United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park. NC 27711
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
-------
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Office 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
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INSTRUCTIONS FOR INSERTING SUPPLEMENT F
(CONT.)
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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
-------
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
-------
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
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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 Paved 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-
4.2.2.3 Magnet Wire Coating 4.2.2.3-
4.2.2.4 Other Metal Coating 4.2.2.4-
4.2.2.5 Flat Wood Interior Panel Coating 4.2.2.5-
4.2.2.6 Paper Coating 4.2.2.6-
4.2.2.7 Fabric Coating 4.2.2.7-
4.2.2.8 Automobile And Light Duty Truck Surface Coating Operations 4.2.2.8-
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
vii
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4.7 Waste Solvent Reclamation 4.7-1
4.8 Tank And Drum Cleaning 4.8-1
4.9 Graphic Arts 4.9-1
4.10 Commercial/Consumer Solvent Use 4.10-1
4.11 Textile Fabric Printing 4.11-1
4.12 Polyester Resin Plastics Product Fabrication 4.12-1
4.13 Waste Water Collection, Treatment And Storage 4.13-1
5. CHEMICAL PROCESS INDUSTRY 5.1-1
5.1 Adipic Acid 5.1-1
5.2 Synthetic Ammonia 5.2-1
5.3 Carbon Black ...5.3-1
5.4 Charcoal 5.4-
5.5 Chlor-Alkali 5.5-
5.6 Explosives 5.6-
5.7 Hydrochloric Acid 5.7-
5.8 Hydrofluoric Acid 5.8-
5.9 Nitric Acid 5.9-1
5.10 Paint And Varnish 5.10-1
5.11 Phosphoric Acid 5.11-1
5.12 Phthalic Anhydride 5.12-1
5.13.1 Polyvinyl Chloride And Polypropylene 5.13.1-1
5.13.2 Poly(ethylene terephthalate) 5.13.2-1
5.13.3 Polystyrene 5.13.3-1
5.14 Printing Ink ; 5.14-1
5.15 Soap And Detergents 5.15-1
5.16 Sodium Carbonate 5.16-1
5.17 Sulfuric Acid 5.17-1
5.18 Sulfur Recovery 5.18-1
5.19 Synthetic Fibers 5.19-1
5.20 Synthetic Rubber 5.20-1
5.21 Terephthalic Acid 5.21-1
5.22 Lead Alkyl 5.22-1
5.23 Pharmaceuticals Production 5.23-
5.24 Maleic Anhydride 5.24-
6. FOOD AND AGRICULTURAL INDUSTRY 6.1-
6.1 Alfalfa Dehydrating 6.1-
6.2 Coffee Roasting 6.2-
6.3 Cotton Ginning 6.3-
6.4 Grain Elevators And Processing Plants 6.4-
6.5 Fermentation 6.5-1
6.6 Fish Processing 6.6-1
6.7 Meat Smokehouses 6.7-1
6.8 Ammonium Nitrate 6.8-1
6.9 Orchard Heaters 6.9-1
6.10 Phosphate Fertilizers 6.10-1
6.11 Starch Manufacturing 6.11-1
6.12 Sugar Cane Processing 6.12-1
6.13 Bread Baking 6.13-1
6.14 Urea 6.14-1
6.15 Beef Cattle Feedlots 6.15-1
6.16 Defoliation And Harvesting Of Cotton 6.16-1
6.17 Harvesting Of Grain 6.17-1
6.18 Ammonium Sulfate 6.18-1
7. METALLURGICAL INDUSTRY 7.1-1
7.1 Primary Aluminum Production 7.1-1
7.2 Coke Production 7.2-1
viii
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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-
8.5 Castable Refractories 8.5-
8.6 Portland Cement Manufacturing 8.6-
8.7 Ceramic Clay Manufacturing 8.7-
8.8 Clay And Fly Ash Sintering 8.8-
8.9 Coal Cleaning 8.9-
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 8.14-1
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 10.1
Chlor-Alkali 5.5
Clay
Bricks And Related Clay Products 8.3
Ceramic Clay Manufacturing 8.7
Clay And Fly Ash Sintering 8.8
Cleaning
Coal 8.9
Dry Cleaning 4.1
Tank And Drum 4.8
Coal
Anthracite Coal Combustion 1.2
Bituminous Coal Combustion 1.1
Cleaning 8.9
Conversion 8.21
Coating, Surface 4.2
Appliance, Large 4.2.2.11
Automobile And Light Duty Truck 4.2.2.8
Can 4.2.2.2
Fabric 4.2.2.7
Flat Wood Interior Panel 4.2.2.5
Metal, General 4.2.2.4
Magnet Wire 4.2.2.3
Magnetic Tape 4.2.2.13
Metal Coil Surface 4.2.2.10
Metal Furniture 4.2.2.12
Paper 4.2.2.6
Plastic Parts For Business Machines 4.2.2.14
Tapes And Label, Pressure Sensitive 4.2.2.9
Coffee Roasting 6.2
Coke Manufacturing 7.2
Combustion
Anthracite Coal 1.2
Bagasse, In Sugar Mill 1.8
Bituminous Coal 1.1
Fuel Oil 1.3
Internal, Mobile Vol. II
Internal, Stationary 3.0
Lignite 1.7
Liquified Petroleum Gas 1.5
Natural Gas 1.4
xii
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Orchard Heater 6.9
Residential Fireplace .- . 1.9
Waste Oil 1.11
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 11.2
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 11.3
Drum
Tank And Drum Cleaning 4.8
Dry Cleaning 4.1
Dual Fuel Engines, Stationary 3.4
Dust
Fugitive Sources 11.2
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
Clay 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
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
Polyethylene 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 ....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 Drum 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
Truck 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
XVll
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XV111
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1.1 BITUMINOUS AND SUBBITUMINOUS 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 gained 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 hi
primary air before being fed through burners to the furnace, where it is fired hi 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 burn 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 bums 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 the 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 their 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 unburnt
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.
Paniculate Matter2"5 - Paniculate matter composition and emission levels are a complex
function of firing configuration, boiler operation, and coal properties, hi pulverized coal systems,
combustion is almost complete, and thus emitted paniculate 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. Paniculate 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 panicles is fired in spreader stokers, significant
unbumt carbon can be present in the paniculate. 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 paniculate 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 paniculate 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 paniculate 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. Paniculate loadings will often increase as load increases (especially as full load is
approached) and with sudden load changes. Similarly, paniculate 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, paniculate can be reduced significantly when overfire air
pressures are increased.
FBCs may tax conventional paniculate control systems. The paniculate 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 paniculate 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.
Paniculate 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 paniculate, 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 in reducing paniculate 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 paniculate loading reaching the controls".
Sulfur Oxides7"9 - Gaseous sulfur oxides (SOJ from coal combustion are primarily sulfur
dioxide (SOz), 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 form 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. hi 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 combustioa 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 (NO^. Nitrous oxide (N20)
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
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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 omly
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 burnere
designed to stage combustion in the flame zone. 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-fired 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 units20121.
Trace elements - Trace elements are also emitted from the combustion of coal. For this update
of AP-41, trace metals included hi the list of 189 hazardous air pollutants under Title in 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, hi general, depends on:
the physical and chemical properties of the element itself;
its concentration in the fuel;
the combustion conditions; and
the type of paniculate control device used, and its collection efficiency
as a function of particle size.
It has become widely recognized that some trace metals become concentrated hi 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 hi 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 hi Tables 1.1-1 and 1.1-2, along with
emission factor ratings. Paniculate matter and PM-10 emission factors and ratings are given hi Tables
1.1-3 and 1.1-4. Cumulative particle size distribution and paniculate size specific emission factors are
given hi 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 NO, emissions, the data
collected from test reports were considered to be baseline if no additional add-on NO, 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
-------
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
Firing Configuration
sec
SO,"
Emisslo
n Factor
Ib/ton
Rating
NO,"
Emissto
n Factor
Ib/ton
Rating
CO"-*
Emissto
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.
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 stoker*
Overfeed stoker, with multiple
cyclones'
Underfeed stoker
Underfeed stoker, with multiple
cyclone
Hand-fed units
Fluidized bed combustor, circulating
bed
Fluidized bed combustor, bubbling
bed
101002-12/26
102002-12/26
103002-16/26
1 01002-1 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
38S A 14.4 A 0.5
(35S)
38S 0 34.0 C 0.5
(35S)
38S D 33.8 C 0.5
(35S)
38S B 13.7 A 5
(35S)
38S B 13.7 A 5
(35S)
38S A 13.7 A 5
(35S)
38S B 7.5 A 6
(35S)
38S B 7.5 A 6
(35S)
31S B 9.5 A 11
31S B 9.5 A 11
31S D 9.1 E 275
g E 3.9 E 18
g E 15.2 D 18
A
A
A
A
A
A
B
B
B
B
E
E
D
a. Factors represent uncontrolled emissions unless otherwise specified and should be applied to
coal feed, as fired.
b. Expressed as SO2, including SO2, SO3, and gaseous sutfates. Factors in parentheses should
be used to estimate gaseous SOX emissions for subbftuminous 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 CO/ton
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)~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 1.1-9
-------
TABLE 1.1-2. (METRIC UNITS) EMISSION FACTORS FOR SULFUR OXIDES (SOJ.NITROGEN
OXIDES (NOJ, AND CARBON MONOXIDE (CO) FROM BITUMINOUS AND SUBBITUMINOUS COAL
COMBUSTION4
Firing Configuration
sec
SO,"
Emlssto
n
Factor
kg/Mg
Rating
NO,0
Ernlssk)
n
Factor
kg/Mg
Rating
co*.
Emlssto
n
Factor
kg/Mg
Rating
Pulverized coal fired, dry bottom, wall 101002-02/22 19S A 10.85 A .25 A
fired 102002-02/22 (17.58)
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 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, circulating
bed
Fluidized 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-O9/24
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
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
9
9
A
D
D
B
B
A
B
B
B
B
D
E
E
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
a. Factors represent uncontrolled emissions unless otherwise specified and should
coal feed, as fired.
b. Expressed as SO,, including SO2, SO3, and gaseous 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
•_s\f^i \s+**r\s\jt «*> v^N^oi " IWIMVMI ly wvoi v^3i CM ivi uowwu0 OUHCIIC^.
be used to estimate gaseous SOX emissions for subbituminous
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 COg/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 SO/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
COMBUSTION"
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
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
Ruidized bed combustor, bubbling bed
Ruidized 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
10A
10A
7A"
2A"
66-
17
12
16"
16"
151
ii-
is
12
17
Rating
A
B
0
E
B
B
A
C
C
D
D
E
E
E
PM-10
Emission
Factor
Ib/ton
2.3A
2.3A"
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 paniculate 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 emission factor for spreader stoker.
SCO = Source classification code.
7/93 External Combustion Sources 1.1-13
-------
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
COMBUSTION"
Fid
Emissii
Facto
Firing Configuration SCC kg/M<
Pulverized coal fired, dry bottom, wall fired 101002-02/22 5A
102002-02/22
103002-06/22
Pulverized coal fired, dry bottom, tangentially fired 101002-12/26 5A
102002-12/26
103002-16/26
arable PM6 PM-10
in Emission
r Factor
3 Rating kg/Mg Rating
A 1.15A E
B 1.15A0 E
Pulverized coal fired, wet bottom 101002-12/21 3.5A" D 1.3A E
102002-01/21
103002-05/21
Cyclone furnace 101002-03/23 1A"
102002-03/23
103002-23/01
Spreader stoker 101002-04/24 33"
102002-04/24
103002-09/24
Spreader stoker, with multiple cyclones, and 101002-03/24 8.5
reinfection 101002-04/24
103002-09/24
Spreader stoker, with multiple cyclones, no reinjection 101002-04/24 6
101002-04/24
103002-09/24
Overfeed stoker1 101002-05/25 8"
102002-05/10/25
103002-07/25
Overfeed stoker, with multiple cyclones' 101002-05/25 4.5"
102002-05/10/25
103-002-07/25
Underfeed stoker 102002-06 7.51
103002-08
Underfeed stoker, with multiple cyclone 102002-06 5.5"
103002-08
Hand-fed units 103002-14 7.5
Fluidized bed combustor, bubbling bed 101002-17 6
102002-17
103002-17
Fluidized bed combustor, circulating bed 101002-17 8.5
102002-17
103002-17
E 0.13A E
B 6.6 E
B 6.6 E
A 3.9 E
C 3.0 E
C 2.5 E
D 3.1 E
D 3.1' E
E 3.1' E
E 6.6" E
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 reinfection 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
-------
TABLE 1.1-5. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS FOR DRY BOTTOM BOILERS
BURNING PULVERIZED BITUMINOUS COAL"
Particle
Size"
0*m)
15
10
6
2.5
tfl
P 1.25
00
00
0 1.00
2
;> 0.625
q
O TOTAL
Cumulative Mass % < stated size
Controlled
Multiple
Uncontrolled cyclones Scrubber ESP
32 54 81 79
23 29 71 67
17 14 62 GO
6 3 51 29
2 1 35 17
2 1 31 14
1 1 20 12
100 100 100 100
Cumulative Emission Factor* [kg/Mg (IMon) coal, as fired]
Uncontrolled
Baghouse Factor Ratir
97 1.6A C
(3.2A)
92 1.15A C
(2.3A)
77 O.B5A C
(1.7A)
53 0.3A C
(0.6A)
31 0.10A C
(0.2A)
25 0.10A C
(0.2A)
14 0.05A C
(0.10A)
100 6A C
(10A)
ControDecf
Multiple cyclones
ig Factor
0.54A
(1.08A)
0.29A
(0.58A)
0.14A
(0.28A)
0.03A
(0.06A)
0.01A
(0.02A)
0.01A
(0.02A)
0.01A
(0.02A)
1A
<2A)
Rating
E
E
E
E
E
E
E
E
Scrubber
Factor
0.24A
(0.48A)
0.21A
(0.42A)
0.19A
(0.38A)
0.15A
(0.3A)
0.11A
(0.22A)
0.09A
(0.18A)
0.06A
(0.12A)
0.3A
(0.6A)
Rating
0
D
D
0
D
0
D
D
ESP
Factor Rath
0.032A 0
(0.06A)
0.027A 0
(0.05A)
0.020A D
(0.04A)
0.012A D
(0.02A)
0.007A D
(0.01A)
O.OOSA 0
(0.01A)
0.005A D
(0.01A)
0.04A D
(0.08A)
Baghouse
g Factor
0.01 OA
(0.02A)
O.OOSA
(0.02A)
0.008A
(0.02A)
O.OOSA
(0.01A)
0.003A
(0.006A)
0.003A
(0.006A)
0.001A
(0.002A)
0.01A
(0.02A)
Rating
E
E
E
E
E
E
E
E
a. Reference 32. Applicable SCCs are 101002-02/22, 102002-02/22, 103002-06/22, 101002-12/26, 102002-12/26, and 103002-16/26.
b. Expressed as aerodynamic equivalent diameter.
c. A = coal ash weight %, as fired.
d. Estimated control efficiency for multiple cyclones is 80%; for scrubber, 94%; for ESP, 99.2%; and for baghouse, 99.8%.
ESP = Electrostatic precipitator.
SCC = Source classification code.
-------
•-•
•— w
If
e o>
Si
2.0A
1.8*
1.6A
1.4A
l.ZA
I.OX
0.8A
0.6A
0.4A
0.2A
0
Scrubber
Bughouse
Uncontrolled
Multiple cyclone
•2 .4 .6 1 2 4 6 10
Particle diMeter (\m)
l.OA
0.6A l
•i
0.4A §C
=3 O.IA _
0.06A
0.04A
20
40 60 100
0.2A 2-Z —
a o
•-• u
0.1A Sfi
JC Jl
*•*—
0.06A ! |
o.oa||
si
0.02A--5 -
Is
0.01A — I
0.02A
0.01A
0.006A
0.004A
0.002A
0.001A
Figure 1.1-1. Cumulative size specific emission factors for dry bottom boilers burning pulverized
bituminous coal.
3.5A
2.8A
£« 2.1A
1.4A
0.70A
.1
l.OA
0.9A
0.8A
0.7A
O.GA
0.5A
0.4A
0.3A
0.2A
O.IA
0
0.1A
0.06A
U
O
*«•
0.04A S —
•a
0.02A o S
0.01A
•o —
.2 S
.4 .6 1 246 10
Particle diameter don)
20 40 60 100
O.lXMAg o.
a.
*rt
0.002A
0.001A
Rgure 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 COAL"
(Emission Factor Rating: E)
Partfcte Size"
(Mm)
Cumulative Mass % < stated size
Uncontrolled
Controlled
Multiple
cyclones
ESP
Cumulative Emission Factor0 [kg/Mg (Ib/ton) coal, as fired]
Uncontrolled
Controlled9
Multiple cyclones
ESP
15 40
10 37
6 33
2.5 21
1 Ofi 6
1.00 4
0.625 2
TOTAL 100
99
93
84
61
31
19
e
100
83
75
63
40
17
8
e
100
1.4A^8A)
1.30A(2.6A)
1.16A(2.32A)
0.74A(1.48A)
021 A (0.42A)
0.14A (0.28A)
0.07A (0.14A)
3.5A (7.0A)
0.69A(1.38A)
0.65A(1.3A)
0.59A(1.18A)
0.43A (0.86A)
0.22A (0.44A)
0.13A (0.26A)
e
0.7A(1.4A)
0.023A (0.46A)
0.021A (0.42A)
0.018A (0.36A)
0.011A(0.022A)
0.005A (0.01 A)
0.002A (O.OO4A)
e
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 = Electrostatic precipitator.
SCC = 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"
(jun)
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
0.055A (0.11 A) 0.0029A (0.006A)
1.25
85
22
0.051 A (0.1 OA) 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
-------
l.OA
0.9A
C.8A
0.7A
0.6A
0.5A
U S 0.4A
l€ 0.3A
B 01
8i 0.2A
0.1A
0
.4 .6 1 2 4 6 10
Particle diameter (inn)
Uncontrolled
0.1QA
O.ObA
0.04A
0.02A
0.01A
0.006A
0.004A
0.002A
0.001A
I
20
40 60 100
Figure 1.1-3. Cumulative size specific emission factors for cyclone furnaces burning bituminous coal.
10.0
•^' ^
s c
Multiple cyclone with
flyash reinjection
Multiple cyclone without
flyash reinjection
- 0.2
1 2 4 6 10
Particle diameter
60 100
0.1 _J
0.10
0.06
U.04 S
w
•a
O.OZ §1
tfl '
-:
0.01 *'
0.006 "g i
1=
0.004 S;
3;
0.002 f
0
0.001
Figure 1.1-4. Cumulative size specific emission factors for spreader stokers burning bituminous coal
1.1-20
EMISSION FACTORS
7/93
-------
TABLE 1.1-8. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS FOR SPREADER STOKERS
BURNING BITUMINOUS COAL'
Parlicki
Sizab
(tun)
Cumulative Mass % < stated size
(SCO) ~
Uncontrolled
Controlled
Multiple
cyclones0
Multiple
cyclones"
ES
P
Baghouse
Cumulative Emission Factor* [kg/Mg (Ib/ton) coal, as fired]
Uncontrolled
(101002-04/24
102002-0474
103002-09/24)
Factor Rating
Controlled'
Multiple cyclones*
(101002-03/24
101002-04/24
103002-09/24)
Factor
15 28 56 74 97 72 8.4 C 4.4
(16.8) (8.8)
Rating
Multiple cyclones'
(101002-04/24
101002-04/24
103002-09/24)
Factor
E 0.23
(0.46)
Rating
ESP1
(101002-04/24
102002-04/24
103002-0974)
Factor
C 0.043
(0.086)
Rating
Baghouse'
(101002-04/24
102002-04/24
103002-09/24)
Factor
E 0.01 OA
(0.02A)
Rating
C
b?
fi?
P
&
f
1
K
o'
S3
00
i
8
en
10
6
2.5
1.25
1.00
0.625
TOTAL
a.
b.
c.
d.
e.
f.
ESP =
SCC =
20 73 65 90
14 51 52 82
7 8 27 61
5 2 16 46
5 2 14 41
4 1 9 e
100 100 100 100
Reference 32.
Expressed as aerodynamic equivalent
With flyash reinjection.
Without flyash reinjection.
Insufficient data.
Estimated control efficiency for ESP is
Electrostatic precipitator.
Source classification code.
60 6.2
(12.4)
46 4.3
(8.6)
26 0.7
(1.4)
18 0.2
(0.4)
15 0.2
(0.4)
7 0.1
(0.2)
100 8.5
(17.0)
diameter.
99.22%; and for
C 3.9 E
(7.8)
C 3.1 E
(6.2)
C 1.6 E
(3.2)
C 1.0 E
(2.0)
C 0.8 E
(1.6)
C 0.5 E
(1.0)
C 6.0 E
(12.0)
baghouse, 99.8%.
0.22
(0.44)
0.20
(0.60)
0.15
(0.30)
0.11
(0.22)
0.10
(0.20)
e
0.24'
(0.48)
C 0.036
(0.072)
C 0.028
(0.066)
C 0.016
(0.032)
C 0.011
(0.022)
C 0.009
(0.018)
C 0.004
(0.006)
C O.OS1
(0.12)
E 0.009A
(0.02A)
E 0.008A
(0.02A)
E 0.005A
(0.01A)
E 0.003A
(0.006A)
E 0.003A
(0.006A)
E 0.001A
(0.002A)
E 0.01A
(0.02A)
C
C
C
C
C
C
C
-------
TABLE 1.1-9. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR OVERFEED STOKERS BURNING BITUMINOUS COAL8
Particle
Size6
Gun)
Cumulative Mass % _< stated size
Uncontrolled
Multiple Cyclones
Controlled
Cumulative Emission Factor* [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.
c. Insufficient data.
d. Estimated control efficiency for multiple cyclones is 80%.
SCC = Source classification code.
1.1-22
EMISSION FACTORS
7/93
-------
8
7.2
- 6-4
r - 4.8
•o S «-0
« U
.— Ol
£| 3.2
|~ 2.4
3
1.6
0.8
0
Multiple
cyclone
.1 .2 .4 .6
1 2 4 6 10
Particle diuwter (no)
10
1.0
8f
1.0 g w
0.2 5
o.i
20 40 60 100
Figure 1.1-5. Cumulative size specific emission factors for overfeed stokers burning bituminous coal.
10
9
&
Uncontrolled
i ill
i ill i i
.1 .2 .4 .6 1 2 4 6 10 20 40 60 100
Particle diueter
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 COAL8
Particle Size"
(urn)
Cumulative Mass %, <_ stated size
Uncontrolled Cumulative Emission Factor0 [kg/Mg (Ib/ton) coal,
Factor
as fired]
Rating
15 50
10 41
6 32
2.5 25
1.25 22
1.00 21
0.625 18
TOTAL 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
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.
1.1-24
EMISSION FACTORS
7/93
-------
TABLE 1.1-11. (ENGLISH UNITS) EMISSION FACTORS FOR METHANE (CHJ, 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,
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 stoker*
Overfeed stoker, with multiple
cyclones'
Underfeed stoker
Underfeed stoker, with multiple
cyclone
Hand-fed units
Ruidized bed combustor, bubbling
bed
Ruidized 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
CH4"
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"-"
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
.09*
.09'
.09°
.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 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
1.1-25
-------
(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 = 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 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 reinjectJon
Spreader stoker, with multiple
cyclones, no reinjecHon
Overfeed stoker*
Overfeed stoker, with multiple
cyclones'
Underfeed stoker
Underfeed stoker, with multiple
cyclone
Hand-fed units
Fluidized bed combustor, bubbling
bed
Ruidized bed combustor, circulating
bed
Ch
Emission
Factor
SCC kg/Mg
101002-02/22 0.02
102002-02/22
103002-06/22
101002-12/26 0.02
102002-12/26
103002-16/26
101002-12/21 0.025
102002-01/21
103002-05/21
101002-03/23 0.005
102002-03/23
103002-23
101002-04/24 0.03
102002-04/24
103002-09/24
101002-03/24 0.03
101002-04/24
103002-09/24
101002-04/24 0.03
101002-04/24
103002-09/24
101002-05/25 0.03
102002-05/10/25
103002-07/25
101002-05/25 0.03
102002-05/10/25
103002-07/25
102002-06 0.4
103002-08
102002-06 0.4
103002-08
103002-14 2.5
101002-17 0.03
102002-17
103002-17
101002-17 0.03
102002-17
103002-17
if NMTOC"-0
Emission
Factor
Rating kg/Mg Rati
B 0.04 B
B 0.04 B
B 0.02 B
B 0.055 B
B 0.025 B
B 0.025 B
B 0.025 B
B 0.025 B
B 0.025 B
B .65 B
B .65 B
E 5 E
E 0.025 E
E 0.025 E
N20
Emission
Factor
ng kg/Mg
.045
.015
.045"
.045°
.045'
.045*
.045*
.045*
.045"
.045*
.045*
.045°
2.75"
2.75
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 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
-------
U)
TABLE 1.1-13. (ENGLISH UNITS) EMISSION FACTORS FOR TRACE ELEMENTS, POLYCYCLIC ORGANIC MATTER (POM), AND
FORMALDEHYDE (HCOH) FROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION"
(Emission Factor Rating: E)
Rring Configuration
(SCC) As
Pulverized coal, NA
configuration unknown
(no SCC)
Pulverized coal, 538
wet bottom
(10100201)
Pulverized coal, 684
W dry bottom
§ (10100202)
g. Pulverized coal, NA
9 dry bottom, tangential
(10100212)
B
if Cyclone furnace 1 15
§. (10100203)
0
3 Stoker, NA
o1 configuration unknown
§ (no SCC)
k Spreader stoker 264-542
(10100204)
Traveling grate, 542-1030
overfeed stoker
(10100205)
Emission Factor, lb/10'2 Btu
Be Cd Cr Pb tJ
In Hg Nl POM HCOH
NA NA 1922 NA NA NA NA NA 112"
81 44-70 1020- 507 808-2980 16 840-1290 NA NA
81 44.4 1250-2570 507 228-2980 16 1030-1290 2.08 NA
NA NA NA NA NA NA NA 2.4 NA
<81 28 212-1502 507 228-1300 16 174-1290 NA NA
73 NA 19-300 NA 2170 16 775-1290 NA NA
NA 21-43 942-1570 507 NA NA NA NA 221"
NA 43-82 NA 507 NA NA NA NA 140"
a. The emission factors in this table represent the ranges of factors reported in the literature. If only one data point was found, it is still
reported in this table.
b. Based on 2 units; 456 MWe and 133 million Btu/hr.
c. Based on 1 unit; 59 million Btu/hr.
d. Based on 1 unit; 52 million Btu/hr.
SCC = Source classification code.
!•* NA = Not available.
-------
TABLE 1.1-14. (METRIC UNITS) EMISSION FACTORS FOR TRACE ELEMENTS, POLYCYCLIC ORGANIC MATTER (POM), AND
FORMALDEHYDE (HCOH) FROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION*
(Emission Factor Rating: E)
Emission Factor, pg/J
Bring Configuration
(SCC) As Be Cd Cr Pb
Pulverized coal, NA NA NA 825 NA
configuration unknown
(no SCC)
Pulverized coal, 231 35 18-30 439-676 218°
wet bottom
(10100201)
Pulverized coal, 294 35 19 638-676 218°
dry bottom
(10100202)
§ Pulverized coal, NA NA NA NA NA
Sg dry bottom, tangential
g (10100212)
Z Cyclone furnace 49.5-133 <34.9 12 91.2-676 218'
^ (10100203)
Q Stoker, NA 31.4 NA 8.1-675 NA
O configuration unknown
£ (no SCC)
Spreader stoker 114-233 NA 9.0-18.5 404-674 218°
(10100204)
Traveling grata, 233-443 NA 19-35 NA 218°
overfeed stoker
(10100205)
a. The emission factors in this table represent the ranges of factors reported in
reported in this table.
b. Based on 2 units; 456 MWe and 39 MW.
c. Based on 1 unit; 17 MW.
d. Based on 1 unit; 15 MW.
SCC = Source classification code.
NA = Not available.
3
Mn Hg Ni POM HCOH
NA NA NA NA 48k
348-1282 7 361-555 NA NA
98-1282 7 443-555 0.894 NA
NA NA NA 1.03 NA
98-5590 6.9 74.9-555 NA NA
934 6.9 334-555 NA NA
NA NA NA NA 95"
NA NA NA NA 60*
the literature. If only one data point was found, it is still
-------
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
Qas
PM
ng/J
(Ib/MMBtu)
[% reduction]
43
(0.10)
S02
ng/J
(Ib/MMBtu)
(% reduction]
NA
NO,
ng/J
(Ib/MMBtu)
[% reduction]
86
(0.20)
Industrial-
Utility
Commence
construction after
8/17/71
Oil
BiL/Subbit.
Coal
43
(0.10)
43
(0.10)
340
(0.80)
520
(1.20)
129
(0.30)
300
(0.70)
Subpart Da
Utility
>73
(>250)
Qas
13
(0.03
[NA]
340
(0.80)
[90r
86
(020)
[25]
Commence
construction after
9/18/78
Industrial-
Commerdal-
Institutional
Commence
construction after
6/19/84"
Oil
Bit/Subblt.
Coal
13
(0.03)
[70]
13
(0.03)
[99]
Distillate Oil
Residual Oil
Pulverized
BiL/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)
520
(1.20)
[90f
130
(0.30)
[30]
260/210°
(0.60/0.50)
[65/65]
Subpart Db
>29
Qas
NA"
NA"
431
(0.10)
3401
(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)
Subpart DC
Small Industrial-
CommerdaJ-
Institutional
Commence
construction after
6/9/89
2.9-29
(10 - 100)
Qas
Oil
Bit & SubWt
Coal
22"
(0.05)
215
(0.50)
520*
(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 = Fluidized bed combustion.
1.1-32 EMISSION FACTORS 7/93
-------
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
-------
TABLE 1-17. COMBUSTION MODIFICATION NO, CONTROLS FOR STOKER COAL-FIRED INDUSTRIAL BOILERS
Control Technique
Low Excess Air
(LEA)
Staged
combustion (LEA
+ OFA)
Load Reduction
(LR)
Reduced air
preheat (RAP)
Ammonia injection
Description of
Technique
Reduction of air
flow under stoker
bed
Reduction of
undergrate air
flow and increase
of overfire air flow
Reduction of coal
and air feed to the
stoker
Reduction of
combustion air
temperature
Injection of NHS in
convective section
of boiler
Effectiveness of
Control
(% NO, reduction) Range of
Application
5-25 Excess oxygen
limited to 5-6%
minimum
5-25 Excess oxygen
limited to 5%
minimum
Varies from 49% Has been used
decrease to 25% down to 25% load
increase in NO,
(average 15%
decrease)
8 Combustion air
temperature
reduced from
473K to 453K
40-40 (from gas- Limited by furnace
and oil-fired boiler geometry.
experience) Feasible NH3
injection rate
limited to 1.5
NHL/NO
Commercial
Availability/R&D
Status
Available now but
need R&D on
lower limit of
excess air
Most stokers have
OFA ports as
smoke control
devices but may
need better sir
flow control
devices
Available
Available now if
boiler has
combustion air
heater
Commercially
offered but not yet
demonstrated
Comments
Danger of
overheating grate,
clinker formation,
corrosion, and
high CO
emissions
Need research to
determined
optimum location
and orientation of
OFA ports for NO,
emission control.
Overheating grate,
corrosion, and
high CO emission
can occur if
undergrate airflow
is reduced below
acceptable level
as in LEA
Only stokers that
can reduce load
without increasing
excess air. Not a
desirable
technique
because of loss in
boiler efficiency
Not a desirable
technique
because of loss in
boiler efficiency
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
-------
REFERENCES FOR SECTION 1.1
1. Steam. 38th Edition, Babcock and Wilcox, New York, 1975.
2. Control Techniques for Particulate Emissions from Stationary Sources. Volume
I, EPA-450/3-81-005a, U.S. Environmental Protection Agency, Research
Triangle Park, NC, April 1981.
3. Ibidem. Volume U. 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 NO, 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 (SO,) 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 Polvcvclic 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,
1975.
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: NOT
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 Particulate 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
-------
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 palletizing; 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 there are over IS
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/Ib) 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) in 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 bum 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 bum 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 hi a wet-
bottom or dry bottom mode; because of its high ash fusion temperature, anthracite coal is burned hi
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 hi 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 bums hi 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
participate 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, paniculate 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 paniculate.
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 paniculate 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
-------
Table 1.2-1. EMISSION FACTORS FOR SPEOATED 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
IbAon
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 pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
Source Classification Codes are 10100102,10200104, and 10300102.
''BDL = Below detection limit
Table 1.2-2. EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS (TOC) AND
METHANE (Oty FROM ANTHRACITE COAL COMBUSTORS8
Source Category
(SCC)b
TOC Emission Factor
kg/Mg
Ib/ton
Rating
CH4 Emission Factor
kg/Mg
Ib/ton
Rating
Stoker fired boilers0
(SCC 10100102,
10200104, 10300102)
Residential spaced
heaters
(no SCC)
0.10
NDe
0.20
ND
E
ND
ND
aUnits are kg of pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
bSCC = Source Classification Code.
Reference 9.
Reference 14.
eND = Nodata.
1.2-4
EMISSION FACTORS
7/93
-------
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
Fluoranthrene
Pyrene
Benzo(a)anthracene
Chrysene
Benzo(k)fluoranthrene
Benzo(e)pyrene
Benzo(a)pyrene
Perylene
Indeno(123-cd) perylene
Benzo(g4i4.) perylene
Anthanthrene
Coronene
Stoker Fired Boilersb
(SCC 10100102,
10200104, 10300102)
Emission Factor
1.25E-02
3.4E-03
0.65E-01
NDd
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
"Units are kg of pollutant/Mg of anthracite coal burned
Residential Space Heaters0
(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
SCC = Source Classification Code.
Reference 9.
Reference 14.
dND = No data.
7/93
External Combustion Sources
1.2-5
-------
Table 1.2-4 (English Units). EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
FROM ANTHRACITE COAL COMBUSTORS"
EMISSION FACTOR RATING: E
Pollutant
Stoker Fired Boilers5
(SCC 10100102,
10200104,
10300102)
Emission Factor
Residential Space Heaters0
(No SCO
Emission Factor
Range
Emission Factor
Biphenyl
Phenanthrene
Naphthalene
Acenaphthene
Acenaphthalene
Fluorene
Anthracene
Fluoranthrene
Pyrene
Benzo(a)anthracene
Chrysene
Benzo(k)fluoranthrene
Benzo(e)pyrene
Benzo(a)pyrene
Perylene
Indeno(123-cd) perylene
Benzo(gji4,) perylene
Anthanthrene
Coronene
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
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
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
&Units 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
-------
Table 1.2-5. EMISSION FACTORS FOR PARTICIPATE MATTER (PM), AND LEAD (Pb)
FROM ANTHRACITE COAL COMBUSTORSa
Source Category
(SCC)b
Filterable PM
Emission Factor
kg/Mg
IbAon
Rating
Condensible PM
Emission Factor
kg/Mg
Ib/ton
Rating
Pb
Emission Factor
kg/Mg
Ib/ton
Rating
I
Stoker fired boilersc
(SCC 10100102,
10200104, 10300102)
Hand fired units6
(SCC 10200207,
10300103)
0.4Ad
0.8A
10
0.04A
B
0.08A
ND
4.5E-03 8.9E-03
ND
ND
§
aUnits are kg of pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
bSCC = Source Classification Code.
''References 9-12.
dA = ash content of fuel, weight percent
Reference 16.
fND = No data.
-------
Table 1.2-6. EMISSION FACTORS FOR NITROGEN OXIDE COMPOUNDS (NO.) AND
to
oo
W
B
do
HH
o
2
52
SULFUR
Source Category
(SCC)b
Stoker fired boilers6
(SCC 10100102, 10200104,
10300102)
FBC boilers8
(no SCC)
Pulverized coal boilers
(SCC 10100101, 10200101,
10300101)
Residential space heaters
(no SCC)
DIOXIDE (S02) FROM ANTHRACITE COAL COMBUSTORSa
NOX Emission Factor*
kg/Mg IbAon
4.6 9.0
0.9 1.8
9 18
1.5 3
Rating
C
E
B
B
SO2 Emission Factor'1
kg/Mg
19.5Sf
1.5
19.5S
19.5S
Ib/ton
39S
2.9
39S
39S
Rating
B
E
B
B
RS
"Units are kg of pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
bSCC = Source Classification Code.
References 17-18.
Reference 19.
References 10-11.
fS = weight percent sulfur.
Reference 15. FBC = Fluidized bed combustion; FBC boilers burning culm fuel; all other sources burning anthracite coal.
-------
Table 1.2-7. EMISSION FACTORS FOR CARBON MONOXIDE (CO) AND
CARBON DIOXIDE (COj) FROM ANTHRACITE COAL COMBUSTORS*
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
2840
NDe
5680
ND
"Units 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.
®ND = No data.
7/93
External Combustion Sources
1.2-9
-------
Table 1.2-8. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION
FACTORS FOR DRY BOTTOM BOILERS BURNING PULVERIZED ANTHRACITE GOAL8
EMISSION FACTOR RATING: D
Particle
Sizeb
(urn)
Cumulative Mass % < stated size
Uncontrolled
Controlled0
Multiple
Cyclone
Baghouse
Cumulative Emission Factor*1
kg/Mg (Ib/ton) coal, as fiied
Uncontrolled
Controlled0
Multiple
Cyclone
Baghouse
15
10
6
2.5
1.25
1.00
0.625
TOTAL
32
23
17
6
2
2
1
100
63
55
46
24
13
10
7
100
79
67
51
32
21
18
100
1.6A (3.2A)e
1.2A (2.3A)
0.9A (1.7A)
0.3A (0.6A)
0.1 A (0.2A)
0.1 A (0.2A)
0.05A (0.1 A)
5A (10A)
0.63A
(1.26A)
0.55A
(1.10A)
0.46A
(0.92A)
0.24A
(0.48A)
0.1 3A
(0.26A)
0.10A
(0.20A)
0.07A
(0.14A)
1A (2A)
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%.
dUnits are kg of pollutant/Mg of coal burned and Ibs. of pollutant/ton of coal burned.
eA = coal ash weight %, as fired.
Insufficient data.
1.2-10
EMISSION FACTORS
7/93
-------
2.0A
1.8A
1.6A
1.4A
8-" l.OA
"88
= » 0.8A
sC
§£ 0.6A
u
= 0.4A
0.2A
0
Baghouse
Multiple
cyclone
Uncontrolled
.1
.4 .6 1 2 46 10
farticle diameter (|jm)
l.OA
0.9A
0.8A
0.7A
0.6A
0.5A
0.4A
0.3A
0.2A
0.1A
sl
f.
40 60 10'J
0.010A
0.009A
o
0.008A tj
0.007A .f'
*
0.006A |v
0.005A _•
oS
0.004A hu
c 01
O X
0.003A ^f"
0.00? A
0.001A
0
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
-------
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 Paniculate 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., Bedfoid, 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, Inc, 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
-------
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, Moigantown, 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 a/., 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
-------
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 me 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.
1.3.2 Emissions27
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 (SO^ and particulate matter (PM) can also be obtained
from measurements taken upstream of APC equipment.
In this section, point source emissions of nitrogen oxides (NO^), S02, PM, and carbon
monoxide (CO) are being evaluated as criteria pollutants (those emissions which have established
National Primary and Secondary Ambient Air Quality Standards. Particulate 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 (COj) 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 sectioa
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
-------
Paniculate Matter Emissions3-7-12-13*1-*3-24
Paniculate 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 S 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, paniculate 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 paniculate
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 paniculate
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 dioxide (SO,); and about 1 to 3 percent is emitted as sulfate paniculate. SO3 readily reacts with
water vapor (both in the atmosphere and in flue gases) to form a sulfuric acid mist.
Nitrogen Oxides Emissions1'11-14-15-20-24-25-2^29'1
Oxides of nitrogen (NOJ 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 (NO^. 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
-------
Fuel nitrogen conversion is the more important NOx-forming mechanism in residual oil boilers.
It can account for SO percent of the total NO, 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 other 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 configuratioa NOX emissions from tangentially (comer) fired boilers are,
on the average, less than those of horizontally opposed units. Also important are the firing practices
employed during boiler operation. 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 the 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 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 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 (OJ availability;
poor fuel/air mixing;
7/93 External Combustion Sources 1.3-3
-------
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"19'30'35164
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 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 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 in 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, FGR, 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 improved 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 FGR)
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 NO,
control purposes, although for small units, some reduction hi 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 Substitution3-542-56
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-*0
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
hi small units for maximum operating efficiency and emissions control, particularly for PM and CO
emissions. Combustion modifications, such as LEA, FGR, 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. In 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 combustioa 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 the 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.
Particulate Matter Control56
Large industrial and utility boilers are generally, well-designed and well-maintained. Hence,
paniculate 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
paniculate. 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 hi
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 paniculate. 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 Hue 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
-------
TABLE 1.3-1 (METRIC UNITS). CRITERIA POLLUTANT EMISSION FACTORS FOR UNCONTROLLED FUEL OIL COMBUSTION
u>
Firing Configuration
(SCC)'
SO2b
Emission
Factor
kg/103 fi
Rating
S03C
Emission
Factor
kg/103 «
Rating
N0xd
Emission
Factor
kg/103 C
Rating
CO"
Emission
Factor
kg/103 C
Rating
Filterable PM8
Emission
Factor
kg/103 S
Rating
Utility boilers
No. 6 oil fired,
normal firing
(10100401)
19S
0.69S
0.6
w
x
£
i.
8
B
0*
§
o'
Tf\
0
8
co
?
NO
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)
19S A 0.69S C 5 A 0.6 A h A
19S A 0.69S C 8 A 0.6 A h B
19S A 0.69S C 5 A 0.6 A h B
18S A 0.69S C 8 A 0.6 A h B
18S A 0.69S C 5 A 0.6 A h B
19S A 0.24S A 0.6 A 0.6 A h A
19S A 0.24S A 0.6 A 0.6 A h B
-------
TABLE 1.3-1 (METRIC UNITS). CRITERIA POLLUTANT EMISSION FACTORS FOR UNCONTROLLED FUEL OIL COMBUSTION
(Continued)
Firing Configuration
(SCC)a
S02b
Emission
Factor
kg/103 '«
Rating
S03C
Emission
Factor
kg/103 a
Rating
NO/
Emission
Factor
kg/103 1
Rating
CO"
Emission
Factor
kg/103 fi
Rating
Filterable PM8
Emission
Factor
kg/103 5
Rating
Distillate oil fired
(102005-01/02/03)
No. 4 oil fired
(10200504)
17S
18S
w Commercial/insn'tutional/residential
GO
§
5
§
§
GO
No. 6 oil fired
(103004-01/02/03)
No. 5 oil fired
(10300404)
Distillate oil fired
(103005-01/02/03)
No. 4 oil fired
(10300504)
Residential furnace
(No SCC)
19S
19S
17S
18S
17S
A
A
combustors
A
A
A
A
A
0.24S
0.24S
0.24S
0.24S
0.24S
0.24S
0.24S
A
A
A
A
A
A
A
2.4
2.4
0.6
0.6
2.4
2.4
2.2
A
A
A
A
A
A
A
0.6
0.6
0.6
0.6
0.6
0.6
0.6
A
A
A
A
A
A
A
h
h
h
h
h
h
0.3
A
B
A
B
A
B
A
aSCC = Source Classification Code.
References 1-6, 23, 42-46. S indicates that the weight % of sulfur in the oil should be multiplied by the value given.
•References 1-5,45-46, 22.
•"References 3-4, 10, 15, 24, 42-46, 48-49. Expressed as N02. Test results indicate that at lease 95 % by weight of NO, is NO for all boiler
types except residential furnaces, where about 75 % is NO. For utility vertical fired boilers use 12.6 kg/103 C at full load and normal (>15%)
excess air. Nitrogen oxides emissions from residual oil combustion in industrial and commercial boilers are related to fuel nitrogen content,
estimated by the following empirical relationship: kg N02 /103 C = 2.465 + 12.526(N) where N is the weight percent of nitrogen in the
oil.
"References 3-5, 8-10, 23, 42-46,48. CO emissions may increase by factors of 10 to 100 if the unit is improperly operated or not well
maintained.
-------
w
8
00
o
TABLE 1.3-1 (METRIC UNITS). CRITERIA POLLUTANT EMISSION FACTORS FOR UNCONTROLLED FUEL GEL COMBUSTION
(Continued)
"Emission factor for CO2 from oil combustion should be calculated using kg (XyiO3 H oil = 31.0 C (distillate) or 34.6 C (residual).
References 3-5, 7, 21, 23-24, 42-46, 47, 49. Filterable PM is that paniculate collected on or prior to the filter of an EPA Method 5 (or
equivalent) sampling train. PM-10 values include that particulate collected in the PM-10 filter cyclone of an EPA Method 201 or 201 A
sampling train.
"Paniculate emission factors for residual oil combustion are, on average, a function of fuel oil grade and sulfur content:
No. 6 oil:U2(S) + 0.37 kg/103 fi where S is the weight % of sulfur in oil.
No. 5 oil: 1.2 kg/103 fl
No. 4 oil:0.84 kg/103 C
No. 2 oil:0.24 kg/103 fi
-------
TABLE 1.3-2 (ENGLISH UNITS). CRITERIA POLLUTANT EMISSION FACTORS FOR UNCONTROLLED FUEL OIL COMBUSTION
u>
1— »
Firing Configuration
(SCQa
Utility boilers
No. 6 oil fired,
normal firing
(10100401)
w No. 6 oil fired,
H tangential firing
03 (10100404)
0
2 No. 5 oil fired,
j> normal firing
Q (10100405)
g No. 5 oil fired,
tangential firing
(10100406)
No. 4 oil fired,
normal firing
(10100504)
No. 4 oil fired,
tangential firing
(10100505)
Industrial boiler
No. 6 oil fired
o (102004-01/02/03)
w No. 5 oil fired
(10200404)
S02b
Emission Ratii
Factor
lb/103 gal
157S A
157S A
157S A
157S A
150S A
150S A
157S A
157S A
S03C
ig Emission Ratii
Factor
lb/103 gal
5.7S C
5.7S C
5.7S C
5.7S C
5.7S C
5.7S C
2S A
2S A
N0xd
ig Emission Rating Emiss
Factor Fac
lb/103 gal lb/ia
67 A 5
42 A 5
67 A 5
42 A 5
67 A 5
42 A 5
55 A 5
55 A 5
CO6' Filterable
PM8
iion Rating Emission
:or Factor
1 gal lb/103 gal
A h
A h
A h
A h
A h
A h
A h
A h
Rating
A
A
B
B
B
B
A
B
-------
TABLE 1.3-2 (ENGLISH UNITS). CRITERIA POLLUTANT EMISSION FACTORS FOR UNCONTROLLED FUEL OIL COMBUSTION
(Continued)
f
£
on
I
00
o
LO
Firing Configuration
(SCC)a
Distillate oil fired
(102005-01/02/03)
SO2b
Emission
Factor
lb/103 gal
142S
Rating
A
No. 4 oil fired 150S A
(10200504)
Commercial/institutional/residential combustors
No. 6 oil fired
(103004-01/02/03)
No. 5 oil fired
(10300404)
Distillate oil fired
(103005-01/02/03)
No. 4 oil fired
(10300504)
Residential furnace
(No SCC)
157S
157S
142S
150S
142S
A
A
A
A
A
SO;
Emission
Factor
lb/103 gal
2S
2S
2S
2S
2S
2S
,2S
c
1
Rating
A
A
A
A
A
A
A
N0xd
Emission
Factor
lb/103 gal
20
20
55
55
20
20
18
Rating
A
A
A
A
A
A
A
CO8'
Emission Rati
Factor
lb/103 gal
5 A
5 A
5 A
5 A
5 A
5 A
5 A
Filterable
PMg
ng Emission
Factor
lb/103 gal
h
h
h
h
h
h
0.3
Rating
A
B
A
B
A
B
A
"SCC = Source Classification Code.
''References 1-6, 23, 42-46. S indicates that the weight % of sulfur in the oil should be multiplied by the value given.
•References 1-5, 45-46, 22.
dReferences 3-4, 10, 15, 24, 42-46, 48-49. Expressed as N02. Test results indicate that at lease 95 % by weight of NOX is NO for all boiler
types except residential furnaces, where about 75 % is NO. For utility vertical fired boilers use 105 lb/103 gal at full load and normal
(>15%) excess air. Nitrogen oxides emissions from residual oil combustion in industrial and commercial boilers are related to fuel nitrogen
content, estimated by the following empirical relationship: Ib NO2 /103 gal = 20.54 + 104.39(N) where N is the weight percent of nitrogen
in the oil.
-------
TABLE 1.3-2 (ENGLISH UNITS). CRITERIA POLLUTANT EMISSION FACTORS FOR UNCONTROLLED FUEL OIL COMBUSTION
£ (Continued)
•»t
•References 3-5, 8-10,23,42-46,48. CO emissions may increase by factors of 10 to 100 if the unit is improperly operated or not well
maintained.
'Emission factor for C02 from oil combustion should be calculated using Ib (XyiO3 gal oil = 259 C (distillate) or 288 C (residual).
"References 3-5, 7, 21, 23-24, 42-46, 47,49. Filterable PM is that paniculate collected on or prior to the filter of an EPA Method 5 (or
equivalent) sampling train. PM-10 values include that paniculate collected in the PM-10 filter cyclone of an EPA Method 201 or 201A
sampling train.
"Paniculate emission factors for residual oil combustion are, on average, a function of fuel oil grade and sulfur content:
No. 6 oil:9.19(S) + 3.22 lb/103 gal where S is the weight % of sulfur in oil
No. 5 oil: 10 lb/103 gal
No. 4 oil:7 lb/103 gal
No. 2 oil:2 lb/103 gal
CO
I
I
00
OJ
-------
TABLE 1.3-3 (METRIC UNITS). EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
(TOC), METHANE, AND NONMETHANE TOC (NMTOC)
FROM UNCONTROLLED FUEL OIL COMBUSTION
Firing Configuration
(SCC)a
TOG*
Emission
Factor
kg/103 fi
Rating
Methane6
Emission
Factor
kg/103*
Rating
NMTOC*
Emission
Factor
kg/103 «
Rating
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)
Distillate oil fired
(102005-01/02/03)
No. 4 oil fired
(10200504)
0.125
0.125
0.125
0.125
0.125
0.125
0.154
0.154
0.030
0.030
Commercial/institutional/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
A
A
A
A
A
A
0.091
0.091
0.091
0.091
0.091
0.091
0.034
0.034
0.024
0.024
A
A
A
A
0.136 A
0.136 A
7/93
External Combustion Sources
1.3-15
-------
TABLE 1.3-3 (METRIC UNITS). EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
(TOO, METHANE, AND NONMETHANE TOC (NMTOC)
FROM UNCONTROLLED FUEL OIL COMBUSTION (Continued)
Firing Configuration
(SCC)*
TOC"
Emission
Factor
kg/103 «
Rating
Methaneb
Emission
Factor
kg/103 i
Rating
NMTOC"
Emission
Factor
kg/103 C
Rating
Distillate oil fired
(103005-01/02/03)
No. 4 oil fired
(10300504)
Residential furnace
(No SCC)
0.067
0.067
0.299
0.026
0.026
0.214
0.041
0.041
0.085
*SCC = Source Classification Code.
"Tleferences 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 TOC (NMTOC)
FROM UNCONTROLLED FUEL OIL COMBUSTION
Firing
Configuration
(SCC)8
TOG"
Emission
Factor
lb/103 gal
Rating
Methane"
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/iristitutional/residential combustors
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
0.28
0.28
0.2
0.2
1.13
1.13
A
A
A
A
A
A
7/93
External Combustion Sources
1.3-17
-------
TABLE 1.3-4 (ENGLISH UNITS). EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
(TOC), METHANE, AND NONMETHANE TOC (NMTOC)
FROM UNCONTROLLED FUEL OIL COMBUSTION (Continued)
Firing
Configuration
(SCC)a
TOG"
Emission
Factor
lb/103 gal
Rating
Methane"
Emission
Factor
lb/103 gal
Rating
NMTOC"
Emission
Factor
lb/103 gal
Rating
Distillate oil fired
(103005-01/02/03)
No. 4 oil fired
(10300504)
Residential furnace
(No SCQ
0.556
0.556
2.493
A
A
A
0.216
0.216
1.78
A
A
A
0.34
0.34
0.713
A
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.
1.3-18
EMISSION FACTORS
7/93
-------
TABLE 1.3-5. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS FOR
UTILITY BOILERS FIRING RESIDUAL OIL"
Particle
Sizeb
(um)
15
10
W 6
£
1 2'5
f i*
i i.oo
o
0
g1 0.625
0 TOTAL
Cumulative Mass %
Uncon-
trolled
80
71
58
52
43
39
20
100
< stated size
Controlled
ESP
75
63
52
41
31
28
10
100
Scrubber
100
100
100
97
91
84
64
100
Cumulative Emission Factor, [kg/103 C (lb/103 gal)]
Uncontrolled0
Factor
0.80A (6.7A)
0.71A (5.9A)
0.58A (4.8A)
0.52A (4.3A)
0.43A (3.6A)
0.39A (3.3A)
0.20A (1.7A)
1A (8.3A)
Rating
C
C
C
C
C
C
C
C
ESP Controlled"
Factor
0.0060A (0.05A)
0.005A (0.042A)
0.0042A (0.035A)
0.0033A (0.028A)
0.0025A (0.021A)
0.0022A (0.018A)
0.0008A (0.007A)
0.008A (0.067A)
Rating
E
E
E
E
E
E
E
E
Scrubber Controlled'
Factor
0.06A (0.50A)
0.06A (0.050A)
0.06A (0.50A)
0.058A (0.48A)
0.055A (0.46A)
0.050A (0.42A)
0.038A (0.32A)
0.06A (0.50A)
Rating
D
D
D
D
D
D
D
"Reference 29. ESP = electrostatic precipitator. Source Classification Codes: 101004-01/04/05/06, 101005-04/05.
""Expressed as aerodynamic equivalent diameter.
^articulate 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/1031 Where S is the weight % of sulfur in the oil
No. 5 oil: A = 1.2 kg/103 5
No. 4 oil: A = 0.84 kg/103 fi
"Estimated control efficiency for scrubber is 94%.
•Estimated control efficiency for ESP is 99.2%.
u>
-------
TABLE 1.3-6. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS FOR
INDUSTRIAL BOILERS FIRING RESIDUAL OIL"
w
§
on
O
J
9
§
03
Particle Size"
(urn)
15
10
6
2.5
1.25
1.00
0.625
TOTAL
Cumulative Mass % £ stated size
Uncontrolled
91
86
77
56
39
36
30
100
Multiple Cyclone
Controlled
100
95
72
22
21
21
d
100
Cumulative Emission Factor0, [Kg/103 1 (lb/103 gal)]
Uncontrolled
Factor
0.91A (7.59A)
0.86A (7.17A)
0.77A (6.42A)
0.56A (4.67A)
0.39A (3.25A)
0.36A (3.00A)
0.30A (2.50A)
1A (8.34A)
Rating
D
D
D
D
D
D
D
D
Multiple Cyclone Controlled6
Factor
0.20A (1.67A)
0.19A (1.58A)
0.14A (1.17A)
0.04A (0.33A)
0.04A (0.33A)
0.04A (0.33A)
d
0.2A (1.67A)
Rating
E
E
E
E
E
E
E
•Reference 29. Source Classification Codes: 102004-01/02/03/04, 10200504.
"Expressed as aerodynamic equivalent diameter.
°Particulate 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) + 0.38 kg/1031! Where S is the weight % of sulfur in the oil
No. 5 oil: A = 1.2 kg/103 C
No. 4 oil: A = 0.84 kg/103 fl
•"Insufficient data.
"Estimated control efficiency for multiple cyclone is 80%.
-------
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 fi (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 OIL*
EMISSION FACTOR RATING: D
Particle
Size" (urn)
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 C Where S is the weight % of sulfur in the oil
No. 5 oil: A = 1.2 kg/103 «
No. 4 oil: A = 0.84 kg/103 «
No. 2 oil: A = 0.24 kg/103 «
1.3-22
EMISSION FACTORS
7/93
-------
il
S
i
i.o*
0.9*
O.BA
0.7*
0.6*
O.SA
0.4*
0.3*
0.2*
0.1*
0
i I i I 1
0.10* — ,
0.09* 3
0.06A t
e
0.07* S
B
0.06A ,-
0.05*
0.04A
0.03* I
0.02* X
0.01A
.1 .2 .4 .6 1 2 46 10
Particle diameter (pin)
20
40 60 100
0.01A
0.006*
0.004* e
u
0.002* J
•Jt
£<•
0.001* -
0.0006* ^
0.0004* §
0.0002* £
O.ObOlA
Figure 1.3-1. Cumulative site specific emission factors for utility boilers firing residual oil.
i>
*
S
1.0*
0.9*
O.BA
0.7A
0.6A
O.SA
0.4A
0.3A
0.2A
0.1A
OA
.1
0.20*
0.18*
0.16*
•"!•
0.14* "S
0.12* I
u
o.io* I
0.08* S
.4 .6 1 2 4 6 10
Particle diameter (u»)
0.06* 5
0.04A
0.02A
0*
« £
-
20
40 60 100
Figure 1.3-2. Cumulative site specific emission factors for industrial boilers firing residual oil.
