AP-42
Fifth Edition
Supplement B
November 1996
SUPPLEMENT B
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
November 1996
-------
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 intented to constitute endorsement or recommendation for use.
AP-42
Fifth Edition
Volume I
Supplement B
ii
-------
Instructions For Inserting
Supplement B Of Volume I
Into AP-42
Preliminary Matter
Chap. I,Sect 1-11
Chap. 2, Sect. 1
Chap. 3, Sect. 1-4
Chap. 6, Sect. 2
Chap. 9, Sect. 7
Chap. 9, Sect. 9.4
Chap. 9, Sect. 12.1
Chap. 11. Sect. 7
Chap. 12, Sect. 20
Chap. 13, Sect. 1
Chap. 14, Sect. 1-3
Insert new Technical
Publications In Series. Contents, Key
Word Index Replace all
External Combustion Sources Replace all
Refuse Combustion Replace entire
Stationary Internal Combustion Sources Replace all
Adipic Acid Replace entire
Cotton Ginning Replace [Work In Progress] sheet
Alfalfa Dehydrating Replace [Work In Progress] sheet
Malt Beverages Replace [Work In Progress] sheet
Ceramic Products Manufacturing Replace entire
Electroplating Add
Wildfires And Prescribed Burning Replace entire
Greenhouse Gas Biogenic Sources Add
Report Data Sheet.
Minor Revision
New Information
Minor Revision
New Information
Major Revision
New Section
New Section
New Section
Major Revision
New Section
Minor Revision
New Chapter
-------
PUBLICATIONS IN SERIES
Issue
COMPILATION OF AIR POLLUTANT EMISSION FACTORS, FIFTH EDITION
Date
1/95
SUPPLEMENT A
Introduction
Section 1.1
1.2
1.3
1.4
1.6
1.7
I.11
3.1
3.2
3.4
5.3
7.0
7.1
9.5.2
9.5.3
9.8.1
9.8.2
9.8.3
9.9.1
9.9.2
9.9.5
9.11.1
9.12.2
9.13.2
10.7
II.10
11.14
11.19
11,22
11.26
11.28
13.2.1
12.2.2
Appendix B.2
11/96
Bituminous And Subbituminous Coal Combustion
Anthracite Coal Combustion
Fuel Oil Combustion
Natural Gas Combustion
Wood Waste Combustion In Boilers
Lignite Combustion
Waste Oil Combustion
Stationary Gas Turbines For Electricity Generation
Heavy-duty Natural Gas-fired Pipeline Compressor Engines
Large Stationary Diesel And All Stationary Dual-fuel Engines
Natural Gas Processing
Liquid Storage Tanks Introduction
Organic Liquid Storage Tanks
Meat Smokehouses
Meat Rendering Plants
Canned Fruits And Vegetables
Dehydrated Fruits And Vegetables
Pickles, Sauces And Salad Dressings
Grain Elevators And Processes
Cereal Breakfast Food
Pasta Manufacturing
Vegetable Oil Processing
Wines And Brandy
Coffee Roasting
Charcoal
Coal Cleaning
Frit Manufacturing
Construction Aggregate Processing
Diatomite Processing
Talc Processing
Vcrmiculite Processing
Paved Roads
Unpaved Roads
Generalized Particle Size Distributions
SUPPLEMENT B 11/96
Section
1.1 Bituminous And Subbituminous Coal Combustion
1.2 Anthracite Coal Combustion
1.3 Fuel Oil Combustion
1.4 Natural Gas Combustion
11/96 Publication In Series iii
-------
1.5 Liquefied Petroleum Gas Combustion
1.6 Wood Waste Combustion In Boilers
1.7 Lignite Combustion
1.8 Bagasse Combustion Ln Sugar Mills
1.9 Residential Fireplaces
1.10 Residential Wood Stoves
1.11 Waste Oil Combustion
2,1 Refuse Combustion
3.1 Stationary Gas Turbines For Electricity Generation
3.2 Heavy-duty Natural Gas-fired Pipeline Compressor Engines
3.3 Gasoline And Diesel Industrial Engines
3.4 Large Stationary Diesel And All Stationary Dual-fuel Engines
6.2 Adipic Acid
9,7 Cotton Ginning
9.9.4 Alfalfa Dehydrating
9.12.1 Malt Beverages
11.7 Ceramic Products Manufacturing
12.20 Electroplating
13.1 Wildfires And Prescribed Burning
14.0 Greenhouse Gas Biogenic Sources
14.1 Emissions From Soils—Greenhouse Gases
14.2 Termites—Greenhouse Gases
14.3 Lightning Emissions—Greenhouse
IV
EMISSION FACTORS
11/96
-------
CONTENTS
Page
Introduction 1
1. External Combustion Sources 1,0-1
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 Liquefied 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 Disposai 2.0-1
2.1 Refuse Combustion 2.1-1
2.2 Sewage Sludge Incineration 2.2-1
2.3 Medical Waste Incineration 2.3-1
2.4 Landfills 2.4-1
2.5 Open Burning 2.5-1
2.6 Automobile Body Incineration 2.6-1
2.7 Conical Burners 2.7-1
3, Stationary Internal Combustion Sources 3.0-1
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 4,0-1
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
4.2.2.1 General Industrial Surface Coating 4.2.2.1-1
4.2.2.2 Can Coating 4.2.2.2-1
4.2.2.3 Magnet Wire Coating 4.2.2.3-1
4.2.2.4 Other Metal Coating 4.2.2.4-1
4.2.2.5 Flat Wood Interior Panel Coating 4.2.2.5-1
4.2.2.6 Paper Coating 4.2,2.6-1
4.2.2.7 Polymeric Coating Of Supporting Substrates 4.2.2.7-1
4.2.2.8 Automobile And Light Duty Truck Surface Coating Operations 4.2.2.8-1
4.2.2.9 Pressure Sensitive Tapes And Labels 4.2.2.9-1
4.2.2.10 Metal Coil Surface Coating 4.2.2.10-1
11/96
Contents
v
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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 Waste Water Collection, Treatment And Storage 4.3-1
4.4 Polyester Resin Plastic Products Fabrication 4.4-1
4.5 Asphalt Paving Operations 4.5-1
4.6 Solvent Degreasing 4.6-1
4.7 Waste Solvent Reclamation 4.7-1
4.8 Tank And Drum Cleaning 4.8-1
4.9 Graphic Arts 4.9 -1
4.9.1 General Graphic Printing 4.9.1-1
4.9.2 Publication Gravure Printing 4.9.2-1
4.10 Commercial/Consumer Solvent Use 4.10-1
4.11 Textile Fabric Printing 4.11-1
5. Petroleum Industry 5.0-1
5.1 Petroleum Refining 5.1-1
5.2 Transportation And Marketing Of Petroleum Liquids 5.2-1
5.3 Natural Gas Processing 5.3-1
6. Organic Chemical Process Industry 6.0-1
6.1 Carbon Black 6.1-1
6.2 AdipicAcid 6.2-1
6.3 Explosives 6.3-1
6.4 Paint And Varnish 6.4-1
6.5 Phthalic Anhydride 6.5-1
6.6 Plastics 6.6-1
6.6.1 Polyvinyl Chloride 6.6.1-1
6.6.2 Poly(ethylene terephthalate) 6.6.2-1
6.6.3 Polystyrene 6.6.3-1
6.6.4 Polypropylene 6.6.4-1
6.7 Printing Ink 6.7-1
6.8 Soap And Detergents 6.8-1
6.9 Synthetic Fibers 6.9-1
6.10 Synthetic Rubber 6.10-1
6.11 Terephthalic Acid 6.11-1
6.12 Lead Alkyl 6.12-1
6.13 Pharmaceuticals Production 6.13-1
6.14 Maleic Anhydride 6.14-1
6.15 Methanol 6,15-1
6.16 Acetone And Phenol 6.16-1
6.17 Propylene 6.17-1
6.18 Benzene, Toluene And Xylenes 6.18-1
6.19 Butadiene 6.19-1
6.20 Cumene 6.20-1
6.21 Ethanol 6.21-1
6.22 Ethyl Benzene 6.22-1
6.23 Ethylene 6.23-1
6.24 Ethylene Dichloride And Vinyl Chloride 6.24-1
6.25 Ethylene Glycol 6.25-1
vi EMISSION FACTORS 11/96
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6.26 Ethylene Oxide 6.26-1
6.27 Formaldehyde 6.27-1
6.28 Glycerine 6.28-1
6.29 Isopropy! Alcohol 6.29-1
7. Liquid Storage Tanks 7.0-1
7.1 Organic Liquid Storage Tanks 7.1-1
8. Inorganic Chemical Industry 8.0-1
8.1 Synthetic Ammonia 8.1-1
8.2 Urea 8.2-1
8.3 Ammonium Nitrate 8.3-1
8.4 Ammonium Sulfate 8.4-1
8.5 Phosphate Fertilizers 8.5-1
8.5.1 Normal Superphosphates 8.5.1-1
8.5.2 Triple Superphosphates 8.5.2-1
8.5.3 Ammonium Phosphate 8.5.3-1
8.6 Hydrochloric Acid 8.6-1
8.7 Hydrofluoric Acid 8.7-1
8.8 Nitric Acid 8.8-1
8.9 Phosphoric Acid 8.9-1
8.10 Sulfuric Acid 8.10-1
8.11 Chlor-Alkali 8.11-1
8.12 Sodium Carbonate 8.12-1
8.13 Sulfur Recovery 8.13-1
8.14 Hydrogen Cyanide 8.14-1
9. Food And Agricultural Industries 9.0-1
9.1 Tilling Operations 9.1-1
9.2 Growing Operations 9.2-1
9.2.1 Fertilizer Application 9.2.1-1
9.2.2 Pesticide Application 9.2.2-1
9.2.3 Orchard Heaters 9.2.3-1
9.3 Harvesting Operations 9.3-1
9.3.1 Cotton Harvesting 9,3.1-1
9.3.2 Grain Harvesting 9.3.2-1
9.3.3 Rice Harvesting 9.3.3-1
9.3.4 Cane Sugar Harvesting 9,3.4-1
9.4 Livestock And Poultry Feed Operations 9.4-1
9.4.1 Cattle Fecdlots 9.4,1-1
9.4.2 Swine Feedlots 9.4.2-1
9.4.3 Poultry Houses 9.4.3-1
9.4.4 Dairy Farms 9.4.4-1
9.5 Animal And Meat Products Preparation 9.5-1
9.5.1 Meat Packing Plants 9.5.1-1
9.5.2 Meat Smokehouses 9.5.2-1
9.5.3 Meat Rendering Plants 9.5.3-1
9.5.4 Manure Processing 9.5,4-1
9.5.5 Poultry Slaughtering 9.5.5-1
9.6 Dairy Products 9.6-1
9.6.1 Natural And Processed Cheese 9.6.1-1
11/96 Contents vii
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9.7 Cotton Ginning 9.7-1
9.8 Preserved Fruits And Vegetables 9.8-1
9.8.1 Canned Fruits And Vegetables 9.8.1-1
9.8.2 Dehydrated Fruits And Vegetables 9.8.2-1
9.8.3 Pickles, Sauces And Salad Dressings 9.8.3-1
9.9 Grain Processing 9.9-1
9.9.1 Grain Elevators And Processes 9.9.1-1
9.9.2 Cereal Breakfast Food 9.9.2-1
9.9.3 PetFood 9.9.3-1
9.9.4 Alfalfa Dehydration 9.9.4-1
9.9.5 Pasta Manufacturing 9.9.5-1
9.9.6 Bread Baking 9.9.6-1
9.9.7 Corn Wet Milling 9.9.7-1
9.10 Confectionery Products 9,10-1
9.10.1 Sugar Processing 9.10.1-1
9.10.1.1 Cane Sugar Processing 9.10.1.1-1
9.10.1.2 Beet Sugar Processing 9,10.1,2-1
9.10.2 Salted And Roasted Nuts And Seeds 9.10.2-1
9.10.2.1 Almond Processing 9,10.2.1-1
9.10.2.2 Peanut Processing 9.10.2.2-1
9.11 Fats And Oils 9.11-1
9.11.1 Vegetable Oil Processing 9.11.1-1
9.12 Beverages 9.12-1
9.12.1 Malt Beverages 9.12.1-1
9.12.2 Wines And Brandy 9.12.2-1
9.12.3 Distilled Spirits 9.12.3-1
9.13 Miscellaneous Food And Kindred Products 9.13-1
9.13.1 Fish Processing 9.13.1-1
9.13.2 Coffee Roasting 9.13.2-1
9.13.3 Snack Chip Deep Fat Frying 9.13,3-1
9.13.4 Yeast Production 9,13.4-1
9.14 Tobacco Products 9.14-1
9.15 Leather Tanning 9.15-1
9.16 Agricultural Wind Erosion 9.16-1
10. Wood Products Industry 10.0-1
10.1 Lumber 10.1-1
10.2 Chemical Wood Pulping 10.2-1
10.3 Pulp Bleaching 10.3-1
10.4 Papermaking 10.4-1
10.5 Plywood 10.5-1
10.6 Reconstituted Wood Products 10.6-1
10.6.1 Waferboard And Oriented Strand Board 10.6.1-1
10.6.2 Particleboard 10.6.2-1
10.6.3 Medium Density Fiberboard 10.6.3-1
10.7 Charcoal 10.7-1
10.8 Wood Preserving 10.8-1
11. Mineral Products Industry 11.0-1
11.1 Hot Mix Asphalt Plants 11.1-1
11.2 Asphalt Roofing 11.2-1
viii
