombined SO3 dissolved in H2SC>4) is produced, SO3 from the
converter is first passed to an oleum tower that is fed with 98 percent acid from the absorption
system. The gases from the oleum tower are then pumped to the absorption column where the
residual sulfur trioxide is removed.

      In the dual absoqjtion process shown in Figure 5.17-1, the SO3 gas formed in the primary
converter stages  is sent to an interpass absorber where most of the SO3 is removed to form H2SO4.
The remaining unconverted sulfur dioxide is forwarded to the final stages in the converter to remove
much of the remaining SO2 by oxidation to SO3, whence it is sent to the final absorber for removal of
the remaining sulfur trioxide. The single absorption process uses only one absorber,  as the name
implies.

5.17.2.2    Spent Acid And Hydrogen Sulfide Burning Plants

      A schematic diagram of a contact process sulfuric acid plant that burns spent acid is shown in
Figure 5.17-2. Two types of plants are used to process this type of sulfuric acid. In one,  the sulfur
dioxide and other products from  the combustion of spent acid and/or hydrogen sulfide with undried
atmospheric air are passed through gas cleaning and mist removal equipment. The gas stream next
passes through a drying tower. A blower draws the gas from the drying tower and discharges the
sulfur dioxide gas to the sulfur trioxide converter, then to the oleum tower and/or  absorber.

      In a  "wet gas plant", the wet gases from the combustion chamber are charged  directly to the
converter, with no intermediate treatment.  The gas from the converter flows to the absorber, through
which 93 to 98 percent sulfuric acid is circulated.

5.17.2.3   Sulfide Ores And Smelter Gas Plants

      The configuration of this type of plant is essentially the same as that of a spent acid plant
(Figure 5.17-2), with the primary exception that a roaster is used in place of the combustion furnace.

      The feed used in these plants  is smelter gas, available from such equipment  as copper
converters, reverberatory furnaces, roasters and flash smelters. The sulfur dioxide in the gas is
contaminated with dust, acid mist and gaseous impurities. To remove the impurities, the gases must
be cooled and passed through purification equipment consisting of cyclone dust collectors,
electrostatic dust and mist precipitators, and scrubbing and gas cooling towers. After the gases are
cleaned and the excess water vapor  is removed, they are scrubbed with 98 percent acid in a drying
tower. Beginning with the drying tower stage, these plants are nearly identical to the elemental sulfur
plants shown in  Figure 5.17-1.

5.17.3     Emissions4'15-7

5.17.3.1   Sulfur Dioxide

      Nearly  all sulfur dioxide emissions from sulfuric acid plants are found in the exit stack gases.
Extensive testing has shown that the mass  of  these SO2 emissions is an inverse function of the sulfur


7/93                               Chemical Process Industry                             5.17-3

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                                                                       I .   Ill
                                                                       t \   fff
    Figure 5.17-2.  Basic flow diagram of contact process sulfuric acid plant burning spent acid.



5.17-4                             EMISSION FACTORS                               7/93

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conversion efficiency (SO2 oxidized to SO3). This conversion is always incomplete, and is affected by
the number of stages in the catalytic converter, the amount of catalyst used, temperature and pressure,
and the concentrations of the reactants (sulfur dioxide and oxygen). For example, if the inlet SO2
concentration to the converter were 9  percent by volume (a representative value), and the conversion
temperature was 430C (806F), the conversion efficiency would be 98 percent. At this conversion,
Table 5.17-1  shows that the uncontrolled emission factor for SO2 would be 13 kg/Mg (26 pounds per
ton) of 100 percent sulfuric acid produced. (For purposes of comparison, note that the Agency's new
source performance standard (NSPS) for new and modified plants is 2 kg/Mg (4 pounds per ton) of
100 percent acid produced, maximum 2 hour average).  As Table 5.17-1 and Figure 5.17-3 indicate,
achieving this standard requires a conversion efficiency of 99.7 percent in an uncontrolled plant, or
the equivalent SO2 collection mechanism in a controlled facility.

      Dual absorption, as discussed above, has generally been accepted as the Best Available Control
Technology (BACT) for meeting NSPS emission limits. There are no by-products or waste scrubbing
materials created, only additional sulfuric acid. Conversion efficiencies of 99.7 percent and higher are
achievable, whereas most single absorption plants have SO2 conversion efficiencies ranging only from
95 to 98 percent. Furthermore, dual absorption permits higher converter  inlet sulfur dioxide
concentrations than are used in single absorption plants, because the final conversion stages effectively
remove any residual sulfur dioxide from the interpass absorber.

      In addition to exit gases, small  quantities of sulfur oxides are emitted from storage tank vents
and tank car and tank track vents during loading operations, from sulfuric acid concentrators, and
through leaks in process equipment. Few data are available on the quantity of emissions from these
sources.

                            Table 5.17-1 (Metric and English Units).
          SULFUR DIOXIDE EMISSION FACTORS FOR SULFURIC ACID PLANTS*
s
SO2 to SO3 kg
Conversion Efficiency
(%) Pn
O2 Emissions'*
/Mg Ib/ton
of of
Dduct Product
93 (SCC 3-01-023-18) 48.0 96
94 (SCC 3-01-023-16) 41.0 82
95 (SCC 3-01-023-14) 35.0 70
96 (SCC 3-01-023-12) 27.5 55
97 (SCC 3-01-023-10) 20.0 40
98 (SCC. 3-01-023-08) 13.0 26
99 (SCC 3-01-023-06) 7.0 14
99.5 (SCC 3-01-023-04) 3.5 7
99.7 2.0 4
100 (SCC 3-01-023-01) 0.0 0.0
Emission
Factor
Rating
E
E
E
E
E
E
E
E
E
E
 Reference 3.  SCC = Source Classification Code.
 bThis linear interpolation formula can be used for calculating emission factors for conversion efficiencies
  between 93 and 100%: emission factor = -13.65 (%-conversion efficiency) + 1365.
 7/93
Chemical Process Industry
5.17-5

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    S
    a,
    a.
    UJ
    O
    O
    o
    CD
    CO
                       SULFUR  CONVERSION, % feedstock sulfur
               99.92          99.7             99.0     98.0  97.0 96.0 95.0
        10,000
         2,500
     ^   1,500
1,000
 900
 800
 700
 600
 500
 400

 300

 250

 200
 150
           100
                    bJ
                    1
                    I
                    UJ
                    o
                    DC
                                                                 92.9
                                                                           100
                 1.5  2  2.5 3   4  5 6 78 910   15  20 25 30  40    6070 90
                                                                      80
                 SO2  EMISSIONS, Ib/ton of 100%
                                                     produced
  Figure 5.17-3. Sulfuric acid plant feedstock conversion versus volumetric and mass SO2 emissions at
              various inlet SO2 concentrations by volume.
5.17-6
                     EMISSION FACTORS
7/93


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5.17.3.2   Acid Mist

      Nearly all the acid mist emitted from sulfuric acid manufacturing can be traced to the absorber exit
gases. Acid mist is created when sulfur trioxide combines with water vapor at a temperature below the
dew point of sulfur trioxide.  Once formed within the process system, this mist is so stable that only a
small quantity can be removed in the absorber.

      In general, the quantity and particle size distribution of acid mist are dependent on the type of
sulfur feedstock used, the strength of acid  produced,  and the conditions in the absorber. Because it
contains virtually no water  vapor, bright  elemental sulfur produces little  acid  mist when burned.
However, the hydrocarbon impurities  in other feedstocks (i. e., dark sulfur, spent acid and hydrogen
sulfide) oxidize to water  vapor during combustion. The water  vapor,  in turn, combines with  sulfur
trioxide as the gas cools in the system.

      The strength of acid produced, whether  oleum or  99 percent sulfuric  acid, also affects mist
emissions. Oleum plants  produce greater  quantities  of finer  more stable mist.  For   example,  an
unpublished report found  that uncontrolled mist emissions from  oleum plants burning spent acid range
from 0.5 to 5.0 kg/Mg (1.0 to 10.0 pounds per ton), while those from  98 percent acid plants burning
elemental sulfur range from 0.2 to 2.0 kg/Mg (0.4 to 4.0 pounds per ton).4 Furthermore, 85 to 95 weight
percent of the mist particles from oleum plants are less than two microns in diameter, compared with only
30 weight percent that are less than two microns in diameter from 98 percent acid plants.

      The operating temperature of the absorption column directly affects sulfur trioxide absorption and,
accordingly, the quality of acid mist formed  after exit gases leave the  stack.  The optimum absorber
operating temperature depends on the strength of the acid produced, throughput rates, inlet sulfur trioxide
concentrations, and other variables peculiar to each individual plant. Finally, it should be emphasized that
the percentage conversion of sulfur trioxide has no direct effect on acid mist emissions.

      Table 5.17-2 presents uncontrolled acid mist emission factors for various sulfuric acid plants. Table
5.17-3  shows emission factors for plants that use fiber mist eliminator control devices. The three most
commonly used fiber mist eliminators are the vertical tube, vertical panel, and horizontal dual pad types.
They differ from one another in the arrangement of the fiber elements,  which are composed of either
chemically resistant glass or fluorocarbon, and in the means employed to collect the trapped liquid. Data
 are available  only with percent oleum ranges for two raw material categories.

 5.17.3.3       Carbon Dioxide

       The nine source tests mentioned above were also used to determine the amount of carbon dioxide
 (CO2), a global warming gas, emitted by sulfuric acid production facilities. Based on the tests, a CO2
 emission factor of 4.05 kg emitted per Mg produced (8.10 Ib/ton) was developed, with an emission factor
 rating of C.
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                           Table 5.17-2 (Metric and English Units).
    UNCONTROLLED ACID MIST EMISSION FACTORS FOR SULFURIC ACID PLANTS*
Raw Material
Oleum
Produced,
% total
output
Emissions1*
kg/Mg of
Product
Recovered sulfur (SCC 3-01-023-22) 0 to 43 0.174-0.4
Bright virgin sulfur (SCC 3-01-023-22) 0 0.85
Dark virgin sulfur (SCC 3-01-023-22) 0 to 100 0. 16 - 3. 14
Spent acid (SCC 3-01-023-22) 0 to 77 1.1-1.2
Ib/ton of
Product
Emission
Factor
Rating
0.348 - 0.8 E
1.7 E
0.32 - 6.28 E
2.2 - 2.4 E
* Reference 3. SCC = Source Classification Code,
bEmissions are proportional to the percentage of oleum in the total product. Use low end of ranges
 for low oleum percentage and high end of ranges for high oleum percentage.
                          Table 5.17-3 (Metric and English Units).
      CONTROLLED ACID MIST EMISSION FACTORS FOR SULFURIC ACID PLANTS
Raw Material
Oleum
produced,
% total
output
Emissions
kg/Mg of
Product
Elemental Sulfur*1 (SCC 3-01-023-22) - 0.064
Dark Virgin Sulfurb (SCC 3-01-023-22) 0 to 13 0.26-1.8
Spent Acid (SCC 3-01-023-22) 0 to 56 0.014-0.20
Ib/ton of
Product
Emission
Factor
Rating
0.128 C
0.52 - 3.6 E
0.28 - 0.40 E
Reference 8-13, 15-17.  SCC = Source Classification Code.
Reference 3.
References for Section 5.17

1.   Chemical Marketing Reporter, Schnell Publishing Company, Inc., New York, 240:8,
     September 16, 1991.

2.   Final Guideline Document: Control OfSuljuric Add Mist Emissions From Existing Suljuric Acid
     Production Units, EPA-450/2-77-019, U. S. Environmental Protection Agency, Research
     Triangle Park, NC, September 1977.

3.   Atmospheric Emissions From Suljuric Acid Manufacturing Processes, 999-AP-13,
     U. S. Department of Health, Education and Welfare, Washington, DC, 1966.

4.   Unpublished report on control of air pollution from sulfuric acid plants, U. S.  Environmental
     Protection Agency, Research Triangle Park, NC, August 1971.
5.17-8
EMISSION FACTORS
7/93

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5.   Review Of New Source Performance Standards For Sulfuric Acid Plants, EPA-450/3-85-012,
     U. S. Environmental Protection Agency, Research Triangle Park, NC, March 1985.

6.   Standards Of Performance For New Stationary Sources, 36 FR 24875, December 23, 1971.

7.   "Sulfuric Acid", Air Pollution Engineering Manual, Air And Water Management Association,
     1992.

8.   Source Emissions Compliance Test Report, Sulfuric Acid Stack, Roy F. Weston, Inc., West
     Chester, PA, October 1989.

9.   Source Emissions Compliance Test Report, Sulfuric Acid Stack, Roy F. Weston, Inc., West
     Chester, PA, February 1988.

10.  Source Emissions Compliance Test Report, Sulfuric Acid Stack, Roy F. Weston, Inc., West
     Chester, PA, December  1989.

11.  Source Emissions Compliance Test Report, Sulfuric Acid Stack, Roy F. Weston, Inc.; West
     Chester, PA, December  1991.

12.  Stationary Source Sampling Report, Suljuric Add Plant, Entropy Environmentalists, Inc.,
     Research Triangle Park, NC, January 1983.

13.  Source Emissions Test: Sulfuric Acid Plant, Ramcon Environmental Corporation, Memphis, TN,
     October 1989.

14.  Mississippi Chemical Corporation, Air Pollution Emission Tests, Suljuric Acid Stack,
     Environmental  Science and Engineering, Inc., Gainesville, PL, September 1973.

15.  Kennecott Copper Corporation, Air Pollution Emission Tests, Sulfuric Acid Stack - Plant 6,
     Engineering Science, Inc., Washington, DC, August 1972.

16.  Kennecott Copper Corporation, Air Pollution Emission Tests, Sulfuric Acid Stack - Plant 7,
     Engineering Science, Inc., Washington, DC, August 1972.

17.  American Smelting Corporation, Air Pollution Emission Tests, Sulfuric Acid Stack, Engineering
     Science, Inc., Washington, DC, June 1972.
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5.18      SULFUR RECOVERY

5.18.1    General1-2

      Sulfur recovery refers to the conversion of hydrogen sulfide (H2S) to elemental sulfur.
Hydrogen sulfide is a byproduct of processing natural gas and refining high-sulfur crude oils. The
most common conversion method used is the Claus process. Approximately 90 to 95 percent of
recovered sulfur is produced by the Claus process. The Claus process typically recovers 95 to 97
percent of the hydrogen sulfide feedstream.

      Over 5.9 million megagrams (6.5  million tons) of sulfur were recovered in 1989, representing
about 63 percent of the total elemental sulfur market in the U.S. The remainder was mined or
imported. The average production rate of a sulfur recovery plant in the U.S. varies from 51 to 203
megagrams (56 to 224 tons) per day.

5.18.2    Process Description1'2

      Hydrogen sulfide, a byproduct of crude oil and natural gas processing, is recovered  and
converted to elemental sulfur by the Claus process. Figure 5.18-1 shows a typical Claus sulfur
recovery unit. The process consists of multistage catalytic oxidation of hydrogen sulfide according to
the following overall reaction:

                                 2H2S + O2  -  2S  +  2H2O                               (1)

Each catalytic stage consists of a gas reheater, a catalyst chamber and a condenser.

      The Claus process involves burning one third of the hydrogen sulfide (H2S) with air in  a
reactor furnace to form sulfur dioxide (SO2) according to the following reaction:

                            2H2S  + 3O2  -*  2SO2 + 2H2O + heat          '              (2)

The furnace normally operates at combustion chamber temperatures ranging from 980 to 1540C
(1800 to 2800F) with pressures rarely higher than 70 kPa (10 psia). Before entering a sulfur
condenser, hot gas from the combustion chamber is quenched in a waste heat boiler that generates
high to medium pressure steam.  About 80 percent of the heat released could be recovered  as useful
energy. Liquid sulfur from the condenser runs through a seal leg into a covered pit from which it is
pumped to trucks or railcars for shipment to end users. Approximately 65 to 70 percent of the sulfur
is recovered. The cooled gases exiting the condenser  are then sent to the catalyst beds.

      The remaining uncombusted two-thirds of the hydrogen sulfide undergoes Claus reaction (reacts
with SO2) to form elemental sulfur as follows:

                              2H2S + SO2  ^3S + 2H2O  + heat                           (3)

The catalytic reactors operate at lower temperatures,  ranging from 200 to 315C (400 to 600F).
Alumina or bauxite is sometimes used as a catalyst. Because this reaction represents an equilibrium
chemical reaction, it is not possible for a Claus plant to convert all the incoming sulfur compounds to
elemental sulfur. Therefore, two or more stages  are used in series to recover the sulfur. Each catalytic
stage can recover half to two-thirds of the incoming sulfur.  The number of catalytic stages depends
upon the level of conversion desired. It  is estimated that 95 to 97 percent overall recovery can be

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                                   SPENT
                                  CATALYST


        ADDfTlONAL CONVERTERS/CONDENSERS TO
        ACHIEVE ADDITIONAL RECOVERY OF
        ELEMENTALSULFUR ARE OPTTONALATTHIS
        POINT
                               SULFUR
                         Figure 5.18-1  Typical Claus sulfur recovery unit
achieved depending on the number of catalytic reaction stages and the type of reheating method used.
If the sulfur recovery unit is located in a natural gas processing plant, the type of reheat employed is
typically either auxiliary burners or heat exchangers, with steam reheat being used occasionally. If the
sulfur recovery unit is located in a crude oil refinery, the typical reheat scheme uses 3536 to 4223
kPa (500 to 600 psig)  steam for reheating purposes. Most plants are now built with two catalytic
stages, although some ah- quality jurisdictions require three. From the condenser of the final catalytic
stage, the process stream passes to some form of tailgas treatment process. The tailgas, containing
H2S, SO2, sulfur vapor and traces of other sulfur  compounds formed in the combustion section,
escapes with the inert gases from the tail end of the plant. Thus, it is frequently necessary to follow
the Claus unit with a tailgas cleanup unit to achieve higher recovery.
5.18-2
EMISSION FACTORS
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      In addition to the oxidation of H2S to SO2 and the reaction of SO2 with H2S in the reaction
furnace, many other side reactions can and do occur in the furnace. Several of these possible side
reactions are:

                                  CO2 + H2S  -  COS + H2O                               (4)

                                  COS + H2S  -  CS2 + H2O                               (5)

                                     2COS  -*  CO2 + CS2                                  (6)


5.18.3     Emissions and Controls1"4

      Table 5.18-1 shows emission factors and recovery efficiencies for modified Glaus sulfur
recovery plants. Emissions from the Claus process are directly related to the recovery efficiency.
Higher recovery efficiencies mean less sulfur emitted in the tailgas. Older plants, or very small Claus
plants producing  less than 20 megagrams (22 tons) per day of sulfur without tailgas cleanup, have
varying sulfur recovery efficiencies. The efficiency depends upon several factors, including the
number of catalytic stages, the concentrations of H2S and  contaminants in the feed stream,
stoichiometric balance of gaseous components of the inlet, operating temperature, and catalyst
maintenance.

       A two-bed catalytic Claus plant can achieve 94 to 96 percent efficiency. Recoveries range from
96 to 97.5 percent for a three-bed catalytic plant and range from 97 to 98.5 percent for a four-bed
catalytic plant. At normal operating temperatures and pressures, the Claus reaction is
thermodynamically limited to  97 to 98 percent recovery. Tailgas from the Claus plant still contains
0.8 to 1.5 percent sulfur compounds.

       Existing new source performance standard (NSPS) limits sulfur emissions from Claus sulfur
recovery plants of greater than 20.32 megagrams (22.40 ton) per day capacity to 0.025 percent (250
ppmv) by volume. This limitation is effective at zero percent oxygen on a dry basis if emissions are
controlled by an  oxidation control system or a reduction control system followed by" incineration. This
is comparable to the 99.8 to 99.9 percent control level for reduced sulfur.
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                             Table 5.18-1 (Metric and English Units).
         EMISSION FACTORS FOR MODIFIED GLAUS SULFUR RECOVERY PLANTS
Number of
Catalytic Stages
Average Percent
Sulfur Recovery*
SO2 Emissions
kg/Mg of
Sulfur
Produced
Two, uncontrolled 93.5 139b'c
Three, uncontrolled 95.5d 94b>d
Four, uncontrolled 96.5e 73b'e
Two, controlledf 98.6 29
Three, controlled2 96.8 65
Ib/ton of
Sulfur
Produced
278b,c
188b'd
145b,e
57
129
Emission
Factor
Rating
E
E
E
B
B
"Efficiencies are for feedgas streams with high H2S concentrations. Gases with lower H2S concentrations would
 have lower efficiencies. For example, a 2- or 3-stage plant could have a recovery efficiency of 95% for a 90%
 H2S stream, 93% for 50% H2S, and 90% for 15% H2S.
^Reference 5. Based on net weight of pure sulfur produced. The emission factors were determined using the
average of the percentage recovery of sulfur. Sulfur dioxide emissions are calculated from percentage sulfur
recovery by one of the following equations:


                       S02 emissions (kg/Mg) =  (100-Recovery) x -^
                                                    %recovery



                       S02 emissions Ob/ton)  =  (l)-*ieeovtty) x  4000
                                                    %recovery

Typical sulfur recovery ranges from 92 to 95 percent.
^Typical sulfur recovery ranges from 95 to 96 percent.
^Typical sulfur recovery ranges from 96 to 97 percent.
^Reference 6. Test data indicated sulfur recovery ranges from 98.3 to 98.8 percent.
References 7, 8 and 9. Test data indicated sulfur recovery ranges from 95 to 99.8 percent.
 Emissions from the Claus process may be reduced by: 1) extending the Claus reaction into a lower
temperature liquid phase, 2) adding a scrubbing process to the Claus exhaust stream, or 3)
incinerating the hydrogen sulfide gases to form sulfur dioxide.