7/93
External Combustion Sources
1.3-23
-------
0.2S
0.20
«*
u
J 0.15
if
? « o. 10
I**
g 0.05
.1 .2 .4 .6 1 2 4 6 10 20 40 M 100
Ptrticlt dlMtttr (v»)
Figure 1.3-3. Cumulative site specific emission factors for uncontrolled industrial boilers firing
distillate oil.
l.OOA
0.90A
0.80A
0.7QA
0.6QA
O.SOA
0.4QA
O.JQA
0.20A
O.iOft
0
.1
DistilUte oil
Residual oil
•4 .6 1 2 4 6 10 20
Ptrticlt diameter (ym)
0.25
0.20 r
0.10
o.os s
40 60 100
Rgure 1.3-4. Cumulative site specific emission factors for uncontrolled commercial boilers burning
residual fl"d diisHHate 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
(SCG)"
Emission Factor, kg/103 { (lb/103 gal)
N2Ob
POM0
HCOff
UtJlitv/industrial/commercial boilers
No. 6 oil fired 0.013 (0.11) 3.2-3.6 (7.4-8.4)" 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 SCQ
*SCC = Source Classification Code.
•References 28-29.
•References 16-19.
"Paniculate 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
SubpaitD
Industrial-
Utility
Commence
construction
after 8/17/71
SubpartDa
Utility
Commence
construction
after 9/18/78
SubpartDb
Industrial-
Commercial-
Institutional
Commence
construction
after 6/19/84m
Boiler Size Fuel
MW or
(Million Boiler
Btu/hr) Type
>73 Gas
(>250)
Oil
Bit/Subbit.
Coal
>73 Gas
(>250)
Oil
BiL/Subbit
Coal
>29 Gas
(>100)
Distillate Oil
Residual Oil
Pulverized
BiL/Subbit.
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]
NA"
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]'
340
(0.80)
[90]8
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]
60
(0.20)
129
(0.30)
300
(0.70)
86
(020)
[25]
130
(0.30)
[30]
260/210°
(0.60/0.50)
[65/65]
43f
(0.10)
43f
(0.10)
130s
(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
Industrial-
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
JHJ
22*
(0.05)
SO2
ng/J
Gb/MMBtu)
[% reduction]
-
215
(0.50)
520"
(1.20
[90]
NOX
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 man 260 ng/J (0.60 Ib/MMBtu).
The first number applies to bituminous coal and the 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.
fpor 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.
Standard 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 faculties
combust only very low sulfur oil (< 0.5 wL % sulfur).
FBC = Fluidized bed combustion.
7/93
External Combustion Sources
1.3-27
-------
oo
TABLE 1.3-11. EMISSION FACTORS FOR TRACE ELEMENTS FROM FUEL OIL COMBUSTION SOURCES
EMISSION FACTOR RATING: E
Firing Configuration
(SCC)"
Emission Factor, pg/J
Sb As
No. 6 oil fired 10-20 8.2-49
(101004-01/04 (24-46) (19-114)
10200401
10300401)
Distillate oil fired
W (10100501
I 10200501
GO 10300501)
w
55
NA 1.8
(4.2)
Be
1.8
(4.2)
1.1
(2.5)
Cd
6.8-91
(16-211)
4.5
(11)
Cr
9.0-55
(21-128)
21-29
(48-67)
Co
33-50
(77-121)
NA
(lb/1012 Btu)b
Pb
12-80
(28-194)
3.8
(8.9)
Mn
10-30
(23-74)
6.0
(14)
Hg
0.6-14
(1.4-32)
1.3
(3.0)
Ni
360-964
(837-2330)
7.3
(18)
Se
16
(38)
NA
""References 16-19, 36-40. The emission factors in this table represent the ranges of factors reported in the literature. If only one data point
was found, it is still reported in this table.
NA = Not available.
-------
TABLE 1.3-12. COMBUSTION MODIFICATION NOX CONTROLS FOR OIL FIRED BOILERS
Control
Technique
Description of
Technique
Effectiveness of Control
(Percent NOX Reduction)
Residual
Oil
Distillate
Oil
Range of Application
Commercial Availability/
R&D Status
Comments
I
C/3
o
to
VO
Low Excess
Air (LEA)
Staged
Combustion
(SC)
Burners Out
of Service
(BOOS)
Flue Gas
Recirculation
(FOR)
Flue Gas
Recirculation
Plus Staged
Combustion
Reduction of 0 to 28
combustion air
Fuel-rich firing 20 to 50
burners with
secondary
combustion air
ports
One or more 10 to 30
burners on air
only.
Remainder
firing fuel rich.
Recirculation of 15 to 30
portion of flue
gas to burners
Combined 25 to 53
techniques of
FOR and staged
combustion
0 to 24 Generally excess O2
can be reduced to 2.5
% representing a 3 %
drop from baseline
17 to 44 70-90% burner
stoichiometries can
be used with proper
installation of
secondary air ports
N/A Applicable only for
boilers with
minimum of 4
burners. Best suited
for square burner
pattern with top
burner or burners out
of service. Only for
retrofit application.
58 to 73 Up to 25-30% of
flue gas recycled.
Can be implemented
on all design types.
73 to 77 Max. FGR rates set
at 25% for distillate
oil and 20% for
residual oil
Available
Technique is applicable
on package and field-
erected units. However,
not commercially
available for all design
types
Available.
Retrofit requires careful
selection of BOOS pattern
and control of air flow.
Available.
Requires extensive
modifications to the
burner and windbox.
Combined techniques are
still at experimental stage.
Added benefits included
increase in boiler efficiency.
Limited by increase in CO,
HC, and smoke emissions.
Best implemented on new
units. Retrofit is probably not
feasible for most units,
especially packaged ones.
Retrofit often requires boiler
de-rating unless fuel delivery
system is modified.
Best suited for new units.
Costly to retrofit. Possible
flame instability at high FGR
rates.
Retrofit may not be feasible.
Best implemented on new
units.
-------
U)
TABLE 1.3-12. COMBUSTION MODIFICATION NOX CONTROLS FOR OIL FIRED BOILERS (Continued)
Control
Technique
Description of
Technique
Effectiveness of Control
(Percent NOX Reduction)
Residual
Oil
Distillate
Oil
Range of Application
Commercial Availability/
R&D Status
Comments
Load
Reduction
(LR)
B
Reduction of air
and fuel flow to
all burners in
service
33% decrease 31% Applicable to all
to 25% decrease boiler types and
increase in to 17% sizes. Load can be
NOX increase reduced to 25% of
in NO, maximum.
Available now as a
retrofit application. Better
implemented with
improved firebox design.
Technique not effective when
it necessitates an increase in
excess 02 levels. LR possibly
implemented in new designs
as reduced combustion
intensity (enlarged furnace
plan area).
Low NOX
Burners
(LNB)
New burner
designs with
controlled
air/fuel mixing
and increased
heat dissipation
20 to 50 20 to 50 New burners
described generally
applicable to all
boilers. More
specific information
needed.
Commercially offered but
not demonstrated
Specific emissions data from
industrial boilers equipped
with LNB are lacking
Ammonia
Injection
Injection of
NH3asa
reducing agent
in the flue gas
40 to 70 40 to 70
Applicable for large
package and field-
erected watertube
boilers. May not be
feasible for fire-tube
boilers.
Commercially offered but
not demonstrated
Elaborate NH3 injection,
monitoring and control
system required. Possible
load restrictions on boiler and
air preheater fouling when
burning high sulfur oil.
Reduced Air Bypass of
Preheat combustion air
(RAP) preheater
5 to 16 N/A Combustion air
temperature can be
reduced to ambient
conditions (340K)
Available. Not
implemented because of
significant loss in thermal
efficiency.
Application of this technique
on new boilers requires
installation of alternate heat
recovery system (e.g., an
economizer)
3
-------
TABLE 1.3-13. POST-COMBUSTION NOX REDUCTION TECHNOLOGIES
Technique
Description
Advantages
Disadvantages
1. Urea
injection
Injection of urea
into furnace to react
with NOX to form
N2 and H2O
Low capital cost
Relatively simple system
Moderate NOX removal (30-
60%)
Non-toxic chemical
Typically, low energy injection
sufficient
Temperature dependent
Design must consider boiler operating
conditions and design
Reduction may decreased at lower
loads
2. Ammonia
injection
(Thermal-
DeNOx)
Injection of
ammonia into
furnace to react
with NOX to form
N2 and H2O
- Low operating cost
- Moderate NOX removal (30-
60%)
Moderately high capital cost
Ammonia handling, storage,
vaporization and injection systems
required (Ammonia is a toxic
chemical)
3. Air Heater
(AH-)SCR
Air heater baskets
replaced with
catalyst coated
baskets. Catalyst
promotes reaction
of ammonia with
NO,.
- 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
Design must address pressure drop,
maintain heat transfer
Due to rotation of air heater, only
50% of catalyst is active at any time
4. Duct SCR
A smaller version of
conventional SCR is
placed in existing
ductwork
- Moderate capital cost
- Moderate NOX removal (30%)
- No additional ductwork
required
Duct location unit specific
temperature, access dependent
Some pressure drop must be
accommodated
5. Activated
Carbon
SCR
Activate carbon
catalyst, installed
downstream of air
heater, promotes
reaction of
ammonia with NOX
at low temperature.
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
SOX removal as well as NOX
removal
High pressure drop
Not a fully commercial technology
7/93
External Combustion Sources
1.3-31
-------
TABLE 1.3-13. POST-COMBUSTION NO, REDUCTION TECHNOLOGIES (Continued)
Technique
Description
Advantages
Disadvantages
1. Urea
injection
Injection of urea
into furnace to react
with NOX to form
NjandHjO
- Low capital cost
- Relatively simple system
- Moderate NO, removal (30-
60%)
- Non-toxic chemical
- Typically, low energy injection
sufficient
Temperature dependent
Design must consider boiler operating
conditions and design
Reduction may decreased at lower
loads
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%)
Very high capital cost
High operating cost
Extensive ductwork to/from reactor
Large volume reacU>* ^XUG: tc ci'el
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
Magnesium
oxide/hydroxide
Dual alkali
80-95+%
90-96%
Can be regenerated
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
1.3-33
-------
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-------
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7/93 External Combustion Sources 1.3-35
-------
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1.3-36 EMISSION FACTORS 7/93
-------
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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, et al.. 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 Desuifurization: Installations and Operations. PB 257721, National Technical
Information Service, Springfield, VA, September 1974.
55. Proceedings: Flue Gas Desuifurization Symposium - 1973, EPA-650/2-73-038, U.S.
Environmental Protection Agency, Washington, DC, December 1973.
56. G.R. Offen, et al.. 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
16tfa International Symposium on Combustion). August 1976.
7/93 External Combustion Sources 1.3-37
-------
58. D.W. Perching 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. Nutcher, 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, et al.. Integrated NOx Reduction Plan to Meet Staged SCAQMD Requirements
for Steam Electric Power Plants. Proceedings of the 53rd American Power Conference, 1991.
62. D.W. South, et al.. 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
-------
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 generatioa 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 HOOBtu/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 in 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 FGR 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 in the combustion zone, thereby lowering die peak flame temperature
and reducing the amount of NOX formed. To a lesser extent, FGR also reduces NOX formation by
7/93 External Combustion Sources 1.4-1
-------
lowering die oxygen concentration in the primary flame zone. Hie amount of flue gas recirculated is a
key operating parameter influencing NOX emission rates for these systems. Flue 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 in 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. hi some cases, the addition of NOX control systems such as FGR
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
1.4-2 EMISSION FACTORS 7/93
-------
40
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
-------
Table 1.4-1. EMISSION FACTORS FOR PARTICULATE MATTER (PM)
FROM NATURAL GAS COMBUSTION8
Combustor Type
(Size, 106 Btu/hr heat input)
[SCC]b
Filterable PM°
kg/106 m3
lb/106 ft3
Rating
Condensible PM'1
kg/106 m3
lb/106 ft3
Rating
m
§
a
Utility/large industrial boilers (>100)
[10106001, 10100604]
Small industrial boilers (10 - 100)
[10200602]
Commercial boilers (0.3 -<10)
[10300603]
Residential furnaces (<0.3)
[no SCC]
16-80
99
72
2.8
1-5
6.2
4.5
0.18
B
B
C
C
NDe
120
120
180
ND
7.5
7.5
11
D
C
D
"References 9-14. All factors represent uncontrolled emissions. Units are kg of pollutant/106 cubic meters and Ibs. of pollutant/106 cubic
feet. Based on an average natural gas higher heating value of 8270 kcal/nr (1000 Btu/scf). The emission factors in this table may be
converted to other natural gas heating values by multiplying the given emission factor by the ratio of the specified heating value to this
average heating value.
bSCC = Source Classification Code.
cFilterable PM is that paniculate matter collected on or prior to the filter of an EPA Method 5 (or equivalent) sampling train.
dCondensible PM is that participate matter collected in the impinger portion of an EPA Method 5 (or equivalent) sampling train. Total PM
is the sum of the filterable PM and condensible PM. All PM emissions can be assumed to be less man 10 microns in aerodynamic
equivalent diameter (PM-10).
= No data.
-------
Table 1.4-2. EMISSION FACTORS FOR SULFUR DIOXIDE (SO2), NITROGEN OXIDES (NOX),
AND CARBON MONOXIDE (CO) FROM NATURAL GAS COMBUSTION"
Combustor Type
(Size, 106 Btu/hr heat input)
[SCC]b
Utility/Large Industrial Boilers (>100)
[10100601, 10100604]
Uncontrolled
Controlled - Low NOX burners
Controlled - Flue gas recirculation
Small Industrial Boilers (10-100)
W [10200602]
S Uncontrolled
g. Controlled - Low NOX burners
Q Controlled - Flue gas recirculation
B
§• Commercial Boilers (0.3-<10)
1 [10300603]
§ Uncontrolled
£3" Controlled - Low NOX burners
3 Controlled - Flue gas recirculation
kg/106m3
9.6
9.6
9.6
9.6
9.6
9.6
9.6
9.6
9.6
S02C
lb/106ft3
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.6
Rating
A
A
A
A
A
A
A
A
A
kg/106m3
8800
1300
850
2240
1300
480
1600
270
580
NOxd
lb/106ft3
550*
81f
53f
140
81f
30
100
17
36
Rating
A
D
D
A
D
C
B
C
D
kg/106m3
640
ND*
ND
560
980
590
330
425
ND
C0e
lb/10%3
40
ND
ND
35
61
37
21
27
ND
Rating
A
A
D
C
C
C
Residential Furnaces (<0.3)
[no SCC]
Uncontrolled
9.6
0.6
1500
94
B
640
40
B
*Units are kg of pollutant/106 cubic meters and Ibs. of pollutant/106 cubic feet Based on an average natural gas higher heating value of 8270 kcal/m3
(1000 Btu/scf). The emission factors in this table may be converted to other natural gas heating values by multiplying the given emission factor by the ratio
of the specified heating value to this average heating value.
bSCC = Source Classification Code.
dReference 7. Based on average sulfur content of natural gas, 4600 g/106 Nm3 (2000 gr/106 set).
"References 10, 15-19. Expressed as NO2. For tangentially fired units, use 4400 kg/106 m3 (275 lb/106 ft3). At reduced loads, multiply factor by load
reduction coefficient in Figure 1.4-1. Note that NOX emissions from controlled boilers will be reduced at low load conditions.
References 9-10, 16-18, 20-21.
^Emission factors apply to packaged boilers only.
hND = No data.
-------
ON
Table 1.4-3. EMISSION FACTORS FOR CARBON DIOXIDE (CO2), AND TOTAL ORGANIC COMPOUNDS (TOC)
FROM NATURAL GAS COMBUSTION*
w
§
'S3
o
z
!fl
Combustor Type
(Size, 106 Btu/hr heat input)
[SCC]b
Utility/large industrial boilers (>100)
[10100601, 10100604]
Small industrial boilers (10-100)
[10200602]
Commercial boilers (0.3-<10)
[10300603]
Residential furnaces
[no SCC]
kg/106m3
NDe
1.9E06
1.9E06
2.0E06
aAll factors represent uncontrolled emissions. Units are
C02C
Ib/lO6^
ND
1.2E05
1.2E05
1.3E05
Rating
D
C
D
kg of pollutant/106 cubic meters
kg/106m3
28f
92«
92h
ISO11
TOC11
Ib/lO6*3
1.7f
5.88
5.8h
llh
and Ibs. of pollutant/106 cubic feet
Rating
C
C
C
D
Based on
90
00
an average natural gas higher heating value of 8270 kcal/m (1000 Btu/scf). The emission factors in this table may be converted to
other natural gas heating values bay multiplying the given factor by the ratio of the specified heating value to this average heating
value.
bSCC = Source Classification Code.
References 10, 22-23.
References 9-10, 18.
CND = No data.
Reference 8: methane comprises 17 percent of organic compounds.
8Reference 8: methane comprises 52 percent of organic compounds.
Reference 8: methane comprises 34 percent of organic compounds.
OJ
-------
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 Paniculate 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, "Particulate 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. Shin, 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.
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
-------
References for Section 1.4 (Continued)
14. N. F. Suprenant, el 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
-------
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.
1-4
1.5.2 Emissions and Controls
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 venting. 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 air, 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 in 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-
NO, 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 NO, reduction. This is a trimming technique
which may be necessary during backup fuel periods because LPG typically has a higher NO^-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 (FGR). Nitrogen oxide emissions from propane combustion can be reduced by as much
7/93 External Combustion Sources 1.5-1
-------
as 50 percent by recirculating 16 percent of the flue gas. Nitrogen oxide emission reductions of over
60 percent have been achieved with FOR and low NO, burners used in combinatioa
1.5-2 EMISSION FACTORS 7/93
-------
TABLE 1.5-1. (ENGLISH UNITS) EMISSION FACTORS FOR LPG
COMBUSTION8
(Source Classification Codes)
EMISSION FACTOR RATING: E
Pollutant
Butane Emission Factor
lb/1000 gal
Industrial
Boilersb
(10201001)
Filterable paniculate matter* 0.6
Sulfur oxides' 0.09S
Nitrogen oxides' 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 NOJ 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 paniculate 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 (0.09 x 0.18=) 0.016 Ib of
SOj/1000 gal butane burned.
'Expressed as NO2.
7/93
External Combustion Sources
1.5-3
-------
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 paniculate matter4 0.07
Sulfur oxides' 0.01 IS
Nitrogen oxides' 2.5
Carbon dioxide 1,760
Carbon monoxide 0.4
Total organic compounds 0.07
Commercial
Boilers6
(10301001)
Propane Emission Factor
kg/1000 liters
Industrial
Boilers6
(10201002)
0.06 0.07
0.01 IS 0.012S
1.8 2.3
1,760 1,500
0.3 0.4
0.07 0.06
Commercial
Boilers"
(10301002)
0.05
0.012S
1.7
1,500
0.2
0.06
"Assumes emissions (except SOX and NOJ 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.
bHeat 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
SCyiOOO liters butane burned.
'Expressed as NO2.
1.5-4
EMISSION FACTORS
7/93
-------
References for Section 1.5
1. Letter dated August 19, 1992. From W. Butterbaugh of the National Propane Gas Association,
Lisle, Illinois, to J. McSoriey of the U.S. Environmental Protection Agency, Research Triangle
Paik, NC.
2. Air Pollutant Emission Factors. Final Report, Contract No. CPA-22-69-119, Resources
Research, Inc., Reston, VA, Durtiam, 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. Childless of Suburban/Petrolane, Durham, NC.
7/93 External Combustion Sources 1.5-5
-------
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 Practices5'7
Various boiler firing configurations are used for burning wood waste. One common type of
boiler used in smaller operations is the Dutch ovea 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 hi 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 bum 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 in 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 hi
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 die 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 man on fixed grates. Rapid changes in
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 paniculate 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 paniculate emission levels when
property 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 bum 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 paniculate 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), paniculate
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. Paniculate 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,
paniculate collection efficiencies were above 98 percent
Emissions of nitrogen oxides (NO*) 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, hi 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.
Fjnission 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 Btu/lb) higher heating values.
EMISSION FACTORS 7/93
-------
25
20
15
Multiple cyclone
• I.
M '
6 I;
5 =
4 S
S -
.1 .2 .4 .6 1 2 46 10 20 40 60 100 *
P«rt1clc dlooeter (un)
Figure 1.6-1. Cumulative size specific emission factors for bark fired boilers.
2.0
1.8
1.6
1.4
1.2
1.0
0.8
0.6
0.4
0.2
0.0
7/93
External Combustion Sources
1.6-5
-------
00
00
o
55
g
00
i.
o — •
*J -O
0 4J
rtJ L.
O Irt
••- ta
ts>
v\ •
,
0) -o
•— o
e*
*J o>
u en
c .vc
3.5
2.8
2.1
1.4
0.7
Uncontrolled
Dry electrostatic
granular filter
Multiple cyclone
-with flyash
reinjectlon
j I
Multiple cyclone
without flyash
reinjection
.1 .2 .4 .6 1 2 46 10
Particle diameter dim)
3.0
2.7
2.4
2.1
1.8
1.5
1.2
0.9
0.6
0.3
0
u
Iff
O
•r-
w y ~~
•r- '
g
TJ
01
E!5
•»-» ^>
c ^^
O T>
U O
0§
o en
r- s:
o ^>«
x, m
u ^
a.
•r-
4^
20
40 60 100
0.220
0.218
t.
0.216 2^
«J? ^
0.214 c C
0.212 | «
5 «
0.210 "gfe
0.208 SI
c 5
0.206 uf
01 at
0.204 |^
0.202 "*
0.200
0.2
u
01
4J
,2
*3 e
c o
«o -a T)
«
i— 0
- *
«8-S*
£ ~
a
Figure 1.6-2. Cumulative size specific paniculate matter emission factors for wood/bark-fired boilers.
-------
Table 1.6-1. EMISSION FACTORS FOR PARTICULATE MATTER (PM), PARTICULATE MATTER LESS THAN 10 MICRONS
(PM-10), AND LEAD FROM WOOD WASTE COMBUSTION8
s
I
§
£
Source Category
(SCC)b
PM°
kg/Mg 1 Ib/ton
Rating
kg/Mg
PM-10"
IbAon
Rating
kg/Mg
Lead"
Ib/ton
Rating
Bark-fired boilers
(10100901, 10200901, 10200904, 10300901)
Uncontrolled
Mechanical collector
with flyash reinjection
without flyash reinjection
Wet scrubber
Wood/bark-fired boilers
23.5 47
7 14
4.5 9.0
1.5 2.9
B
B
B
D
84
5.5
1.6
1.3
17
11
3.2
25
D
D
D
D
1.4E-03
NDf
ND
2.9E-03
ND
ND
D
(10100902, 10200902, 10200905, 10300902)
Uncontrolled
Mechanical collector
with flyash reinjection
without flyash reinjection
Wet scrubber
Electrostatic precipitator
Wood-fired boilers
3.6 7.2
3.0 6.0
2.7 5.3
0.24 0.48
0.02 0.04
C
C
C
D
D
3.2
2.7
0.08
0.23
ND
6.5
5.5
1.7
0.47
ND
E
E
E
E
ND
1.6E-048
1.6E-048
1.8E-04
8.0E-05
ND
3.2E-048
3.2E-04"
3.5E-04
1.6E-05
D
D
D
(10100903, 10200903, 10200906, 10300903)
Uncontrolled
Mechanical collector
without flyash reinjection
Electrostatic precipitator
4.4 8.8
2.1 4.2
0.08 0.17
C
C
D
ND
1.3"
ND
ND
2.6"
ND
D
ND
1.5E-04
5.5E-03
ND
3.1E-04
1.1E-03
D
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 2,500 kcal/kg (4,\500 Btu/lb) higher heating value.
"SCC = Source Classification Code.
'References 11-15.
"References 13, 16.
"References 11, 13-15, 17.
"ND = No data.
8Due to lead's relative volatility, it is assumed that flyash reinjection does not have a significant effect on lead emissions
following mechanical collectors.
hBased on one test in which 61 percent of emitted PM was less than 10 micrometer in size.
-------
£ Table 1.6-2. EMISSION FACTORS FOR NITROGEN OXIDES (NOX), SULFUR OXIDES (SOX), AND CARBON MONOXIDE (CO)
FROM WOOD WASTE COMBUSTION"
oo
Source Category
(SCC)b
Fuel cell/Dutch
oven boiler
(no SCC)
Stoker boilers
(no SCC)
FBC boilers'
W (no SCC)
kg/Mg
0.19
(0.0017-0.75)
0.75
(0.33-1.8)
1.0
NOXC
IbAon
0.38
(0.0033-1.5)
1.5
(0.66-3.6)
2.0
Rating
C
C
D
kg/Mg
0.37
(0.005-0.1)
0.37
(0.005-0.1)
0.37
(0.005-0.1)
S0xd
Ib/ton
0.075
(0.01-0.2)
0.075
(0.01-0.2)
0.075
(0.01-0.2)
Rating
B
B
B
&2 "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
kg/Mg
3.3
(0.33-11)
6.8
(0.95-40)
0.7
(0.24-1.2)
moisture and
C0e
IbAon
6.6
(0.65-21)
13.6
(1.9-80)
1.4
(0.47-2.4)
Rating
C
C
D
2,500 kcal/kg (4,500
Btu/lb) higher heating value.
"SCC = Source Classification Code.
°References 12-14,18-20. NOX formation is primarily a function of wood nitrogen content. Higher values in the range (parentheses) should
be used for wood nitrogen contents above a typical value of 0.08 weight percent, as fired.
Reference 23. Lower limit of the range (in parentheses) should be used for wood and higher values for bark.
'References 11-15, 18, 24-26. Higher values in the range (in parentheses) should be used if combustion conditions are less than adequate,
such as unusually wet wood or high air-to-fuel ratios.
*FBC = Fluidized bed combustion.
u>
-------
TABLE 1.6-3 EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS (TOC) AND
CARBON DIOXIDE (COj) FROM WOOD WASTE COMBUSTION8
Source Category
(SCC)b
TOC
kg/Mg
Ib/ton
Rating
C02d
kg/Mg
Ib/ton
Rating
Fuel cell/Dutch oven
boilers
(no SCC)
0.09
0.18
1100
2100
B
Stoker boilers
(no SCC)
FBC boilers'
(no SCC)
0.11
NDf
0.22
ND
C 1100
1100
2100
2100
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 SO 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 1.6-4 (Metric Units). EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
FROM WOOD WASTE COMBUSTION"
Organic Compound*
Phenols
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoianthene
Pyrene
Benzo(a)anthracene
Benzo(b+k)fluoranthene
Benzo(a)pyrene
Benzo(g,h4)perylene
Chrysene
Indeno(l,23,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
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^.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
43E-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
K2E-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
6.0E-09"*
LSE-OS^
2.2E-05
4.5E-06*
7.0E-058
2.0E-06*
1.1E-05*
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 Compound*
Phenols
Acenaphthene
Fluorene
Phenanthrene
Anthracene
Fluoranthene
Pyrene
Benzo(a)anthracene
Benzo(bfk)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
23,7,8-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-01 1-5.1 IE-Oil
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
1.2E-08*0
2.9E-08
-------
Table 1.6-6 (Metric Units). EMISSION FACTORS FOR SPECIATED METALS
FROM WOOD WASTE COMBUSTION8
Trace Element" Emission Factor
Rangec
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-01" D
9.0E-03" D
2.2E-02 D
3.5E-05" D
4.0E-04d D
3.9E-03" D
6.0E-05d D
6.5E-05d D
8.5E-06" D
5.5E-06d D
6.5E-06d D
l.OE-05" 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-04" D
2.8E-05" D
6.0E-04d D
1.8E-04d D
1.7E-06" 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/ton 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.
"teased on data from one source test.
1.6-12
EMISSION FACTORS
7/93
-------
Table 1.6-7 (English Units). EMISSION FACTORS FOR SPECIATED METALS
FROM WOOD WASTE COMBUSTION"
Trace Element* Emission Factor
Range'
Ib/ton
Chromium (VI) 3.1E-05-5.9E-05
Copper 1.4E-05-1.2E-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-01" D
1.8E-02d D
4.4E-02 D
7.0E-05" D
8.0E-04" D
7.8E-03" D
1-2E-04" D
1.3E-04" D
1.7E-05d D
l.lE-05d D
1.3E-05d D
2.0E-05d D
2.6E-05" D
3.0E-05" D
1.8E-05" D
3.1E-05" D
1.9E-04" D
3.5E-05" D
3.5E-04" D
5.6E-05" D
1.2E-03" 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 SO 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.
"Based on data from one source test.
7/93
External Combustion Sources
1.6-13
-------
Table 1.6-8. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS
FOR BARK-FIRED BOILERS"
EMISSION FACTOR RATING: D
Particle Sizeb
(urn)
Cumulative Mass % < stated size
Uncon-
trolled
Controlled
Multiple
Cycloned
Multiple
Cyclone*
Scrubber1
Cumulative Emission Factor0
[kg/Mg (Ib/ton) bark, as fired]
Uncon-
trolled
Controlled
Multiple
Cyclone*
Multiple
Cyclone*
Scrubber1
oo
I-H
i
§
oo
15
10
6
2.5
1.25
1.00
0.625
TOTAL
42
35
28
21
15
13
9
100
90
79
64
40
26
21
15
100
40
36
30
19
14
11
8
100
92
87
78
56
29
23
14
100
10.1
(20.2)
8.4
(16.8)
6.7
(13.4)
5.0
(10.0)
3.6
(7.2)
3.1
(6.2)
2.2
(4.4)
24
(47)
6.3
(12.6)
5.5
(11.0)
4.5
(9.0)
2.8
(5.6)
1.8
(3.6)
1.5
(3.0)
1.1
(2.2)
7
(14)
1.8
(3.6)
1.62
(3.24)
1.35
(2.7)
0.86
(1.72)
0.63
(1.26)
0.5
(1.0)
0.36
(0.72)
4.5
(9.0)
1.32
(2.64)
1.25
(2.50)
1.12
(2.24)
0.81
(1.62)
0.42
(0.84)
0.33
(0.66)
0.20
(0.40)
1.44
(2.88)
'Reference 16. Emission factors are based on wet, as-fired wood waste with average properties of 50 weight percent moisture and 2,500 kcal/kg
(4,500 Btu/lb) higher heating value. Source Classification Codes are 10100901, 10200901, 10200904, and 10300901.
''Expressed as aerodynamic equivalent diameter.
"Units are kg of pollutant/Mg of wood waste burned and Ibs. of pollutant/ton of wood waste burned. Data limited to spreader stoker boilers.
•"With flyash reinjection.
"Without flyash reinjection.
'Assumed control efficiency for scrubber is 94%.
-------
Table 1.6-9. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS
FOR WOOD/BARK-FIRED BOILERS"
EMISSION FACTOR RATING: E
Particle
Size*
(urn)
15
$ 10
ff
1 6
9
I 2.5
i
§' 1.25
in
1 1.00
8
0.625
TOTAL
Cumulative Mass % < stated size
Uncon-
trolled"
94
90
86
76
69
67
ND
100
Controlled
Multiple
Cyclone"
96
91
80
54
30
24
16
100
Multiple
Cyclone*
35
32
27
16
84
6
3
100
Scrubber'
98
98
98
98
96
95
ND
100
DEGF
77
74
69
65
.,61
58
51
100
Cumulative Emission Factor0
[kg/Mg Ob/ton) bark, as fired]
Uncon-
trolled6
3.38
(6.77)
3.24
(6.48)
3.10
(6.20)
2.74
(5.47)
2.48
(4.97)
2.41
(4.82)
ND
3.6
(7.2)
Controlled
Multiple
Cyclone*
2.88
(5.76)
2.73
(5.46)
2.40
(4.80)
1.62
(3.24)
0.90
(1.80)
0.72
(1.44)
0.48
(0.96)
3.0
(6.0)
Multiple
Cyclone*
0.95
(1.90)
0.86
(1.72)
0.73
(1.46)
0.43
(0.86)
0.22
(0.44)
0.16
(0.32)
0.081
(0.162)
2.7
(5.4)
Scrubber'
0.216
(0.431)
0.216
(0.432)
0.216
(0.432)
0.216
(0.432)
0.211
(0.422)
0.209
(0.418)
ND
024
(0.48)
DEGF8
0.123
(0.246)
0.118
(0.236)
0.110
(0.220)
0.104
(0.208)
0.098
(0.196)
0.093
(0.186)
0.082
(0.164)
0.16
(0.32)
"Reference 16. Emission factors are based on wet, as-fired wood waste with average properties of SO weight percent moisture and 2500 kcal/kg (4500
Btu/Ib) higher heating value. Source Classification Codes are 10100902, 10200902,10200905, and 10300902.
""Expressed as aerodynamic equivalent diameter.
"Units are kg of poUutant/Mg of wood/bark burned and Ibs. of pollutant/ton of wood/bark burned.
*From data on underfeed stokers. May also be used as size distribution for wood-fired boilers.
'From data on spreader stokers without flyash reinjection.
'From data on Dutch ovens. Assumed control efficiency is 94%.
'From data on spreader stokers with flyash reinjection.
""ND = No data.
-------
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 Pofycyclic 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
-------
1.7 LIGNITE COMBUSTION
1.7.1 General1^
Lignite is a coal in the early stages of codification, 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 (in 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 folding.
Hie 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 SO 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.S 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 (CO2) 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 COMBUSTION8
Firing Configuration
(SCC)b
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)6
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
aUnits are kg of pollutant/Mg of fuel burned.
bSCC= Source Classification Code.
"Reference 2.
References 2-3, 7-8, 15-16.
References 7, 16.
eS= 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
30S
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
"Units arc 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 22S.
For low sodium ash (NajO < 2%), use 34S.
If ash sodium content is unknown, use 30S.
7/93
External Combustion Sources
1.7-5
-------
Table 1.7-3. EMISSION FACTORS FOR PARTICULATE MATTER (PM) AND
NITROUS OXIDE (N2O) FROM LIGNITE COMBUSTION8
Firing Configuration
(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
PM1'
Emission Factor Rating
3.3A (6.5A) E
2.6A (5.1 A) E
3.4A (6.7A) C
4.0A (8.0A) E
1.7A (3.4A) E
N20C
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.
SCO 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
-------
3
Table 1.7-4. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS
FOR BOILERS FIRING PULVERIZED LIGNITE"
EMISSION FACTOR RATING: E
Particle Sizeb
pm
Cumulative Mass % < stated size
Uncontrolled
Multiple Cyclone
Controlled
Cumulative Emission Factor6
Uncontrolled
Multiple Cyclone
Controlled*1
ff
i
9
3
o-
§'
00
o
E
15
10
6
2.5
1.25
1.00
0.625
TOTAL
51
35
26
10
7
6
3
77
67
57
27
16
14
8
1.7A (3.4A)
1.2A (2.3A)
0.86A (1.7A)
0.33A (0.66A)
0.23A (0.47A)
0.20A (0.40A)
0.10A (0.19A)
3.3A (6.6A)
0.51A (l.OA)
0.44A (0.88A)
0.38A (0.75A)
0.1 8A (0.36A)
0.1 1A (0.21A)
0.093A (0.19A)
0.053 A (0.11 A)
0.66A (1.3A)
"Reference 13. Based on tangential-fired units. For wall-fired units, multiply emission factors in the table by 0.79.
''Expressed as aerodynamic equivalent diameter.
cUnits are kg of pollutant/Mg of fuel burned and Ib. of pollutant/ton of fuel burned.
A = weight % ash content of coal, wet basis.
Estimated control efficiency for multiple cyclone is 80%.
-------
3A.
2.7A
2.4A
U
o
**-* 2 1A
u -o *•*"
:l i.8A
o
I ' 1-SA
*1 L2A
g€ 0.9A
|~* 0.6A
3
0.3A
0
Multiple
cyclone
Uncontrolled
.2 .4 .6 1 24 6 10
Particle dlaneter (us)
l.M
0.9A o
0.8*
0.7A
0.6A
O.SA
0.4A
0.3A
0.2A
0.1A
20
40 60 100
0.0
II
2s
II
Figure 1.7-1. Cumulative size specific emission factors for boileis
firing pulverized lignite.
l.OA
0.9A
•Gfe 0.8A
$3?
• ft 0.7A
5g£
*5« 0.6A
^5*
•9 I «* O.SA
• -S
|fg0.4A
f|t 0.3A
|° »-2*
0.1A
0
Uncontrolled
Itlole cyclone
ll
d.
.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
-------
Table 1.7-5. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE SPECIFIC EMISSION FACTORS
FOR LIGNITE FIRED SPREADER STOKERS4
EMISSION FACTOR RATING: E
Particle Sizeb
urn
Cumulative Mass % £ stated size
Uncontrolled
Multiple Cyclone
Controlled
Cumulative Emission Factor"
Uncontrolled
Multiple Cyclone
Controlled*1
1
1
9
3
g*
&
1
o
15
10
6
2.5
1.25
1.00
0.625
TOTAL
28
20
14
7
5
5
4
55
41
31
26
23
22
e
1.1A (2.2A)
0.80A (1.6A)
0.56A (1.1 A)
0.28A (0.56A)
0.20A (0.40A)
0.20A (0.40A)
0.16A (0.33A)
4.0A (8.0A)
0.44A (0.88A)
0.33A (0.66A)
0.25A (0.50A)
0.21A (0.42A)
0.18A (0.37A)
0.18A (0.35A)
e
0.80A (1.6A)
Reference 13.
Expressed as aerodynamic equivalent diameter.
°Units are kg of pollutant/Mg of fuel burned and Ib. of pollutant/ton of fuel burned.
A = weight % ash content of lignite, wet basis.
Estimated control efficiency for multiple cyclone is 80%.
elnsufficient data.
VO
-------
Table 1.7-6 (Metric Units). EMISSION FACTORS FOR TRACE ELEMENTS FROM UNCONTROLLED LIGNITE COMBUSTION8
EMISSION FACTOR RATING: E
Firing Configuration (SCC)
As Be Cd
Pg/J
Cr Mn Hg Ni
Pulverized, wet bottom 1175 56 21-33 525-809 1917-7065 9 70-504
(no SCC)
Pulverized, dry bottom 598 56 21
(no SCC)
Cyclone 101-272 56 13
w furnace
| (SCC 10100303)
O Stoker, 51
^ configuration unknown
32 (no SCC)
645-809 7043 9 404-504
109-809 1635 9 68-504
5130 9 303-504
§ Spreader 231-473 10-20 486-809
g stoker
(SCC 10100306)
Traveling 473-904 20-39
grate
(overfed)
stoker
(SCC 10100304)
~12
"References 19-20. Units are picograms (10~) of pollutant/Joule of fuel burned. SCO Source Classification Code.
-------
Table 1.7-7 (English Units). EMISSION FACTORS FOR TRACE ELEMENTS FROM UNCONTROLLED LIGNITE COMBUSTION8
EMISSION FACTOR RATING: E
Firing Configuration (SCC)
As Be Cd
Pulverized
(SCC 10100301)
Pulverized, wet bottom 2730 131 49-77
(no SCC)
g1 Pulverized, dry bottom 1390 131 49
1 (no SCC)
!: Cyclone furnace 235-632 130 31
| (SCC 10100303)
f Stoker 118
o* configuration unknown
2> (no SCC)
o
| Spreader stoker 538-1100 23-47
8 (SCC 10100306)
Traveling grate 1100-2100 47-90
(overfed) stoker
(SCC 10100304)
lb/1012 Btu
Cr Mn Hg Ni
1220-1880 4410-16,250 21 154-1160
1500-1880 16,200 21 928-1160
253-1880 3760 21 157-1160
11800 21
1130-1880 696-1160
•02-
'References 19-20. Units are Ib. of pollutant/10lzBtu of fuel burned. SCC = Source Classification Code.
-------
Table 1.7-8. CONTROLLED EMISSION FACTORS FOR
NITROGEN OXIDES (NOX) AND CARBON MONOXIDE (CO)
FROM CONTROLLED LIGNITE COMBUSTION11
Firing Configuration
(SCO
N0xb
Emission Factor
kg/Mg Ob/ton)
Rating
COC
Emission Factor
kg/Mg (IbAon)
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)
"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 COMBUSTION8
Firing Configuration
(SCQ
Control Device
PM
Emission Factor
Subpart D Boilers, Baghouse 0.08A (0.16A)
Pulverized coal,
Tangential and wall-fired Wet scrubber 0.05A (0.10A)
(noSCC)
Rating
C
C
Subpart Da Boilers,
Pulverized coal,
Tangential fired
(no SCQ
Wet scrubber
0.01A (0.02A)
Atmospheric iluidized bed
Limestone addition
0.03A (0.06A)
"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
-------
Table 1.7-10 (Metric Units). EMISSION FACTORS FOR
TRACE METALS AND POLYCYCLIC ORGANIC MATTER (POM)
FROM CONTROLLED LIGNITE COMBUSTION8
EMISSION FACTOR RATING: E
Firing Configuration
(SCO
Control Device
Emission Factor, pg/J
Cr
Pulverized coal Multi-cyclones 29-32
(SCC 10100301) ^ g>6
Mn
POM
High efficiency cold-side
ESP
0.99
Pulverized wet bottom
(no SCC)
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 6.3C
References 19-20. Units are picograms (10~12) of pollutant/Joule of fuel burned.
SCC = Source Classification Code.
bPrimarily trimethyl propenyl naphthalene.
cPrimarily 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
Pulverized coal Multi-cyclones 67-74
(SCC 10100301) ^ 2Q
Mn
POM
High efficiency cold-side ESP
2.3
Pulverized wet bottom
(no SCO
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
1.8-18b
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.
"Primarily 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 Hied 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. 1965 Keystone Coal Buyers Manual, McGraw-Hill, Inc., New York, NY, 1965.
5. Source Test Data on Lignite-Fired Power Plants, Norm 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
XXVin, 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 Paniculate 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
-------
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 hi 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 bum bagasse. Horseshoe
boilers and fuel cells differ in the shapes of their furnace area but in other respects are similar in
design and operation, hi these boilers (most common among older plants), bagasse is gravity-fed
through chutes and piles onto a refractory hearth. Primary and overfire combustion ah" 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 bums while in suspension. Simultaneously, large pieces of
fuel are spread in 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 tuibulent 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 paniculate 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 IS 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.
Paniculate matter emissions from these sources may be estimated by consulting Section 11.2.
1.8-2 EMISSION FACTORS 7/93
-------
Table 1.8-1 (Metric Units). EMISSION FACTORS FOR BAGASSE-FIRED BOILERS"
Pollutant
Emission factor,
g/kg steamb
kg/Mg bagasse0
Rating
Paniculate matter"1
Uncontrolled
Controlled
Mechanical collector
Wet scrubber
PM-10"
Controlled
3.9
2.1
0.4
7.8
4.2
0.8
D
B
Wet scrubber
Carbon dioxide
Uncontrolled6
Nitrogen oxides
Uncontrolled'
Polvcvclic organic matter
Uncontrolled8
0.34
390
0.3
2.5E-4
0.68
780
0.6
5.0E-4
D
A
C
D
"Source Classification Code is 10201101.
''Units 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
-------
Table 1.8-2 (English Units). EMISSION FACTORS FOR BAGASSE-FIRED BOILERS'1
Pollutant
Emission factor
lb/1,000 Ib steam"
lb/ton bagasse0
Rating
Paniculate matted
Uncontrolled
Controlled
Mechanical collector
Wet scrubber
PM-IO"
Controlled
3.9
2.1
0.4
15.6
8.4
1.6
D
B
Wet scrubber
Carbon dioxide
Uncontrolled*
Nitrogen oxides
Uncontrolled'
Polvcvclic organic matter
Uncontrolled8
0.34
390
0.3
2.5E-4
1.36
1,560
1.2
l.OE-3
D
A
C
D
"Source Classification Code is 10201101.
"Units 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 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.
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. 238-5, 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-S, South Florida
Environmental Services, Inc., February 1980.
10. Compliance Stack Test: Osceola Farms Company: Report No. 275-5, 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
-------
1.9 RESIDENTIAL FIREPLACES
1.9.1 General'-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 are usually inefficient heating
devices. Indeed, hi 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 in a residence using a fireplace. Fireplace heating efficiency may
be unproved 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 hi 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.
1.9.2 Emissions1'13
The major pollutants of concern from fireplaces are unburnt combustibles, including carbon
monoxide, gaseous organics and paniculate 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
-------
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 bum 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 in 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 burn 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 bums 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
-------
Table 1.9-1. (ENGLISH UNITS) EMISSION FACTORS FOR WOOD COMBUSTION IN
RESIDENTIAL FIREPLACES
(Source Classification Code: 2104008001)
Device
Fireplace
Pollutant
PM-10"
Carbon Monoxide"
Sulfur Oxides'1
Nitrogen oxides6
Carbon Dioxidef
Total VOCs8
POM"
Aldehydes"
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
EJ
"Units are in Ibs. of pollutant/ton 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.
7/93
External Combustion Sources
1.9-3
-------
Table 1.9-2. (METRIC UNITS) EMISSION FACTORS FOR WOOD COMBUSTION IN
RESIDENTIAL FIREPLACES
(Source Classification Code: 2104008001)
Device
Fireplace
Pollutant
PM-10"
Carbon Monoxide0
Sulfur Oxides"
Nitrogen oxides'
Carbon Dioxidef
Total VOCs8
POM11
Aldehydes11
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 Fireplaces 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., "Paniculate And Gaseous Emissions From Wood-burning Fireplaces,"
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 Fireplaces. 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 Fired
Residential Combustion Equipment EPA-600/7-80-040, U.S. Environmental Protection
Agency, Cincinnati, OH, March 1980.
9. Kosel, P., et al., Emissions From Residential Fireplaces. CARB Report C-80-027,
California Air Resources Board, Sacramento, CA, April 1980.
10. Clayton, L., et al., Emissions From Residential Type Fireplaces. Source Tests 24C67,
26C, 29C67, 40C67, 41C67, 65C67 and 66C67, Bay Area Air Pollution Control
District, San Francisco, CA, January 31, 1968.
11. Lipari, F., et al., Aldehyde Emissions From Wood-Burning Fireplaces. Publication
GMR-4377R, General Motors Research Laboratories, Warren, MI, March 1984.
12. Hayden, A., C.S., and R.W. Braaten, "Performance Of Domestic Wood Fired
Appliances," Presented at the 73rd Annual Meeting of the Air Pollution Control
Association, Montreal, Quebec, Canada, June 1980.
13. Barnett, S.G., In-Home Evaluation of Emissions From Masonry Fireplaces and
Heaters, OMNI Environmental Services, Inc., Beaverton, OR, September 1991.
7/93 External Combustion Sources 1.9.5
-------
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-flow.
Noncatalytic wood stoves are those units 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 unbumed 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. Hie 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
paniculate 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 bum cycle characterized by a slower burn rate and
decreased emissions. Emission rates during mis stage are cyclical, characterized by relatively long
periods of low emissions and shorter episodes of emission spikes.
Paniculate 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 paniculate emissions
includes "solid" particles of elemental carbon and wood. The vast majority of paniculate emissions is
condensed organic products of incomplete combustion equal to or less than 10 micrometers in
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 in size.3
Sulfur oxides (SOJ are formed by oxidation of sulfur in the wood. Nitrogen oxides (NOJ are
formed by oxidation of fuel and atmospheric nitrogea 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 300°C (572°F).
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 in the flame zone. This
group which is classified as a Hazardous Air Pollutant (HAP) under Title ni 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 in Tables 1.10-1 through 1.10-8. The analysis leading to the
revision of these emission factors is contained in the emission factor documentatioa29 These tables
include emission factors for criteria pollutants (PM-10, CO, NOX, SO,), 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 n stoves are those certified to meet the July 1, 1990 EPA standards;
1.10-2 EMISSION FACTORS 7/93
-------
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 arc 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, particulate 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. Particulate 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
-------
TABLE 1.10-1. (ENGLISH UNITS) EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION'
(Source Classification Codes)
Pollutant/EPA
Certification11
Emission
Factor
Rating
Wood Stove Type
Conventional
(SCC 2104008051)
Noncatalytic
(SCC 2104008050)
Catalytic
(SCC 2104008030)
Pellet Stove Type'
(SCC 2104008053)
Certified
Exempt
Masonry Heater
(SCC 2104008055)
Exempt11
w
O3
O
Z
>
3
03
PM-106
Pre-Phase I
Phase I
Phase II
All
Carbon Monoxide'
Pre-Phase I
Phase I
Phase II
All
Nitrogen Oxides'
Sulfur Oxides'
Carbon Dioxideh
TOCj
Methane
TNMOC
B
B
B
B
B
B
B
B
B
C
E
E
E
30.6 25.8
20.0
14.6
30.6 19.6
230.8
140.8
230.8 140.8
2.8'
0.4 0.4
48.6
4.8
43.8
24.2
19.6
16.2
20.4
104.4
107.0
104.4
2.0»
0.4
24.2
8.6
15.6
4.2
4.2 8.8
39.4
39.4 5Z2
13.8'
0.4
2,951.6 3,671.2
5.6
149.0
3,849.4
'Units are in Ibs. of pollutant/ton of dry wood burned.
bPre-Phase I = Not certified to 1988 EPA emission standards; Phase I = Certified to 1988 EPA emission standards;
Phase II = Certified to 1990 EPA emission standards; All = Average of emission factors for all devices.
'Certified = Certified pursuant to 1988 NSPS; Exempt = Exempt from 1988 NSPS (i.e., air : ratio >35:1).
dExempt = Exempt from 1988 NSPS (i.e., device weight >800 kg).
'References 6 - 14, 23 - 27, 29. PM-10 is defined as equivalent to total catch by EPA method 5H train.
Bating = C.
8Rating = E.
•"References 13, 24 - 27, 29.
References 13, 17 - 18. TOC = Total organic compounds; TNMOC = Total nonmethane organic compounds. Data show a high degree of variability within
the source population. Factors may not be accurate for individual sources.
-------
TABLE 1.10-2. (METRIC UNITS) EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION"
(Source Classification Codes)
Pollutant/EPA
Certificationb
Emission
Factor
Rating
Wood Stove Type
Conventional
(SCC 2104008051)
Noncatalytic
(SCC 2104008050)
Catalytic
(SCC 2104008030)
Pellet Stove Type"
(SCC 2104008053)
Certified
Exempt
Masonry Heater
(SCC 2104008055)
Exempt*
PM-KT
Pre-Phase I
Phase I
Phase H
All
Carbon Monoxide*
Pre-Phase I
Phase I
Phase H
All
Nitrogen Oxides*
Sulfur Oxides*
Carbon Dioxide11
TOCJ
Methane
TNMOC
B
B
B
B
B
B
B
B
B
C
E
E
E
15.3
15.3
115.4
115.4
1.4'
0.2
24.3
2.4
21.9
12.9
10.0
7.3
9.8
70.4
70.4
0.2
12.1
9.8
8.1
10.2
52.2
52.2
1.0»
0.2
12.1
4.3
7.8
2.1
2.1 4.4
19.7
19.7 26.1
6.9'
0.2
1,475.8 1,835.6
2.8
74.5
1,924.7
"Units are in grams of pollutant/kg of dry wood burned.
bPre-Phase I = Not certified to 1988 EPA emission standards; Phase I = Certified to 1988 EPA emission standards;
Phase II = Certified to 1990 EPA emission standards; All = Average of emission factors for all devices.
'Certified = Certified pursuant to 1988 NSPS; Exempt = Exempt from 1988 NSPS (i.e., air : fuel >35:1).
•"Exempt = Exempt from 1988 NSPS (i.e., device weight >800 kg).
'References 6 - 14, 23 - 27, 29. PM-10 is defined as equivalent to total catch by EPA method 5H train.
•Rating = C.
'Rating = E.
"References 13, 24 - 27, 29.
References 13, 17 - 18. TOC = Total organic compounds; TNMOC = Total nonmethane organic compounds. Data show a high degree of variability within
the source population. Factors may not be accurate for individual sources.
-------
TABLE 1.10-3. (ENGLISH AND METRIC UNITS) ORGANIC COMPOUND EMISSION
FACTORS FOR RESIDENTIAL WOOD COMBUSTION"
(Source Classification Codes)
(EMISSION FACTOR RATING: E)b
Compounds
Ethane
Ethylene
Acetylene
Propane
Propene
i-Butane
n-Butane
Butenes6
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 pollutanl/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.
cl-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) POLYCYCLIC AROMATIC HYDROCARBON (PAH)
EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION11
(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 0.010
Acenaphthylene 0.212
Anthracene 0.014
Benzo(a)Anthracene 0.020
Benzo(b)Fluoranthene 0.006
Benzo(g,h4)Fluoranthene
Benzo(k)Fluoranthene 0.002
Benzo(g4i4)Perylene 0.004
Benzo(a)Pyrene 0.004
Benzo(e)Pyrene 0.012
Biphenyl
Chrysene 0.012
Dibenzo(a4i)Anthracene 0.000
7,12-Dimethylbenz(a)Anthracene
Fluoranthene 0.020
Fluorene 0.024
Indeno(l,2,3,cd)Pyrene 0.000
9-Methylanthracene
12-Methylbenz(a)Anthracene
3-Methylchlolanthrene
1-Methylphenanthrene
Naphthalene 0288
Nitronaphthalene
Perylene
Phenanthrene 0.078
Phenanthrol
Phenol
Pyrene 0.024
PAH Total 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
2.60E-05
7.52E-05
5.48E-05
0.186
0.489
0.010
0.414
3.32E-05
4.84E-05
"Units are 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
-------
TABLE 1.10-5. (METRIC UNITS) POLYCYCLIC AROMATIC HYDROCARBON (PAH)
EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION8
(Source Classification Codes)
(Emission Factor Rating: E)b
Pollutant
STOVE TYPE
Conventional0
(SCC
2104008051)
Noncatalyticd
(SCC
2104008050)
Catalytic'
(SCC
2104008030)
Exempt Pellet1
(SCC
2104008053)
PAH
Acenaphthene
Acenaphthylene
Anthracene
Benzo(a)Anthracene
Benzo(b)Fluoranthene
Benzo(g,h4)Fluoranthene
Benzo(k)Fluoranthene
Benzo(g,h4)Perylene
Benzo(a)Pyrene
Benzo(e)Pyrene
Biphenyl
Chrysene
Dibenzo(aJi)Anthracene
7,12-Dimethylbenz(a)Anthracene
Fluoranthene
Fluoiene
Indeno( 13.$ ,cd)Pyrene
9-Methylanthracene
12-Methylbenz(a)Anthracene
3-Methylchlolanthrene
1-Methylphenanthrene
Naphthalene
Nitronaphthalene
Perylene
Phenanthrene
Phenanthrol
Phenol
Pyrene
PAH Total
0.005
0.106
0.007
0.010
0.003
0.001
0.002
0.002
0.006
0.006
0.000
0.010
0.012
0.000
0.144
0.039
0.012
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
1.30E-05
3.76E-05
2.74E-05
0.093
0.024
0.005
0.207
1.66E-05
2.42E-05
"Units arc 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
-------
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/ton 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 1
Classification
Code
Wood Stoves
Conventional 2104008051
Noncatalytic 2104008050
Catalytic 2104008030
Pellet Stovesb
Certified 2104008053
Exempt
Masonry Heaters
All 2104008055
^et 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 J.J. 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 In-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 In Glens Falls. N.Y.
1988-1989.. Vol. 1, New York State Energy Research and Development Authority, Albany, NY,
October 1989.
7. Burnet, 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 M.R. Champion, Field Performance Of Woodbuming Stoves In Crested Butte
During The 1989-90 Heating Season. Town of Crested Butte, Crested Butte, CO, September 1990.
9. Dembach, S., Woodstove Field Performance hi Klamath 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
CBEST) Hybrid Woodstove And Catalytic Retrofit Device. Oregon Department of Environmental
Quality, Portland, OR, July 1989.
11. Barnett, 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-
Catalvtic 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
WeiRht 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. Bumet, 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 Biofire 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 Woodstove
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
-------
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 bum 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 bum 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 paniculate matter (PM), small particles below
10 micrometers in size (PM-10), toxic metals, organic compounds, carbon monoxide (CO), sulfur
oxides (SO^, 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
-------
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 hi batch asphalt plants may be estimated using the procedures
outlined in Section 4.5.
1.11-2 EMISSION FACTORS 7/93
-------
3
Table 1.11-1. EMISSION FACTORS FOR PARTICIPATE MATTER (PM), PARTICIPATE MATTER LESS THAN
10 MICRONS (PM-10), AND LEAD FROM WASTE OIL COMBUSTORS
Source Category
(SCC)a
kg/m3d
Small boilers" 1.3A
(10301302)
Space heaters6
PM
lb/1000 gaT
61Af
Rating
kg/m3
C 6.1A
PM-10
lb/1000 gal
51A
Rating
kg/m3
C 6.6L8
Lead
lb/1000 gal
55L
Rating
D
Vaporizing burner 0.3A
(10500114,
10500214)
Atomizing burner 7.7A
(10500113,
10500213)
2.8A
64A
ND
D 6.8A
ND
57A
0.049L 0.41L
6.0L SOL
'SCC = Source Classification Code.
'Reference 2,4-6.
Tteferences 6-7.
'Units are kg of pollutant/cubic meter of waste oil burned.
'Units are Ib of pollutant/1000 gallons of waste oil burned.
fA = weight percent ash in fuel. Multiply numeric value by A to obtain emission factor.
*L = weight percent lead hi fuel. Multiply numeric value by L to obtain emission factor.
-------
Table 1.11-2. EMISSION FACTORS FOR NITROGEN OXIDES (NOX), SULFUR OXIDES (SOX),
AND CARBON MONOXIDE (CO) FROM WASTE OIL COMBUSTORS
Source Category
(SCC)a
Small boilers"
(10301302)
SDaceheaters"
Vaporizing burner
(10500114,
H 10500214)
£g Atomizing burner
3 (10500113,
2 10500213)
>TI _,.,,
kg/m3d
19
11
16
NOX
lb/1000 gale Rating
2.3 C
1.3 D
1.9 D
SOX
kg/hi3 lb/1000 gal Rating
147S 17.6Sf C
100S 12.0S D
107S 12.8S D
CO
kg/rn3 lb/1000 gal
5 0.60
1.7 0.20
2.1 0.25
Rating
D
D
D
*SCC = Source Classification Code.
"References 2,4,6,8.
Tleferences 6-7.
dUnits are kg of pollutant/cubic meter of waste oil burned.