EMISSION FACTORS
11/96
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11.3 Bricks And Related Clay Products 11.3-1
11.4 Calcium Carbide Manufacturing 11.4-1
11.5 Refractory Manufacturing 11.5-1
11.6 Portland Cement Manufacturing 11.6-1
11.7 Ceramic Products Manufacturing 11.7-1
11.8 Clay And Fly Ash Sintering 11.8-1
11.9 Western Surface Coal Mining 11.9-1
11.10 Coal Cleaning 11.10-1
11.11 Coal Conversion 11.11-1
11.12 Concrete Batching 11.12-1
11.13 Glass Fiber Manufacturing 11.13-1
11.14 Frit Manufacturing 11,14-1
11.15 Glass Manufacturing 11.15-1
11.16 Gypsum Manufacturing 11.16-1
11.17 Lime Manufacturing 11.17-1
11.18 Mineral Wool Manufacturing 11.18-1
11.19 Construction Aggregate Processing 11.19-1
11.19.1 Sand And Gravel Processing 11.19.1-1
11.19.2 Crushed Stone Processing 11.19.2-1
11.20 Lightweight Aggregate Manufacturing 11.20-1
11.21 Phosphate Rock Processing 11.21-1
11.22 Diatomite Processing 11.22-1
11.23 Taconite Ore Processing 11.23-1
11.24 Metallic Minerals Processing 11.24-1
11.25 Clay Processing 11.25-1
11.26 Talc Processing 11.26-1
11.27 Feldspar Processing 11.27-1
11.28 Vermiculite Processing 11.28-1
11.29 Alumina Manufacturing 11.29-1
11.30 Perlite Manufacturing 11.30-1
11.31 Abrasives Manufacturing 11.31-1
Metallurgical Industry 12.0-1
12.1 Primary Aluminum Production 12.1-1
12.2 Coke Production 12.2-1
12.3 Primary Copper Smelting 12.3-1
12.4 Ferroalloy Production 12.4-1
12.5 Iron And Steel Production 12.5-1
12.6 Primary Lead Smelting 12.6-1
12.7 Zinc Smelting 12.7-1
12.8 Secondary Aluminum Operations 12.8-1
12.9 Secondary Copper Smelting And Alloying 12.9-1
12.10 Gray Iron Foundries 12.10-1
12.11 Secondary Lead Processing 12.11-1
12.12 Secondary Magnesium Smelting 12.12-1
12.13 Steel Foundries 12.13-1
12.14 Secondary Zinc Processing 12.14-1
12.15 Storage Battery Production 12.15-1
12.16 Lead Oxide And Pigment Production 12.16-1
12.17 Miscellaneous Lead Products 12.17-1
Contents
ix
-------
12.18 Leadbearing Ore Crushing And Grinding 12,18-1
12.19 Electric Arc Welding 12.19-1
12.20 Electroplating 12.20-1
13. Miscellaneous Sources 13.0-1
13.1 Wildfires And Prescribed Burning 13.1-1
13.2 Fugitive Dust Sources 13.2-1
13.2.1 Paved Roads 13.2.1-1
13.2.2 Unpaved Roads 13.2.2-1
13.2.3 Heavy Construction Operations 13.2.3-1
13.2.4 Aggregate Handling And Storage Piles 13.2.4-1
13.2.5 Industrial Wind Erosion 13.2.5-1
13.3 Explosives Detonation 13.3-1
13.4 Wet Cooling Towers 13.4-1
13.5 Industrial Flares 13.5-1
13. Greenhouse Gas Biogenic Sources 14.0-1
14.1 Emissions From Soils — Greenhouse Gases 14.1-1
14.2 Termites — Greenhouse Gases 14.2-1
14.3 Lightning Emissions — Greenhouse Gases 14.2-1
Appendix A
Miscellaneous Data And Conversion Factors A-l
Appendix B. 1
Particle Size Distribution Data And Sized Emission Factors For Selected Sources B. 1-1
Appendix B.2
Generalized Particle Size Distributions B.2-1
Appendix C. 1
Procedures For Sampling Surface/Bulk Dust Loading C. 1-1
Appendix C.2
Procedures For Laboratory Analysis Of Surface/Bulk Dust Loading Samples C.2-1
x EMISSION FACTORS 11/96
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KEY WORD INDEX
Chapter/Section
Abrasives Manufacturing 11.31
Acetone And Phenol 6.16
Acid
Adipic 6.2
Hydrochloric 8.6
Hydrofluoric 8.7
Nitric 8.8
Phosphoric 8.9
Sulfuric 8.10
Terephthalic 6.11
Adipic Acid 6.2
Aggregate Handling 13.2.4
Aggregate Manufacturing, Lightweight 11.20
Aggregate Processing, Construction 11.19
Aggregate Storage Piles 13.2.4
Agricultural Industries 9.0
Agricultural Wind Erosion 9.16
Alcohol. Isopropyl 6.29
Alfalfa Dehydration 9.9.4
Alkali, Chlor- 8.11
Almond Processing 9.10.2,1
Alumina Manufacturing 11.29
Aluminum
Operations, Secondary 12.8
Production, Primary 12.1
Ammonia. Synthetic 8.1
Ammonium Nitrate 8.3
Ammonium Phosphate 8.5.3
Ammonium Sulfate 8.4
Analysis, Surface/Bulk Dust Loading App. C.2
Anhydride, Phlhalic 6.5
Animal And Meat Products Preparation 9.5
Anthracite Coal Combustion 1.2
Appliance Surface Coating 4.2.2.11
Ash
Fly Ash Sintering 11.8
Asphalt
Hot Mix Plants 11.1
Paving 4.5
Roofing 11.2
Automobile Body Incineration 2.6
Automobile Surface Coating 4.2.2.8
11/96 Key Word Index xi
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Bagasse Combustion In Sugar Mills 1.8
Baking, Bread 9,9.6
Bark
Wood Waste Combustion In Boilers 1.6
Batching, Concrete 11.12
Battery Production, Storage 12.15
Beet Sugar Processing 9.10.1.2
Benzene, Toluene And Xylenes 6,18
Beverages 9.12
Brandy 9.12.2
Liquors, Distilled Spirits 9.12.3
Malt 9.12.1
Wines 9.12.2
Bituminous Coal Combustion 1.1
Bleaching, Wood Pulp 10.3
Brandy 9.12.2
Bread Baking 9.9.6
Bricks And Related Clay Products 11.3
Bulk Material Analysis Procedures App. C.2
Bulk Material Sampling Procedures App. C. 1
Burners, Conical (Teepee) 2.7
Burning, Open 2.5
Burning, Prescribed, And Wildfires 13.1
Business Machines, Plastic Parts Coating 4.2.2.14
Butadiene 6.19
Calcium Carbide Manufacturing 11.4
Can Coating 4.2.2.2
Cane Sugar Processing 9.10.1.1
Canned Fruits And Vegetables 9.8.1
Carbon Black 6.1
Carbonate
Sodium Carbonate Manufacturing 8.12
Cattle Feedlots 9.4.1
Cement
Portland Cement Manufacturing 11.6
Ceramic Products Manufacturing 11.7
Cereal Breakfast Food 9.9.2
Charcoal 10.7
Cheese, Natural And Processed 9.6.1
Chemical Wood Pulping 10.2
Chemicals, Inorganic 8.0
Chemicals, Organic 6.0
Chlor-Alkali 8.11
Clay
Bricks And Related Clay Products 11.3
Ceramic Products Manufacturing 11.7
Clay And Fly Ash Sintering 11.8
Clay Processing 11.25
xii EMISSION FACTORS 11/96
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Cleaning
Coal 11.10
Drum 4.8
Dry Cleaning 4.1
Tank 4.8
Coal
Anthracite Combustion 1.2
Bituminous Combustion 1.1
Cleaning 11.10
Conversion 11.11
Subbituminous Combustion 1.1
Surface Mining, Western 11.9
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
Labels, Pressure Sensitive 4.2.2.9
Magnet Wire 4.2.2.3
Magnetic Tape 4.2.2.13
Metal Coil 4.2.2.10
Metal Furniture 4.2.2.12
Metal, General 4.2.2.4
Paper 4.2.2.6
Plastic Parts For Business Machines 4.2.2.14
Polymeric Coating Of Supporting Substrates 4.2.2.7
Tapes, Pressure Sensitive 4.2.2,9
Coffee Roasting 9.13.2
Coke Manufacturing .12.2
Collection, Waste Water 4.3
Combustion
Anthracite Coal 1.2
Bagasse, In Sugar Mills 1,8
Bituminous Coal 1.1
Fuel Oil ..1.3
Internal, Mobile Vol. II
Internal, Stationary 3.0
Lignite 1.7
Liquefied Petroleum Gas 1.5
Natural Gas 1.4
Orchard Heaters 9.2.3
Refuse 2.1
Residential Fireplaces 1.9
Residential Wood Stoves 1.10
Subbituminous Coal 1.1
Waste Oil 1.11
Wood Waste In Boilers 1.6
Compressors, Pipeline, Natural Gas Fired 3.2
Concrete Batching 11.12
Confectionery Products 9.10
11/96 Key Word Index xiii
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Conical Burners 2.7
Construction Aggregate Processing 11.19
Construction Operations, Heavy 13.2.3
Conversion factors, units, etc. - Miscellaneous App. A
Cooling Towers, Wet 13.4
Copper
Alloying 12.9
Smelting, Primary 12.3
Smelting, Secondary 12.9
Cora Wet Milling 9.9.7
Cotton
Ginning 9.7
Harvesting 9.3,1
Crushed Stone Processing 11.19.2
Cumene 6.20
Cyanide, Hydrogen 8.14
Dairy Farms 9.4.4
Dairy Products 9.6
Deep Fat Frying, Snack Chip 9.13.3
Degreasing, Solvent 4.6
Dehydrated Fruits And Vegetables 9.8.2
Dehydration, Alfalfa 9.9.4
Detergents
Soap And Detergents 6.8
Detonation, Explosives 13.3
Diatomite Processing 11.22
Diesel Engines, Industrial 3.3
Diesel Engines, Stationary 3.4
Distilled Spirits 9.12.3
Drum Cleaning 4.8
Dry Cleaning 4.1
Dual Fuel Engines, Stationary 3.4
Dust Loading Analysis, Surface/Bulk App. C.2
Dust Loading Sampling Procedures, Surface/Bulk App. C. 1
Dust Sources, Fugitive 13.2
Electric Arc Welding 12.19
Electric Utility Power Plants, Gas 3.1
Electricity Generators, Stationary Gas Turbine 3.1
Electroplating 12.20
Erosion, Wind, Industrial 13.2.5
Ethanol 6.21
Ethyl Benzene 6.22
Ethylene 6.23
Ethylene Dichloride And Vinyl Chloride 6.24
Ethylene Glycol 6.25
Ethylene Oxide 6.26
Evaporation Loss Sources 4.0
Explosives 6.3
Explosives Detonation 13.3
xiv EMISSION FACTORS 11/96
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External Combustion Sources 1.0
Fabric Coating 4.2.2.7
Fabric Printing, Textile 4.11
Fats, Cooking 9.11
Feedlots
Cattle 9.4.1
Dairy Farms 9.4.4
Poultry Houses 9.4.3
Swine 9.4.2
Feldspar Processing 11.27
Ferroalloy Production 12.4
Fertilizer Application 9.2.1
Fertilizers
Ammonium Phosphate 8.5.3
Phosphate 8.5
Fiberboard, Medium Density 10.6.3
Fiber Manufacturing, Glass 11.13
Fibers, Synthetic 6.9
Fireplaces, Residential 1.9
Fires
Forest Wildfires And Prescribed Burning . 13.1
Fish Processing 9.13.1
Flares, Industrial 13.5
Flat Wood Interior Panel Coating 4.2,2.5
Fly Ash
Clay And Fly Ash Sintering 11.8
Food And Agricultural Industries 9.0
Food And Kindred Products, Miscellaneous 9.13
Coffee Roasting 9.13.2
Fish Processing 9.13.1
Snack Chip Deep Fat Frying 9.13.3
Yeast Production 9.13.4
Formaldehyde 6.27
Foundries
Gray Iron .. 12.10
Steel 12.13
Frit Manufacturing 11.14
Fruits, Preserved 9.8
Canned 9.8.1
Dehydrated 9.8.2
Fuel Oil Combustion 1.3
Fugitive Dust Sources 13.2
Furniture Surface Coating, Metal 4.2.2.12
Gas Combustion, Liquefied Petroleum 1.5
Gas, Natural
Combustion 1.4
Pipeline Compressors 3.2
Processing 5.3
Turbines, Electricity-generating 3.1
11/96 Key Word Index xv
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Gasoline/Diesel Industrial Engines 3.3
Ginning, Cotton 9.7
Glass Fiber Manufacturing 11,13
Glass Manufacturing 11,15
Graphic Arts 4.9
General Graphic Printing 4.9.1
Publication Gravure Printing 4.9.2
Glycerine 6.28
Grain