 Currently, there are five processes available that extend the Claus reaction into a lower temperature
liquid phase including the BSR/selectox,  Sulfreen, Cold Bed Absorption, Maxisulf,  and IFP-1
processes. These processes take advantage of the enhanced Claus conversion at cooler temperatures in
the catalytic stages. All of these processes give higher overall sulfur recoveries of 98 to 99 percent
when following downstream of a typical two- or three-stage Claus sulfur recovery unit, and therefore
reduce sulfur emissions.
5.18-4
EMISSION FACTORS
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 Sulfur emissions can also be reduced by adding a scrubber at the tail end of the plant. There are
essentially two generic types of tailgas scrubbing processes: oxidation tailgas scrubbers and reduction
tailgas scrubbers. The first scrubbing process is used to scrub sulfur dioxide (SO2) from incinerated
tailgas and recycle the concentrated SO2 stream back to the Glaus process for conversion to elemental
sulfur. There are at least three oxidation scrubbing processes: the Wellman-Lord, Stauffer Aquaclaus
and IFP-2. Only the Wellman-Lord process has been applied successfully to U.S. refineries.

 The Wellman-Lord process uses a wet generative process to reduce stack gas sulfur dioxide
concentration to less than 250 parts per million volume (ppmv) and can achieve approximately 99.9
percent sulfur recovery. Claus plant tailgas is incinerated and all  sulfur species are oxidized to form
sulfur dioxide (SO2) in the Wellman-Lord process. Gases are then cooled and quenched to remove
excess water and to reduce gas temperature to absorber conditions. The rich SO2 gas is then reacted
with a solution of sodium sulfite (Na2SO3) and sodium bisulfite (NaHSO3) to form the bisulfite:


                               SO2 + Na2SO3 + H2O  ^  2NaHSO3                            (7)


The offgas is reheated and vented to the atmosphere. The resulting bisulfite solution is boiled in an
evaporator-crystallizer, where it decomposes to SO2 and H2O vapor and sodium sulfite is precipitated:

                              2NaHS03  ->   NajSOgi  + H2O + SO2t                          (8)
Sulfite crystals are separated and redissolved for reuse as lean solution in the absorber. The wet SO2
gas is directed to a partial condenser where most of the water is condensed and reused to dissolve
sulfite crystals. The enriched SO2 stream is then recycled back to the Claus plant for conversion to
elemental sulfur.

  In the second type of scrubbing process, sulfur in the tailgas is converted to H2S by hydrogenation
in a reduction step. After hydrogenation, the tailgas is cooled and water is removed. The cooled
tailgas is then sent to the scrubber for H2S removal prior to venting. There are at least four reduction
scrubbing processes developed for tailgas sulfur removal: Beavon, Beavon MDEA, SCOT and
ARCO. In the Beavon process, H2S is converted to sulfur outside the  Claus  unit using a lean H2S-to-
sulfur process (the Strefford process). The other three processes utilize conventional amine scrubbing
and regeneration to remove H2S an recycle back as Claus feed.

  Emissions from the  Claus process may also be reduced by incinerating sulfur-containing tailgases to
form sulfur dioxide. In order to properly remove the  sulfur, incinerators must operate at a
temperature of 650C (1,200F) or higher if all the H2S is to be combusted. Proper air-to-fuel ratios
are needed to eliminate pluming from the incinerator  stack. The stack should be equipped with
analyzers to monitor  the SO2 level.
 7/93                               Chemical Process Industry                             5.18-5

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 References for Section 5.18

 1.    B. Goar et al., "Sulfur Recovery Technology," Energy Progress, Vol. 6(2): 71-75, June, 1986.

 2.    Written communication from Bruce Scott, Bruce Scott, Inc. to David Hendricks, Pacific
      Environmental Services, Inc., February 28, 1992.

 3.    Review of New Source Performance Standards for Petroleum Refinery Claus Sulfur Recovery
      Plants, EPA-450/3-83-014, U. S. Environmental Protection Agency, Research Triangle Park,
      NC, August 1983.

 4.    Standards Support and Environmental Impact Statement, Volume 1: Proposed Standards of
      Performance for Petroleum. Refinery Sulfur Recovery Plants. EPA-450/2-76-016a, U. S.
      Environmental Protection Agency, Research Triangle Park, NC, September 1976.

 5.    D. K. Beavon, "Abating Sulfur Plant Gases," Pollution Engineering, January/February 1972,
      pp. 34-35.

 6.    "Compliance Test Report:  Collett Ventures Company, Chatom, Alabama," Environmental
      Science & Engineering, Inc., Gainesville, FL, May 1991.

 7.    "Compliance Test Report:  Phillips Petroleum Company,  Chatom, Alabama," Environmental
      Science & Engineering, Inc., Gainesville, FL, July 1991.

 8.    "Compliance Test report: Mobil Exploration and Producing Southeast, Inc., Coden, Alabama,"
      Cubix Corporation, Austin, TX, September 1990.

 9.    "Emission Test Report: Getty Oil Company, New Hope, TX," EMB Report No. 81-OSP-9,
      July 1981.
5.18-6
EMISSION FACTORS
                                                                                      7/93

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6.8   AMMONIUM NITRATE

6.8.1 General1'3

      Ammonium nitrate (NH4NO3) is produced by neutralizing nitric acid (HNO3) with ammonia
(NH3). In 1991, there were 58 U.S. ammonium nitrate plants located in 22 states producing about 8.2
million megagrams (nine million tons) of ammonium nitrate. Approximately 15 to 20 percent of this
amount was used for explosives and the balance for fertilizer.

      Ammonium nitrate is marketed in several forms, depending upon its use. Liquid ammonium
nitrate may be sold as a fertilizer, generally in combination with urea. Liquid ammonium nitrate may
be concentrated to form an ammonium nitrate "melt" for use in solids formation processes. Solid
ammonium nitrate may be produced in the form of prills, grains, granules or crystals. Prills can be
produced in either high or low  density form,  depending on the concentration of the melt. High density
prills, granules and crystals are used as fertilizer, grains are used solely in explosives, and low
density prills can be used as either.

6.8.2 Process Description1'2

      The manufacture of ammonium nitrate involves several major unit operations including solution
formation and concentration; solids formation, finishing, screening and coating; and product bagging
and/or bulk shipping. In some cases, solutions may be blended for marketing as liquid fertilizers.
These operations are shown schematically in  Figure 6.8-1.

      The number of operating steps employed depends on the end product desired. For example,
plants producing ammonium  nitrate solutions alone use only the solution formation, solution blending
and bulk shipping operations. Plants producing a solid ammonium nitrate product may employ all of
the operations.

      All ammonium nitrate plants produce an aqueous ammonium nitrate solution through the
reaction of ammonia and nitric acid in a neutralizer as follows:

                                   NH3 + HNO3  - NH4NO3                               (1)

       Approximately 60 percent of the ammonium nitrate produced in the U.S. is sold as a solid
 product. To produce a solid product, the ammonium nitrate solution is concentrated in an evaporator
 or concentrator.  The resulting  "melt" contains about 95 to 99.8 percent ammonium nitrate at
 approximately 149C (300F). This melt is then used to make solid  ammonium nitrate products.

       Prilling and granulation  are the most common processes used to produce solid ammonium
 nitrate.  To produce prills, concentrated melt is sprayed into the top of a prill tower. In the tower,
 ammonium nitrate droplets fall countercurrent to a rising air stream that cools and solidifies the
 falling droplets into spherical prills. Prill density can be varied by using different concentrations of
 ammonium nitrate melt. Low density prills,  in the range of 1.29 specific gravity, are formed from a
 95 to 97.5 percent ammonium nitrate melt, and high density prills, in the range of 1.65 specific


 7/93                                Chemical Process Industry                               6.8-1

-------















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Figure 6.8-1 Ammonium nitrate manufacturing operations


             EMISSION FACTORS
                                                                                 7/9

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gravity, are formed from a 99.5 to 99.8 percent melt. Low density prills are more porous than high
density prills. Therefore, low density prills are used for making blasting agents because they will
absorb oil. Most high density prills are used as fertilizers.

      Rotary drum granulators produce granules by spraying a concentrated ammonium nitrate melt
(99.0 to 99.8 percent) onto small seed particles of ammonium nitrate in a long rotating cylindrical
drum. As the seed particles rotate in the drum, successive layers of ammonium nitrate are added to
the particles, forming granules. Granules are removed from the granulator and screened. Offsize
granules are crushed and recycled to the granulator to supply additional seed particles or are dissolved
and returned to the solution process. Pan granulators  operate on the same principle as drum
granulators, except the solids are formed in a large, rotating circular pan. Pan granulators produce a
solid product with physical characteristics similar to those of drum granules.

      Although not widely used, an additive such as magnesium nitrate or magnesium oxide may be
injected directly into the melt stream. This additive serves three purposes: to raise the crystalline
transition temperature of the final solid product; to act as a  desiccant, drawing water into the final
product to reduce caking; and to allow solidification to occur at a low temperature by reducing the
freezing point of molten ammonium nitrate.

      The temperature of the ammonium nitrate product exiting the solids formation process is
approximately 66 to 124C (150 to 255F). Rotary drum or fluidized bed cooling prevents
deterioration and agglomeration of solids before storage and shipping.  Low density prills have a high
moisture content because of the lower melt concentration, and therefore require drying in rotary
drums or fluidized beds before cooling.

       Since the solids are produced in a wide variety of sizes, they must be screened for consistently
sized prills or granules. Cooled prills are screened and offsize prills are dissolved and recycled to the
solution concentration process. Granules are screened before cooling. Undersize particles are returned
directly to the granulator and oversize granules may be either crushed and returned to the granulator
or sent to the solution concentration process.

       Following screening, products can be coated in a rotary drum to prevent  agglomeration during
 storage and shipment. The most common coating materials  are clays and diatomaceous  earth.
However, the use of additives  in the ammonium  nitrate melt before solidification, as described above,
 may preclude the use of coatings.

       Solid ammonium nitrate is stored and shipped  in either bulk or bags. Approximately ten percent
 of solid ammonium nitrate produced in the U.S.  is bagged.

 6.8.3      Emissions and Controls

       Emissions from ammonium nitrate production plants are paniculate matter (ammonium nitrate
 and coating materials), ammonia and nitric acid. Ammonia and nitric acid are emitted primarily from
 solution formation and granulators. Particulate matter (largely as ammonium nitrate) is emitted  from
 most of the process operations and is the primary emission addressed here.

       The emission sources in solution formation  and concentration processes are neutralizes and
 evaporators, primarily emitting nitric acid and ammonia. The vapor stream off the top  of the

 7/93                               Chemical Process Industry                              6.8-3

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 neutralization reactor is primarily steam with some ammonia and NH4NO3 participates present.
 Specific plant operating characteristics, however, make these emissions vary depending upon use of
 excess ammonia or acid in the neutralizer. Since the neutralization operation can dictate the quantity
 of these emissions, a range of emission factors is presented in Table 6.8-1. Particulate emissions from
 these operations tend to be smaller hi size than those from solids production and handling processes
 and generally are recycled back to the process.

      Emissions from solids formation processes are ammonium nitrate particulate matter and
 ammonia. The sources of primary importance are prill towers (for high density and low density  prills)
 and granulators (rotary drum and pan). Emissions from prill towers result from carryover of fine
 particles and fume by the prill cooling air flowing through the tower. These fine particles are from
 microprill formation, attrition of prills colliding with the tower or one another, and from rapid
 transition of the ammonia nitrate between crystal states.  The uncontrolled particulate emissions from
 prill towers, therefore, are affected by tower airflow, spray melt temperature, condition and type of
 melt spray device, air temperature, and crystal state changes of the solid prills. The amount of
 microprill mass that can be entrained in the prill tower exhaust is determined by the tower air
 velocity. Increasing spray melt temperature causes an increase in the amount of gas phase ammonium
 nitrate generated. Thus, gaseous emissions from high density prilling are greater than from low
 density towers.
6.8-4                                EMISSION FACTORS                                  7/9

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                                    Table 6.8-1 (Metric Units)
                           EMISSION FACTORS FOR PROCESSES IN
                     AMMONIUM NITRATE MANUFACTURING PLANTS*



Process

Meutralizer _
Evaporation/concentration operations
Solids Formation Operations
High density prill towers
Low density prill towers
Rotary drum granulators
Pan granulators
Coolers and dryers
High density prill coolers6
Low density prill coolers
Low density prill dryers6
Rotary drum granulator coolers8
Pan granulator coolers6
Coating operations^
Bulk loading operations'
Particulate Matter
Uncontrolled

kg/Mg of
Product
0.045-4.3
0.26

1.59
0.46
146
1.34

0.8
25.8
57.2
8.1
18.3
< 2.0
^ 0.01

Factor
Rating
B
A

A
A
A
A

A
A
A
A
A
B
B
Controlled1"

kg/Mg of
Product
0.002-0.22


0.60
0.26
0.22
0.02

0.01
0.26
0.57
0.08
0.18
< 0.02


Factor
Rating
B


A
A
A
A

A
A
A
A
B
B

Ammonia '.
Uncontrolled0

kg/Mg of
Product
0.43-18.0
0.27-16.7

28.6
0.13
29.7
0.07

0.02
0.15
0-1.59




iq
Factor
Rating Pr
Citric Acid

?/Mg
of Factor
oduct Rating
B 0.042-ld B
A

A
A
A.
A

A
A
A


















"Some ammonium nitrate emission factors are based on data gathered using a modification of EPA Method 5
 (See Reference 1).
bBased on the following control efficiencies for wet scrubbers, applied to uncontrolled emissions: neutralizes,
 95 percent; high density prill towers, 62 percent; low density prill towers, 43 percent; rotary drum granulators,
 99.9 percent; pan granulators, 98.5 percent; coolers, dryers, and coaters, 99%.
Given as ranges because of variation in data and plant operations. Factors for controlled emissions not
 presented due to conflicting results on control efficiency.
dBased on 95 percent recovery  in a granulator recycle scrubber.
"Factors for coolers represent combined precooler and cooler emissions, and factors for dryers represent
 combined predryer and dryer emissions.
^Fugitive particulate emissions arise from coating and bulk loading operations.
7/93
Chemical Process Industry
6.8-5

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                                 TABLE 6.8-1 (ENGLISH UNITS)
                           EMISSION FACTORS FOR PROCESSES IN
                     AMMONIUM NITRATE MANUFACTURING PLANTS4
                                    All Emission Factors are in
                                 Ratings (A-E) Follow Each Factor




Process
Neutralizer
Evaporation/concentration operations
Solids Formation Operations
High density prill towers
Low density prill towers
Rotary drum granulators
Pan granulators
Coolers and dryers
High density prill coolers0
Low density prill coolers0
Low density prill dryers0
Rotary drum granulator coolers8
Pan granulator coolers0
Coating operations^
Bulk loading operationsf
Particulate Matter


Uncontrolled
Ib/ton of
Product
0.09-8.6
0.52

3.18
0.92
392
2.68

1.6
51.6
114.4
16.2
36.6

-------
      Microprill formation resulting from partially plugged orifices of melt spray devices can increase
fine dust loading and emissions. Certain designs (spinning buckets) and practices (vibration of spray
plates) help reduce microprill formation.  High ambient air temperatures can cause increased emissions
because of entrainment as a result of higher air flow required to cool prills and because of increased
fume formation at the higher temperatures.

      The granulation process in general provides a larger degree of control in product formation
than does prilling. Granulation produces  a solid ammonium nitrate product that, relative to prills, is
larger and has greater abrasion resistance and crushing strength. The air flow in granulation processes
is lower than that in prilling operations. Granulators, however, cannot produce low density
ammonium nitrate economically with current technology. The design and operating parameters of
granulators may affect emission rates. For example, the recycle rate of seed ammonium nitrate
particles affects the bed temperature in the granulator. An increase in bed temperature resulting from
decreased recycle of seed particles may cause an increase in dust emissions from granule
disintegration.

      Cooling and drying are usually conducted in rotary drums.  As with granulators, the design and
operating parameters of the rotary drums may affect the quantity of emissions.  In addition to design
parameters, prill and granule temperature control is necessary to control emissions from  disintegration
of solids caused by changes in crystal state.

      Emissions from screening operations are generated by the attrition of the ammonium nitrate
solids against the screens and  against one another. Almost all  screening operations used in the
ammonium nitrate manufacturing industry are enclosed or have a cover over the uppermost screen.
Screening equipment  is located inside a building and emissions are ducted from the process for
recovery or reuse.

      Prills and granules are typically  coated in a rotary drum. The rotating action produces a
uniformly coated product. The mixing action also causes some of the coating material to be
suspended, creating paniculate emissions. Rotary drums used to coat solid product are typically kept
at a slight negative pressure and emissions are vented to a paniculate control device. Any dust
captured is usually recycled to the coating storage bins.

      Bagging and bulk loading operations are a source of paniculate emissions. Dust is emitted from
each type of bagging process during final filling when dust laden air is displaced from the bag by the
ammonium nitrate. The potential for emissions during bagging is greater for coated than for uncoated
material. It is expected that emissions  from bagging operations are primarily the kaolin,  talc or
diatomaceous earth coating matter. About 90 percent of solid ammonium  nitrate produced
domestically is bulk loaded. While paniculate emissions from bulk loading are not generally
controlled, visible emissions are within typical state regulatory requirements (below 20 percent
opacity).

       Table 6.8-1 summarizes emission  factors for various processes involved in the manufacture of
ammonium nitrate. Uncontrolled emissions of paniculate matter, ammonia and nitric  acid are given in
the Table. Emissions of ammonia and nitric acid depend upon specific operating practices, so ranges
of factors are given for some emission sources.

       Emission factors for controlled paniculate emissions are also in Table 6.8-1, reflecting wet

7/93                                Chemical Process Industry                               6.8-7

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 scrubbing particulate control techniques. The particle size distribution data presented in Table 6.8-2
 indicate the emissions. In addition, wet scrubbing is used as a control technique because the solution
 containing the recovered ammonium nitrate can be sent to the solution concentration process for reuse
 in production of ammonium nitrate, rather than to waste  disposal facilities.

                                         Table 6.8-2
         PARTICLE SIZE DISTRIBUTION DATA FOR UNCONTROLLED EMISSIONS
               FROM AMMONIUM NITRATE MANUFACTURING FACILITIES*
                     Operation
                                                      Cumulative Weight %
                                                2.5 /on
                                                               10 /-tm
        Solids Formation Operations
              Low density prill tower        56
              Rotary drum granulator        0.07

        Coolers and Dryers
              Low density prill cooler        0.03
              Low density prill predryer      0.03
              Low density prill dryer        0.04
              Rotary drum granulator cooler  0.06
              Pan granulator precooler       0.3
                                            73
                                            0.3


                                            0.09
                                            0.06
                                            0.04
                                            0.5
                                            0.3
83
2


0.4
0.2
0.15
3
1.5
       "References 5, 12, 13, 23 and 24. Particle size determinations were not done in strict
        accordance with EPA Method 5. A modification was used to handle the high
        concentrations of soluble nitrogenous compounds (See Reference 1). Particle size
        distributions were not determined for controlled particulate emissions.
       References for Section 6.8
       1.


       2.



       3.


       4.
Ammonium Nitrate Manufacturing Industry: Technical Document, EPA-450/3-81-002,
U.S. Environmental Protection Agency, Research Triangle Park, NC, January 1981.

WJ. Search and R.B. Reznik, Source Assessment: Ammonium Nitrate Production,
EPA-600/2-77-107i, U.S. Environmental Protection Agency, Research Triangle Park,
NC, September 1977.

North American Fertilizer Capacity Data, Tennessee Valley Authority, Muscle Shoals,
AL, December, 1.991.

Memo from C.D.  Anderson, Radian Corporation, Durham,  NC, to Ammonium Nitrate
file, July 2, 1980.
6.8-8
                       EMISSION FACTORS
                                                                                        7/9

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     5.    D.P. Becvar, et al., Ammonium Nitrate Emission Test Report: Union Oil Company of
           California, EMB-78-NHF-7, U.S. Environmental Protection Agency, Research Triangle
           Park, NC, October 1979.