'Units are Ib of pollutant/1000 gallons of waste oil burned.
fS = weight percent sulfur in fuel. Multiply numeric value by S to obtain emission factor.
-------
3
u>
Table 1.11-3. EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS (TOC), HYDROGEN CHLORIDE (HC1),
AND CARBON DIOXIDE (CO,) FROM WASTE OIL COMBUSTORS
Source Category
(SCC)a
TOC
kg/m3d
lb/1000 gale
Rating
HC1
kg/m3
lb/1000 gal
Rating
C02
kg/m3
lb/1000 gal
Rating
Small boilers'*
(10301302)
Space heaters"
Vaporizing burner
(10500114,
10500214)
Atomizing burner
(10500113,
10500213)
0.01
0.01
0.01
0.1
0.1
0.1
D 7.9Clf 66C1
D
D
ND8
ND
ND
ND
2,400 20,000
2,700 23,000 D
2,900 24,000 D
o
I
"SCC = Source Classification Code.
References 2,4,6-7,9.
'References 4,6-7,9.
dUnits are kg of pollutant/cubic meter of waste oil burned.
'Units are Ib of pollutant/1000 gallons of waste oil burned.
fCl = weight percent chlorine in fuel. Multiply numeric value by Cl to obtain emission factor.
«ND = No data.
-------
Table 1.11-4 EMISSION FACTORS FOR SPECIATED METALS FROM WASTE OIL COMBUSTORS"
EMISSION FACTOR RATING: D
Pollutant
Small Boilers'5
(SCC 10301302)
kg/m3e
lb/1000 galf
Space Heaters: Vaporizing
Burner0
(SCC 10500114, 10500214)
kg/m3
lb/1000 gal
Space Heaters: Atomizing
Bumerd
(SCC 10500113, 10500213)
kg/m3
lb/1000 gal
m
03
S3
o
z
T1
ACTORS
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Cobalt
Manganese
Nickel
Selenium
Phosphorous
ND
1.3E-02
NDg
1.1E-03
2.4E-03
2.5E-05
8.2E-03
1.3E-03
ND
ND
ND
1.1E-01
ND
9.3E-03
2.0E-02
2.1E-04
6.8E-02
1.1E-02
ND
ND
4.1E-05
1.3E-04
ND
1.8E-05
3.1E-02
6.8E-04
2.6E-04
6.0E-03
ND
4.3E-03
3.4E-04
1.1E-03
ND
1.5E-04
2.6E-01
5.7E-03
2.2E-03
5.0E-02
ND
3.6E-02
5.4E-04
7.2E-03
4.7E-05
1.4E-03
2.2E-02
6.2E-04
6.0E-03
1.9E-02
ND
ND
4.5E-03
6.0E-02
3.9E-07
1.2E-02
1.8E-01
5.2E-03
5.0E-02
1.6E-01
ND
ND
"Pollutants in this table represent metal species measured for waste oil combustors. Other metal species may also have been
emitted but were either not measured or were present at concentrations below analytical detection limits.
""Reference 6. SCC = Source Classificatin Code.
References 6-7.
•"References 6-7.
tlnits are kg of pollutant/cubic meter of waste oil burned.
fUnits are Ib of pollutant/1000 gallons of waste oil burned.
8ND = No data.
-------
Table 1.11-5. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS FROM WASTE OIL COMBUSTORS"
EMISSION FACTOR RATING: D
Pollutant
Space Heaters: Vaporizing Burner
(SCC 10500114, 10500214)
kg/m3b
lb/1000 galc
Space Heaters: Atomizing Burner
(SCC 10500113, 10500213)
kg/m3
lb/1000 gal
1
1
1
a4
c
00
o'
D
00
o
"
Phenol
Dichlorobenzene
Naphthalene
Phenanthrene/anthracene
Dibutylphthalate
Butylbenzylphthalate
Bis(2-ethylhexyl)phthalate
Pyrene
Benz(a)anthracene/chrysene
Benzo(a)pyrene
Trichloroethylene
2.9E-04
8.0E-07
1.6E-03
1.3E-03
NDd
6.1E-05
2.6E-04
8.4E-04
4.8E-04
4.8E-04
ND
2.4E-03
6.7E-06
1.3E-02
1.1E-02
ND
5.1E-04
2.2E-03
7.0E-03
4.0E-03
4.0E-03
ND
3.3E-06
ND
1.1E-04
1.5E-05
4.0E-06
ND
ND
6.1E-06
ND
ND
ND
2.8E-05
ND
9.4E-04
9.9E-05
3.4E-05
ND
ND
5.1E-05
ND
ND
ND
"Reference 6. Pollutants in this table represent organic species measured for waste oil combustors. Other organic species may
also have been emitted but were either not measured or were present at concentrations below analytical detection limits. SCC =
Source Classification Code.
bUnits are kg of pollutant/cubic meter of waste oil burned.
"Units are Ib of pollutant/1000 gallons of waste oil burned.
"ND = No data.
-------
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
-------
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 paniculate 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
-------
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/RC), 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
-------
C/5
1
K.
Secondary
Fan
Ridding Conveyor
Discharge
Quench Tmk
N)
OJ
-------
O
•fl
f
3
O
C/5
"2.
s
a
•o
3
m
S
I—*
V)
VI
5
i
3
o
Branch
Ring Pipe
Header
Rotary
Joint
Afterburning
Grate
Convection
Section
Economizer
Flue Gas
-------
GO
O
I
a
So'
T3
O
T1
f
s
°
cr
9-
e.
8
•
era
Stack
Overhead
Crane
Emergency
Stack
Air
Pollution
Control
Device
1 Waste Tipping Floor
Forced Overfire Vibrating
Draft Air Conveyor
Fan Fan for Bottom
Ash
Ash
Conveyors
Ash
Quench
Pit
Bottom
Ash
Conveyor
Chamber
to
-------
Superheater
f
3
K)
g
a o
O
z 71
Q !
o -g
* I
l-l
09
s
Stack
Air
Pollution
Control
Device
Steam Coll
Air Preheater
Ash Removal
~J
u>
-------
To Stack or
Waste Heat Boiler
to
00
o_
Si
«
I
o
T3
O
o
e.
1
o.
S.
o
cr
CXI
Primary
Gas Burner
Secondary
Air
Secondary
Chamber
o o o
o o o
o o o
*-**/
Primary Chamber
Fire Door Transfer Rams
Charge
Hopper
Secondary
Gas Burner
Ash Quench
Primary Air
K)
-------
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 in 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
-------
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.
7/93 Solid Waste Disposal 2.1-9
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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 time 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. Overfire 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-(PC) 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. Overfire 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 air 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
2.1-10 EMISSION FACTORS 7/93
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cyclone separator which recycles unturned 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 815°C (1,500°F). 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 980°C (1,200 to
1,800°F), 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 1,200°C (1,800 to 2,200°F). 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.
7/93 Solid Waste Disposal 2.1-11
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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,
2.1-12 EMISSION FACTORS 7/93
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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 (/xm). Fine particulates, having diameters less than 10/un
(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
7/93 Solid Waste Disposal 2.1-13
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convert CO to CO2. As waste burns in a fuel bed, it releases CO, hydrogen (H2), and unburned
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
[ppmv]), 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 (NO2) 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 in the waste, and (2)
fixation of atmospheric nitrogen. Conversion of nitrogen in the waste occurs at relatively low
temperatures Pess than 1,090°C (2,000°F)], 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 participates. 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 /un. As compared to pulverized coal fired combustors, in which only 1 to
3 percent of the fly ash is generally smaller than 1 /un, 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 /tin. 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.
7/93 Solid Waste Disposal 2.1-15
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As the flue gas flows through the filter bags, paniculate is collected on the filter surface,
mainly through inertia! impaction. The collected paniculate 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 paniculate on the inside of the bags. The paniculate builds up to
form a paniculate 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 paniculate on
the outside of the bags. To remove the paniculate 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 paniculate 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 115°C (240°F) is required to control agglomeration of PM and sorbent by calcium chloride.
Outlet gas temperature from the SD is usually around 140°C (285°F).
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 (CaF2), 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 320°C (300 to 600°F) 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 overfire 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 1,200°C (1,600 to 2,200 °F)]
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 760°C (1,400°F). 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.
7/93 Solid Waste Disposal 2.1-17
-------
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 Controls1 M4
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 adsorption 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 400°F.
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 (N^S) 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
-------
to
o
Table 2.1-1 (Metric Units). PARTICULATE MATTER, METALS, AND ACID GAS EMISSION FACTORS FOR MASS BURN
AND MODULAR/EXCESS AIR COMBUSTORSa>b
(SCCs 50100104, 50100105, 50100106, 50100107, 50300111, 50300112, 50300113, 50300115)
Pollutant
PMh
As'
Cd«
Cr»
Hg1
Ni1
Pb>
SO2
HC1»
Uncontrolled
kg/Mg
1.26E+01
2.14E-03
5.45E-03
4.49E-03
2.8 E-03
3.93E-03
1.07E-01
1.73E+00
3.20E+00
Emission
Factor
Rating
A
A
A
A
A
A
A
A
A
ESP°
kg/Mg
1.05E-01
1.09E-05
3.23E-Q4
5.65E-05
2.8 E-03
5.60E-05
1.50E-03
—
—
Emission
Factor
Rating
A
A
B
B
A
B
A
DSI/ESP*1
kg/Mg
2.95E-02
NDJ
4.44E-05
1.55E-05
1.98E-03
1.61E-03
1.45E-03
4.76E-01
1.39E-01
Emission
Factor
Rating
E
E
E
E
E
E
E
C
C
SD/ESP6
kg/Mg
3.52E-02
6.85E-06
3.76E-06
1.30E-04
1.63E-03
1.35E-04
4.58E-04
3.27E-01k
7.90E-02k
Emission
Factor
Rating
A
A
A
A
A
A
A
A
A
DSI/FFf
kg/Mg
8.95E-02
5.15E-06
1.17E-05
l.OOE-04
1.10E-03
7.15E-05
1.49E-04
7.15E-01
3.19E-01
Emission
Factor
Rating
A
C
C
C
C
C
C
C
C
SD/FF8
kg/Mg
3.11E-02
2.12E-05
1.36E-05
1.50E-05
1.10E-03
2.58E-05
1.31E-04
2.77E-01k
1.06E-01k
Emission
Factor
Rating
A
A
A
A
A
A
A
A
A
m
C/3
C/5
(-H
i
o
90
00
a All factors in kg/Mg refuse combusted. Emission factors were calculated from concentrations using an F-factor of 9,570 dscf/MBtu and a
Other heating values can be substituted by multiplying the emission factor by the new heating value and dividing by 4,500 Btu/lb. SCC =
b Emission factors should be used for estimating long-term, not short-term, emission levels. This particularly applies to pollutants measured
monitoring system (e.g., SC>2).
c ESP = Electrostatic Precipitator
d DSI/ESP = Duct Sorbent Injection/Electrostatic Precipitator
e SD/ESP = Spray Dryer/Electrostatic Precipitator
f DSI/FF = Duct Sorbent Injection/Fabric Filter
g SD/FF = Spray Dryer/Fabric Filter
n PM = total particulate matter, as measured with EPA Reference Method 5.
i Hazardous Air Pollutants listed in Tide I of the 1990 Clean Air Act Amendments.
J ND = No data available at levels greater than detection limits.
k Acid gas emissions from SD/ESP- and SD/FF-equipped MWCs are essentially the same. Any differences are due to scatter in the data.
— = Not available.
heating value of 4,500 Btu/lb.
Source Classification Code.
with a continuous emission
-------
Table 2.1-2 (English Units). PARTICULATE MATTER, METALS, AND ACID GAS EMISSION FACTORS
FOR MASS BURN AND MODULAR/EXCESS AIR COMBUSTORSa'b
(SCCs 50100104, 50100105, 50100106, 50100107, 50300111, 50300112, 50300113, 50300115)
Pollutant
PMh
As1
Cd1
Cr1
Hg1
Ni»
Pb1
S02
HC11
Uncontrolled
Ib/ton
2.51E+01
4.37E-03
1.09E-02
8.97E-O3
5.6 E-03
7.85E-03
2.13E-01
3.46E+00
6.40E+00
Emission
Factor
Rating
A
A
A
A
A
A
A
A
A
ESPC
Ib/ton
2.10E-01
2.17E-05
6.46E-04
1.13E-04
5.6 E-03
1.12E-04
3.00E-03
—
—
Emission
Factor
Rating
A
A
B
B
A
B
A
DSI/ESpd
Ib/ton
5.90E-02
NDJ
8.87E-05
3.09E-05
3.96E-03
3.22E-05
2.90E-03
9.51E-01
2.78E-01
Emission
Factor
Rating
E
E
E
E
E
E
E
C
C
SB/ESP6
Ib/ton
7.03E-02
1.37E-05
7.51E-05
2.59E-04
3.26E-03
2.70E-04
9.15E-04
6.53E-01k
1.58E-01k
Emission
Factor
Rating
A
A
A
A
A
A
A
A
A
DSI/FFf
Ib/ton
1.79E-01
1.03E-05
2.34E-05
2.00E-04
2.20E-03
1.43E-04
2.97E-04
1.43E-00
6.36E-01
Emission
Factor
Rating
A
C
C
C
C
C
C
C
C
SD/FFg
Ib/ton
6.20E-02
4.23E-O6
2.71E-05
3.00E-05
2.20E-03
5.16E-05
2.61E-04
5.54E-01k
2.11E-01k
Emission
Factor
Rating
A
A
A
A
A
A
A
A
A
o_
o!
g
ff
O
£«'
o
e.
to
All factors in Ib/ton refuse combusted. 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., SC>2).
ESP = Electrostatic Precipitator
DSI/ESP = Duct Sorbent Injection/Electrostatic Precipitator
SD/ESP = Spray Dryer/Electrostatic Precipitator
DSI/FF = Duct Sorbent Injection/Fabric Filter
SD/FF = Spray Dryer/Fabric Filter
PM = total particulate matter, as measured with EPA Reference Method 5.
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
ND = No data available at levels greater than detection limits.
Acid gas emissions from SD/ESP- and SD/FF-equipped MWCs are essentially the same. Any differences are due to scatter in the data.
= Not available.
-------
to
to
Table 2.1-3 (Metric Units). ORGANIC, NITROGEN OXIDE, AND CARBON MONOXIDE EMISSION FACTORS FOR
MASS BURN/WATERWALL COMBUSTORSa'b
(SCCs 50100105, 50300112)
Pollutant
CDD/CDFS
N0xh
CO11
Uncontrolled
kg/Mg
8.35E-07
1.83E+00
2.32E-01
Emission
Factor Rating
A
A
A
ESP0
kg/Mg
5.85E-07
*
*
Emission
Factor Rating
A
SO/ESP*1
kg/Mg
3.11E-07
*
*
Emission
Factor Rating
A
DSI/FF*1
kg/Mg
8.0E-08
H<
*
Emission
Factor Rating
C
SD/FF6
kg/Mg
3.31E-08
*
*
Emission
Factor Rating
A
m
2
NH
(/>
CO
o
Z
%
All factors in kg/Mg refuse combusted. 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
SD/ESP = Spray Diyer/Electrostatic Precipitator
DSI/FF = Duct Sorbent Injection/Fabric Filter
SD/FF = Spray Dryer/Fabric Filter
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.
h Control of NOX and CO is not tied to traditional acid gas/PM control devices.
* = Same as "uncontrolled" for these pollutants.
-------
^
vB
Table 2.1-4 (English Units). ORGANIC, NITROGEN OXIDE, AND CARBON MONOXIDE EMISSION FACTORS FOR
MASS BURN/WATERWALL COMBUSTORSa'b
(SCCs 50100105, 50300112)
Pollutant
CDD/CDFS
N0xh
CO11
Uncontrolled
Ib/ton
1.67E-06
3.56E+00
4.63E-01
Emission
Factor Rating
A
A
A
ESP=
Ib/ton
1.17E-06
*
*
Emission
Factor Rating
A
SD/ESI*1
Ib/ton
6.21E-07
*
>ii
Emission
Factor Rating
A
DSI/FF6
Ib/ton
1.60E-07
*
*
Emission
Factor Rating
C
SD/FFf
Ib/ton
6.61E-08
*
+
Emission
Factor Rating
A
o.
51
«
I
q
•i'
O
on
B.
c
d
e
f
g
* =
All factors in Ib/ton refuse combusted. 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
SD/ESP = Spray Dryer/Electrostatic Precipitator
DSI/FF = Duct Sorbent Injection/Fabric Filter
SD/FF = Spray Dryer/Fabric Filter
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.
Control of NOX and CO is not tied to traditional acid gas/PM control devices.
Same as "uncontrolled" for these pollutants.
to
-------
to
Table 2.1-5 (Metric and English Units). ORGANIC, NITROGEN OXIDE, AND CARBON MONOXIDE EMISSION FACTORS FOR
MASS BURN/ROTARY WATERWALL COMBUSTORSa'b
(SCCs 50100106, 50300113)
Pollutant
CDD/CDFf
NOX8
cos
Uncontrolled
kg/Mg
—
1.13E+00
3.83E-01
Ib/ton
—
2.25E+00
7.66E-01
Emission
Factor
Rating
E
C
ESPC
kg/Mg
—
*
*
Ib/ton
—
*
*
Emission
Factor
Rating
DSI/FFd
kg/Mg
4.58E-08
*
*
Ib/ton
9.16E-08
*
*
Emission
Factor
Rating
D
SD/FF6
kg/Mg
2.66E-08
*
*
Ib/ton
5.31E-08
*
*
Emission
Factor
Rating
B
EMISSION F,
3>
ij
00
a
b
c
d
e
f
g
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
DSI/FF = Duct Sorbent Injection/Fabric Filter
SD/FF = Spray Dryer/Fabric Filter
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.
Control of NOX and CO is not tied to traditional acid gas/PM control devices.
— = Not available.
* = Same as "uncontrolled" for these pollutants.
-------
Table 2.1-6 (Metric and English Units). ORGANIC, NITROGEN OXIDE, AND CARBON MONOXIDE EMISSION FACTORS FOR
MASS BURN/REFRACTORY WALL COMBUSTORSa'b
(SCCs 50100104, 50300111)
00
o
e
T3
O
tfl
EL
Pollutant
CDD/CDpe
N0xf
cof
Uncontrolled
kg/Mg
7.50E-06
1.23E+00
6.85E-01
Ib/ton
1.50E-05
2.46E+00
1.37E+00
Emission
Factor
Rating
D
A
C
ESPC
kg/Mg
3.63E-05
*
*
Ib/ton
7.25E-05
*
*
Emission
Factor
Rating
D
DSI/ESPd
kg/Mg
2.31E-07
*
*
Ib/ton
4.61E-07
*
*
Emission
Factor
Rating
E
a 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.
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.
-------
K>
Table 2.1-7 (Metric and English Units). ORGANIC, NITROGEN OXIDE, AND CARBON MONOXIDE EMISSION FACTORS FOR
MODULAR/EXCESS AIR COMBUSTORSa'b
(SCCs 50100107, 50300115)
i
00
c/3
1
O
73
V)
Pollutant
CDD/CDF6
N0xf
cof
Uncontrolled
kg/Mg
—
1.24E+00
—
Ib/ton
—
2.47E+00
—
Emission
Factor
Rating
A
ESPC
kg/Mg
1.11E-06
*
*
Ib/ton
2.22E-06
*
*
Emission
Factor
Rating
C
DSI/FFd
kg/Mg
3.12E-08
*
*
Ib/ton
6.23E-08
*
*
Emission
Factor
Rating
E
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
DSI/FF = Duct Sorbent Injection/Fabric Filter
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.
— = Not available.
* = Same as "uncontrolled" for these pollutants.
-------
~J
UJ
Table 2.1-8 (Metric and English Units). EMISSION FACTORS FOR REFUSE-DERIVED FUEL-FIRED COMBUSTORSa>b
(SCCs 50100103)
Pollutant
PMf
AsS
CdS
CrS
HgS
NiS
Pb§
SO2
HC18
NO*!
COJ
CDD/CDFk
Uncontrolled
kg/Mg
3.48E+01
2.97E-03
4.37E-03
6.99E-03
2.8 E-03
2.18E-03
l.OOE-01
1.95E+00
3.49E+00
2.51E+00
9.60E-01
4.73E-06
Ib/ton
6.96E+01
5.94E-03
8.75E-03
1.40E-02
5.5 E-03
4.36E-03
2.01E-01
3.90E+00
6.97E+00
5.02E+00
1.92E+00
9.47E-06
Emission
Factor
Rating
A
B
C
B
D
C
C
C
E
A
A
D
ESPC
kg/Mg
5.17E-01
6.70E-05
1.10E-04
2.34E-04
2.8 E-03
9.05E-03
1.84E-03n
—
i>
*
«
8.46E-06
Ib/ton
1.04E+00
1.34E-04
2.20E-04
4.68E-04
5.5 E-03
1.81E-02
3.66E-03h
...
*
0
a
1.69E-05
Emission
Factor
Rating
A
D
C
D
D
D
A
B
SO/ESP*1
kg/Mg
4.82E-02
5.41E-06
4.18E-05
5.44E-05
2.10E-04
9.64E-05
5.77E-04
7.99E-01
_.
a
$
5.31E-03
Ib/ton
9.65E-02
1.08E-05
8.37E-05
1.09E-04
4.20E-04
1.93E-04
1.16E-03
1.60E+00
...
s
»
1.06E-07
Emission
Factor
Rating
B
D
D
D
B
D
B
D
D
SD/FF6
kg/Mg
6.64E-02
2.59E-06h
1.66E-05n
2.04E-05
1.46E-04
3.15E-051
5.19E-04
2.21E-01
2.64E-02
0
«
1.22E-08
Ib/ton
1.33E-01
5.17E-06h
3.32E-05h
4.07E-05
2.92E-04
6.30E-051
1.04E-03
4.41E-01
5.28E-02
a
if
2.44E-08
Emission
Factor
Rating
B
A
A
D
D
A
D
D
C
E
GO
o
s
5
q
I
S»
e.
a Emission factors were calculated from concentrations using an F-factor of 9,570 dscf/MBtu and a heating value of 5,500 Btu/lb. Other heating values can be
substituted by multiplying the emission factor by the new heating value and dividing by 5,500 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 (SO2, NOX, CO).
c ESP = Electrostatic Precipitator
d SD/ESP = Spray Dryer/Electrostatic Precipitator
e SD/FF = Spray Dryer/Fabric Filter
' PM = total paniculate matter, as measured with EPA Reference Method 5.
8 Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
n Levels were measured at non-detect levels, where the detection limit was higher than levels measured at other similarly equipped MWCs. Emission factors shown are
based on emission levels from similarly equipped mass bum and MOD/EA combustors.
No data available. Values shown are based on emission levels from SD/FF-equipped mass burn combustors.
Control of NOX and CO is not tied to traditional acid gas/PM control devices.
k CDD/CDF = total tetra-through octa-chlorinateddibenzo-p-dioxin/chlorinateddibenzofurans, 2,3,7,8-tetrachlorodibenzo-p-dioxinand dibenzofurans are Hazardous Air
Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
- = Not available
0 = Same as uncontrolled for these pollutants.
J
-------
Table 2.1-9 (Metric and English Units). EMISSION FACTORS FOR
MODULAR STARVED
AIR COMBUSTORSa>b
(SCCs 50100101, 50300114)
Pollutant
PMd
Ase
Cde
Cre
Hge,f
Nie
Pbe
SO2
HCle
N0xg
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
*
*
*
*
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
*
*
*
*
3.76E-06
Emission
Factor
Rating
B
D
D
D
A
E
C
C
C
d
e
g
h
* _
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
Divide
By
To Obtain*
For As, Cd, Cr, Hg, Ni, Pb, and CDD/CDF:
kg/Mg refuse
Ib/ton refuse
4.03 x
8.06 x 10-6
/xg/dscm
For PM:
kg/Mg refuse
Ib/ton refuse
4.03 x 10'3
8.06 x 10'3
mg/dscm
For HC1:
kg/Mg refuse
Ib/ton refuse
6.15x10-3
1.23xlO-2
ppmv
For SO2:
kg/Mg refuse
Ib/ton refuse
1.07x 10-2
2.15x JO"2
ppmv
For NOX:
kg/Mg refuse
Ib/ton refuse
7.70 x JO'3
1.54x 10-2
ppmv
For CO:
kg/Mg refuse
Ib/ton refuse
4.69 x 10'3
9.4 x 10-3
ppmv
"at 7 percent O2-
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 10-6
9.85 x ID"6
4.92 x 10'3
9.85 x 10'3
7.5 x 1C'3
1.5 x lO-2
1.31 x ID'2
2.62 x ID'2
9.45 x 10-3
1.89x ID'2
5.75 x 1C-3
1.15x 10-2
To Obtain*
jig/dscm
mg/dscm
ppmv
ppmv
ppmv
ppmv
*at 7 percent O2-
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
-------
^J
u>
Table 2.1-12 (Metric and English Units). UNCONTROLLED EMISSION FACTORS FOR REFUSE COMBUSTORS
OTHER THAN MUNICIPAL WASTE3
EMISSION FACTOR RATING: D
Combustor Type
Industrial/Commercial
Multiple Chamber
Single Chamber
Trench
Wood
(50100510, 50300106)
Rubber tires
(50100511, 50300107)
Municipal refuse
(50100512, 50300109)
Flue-fed single chamber
Flue-fed (modified)
Domestic single chamber
(no SCC)
Without primary burner
With primary burner
PM
kg/Mg
3.50E+00
7.50E+00
6.50E+00
6.90E+01
1.85E+01
1.50E+01
3.00E+00
1.75E+01
3.50E+00
Ib/ton
7.00E+00
1.50E+01
1.30E+01
1.38E+02
3.70E+01
3.00E+01
6.00E+00
3.50E+01
7.00E+00
SO2
kg/Mg
1.25E+00
1.25E+00
5.00E-02
—
1.25E+00
2.50E-01
2.50E-01
2.50E-01
2.50E-01
Ib/ton
2.50E+00
2.50E+00
l.OOE-01
—
2.50E+00
5.00E-01
5.00E-01
5.00E-01
5.00E-01
CO
kg/Mg
5.00E+00
l.OOE+01
—
—
—
l.OOE+01
5.00E+00
1.50E+02
Negc
Ib/ton
l.OOE+01
2.00E+01
—
—
—
2.00E+01
l.OOE+01
3.00E+02
Negc
Total Organic
Compounds^
kg/Mg
1.50E+00
7.50E+01
—
—
—
7.50E+00
1.50E+00
5.00E+01
l.OOE+00
Ib/ton
3.00E+00
1.50E+01
—
—
—
1.50E+01
3.00E+00
l.OOE+02
2.00E+00
NOX
kg/Mg
1.50E+00
l.OOE+00
2.00E+00
—
—
1.50E+00
5.00E+00
5.00E-01
l.OOE+00
Ib/ton
3.00E+00
2.00E+00
4.00E+00
—
—
3.00E+00
l.OOE+01
l.OOE+00
2.00E+00
o_
CL
1
g
T3
O
Cfl
e.
a References 116-123.
b Expressed as methane.
c Neg = negligible.
— = Not available.
-------
References for Section 2.1
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2.1-34 EMISSION FACTORS 7/93
-------
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7/93 Solid Waste Disposal 2.1-35
-------
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2.1-36 EMISSION FACTORS 7/93
-------
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7/93 Solid Waste Disposal 2.1-37
-------
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60. Entropy Environmentalist, Municipal Waste Combustion Multipollutant Study: Emission Test
Report - Wheelabrator Millbury, Inc. Millbury, Massachusetts, EMB Report No. 88-MIN-07,
July 1988.
61. Entropy Environmentalists, Emission Test Report, Municipal Waste Combustion, Continuous
Emission Monitoring Program, Wheelabrator Resource Recovery Facility, Millbury,
Massachusetts, Prepared for the U. S. Environmental Protection Agency, Research Triangle
Park, NC. EPA Contract No. 68-02-4336. October 1988.
62. Entropy Environmentalists, Emissions Testing at Wheelabrator Millbury, Inc. Resource
Recovery Facility, Millbury, Massachusetts, Prepared for Rust International Corporation.
February 8-12, 1988.
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
Division South Incinerator - Unit #3, Prepared for U. S. EPA, OAQPS and ORD, Research
Triangle Park, NC. November 1988.
64. Letter and enclosures from John W. Norton, County of Montgomery, OH, to Jack R.
Farmer, U. S. Environmental Protection Agency, Research Triangle Park, NC. May 31,
1988.
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
Control Corp.), "Air Emissions Tests of a Deutsche Babcock Anlagen Dry Scrubber System
at the Munich North Refuse-Fired Power Plant," Presented at: 78th Annual Meeting of the
Pollution Control Association, Detroit, MI, June 1985.
66. Clean Air Engineering, Results of Diagnostic and Compliance Testing at NSP French Island
Generating Facility Conducted May 17-19, 1989, July 1989.
67. Preliminary Report on Occidental Chemical Corporation EFW. New York State Department of
Environmental Conservation, (Niagara Falls), Albany, NY, January 1986.
68. H. J. Hall, Associates, Summary Analysis on Precipitator Tests and Performance Factors,
May 13-15, 1986 at Incinerator Units 1,2- Occidental Chemical Company, Prepared for
Occidental Chemical Company EFW. Niagara Falls, NY. June 25, 1986.
69. Anderson, C.L., et al. (Radian Corporation), Summary Report, CDD/CDF, Metals and
Paniculate, Uncontrolled and Controlled Emissions, Signal Environmental Systems, Inc.,
North Andover RESCO, North Andover, MA, U. S. Environmental Protection Agency,
Research Triangle Park, NC, EMB Report No. 86-MINO2A, March 1988.
70. York Services Corporation, Final Report for a Test Program on the Municipal Incinerator
Located at Northern Aroostook Regional Airport, Frenchville, Maine, Prepared for Northern
Aroostook Regional Incinerator Frenchville, ME. January 26, 1987.
71. Radian Corporation, Results From the Analysis ofMSW Incinerator Testing at Oswego
County, New York, Prepared for New York State Energy Research and Development
Authority. March 1988.
72. Radian Corporation, Data Analysis Results for Testing at a Two-Stage Modular MSW
Combustor: Oswego County ERF, Fulton, New York, Prepared for New York State's Energy
Research and Development Authority. Albany, NY. November 1988.
73. Fossa, A.J., et al., Phase I Resource Recovery Facility Emission Characterization Study,
Overview Report, (Oneida, Peekskill), New York State Department of Environmental
Conservation, Albany, NY, May 1987.
74. Radian Corporation, Results from the Analysis of MSW Incinerator Testing at Peekskill,
New York, Prepared for New York State Energy Research and Development Authority,
DCN:88-233-012-21, August 1988.
75. Radian Corporation; Results from the Analysis of MSW Incinerator Testing at Peekskill, New
York (DRAFT), (Prepared for the New York State Energy Research and Development
Authority), Albany, NY, March 1988.
76. Ogden Martin Systems of Pennsauken, Inc., Pennsauken Resource Recovery Project, BACT
Assessment for Control ofNOx Emissions, Top-Down Technology Consideration, Fairfield,
NJ, pp. 11, 13, December 15, 1988.
7/93 Solid Waste Disposal 2.1-39
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77. Roy F. Western, Incorporated, Penobscot Energy Recovery Company Facility, Orrington,
Maine, Source Emissions Compliance Test Report Incinerator Units A and B (Penobscot,
Maine), Prepared for GE Company September 1988.
78. Zaitlin, S., Air Emission License Finding of Fact and Order, Penobscot Energy Recovery
Company, Orrington, ME, State of Maine, Department of Environmental Protection, Board of
Environmental Protection, February 26, 1986.
79. Neulicht, R. (Midwest Research Institute), Emissions Test Report: City of Philadelphia
Northwest and East Central Municipal Incinerators, Prepared for the U. S. Environmental
Protection Agency, Philadelphia, PA. October 31, 1985.
80. Letter with attachments from Gehring, Philip, Plant Manager (Pigeon Point Energy
Generating Facility), to Farmer, Jack R., Director, BSD, OAQPS, U. S. Environmental
Protection Agency, June 30, 1988.
81. Entropy Environmentalists, Inc., Stationary Source Sampling Report, Signal RESCO, Pinellas
County Resource Recovery Facility, St. Petersburg, Florida, CARB/DER Emission Testing,
Unit 3 Precipitator Inlets and Stack, February and March 1987.
82. Midwest Research Institute, Results of the Combustion and Emissions Research Project at the
Vicon Incinerator Facility in Pittsfield, Massachusetts, Prepared for New York State Energy
Research and Development Authority, June 1987.
83. Response to Clean Air Act Section 114 Information Questionnaire, Results of Non-Criteria
Pollutant Testing Performed at Pope-Douglas Waste to Energy Facility, July 1987, Provided
to EPA on May 9, 1988.
84. Engineering Science, Inc., A Report on Air Emission Compliance Testing at the Regional
Waste Systems, Inc. Greater Portland Resource Recovery Project, Prepared for Dravo Energy
Resources, Inc., Pittsburgh, PA, March 1989.
85. Woodman, D.E., Test Report Emission Tests, Regional Waste Systems, Portland, ME,
February 1990.
86. Environment Canada, The National Incinerator Testing and Evaluation Program: Two State
Combustion, Report EPS 3/up/l, (Prince Edward Island), September 1985.
87. Statistical Analysis of Emission Test Data from Fluidized Bed Combustion Boilers at Prince
Edward Island, Canada, U. S. Environmental Protection Agency, Publication No.
EPA-450/3-86-015, December 1986.
88. The National Incinerator Testing and Evaluation Program: Air Pollution Control Technology,
EPS 3/UP/2, (Quebec City), Environment Canada, Ottawa, September 1986.
89. Lavalin, Inc., National Incinerator Testing and Evaluation Program: The Combustion
Characterization of Mass Burning Incinerator Technology; Quebec City (DRAFT), (Prepared
for Environmental Protection Service, Environmental Canada), Ottawa, Canada,
September 1987.
2.1-40 EMISSION FACTORS 7/93
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90. Environment Canada, N1TEP, Environmental Characterization of Mass Burning Incinerator
Technology at Quebec City. Summary Report, EPS 3/UP/5. June 1988.
91. Interpoll Laboratories, Results of the March 21 - 26, 1988, Air Emission Compliance Test on
the No. 2 Boiler at the Red Wing Station, Test IV (High Load), Prepared for Northern States
Power Company, Minneapolis, MN, Report No. 8-2526, May 10, 1988.
92. Interpoll Laboratories, Results of the May 24-27, 1988 High Load Compliance Test on Unit 1
and Low Load Compliance Test on Unit 2 at the NSP Red Wing Station, Prepared for
Northern States Power Company, Minneapolis, MN, Report No. 8-2559, July 21, 1988.
93. Cal Recovery Systems, Inc., Final Report, Evaluation of Municipal Solid Waste Incineration.
(Red Wing, Minnesota facility) Submitted to Minnesota Pollution Control Agency, Report
No. 1130-87-1, January 1987.
94. Eastmount Engineering, Inc., Final Report, Waste-to-Energy Resource Recovery Facility,
Compliance Test Program, Volumes II-V, (Prepared for SEMASS Partnership.), March 1990.
95. McClanahan, D (Fluor Daniel), A. Licata (Dravo), and J. Buschmann (Flakt, Inc.).,
"Operating Experience with Three APC Designs on Municipal Incinerators." Proceedings of
the International Conference on Municipal Waste Combustion, pp. 7C-19 to 7C-41,
(Springfield), April 11-14, 1988.
96. Interpoll Laboratories, Inc., Results of the June 1988 Air Emission Performance Test on the
MSW Incinerators at the St. Croix Waste to Energy Facility in New Richmond, Wisconsin,
Prepared for American Resource Recovery, Waukesha, WI, Report No. 8-2560,
September 12, 1988.
97. Interpoll Laboratories, Inc, Results of the June 6, 1988, Scrubber Performance Test at the
St. Croix Waste to Energy Incineration Facility in New Richmond, Wisconsin, Prepared for
Interel Corporation, Englewood, CO, Report No. 8-25601, September 20, 1988.
98. Interpoll Laboratories, Inc., Results of the August 23, 1988, Scrubber Performance Test at the
St. Croix Waste to Energy Incineration Facility in New Richmond, Wisconsin, Prepared for
Interel Corporation, Englewood, CO, Report No. 8-2609, September 20, 1988.
99. Interpoll Laboratories, Inc., Results of the October 1988 Paniculate Emission Compliance
Test on the MSW Incinerator at the St. Croix Waste to Energy Facility in New Richmond,
Wisconsin, Prepared for American Resource Recovery, Waukesha, WI, Report No. 8-2547,
November 3, 1988.
100. Interpoll Laboratories, Inc., Results of the October 21, 1988, Scrubber Performance Test at
the St. Croix Waste to Energy Facility in New Richmond, Wisconsin, Prepared for Interel
Corporation, Englewood, CO, Report No. 8-2648, December 2, 1988.
101. Harm, J. L. (Ogden Projects, Inc.), Environmental Test Report, Prepared for Stanislaus Waste
Energy Company Crows Landing, CA, OPI Report No. 177R, April 7, 1989.
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,
California Resource Recovery Facility", Presented at the International Conference on
Municipal Waste Combustion, Hollywood, FL, pp. 4A-1 to 4A-14, April 11-14, 1989.
103. Seelinger, R., et al. (Ogden Products, Inc.), Environmental Test Report, Walter B. Hall
Resource Recovery Facility, Units 1 and 2, (Prepared for Ogden Martin Systems of Tulsa,
Inc.), Tulsa, OK, September 1986.
104. PEI Associates, Inc, Method Development and Testing for Chromium, Municipal Refuse
Incinerator, Tuscaloosa Energy Recovery, Tuscaloosa, Alabama, U.S. Environmental
Protection Agency, Research Triangle Park, NC, EMB Report 85-CHM-9, January 1986.
105. Guest, T. and O. Knizek, "Mercury Control at Burnaby's Municipal Waste Incinerator",
Proceedings of the 84th Annual Meeting and Exhibition of the Air and Waste Management
Association, Vancouver, British Columbia, Canada, June 16-21, 1991.
106. Trip Report, Burnaby MWC, British Columbia, Canada. White, D., Radian Corporation,
May 1990.
107. Entropy Environmentalists, Inc. for Babcock & Wilcox Co. North County Regional Resource
Recovery Facility, West Palm Beach, FL, October 1989.
108. Maly, P.M., G.C. England. W.R. Seeker, N.R. Soelberg, and D.G. Linz. Results of the
July 1988 Wilmarth Boiler Characterization Tests, Gas Research Institute Topical Report
No. GRI-89/0109, June 1988-March 1989.
109. Hahn, J.L. (Cooper Engineers, Inc.), Air Emissions Testing at the Martin GmbH Waste-to-
Energy Facility in Wurzburg, West Germany, Prepared for Ogden Martin Systems, Inc.,
Paramus, NJ, January 1986.
110. Entropy Environmentalists, Inc. for Westinghouse RESD, Metals Emission Testing Results,
Conducted at the York County Resource Recovery Facility, February 1991.
111. Entropy Environmentalists, Inc. for Westinghouse RESD, Emissions Testing for: Hexavalent
Chromium, Metals, Paniculate. Conducted at the York County Resource Recovery Facility,
July 31 - August 4, 1990.
112. Interpoll Laboratories, Results of the July 1987 Emission Performance Tests of the
Pope/Douglas Waste-to-Energy Facility MSW Incinerators in Alexandria, Minnesota,
(Prepared for HDR Techserv, Inc.), Minneapolis, MN, October 1987.
113. Sussman, D.B., Ogden Martin System, Inc., Submittal to Air Docket (LE-131), Docket
No. A-89-08, Category IV-M, Washington, DC, October 1990.
114. Ferraro, F., Wheelabrator Technologies, Inc., Data package to D.M. White, Radian
Corporation, February 1991.
115. Knisley, D.R., et al. (Radian Corporation), Emissions Test Report, Dioxin/Furan Emission
Testing, Refuse Fuels Associates, Lawrence, Massachusetts, (Prepared for Refuse Fuels
Association), Haverhill, MA, June 1987.
2.1-42 EMISSION FACTORS 7/93
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116. Entropy Environmentalists, Inc., Stationary Source Sampling Report, Ogden Martin Systems
of Haverhill, Inc., Lawrence, Massachusetts Thermal Conversion Facility. Paniculate,
Dioxins/Furans and Nitrogen Oxides Emission Compliance Testing. September 1987.
117. Fossa, A.J., et al., Phase I Resource Recovery Facility Emission Characterization Study,
Overview Report, New York State Department of Environmental Conservation, Albany, NY.
May 1987.
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 Report-Sheridan 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-450/3-89-27e, 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 paniculate 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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Cooling Air
Discharge
Exhaust
Scum.
Auxiliary
Air Port*
Rabbla Arm
2 or 4 Per
Htarth
Gaa Flow
Cltnkar
Breaker
Sludga Caka.
Scraanings.
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 760°C
(800 and 1400°F). Sludge combustion occurs in the middle hearths (second zone) as the temperature
is increased to about 925°C (1700°F). 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 furnace. 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 925°C
(1400 to 1700°F) 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
Thermocouple
Sludge
Inlet
Fluid Wr*g
Air Inlet
Burner
Startup
Preheat
Burner
For Hot
Windboi
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 315°C (350 and 600°F). 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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Belt
& Drive R(
^ Sludge Feed 1 ,Le
R_^ 1 f
— -^•~~ — • ~^ 1 1
o pi AM
r- \ I / ^\J F
| Airlock ^!/fm ^
R f •-•H»L"H ixi f" i* f 1
Gas f-—
Exhaust ~"" v—
Radiant
Infrared
>ller Healing
veiei Elements (Typl
Cooling I Cooling
abbling Air 1 Air
,.vic. | » |
V-pAl •••_••_•_•
p-rjOir T/>C
III
o o o
o u o
V
c
i/oven Wire
oniinuous Bell
o o o o o o o
o o o o o o o
I
a i
1
—
k f
- •*»
tJ
I
1
1
1
?J
-^ Air
Ash
Discharge
ro
i
^J
Figure 2.5-3. Cross Section of an Electric Infrared Furnace
-------
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) particulate 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 particulate emissions are highest from fluidized bed incinerators because suspension
burning results in 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 particulate 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 particulate 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 particulate emissions.
Metals emissions are affected by metals content of the sludge, fuel bed temperature, and the
level of particulate 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 particulate
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
-------
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 precooling 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. Paniculate matter carried along with the gas
stream impacts on these water panicles 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
paniculate 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
-------
N)
In
Table 2.5-1 (Metric and English Units). CRITERIA POLLUTANT EMISSION FACTORS FOR MULTIPLE HEARTH
SEWAGE SLUDGE INCINERATORS"
(SCC 50100515)
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingemenl/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Particulate matter (PM)
kg/Mg
5.2E + 01
2.0E+00
4.0E-01
2.5E-01
3.1E-01
2.0E-03
7.0E-01
1.6E+00
1.1E+00
2.0E-01
Ib/ton
l.OE + 02
4.0E + 00
8.0E-01
5.0E-01
6.2E-01
4.0E-03
1.4E + 00
3.2E+00
2.2E + 00
4.0E-01
Emission
Factor Rating
B
E
E
D
E
E
B
B
A
E
Sulfur dioxide (SO2)
kg/Mg
1.4E+01
2.8E + 00
3.2E-01
2.3E + 00
l.OE-01
Ib/ton
2.8E+01
5.6E+00
6.4E-01
4.6E+00
2.0E-01
Emission
Factor Rating
B
E
D
E
E
Nitrogen oxides (NOX)
kg/Mg
4.3E+00
4.0E-03
2.7E+00
l.OE + 00
8.0E-02
Ib/ton
8.6E + 00
8.0E-03
5.4E + 00
2.0E + 00
1.6E-01
Emission
Factor Rating
D
E
D
E
E
m
00
00
O
2:
T)
e
73
CO
-------
Table 2.5-1. (Continued)
Source Category
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Vetlturi/WESP
Carbon Monoxide (CO)
kg/Mg
3.6E + 01
1.3E + 00
2.2E + 00
1.7E+00
Ib/ton
7.2E + 01
2.6E + 00
4.4E + 00
3.4E+00
Emission
Factor
Rating
D
E
E
E
Lead0
kg/Mg
5.0E-02
3.0E-02
3.0E-03
1.1E-02
l.OE-03
2.0E-02
9.0E-04
5.0E-02
3.0E-02
9.0E-05
Ib/ton
l.OE-01
6.0E-02
6.0E-03
2.2E-02
2.0E-03
4.0E-02
1.8E-03
l.OE-01
6.0E-02
1.8E-04
Emission
Factor
Rating
B
E
E
E
E
E
E
E
B
E
Methane
kg/Mg
3.9E-01
3.2E+00
Ib/ton
7.8E-01
6.4E+00
Emission
Factor
Rating
E
E
Total Nonmethane Organic Compounds
kg/Mg
8.4E-01
1.5E+00
2.2E-01
7.8E-01
Ib/ton
1.7E + 00
3.0E + 00
4.4E-01
1.6E+00
Emission
Factor
Rating
D
E
E i
E
I
\
1
a Units are pollutants emitted of dry sludge burned. SCC = Source Classification Code.
b WESP = Wet Electrostatic Precipilator. •
c Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
K)
in
-------
to
Table 2.5-2 (Metric and English Units). ACID GAS EMISSION FACTORS FOR MULTIPLE HEARTH
SEWAGE SLUDGE INCINERATORS3
(SCC 50100515)
m
e
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Sulfuric Acid (H2SO4)
kg/Mg
6.0E-01
3.3E-01
5.0E-02
2.0E-01
Ib/ton
1.2E+00
6.6E-01
l.OE-01
4.0E-01
Emission
Factor Rating
D
E
E
E
Hydrogen Chloride (HC1)C
kg/Mg
l.OE-02
l.OE-02
l.OE-02
l.OE-02
Ib/ton
2.0E-02
2.0E-02
2.0E-02
2.0E-02
Emission
Factor Rating
E
E
E
E
a Units are pollutants emitted of dry sludge burned. SCC = Source Classification Code.
b WESP = Wet Electrostatic Precipitator.
c Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
-------
Table 2.5-3 (Metric and English Units). CHLORINATED DIBENZO-P-DIOXIN (CDD) AND DIBENZOFURAN (CDF)
EMISSION FACTORS FOR MULTIPLE HEARTH SEWAGE SLUDGE INCINERATORS3
(SCC 50100515)
EMISSION FACTOR RATING: E
o
0.°
n
O
Vt
CO
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
2,3,7,8-TCDDc
/
-------
to
Table 2.5-3. (Continued)
m
5
HH
CO
GO
«—«
O
2;
5
O
73
CO
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Total HxCDDc
Ag/Mg
6.8E+01
4.4E+00
2.4E+01
6.0E+01
3.8E+01
Ib/ton
1.4E-07
8.8E-09
4.8E-08
1.2E-07
7.6E-08
Total HpCDD
/
-------
Table 2.5-3. (Continued)
o.
I
1/1
n
q
En'
"B
c/i
^
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
W.S-TCDF*
/
-------
NJ
Table 2.5-3. (Continued)
m
Z
KH
CO
CO
P~H
O
Z
T)
>
q
O
73
CO
Source Category^
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Total HxCDF
/
-------
Table 2.5-3. (Continued)
on
o
O
O
VI
cu
Source Category
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Total Tetra through Octa CDD
/'g/Mg
8.5E + 02
5.6E+00
l.lE-t-02
1.8E+02
3.1E+02
2.7E+02
Ib/ton
1.7E-06
1.1E-08
2.2E-07
3.6E-07
6.2E-07
5.4E-07
Total Tetra through Octa CDF
/'g/Mg
3.8E + 03
6.6E+01
2.5E+02
1.5E+03
4.6E+02
9.3E+02
Ib/ton
7.6E-06
1.3E-07
5.0E-07
3.0E-06
9.2E-07
1.9E-06
a Units are pollutant emitted of dry sludge
b WESP = Wet Electrostatic Precipitator.
c Hazardous Air Pollutants listed in Title I
burned. SCC = Source Classification Code.
of the 1990 Clean Air Act Amendments.
to
-------
N>
00
Table 2.5-4 (Metric and English Units). SUMMARY OF ORGANIC COMPOUND EMISSIONS
FROM MULTIPLE HEARTH SEWAGE SLUDGE INCINERATORS"
(SCC 50100515)
Source Category**
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
I,l,l-Trichloroethanec
g/Mg
6.0E-02
1.9E+00
7.0E-02
1.4E+00
6.1E-01
Ib/ton
1.2E-04
3.8E-03
1.4E-04
2.8E-03
1.2E-03
Emission
Factor Rating
D
E
E
E
D
l,l-Dichloroethanec
g/Mg
2.3E-01
Ib/ton
4.6E-04
Emission
Factor Rating
E
l,2-Dichloroethanec
g/Mg
4.0E-03
3.0E-02
l.OE-02
Ib/ton
8.0E-06
6.0E-05
2.0E-05
Emission
Factor Rating
E
E
E
m
CO
C/5
o
ye
C/)
-------
Table 2.5-4. (Continued)
Source Category*5
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
1,2-Dichlorobenzene
g/Mg
3.7E-01
1.9E-01
Ib/ton
7.4E-04
3.8E-04
Emission
Factor Rating
E
E
1,3-Dichlorobenzene
g/Mg
5.0E-02
2.0E-02
Ib/ton
l.OE-04
4.0E-05
Emission
Factor Rating
E
E
l,4-Dichlorobenzenec
g/Mg
4.1E-01
7.0E-03
2.4E-01
Ib/ton
8.2E-04
1.4E-05
4.8E-04
Emission
Factor Rating
E
E
E
c_
CL.
Z
Co
o
o
NJ
-------
Table 2.5-4 (Continued)
A
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
2-Nitrophenol
g/Mg
6.0E+00
3.8E-01
1.2E+00
Ib/ton
1.2E-02
7.6E-04
2.4E-03
Emission
Factor Rating
E
E
E
Acetaldehydec
g/Mg
1.6E-01
Ib/ton
3.2E-04
Emission
Factor Rating
E
Acetone
g/Mg
3.2E + 00
Ib/ton
6.4E-03
Emission
Factor Rating
E
m
S
I-H
GO
V)
O
Z
T]
>
e
73
oo
-------
Table 2.5-4. (Continued)
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Acetonitrilec
g/Mg
2.5E+01
7.4E-01
9.7E+00
Ib/ton
5.0E-02
1.5E-03
2.0E-02
Emission
Factor Rating
E
E
E
Acrylonitrilec
g/Mg
2.5E+01
1.5E-01
4.9E-01
1.7E+01
Ib/ton
5.0E-02
3.0E-04
9.8E-04
3.4E-02
Emission
Factor Rating
E
E
E
E
Benzene0
g/Mg
5.8E+00
3.5E-01
1.4E+01
1.7E-01
6.3E+00
Ib/ton
1.2E-02
7.0E-04
2.8E-02
3.4E-04
1.3E-02
Emission
Factor Rating
D
E
E
E
D
o_
CL
%
I
n
a
K)
Lfi
K)
-------
JO
In
to
to
Table 2.5-4. (Continued)
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Bis (2-ethylhexyl) phthalatec
g/Mg
9.3E-01
4.0E-02
3.2E-01
Ib/ton
1.9E-03
8.0E-05
6.4E-04
Emission
Factor Rating
E
E
E
Bromodichloromethane
g/Mg
4.0E-03
1.5E-I-00
Ib/ton
8.0E-06
3.0E-03
Emission
Factor Rating
E
E
Carbon Tetrachloridec
g/Mg
l.OE-02
7.0E-03
l.OE-03
3.0E-02
Ib/ton
2.0E-05
1.4E-05
2.0E-06
6.0E-05
Emission
Factor Rating
E
E
E
D
m
Z
^-*
GO
i
70
-------
Table 2.5-4. (Continued)
C/3
0.
cL
I
o
a
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Chlorobenzene0
g/Mg
7.5E-01
6.0E-03
4.2E+00
2.6E-01
6.0E-01
Ib/ton
1.5E-03
1.2E-05
8.4E-03
5.2E-04
1.2E-03
Emission
Factor Rating
E
E
E
E
E
Chloroform0
g/Mg
3.0E-02
2.0E-02
3.3E + 00
4.9E-01
1.30E+00
Ib/ton
6.0E-05
4.0E-05
6.6E-03
9.8E-04
2.6E-03
Emission
Factor Rating
E
E
E
E
D
K)
Irt
to
-------
K>
in
N>
Table 2.5-4. (Continued)
Source Category*1
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Ethylbenzenec
g/Mg
8.0E-01
3.0E-03
6.0E + 00
2.0E-02
l.OE+00
Ib/ton
1.6E-03
6.0E-06
1.2E-02
4.0E-05
2.0E-03
Emission
Factor Rating
E
E
E
E
D
Formaldehyde0
g/Mg
1.3E+00
4.0E-01
Ib/ton
2.6E-03
8.0E-04
Emission
Factor Rating
E
E
Methyl Ethyl Ketone0
g/Mg
6.1E+00
6.1E+00
5.0E-02
8.9E+00
Ib/ton
1.2E-02
1.2E-02
l.OE-04
1.8E-02
Emission
Factor Rating
E
E
E
E
ffl
2
c/5
CO
O
Z
T)
>
e
73
C/5
-------
Table 2.5-4. (Continued)
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venluri/impingement/
WESP
Venturi/WESP
Methyl Isobutyl Ketonec
g/Mg
l.OE-02
Ib/ton
2.0E-05
Emission
Factor Rating
E
Methylene Chloride0
g/Mg
4.0E-01
3.0E-01
4.0E-01
9.0E-01
Ib/ton
8.0E-Q4
6.0E-04
8.0E-04
1.8E-03
Emission
Factor Rating
D
E
E
D
Naphthalene0
g/Mg
9.2E+00
9.7E-01
Ib/ton
1.8E-02
1.9E-03
Emission
Factor Rating
E
D
c.
?
t/>
NJ
N)
-------
K)
Table 2.5-4. (Continued)
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Perchloroethylenec
g/Mg
4.0E-01
3.0E-01
2.0E-01
Ib/ton
8.0E-04
6.0E-04
4.0E-04
Emission
Factor Rating
E
E
E
Phenol0
g/Mg
2.2E+01
1.8E+00
Ib/ton
4.4E-02
3.6E-03
Emission
Factor Rating
E
E
Tetrachloroethanec
g/Mg
1.2E+01
Ib/ton
2.4E-02
Emission
Factor Rating
E
K)
0\
m
S
^H
CO
M
O
e
CO
-------
Table 2.5-4. (Continued)
Source Category1*
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Toluene0
g/Mg
7.8E+00
3.3E + 00
1.6E+01
6.6E-01
6.5E+00
Ib/ton
1.5E-02
6.6E-03
3.0E-02
1.3E-03
1.3E-02
Emission
Factor Rating
D
E
E
E
D
Trans-l,2-Dichloroethenec
g/Mg
9.0E-02
4.0E-02
5.0E-02
Ib/ton
1.8E-04
8.0E-05
l.OE-04
Emission
Factor Rating
E
D
E
Trichloroethenec
g/Mg
4.0E-01
4.5E-01
Ib/ton
8.0E-04
-
9.0E-04
Emission
Factor Rating
E
E
c.
3
D
v>'
1
Cii
N)
(J\
NJ
-------
K)
1
Table 2.5-4. (Continued)
Source Category*5
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Vinyl Chloride0
g/Mg
6.6E+00
l.OE+00
8.0E-01
3.7E+00
Ib/ton
1.3E-02
2.0E-03
1.6E-03
7.4E-03
Emission
Factor Rating
E
E
E
D
Xylene, m,pc
g/Mg
2.0E+00
Ib/ton
4.0E-03
Emission
Factor Rating
E
Xylene (total)0
g/Mg
9.5E-01
Ib/ton
1.9E-03
Emission
Factor Rating
E
m
2
00
GO
O
z:
i
a Units are pollutants emitted of dry sludge burned. SCC = Source Classification Code.
b WESP = Wet Electrostatic Precipitator.