Alfalfa Dehydration 9.9.4
Bread Baking 9.9.6
Cereal Breakfast Food 9.9.2
Corn Wet Milling 9,9,7
Elevators And Processes 9,9,1
Harvesting 9.3.2
Pasta Manufacturing 9.9.5
Pet Food 9.9.3
Processing 9.9
Gravel Processing 11.19.1
Gray Iron Foundries 12.10
Greenhouse Gas biogenic Sources 14.0
Growing Operations 9.2
Gypsum Manufacturing 11.16
Harvesting Operations 9.3
Cotton Harvesting 9.3.1
Grain Harvesting 9.3.2
Rice Harvesting 9.3.3
Sugar Cane Harvesting 9.3.4
Heaters, Orchard 9.2.3
Highway Vehicles Vol. II
Hot Mix Asphalt Plants 11.1
Hydrochloric Acid 8.6
Hydrofluoric Acid 8.7
Hydrogen Cyanide 8,14
Incineration
Automobile Body 2.6
Medical Waste 2.3
Open Burning 2.5
Sewage Sludge 2.2
Industrial Engines, Gasoline And Diesel 3.3
Industrial Flares 13.5
Industrial Surface Coating 4.2.2
Industrial Surface Coating, General 4.2.2.1
Industrial Wind Erosion 13.2.5
Ink, Printing 6,7
Inorganic Chemical Industry 8,0
Interior Panel Coating, Flat Wood 4.2.2.5
xvi
EMISSION FACTORS
11/96
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Internal Combustion Engines
Highway Vehicle Vol. II
Off-highway Mobile Vol. II
Off-highwav Stationary 3.0
Iron
Gray Iron Foundries 12.10
Iron Production 12.5
Isopropyl Alcohol 6.29
Labels, Pressure Sensitive 4.2.2.9
Landfills 2.4
Large Bore Engines 3.4
Lead
Ore Crushing And Grinding 12.18
Processing, Secondary 12.11
Products, Miscellaneous 12.17
Smelting, Primary 12.6
Lead Alkyl 6.12
Lead Oxide Production 12.16
Lead Pigment Production 12.16
Leadbcaring Ore Crushing And Grinding 12.18
Leather Tanning 9.15
Light Duty Truck Surface Coating 4.2.2.8
Lightning 14.1
Lightweight Aggregate Manufacturing 11.20
Lignite Combustion 1.7
Lime Manufacturing 11.17
Liquefied Petroleum Gas Combustion 1.5
Liquid Storage Tanks 7.0
Livestock Feed Operations 9.4
Lumber 10.1
Magnesium, Secondary Smelting 12,12
Magnet Wire Coaling 4.2.2.3
Magnetic Tape Manufacturing 4.2.2.13
Maleic Anhydride 6.14
Malt Beverages 9.12.1
Manure Processing 9.5.4
Marketing, Petroleum Liquids 5.2
Meat Packing Plants 9.5.1
Meat Products Preparation 9.5
Meat Rendering Plants 9.5.3
Meat Smokehouses 9.5.2
Medical Waste Incineration 2.3
Metal Coating, General 4.2.2.4
Metal Coil Surface Coating 4.2.2,10
Metal Furniture Surface Coating 4.2,2.12
Metallic Minerals Processing 11.24
Metallurgical Industry 12.0
Methanol 6.15
11/96 Key Word Index xvii
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Mineral Products Industry 11.0
Mineral Wool Manufacturing 11.18
Minerals Processing, Metallic 11.24
Mining, Western Surface Coal 11.9
Miscellaneous Sources 13.0
Mobile Sources
Highway Vol. II
Off-highway Vol. II
Natural And Processed Cheese 9.6.1
Natural Gas Combustion 1.4
Natural Gas Fired Pipeline Compressors 3.2
Natural Gas Processing 5.3
Nitric Acid Manufacturing 8.8
Nonindustrial Surface Coating 4.2.1
Normal Superphosphates 8.5.1
Nuts And Seeds, Salted And Roasted 9.10.2
Almond Processing 9.10.2.1
Peanut Processing 9.10.2.2
Off-highway Mobile Sources Vol. II
Off-highway Stationary Sources 3.0
Oil
Fuel Oil Combustion 1.3
Waste Oil Combustion 1.11
Oils, Cooking 9.11
Vegetable Oil Processing 9.11.1
Open Burning 2.5
Orchard Heaters 9.2.3
Ore Processing
Leadbearing Ore Crushing And Grinding 12.18
Taconite 11.23
Organic Chemical Process Industry 6.0
Organic Liquid Storage Tanks 7.1
Oriented Strand Board 10.6.1
Paint And Varnish 6.4
Panel Coating, Flat Wood Interior 4.2.2.5
Paper Coating 4.2.2.6
Papermaking 10.4
Particleboard 10.6.2
Particle size distribution data, factors, generalized App. B.2
Particle size distribution data, factors, selected App. B. 1
Pasta Manufacturing 9.9.5
Paved Roads 13 .2.1
Paving, Asphalt 4.5
Peanut Processing 9.10.2.2
Perlite Manufacturing 11.30
Pesticide Application 9.2.2
Pet Food 9.9.3
xviii EMISSION FACTORS 11/96
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Petroleum
Liquefied Petroleum Gas Combustion 1.5
Liquids, Transportation And Marketing 5.2
Refining 5.1
Storage Of Organic Liquids 7.1
Petroleum Industry 5.0
Pharmaceuticals Production 6.13
Phenol 6.16
Phosphate, Ammonium 8.5.3
Phosphate Fertilizers 8.5
Phosphate Rock Processing 11.21
Phosphoric Acid 8.9
Phthalic Anhydride 6.5
Pickles 9.8.3
Pigment
Lead Oxide And Pigment Production 12.16
Pipeline Compressors, Natural Gas Fired 3.2
Plastic Part Surface Coating, Business Machine 4.2.2.14
Plastics 6.6
Plywood 10.5
Polyester Resin Plastic Products Fabrication 4.4
Poly(ethylene terephthalatc) 6.6.2
Polymeric Coating Of Supporting Substrates 4.2.2.7
Polypropylene 6.6.4
Polystyrene 6.6.3
Polyvinyl Chloride 6.6.1
Portland Cement Manufacturing 11.6
Poultry Feed Operations 9.4
Poultry Houses 9.4.3
Poultry Slaughtering 9.5.5
Prescribed Burning, Wildfires And 13.1
Preserved Fruits And Vegetables 9.8
Preserving, Wood 10.8
Printing, General Graphic 4.9.1
Printing, Publication Gravure 4.9.2
Printing, Textile Fabric 4.11
Printing Ink 6.7
Processed Cheese 9.6.1
Propylene 6.17
Pulp Bleaching, Wood 10.3
Pulping, Chemical Wood 10.2
Reclamation, Waste Solvent 4.7
Reconstituted Wood Products 10.6
Recovery, Sulfur 8.13
Refining, Petroleum 5.1
Refractory Manufacturing 11.5
Refuse Combustion 2.1
Rendering Plants, Meat 9.5.3
Residential Fireplaces 1.9
Resin, Polyester, Plastic Product Fabrication 4.4
11/96 Key Word Index xix
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Rice Harvesting 9.3.3
Roads
Paved 13.2.1
Unpaved 13.2.2
Roasted Nuts And Seeds 9.10.2
Roasting, Coffee 9.13.2
Rock Processing, Phosphate 11.21
Roofing, Asphalt 11.2
Rubber, Synthetic 6.10
Salad Dressings 9.8.3
Salted And Roasted Nuts And Seeds 9.10.2
Almond Processing 9.10.2.1
Peanut Processing 9.10.2.2
Sampling, Surface/Bulk Loading App. C. 1
Sand And Gravel Processing 11.19.1
Sauces 9.8,3
Seeds, Salted And Roasted 9.10.2
Sewage Sludge Incineration 2.2
Sized emission factors, generalized App. B.2
Sized emission factors, selected App. B. 1
Smelting
Primary Copper 12.3
Primary Lead 12.6
Secondary Copper Smelting And Alloying 12.9
Secondary Magnesium 12.12
Zinc 12.7
Smokehouses, Meat 9.5.2
Snack Chip Deep Fat Frying 9.13.3
Soap And Detergent Manufacturing 6.8
Sodium Carbonate Manufacturing 8.12
Soils 14.1
Solid Waste Disposal 2.0
Solvent
Commercial/Consumer Use 4.10
Degreasing 4.6
Waste, Reclamation 4.7
Stationary Gas Turbines 3.1
Stationary Internal Combustion Sources, Off-highway 3.0
Steel
Foundries 12.13
Production 12.5
Stone Processing, Crushed 11.19.2
Storage, Waste Water 4.3
Storage Battery Production 12.15
Storage Piles, Aggregate 13.2.4
Storage Tanks, Liquid 7.0
Organic Liquid Storage Tanks 7.1
Subbituminous Coal Combustion 1.1
Substrates, Supporting, Polymeric Coating Of 4.2.2.7
Sugar Harvesting, Cane 9.3.4
xx
EMISSION FACTORS
11/96
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Sugar Mills, Bagasse Combustion In 1.8
Sugar Processing 9.10.1
Sugar Processing, Beet 9.10.1.2
Sugar Processing, Cane 9.10.1.1
Sulfur Recovery 8.13
Sulfuric Acid 8.10
Surface/Bulk Dust Loading Analysis App. C.2
Surface/Bulk Dust Loading Sampling Procedures App. C. 1
Surface Coal Mining, Western 11.9
Surface Coating 4.2
Surface Coating, Industrial 4.2.2
Surface Coating, Nonindustrial 4.2.1
Surface Material Analysis Procedures App. C.2
Surface Material Sampling Procedures App. C. 1
Swine Feedlots 9.4.2
Synthetic Ammonia 8.1
Synthetic Fibers 6.9
Synthetic Rubber 6.10
Taconite Ore Processing 11.23
Talc Processing 11.26
Tank And Drum Cleaning 4.8
Tape, Magnetic, Manufacturing 4.2.2.13
Tapes And Labels, Pressure Sensitive 4.2.2.9
Teepee (Conical) Burners 2.7
Terephthalic Acid 6.11
Termites 14.2
Textile Fabric Printing 4.11
Tilling Operations 9.1
Tobacco Products 9.14
Toluene 6.18
Transportation And Marketing Of Petroleum Liquids 5 .2
Treatment, Waste Water 4.3
Triple Superphosphates 8.5.2
Truck, Light Duty, Surface Coating, 4.2.2.8
Turbines, Natural Gas Fired 3.1
Unpaved Roads 13.2.2
Urea 8.2
Varnish
Paint And Varnish Manufacturing 6.4
Vegetable Oil Processing 9.11.1
Vegetables, Canned 9.8.1
Vegetables, Dehydrated 9.8.2
Vegetables, Preserved 9.8
Vehicles, Highway And Off-highway Vol. II
Vermiculite Processing 11.28
Vinyl Chloride 6.24
11/96 Key Word Index xxi
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Waferboard 10.6.1
Waste Disposal, Solid 2.0
Waste Oil Combustion 1.11
Waste Solvent Reclamation 4.7
Waste Water Collection, Treatment and Storage 4.3
Welding, Electric Arc 12.19
Wet Cooling Towers 13.4
Wet Milling, Corn 9.9.7
Wildfires 13.1
Wind Erosion
Agricultural 9.16
Industrial 13.2.5
Wines 9.12.2
Wire Coating, Magnet 4.2.2.3
Wood
Charcoal 10.7
Flat Interior Panel Coating 4.2.2.5
Lumber 10.1
Medium Density Fiberboard 10.6.3
Oriented Strand Board 10.6.1
Papermaking 10.4
Particleboard 10.6.2
Plywood 10.5
Pulp Bleaching ,10,3
Pulping, Chemical 10.2
Reconstituted Wood Products .10.6
Stoves 1.10
Waferboard 10.6.1
Waste Combustion In Boilers ,1.6
Wood Preserving 10.8
Wood Products Industry 10,0
Xylenes 6.18
Yeast Production 9.13.4
Zinc
Processing, Secondary 12.14
Smelting 12.7
xxii EMISSION FACTORS 11/96
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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 mineral matter formed over
eons from successive layers of fallen vegetation. Coals are classified by rank according to their
progressive alteration in the natural metamorphosis from lignite to anthracite. Coal rank depends on
the volatile matter, fixed carbon, inherent moisture, and oxygen, although no single parameter defines
a rank. Typically, coal rank increases as the amount of fixed carbon increases and the amount of
volatile matter and moisture decreases.