     6.    K.P. Brockman, Emission Tests for Particulates, Cominco American, Beatrice, NE,
           1974.

     7.    Written communication from S.V.  Capone, GCA Corporation, Chapel Hill, NC, To
           E.A. Noble, U.S. Environmental Protection Agency, Research Triangle Park, NC,
           September 6, 1979.

      8.    Written communication from D.E. Cayard, Monsanto Agricultural Products Company,
           St. Louis, MO, to E.A.  Noble, U.S. Environmental Protection Agency, Research
           Triangle Park,  NC, December 4, 1978.

      9.    Written communication from D.E. Cayard, Monsanto Agricultural Products Company,
           St. Louis, MO, to E.A.  Noble, U.S. Environmental Protection Agency, Research
           Triangle Park,  NC, December 27, 1978.

      10.  Written communication from T.H. Davenport, Hercules Incorporated, Donora, PA, to
           D.R. Goodwin, U.S. Environmental Protection Agency, Research Triangle Park, NC,
           November 16,  1978.

      11.  R.N. Doster and D.J. Grove, Source Sampling Report: Atlas Powder Company,
           Entropy Environmentalists, Inc., Research Triangle Park, NC, August 1976.

      12.  M.D. Hansen, et al, Ammonium Nitrate Emission Test Report: Swift Chemical
           Company, EMB-79-NHF-11, U.S. Environmental Protection Agency, Research
           Triangle Park, NC, July 1980.

      13.  R.A. Kniskern, et al., Ammonium Nitrate Emission Test Report: Cominco American,
           Inc., Beatrice, NE, EMB-79-NHF-9, U.S. Environmental Protection Agency, Research
           Triangle Park, NC,  April 1979.


      14.   Written communication from J.A. Lawrence, C.F. Industries, Long Grove, IL, to D.R.
            Goodwin, U.S. Environmental Protection Agency, Research Triangle Park, NC,
            December 15, 1978.

      15.   Written communication from F.D. McLauley, Hercules Incorporated, Louisiana, MO,
            to D.R. Goodwin, U.S. Environmental Protection Agency, Research Triangle Park,
            NC, October 31,  1978.

      16.   W.E.  Misa, Report of Source Test: Collier Carbon and Chemical Corporation (Union
            Oil), Test No. 5Z-78-3, Anaheim, CA, January 12,  1978.

       17.   Written communication from L. Musgrove,  Georgia Department of Natural Resources,


7/93                             Chemical  Process Industry                             6.8-9

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             Atlanta, GA, to R. Rader, Radian Corporation, Durham, NC, May 21, 1980.

        18.   Written communication from D J. Patterson, Nitrogen Corporation, Cincinnati, OH, to
             E.A. Noble, U.S. Environmental Protection Agency, Research Triangle Park, NC,
             March 26, 1979.

        19.   Written communication from H.  Schuyten, Chevron Chemical Company,  San
             Francisco, CA, to D.R. Goodwin, U.S. Environmental Protection Agency, March 2
             1979.

        20.   Emission Test Report: Phillips Chemical Company, Texas Air Control Board, Austin,
             TX, 1975.

        21.   Surveillance Report: Hawkeye Chemical Company, U.S. Environmental Protection
             Agency, Research Triangle Park, NC, December 29, 1976.

        22.   W.A. Wade and R.W. Cass, Ammonium Nitrate Emission Test Report: C.F. Industries,
             EMB-79-NHF-10, U.S. Environmental Protection Agency, Research Triangle Park,
             NC, November 1979.

        23.   W.A. Wade, et al., Ammonium Nitrate Emission Test Report: Columbia Nitrogen
             Corporation, EMB-80-NHF-16, U.S. Environmental Protection Agency, Research
             Triangle Park, NC, January,  1981.

        24.   York Research Corporation, Ammonium. Nitrate Emission Test Report: Nitrogen
             Corporation, EMB-78-NHF-5, U.S. Environmental Protection Agency, Research
             Triangle Park, NC, May 1979.
6.8-10                            EMISSION FACTORS                                7/9

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6.10  PHOSPHATE FERTILIZERS

      Phosphate fertilizers are classified into three groups of chemical compounds.  Two of these
groups are known as supeiphosphates and are defined by the percentage of phosphorous as P2O5.
Normal superphoshate contains between 15 and 21 percent phosphorous as P2O5 wheras triple
superphosphate contains over 40 percent phosphorous. The remaining group is Ammonium
Phosphate (NH4H2PO4).
  7/93                              Chemical Process Industry                            6.10-1

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6.10.1    NORMAL SUPERPHOSPHATES

6.10.1.1  General1'3

      Normal superphosphate refers to fertilizer material containing 15 to 21 percent phosphorous as
phosphorous pentoxide (P2O5).  As defined by the Census Bureau, normal superphosphate contains not
more than 22 percent of available P2O5. There are currently about eight fertilizer facilities producing
normal superphosphates in the U.S. with an estimated total production of about 273,000 megagrams
(300,000 tons) per year.

6.10.1.2  Process Description1

      Normal superphosphates  are prepared by reacting ground phosphate rock with 65 to 75 percent
sulfuric acid. An important factor in the production of normal superphosphates is the amount of iron
and aluminum in the phosphate rock. Aluminum (as A12O3) and iron (as Fe2O3) above five percent
imparts an extreme stickiness to the superphosphate and makes it difficult to handle.

      The two general types of sulfuric acid used in superphosphate manufacture are virgin and spent
acid. Virgin acid is produced from  elemental sulfur, pyrites, and industrial gases and is relatively
pure. Spent acid is a recycled waste product from various industries that use large quantities of
sulfuric acid. Problems encountered with using spent acid include unusual color, unfamiliar odor, and
toxicity.

       A generalized flow diagram of normal superphosphate production is  shown in Figure 6.10.1-1.
Ground phosphate rock and acid are mixed  in a reaction vessel, held in an  enclosed area for about 30
minutes until the reaction is partially completed, and then transferred, using an enclosed conveyer
known as the den, to a storage pile for curing (the completion of the reaction). Following curing, the
product is most often used as a high-phosphate additive in the production of granular fertilizers. It can
 also be granulated for sale as granulated superphosphate or granular mixed fertilizer. To produce
 granulated normal superphosphate, cured superphosphate is fed through a clod breaker and sent to a
 rotary drum granulator where steam, water, and acid may be added to aid in granulation.  Material is
 processed through a rotary drum granulator, a rotary dryer, a rotary cooler, and is then screened to
 specification. Finally, it is stored in bagged or bulk form prior to being sold.

 6.10.1.3    Emissions  and Controls1"6

       Sources of emissions at a normal superphosphate plant include rock  unloading and feeding,
 mixing operations (in the reactor), storage (in the curing building), and fertilizer handling operations.
 Rock unloading, handling and  feeding generate paniculate emissions of phosphate rock dust. The
 mixer, den and curing building emit gases in the form of silicon tetrafluoride (SiF^), hydrogen
 fluoride (HF) and particulates composed of fluoride and phosphate material. Fertilizer handling
 operations  release fertilizer dust. Emission  factors  for the production of normal superphosphate are
 presented in Table 6.10.1-1.

        At a typical normal superphosphate plant, emissions from the rock unloading, handling and
 feeding operations are controlled by a baghouse. Baghouse cloth filters have reported efficiencies of

-------
                Figure 6.10.1-1  Normal superphosphate process flow diagram
6.10.1-2
EMISSION FACTORS
                                                                                  7/93

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over 99 percent under ideal conditions. Collected dust is recycled. Emissions from the mixer and den
are controlled by a wet scrubber. The curing building and fertilizer handling operations normally are
not controlled.

      Silicon tetrafluoride (SiF^ and hydrogen fluoride (HF) emissions, and paniculate from the
mixer, den and curing building are controlled by scrubbing the offgases with recycled water. Gaseous
silicon tetrafluoride in the presence of moisture reacts to form gelatinous silica, which has a tendency
to plug scrubber packings. The use of conventional packed-countercurrent scrubbers and other
contacting devices with small gas passages for emissions control is therefore limited. Scrubbers that
can be used are cyclones, venturi, impingement, jet ejector and spray-crossflow packed scrubbers.
Spray towers are also used as precontactors for fluorine removal at relatively high concentration
levels of greater than 4.67 g/m3 (3000 ppm).

      Air pollution control techniques vary with particular plant designs. The effectiveness of
abatement systems in removing fluoride and particulate also varies from plant to plant, depending on
a number of factors. The effectiveness of fluorine abatement is determined by the inlet fluorine
concentration, outlet or saturated gas temperature, composition and temperature of the scrubbing
liquid, scrubber  type and transfer units, and the effectiveness of entrainment separation. Control
efficiency is enhanced by increasing the number of scrubbing stages in series and by using a fresh
water scrub in the final stage.  Reported efficiencies for fluoride control range from less than 90
percent to over 99 percent, depending on inlet fluoride concentrations and the system employed. An
efficiency of 98  percent for particulate control is achievable.

      The emission factors have not been adjusted by this  revision, but they have been downgraded to
an "E" quality rating based on the absence of supporting source tests. The PM-10 emission factors
have been added to  the table, but were taken from the AIRS Listing for Criteria Air Pollutants, which
is also rated "E." No additional or recent data were found  concerning fluoride emissions from
gypsum ponds. A number of hazardous air pollutants (HAPs) have been identified by SPECIATE as
being present in the phosphate manufacturing process. Some HAPs identified include hexane, methyl
alcohol, formaldehyde, MEK, benzene, toluene, and styrene. Heavy metals such as lead and mercury
are present in the phosphate rock. The phosphate rock is mildly radioactive due to the presence of
some radionuclides. No emission factors are included for these HAPs, heavy metals, or radionuclides
due to the lack of sufficient data.
 7/93                               Chemical Process Industry                            6.10.1-3

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                          Table 6.10.1-1. (Metric and English Units)
      EMISSION FACTORS FOR THE PRODUCTION OF NORMAL SUPERPHOSPHATE
Emission point Pollutant
Rock
unloading1* Paniculate
PM-10
Rock feedingb Paniculate
PM-10
Mixer and den Paniculate


Fluoride
PM-10
Curing building*1 Paniculate
Fluoride

PM-10
Emission Factor
kg/Mg Ib/ton Emission
ofP2O5 ofP2O5 Factor
Produced Produced Rating
0.28 0.56 Ea
0.15 0.29 Ee
0.06 0.11 Ea
0.03 0.06 Ee
0.26 0.52 Ea
0.10 0.2 Ea
0.22 0.44 Ee
3.60 7.20 Ea
1.90 3.80 Ea
3.0 6.1 Ee
Reference 1, pp. 74-77,  169.
bFactors are for emissions from baghouse with an estimated collection efficiency of 99%.
cFactors are for emissions from wet scrubbers with a reported 97% control efficiency.
dUncontrolled.
Taken from AIRS Listing for Criteria Air Pollutants.
References for Section 6.10.1
1.    J.M. Nyers, et al., Source Assessment: Phosphate Fertilizer Industry, EPA-600/2-79-019c, U.
      S. Environmental Protection Agency, Research Triangle Park, NC, May 1979.

2.    H.C. Mann, Normal Superphosphate, National Fertilizer & Environmental Research Center,
      Tennessee Valley Authority, Muscle Shoals, Alabama, February 1992.

3.    North American Fertilizer Capacity Data (including supplement). Tennessee Valley Authority,
      Muscle Shoals, Alabama, December 1991.

4.    Background Information for Standards of Performance: Phosphate Fertilizer Industry: Volume
      1: Proposed Standards. EPA-450/2-74-019a, U. S. Environmental Protection Agency, Research
      Triangle Park, NC, October 1974.

5.    Background Information for Standards of Performance: Phosphate Fertilizer Industry: Volume
      2: Test Data Summary. EPA-450/2-74-019b, U. S. Environmental Protection Agency, Research
      Triangle Park, NC, October 1974.

6.    Final Guideline Document: Control of Fluoride Emissions from Existing Phosphate Fertilizer
      Plants. EPA-450/2-77-005, U. S.  Environmental Protection Agency, Research Triangle Park,
      NC, March  1977.
6.10.1-4
EMISSION FACTORS
7/93

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6.10.2    TRIPLE SUPERPHOSPHATES

6.10.2.1  General2'3

      Triple superphosphate, also known as double, treble, or concentrated superphosphate, is a
fertilizer material with a phosphorus content of over 40 percent, measured as phosphorus pentoxide
(P2O5). Triple superphosphate is produced in only six fertilizer facilities in the U. S. In 1989, there
were an estimated 3.2 million megagrams  (3.5 million tons) of triple superphosphate produced.
Production rates from the various facilities range from 23 to 92 megagrams (25 to 100 tons) per hour.

6.10.2.2  Process Description1'2

      Two processes have been used to produce triple superphosphate: run-of-the-pile (ROP-TSP) and
granular (GTSP). At this time, no facilities in the U. S.  are currently producing ROP-TSP, but a
process description is given.

      The ROP-TSP material is essentially a pulverized mass of variable particle size produced in a
manner similar to normal superphosphate. Wet-process phosphoric acid (50 to 55 percent P2O5) is
reacted with ground phosphate rock in a cone mixer. The resultant slurry begins to solidify on a slow
moving conveyer en route to the curing area. At the point of discharge from the den, the material
passes through a rotary mechanical cutter that breaks up the solid mass. Coarse ROP-TSP product is
sent to a storage pile and cured for three to five weeks. The product is then mined from the storage
pile to be crushed, screened, and shipped in bulk.

      Granular triple superphosphate yields larger, more uniform particles with improved storage and
handling properties. Most of this material  is made with the Dorr-Oliver slurry granulation process,
illustrated in Figure 6.10.2-1. In this process, ground phosphate rock or limestone is reacted with
phosphoric acid in one or two reactors in series. The phosphoric acid used in this process is
appreciably lower in concentration (40 percent P2O5) than that used to  manufacture ROP-TSP
product. The lower strength acid maintains the slurry in a fluid state during a mixing period of one to
two hours. A small sidestream of slurry is continuously removed and distributed onto dried, recycled
fines, where it coats the granule surfaces and builds up its size.

      Pugmills and rotating drum granulators have been used in the granulation process. Only one
pugmill is currently operating in the U.S. A pugmill is composed of a u-shaped trough carrying twin
counter-rotating shafts, upon which are mounted strong blades or paddles. The blades agitate, shear
and knead the liquified mix and transport the material along the trough. The basic rotary drum
granulator consists of an open-ended, slightly inclined rotary cylinder,  with retaining rings at each end
and a scraper or cutter mounted inside the drum shell. A rolling bed of dry material  is maintained in
the unit while the slurry is introduced through distributor pipes set lengthwise in the drum under the
bed. Slurry-wetted granules are then discharged onto a rotary dryer, where excess water is evaporated
and the chemical reaction is accelerated to completion by the dryer heat. Dried granules are then sized
on vibrating screens. Oversize particles are crushed and recirculated to the screen, and undersize
particles are recycled to the granulator. Product-size granules are cooled in a countercurrent rotary
drum, then  sent to a storage pile for curing. After a curing period of three to five days, granules are
removed from storage, screened, bagged and shipped.
 7/93                                Chemical Process Industry                           6.10.2-1

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          g
                                uj Q

                                l|i
                                111
                                o. < ui
                                        u
1
  3
i
2a
 !
                                           
                                   i
                               -3   i
                           rO:>^
      Figure 6.10.2-1. Dorr-Oliver process for granular triple superphosphate production1

6.10.2-2                      EMISSION FACTORS
                            7/93

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6.10.2.3  Emissions and Controls1'6

      Controlled emission factors for the production of GTSP are given in Table 6.10.2-1. Emission
factors for ROP-TSP are not given since it is not being produced currently in the U. S.

      Sources of particulate emissions include the reactor, granulator, dryer, screens, cooler, mills,
and transfer conveyors. Additional emissions of particulate result from the unloading, grinding,
storage, and transfer of ground phosphate rock. One facility uses limestone, which is received in
granulated form and does not require additional milling.
                              TABLE 6.10.2-1 (METRIC UNITS)
                CONTROLLED EMISSION FACTORS FOR THE PRODUCTION
                              OF TRIPLE SUPERPHOSPHATES




Granular

Process

Pollutant
triple superphosphate
Rock unloading15 Particulate

PM-10
Rock feeding15 Particulate

PM-10
Reactor, granulator, dryer, cooler and Particulate
screens0 Fluoride

PM-10
Curing building0 Particulate


Fluoride
PM-10
Controlled emission factor
kg/Mg Ib/ton Emission
of of Factor
Product Product Rating

0.09 0.18 Ea
0.04 0.08 Ed
0.02 0.04 Ea
0.01 0.02 Ed
0.05 0.10 Ea
0.12 0.24 Ea
0.04 0.08 Ed
0.10 0.20 Ea
0.02 0.04 Ea
0.08 0.17 Ed
Reference 1, pp. 77-80, 168, 170-171.
bFactors are for emissions  from baghouses with an estimated collection efficiency of 99 percent.
Factors are for emissions  from wet scrubbers with an estimated 97 percent control efficiency.
dBased on AIRS  Listing For Criteria Air Pollutants.
      Emissions of fluorine compounds and dust particles occur during the production of GTSP triple
superphosphate. Silicon tetrafluoride (SiF4) and hydrogen fluoride (HF) are released by the
acidulation reaction and they evolve from the reactors, den, granulator, and dryer. Evolution of
fluoride is essentially finished in the dryer and there is little fluoride
evolved from the storage pile in the curing building.

      At a typical plant, baghouses are used to control the fine rock particles generated by the rock
grinding and handling activities. Emissions from the reactor, den and granulator are controlled by
7/93
Chemical Process Industry
6.10.2-3

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scrubbing the effluent gas with recycled gypsum pond water hi cyclonic scrubbers. Emissions from
the dryer, cooler, screens, mills, product transfer systems, and storage building are sent to a cyclone
separator for removal of a portion of the dust before going to wet scrubbers to remove fluorides.

      Particulate emissions from ground rock unloading, storage and transfer systems are controlled
by baghouse collectors. These baghouse cloth filters have reported efficiencies of over 99 percent.
Collected  solids are recycled to the process. Emissions of silicon tetrafluoride, hydrogen fluoride, and
paniculate from the production area and curing building are controlled by scrubbing the offgases with
recycled water. Exhausts from the dryer, cooler, screens, mills, and curing building are sent first to a
cyclone separator and then to a wet scrubber. Tailgas wet scrubbers perform final cleanup of the plant
offgases.

      Gaseous silicon tetrafluoride hi the presence of moisture reacts to form gelatinous silica, which
has the tendency to plug scrubber packings. Therefore, the use of conventional packed  countercurrent
scrubbers and other contacting devices with small gas passages for emissions control is not feasible.
Scrubber types  that can be used are 1) spray tower, 2) cyclone, 3) venturi, 4) impingement, 5) jet
ejector, and 6) spray-crossflow packed.

      The effectiveness  of abatement systems for the removal of fluoride and paniculate varies from
plant to plant, depending on a number of factors. The effectiveness of fluorine abatement is
determined by:  1) inlet fluorine concentration, 2) outlet or saturated gas temperature, 3) composition
and temperature of the scrubbing liquid, 4) scrubber type and transfer units, and 5) effectiveness of
entrainment separation.  Control efficiency is enhanced by increasing the number of scrubbing stages
in series and by using a fresh water scrub in the final stage. Reported efficiencies for fluoride control
range from less than 90 percent to over 99 percent, depending on inlet fluoride concentrations and the
system employed. An efficiency of 98 percent for paniculate control is achievable.

      The paniculate and fluoride emission factors are identical to the previous revisions, but have
been downgraded to "E" quality because no documented, up-to-date source tests were available and
previous emission factors could not be validated from the references which were given. The PM-10
emission factors have been added to the table, but were derived from the AIRS Database, which  also
has an "E" rating. No additional or recent data were found concerning fluoride emissions from
gypsum ponds. A number of hazardous air pollutants (HAPs) have been identified by SPECIATE as
being present in the phosphate fertilizer manufacturing process. Some HAPs identified include
hexane, methyl  alcohol, formaldehyde, MEK, benzene, toluene, and styrene. Heavy metals such as
lead and mercury are present in the phosphate rock. The phosphate rock is mildly radioactive due to
the presence of some radionuclides. No emission factors are included for these HAPs,  heavy metals,
or radionuclides due to the lack of sufficient data.
 6.10.2-4
EMISSION FACTORS
7/93

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References for Section 6.10.2

1.    J. M. Nyers, et al, Source Assessment: Phosphate Fertilizer Industry, EPA-600/2-79-019c,
      U. S. Environmental Protection Agency, Research Triangle Park, NC, May 1979.