0 Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
-------
Table 2.5-5 (Metric and English Units). SUMMARY OF METAL EMISSIONS FROM
MULTIPLE HEARTH SEWAGE SLUDGE INCINERATORS3
(SCC 50100515)
Source Category^
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Aluminum
g/Mg
2.4E + 02
3.0E-01
3.8E+02
6.8E-01
9.2E + 01
Ib/ton
4.8E-01
6.0E-04
7.6E-02
1.8E-01
Emission
Factor Rating
D
E
E
E
E
Antimony'
g/Mg
1.5E + 00
3.2E-01
4.0E-02
4.0E-03
2.4E-01
Ib/ton
3.0E-03
6.4E-04
8.0E-05
8.0E-06
4.8E-04
Emission
Factor Rating
E
E
E
E
E
Arsenic0
g/Mg
4.7E+00
l.OE-01
8.5E-01
1.2E+00
3.0E-03
5.0E-02
4.0E-02
6.1E-01
6.0E-01
Ib/ton
9.4E-03
2.0E-04
1.7E-03
2.4E-03
6.0E-06
l.OE-04
8.0E-05
1.2E-03
1.2E-03
Emission
Factor Rating
B
E
E
E
E
E
E
B
E
CO
o_
EL'
OJ
C/l
O
Vt'
K)
I
K)
-------
Table 2.5-5. (Continued)
LA
u>
O
Source Category15
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Barium
g/Mg
1.5E+01
l.OE-01
7.4E-KX)
4.0E-03
3.2E+00
Ib/ton
3.0E-02
2.0E-04
1.5E-02
8.0E-06
6.4E-03
Emission
Factor Rating
D
E
E
E
D
Beryllium0
g/Mg
1.5E-01
9.0E-03
5.0E-03
Ib/ton
3.0E-04
1.8E-05
l.OE-05
Emission
Factor Rating
E
D
E
Cadmium0
g/Mg
1.6E+01
1.7E+01
1.3E+01
8.1E+00
1.7E-01
l.OE-02
1.2E+00
1.1E-01
3.0E-I-00
3.3E+00
l.OE-01
4.0E-02
Ib/ton
3.7E-02
3.4E-02
2.6E-02
1.6E-02
3.4E-04
2.0E-05
2.4E-03
2.2E-04
6.0E-03
6.6E-03
2.0E-04
8.0E-05
Emission
Factor Rating
B
D
C
E
E
E
E
E
E
E
E
E
m
CO
CO
e
00
-------
Table 2.5-5. (Continued)
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venluri/WESP
Calcium
g/Mg
7.0E+02
1.2E+00
3.5E-f02
8.0E-02
2.6E+02
Ib/ton
1.4E+00
2.4E-03
7.0E-01
1.6E-04
5.2E-01
Emission
Factor Rating
C
E
E
E
D
Chromium0
g/Mg
1.4E + 01
1.9E+00
4.0E-02
5.0E-01
1.1E + 01
1.4E+00
4.0E-02
9.8E+00
5.0E-01
4.9E+00
2.1E+00
1.1E-01
l.OE-02
Ib/ton
2.9E-02
3.8E-03
8.0E-05
l.OE-03
2.7E-02
2.8E-03
8.0E-05
1.9E-02
l.OE-03
9.8E-03
4.2E-03
2.2E-04
2.0E-05
Emission
Factor Rating
B
D
E
E
E
E
E
E
E
E
E
E
E
Cobaltc
g/Mg
9.0E-01
2.0E-01
3.8E-01
6.0E-03
4.5E-01
Ib/ton
1.8E-03
4.0E-04
7.6E-04
1.2E-05
9.0E-04
Emission
Factor Rating
C
E
E
E
D
o
S/l
n
D
N)
(J\
-------
Table 2.5-5. (Continued)
K)
U)
NJ
Source Category'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Copper
g/Mg
4.0E+01
2.7E+00
l.OE+00
2.0E-01
2.0E-03
4.0E-01
5.8E+00
5.5E + 00
l.OE-02
Ib/ton
8.0E-02
5.4E-03
2.0E-03
4.0E-04
4.0E-06
8.0E-04
1.2E-02
1.1E-02
2.0E-05
Emission
Factor Rating
B
E
E
E
E
E
E
D
E
Gold
g/Mg
3.0E-02
9.0E-03
2.0E-03
l.OE-02
Ib/ton
6.0E-05
1.8E-05
4.0E-06
2.0E-05
Emission
Factor Rating
E
E
E
E
Iron
g/Mg
5.6E+02
1.7E+00
2.5E + 01
2.3E-01
4.8E+01
Ib/ton
1.1E+00
3.4E-03
5.0E-02
4.6E-04
9.6E-02
Emission
Factor Rating
C
E
E
E
D
m
So
on
§
CO
-------
Table 2.5-5. (Continued)
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Manganese0
g/Mg
9.4E+00
3.3E-01
3.2E-01
5.0E-03
8.5E-01
Ib/ton
1.9E-02
6.6E-04
6.4E-04
l.OE-05
1.7E-03
Emission
Factor Rating
C
E
E
E
D
Magnesium
g/Mg
1.4E+02
1.4E+00
8.8E+00
3.0E-02
4.2E+00
Ib/ton
2.8E-01
2.8E-03
1.8E-02
6.0E-05
8.4E-03
Emission
Factor Rating
C
E
E
E
D
Mercury0
g/Mg
2.3E+00
1.6E+00
9.7E-01
5.0E-03
Ib/ton
4.6E-03
3.2E-03
1.9E-03
l.OE-05
Emission
Factor Rating
E
E
E
E
M
VI
O
D
N)
I
u>
-------
Table 2.5-5. (Continued)
SJ
Source Category''
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Nickel0
g/Mg
8.0E+00
8.0E-02
1.3E-KX)
3.5E-01
4.5E+00
2.0E+00
1.4E-02
4.1E+00
6.0E-02
9.0E-01
9.0E-01
3.0E-03
Ib/ton
1.6E-02
1.6E-04
2.6E-03
7.0E-04
9.0E-03
4.0E-03
2.8E-05
8.2E-03
1.2E-04
1.8E-03
1.8E-03
6.0E-06
Emission
Factor Rating
B
E
D
E
E
E
E
E
E
E
A
E
Phosphorus0
g/Mg
3.8E+02
8.9E+00
6.9E+00
2.0E-01
9.6E-01
. 1.2E+01
Ib/ton
7.6E-01
1.8E-02
1.4E-02
1.9E-03
2.4E-02
Emission
Factor Rating
D
E
E
E
E
D
Potassium
g/Mg
5.3E+01
9.0E-01
7.3E+00
Ib/ton
1.1E-01
1.8E-03
1.4E-02
Emission
Factor Rating
E
E
E
m
C/5
»— i
o
2:
CO
«J
s
-------
Table 2.5-5. (Continued)
Source Category*5
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Selenium0
g/Mg
1.5E-01
1.2E-01
6.0E-02
Ib/ton
3.0E-04
2.4E-04
1.2E-04
Emission
Factor Rating
D
E
E
Silicon
g/Mg
3.4E+02
4.6E+00
4.4E+01
Ib/ton
6.8E-01
9.2E-03
8.8E-02
Emission
Factor Rating
E
E
E
Silver
g/Mg
6.5E-01
6.0E-03
l.OE-04
4.0E-01
9.0E-02
Ib/ton
13E-03
1.2E-05
2.0E-07
8.0E-04
1.8E-04
Emission
Factor Rating
E
E
E
E
E
o
L
C/l
n
VI
CO
K)
In
-------
Table 2.5-5. (Continued)
to
ON
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Sodium
g/Mg
4.7E+01
1.8E+00
5.5E-01
l.OE-02
1.4E + 01
Ib/ton
9.4E-02
3.6E-03
1.1E-03
2.0E-05
2.8E-02
Emission
Factor Rating
C
E
E
E
D
Sulfur
g/Mg
3.6E+03
1.9E+01
6.0E+01
1.1E+02
Ib/ton
7.2E+00
3.9E-02
1.2E-01
2.2E-01
Emission
Factor Rating
D
E
E
E
Tin
g/Mg
1.3E+01
5.9E+00
2.0E-01
2.0E-02
7.9E+00
Ib/ton
2.6E-02
1.2E-02
4.0E-04
4.0E-05
1.6E-02
Emission
Factor Rating
C
E
E
E
D
m
^H
c/3
co
i—*
O
21
q
O
-------
Table 2.5-5. (Continued)
Source Category5
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Titanium
g/Mg
5.1E + 01
l.OE-01
9.0E-01
6.0E-03
3.1E + 00
Ib/ton
l.OE-01
2.0E-04
1.8E-03
1.2E-05
6.2E-03
Emission
Factor Rating
C
E
E
E
D
Vanadium
g/Mg
3.3E+00
3.0E-01
9.9E-01
2.0E-03
8.0E-01
Ib/ton
6.6E-03
6.0E-04
2.0E-03
4.0E-06
1.6E-03
Emission
Factor Rating
C
E
E
E
E
Zinc
g/Mg
6.6E + 01
1.1E + 01
3.8E + 01
3.9E-01
4.0E-02
4.4E+00
3.3E+01
2.4E+01
2.0E-01
Ib/ton
1.3E-01
2.2E-02
7.6E-02
7.8E-04
8.0E-05
8.8E-03
6.6E-02
4.8E-02
4.0E-04
Emission
Factor Rating
C
E
E
E
E
E
E
C
E
C/J
o
a Units are pollutants emitted of dry sludge burned. SCC = Source Classification Code.
b WESP = Wet Electrostatic Precipitator.
c Hazardous Air Pollutants listed in Title 1 of the 1990 Clean Air Act Amendments.
vJ
-------
to
l/>
u>
oo
Table 2.5-6 (Metric and English Units). CRITERIA POLLUTANT EMISSION FACTORS FOR
FLUIDIZED BED SEWAGE SLUDGE INCINERATORS8
(SCC 50100516)
EMISSION FACTOR RATING: E
m
2
CO
00
o
e
CO
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Paniculate Matter
kg/Mg
2.3E + 02
5.0E-ai
1.3E-01
5.7E-01
2.7E-01
l.OE-01
Ib/ton
4.6E+02
l.OE+00
2.6E-01
1.1E+00
2.0E-01
Sulfur Dioxide
kg/Mg
1.5E-01
3.0E-01
9.2E+00
4.0E-01
Ib/ton
3.0E-01
6.0E-01
1.8E + 01
8.0E-01
Nitrogen Oxides
kg/Mg
4.0E-02
2.9E + 00
5.0E-01
Ib/ton
8.0E-02
5.8E + 00
l.OE + 00
-------
Table 2.5-6. (Continued)
C/3
o_
oi
3
I
o
O
S5°
Source Category1'
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Carbon Monoxide (CO)
kg/Mg
5.0E-03
1.1E+00
Ib/ton
l.OE-02
2.2E+00
Lead0
kg/Mg
2.0E-02
5.0E-06
3.0E-03
8.0E-02
l.OE-06
Ib/ton
4.0E-02
l.OE-05
6.0E-03
1.6E-01
2.0E-06
Methane VOC
kg/Mg
1.6E+00
4.0E-01
Ib/ton
3.2E+00
8.0E-01
a Units are pollutants emitted of dry sludge burned. SCC = Source Classification Code.
b WESP = Wet Electrostatic Precipitator.
c Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
KJ
(
UJ
-------
V"
-k
O
Table 2.5-7 (Metric and English Units). ACID GAS AND ORGANIC COMPOUND EMISSION FACTORS
FOR FLUIDIZED BED SEWAGE SLUDGE INCINERATORS"
(SCC 50100516)
EMISSION FACTOR RATING: E
Pollutant
Sulfuric Acid (H2SO4)
Hydrogen Chloride (HCl)b
2,3,7,8-TCDDb
Total TCDD
Total PCDD
Total HxCDD
Total HpCDD
Total OCDD
2,3,7,8-TCDF*
Total TCDF"
Total PCDF*5
Total HxCDF*
Total HpCDF*
Total OCDF*
1, 1, l-Trichloroethaneb
1,2-Dichlorobenzene
l,4-Dichlorobenzeneb
Benzeneb
Bis (2-ethylhexyl) phthalateb
Carbon Tetrachloride6
Uncontrolled
g/Mg
1.1E-06
Ib/ton
2.2E-09
Impingement
g/Mg
3.0E+01
Ib/ton
6.0E-02
Venturi/impingement
g/Mg
6.0E+01
5.0E + 01
3.0E-07
2.2E-06
9.0E-07
9.0E-07
4.3E-06
2.0E-07
6.2E-06
5.2E-06
4.1E-06
1.6E-06
1.3E-06
2.6E-01
6.4E+01
2.4E-I-02
2.0E-01
4.1E+01
1.2E-02
Ib/ton
1.2E-01
l.OE-01
6.0E-10
4.4E-09
1.8E-09
1.8E-09
8.6E-09
4.0E-10
1.2E-08
l.OE-08
8.2E-09
3.2E-09
2.6E-09
5.2E-04
1.3E-01
4.8E-01
4.0E-04
8.2E-02
2.4E-05
Cyclone/impingement
g/Mg
Ib/ton
m
CO
CO
O
2;
CO
-------
Table 2.5-7. (Continued)
Pollutant
Chlorobenzeneb
Chloroform6
Ethylbenzene6
Methylene Chloride6
Naphthalene6
Perchloroethylene6
Toluene6
Trichloroethene6
Uncontrolled
g/Mg
Ib/ton
Impingement
g/Mg
Ib/ton
Venturi/impingement
g/Mg
5.0E-03
2.0E+00
2.5E-02
7.0E-01
9.7E+01
1.2E-01
3.0E-02
Ib/ton
l.OE-05
4.0E-03
5.0E-05
1.4E-03
1.9E-01
2.4E-04
6.0E-05
Cyclone/impingement
g/Mg
3.5E-01
Ib/ton
7.0E-04
C/5
O
I
n
O
Vi'
I
a Units are pollutants emitted of dry sludge burned. SCC = Source Classification Code.
6 Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
N)
-------
/I
h
Table 2.5-8 (Metric and English Units). METALS EMISSION FACTORS
FOR FLUIDIZED BED SEWAGE SLUDGE INCINERATORS8
(SCC 50100516)
EMISSION FACTOR RATING: E
ffl
2
00
i
73
C/5
Pollutant
Aluminum
Arsenic0
Barium
Beryllium0
Cadmium0
Calcium0
Chromium0
Copper
Manganese0
Magnesium
Mercury0
Nickel0
Potassium
Selenium0
Silicon
Sulfur
Uncontrolled
g/Mg
2.2E+00
2.2E+00
1.78E + 01
Ib/ton
4.4E-03
4.4E-03
3.5E-02
Impingement
g/Mg
4.0E-01
3.2E-01
Ib/ton
8.0E-04
6.4E-04
Venturi/impingement
g/Mg
1.9E+00
1.5E-02
2.4E-01
2.0E-04
5.7E-01
5.2E+00
2.5E-01
3.0E-01
3.0E-01
6.0E-01
3.0E-02
1.7E + 00
6.0E-01
2.0E-01
3.2E + 00
8.6E+00
Ib/ton
3.8E-03
3.0E-05
4.8E-04
4.0E-07
1.1E-03
l.OE-02
5.0E-04
6.0E-04
6.0E-04
1.2E-03
6.0E-05
3.4E-03
1.2E-03
4.0E-04
6.4E-03
1.7E-02
Venturi/impingment/WESP
g/Mg
5.0E-03
2.0E-04
l.OE-03
3.0E-02
5.0E-03
Ib/ton
l.OE-05
4.0E-07
2.0E-06
6.0E-05
l.OE-05
-------
g
CL
n
a
Table 2.5-8. (Continued)
Pollutant
Tin
Titanium
Zinc
Uncontrolled
g/Mg
Ib/ton
Impingement
g/Mg
Ib/ton
Venturi/impingement
g/Mg
3.5E-01
4.0E-01
l.OE+00
Ib/ton
7.0E-04
8.0E-04
2.0E-03
Venturi/impingment/WESP
g/Mg
Ib/ton
a Units are pollutants emitted of dry sludge burned. SCC =. Source Classification Code.
b WESP = Wet Electrostatic Precipitator.
0 Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
to
.u
U)
-------
N)
Table 2.5-9 (Metric and English Units). SUMMARY OF EMISSION FACTORS FOR
ELECTRIC INFRARED SEWAGE SLUDGE INCINERATORS8
(SCC 50100517)
EMISSION FACTOR RATING: E
m
c/
CO
O
2;
I
LO
Source Category*5
Uncontrolled
Controlled
Cyclone
Cyclone/impingement
Cyclone/venturi
Cyclone/venturi/
impingement
Electrostatic
precipitator
Fabric filter
Impingement
Venturi
Venturi/impingement/
afterburner
Venturi/impingement
Venturi/impingement/
WESP
Venturi/WESP
Particulate Matter
kg/Mg
3.7E+00
1.9E+00
8.2E-01
9.5E-01
Ib/ton
7.4E + 00
3.8E+00
1.6E+00
1.9E+00
Sulfur Dioxide
kg/Mg
9.2E + 00
2.3E+00
Ib/ton
1.8E+01
4.6E+00
Nitrogen Oxides
kg/Mg
4.3E+00
2.9E+00
Ib/ton
8.6E+00
5.8E+00
a Units are pollutants emitted of dry sludge burned.
b WESP = Wet Electrostatic Precipitator.
SCC = Source Classification Code.
-------
Table 2.5-10 (Metric and English Units). CUMULATIVE PARTICLE SIZE DISTRIBUTION
FOR SEWAGE SLUDGE INCINERATORS4
EMISSION FACTOR RATING: E
Particle
Size,
Microns
15
10
5.0
2.5
1.0
0.625
Cumulative mass % stated size
Uncontrolled
MHb
15
10
5.3
2.8
1.2
0.75
EIC
43
30
17
10
6.0
5.0
Controlled (Scrubber)
MH
30
27
25
22
20
17
FBd
7.7
7.3
6.7
6.0
5.0
2.7
El
60
50
35
25
18
15
a Reference 5.
b MH = multiple hearth incinerator. Source
Classification Code (SCC) 50100515.
c El = electric infrared incinerator. SCC 50100517.
d FB = fluidized bed incinerator. SCC 50100516.
7/93
Solid Waste Disposal
2.5-45
-------
to
Ln
Table 2.5-11 (Metric and English Units). CUMULATIVE PARTICLE SIZE-SPECIFIC EMISSION FACTORS
FOR SEWAGE SLUDGE INCINERATORS"
EMISSION FACTOR RATING: E
m
2
co
CO
O
I
CO
Particle
Size,
Microns
15
10
5.0
2.5
1.0
0.625
Cumulative emission factor
Uncontrolled
MHb
kg/Mg
6.0E + 00
4.1E+00
2.1E + 00
1.1E+00
4.7E-01
3.0E-01
Ib/ton
1.2E + 01
8.2E+00
4.2E+00
2.2E+00
9.4E-01
6.0E-01
EIC
kg/Mg
4.3E+00
3.0E+00
1.7E+00
l.OE+00
6.0E-01
5.0E-01
Ib/ton
8.6E+00
6.0E+00
3.4E+00
2.0E+00
h2E+00
l.OE+00
Controlled (Scrubber)
MH
kg/Mg
1.2E-01
1.1E-01
l.OE-01
9.0E-02
8.0E-02
7.0E-02
Ib/ton
2.4E-01
2.2E-01
2.0E-01
1.8E-01
1.6E-01
1.4E-01
FBd
kg/Mg
2.3E-01
2.2E-01
2.0E-01
1.8E-01
1.5E-01
8.0E-02
Ib/lon
4.6E-01
4.4E-01
4.0E-01
3.6E-01
3.0E-01
1.6E-01
El
kg/Mg
1.2E+00
l.OE+00
7.0E-01
5.0E-01
3.5E-01
3.0E-01
Ib/ton
2.4E+00
2.0E+00
1.4E+00
l.OE+00
7.0E-01
6.0E-01
"Reference 5.
bMH = multiple hearth incinerator. Source Classification Code (SCC) 50100515.
CEI = electric infrared incinerator. SCC 50100517.
dFB = fluidized bed incinerator. SCC 50100516.
-------
Figure 2.5-4. Cumulative Particle Size Distribution and
Size-Specific Emission Factors for
Multiple-Health Incinerators
- 7,
- 6.0
31
a
"a
V
e
. 5
v 3.0
«4
•*
o
£ 0
0.18
ContrvM
0.1
1.0
r
30
u
O
0.15
0.12
C
0.09 °
39
9
-0.06
-0.03 5
c
o
u
Figure 2.5-5. Cumulative Particle Size Distribution and
Size-Specific Emission Factors for Fluidized-Bed Incinerators
i 9
a
0.24
0.20
z
90
100
0.16 '4
0.12 I
0.08 'J
-3
o.04 2
o
0
7/93
Solid Waste Disposal
2.5-47
-------
Figure 2.5-6. Cumulative Particle Size Distribution and
Size-Specific Emission Factors for Electric
(infrared) Incinerators
E
ee
JL
. 5
u
O
O
O
u
L.50 *
r
L.25
L.O *
o
0.75 |
"a
0.50 -3
v
4.1
19
19
100
0.25
0
s
O
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, EP A-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., Paniculate 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 Repon. 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 Repon. 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, Paniculate 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 6, 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, Paniculate 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. Paniculate 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,
Nonh 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 Facility—Sand Island Wastewater Treatment Plant in Honolulu, Hawaii-Phase 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, Nonh Carolina, [STAPPA/ALAPCO/07/28/86-No. 06],
Paniculate 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. Paniculate 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. Paniculate 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 Repon—Bayshore 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 Report—Jersey 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 Report—Nonhwest 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 Report—Pequannock, Lincoln Park, and Fairfield 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 Heanh 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/11/04/86-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 I, 1982), at the City of
Wdterbury 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
-------
52. Final Report—Emission 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 Enfield Sewage Treatment Plant in Enfield, 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,
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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.
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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.
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No. 136], The Research Corp., East Hartford, Connecticut, April 1985.
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Bridges, New Jersey, June 1986.
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October 19, 1987.
7/93 Solid Waste Disposal 2.5-53
-------
64. D.R. Knisley, et al., Site 3 Draft Emission Test Report and Addendum, Sewage Sludge Test
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September 30, 1985.
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Water Engineering Research Laboratory, Cincinnati, Ohio, September 30, 1985.
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Agency, Research Triangle Park, North Carolina, November 1984.
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Journal of the Water Pollution Control Federation, Vol. 52, No. 10, October 1980.
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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.
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Wastewater Sludge Incinerators, Volume I: Summary Report, U. S. Environmental Protection
Agency, Cincinnati, Ohio, 1992.
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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
-------
76. R.R. Segal, et al., Emissions of Metals, Chromium and Nickel Species, and Organicsfrom
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 Organicsfrom
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 Organicsfrom
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 Organicsfrom
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 Organicsfrom
Municipal Wastewater Sludge Incinerators, Volume VII: Site 9 Test Report,
EPA 600/R-92/003a, March 1.992.
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.
7/93 Solid Waste Disposal 2.5-55
-------
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 980°C (1,400 to 1,800°F)].
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 1,095°C (1,800 to 2,000°F). 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
7/93 Solid Waste Disposal 2.6-1
-------
Carbon Dioxide,
Water Vapor
Oxygen and Nitrogen
and Excess
to Atmosphere
Mr
Air
Main Burner for
Minimum Combustion
Temperature
Starved-Alr
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
-------
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 980°C (1600 to 1800°F)]. 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.
7/93 Solid Waste Disposal 2.6-3
-------
RamePort
Stack
Charging
Door
Ignition
Chamber
Secondary
Air Ports
Secondary
/^ Burner Port
Mixing
Chamber
First
Underneath Port
Hearth
Side View
Secondary
Combustion
Chamber
Mixing
Chamber RamePort
deanout
Doors
Charging Door
Hearth
Primary
Burner Port
Secondary
Underneath Port
Figure 2.6-2. Excess Air Incinerator
2.6-4
EMISSION FACTORS
7/93
-------
i
i
Figure 2.6-3. Rotary Kiln Incinerator
7/93
Solid Waste Disposal
2.6-5
-------
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 particulate 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) particulate 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.
Particulate 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.
Particulate matter may exit as a solid or an aerosol, and may contain heavy metals, acids, and/or trace
organics.
Uncontrolled particulate 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 in 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 150°C (300°F).
Acid gas concentrations of hydrogen chloride (HC1) and sulfur dioxide (SO2) 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 in 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 (NO2). 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
-------
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
-------
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
paniculate matter is collected on the inside of the bag; paniculate 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 paniculate matter, which results
in good control of metals and organics entrained on fine paniculate.
Paniculate 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
paniculate 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 paniculate 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
-------
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
participates 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
-------
JO
£
o
Table 2.6-1 (Metric and English Units). EMISSION FACTORS FOR NITROGEN OXIDES (NOX), CARBON MONOXIDE (CO),
AND SULFUR DIOXIDE (SO^ FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS*
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy
Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
NOX
Ib/ton
4.95E+00
3.55E+00
2.12E+00
2.12E+00
6.36E+00
2.90E+00
kg/Mg
2.48E+00
1.77E+00
1.06E+00
1.06E+00
3.18E+00
1.45E+00
Rating
B
E
E
E
E
E
CO
Ib/ton
3.86E+00
1.20E+00
8.27E-01
8.27E-01
5.32E-01
5.09E-03
7.08E-03
kg/Mg
1.93E+00
6.01E-01
4.14E-01
4.14E-01
2.66E-01
2.54E-03
3.54E-03
Rating
B
E
E
E
E
E
E
SO2
Ib/ton
2.17E+00
3.75E-01
8.45E-01
2.09E+00
2.57E-02
3.83E-01
7.14E-01
1.51E-02
kg/Mg
1.09E+00
1.88E-01
4.22E-01
1.04E+00
1.29E-02
1.92E-01
3.57E-01
7.57E-03
Rating
B
E
E
E
E
E
E
E
PI
1
(A
I
§
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
~J
VO
-------
Table 2.6-2 (Metric and Electric Units). EMISSION FACTORS FOR TOTAL PARTICIPATE MATTER, LEAD, AND
TOTAL ORGANIC COMPOUNDS (TOC) FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS*
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy
Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
Total Paniculate Matter
Ib/ton
4.67E+00
9.09E-01
1.61E-01
1.75E-01
2.90E+00
1.48E+00
3.37E-01
7.23E-02
2.68E+00
7.34E-01
kg/Mg
2.33E+00
4.55E-01
8.03E-02
8.76E-02
1.45E+00
7.41E-01
1.69E-01
3.61E-02
1.34E+00
3.67E-01
Rating
B
E
E
E
E
E
E
E
E
E
Lead0
Ib/ton
7.28E-02
1.60E-03
9.92E-05
7.94E-02
6.98E-02
6.25E-05
9.27E-05
5.17E-05
4.70E-03
kg/Mg
3.64E-02
7.99E-04
4.96E-05
3.97E-02
3.49E-02
3.12E+01
4.64E-05
2.58E-05
2.35E-03
Rating
B
E
E
E
E
E
E
E
E
TOC
Ib/ton
2.99E-01
6.86E-02
1.40E-01
1.40E-01
4.71E-02
kg/Mg
1.50E-01
3.43E-01
7.01E-02
7.01E-02
2.35E-02
Rating
B
E
E
E
E
00
I
a
5°
"8
u>
fiL
a
b
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
-------
J°
£
to
Table 2.6-3 (Metric and English Units). EMISSION FACTORS FOR HYDROGEN CHLORIDE (HC1) AND
POLYCHLORINATED BIPHENYLS (PCBs) FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS8
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
i
00
00
§
g
03
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
HC1C
Ib/ton
3.35E+01
1.90E+00
2.82E+00
5.65E+00
l.OOE+00
1.39E-01
1.27E+01
9.01E-01
9.43E-02
4.98E-01
kg/Mg
1.68E+01
9.48E-01
1.41E+00
2.82E+00
5.01E-01
6.97E-02
6.37EH-00
4.50E-01
4.71E-02
2.49E-01
Rating
C
E
E
E
E
E
D
E
E
E
Total PCBC
Ib/ton
4.65E-05
kg/Mg
2.33E-05
Rating
E
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
-------
VO
OJ
Table 2.6-4 (Metric and English Units). EMISSION FACTORS FOR ALUMINUM, ANTIMONY, AND ARSENIC
CONTROLLED AIR MEDICAL WASTE INCINERATORS8
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy
Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
Aluminum
Ib/ton
1.05E-02
3.03E-03
2.99E-03
kg/Mg
5.24E-03
1.51E-03
1.50E-03
Rating
E
E
E
Antimony0
Ib/ton
1.28E-02
3.09E-04
4.08E-04
2.10E-04
1.51E-04
kg/Mg
6.39E-03
1.55E-04
2.04E-04
1.05E-04
7.53E-05
Rating
D
E
E
E
E
Arsenic0
Ib/ton
2.42E-04
3.27E-05
3.95E-08
1.42E-04
3.27E-05
1.19E-05
1.46E-05
5.01E-05
kg/Mg
1.21E-04
1.53E-02
1.97E-08
7.12E-05
1.64E-05
5.93E-06
7.32E-06
2.51E-05
Rating
B
E
E
E
E
E
E
E
o.
SI
3
•8
o
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
to
-------
to
Table 2.6-5 (Metric and English Units). EMISSION FACTORS FOR BARIUM, BERYLLIUM, AND CADMIUM
FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS8
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy
Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
Barium
Ib/ton
3.24E-03
2.07E-04
7.39E-05
7.39E-05
kg/Mg
1.62E-03
1.03E-04
3.70E-05
3.69E-05
Rating
D
E
E
E
Beryllium0
Ib/ton
6.25E-06
3.84E-06
kg/Mg
3.12E-06
1.92E-06
Rating
D
E
Cadmium0
Ib/ton
5.48E-03
1.78E-04
6.97E-03
7.43E-02
2.46E-05
9.99E-05
1.30E-05
5.93E-04
kg/Mg
2.74E-03
8.89E-05
3.49E-03
3.72E-02
1.23E-05
4.99E-05
6.48E-06
2.97E-04
Rating
B
E
E
E
E
E
E
E
00
C/3
1
3
a
b
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
-------
VO
Table 2.6-6 (Metric and English Units). EMISSION FACTORS FOR CHROMIUM, COPPER,
AND IRON FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS*
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy
Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
Chromium0
Ib/ton
7.75E-04
2.58E-04
2.15E-06
4.13E-04
1.03E-03
3.06E-04
1.92E-04
3.96E-05
6.58E-04
kg/Mg
3.88E-04
1.29E-04
1.07E-06
2.07E-04
5.15E-04
1.53E-04
9.58E-05
1.98E-05
3.29E-04
Rating
B
E
E
E
E
E
E
E
E
Copper
Ib/ton
1.25E-02
1.25E-03
2.75E-04
kg/Mg
6.24E-03
6.25E-04
1.37E-04
Rating
E
E
E
Iron
Ib/ton
1.44E-02
9.47E-03
kg/Mg
7.22E-03
4.73E-03
Rating
C
E
00
o
•8
o
en
BL
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
K>
-------
Table 2.6-7 (Metric and English Units). EMISSION FACTORS FOR MANGANESE, MERCURY,
AND NICKEL FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS8
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy
Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
Manganese0
Ib/ton
5.67E-04
4.66E-04
6.12E-04
kg/Mg
2.84E-04
2.33E-04
3.06E-04
Rating
C
E
E
Mercury0
Ib/ton
1.07E-01
3.07E-02
1.55E-02
1.73E-02
1.11E-01
9.74E-03
3.56E-04
1.81E-02
kg/Mg
5.37E-02
1.53E-02
7.75E-03
8.65E-03
5.55E-02
4.87E-03
1.78E-04
9.05E-03
Rating
C
E
E
E
E
E
E
E
Nickel0
Ib/ton
5.90E-04
5.30E-04
3.28E-04
2.54E-03
4.54E-04
2.84E-04
4.84E-04
kg/Mg
2.95E-04
2.65E-04
1.64E-02
1.27E-03
2.27E-04
1.42E-04
2.42E-04
Rating
B
E
E
E
E
E
E
w
C/5
05
I
a
b
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
-o
VO
-------
GO
o_
51
g
55'
"8
v>
e.
Table 2.6-8 (Metric and English Units). EMISSION FACTORS FOR SILVER AND THALLIUM
FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS*
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy
Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
Silver
Ib/ton
2.26E-04
1.71E-04
4.33E-04
6.65E-05
7.19E-05
kg/Mg
1.13E-04
8.57E-05
2.17E-04
3.32E-05
3.59E-05
Rating
D
E
E
E
E
Thallium
Ib/ton
1.10E-03
kg/Mg
5.51E-04
Rating
D
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
o
-------
O
oo
VI
1
1
Table 2.6-9 (Metric and English Units). EMISSION FACTORS FOR SULFUR TRIOXIDE (SO3)
AND HYDROGEN BROMIDE (HBr) FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS11
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
SO3
Ib/ton
9.07E-03
kg/Mg
4.53E-03
Rating
E
HBr
Ib/ton
4.33E-02
5.24E-02
4.42E-03
kg/Mg
2.16E-02
2.62E-02
2.21E-03
Rating
D
E
E
a
b
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
-------
;.J
VO
C/J
o
•o
o
Table 2.6-10 (Metric and English Units). EMISSION FACTORS FOR HYDROGEN FLUORIDE AND
CHLORINE FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS*
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Control Levelb
Uncontrolled
Low Energy Scrubber/FF
Medium Energy Scrubber/FF
FF
Low Energy Scrubber
High Energy Scrubber
DSI/FF
DSI/Carbon Injection/FF
DSI/FF/Scrubber
DSI/ESP
Hydrogen Fluoride0
Ib/ton
1.49E-01
1.33E-02
kg/Mg
7.43E-02
6.66E-03
Rating
D
E
Chlorine0
Ib/ton
1.05E-01
kg/Mg
5.23E-02
Rating
E
a
b
References 7-43. SCC = Source Classification Code.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
-------
N>
ON
Table 2.6-11 (Metric and English Units). CHLORINATED DIBENZO-P-DIOXIN EMISSION FACTORS
FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS*
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Congenerb
TCDD
2,3,7,8-
Total
PeCDD
1,2,3,7,8-
Total
HxCDD
1,2,3,6,7,
8-
1,2,3,7,8,
9-
1,2,3,4,7,
8-
Total
HpCDD
1,2,3,4,6,
7,8-
Total
OCDD - total
Total CDD
Uncontrolled
Ib/ton
5.47E-08
l.OOE-06
3.78E-10
1.21E-09
5.23E-09
2.21E-08
2.13E-05
kg/Mg
2.73E-08
5.01E-07
1.89E-10
6.07E-10
2.62E-09
1.11E-08
1.07E-05
Rating
E
B
E
E
E
E
B
Fabric Filter
Ib/ton
6.72E-09
1.23E-07
2.68E-06
kg/Mg
3.36E-09
6.17E-08
1.34E-06
Rating
E
E
E
Wet Scrubber
Ib/ton
1.29E-10
2.67E-08
6.08E-10
5.53E-10
1.84E-09
2.28E-09
9.22E-10
5.77E-10
6.94E-09
1.98E-09
1.84E-06
kg/Mg
6.45E-11
1.34E-08
3.04E-10
2.77E-10
9.05E-10
1.14E-09
4.61E-10
2.89E-10
3.47E-09
9.91E-10
9.18E-07
Rating
E
E
E
E
E
E
E
E
E
E
E
DSI/FF0
Ib/ton
5.61E-10
6.50E-09
3.44E-07
kg/Mg
2.81E-10
3.25E-09
1.72E-07
Rating
E
E
E
i
in
c/j
O
a
b
c
References 7-43. SCC = Source Classification Code.
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
FF = Fabric Filter
DSI = Dry Sorbent Injection
SO
-------
o^
SI
3
"O
o
CO
e.
Table 2.6-12 (Metric and English Units). CHLORINATED DIBENZO-P-DIOXIN EMISSION FACTORS
FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS*
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Congener*5
TCDD
2,3,7,8-
Total
PeCDD
1,2,3,7,8-
Total
HxCDD
1,2,3,6,7,8-
1,2,3,7,8,9-
1,2,3,4,7,8-
Total
HpCDD
2,3,4,6,7,8-
1,2,3,4,6,7,8
Total
OCDD - total
Total CDD
DSI/Carbon Injection/FF6
Ib/ton
8.23E-10
5.38E-08
kg/Mg
4.11E-10
2.69E-08
Rating
E
E
DSI/ESPd
Ib/ton
1.73E-10
kg/Mg
8.65E-11
Rating
E
JO
b\
to
References 7-43. SCC = Source Classification Code.
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
-------
O
Table 2.6-13 (Metric and English Units). CHLORINATED DffiENZOFURAN EMISSION FACTORS
FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS8
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Congener**
TCDF
2,3,7,8-
Total
PeCDF
1,2,3,7,8-
2,3,4,7,8-
Total
HxCDF
1,2,3,4,7,8-
1,2,3,6,7,8-
2,3,4,6,7,8-
1,2,3,7,8,9-
Total
HpCDF
1,2,3,4,6,7,8
1,2,3,4,7,8,9
Total
OCDF - total
Total CDF
Uncontrolled
Ib/ton
2.40E-07
7.21E-06
7.56E-10
2.07E-09
7.55E-09
2.53E-09
7.18E-09
1.76E-08
2.72E-09
7.42E-08
7.15E-05
kg/Mg
1.20E-07
3.61E-06
3.78E-10
1.04E-09
3.77E-09
1.26E-09
3.59E-09
8.78E-09
1.36E-09
3.71E-08
3.58E-05
Rating
E
E
E
E
E
E
E
E
E
E
B
Fabric Filter
Ib/ton
3.85E-08
1.28E-06
8.50E-06
kg/Mg
1.97E-08
6.39E-07
4.25E-06
Rating
E
E
E
Wet Scrubber
Ib/ton
1.26E-08
4.45E-07
1.04E-09
3.07E-O9
6.18E-09
8.96E-09
3.53E-09
9.59E-09
3.51E-10
5.10E-09
1.79E-08
3.50E-09
1.91E-09
4.91E-10
4.92E-06
kg/Mg
6.30E-09
2.22E-07
5.22E-10
1.53E-09
3.09E-09
4.48E-09
1.76E-09
4.80E-09
1.76E-10
2.55E-09
8.97E-09
1.75E-09
9.56E-10
2.45E-10
2.46E-06
Rating
E
E
E
E
E
E
E
E
E
E
E
E
E
E
E
DSI/FF*
Ib/ton
4.93E-09
1.39E-07
1.47E-06
kg/Mg
2.47E-09
6.96E-08
7.37E-07
Rating
E
E
E
tn
oo
1
90
C/3
References 7-43. SCC = Source Classification Code.
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
FF = Fabric Filter
DSI = Dry Sorbent Injection
-------
00
o.
Si
q
f
e.
N>
9*
to
Table 2.6-14 (Metric and English Units). CHLORINATED DIBENZOFURANS EMISSION FACTORS
FOR CONTROLLED AIR MEDICAL WASTE INCINERATORS"
(SCC 50100505, 50200505)
Rating (A-E) Follows Each Factor
Congener13
TCDF
2,3,7,8-
Total
PeCDF
1,2,3,7,8-
2,3,4,7,8-
Total
HxCDF
1,2,3,4,7,8-
1,2,3,6,7,8-
2,3,4,6,7,8-
1,2,3,7,8,9-
Total
HpCDF
1,2,3,4,6,7,8
1,2,3,4,7,8,9
Total
OCDF - total
Total CDF
DSI/Carbon Injection/FF0
Ib/ton
7.31E-10
1.01E-08
9.47E-08
kg/Mg
3.65E-10
5.07E-09
4.74E-08
Rating
E
E
E
DSI/ESPd
Ib/ton
1.73E-09
kg/Mg
8.66E-10
Rating
E
References 7-43. SCC = Source Classification Code.
Hazardous Air Pollutants listed in Title I of the 1990 Clean Air Act Amendments.
FF = Fabric Filter
DSI = Dry Sorbent Injection
ESP = Electrostatic Precipitator
-------
Table 2.6-15. PARTICLE SIZE DISTRIBUTION FOR
CONTROLLED AIR MEDICAL WASTE INCINERATOR
PARTICULATE MATTER EMISSIONS8
(SCC 50100505, 50200505)
EMISSION FACTOR RATING = E
Cut Diameter
(microns)
0.625
1.0
2.5
5.0
10.0
Uncontrolled Cumulative
Mass % less than Stated
Size
31.1
35.4
43.3
52.0
65.0
Scrubber
Cumulative Mass % less
than Stated Size
0.1
0.2
2.7
28.1
71.9
a References 7-43. SCC = Source Classification Code.
2.6-24
EMISSION FACTORS
7/93
-------
C/3
O
e
o
"8
CO
B.
Table 2.6-16 (Metric and English Units). ROTARY KILN MEDICAL WASTE INCINERATOR EMISSION FACTORS
FOR CRITERIA POLLUTANTS AND ACID GASESa
(SCC 50100505, 50200505)
EMISSION FACTOR RATING = E
Pollutant
Carbon monoxide
Nitrogen oxides
Sulfur dioxide
PM
TOC
HC1
HF
HBr
H2S04
Uncontrolled
Ib/ton
3.82E-01
4.63E+00
1.09E+00
3.45E+01
6.66E-02
4.42E+01
9.31E-02
1.05E+00
kg/Mg
1.91E-01
2.31E+00
5.43E-01
1.73E+01
3.33E-02
2.21E+01
4.65E-02
5.25E-01
SD/Fabric Filterb
Ib/ton
3.89E-02
5.25E+00
6.47E-01
3.09E-01
4.11E-02
2.68E-01
2.99E-02
6.01E-02
kg/Mg
1.94E-02
2.63E+00
3.24E-01
1.54E-01
2.05E-02
1.34E-01
1.50E-02
3.00E-02
SD/Carbon Injection/FF0
Ib/ton
4.99E-02
4.91E+00
3.00E-01
7.56E-02
5.05E-02
3.57E-01
1.90E-02
kg/Mg
2.50E-02
2.45E+00
1.50E-01
3.78E-02
2.53E-02
1.79E-01
9.48E-03
High Energy Scrubber
Ib/ton
5.99E-02
4.08E+00
8.53E-01
2.17E-02
2.94E+01
2.98E+00
kg/Mg
3.00E-02
2.04E+00
4.27E-01
1.08E-02
1.47E+01
1.49E+00
a References 7-43. SCC = Source Classification Code.
b SD = Spray Dryer
c FF = Fabric Filter
^
to
Ul
-------
to
Table 2.6-17 (Metric and English Units). ROTARY KILN MEDICAL WASTE INCINERATOR
EMISSION FACTORS FOR METALS*
(SCC 50100505, 50200505)
EMISSION FACTOR RATING = E
i
*M
or)
c/a
MH
i
Pollutant
Aluminum
Antimony
Arsenic
Barium
Beryllium
Cadmium
Chromium
Copper
Lead
Mercury
Nickel
Silver
Thallium
Uncontrolled
Ib/ton
6.13E-01
1.99E-02
3.32E-04
8.93E-02
4.81E-05
1.51E-02
4.43E-03
1.95E-01
1.24E-01
8.68E-02
3.53E-03
1.30E-04
7.58E-04
kg/Mg
3.06E-01
9.96E-03
1.66E-04
4.46E-02
2.41E-05
7.53E-03
2.21E-03
9.77E-02
6.19E-02
4.34E-02
1.77E-03
6.51E-05
3.79E-04
SD/Fabric Filterb
Ib/ton
4.18E-03
2.13E-04
2.71E-04
5.81E-06
5.36E-05
9.85E-05
6.23E-04
1.89E-04
6.65E-02
8.69E-05
9.23E-05
kg/Mg
2.09E-03
1.15E-04
1.35E-04
2.91E-06
2.68E-05
4.92E-05
3.12E-04
9.47E-05
3.33E-02
4.34E-05
4.61E-05
SD/Carbon Injection/FFc
Ib/ton
2.62E-03
1.41E-04
1.25E-04
2.42E-05
7.73E-05
4.11E-04
7.38E-05
7.86E-03
3.58E-05
8.05E-05
kg/Mg
1.31E-03
7.04E-05
6.25E-05
1.21E-05
3.86E-05
2.06E-04
3.69E-05
3.93E-03
1.79E-05
4.03E-05
References 7-43. SCC
SD = Spray Dryer
FF = Fabric Filter
Source Classification Code.
-------
5j
VO
Table 2.6-18 (Metric and English Units). ROTARY KILN MEDICAL WASTE INCINERATOR EMISSION FACTORS
FOR DIOXINS AND FURANSa
(SCC 50100505, 50200505)
EMISSION FACTOR RATING = E
C/3
I
q
f
e.
Congener
2,3,7,8-TCDD
Total TCDD
Total CDD
2,3,7,8-TCDF
Total TCDF
Total CDF
Uncontrolled
Ib/ton
6.61E-10
7.23E-09
7.49E-07
1.67E-08
2.55E-07
5.20E-06
kg/Mg
3.30E-10
3.61E-09
3.75E-07
8.37E-09
1.27E-07
2.60E-06
SD/Fabric Filterb
Ib/ton
4.52E-10
4.16E-09
5.79E-08
1.68E-08
1.92E-07
7.91E-07
kg/Mg
2.26E-10
2.08E-09
2.90E-08
8.42E-09
9.58E-08
3.96E-07
SD/Carbon Injection/FFc
Ib/ton
6.42E-11
1.55E-10
2.01E-08
4.96E-10
1.15E-08
7.57E-08
kg/Mg
3.21E-11
7.77E-11
1.01E-08
2.48E-10
5.74E-09
3.78E-08
References 7-43. SCC = Source Classification Code.
SD = Spray Dryer
FF = Fabric Filter
-------
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
Bernardine'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, Bel ing Consultants,
Rockford, Illinois, December 1986.
17. J.E. McCormack, ARB 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. M.J. Bumbaco, Report on a Stack Sampling Program to Measure the Emissions of Selected
Trace Organic Compounds, Particulates, Heavy Metals, and HClfrom 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. Paniculate 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 Nonh 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. All 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 ISO 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 (O2) 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 (N2) 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
-------
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 in its vapor phase are diffusion, convection,
and displacement.
2.7A.I 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'^t)
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 (L^ 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
-------
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 fP/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:
(PPmv as hexane) (1 x 106) = C^MOC Ppmv as hexane
(corrected for air
Cc02 (PPmv) + CCH4 (PPmv) infiltration)
where:
= Total NMOC concentration in landfill gas, ppmv as hexane;
= CO2 concentration in landfill gas, ppmv.
= CH4 Concentration in landfill gas, ppmv; and
1 x 106 = Constant used to correct NMOC concentration to units of ppmv.
Values for CCQ, and CCHA can be 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
-------
To estimate total NMOC emissions, the following equation should be used:
QNMOC = 2 QcH4 * CNMOC/O * io6)
where:
QNMOC = NMOC emission rate, m3/yr;
QCH4 ~ CH4 generation rate, m3/yr (from the Landfill Air Emissions Estimation
model);
= Total NMOC concentration in landfill gas, ppmv as hexane; and
2 = Multiplication factor (assumes that approximately SO percent of landfill
gas is
The mass emissions per year of total NMOCs (as hexane) can be estimated by the following equation:
M - n * f 105°-
MNMOC - QNMOC * -7^
where:
0.2 "I
+T)J
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 25°C (75°F) 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 air 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 * io6)
where:
QNMOC = NMOC emission rate, m3/yr;
QCH4 = CH4 generation rate, m3/yr (from the Landfill Air Emission Estimation
model);
= NMOC concentration in landfill gas, ppmv; and
2 = Multiplication factor (assumes that approximately SO percent of landfill
gas is
7/93 Solid Waste Disposal 2.7-5
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Table 2.7-1. UNCONTROLLED LANDFILL GAS CONCENTRATIONS8
(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 (vinyl idene 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 HISTORY8
(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
-------
= QNMOC * (Molecular weight of compound)
(8.205xlO-5 m3-atm/mol-°K) (1000 g)(273 + T)
where:
INMOC = Individual NMOC mass emissions (Mg/yr);
QNMOC = NMOC emission rate (m3/yr); and
T = Temperature of landfill gas C*Q.
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 die 75 percent average.
Uncollected CH4, CO2, and NMOCs can be calculated with the following equation:
. _ Collection Efficiency
" HXJ
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 II-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 CONSTITUENTS8
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
a 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/dscfm
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
a 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-450/3-90-011 a. 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
-------
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 847315. 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
-------
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, OAQPS:ESD, 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
-------
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 rather 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, hi 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 NO,
by reaction of ammonia and NO on a catalytic surface to form N2 and Hfl. 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
600-800°F 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
-------
With the proliferation and advancement of NO, 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 hi Tables 3.1-1 and 3.1-2. There is some variation in 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
-------
TABLE 3.1-1. (ENGLISH UNITS)
EMISSION FACTORS FOR LARGE UNCONTROLLED GAS TURBINES'1
(Source Classification Codes)
Pollutant
Emission
Factor
Rating1"
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
C02d
TOC(as
methane)
SOX (as SOz)0
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
.94S
.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).
"teased 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 convened to SO2. S = percent sulfur in fuel.
7/93
Stationary Internal Combustion Sources
3.1-3
-------
TABLE 3.1-2. (METRIC UNITS)
EMISSION FACTORS FOR LARGE UNCONTROLLED GAS TURBINES'
(Source Classification Codes)
Pollutant
Emission
factor
Rating1"
Natural Gas
(SCC 20100201)
[grams/kW-hrc fng/I]
(power output) (fuel input)
Fuel Oil (i.e. Distillate)
(SCC 20100101)
[grams/kW-hr]c [ng/J]
(power output) (fuel input)
NOX
CO
C02d
TOC (as methane)
SO, (as SOz)"
PM (solids)
PM (condensables)
PM Sizing %
< .05 microns
< .10 microns
< .15 microns
< 20 microns
< .25 microns
< 1 micron
C
D
B
D
B
E
E
D
D
D
D
D
D
2.15
.52
546
.117
4.57S
.094
.11
190
46
48160
10.32
404S
8.30
9.72
15%
40%
63%
78%
89%
100%
3.41
.233
799
.083
4.92S
.185
.113
300
20.6
70520
7.31
434.3S
16.3
9.89
16%
48%
72%
85%
93%
100%
•References 1-8.
b>1D" 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.
"•Based on 100 percent conversion of the fuel carbon to CO2. CO2 [Ib/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.
CA11 sulfur in the fuel is assumed to be converted to SO2.
3.1-4
EMISSION FACTORS
7/93
-------
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]
(power
output)
NO, .50
CO .94
TOC (as methane)
NH3
NMHC
Formaldehyde
[Ib/MMBtu]
(fuel
input)
Steam Injection
(1.2 water/fuel ratio)
[grams/hr-hp]
(power
output)
.14 .44
.28 .53
[Ib/MMBtu]
(fuel
input)
.12
.16
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.
bAverage of 78 percent reduction of NO, through the SCR catalyst.
7/93
Stationary Internal Combustion Sources
3.1-5
-------
TABLE 3. M. (METRIC UNITS)
EMISSION FACTORS FOR LARGE GAS-FIRED CONTROLLED GAS TURBINES*
(Source Classification Code: 20100201)
EMISSION FACTOR RATING: C
Pollutant
Water Injection
(0.8 water/fuel ratio)
[grams/kW-nr]
(power output)
NO, .66
CO 1.3
TOC (as methane)
NH3
NMHC
Formaldehyde
[ng/J]
(fuel input)
Steam Injection
(1.2 water/fuel ratio)
[grams/kW-hr]
(power output)
61 .59
120 .71
[ng/n
(fuel input)
52
69
Selective
Catalytic
Reduction (with
water injection)
[ng/I]
(fuel input)
3.78"
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.
bAverage 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 TURBINES1
(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.
bCalculated 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/kW-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.
bCalculated 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.
7/93
Stationary Internal Combustion Sources
3.1-7
-------
TABLE 3.1-7. TRACE ELEMENT EMISSION FACTORS FOR DISTILLATE OIL-FIRED GAS TURBINES'
(Source Classification Code: 20100101)
EMISSION FACTOR RATING: Eb
Trace Element
PS/J
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
-------
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 NOT 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
-------
REFERENCES FOR SECTION 3.1 (concluded)
12. CEMS 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. II. 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
-------
3.2 HEAVY DUTY NATURAL GAS FERED 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 in 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
bum 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 bum 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. In general, NOX emissions increase with increasing
7/93 Stationary Internal Combustion Sources 3.2-1
-------
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 burn 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
-------
TABLE 3.2-1. (ENGLISH UNITS) CRITERIA EMISSION FACTORS FOR UNCONTROLLED
NATURAL GAS PRIME MOVERS'
(Source Classification Codes)
C/J
0
^
3
&
9
5
g-
Pollutant
[Rating]
Gas
(SCC
[grams/hp-
hr]
NO, [A] 1.3
CO [A] .83
CO2 [B]b 405
TOC [A] .18
TNMOC [A] .01
CH4 [A] .17
Turbines
20200201)
[Ib/MMBtu]
(fuel input)
2-Cycle
Lean Burn
(SCC 20200202)
[grams/hp-
hr]
.34 11
.17 1.5
110 405
.053 6.1
.002 .43
.051 5.6
[Ib/MMBtu]
(fuel input)
4-Cycle
Lean Bum
SCC
[grams/hp-
hr]
2.7 12
.38 1.6
110 405
1.5 4.9
.11 .72
1.4 4.1
[Ib/MMBtu]
(fuel input)
4-Cycle
Rich Bum
SCC
[grams/hp-
hr]
3.2 10
.42 8.6
110 405
1.2 1.2
.18 .14
1.1 1.1
[Ib/MMBtu]
(fuel input)
2.3
1.6
110
.27
.03
.24
s
c/3
"Reference 1-5. Emission factors are based on entire population. Emission factors for individual engines from specific
manufacturers may vary.
bBased on 100 percent conversion of the fuel carbon to CO2. C02[lb/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 natural gas prime movers controlled by combustion
modifications, NSCR, and SCR.
-------
S)
TABLE 3.2-2. (METRIC UNITS) CRITERIA EMISSION FACTORS FOR UNCONTROLLED
NATURAL GAS PRIME MOVERS"
(Source Classification Codes)
I
CO
5
z
1
Q
Pollutant
[Rating]
I* ^******OJ
Gas
Turbines
(SCC 20200201)
[grams/
kW-hr]
NOX [A] 1.70
CO [A] 1.11
C02 [D]b 741
TOC [A] .24
TNMOC [A] .013
CH4 [A] .228
[ng/J]
(fuel input)
2-Cycle
Lean Burn
(SCC 20200202)
[grams/
kW-hr]
145 14.79
71 2.04
47,424 741
22.8 8.14
.86 .58
21.9 7.56
[ng/J]
(fuel input)
4-Cycle
Lean Bum
SCC
[grams/
kW-hr]
1165 15.49
165 10.29
47,424 741
662 5.50
47.3 .76
615 4.73
[ng/J]
(fuel input)
4-Cycle
Rich Burn
SCC
[grams/
kW-hr]
1286 13.46
1195 11.55
47,424 741
447 1.66
60.2 .19
387 1.48
[ng/J]
(fuel input)
980
697
47,424
116
12.9
103
"References 1-5. Emission factors are based on entire population. Emission factors for individual engines from specific
manufacturers may vary.
"Based on 100 percent conversion of the fuel carbon to CO2. CO2[lb/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 C02 emission factors are also applicable to natural gas prime movers controlled by combustion
modifications, NSCR, and SCR.
-------
TABLE 3.2-3. (ENGLISH AND METRIC UNITS) NON-CRITERIA EMISSION FACTORS
FOR UNCONTROLLED NATURAL GAS PRIME MOVERS8
(Source Classification Code: 20200202)
EMISSION FACTOR RATING: Eb
Pollutant
2-Cycle Lean Bum
[grams/kW-hr]
[ng/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.
"All 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
-------
£ TABLE 3.2-4. (ENGLISH AND METRIC UNITS) EMISSION FACTORS FOR CONTROLLED NATURAL GAS PRIME MOVERS:
AN COMBUSTION MODIFICATIONS ON TWO-STROKE LEAN BURN ENGINE"
(Source Classification Code:
20200202)
EMISSION FACTOR RATING: Eb
Pollutant Baseline
[g/hp-hr] [g/kW-hr] [Ib/MMBtu]
NOX 9.9 13 2.9
CO .94 1.3 .28
w TOC 7.5 10 2.2
§ TNMOC 5.2 7.0 1.6
C/3
§ CH4 2.3 3.1 .68
25
TI PM (total = front+back) .16 .21 .046
Q (solids = front half) .098 .13 .029
s
g; (condensibles = back half) .057 .076 .017
Increased A/F Ratio With Intercooling
[ng/J] [g/hp-nr] [g/kW-hr] [Ib/MMBtu] [ng/J]
1300 5.1 6.8 1.5 650
120 1.5 2.1 .46 200
960 8.5 11 2.6 1100
670 6.0 8.1 1.8 780
290 2.5 3.4 .75 320
20 .18 .25 .055 24
13 .13 .17 .038 16
7.3 .058 .078 .017 7.3
"Reference 6. CO2 emissions are not affected by control.
bAll emission factor qualities are "E" due to a very limited data set, for one engine, and may not be accurate for source
populations.
s
-------
<: IADMI j.zo. i.in\»juon twu r
u>
oc,iru.v_ urNiioj cjyudoiufi r/\\-* i VJK.O rui\. \*\jri H\\JL,L^E,U nf\i «JR/\L, vj/\o riuivic ivivy vcno.
NSCR ON FOUR-CYCLE RICH BURN ENGINE8
EMISSION FACTOR RATING: Eb
Pollutant
[g/hp-hr
NO, 7.8
CO 12
| TOC .33
| NH3 .05
| C7 -> C16 .019
1 C16+ .017
S PM (solids = front half) .003
§-
g Benzene
g-
3 Toluene
00
§ Xylenes
* Propylene
Naphthalene
Formaldehyde
Acetaldehyde
Acrolein
Inlet
] [g/kW-hr] [Ib/MMBtu]
10 1.8
16 2.8
.44 .079
.07 .012
.026 .0042
.029 .004
.004 .0007
7.1EE4
2.3EE4
<5.9E-5
-------
00
TABLE 3.2-6. (ENGLISH AND METRIC UNITS) EMISSION FACTORS FOR CONTROLLED NATURAL GAS PRIME MOVERS:
SCR ON FOUR-CYCLE LEAN BURN ENGINE'
EMISSION FACTOR RATING: Eb
Pollutant
NO,
CO
NH3
C7 -> C16
C16+
Inlet
[g/hp-hr]
19
1.2
.007
.013
[g/kW-hr]
26
1.6
.009
.017
[Ib/MMBtu]
6.4
.38
.0023
.0044
[ng/J]
2800
160
.99
1.9
Outlet
[g/hp-hr]
3.6
1.1
.27
.0031
.0024
[g/kW-hr]
4.8
1.5
.36
.0042
.0032
[Ib/MMBtu]
1.2
.37
.091
.0013
.0008
[ng/J]
510
160
39
.56
.34
£2 "Reference 8. CO2 emissions are not affected by control.
g bAll emission factor qualities are "E" due to a very limited data set. "E" rated emission factors may not be applicable to specific facilities or populations.