Bituminous coals are by far the largest group and are characterized as having lower fixed
carbon and higher volatile matter than anthracite. The key distinguishing characteristics of bituminous
coal are its relative volatile matter and sulfur content as well as its slagging and agglomerating
characteristics. Subbituminous coals have higher moisture and volatile matter and lower sulfur content
than bituminous coals and may be used as an alternative fuel in some boilers originally designed to
burn bituminous coals.1 Generally, bituminous coals have heating values of 10,500 to 14,000 British
thermal units per pound (Btu/lb) on a wet, mineral-matter-frec basis 2 As mined, the heating values of
typical U.S. bituminous coals range from 10,720 to 14,730 Btu/lb.3 The heating values of
subbituminous coals range from 8,300 to 11,500 Btu/lb on a wet, mineral-matter-free basis2, and from
9.420 to 10,130 Btu/lb on an as-mined basis.3 Formulae and tables for classifying coals are given in
Reference 2.
1.1.2 Firing Practices4
Coal-fired boilers can be classified by type, fuel, and method of construction. Boiler types are
identified by the heat transfer method (watertube, firetube, or cast iron), the arrangement of the heat
transfer surfaces (horizontal or vertical, straight or bent tube), and the firing configuration (suspension,
stoker, or fluidized bed). The most common heat transfer method for coal-fired boilers is the
watertube method in which the hot combustion gases contact the outside of the heat transfer tubes,
while the boiler water and steam are contained within the tubes.
Coal-fired watertube boilers include pulverized coal, cyclone, stoker, fluidized bed, and
handfed units. In stoker-fired systems and most handfed units, the fuel is primarily burned on the
bottom of the furnace or on a grate. In a fluidized bed combustor (FBC), the coal is introduced to a
bed of either sorbent or inert material (usually sand) which is fluidized by an upward flow of air. In
pulverized coal-fired (PC-fired) boilers, the fuel is pulverized to the consistency of talcum powder
(i.e., at least 70 percent of the particles will pass through a 200-mesh sieve) and pneumatically injected
through the burners into the furnace. Combustion in PC-fired units takes place almost entirely while
the coal is suspended in the furnace volume. PC-fired boilers are classified as either dry bottom or
wet bottom (also referred to as slag tap furnaces), depending on whether the ash is removed in a solid
or molten state. In diy bottom furnaces, coals with high fusion temperatures are burned, resulting in
dry ash. In wet bottom furnaces, coals with low fusion temperatures arc used, resulting in molten ash
or slag.
Depending upon the type and location of the burners and the direction of coal injection into
the furnace. PC-fired boilers can also be classified into two different firing types, including wall, and
tangential. 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.
10/96
External Combustion Sources
1.1-1
-------
Tangential (or comer-fired) boilers have burners mounted in the comers of the furnace. The fuel and
air are injected tangent to an imaginary circle in the plane of the boilers. Cyclone furnaces are often
categorized as PC-fired systems even though the coal is crushed to a maximum size of about 4-mesh.
The coal is fed tangentially, with primary air, into a horizonal cylindrical furnace. Smaller coal
particles are burned in suspension while larger particles adhere to the molten layer of slag on the
combustion chamber wall. Cyclone boilers are high-temperature, wet-bottom type systems.
Stoker-fired systems account for the vast majority of coal-fired watertube boilers for industrial,
commercial, and institutional applications. Most packaged stoker units designed for coal firing are
small and can be divided into three groups: underfeed stokers, overfeed stokers, and spreader stokers.
Underfeed stokers are generally either the horizontal-feed, side-ash-discharge type or the gravity-feed,
rear-ash-discharge type. An overfeed stoker uses a moving grate assembly in which coal is fed from a
hopper onto a continuous grate which conveys the fuel into the furnace. In a spreader stoker,
mechanical or pneumatic feeders distribute coal uniformly over the surface of a moving grate. The
injection of the fuel into the furnace and onto the grate combines suspension burning with a thin,
fast-burning fuel bed. The amount of fuel burned in suspension depends primarily on fuel size and
composition, and air flow velocity. Generally, fuels with finer size distributions, higher volatile matter
contents, and lower moisture contents result in a greater percentage of combustion and corresponding
heat release rates in suspension above the bed.
FBCs, while not constituting a significant percentage of the total boiler population, have
nonetheless gained popularity in the last decade, and today generate steam for industries, cogenerators,
independent power producers, and utilities. There are two major categories of FBC systems: (1)
atmospheric, operating at or near ambient pressures, and (2) pressurized, operating from 4 to 30
atmospheres (60 to 450 pounds per square inch gauge). At this time, atmospheric FBCs are more
advanced (or commercialized) than pressurized FBCs. The two principal types of atmospheric FBCs
are bubbling bed and circulating bed. The feature that varies most fundamentally between these two
types is the fluidization velocity. In the bubbling bed design, the fluidation velocity is relatively low
in order to minimize solids carryover or elutriation from the combustor. Circulating FBCs, however,
employ high fluidization velocities to promote the carryover or circulation of the 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 residence time compared to the bubbling bed
design. Because of this feature, circulating FBCs often achieve higher combustion efficiencies and
better sorbent utilization than bubbling bed units.
Small, coal-fired boilers and furnaces are found in industrial, commercial, institutional, or
residential applications and are sometimes capable of being hand-fired. The most common types of
firetube boilers used with coal are the horizontal return tubular (HRT), Scotch, vertical, and the
firebox. Cast iron boilers are also sometimes available as coal-fired units in a handfed configuration.
The HRT boilers are generally fired with gas or oil instead of coal. The boiler and furnace are
contained in the same shell in a Scotch or shell boiler. Vertical firetube boilers are typically small
singlepass units ir. which the firetubes come straight up from the water-cooled combustion chamber
located at the bottom cf the unit. A firebox boiler is constructed with an internal steel-encased,
water-jacketed firebox. Firebox firetube boilers are also referred to as locomotive, short firebox, and
compact firebox boilers and employ mechanical stokers or are hand-fired.
1.1-2
EMISSION FACTORS
10/96
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1.1.3 Emissions4
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. The major pollutants of concern from bituminous and subbituminous coal combustion
are particulate matter (PM), sulfur oxides (SOx), and nitrogen oxides (NOx). Some unbumed
combustibles, including carbon monoxide (CO) and numerous organic compounds, are generally
emitted even under proper boiler operating conditions.
1.1.3.1 Particulate Matter4 -
PM composition and emission levels are a complex function of boiler firing configuration,
boiler operation, pollution control equipment, and coal properties. Uncontrolled PM emissions from
coal-fired boilers include the ash from combustion of the fuel as well as unbumed carbon resulting
from incomplete combustion. In pulverized coal systems, combustion is almost complete; thus, the
emitted PM is primarily composed of inorganic ash residues.
Coal ash may either settle out in the boiler (bottom ash) or entrained in the flue gas (fly ash).
The distribution of ash between the bottom ash and fly ash fractions directly affects the PM emission
rate and depends on the boiler firing method and furnace type (wet or dry bottom). Boiler load also
affects the PM emissions as decreasing load tends to reduce PM emissions. However, the magnitude
of the reduction varies considerably depending on boiler type, fuel, and boiler operation,
Soot blowing is also a source of intermittent PM emissions in coal-fired boilers. Steam soot
and air soot blowing is periodically used to dislodge ash from heat transfer surfaces in the furnace,
convective section, economizer, and air preheater.
Particulate emissions may be categorized as either filterable or condensable. Filterable
emissions are generally considered to be the particles that are trapped by the glass fiber filter in the
front half of a Reference Method 5 or Method 17 sampling train. Vapors and particles less than
0.3 microns pass through the filter. Condensable particulate matter is material that is emitted in the
vapor state which later condenses to form homogeneous and/or heterogeneous aerosol particles. The
condensable particulate emitted from boilers fueled on coal or oil is primarily inorganic in nature.
1.1.3.2 Sulfur Oxides4 -
Gaseous SOx from coal combustion are primarily sulfur dioxide (S02), with a much lower
quantity of sulfur trioxide (S03) and gaseous sulfates. These compounds form as the organic and
pyntic sulfur in the coal are 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.
1.1.3.3 Nitrogen Oxides5"6 -
NOx emissions from coal combustion are primarily nitric oxide (NO), with only a few volume
percent as nitrogen dioxide (N02). Nitrous oxide (N20) is also emitted at a few parts per million.
N0X 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 N0X formation
have shown that the N0X concentration is exponentially dependent on temperature and is proportional
to nitrogen concentration in the flame, the square root of oxygen concentration in the flame, and the
gas residence time 7 Cyclone boilers typically have high conversion of nitrogen to N0X Typically,
only 20 to 60 percent of the fuel nitrogen is converted to N0X Bituminous and subbituminous coals
10/96
External Combustion Sources
1.1-3
-------
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.
1.1.3.4 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 is 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 typically 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. Combustion modification techniques and equipment used to
reduce NOx can increase CO emissions if the modification techniques are improperly implemented or
if the equipment is improperly designed.
1.1.3.5 Organic Compounds -
As with CO emissions, the rate at which organic compounds are emitted depends on the
combustion efficiency of the boiler. Therefore, combustion modifications that change combustion
residence time, temperature, or turbulence may increase or decrease concentrations of organic
compounds in the flue gas.
Organic emissions include volatile, semivolatile, and condensable organic compounds either
present in the coal or formed as a product of incomplete combustion (PIC). Organic emissions are
primarily characterized by the criteria pollutant class of unbumed vapor-phase hydrocarbons. These
emissions include alkanes, alkenes, aldehydes, alcohols, and substituted benzenes (e.g., benzene,
toluene, xylene, and ethyl benzene). 8'9
Emissions of polychlorinated dibenzo-p-dioxins and polychlorinated dibenzofurans
(PCDD/PCDF) also result from the combustion of coal. Of primary interest environmentally are
tetrachloro- through octachloro- dioxins and furans. Dioxin and fiiran emissions are influenced by the
extent of destruction of organics during combustion and through reactions in the air pollution control
equipment. The formation of PCDD/PCDF in air pollution control equipment is primarily dependent
on flue gas temperature, with maximum potential for formation occurring at flue gas temperatures of
450 degrees to 650 degrees Fahrenheit.
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). Polycyclic organic matter is more prevalent in the emissions
from coal combustion because of the more complex structure of coal.
1.1.3.6 Trace Metals-
Trace metals are also emitted during coal combustion. The quantity of any given metal
emitted, in general, depends on:
the physical and chemical properties of the metal itself;
the concentration of the metal in the coal;
the combustion conditions; and
1.1-4
EMISSION FACTORS
10/96
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the type of particulate control device used, and its collection efficiency as a function of
particle size.
Some trace metals become concentrated in certain particle streams from a combustor (e.g.,
bottom ash, collector ash, and flue gas particulate) while others do not.10 Various classification
schemes have been developed to describe this partitioning behavior.10"12 These classification schemes
generally distinguish between:
Class 1: Elements that are approximately equally concentrated in the fly ash and
bottom ash, or show little or no small particle enrichment. Examples include
manganese, beryllium, cobalt, and chromium.
Class 2: Elements that are enriched in fly ash relative to bottom ash, or show-
increasing enrichment with decreasing particle size. Examples include arsenic,
cadmium, lead, and antimony.
Class 3: Elements which are emitted in the gas phase (primarily mercury and, in some
cases, selenium).
Control of Class 1 metals is directly related to control of total particulate matter emissions, while
control of Class 2 metals depends on collection of fine particulate. Because of variability in
particulate control device efficiencies, emission rates of these metals can vary substantially. Because
of the volatility of Class 3 metals, particulate controls have only a limited impact on emissions of
these metals.
1.1.3.7 Acid Gases-
In addition to S02 and NOx emissions, combustion of coal also results in emissions of
chlorine and fluorine, primarily in the form of hydrogen chloride (HC1) and hydrogen fluoride (HF).
Lesser amounts of chlorine gas and fluorine gas are also emitted. A portion of the chlorine and
fluorine in the fuel may be absorbed onto fly ash or bottom ash. Both HC1 and HF are water soluble
and are readily controlled by acid gas scrubbing systems.