2.    H.C. Mann, Triple Superphosphate, National Fertilizer & Environmental Research Center,
      Tennessee Valley Authority, Muscle Shoals, Alabama, February 1992.

3.    North American Fertilizer Capacity Data (including supplement). Tennesee Valley Authority,
      Muscle Shoals, Alabama, December 1991.

4.    Background Information for Standards of Performance: Phosphate Fertilizer Industry:
      Volume 1: Proposed Standards. EPA-450/2-74-019a, U. S. Environmental Protection Agency,
      Research Triangle Park, NC, October 1974.

5.    Background Information for Standards of Performance: Phosphate Fertilizer Industry:
      Volume 2: Test Data Summary. EPA-450/2-74-019b, U. S. Environmental Protection Agency,
      Research Triangle Park, NC, October 1974.

6.    Final Guideline Document: Control of Fluoride Emissions from Existing Phosphate Fertilizer
      Plants.  EPA-450/2-77-005, U.  S. Environmental  Protection Agency, Research Triangle Park,
      NC, March 1977.
7/93                              Chemical Process Industry                           6.10.2-5

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6.10.3   AMMONIUM PHOSPHATE

6.10.3.1 General1

        Ammonium phosphate (NH4H2PO4) is produced by reacting phosphoric acid (H3PO4) with
anhydrous ammonia (NH3). Ammoniated superphosphates are produced by adding normal
superphosphate or triple superphosphate to the mixture. The production of liquid ammonium
phosphate and ammoniated superphosphates in fertilizer mixing plants is considered a separate
process. Both solid and liquid ammonium phosphate fertilizers are produced in the  U.S. This
discussion covers only the granulation of phosphoric acid with anhydrous ammonia to produce
granular fertilizer. Total ammonium phosphate production in the U.S. in 1992 was  estimatd to be 7.7
million  megagrams (8.5 million tons).2

6.10.3.2 Process Description1

        Two basic mixer designs are used by ammoniation-granulation plants: the pugmill ammoniator
and the  rotary drum ammoniator. Approximately 95 percent of ammoniation-granulation plants in the
United States use a rotary drum mixer developed and patented by the Tennessee Valley Authority
(TVA).  The basic rotary drum ammoniator-granulator consists of a slightly inclined open-end rotary
cylinder with retaining rings at each end, and  a scrapper or cutter mounted inside the drum shell. A
rolling bed of recycled solids is maintained in the unit.

        Ammonia-rich offgases pass through a wet scrubber before exhausting to the atmosphere.
Primary scrubbers use raw materials mixed with acids (such as scrubbing liquor), and secondary
scrubbers use gypsum pond water.

        In the TVA process, phosphoric acid is mixed in an acid surge tank with 93 percent sulfuric
acid (H2SO4), which is used for product analysis control, and with recycled acid from wet scrubbers.
(A schematic diagram of the ammonium phosphate process flow diagram is shown  in Figure
6.10.3-1.) Mixed acids are then partially neutralized with liquid or gaseous anhydrous ammonia in a
brick-lined acid reactor. All of the phosphoric acid and approximately 70 percent of the ammonia are
introduced into this vessel. A slurry of ammonium phosphate and 22 percent water are produced and
sent through steam-traced lines to the ammoniator-granulator. Slurry from the reactor is distributed on
the bed, the remaining ammonia (approximately 30 percent) is sparged underneath. Granulation, by
agglomeration and by coating paniculate with slurry, takes place in the rotating drum and is
completed in the dryer. Ammonia-rich offgases pass through a wet scrubber before exhausting to the
atmosphere. Primary scrubbers use raw materials mixed with acid (such as scrubbing liquor), and
secondary scrubbers use pond water.

        Moist ammonium phosphate granules  are transferred to a rotary concurrent dryer and then to
a cooler. Before being exhausted to the atmosphere,  these offgases pass through cyclones and wet
scrubbers.  Cooled granules pass to a double-deck screen, in which oversize and undersize particles
are separated from product particles. The product ranges in granule size from 1 to 4 millimeters
(mm). The oversized granules are crushed, mixed with the undersized, and recycled back to the
ammoniator-granulator.

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                         11
                         11
                         TT
                                                 I
                Figure 6.10.3-1.  Ammonium phosphate process flow diagram
6.10.3-2
EMISSION FACTORS
7/93

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6.10.3.3  Emissions and Controls1

       Sources of air emissions from the production of ammonium phosphate fertilizers include the
reactor, the ammoniator-granulator, the dryer and cooler, product sizing and material transfer, and
the gypsum pond. The reactor and ammoniator-granulator produce emissions of gaseous ammonia,
gaseous fluorides such as hydrogen fluoride (HF) and silicon tetrafluoride (SiF^, and paniculate
ammonium phosphates.  These two exhaust streams  are generally combined and passed through
primary and secondary scrubbers.

       Exhaust gases from the dryer and cooler also contain ammonia, fluorides and particulates and
these streams are commonly combined and  passed through cyclones and primary and secondary
scrubbers. Particulate emissions and low levels of ammonia and fluorides from product sizing and
material transfer operations are controlled the same way.

       Emissions factors for ammonium phosphate production are summarized in Table 6.10.3-1.
These emission factors are averaged based on recent source test data from controlled phosphate
fertilizer plants in Tampa, Florida.

                                Table 6.10.3-1. (Metric  Units)
                   AVERAGE CONTROLLED  EMISSION FACTORS FOR
                    THE PRODUCTION OF AMMONIUM PHOSPHATES*
Emission Point
Fluoride as F
kg/Mg
of
Product
Reactor/ammoniator-
granulator 0.02
Dryer/cooler 0.02
Product sizing and
material transfer1* 0.001
Total plant emissions 0.02C
Factor
Rating
Particulate
kg/Mg
of
Product

E 0.76
E 0.75
E 0.03
A 0.34d
Factor
Rating
Ammonia
kg/Mg
of
Product
Factor
Rating
SO2
kg/Mg Factor
of Rating
Product

E
E
E
A 0.07 E 0.04e E
a Reference 1, pp. 80-83, 173
b Represents only one sample.
c References 7, 8, 10, 11, 13-15. EPA has promulgated a fluoride emission guideline of 0.03 kg/Mg
  P2O5 input.
d References 7, 9, 10, 13-15.
eBased on limited data from only one plant, Reference 9.
7/93
Food and Agricultural Industry
6.10.3-3

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                                Table 6.10.3-1. (English Units)
                   AVERAGE CONTROLLED EMISSION FACTORS FOR
                    THE PRODUCTION OF AMMONIUM PHOSPHATES*
Emission Point
Fluoride as F
Ib/ton of
Product
Reactor/ammoniator-
granulator 0.05
Dryer/cooler 0.04
Product sizing and
material transfer1' 0.002
Total plant emissions 0.04
Factor
Rating
Particulate
Ib/ton
of
Product
E 1.52
E 1.50
E 0.06
A 0.68d
Factor
Rating
Ammonia
Ib/ton
of
Product
Factor
Rating
SO2
Ib/ton
of Factor
Product Rating
E
E
E
A 0.14 E 0.08e E
* Reference 1, pp. 80-83,  173
b Represents only one sample.
0 References 7, 8, 10, 11, 13-15. EPA has promulgated a fluoride emission guideline of 0.03 kg/Mg
 P2O5 input.
d References 7, 9, 10, 13-15.
       on limited data from only one plant, Reference 9.
      Exhaust streams from the reactor and ammoniator-granulator pass through a primary scrubber,
in which phosphoric acid is used to recover ammonia and paniculate. Exhaust gases from the dryer,
cooler and screen first go to cyclones for particulate recovery, and then to primary  scrubbers.
Materials collected in the cyclone and primary scrubbers are returned to the process. The exhaust is
sent to secondary scrubbers, where recycled gypsum pond water is used as a scrubbing liquid to
control fluoride emissions.  The scrubber effluent is returned to the gypsum pond.

      Primary scrubbing equipment commonly includes venturi and cyclonic spray  towers.
Impingement scrubbers and spray-crossflow packed bed scrubbers are used as secondary  controls.
Primary scrubbers generally use phosphoric acid of 20 to 30 percent as scrubbing liquor, principally
to recover ammonia. Secondary scrubbers generally use gypsum and pond water for fluoride control.

      Throughout the industry, however, there are many combinations and variations. Some plants
use reactor-feed concentration phosphoric acid (40 percent P2O5) in both primary and secondary
scrubbers, and some use phosphoric acid near the dilute end of the 20 to 30 percent P2O5 range in
only a single scrubber. Existing plants are equipped with ammonia recovery scrubbers on the reactor,
ammoniator-granulator and dryer, and particulate controls  on the dryer and cooler.  Additional
scrubbers for fluoride removal exist, but they are not typical. Only 15 to 20 percent of installations
contacted in an EPA survey were equipped with spray-crossflow packed bed scrubbers or their
equivalent for fluoride removal.
6.10.3-4
EMISSION FACTORS
7/93

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      Emission control efficiencies for ammonium phosphate plant control equipment are reported as
94 to 99 percent for ammonium, 75 to 99.8 percent for particulates, and 74 to 94 percent for
fluorides.
References for Section 6.10.3
1.    J.M. Nyers, et al., Source Assessment: Phosphate Fertilizer Industry, EPA-600/2-79-019c, U.S.
      Environmental Protection Agency, Research Triangle Park, NC, May 1979.

2.    North American Fertilizer Capacity Data, Tennessee Valley Authority, Muscle Shoals, AL,
      December 1991.

3.    Compliance Source Test Report: Texasgulf Inc., Granular Triple Super Phosphate Plant,
      Aurora, NC, May 1987.

4.    Compliance Source Test Report: Texasgulf Inc., Diammonium Phosphate Plant No.2, Aurora,
      NC, August 1989.

5.    Compliance Source Test Report: Texasgulf Inc., Diammonium Phosphate Plant #2, Aurora,
      NC, December 1991.

6.    Compliance Test Report: Texasgulf, Inc., Diammonium Phosphate #1, Aurora, NC, September
      1990.

7.    Compliance Source Test Report: Texasgulf Inc., Ammonium Phosphate Plant #2, Aurora, NC,
      November 1990.

8.    Compliance Source Test Report: Texasgulf Inc., Diammonium Phosphate Plant #2, Aurora,
      NC, November  1991.

9.    Compliance Source Test Report: IMC Fertilizer, Inc., $1 DAP plant, Western Polk County, PL,
      October 1991.

10.   Compliance Source Test Report: IMC Fertilizer, Inc., #2 DAP Plant, Western Polk County, FL,
      June 1991. 7

11.   Compliance Source Test Report: IMC Fertilizer, Inc., Western Polk County, FL, April  1991.
 7/93                            Food and Agricultural Industry                        6.10.3-5

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6.14      UREA

6.14.1    General1'14
      Urea [ CO^H^ ], also known as carbamide or carbonyl diamide, is marketed as a solution or
in solid form. Most urea, solution produced is used in fertilizer mixtures,  with a small amount going to
animal feed supplements. Most solids are produced as prills or granules, for use as fertilizer or protein
supplement in animal feed, and in plastics manufacturing.  Five U.S. plants  produce solid urea in
crystalline form. About  7.3 million megagrams (8 million tons) of urea were produced in the U.S. in
1991. About 85 percent was used in fertilizers (both solid and solution forms), 3 percent in animal feed
supplements and the remaining 12 percent in plastics and other uses.

6.14.2    Process Description1'2

      The process for manufacturing urea involves a combination of up to seven major unit operations.
These  operations, illustrated by  the flow diagram  in Figure 6.14-1, are solution synthesis, solution
concentration, solids formation, solids cooling, solids screening, solids coating and bagging and/or bulk
shipping.

      The combination of processing steps is determined by the desired end products. For example, plants
producing urea solution use only the  solution formulation  and bulk shipping operations.  Facilities
producing solid  urea  employ  these two  operations  and various combinations  of the remaining five
operations, depending upon the specific end product  being produced.

      In the solution synthesis operation, ammonia (NH3) and carbon dioxide (CO^ are reacted to form
ammonium carbamate (NH2CO2NH4). Typical operating conditions include temperatures from 180 to
20C (356 to 392F), pressures from  140 to 250 atm, NH3:CO2 molar  ratios from 3:1 to 4:1, and a
retention time of 20 to 30 minutes. The carbamate is then dehydrated to yield 70 to 77 percent aqueous
urea solution. These reactions are as follows:

                                2NH3  +  C02 -*  NH2CO2NH4                             (1)

                             NH2CO2NH4 - NH2CONH2 + H2O                         (2)

The urea solution can be used as an ingredient of nitrogen solution fertilizers, or it can be concentrated
further to produce solid  urea.

      The three methods of concentrating the urea solution are vacuum concentration, crystallization and
atmospheric evaporation. The  method chosen  depends upon the level of biuret (NH2CONHCONH2)
impurity  allowable in the end product. Aqueous urea solution begins to decompose at 60C (140F) to
biuret  and ammonia. The most common method of solution concentration is evaporation.
      The concentration process furnishes urea "melt" for solids formation. Urea solids are produced
from the urea melt by two basic methods: prilling and granulation. Prilling is a  process by which solid
particles  are produced from molten urea. Molten urea is sprayed from the top of a prill tower. As the
droplets fall through a countercurrent air flow, they cool  and solidify into nearly spherical particles.
There  are two types of prill towers, fluidized bed and nonfluidized bed. The major difference is that a
separate solids cooling operation may be required to produce agricultural grade  prills in a nonfluidized
bed prill  tower.

7/93                               Chemical Process Industry                             6.14-1

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6.14-2
                      Figure 6.14-1  Major urea manufacturing operations
EMISSION FACTORS
7/93


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       Granulation is used more frequently than prilling in producing solid urea for fertilizer. Granular
 urea is generally stronger than prilled urea, both in crushing strength and abrasion resistance. There are
 two granulation methods, drum granulation and pan granulation. In drum granulation, solids are built up
 in layers on seed granules placed in a rotating drum granulator/cooler approximately 4.3 meters (14 feet)
 in diameter. Pan granulators also form the product in a layering process, but different equipment is used
 and pan granulators are not commonly used in the U.S.

       The solids cooling operation is generally accomplished  during solids formation, but for  pan
 granulation processes and for some agricultural grade prills, some supplementary cooling is provided by
 auxiliary rotary drums.

       The solids screening operation removes offsize product from solid urea. The offsize material may
 be  returned to the process in the  solid phase or be redissolved in water and returned to the solution
 concentration process.

       Clay coatings are used in the urea industry to reduce product caking and urea dust formation. The
 coating also reduces  the nitrogen content of  the product. The use of clay coating  has  diminished
 considerably,  being replaced by injection of formaldehyde additives into the liquid or molten urea before
 solids  formation. Formaldehyde reacts with  urea to from methylenediurea,  which is the conditioning
 agent.  Additives reduce solids  caking during  storage and urea  dust formation during  transport  and
 handling.
       The majority of solid urea product is bulk shipped in trucks, enclosed railroad cars or barges, but
 approximately ten percent is bagged.

 6.14.3    Emissions and Controls1'3"7

       Emissions from urea manufacture are mainly ammonia and particulate matter. Formaldehyde  and
 methanol, hazardous air pollutants (HAPs) may be emitted if additives are used. Formalin, used as a
 formaldehyde additive, may contain up to 15 percent methanol. Ammonia is emitted during the solution
 synthesis and  solids production processes. Particulate matter is emitted during all urea processes. There
 have been no reliable measurements of free  gaseous formaldehyde emissions. The chromotropic acid
 procedure that has been used to measure formaldehyde is not capable of distinguishing between gaseous
 formaldehyde and methylenediurea, the principle compound formed when the formaldehyde additive
 reacts  with hot urea.
      Table 6.14-1  summarizes the uncontrolled and controlled emission factors, by processes, for urea
 manufacture. Table 6.14-2 summarizes particle sizes for these emissions.
      In the synthesis process, some emission control is inherent in the recycle process where carbamate
 gases and/or liquids are recovered and recycled. Typical emission sources from the solution synthesis
 process are noncondensable vent  streams  from  ammonium  carbamate decomposers and  separators.
 Emissions  from synthesis processes  are generally combined  with  emissions  from  the  solution
 concentration process and are vented through a common stack. Combined particulate emissions from urea
 synthesis and concentration operations are small compared to particulate emissions from a typical solids-
 producing urea plant. The synthesis and concentration operations are usually uncontrolled except for
 recycle provisions to  recover  ammonia. For these reasons, no  factor for controlled emissions from
 synthesis and concentration processes is given in this section.

     Uncontrolled emission rates from prill towers may be affected by the following factors: 1) product
grade  being produced,  2)  air flow rate through  the tower, 3)  type of tower bed, and 4) ambient
temperature and humidity.


7/93                               Chemical Process Industry                             6.14-3

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      The total of mass emissions per unit is usually lower for feed grade prill production than for
agricultural grade prills, due to lower airflows. Uncontrolled paniculate emission rates for fluidized bed
prill towers are higher than those for nonfluidized bed prill towers making agricultural grade prills, and
are approximately equal to those for nonfluidized bed feed grade prills. Ambient air conditions can affect
prill tower emissions. Available data indicate that colder temperatures promote the formation of smaller
particles in the prill tower exhaust. Since smaller particles are more difficult to remove, the efficiency
of prill tower control devices tends to decrease with ambient temperatures.  This can lead to higher
emission levels for prill towers operated  during cold weather. Ambient humidity can also  affect prill
tower emissions. Air flow rates must be increased with high humidity, and higher air flow rates usually
cause higher emissions.
      The design parameters of drum granulators and rotary drum coolers may affect emissions. Drum
granulators have an advantage over prill towers in that they are capable of producing very large particles
without difficulty.  Granulators also require less air for operation than do prill towers. A disadvantage of
granulators is their inability to produce the smaller feed grade granules economically. To produce smaller
granules, the drum must be operated at a higher seed particle recycle rate. It has been reported that,
although the increase in seed material results in a lower bed temperature, the corresponding  increase in
fines  in the granulator causes a higher emission rate. Cooling air passing through the drum granulator
entrains approximately  10 to 20 percent of the  product. This  air stream is controlled with a wet scrubber
which is standard process equipment on drum granulators.

      In the solids screening process,  dust is  generated by abrasion of urea particles and the vibration
of the screening mechanisms.  Therefore, almost all screening operations used in the urea manufacturing
industry are enclosed or are  covered  over the uppermost screen. This operation is a small emission
source, therefore particulate emission factors from solids screening are not presented.

      Emissions attributable to coating include entrained clay dust from loading, inplant transfer and leaks
from the seals of the coater. No emissions data are available to quantify this fugitive dust source.

      Bagging operations are sources of particulate emissions. Dust is emitted from each bagging method
during the final stages of filling, when dust-laden air is  displaced from  the bag by  urea. Bagging
operations are conducted inside warehouses and are usually vented to keep dust out of the workroom area,
as mandated by OSHA regulations. Most vents are controlled with baghouses. Nationwide, approximately
90 percent of urea produced is bulk loaded. Few plants control their bulk loading operations.  Generation
of visible fugitive particles is negligible.

      Urea manufacturers presently control particulate matter emissions from  prill towers, coolers,
granulators and bagging operations. With the exception of bagging operations, urea emission  sources are
usually controlled with wet  scrubbers. Scrubber  systems  are preferred over dry collection systems
primarily for the easy recycling of dissolved urea collected in the device.  Scrubber liquors are recycled
to  the solution concentration process to eliminate waste disposal problems  and to recover the urea
collected.