K
03
TABLE 3.2-7 (ENGLISH AND METRIC UNITS) EMISSION FACTORS FOR CONTROLLED NATURAL GAS PRIME MOVERS:
"PCC" AND "CLEAN BURN" ON TWO-CYCLE LEAN BURN ENGINE"
(Source Classification Code: 20200202)
EMISSION FACTOR RATING: C
Pollutant
NO,
CO
TOC
TNMOC
CH,
"CleanBurn11
fg/hD-hr]
2.3
1.1
2.5
.12
2.4
Fg/kW-hrl
3.1
1.5
3.4
.16
3.3
rib/MMBtul
.83
.30
.77
.15
.62
fne/Jl
360
130
330
65
260
F^D-hr]
2.9
2.4
6.4
.88
5.5
"PreCombustion
fg/kW-hrl
3.9
3.3
8.6
1.2
7.4
Chamber"
rib/MMBtul
.85
.67
1.8
.25
1.5
Fng/Jl
370
290
760
110
650
•si
\S 'Reference 9. CO2 emissions are not affected by control.
-------
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 South West 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, Inc., 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 NO, 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 South West 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
-------
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]
SO, [D]
Paniculate [D]
C02 [B]c
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 (BSFC) 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 ENGINES8
(Source Classification Codes)
Pollutant
[Rating]"
NOX [D]
CO[D]
SOX [D]
Paniculate [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
-------
TABLE 3.3-3. (ENGLISH AND METRIC UMTS) SPECIATED ORGANIC COMPOUNDS AND
AIR TOXIC EMISSION FACTORS FOR UNCONTROLLED DIESEL ENGINES3
(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
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)
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.
*"'£" 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.
cData are based on one engine.
7/93
Stationary Internal Combustion Sources
3.3-5
-------
TABLE 3.3-4. DIESEL EMISSION CONTROL TECHNOLOGIES8
Technology
Affected Parameter"
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
Paniculate 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
NOX
NOX, PM
PM
NOX, PM
PM
NOX, PM
NOX
NOX
NOX
PM, Wear
PM
NOX
HC, CO, PM
"Reference 4.
"NO, = Nitrogen oxides; PM = Paniculate matter, HC = Hydrocarbons;
CO = Carbon monoxide; BSFC = Brake specific fuel consumption.
3.3-6
EMISSION FACTORS
7/93
-------
References for Section 3.3
1. Hare, C.T. and KJ. 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 KJ. 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 Paniculate Emissions from Heavv-Dutv Engines.
Draft Report by Acurex Environmental Corporation for the California Air Resources Board,
Sacramento, CA, March 1992, CARB Contract Al32-085.
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. Osbom, W.E., and M.D. McDannel, Emissions of Air Toxic Species: Test Conducted Under
AB2588 for the Western States Petroleum Association. Report prepared by Camot for Western
States Petroleum Association (WSPA), Glendale, CA, May 1990, CR 72600-2061.
7/93 Stationary Internal Combustion Sources 3.3.7
-------
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 hi 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. 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
are 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 (NO,), 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 (SOX) 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
-------
TABLE 3.4-1. (ENGLISH UNITS) GASEOUS EMISSION FACTORS FOR LARGE STATIONARY DIESEL
AND ALL STATIONARY DUAL FUEL ENGINES"
(Source Classification Codes)
Pollutant
NO,
CO
SO,"
CO2e
^f /ac ptl \
, ^oo V^fl^/
Methane
Nonmethane
[grams/hp-hr]
(power output)
11
2.4
3.67S,
524
0.32
0.03
0.33
Diesel Fuel
(SCC 20200401)
[Ib/MMBtu]
(fuel input)
3.1
0.81
1.01S,
165
0.09
0.01
0.10
Emission Factor
Rating0
C
C
B
B
C
E*
E*
Dual Fuel"
(SCC 20200402)
[grams/hp-hr]
(power output)
9.2
2.3
0.184S, + 4.34S2
350
2.4
1.8
0.6
[Ib/MMBtu]
(fuel input)
3.1
0.79
0.05S, + 0.895S2
110
0.8
0.6
0.2
Emission
Factor Rating0
D
D
B
B
D
Eb
Eh
'Data are based on uncontrolled levels for each fuel from references 4, 5, and 6. When necessary, the average heating value of diesel was assumed to be
19300 Btu/lb with a density of 7.1 Ib/gal. The power output and fuel input values were averaged independently from each other due to the use of actual
Brake Specific Fuel Consumption values for each data point and the use of data that may have enough information to calculate only one of the two
emission factors (e.g., if there was enough information to calculate Ib/MMBtu, but not enough to calculate the g/hp-hr). The emission factors are based on
averages across all manufacturers and duty cycles. The actual emissions from a particular engine or manufacturer could vary considerably from these
levels.
bDual fuel is based on a mixture of 95 percent natural gas and 5 percent diesel fuel.
C"D" and "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.
"D" and "E" rated emission factors may not be suitable for specific facilities or populations and should be used with care.
•"Emission factors are based on the assumption that all sulfur in the fuel is converted to SO2. S, = percent sulfur in diesel fuel; S2 = percent sulfur in gas.
'Based on assumed 100 percent conversion of carbon in fuel to CO2 with 87 weight percent carbon in diesel, 70 weight percent carbon in natural gas, dual
fuel mixture of 5 percent diesel with 95 percent natural gas, average brake specific fuel consumption of 7000 Btu/hp-hr, diesel heating value of 19,300
Btu/lb, and natural gas heating value of 23,900 Btu/lb.
Total Organic Compounds.
EBased on emissions data from one engine.
bBased on the assumption that nonmethane organic compounds are 25 percent of TOC emissions from dual fuel engines. Molecular weight of nonmethane
gas stream is assumed to be that of methane.
£
-------
TABLE 3.4-2. (METRIC UNITS) GASEOUS EMISSION FACTORS FOR LARGE STATIONARY DIESEL AND
ALL STATIONARY DUAL FUEL ENGINES8
(Source Classification Codes)
Pollutant
Diesel Fuel
(SCC 20200401)
[g/kW-hr]
(power output)
NO, 14
CO 3.2
[ng/J]
(fuel input)
U22
349
Emission Factor
Rating0
Dual Fuelb
(SCC 20200402)
[g/kW-lir]
(power output)
C 12.3
C 3.1
[ng/J]
(fuel input)
1,331
340
Emission Factor
Rating0
D
D
GO
HH
o
I
g
CO
SO."
CO2C
TOC,f (as CHJ
Methane
Nonmellianc
4.92S,
703
0.43
0.04
0.44
434S,
70,942
38
4
45
B
B
C
E«
E«
0.25S, + 4.34S,
469
3.2
2.4
0.8
21.7S, + 384S,
47,424
352
240
80
B
B
D
Bb-
Eh
'Data are based on uncontrolled levels for each fuel from references 4, 5, and 6. When necessary, the average heating value of diesel was assumed to be
19300 Btu/lb with a density of 7.1 Ib/gal. The power output and fuel input values were averaged independently from each other due to the use of actual
Brake Specific Fuel Consumption values for each data point and the use of data that may have enough infoiuiation to calculate only one of the two
emission factors (e.g., if there was enough information to calculate Ib/MMBtu, but not enough to calculate the g/lip-hr). The emission factors are based on
averages across all manufacturers and duty cycles. The actual emissions from a particular engine or manufacturer could vary considerably from these
levels.
bDual fuel is based on 95 percent natural gas and 5 percent diesel fuel.
C"D" and "E" rating for emission factors are due to limited data sets, inherent variability in the population and/or a lack of documentation of lest results. "D"
and "E" rated emission factors may not be suitable for specific facilities or populations and should be used with care.
Emission factors are based on the assumption that all sulfur in the fuel is converted to S02. S, = percent sulfur in fuel oil; S2 = percent sulfur in gas.
'Based on assumed 100 percent conversion of carbon in fuel to CO2 with 87 weight percent carbon in diesel, 70 weight percent carbon in natural gas, dual
fuel mixture of 5 percent diesel with 95 percent natural gas, average brake specific fuel consumption of 7000 Btu/hp-hr, diesel heating value of 19,300
Blu/lb, and natural gas heating value of 23,900 Btu/lb.
Total Organic Compounds.
"Based on emissions data from one engine.
hBased on the assumption that nonmethane organic compounds are 25 percent of TOC emissions from dual fuel engines. Molecular weight of
nonmcthane gas stream is assumed to be that of methane.
-------
TABLE 3.4-3. (ENGLISH AND METRIC UNITS) SPECIATED ORGANIC COMPOUND
EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES8
(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
1.20E-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 ENGINES8
(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( 1 ,2, 3-cd)pyrene
Dibenz(a,h)anthracene
Benzo(g4i,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) PARTICULATE AND PARTICLE SIZING
EMISSION FACTORS FOR LARGE STATIONARY DIESEL ENGINES"
(Source Classification Code: 20200401)
(Emission Factor Rating: E)b
Pollutant
Paniculate 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 panicle 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 ENGINES"
(Source Classification Codes)
Control Approach
Diesel
(SCC 20200401)
Percent NOX
Reduction
ABSFC,"
Percent
Dual Fuel
(SCC 20200402)
Percent
NO,
Reduction
ABSFC,b
Percent
Derate
Retard
Air-to-Fuel
Water Injection (H2O/fuel ratio)
Selective Catalytic Reduction (SCR)
10%
20%
25%
2°
4°
8°
3%
±10%
50%
<20
5-23
<20
<40
28^5
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., O.K. Stone, and G.S. Shareef, Sourcebook: NO, 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) in 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 -33°C (-27°F). 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
NATURAL GAS ••
^
FUEL
STEAM "•
AIR *
EMISSIONS
3-01-003-09
A PROCESS ^
CONDENSATE
t
STEAM
CTDIDDCD
Ol nlrrCn
f
STEAM
FEEDSTOCK
DESULFURIZATION
*
PRIMARY REFORMER
*
SECONDARY
REFORMER
I
HIGH TEMPERATURE
SHIFT
LOW TEMPERATURE
SHIFT
r
CO2 ABSORBER
;
METHANATION
T
AMMONIA SYNTHcSIS
t
NH3
3-01-003-05 |
FUEL COMBUSTION
EMISSIONS
i
t
3-01-003-06 /natural oas^
3-01-003-07 (oil fired)
EMISSIONS
3-01-003-008
* CO^ SOLUTION
„ REGENERATION
t
STEAM
PURGE GAS VENTED TO
*• PRIMARY REFORMER
FOR FUEL
I i
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
540°C (1004°F). 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 (CO^. 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
540°C (1004°F). 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
(680T) 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 110°C (410 to 230°F) 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: monoethanolamine (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 600°C (752 to 1112°F) 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
38°C (100°F).
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
0°C (32°F). 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
180°C (356°F) 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 -33°C (-27°F) 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 (CO2) 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
-------
Table 5.2-1 (Metric and English Units).
UNCONTROLLED EMISSION FACTORS FOR A TYPICAL AMMONIA PLANT*
>fc
p
(D
g.
O
EL
3
w
_
g.
Emission Point
(SCC)
CO
kg/Mg Ib/ton
Desulfurization unit
regeneration11 6.9 13.8
(SCC 3-01-003-05)
Carbon dioxide regenerator
(SCC 3-01-003-008) l.O11 2.011
Condensate steam stripper
(SCC 3-01-003-09
Emission
Factor
Rating
kg/Mg
E 0.0288c-d
E
SO2
Ib/ton
0.0576c'd
Emission
Factor
Rating
Total Organic Compounds
kg/Mg lb/
E 3.6 7
Emission
Factor
ton Rating
kg/Mg
2 E
0.52e 1.04 E 1.0
0.6f 1
2 E 1.1
Ammonia
Ib/ton
2.0
2.2
Emission
Factor
Rating
CO2
Emission
Factor
kg/Mg Ib/ton Rating
E 1220 2440 E
E 3.48 6.88 E
j| "References 1,3. SCC = Source Classification Code
cAssumed worst case, that all sulfur entering tank is emitted during regeneration.
dNormalized to a 24-hour emission factor. Total sulfur is 0.0096 kg/Mg (0.019 Ib/ton).
e0.05 kg/Mg (0.1 Ib/ton) is monoethanolamine.
fMostly methanol, which is classified as Non Methane Organic Compound and a hazardous air pollutant (HAP).
hMostly CO.
K>
-------
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
-------
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 (Cl?) is produced at the positive electrode (anode) and the caustic
soda (NaOH) and hydrogen (H2) 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 (NaCl) 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
-------
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 die 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
-------
WATER
SALT
SALT
j (BRINE)
BRINE
SATURATIOH
RAW BRINE
PRECIPITATION
FILTRATION
CHLORINE
PURIFIED BRINE
HEAT
EXCHANGE
SALT
BRINE
SATURATION
SALT
HEAT
EXCHANGE
HYDROGEN
ELECTROLYSIS
CONCENTRATION
COOLING
STORAGE
SODIUH
HYDROXIDE
HYDROGEN
OXYGEH
REMOVAL
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
-------
DILUTED BRINE
CAUSTIC
SOLUTION
DECHLORINATION
HYDRO-
CHLORIC
ACID
ANOLYTE
WATER AMALGAM
CAUSTIC
SOLUTION
COOLINO
MERCURY
REMOVAL
STORAGE
SODIUM HYDROXIDE
I SALT
BRINE
SATURATION
RAW BRINE
PRECIPITATION
PRECIPITANTS
FILTRATION
RESIDUE
COOLINO
HYDROCHLORIC ACID
ELECTROLYSIS
CHLORINE GAS
MERCURY
AMALGAM
DECOMPOSITION
HYDROGEN
COOLING
COOLING
MERCURY
REMOVAL
DRYING
COMPRESSION
HYDROGEN
CHLORINE
5.5-4
Figure 5.5-2 Simplified diagram of the mercury cell process
EMISSION FACTORS
7/93
-------
Table 5.5-1 (Metric Units).
EMISSION FACTORS FOR CHLORINE FROM CHLOR-ALKALI PLANTS*
Source (SCC)
Chlorine Gas
kg/Mg
of Chlorine
Produced
Emission
Factor
Rating
Liquefaction blow gases
Diaphragm cell (SCC 3-01-008-01)
Mercury cell (SCC 3-01-008-02)
Water absorber15 (SCC 3-01-008-99)
Caustic scrubberb (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)
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 PLANTS8
Source (SCC)
Chlorine Gas
kg/Mg
of Chlorine
Produced
Emission
Factor
Rating
Liquefaction blow gases
Diaphragm cell (SCC 3-01-008-01)
Mercury cell (SCC 3-01-008-02)
Water absorber15 (SCC 3-01-008-99)
Caustic scrubber15 (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)
20 to 100
40 to 160
1.66
0.012
8.2
17.3
5.4
E
E
E
E
E
E
aReference 4. Units are Ib of pollutant/ton .
bControl devices.
7/93
Chemical Process Industry
5.5-5
-------
Table 5.5-2 (Metric and English Units).
EMISSION FACTORS FOR MERCURY FROM MERCURY CELL CHLOR-ALKALI PLANTS8
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 Color-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 Odor-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
-------
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 in 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 - NajSC^ + HC1 (3)
2NaCl + H2SO4 - Na^C^ + 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 -* FejOj + 3H2O + 6HC1 (7)
7/93 Chemical Process Industry 5.7-1
-------
5) From incineration of chlorinated organic waste:
C4H6C12 + 502 -> 4CO2 + 2H20 + 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
CHLORINATION
PROCESS
t
HCI
ABSORPTION
1
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
-------
TABLE 5.7-1 (METRIC UNITS)
EMISSION FACTORS FOR HYDROCHLORIC ACID MANUFACTURE5
Type of Process
(SCC)
HC1 Emissions
kg/Mg
HC1
Produced
Emission
Factor
Rating
Byproduct hydrochloric acid
With final scrubber (3-011-01-99) 0.08 E
Without final scrubber (3-011-01-99) 0.90 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
-------
References for Section 5.7
1. Encyclopedia of Chemical Technology, Third Edition, Volume 12, John Wiley and Sons, New
York, 1978.
2. Ullmann'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
-------
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 250°C (390 to 480°F). 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 products—hydrogen fluoride and excess
H2SO4 from the primary reaction, silicon tetrafluoride (SiF4), sulfur dioxide (SO^, carbon dioxide
(CO^, and water produced in secondary reactions—are 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 (H^iFg). 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. Paniculate in the gas
7/93 Chemical Process Industry 5.8-1
-------
o
to
Tl
f
o
S 1
- I
I §
O 3.
Z o
-n 8
TJ
3
o
3
o.
PRINCIPAL EMISSION LOCATIONS
FLUORSPAR
CALCIUM SULFATE
-------
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
-------
Table 5.8-1 (Metric Units).
EMISSION FACTORS FOR HYDROFLUORIC ACID MANUFACTURE*
Operation And Controls
Control
efficiency
Emissions
Gases
kg/Mg
Acid
Produced
Emission
Factor
Rating
Particulate (Spar)
kg/Mg
Fluorspar
Produced
Emission
Factor
Rating
Spar Dryingb (SCC 3-01-012-03)
Uncontrolled
Fabric filter
Spar Handling Silosc
Uncontrolled
Fabric filter
(SCC 3-01-012-04)
Transfer Operations (SCC 3-01-012-05)
Uncontrolled
Covers, additives
Tail Gasc (SCC 3-01-012-06)
Uncontrolled
0
99
0
99
0
80
0
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 (
0.3 (S02)
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 (kg/Mg)
1 13,600 Mg HF 53
2 18,100 MgHF 65
3 45,400 Mg HF 21
4 10,000 Mg HF 15
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.
5.8-4
EMISSION FACTORS
7/93
-------
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
45.0
0.2 (HF)
0.3
0.5 (SO2)
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 (Ib/ton)
1 15,000 ton HF 106
2 20,000 ton HF 130
3 50,000 ton HF 42
4 11,000 ton HF 30
"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.
7/93
Chemical Process Industry
5.8-5
-------
References for Section 5.8
1. Screening Study On Feasibility Of Standards Of Performance For Hydrofluoric Add
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
-------
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 in 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 800°C (1380 to 1470°F) as it passes through a catalytic convenor, 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 900°C (1380 to 1650°F). 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
-------
EMISSION
POINT
TAIL
COMPRESSOR
EXPANDER
J-,GAS
3-01-01342
EFFLUENT
STACK
AMMONIA
AIR
,PREHEATER
NOV EMISSIONS —-
XCONTROL
FUEL
IsnCUlA/llUN '
NITS/-N
M 1 L.
A V / A r
T ^-^ \ ">
4 r^ r
NITRIC OXIDE
GAS
I
c
4
/
)
>
NI /
5
0
_j
WATER
STEAM
ENTRAINED
MIST
SEPERATOR
SECONDARY AIR
AIR
GEN
)E
irvv»i IMA
lAAJLJNu
WATER
A * ")
f C
— I )
C
COOLER
w
I ^
^
NO,
Rxn3
"ABSORPTidN
TOWER
— h.
CONDENSER
PRODUCT
(50-70%
HN04
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
-------
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 38°C
(100°F) 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:
3NO2 + H2O - 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
(392°F). 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
-------
distillation. The weak nitric acid cannot be concentrated by simple fractional distillation. The
distillation must be carried out in 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 die 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.
HNOS>NO,,<
COOLING
WATER
INERT,
UNREACTED
BLEACHER
^
1 CONDENSI
)
(
)
C ,
STRONG
NITRIC ACK
3R
AIR
| ^_
'
O^NO
)
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 die 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
-------
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 NO2) 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
7/93 Chemical Process Industry 5.9-5
-------
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
Uncontrolled5'6 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 Scrubber* N/A
High Strength Acid Plant* N/A
1.1 2.2 E
5 10 E
aAssumes 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.
b Reference 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%).
c Single-stage Pressure Process.
d Reference 4. Fuel is assumed to be natural gas. Based on data from 7 plants, with average production rate of
309 Mg (100% HNO3)/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 °F) {range 25 - 32°C (78 - 90°F)}, and the average exit pressure is 586 kPa (85 psig) {range 552 - 648 kPa
(80 - 94 psig)}.
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 33°C
(91 op) {range 28 - 37°C (83 - 98°F)>, 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.
kReference 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
-------
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 (HjPO^ 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. 1 1 .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 • 1A
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:
Ca3(PO4)2 + 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.
7/93 Chemical Process Industry 5.11-1
-------
I/I
to
•fl
ff
w
oo
3
z
c
<
"S-
o
oo
O
o'
§
SI
•a
WASH
WATER
QYPSUM
TO VACUU
TO 1ST STAGE
EVAPORATOR
QYPSUM SLURY
TO POND -*
TO SCRUBBER
-------
VACUUM
TO VACUUM*
AND HOT WELL
TO ACID PLANT -*
HVDROFLUOSIUC AGIO
Figure 5.11 -IB. 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 P2C>5- 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 2760°C (3000 to 5000°F) 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
-------
l/l
1/9
00
N-4
O
•fl
•fl
f
3
l/l
AIR
w
Q ^
B-
I
E.
•o
•O
O
VI
O
8
CL
T3
s
I I
STACK
EFFLUENT
(Ala H3PO4 MIST)
BLOWER
STACK EFFLUENT
ACID TREATING PLANT
(Ala H2S)
HYDROGEN SULFIDE,
SODIUM HYDRO-
SULFIDE. OR
SODIUM SULFIDE
PRODUCT
IP-
ACID TO
STORAGE
PHOSPHORUS
COMBUSTION
CHAMBER
BURNING AND HYDRATKDN SECTION
PUMP
COOUNQ WATER
AIR TO
SPARQER
BLOWER
ACID TREATING SECTION
(USED IN THE MANUFACTURE OF ACID
FOR FOOD AND SPECIAL USES)
-------
This is usually done with high-pressure drop demistors.
P4 + 5O2 -» 2P2O5 (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 paniculate emissions from process equipment were measured for one digester and for one
filter. As much as 5.5 kilograms of paniculate 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 paniculate, three to six percent were fluorides.
Paniculate emissions occurring from phosphate rock handling are discussed in Section 8.18,
Phosphate Rock Processing.
7/93 Chemical Process Industry 5.11-5
-------
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 (/xm). It is not uncommon for as much as half of the total phosphorus pentoxide
(P2OS) 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 in 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 PRODUCTION11
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 Filter0 (SCC 3-01-016-99)
Belt Filter Vacuum Pumpc (SCC 3-01-016-99)
Gypsum settling and cooling pondsd'e (SCC 3-01-016-02)
1.9xlO'3 3.8 xlO'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 O.lSxlO'3 B
Site specific Site specific
SCC = Source Classification Code
b Reference 8-13
c 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.
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."
5.11-6
EMISSION FACTORS
7/93
-------
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 Pumpc (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
P20s
Produced
0.38
0.0044
0.064
0.015
Site
specific
Emission
Factor
Rating
B
C
C
C
8 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) P2OS 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."
7/93
Chemical Process Industry
5.11-7
-------
Table 5.11-3. (Metric and English Units).
CONTROLLED EMISSION FACTORS FOR THERMAL PHOSPHORIC ACID PRODUCTION*
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 (SCC3-0 1-0 17-04) 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
a SCC = Source Classification Code.
b Reference 6.
References for Section 5.11
1. "Phosphoric Acid", Chemical and Engineering News. March 2, 1987.
2. Sulfuric/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
7/93
-------
9. Summary Of Emission Measurements - East Phos Acid, 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
-------
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 Soap1'3'6
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
-------
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 fatty acid, which is then neutralized with a caustic solution containing sodium hydroxide
(NaOH). The blended slurry is held in 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 400°C (600 to 750°F). 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
-------
•»J
VO
Steam •*
9
CD
3
a
o.
Cfl
-q
f
Ul
o
CA
8
51
Cfl
Cfl
O
•§
Cfl
Steam
Conventional
soap finishing:
bar, flake or
powder
Evaporators
Fatty adds
Ul
-------
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 paniculate 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 paniculate 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 paniculate 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 panicles. 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
-------
I
8
yi
N»*
Ui
Receiving, Storage
and Transfer
9
i
I
Surfactants:
LAS, slurry alcohols,
Builders:
silicates, and
carbonates
Additives:
Perfumes dyes
anti-caking agents
Slurry Preparation
Spray Drying
Blending and Packing
Finished
detergents
to warehouse
-------
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 Efficiency
(%)
Uncontrolled
Cyclone 85
Cyclone with:
Spray chamber 92
Packed scrubber 95
Venturi scrubber 97
Wet scrubber 99
Wet scrubber/ESP 99.9
Packed bed/ESP 99
Fabric filter 99
Paniculate
kg/Mg. Ib/ton
of Product of Product
45 90
7 .14
3.5 7
2.5 5
1.5 3
0.544 1.09
0.023 0.046
0.47 0.94
0.54 1.1
Emission
T^ .4.
Factor
Rating
Eb
Eb
Eb
Eb
Eb
Eb
Eb
Ec
Eb
aSome 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
-------
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,
77, (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
-------
5.16 SODIUM CARBONATE
5.16.1 General
Sodium carbonate (Na2CO3), 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 (NH4) 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 in water and then treated as brine. The liquid is filtered to remove
insoluble impurities before the sodium sesquicarbonate (Na^CO^ • 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 in 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
-------
COHTROL
DEVICE
CONTROL
DEVICE
TRONA_
ORE
1
CRUSHERS
AND
SCREENS
DKSOLVER
VACUUM
CRYSTALLIZER
CENTRIFUGE
i
1
CALCINER
DRY
SODIUM
CARBONATE
Figure 5.16-1 Flow diagram for sesquicarbonate sodium carbonate processing
DRY
SODIUM
CARBONATE
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 (N^SO^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 paniculate matter from individual processes and process
5.16-2
EMISSION FACTORS
7/93
-------
components are quantified in Table 5.16-1 on a controlled (as-measured) basis. Emissions of total
paniculate matter from these same processes are quantified in Table 5.16-2 on an uncontrolled basis.
No data quantifying emissions of organic condensible paniculate matter from sodium carbonate
manufacturing processes are available, but this portion of the paniculate 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.
Paniculate 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. Paniculate emissions from the ore and
product handling operations are typically controlled by either venturi scrubbers or baghouse filters.
These control devices are an integral pan 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
-------
Table 5.16-1 (Metric Units)
PARTICULATE MATTER: CONTROLLED BASIS
Process (SCC Code)
Ore mining0 (3-01-023-99)
Ore crushing and screening0 (3-01-023-99)
Ore transfer0 (3-O1-O23-99)
Monohydrate process: rotary ore calciner
(3-O1-O23-04/05)
Sesquicarbonate process: rotary calciner
(3-O1-023-99)
Sesquicarbonate process: fluid-bed calciner
(3-01-023-99)
Rotary soda ash dryers (3-01-023-06)
Fluid-bed soda ash dryers/coolers (3-01-023-07)
Soda ash screening (3-01-023-99)
Soda ash storage/loading and unloading0
(3-01-023-99)
Filterable8
kg/Mg
of
Product
0.0016
0.0010
0.00008
0.091
0.36
0.021
0.25
0.015
0.0097
0.0021
Emission
Factor
Rating
C
D
E
A
B
C
C
C
E
E
Totalb
kg/Mg
of
Product
N/Ad
0.0018
0.0001
0.12
0.36
N/Ad
0.25
0.019
0.013
0.0026
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.
5.16-4
EMISSION FACTORS
7/93
-------
Table 5.16-1 (English Units)
PARTICULATE MATTER: CONTROLLED BASIS
Ib
Process (SCC Code) Prc
Filterable8
/ton Emission
of Factor
xiuct Rating
Ore mining6 (3-01-023-99) 0.0033 C
Ore crushing and screening0 (3-O1-023-99) 0.0021 D
Ore transfer0 (3-01-023-99) 0.0002 E
Monohydrate process: rotary ore calciner 0
(3-01-023-O4/05)
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.
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.
d N/A = data not available.
7/93
Chemical Process Industry
5.16-5
-------
TABLE 5.16-2
PARTICULATE MATTER: UNCONTROLLED BASIS
Process (SCC
Ore mining (3-01-023-99)
Nominal
Control
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
Sesquicarbonate process: rotary calciner (3-01-023-99)
Sesquicarbonate process: fluid-bed
calciner (3-01-023-99)
Rotary soda ash dryers (3-O1-023-06)
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) 99 9
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 DIOXIDE8
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
* 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
-------
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: Rh6ne-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. "Rhfine-Poulenc Wyoming Co. Paniculate Emission Compliance Program," TRC
Environmental Measurements Division, Englewood, CO, 21 May 1990.
11. "Rh6ne-Poulenc Wyoming Co. Paniculate 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
-------
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 (H2SO4) 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
7/93 Chemical Process Industry 5.17-1
-------
Ul
•fl
g
•fl
f
o
E.
8
I
en s
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51
TJ
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| HEAT EXCHAf*
«-. SULFUR CONVERTER
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fH~~" ^/COMBUSTIONS A~A i ^^^^H
V ) "I CHAMBER J ( ) ^===J
AIR Wn ACID WA2T5 cP ' •" ^
TO STORAGE BUiLtM |
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STACK ACID MIST
fl , r->
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FINAL
iSS,^ ABSOHBhH ECONOMIZER
EQUIPMENT < — '
*
t
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S0o+ r PRODUCT t u OQ
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i
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INTERPASS
* ABSORBER
SO 3 98-99%
H^SO,,
i i 2 A
OLEUM
TO
STORAGE
-------
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 absorption 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 Emissions4'6-7
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
-------
00
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^4
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S02
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STACK
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SO,
HYDROGEN SULFIDE
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BATE®
LERS
AIR
1.
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TOWER
4
TO WASTE
TREATMENT
93S ACID
TO STORAGE
SO,
-------
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 430°C (806°F), 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 truck 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 PLANTS8
s
SO2 to SO3 kg
Conversion Efficiency
(%) Pr<
O2 Emissions1*
/Mg Ib/ton
of of
aduct 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
-------
SULFUR CONVERSION, % feedstock sulfur
99.92 99.7 99.0 98.0 97.0 96.0 95.0
10,000
100
6070 90
80
1.5 2 2.5 3 4 5 6 78 910 15 20 25 30 40
SO2 EMISSIONS, Ib/ton of 100% H^SC^ 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
(CO£, 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.
7/93 Chemical Process Industry 5.17-7
-------
Table 5.17-2 (Metric and English Units).
UNCONTROLLED ACID MIST EMISSION FACTORS FOR SULFURIC ACID PLANTS*
Raw Material
Oleum
Produced,
% total
output
Emissions'*
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.
b Emissions 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* (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.
bReference 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 Of Sulfuric Acid Mist Emissions From Existing Sulfuric Acid
Production Units, EPA-450/2-77-019, U. S. Environmental Protection Agency, Research
Triangle Park, NC, September 1977.
3. Atmospheric Emissions From Sulfuric 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
-------
5. Review Of New Source Performance Standards For Sulfitric 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, Sulfuric Acid Plant, Entropy Environmentalists, Inc.,
Research Triangle Park, NC, January 1983.
13. Source Emissions Test: Sulfuric Acid Plant, Ramcon Environment^ Corporation, Memphis, TN,
October 1989.
14. ^Mississippi Chemical Corporation, Air Pollution Emission Tests, Sulfuric Acid Stack,
Environmental Science and Engineering, Inc., Gainesville, FL, 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.
7/93 Chemical Process Industry 5.17-9
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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 1540°C
(1800 to 2800°F) 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 315°C (400 to 600°F).
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
7/93 Chemical Process Industry 5.18-1
-------
SULFUR
CONDENSER
SPENT
CATALYST
ADDITIONAL CONVERTERS/CONDENSERS TO
ACHIEVE ADDITIONAL RECOVERY OF
ELEMENTAL SULFUR ARE OPTIONAL AT THIS
POINT
Figure 5.18-1 Typical Glaus 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 air 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
7/93
-------
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 Claus 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.
7/93 Chemical Process Industry 5.18-3
-------
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, controlled1" 98.6 29
Three, controlled8 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) = d 00 ^recovery) x
% recovery
SO, emissions (Ib/ton) = (100"%recovery) X 4000
% recovery
°Typical sulfur recovery ranges from 92 to 95 percent.
dTypical sulfur recovery ranges from 95 to 96 percent.
eTypical 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
7/93
-------
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 Claus 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:
2NaHSO3 -» Na2SO3i + 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 650°C (1,200°F) 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
-------
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
-------
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 IS 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 149°C (300°F). 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
-------
ON
bo
W
on
oo
i
e
ON
00
3
9
V %'
O AMMONIA •
£• NITRIC ACID-
rtUUIIIVt
i '
SOLUTION 'L^ SOLUTIO
FORMATION . " CONCENTR/
i
1
N ,, FORMATION
^TION ^--PRILLING
-GRANULATING
OFFSIZE RECYCLE
SOLUTIONS
SOLIDS
FINISHING
"*" --DRYING
-COOLING
SOLIDS 2
SCREENING
i
SO
BLE
LUTI
NDI
ON ^_
NG
SOLIDS
COATING
BAGGING
BULK
SHIPPING
BULK
SHIPPING
o
•o
a
R
o'
en
'ADDITIVE MAY BE ADDED BEFORE. DURING. OR AFTER CONCENTRATION
'SCREENING MAY BE PERFORMED BEFORE OR AFTER SOLIDS FINISHING
-------
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 124°C (150 to 255°F). 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. Paniculate 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
-------
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 neutralizes Since the neutralization operation can dictate the quantity
of these emissions, a range of emission factors is presented in Table 6.8-1. Paniculate emissions from
these operations tend to be smaller in 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 paniculate 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 paniculate 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
-------
Table 6.8-1 (Metric Units)
EMISSION FACTORS FOR PROCESSES IN
AMMONIUM NITRATE MANUFACTURING PLANTS*
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 coolers6
Low density prill coolers0
Low density prill dryers6
Rotary drum granulator coolers6
Pan granulator coolers8
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
k{
Factor
Rating Pr
Citric Acid
5/Mg
of Factor
oduct Rating
B 0.042-ld B
A
A
A
A
A
A
A
A
(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 coalers, 99%.
cGiven as ranges because of variation in data and plant operations. Factors for controlled emissions not
presented due to conflicting results on control efficiency.
Based 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
-------
TABLE 6.8-1 (ENGLISH UNITS)
EMISSION FACTORS FOR PROCESSES IN
AMMONIUM NITRATE MANUFACTURING PLANTS*
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 coolers6
Low density prill dryers6
Rotary drum granulator coolers6
Pan granulator coolers6
Coating operations^
Bulk loading operations*
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
«£ 4.0
<; 0.02
Factor
Rating
B
A
A
A
A
A
A
A
A
A
A
B
B
Controlled15
Ib/ton of
Product
0.004-0.43
1.20
0.52
0.44
0.04
0.02
0.52
1.14
0.16
0.36
:£ 0.04
Factor
Rating
B
A
A
A
A
A
A
A
A
B
B
Ammonia
Uncontrolled0
Ib/ton of
Product
0.86-36.0
0.54-33.4
57.2
0.26
59.4
0.14
0.04
0.30
0-3.18
Factor lb/
Rating Pi
Nitric Acid
ton of Factor
•oduct Rating
B 0.084-2d B
A
A
A
A
A
A
A
A
(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%.
cGiven 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.
6.8-6
EMISSION FACTORS
7/9
-------
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
-------
scrubbing paniculate 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
<, 5 fan
10
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
aReferences 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 paniculate emissions.
References for Section 6.8
1. Ammonium Nitrate Manufacturing Industry: Technical Document, EPA-450/3-81-002,
U.S. Environmental Protection Agency, Research Triangle Park, NC, January 1981.
2. W.J. 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.
3. North American Fertilizer Capacity Data, Tennessee Valley Authority, Muscle Shoals,
AL, December, 1991.
4. Memo from C.D. Anderson, Radian Corporation, Durham, NC, to Ammonium Nitrate
file, July 2, 1980.
6.8-8
EMISSION FACTORS
7/9
-------
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, ME,
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
-------
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: Hawkey>e 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
-------
6.10 PHOSPHATE FERTILIZERS
Phosphate fertilizers are classified into three groups of chemical compounds. Two of these
groups are known as superphosphates and are defined by the percentage of phosphorous as ^2^5-
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
7/93 Chemical Process Industry 6.10-1
-------
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
-------
ON
i—*
O
Paniculate
emissions
m
IS)
O
z
i
Partculate
emissions
To Gypsum
Pond
Paniculate and
Fluoride Emissions
Partculate and
*. Ruoride Emissions
(Uncontrolled)
Product
-------
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 (SiF4) 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
-------
Table 6.10.1-1. (Metric and English Units)
EMISSION FACTORS FOR THE PRODUCTION OF NORMAL SUPERPHOSPHATE
Emission point
Rock unloading1'
Rock feedingb
Mixer and denc
Curing building*1
I
kg/Mg
of P2O5
Pollutant Produced
Paniculate 0.28
PM-10 0.15
Paniculate 0.06
PM-10 0.03
Paniculate 0.26
Fluoride 0.10
PM-10 0.22
Paniculate 3.60
Fluoride 1.90
PM-10 3.0
Emission Factor
Ib/ton Emission
of P2O5 Factor
Produced Rating
0.56 Ea
0.29 Ee
0.11 Ea
0.06 Ee
0.52 Ea
0.2 Ea
0.44 Ee
7.20 Ea
3.80 Ea
6.1 Ee
"Reference 1, pp. 74-77, 169.
bFactors are for emissions from baghouse with an estimated collection efficiency of 99%.
"Factors 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
-------
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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-------
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 paniculate emissions include the reactor, granulator, dryer, screens, cooler, mills,
and transfer conveyors. Additional emissions of paniculate 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
Process
Pollutant
Controlled emission factor
kg/Mg Ib/ton Emission
of of Factor
Product Product Rating
Granular triple superphosphate
Rock
Rock
unloadingb Paniculate
PM-10
feeding1* Paniculate
PM-10
Reactor, granulator, dryer, cooler and Paniculate
screens0 Fluoride
PM-10
Curing building0 Paniculate
Fluoride
PM-10
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.
cFactors 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 panicles occur during the production of GTSP triple
superphosphate. Silicon tetrafluoride (SiF^ 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
-------
scrubbing the effluent gas with recycled gypsum pond water in 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.
Paniculate 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 in 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
-------
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.
S. 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
-------
6.10.3 AMMONIUM PHOSPHATE
6.10.3.1 General1
Ammonium phosphate (NH4H2PO4) is produced by reacting phosphoric acid (^PO^ 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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-------
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. Paniculate 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
Diyer/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
* 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
P^C^ 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
-------
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
Diyer/cooler 0.04
Product sizing and
material transfer1' 0.002
Total plant emissions 0.04C
Factor
Rating
Participate
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 0.08° E
"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.
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 paniculate 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 paniculate 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
-------
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 til, 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., til DAP plant, Western Polk County, FL,
October 1991.
10. Compliance Source Test Report: IMC Fertilizer, Inc., #2 DAP Plant, Western Polk County, FL,
June 1991.
11. Compliance Source Test Report: IMC Fertilizer, Inc., Western Polk County, FL, April 1991.
7/93 Food and Agricultural Industry 6.10.3-5
-------
6.14 UREA
6.14.1 General1'14
Urea [ CO(NH2)2 ], 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 (CO2) are reacted to form
ammonium carbamate (Nf^CC^NH^. Typical operating conditions include temperatures from 180 to
20°C (356 to 392°F), 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 + CO2 -» 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 (NHjCONHCONH^
impurity allowable in the end product. Aqueous urea solution begins to decompose at 60°C (140°F) 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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ADDITIVE*
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SOLUTION
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SOLUTIONS
•OPTIONAL WITH INDIVIDUAL MANUFACTURING PRACTICES
OFFSIZE RECYCLE
on
-------
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
-------
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 paniculate 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 paniculate 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 panicles is negligible.
Urea manufacturers presently control paniculate 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
-------
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
concentration11
Nonfluidized bed prilling
Agricultural grade6
Feed gradeh
Fluidized bed prilling
Agricultural grade*1
Feed grade11
Drum granulation1
Rotary drum cooler
Bagging
Particulate8
Uncontrolled
kg/Mg
of
Product
0.0105C
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
1.07J
0.0256k
kg
Factor
Rating Pn
A
A
A
A 1
A
A
Controlled*
/Mg
of Factor
xluct Rating
.04 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).
-------
Table 6.14-1. (English Units)
EMISSION FACTORS FOR UREA PRODUCTION
Type of Operation
Solution formation and
concentration'1
Nonfluidized bed prilling
Agricultural grade0
Feed gradeh
Fluidized bed prilling
Agricultural grade
Feed gradeh
Drum granulation1
Rotary drum cooler
Bagging
Particulate"
Uncontrolled
Ib/ton
of
Product
0.021C
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
2.15)
0.05 lk
Ib
Factor
Rating Prc
A
A
A
A 2
A
A
Controlled^
/ton
of Factor
)duct Rating
.08 A
^articulate 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).
•fePA 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 69°F). 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.
Only 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.
Tleference 11. Feed grade factors were determined at an ambient temperature of 29 °C (85 °F) and agricultural
grade factors at an ambient temperature of 27°C (80°F). 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.
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.
6.14-6
EMISSION FACTORS
7/93
-------
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 nm £ 5 /un
90 84
85 74
60 52
24 18
a a
0.70 0.15
<, 2.5
79
50
43
14
a
jim
0.04
a All particulate matter ^ 5.7 pm 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
-------
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
-------
6.18 AMMONIUM SULFATE MANUFACTURE
6.18. General1'2
Ammonium sulfate [ (NH^SC^ ] 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 (H2SO4) 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.
7/93 Chemical Process Industry 6.18-1
-------
oo
K>
CAPROUCTAM BYPRODUCT PROCESS
PI
§
&
(A
O
Tl
35-40% | 1
AUUDNII IU ^1 II FATF M. i I«-*TTT> » CRYSTALLJZER
nt"' fcri /in/An/xnATnov
SOLUTION GENERATION "T r1 itwwuwiurij
STEAM COND.
^ TO ATM
SYNTHETIC PROCESS
.. VACUUM CONDt
NH3 REACTOR STEAM • SYSTEM
COOLING
TOWER
H2S04
COKE OVEN BYPRODUCT PROCESS
nvFN AMMONIA » AMMONIA . REACTOR
^" ABSORBER STILL (SATURATOR)
cyrcAU ». r*rtwn
«. VACUUM PApnn it ATP A vnr
SYSTEM TOA™ EMISSIONS
fl ;
(
STEAM COND.
SCRUBBER
OR
BAGHOUSE
(3)
(D (2)
• CENTRIFUGE * — ' I 1
| „ OLJIIHlruv;lc ! „ DRYER -SCREENS
ENCLOSED
1 [HEAT K-AIR STORAGE
' *
STEAM COND. 1
AMMONIUM SULFATE
PRODUCTS
^ ROOTS ^ T0 ATU
BLOWER T°A™
VACUUM PNCLQSFD
^ FILTER * e^«oA/sE
(ALT.) DRYER STORAGE
"
1
AMMONIUM SULFATE
HEAT
NOTES:
(1.) Dryer may be rotary or fluklzed bed type.
(2.) Coke oven plant may Integrate centrifuge and drying or oantrifuglng only.
(3.) Coke oven plant product not screened.
STEAM-
AIR
COND.
Figure 6.18-1. Typical diagram of ammonium sulfate processes.
-------
6.18.3 Emissions And 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
paniculate 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 paniculate emissions from the dryers. Wet
scrubbers use the process streams as the scrubbing liquid so that the collected paniculate can be easily
recycled to the production system.
Tables 6.18-1 and 6.18-2 shows uncontrolled and controlled paniculate 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 MANUFACTURE8
Dryer Type
Rotary dryers
Uncontrolled
Wet scrubber
Fluidized-bed dryers
Uncontrolled
Wet scrubber
Paniculate
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.
7/93
Chemical Process Industry
6.18-3
-------
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
Paniculate
Ib/ton
46
0.04C
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
a 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.
c 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
-------
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 elcctrothermic 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. Bencficiation, 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
-------
-J
'-J
m
00
O
n
O
73
00
CONCEN-
TRATE
SODIUM ' DUS1
HYDROXIDE > | FU
I
^. ROASTINQ L
[
J
SODIUM OR
ZINC CHLORIDE]
CALCINE
| SODIUM
i DUST AND
1 HYDROXIDE j FUME
* '
I, I I
j FUME j
f
1
ENTERING |— •• SINTER I-T-* RETORTING 1— f
MOLTEN
ZINC
1 |
; FUME ;
~r
Hi
CASIING | "'
-• SAND -• COAL OR COKE
•• COKE •" RECYCLED BLUE POWDER
L. ZINCSULFATE U SILICA
!"*»"!
1 MIST
"T"
T-»- LEACHING
! ACID
i
' MIST «'ST|
1
H LEACH 7|Mr
SOLU -i-»- PURIFYING _». ^.VTi
SOLU-
TION ' ' -now
„ SULFURIC ACID
•• ZINC DUST
„ LIMESTONE
< PURIFYING ADDITIVES
v ZINC OXIDE
.. THICKENER
„ CYANIDE
r
ELECTRO- CATHODE _»
LYSIS ^ ZINC
SLAB
ZINC
'( \
1 FUME 1
MELTMQ ANC
CASTINQ
« SULFURIC AGIO
•• COLLODIAL ADDITIVES
^ BARIUM HYDROXIDE
OR SODIUM
CARBONATE
U SPENT ELECTROLYTE
Figure 7.7.2-1. Generalized process flow for primary zinc smelting.
-------
Multiple hearth roasters are unpressurized and operate at about 690°C (1300°F). 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 980°C (1800°F).
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 1000°C
(1800°F). 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 dcsulfurized 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 + 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 fcrrile 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
85°C (104 to 185°F), 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 heat, which increases the temperature of the electrolyte.
7/93 Metallurgical Industry 7.7-3
-------
Electrolytic cells operate at temperature ranges from 30 to 35°C (86 to 95°F) 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
1400°C (2600°F) 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 particulate mailer 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 How 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 arc contained in the offgases from both the sintering machine and the retort
furnaces.
Table 7.7-1 (Metric Units).
PARTICULATE EMISSION FACTORS FOR ZINC SMELTING''1
Process
Roasting
Multiple hcarthh (SCC 3-03-030-02)
Suspension0 (SCC 3-03-030-07)
Fluidized bed'1 (SCC 3-03-030-08)
Sinter plant (SCC 3-03-030-03)
Uncontrolled0
With cyclonef
With cyclone and ESP**
Electric rctorlh (SCC 3-03-030-21)
Electrolytic proccssJ (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 precipitalor.
bRefcrenccs 2,4. Averaged from an estimated 10% of feed released as particulate, zinc
production rale at 60% of roaster feed rate, and other estimates.
cRefercnces 2,4. Based on an average 60% of feed released as particulate emission and a zinc
production rate at 60% of roaster feed rate. Controlled emissions based on 20% dropout in
waste heat boiler and 99.5% dropout in cyclone and ESP.
dRefercnces 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.
hRefcrcnce 1. Based on unspecified industrial source data.
JReference 2.
7/93
Metallurgical Industry
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)
Uncontrolled6
With cyclonef
With cyclone and ESPS
Electric retort*1 (SCC 3-03-030-21)
Electrolytic processJ (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/ton 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 rate at 60% of roaster feed rate. Controlled emissions based on 20% dropout in
waste heat boiler and 99.5% dropout in cyclone and ESP.
dReferences 4,7. Based on an average 65% of feed released as particulale emissions and a zinc
production rate of 60 percent of roaster feed rate.
eReference 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
-------
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)
Caslingd (SCC 3-03-030-1 1)
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 arc 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 plantb
Wind box (SCC 3-03-030-19)
Discharge screens (SCC 3-03-030-20)
Retort building0 (SCC 3-03-030-24)
Caslingd (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/lon of product. SCC = Source Classification Code.
bFrom steel industry operations for which there arc emission factors. Based on quantity of sinter
produced.
GFrom 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. Paniculate 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 Corjyoralion 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
-------
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 364°C (787°F). 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 smellers. The washed zinc-containing metal portion becomes the raw
material for the melting process.
7/93 Metallurgical Industry 7.14-1
-------
-J
£
m
z
n
o
REFINING/ALLOYING
PRETREATMENT
r~
MELTING
DIE CAST
PRODUCTS
RESIDUES
SKIMMINGS
OTHER
MIXED
SCRAP
CLEAN
SCRAP
ZINC ALLOYS
CONTAMINATED
ZINC OXIDE
r
FUEL
T ^
TS *
GS
,
IT
n
G
IT
REVER3ERATORY
SWEATING
FUEL
ROTARY
SWEATING
FUEL
MUFFLE
SWEATING
FUEL
KETTLE (POT)
SWEATING
FUEL
ELECTRIC
RESISTANCE
SWEATING
SWEATED
SCRAP (MELT
OR INGOT)
RESIDUES
SKIMMINGS
TED
DUST
H
i—e
CRUSHING/
SCREENING
R WATER
jODIUM
CARBONATE
LEACHING
S v
/CRUDE\
J ZINC >• T0 PRIMARY
\OXIDEy SMELTERS
UlbllLlAllUN
OXIDATION
t— FUEL L_
WATER 1
JL 1 r
RETORT
REDUCTION
-WATER
AIR
.SODIUM
CARBONATE
Figure 7.14-1. Secondary zinc recovery process.
-------
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 1249°C (1800 to 2280°F) 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
-------
Figure 7.14-2. Zinc retort distillation furnace.
STACK
MOLTEN METAL , , ,
TAPHOLE r-H METAL VAPORS
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
-------
o
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
-------
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 sweating13
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/oxidation1 (SCC 3-04-008-54)
Muffle distillation/oxidation1 (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.
e Reference 1.
f 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 sweating15 (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 sweat ingb
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 distillation11 (SCC 3-04-008-02
Graphite rod distillation0-6 (SCC 3-04-008-53)
Retort distillation/oxidation1' (SCC 3-04-008-54)
Muffle distillation/oxidalionf (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 Ih/ton 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.
f Reference 4. Factors are for Ih/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
-------
Table 7.14-3 (Metric Units).
FUGITIVE PARTICULATE EMISSION FACTORS FOR
SECONDARY ZINC SMELTING3
Operation
Reverberatory sweating13 (SCC 3-04-008-61)
Rotary sweating13 (SCC 3-04-008-62)
Muffle sweating" (SCC 3-04-008-63)
Kettle (pot) sweating" (SCC 3-04-008-64)
Electrical resistance sweating, per kg processed"
(SCC 3-04-008-65)
Crushing/screeningc (SCC 3-04-008-12)
Sodium carbonate leaching (SCC 3-04-008-66)
Kettle (pot) melting furnace" (SCC 3-04-008-67)
Crucible melting furnaced (SCC 3-04-008-68)
Reverberatory melting furnace" (SCC 3-04-008-69)
Electric induction melting" (SCC 3-04-008-70)
Alloying retort distillation (SCC 3-04-008-71)
Retort and muffle distillation (SCC 3-04-008-72)
Casting" (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.
c Reference 1. Factors are for kg/Mg of scrap processed. Average of reported emission factors.
dEngineering 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 SMELTING"
Operation
Rcvcrbcratory sweating15 (SCC 3-04-008-61)
Rotary sweating11 (SCC 3-04-008-62)
Muffle sweatingh (SCC 3-04-008-63)
Kettle (pot) sweatingb (SCC 3-04-008-64)
Electrical resistance sweating, per ton processed15
(SCC 3-04-008-65)
Crushing/screening0 (SCC 3-04-008-12)
Sodium carbonate leaching (SCC 3-04-008-66)
Kettle (pot) melting furnace11 (SCC 3-04-008-67)
Crucible melting furnaced (SCC 3-04-008-68)
Rcverberatory melting furnace15 (SCC 3-04-008-69)
Electric induction meltingh (SCC 3-04-008-70)
Alloying retort distillation (SCC 3-04-008-71)
Retort and muffle distillation (SCC 3-04-008-72)
Castingb (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
"Reference 8. Factors are Ib/ton of end product, except as noted. SCC = Source Classification
Code. ND = no data.
^Estimate based on slack emission factor given in Reference 1, assuming fugitive emissions to be
equal to five % of stack emissions.
cRefcrcncc 1. Factors arc for Ib/lon 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
-------
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 Paniculate 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
-------
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 reverberatory 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 How 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 heal 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
-------
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 700°C (1112 to 1292°F)
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 480°C (698 to 896°F). 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 orthorhombic litharge is made by burning a fine stream of molten lead in
a special blast-type burner. The flame temperature is around 1200°C (2192°F). 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 nonisokinetic 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 are covered under federal regulations, one would expect lower emissions
from these sources.
7.16-2 EMISSION FACTORS 7/93
-------
LEAD
FEED
LEAD OXIDE
LEAD
CONVEYER
(PRODUCI TO 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
-------
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 3-0 1-035- 10)
White leadb
(SCC 3-01-035-15)
Chrome pigments
(SCC 3-01 -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
'''Factors are for kg/Mg 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.
7.16-4
EMISSION FACTORS
7/93
-------
Table 7.16-2 (English Units).
CONTROLLED EMISSIONS FROM LEAD OXIDE AND PIGMENT PRODUCTION"
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 3-0 1-035- 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 arc tor Ib/ton of product. SCC = Source Classification Code.
bMeasured at baghouse outlet. Baghouse is considered process equipment.
°Only 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
-------
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. Betz, el al., 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
-------
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
-------
TABLE 8.8-1 (METRIC UNITS)
EMISSION FACTORS FOR CLAY AND FLY ASH SINTERING*
k
Source (SSC) M
Fly ash crushing,
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)3
Natural clay
crushing, screening,
and storage
(3-05-009-04)f
Filterable8
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 Ratin
ND
ND
ND
ND
ND
Condensible PMC
Inorganic
on kg/Mg Emiss
r of Fact
1 Material Ratij
ND
ND
ND
ND
ND
Organic
don kg/Mg
or of
ng 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.
dReference 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.
gReference 2; rotary dryer sinterer.
8.8-2
EMISSION FACTORS
2/72
-------
TABLE 8.8-1 (ENGISH UNITS)
EMISSION FACTORS FOR CLAY AND FLY ASH SINTERING*
I
_ Ib/ton
Source of
(SSC) Material
Fly ash crushing, 1 10
screening, sintering, and
storage
(3-05-009-01)d
Clay/coke mixture 40
sintering
(3-05-009-02)6
Clay /coke mixture 15
crushing, screening, and
storage
(3-05-009-07)f
Natural clay sintering 12
(3-05-009-03)8
Natural clay crushing, 12
screening, and storage
(3-05-009-04)f
Filterableb
»M PM-10
Emission Ib/ton Emissi
Factor of Facto
Rating Material Ratin
E ND
E ND
E ND
E ND
E ND
Condensible PMC
Inorganic
on Ib/ton Emisf
r of Fact
g Material Rati
ND
ND
ND
ND
ND
Organic
ion Ib/ton Emission
or of Factor
ng Material Rating
ND
ND
ND
ND
ND
ND = No data.
aFactors represent uncontrolled emissions unless otherwise noted.
"Filterable PM is that PM collected on or prior to the filter of an EPA Method 5 (or equivalent)
sampling train.
cCondensible 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.
gReference 2; rotary dryer sinterer.
2/72
Mineral Products Industry
8.8-3
-------
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 Gay: 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
-------
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 in 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 in and around the plant, can be controlled by good
maintenance and wetting of the road surface.
10/86 Mineral Products Industry 8.10-1
-------
o
PNEUMATIC
TRANSFER
C/3
I
T)
C/3
TRUCK MIXED
PRODUCT
Figure 8.1-1. Typical concrete batching process.
-------
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
Source.
(SSC)
Filterableb
PM
PM-10
Condensible PMC
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
(3-05-011-108
Vehicle traffic (unpaved roads) 4.5 C ND ND ND
(3-05-011-^
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!-_)»
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 that PM collected in the impinger portion of a PM sampling train.
•"Reference 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.
8Reference 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.
'From 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
-------
Table 8.10-2 (English Units)
EMISSION FACTORS FOR CONCRETE BATCHING"
All Emission Factors in the Ib/ton (Ib/yd3) of Material Mixed Unless Notedb
Ratings (A-E) Follow Each Emission Factor
Source
(SSC)
Filterable0
PM
PM-10
Condensible PMd
Inorganic
Organic
Sand and aggregate transfer to elevated bin
(3-05-01 l-06)e
Cement unloading to elevated storage silo
Pneumaticf
Bucket elevator8
(3-05-011-07)
Weigh hopper loading
(3-05-01 l-O&p
Mixer loading (central mix)
(3-05-011-09?'
Truck loading (truck mix)
(3-05-01 MO*
Vehicle traffic (unpaved roads)
(3-05-01!-_)'
Wind erosion from sand and aggregate storage piles
(3-05-01 l-_)i
Total process emissions (truck mix)
(3-05-01 l-_)m
0.029
(0.05)
0.27
(0.07)
0.24
(0.06)
0.02
(0.04)
0.04
(0.07)
0.02
(0.04)
16
(0.02)
3.5k
(O.I)1
0.1
(0.2)
D
E
E
E
E
C
D
E
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
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.
'Filterable PM is that PM collected on or prior to die filter of an EPA Method 5 (or equivalent) sampling train.
dCondensible PM is (hat 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.
hReference 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 nrVyr (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).
JFrom Section 8.19.1, for emissions <30 micrometers from inactive storage piles.
kUmts 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 yr'/yr).
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
-------
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.
10/86 Mineral Products Industry 8.10-5
-------
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 1700°C (2700° to 3100°F) 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. Recuperative 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
-------
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
Glass
v melting
/ and
forming
Fiber
forming
and
finishing
Figure 8.11-1. Typical flow diagram of the glass fiber production process.
8.11-2
EMISSION FACTORS
9/85
-------
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 insulation) and bulk packaged or are recycled to the forming section
and blended with newly formed product.
During the formation of fibers into a wool fiberglass mat (the process known as "forming" in
the industry), glass fibers are made from molten glass, and a chemical binder is simultaneously
sprayed on the fibers as they are created. The binder is a thermosetting resin that holds the glass
fibers together. Although the binder composition varies with product type, typically the binder
consists of a solution of phenol-formaldehyde resin, water, urea, lignin, silane, and ammonia.