1.1.3.8 Fugitive Emissions -
Fugitive emissions are defined as pollutants which escape from an industrial process due to
leakage, materials handling, inadequate operational control, transfer, or storage. The fly ash handling
operations in most modern utility' and industrial combustion sources consist of pneumatic systems or
enclosed and hooded systems which are vented through small fabric filters or other dust control
devices. The fugitive PM emissions from these systems are therefore minimal. Fugitive particulate
emissions can sometimes occur during fly ash transfer operations from silos to tracks or rail cars.
1.1.3.9 Greenhouse Gases13"18 -
Carbon dioxide (C02), methane (CH4), and nitrous oxide (N20) emissions are all produced
during coal combustion. Nearly all of the fuel carbon (99 percent) in coal is converted to C02 during
the combustion process. This conversion is relatively independent of firing configuration. Although
the formation of CO acts to reduce C02 emissions, the amount of CO produced is insignificant
compared to the amount of C02 produced. The majority of the fuel carbon not converted to C02 is
entrained in bottom ash. C02 emissions for coal vary with carbon content, and carbon content varies
between the classes of bituminous and subbituminous coals. Further, carbon content also varies within
each class of coal based on the geographical location of the mine.
10/96
External Combustion Sources
1.1-5
-------
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Formation of N20 is minimized when combustion
temperatures are kept high (above 1575°F) and excess air is kept to a minimum (less than 1 percent).
N2Q emissions for coal combustion are not significant except for fluidized bed combustion (FBC),
where the emissions are typically two orders of magnitude higher than all other types of coal firing
due to areas of low temperature combustion in the fuel bed.
Methane emissions vary with the type of coal being fired and firing configuration, but are
highest during periods of incomplete combustion, such as the start-up or shut-down cycle for coal-fired
boilers. Typically, conditions that favor formation of N20 also favor emissions of CH4
1.1.4 Controls4
Control techniques for criteria pollutants from coal combustion may be classified into three
broad categories: fuel treatment/substitution, combustion modification, and postcombustion control.
Emissions of noncriteria pollutants such as particulate phase metals have been controlled through the
use of post combustion controls designed for criteria pollutants. Fuel treatment primarily reduces S02
and includes coal cleaning using physical, chemical, or biological processes; fuel substitution involves
burning a cleaner fuel. Combustion modification includes any physical or operational change in the
furnace or boiler and is applied primarily for NOx control purposes, although for small units, some
reduction in PM emissions may be available through improved combustion practice. Postcombustion
control employs a device after the combustion of the fuel and is applied to control emissions of PM,
S02 , and NOx for coal combustion.
1.1.4.1 Particulate Matter Control4 -
The principal control techniques for PM are combustion modifications (applicable to small
stoker-fired boilers) and postcombustion methods (applicable to most boiler types and sizes).
Uncontrolled PM emissions from small stoker-fired and hand-feed combustion sources can be
minimized by employing good combustion practices such as operating within the recommended load
ranges, controlling the rate of load changes, and ensuring steady, uniform fuel feed. Proper design and
operation of the combustion air delivery systems can also minimize PM emissions. The
postcombustion control of PM emissions from coal-fired combustion sources can be accomplished by
using one or more or the following particulate control devices:
• Electrostatic precipitator (ESP),
• Fabric filter (or baghouse),
• Wet scrubber,
• Cyclone or multiclone collector, or
• Side stream separator.
Electrostatic precipitation technology is applicable to a variety of coal combustion sources.
Because of their modular design, ESPs can be applied to a wide range of system sizes and should have
no adverse effect on combustion system performance. The operating parameters that influence ESP
performance include fly ash mass loading, particle size distribution, fly ash electrical resistivity, and
precipitator voltage and current. Other factors that determine ESP collection efficiency are collection
plate area, gas flow velocity, and cleaning cycle. Data for ESPs applied to coal-fired sources show
fractional collection efficiencies greater than 99 percent for fine (less than 0.1 micrometer) and coarse
particles (greater than 10 micrometers). These data show a reduction in collection efficiency for
particle diameters between 0.1 and 10 micrometers.
1.1-6
EMISSION FACTORS
10/96
-------
Fabric filtration has been widely applied to coal combustion sources since the early 1970s and
consists of a number of filtering elements (bags) along with a bag cleaning system contained in a main
shell structure incorporating dust hoppers. The particulate removal efficiency of fabric filters is
dependent on a variety of particle and operational characteristics. Particle characteristics that affect the
collection efficiency include particle size distribution, particle cohesion characteristics, and particle
electrical resistivity. Operational parameters that affect fabric filter collection efficiency include
air-to-cloth ratio, operating pressure loss, cleaning sequence, interval between cleanings, cleaning
method, and cleaning intensity. In addition, the particle collection efficiency and size distribution can
be affected by certain fabric properties (e. g ., structure of fabric, fiber composition, and bag
properties). Collection efficiencies of fabric filters can be as high as 99.9 percent.
Wet scrubbers, including venturi and flooded disc scrubbers, tray or tower units, turbulent
contact absorbers, or high-pressure spray impingement scrubbers are applicable for PM as well as S02
control on coal-fired combustion sources. Scrubber collection efficiency depends on particle size
distribution, gas side pressure drop through the scrubber, and water (or scrubbing liquor) pressure, and
can range between 95 and 99 percent for a 2-mieron particle.
Cyclone separators can be installed singly, in series, or grouped as in a multicyclone or
multiclone collector. These devices are referred to as mechanical collectors and are often used as a
precollector upstream of an ESP, fabric filter, or wet scrubber so that these devices can be specified
for lower particle loadings to reduce capital and/or operating costs. The collection efficiency of a
mechanical collector depends strongly on the effective aerodynamic particle diameter. Although these
devices will reduce PM emissions from coal combustion, they are relatively ineffective for collection
of particles less than 10 micron (PM-10), The typical overall collection efficiency for mechanical
collectors ranges from 90 to 95 percent.
The side-stream separator combines a multicyclone and a small pulse-jet baghouse to more
efficiently collect small-diameter particles that are difficult to capture by a mechanical collector alone.
Most applications to date for side-stream separators have been on small stoker boilers.
Atmospheric fluidized bed combustion (AFBC) boilers may tax conventional particulate
control systems. The particulate mass concentration exiting AFBC boilers is typically 2 to 4 times
higher than pulverized coal boilers. AFBC particles are also, on average, smaller in size, and
irregularly shaped with higher surface area and porosity relative to pulverized coal ashes. The effect is
a higher pressure drop. The AFBC ash is more difficult to collect in ESPs than pulverized coal ash
because AFBC ash has a higher electrical resistivity and the use of multiclones for recycling, inherent
with the AFBC process, tends to reduce exit gas stream particulate size.
1.1.4.2 Sulfur Oxides Control4 -
Several techniques are used to reduce SOx emissions from coal combustion. Table 1.1-1
presents the techniques most frequently used. 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.
Post combustion flue gas desulfunzation (FGD) techniques can remove S02 formed during
combustion by using an alkaline reagent to absorb S02 in the flue gas. Flue gases can be treated
using wet. dry. or semi-dry desulfurization processes of either the throwaway type (in which all waste
10/96
External Combustion Sources
1.1-7
-------
streams are discarded) or the recovery/regenerable type (in which the S02 absorbent is regenerated and
reused). To date, wet systems are the most commonly applied. Wet systems generally use alkali
slurries as the S02 absorbent medium and can be designed to remove greater than 90 percent of the
incoming S02 Lime/limestone scrubbers, sodium scrubbers, and dual alkali scrubbers are among the
commercially proven wet FGD systems. The effectiveness of these devices depends not only on
control device design but also on operating variables. Particulate reduction of more than 99 percent is
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 reactions.18
Also, the volume of scrubber sludge is reduced with separate fly ash removal, and contamination of
the reagents and by-products is prevented.
The lime and limestone wet scrubbing process uses a slurry of calcium oxide or limestone to
absorb S02 in a wet scrubber. Control efficiencies in excess of 91 percent for lime and 94 percent for
limestone over extended periods are possible. Sodium scrubbing processes generally employ a wet
scrubbing solution of sodium hydroxide or sodium carbonate to absorb S02 from the flue gas.
Sodium scrubbers are generally limited to smaller sources because of high reagent costs and can have
S02 removal efficiencies of up to 96.2 percent. The double or dual alkali system uses a clear sodium
alkali solution for S02 removal followed by a regeneration step using lime or limestone to recover the
sodium alkali and produce a calcium sulfite and sulfate sludge. S02 removal efficiencies of 90 to 96
percent are possible.
1.1.4.3 Nitrogen Oxide Controls4 -
Several techniques are used to reduce NOx emissions from coal combustion. These techniques
are summarized in Table 1.1-2. The primary techniques can be classified into one of two
fundamentally different methods—combustion controls and postcombustion controls. Combustion
controls reduce NOx by suppressing NOx formation during the combustion process, while
postcombustion controls reduce NOx emission after their formation. Combustion controls are the most
widely used method of controlling NOx formation in all types of boilers and include low excess air
(LEA), burners out of service (BOOS), biased burner firing, overfire air (OFA), low NOx burners
(LNBs), and reburn. Postcombustion control methods are selective noncatalytic reduction (SNCR) and
selective catalytic reduction (SCR) Combustion and postcombustion controls can be used separately
or combined to achieve greater NOx reduction from fluidized bed combustors in boilers.
Operating at LEA involves reducing the amount of combustion air to the lowest possible level
while maintaining efficient and environmentally compliant boiler operation. NOx formation is
inhibited because less oxygen is available in the combustion zone. BOOS involves withholding fuel
flow to all or part of the top row of burners so that only air is allowed to pass through. This method
simulates air staging, or OFA conditions, and limits NOx formation by lowering the oxygen level in
the burner area. Biased burner firing involves more fuel-rich firing in the lower rows of burners than
in the upper row of burners. This method provides a form of air staging and limits NOx formation by
limiting the amount of oxygen in the firing zone. These methods may change the normal operation of
the boiler and the effectiveness is boiler-specific. Implementation of these techniques may also reduce
operational flexibility; however, they may reduce NOx by 10 to 20 percent from uncontrolled levels.
OFA is a technique in which a percentage of the total combustion air is diverted from the
burners and injected through ports above the top burner level. OFA limits NOx by
(1) suppressing thermal NOx by partially delaying and extending the combustion process resulting in
less intense combustion and cooler flame temperatures and (2) suppressing fuel NOx formation by
reducing the concentration of air in the combustion zone where volatile fuel nitrogen is evolved. OFA
can be applied for various boiler types including tangential and wall-fired, turbo, and stoker boilers
and can reduce NOx by 20 to 30 percent from uncontrolled levels.
1.1-8
EMISSION FACTORS
10/96
-------
LNBs limit N0X formation by controlling the stoichiometric and temperature profiles of the
combustion process in each burner zone. The unique design of features of an LNB may create (1) a
reduced oxygen level in the combustion zone to limit fuel NOx formation, (2) a reduced flame
temperature that limits themal NOx formation, and/or (3) a reduced residence time at peak
temperature which also limits thermal NOx formation,
LNBs are applicable to tangential and wall-fired boilers of various sizes but are not applicable
to other boiler types such as cyclone furnaces or stokers. They have been used as a retrofit NOx
control for existing boilers and can achieve approximately 35 to 55 percent reduction from
uncontrolled levels. They are also used in new boilers to meet New Source Performance Standards
(NSPS) limits. LNBs can be combined with OFA to achieve even greater NOx reduction (40 to
60 percent reduction from uncontrolled levels).
Rebum is a combustion hardware modification in which the NOx produced in the main
combustion zone is reduced in a second combustion zone downstream. This technique involves
withholding up to 40 percent (at full load) of the heat input to the main combustion zone and
introducing that heat input above the top row of burners to create a rebum zone. Rebum fuel (natural
gas, oil, or pulverized coal) is injected with either air or flue gas to create a fuel-rich zone that reduces
the NOx created in the main combustion zone to nitrogen and water vapor. The fuel-rich combustion
gases from the rebum zone are completely combusted by injecting overfire air above the rebum zone.
Rebum may be applicable to many boiler types firing coal as the primary fuel, including tangential,
wall-fired, and cyclone boilers. However, the application and effectiveness are site-specific because
each boiler is originally designed to achieve specific steam conditions and capacity which may be
altered due to rebum. Commercial experience is limited; however, this limited experience does
indicate NOx reduction of 50 to 60 percent from uncontrolled levels may be achieved.
SNCR is a postcombustion technique that involves injecting ammonia (NH3) or urea into
specific temperature zones in the upper furnace or convective pass. The ammonia or urea reacts with
NOx in the flue gas to produce nitrogen and water. The effectiveness of SNCR depends on the
temperature where reagents are injected; mixing of the reagent in the flue gas; residence time of the
reagent within the required temperature window; ratio of reagent to NOx; and the sulfur content of the
fuel that may create sulfur compounds that deposit in downstream equipment. There is not as much
commercial experience to base effectiveness on a wide range of boiler types; however, in limited
applications, NOx reductions of 25 to 40 percent have been achieved.