       Fabric filters  (baghouses)  are  used to control fugitive dust from  bagging operations, where
humidities are low and binding of the bags is not a problem. However,  many bagging operations are
uncontrolled.
 6.14-4
EMISSION FACTORS
                                                                                             7/93

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                                  TABLE 6.14-1 (METRIC UNITS)
                         EMISSION FACTORS FOR UREA PRODUCTION
                                     All Emission Factors are in
                                  Ratings (A-E) Follow Each Factor
Type of Operation
Solution formation and
concentration15
Nonfluidized bed prilling
Agricultural grade8
Feed gradeh
Fluidized bed prilling
Agricultural grade*1
Feed gradeh
Drum granulation1
Rotary drum cooler
Bagging
Particulatea
Uncontrolled
kg/Mg
of
Product
0.0105
1.9
1.8
3.1
1.8
120
3.89k
0.0951
Factor
Rating
A
A
A
A
A
A
A
E
Controlled
kg/Mg
of
Product

0.032f
0.39
0.24
0.115
0.101

Factor
Rating

A
A
A
A
E

Ammonia
Uncontrolled
kg/Mg
of
Product
9.23d
0.43
1.46
2.07
1.07i
0.0256k

kg
Factor
Rating Pix
A
A
A
A 1
A
A

Controlled^
/Mg
of Factor
)duct Rating


04 A



^articulate test data were collected using a modification of EPA Reference Method 3. Reference 1, Appendix B
 explains these modifications.
Tileferences 9 and 11. Emissions from the synthesis process are generally combined with emissions from the
 solution concentration process and vented through a common stack. In the synthesis process, some emission
 control is inherent in the recycle process where carbamate gases and/or liquids are recovered and recycled.
EPA test data indicated a range of 0.005 to 0.016 kg/Mg (0.010 to 0.032 Ib/ton).
%PA test data indicated a range of 4.01 to 14.45 kg/Mg (8.02 to 28.90  Ib/ton).
"Reference 12. These factors were  determined at an ambient temperature  of 14 to 21 C (57 to 69F). The
 controlled emission factors are based on ducting exhaust through a downcomer and then a wetted fiber filter
 scrubber achieving a 98.3 percent efficiency. This represents a higher degree of control than is typical in this
 industry.
fOnly runs two and three were used (test Series A).
SNo ammonia control demonstrated by scrubbers installed for particulate  control. Some increase in ammonia
 emissions exiting the control device was noted.
'Reference 11. Feed grade factors were determined at an ambient temperature of 29C (85F) and agricultural
 grade factors at an ambient temperature of 27C (80F). For fluidized bed prilling, controlled emission factors
 are based on use of an entrainment scrubber.
References 8 and 9. Controlled emission factors are based on use of a wet entrainment scrubber. Wet scrubbers
 are standard process equipment on drum granulaters. Uncontrolled emissions were measured at the scrubber
 inlet.
JEPA test data indicated a range of 0.955 to 1.20 kg/Mg (1.90 to 2.45 Ib/ton).
Reference 10.
 Reference 1.  Data were provided by industry.
7/93
Chemical Process Industry
6.14-5

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                                    Table 6.14-1. (English Units)
                        EMISSION FACTORS FOR UREA PRODUCTION
Type of Operation
Solution formation and
concentration1"
Nonfluidized bed prilling
Agricultural grade0
Feed gradeh
Fluidized bed prilling
Agricultural grade1*
Feed gradeh
Drum granulation1
Rotary drum cooler
Bagging
Particulate8
Uncontrolled
Ib/ton
of
Product
0.021
3.8
3.6
6.2
3.6
241
7.78k
0.191
Factor
Rating
A
A
A
A
. A
A
A
E
Controlled
Ib/ton
of
Product

0.063f
0.78
0.48
0.234
0.201

Factor
Rating

A
A
A
A
E

Ammonia
Uncontrolled
Ib/ton
of
Product
18.46d
0.87
2.91
4.14
2.15J
0.05 lk

Ib
Factor
Rating Pr<
A
A
Controlled^
/ton
of Factor
jduct Rating


A
A 2.08 A
A
A




Particulate test data were collected using a modification of EPA Reference Method 3. Reference 1, Appendix B
 explains these modifications.
^References 9 and 11. Emissions from the synthesis process are generally combined with emissions from the
 solution concentration process and vented through a common stack. In the synthesis process, some emission
 control is inherent in the recycle process where carbamate gases and/or liquids are recovered and recycled.
"EPA test data indicated a range of 0.005 to 0.016 kg/Mg (0.010 to 0.032 Ib/ton).
''EPA test data indicated a range of 4.01 to 14.45 kg/Mg (8.02 to 28.90  Ib/ton).
Reference 12. These factors were determined at an ambient temperature of 14 to 21 C (57 to 69F). The
 controlled emission factors are based on ducting exhaust through a downcomer and then a wetted fiber filter
 scrubber achieving a 98.3 percent efficiency. This represents a higher degree of control than is typical in this
 industry.
fOnly runs two and three  were used (test Series A).
SNo ammonia control demonstrated by scrubbers installed for particulate control. Some increase in ammonia
 emissions exiting the control  device was noted.
'Reference 11. Feed grade factors were determined at an ambient temperature of 29C (85F) and agricultural
 grade factors at an ambient temperature of 27 C (80F). For fluidized bed prilling, controlled emission factors
 are based on use of an entrainment scrubber.
'References 8 and 9.  Controlled emission factors are based on use of a wet entrainment scrubber. Wet scrubbers
 are standard process equipment on drum granulators. Uncontrolled emissions were measured at the scrubber
 inlet.
%PA test data indicated a range of 0.955 to 1.20 kg/Mg (1.90 to 2.45 Ib/ton).
Reference 10.
'Reference 1. Data were provided by industry.
 6.14-6
EMISSION FACTORS
                                                                                                  7/93

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                                      TABLE 6.14-2
            UNCONTROLLED PARTICLE SIZE DATA FOR UREA PRODUCTION

Particle size


(cumulative weight %)
Type of Operation <
Solid Formation
Nonfluidized bed prilling
Agricultural grade
Feed grade
Fluidized bed prilling
Agricultural grade
Feed grade
Drum granulation
Rotary drum cooler
= 10 fjim  5 jum

90 84
85 74


60 52
24 18
a a
0.70 0.15
< 2.5

79
50


43
14
a
/tm








0.04
          1 All particulate matter ^ 5.7 /tm was collected in the cyclone precollector sampling equipment.
References for Section 6.14

1.    Urea Manufacturing Industry: Technical Document, EPA-450/3-81-001, U.S. Environmental
      Protection Agency, Research Triangle Park, NC, January 1981.

2.    D.F. Bress, M.W. Packbier, "The Startup of Two  Major Urea Plants," Chemical Engineering
      Progress, May 1977, p. 80.

3.    Written communication from Gary McAlister, U.S. Environmental Protection Agency,
      Emission Measurement Branch, to Eric Noble, U.S. Environmental Protection Agency,
      Emission, Industrial Studies Branch, Research Triangle Park, NC, July 28, 1983.

4.    Formaldehyde Use in Urea-Based Fertilizers, Report of the Fertilizer Institute's Formaldehyde
      Task Group, The Fertilizer Institute, Washington, DC, February 4, 1983.

5.    J.H. Cramer, "Urea Prill Tower Control Meeting 20% Opacity."  Presented at the Fertilizer
      Institute Environment Symposium, New Orleans, LA, April 1980.

6.    Written communication from M.I. Bornstein, GCA Corporation, Bedford, MA, to E.A. Noble,
      U.S. Environmental Protection Agency, Research Triangle Park, NC,  August 2, 1978.

7.    Written communication from M.I. Bornstein and S.V. Capone, GCA Corporation, Bedford,
      MA, to E.A. Noble, U.S. Environmental Protection Agency, Research Triangle Park, NC,
      June 23, 1978.

8.    Urea Manufacture: Agrico Chemical Company Emission Test Report, EMB Report 78-NHF-4,
      U.S. Environmental Protection Agency, Research Triangle Park, NC,  April  1979.
7/93
Chemical Process Industry
6.14-7

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9.    Urea Manufacture: CF Industries Emission Test Report, EMB Report 78-NHF-8, U.S.
      Environmental Protection Agency, Research Triangle Park, NC, May 1979.

10.   Urea Manufacture: Union Oil of California Emission Test Report, EMB Report 80-NHF-15,
      U.S. Environmental Protection Agency, Research Triangle Park, NC, September 1980.

11.   Urea Manufacture: W.R. Grace and Company Emission Test Report, EMB Report 80-NHF-3,
      U.S. Environmental Protection Agency, Research Triangle Park, NC, December 1979.

12.   Urea Manufacture: Reichhold Chemicals Emission Test Report,  EMB Report 80-NHF-14, U.S.
      Environmental Protection Agency, Research Triangle Park, NC, August 1980.

13.   North American Fertilizer Capacity Data, Tennessee Valley Authority, Muscle Shoals, AL,
      December 1991.
 6.14-8
EMISSION FACTORS
7/93

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 6.18      AMMONIUM SULFATE MANUFACTURE

 6.18.      General1'2

      Ammonium sulfate [ (NH4)2SO4 ] is commonly used as a fertilizer. In 1991, U. S. facilities
 produced about 2.7 million megagrams (three million tons) of ammonium sulfate in about 35 plants.
 Production rates at these plants range from 1.8 to 360 megagrams (2 to 400 tons) per year.

 6.18.2     Process Description1

      About 90 percent of ammonium sulfate is produced by three different processes: 1) as a
 byproduct of caprolactam [ (CH2)5COHN ] production, 2) from synthetic manufacture, and 3) as a
 coke oven byproduct. The remainder is produced as a byproduct of either nickel or methyl
 methacrylate manufacture, or from ammonia  scrubbing of tail gas at sulfuric acid (B^SO^ plants.
 These minor sources are not discussed here.

      Ammonium sulfate is produced as a byproduct from the caprolactam oxidation process stream
 and the rearrangement reaction stream. Synthetic ammonium sulfate is produced by combining
 anhydrous ammonia and sulfuric acid in a reactor. Coke oven byproduct ammonium sulfate is
 produced by reacting the ammonia recovered  from coke oven off-gas with sulfuric acid. Figure 6.18-1
 is a diagram of typical ammonium sulfate manufacturing for each of the three primary commercial
 processes.

      After formation of the ammonium sulfate solution,  manufacturing operations of each process
 are similar. Ammonium sulfate crystals are formed by circulating the ammonium sulfate liquor
 through a water evaporator, which thickens the solution. Ammonium sulfate crystals are separated
 from the liquor in a centrifuge. In the caprolactam byproduct process, the product is first transferred
 to a settling tank to reduce the liquid load on  the centrifuge.  The saturated liquor is returned to the
 dilute ammonium sulfate brine of the evaporator. The crystals, which contain about 1  to 2.5 percent
 moisture by weight after the centrifuge, are fed to either a fluidized-bed or a rotary drum dryer.
 Fluidized-bed dryers are continuously steam heated, while the rotary dryers are fired directly with
 either oil or natural gas or may use steam-heated air.

      At coke oven byproduct plants, rotary vacuum filters may be used in place of a centrifuge and
 dryer. The crystal layer is deposited on the filter and is removed as product. These crystals are
 generally not screened, although they contain  a wide range of particle sizes.  They are then carried by
 conveyors to bulk storage.

      At synthetic plants, a small quantity (about 0.05 percent) of a heavy organic (i.e., high
molecular weight organic) is added to the product after drying to reduce caking.

      Dryer exhaust gases pass through a paniculate collection device, such as a wet scrubber. This
collection controls emissions and reclaims residual product. After being dried, the ammonium sulfate
crystals are screened into coarse and fine crystals.  This screening is done in an enclosed area to
restrict fugitive dust in the building.
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                                                                  fe
                                                                  I
                                                                ESS
                                                                        
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6.18.3    Emissions Arid Controls1

      Ammonium sulfate paniculate is the principal emission from ammonium sulfate manufacturing
plants. The gaseous exhaust of the dryers contains nearly all the emitted ammonium sulfate. Other
plant processes, such as evaporation, screening and materials handling, are not significant sources of
emissions.

      The paniculate emission rate of a dryer is dependent on gas velocity and particle size
distribution. Gas velocity, and thus emission rates, varies according to the dryer type. Generally, the
gas velocity of fluidized-bed dryers is higher than for most rotary drum dryers. Therefore, the
particulate emission rates are higher for fluidized-bed dryers. At caprolactam byproduct plants,
relatively small amounts of volatile organic compounds (VOC) are emitted from the dryers.

      Some plants use baghouses for emission control, but wet scrubbers, such as venturi and
centrifugal scrubbers, are more suitable for reducing particulate emissions from the dryers. Wet
scrubbers use the process streams as the scrubbing liquid so  that the collected particulate can be easily
recycled to the production system.

      Tables 6.18-1 and 6.18-2 shows uncontrolled  and controlled particulate and VOC emission
factors for various dryer types. The VOC emissions shown apply only to caprolactam byproduct
plants.
                                  Table 6.18-1 (Metric Units).
            EMISSION FACTORS FOR AMMONIUM SULFATE MANUFACTURE3
Dryer Type
Rotary dryers
Uncontrolled
Wet scrubber
Fluidized-bed dryers
Uncontrolled
Wet scrubber
Particulate
kg/MG
23
0.02C
109
0.14
Emission
Factor Rating
C
A
C
C
vocb
kg/Mg
0.74
0.11
0.74
0.11
Emission
Factor Rating
C
C
C
C
          a Reference 3.  Units are kg of pollutant/Mg of ammonium sulfate produced.
          b VOC emissions occur only at caprolactam plants.  The emissions are caprolactam vapor.
          c Reference 4.
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Chemical Process Industry
6.18-3

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                               Table 6.18-2 (English Units).
           EMISSION FACTORS FOR AMMONIUM SULFATE MANUFACTURE*
Dryer Type
Rotary dryers
Uncontrolled
Wet scrubber
Fluidized-bed dryers
Uncontrolled
Wet scrubber
Particulate
Ib/ton
46
0.04
218
0.28
Emission
Factor Rating
C
A
C
C
vocb
Ib/ton
1.48
0.22
1.48
0.22
Emission
Factor Rating
B
B
B
B
          * Reference 3. Units are Ibs. of pollutant/ton of ammonium sulfate produced
          b VOC emissions occur only at caprolactam plants.  The emissions are caprolactam vapor.
          0 Reference 4.

References for Section 6.18

1.   Ammonium Sulfate Manufacture: Background Information for Proposed Emission Standards,
     EPA-450/3-79-034a, U. S. Environmental Protection Agency, Research Triangle Park, NC,
     December 1979.

2.   North American Fertilizer Capacity Data, Tennessee Valley Authority, Muscle Shoals, AL,
     December 1991.

3.   Emission Factor Documentation For Section 6.18, Ammonium Sulfate Manufacture, Pacific
     Environmental Services, Inc., Research Triangle Park, NC, March 1981.

4.   Compliance Test Report: J.R. Simplot Company, Pocatello, ID, February, 1990.
6.18-4
EMISSION FACTORS
7/93

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7.7    PRIMARY ZINC SMELTING

7.7.1  General1'2

       Zinc is found in the earth's crust primarily as zinc sulfide (ZnS). Primary uses for zinc
include galvanizing of all forms of steel, as a constituent of brass, for electrical conductors,
vulcanization of rubber and in primers and paints. Most of these applications are highly
dependent upon zinc's resistance to corrosion and its light weight characteristics. In 1991,
approximately 260 thousand megagrams of zinc were refined at the four U. S. primary zinc
smelters.  The annual production volume has remained constant since the  1980s. Three of these
four plants, located in Illinois, Oklahoma,  and Tennessee) utilize electrolytic technology, and the
one plant in Pennsylvania uses electrothermic process.  This annual production level
approximately equals production capacity,  despite a mined zinc ore recovery level of 520
megagrams, a domestic zinc demand of 1190 megagrams, and a secondary smelting  production
level of only 110 megagrams.  As a result,  the
U. S. is a leading exporter of zinc concentrates  as well as the world's largest importer of refined
zinc.

       Zinc ores typically may contain from three to eleven percent zinc, along with cadmium,
copper, lead, silver, and iron.  Beneficiation, or the  concentration of the zinc in the recovered ore,
is accomplished at or near the mine by crushing, grinding, and flotation process.  Once
concentrated, the zinc ore is transferred to smelters for the production of zinc or zinc oxide. The
primary product of most zinc companies is slab  zinc, which  is  produced in five grades: special high
grade, high grade,  intermediate, brass special, and prime western.  The four U. S. primary smelters
also produce sulfuric acid as a byproduct.

7.7.2  Process Description3

       Reduction  of zinc sulfide concentrates to metallic zinc is accomplished through either
electrolytic deposition from a sulfate solution or by  distillation in retorts or furnaces.  Both  of
these methods begin with the elimination of most of the sulfur in the concentrate through a
roasting process, which is described below.  A generalized process diagram depicting primary zinc
smelting is presented in Figure 7.7-1.

       Roasting is a high-temperature process that  converts zinc sulfide concentrate to an impure
zinc oxide called calcine. Roaster types include multiple-hearth, suspension or fluidized bed. The
following reactions occur during roasting:


                              2ZnS + 3O2   ->  2ZnO +  SO2                           [1]

                                  2SO2 + O2  -  2SO3                               [2]


       In a multiple-hearth roaster, the concentrate drops through a series of nine or more
hearths stacked inside a brick lined cylindrical column.  As the feed concentrate drops through
the furnace, it is first dried by the hot gases passing through the hearths and then oxidized to
produce calcine. The reactions are slow and can be sustained only by the addition of fuel.

7/93                                Metallurgical Industry                               7.7-1

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                                                                                 bo
                                                                                 c/3
                                                                                 .

                                                                                 Q.


                                                                                 

                                                                                 
                                                                                 O
                                                                                 O
                                                                                 
                                                                                 O
                                                                                 o


                                                                                 I
7.7-2
EMISSION FACTORS
7/93

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Multiple hearth roasters are unpressurized and operate at about 690C (1300F).  Operating time
depends upon the composition of concentrate and amount of the sulfur removal required.
Multiple hearth roasters have the capability of producing a high-purity calcine.

       In a suspension roaster, the concentrates are blown into a combustion chamber very
similar to that of a pulverized coal furnace. The roaster consists of a refractory-lined cylindrical
steel shell, with a large combustion space at the top and two to four hearths in  the lower portion,
similar to those of a multiple hearth furnace.  Additional grinding, beyond that  required for a
multiple hearth furnace, is normally required to assure that heat transfer to the material is
sufficiently rapid for the desulfurization and oxidation reactions to occur in the  furnace chamber.
Suspension roasters are unpressurized and operate at  about 980C (1800F).

       In a fluidized-bed roaster, finely ground sulfide concentrates are suspended and oxidized in
a feedstock bed supported on an air column.  As in the suspension roaster, the  reaction rates for
desulfurization are more rapid than  in the older multiple-hearth processes. Fluidized-bed roasters
operate under  a pressure slightly lower than atmospheric and at temperatures averaging 1000C
(1800F). In the fluidized-bed process, no additional fuel is required after ignition has been
achieved. The major advantages of this roaster are greater throughput capacities and greater
sulfur removal  capabilities.

       Electrolytic processing of desulfurized calcine consists of three basic steps, leaching,
purification and electrolysis. Leaching occurs in an aqueous solution of sulfuric acid, yielding a
zinc sulfate solution as shown in  Equation 3 below.

                                  ZnO  H- SO3   -*  ZnSO4                               [3]

In double leaching, the calcine is first leached in a  neutral or slightly alkaline solution, then in an
acidic solution, with the liquid passing countercurrent to the flow of calcine. In the neutral
leaching solution, sulfates from the calcine dissolve, but  only a portion of the zinc oxide enters
into solution. The acidic leaching solution dissolves the remainder of the zinc oxide, along with
metallic  impurities such as arsenic, antimony, cobalt, germanium, nickel, and thallium. Insoluble
zinc ferrite, formed during concentrate roasting by the reaction of iron with zinc,-remains in the
leach residue, along with lead and silver.  Lead and silver  typically are shipped to a lead smelter
for recovery, while the zinc is extracted from the zinc ferrite to increase recovery efficiency.

       In the purification process, a number of various reagents are added to the zinc-laden
electrolyte in a sequence of steps designed to precipitate the metallic impurities, which otherwise
will interfere with deposition of zinc.  After purification, concentrations of these impurities are
limited to less  than 0.05 milligram per liter (4 x 10'7 pounds  per gallon).  Purification is usually
conducted in large agitated tanks. The process takes  place at temperatures ranging from 40 to
85C (104 to 185F), and pressures ranging from atmospheric to 240 kilopascals (Kpa) (2.4
atmospheres).

        In electrolysis, metallic zinc is recovered from  the  purified solution by passing current
through an electrolyte solution, causing zinc to deposit on an aluminum cathode. As the
electrolyte is slowly circulated  through the cells, water in the electrolyte dissociates, releasing
oxygen gas at the anode. Zinc metal is deposited at the cathode and sulfuric acid is  regenerated
for recycle to the leach process.  The sulfuric acid  acts as  a catalyst  in the process as a whole.

       Electrolytic zinc smelters contain as many as several hundred cells. A portion of the
electrical energy is converted into heal, which  increases  the temperature of the electrolyte.

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 Electrolytic cells operate at temperature ranges from 30 to 35C (86 to 95F) and at atmospheric
 pressure.  A portion of the electrolyte is continuously circulated through the cooling towers both
 to cool and concentrate the electrolyte through evaporation of water.  The cooled and
 concentrated electrolyte is then recycled to the cells.  Every 24 to 48 hours, each cell is shut
 down, the zinc-coated cathodes are removed and rinsed, and the zinc is mechanically stripped
 from the aluminum plates.