Coloring agents may also be added to the binder. Two methods of creating fibers are used by the
industry. In the rotary spin process, depicted in Figure 8.11-2, centrifugal force causes molten glass
to flow through small holes in the wall of a rapidly rotating cylinder to create fibers that are broken
into pieces by an air stream. This is the newer of the two processes and dominates the industry
today. In the flame attenuation process, molten glass flows by gravity from a furnace through
numerous small orifices to create threads that are then attenuated (stretched to the point of breaking)
by high velocity, hot air, and/or a flame. After the glass fibers are created (by either process) and
sprayed with the binder solution, they are collected by gravity on a conveyor belt in the form of a
mat.
The conveyor carries the newly formed mat through a large oven to cure the thermosetting
binder and then through a cooling section where ambient air is drawn down through the mat.
Figure 8.11-3 presents a schematic drawing of the curing and cooling sections. The cooled mat
remains on the conveyor for trimming of the uneven edges. Then, if product specifications require it,
a backing is applied with an adhesive to form a vapor barrier. The mat is then cut into batts of the
desired dimensions and packaged.
9/85 Mineral Products Industry 8.11-3
-------
oo
m
g
5>
C/3
1
O
50
c/5
MOLTEN
GLASS
ATTENUATION AIR
SPINNER
TO CURING OVEN
CONVEYOR
FORMING EXHAUST IS PULLED THROUGH
THE CONVEYOR AND MAT BY FANS
Figure 8.11.2. A typical spin process.
oo
Ul
-------
KOLLKRS
UNCORED MAT
o
3
a.
CURING AIR
ZONE 1
ZONE 2
COOLING AIR
CURED MAT
\
EXHAUST
CURING AIR
CURING EXHAUST
. TO CONTROL DEVICE
(INCLUDES FUEL
COMBUSTION GASES)
oo
Figure 8.11-3. Side view of curing oven (indirect heating) and cooling section.
-------
Textile Glass Fiber Forming and Finishing - Molten glass from either the direct melting
furnace or the indirect marble melting furnace is temperature-regulated to a precise viscosity and
delivered to forming stations. At the forming stations, the molten glass is forced through heated
platinum bushings containing numerous very small openings. The continuous fibers emerging from
the openings are drawn over a roller applicator, which applies a coating of a water-soluble sizing
and/or coupling agent. The coated fibers are gathered and wound into a spindle. The spindles of
glass fibers are next conveyed to a drying oven, where moisture is removed from the sizing and
coupling agents. The spindles are then sent to an oven to cure the coatings. The final fabrication
includes twisting, chopping, weaving, and packaging the fiber.
8.11.2 Emissions and Controls1'3'4
Emissions and controls for glass fiber manufacturing can be categorized by the three
production phases with which they are associated. Emission factors for the glass fiber manufacturing
industry are given in Tables 8.11-1 through 8.11-3.
Raw Materials Handling - The major emissions from the raw materials handling phase are
fugitive dust and raw material particles generated at each of the material transfer points. Such a point
would be where sand pours from a conveyor belt into a storage silo. The two major control
techniques are wet or moist handling and fabric filters. When fabric filters are used, the transfer
points are enclosed, and air from the transfer area is continuously circulated through the fabric filters.
Glass Melting and Refining - The emissions from glass melting and refining include volatile
organic compounds from the melt, raw material particles entrained in the furnace flue gas, and, if
furnaces are heated with fossil fuels, combustion products. The variation in emission rates among
furnaces is attributable to varying operating temperatures, raw material compositions, fuels, and flue
gas flow rates. Of the various types of furnaces used, electric furnaces generally have the lowest
emission rates, because of the lack of combustion products and of the lower temperature of the melt
surface caused by bottom heating. Emission control for furnaces is primarily fabric filtration. Fabric
filters are effective on paniculate matter (PM) and sulfur oxides (SOX) and, to a lesser extent, on
carbon monoxide (CO), nitrogen oxides (NOX), and fluorides. The efficiency of these compounds is
attributable to both condensation on filterable PM and chemical reaction with PM trapped on the
filters. Reported fabric filter efficiencies on regenerative and recuperative wool furnaces are for PM,
95+ percent; SOX, 99+ percent; CO, 30 percent; and fluoride, 91 to 99 percent. Efficiencies on
other furnaces are lower because of lower emission loading and pollutant characteristics.
Wool Fiber Forming and Finishing - Emissions generated during the manufacture of wool
fiberglass insulation include solid particles of glass and binder resin, droplets of binder, and
components of the binder that have vaporized. Glass particles may be entrained in the exhaust gas
stream during forming, curing, or cooling operations. Test data show that approximately 99 percent
of the total emissions from the production line are emitted from the forming and curing sections.
Even though cooling emissions are negligible at some plants, cooling emissions at others may include
fugitives from the curing section. This commingling of emissions occurs because fugitive emissions
from the open terminal end of the curing oven may be induced into the cooling exhaust ductwork and
be discharged into the atmosphere. Solid particles of resin may be entrained in the gas stream in
either the curing or cooling sections. Droplets of organic binder may be entrained in the gas stream
in the forming section or may be a result of condensation of gaseous pollutants as the gas stream is
cooled. Some of the liquid binder used in the forming section is vaporized by the elevated
temperatures in the forming and curing processes. Much of the vaporized material will condense
8.11-6 EMISSION FACTORS 9/85
-------
VO
ft Table 8. 1 1-1 (Metric Units)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING*
2
5'
a
B.
3
1
ss
3
oo
Filterable1*
PM Pfl
kg/Mg of Emission kg/Mg of
Material Factor Material
Source (SSC) Processed Rating Processed
Unloading and conveying (3-05-021-21)d 1.5 B ND
Storage bins (3-05-02 l-22)d 0.1 B ND
Mixing and weighing (3-05-02 l-23)d 0.3 B ND
Crushing and batch charging (3-05-02 l-24)d Neg. ND
Glass furnace-wool6
Electric (3-05-021-03) 0.25 B ND
Gas-regenerative (3-05-021-01) 11 B ND
Gas-recuperative (3-05-021-02) 13-15 B ND
Gas-unit melter (3-05-021-07) 4.5 B ND
Glass furnace-textile6
Gas-regenerative (3-05-021-11) 1 B ND
Gas-recuperative (3-05-021-12) 8 B ND
Gas-unit melter (3-05-021-13) 3 B ND
Forming-wool
Flame attenuation (3-05-02 1-08)6 1 B ND
Forming-textile (3-05-02 1-14)6 0.5 B ND
Oven curing-wool
Flame attenuation (3-05-02 l-09)e 3 B ND
Oven curing and cooling-textile (3-05-021-15)6 0.6 ND
Condensible PMC
A- 10 Inorganic Organic
Emission kg/Mg of kg/Mg of Emission
Factor Material Material Factor
Rating Processed Processed Rating
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
ND ND
-------
00
oo
Table 8.11-1 (Metric Units) (Continued)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING*
Source (SSC)
Filterable15
PM
kg/Mg of
Material
Processed
Rotary spin wool glass manufacturing (3-05-02 l-04)f
R-19 17.81
R-ll 19.61
Ductboard 27.72
Heavy density " 4.91
Emission
Factor
Rating
PM-10
kg/Mg of
Material
Processed
B ND
B ND
B ND
B ND
Emission
Factor
Rating
Condensible PMC
Inorganic
kg/Mg of
Material
Processed
Organic
kg/Mg of
Material
Processed
ND 4.25
ND 3.19
ND 8.55
ND 1.16
Emission
Factor
Rating
B
B
B
B
m
§
53
C/5
^-4
s
32
o
50
ND = No data.
Neg. = Negligible.
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 that PM collected in the impinger portion of a PM sampling train.
dReference 1.
Reference 5.
^Reference 4; expressed in kg/Mg of finished product.
vo
oo
-------
Table 8.11-2 (English Units)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING4
1
Ib/ton of
Material
Source (SSC) Processed
Unloading and conveying . (3-05-02 1 -2 1 )d 3.0
Storage bins (3-05-02 l-22)d 0.2
Mixing and weighing (3-05-02 l-23)d 0.6
Crushing and batch charging (3-05-02 l-24)d Neg.
Glass furnace-wool6
Electric (3-05-021-03) 0.5
Gas-regenerative (3-05-021-01) 22
Gas-recuperative (3-05-021-02) 25-30
Gas-unit melter (3-05-021-07) 9
Glass furnace-textile6
Gas-regenerative (3-05-021-11) 2
Gas-recuperative (3-05-021-12) 16
Gas-unit melter (3-05-021-13) 6
Forming-wool
Flame attenuation (3-05-02 l-08)e 2
Forming-textile (3-05-02 l-14)e 1
Oven curing— wool
Flame attenuation (3-05-02 1-09)& 6
Oven curing and cooling-textile (3-05-021-15)6 1.2
Filterable1*
3M PM-10
Emission Ib/ton of Emiss
Factor Material Factc
Rating Processed Ratin
B ND
B ND
B ND
ND
B ND
B ND
B ND
B ND
B ND
B ND
B ND
B ND
B ND
B ND
B ND
Condensible PM
Inorganic
ion Ib/ton of
>r Material
ig Processed
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Organic
Ib/ton of
Material
Processed
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
Emission
Factor
Rating
2
3
o.
o.
00
-------
00
Table 8.11-2 (English Units) (Continued)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING4
Source (SSC)
Filterable15
PM
Ib/ton of
Material
Processed
Rotary spin wool glass manufacturing (3-05-02 l-04)f
R-19 36.21
R-ll 39.21
Ductboard 55.42
Heavy density 9.81
Emission
Factor
Rating
PM-10
Ib/ton of
Material
Processed
B ND
B ND
B ND
B ND
Emission
Factor
Rating
Condensible PM
Inorganic
Ib/ton of
Material
Processed
Organic
Ib/ton of
Material
Processed
ND 8.52
ND 6.37
ND 17.08
ND 2.33
Emission
Factor
Rating
B
B
B
B
tn
00
O
Z
*n
9
ND = No data.
Neg. = Negligible.
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.
cCondensible PM is that PM collected in the impinger portion of a PM sampling train.
dReference 1.
Reference 5.
Reference 4; expressed in Ib/ton of finished product.
oo
(Jt
-------
Table 8.11-3 (Metric Units)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING*
Source (SCC)
Glass ftirnace-woolb
Electric (3-05-021-03) .
Gas-regenerative (3-05-021-01)
Gas-recuperative (3-05-021-02)
Gas-unit melter (3-05-021-07)
Glass furnace— textile1*
Gas-regenerative (3-05-02 1-11)
Gas-recuperative (3-05-021-12)
Gas-unit melter (3-05-021-13)
Forming-wool1*
Flame attenuation (3-05-021-08)
Forming-textile1* (3-05-021-14)
Oven curing-wool1*
Flame attenuation (3-05-021-09)
Oven curing and cooling-textile1*
(3-05-021-15)
sox
kg/Mg of
Material
Processed
0.02
5
5
0.3
1.5
15
ND
NA
NA
ND
NA
Emission
Factor
Rating
B
B
B
B
B
B
NOX
kg/Mg of
Material
Processed
0.14
2.5
0.85
0.15
10
10
10
NA
NA
1
1.3
Emission
Factor
Rating
B
B
B
B
B
B
B
B
B
CO
kg/Mg of
Material
Processed
0.025
0.13
0.13
0.13
0.25
0.5
0.45
NA
NA
1.8
0.75
Emissio
n Factor
Rating
B
B
B
B
B
B
B
B
B
2
5'
2.
I
Q.
oo
ND = No data.
NA = Not applicable.
aFactors represent uncontrolled emissions unless otherwise noted.
bReference 5.
-------
00
TABLE 8.11-4 (ENGLISH UNITS)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING*
Source (SCC)
Glass furnace-wool
Electric (3-05-02 l-03)b
Gas-regenerative (3-05-021-01)
Gas-recuperative (3-05-021-02)
Gas-unit melter (3-05-021-07)
Glass furnace-textile
Gas-regenerative (3-05-021-1 l)b
Gas-recuperative (3-05-021-12)
Gas-unit melter (3-05-021-13)
Forming-wool
Flame attenuation (3-05-02 l-08)b
Forming-textile (3-05-02 l-14)b
Oven curing-wool
Flame attenuation (3-05-02 l-09)b
Oven curing and cooling-textile
(3-05-021-15)b
SO
Ib/ton of
Material
Processed
0.04
10
10
0.6
3
30
ND
NA
NA
ND
NA
Emission
Factor
Rating
B
B
B
B
B
B
NO
Ib/ton of
Material
Processed
0.27
5
1.7
0.3
20
20
20
NA
NA
2
2.6
X
Emission
Factor
Rating
B
B
B
B
B
B
B
B
B
CO
Ib/ton of
Material
Processed
0.05
0.25
0.25
0.25
0.5
1
0.9
NA
NA
3.5
1.5
Emissio
n
Factor
Rating
B
B
B
B
B
B
B
B
B
ND = No data.
m
g
55
03
O
NA = Not applicable.
aFactors represent uncontrolled emissions unless otherwise noted.
bReference 5.
o
-------
Table 8.11-5 (Metric Units)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING*
Source (SCC)
Glass furnace-wool
Electric (3-05-021-03)b
Gas-regenerative (3-05-021-01)
Gas-recuperative (3-05-021-02)
Gas-unit melter (3-05-021-07)
Glass furnace— textile1*
Gas-regenerative (3-05-021-11)
Gas-recuperative (3-05-021-12)
Gas-unit melter (3-05-021-13)
Forming— wool
Flame attenuation (3-05-02 l-08)b
Forming-textile (3-05-021-14)b
Oven curing— wool
Flame attenuation (3-05-02 l-09)b
Oven curing and cooling —textile
(3-05-021-15)b
Rotary spin wool glass fiber
manufacturing
(3-05-021-04)°
R-19
R-ll
Ductboard
Heavy duty
VOC
kg/Mg of Emisf
Material Fact
Processed Ratii
ND
ND
ND
ND
ND
ND
ND
0.15 B
Neg.
3.5 B
Neg.
ND
ND
ND
ND
Phenolics
don kg/Mg of Emiss
or Material Fact
ng Processed Ratii
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
3.21 B
6.21 B
10.66 B
0.88 B
Phenol
iion kg/Mg of Emiss
or Material Fact
ng Processed Ratii
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
0.96 B
0.92 B
3.84 B
0.53 B
Formaldehyde
don kg/Mg of Emis!
or Material Fact
ng Processed Ratii
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
0.75 B
1.23 B
1.80 B
0.43 B
Fluorides
don kg/Mg of
or Material
ng Processed
0.001
0.06
0.06
0.06
1
1
1
ND
NA
ND
ND
ND
ND
ND
ND
Emission
Factor
Rating
B
B
B
B
B
B
B
I
e.
I
i
B4
a.
I
oo
ND = No data.
NA = Not applicable.
Neg. = Negligible.
"Factors represent uncontrolled emissions unless otherwise noted..
bReference 5.
cReference 4.
-------
oo
Table 8.11-6 (English Units)
EMISSION FACTORS FOR GLASS FIBER MANUFACTURING4
Source (SCC)
Glass furnace— wool
Electric (3-05-021-03)b
Gas-regenerative (3-05-021-01)
Gas-recuperative (3-05-021-02)
Gas-unit melter (3-05-021-07)
Glass furnace— textile"
Gas-regenerative (3-05-021-11)
Gas-recuperative (3-05-021-12)
Gas-unit melter (3-05-021-13)
Forming— wool
Flame attenuation (3-05-021 -08)b
Forming-textile (3-05-021-14)b
Oven curing— wool
Flame attenuation (3-05-021-09)b
Oven curing and cooling —textile
(3-05-021-15)b
Rotary spin wool glass fiber
manufacturing (3-05-021-04/
R-19
R-ll
Ductboard
Heavy duty
VOC
Ib/ton of Emisi
Material Fact
Processed Ratii
ND
ND
ND
ND
ND
ND
ND
0.3
Neg.
7
Neg.
ND
ND
ND
ND
Phenolics
don Ib/ton of Emisf
or Material Fact
ng Processed Rati
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
6.92 B
12.41 B
21.31 B
1.74 B
Phenol
iion Ib/ton of Emis
or Material Fact
ng Processed Rati
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
1.92 B
1.84 B
7.68 B
1.04 B
Formaldehyde
sion Ib/ton of Emis
JOT Material Facl
ng Processed Rati
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
ND
1.50 B
2.46 B
3.61 B
0.85 B
Fluorides
sion Ib/ton of
or Material
ng Processed
0.002
0.12
0.11
0.12
2
2
2
ND
NA
ND
ND
ND
ND
ND
ND
Emission
Factor
Rating
B
B
B
B
B
B
B
m
S
t-H
GO
C/5
O
on
ND = No data.
NA = Not applicable.
Neg. = Negligible.
"Factors represent uncontrolled emissions unless otherwise noted.
bReference 5.
cReference 4.
OO
-------
when the gas stream cools in the ductwork or in the emission control device.
Paniculate matter is the principal pollutant that has been identified and measured at wool
fiberglass insulation manufacturing facilities. It was known that some fraction of the PM emissions
results from condensation of organic compounds used in the binder. Therefore, in evaluating
emissions and control device performance for this source, a sampling method, EPA Reference
Method 5E, was used that permitted collection and measurement of both solid particles and condensed
PM.
Tests were performed during the production of R-ll building insulation, R-19 building
insulation, ductboard, and heavy-density insulation. These products, which account for 91 percent of
industry production, had densities ranging from 9.1 to 12.3 kilograms per cubic meter (kg/m3) (0.57
to 0.77 pounds per cubic foot Db/ft3]) for R-ll, 8.2 to 9.3 kg/m3 (0.51 to 0.58 Ib/ft3) for R-19, and
54.5 to 65.7 kg/m3 (3.4 to 4.1 Ib/ft3) for ductboard. The heavy-density insulation had a density of
118.5 kg/m3 (7.4 Ib/ft3). (The remaining 9 percent of industry wool fiberglass production is a variety
of specialty products for which qualitative and quantitative information is not available.) The loss on
ignition (LOT) of the product is a measure of the amount of binder present. The LOI values ranged
from 3.9 to 6.5 percent, 4.5 to 4.6 percent, and 14.7 to 17.3 percent for R-ll, R-19, and ductboard,
respectively. The LOI for heavy-density insulation is 10.6 percent. A production line may be used
to manufacture more than one of these product types because the processes involved do not differ.
Although the data base did not show sufficient differences in mass emission levels to establish
separate emission standards for each product, the uncontrolled emission factors are sufficiently
different to warrant their segregation for AP-42.
The level of emissions control found in the wool fiberglass insulation manufacturing industry
ranges from uncontrolled to control of forming, curing, and cooling emissions from a line. The
exhausts from these process operations may be controlled separately or in combination. Control
technologies currently used by the industry include wet ESP's, low- and high-pressure-drop wet
scrubbers, low- and high-temperature thermal incinerators, high-velocity air filters, and process
modifications. These added control technologies are available to all firms in the industry, but the
process modifications used in this industry are considered confidential. Wet ESP's are considered to
be best demonstrated technology for the control of emissions from wool fiberglass insulation
manufacturing lines. Therefore, it is expected that most new facilities will be controlled in this
manner.
Textile Fiber Forming and Finishing - Emissions from the forming and finishing processes
include glass fiber particles, resin particles, hydrocarbons (primarily phenols and aldehydes), and
combustion products from dryers and ovens. Emissions are usually lower in the textile fiber glass
process than in the wool fiberglass process because of lower turbulence in the forming step, roller
application of coatings, and use of much less coating per ton of fiber produced.
References for Section 8.11
1. J. R. Schorr et al., Source Assessment: Pressed and Blown Glass Manufacturing Plants,
EPA-600/2-77-005, U.S. Environmental Protection Agency, Research Triangle Park, NC,
January 1977.
2. Annual Book ofASTM Standards, Pan 18, ASTM Standard C167-64 (Reapproved 1979),
American Society for Testing and Materials, Philadelphia, PA.
9/85 Mineral Products Industry 8.11-15
-------
3. Standard of Performance For Wool Fiberglass Insulation Manufacturing Plants, 50 FR 7700,
February 25, 1985.
4. Wool Fiberglass Insulation Manufacturing Industry: Background Information for Proposed
Standards, U. S. Environmental Protection Agency, Research Triangle Park, NC, EPA-
450/3-83-022a, December 1983.
5. Screening Study to Determine Need for Standards of Performance for New Sources in the Fiber
Glass Manufacturing Industry—Draft, U.S. Environmental Protection Agency, Research Triangle
Park, NC, December 1976.
8.11-16 EMISSION FACTORS 9/85
-------
8.14 GYPSUM PROCESSING
8.14.1 Process Description1"2
Gypsum is calcium sulfate dihydrate (CaSO4 • 2H2O), a white or gray naturally occurring
mineral. Raw gypsum ore is processed into a variety of products such as a portland cement additive,
soil conditioner, industrial and building plasters, and gypsum wallboard. To produce plasters or
wall board, gypsum must be partially dehydrated or calcined to produce calcium sulfate hemihydrate
(CaSO4 • l£H2O), commonly called stucco.
A flow diagram for a typical gypsum process producing both crude and finished gypsum
products is shown in Figure 8.14-1. In this process gypsum is crushed, dried, ground, and calcined.
Not all of the operations shown in Figure 8.14-1 are performed at all gypsum plants. Some plants
produce only wallboard, and many plants do not produce soil conditioner.
Gypsum ore, from quarries and underground mines, is crushed and stockpiled near a plant.
As needed, the stockpiled ore is further crushed and screened to about 50 millimeters (2 inches) in
diameter. If the moisture content of the mined ore is greater than about 0.5 weight percent, the ore
must be dried in a rotary dryer or a heated roller mill. Ore dried in a rotary dryer is conveyed to a
roller mill, where it is ground to the extent that 90 percent of it is less 149 micrometers (100 mesh).
The ground gypsum exits the mill in a gas stream and is collected in a product cyclone. Ore is
sometimes dried in the roller mill by heating the gas stream, so that drying and grinding are
accomplished simultaneously and no rotary dryer is needed. The finely ground gypsum ore is known
as landplaster, which may be used as a soil conditioner.
In most plants, landplaster is fed to kettle calciners or flash calciners, where it is heated to
remove three-quarters of the chemically bound water to form stucco. Calcination occurs at
approximately 120° to 150°C (250° to 300°F), and 0.908 megagrams (Mg) (1 ton) of gypsum
calcines to about 0.77 Mg (0.85 ton) of stucco.
In kettle calciners, the gypsum is indirectly heated by hot combustion gas passed through flues
in the kettle, and the stucco product is discharged into a "hot pit" located below the kettle. Kettle
calciners may be operated in either batch or continuous mode. In flash calciners, the gypsum is
directly contacted with hot gases, and the stucco product is collected at the bottom of the calciner.
At some gypsum plants, drying, grinding, and calcining are performed in heated impact mills.
In these mills hot gas contacts gypsum as it is ground. The gas dries and calcines the ore and then
conveys the stucco to a product cyclone for collection. The use of heated impact mills eliminates the
need for rotary dryers, calciners, and roller mills.
Gypsum and stucco are usually transferred from one process to another by means of screw
conveyors or bucket elevators. Storage bins or silos are normally located downstream of roller mills
and calciners but may also be used elsewhere.
7/93 Mineral Products Industry 8.14-1
-------
©~
0 ©
t i
©
Product
cyclone
Key to Source Classification Codes
(5 3-05-015-05, -06
H 3-05-015-08
B 3-05-015-07
E) 3-06-O15-09
E 3-05-015-01
B 3-05-015-02
S3 3-05-015-04
IB 3-OS-O15-11. -12
IE 3-05-015-14
HI 3-05-015-18
B 3-05-015-17
Calcfner
0
1 1
Sr'-V
Conveying
Hot
pit
Key to Emission Sources I
© Point source PM emissions I
(2) Combustion emissions •
(J) Fugitive PM emissions
Sold as
prefabricat
Paper rolls
1 .' Water, foam \ «»«
"" r-1 ^\ ^__^-- paper and/or \ |»iwd
(?) 1 •' _—- ^^^""^ pulpwood \^_^
^^ Scoring and \ Pan mixer ^/ '. lp'
chamfering 111 \
*\ X'\
N^ t 1 f i" i Mult'-aeck '
1 Boardline convevor board drying | ^ 1
ird y
ucta/
9
Board end !
sawing i
1 kiln ! " 11.1
Figure 8.14-1. Overall process flow diagram for gypsum processing.
8.14-2
EMISSION FACTORS
7/93
-------
In the manufacture of plasters, stucco is ground further in a tube or ball mill and then batch-
mixed with retarders and stabilizers to produce plasters with specific setting rates. The thoroughly
mixed plaster is fed continuously from intermediate storage bins to a bagging operation.
In the manufacture of wallboard, stucco from storage is first mixed with dry additives such as
perlite, starch, fiberglass, or vermiculite. This dry mix is combined with water, soap foam,
accelerators and shredded paper, or pulpwood in a pin mixer at the head of a board forming line.
The slurry is then spread between two paper sheets that serve as a mold. The edges of the paper are
scored, and sometimes chamfered, to allow precise folding of the paper to form the edges of the
board. As the wet board travels the length of a conveying line, the calcium sulfate hemihydrate
combines with the water in the slurry to form solid calcium sulfate dihydrate, or gypsum, resulting in
rigid board. The board is rough-cut to length, and it enters a multideck kiln dryer, where it is dried
by direct contact with hot combustion gases or by indirect steam heating. The dried board is
conveyed to the board end sawing area and is trimmed and bundled for shipment.
8.14.2 Emissions and Controls2'7
Potential emission sources in gypsum processing plants are shown in Figure 8.14-1. While
paniculate matter (PM) is the dominant pollutant in gypsum processing plants, several sources may
emit gaseous pollutants also. The major sources of PM emissions include rotary ore dryers, grinding
mills, calciners, and board end sawing operations. Paniculate matter emission factors for these
operations are shown in Table 8.14-1. In addition, emission factors for PM less than or equal to 10
microns in aerodynamic diameter (PM10) emissions from selected processes are presented in
Table 8.14-1. All of these factors are based on output production rates. Particle size data for ore
dryers, calciners, and board end sawing operations are shown in Tables 8.14-2 and 8.14-3.
The uncontrolled emission factors presented in Table 8.14-1 represent the process dust
entering the emission control device. It is important to note that emission control devices are
frequently needed to collect the product from some gypsum processes and, thus, are commonly
thought of by the industry as process equipment and not as added control devices.
Emissions sources in gypsum plants are most often controlled with fabric filters. These
sources include:
- rotary ore dryers (SCC 3-05-015-01) - board end sawing (SCC 3-05-015-21,-22)
- roller mills (SCC 3-05-015-02) - scoring and chamfering (SCC 3-05-015-_)
- impact mills (SCC 3-05-015-13) - plaster mixing and bagging (SCC 3-05-015-16,-17)
- kettle calciners (SCC 3-05-015-11) - conveying systems (SCC 3-05-015-04)
- flash calciners (SCC 3-05-015-12) - storage bins (SCC 3-05-015-09,-10,-14)
Uncontrolled emissions from scoring and chamfering, plaster mixing and bagging, conveying systems,
and storage bins are not well quantified.
Emissions from some gypsum sources are also controlled with electrostatic precipitators
(ESP's). These sources include rotary ore dryers, roller mills, kettle calciners, and conveying
systems. Although rotary ore dryers may be controlled separately, emissions from roller mills and
conveying systems are usually controlled jointly with kettle calciner emissions. Moisture in the kettle
calciner exit gas improves the ESP performance by lowering the resistivity of the dust.
7/93 Mineral Products Industry 8.14-3
-------
TABLE 8.14-1 (METRIC UNITS)
EMISSION FACTORS FOR GYPSUM PROCESSING*
All Emission Factors in kg/Mg of Output Rate
Ratings (A-E) follow Each Emission Factor
Process (SCC)
Crushers, screens, stockpiles, and roads
(3-05-015-05,-06,-07,-08)
Rotary ore dryers (3-05-015-01)
Rotary ore dryers w/ fabric filters
(3-05-015-01)
Roller mills w/ cyclones (3-05-015-02)
Roller mills w/ fabric filters
(3-05-015-02)
Roller mill and kettle calciner
w/electrostatic precipitators
(3-05-015-02,-! 1)
Continuous kettle calciners and hot pit
(3-05-015-11)
Continuous kettle calciners and hot pit
w/ fabric filters (3-05-015-11)
Continuous kettle calciners w/ cyclones
and electrostatic precipitators
(3-05-015-11)
Flash calciners (3-05-015-12)
Flash calciners w/fabric filters
(3-05-015-12)
Impact mills w/cyclones (3-05-015-13)
Impact mills w/ fabric filters
(3-05-015-13)
Board end sawing-2.4-m boards
(3-05-015-21)
Board end sawing~3.7-m boards
(3-05-015-22)
Board end sawing w/ fabric filters~2.4-
and 3.7-m boards (3-05-015-21, -22)
Filterable PMb
d
0.0042(FFF)1-7e
0.0208
1.3h
0.06011
O.OSO"'1
21J
0.0030J
0.050J
19k
0.020k
50m
0.010m
0.040"
0.030°
36°
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
PM10
d
0.00034(FFF)1<7
0.0052
ND
ND
ND
13
ND
ND
7.2
0.017
ND
ND
ND
ND
27
D
D
D
D
D
D
CO2C
NA
12f
NA
NA
NA
ND
ND
NA
NA
551
ND
NA
NA
NA
NA
NA
D
D
8.14-4
EMISSION FACTORS
7/93
-------
Table 8.14-1 (METRIC UNITS) (continued)
ND = No data available. NA = Not applicable.
"Factors represent uncontrolled emissions unless otherwise specified.
bFilterable PM is that PM collected on or prior to an EPA Method 5 (or equivalent) sampling train.
typical pollution control devices generally have a negligible effect on CO2 emissions.
dFactors for these operations are in Sections 8.19 and 11.2.
"References 3-4, 8, 11-12. Equation is for the emission rate upstream of any process cyclones and
applies only to concurrent rotary ore dryers with flowrates of 7.5 cubic meters per second (m3/s) or
less. FFF in the uncontrolled emission factor equation is "flow feed factor," the ratio of gas mass
rate per unit dryer cross section area to the dry mass feed rate, in the following units: (kg/hr-m2 of
gas flow)/(Mg/hr dry feed). Measured uncontrolled emission factors for 4.2 and 5.7 m3/s range
from 5 to 60 kg/Mg.
'References 3-4.
References 3-4, 8, 11-12. Applies to rotary dryers with and without cyclones upstream of fabric
filter.
hReferences 11-14. Applies to both heated and unheated roller mills.
'References 11-14. Factor is for combined emissions from roller mills and kettle calciners, based on
the sum of the roller mill and kettle calciner output rates.
JReferences 4-5, 11, 13-14. Emission factors based on the kettle and the hot pit do not apply to batch
kettle calciners.
References 3, 6, 10.
'References 3, 6, 9.
"References 9, 15. As used here, an impact mill is a process unit used to dry, grind, and calcine
gypsum simultaneously.
"References 4-5, 16. Emission factor units = kg/m2. Based on 13 mm board thickness and 1.2 m
board width. For other thicknesses, multiply the appropriate emission factor by 0.079 times board
thickness in mm.
References 4-5, 16. Emission factor units = kg/106 m2.
7/93 Mineral Products Industry 8.14-5
-------
TABLE 8.14-1 (ENGLISH UNITS)
EMISSION FACTORS FOR GYPSUM PROCESSING8
All Emission Factors in Rate
Ratings (A-E) follow Each Emission Factor
Process (SCC)
Crushers, screens, stockpiles, and roads
(3-05-015-05,-06,-07,-08)
Rotary ore dryers (3-05-015-01)
Rotary ore dryers w/fabric filters
(3-05-015-01)
Roller mills w/cyclones (3-05-015-02)
Roller mills w/ fabric filters
(3-05-015-02)
Roller mill and kettle calciner w/
electrostatic precipitators
(3-05-015-02,-! 1)
Continuous kettle calciners and hot pit
(3-05-015-11)
Continuous kettle calciners and hot pit
w/ fabric filters (3-05-015-1 1)
Continuous kettle calciners w/ cyclones
and electrostatic precipitators
(3-05-015-11)
Flash calciners (3-05-015-12)
Flash calciners w/fabric filters
(3-05-015-12)
Impact mills w/ cyclones (3-05-015-13)
Impact mills w/ fabric filters
(3-05-015-13)
Board end sawing~8-ft boards
(3-05-015-21)
Board end sawing— 12-ft boards
(3-05-015-22)
Board end sawing w/ fabric filters-S-
and 12-ft boards (3-05-0 15-21, -22)
Filterable PMb
d
O.ietFFF)1-77*
0.040«
2.6h
0.12h
O.OQO11'1
41J
o.oo60>
0.090>
37k
0.040k
lOO"1
0.020m
0.80"
0.50"
7.5°
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
PM10
d
0.013CFFF)1'7
0.010
ND
ND
ND
26
ND
ND
14
0.034
ND
ND
ND
ND
5.7
D
D
D
D
D
D
C02C
NA
23f
NA
NA
NA
ND
ND
NA
NA
no1
ND
NA
NA
NA
NA
NA
D
D
8.14-6
EMISSION FACTORS
7/93
-------
Table 8.14-1 (ENGLISH UNITS) (continued)
ND = No data available. NA = Not applicable.
"Factors represent uncontrolled emissions unless otherwise specified.
bFilterable PM is that paniculate collected on or prior to an EPA Method 5 (or equivalent) sampling
train.
cTypical pollution control devices generally have a negligible effect on CO2 emissions.
dFactors for these operations are in Sections 8.19 and 11.2.
References 3-4, 8, 11-12. Equation is for the emission rate upstream of any process cyclones and
applies only to concurrent rotary ore dryers with flowrates of 16,000 actual cubic feet per minute
(acfrn) or less. FFF in the uncontrolled emission factor equation is "flow feed factor," the ratio of
gas mass rate per unit dryer cross section area to the dry mass feed rate, in the following units:
(lb/hr-ft2 of gas flow)/(ton/hr dry feed). Measured uncontrolled emission factors for 9,000 and
12,000 acfm range from 10 to 120 Ib/ton.
'References 3-4.
References 304, 8, 11-12. Applies to rotary dryers with and without cyclones upstream of fabric
filter.
References 11-14. Applies to both heated and unheated roller mills.
'References 11-14. Factor is for combined emissions from roller mills and kettle calciners, based on
the sum of the roller mill and kettle calciner output rates.
•(References 4-05, 11, 13-14. Emission factors based on the kettle and the hot pit do not apply to
batch kettle calciners.
References 3, 6, 10.
References 3, 6, 9.
"References 9, IS. As used here, an impact mill is a process unit used to dry, grind, and calcine
gypsum simultaneously.
References 4-5, 16. Emission factor units = lb/100 ft2. Based on 1/2-in. board thickness and 4-ft
board width. For other thicknesses, multiply the appropriate emission factor by 2 times board
thickness in inches.
References 4-5, 16. Emission factor units = lb/106 ft2.
7/93 Mineral Products Industry 8.14-7
-------
TABLE 8.14-2. SUMMARY OF PARTICLE SIZE DISTRIBUTION DATA FOR
UNCONTROLLED PM EMISSIONS FROM GYPSUM PROCESSING*
EMISSION FACTOR RATING: D
Diameter
(microns)
Cumulative % less than diameter
Rotary ore
dryerb
Rotary ore dryer
with cyclone6
Continuous kettle
calcinerd
Flash calciner6
2.0 1 12 17 10
10.0 8 45 63 38
"Weight percent given as filterable PM. Diameter is given as aerodynamic diameter, except for
continuous kettle calciner, which is given as equivalent diameter, as determined by Bahco and
Sedigraph analyses.
bReference 3.
cReference 4.
dReferences 4, 5.
References 3, 6.
TABLE 8.14-3. SUMMARY OF PARTICLE SIZE DISTRIBUTION DATA FOR
FABRIC FILTER-CONTROLLED PM EMISSIONS FROM GYPSUM MANUFACTURING*
EMISSION FACTOR RATING: D
Diameter
(microns)
Cumulative % less than diameter
Rotary ore dryerb
2.0 9
10.0 26
Flash calciner0
52
84
Board end sawing0
49
76
^Aerodynamic diameters, Andersen analysis.
Reference 3.
°Reference 3, 6.
8.14-8
EMISSION FACTORS
7/93
-------
Other sources of PM emissions in gypsum plants are primary and secondary crushers,
screens, stockpiles, and roads. If quarrying is part of the mining operation, PM emissions may also
result from drilling and blasting. Emission factors for some of these sources are presented in
Sections 8.19 and 11.2. Gaseous emissions from gypsum processes result from fuel combustion and
may include nitrogen oxides, sulfur oxides, carbon monoxide, and carbon dioxide (CO2). Processes
using fuel include rotary ore dryers, heated roller mills, impact mills, calciners, and board drying
kilns. Although some plants use residual fuel oil, the majority of the industry uses clean fuels such as
natural gas or distillate fuel oil. Emissions from fuel combustion may be estimated using emission
factors presented in Sections 1.3 and 1.4 and fuel consumption data in addition to those emission
factors presented in Table 8.14-1.
REFERENCES FOR SECTION 8.14
1. Kirk-Othmer Encyclopedia of Chemical Technology, Volume 4, John Wiley & Sons, Inc., New
York, 1978.
2. Gypsum Industry - Background Information for Proposed Standards (Draft), U. S. Environmental
Protection Agency, Research Triangle Park, NC, April 1981.
3. Source Emissions Test Report, Gold Bond Building Products, EMB-80- GYP-1,
U. S. Environmental Protection Agency, Research Triangle Park, NC, November 1980.
4. Source Emissions Test Report, United States Gypsum Company, EMB-80- GYP-2,
U.S. Environmental Protection Agency, Research Triangle Park, NC, November 1980.
5. Source Emission Tests, United States Gypsum Company Wallboard Plant, EMB-80-GYP-6,
U. S. Environmental Protection Agency, Research Triangle Park, NC, January 1981.
6. Source Emission Tests, Gold Bond Building Products, EMB-80-GYP-5, U. S. Environmental
Protection Agency, Research Triangle Park, NC, December 1980.
7. S. Oglesby and G. B. Nichols, A Manual of Electrostatic Precipitation Technology, Part II:
Application Areas, APTD-0611, U. S. Environmental Protection Agency, Cincinnati, OH,
August 25, 1970.
8. Official Air Pollution Emission Tests Conducted on the Rock Dryer and No. 3 Calcidyne Unit,
Gold Bond Building Products, Report No. 5767, Rosnagel and Associates, Medford, NJ,
August 3, 1979.
9. Particulate Analysis ofCalcinator Exhaust at Western Gypsum Company, Kramer, Callahan and
Associates, Rosario, NM, April 1979. Unpublished.
10. Official Air Pollution Tests Conducted on the #7 Calcidyner Baghouse Exhaust at the National
Gypsum Company, Report No. 2966, Rossnagel and Associates, Atlanta, GA, April 10, 1978.
11. Report to United States Gypsum Company on Particulate Emission Compliance Testing,
Environmental Instrument Systems, Inc., South Bend, IN, November 1975. Unpublished.
7/93 Mineral Products Industry 8.14-9
-------
12. Paniculate Emission Sampling and Analysis, United States Gypsum Company, Environmental
Instrument Systems, Inc., South Bend, IN, July 1973. Unpublished.
13. Written communication from Wyoming Air Quality Division, Cheyenne, WY, to M. Palazzolo,
Radian Corporation, Durham, NC, 1980.
14. Written communication from V. J. Tretter, Georgia-Pacific Corporation, Atlanta, GA, to
M. E. Kelly, Radian Corporation, Durham, NC, November 14, 1979.
IS. Telephone communication between M. Palazzolo, Radian Corporation, Durham, NC, and
D. Louis, C. E. Raymond Company, Chicago, IL, April 23, 1981.
16. Written communication from M. Palazzolo, Radian Corporation, Durham, NC, to B. L. Jackson,
Weston Consultants, West Chester, PA, June 19, 1980.
17. Telephone communication between P. J. Murin, Radian Corporation, Durham, NC, and
J. W. Pressler, U. S. Department of the Interior, Bureau of Mines, Washington, DC,
November 6, 1979.
8.14-10 EMISSION FACTORS 7/93
-------
8.16 MINERAL WOOL MANUFACTURING
8.16.1 General1'2
Mineral wool often is defined as any fibrous glassy substance made from minerals (typically
natural rock materials such as basalt or diabase) or mineral products such as slag and glass. Because
glass wool production is covered separately in AP-42 (Section 8.11), this section deals only with the
production of mineral wool from natural rock and slags such as iron blast furnace slag, the primary
material, and copper, lead, and phosphate slags. These materials are processed into insulation and
other fibrous building materials that are used for structural strength and fire resistance. Generally,
these products take one of four forms: "blowing" wool or "pouring" wool, which is put into the
structural spaces of buildings; batts, which may be covered with a vapor barrier of paper or foil and
are shaped to fit between the structural members of buildings; industrial and commercial products
such as high-density fiber felts and blankets, which are used for insulating boilers, ovens, pipes,
refrigerators, and other process equipment; and bulk fiber, which is used as a raw material in
manufacturing other products, such as ceiling tile, wall board, spray-on insulation, cement, and
mortar.
Mineral wool manufacturing facilities are included in Standard Industrial Classification (SIC)
Code 3296, mineral wool. This SIC code also includes the production of glass wool insulation
products, but those facilities engaged in manufacturing textile glass fibers are included in SIC
Code 3229. The six digit source category code (SCC) for mineral wool manufacturing is 3-05-017.
8.16.2 Process Description1'4'5
Most mineral wool produced in the United States today is produced from slag or a mixture of
slag and rock. Most of the slag used by the industry is generated by integrated iron "and steel plants
as a blast furnace byproduct from pig iron production. Other sources of slag include the copper,
lead, and phosphate industries. The production process has three primary components—molten
mineral generation in the cupola, fiber formation and collection, and final product formation.
Figure 8.16-1 illustrates the mineral wool manufacturing process.
The first step in the process involves melting the mineral feed. The raw material (slag and
rock) is loaded into a cupola in alternating layers with coke at weight ratios of about 5 to 6 parts
mineral to 1 part coke. As the coke is ignited and burned, the mineral charge is heated to the molten
state at a temperature of 1300° to 1650°C (2400° to 3000°F). Combustion air is supplied through
tuyeres located near the bottom of the furnace. Process modifications at some plants include air
enrichment and the use of natural gas auxiliary burners to reduce coke consumption. One facility also
reported using an aluminum flux byproduct to reduce coke consumption.
The molten mineral charge exits the bottom of the cupola in a water-cooled trough and falls
onto a fiberization device. Most of the mineral wool produced in the United States is made by
variations of two fiberization methods. The Powell process uses groups of rotors revolving at a high
rate of speed to form the fibers. Molten material is distributed in a thin film on the surfaces of the
rotors and then is thrown off by centrifugal force. As the material is discharged from the rotor, small
globules develop on the rotors and form long, fibrous tails as they travel horizontally. Air or steam
7/93 Mineral Products Industry 8.16-1
-------
From Processing
Granulaled
ft-oducto
8.16-2
Figure 8.16-1. Mineral wool manufacturing process flow diagram.
EMISSION FACTORS
7/93
-------
may be blown around the rotors to assist in fiberizing the material. A second fiberization method, the
Downey process, uses a spinning concave rotor with air or steam attenuation. Molten material is
distributed over the surface of the rotor, from which it flows up and over the edge and is captured
and directed by a high-velocity stream of air or steam.
During the spinning process, not all globules that develop are converted into fiber. The
nonfiberized globules that remain are referred to as "shot." In raw mineral wool, as much as half of
the mass of the product may consist of shot. As shown in Figure 8.16-1, shot is usually separated
from the wool by gravity immediately following fiberization.
Depending on the desired product, various chemical agents may be applied to the newly
formed fiber immediately following the rotor. In almost all cases, an oil is applied to suppress dust
and, to some degree, anneal the fiber. This oil can be either a proprietary product or a medium-
weight fuel or lubricating oil. If the fiber is intended for use as loose wool or bulk products, no
further chemical treatment is necessary. If the mineral wool product is required to have structural
rigidity, as in batts and industrial felt, a binding agent is applied with or in place of the oil treatment.
This binder is typically a phenol-formaldehyde resin that requires curing at elevated temperatures.
Both the oil and the binder are applied by atomizing the liquids and spraying the agents to coat the
airborne fiber.
After formation and chemical treatment, the fiber is collected in a blowchamber.
Resin-and/or oil-coated fibers are drawn down on a wire mesh conveyor by fans located beneath the
collector. The speed of the conveyor is set so that a wool blanket of desired thickness can be
obtained.
Mineral wool containing the binding agent is carried by conveyor to a curing oven, where the
wool blanket is compressed to the appropriate density and the binder is baked. Hot air, at a
temperature of 150° to 320°C (300° to 600°F), is forced through the blanket until the binder has set.
Curing time and temperature depend on the type of binder used and the mass rate through the oven.
A cooling section follows the oven, where blowers force air at ambient temperatures through the wool
blanket.
To make batts and industrial felt products, the cooled wool blanket is cut longitudinally and
transversely to the desired size. Some insulation products are then covered with a vapor barrier of
aluminum foil or asphalt-coated kraft paper on one side and untreated paper on the other side. The
cutters, vapor barrier applicators, and conveyors are sometimes referred to collectively as a batt
machine. Those products that do not require a vapor barrier, such as industrial felt and some
residential insulation batts, can be packed for shipment immediately after cutting.
Loose wool products consist primarily of blowing wool and bulk fiber. For these products,
no binding agent is applied, and the curing oven is eliminated. For granulated wool products, the
fiber blanket leaving the blowchamber is fed to a shredder and pelletizer. The pelletizer forms small,
1-inch diameter pellets and separates shot from the wool. A bagging operation completes the
processes. For other loose wool products, fiber can be transported directly from the blowchamber to
a baler or bagger for packaging.
7/93 Mineral Products Industry 8.16-3
-------
8.16.3 Emissions and Controls1'13
The sources of emissions in the mineral wool manufacturing industry are the cupola; binder
storage, mixing, and application; the blow chamber; the curing oven; the mineral wool cooler;
materials handling and bagging operations; and wastewater treatment and storage. With the exception
of lead, the industry emits the full range of criteria pollutants. Also, depending on the particular
types of slag and binding agents used, the facilities may emit both metallic and organic hazardous air
pollutants (HAP's).
The primary source of emissions in the mineral wool manufacturing process is the cupola. It
is a significant source of paniculate matter (PM) emissions and is likely to be a source of PM less
than 10 micrometers (jim) in diameter (PM-10) emissions, although no particle size data are available.
The cupola is also a potential source of HAP metal emissions attributable to the coke and slags used
in the furnace. Coke combustion in the furnace produces carbon monoxide (CO), carbon dioxide
(CO2), and nitrogen oxide (NOX) emissions. Finally, because blast furnace slags contain sulfur, the
cupola is also a source of sulfur dioxide (SO2) and hydrogen sulfide (H2S) emissions.
The blowchamber is a source of PM (and probably PM-10) emissions. Also, the annealing
oils and binders used in the process can lead to VOC emissions from the process. Other sources of
VOC emissions include batt application, the curing oven, and wastewater storage and treatment.
Finally, fugitive PM emissions can be generated during cooling, handling, and bagging operations.
Tables 8.16-1 and 8.16-2 present emission factors for filterable PM emissions from various mineral
wool manufacturing processes; Tables 8-16.3 and 8.16-4 show emission factors for CO, CO2, SO2,
and sulfates; and Tables 8.16-5 and 8.16-6 present emission factors for NOX, N2O, H2S and
fluorides.
Mineral wool manufacturers use a variety of air pollution control techniques, but most are
directed toward PM control with minimal control of other pollutants. The industry has given greatest
attention to cupola PM control, with two-thirds of the cupolas in operation having fabric filter control
systems. Some cupola exhausts are controlled by wet scrubbers and electrostatic precipitators
(ESP's); cyclones are also used for cupola PM control either alone or in combination with other
control devices. About half of the blow chambers in the industry also have some level of PM
control, with the predominant control device being low-energy wet scrubbers. Cyclones and fabric
filters have been used to a limited degree on blow chambers. Finally, afterburners have been used to
control VOC emissions from blow chambers and curing ovens and CO emissions from cupolas.
8.16-4 EMISSION FACTORS 7/93
-------
Table 8.16-1. (Metric Units)
EMISSION FACTORS FOR MINERAL WOOL MANUFACTURING*
Process
Cupola0 (30501701)
(SCQ kg
P
Cupola with fabric filter*1 (30501701)
Reverberatory furnace6 (30501702)
Batt curing ovene (30501704)
Batt curing oven with ESPf
Blow chamber0 (30501703)
(30501704)
Blow chamber with wire mesh filter^ (30501703)
Cooler6 (30501705)
Filterable PMb
/Mg of Emission
roduct Factor Rating
8.2 E
0.051 D
2.4 E
1.8 E
0.36 D
6.0 E
0.45 D
1.2 E
'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.
References 1, 12. Activity level is assumed to be total feed charged.
References 6, 7, 8, 10, and 11. Activity level is total feed charged.
"Reference 12.
^Reference 9.
^Reference 7. Activity level is mass of molten mineral feed charged.
7/93
Mineral Products Industry
8.16-5
-------
Table 8.16-2. (English Units)
EMISSION FACTORS FOR MINERAL WOOL MANUFACTURING*
Process (SCC)
Cupola0 (30501701)
Cupola with fabric filterd (30501701)
Reverberatory furnace6 (30501702)
Batt curing oven6 (30501704)
Batt curing oven with ESPf (30501704)
Blow chamber6 (30501703)
Blow chamber with wire mesh filter^ (30501703)
Cooler6 (30501705)
Filterable PMb
Ib/ton of
product
16
0.10
4.8
3.6
0.72
12
0.91
2.4
Emission
Factor Rating
E
D
E
E
D
E
D
E
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.
"Reference 1, 12. Activity level is assumed to be total feed charged.
References 6, 7, 8, 10, and 11. Activity level is total feed charged.
Reference 12.
Reference 9.
gReference 7. Activity level is mass of molten mineral feed charged.
8.16-6
EMISSION FACTORS
7/93
-------
Table 8.16-3 (Metric Units)
EMISSION FACTORS FOR MINERAL WOOL MANUFACTURING*
Source (SCC)
cob
kg/Mg of
total feed
charged
Cupola (30501701) 125
Cupola with fabric NA
filter (30501701)
Batt curing oven ND
(30501704)
Blow chamber ND
(30501703)
Cooler (30501705) ND
Emission
Factor
Rating
C02b
kg/Mg of
total feed
charged
D 260
NA
ND
80e
ND
Emissio
n Factor
Rating
S02
kg/Mg of
total feed
charged
D 4.0C
NA
0.58d
E 0.43d
0.034d
Emission
Factor
Rating
S03
kg/Mg of
total feed
charged
D 3.2d
0.077b
E ND
E ND
E ND
Emissio
n Factor
Rating
E
E
NA = Not applicable.
ND = No data available.
"Factors represent uncontrolled emissions unless otherwise noted.
bReference 6.
References 6, 10, and 11.
dReference 12.
Reference 9.
7/93
Mineral Products Industry
8.16-7
-------
Table 8.16-4 (English Units)
EMISSION FACTORS FOR MINERAL WOOL MANUFACTURING4
Source (SCC)
cob
lb/ton of
total feed
charged
Cupola (30501701) 250
Cupola with fabric filter NA
(30501701)
Batt curing oven ND
(30501704)
Blow chamber ND
(30501703)
Cooler (30501705) ND
Emission
Factor
Rating
CO2b
lb/ton of Emission
total feed Factor
charged Rating
SO2
lb/ton of
total feed
charged
D 520 D 8.0*
NA NA
ND 1.2d
160e E 0.087d
ND 0.068d
Emission
Factor
Rating
SO3
lb/ton of
total feed
charged
D 6.3d
0.15b
E ND
E ND
E ND
Emission
Factor
Rating
E
E
NA = Not applicable.
ND = No data available.
aFactors represent uncontrolled emissions unless otherwise noted.
bReference 6.
References 6, 10, and 11.
Reference 12.
eReference 9.
8.16-8
EMISSION FACTORS
7/93
-------
Table 8.16-5 (Metric Units)
EMISSION FACTORS FOR MINERAL WOOL MANUFACTURING4
Process (SCC)
NOX
kg/Mg of
total feed
charged
Cupola (30501701) 0.8b
Cupola with fabric filter (30501701) ND
Cupola with fabric filter (30501701) ND
Batt curing oven (30501714) ND
Emission
Factor
Rating
N2O
kg/Mg of
total feed
charged
E ND
ND
ND
0.079
Emission
Factor
Rating
H2S
kg/Mg of
total feed
charged
1.5b
ND
ND
E ND
Emission
Factor
Rating
Fluorides
kg/Mg of
total feed
charged
E ND
0.019C
0.19d
ND
Emission
Factor
Rating
D
D
D.
B.
I
ND = No data available.
aFactors represent uncontrolled emissions unless otherwise noted.
bReference 1.
References 10 and 11. Coke only used as fuel.
dReferences 10 and 11. Fuel combination of coke and aluminum smelting byproducts.
oo
-------
00
Table 8.16-6 (English Units)
EMISSION FACTORS FOR MINERAL WOOL MANUFACTURING11
Process (SCC)
Cupola (30501701)
Cupola with fabric filter (30501701)
Cupola with fabric filter (30501701)
Batt curing oven (30501714)
NOX
Ib/ton of
total feed
charged
1.6b
ND
ND
ND
Emission
Factor
Rating
E
N2O
Ib/ton of
total feed
charged
ND
ND
ND
0.16
Emission
Factor
Rating
E
H2S
Ib/ton of
total feed
charged
3. Ob
ND
ND
ND
Emission
Factor
Rating
E
Fluorides
Ib/ton of
total feed
charged
ND
0.038C
0.38d
ND
Emission
Factor
Rating
D
D
m
I/}
00
O
Z
8
on
ND = No data available.
aFactors represent uncontrolled emissions unless otherwise noted.
bReference 1.
References 10 and 11. Coke only used as fuel.
dReferences 10 and 11. Fuel combination of coke and aluminum smelting byproducts.
-------
REFERENCES FOR SECTION 8.16
1. Source Category Survey: Mineral Wool Manufacturing Industry, EPA-450/3-80-016, U. S.
Environmental Protection Agency, Research Triangle Park, NC, March 1980.
2. The Facts on Rocks and Slag Wool, Pub. No. N 020, North American Insulation
Manufacturers Association, Alexandria, VA, Undated.
3. ICF Corporation, Supply Response to Residential Insulation Retrofit Demand, Report to the
Federal Energy Administration, Contract No. P-14-77-5438-0, Washington, D.C.,
June 1977.
4. Personal communication between F. May, U.S.G. Corporation, Chicago, Illinois, and
R. Marinshaw, Midwest Research Institute, Gary, NC, June 5, 1992.
5. Memorandum from K. Schuster, N.C. Department of Environmental Management, to M.
Aldridge, American Rockwool, April 25, 1988.
6. Sulfur Oxide Emission Tests Conducted on the #1 and #2 Cupola Stacks in Leeds, Alabama
for Rock Wool Company, November 8 & 9, 1988, Guardian Systems, Inc., Leeds, AL,
Undated.
7. Particulate Emissions Tests for U.S. Gypsum Company on the Number 4 Dry Filter and
Cupola Stack Located in Birmingham, Alabama on January 14, 1981, Guardian Systems,
Inc., Birmingham, AL, Undated.
8. Untitled Test Report, Cupolas Nos. 1, 2, and 3, U.S. Gypsum, Birmingham, AL, June 1979.
9. Particulate Emission Tests on Batt Curing Oven for U.S. Gypsum, Birmingham, Alabama on
October 31-November 1, 1977, Guardian Systems, Inc., Birmingham, AL, Undated.
10. J.V. Apicella, Particulate, Sulfur Dioxide, and Fluoride Emissions from Mineral Wool
Emission, with Varying Charge Compositions, American Rockwool, Inc. Spring Hope, N. C.
27882, Alumina Company of America, Alcoa Center, PA, June 1988.
11. J.V. Apicella, Compliance Report on Particulate, Sulfur Dioxide, Fluoride, and Visual
Emissions from Mineral Wool Production, American Rockwool, Inc., Spring Hope, NC
27882, Aluminum Company of America, Alcoa Center, PA, February 1988.
12. J.L. Spinks, "Mineral Wool Furnaces," In: Air Pollution Engineering Manual, J.A.
Danielson, ed., U. S. DHEW, PHS, National Center for Air Pollution Control, Cincinnati,
OH. PHS Publication Number 999-AP-40, 1967, pp. 343-347.
13. Personal communication between M. Johnson, U. S. Environmental Protection Agency,
Research Triangle Park, NC, and D. Bullock, Midwest Research Institute, Gary, NC,
March 22, 1993.
7/93 Mineral Products Industry 8.16-11
-------
8.17 PERLITE PROCESSING
8.17.1 Process Description1 >2
Perlite is a glassy volcanic rock with a pearl-like luster. It usually exhibits numerous
concentric cracks that cause it to resemble an onion skin. A typical perlite sample is composed of 71
to 75 percent silicon dioxide, 12.5 to 18.0 percent alumina, 4 to 5 percent potassium oxide, 1 to
4 percent sodium and calcium oxides, and trace amounts of metal oxides.
Crude perlite ore is mined, crushed, dried in a rotary dryer, ground, screened, and shipped to
expansion plants. Horizontal rotary or vertical stationary expansion furnaces are used to expand the
processed perlite ore.
The normal size of crude perlite expanded for use in plaster aggregates ranges from plus
250 micrometers (jim) (60 mesh) to minus 1.4 millimeters (mm) (12 mesh). Crude perlite expanded
for use as a concrete aggregate ranges from 1 mm (plus 16 mesh) to 0.2 mm (plus 100 mesh).