SCR is another postcombustion technique that involves injecting NH3 into the flue gas in the
presence of a catalyst to reduce NOx to nitrogen and then water. The SCR reactor can be located at
various positions in the process including before an air heater and particulate control device, or
downstream of the air heater, particulate control device, and flue gas desulfurization systems. The
performance of SCR is influenced by flue gas temperature, fuel sulfur content, ammonia-to-NOx ratio,
inlet NOx concentration, space velocity, and catalyst condition. Although there is currently very
limited application of SCR in the U.S. on coal-fired boilers, NOx reductions of 75 to 86 percent have
been realized on a few pilot systems.
10/96
External Combustion Sources
1.1-9
-------
1.1.5 Emission Factors
Emission factors for SOx, NOx, and CO are presented in Table 1.1-3. Tables in this section
present emission factors on both a weight basis (lb/ton) and an energy basis (Ib/Btu). To convert from
lb/ton to lb/MMBtu, divide by a heating value of 26.0 MMBtu/ton. Because of the inherently low
NOx emission characteristics of FBCs and the potential for in-bed S02 capture by calcium-based
sorbents, uncontrolled emission factors for this source category were not developed in the same sense
as with other source categories. For NOx emissions, the data collected from test reports were
considered to be baseline (uncontrolled) if no additional add-on NOx control system (such as ammonia
injection) was operated. For S02 emissions, a correlation was developed from reported data on FBCs
to relate S02 emissions to the coal sulfur content and the calcium-to-sulfur ratio in the bed.
Particulate matter and particulate matter less than, or equal to, 10 micrometers in diameter
(PM-10) emission factors are presented in Table 1.1-4. Cumulative particle size distributions and
particulate size-specific emission factors are given in Tables 1.1-5, 1.1-6, 1.1-7, 1.1-8, 1.1-9, and
1,1-10. Particulate size-specific emission factors are also presented graphically in Figures 1.1-1, 1.1-2,
1.1-3, 1.1-4, 1.1-5, and 1.1-6.
Controlled emission factors for PCDD/PCDF and PAHs are provided in Tables 1.1-11 and
1.1-12, respectively. Controlled emission factors for other organic compounds are presented in Table
1.1-13. Emission factors for hydrogen chloride and hydrogen fluoride are presented in Table 1.1-14.
Table 1.1-15 presents emission factor equations for nine trace metals from controlled and
uncontrolled boilers. Table 1.1-16 presents uncontrolled emission factors for seven of the same
metals, along with mercury, POM and formaldehyde. Table 1.1-17 presents controlled emission
factors for 13 trace metals and includes the metals found in Tables 1.1-15 and 1.1-16. The emission
factor equations in Table 1.1-15 are based on statistical correlations among measured trace element
concentrations in coal, measured fractions of ash in coal, and measured particulate matter emission
factors. Because these are the major parameters affecting trace metals emissions from coal
combustion, it is recommended that the emission factor equations be used when the inputs to the
equations are available. If the inputs to the emission factor equations are not available for a pollutant,
then the emission factors provided in Table 1.1-16 and 1.1-17 for the pollutant should be used.
Greenhouse gas emission factors, including CH4. non-methane organic compounds (NMOC),
and N20 are provided in Table 1.1-18. In addition, Table 1.1-19 provides emission factors for C02.
1.1.6 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
SCC's were corrected from 1-01-002-17, 1-02-002-17, and 1-03-002-17, to
1-01-002-18, 1-02-002-18, and 1-03-002-18 in the tables with SOx, NOx, CO, and
PM/PM10 emission factors.
1.1-10
EMISSION FACTORS
10/96
-------
• For SOx factors, clarifications were added to the table footnotes to clarify that "S" is a
weight percent and not a fraction. Similar clarification was added to the footnote for
the C02 factor.
• For fluidized bed combustors (bubbling bed and circulating bed), the PM10 factors
were replaced with footnote "m." The revised footnote "m" directs the user to the
emission factor for spreader stoker with multiple cyclones and no flyash reinjection.
• In the table with filterable PM factors, the misspelling of "filterable" was corrected.
• In the cumulative particle size distribution table, text was added to the table footnotes
to clarify that "A" is a weight percent and not a fraction.
• In the cumulative particle size distribution for spreader stokers, all of the factors were
corrected.
• The N20 emission factor for bubbling bed was changed from 5.9 lb/ton to 5.5 lb/ton.
Supplement B, October 1996
• Text was added concerning coal rank/classification, firing practices, emissions, and
controls.
• The table for NOx control technologies was revised to include controls for all types of
coal-fired boilers.
• SOx, NOx, and CO emission factors were added for cell burners.
• The PM table was revised to recommend using spreader stoker PM factors for FBC
units.
• Tables were added for new emission factors for polychlonnated toxics, polynuclear
aromatics, organic toxics, acid gas toxics, trace metal toxics, and controlled toxics.
• N20 emission factors were added.
• Default C02 emission factors were added.
10/96
External Combustion Sources
1.1-11
-------
Table 1.1-1, POSTCOMBUSTION S02 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%
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 are
completed
Duct injection
Dry sorbent injection
into duct, sometimes
combined with water
spray
25 - 50+%
Several research and
development, and
demonstration projects
underway, not yet
commercially available in
the United States.
1.1-12
EMISSION FACTORS
10/96
-------
£ Table 1.1-2. N0X CONTROL OPTIONS FOR COAL-FIRED BOILERS3
OS X
tn
&
n>
EL
n
o
3
cr
c:
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o
3
W
o
e
3
Control Technique
Description of
Technique
Applicable Boiler
Designs
NOx Reduction
Potential1*
(%)
Commercial
Availability/R & D
Status
Comments
Combustion Modifications
Load reduction
Reduction of
coal and air
Stokers
Minimal
Available
Applicable to stokers that can reduce load without
increasing excess air, may cause reduction in boiler
efficiency; N()x reduction varies with percent load
reduction.
Operational
modifications (BOOS,
LEA, BF, or
combination)
Rearrangement
of air or fuel in
the main
combustion zone
Pulverized coal
boilers (some
designs); Stokers
(LEA only)
10 - 20
Available
Must have sufficient operational flexibility to achieve
NOx reduction potential without sacrificing boiler
performance.
Overfire Air
Injection of air
above main
combustion zone
Pulverized coal
boilers and stokers
20 - 30
Available
Must have sufficient furnace height above top row of
burners in order to retrofit this technology to existing
boilers.
Low NOx Burners
New burner
designs
controlling air-
fuel mixing
Pulverized coal
boilers
35 - 55
Available
Available in new boiler designs and can be retrofit in
existing boilers.
LNB with OFA
Combination of
new burner
designs and
injection of air
above main
combustion zone
Pulverized coal
boilers
40 - 60
Available
Available in new boiler designs and can be retrofit in
existing boilers with sufficient furnace height above
top row of burners.
Rebum
Injection of
rebum fuel and
completion air
above main
combustion zone
Pulverized coal
boilers, cyclone
furnaces
50-60
Commercially
available but not
widely demonstrated
Rebum fuel can be natural gas, fuel oil, or pulverized
coal. Must have sufficient furnace height to retrofit
this technology to existing boilers.
-------
Table 1.1-2 (cont.).
m
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T1
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n
3
7»
w
Control Technique
Description of
Technique
Applicable Boiler
Designs
NOx Reduction
Potential
(%)
Commercial
Availability/R & D
Status
Comments
Post-Combustion Modifications
SNCR
Injection of NHj
or urea in the
convective pass
Pulverized coal
boilers, cyclone
furnaces, stokers, and
fluidized bed boilers
30 - 60
Commercially
available but not
widely demonstrated
Applicable to new boilers or as a retrofit technology;
must have sufficient residence time at correct
temperature (1,750°±90°F); elaborate reagent injection
system; possible load restrictions on boiler, and
possible air preheater fouling by ammonium bisulfate.
SCR
Injection of NH3
in combination
with catalyst
material
Pulverized coal
boilers, cyclone
furnaces
75 - 85
Commercially
offered, but not yet
demonstrated
Applicable to new boilers or as a retrofit technology
provided there is sufficient space; hot-side SCR best
on low-sulfur fuel and low fly ash applications; cold-
side SCR can be used on high-sulfur/high-ash
applications if equipped with an upstream FGD
system.
LNB with SNCR
Combination of
new burner
designs and
injection of NH3
or urea
Pulverized coal
boilers
50-80
Commercially
offered, but not
widely demonstrated
as a combined
technology
Same as LNB and SNCR alone.
LNB with OFA and
SCR
Combination of
new burner
design, injection
of air above
combustion zone,
and injection of
NHj or urea
Pulverized coal
boiler
85-95
Commercially
offered, but not
widely demonstrated
as a combined
technology
Same as LNB, OFA, and SCR alone.
® References 20-21.
NOx reduction potential from uncontrolled levels.
VO
Us
-------
Table 1.1-3. UNCONTROLLED EMISSION FACTORS FOR SOx, NOx, AND CO
FROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION3
soxb
NOxc
COde
Firing Configuration
see
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
PC-fired, dry bottom,
wall-fired
1-01-002-02/22
1-02-002-02/22
1-03-002-06/22
38S
(35S)
A
21.7
A
0.5
A
PC-fired, bituminous coal,
dry bottom, cell burner
firedf
1-01-002-15
38S
(35 S)
A
31.1
C
0.5
A
PC-fired, dry bottom,
tangentially fired
1-01-002-12/26
1-02-002-12/26
1-03-002-16/26
38S
(35S)
A
14.4
A
0.5
A
PC-fired, wet bottom
1-01-002-01/21
1-02-002-01/21
1-03-002-05/21
38S
(35S)
D
34.0
C
0.5
A
Cyclone furnace
1-01-002-03/23
1-02-002-03/23
1-03-002-03/23
38S
(35S)
D
33.8
C
0.5
A
Spreader stoker
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
38S
(35S)
B
13.7
A
5
A
Spreader stoker, with
multiple cyclones,
and reinjection
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
38S
(35S)
B
13.7
A
5
A
Spreader stoker, with
multiple cyclones,
no reinjection
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
38S
(35S)
A
13.7
A
5
A
-------
Table 1.1-3 (cont).
m
§
53
t/J
O
5S
n
£
so„b
NOxc
COd>e
Firing Configuration
SCC
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Overfeed stoker®
1-01-002-05/25
1-02-002-05/25
1-03-002-07/25
38S
(35S)
B
7,5
A
6
B
Feed stoker, with
multiple cyclones8
1-01-002-05/25
1-02-002-05/25
1-03-002-07/25
38S
(35S)
B
7.5
A
6
B
Underfeed stoker
1-02-002-06
1-03-002-08
31S
B
9,5
A
11
B
Underfeed stoker, with
multiple cyclones
1-02-002-06
1-03-002-08
31S
B
9.5
A
11
B
Hand-fed units
1-03-002-14
31S
D
9.1
E
275
E
FBC, circulating bed
1-01-002-18
1-02-002-18
1-03-002-18
h
E
3.9
E
18
E
FBC, bubbling bed
1-01-002-17
1-02-002-17
1-03-002-17
h
E
15.2
D
18
D
a Factors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired. SCC = Source
Classification Code. To convert from lb/ton to kg/Mg, multiply by 0.5.
b Expressed as S02, including S02, S03, and gaseous sulfates. Factors in parentheses should be used to estimate gaseous SOx emissions for
subbituminous coal. In all cases, S is weight % sulfur content of coal as fired. Emission factor would be calculated by multiplying the
weight percent sulfur in the coal by the numerical value preceding S. For example, if fuel is 1.2% sulfur, then S = 12. On average for
bituminous coal, 95% of fuel sulfur is emitted as S02, and only about 0.7% of fuel sulfur is emitted as S03 and gaseous sulfate. An
equally small percent of fuel sulfur is emitted as particulate sulfate (References 22-23). Small quantities of sulfur are also retained in
3 bottom ash. With subbituminous coal, about 10% more fuel sulfur is retained in the bottom ash and particulate because of the more
vo alkaline nature of the coal ash. Conversion to gaseous sulfate appears about the same as for bituminous coal.
-------
Table 1.1-3 (cont).
Expressed as N02. Generally, 95 volume % or more of NOx present in combustion exhaust will be in the form of NO, the rest N02
(Reference 6). To express factors as NO, multiply factors by 0.66. All factors represent emissions at baseline operation (i. e., 60 to 110%
load and no NOx control measures).
Nominal values achievable under normal operating conditions. Values 1 or 2 orders of magnitude higher can occur when combustion is
not complete.
Emission factors for C02 emissions from coal combustion should be calculated using lb C02/ton coal = 72.6C. where C is the weight %
carbon content of the coal. For example, if carbon content is 85%, then C equals 85.
References 24-27.
Includes traveling grate, vibrating grate, and chain grate stokers.