        The electrothermic distillation retort process, as it exists at one U.  S. plant, was developed
 by the St. Joe Minerals Corporation in 1930.  The principal advantage of this pyrometallurgical
 technique over electrolytic processes is its ability to accommodate a wide variety of zinc-bearing
 materials, including secondary items such as calcine derived from electric arc furnace (EAF) dust.
 Electrothermic processing of desulfurized calcine begins with a down draft sintering operation, in
 which grate pallets are joined to form a continuous conveyor system.  The  sinter feed is essentially
 a mixture of roaster calcine and EAF calcine.  Combustion air is drawn down through  the
 conveyor, and impurities such as lead, cadmium, and halides in the sinter feed are driven off and
 collected in a bag filter. The product sinter typically includes 48 percent zinc, 8 percent iron,  5
 percent aluminum, 4 percent silicon, 2.5 percent calcium, and smaller quantities of magnesium,
 lead, and other metals.

        Electric retorting with its greater thermal efficiency than externally heated furnaces, is the
 only pyrometallurgical technique utilized by the U. S. primary zinc industry, now and in the future.
 Product sinter and, possibly, secondary zinc materials are charged with coke to an  electric retort
 furnace.  The charge moves downward from a rotary feeder in the furnace top into a refractory-
 lined vertical cylinder.  Paired graphite electrodes protrude from  the top and bottom of this
 cylinder, producing a current flow. The coke serves to provide electrical resistance, producing
 heat and  generating the carbon  monoxide required  for the reduction process.  Temperatures of
 1400C (2600F)  are attained, immediately vaporizing zinc oxides according to the  following
 reaction:

                           ZnO + CO  -*  Zn (vapor)  + CO2                         [4]

 The zinc vapor and carbon dioxide pass  to a vacuum condenser, where zinc is recovered by
 bubbling through a molten zinc bath.  Over 95 percent of the zinc vapor leaving the retort is
 condensed to liquid  zinc.  The carbon dioxide is regenerated with carbon, and the  carbon
 monoxide is recycled back to the retort furnace.

 7.7.3   Emissions And Controls

        Each of the two smelting processes generates emissions along the various process steps.
 The roasting process in a zinc smelter is typically responsible  for more  than 90 percent of the
 potential SO2 emissions. About 93 to 97 percent of the sulfur in the feed is emitted as sulfur
 oxides. Concentrations of SO2 in the offgas vary with the type of roaster operation. Typical SO2
 concentrations for multiple hearth, suspension, and  fluidizcd bed roasters are 4.5 to 6.5 percent,
 10 to 13 percent, and 7 to 12 percent, respectively.  Sulfur  dioxide emissions from  the roasting
 processes at all four U. S. primary zinc processing facilities  are recovered at on-site sulfuric acid
 plants.  Much of the particulatc matter emitted from primary zinc processing facilities is also
 attributable to the concentrate roasters.  The amount and composition of particulate varies with
 operating parameters, such as  air flow rate and equipment configuration. Various  combinations
 of control devices such  as cyclones, electrostatic precipitalors (ESP), and baghouses can be used
 on roasters  and on sintering machines, achieving 94 to 99 percent emission  reduction.
7.7-4                              EMISSION FACTORS                               7/93

-------
       Controlled and uncontrolled particulate emission factors for points within a zinc smelting
facility are presented in Tables 7.7-1  and 7.7-2. Fugitive emission factors are presented in Tables
7.7-3 and 7.7-4.  These emission factors should be applied carefully. Emission factors for sintering
operations are derived from data from a single facility no longer operating. Others are estimated
based on similar operations in the steel, lead and copper industries. Testing on one
electrothermic primary zinc smelling facility indicates that  cadmium, chromium, lead,  mercury,
nickel, and zinc are contained in the offgases from both the sintering machine and the retort
furnaces.

                                 Table 7.7-1 (Metric Units).
              PARTICULATE EMISSION FACTORS FOR ZINC SMELTING3
Process
Roasting
Multiple hearth1"1 (SCC 3-03-030-02)
Suspension0 (SCC 3-03-030-07)
Fluidized bed* (SCC 3-03-030-08)
Sinter plant (SCC 3-03-030-03)
Uncontrolled6
With cyclonef
With cyclone and ESP8
Electric retort11 (SCC 3-03-030-21)
Electrolytic process-' (SCC 3-03-030-06)
Uncontrolled

113
2000
2167

62.5


10.0
3.3
Emission
Factor
Rating

E
E
E

E


E
E
Controlled


4



24.1
8.25


Emission
Factor
Rating


E



E
E


aFactors are for kg/Mg of zinc produced. SCC = Source Classification Code.
 ESP = Electrostatic prccipitalor.
 References 2,4.  Averaged from an estimated 10% of feed released as particulate, zinc
 production rate at 60% of roaster feed rate, and other estimates.
cReferences 2,4.  Based on an average 60% of feed released as particulate emission and a zinc
 production rate at 60% of roaster feed rale.  Controlled emissions based on 20% dropoul in
 wasle heat boiler and 99.5% dropout in cyclone and ESP.
 References 4,7.  Based on an average 65% of feed released as parliculale emissions and a zinc
 produclion rale of 60 percenl of roaster feed rale.
eReference 4.  Based on unspecified induslrial source dala.
 Reference 8.  Dala  nol necessarily compalible wilh unconlrolled emissions.
^Reference 8.
 Reference 1.  Based on unspecified induslrial source dala.
J Reference 2.
7/93
Melallurgical Induslry
7.7-5

-------
                                Table 7.7-2 (English Units).
              PARTICULATE EMISSION FACTORS FOR ZINC SMELTING3
Process
Roasting
Multiple hearthb (SCC 3-03-030-02)
Suspension0 (SCC 3-03-030-07)
Fluidized bed* (SCC 3-03-030-08)
Sinter plant (SCC 3-03-030-03)
Uncontrolled0
With cyclonef
With cyclone and ESP8
Electric retort11 (SCC 3-03-030-21)
Electrolytic process^ (SCC 3-03-030-06)
Uncontrolled

227
2000
2167

125


20.0
6.6
Emission
Factor
Rating

E
E
E

E


E
E
Controlled


8



48.2
16.5


Emission
Factor
Rating


E



E
E


aFactors are for Ib/lon of zinc produced.  SCC = Source Classification Code.
 ESP = Electrostatic precipitator.
bReferences 2,4. Averaged from an estimated 10% of feed released as particulate, zinc
 production rate at 60% of roaster feed rate, and other estimates.
References 2,4. Based on an average 60% of feed released as particulate emission and a zinc
 production rale at 60% of roaster feed rate.  Controlled emissions based on 20% dropout in
 waste heat boiler and 99.5% dropout in cyclone and ESP.
References 4,7. Based on an average 65% of feed released as particulate emissions and a zinc
 production rate of 60 percent of roaster feed rate.
cReference 4.  Based on unspecified industrial source data.
^Reference 8.  Data not necessarily compatible with uncontrolled emissions.
SReference 8.
^Reference 1.  Based on unspecified industrial source data.
^Reference 2.
7.7-6
EMISSION FACTORS
7/93

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                               Table 7.7-3 (Metric Units).
          UNCONTROLLED FUGITIVE PARTICULATE EMISSION FACTORS
                            FOR SLAB ZINC SMELTING3


Process
Roasting
Sinter plantb
Wind box (SCC 3-03-030-19)
Discharge screens (SCC 3-03-030-20)
Retort building0 (SCC 3-03-030-24)
Casting (SCC 3-03-030- 11)


Emissions
Negligible
0.12 - 0.55
0.28 - 1.22
1.0 - 2.0
1.26
Emission
Factor
Rating

E
E
E
E
"Reference 9. Factors are in kg/Mg of product.  SCC = Source Classification Code.
bFrom steel industry operations for which there are emission factors.  Based on quantity of sinter
 produced.
cFrom lead industry operations.
dFrom copper industry operations.
                               Table 7.7-4 (English Units).
          UNCONTROLLED FUGITIVE PARTICULATE EMISSION FACTORS
                             FOR SLAB ZINC SMELTING
Process
Roasting
Sinter plant13
Wind box (SCC 3-03-030-19)
Discharge screens (SCC 3-03-030-20)
Retort building0 (SCC 3-03-030-24)
Casting" (SCC 3-03-030-1 1)
Emissions
Negligible
0.24 - 1.10
0.56 - 2.44
2.0 - 4.0
2.52
Emission
Factor
Rating

E
E
E
E
''Reference 9. Factors are in Ib/ton of product. SCC = Source Classification Code.
bFrom steel industry operations for which there are emission factors.  Based on quantity of sinter
 produced.
cFrom lead industry operations.
 From copper industry operations.
7/93
Metallurgical Industry
7.7-7

-------
 References for Section 7.7

 1.   J. H. Jolly, "Zinc", Mineral Commodity Summaries 1992, U. S. Department Of The Interior,
      Washington, DC, 1992.

 2.   J. H. Jolly, "Zinc", Minerals Yearbook 1989, U. S. Department Of The Interior, Washington,
      DC, 1990.

 3.   R. L. Williams, "The Monaca Electrothermic Smelter - The Old Becomes The New", Lead-
      Zinc '90, The Minerals, Metals & Materials Society, Philadelphia, PA, 1990.

 4.   Environmental Assessment Of The Domestic Primary Copper, Lead And. Zinc Industries,
      EPA-600/2-82-066, U. S. Environmental Protection Agency, Cincinnati, OH, October 1978.

 5.   Particulate Pollutant System Study, Volume I:  Mass Emissions, APTD-0743, U. S.
      Environmental Protection Agency, Research  Triangle Park, NC, May 1971.

 6.   G. Sallee, Personal Communication, Midwest Research Institute, Kansas City, MO, June
      1970.

 7.   Systems Study For Control Of Emissions In The Primary Nonferrous Smelting Industry,
      Volume /, APTD-1280, U. S. Environmental Protection Agency, Research Triangle Park,
      NC, June 1969.

 8.   R. B. Jacko and D. W. Nevendorf, "Trace Metal Emission Test Results From A Number Of
      Industrial And Municipal Point Sources", Journal Of The Air Pollution Control Association,
      27(10):989-994, October 1977.

 9.   Technical Guidance For Control Of Industrial Process Fugitive Paniculate Emissions, EPA-
      450/3-77-010, U. S. Environmental Protection Agency, Research Triangle Park, NC, March
      1977.

 10.   Background Information For New Source Performance Standards: Primary Copper, Zinc And
      Lead Smelters, Volume I: Proposed Standards, EPA-450/2-74-002a, U. S. Environmental
      Protection Agency, Research Triangle Park, NC, October 1974.

 11.   Written communication from J. D. Reese, Zinc Corporation Of America, Monaca, PA, to
      C. M. Campbell, Pacific Environmental Services,  Inc., Research Triangle Park, NC, 18
      November 1992.

 12.   Emission  Study Performed For Zinc Corporation Of America At The Monaca Facilities, 14-30
      May 1991, EMC Analytical, Inc., Gilberts, IL, 27 April 1992.
7.7-8                              EMISSION FACTORS                             7/93

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7.14   SECONDARY ZINC PROCESSING

7.14.1  General1'2

      The secondary zinc industry processes scrap metals for the recovery of zinc in the form of in
the form of zinc slabs, zinc oxide, or zinc dust.  There are currently 10 secondary zinc recovery
plants operating in the U. S., with an aggregate capacity of approximately 60 megagrams (60 tons)
per year.

7.14.2    Process Description

      Zinc recovery involves three general operations performed on scrap, pretreatment, melting,
and refining.  Processes typically used in each operation are shown in  Figure 7.14-1.

7.14.2.1   Scrap Pretreatment

      Scrap metal is delivered to the secondary zinc processor as ingots, rejected castings, flashing
and other mixed metal scrap containing zinc. Scrap pretreatment includes: (1) sorting, (2)
cleaning, (3) crushing and screening, (4) sweating, and (5) leaching.

      In the sorting operation, zinc scrap is manually separated according to zinc content and any
subsequent processing requirements. Cleaning removes foreign materials to improve product
quality and recovery efficiency.  Crushing facilitates the ability to separate the zinc from the
contaminants. Screening and pneumatic classification concentrates the zinc metal for further
processing.

      A sweating furnace (rotary, reverberatory, or muffle furnace) slowly heats the scrap
containing zinc and other metals to approximately 364C (787F). This temperature is sufficient
to melt zinc but is still below the melting point of the remaining metals.  Molten zinc collects at
the bottom of the sweat  furnace and is subsequently recovered. The remaining scrap metal is
cooled and removed to be sold to other secondary processors.

      Leaching with sodium carbonate solution converts dross  and skimmings to  zinc oxide, which
can be reduced to zinc metal. The zinc containing material is crushed and washed  with water,
separating contaminants  from zinc-containing metal.  The contaminated aqueous stream is treated
with sodium carbonate to convert zinc chloride into sodium chloride (NaCl) and  insoluble zinc
hydroxide (ZnOH). The NaCl is separated from the insoluble residues by filtration and settling.
The precipitate zinc hydroxide is dried  and calcined (dehydrated into a powder at high
temperature) to convert  it into crude zinc oxide (ZnO).  The ZnO product is usually refined to
zinc at primary  zinc smelters. The washed zinc-containing metal portion becomes the raw
material for the melting process.
7/93                               Metallurgical Industry                              7.14-1

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                                                                                  S3
                                                                                  O

                                                                                  2
                                                                                  P
                                                                                  o
                                                                                  o
                                                                                  c

                                                                                 'N
                                                                                  O
                                                                                  o
                                                                                  
-------
7.14.2.2   Melting

      Zinc scrap is melted in kettle, crucible, reverberatory, and electric induction furnaces. Flux
is used in these furnaces to trap impurities from the molten zinc. Facilitated by agitation, flux and
impurities float to the surface of the melt as dross, and is skimmed from the surface.  The
remaining molten zinc may be poured into molds or transferred to the refining operation in a
molten state.

      Zinc alloys are produced from pretreated scrap during sweating and melting processes. The
alloys may contain small amounts of copper, aluminum, magnesium, iron, lead, cadmium and tin.
Alloys containing 0.65 to 1.25 percent copper are significantly stronger than unalloyed zinc.

7.14.2.3   Refining

      Refining processes remove further impurities in clean zinc alloy scrap and in zinc vaporized
during the melt phase in retort furnaces, as shown in Figure 7.14-2.

Molten zinc is heated until it vaporizes.  Zinc vapor is condensed and recovered in several forms,
depending upon temperature, recovery time,  absence or  presence of oxygen, and equipment used
during zinc vapor condensation. Final products from refining processes include zinc ingots, zinc
dust, zinc oxide, and zinc alloys.

      Distillation retorts and furnaces are used either to  reclaim zinc from alloys or to refine
crude zinc.  Bottle retort furnaces consist of a pear-shaped ceramic retort (a long-necked vessel
used for distillation). Bottle retorts are filled with zinc alloys and  heated until most of the zinc is
vaporized, sometimes as long as 24 hours.  Distillation involves vaporization of zinc at
temperatures from 982  to 1249C (1800 to 2280F) and condensation as zinc dust or liquid zinc.
Zinc dust is produced by vaporization and rapid cooling,  and liquid zinc results when the vaporous
product is condensed slowly at moderate temperatures.  The melt is cast into ingots or slabs.

      A muffle furnace is a continuously charged retort furnace, which can operate for several
days at a time.
  Molten zinc is charged through a feed well  that also acts  as an airlock.  Muffle furnaces
generally have a much greater vaporization capacity than bottle retort furnaces. They produce
both zinc ingots and zinc oxide of 99.8 percent purity.

      Pot melting, unlike bottle retort and muffle furnaces, does not incorporate distillation as  a
part of the refinement process.  This method merely monitors the composition of the intake to
control the composition of the product.  Specified die-cast  scraps containing zinc are melted in a
steel pot. Pot melting is a simple indirect heat melting operation where the final alloy cast into
zinc alloy slabs is controlled by the scrap input into the pot.

      Furnace distillation with oxidation produces zinc oxide dust. These processes are similar to
distillation without the condenser.  Instead of entering a  condenser, the zinc vapor discharges
directly into an air stream leading to a refractory-lined combustion chamber. Excess air completes
the oxidation and cools the zinc oxide dust before it is collected in a fabric filter.

      Zinc oxide is transformed into zinc metal though a retort reduction process using coke as a
reducing agent.  Carbon monoxide produced by the partial oxidation of the coke reduces the zinc
oxide to metal and carbon dioxide. The zinc vapor is recovered by condensation.


7/93                                Metallurgical Industry                              7.14-3

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                          Figure 7.14-2. Zinc retort distillation furnace.
         STACK
     MOLTEN METAL
     TAPHOLE
                                                                        FLAME  PORT
                                                                        AIR IN
                                                                             DUCT FOR OXIDE
                                                                             COLLECTION
                                                                       RISER CONDENSER
                                                                             UNIT
                                                                            MOLTEN METAL
                                                                              TAPHOLE
                          Figure 7.14-3. Muffle furnace and condenser.
7.14-4
EMISSION FACTORS
7/93

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7.14.3     Emissions1'4

      Process and fugitive emission factors for secondary zinc operations are tabulated in Tables
7.14-1 through 7.14-4.  Emissions from sweating and melting operations consist of particulate, zinc
fumes, other volatile metals, flux fumes, and smoke generated by the incomplete combustion of
grease, rubber and plastics in zinc scrap.  Zinc fumes are negligible at low furnace temperatures.
Flux emissions may be minimized by using a nonfuming flux. In production  requiring special
fluxes that do generate fumes, fabric filters may be used to collect  emissions. Substantial
emissions may arise from incomplete combustion of carbonaceous material in the zinc scrap.
These contaminants are usually controlled by afterburners.

      Particulate emissions from sweating and melting are most commonly recovered by fabric
filter. In one application on a muffle sweating furnace, a cyclone and fabric  filter achieved
particulate recovery efficiencies in excess of 99.7 percent. In one application on a reverberatory
sweating furnace, a fabric filter removed 96.3 percent of the particulate.  Fabric filters show
similar efficiencies in removing particulate from exhaust gases of melting furnaces.

      Crushing and screening operations are also sources of dust emissions.  These emissions are
composed of zinc, aluminum, copper, iron, lead, cadmium, tin,  and chromium.  They  can be
recovered by hooded exhausts used as capture devices and can be controlled with fabric filters.

      The sodium carbonate leaching process emits zinc oxide dust during the calcining operation
(oxidizing precipitate into powder at high temperature).  This dust can be recovered  in fabric
filters, although  zinc chloride in the dust may cause plugging problems.