Ninety percent of the crude perlite ore expanded for horticultural uses is greater than 841 /im
(20 mesh).
Crude perlite is mined using open-pit methods and then is moved to the plant site, where it is
stockpiled. Figure 8.17-1 is a flow diagram of crude ore processing. The first processing step is to
reduce the diameter of the ore to approximately 1.6 centimeters (cm) (0.6 inch [in.]) in a primary jaw
crusher. The crude ore is then passed through a rotary dryer, which reduces the moisture content
from between 4 and 10 percent to less than 1 percent.
After drying, secondary grinding takes place in a closed-circuit system using screens, air
classifiers, hammer mills, and rod mills. Oversized material produced from the secondary circuit is
returned to the primary crusher. Large quantities of fines, produced throughout the processing
stages, are removed by air classification at designated stages. The desired size processed perlite ore
is stored until it is shipped to an expansion plant.
At the expansion plants, the processed ore is either preheated or fed directly to the furnace.
Preheating the material to approximately 430°C (800°F) reduces the amount of fines produced in the
expansion process, which increases usable output and controls the uniformity of product density. In
the furnace, the perlite ore reaches a temperature of 760° to 980°C (1400° to 1800°F), at which
point it begins to soften to a plastic state where the entrapped combined water is released as steam.
This causes the hot perlite particles to expand 4 to 20 times their original size. A suction fan draws
the expanded particles out of the furnace and transports them pneumatically to a cyclone classifier
system to be collected. The air-suspended perlite particles are also cooled as they are transported to
the collection equipment. The cyclone classifier system collects the expanded perlite, removes the
excessive fines, and discharges gases to a baghouse or wet scrubber for air pollution control.
The grades of expanded perlite produced can also be adjusted by changing the heating cycle,
altering the cutoff points for size collection, and blending various crude ore sizes. All processed
products are graded for specific uses and are usually stored before being shipped. Most production
rates are less than 1.8 megagrams per hour (Mg/hr) megagrams (2 tons/hr), and expansion furnace
7/93 Mineral Products Industry 8.17-1
-------
,YAHD STORAGE
DRYER
STORAGE
SCREENING
AND SIZING
8AGHOUSE OH
WET SCRUBBER
EXPANSION
FURNACE
CSCC: 3-05-018-015
SHIPPING
TO EXPANSION
PLANT
STORAGE
BINS
BAGGING
.AND
SHI PPI NG
8.17-2
Figure 8.17-1. Flow diagram for perlite processing.1
EMISSION FACTORS
7/93
-------
temperatures range from 870° to 980°C (1600° to 1800°F). Natural gas is typically used for fuel,
although No. 2 fuel oil and propane are occasionally used. Fuel consumption varies from 2,800 to
8,960 kilojoules per kilogram (id/kg) (2.4 x 106 to 7.7 x 106 British thermal units per ton [Btu/ton])
of product.
8.17.2 Emissions and Controls1'3'11
The major pollutant of concern emitted from perlite processing facilities is paniculate matter
(PM). The dryers, expansion furnaces, and handling operations can all be sources of PM emissions.
Emissions of nitrogen oxides from perlite expansion and drying generally are negligible. When
sulfur-containing fuels are used, sulfur dioxide (SO^ emissions may result from combustion sources.
However, the most common type of fuel used in perlite expansion furnaces and dryers is natural gas,
which is not a significant source of SO2 emissions.
Test data from one perlite plant indicate that perlite expansion furnaces emit a number of trace
elements, including aluminum, calcium, chromium, fluorine, iron, lead, magnesium, manganese,
mercury, nickel, titanium, and zinc. However, because the data consist of a single test run, emission
factors were not developed for these elements. The sample also was analyzed for beryllium, uranium,
and vanadium, but these elements were not detected.
To control PM emissions from both dryers and expansion furnaces, the majority of perlite
plants use baghouses, some use cyclones either alone or in conjunction with baghouses, and a few use
scrubbers. Frequently, PM emissions from material handling processes and from the dryers are
controlled by the same device. Large plants generally have separate fabric filters for dryer emissions,
whereas small plants often use a common fabric filter to control emissions from dryers and materials
handling operations. In most plants, fabric filters are preceded by cyclones for product recovery.
Wet scrubbers are also used in a small number of perlite plants to control emissions from perlite
milling and expansion sources.
Table 8.17-1 presents emission factors for filterable PM and CO2 emissions from the
expanding and drying processes.
7/93 Mineral Products Industry 8.17-3
-------
Table 8.17-1 (Metric Units). EMISSION FACTORS FOR PERLITE PROCESSING*
Filterable Pt»
kg/Mg Em
Perlite Fz
Process (SCQ Expanded RJ
Expansion furnace (3-05-018-01) ND
Expansion furnace with wet cyclone l.ld
(3-05-018-01)
Expansion furnace with cyclone 0. 15e
and baghouse (3-05-018-01)
Dryer (3-05-01 8-_) ND
Dryer with baghouse (3-05-01 8-_J 0.64f
Dryer with
(3-05-018-.
cyclones and baghouses
_J 0.138
rfb CO2
ission kg/Mg Emission
ictor Perlite Factor
iting Expanded Rating
420C D
D NA
D NA
16f D
D NA
D NA
Table 8.17-1 (English Units). EMISSION FACTORS FOR PERLITE PROCESSING3
Ib
Pe
Process (SCC) Exp
Filterable PMb
/ton Emission
,rlite Factor
anded Rating
Expansion furnace (3-05-018-01) ND
Expansion furnace with wet cyclone 2.1d D
(3-05-018-01)
Expansion furnace with cyclone 0
and baghouse (3-05-018-01)
29e D
Dryer (3-05-01 8-_) ND
Dryer with baghouse (3-05-0 18-_) 1
Dryer with cyclones and baghouses 0
(3-05-018-_)
.28f D
258 D
C02
Ib/ton
Perlite
Expanded
850C
NA
NA
31f
NA
NA
Emission
Factor
Rating
D
D
ND = no data available. NA = not applicable.
*A11 emission factors represent controlled emissions.
bFilterable PM is that PM collected on or prior to the filter of an EPA Method 5 (or equivalent)
sampling train.
°Reference 4.
dReference 11.
References 4, 8.
'Reference 10.
^References 7, 9.
8.17-4
EMISSION FACTORS
7/93
-------
REFERENCES FOR SECTION 8.17
1. Calciners and Dryers in Mineral Industries — Background Information for Proposed Standards,
EPA-450/3-85-025a, U. S. Environmental Protection Agency, Research Triangle Park, NC,
October 1985.
2. Perlite: US Minerals Yearbook 1989, Volume I: Metals and Minerals, U.S. Department of the
Interior, Bureau of Mines, Washington, DC, pp. 765 - 767.
3. Perlite Industry Source Category Survey, EPA-450/3-80-005, U. S. Environmental Protection
Agency, Research Triangle Park, NC, February 1980.
4. Emission Test Report (Perlite): W.R. Grace and Company, Irondale, Alabama, EMB Report
83-CDR-4, U. S. Environmental Protection Agency, Research Triangle Park, NC,
February 1984.
5. Paniculate Emission Sampling and Analysis: United States Gypsum Company, East Chicago,
Indiana, Environmental Instrument Systems, Inc., South Bend, IN, July 1973.
6. Air Quality Source Sampling Report #216: Grefco, Inc., Perlite Mill, Socorro, New Mexico,
State of New Mexico Environmental Improvement Division, Santa Fe, NM, January 1982.
7. Air Quality Source Sampling Report #198: Johns Manville Perlite Plant, No Agua, New Mexico,
State of New Mexico Environmental Improvement Division, Santa Fe, NM, February 1981.
8. Stack Test Report, Perlite Process: National Gypsum Company, Roll Road, Clarence Center,
New York, Buffalo Testing Laboratories, Buffalo, NY, December 1972.
9. Paniculate Analyses of Dryer and Mill Baghouse Exhaust Emissions at Silbrico Perlite Plant, No
Agua, New Mexico, Kramer, Callahan & Associates, NM, February 1980.
10. Stack Emissions Survey for U.S. Gypsum, Perlite Mill Dryer Stack, Grants, New Mexico, File
Number EA 7922-17, Ecology Audits, Inc., Dallas, TX, August 1979.
11. Sampling Observation and Report Review, Grefco, Incorporated, Perlite Insulation Board Plant,
Florence, Kentucky, Commonwealth of Kentucky Department for Natural Resources and
Environmental Protection, Bureau of Environmental Protection, Frankfort, KY, January 1979.
7/93 Mineral Products Industry 8.17-5
-------
8.18 PHOSPHATE ROCK PROCESSING
8.18.1 Process Description1"5
The separation of phosphate rock from impurities and nonphosphate materials for use in
fertilizer manufacture consists of beneficiation, drying or calcining at some operations, and grinding.
The Standard Industrial Classification (SIC) code for phosphate rock processing is 1475. The six-
digit Source Classification Code (SCC) for phosphate rock processing is 3-05-019.
Because the primary use of phosphate rock is in the manufacture of phosphatic fertilizer, only
those phosphate rock processing operations associated with fertilizer manufacture are discussed here.
Florida and North Carolina accounted for 94 percent of the domestic phosphate rock mined and
89 percent of the marketable phosphate rock produced during 1989. Other States in which phosphate
rock is mined and processed include Idaho, Montana, Utah, and Tennessee. Alternative flow
diagrams of these operations are shown in Figure 8.18-1.
Phosphate rock from the mines is first sent to beneficiation units to separate sand and clay and
to remove impurities. Steps used in beneficiation depend on the type of rock. A typical beneficiation
unit for separating phosphate rock mined in Florida begins with wet screening to separate pebble
rock, which is larger than 1.43 millimeters (mm) (0.056 inch [in.]), or 14 mesh, and smaller than
6.35 mm (0.25 in.) from the balance of the rock. The pebble rock is shipped as pebble product. The
material that is larger than 0.85 mm (0.033 in.), or 20 mesh, and smaller than 14 mesh is separated
using hydrocyclones and finer mesh screens and is added to the pebble product. The fraction smaller
than 20 mesh is treated by two-stage flotation. The flotation process uses hydrophilic or hydrophobic
chemical reagents with aeration to separate suspended particles. Phosphate rock mined in North
Carolina does not contain pebble rock. In processing this type of phosphate, 2-mm (0.078 in.) or
10-mesh screens are used. Like Florida rock, the fraction that is less than 10 mesh is treated by two-
stage flotation, and the fraction larger than 10 mesh is used for secondary road building.
Phosphate rock mined in North Carolina does not contain pebble rock. In processing this
type of phosphate, 10-mesh screens are used. Like Florida rock, the fraction that is less than
10 mesh is treated by two-stage flotation, and the fraction larger than 10 mesh is used for secondary
road building.
The two major western phosphate rock ore deposits are located in southeastern Idaho and
northeastern Utah, and the beneficiation processes used on materials from these deposits differ
greatly. In general, southeastern Idaho deposits require crushing, grinding, and classification.
Further processing may include filtration and/or drying, depending on the phosphoric acid plant
requirements. Primary size reduction generally is accomplished by crushers (impact) and grinding
mills. Some classification of the primary crushed rock may be necessary before secondary grinding
(rod milling) takes place. The ground material then passes through hydrocyclones that are oriented in
a three-stage countercurrent arrangement. Further processing in the form of chemical flotation may
be required. Most of the processes are wet to facilitate material transport and to reduce dust.
Northeastern Utah deposits are lower grade and harder than the southeastern Idaho deposits
and requiring processing similar to that of the Florida deposits. Extensive crushing and grinding is
7/93 Mineral Products Industry 8.18-1
-------
Amber Acid Production
Phosphate rock _^^^
from mine
Benefoation
t
i
Rock
Transfer
SCO: 3-05-01 9-03
© PM emissions
(D Gaseous emissions
To phosphoric
acid manufacturing
Green Acid Production
Phosphate rock ^
from mine
Benefication
f t
i i
Drying
SCC: 3-05-019-01
or
Calcining
SCC: 3-05-019-05
T
i
Rock
Transfer
SCC: 3-05-01 9-03
Fuel Air
Granular Triple Super Phosphate Production (GTSP)
To phosphoric
acid production
Phosphate rock _ ^^^
from rnino
Grinding
SCC: 3-05-19-02
Rock
Transfer
SCC: 3-05-019-03
m To GTSP
production
Figure 8.18-1. Alternative process flow diagrams for phosphate rock processing.
8.18-2 EMISSION FACTORS
7/93
-------
necessary to liberate phosphate from the material. The primary product is classified with 150- to
200-mesh screens, and the finer material is disposed of with the tailings. The coarser fraction is
processed through multiple steps of phosphate flotation and then diluent flotation. Further processing
may include filtration and/or drying, depending on the phosphoric acid plant requirements. As is the
case for southeastern Idaho deposits, most of the processes are wet to facilitate material transport and
to reduce dust.
The wet beneficiated phosphate rock may be dried or calcined, depending on its organic
content. Florida rock is relatively free of organics and is for the most part no longer dried or
calcined. The rock is maintained at about 10 percent moisture and is stored in piles at the mine
and/or chemical plant for future use. The rock is slurried in water and wet-ground in ball mills or
rod mills at the chemical plant. Consequently, there is no significant emission potential from wet
grinding. The small amount of rock that is dried in Florida is dried in direct-fired dryers at about
120°C (250°F), where the moisture content of the rock falls from 10 to 15 percent to 1 to 3 percent.
Both rotary and fluidized bed dryers are used, but rotary dryers are more common. Most dryers are
fired with natural gas or fuel oil (No. 2 or No. 6), with many equipped to burn more than one type of
fuel. Unlike Florida rock, phosphate rock mined from other reserves contains organics and must be
heated to 760° to 870°C (1400° to 1600°F) to remove them. Fluidized bed calciners are most
commonly used for this purpose, but rotary calciners are also used. After drying, the rock is usually
conveyed to storage silos on weather-protected conveyors and, from there, to grinding mills. In
North Carolina, a portion of the beneficiated rock is calcined at temperatures generally between 800°
and 825°C (1480° and 1520°F) for use in "green" phosphoric acid production, which is used for
producing super phosphoric acid and as a raw material for purified phosphoric acid manufacturing.
To produce "amber" phosphoric acid, the calcining step is omitted, and the beneficiated rock is
transferred directly to the phosphoric acid production processes. Phosphate rock that is to be used for
the production of granular triple super phosphate (GTSP) is beneficiated, dried, and ground before
being transferred to the GTSP production processes.
Dried or calcined rock is ground in roll or ball mills to a fine powder, typically specified as
60 percent by weight passing a 200-mesh sieve. Rock is fed into the mill by a rotary valve, and
ground rock is swept from the mill by a circulating air stream. Product size classification is provided
by a "revolving whizzer, which is mounted on top of the ball mill," and by an air classifier. Oversize
particles are recycled to the mill, and product size particles are separated from the carrying air stream
by a cyclone.
8.18.2 Emissions and Controls1'3"9
The major emission sources for phosphate rock processing are dryers, calciners, and grinders.
These sources emit paniculate matter (PM) in the form of fine rock dust and sulfur dioxide (SO2).
Beneficiation has no significant emission potential, because the operations involve slurries of rock and
water. The majority of mining operations in Florida handle only the beneficiation step at the mine;
all wet grinding is done at the chemical processing facility.
Emissions from dryers depend on several factors, including fuel types, air flow rates, product
moisture content, speed of rotation, and the type of rock. The pebble portion of Florida rock receives
much less washing than the concentrate rock from the flotation processes. It has a higher clay content
and generates more emissions when dried. No significant differences have been noted in gas volume
or emissions from fluid bed or rotary dryers. A typical dryer processing 230 megagrams per hour
(Mg/hr) (250 tons per hour [tons/hr]) of rock will discharge between 31 and 45 dry normal cubic
7/93 Mineral Products Industry 8.18-3
-------
meters per second (dry nm3/sec) (70,000 and 100,000 dry standard cubic feet per minute [dscfm]) of
gas, with a PM loading of 1,100 to 11,000 milligrams per nm3 (mg/nm3) (0.5 to 5 grains per dry
standard cubic feet [gr/dscf]). Emissions from calciners consist of PM and SO2 and depend on fuel
type (coal or oil), air flow rates, product moisture, and grade of rock.
Phosphate rock contains radionuclides in concentrations that are 10 to 100 times the
radionuclide concentration found in most natural material. Most of the radionuclides consist of
uranium and its decay products. Some phosphate rock also contains elevated levels of thorium and its
daughter products. The specific radionuclides of significance include uranium-238, uranium-234,
thorium-230, radium-226, radon-222, lead-210, and polonium-210.
The radioactivity of phosphate rock varies regionally, and within the same region the
radioactivity of the material may vary widely from deposit to deposit. Table 8.18-1 summarizes data
TABLE 8.18-1. RADIONUCLIDE CONCENTRATIONS OF
DOMESTIC PHOSPHATE ROCK*
Origin
Florida
Tennessee
South Carolina
North Carolina
Arkansas, Oklahoma
Western States
Typical values, pCi/g
48 to 143
5.8 to 12.6
267
5.86b
19 to 22
80 to 123
"Reference 8, except where indicated otherwise.
Reference 9.
on radionuclide concentrations for domestic deposits of phosphate rock. Materials handling and
processing operations can emit radionuclides either as dust, or in the case of radon-222, which is a
decay product of uranium-238, as a gas. Phosphate dust particles generally have the same specific
activity as the phosphate rock from which the dust originates.
Scrubbers are most commonly used to control emissions from phosphate rock dryers, but
electrostatic precipitators are also used. Fabric filters are not currently being used to control
emissions from dryers. Venturi scrubbers with a relatively low pressure loss (3,000 pascals [Pa]
[12 in. of water]) may remove 80 to 99 percent of PM 1 to 10 micrometers (jim) in diameter, and 10
to 80 percent of PM less than 1 /tin. High-pressure-drop scrubbers (7,500 Pa [30 in. of water]) may
have collection efficiencies of 96 to 99.9 percent for PM in the size range of 1 to 10 jim and 80 to
86 percent for particles less than 1 jtm. Electrostatic precipitators may remove 90 to 99 percent of all
PM. Another control technique for phosphate rock dryers is use of the wet grinding process. In this
process, rock is ground in a wet slurry and then added directly to wet process phosphoric acid
reactors without drying.
A typical 45 Mg/hr (50 ton/hr) calciner will discharge about 13 to 27 dry nnrVsec (30,000 to
60,000 dscfm) of exhaust gas, with a PM loading of 0.5 to 5 gr/dscf. As with dryers, scrubbers are
8.18-4
EMISSION FACTORS
7/93
-------
the most common control devices used for calciners. At least one operating calciner is equipped with
a precipitator. Fabric filters could also be applied.
Oil-fired dryers and calciners have a potential to emit sulfur oxides when high-sulfur residual
fuel oils are burned. However, phosphate rock typically contains about 55 percent lime (CaO), which
reacts with the SO2 to form calcium sulfites and sulfates and thus reduces SO2 emissions. Dryers and
calciners also emit fluorides.
A typical grinder of 45 Mg/hr (50 ton/hr) capacity will discharge about 1.6 to 2.5 dry
nm3/sec (3,500 to 5,500 dscfm) of air containing 0.5 to 5.0 gr/dscf of PM. The air discharged is
"tramp air," which infiltrates the circulating streams. To avoid fugitive emissions of rock dust, these
grinding processes are operated at negative pressure. Fabric filters, and sometimes scrubbers, are
used to control grinder emissions. Substituting wet grinding for conventional grinding would reduce
the potential for PM emissions.
Emissions from material handling systems are difficult to quantify because several different
systems are used to convey rock. Moreover, a large part of the emission potential for these
operations is fugitives. Conveyor belts moving dried rock are usually covered and sometimes
enclosed. Transfer points are sometimes hooded and evacuated. Bucket elevators are usually
enclosed and evacuated to a control device, and ground rock is generally conveyed in totally enclosed
systems with well defined and easily controlled discharge points. Dry rock is normally stored in
enclosed bins or silos, which are vented to the atmosphere, with fabric filters frequently used to
control emissions.
Table 8.18-2 summarizes emission factors for controlled emissions of SO2 from phosphate
rock calciners and for uncontrolled emissions of CO and CO2 from phosphate rock dryers and
calciners. Emission factors for PM emissions from phosphate rock dryers, grinders, and calciners are
presented in Table 8.18-3. Particle size distribution for uncontrolled filterable PM emissions from
phosphate rock dryers and calciners are presented in Table 8.18-4. As shown in Table 8.18-4, the
size distribution of the uncontrolled-calciner emissions is very similar to that of the dryer emissions.
Table 8.18-5 summarizes emission factors for emissions of water-soluble and total fluorides from
phosphate rock dryers and calciners. Emission factors for controlled and uncontrolled radionuclide
emissions from phosphate rock grinders also are presented in Table 8.18-5. Emission factors for PM
emissions from phosphate rock ore storage, handling, and transfer can be developed using the
equations presented in Section 11.3.
The new source performance standard (NSPS) for phosphate rock plants was promulgated in
April 1982 (40 CFR 60 Subpart NN). This standard limits PM emissions and opacity for phosphate
rock calciners, dryers, and grinders and limits opacity for handling and transfer operations. The
national emission standard for radionuclide emissions from elemental phosphorus plants was
promulgated in December 1989 (40 CFR 61 Subpart K). This standard limits emissions of
polonium-210 from phosphate rock calciners and nodulizing kilns at elemental phosphorus plants and
requires annual compliance tests.
7/93 Mineral Products Industry 8.18-5
-------
Table 8.18-2 (Metric Units)
EMISSION FACTORS FOR PHOSPHATE ROCK PROCESSING8
Process (SCQ
SO2
kg/Mg
of Total
Feed
Emission
Factor
Rating
CO2
kg/Mg
of Total
Feed
Emissio
n Factor
Rating
CO
kg/Mg
of Total
Feed
Emission
Factor
Rating
Dryer (3-05-019-01) ND 43b D 0.17C D
Calciner with scrubber 0.0034d D 1 15e D ND
(3-05-019-05)
Table 8.18-2 (English Units)
EMISSION FACTORS FOR PHOSPHATE ROCK PROCESSING*
Process (SCQ
SO2
lb/ton of
Total
Feed
Emission
Factor
Rating
C02
lb/ton
of Total
Feed
Emission
Factor
Rating
CO
lb/ton
of Total
Feed
Emission
Factor
Rating
Dryer (3-05-019-01) ND 86b D 0.34C D
Calciner with scrubber 0.0069 D 230e D ND
(3-05-019-05)
ND = no data available.
"Factors represent uncontrolled emissions unless otherwise noted.
bReferences 10, 11.
"Reference 10.
References 13, 15.
^References 14 to 22.
8.18-6
EMISSION FACTORS
7/93
-------
Table 8.18^3 (Metric Units)
EMISSION FACTORS FOR PHOSPHATE ROCK PROCESSING*
ki
of
Process (SCC) F
Filterable PMb
PM
;/Mg Emission
Total Factor
•eed Rating
Dryer (3-05-01 9-0 l)d 2.90 D
Dryer with scrubber 0.035 D
(3-05-019-Olf
Dryer with ESP 0.016 D
(3-05-019-01)d
Grinder (3-05-019-02)d 0.8 C
Grinder with fabric filter (3- 0.0022 D
05-019-02)f
Calciner (3-05-0 19-05)d 7.7 D
Calciner with scrubber (3-05- 0.
019-05)
Transfer and storage 2
(3-05-0 19-_)d
10« C
E
PM-10
kg/Mg Emissi
of Total Factc
Feed Ratin
2.4 E
ND
ND
ND
ND
7.4 E
ND
ND
Condensible PMC
Inorganic
on kg/Mg
>r of Total
g Feed
ND
0.015
0.004
ND
0.0011
ND
0.0079
g
ND
Emission
Factor
Rating
D
D
D
D
C
Organic
kg/Mg
of Total
Feed
ND
ND
ND
ND
ND
ND
0.044h
ND
Emission
Factor
Rating
D
ND = No data available.
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. PM-10 values are based on cascade impaction particle size distribution.
cCondensible PM is that PM collected in the impinger portion of a PM sampling train.
dReference 1.
Reference 1, 10, and 11
^References 1, 11 and 12
^References 1, 14 to 22.
hReference 14 to 22.
7/93
Mineral Products Industry
8.18-7
-------
Table 8.18-3 (English Units)
EMISSION FACTORS FOR PHOSPHATE ROCK PROCESSING*
Process (SCC)
Dryer (3-05-019-01)d
Dryer with scrubber
(3-05-019-01)6
Dryer with ESP
(3-05-019-01)d
Grinder (3-05-0 190-2)d
Grinder with fabric filter
(3-05-019-02)f
Filterable PMb
PM
lb/ton
of Total
Peed
5.70
0.070
0.033
1.5
0.0043
Calciner (3-05-0 19-05)d 15.4
Calciner with scrubber
(3-05-019-05)
Transfer and storage
(3-05-019-_)d
0.138
1
Emission
Factor
Rating
D
D
D
C
D
D
C
E
PM-10
lb/ton of Emissi
Total Facte
Feed Ratin
4.8 E
ND
ND
ND
ND
15 E
ND
ND
Condensible PM
Inorganic
on lb/ton of
>r Total
g Feed
ND
0.030
0.008
ND
0.0021
ND
0.02
ND
Emission
Factor
Rating
D
D
D
D
C
C
Organic
lb/ton
of Total
Feed
ND
ND
ND
ND
ND
ND
0.088h
ND
Emission
Factor
Rating
D
ND = No data available.
"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. PM-10 values are based on cascade impaction particle size distribution.
°Condensible PM is that PM collected in the impinger portion of a PM sampling train.
dReference 1.
References 8, 10 and 11.
References 1, 11, and 12.
^References 1, 14 to 22.
hReferences 14 to 22.
8.18-8
EMISSION FACTORS
7/93
-------
Table 8.18^. PARTICLE SIZE DISTRIBUTION OF FILTERABLE PARTICIPATE
EMISSIONS FROM PHOSPHATE ROCK DRYERS AND CALCINERS1
RATING: E
Diameter,
Percent less than size
Dryers
Calciners
10
5
2
1
0.8
0.5
82
60
27
11
7
3
96
81
52
26
110
5
7/93
Mineral Products Industry
8.18-9
-------
Table 8.18-5 (Metric Units)
EMISSION FACTORS FOR PHOSPHATE ROCK PROCESSING8
Process (SCC)
Dryer (3-05-019-01)°
Dryer with scrubber
(3-05-019-01)d
Grinder (3-05-019-02)6
Grinder with fabric filter
(3-05-019-02)6
Calciner with scrubber
(3-05-019-05)f
Fluoride, H
kg/Mg
of Total
Feed
0.0009
0.00048 .
ND
ND
ND
2O-soluble
Emission
Factor
Rating
D
D
Fluoride, total
kg/Mg
of Total
Feed
0.037
0.0048
ND
ND
0.00081
Emission
Factor
Rating
D
D
D
Radionuclidesb
kg/Mg
of Total
Feed
ND
ND
800R
5.2R
ND
Emission
Factor
Rating
E
E
Table 8.18-5 (English Units)
EMISSION FACTORS FOR PHOSPHATE ROCK PROCESSING4
Process (SCC)
Dryer (3-05-019-01)°
Dryer with scrubber
(3-05-019-01)d
Grinder (3-05-0 19-02)e
Grinder with fabric filter
(3-05-0 19-02)6
Calciner with scrubber
(3-05-019-05)f
Fluoride, H2O-soluble
lb/ton
of Total
Feed
0.0017
0.00095
ND
ND
ND
Emission
Factor
Rating
D
D
Fluoride, total
lb/ton
of Total
Feed
0.073
0.0096
ND
ND
0.0016
Emission
Factor
Rating
D
D
D
Radionuclidesb
lb/ton
of Total
Feed
ND
ND
730R
4.7R
ND
Emission
Factor
Rating
E
E
ND = No data available.
"Factors represent uncontrolled emissions unless otherwise noted.
bln units of pCi/Mg of feed.
Reference 10.
References 10 and 11.
References 7 and 8.
Reference 1.
8.18-10
EMISSION FACTORS
7/93
-------
REFERENCES FOR SECTION 8.18
1. Background Information: Proposed Standards for Phosphate Rock Plants (Draft),
EPA-450/3-79-017, U. S. Environmental Protection Agency, Research Triangle Park, NC,
September 1979.
2. Minerals Yearbook, Volume I, Metals and Minerals, Bureau of Mines, U. S. Department of the
Interior, Washington D.C., 1991.
3. Written communication from B. S. Batts, Florida Phosphate Council, to R. Myers, Emission
Inventory Branch, U. S. Environmental Protection Agency, Research Triangle Park, NC,
March 12, 1992.
4. Written communication from K. T. Johnson, The Fertilizer Institute, to R. Myers, Emission
Inventory Branch, U. S. Environmental Protection Agency, Research Triangle Park, NC,
April 30, 1992.
5. Written communication for K. T. Johnson, The Fertilizer Institute to R. Myers, Emission
Inventory Branch, U. S. Environmental Protection Agency, Research Triangle Park, NC,
February 12, 1989.
6. "Sources of Air Pollution and Their Control," Air Pollution, Volume III, 2nd Ed., Arthur Stern,
ed., New York, Academic Press, 1968, pp. 221-222.
7. Background Information Document: Proposed Standards for Radionuclides, EPA 520/1-83-001,
U. S. Environmental Protection Agency, Office of Radiation Programs, Washington, D.C.,
March 1983.
8. R. T. Stula et al., Control Technology Alternatives and Costs for Compliance—Elemental
Phosphorus Plants, Final Report, EPA Contract No. 68-01-6429, Energy Systems Group, Science
Applications, Incorporated, La Jolla, CA, December 1, 1983.
9. Telephone communication from B. Peacock, Texasgulf, Incorporated, to R. Marinshaw, Midwest
Research Institute, Gary, NC, April 4, 1993.
10. Emission Test Report: International Minerals and Chemical Corporation, Kingsford, Florida,
EMB Report 73-ROC-l, U. S. Environmental Protection Agency, Research Triangle Park, NC,
February 1973.
11. Emission Test Report: Occidental Chemical Company, White Springs, Florida, EMB
Report 73-ROC-3, U. S. Environmental Protection Agency, Research Triangle Park, NC,
January 1973.
12. Emission Test Report: International Minerals and Chemical Corporation, Norafyn, Florida, EMB
Report 73-ROC-2, U.S. Environmental Protection Agency, Research Triangle Park, NC,
February 1973.
13. Sulfur Dioxide Emission Rate Test, No. 1 Calciner, Texasgulf, Incorporated, Aurora, North
Carolina, Texasgulf Environmental Section, Aurora, NC, May 1990.
7/93 Mineral Products Industry 8.18-11
-------
14. Source Performance Test, Calciner Number 4, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, August 28, 1991, Texasgulf, Incorporated, Aurora, NC, September 25, 1991.
15. Source Performance Test, Calciner Number 6, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, August 5 and 6, 1992, Texasgulf, Incorporated, Aurora, NC, September 17, 1992.
16. Source Performance Test, Calciner Number 4, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, June 30, 1992, Texasgulf, Incorporated, Aurora, NC, July 16, 1992.
17. Source Performance Test, Calciner Number 1, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, June 10, 1992, Texasgulf, Incorporated, Aurora, NC, July 8, 1992.
18. Source Performance Test, Calciner Number 2, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, Jufy 7, 1992, Texasgulf, Incorporated, Aurora, NC, July 16, 1992.
19. Source Performance Test, Calciner Number 5, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, June 16, 1992, Texasgulf, Incorporated, Aurora, NC, July 8, 1992.
20. Source Performance Test, Calciner Number 6, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, August 4 and 5, 1992, Texasgulf, Incorporated, Aurora, NC, September 21, 1992.
21. Source Performance Test, Calciner Number 3, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, August 27, 1992, Texasgulf, Incorporated, Aurora, NC, September 21, 1992.
22. Source Performance Test, Calciner Number 2, Texasgulf, Inc., Phosphate Operations, Aurora,
NC, August 21 and 22, 1992, Texasgulf, Incorporated, Aurora, NC, September 20, 1992.
8.18-12 EMISSION FACTORS 7/93
-------
8.23 METALLIC MINERALS PROCESSING
8.23.1 Process Description1"6
Metallic mineral processing typically involves the mining of ore, from either open pit or
underground mines; the crushing and grinding of ore; the separation of valuable minerals from matrix
rock through various concentration steps; and at some operations, the drying, calcining, or pelletizing
of concentrates to ease further handling and refining. Figure 8.23-1 is a general flow diagram for
metallic mineral processing. Very few metallic mineral processing facilities will contain all of the
operations depicted in this figure, but all facilities will use at least some of these operations in the
process of separating valued minerals from the matrix rock.
The number of crushing steps necessary to reduce ore to the proper size vary with the type of
ore. Hard ores, including some copper, gold, iron, and molybdenum ores, may require as much as a
tertiary crushing. Softer ores, such as some uranium, bauxite, and titanium/zirconium ores, require
little or no crushing. Final comminution of both hard and soft ores is often accomplished by grinding
operations using media such as balls or rods of various materials. Grinding is most often performed
with an ore/water slurry, which reduces paniculate matter emissions to negligible levels. When dry
grinding processes are used, paniculate matter emissions can be considerable.
After final size reduction, the beneficiation of the ore increases the concentration of valuable
minerals by separating them from the matrix rock. A variety of physical and chemical processes is
used to concentrate the mineral. Most often, physical or chemical separation is performed in an
aqueous environment, which eliminates paniculate matter emissions, although some ferrous and
titaniferous minerals are separated by magnetic or electrostatic methods in a dry environment.
The concentrated mineral products may be dried to remove surface moisture. Drying is most
frequently done in natural gas-fired rotary dryers. Calcining or pelletizing of some products, such as
alumina or iron concentrates, is also performed. Emissions from calcining and pelletizing operations
are not covered in this section.
8.23.2 Process Emissions7"9
Paniculate matter emissions result from metallic mineral plant operations such as crushing and
dry grinding ore; drying concentrates; storing and reclaiming ores and concentrates from storage bins;
transferring materials; and loading final products for shipment. Paniculate matter emission factors
are provided in Table 8.23-1 for various metallic mineral process operations, including primary,
secondary, and tertiary crushing; dry grinding; drying; and material handling and transfer. Fugitive
emissions are also possible from roads and open stockpiles, factors for which are in Section 11.2.
The emission factors in Table 8.23-1 are for the process operations as a whole. At most
metallic mineral processing plants, each process operation requires several types of equipment. A
single crushing operation likely includes a hopper or ore dump, screen(s), crusher, surge bin, apron
feeder, and conveyor belt transfer points. Emissions from these various pieces of equipment are often
ducted to a single control device. The emission factors provided in Table 8.23-1 for primary,
8/82 Minerals Products Industry 8.23-1
-------
ORE
MINING
SCO: 3-05-
PRIMARY CRUSHING
SCC: 3-03-024-01,05
SECONDARY CRUSHING
SCC: 3-03-024-02, 06
STORAGE
SCC: 3-05-
TERTIARY CRUSHING
SCC: 3-03-024-03, 07
STORAGE
SCC: 3-05-
GRINDING
SCC: 3-03-024-09,10
BENEFICIATION
Tailings
DRYING
SCC: 3-03-024-11
t t
PACKAGING AND
SHIPPING
SCC: 3-05-024-04,08
KEY
PM emissions
Gaseous emissions
Figure 8.23-1. Process flow diagram for metallic mineral processing.
8.23-2
EMISSION FACTORS
8/82
-------
Table 8.23-1 (Metric Units)
EMISSION FACTORS FOR METALLIC MINERALS PROCESSING*
All Emission Factors in the kg/Mg of Material Processed Unless Noted*'
Ratings (A-E) Follow Each Emission Factor
Source (SCC)
Low moisture orec
Primary crushing (3-03-024-01)d
Secondary crushing (3-03-024-02)d
Tertiary crushing (3-03-024-03)d
Wet grinding
Dry grinding with air conveying and/or air classification (3-03-024-09)e
Dry grinding without air conveying and/or air classification (3-03-024-10)°
Drying— all minerals except titanium/zirconium sands (3-O3-024-ll)f
Drying—titanium/zirconium with cyclones (3-03-024-1 l)f
Material handling and transfer— all minerals except bauxite (3-03-024-04)8
Material handling and transfer— bauxite/alumina (3-03-024-04)*>h
High moisture orec
Primary crushing (3-03-024-O5)d
Secondary crushing (3-03-024-06)d
Tertiary crushing (3-03-024J07)d
Wet grinding
Dry grinding with air conveying and/or air classification (3-03-024-09)°
Dry grinding without air conveying and/or air classification (3-03-024-10)°
Drying—all minerals except titanium/zirconium sands (3-03-024-1 l)f
Drying—titanium/zirconium with cyclones (3-03-024-1 l)f
Material handling and transfer— all minerals except bauxite (3-03-024-08)3
Material handling and transfer-bauxite/alumina (3-03-024-08)g>h
Filterable0
PM
0.2
0.6
1.4
Neg.
14.4
1.2
9.8
0.3
0.06
0.6
0.01
0.03
0.03
Neg.
14.4
1.2
9.8
0.3
0.005
NA
C
D
E
C
D
C
C
C
C
C
D
E
C
D
C
C
C
PM-10
0.02
NA
0.08
Neg.
13
0.16
5.9
NA
0.03
NA
0.004
0.012
0.01
Neg.
13
0.16
5.9
NA
0.002
NA
C
D
E
C
D
C
C
C
C
D
E
C
D
C
C
C
NA = not available
Neg. = negligible
"References 9 to 12; factors represent uncontrolled emissions unless otherwise noted; controlled emission
factors are discussed in Section 8.23.3.
bFilterable PM is that PM collected on or prior to the filter of an EPA Method 5 (or equivalent) sampling
train.
Defined in Section 8.23.2.
dBased on weight of material entering primary crusher.
°Based on weight of material entering grinder; emission factors are the same for both low moisture and high
moisture ore because material is usually dried before entering grinder.
fBased on weight of material exiting dryer; emission factors are the same for both high moisture and low
moisture ores; SOX emissions are fuel dependent (see Chapter 1); NOX emissions depend on burner design
and combustion temperature (see Chapter 1).
gBased on weight of material transferred; applies to each loading or unloading operation and to each conveyor
belt transfer point.
hBauxite with moisture content as high as 15 to 18 percent can exhibit the emission characteristics of low
moisture ore; use low moisture ore emission factor for bauxite unless material exhibits obvious sticky,
nondusting characteristics.
8/82
Minerals Products Industry
8.23-3
-------
Table 8.23-1 (English Units)
EMISSION FACTORS FOR METALLIC MINERALS PROCESSING8
All Emission Factors in the Ib/ton of Material Processed Unless Notedb
Ratings (A-E) FoUow Each Emission Factor
Source (SCC)
Low moisture ore0
Primary crushing (3-03-024-01)d
Secondary crushing (303-O24-02)d
Tertiary crushing (3-03-024-03)**
Wet grinding
Dry grinding with air conveying and/or air classification (3-03-024-09)°
Dry grinding without air conveying and/or air classification (3-03-024- 10)e
Drying—all minerals except titanium/zirconium sands (3-03-O24-ll)f
Drying— titanium/zirconium with cyclones (3-03-024-1 l)f
Material handling and transfer—all minerals except bauxite (3-03-024-04)8
Material handling and transfer-bauxite/alumina (3-03-024-04)g'h
High moisture orec
Primary crushing (3-03-024-05)d
Secondary crushing (3-03-024-06)d
Tertiary crushing (3-O3-024-O7)d
Wet >grinding
Dry grinding with air conveying and/or air classification (3-03-0244)9)*
Dry grinding without air conveying and/or air classification (3-03-024-10)*
Drying— all minerals except titanium/zirconium sands (3-03-024- 11)*
Drying— titanium/zirconium with cyclones (3-03-O24-ll)f
Material handling and transfer— all minerals except bauxite (3-03-024-08)8
Material handling and transfer-bauxite/alumina (3-03-024-08)g>h
Filterable0
PM
0.5
1.2
2.7
Neg.
28.8
2.4
19.7
0.5
0.12
1.1
0.02
0.05
0.06
Neg.
28.8
2.4
19.7
0.5
0.01
NA
C
D
E
C
D
C
C
C
C
C
D
E
C
D
C
C
C
PM-10
0.05
NA
0.16
Neg.
26
0.31
12
NA
0.06
NA
0.009
0.02
0.02
Neg.
26
0.31
12
NA
0.004
NA
C
D
E
C
D
C
C
C
C
D
E
C
D
C
C
C
NA = not available
Neg. = negligible
'References 9 to 12; factors represent uncontrolled emissions unless otherwise noted; controlled emission
factors are discussed in Section 8.23.3.
bFilterable PM is that PM collected on or prior to the filter of an EPA Method 5 (or equivalent) sampling
train.
•Defined in Section 8.23.2.
dBased on weight of material entering primary crusher.
"Based on weight of material entering grinder; emission factors are the same for both low moisture and high
moisture ore because material is usually dried before entering grinder.
*Based on weight of material exiting dryer; emission factors are the same for both high moisture and low
moisture ores; SOX emissions are fuel dependent (see Chapter 1); NOX emissions depend on burner design
and combustion temperature (see Chapter 1).
SBased on weight of material transferred; applies to each loading or unloading operation and to each conveyor
belt transfer point.
''Bauxite with moisture content as high as 15 to 18 percent can exhibit the emission characteristics of low
moisture ore; use low moisture ore emission factor for bauxite unless material exhibits obvious sticky,
nondusting characteristics.
8.23-4
EMISSION FACTORS
8/82
-------
secondary, and tertiary crushing operations are for process units that are typical arrangements of the
above equipment.
Emission factors are provided in Table 8.23-1 for two types of dry grinding operations: those
that involve air conveying and/or air classification of material and those that involve screening of
material without air conveying. Grinding operations that involve air conveying and air classification
usually require dry cyclones for efficient product recovery. The factors in Table 8.23-1 are for
emissions after product recovery cyclones. Grinders in closed circuit with screens usually do not
require cyclones. Emission factors are not provided for wet grinders because the high moisture
content in these operations can reduce emissions to negligible levels.
The emission factors for dryers in Table 8.23-1 include transfer points integral to the drying
operation. A separate emission factor is provided for dryers at titanium/zirconium plants that use dry
cyclones for product recovery and for emission control. Titanium/zirconium sand-type ores do not
require crushing or grinding, and the ore is washed to remove humic and clay material before
concentration and drying operations.
At some metallic mineral processing plants, material is stored in enclosed bins between
process operations. The emission factors provided in Table 8.23-1 for the handling and transfer of
material should be applied to the loading of material into storage bins and the transferring of material
from the bin. The emission factor will usually be applied twice to a storage operation: once for the
loading operation and once for the reclaiming operation. If material is stored at multiple points in the
plant, the emission factor should be applied to each operation and should apply to the material being
stored at each bin. The material handling and transfer factors do not apply to small hoppers, surge
bins, or transfer points that are integral with crushing, drying, or grinding operations.
At some large metallic mineral processing plants, extensive material transfer operations, with
numerous conveyor belt transfer points, may be required. The emission factors for material handling
and transfer should be applied to each transfer point that is not an integral part of another process
unit. These emission factors should be applied to each such conveyor transfer point and should be
based on the amount of material transferred through that point.
The emission factors for material handling can also be applied to final product loading for
shipment. Again, these factors should be applied to each transfer point, ore dump, or other point
where material is allowed to fall freely.
Test data collected in the mineral processing industries indicate that the moisture content of
ore can have a significant effect on emissions from several process operations. High moisture
generally reduces the uncontrolled emission rates, and separate emission rates are provided for
primary crushers, secondary crushers, tertiary crushers, and material handling and transfer operations
that process high-moisture ore. Drying and dry grinding operations are assumed to produce or to
involve only low-moisture material.
For most metallic minerals covered in this section, high-moisture ore is defined as ore whose
moisture content, as measured at the primary crusher inlet or at the mine, is 4 weight percent or
greater. Ore defined as high-moisture at the primary crusher is presumed to be high moisture ore at
any subsequent operation for which high moisture factors are provided, unless a drying operation
precedes the operation under consideration. Ore is defined as low-moisture when a dryer precedes
8/82 Minerals Products Industry 8.23-5
-------
the operation under consideration or when the ore moisture at the mine or primary crusher is less than
4 weight percent.
Separate factors are provided for bauxite handling operations because some types of bauxite
with a moisture content as high as 15 to 18 weight percent can still produce relatively high emissions
during material handling procedures. These emissions could be eliminated by adding sufficient
moisture to the ore, but bauxite then becomes so sticky that it is difficult to handle. Thus, there is
some advantage to keeping bauxite in a relatively dusty state, and the low-moisture emission factors
given represent conditions fairly typical of the industry.
Paniculate matter size distribution data for some process operations have been obtained for
control device inlet streams. Since these inlet streams contain paniculate matter from several
activities, a variability has been anticipated in the calculated size-specific emission factors for
paniculate matter.
Emission factors for paniculate matter equal to or less than 10 fim in aerodynamic diameter
(PM-10), from a limited number of tests performed to characterize the processes, are presented in
Table 8.23-1.
In some plants, paniculate matter emissions from multiple pieces of equipment and operations
are collected and ducted to a control device. Therefore, examination of reference documents is '
recommended before applying the factors to specific plants.
Emission factors for PM-10 from high-moisture primary crushing operations and material
handling and transfer operations were based on test results usually in the 30 to 40 weight percent
range. However, high values were obtained for high-moisture ore at both the primary crushing and
the material handling and transfer operations, and these were included in the average values in the
table. A similarly wide range occurred in the low-moisture drying operation.
Several other factors are generally assumed to affect the level of emissions from a particular
process operation. These include ore characteristics such as hardness, crystal and grain structure, and
friability. Equipment design characteristics, such as crusher type, could also affect the emissions
level. At this time, data are not sufficient to quantify each of these variables.
8.23.3 Controlled Emissions7"9
Emissions from metallic mineral processing plants are usually controlled with wet scrubbers
or baghouses. For moderate to heavy uncontrolled emission rates from typical dry ore operations,
dryers, and dry grinders, a wet scrubber with pressure drop of 1.5 to 2.5 kilopascals (6 to 10 inches
of water) will reduce emissions by approximately 95 percent. With very low uncontrolled emission
rates typical of high-moisture conditions, the percentage reduction will be lower (approximately 70
percent).
Over a wide range of inlet mass loadings, a well-designed and maintained baghouse will
reduce emissions to a relatively constant outlet concentration. Such baghouses tested in the mineral
processing industry consistently reduce emissions to less than 0.05 gram per dry standard cubic meter
(g/dscm) (0.02 grains per dry standard cubic foot [gr/dscfj), with an average concentration of
0.015 g/dscm (0.006 gr/dscf). Under conditions of moderate to high uncontrolled emission rates of
typical dry ore facilities, this level of controlled emissions represents greater than 99 percent removal
8.23-6 EMISSION FACTORS 8/82
-------
of paniculate matter emissions. Because baghouses reduce emissions to a relatively constant outlet
concentration, percentage emission reductions would be less for baghouses on facilities with a low
level of uncontrolled emissions.
References for Section 8.23
1. D. Kram, "Modern Mineral Processing: Drying, Calcining and Agglomeration", Engineering
and Mining Journal, 181(6): 134-151, June 1980.
2. A. Lynch, Mineral Crushing and Grinding Circuits, Elsevier Scientific Publishing Company,
New York, 1977.
3. "Modern Mineral Processing: Grinding", Engineering and Mining Journal, 757(161): 106-113,
June 1980.
4. L. Mollick, "Modern Mineral Processing: Crushing", Engineering and Mining Journal,
787(6):96-103, June 1980.
5. R. H. Perry, et al., Chemical Engineer's Handbook, 4th Ed., McGraw-Hill, New York, 1963.
6. R. Richards and C. Locke, Textbook of Ore Dressing, McGraw-Hill, New York, 1940.
7. "Modern Mineral Processing: Air and Water Pollution Controls", Engineering and Mining
Journal, 787(6): 156-171, June 1980.
8. W. E. Horst and R. C. Enochs, "Modern Mineral Processing: Instrumentation and Process
Control", Engineering and Mining Journal, 7&7(6):70-92, June 1980.
9. Metallic Mineral Processing Plants - Background Information for Proposed Standards (Draft).
EPA Contract No. 68-02-3063, TRW, Research Triangle Park, NC, 1981.
10. Telephone communication between E. C. Monnig, TRW, Environmental Division, and R. Beale,
Associated Minerals, Inc., May 17, 1982.
11. Written communication from W. R. Chalker, DuPont, Inc., to S. T. Cuffe, U.S. Environmental
Protection Agency, Research Triangle Park, NC, December 21, 1981.
12. Written communication from P. H. Fournet, Kaiser Aluminum and Chemical Corporation, to S.
T. Cuffe, U. S. Environmental Protection Agency, Research Triangle Park, NC, March 5, 1982.
8/82 Minerals Products Industry 8.23-7
-------
8.25 LIGHTWEIGHT AGGREGATE MANUFACTURING
8.25.1 Process Description1 >2
Lightweight aggregate is a type of coarse aggregate that is used in the production of
lightweight concrete products such as concrete block, structural concrete, and pavement. The
Standard Industrial Classification (SIC) code for lightweight aggregate manufacturing is 3295; there
currently is no Source Classification Code (SCC) for the industry.
Most lightweight aggregate is produced from materials such as clay, shale, or slate. Blast
furnace slag, natural pumice, vermiculite, and perlite can be used as substitutes, however. To
produce lightweight aggregate, the raw material (excluding pumice) is expanded to about twice the
original volume of the raw material. The expanded material has properties similar to natural
aggregate, but is less dense and therefore yields a lighter concrete product.
The production of lightweight aggregate begins with mining or quarrying the raw material.
The material is crushed with cone crushers, jaw crushers, hammermills, or pugmills and is screened
for size. Oversized material is returned to the crushers, and the material that passes through the
screens is transferred to hoppers. From the hoppers, the material is fed to a rotary kiln, which is
fired with coal, coke, natural gas, or fuel oil, to temperatures of about 1200°C (2200°F). As the
material is heated, it liquefies and carbonaceous compounds in the material form gas bubbles, which
expand the material; in the process, volatile organic compounds (VOC's) are released. From the kiln,
the expanded product (clinker) is transferred by conveyor into the clinker cooler, where it is cooled
by air, forming a porous material. After cooling, the lightweight aggregate is screened for size;
crushed, if necessary; stockpiled; and shipped. Figure 8.25-1 illustrates the lightweight aggregate
manufacturing process.
Although the majority (approximately 90 percent) of plants use rotary kilns, traveling grates
are also used to heat the raw material. In addition, a few plants process naturally occurring
lightweight aggregate such as pumice.
8.25.2 Emissions and Controls1
Emissions from the production of lightweight aggregate consist primarily of paniculate
matter (PM), which is emitted by the rotary kilns, clinker coolers, and crushing, screening, and
material transfer operations. Pollutants emitted as a result of combustion in the rotary kilns include
sulfur oxides (SO2), nitrogen oxides (NOX), carbon monoxide (CO), carbon dioxide (CO^, and
VOC's. Chromium, lead, and chlorides also are emitted from the kilns. In addition, other metals,
including aluminum, copper, manganese, vanadium, and zinc, are emitted in trace amounts by the
kilns. However, emission rates for these pollutants have not been quantified. In addition to PM,
clinker coolers emit CO2 and VOC's. Emission factors for crushing, screening, and material transfer
operations can be found in AP-42 Section 8.19.
7/93 Mineral Products Industry 8.25-1
-------
Mining
or
Quanylng
Oversize
Material
Crushing
Screening
i
Stockpiling
Rotary Kiln
Cooling
1
Screening
Oversize
Material
Stockpiling
Shipping
Figure 8.25-1. Process flow diagram for lightweight aggregate manufacturing.
8.25-2
EMISSION FACTORS
7/93
-------
Some lightweight aggregate plants fire kilns with material classified as hazardous waste under
the Resource Conservation and Recovery Act. Emission data are available for emissions of hydrogen
chloride, chlorine, and several metals from lightweight aggregate kilns burning hazardous waste.
However, emission factors developed from these data have not been incorporated in the AP-42 section
because the magnitude of emissions of these pollutants is largely a function of the waste fuel
composition, which can vary considerably.
Emissions from rotary kilns generally are controlled with wet scrubbers. However, fabric
filters and electrostatic precipitators (ESP's) are also used to control kiln emissions. Multiclones and
settling chambers generally are the only types of controls for clinker cooler emissions.
Table 8.25-1 summarizes uncontrolled and controlled emission factors for PM emissions (both
filterable and condensible) from rotary kilns and clinker coolers. Emission factors for SO2, NOX,
CO, and CO2 emissions from rotary kilns are presented in Table 8.25-2. An emission factor for CO2
emissions from clinker coolers is included in Table 8.25-2. Table 8.25-3 presents emission factors
for total VOC (TVOC), emissions from rotary kilns. Size-specific PM emission factors for rotary
kilns and clinker coolers are presented in Table 8.25-4.
7/93 Mineral Products Industry 8.25-3
-------
TABLE 8.25-1 (METRIC UNITS)
EMISSION FACTORS FOR LIGHTWEIGHT AGGREGATE PRODUCTION8
kgJ
1
Process
Filterable15
PM
"Mg of Emission
3eed Factor
Rating
Rotary kiln 65d D
(3-05 )
Rotary kiln with scrubber 0
(3-05 )
Rotary kiln with fabric filter 0
(3-05 )
.398 C
.13' C
Rotary kiln with ESP 0.34k D
(3-05 )
Clinker cooler with 0
settling chamber
(3-05 )
Clinker cooler with multiclone 0
(3-05 )
.14' D
15m D
PM-10
kg/Mg Emiss
of Feed Facfa
Ratii
ND
0.15h D
ND
ND
0.0551 D
0.060m D
Condensible PMC
Inorganic
ion kg/Mg
x of Feed
'g
0.41e
0.1011
0.070>
0.015k
0.00851
0.0013m
Emission
Factor
Rating
D
D
D
D
D
D
Organic
kg/Mg of
Feed
o.oostf
0.0046h
ND
ND
0.000341
0.0014m
Emission
Factor
Rating
D
D
D
D
ND = No data available.
"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.
PM-10 values are based on cascade impaction particle size distribution.
°Condensible PM is that PM collected in the impinger portion of a PM sampling train.
dReferences 3,7,14. Average of 3 tests mat ranged from 6.5 to 170 kg/Mg.
Reference 3,14.
Reference 3.
^References 3,5,10,12-14.
hReferences3,5.
'References 7,14, 17-19.
•(Reference 14.
kReferences 15,16.
'References 3,6.
"Reference 4.
8.25-4
EMISSION FACTORS
7/93
-------
TABLE 8.25-1 (ENGLISH UNITS)
EMISSION FACTORS FOR LIGHTWEIGHT AGGREGATE PRODUCTION8
All Emission Factors in Unless Noted
Ratings (A-E) Follow Each Emission Factor
Process (SCC)
Filterableb
PM
Ib/ton
of Feed
Emission
Factor
Rating
PM-10
Ib/ton
of Feed
Emission
Factor
Rating
Condensible PMC
Inorganic
Ib/ton of
Feed
Emission
Factor
Rating
Organic
Ib/ton
of Feed
Emission
Factor
Rating
Rotary kiln 130*1
(3-05 )
Rotary kiln with scrubber 0.788
(3-05 )
Rotary kiln with fabric filter 0.26'
(3-05 )
Rotary kiln with ESP 0.67k
(3-05 )
Clinker cooler with settling chamber 0.281
(3-05 )
Clinker cooler with multiclone 0.30m
(3-05 )
D ND 0.82e D 0.016f
C 0.2911 D 0.1911 D 0.0092h
C
D
D
D
ND
ND
O.ll1
0.12m
D
D
0.141
0.03 lk
0.0171
0.0025111
D
D
D
D
ND
ND
0.000671
0.0027m
D
D
D
D
ND = No data available.
"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.
PM-10 values are based on cascade impaction particle size distribution.
cCondensible PM is that PM collected in the impinger portion of a PM sampling train.
dReferences 3,7,14. Average of 3 tests that ranged from 13 to 340 Ib/ton.
'Reference 3,14.
'Reference 3.
^References 3,5,10,12-14.
hReferences 3,5.
JReferences7,14, 17-19.
JReference 14.
References 15,16.
'References 3,6.
"Reference 4.
7/93
Mineral Products Industry
8.25-5
-------
Table 8.25-2 (Metric Units)
EMISSION FACTORS FOR LIGHTWEIGHT AGGREGATE PRODUCTION11
Process
(SCQ
S
kg/Mg
of
Product
Rotary kiln 2.8b
(3-05 )
Rotary kiln 1.7e
with scrubber
(3-05 )
Clinker cooler with ND
dry multicyclone
(3-05 )
3x
Emission
Factor
Rating
NOX
kg/Mg
of
Product
C ND
C 1.0*
ND
Emission
Factor
Rating
CO
kg/Mg
of
Product
0.29C
D ND
ND
Emission
Factor
Rating
CO2
kg/Mg
of
Product
C 240d
ND
22«
Emission
Factor
Rating
C
D
TABLE 8.25-2 (ENGLISH UNITS)
EMISSION FACTORS FOR LIGHTWEIGHT AGGREGATE PRODUCTION11
Process (SCC)
S(
lb/ton
of
Product
Rotary kiln 5.6b
(3-05 )
Rotary kiln 3.4e
with scrubber
(3-05 )
Clinker cooler with ND
dry multicyclone
(3-05 )
3X
Emission
Factor
Rating
NOX
lb/ton
of
Product
C ND
C 1.9f
ND
Emission
Factor
Rating
CO
lb/ton
of
Product
0.59C
D ND
ND
Emission
Factor
Rating
CO2
lb/ton
of
Product
C 480d
ND
43S
Emission
Factor
Rating
C
D
ND = No data available.