S°2 emission factors for fluidized bed combustion arc a function of fuel sulfur content and calc.um-to-sulfur ratio. For both bubbling bed
and circulating bed design, use: lb S02/ton coal = 39.6(S)(Ca/S) . 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 S02 emissions. In this case, the emission factor ratings are E for both bubbling and circulating units.
-------
Table 1.1-4. UNCONTROLLED EMISSION FACTORS FOR PM AND PM-10
FROM BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION3
en
(*>
C/i
I—>I
O
z
>
o
H
o
*3
c/i
VO
as
Filterable PMb
PM-10
Firing Configuration
see
Emission Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission Factor
(lb/ton)
EMISSION
FACTOR
RATING
PC-fired, dry bottom,
wall-fired
1-01-002-02/22
1-02-002-02/22
1-03-002-06/22
10A
A
2.3A
E
PC-fired, dry bottom,
tangentially fired
1-01-002-12/26
1-02-002-12/26
1-03-002-16/26
10A
B
2.3AC
E
PC-fired, wet bottom
1-01-002-01/21
1-02-002-01/21
1-03-002-05/21
7Ad
D
2.6A
E
Cyclone furnace
1-01-002-03/23
1-02-002-03/23
1-03-002-03/23
2Ad
E
0.26A
E
Spreader stoker
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
66e
B
13.2
E
Spreader stoker, with multiple
cyclones, and reinjection
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
17
B
12.4
E
Spreader stoker, with multiple
cyclones, no reinjection
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
12
A
7.8
E
Overfeed stoke/
1-01-002-05/25
1-02-002-05/25
1-03-002-07/25
16g
C
6.0
E
-------
o
5? Table 1.1-4 (cont.).
m
x
O
o
cr
c
W
o"
3
in
o
c
?5
Filterable PMb
PM-10
Firing Configuration
SCC
Emission Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission Factor
(lb/ton)
EMISSION
FACTOR
RATING
Overfeed stoker, with
r
multiple cyclones
1-01-002-05/25
1-02-002-05/25
1-03-002-07/25
9h
C
5.0
E
Underfeed stoker
1-02-002-06
1-03-002-08
15J
D
6.2
E
Underfeed stoker, with
multiple cyclone
1-02-002-06
1-03-002-08
1 lh
D
6.2J
E
Hand-fed units
1-03-002-14
15
E
6.2k
E
FBC, bubbling bed
1-01-002-17
1-02-002-17
1-03-002-17
m
E
m
E
FBC, circulating bed
1-01-002-18
1-02-002-18
1-03-002-18
m
E
m
E
a Factors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired.
To convert from lb/ton to kg/Mg, multiply by 0.5. SCC = Source Classification Code.
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% ash is fired in a PC-fired, dry bottom unit, the PM emission factor would be 10 x 8, or 80 lb/ton. Hie "condensable" 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 28-32.
c No data found; emission factor for PC-fired dry bottom boilers used.
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 2.
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.
-------
Table 1.1-4 (cont).
f Includes traveling grate, vibrating grate, and chain grate stokers.
8 Accounts for fly ash settling in breaching or stack base. Particulate loadings directly at boiler outlet typically can be 50% higher.
h See Reference 4 for discussion of apparently low multiple cyclone control efficiencies, regarding uncontrolled emissions.
J Accounts for fly ash settling in breaching downstream of boiler outlet.
k No data found; emission factor for underfeed stoker used.
m No data found; use emission factor for spreader stoker with multiple cyclones and reinjection.
m
Xfi
1/3
*—*
o
z
>
n
H
o
*
(73
O
"3
OS
-------
Table 1.1-5. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION
FACTORS FOR DRY BOTTOM BOILERS BURNING PULVERIZED BITUMINOUS AND SUBBITUMINOUS COAL3
Particle
Sizeb
(pm)
Cumulative Mass % < Stated Size
Cumulative Emission Factor0 (lb/ton)
Uncontrolled
Controlled
Uncontrolled11
Controlled6
Multiple
Cyclones
Scrubber
ESP
Baghouse
Multiple
Cyclones'"
Scrubber8
ESP8
f
Baghouse
15
32
54
81
79
97
3.2A
1.08 A
0.48A
0.064A
0.02A
10
23
29
71
67
92
2.3A
0.58 A
0.42A
0.054A
0.02A
6
17
14
62
50
77
1.7A
0.28A
0.38A
0.024A
0.02A
2.5
6
3
51
29
53
0.6A
0.06A
0.3A
0.024A
0.01A
1.25
2
I
35
17
31
0.2 A
0.02A
0.22A
0.01A
0.006A
1.00
2
1
31
14
25
0.2A
0.02A
0.18A
0.01 A
0.006A
0.625
1
1
20
12
14
0.10A
0.02A
0.12A
0.01A
0.002A
TOTAL
100
100
100
100
100
10A
2A
0.6A
0.08A
0.02A
a Reference 33, Applicable Source Classification Codes are 1-01-002-02, 1-02-002-02, 1-03-002-06, 1-01-002-12, 1-02-002-12, and
1-03-002-16. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission Factors are lb of pollutant per ton of coal combusted, as fired.
ESP = Electrostatic precipitator.
b Expressed as aerodynamic equivalent diameter.
c A = coal ash weight percent, as fired. For example, if coal ash weight is 8.2%, then A = 8.2.
d EMISSION FACTOR RATING = C.
e Estimated control efficiency for multiple cyclones is 80%; for scrubber, 94%; for ESP, 99.2%; and for baghouse, 99.8%.
f EMISSION FACTOR RATING = E.
8 EMISSION FACTOR RATING = D.
-------
Table 1.1-6. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND
SIZE-SPECIFIC EMISSION FACTORS FOR WET BOTTOM BOILERS BURNING PULVERIZED
BITUMINOUS COALa
EMISSION FACTOR RATING: E
Particle Sizeb
(Mm)
Cumulative Mass % < Stated Size
Cumulative Emission Factor0
(lb/ton)
Uncontrolled
Controlled
Uncontrolled
Controlled**
Multiple
Cyclones
ESP
Multiple
Cyclones
ESP
15
40
99
83
2.8A
1.38A
0.046
10
37
93
75
2.6 A
1.3A
0.042
6
33
84
63
2.32A
1.18A
0.036
2.5
21
61
40
1.48A
0.86A
0.022A
1.25
6
31
17
0.42A
0.44A
0.01A
1.00
4
19
8
0.28A
0.26 A
0.004A
0.625
2
e
e
0.14A
e
e
TOTAL
100
100
100
7.0A
1.4A
0.056A
a Reference 33. Applicable Source Classification Codes are 1-01-002-01, 1-02-002-01, and
1-03-002-05, To convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are lb of
pollutant per ton of coal combusted as fired. ESP = Electrostatic precipitator.
b Expressed as aerodynamic equivalent diameter.
c A = coal ash weight %, as fired. For example, if coal ash weight is 2.4%, then A = 2.4.
d Estimated control efficiency for multiple cyclones is 94%, and for ESPs, 99.2%.
e Insufficient data.
1.1-22
EMISSION FACTORS
10/96
-------
Table 1.1-7. CUMULATIVE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS
FOR CYCLONE FURNACES BURNING BITUMINOUS COAL3
EMISSION FACTOR RATING: E
Cumulative Mass % < Stated Size
Cumulative Emission Factor0
(lb/ton)
Particle
Sizeb
(Mm)
Controlled
Controlled13
Uncontrolled
Multiple
Cyclones
ESP
Uncontrolled
Multiple
Cyclones
ESP
15
33
95
90
0.66A
0.114A
0.013A
10
13
94
68
0.26A
0.112A
0.011A
6
8
93
56
0.16A
0.112A
0.009A
2.5
0
92
36
0
0.11A
0.006A
1.25
0
85
22
0
0.1 OA
0.004A
1.00
0
82
17
0
0.1 OA
0.003A
0.625
0
e
e
0
e
e
TOTAL
100
100
100
2A
0.12A
0.0I6A
a Reference 33. Applicable Source Classification Codes are 1-01-002-03, 1-02-002-03, and
1-03-002-03. To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per
ton of coal combusted, as fired.
b Expressed as aerodynamic equivalent diameter.
c A = coal ash weight %, as fired. For example, if coal ash weight is 2.4%, then A = 2.4.
d Estimated control efficiency for multiple cyclones is 94%, and for ESPs, 99.2%.
e Insufficient data.
10/96
External Combustion Sources
1.1-23
-------
Table 1.1-8. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC
EMISSION FACTORS FOR SPREADER STOKERS BURNING BITUMINOUS COAL3
Particle
Sizeb
(Mm)
Cumulative Mass % < Stated Size
Cumulative Emission Factor0 (lb/ton)
Uncontrolled
Controlled
Uncontrolled®
Controlled*1
Multiple
Cvclonesc
Multiple
Cyclonesd
ESP
Baghouse
Multiple
Cycloncsc*f
Multiple
Cyclones'1'®
Espf,g
Baghousce,g
15
28
86
74
97
72
18.5
14.6
8.8
0.46
0.086
10
20
73
65
90
60
13.2
12
7.8
0.44
0.072
6
14
51
52
82
46
9.2
8.6
6.2
0.40
0.056
2.5
7
8
27
61
26
4.6
1.4
3.2
0.30
0.032
1.25
5
2
16
46
18
3.3
0.4
2,0
0.22
0.022
1.00
5
2
14
41
15
3.3
0.4
1.6
0.20
0.018
0.625
4
1
9
h
7
2.6
0.2
1.0
_h
0.006
TOTAL
100
100
100
100
100
66.0
17.0
12.0
0.48
0.12
Reference 33. Applicable Source Classification Codes are 1-01-002-04, 1-02-002-04, 1-03-002-09. To convert from lb/ton to kg/Mg,
multiply by 0.5. Emissions are lb of pollutant per ton of coal combusted, as fired.
Expressed as aerodynamic equivalent diameter.
With flyash reinjection.
Without flvash reinjection.
EMISSION FACTOR RATING = C.
EMISSION FACTOR RATING = E.
Estimated control efficiency for ESP is 99.22%; and for baghouse, 99.8%.
Insufficient data.
V©
OS
-------
Table 1.1-9. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION-
FACTORS FOR OVERFEED STOKERS BURNING
BITUMINOUS COAL®
Particle
Sizeb
(m)
Cumulative Mass %
< Stated Size
Cumulative Emission Factor
(lb/ton)
Uncontrolled
Multiple
Cyclones
Controlled
Uncontrolled
Multiple Cyclones
Controlled*5
Emission
Factor
EMISSION
FACTOR
RATING
Emission
Factor
EMISSION
FACTOR
RATING
15
49
60
7.8
C
5.4
E
10
37
55
6.0
C
5.0
E
6
24
49
3.8
C
4.4
E
2.5
14
43
2.2
C
3.8
E
1.25
13
39
2.0
C
3.6
E
1,00
12
39
2.0
C
3.6
E
0.625
d
16
d
C
1.4
E
TOTAL
100
100
16.0
C
9.0
E
a Reference 33. Applicable Source Classification Codes are 1-01-002-05, 1-02-002-05, and
1-03-002-07. To convert from lb/ton to kg/Mg, multiply by 0.5. Emissions are lb of pollutant per
ton of coal combusted, as fired.
b Expressed as aerodynamic equivalent diameter.
c Estimated control efficiency for multiple cyclones is 80%.
d Insufficient data.
10/96
External Combustion Sources
1,1-25
-------
Table 1.1-10. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND
SIZE-SPECIFIC EMISSION FACTORS FOR UNDERFEED STOKERS BURNING
BITUMINOUS COAL®
EMISSION FACTOR RATING: C
Particle Sizeb (jun)
Cumulative Mass %
< Stated Size
Uncontrolled Cumulative Emission Factor®
(lb/ton)
15
50
7.6
10
41
6.2
6
32
4.8
2.5
25
3.8
1.25
22
3.4
1.00
21
3.2
0.625
18
2.7
TOTAL
100
15.0
a Reference 33. Applicable Source Classification Codes are 1-02-002-06 and 1-03-002-08. To
convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are lb of pollutant per ton of coal
combusted, as fired.
b Expressed as aerodynamic equivalent diameter.
c May also be used for uncontrolled hand-fired units.