      Emissions from refining operations are mainly metallic fumes.  Distillation/oxidation
operations emit  their entire zinc oxide product in the exhaust gas.  Zinc oxide is usually recovered
in fabric filters with collection efficiencies of 98 to 99 percent.
7/93                                Metallurgical Industry                               7.14-5

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                              Table 7.14-1 (Metric Units).
             UNCONTROLLED PARTICULATE EMISSION FACTORS FOR
                           SECONDARY ZINC SMELTING3
Operation
Reverberatory sweating13 (in mg/Mg feed material)
Clean metallic scrap (SCC 3-04-008-18)
General metallic scrap (SCC 3-04-008-28)
Residual scrap (SCC 3-04-008-38)
Rotary sweating0 (SCC 3-04-008-09)
Muffle sweating0 (SCC 3-04-008-10)
Kettle sweating5
Clean metallic scrap (SCC 3-04-008-14)
General metallic scrap (SCC 3-04-008-24)
Residual scrap (SCC 3-04-008-34)
Electric resistance sweating0 (SCC 3-04-008-11)
Sodium carbonate leaching calciningd (SCC 3-04-008-06)
Kettle potd, mg/Mg product (SCC 3-04-008-03)
Crucible melting (SCC 3-04-008-42)
Reverberatory melting (SCC 3-04-008-42)
Electric induction melting (SCC 3-04-008-43)
Alloying (SCC 3-04-008-40)
Retort and muffle distillation, in kg/Mg of product
Pouring0 (SCC 3-04-008-51)
Casting0 (SCC 3-04-008-52)
Muffle distillationd (SCC 3-04-008-02
Graphite rod distillation0-6 (SCC 3-04-008-53)
Retort distillation/oxidationf (SCC 3-04-008-54)
Muffle distillation/oxidationf (SCC 3-04-008-55)
Retort reduction (SCC 3-04-008-01)
Galvanizingd (SCC 3-04-008-05)
Emissions
Negligible
6.5
16
5.5 - 12.5
5.4 - 16
Negligible
5.5
12.5
< 5
44.5
0.05
ND
ND
ND
ND
0.2 - 0.4
0.1 - 0.2
22.5
Negligible
10-20
10-20
23.5
2.5
Emission Factor
Rating
C
C
C
C
C
C
C
C
C




C
C
C
C
C
C
C
C
a Factors are for kg/Mg of zinc used, except as noted. SCC = Source Classification Code.
  ND = no data.
b Reference 3.
c Reference 4.
d References 5-7.
c Reference 1.
  Reference 4.  Factors are for kg/Mg of ZnO produced.  All product zinc oxide dust is carried
  over in the exhaust gas from the furnace and is recovered with 98 - 99 percent efficiency.
7.14-6
EMISSION FACTORS
7/93

-------
                               Table 7.14-2 (English Units).
              UNCONTROLLED PARTICULATE EMISSION FACTORS FOR
                            SECONDARY ZINC SMELTING3
Operation
Reverberatory sweating"3 (in mg/Mg feed material)
Clean metallic scrap (SCC 3-04-008-18)
General metallic scrap (SCC 3-04-008-28)
Residual scrap (SCC 3-04-008-38)
Rotary sweating0 (SCC 3-04-008-09)
Muffle sweating0 (SCC 3-04-008-10)
Kettle sweating11
Clean metallic scrap (SCC 3-04-008-14)
General metallic scrap (SCC 3-04-008-24)
Residual scrap (SCC 3-04-008-34)
Electric resistance sweating0 (SCC 3-04-008-11)
Sodium carbonate leaching calciningd (SCC 3-04-008-06)
Kettle potd, mg/Mg product (SCC 3-04-008-03)
Crucible melting (SCC 3-04-008-42)
Reverberatory melting (SCC 3-04-008-42)
Electric induction melting (SCC 3-04-008-43)
Alloying (SCC 3-04-008-40)
Retort and muffle distillation, in Ib/ton of product
Pouring0 (SCC 3-04-008-51)
Casting0 (SCC 3-04-008-52)
Muffle distillationd (SCC 3-04-008-02
Graphile rod distillation0'6 (SCC 3-04-008-53)
Retort distillation/oxidation' (SCC 3-04-008-54)
Muffle distillation/oxidationf (SCC 3-04-008-55)
Retort reduction (SCC 3-04-008-01)
Galvanizingd (SCC 3-04-008-05)
Emissions
Negligible
13
32
11-25
10.8 - 32
Negligible
11
25
< 10
89
0.1
ND
ND
ND
ND
0.4 - 0.8
0.2-0.4
45
Negligible
20 - 40
20-40
47
5
Emission Factor
Rating
C
C
C
C
C
C
C
C
C




C
C
C
C
C
C
C
C
a Factors are for Ib/ton of zinc used, except as noted. SCC = Source Classification Code.
  ND = no data.
b Reference 3.
c Reference 4.
d References 5-7.
e Reference 1.
f Reference 4. Factors are for Ib/ton of ZnO produced.  All product zinc oxide dust is carried
  over in the exhaust gas from the furnace and is recovered with 98-99 percent efficiency.
7/93
Metallurgical Industry
7.14-7

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                               Table 7.14-3 (Metric Units).
                 FUGITIVE PARTICULATE EMISSION FACTORS FOR
                           SECONDARY ZINC SMELTING2
Operation
Reverberatory sweating13 (SCC 3-04-008-61)
Rotary sweating5 (SCC 3-04-008-62)
Muffle sweating5 (SCC 3-04-008-63)
Kettle (pot) sweating5 (SCC 3-04-008-64)
Electrical resistance sweating, per kg processed5
(SCC 3-04-008-65)
Crushing/screening0 (SCC 3-04-008-12)
Sodium carbonate leaching (SCC 3-04-008-66)
Kettle (pot) melting furnace5 (SCC 3-04-008-67)
Crucible melting furnaced (SCC 3-04-008-68)
Reverberatory melting furnace5 (SCC 3-04-008-69)
Electric induction melting5 (SCC 3-04-008-70)
Alloying retort distillation (SCC 3-04-008-71)
Retort and muffle distillation (SCC 3-04-008-72)
Casting5 (SCC 3-04-008-73)
Graphite rod distillation (SCC 3-04-008-74)
Retort distillation/oxidation (SCC 3-04-008-75)
Muffle distillation/oxidation (SCC 3-04-008-76)
Retort reduction (SCC 3-04-008-77)
Emissions
0.63
0.45
0.54
0.28

0.25
2.13
ND
0.0025
0.0025
0.0025
0.0025
ND
1.18
0.0075
ND
ND
ND
ND
Emission
Factor
Rating
E
E
E
E

E
E

E
E
E
E

E
E




aReference 8.  Factors are kg/Mg of end product, except as noted. SCC = Source Classification
 Code. ND = no data.
 Estimate based on stack emission factor given in Reference 1, assuming fugitive emissions to be
 equal to five % of stack emissions.
cReference 1.  Factors are for kg/Mg of scrap processed. Average of reported emission factors.
 Engineering judgment, assuming fugitive emissions from crucible melting furnace to be equal to
 fugitive emissions from kettle (pot) melting furnace.
7.14-8
EMISSION FACTORS
7/93

-------
                                Table 7.14-4 (English Units).
                  FUGITIVE PARTICULATE EMISSION FACTORS FOR
                             SECONDARY ZINC SMELTING3
Operation
Reverberatory sweating13 (SCC 3-04.-008-61)
Rotary sweating13 (SCC 3-04-008-62)
MulTle sweating11 (SCC 3-04-008-63)
Kettle (pot) sweating11 (SCC 3-04-008-64)
Electrical resistance sweating, per ton processed13
(SCC 3-04-008-65)
Crushing/screening0 (SCC 3-04-008-12)
Sodium carbonate leaching (SCC 3-04-008-66)
Kettle (pot) melting furnaccb (SCC 3-04-008-67)
Crucible melting furnace13 (SCC 3-04-008-68)
Reverberatory melting furnace13 (SCC 3-04-008-69)
Electric induction melting13 (SCC 3-04-008-70)
Alloying retort distillation (SCC 3-04-008-71)
Retort and muffle distillation (SCC 3-04-008-72)
Casting15 (SCC 3-04-008-73)
Graphite rod distillation (SCC 3-04-008-74)
Retort distillation/oxidation (SCC 3-04-008-75)
Muffle distillation/oxidation (SCC 3-04-008-76)
Retort reduction (SCC 3-04-008-77)
Emissions
1.30
0.90
1.07
0.56
0.50
4.25
ND
0.005
0.005
0.005
0.005

2.36
0.015
ND
ND
ND
ND
Emission
Factor
Rating
E
E
E
E
E
E

E
E
E
E

E
E




aRefcrence 8.  Factors are Ib/ton of end product, except as noted. SCC = Source Classification
 Code.  ND = no data.
 Estimate based on stack emission factor given in Reference 1, assuming fugitive emissions to be
 equal to five % of stack emissions.
cRefcrcnce 1.  Factors are for Ib/ton of scrap processed.  Average of reported emission factors.
 Engineering judgment, assuming fugitive emissions from crucible melting furnace to be equal to
 fugitive emissions from kettle (pot) melting furnace.
7/93
Metallurgical Industry
7.14-9

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References for Section 7.14

1.    William M. Coltharp, et al, Multimedia Environmental Assessment Of The Secondary
     Nonferrous Metal Industry, Draft, EPA Contract No. 68-02-1319, Radian Corporation,
     Austin, TX, June 1976.                                                           ,

2.    John A. Danielson, Air Pollution Engineering Manual,  2nd Edition, AP-40, U. S.
     Environmental Protection Agency, Research Triangle  Park, NC, 1973. Out of Print.

3.    W. Herring, Secondary Zinc Industry Emission Control Problem Definition Study (Part I),   .
     APTD-0706, U. S. Environmental Protection Agency,  Research Triangle Park, NC, May
     1971.

4.    H. Nack, et al, Development Of An Approach To Identification Of Emerging Technology And
     Demonstration Opportunities, EPA-650/2-74-048, U. S. Environmental Protection Agency,
     Cincinnati, Ohio, May 1974.

5.    G. L. Allen, et al., Control Of Metallurgical And Mineral Dusts And Fumes In Los Angeles
     County, Report Number 7627, U. S. Department Of The Interior, Washington, DC, April
     1952.

6,    Restricting Dust And Sulfur Dioxide Emissions From Lead Smelters, VDI Number 2285, U. S.
     Department Of Health And Human Services, Washington, DC, September 1961.

7.    W. F. Hammond, Data On Nonferrous Metallurgical Operations, Los Angeles County Air
     Pollution Control District, Los Angeles, CA, November 1966.

8,    Assessment Of Fugitive Particulate Emission Factors For Industrial Processes, EPA-450/3-78-
     107, U. S. Environmental Protection Agency, Research Triangle Park, NC, September 1978.

9.    Source Category Survey: Secondary Zinc Smelting And  Refining Industry, EPA-450/3-80-012,
     U. S. Environmental Protection Agency, Research Triangle Park, NC, May 1980.
 7.14-10                           EMISSION FACTORS                              7/93

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7.16   LEAD OXIDE AND PIGMENT PRODUCTION

7.16.1  General1'2'7

       Lead oxide is a general term and can be either lead monoxide, or "litharge" (PbO); lead
tetroxide, or "red lead" (Pb3O4);  or black, or "gray", oxide which is a mixture of 70 percent lead
monoxide and 30 percent metallic lead. Black lead is made for specific use in the manufacture of
lead acid storage batteries. Because of the size of the lead acid battery industry, lead monoxide is
the most important commercial compound of lead, based on volume. Total oxide production in 1989
was 57,984 megagrams (64,000 tons).

       Litharge is used primarily in the manufacture of various ceramic products.  Because of its
electrical  and electronic properties, litharge is also used  in  capacitors,  Vidicon  tubes, and
electrophotographic plates, as well as in ferromagnetic and ferroelectric materials.  It is also used as
an activator in rubber, a curing agent in elastomers, a sulfur removal  agent  in the production of
thioles and in oil refining, and an oxidation catalyst in several organic chemical processes. It also has
important markets in the production of many lead chemicals,  dry colors, soaps (i. e., lead stearate),
and driers for paint.  Another important use of litharge is the production of lead salts, particularly
those used as stabilizers for plastics, notably polyvinyl chloride materials.

       The major lead pigment  is red lead  (Pb3O4), which is used  principally in ferrous metal
protective paints.  Other lead pigments include white lead and lead chromates. There are several
commercial varieties of white lead including leaded zinc oxide, basic carbonate white lead, basic
sulfate white lead, and basic lead silicates.  Of these, the most important is leaded zinc oxide, which
is used almost entirely as white pigment for exterior oil-based paints.

7.16.2  Process Description8

       Black oxide is usually produced  by a Barton Pot  process.   Basic carbonate white lead
production is based on the reaction of litharge with acetic acid or acetate ions. This product is then
reacted with carbon dioxide will form lead carbonate.  White leads (other than carbonates) are made
either by chemical, fuming, or mechanical blending processes. Red lead is produced by oxidizing
litharge in a reverbcratory furnace. Chromatc pigments are generally manufactured by precipitation
or calcination as in the following equation:

                       Pb(NO3)2 +  Na2(CrO4) -  PbCrO4 + 2 NaNO3                    [1]

       Commercial lead  oxides can all be prepared by wet chemical methods.  With the exception
of lead dioxide, lead oxides are produced by thermal processes in which lead is directly oxidized with
air.  The  processes  may  be  classified according  to the  temperature of  the  reaction:  1) low
temperature, below the melting point of lead; 2) moderate temperature, between the melting points
of lead and of lead monoxide; and 3) high temperature, above the melting point of lead monoxide.

       Low Temperature Oxidation - Low temperature oxidation of lead is accomplished by tumbling
slugs of metallic lead in a ball mill equipped with an air flow. The air flow provides oxygen and is
used as a coolant.  If some form of cooling were not supplied, the heat generated by the oxidation
of the lead plus the  mechanical heat of the tumbling charge would raise the charge temperature
above the melting point of lead. The ball  mill product is a "leady" oxide with 20 to 50 percent free
lead.


7/93                                Metallurgical Industry                              7,16-1

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       Moderate Temperature Oxidation - Three processes are used commercially in the moderate
temperature range: 1) refractory furnace, 2) rotary tube furnace, and 3) the Barton Pot process. In
the  refractory furnace process, a cast steel pan is equipped with a rotating vertical shaft and a
horizontal crossarm mounted with plows. The plows move the charge continuously to expose fresh
surfaces for oxidation.  The charge is heated by a gas flame on its surface. Oxidation of the charge
supplies  much of the reactive heat as the reaction  progresses.   A  variety of products can be
manufactured from pig lead feed by varying the feed temperature, and time of furnacing.  Yellow
litharge (orthorhombic) can be made by cooking for several hours at 600 to 700C (1112 to 1292F)
but may contain traces of red lead and/or free  metallic lead.

       In the rotary tube furnace process, molten lead  is  introduced  into the  upper end of a
refractory-lined inclined rotating tube.  An oxidizing flame in the  lower end maintains the desired
temperature of reaction.  The tube is long enough so that the charge is completely oxidized when it
emerges  from the lower end.  This type of furnace has been used  commonly to produce lead
monoxide (tetragonal type), but it is not unusual for the final product to contain traces of both free
metallic and red lead.

       The Barton Pot process (Figure 7.16-1) uses a cast iron pot with an upper and lower stirrer
rotating at different speeds. Molten lead is fed through a port in the cover into the pot, where it is
broken up into droplets by high-speed blades.  Heat is  supplied initially to develop  an operating
temperature from 370  to 480C (698 to 896F).  The exothermic heat  from the resulting oxidation
of the droplets is usually sufficient to maintain the desired temperature.  The oxidized product is
swept out of the pot by an  air stream.

       The operation is controlled by adjusting the rate of molten lead feed, the speed of the stirrers,
the temperature of the system, and the rate of air flow through the pot.  The Barton Pot produces
either  litharge or leady litharge (litharge with 50 percent free lead). Since it operates at a higher
temperature than a ball mill unit, the oxide portion will usually contain some orthorhombic litharge.
It may also be operated to  obtain almost entirely orthorhombic product.

       High Temperature  Oxidation - High temperature oxidation is a fume-type process. A very
fine particle, high-purity orlhorhombic litharge is made by burning a fine stream of molten lead in
a special blast-type burner.  The flame temperature is around 1200C (2192F). The fume is swept
out of the chamber by an air stream, cooled in a series of "goosenecks" and collected in a baghouse.
The median particle diameter is from 0.50 to 1.0 microns, as compared with  3.0 to  16.0 microns for
lead monoxide manufactured  by other methods.

7.16.3  Emissions And  Controls3"4'6

       Emission factors for lead oxide and pigment production processes are given in Tables 7.16.3-1
and 7.16.3-2. The emission  factors were assigned an E rating because of high variabilities in test run
results and nonisokinelic sampling.  Also, since Storage  battery production facilities produce lead
oxide using the Barton Pot process, a comparison of the  lead emission  factors from both industries
has been  performed.  The lead  oxide emission factors from the battery plants were  found to be
considerably lower than the emission factors from the lead oxide and pigment industry.  Since lead
battery production plants arc covered under federal regulations, one would expect lower emissions
from these sources.
7.16-2                             EMISSION FACTORS                               7/93

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       LEAD
       FEED
                             LEAD OXIDE
                               LEAD
                                                             CONVEYER
                                                             (PRODUCT IO STORAGE)
                         Figure 2.2.2-1. Lead oxide Barton Pot process.
       Automatic shaker-type fabric filters, often preceded by  cyclone mechanical collectors  or
settling chambers,  are the common choice for  collecting lead oxides and pigments.  Control
efficiencies of 99 percent are achieved with these control device combinations. Where fabric filters
are not appropriate scrubbers may be used, to achieve control efficiencies from 70  to 95 percent.
The ball mill and Barton Pot processes of black oxide manufacturing recover the lead  product  by
these two  means.  Collection of dust and fumes from the production of red lead  is likewise  an
economic necessity, since particulate emissions, although small, are about 90 percent lead. Emissions
data from  the production of white lead pigments  are not available, but they have been estimated
because of health and safety regulations.  The emissions from dryer exhaust scrubbers account for
over 50 percent of the total lead emitted in lead chromate production.
7/93
Metallurgical Industry
7.16-3

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                              Table 7.16-1 (Metric Units).
   CONTROLLED EMISSIONS FROM LEAD OXIDE AND PIGMENT PRODUCTION3
Process
Lead Oxide Production
Barton Potb
(SCC 3-01-035-06)
Calcining
(SCC 3-01-035-07)
Baghouse Inlet
Baghouse Outlet
Pigment Production
Red leadb
(SCC 3-01-035-10)
White leadb
(SCC 3-01-035-15)
Chrome pigments
(SCC 3-0 1-035-20)
Particulate
Emissions

0.21 - 0.43
7.13
0.032

0.5C


Emission
Factor
Rating

E
E
E

B


Lead
Emissions

0.22
7.00
0.024

0.50
0.28
0.065
Emission
Factor
Rating

E
E
E

B
B
B
References

4,6
6
6

4-5
4-5
4-5
aFactors are for kg/Mg of product.  SOC = Source Classification Code.
bMeasured at baghouse outlet. Baghouse is considered process equipment.
cOn!y PbO and oxygen are used in red lead production, so particulate emissions are assumed to be
 about 90% lead.
7.16-4
EMISSION FACTORS
7/93

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                                                                                                    1
                               Table 7.16-2 (English Units).
    CONTROLLED EMISSIONS FROM LEAD OXIDE AND PIGMENT PRODUCTION3
Process
Lead Oxide Production
Barton Potb
(SCC 3-01-035-06)
Calcining
(SCC 3-01-035-07)
Baghouse Inlet
Baghouse Outlet
Pigment Production
Red leadb
(SCC 3-01-035-10)
White leadb
(SCC 3-01-035-15)
Chrome pigments
(SCC 3-01-035-20)
Particulate
Emissions


0.43 - 0.85
14.27
0.064


1.0C



Emission
Factor
Rating


E
E
E


B



Lead
Emissions


0.44
14.00
0.05


0.90

0.55
0.13
Emission
Factor
Rating


E
E
E


B

B
B
References


4,6
6
6


4-5

4-5
4-5
'^Factors are for Ib/ton of product. SCC = Source Classification Code.
 Measured at baghouse outlet.  Baghouse is considered process equipment.
cOnly PbO and oxygen are used in red lead production, so particulate emissions are assumed to be
 about 90% lead.
7/93
Metallurgical Industry
                                                                                 7.16-5

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References for Section 7.16

1.   E. J. Ritchie, Lead Oxides, Independent Battery Manufacturers Association, Inc., Largo, FL,
     1974.

2.   W. E. Davis, Emissions Study Of Industrial Sources Of Lead Air Pollutants, 1970, EPA Contract
     No. 68-02-0271, W. E. Davis and Associates, Leawood, KS, April 1973.

3.   Background Information In Support Of The Development Of Performance Standards For The
     Lead Additive Industry, EPA Contract No. 68-02-2085, PEDCo Environmental Specialists, Inc.,
     Cincinnati, OH, January 1976.

4.   Control Techniques For Lead Air Emissions, EPA-450/2-77-012A.  U.  S. Environmental
     Protection Agency, Research Triangle Park, NC, December 1977.

5.   R. P. Bctz, el ai, Economics Of Lead Removal In Selected Industries, EPA Contract No. 68-02-
     0299, Batlelle Columbus Laboratories, Columbus OH, December 1972.

6.   Air Pollution Emission Test, Contract No. 74-PB-O-l, Task No. 10, Office Of Air Quality
     Planning And Standards, U. S. Environmental Protection Agency, Research Triangle Park, NC,
     August 1973.

7.   Mineral Yearbook,  Volume 1:  Metals And Minerals, Bureau Of Mines, U.S. Department Of
     The Interior, Washington, DC, 1989.

8.   Harvey E. Brown, Lead Oxide: Properties and Applications, International Lead  Zinc Research
     Organization, Inc., New York, NY, 1985.
7.16-6
EMISSION FACTORS
7/93

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 8.8  CLAY AND FLY ASH SINTERING

 NOTE:  Clay and fly ash sintering operations are no longer conducted in the United States.
          However,  this section is being retained for historical purposes.

 8.8.1  Process Description1"3

         Although the process for sintering fly ash and clay are similar, there are some distinctions that
 justify a separate discussion of each process.  Fly ash sintering plants  are generally located near the
 source, with the fly ash delivered to a storage silo at the plant.  The dry fly ash is moistened with a
 water solution of lignin and agglomerated into pellets or balls. This material goes to a traveling-grate
 sintering machine where direct contact with hot combustion gases sinters the individual particles of
 the pellet and  completely burns off the residual carbon in the fly ash.  The product is then crushed,
 screened, graded, and stored in yard piles.

         Clay sintering involves the driving off of entrained volatile matter.  It is desirable that the
 clay  contain a sufficient amount of volatile matter so that the resultant aggregate will not be too
 heavy.  It is thus sometimes necessary to mix the clay with finely pulverized coke (up to 10 percent
 coke by weight).  In the sintering process, the clay is first mixed with pulverized coke, if necessary,
 and then pelletized.  The clay is next sintered in a rotating kiln or on a traveling grate.  The sintered
pellets are then crushed, screened, and stored, in a procedure  similar to that for fly ash pellets.