*Factors represent uncontrolled emissions unless otherwise noted.
bReferences 3, 4, 5, 8.
References 17, 18, 19.
References 3, 4, 5, 12, 13, 14, 17, 18, 19
References 3, 4, 5, 9.
References 3, 4, 5.
Reference 4.
8.25-6
EMISSION FACTORS
7/93
-------
TABLE 8.25-3 (METRIC UNITS)
EMISSION FACTORS FOR LIGHTWEIGHT AGGREGATE PRODUCTION8
Process
(SCC)
TVOC's
kg/Mg
of
Product
Emission
Factor
Rating
Rotary kiln (3-05 ) ND
Rotary kiln with scrubber 0.39b D
(3-05 )
TABLE 8.25-3 (ENGLISH UNITS)
EMISSION FACTORS FOR LIGHTWEIGHT AGGREGATE PRODUCTION11
All Emission Factors in Unless Noted
Ratings (A-E) Follow Each Emission Factor
Process
(SCC)
TVOC's
Ib/ton
of
Product
Emission
Factor
Rating
Rotary kiln (3-05 ) ND
Rotary kiln with scrubber 0.78b D
(3-05 )
ND = No data available.
"Factors represent uncontrolled emissions unless otherwise noted.
bReference 3.
7/93
Mineral Products Industry
8.25-7
-------
TABLE 8.25^. PARTICULATE MATTER SIZE-SPECIFIC EMISSION FACTORS
FOR EMISSIONS FROM ROTARY KILNS AND CLINKER COOLERS8
Rotary Kiln with Scrubbed
EMISSION FACTOR RATING:
D
Diameter,
microns
Cumulative %
less than
diameter
Emission factor
kg/Mg
2.5 35 0.10
6.0 46 0.13
10.0 50 0.14
15.0 55 0.16
20.0 57 0.16
Ib/ton
0.20
0.26
0.28
0.31
0.32
Clinker Cooler with Settling Chamber0
EMISSION FACTOR RATING: D
Diameter,
microns
Cumulative %
less than
diameter
Emission factor
kg/Mg
2.5 9 0.014
6.0 21 0.032
10.0 35 0.055
15.0 49 0.080
20.0 58 0.095
Ib/ton
0.027
0.063
0.11
0.16
0.19
Clinker Cooler with Multicloned
EMISSION FACTOR RATING: D
Diameter,
microns
Cumulative %
less than
diameter
Emission factor
kg/Mg
2.5 19 0.029
6.0 31 0.047
10.0 40 0.060
15.0 48 0.072
20.0 53 0.080
Ib/ton
0.057
0.093
0.12
0.14
0.16
aEmission factors based on total feed.
bReferences 3, 5.
References 3, 6.
dReference 4.
8.25-8
EMISSION FACTORS
7/93
-------
REFERENCES FOR SECTION 8.25
1. Calciners and Dryers in Mineral Industries-Background Information for Proposed Standards,
EPA-450/3-85-025a, U. S. Environmental Protection Agency, Research Triangle Park, NC,
October 1985.
2. B. H. Spratt, The Structural Use of Lightweight Aggregate Concrete, Cement and Concrete
Association, United Kingdom, 1974.
3. Emission Test Report: Vulcan Materials Company, Bessemer, Alabama, EMB Report 80-LWA-4,
U. S. Environmental Protection Agency, Research Triangle Park, NC, March 1982.
4. Emission Test Report: Arkansas Lightweight Aggregate Corporation, West Memphis, Arkansas,
EMB Report 80-LWA-2, U.S. Environmental Protection Agency, Research Triangle Park, NC,
May 1981.
5. Emission Test Report: Plant K6, from Calciners and Dryers in Mineral Industries - Background
Information Standards, EPA-450/3-85-025a, U.S. Environmental Protection Agency, Research
Triangle Park, NC, October 1985.
6. Emission Test Report: Galite Corporation, Rockmart, Georgia, EMB Report 80-LWA-6, U.S.
Environmental Protection Agency, Research Triangle Park, NC, February 1982.
7. Summary of Emission Measurements on No. 5 Kiln, Carolina Solite Corporation, Aquadale,
North Carolina, Sholtes & Koogler Environmental Consultants, Inc., Gainesville, FL, April
1983.
8. Sulfur Dioxide Emission Measurements, Lightweight Aggregate Kiln No. 5 (Inlet), Carolina Solite
Corporation, Aquadale, North Carolina, Sholtes & Koogler Environmental Consultants, Inc.,
Gainesville, FL, May 1991.
9. Sulfur Dioxide Emission Measurements, Lightweight Aggregate Kiln No. 5 (Outlet), Carolina
Solite Corporation, Aquadale, North Carolina, Sholtes & Koogler Environmental Consultants,
Inc., Gainesville, FL, May 1991.
10. Summary of Paniculate Matter Emission Measurements, No. 5 Kiln Outlet, Florida Solite
Corporation, Green Cove Springs, Florida, Sholtes and Koogler Environmental Consultants,
Gainesville, FL, June 19, 1981.
11. Summary of Paniculate Matter Emission Measurements, No. 5 Kiln Outlet, Florida Solite
Corporation, Green Cove Springs, Florida, Sholtes and Koogler Environmental Consultants,
Gainesville, FL, September 3, 1982.
12. Paniculate Emission Source Test Conducted on No. I Kiln Wet Scrubber at Tombigbee
Lightweight Aggregate Corporation, Livingston, Alabama, Resource Consultants, Brentwood, TN,
November 12, 1981.
7/93 Mineral Products Industry 8.25-9
-------
13. Paniculate Emission Source Test Conducted on No.2 Kiln Wet Scrubber at Tombigbee
Lightweight Aggregate Corporation, Livingston, Alabama, Resource Consultants, Brentwood, TN,
November 12, 1981.
14. Report of Simultaneous Efficiency Tests Conducted on the Orange Kiln and Baghouse at Carolina
Stalite, Gold Hill, N.C., Rossnagel & Associates, Charlotte, NC, May 9, 1980.
15. Stack Test Report No. 85-1, Lehigh Lightweight Aggregate Plant, Dryer-Kiln No. 2, Woodsboro,
Maryland, Division of Stationary Source Enforcement, Maryland Department of Health and
Mental Hygiene, Baltimore, MD, February 1, 1985.
16. Stack Test Report No. 85-7, Lehigh Lightweight Aggregate Plant, Dryer-Kiln No. 1, Woodsboro,
Maryland, Division of Stationary Source Enforcement, Maryland Department of Health and
Mental Hygiene, Baltimore, MD, May 1985.
17. Emission Test Results for No. 2 and No. 4 Aggregate Kilns, Solite Corporation, Leaksville Plant,
Cascade, Virginia, IEA, Research Triangle Park, NC, August 8, 1992.
18. Emission Test Results for No. 2 Aggregate Kiln, Solite Corporation, Hubers Plant, Brooks,
Kentucky, IEA, Research Triangle Park, NC, August 12, 1992.
19. Emission Test Results for No. 7 and No. 8 Aggregate Kilns, Solite Corporation, A. F. Old Plant,
Arvonia, Virginia, IEA, Research Triangle Park, NC, August 8, 1992.
8.25-10 EMISSION FACTORS 7/93
-------
8.27 FELDSPAR PROCESSING
8.27.1 General1
Feldspar consists essentially of aluminum silicates combined with varying percentages of
potassium, sodium, and calcium, and it is the most abundant mineral of the igneous rocks. The two
types of feldspar are soda feldspar (7 percent or higher Na2O) and potash feldspar (8 percent or
higher K2O). Feldspar-silica mixtures can occur naturally, such as in sand deposits, or can be
obtained from flotation of mined and crushed rock.
8.27.2 Process Description l~2
Conventional open-pit mining methods including removal of overburden, drilling and blasting,
loading, and transport by trucks are used to mine ores containing feldspar. A froth flotation process
is used for most feldspar ore beneficiation. Figure 8.27-1 shows a process flow diagram of the
flotation process. The ore is crushed by primary and secondary crushers and ground by jaw crushers,
cone crushers, and rod mills until it is reduced to less than 841 /xm (20 mesh). Then the ore passes
to a three-stage, acid-circuit flotation process.
An amine collector that floats off and removes mica is used in the first flotation step. Also,
sulfuric acid, pine oil, and fuel oil are added. After the feed is dewatered in a classifier or cyclone to
remove reagents, sulfuric acid is added to lower the pH. Petroleum sulfonate (mahogany soap) is
used to remove iron-bearing minerals. To finish the flotation process, the discharge from the second
flotation step is dewatered again, and a cationic amine is used for collection as the feldspar is floated
away from quartz in an environment of hydrofluoric acid (pH of 2.5 to 3.0).
If feldspathic sand is the raw material, no size reduction may be required. Also, if little or no
mica is present, the first flotation step may be bypassed. Sometimes the final flotation stage is
omitted, leaving a feldspar-silica mixture (often referred to as sandspar), which is usually used in
glassmaking.
From the completed flotation process, the feldspar float concentrate is dewatered to 5 to 9
percent moisture. A rotary dryer is then used to reduce the moisture content to 1 percent or less.
Rotary dryers are the most common dryer type used, although fluid bed dryers are also used. Typical
rotary feldspar dryers are fired with No. 2 oil or natural gas, operate at about 230°C (450°F), and
have a retention time of 10 to 15 minutes. Magnetic separation is used as a backup process to
remove any iron minerals present. Following the drying process, dry grinding is sometimes
performed to reduce the feldspar to less than 74 /an (200 mesh) for use in ceramics, paints, and tiles.
Drying and grinding are often performed simultaneously by passing the dewatered cake through a
rotating gas-fired cylinder lined with ceramic blocks and charged with ceramic grinding balls.
Material processed in this manner must then be screened for size or air classified to ensure proper
particle size.
7/93 Mineral Products Industry 8.27-1
-------
CRUSHING, GRINDING
*
VIBRATING SCREEN
*
HYDROCLASS 1 F 1 ER
i
CONDITIONER
*
FLOTATION CELLS
*
CYCLONE
+
CONDITIONER
+
FLOTATION CELLS
—
»20 MESH
OVERFLOW SLIME
TO WASTE
AMINE, H 2SO^ .
PINE OIL, FUEL OIL
OVERFLOW
H a SO4 , PETROLEUM SULFONATE
OVERFLOW CGARNET}
SCC:
DRYER
3-05-034-02
f
GLASS PLANTS
GLASS PLANTS
POTTERY
8.27-2
Figure 8.27-1. Feldspar flotation process.1
EMISSION FACTORS
7/93
-------
8.27.2 Emissions and Controls
The primary pollutant of concern that is emitted from feldspar processing is paniculate matter
(PM). Paniculate matter is emitted by several feldspar processing operations, including crushing,
grinding, screening, drying, and materials handling and transfer operations.
Emissions from dryers typically are controlled by a combination of a cyclone or a multiclone
and a scrubber system. Paniculate matter emissions from crushing and grinding generally are
controlled by fabric filters.
Table 8.27-1 presents controlled emission factors for filterable PM from the drying process.
Table 8.27-2 presents emission factors for CO2 from the drying process. The controls used in
feldspar processing achieve only incidental control of CO2.
Table 8.27-1 (Metric Units).
EMISSION FACTORS FOR FILTERABLE PARTICULATE MATTER11
Process (SCC)
Dryer with
Dryer with
Filterable Paniculate
kg/Mg Emission
Feldspar Factor
Dried Rating
scrubber and demisterb (SCC 3-05-034-02) 0.60 D
mechanical collector and scrubberc>d (SCC 3-05-034-02) 0.041 D
Table 8.27-1 (English Units).
EMISSION FACTORS FOR FILTERABLE PARTICULATE MATTER*
Process (SCC)
Filterable Paniculate
Ib/Ton
Feldspar Dried
Emission
Factor
Rating
Dryer with scrubbed (SCC 3-05-034-02) 1.2 D
Dryer with mechanical collector and scrubberc>d (SCC 3-05-034-02) 0.081 D
a SCC = Source Classification Code
b Reference 4.
c Reference 3.
d Reference 5.
7/93
Mineral Products Industry
8.27-3
-------
Table 8.27-2 (Metric Units).
EMISSION FACTOR FOR CARBON DIOXIDE11
Process (SCQ
Dryer with
Carbon Dioxide
kg/Mg Emission
Feldspar Factor
Dried Rating
multiclone and scrubber5 (SCC 3-05-034-02) 51 D
Table 8.27-2 (English Units).
EMISSION FACTOR FOR CARBON DIOXIDE*
Process (SCQ
Dryer with
Carbon Dioxide
Ib/Ton
Feldspar
Dried
Emission
Factor
Rating
multiclone and scrubber5 (SCC 3-05-034-02) 102 D
* SCC = Source Classification Code.
b Scrubbers may achieve incidental control of CO2 emissions. Multiclones do not control CO2
emissions.
REFERENCES FOR SECTION 8.27
1. Calciners and Dryers in Mineral Industries-Background Information for Proposed Standards,
EPA-450/3-85-025a, U.S. Environmental Protection Agency, Research Triangle Park, NC,
October 1985.
2. US Minerals Yearbook 1989: Feldspar, Nepheline syenite, and Aplite: US Minerals Yearbook
1989, pp. 389-396.
3. Source Sampling Report for The Feldspar Corporation: Spruce Pine, NC, Environmental Testing
Inc., Charlotte, NC, May 1979.
4. Paniculate Emission Test Report for a Scrubber Stack at International Minerals Corporation:
Spruce Pine, NC, North Carolina Department of Natural Resources & Community Development,
Division of Environmental Management, September 1981.
5. Particulate Emission Test Report for Two Scrubber Stacks at Lawson United Feldspar & Mineral
Company: Spruce Pine, NC, North Carolina Department of Natural Resources & Community
Development, Division of Environmental Management, October 1978.
8.27-4
EMISSION FACTORS
7/93
-------
STORAGE OF ORGANIC LIQUIDS
12.1 PROCESS DESCRIPTION1'2
Storage vessels containing organic liquids can be found in many industries, including
(1) petroleum producing and refining, (2) petrochemical and chemical manufacturing,
(3) bulk storage and transfer operations, and (4) other industries consuming or producing
organic liquids. Organic liquids in the petroleum industry, usually called petroleum liquids,
generally are mixtures of hydrocarbons having dissimilar true vapor pressures (for example,
gasoline and crude oil). Organic liquids in the chemical industry, usually called volatile
organic liquids, are composed of pure chemicals or mixtures of chemicals with similar true
vapor pressures (for example, benzene or a mixture of isopropyl and butyl alcohols).
Five basic tank designs are used for organic liquid storage vessels: fixed roof
(vertical and horizontal), external floating roof, internal floating roof, variable vapor space,
and pressure (low and high). A brief description of each tank is provided below. Loss
mechanisms associated with each type of tank are provided in Section 12.2.
The emission estimating equations presented in Chapter 12 were developed by the
American Petroleum Institute (API). API retains the copyright to these equations. API has
granted permission for the nonexclusive; noncommercial distribution of this material to
governmental and regulatory agencies. However, API reserves its rights regarding all
commercial duplication and distribution of its material. Therefore, the material presented in
Chapter 12 is available for public use, but the material cannot be sold without written
permission from the American Petroleum Institute and the U. S. Environmental Protection
Agency.
Fixed Roof Tanks - A typical vertical fixed roof tank is shown in Figure 12.1-1. This type
of tank consists of a cylindrical steel shell with a permanently affixed roof, which may vary
in design from cone- or dome-shaped to flat.
Fixed roof tanks are either freely vented or equipped with a pressure/vacuum vent.
The latter allows them to operate at a slight internal pressure or vacuum to prevent the
release of vapors during very small changes in temperature, pressure, or liquid level. Of
current tank designs, the fixed roof tank is the least expensive to construct and is generally
considered the minimum acceptable equipment for storing organic liquids.
Horizontal fixed roof tanks are constructed for both above-ground and underground
service and are usually constructed of steel, steel with a fiberglass overlay, or fiberglass-
reinforced polyester. Horizontal tanks are generally small storage tanks with capacities of
less than 40,000 gallons. Horizontal tanks are constructed such that the length of the tank is
not greater than six times the diameter to ensure structural integrity. Horizontal tanks are
usually equipped with pressure-vacuum vents, gauge hatches and sample wells, and manholes
to provide access to these tanks. In addition, underground tanks are cathodically protected to
prevent corrosion of the tank shell. Cathodic protection is accomplished by placing
07/93 Storage of Organic Liquids 12-1
-------
sacrificial anodes in the tank that are connected to an impressed current system or by using
galvanic anodes in the tank.
The potential emission sources for above-ground horizontal tanks are the same as
those for vertical fixed roof tanks. Emissions from underground storage tanks are associated
mainly with changes in the liquid level in the tank. Losses due to changes in temperature or
barometric pressure are minimal for underground tanks because the surrounding earth limits
the diurnal temperature change, and changes in the barometric pressure result in only small
losses.
External Floating Roof Tanks - A typical external floating roof tank consists of an open-
topped cylindrical steel shell equipped with a roof that floats on the surface of the stored
liquid. Floating roof tanks that are currently in use are constructed of welded steel plate and
are of two general types: pontoon or double-deck. Pontoon-type and double-deck-type
external floating roofs are shown in Figures 12.1-2 and 12.1-3, respectively. With aU types
of external floating roof tanks, the roof rises and falls with the liquid level in the tank.
External floating roof tanks are equipped with a seal system, which is attached to the roof
perimeter and contacts the tank wall. The purpose of the floating roof and seal system is to
reduce evaporative loss of the stored liquid. Some annular space remains between the seal
system and the tank wall. The seal system slides against the tank wall as the roof is raised
and lowered. The floating roof is also equipped with roof fittings that penetrate the floating
roof and serve operational functions. The external floating roof design is such that
evaporative losses from the stored liquid are limited to losses from the seal system and roof
fittings (standing storage loss) and any exposed liquid on the tank walls (withdrawal loss).
Internal Floating Roof Tanks - An internal floating roof tank has both a permanent fixed roof
and a floating deck inside. The terms "deck" and "floating roof can be used
interchangeably in reference to the structure floating on the liquid inside the tank. There are
two basic types of internal floating roof tanks: tanks in which the fixed roof is supported by
vertical columns within the tank, and tanks with a self-supporting fixed roof and no internal
support columns. Fixed roof tanks that have been retrofitted to use a floating deck are
typically of the first type. External floating roof tanks that have been converted to internal
floating roof tanks typically have a self-supporting roof. Newly constructed internal floating
roof tanks may be of either type. The deck in internal floating roof tanks rises and falls with
the liquid level and either floats directly on the liquid surface (contact deck) or rests on
pontoons several inches above the liquid surface (noncontact deck). The majority of
aluminum internal floating roofs currently in service are noncontact decks. Typical contact
deck and noncontact deck internal floating roof tanks are shown in Figure 12.1-4.
Contact decks can be (1) aluminum sandwich panels that are bolted together, with a
honeycomb aluminum core floating in contact with the liquid; (2) pan steel decks floating in
contact with the liquid, with or without pontoons; and (3) resin-coated, fiberglass reinforced
polyester (FRP), buoyant panels floating in contact with the liquid. The majority of internal
contact floating roofs currently in service are aluminum sandwich panel-type or pan
steel-type. The FRP roofs are less common. The panels of pan steel decks are usually
welded together.
12-2 EMISSION FACTORS 07/93
-------
Typical noncontact decks have an aluminum deck and an aluminum grid framework
supported above the liquid surface by tubular aluminum pontoons or some other buoyant
structure. The noncontact decks usually have bolted deck seams. Installing a floating roof
or deck minimizes evaporative losses of the stored liquid. As with the external floating roof
tanks, both contact and noncontact decks incorporate rim seals and deck fittings for the same
purposes previously described for external floating roof tanks. Evaporation losses from
decks may come from deck fittings, nonwelded deck seams, and the annular space between
the deck and tank wall. In addition, these tanks are freely vented by circulation vents at the
top of the fixed roof. The vents minimize the possibility of organic vapor accumulation in
concentrations approaching the flammable range. An internal floating roof tank not freely
vented is considered a pressure tank. Emission estimation methods for such tanks are not
provided in AP-42.
Variable Vapor Space Tanks - Variable vapor space tanks are equipped with expandable
vapor reservoirs to accommodate vapor volume fluctuations attributable to temperature and
barometric pressure changes. Although variable vapor space tanks are sometimes used
independently, they are normally connected to the vapor spaces of one or more fixed roof
tanks. The two most common types of variable vapor space tanks are lifter roof tanks and
flexible diaphragm tanks.
Lifter roof tanks have a telescoping roof that fits loosely around the outside of the
main tank wall. The space between the roof and the wall is closed by either a wet seal,
which is a trough filled with liquid, or a dry seal, which uses a flexible coated fabric.
Flexible diaphragm tanks use flexible membranes to provide expandable volume.
They may be either separate gasholder units or integral units mounted atop fixed roof tanks.
Variable vapor space tank losses occur during tank filling when vapor is displaced by
liquid. Loss of vapor occurs only when the tank's vapor storage capacity is exceeded.
Pressure Tanks - Two classes of pressure tanks are in general use: low pressure (2.5 to
15 psig) and high pressure (higher than IS psig). Pressure tanks generally are used for
storing organic liquids and gases with high vapor pressures and are found in many sizes and
shapes, depending on the operating pressure of the tank. Pressure tanks are equipped with a
pressure/vacuum vent that is set to prevent venting loss from boiling and breathing loss from
daily temperature or barometric pressure changes. High-pressure storage tanks can be
07/93 Storage of Organic Liquids 12-3
-------
operated so that virtually no evaporative or working losses occur. In low-pressure tanks
working losses can occur with atmospheric venting of the tank during filling operations.' No
appropriate correlations are available to estimate vapor losses from pressure tanks.
Pressure/Vacuum Vent
Fixed Roo f
Float Gauge
Poo f Co Iumn
L i qu i d Leva I
Indi ca t or
Inlet Nozzl
Outlet Nozzle
Roof Manhole
Gouge-Hatch/
Sample Wei I
Cougar's PIo t f or
Spiral Stairway
Culindrical Shell
She I I Manhole
Figure 12.1-1. Typical fixed-roof tank.1
12-4
EMISSION FACTORS
07/93
-------
TABLE 12.3-2. PROPERTIES (Mv, Wvc, PVA, WL) OF SELECTED PETROLEUM LIQUIDS"
Petroleum liquid
Gasoline RVP 13
Oiioline RVP 10
Otioline RVP 7
Crude Oil RVP 5
Jet naphtha (JP-4)
Jet kerosene
Distillate fuel oil No. 2
Residual oil No. 6
Vapor
molecular
weight
(at 60°F)
Mv
(Ib/lb-mole)
62
66
68
50
80
130
130
190
Condensed vapor
density
(at 60"F)
Wvc
(Ib/gal)
4.9
5.1
5.2
4.5
5.4
6.1
6.1
6.4
Liquid
density, Ib/gal
at60"F
4.9
5.1
5.2
4.5
5.4
6.1
6.1
6.4
True vapor pressure in psi at
40°C
4.7
3.4
2.3
1.8
0.8
0.0041
0.0031
0.00002
50'F
5.7
4.2
2.9
2.3
1.0
0.0060
0.0045
0.00003
60°F
6.9
5.2
3.5
2.8
1.3
0.0085
0.0074
0.00004
70°F
8.3
6.2
4.3
3.4
1.6
0.011
0.0090
0.00006
80"F
9.9
7.4
5.2
4.0
1.9
0.015
0.012
0.00009
90°F
11.7
8.8
6.2
4.8
2.4
0.021
0.016
0.00013
100°F
13.8
10.5
7.4
5.7
2.7
0.029
0.022
0.00019
U)
Notes:
•References 7 and 8.
K>
-------
TABLE 12.3-3. PHYSICAL PROPERTIES OF SELECTED PETROCHEMICALS*
Name
Acetone
Acetonitrile
Acrytonitrile
Allyl alcohol
Allyl chloride
Ammonium
hydroxide
(28.8ft solution)
Benzene
in>-Butyl ilcohol
fe/1-Butyl alcohol
n-Butyl chloride
Carbon ditulfide
Caftan
tetrachloride
Chloroform
Chloroprene
Cyclohexaoe
Cyclopentaoe
1 , 1 -Dichloroethane
1 ,2-Dichloroethane
d»-1.2-
Dichloroethylene
tnau- 1 ,2-Dichloro-
ethylene
Dietfaytamine
Diethyl ether
Di-ito-propyl ether
1 ,4-Dioxane
Dipropyl ether
Ethyl acetate
Ethyl acrylate
Ethyl alcohol
Freon II
Formula
CH3COCH3
CH3CN
CH^CHCN
CH^CHCHjOH
CH^CHCHjCI
NH4OH-H2O
C6H6
(CH^CHCt^OH
(CHj)3COH
CHjCHjCr^CHjCI
CS,
cci4
CHC13
CH^CCrCH-.CH^
C6HI2
C5H10
CI^CHCI,
CHjCIC^CI
CHCI:CHCI
CHCI:CHCI
(CjH^NH
^"S^HS
(CH^CHOCHCCHj),
O • CBjCHjOCHjCHj
CI^CHjCHjOCH^HjCHj
CjHjOOCCI^
CjH^OOCCHiCHj
CjHjOH
CC3F
Molecular
weight
58.08
41.05
53.06
58.08
76.53
35.05
78.11
74.12
74.12
92.57
76.13
153.84
119.39
88.54
84.16
70.1?
98.97
98.97
96.95
96.95
73.14
74.12
102.17
88.10
102.17
88.10
100.11
46.07
137.38
Boiling
point at 1
atmosphere
(°F)
133.0
178.9
173.5
206.6
113.2
83.0
176.2
227.1
180.5
172.0
115.3
170.2
142.7
138.9
177.3
120.7
135.1
182.5
140.2
119.1
131.9
94.3
153.5
214.7
195.8
170.9
211.8
173.1
75.4
Liquid
density at
60°F(pounds
per gallon)
6.628
6.558
6.758
7.125
7.864
7.481
7.365
6.712
6.595
7.430
10.588
13.366
12.488
8.046
6.522
6.248
9.861
10.500
10.763
10.524
5.906
5.988
6.075
8.659
6.260
7.551
7.750
6.610
12.480
Vapor pressure (pounds per square inch absolute) at
40«p
1.682
0.638
0.812
0.135
2.998
5.130
0.638
0.058
0.174
0.715
3.036
0.793
1.528
1.760
0.677
2.514
1.682
0.561
1.450
2.552
1.644
4.215
1.199
0.232
0.425
0.580
0.213
0.193
7.032
50°F
2.185
0.831
0.967
0.193
3.772
6.630
0.870
0.097
0.290
1.006
3.867
1.064
1.934
2.320
0.928
3.287
2.243
0.773
2.011
3.384
1.992
5.666
1.586
0.329
0.619
0.831
0.290
0.406
8.804
60"F
2.862
1.083
1.373
0.261
4.797
8.480
1.160
0.135
0.425
1.320
4.834
1.412
2.475
2.901
1.218
4.177
2.901
1.025
2.668
4.351
2.862
7.019
2.127
0.425
0.831
1.102
0.425
0.619
10.900
70°F
3.713
1.412
1.799
0.387
6.015
10.760
1.508
0.193
0.638
1.740
6.014
1.798
3.191
3.655
1.605
5.240
3.771
1.431
3.461
5.530
3.867
8.702
2.746
0.619
1.102
1.489
0.599
0.870
13.40
80'F
4.699
1.876
2.378
0.522
7.447
13.520
1.972
0.271
0.909
2.185
7.387
2.301
4.061
4.563
2.069
6.517
4.738
1.740
4.409
6.807
4.892
10.442
3.481
0.831
1.431
1.934
0.831
1.218
16.31
90°F
5.917
2.456
3.133
0.716
9.110
16.760
2.610
0.387
1.238
2.684
9.185
2.997
5.163
5.685
2.610
8.063
5.840
2.243
5.646
8.315
6.130
13.342
4.254
1.141
1.876
2.514
1.122
1.682
19.69
100-F
7.251
3.133
4.022
1.006
11.025
20.680
3.287
0.541
1.702
3.481
11.215
3.771
6.342
6.981
3.249
9.668
7.193
2.804
6.807
10.016
7.541
Boils
5.298
1.508
2.320
3.191
1.470
2.320
2360
O
8
-------
Appendix D
Procedures For Sampling Surface And Bulk Materials
This appendix presents procedures recommended for the collection of material samples from paved
and unpaved roads and from bulk storage piles. (AP-42 Appendix E, "Procedures For Analyzing
Surface And Bulk Materials Samples", presents analogous information for the analysis of the samples.)
These recommended procedures are based on a review of American Society For Testing And Materials
(ASTM) methods, such as C-136 (sieve analysis) and D-2216 (moisture content). The
recommendations follow ASTM standards where practical, and where not, an effort has been made to
develop procedures consistent with the intent of the pertinent ASTM standards.
This appendix emphasizes that, before starting any field sampling program, one must first define
the study area of interest and then determine the number of samples that can be collected and analyzed
within the constraints of time, labor, and money available. For example, the study area could be
defined as an individual industrial plant with its network of paved/unpaved roadways and material
piles. In that instance, it is advantageous to collect a separate sample for each major dust source in
the plant. This level of resolution is useful in developing cost-effective emission reduction plans. On
the other hand, if the area of interest is geographically large (say a city or county, with a network of
public roads), collecting at least one sample from each source would be highly impractical. However,
in such an area, it is important to obtain samples representative of different source types within the
area.
D.I Samples From Unpaved Roads
Objective
The overall objective in an unpaved road sampling program is to inventory the mass of paniculate
matter (PM) emissions from the roads. This is typically done by
1. Collecting "representative" samples of the loose surface material from the road,
2. Analyzing the samples to determine silt fractions, and,
3. Using the results in the predictive emission factor model given in AP-42 Section 11.2.1,
Unpaved Roads, together with traffic data (e. g., number of vehicles traveling the road each
day).
Before any field sampling program, it is necessary to define the study area of interest and to
determine the number of unpaved road samples that can be collected and analyzed within the
constraints of time, labor, and money available. For example, the study area could be defined as a
very specific industrial plant having a network of roadways. Here it is advantageous to collect a
separate sample for each major unpaved road in the plant. This level of resolution is useful in
developing cost-effective emission reduction plans involving dust suppressants or traffic rerouting. On
the other hand, the area of interest may be geographically large, and well-defined traffic information
may not be easily obtained. In this case, resolution of the PM emission inventory to specific road
7/93 Appendix D D-l
-------
segments would not be feasible, and it would be more important to obtain representative road-type
samples within the area by aggregating several sample increments.
Procedure
For a network consisting of many relatively short roads contained in a well-defined study area (as
would be the case at an industrial plant), it is recommended that one collect a sample for each 0.8
kilometers (km) (0.5 miles [mi]) length, or portion thereof, for each major road segment. Here, the
term "road segment" refers to the length of road between intersections (the nodes of the network) with
other paved or unpaved roads. Thus, for a major segment 1 km (0.6 mi) long, two samples are
recommended.
For longer roads in study areas that are spatially diverse, it is recommended that one collect a
sample for each 4.8 km (3 mi) length of the road. Composite a sample from a minimum of three
incremental samples. Collect the first sample increment at a random location within the first 0.8 km
(0.5 mi), with additional increments taken from each remaining 0.8 km (0.5 mi) of the road, up to a
maximum length of 4.8 km (3 mi). For a road less than 1.5 mi in length, an acceptable method for
selecting sites for the increments is based on drawing three random numbers (xl, x2, x3) between zero
and the length. Random numbers may be obtained from tabulations in statistical reference books, or
scientific calculators may be used to generate pseudorandom numbers. See Figure D-l.
The following steps describe the collection method for samples (increments).
1. Ensure that the site offers an unobstructed view of traffic and that sampling personnel are
visible to drivers. If the road is heavily traveled, use one person to "spot" and route traffic safely
around another person collecting the surface sample (increment).
2. Using string or other suitable markers, mark a 0.3 meters (m) (1 foot [ft]) wide portion across
the road. (WARNING: Do not mark the collection area with a chalk line or in any other method
likely to introduce fine material into the sample.)
3. With a whisk broom and dustpan, remove the loose surface material from the hard road base.
Do not abrade the base during sweeping. Sweeping should be performed slowly so that fine surface
material is not injected into the air. NOTE: Collect material only from the portion of the road over
which the wheels and carriages routinely travel (i. e., not from berms or any "mounds" along the road
centerline).
4. Periodically deposit the swept material into a clean, labeled container of suitable size, such as
a metal or plastic 19 liter (L) (5 gallon [gal]) bucket, having a scalable polyethylene liner. Increments
may be mixed within this container.
5. Record the required information on the sample collection sheet (Figure D-2).
Sample Specifications
For uncontrolled unpaved road surfaces, a gross sample of 5 kilograms (kg) (10 pounds [lb]) to
23 kg (50 lb) is desired. Samples of this size will require splitting to a size amenable for analysis (see
D-2 EMISSION FACTORS 7/93
-------
Appendix E). For unpaved roads having been treated with chemical dust suppressants (such as
petroleum resins, asphalt emulsions, etc.), the above goal may not be practical in well-defined study
areas because a very large area would need to be swept. In general, a minimum of 400 grams (g)
(1 Ib) is required for silt and moisture analysis. Additional increments should be taken from heavily
controlled unpaved surfaces, until the minimum sample mass has been achieved.
D.2 Samples From Paved Roads
Objective
The overall objective in a paved road sampling program is to inventory the mass of paniculate
emissions from the roads. This is typically done by
1. Collecting "representative" samples of the loose surface material from the road,
2. Analyzing the sample to determine the silt fraction, and,
3. Combining the results with traffic data in a predictive emission factor model.
The remarks above about definition of the study area and the appropriate level of resolution for
sampling unpaved roads are equally applicable to paved roads. Before a field sampling program, it is
necessary first to define the study area of interest and then to determine the number of paved road
samples that can be collected and analyzed. For example, in a well-defined study area (e. g., an
industrial plant), it is advantageous to collect a separate sample for each major paved road, because
the resolution can be useful in developing cost-effective emission reduction plans. Similarly, in
geographically large study areas, it may be more important to obtain samples representative of road
types within the area by aggregating several sample increments.
Compared to unpaved road sampling, planning for a paved road sample collection exercise
necessarily involves greater consideration as to types of equipment to be used. Specifically, provisions
must be made to accommodate the characteristics of the vacuum cleaner chosen. For example, paved
road samples are collected by cleaning the surface with a vacuum cleaner with "tared" (i. e., weighed
before use) filter bags. Upright "stick broom" vacuums use relatively small, lightweight filter bags,
while bags for industrial-type vacuums are bulky and heavy. Because the mass collected is usually
several times greater than the bag tare weight, uprights are thus well suited for collecting samples from
lightly loaded road surfaces. On the other hand, on heavily loaded roads, the larger industrial-type
vacuum bags are easier to use and can be more readily used to aggregate incremental samples from all
road surfaces. These features are discussed further below.
Procedure
For a network of many relatively short roads contained in a well-defined study area (as would be
the case at an industrial plant), it is recommended that one collect a sample for each 0.8 km (0.5 mi)
length, or portion thereof, for each major road segment. For a 1 km long (0.6 mi) segment, then, two
samples are recommended. As mentioned, the term "road segment" refers to the length of road
between intersections with other paved or unpaved roads (the nodes of the network).
7/93 Appendix D D-3
-------
For longer roads in spatially heterogeneous study areas, it is recommended that one collect a
sample for each 4.8 km (3 mi) of sampled road length. Create a composite sample from a minimum
of three incremental samples. Collect the first increment at a random location within the first 0.8 km
(0.5 mi), with additional increments taken from each remaining 0.8 km (0.5 mi) of the road, up to a
maximum length of 4.8 km (3 mi.) For a road less than 2.4 km (1.5 mi) long, an acceptable method
for selecting sites for the increments is based on drawing three random numbers (xl, x2, x3) between
zero and the length (See Figure D-3). Random numbers may be obtained from tabulations in
statistical reference books, or scientific calculators may be used to generate pseudorandom numbers.
The following steps describe the collection method for samples (increments).
1. Ensure that the site offers an unobstructed view of traffic and that sampling personnel are
visible to drivers. If the road is heavily traveled, use one crew member to "spot" and route traffic
safely around another person collecting the surface sample (increment).
2. Using string or other suitable markers, mark the sampling portion across the road.
(WARNING: Do not mark the collection area with a chalk line or in any other method likely to
introduce fine, material into the sample.) The widths may be varied between 0.3 m (1 ft) for visibly
dirty roads and 3 m (10 ft) for clean roads. When an industrial-type vacuum is used to sample lightly
loaded roads, a width greater than 3 m (10 ft) may be necessary to meet sample specifications, unless
increments are being combined.
3. If large, loose material is present on the surface, it should be collected with a whisk broom
and dustpan. NOTE: Collect material only from the portion of the road over which the wheels and
carriages routinely travel (i. e., not from berms or any "mounds" along the road centerline). On roads
with painted side markings, collect material "from white line to white line" (but avoid centerline
mounds). Store the swept material in a clean, labeled container of suitable size, such as a metal or
plastic 19 L (5 gal) bucket, with a scalable polyethylene liner. Increments for the same sample may
be mixed within the container.
4. Vacuum the collection area using a portable vacuum cleaner fitted with an empty tared
(preweighed) filter bag. NOTE: Collect material only from the portion of the road over which the
wheels and carriages routinely travel (i. e., not from berms or any "mounds" along the road
centerline). On roads with painted side markings, collect material "from white line to white line" (but
avoid centerline mounds). The same filter bag may be used for different increments for one sample.
For heavily loaded roads, more than one filter bag may be needed for a sample (increment).
5. Carefully remove the bag from the vacuum sweeper and check for tears or leaks. If necessary,
reduce samples (using the procedure in Appendix E) from broom sweeping to a size amenable to
analysis. Seal broom-swept material in a clean, labeled plastic jar for transport (alternatively, the
swept material may be placed in the vacuum filter bag). Fold the unused portion of the filter bag,
wrap a rubber band around the folded bag, and store the bag for transport.
6. Record the required information on the sample collection sheet (Figure D-4).
D-4 EMISSION FACTORS 7/93
-------
Sample Specifications
When broom swept samples are collected, they should be at least 400 g (1 Ib) for silt and moisture
analysis. Vacuum swept samples should be at least 200 g (0.5 Ib). Also, the weight of an "exposed"
filter bag should be at least 3 to 5 times greater than when empty. Additional increments should be
taken until these sample mass goals have been attained.
D.3 Samples From Storage Piles
Objective
The overall objective of a storage pile sampling and analysis program is to inventory paniculate
matter emissions from the storage and handling of materials. This is done typically by
1. Collecting "representative" samples of the material,
2. Analyzing the samples to determine moisture and silt contents, and,
3. Combining analytical results with material throughput and meteorological information in an
emission factor model.
As initial steps in storage pile sampling, it is necessary to decide (a) what emission mechanisms -
material load-in to and load-out from the pile, wind erosion of the piles - are of interest and (b) how
many samples can be collected and analyzed, given time and monetary constraints. (In general, annual
average PM emissions from material handling can be expected to be much greater than those from
wind erosion.) For an industrial plant, it is recommended that at least one sample be collected for
each major type of material handled within the facility.
In a program to characterize load-in emissions, representative samples should be collected from
material recently loaded into the pile. Similarly, representative samples for load-out emissions should
be collected from areas that are worked by load-out equipment such as front end loaders or clamshells.
For most "active" piles (i. e., those with frequent load-in and load-out operations), one sample may be
considered representative of both loaded-in and loaded-out materials. Wind erosion material samples
should be representative of the surfaces exposed to the wind.
In general, samples should consist of increments taken from all exposed areas of the pile (i. e., top,
middle, and bottom). If the same material is stored in several piles, it is recommended that piles with
at least 25% of the amount in storage be sampled. For large piles that are common in industrial
settings (e. g., quarries, iron and steel plants), access to some portions may be impossible for the
person collecting the sample. In that case, increments should be taken no higher than it is practical for
a person to climb carrying a shovel and a pail.
Procedure
The following steps describe the method for collecting samples from storage piles.
7/93 Appendix D D-5
-------
1. Sketch plan and elevation views of the pile. Indicate if any portion is not accessible. Use the
sketch to plan where the N increments will be taken by dividing the perimeter into N-l roughly
equivalent segments.
a. For a large pile, collect a minimum of 10 increments, as near to mid-height of the pile as
practical.
b. For a small pile, a sample should be a minimum of 6increments, evenly distributed among
the top, middle, and bottom.
"Small" or "large" piles, for practical purposes, may be defined as those piles which can or
cannot, respectively, be scaled by a person carrying a shovel and pail.
2. Collect material with a straight-point shovel or a small garden spade, and store the increments
in a clean, labeled container of suitable size (such as a metal or plastic 19 L [5 gal] bucket) with a
scalable polyethylene liner. Depending upon the ultimate goals of the sampling program, choose one
of the following procedures:
a. To characterize emissions from material handling operations at an active pile, take
increments from the portions of the pile which most recently had material added and
removed. Collect the material with a shovel to a depth of 10 to 15 centimeters (cm) (4 to
6 inches [in]). Do not deliberately avoid larger pieces of aggregate present on the surface.
b. To characterize handling emissions from an inactive, pile, obtain increments of the core
material from a 1 m (3 ft) depth in the pile. A sampling tube 2 m (6 ft) long, with a
diameter at least 10 times the diameter of the largest particle being sampled, is
recommended for these samples. Note that, for piles containing large particles, the
diameter recommendation may be impractical.
c. If characterization of wind erosion , rather than material handling is the goal of the
sampling program, collect the increments by skimming the surface in an upwards direction.
The depth of the sample should be 2.5 cm (1 in), or the diameter of the largest particle,
whichever is less. Do not deliberately avoid collecting larger pieces of aggregate present
on the surface.
In most instances, collection method "a" should be selected.
3. Record the required information on the sample collection sheet (Figure D-5). Note the space
for deviations from the summarized method.
Sample Specifications
For any of the procedures, the sample mass collected should be at least 5 kg (10 Ib). When most
materials are sampled with procedures 2.a or 2.b, ten increments will normally result in a sample of at
least 23 kg (50 Ib). Note that storage pile samples usually require splitting to a size more amenable to
laboratory analysis.
D-6 EMISSION FACTORS 7/93
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J
Road Length >1.5 mi
Road
Intersection
~l
1 ft. 1 ft.
x ^- •*• 0.5 mi ^- •*• 0.5 mi-
M
1ft.
•0.5 mi
x
a
j
Road
Intersection
Road Length <1 .5 mi
n
I
I
I
M MM
1 ft. 1 ft. 1 ft.
x2-
x3-
Road
Intersection
Figure D-l. Sampling locations for unpaved roads.
-------
Date Collected
SAMPLING DATA FOR UNPAVED ROADS
Recorded by
Road Material (e.g., gravel, slag, dirt,
etc.):*
Site of sampling:
METHOD:
1. Sampling device: whisk broom and dustpan
2. Sampling depth: loose surface material (do not abrade road base)
3. Sample container: bucket with sealable liner
4. Gross sample specifications:
a. Uncontrolled surfaces -- 5 kg (10 Ib) to 23 kg (50 Ib)
b. Controlled surfaces - minimum of 400 g (1 Ib) is required for analysis
Refer to AP-42 Appendix D for more detailed instructions.
Indicate any deviations from the above:.
SAMPLING DATA COLLECTED:
Sample
No.
Time
Location +
Surf.
Area
Depth
Mass of
Sample
* Indicate and give details if roads are controlled.
+ Use code given on plant or road map for segment identification. Indicate sampling
location on map.
D-8
Figure D-2. Example data form for unpaved road samples.
EMISSION FACTORS
7/93
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Road
Intersection
Road Length ^1 .5 mi
n
*
1 ••% '•
••.,,,,
•-r-" "-r-J l-r-J
MOft. MOft. MOft.
I
x'
a
Road Length <1.5mi
Road
Intersection
Road
Intersection
MOft. MOft. MOft.
x2-
x3-
Figure D-3. Sampling locations for paved roads.
-------
SAMPLING DATA FOR PAVED ROADS
Date Collected
Sampling location*
Recorded by
No. of Lanes
Surface type (e.g., asphalt, concrete, etc.).
Surface condition (e.g., good, rutted, etc.).
* Use code given on plant or road map for segment identification. Indication sampling
location on map.
METHOD:
1. Sampling device: portable vacuum cleaner (whisk broom and dustpan if heavy
loading present)
2. Sampling depth: loose surface material (do not sample curb areas or other
untravelled portions of the road)
3. Sample container: tared and numbered vacuum cleaner bags (bucket with sealable
liner if heavy loading present)
4. Gross sample specifications: Vacuum swept samples should be at least 200 g
(0.5 Ib), with the exposed filter bag weight should be at least 3 to 5 times greater
than the empty bag tare weight.
Refer to AP-42 Appendix D for more detailed instructions.
Indicate any deviations from the above:.
SAMPLING DATA COLLECTED:
Sample
No.
Vacuum Bag
ID Tare Wgt (g)
Sampling
Surface Dimensions
(Ixw)
Time
Mass of
Broom-Swept
Sample +
+ Enter "0" if no broom sweeping is performed.
Figure D-4. Example data form for paved roads.
D-10
EMISSION FACTORS
7/93
-------
Date Collected
SAMPLING DATA FOR STORAGE PILES
Recorded by
Type of material sampled
Sampling location*
METHOD:
1. Sampling device: pointed shovel (hollow sampling tube if inactive pile is to be
sampled)
2. Sampling depth:
For material handling of active piles: 10-15 cm (4-6 in)
For material handling of inactive piles: 1 m (3 ft)
For wind erosion samples: 2.5 cm (1 in) or depth of the largest particle (whichever
is less)
3. Sample container: bucket with sealable liner
4. Gross sample specifications:
For material handling of active or inactive piles: minimum of 6 increments with total
sample weight of 5 kg (10 Ib) [10 increments totalling 23 kg (50 Ib) are
recommended]
For wind erosion samples: minimum of 6 increments with total sample weight of
5kg(10lb)
Refer to AP-42 Appendix D for more detailed instructions.
Indicate any deviations from the above:
SAMPLING DATA COLLECTED:
Sample
No.
Time
Location* of
Sample Collection
Device Used
S/T**
Depth
Mass of
Sample
* Use code given of plant or area map for pile/sample identification. Indicate each sampling location
on map.
"Indicate whether shovel or tube.
Figure D-5. Example data form for storage piles.
7/93
Appendix D
D-ll
-------
Appendix E
Procedures For Analyzing Surface And Bulk Material Samples
This appendix discusses procedures recommended for the analysis of samples collected from paved
and unpaved surfaces and from bulk storage piles. (AP-42 Appendix D, "Procedures For Sampling
Surface And Bulk Materials", presents procedures for the collection of these samples.) These
recommended procedures are based on a review of American Society For Testing And Materials
(ASTM) methods, such as C-136 (sieve analysis) or D-2216 (moisture content). The recommendations
follow ASTM standards where practical, and where not, an effort has been made to develop
procedures consistent with the intent of the pertinent ASTM standards.
E.I Sample Splitting
Objective
The collection procedures presented in Appendix D can result in samples that need to be reduced
in size before laboratory analysis. Samples are often unwieldy, and field splitting is advisable before
transporting the samples.
The size of the laboratory sample is important. Too small a sample will not be representative, and
too much sample will be unnecessary as well as unwieldy. Ideally, one would like to analyze the
entire gross sample in batches, but that is not practical. While all ASTM standards acknowledge this
impracticality, they disagree on the exact optimum size, as indicated by the range of recommended
samples, extending from 0.05 to 27 kilograms (kg) (0.1 to 60 pounds [lb]).
Splitting a sample may be necessary before a proper analysis. The principle in sizing a laboratory
sample for silt analysis is to have sufficient coarse and fine portions both to be representative of the
material and to allow sufficient mass on each sieve to assure accurate weighing. A laboratory sample
of 400 to 1,600 grams (g) is recommended because of the capacity of normally available scales (1.6 to
2.6 kg). A larger sample than this may produce "screen blinding" for the 20 centimeter (cm) (8 inch
[in]) diameter screens normally available for silt analysis. Screen blinding can also occur with small
samples of finer texture. Finally, the sample mass should be such that it can be spread out in a
reasonably sized drying pan to a depth of < 2.5cm (1 in).
Two methods are recommended for sample splitting: riffles, and coning and quartering. Both
procedures are described below.
Procedures
Figure E-l shows two riffles for sample division. Riffle slot widths should be at least three times
the size of the largest aggregate in the material being divided. The following quote from ASTM
Standard Method D2013-72 describes the use of the riffle.
7/93 Appendix E E-l
-------
SAMPLE DIVIDERS (RIFFLES)
Feed Chute
Rolled
Edges
Riffle Sampler
(b)
Riffle Bucket and
Separate Feed Chute Stand
(b)
Figure E-l. Sample riffle dividers.
CONING AND QUARTERING
Figure E-2. Procedure for coning and quartering.
E-2
EMISSION FACTORS
7/93
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Divide the gross sample by using a riffle. Riffles properly used will reduce sample
variability but cannot eliminate it. Riffles are shown in [Figure E-l]. Pass the material
through the riffle from a feed scoop, feed bucket, or riffle pan having a lip or opening the full
length of the riffle. When using any of the above containers to feed the riffle, spread the
material evenly in the container, raise the container, and hold it with its front edge resting on
top of the feed chute, then slowly tilt it so that the material flows in a uniform stream through
the hopper straight down over the center of the riffle into all the slots, thence into the riffle
pans, one-half of the sample being collected in a pan. Under no circumstances shovel the
sample into the riffle, or dribble into the riffle from a small-mouthed container. Do not allow
the material to build up in or above the riffle slots. If it does not flow freely through the slots,
shake or vibrate the riffle to facilitate even flow.
Coning and quartering is a simple procedure useful with all powdered materials and with sample
sizes ranging from a few grams to several hundred pounds. Oversized material, defined as > 0.6
millimeters (mm) (3/8 in) in diameter, should be removed before quartering and be weighed in a
"tared" container (one for which its empty weight is known).
Preferably, perform the coning and quartering operation on a floor covered with clean 10 mil
(mm) plastic. Take care that the material is not contaminated by anything on the floor or that any
portion is not lost through cracks or holes. Samples likely affected by moisture or drying must be
handled rapidly, preferably in a controlled atmosphere, and sealed in a container to prevent further
changes during transportation and storage.
The procedure for coning and quartering is illustrated in Figure E-2. The following procedure
should be used:
1. Mix the material and shovel it into a neat cone.
2. Flatten the cone by pressing the top without further mixing.
3. Divide the flat circular pile into equal quarters by cutting or scraping out two diameters at
right angles.
4. Discard two opposite quarters.
5. Thoroughly mix the two remaining quarters, shovel them into a cone, and repeat the quartering
and discarding procedures until the sample is reduced to 0.4 to 1.8 kg (1 to 4 Ib).
E.2 Moisture Analysis
Paved road samples generally are not to be oven dried because vacuum filter bags are used to
collect the samples. After a sample has been recovered by dissection of the bag, it is combined with
any broom swept material for silt analysis. All other sample types are oven dried to determine
moisture content before sieving.
7/93 Appendix E E-3
-------
Procedure
1. Heat the oven to approximately 110°C (230°F). Record oven temperature. (See Figure E-3.)
2. Record the make, capacity, and smallest division of the scale.
3. Weigh the empty laboratory sample containers which will be placed in the oven to determine
their tare weight. Weigh any lidded containers with the lids. Record the tare weight(s). Check zero
before each weighing.
4. Weigh the laboratory sample(s) in the container(s). For materials with high moisture content,
assure that any standing moisture is included in the laboratory sample container. Record the combined
weight(s). Check zero before each weighing.
5. Place sample in oven and dry overnight. Materials composed of hydrated minerals or organic
material such as coal and certain soils should be dried for only 1.5 hours.
6. Remove sample container from oven and (a) weigh immediately if uncovered, being careful of
the hot container; or (b) place a tight-fitting lid on the container and let it cool before weighing.
Record the combined sample and container weight(s). Check zero before weighing.
7. Calculate the moisture, as the initial weight of the sample and container, minus the oven-dried
weight of the sample and container, divided by the initial weight of the sample alone. Record the
value.
8. Calculate the sample weight to be used in the silt analysis, as the oven-dried weight of the
sample and container, minus the weight of the container. Record the value.
Date:
MOISTURE ANALYSIS
By:
Sample No:
Material:
Split Sample Balance:
Make
Oven Temperature:
Date In
Time In
Drying Time
Date Out.
Time Out
Capacity
Smallest division
Sample Weight (after drying)
Pan + Sample:
Pan:
Total Sample Weight:
(Excl. Container)
Number of Splits:
Dry Sample:
Split Sample Weight (before drying)
Pan + Sample:
Pan:
Wet Sample:
MOISTURE CONTENT:
(A) Wet Sample Wt.
(B) Dry Sample Wt.
(C) Difference Wt.
Cx 100
A = % Moisture
Figure E-3. Example moisture analysis form.
E-4
EMISSION FACTORS
7/93
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E.3 Silt Analysis
Objective
Several open dust emission factors have been found to be correlated with the silt content (< 200
mesh) of the material being disturbed. The basic procedure for silt content determination is
mechanical, dry sieving. For sources other than paved roads, the same sample which was oven-dried
to determine moisture content is then mechanically sieved.
For paved road samples, the broom-swept particles and the vacuum-swept dust are individually
weighed on a beam balance. The broom-swept particles are weighed in a container, and the vacuum-
swept dust is weighed in the bag of the vacuum, which was tared before sample collection. After
weighing the sample to calculate total surface dust loading on the traveled lanes, combine the broom-
swept particles and the vacuumed dust. Such a composite sample is usually small and may not require
splitting in preparation for sieving.
Procedure
1. Select the appropriate 20-cm (8-in) diameter, 5-cm (2-in) deep sieve sizes. Recommended U.
S. Standard Series sizes are 3/8 in, No. 4, No. 40, No. 100, No. 140, No. 200, and a pan. Comparable
Tyler Series sizes can also be used. The No. 20 and the No. 200 are mandatory. The others can be
varied if the recommended sieves are not available, or if buildup on one particulate sieve during
sieving indicates that an intermediate sieve should be inserted.
2. Obtain a mechanical sieving device, such as a vibratory shaker or a Roto-Tap® without the
tapping function.
3. Clean the sieves with compressed air and/or a soft brush. Any material lodged in the sieve
openings or adhering to the sides of the sieve should be removed, without handling the screen roughly,
if possible.
4. Obtain a scale (capacity of at least 1600 grams [g] or 3.5 Ib) and record make, capacity,
smallest division, date of last calibration, and accuracy. (See Figure E-4.)
5. Weigh the sieves and pan to determine tare weights. Check the zero before every weighing.
Record the weights.
6. After nesting the sieves in decreasing order of size, and with pan at the bottom, dump dried
laboratory sample (preferably immediately after moisture analysis) into the top sieve. The sample
should weigh between - 400 and 1600 g (- 0.9 and 3.5 Ib). This amount will vary for finely textured
materials, and 100 to 300 g may be sufficient when 90% of the sample passes a No. 8 (2.36 mm)
sieve. Brush any fine material adhering to the sides of the container into the top sieve and cover the
top sieve with a special lid normally purchased with the pan.
7. Place nested sieves into the mechanical sieving device and sieve for 10 minutes (min.).
Remove pan containing minus No. 200 and weigh. Repeat the sieving at 10-min. intervals until the
7/93 Appendix E E-5
-------
difference between two successive pan sample weighings (with the pan tare weight subtracted) is less
than 3.0%. Do not sieve longer than 40 min.
8. Weigh each sieve and its contents and record the weight. Check the zero before every
weighing.
9. Collect the laboratory sample. Place the sample in a separate container if further analysis is
expected.
10. Calculate the percent of mass less than the 200 mesh screen (75 micrometers [um]). This is
the silt content.
E.4 References
1. "Standard Method Of Preparing Coal Samples For Analysis", Annual Book Of ASTM Standards,
1977, D2013-72, American Society For Testing And Materials, Philadelphia, PA, 1977.
2. L. Silverman, et al., Panicle Size Analysis In Industrial Hygiene, Academic Press, New York,
1971.
E-6 EMISSION FACTORS 7/93
-------
SILT ANALYSIS
Date
Sample No:
Material:
By
Sample Weight (after drying)
Pan + Sample:
Pan:
Split Sample Balance:
Make
Smallest Division
SIEVING
Dry Sample:
Capacity
Final Weight:
Net Weight <200 Mesh
% Silt = Total Net Weight x 100 = %
Time: Start:
Initial (Tare):
10 min:
20 min:
30 min:
40 min:
Weight (Pan Only)
Screen
3/8 in.
4 mesh
10 mesh
20 mesh
40 mesh
100 mesh
140 mesh
200 mesh
Pan
Tare Weight
(Screen)
Final Weight
(Screen + Sample)
Net Weight (Sample)
%
Figure E-4. Example silt analysis form.
7/93
Appendix E
E-7
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
AP-42
2.
Volume I, Supplement F
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Supplement F To Compilation Of Air Pollutant Emission
Factors, Volume I
5. REPORT DATE
July 1993
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
U. S. Environmental Protection Agency
Office Of Air Quality Planning And Standards (MD 14)
Research Triangle Park, NC 27711
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This supplement to the AP-42 series contains new or revised emission information on 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; and Procedures For Analyzing Surface And
Bulk Material Samples.
This information is necessary for developing State Implementation Plans, emission inventories and
operating permits.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS c. COSATI Field/Group
Stationary Sources
Point Sources
Area Sources
Emissions
Emission Factors
Air Pollutants
18. DISTRIBUTION STATEMENT
19. SECURITY CLASS (This Report)
21. NO. Or PAGES
628
20. SECURITY CLASS (This page)
22. PRICE
EPA Form 2220-1 (Rev. 4-77) PREVIOUS EDITION is OBSOLETE
*U.S. G.P.O.:1993-728-090:87002
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