 8.8.2  Emissions and Controls1

        In fly  ash sintering, improper handling of the fly ash creates a dust problem.  Adequate
 design features, including fly ash wetting systems  and paniculate collection systems on all transfer
 points  and on  crushing and screening operations,  would greatly reduce emissions. Normally, fabric
 filters are used to control emissions from the storage silo, and emissions are low. The absence of this
 dust  collection system, however, would create a major emission problem.  Moisture is added at the
 point of discharge from silo to the agglomerator,  and very few emissions occur there.  Normally,
 there are few emissions from the sintering machine, but if the grate is  not properly maintained, a  dust
 problem is created.  The consequent crushing, screening, handling, and storage of the sintered
 product also create  dust problems.

        In clay sintering, the addition of pulverized coke presents an emission problem because the
 sintering of coke-impregnated  dry pellets produces more paniculate emissions than the sintering of
 natural clay.  The crushing, screening, handling, and storage of the sintered clay pellets creates dust
 problems similar to those encountered in fly-ash sintering. Emission factors  for both clay and  fly-ash
 sintering are shown in Table 8.8-1.
 2/72                                Mineral Products Industry                                8.8-1

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                             TABLE 8.8-1 (METRIC UNITS)
              EMISSION FACTORS FOR CLAY AND FLY ASH SINTERING*


k

Source (SSQ M
Fly ash crushing,
screening, sintering,
and storage
(3-05-009-01)d
Clay/coke mixture
sintering
(3-05-009-02)6
Clay/coke mixture
crushing, screening,
and storage
(3-05-009-07)f
Natural clay
sintering
(3-05-009-03)6
Natural clay
crushing, screening,
and storage
(3-05-009-04)f
Filterableb
PM
g/Mg Emission
of Factor
aterial Rating
55 E



20 E


7.5 E



6 E


6 E



PM-10
kg/Mg Emissi
of Facto
Material Ratuij
ND



ND


ND



ND


ND



Condensible PMC
Inorganic
on kg/Mg Emiss
r of Fact
I Material Ratii
ND



ND


ND



ND


ND



Organic
iion kg/Mg
or of
ng Material
ND



ND


ND



ND


ND



Emission
Factor
Rating


















  ND = No data.
  *Factors represent uncontrolled emissions unless otherwise noted.
  bFilterab!e PM is that PM collected on or prior to the filter of an EPA Method 5 (or equivalent)
    sampling train.
  Condensible PM is that PM collected in the impinger portion of a PM sampling train.
  ^Reference 1.
  References 3  to 5; for 90 percent clay, 10 percent pulverized coke; traveling grate, single pass,
  up-draft sintering machine.
  fBased on data in Section 8.19-2.
  SReference 2;  rotary dryer sinterer.
8.8-2
EMISSION FACTORS
2/72

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                               TABLE 8.8-1 (ENGISH UNITS)
                EMISSION FACTORS FOR CLAY AND FLY ASH SINTERING*


o 1
Source
(SSC) M
Filterable13
PM
)/ton Emission
of Factor
aterial Rating
Fly ash crushing, 1 10 E
screening, sintering, and
storage
(3-05-009-01)d
Clay/coke mixture
sintering
(3-05-009-02)e
Clay/coke mixture
crushing, screening, and
storage
(3-05-009-07)f
Natural clay sintering
(3-05-009-03)2
Natural clay crushing,
screening, and storage
(3-05-009-04)f



40 E


15 E



12 E

12 E


PM-10
lb/ton Emissi
of Factc
Material Ratin
ND



ND


ND



ND

ND


Condensible PMC
Inorganic
on lb/ton Ernies
r of Fact
g Material Rati
ND



ND


ND



ND

ND


Organic
ion lb/ton
or of
tig Material
ND



ND


ND



ND

ND


Emission
Factor
Rating
















  ND = No data.
  ^Factors represent uncontrolled emissions unless otherwise noted.
  bFilterable PM is that PM collected on or prior to the filter of an EPA Method 5 (or equivalent)
    sampling train.
  ^Condensible PM is that PM collected in the impinger portion of a PM sampling train.
  "Reference 1.
  References 3 to 5; for 90 percent clay, 10 percent pulverized coke; traveling grate, single pass,
    up-draft sintering machine.
  Tiased on data in Section 8.19-2.
  gReference 2; rotary dryer sinterer.
2/72
Mineral Products Industry
8.8-3

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References for Section 8.8

1.    Air Pollutant Emission Factors, Final Report, Resources Research, Inc., VA. Prepared for
      National Air Pollution Control Administration, Durham, N.C., under Contract
      No. (PA-22-68-119).  April 1970.

2.    Communication between Resources Research, Inc., Reston, VA, and a clay sintering firm.
      October 2, 1969.

3.    Communication between Resources Research, Inc., Reston, VA., and an anonymous Air
      Pollution Control Agency. October 16, 1969.

4.    J. J. Henn, et al, Methods for Producing Alumina from Clay: An Evaluation of Two Lime
      Sinter Processes, Department of the Interior, U. S. Bureau of Mines. Washington, DC, Report
      of Investigation No. 7299. September 1969.

5.    F. A. Peters, et al., Methods for Producing Alumina from Clay:  An Evaluation of the Lime-
      Soda Sinter Process, Department of the Interior, U. S. Bureau of Mines, Washington, DC.
      Report of Investigation No. 6927.  1967.
 8.8-4                              EMISSION FACTORS                               2/72

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 8.10 CONCRETE BATCHING

 8.10-1  Process Description1"4

        Concrete is composed essentially of water, cement, sand (fine aggregate) and coarse
 aggregate.  Coarse aggregate may consist of gravel, crushed stone or iron blast furnace slag.  Some
 specialty aggregate products could be either heavyweight aggregate (of barite, magnetite, limonite,
 ilmenite, iron or steel) or lightweight aggregate (with sintered clay, shale, slate, diatomaceous shale,
 perlite, vermiculite,  slag, pumice, cinders, or sintered fly ash).  Concrete batching plants store,
 convey, measure and discharge these constituents into trucks for transport to a job site.  In some
 cases, concrete is prepared at a building construction site or for the manufacture of concrete products
 such as pipes and prefabricated construction parts.  Figure 8.10-1 is a generalized process diagram for
 concrete batching.

        The raw materials can be delivered to a plant by rail, truck or barge.  The cement is
 transferred to elevated storage silos pneumatically or by bucket elevator.  The sand and coarse
 aggregate are transferred to elevated bins by  front end loader, clam shell crane, belt conveyor, or
 bucket elevator. From these elevated bins, the constituents are fed by gravity or screw conveyor to
 weigh hoppers, which combine the proper amounts of each material.

        Truck mixed (transit mixed) concrete involves approximately 75 percent of U. S. concrete
 batching plants. At  these plants, sand, aggregate, cement and water are all gravity fed from the
 weigh hopper into the mixer trucks.  The concrete is mixed on the way to the site where the concrete
 is to be poured. Central mix facilities (including shrink mixed) constitute the other one fourth of the
 industry.  With these, concrete is mixed and  then transferred to  either an  open bed dump truck or an
 agitator truck for transport to the job site.  Shrink mixed concrete is concrete that is partially  mixed at
 the central mix plant and then completely mixed in a truck mixer on the way to the job'site.  Dry
 batching, with concrete mixed and hauled to the construction site in dry form, is seldom, if ever,
 used.

 8.10-2  Emissions and Controls5"7

        Emission factors for concrete batching are given hi Tables 8.10-1  and 8.10-2, with potential
 air pollutant emission points shown.  Paniculate matter, consisting primarily of cement dust but
 including some aggregate and sand dust emissions,  is the only pollutant of concern. All but one of
the emission points are fugitive in nature. The only point source is the transfer of cement to the silo,
and this is usually vented to' a fabric filter or "sock". Fugitive sources include the transfer of sand
and aggregate, truck loading, mixer loading,  vehicle traffic, and wind erosion from sand and
aggregate storage piles. The amount of fugitive emissions  generated during the transfer of sand and
aggregate depends primarily on the surface moisture content of these materials. The extent of fugitive
emission control varies widely from plant to plant.

       Types of controls used may include water sprays, enclosures, hoods, curtains,  shrouds,
movable and telescoping chutes, and the like.  A major source of potential emissions, the movement
of heavy trucks over unpaved or dusty surfaces hi and around the plant, can be controlled by good
maintenance and wetting of the road surface.

 10/86                               Mineral Products Industry                              8.10-1

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                                                                      DO
                                                                       e
                                                                       a
                                                                      E
8.10-2
EMISSION FACTORS
                                                                         10/86

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                                   TABLE 8.10-1  (METRIC UNITS)
                        EMISSION FACTORS FOR CONCRETE BATCHING*

                          All Emission Factors in kg/Mg of Material Mixed Unless Noted
                                  Ratings (A-E) Follow Each Emission Factor
Filterableb
(SSC) PM
Condensible PM
PM-10 Inorganic Organic
Sand and aggregate transfer to elevated bin 0.014 E ND ND ND
(3-05-01 l-06)d
Cement unloading to elevated storage silo
Pneumatic6 0.13 D ND ND ND
Bucket elevated 0.12 E ND ND ND
(3-05-011-07) , 
Weigh hopper loading 0.01 E ND ND ND
(3-05-011-08)8
Mixer loading (central mix); 0.02 E ND ND ND
(3-05-011-09)8
Truck loading (truck mix) 0.01 E ND ND ND
(3-05-01 1-108
Vehicle traffic (unpaved roads) 4.5 C ND ND ND
(3-05-01 !-_/
Wind erosion from sand and aggregate storage 3.9 D ND ND ND
piles
(3-05-01 !-__)'
Total process emissions (truck mix) 0.05 E ND ND ND
(3-05-01 l-_J
   ND = No data.
   aFactors represent uncontrolled emissions unless otherwise noted.
   bFilterable PM is that PM collected on or prior to the filter of an EPA Method 5 (or equivalent) sampling train.
   "Condensible PM is mat PM collected in the impinger portion of a PM sampling train.
   dReference 6.
   eFor uncontrolled emissions measured before filter. Based on two tests on pneumatic conveying controlled by a fabric
   filter.
   Reference 7.  From test of mechanical unloading to hopper and subsequent transport of cement by enclosed bucket
   elevator to
   elevated bins with fabric socks over bin vent.
   gReference 5.  Engineering judgement, based on observations and emissions tests of similar controlled sources.
   hFrom Section 11.2.1, with k = 0.8, s = 12, S = 20, W = 20, w = 14, and p = 100; units of kg/vehicle kilometers
   traveled.
   JFrom Section 8.19.1, for emissions <30 micrometers from inactive storage piles; units of kg/hectare/day
   JBased on pneumatic conveying of cement at a truck mix facility. Does not include vehicle traffic or wind erosion from
   storage
   piles.
10/86
Mineral Products Industry
                                                                                                   8.10-3

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                                      Table 8.10-2 (English Units)
                       EMISSION FACTORS FOR CONCRETE BATCHING*

                    All Emission Factors in the Ib/ton (lb/yd3) of Material Mixed Unless Noted*5
                                  Ratings (A-E) Follow Each Emission Factor
Filterable0
Source  -
(SSC) PM
Condensible PMd
PM-10 Inorganic Organic
Sand and aggregate transfer to elevated bin 0.029 E ND ND ND
(3-05-01 l-06)e (0.05)
Cement unloading to elevated storage silo
Pneumaticf 0.27 D ND ND ND
(0.07)
Bucket elevator^ 0.24 E ND ND ND
(3-05-011-07) (0.06)

Weigh hopper loading 0.02 E ND ND ND
(3-OS-011-08)11 (0.04)
Mixer loading (central mix) 0.04 E ND ND ND
(3-05-01 1-09? (0.07)
Truck loading (truck mix) 0.02 E ND ND ND
(3-05-011-1011 (0.04)
Vehicle traffic (unpaved roads) 16 C ND ND ND
(3-05-01 !-_)' (0.02)
Wind erosion from sand and aggregate storage piles 3.5k D ND ND ND
(3-05-011-_JJ (O-l)1
Total process emissions (truck mix) 0.1 E ND ND ND
(3-05-01 l-_Jm (0.2)
  ND - No data.
  "Factors represent uncontrolled emissions unless otherwise noted.
  bBased on a typical yd3 weighing 1.818 kg (4,000 Ib) and containing 227 kg (500 Ib) cement, 564 kg (1,240 Ib) sand,
    864 kg (1,900 Ib) coarse aggregate and 164 kg (360 Ib) water.
  cFilterable PM is mat PM collected on or prior to the filter of an EPA Method 5 (or equivalent) sampling train.
  dCondensible PM is mat PM collected in the impinger portion of a PM sampling train.
  'Reference 6.
  fFor uncontrolled emissions measured before filter.  Based on two tests on pneumatic conveying controlled by a fabric
    filter.
  ^Reference 7.  From test of mechanical unloading to hopper and subsequent transport of cement by enclosed bucket
    elevator to elevated bins with fabric socks over bin vent.
  ^Reference 5.  Engineering judgement, based  on observations and emission tests of similar controlled sources.
  'From Section 11.2.1, with k = 0.8, s = 12, S - 20, W = 20, w = 14, and p = 100; units of Ib/vehicle miles traveled;
    based on facility producing 23,100 m3/yr (30,000 yd3/yr) of concrete, with average truck load of 6.2 m3 (8 yd3) and
    plant road length of 161 meters (0.1 mile).
  ^From Section 8.19.1, for emissions  <30 micrometers from inactive storage piles.
  fcUnits of Ib/acre/day.
  'Assumes 1,011 m2 (1/4 acre) of sand and aggregate storage at plant with production of 23,000 m3/yr (30,000 yrYyr).
  mBased on pneumatic conveying of cement at a truck mix facility; does not include vehicle traffic or wind erosion from
    storage piles.
8.10-4
EMISSION FACTORS
                                                                                                      10/86

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        Predictive equations that allow for emission factor adjustment based on plant specific
 conditions are given in Chapter 11.  Whenever plant specific data are available, they should be used
 in lieu of the fugitive emission factors presented in Table 8.10-1.

 References for Section 8.10


 1.  Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection Agency, Research
    Triangle Park, NC, April 1970.

 2.  Air Pollution Engineering Manual, 2nd Edition, AP-40, U. S. Environmental Protection Agency,
    Research Triangle Park, NC, 1974. Out of Print.

 3.  Telephone and written communication between Edwin A. Pfetzing, PEDCo Environmental., Inc.,
    Cincinnati, OH, and Richard Morris and Richard Meininger, National Ready Mix Concrete'
    Association, Silver Spring,  MD, May 1984.

 4.  Development Document for Effluent Limitations Guidelines and Standards of Performance,  The
    Concrete Products Industries, Draft, U. S. Environmental Protection Agency, Washington  DC
    August 1975.

 5.  Technical Guidance for Control of Industrial Process Fugitive Paniculate Emissions,
    EPA-450/3-77-010,  U. S. Environmental Protection Agency, Research Triangle Park NC
    March 1977.                                                                     '

6.  Fugitive Dust Assessment at Rock and Sand Facilities in the South Coast Air Basin, Southern
    California Rock Products Association and Southern California Ready Mix Concrete Association,
    Santa Monica, CA, November  1979.

7.  Telephone communication between T. R. Blackwood, Monsanto Research Corp., Dayton, OH,
    and John Zoller, Pedco Environmental, Inc., Cincinnati, OH, October 18, 1976.
                                  Mineral Products Industry                             8.10-5

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8.11  GLASS FIBER MANUFACTURING

8.11.1  General1'4

        Glass fiber manufacturing is the high-temperature conversion of various raw materials
(predominantly borosilicates) into a homogeneous melt, followed by the fabrication of this melt into
glass fibers.  The two basic types of glass fiber products, textile and wool, are manufactured by
similar processes.  A typical diagram of these processes is shown in Figure 8.11-1.  Glass fiber
production can be segmented into three phases:  raw materials handling, glass melting and refining,
and wool glass fiber forming and finishing, this last phase being slightly different for textile and
wool glass fiber production.

        Raw  Materials Handling - The primary component of glass fiber is sand, but it also includes
varying quantities of feldspar, sodium sulfate, anhydrous borax, boric acid, and many other materials.
The bulk supplies are received by rail car and truck, and the lesser-volume supplies  are received in
drums and packages. These raw materials are unloaded by a variety of methods, including drag
shovels, vacuum systems, and vibrator/gravity systems.  Conveying to and from storage piles and
silos is accomplished by belts, screws, and bucket elevators.  From storage, the materials are weighed
according to  the desired product recipe  and then blended well before their introduction into the
melting unit.  The weighing, mixing, and charging operations may be conducted in either batch or
continuous mode.

        Glass Melting and Refining -  In the glass melting furnace, the raw materials are heated to
temperatures ranging from 1500 to 1700C (2700 to 3100F) and are transformed through a
sequence of chemical reactions to molten glass.  Although there are many furnace designs, furnaces
are generally large, shallow, and well-insulated vessels that are heated from above.   In operation, raw
materials are introduced continuously on top  of a bed of molten glass, where they slowly mix and
dissolve.  Mixing is effected by natural convection, gases rising from chemical reactions, and, in
some operations, by air injection into the bottom of the bed.

        Glass melting furnaces can be categorized, by their fuel source and method of heat
application, into four types:  recuperative, regenerative, unit, and electric melter. The recuperative,
regenerative, and unit melter furnaces can be fueled by either gas or oil. The current trend is from
gas-fired to oil-fired. ELecuperative furnaces use a steel heat exchanger, recovering heat from the
exhaust gases by exchange with the combustion air.  Regenerative furnaces use a lattice of brickwork
to recover waste heat from exhaust gases.  In the initial mode of operation, hot exhaust gases are
routed through a chamber containing  a brickwork lattice, while combustion air is heated by passage
through another corresponding brickwork lattice. About every 20 minutes, the airflow is reversed, so
that the combustion air is always being passed through hot brickwork previously heated by exhaust
gases. Electric furnaces melt glass by passing an electric current through the melt.   Electric furnaces
are either hot-top or cold-top. The former use gas for auxiliary heating, and the latter use only the
electric current.  Electric furnaces are currently used only for wool glass fiber production because of
the electrical  properties of the glass formulation.  Unit melters  are used only for the "indirect" marble
melting process, getting raw materials from a continuous screw at the back of the furnace adjacent to
the exhaust air discharge. There are no provisions for heat recovery with unit melters.
9/85                                Mineral Products Industry                              8.11-1

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                           Raw materials
                        receiving and handling
                        Raw materials storage
                       Crushing, weighing, mixing
                         Melting and refining
                         Direct
                         process
                   Wool glass fiber
                                       Indirect
                                       process
                                                     Marble forming
                   Annealing
                                                  Marble storage, shipment
                                                       Marble melting
    Textile glass fiber
            Forming
                      Forming
          Binder addition
               Sizing, binding addition
          Compression
                      Winding
           Oven curing
                     Oven drying
             Cooling
                     Oven curing
            Fabrication
                                                         Fabrication
            Packaging
                     Packaging
                                               Raw
                                              material
                                              handling
                                                                            J
    Glass
    melting
     and
    forming
     Fiber
V   forming
'     and
    finishing
            Figure 8.11-1. Typical flow diagram of the glass fiber production process.
8.11-2
EMISSION FACTORS
                                                                                          9/85

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        In the "indirect" melting process, molten glass passes to a forehearth, where it is drawn off,
 sheared into globs, and formed into marbles by roll-forming.  The marbles are then stress-relieved in
 annealing ovens, cooled, and conveyed to storage or to other plants for later use. In the "direct"
 glass fiber process, molten glass passes from the furnace into a refining unit, where bubbles and
 particles are removed by settling, and the melt is allowed to cool to the proper viscosity for the fiber
 forming operation.

        Wool Glass Fiber Forming and Finishing - Wool fiberglass is produced for insulation and is
 formed into mats that are cut into batts.  (Loose wool is primarily a waste product formed from mat
 trimming, although some is a primary  product, and is only a small part of the total wool fiberglass
 produced.  No specific emission data for loose wool production are available.) The insulation is used
 primarily in the construction industry and is produced to comply with ASTM C167-64, the "Standard
 Test Method for Thickness and Density of Blanket- or Batt-Type Thermal Insulating Material."

        Wool fiberglass insulation production lines usually consist of the following processes:
 (1) preparation of molten glass, (2) formation of fibers into a wool fiberglass mat, (3) curing the
 binder-coated fiberglass mat, (4) cooling the mat, and (5) backing, cutting,  and packaging the
 insulation.  Fiberglass plants contain various sizes, types, and numbers of production lines, although  a
 typical plant has three lines.  Backing (gluing a flat flexible material, usually paper, to the mat),
 cutting, and packaging operations are not significant sources of emissions to the atmosphere.

        The trimmed edge waste from the mat and the fibrous dust generated during the cutting and
 packaging operations are collected by a cyclone and either are transported to a hammer mill to be
 chopped into blown wool (loose