1.1-26
EMISSION FACTORS
10/96
-------
Table 1.1-11 EMISSION FACTORS FOR POLY CHLORINATED
DIBENZO-P-DIOXINS AND POLY CHLORINATED DIBENZOFURANS FROM CONTROLLED
BITUMINOUS AND SUBBITUMINOUS COAL COMBUSTION
Controls
FGD-SDA with FF3
ESP or FFb
Congener
Emission Factorc
(lb/ton)
EMISSION
FACTOR
RATING
Emission Factor0
(lb/ton)
EMISSION
FACTOR
RATING
2,3,7,8-TCDD
No data
—
1.43E-11
E
Total TCDD
3.93E-10
E
9.28E-11
D
Total PeCDD
7.06E-10
E
4.47E-11
D
Total HxCDD
3.00E-09
E
2.87E-11
D
Total HpCDD
1.00E-08
E
8.34E-11
D
Total OCDD
2.87E-08
E
4.16E-10
D
Total PCDDd
4.28E-08
E
6.66E-10
D
2,3,7,8-TCDF
No data
—
5.10E-11
D
Total TCDF
2.49E-09
E
4.04E-10
D
Total PeCDF
4.84E-09
E
3.53E-10
D
Total HxCDF
1.27E-08
E
I.92E-10
D
Total HpCDF
4.39E-08
E
7.68E-11
D
Total OCDF
1.37E-07
E
6.63E-11
D
Total PCDFd
2.01E-07
E
1.09E-09
D
TOTAL PCDD/PCDF
2.44E-07
E
1.76E-09
D
a Reference 34. Factors apply to boilers equipped with both flue gas desulfurization spray dryer
absorber (FGD-SDA) and a fabric filter (FF). SCCs = pulverized coal-fired, dry bottom boilers,
1-01-002-02/22, 1-02-002-02/22, and 1-03-002-06/22.
b References 35-37. Factors apply to boilers equipped with an electrostatic precipitator (ESP) or a
fabric filter, SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22,
1-03-002-06/22; and, cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, and 1-03-002-03/23,
c Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply
by 0.5. Emissions are lb of pollutant per ton of coal combusted.
d Total PCDD is the sum of Total TCDD through Total OCDD. Total PCDF is the sum of Total
TCDF through Total OCDF.
10/96
External Combustion Sources
1.1-27
-------
Table 1.1-12 EMISSION FACTORS FOR POLYNUCLEAR AROMATIC
HYDROCARBONS (PAH) FROM CONTROLLED COAL COMBUSTION11
Pollutant
L
Emission Factor
(lb/ton)
EMISSION FACTOR
RATING
Biphenyl
1.7E-06
D
Acenaphthene
5.1E-07
B
Acenaphthylene
2.5E-07
B
Anthracene
2.1E-07
B
Benzo(a)anthracene
8.0E-08
B
Benzo(a)pyrene
3.8E-08
D
Benzo(bj,k)fluoranthene
1.1E-07
B
Benzo(g,h,i)perylene
2.7E-08
D
Chrvsene
1.0E-07
C
Fluoranthene
7.1E-07
B
Fluorene
9.1E-07
B
Indeno( l,2,3-cd)pyrene
6.1E-08
C
Naphthalene
1.3E-05
C
Phenanthrene
2.7E-06
B
Pyrene
3.3E-07
B
5-Methyl chrysene
2.2E-08
D
a References 35-45. Factors were developed from emissions data from six sites firing bituminous coal,
four sites firing subbituminous coal, and from one site firing lignite. Factors apply to boilers
utilizing both wet limestone scrubbers or spray dryers with an electrostatic precipitator (ESP) or
fabric filter (FF). The factors also apply to boilers utilizing only an ESP or FF.
Bituminous/subbituminous SCCs = pulverized coal-fired dry bottom boilers, 1-01-002-02/22,
1-02-002-02/22, 1-03-002-06; pulverized coal, dry bottom, tangentially-fired boilers, 1-01-002-12/26,
1-02-002-12/26, 1-03-002-16/26; and, cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, and
1-03-002-03/23.
b Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply
by 0.5. Emissions are lb of pollutant per ton of coal combusted.
1.1-28
EMISSION FACTORS
10/96
-------
Table 1.1-13 EMISSION FACTORS FOR VARIOUS ORGANIC COMPOUNDS
FROM CONTROLLED COAL COMBUSTION3
Poilutantb
Emission Factor0
(lb/ton)
EMISSION FACTOR
RATING
Acetaldehyde
5.7E-04
C
Acetophenone
I.5E-05
D
Acrolein
2.9E-04
D
Benzene
1.3E-03
A
Benzyl chloride
7.0E-04
D
Bis(2-ethylhexyl)phthalate (DEHP)
7.3E-05
D
Bromoform
3.9E-05
E
Carbon disulfide
1.3E-04
D
2-Chloroacetophenone
7.0E-06
E
Chlorobenzene
2.2E-05
D
Chloroform
5.9E-05
D
Cumene
5.3E-06
E
Cyanide
2.5E-03
D
2,4-Dinitrotoluene
2.8E-07
D
Dimethyl sulfate
4.8E-05
E
Ethyl benzene
9.4E-05
D
Ethyl chloride
4.2E-05
D
Ethylene dichloride
4.0E-05
E
Ethylene dibromide
1.2E-06
E
Formaldehyde
2.4E-04
A
Hexane
6.7E-05
D
Isophorone
5.8E-04
D
Methyl bromide
1.6E-04
D
Methyl chloride
5.3E-04
D
Methyl ethyl ketone
3.9E-04
D
Methyl hydrazine
1.7E-04
E
Methyl methacrylate
2.0E-05
E
Methyl tert butyl ether
3.5E-05
E
Methylene chloride
2.9E-04
D
10/96
External Combustion Sources
1.1-29
-------
Table 1.1-13 (cont.).
Pollutantb
Emission Factor0
(lb/ton)
EMISSION FACTOR
RATING
Phenol
1.6E-05
D
Propionaldehyde
3.8E-04
D
Tetrachloroethylene
4.3E-05
D
Toluene
2.4E-04
A
1,1,1 -Trichloroethane
2.0E-05
E
Styrene
2.5E-05
D
Xylenes
3.7E-05
C
Vinyl acetate
7.6E-06
E
a References 35-53. Factors were developed from emissions data from ten sites firing bituminous
coal, eight sites firing subbituminous coal, and from one site firing lignite. The emission factors are
applicable to boilers using both wet limestone scrubbers or spray dryers and an electrostatic
precipitator (ESP) or fabric filter (FF). In addition, the factors apply to boilers utilizing only an ESP
or FF. SCCs = pulverized coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22,
1-03-002-06/22; pulverized coal, dry bottom, tangentially-fired boilers, 1-01-002-12/26,
1-02-002-12/26, 1-03-002-16/26; cyclone boilers, 1-01-002-03/23, 1-02-002-03/23, 1-03-002-03/23;
and, atmospheric fluidized bed combustors, circulating bed, 1-01-002-18/38, 1-02-002-18, and
1-03-002-18.
b Pollutants sampled for but not detected in any sampling run include: Carbon tetrachloride- 2 sites;
1,3-Dichloropropylenc- 2 sites; N-nitrosodimethylamine- 2 sites; Ethylidene dichloride- 2 sites;
Hexachlorobutadiene- 1 site; Hexachloroethane- 1 site; Propylene dichloride- 2 sites;
1,1,2,2-Tetrachloroethane- 2 sites; 1,1,2-Trichloroethane- 2 sites; Vinyl chloride- 2 sites; and,
Hexachlorobenzene- 2 sites.
c Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply
by 0.5.
1.1-30
EMISSION FACTORS
10/96
-------
Table 1.1-14. EMISSION FACTORS FOR HYDROGEN CHLORIDE (HCI) AND HYDROGEN FLUORIDE (HF) FROM
COAL COMBUSTION3
EMISSION FACTOR RATING: B
HCI
HF
Firing Configuration
see
Emission Factor (lb/ton)
Emission Factor (lb/ton)
PC-fired, dry bottom
1-01-002-02/22
1-02-002-02/22
1-03-002-06/22
12
0.15
PC-fired, dry bottom, tangential
1-01-002-12/26
1-02-002-12/26
1-03-002-16/26
1.2
0.15
PC-fired, wet bottom
1-01-002-01/21
1-02-002-01/21
1-03-002-05/21
1.2
0.15
Cyclone Furnace
1-01-002-03/23
1-02-002-03/23
1-03-002-03/23
1.2
0.15
Spreader Stoker
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
1.2
0.15
Overfeed Stoker
1-01-002-05/25
1-02-002-05/25
1-03-002-07/25
1.2
0.15
Underfeed Stoker
1-02-002-06
1-03-002-08
1.2
0.15
FBC, Bubbling Bed
1-01-002-17
1-02-002-17
1-03-002-17
1.2
0.15
FBC, Circulating Bed
1-01-002-18/38
1-02-002-18
1-03-002-18
1.2
0.15
Hand-fired
1-03-002-14
1.2
0.15
a Reference 54. The emission factors were developed from bituminous coal, subbituminous coal, and lignite emissions data. To convert
from lb/ton to kg/Mg, multiply by 0.5. The factors apply to both controlled and uncontrolled sources.
-------
Table 1.1-15. EMISSION FACTOR EQUATIONS FOR TRACE ELEMENTS FROM COAL
COMBUSTION3
EMISSION FACTOR EQUATION RATING: Ab
Pollutant
Emission Equation
(lb/1012 Btu)c
Antimony
0.92 * (C/A * PM)° 63
Arsenic
3 .1 * (C/A * PM)0 85
Beryllium
1.2 * (C/A * PM)1 1
Cadmium
3.3 * (C/A * PM)0'5
Chromium
3.7 * (C/A * PM)0 58
Cobalt
1.7 * (C/A * PM)0 69
Lead
3.4 * (C/A * PM)0-80
Manganese
3.8 * (C/A * PM)0 60
Nickel
4.4 * (C/A * PM)048
a Reference 55. The equations were developed from emissions data from bituminous coal combustion,
subbituminous coal combustion, and from lignite combustion. The equations may be used to
generate factors for both controlled and uncontrolled boilers. The emission factor equations are
applicable to all typical firing configurations for electric generation (utility), industrial, and
commercial/industrial boilers firing bituminous coal, subbituminous coal, and lignite. Thus, all SCCs
for these boilers are assigned to the factors.
b AP-42 criteria for rating emission factors were used to rate the equations.
c The factors produced by the equations should be applied to heat input. To convert from lb/1012 Btu
to kg/joules, multiply by 4.31 x 10"16.
C = concentration of metal in the coal, parts per million by weight (ppmwt).
A = weight fraction of ash in the coal. For example, 10% ash is 0.1 ash fraction.
PM = Site-specific emission factor for total particulate matter, lb/106 Btu.
1.1-32
EMISSION FACTORS
10/96
-------
o
5 Table I 1-16. EMISSION FACTORS FOR TRACE ELEMENTS, POM, AND HCOH FROM UNCONTROLLED BITUMINOUS AND
SUBBITUMINOUS COAL COMBUSTION3
EMISSION FACTOR RATING. E
tn
&
CS>
fiL
O
o
3
o*
c
IA
a.
o
3
V>
o
c
—t
o
ro
tn
Firing Configuration
(SCC)
Emission Factor,
lb/1012 Btu
As
Be
Cd
Cr
Pbb
Mn
Hg
Ni
POM
HCOH
Pulverized coal, configuration
unknown (no SCC)
ND
ND
ND
1922
ND
ND
ND
ND
ND
112°
Pulverized coal, wet bottom
(1-01-002-01/21, 1-02-002-01/21,
1-03-002-05/21)
538
81
44-70
1020-1570
507
808-2980
16
840-1290
ND
ND
Pulverized coal, dry bottom
(1-01-002-02/22, 1-02-002-06/22,
1-03-002-06/22)
684
81
44.4
1250-1570
507
228-2980
16
1030-1290
2.08
ND
Pulverized coal, dry bottom,
tangential (1-01-002-12/26,
1-02-002-12/26, 1-03-002-16/26)
ND
ND
ND
ND
ND
ND
ND
ND
2.4
ND
Cyclone furnace (1-01-002-03/23,
1-02-002-03/23, 1-03-002-03/23)
115
<81
28
212-1502
507
228-1300
16
174-1290
ND
ND
Stoker, configuration unknown
(no SCC)
ND
73
ND
19-300
ND
2170
16
775-1290
ND
ND
Spreader stoker (1-01-002-04/24,
1-02-002-04/24, 1-03-002-09/24)
264-542
ND
21-43
942-1570
507
ND
ND
ND
ND
22 ld
Overfeed stoker, traveling grate
(1-01 -002-05/25, 1-02-002-05/25,
1-03-002-07/25)
542-1030
ND
43-82
ND
507
ND
ND
ND
ND
140e
a References 56-61. The emission factors in this table represent the ranges of factors reported in the literature. If only 1 data point was
found, it is still reported in this table. To convert from lb/1012 Btu to pg/J, multiply by 0.43. SCC = Source Classification Code. ND =
no data.
L
Lead emission factors were taken directly from an EPA background document for support of the National Ambient Air Quality Standards.
— c Based on 2 units; 133 x 106 Btu/hr and 1550 x 106 Btu/hr.
T d Based on 1 unit; 59 x 106 Btu/hr.
& e Based on 1 unit; 52 x 106 Btu/hr.
-------
Table 1.1-17 EMISSION FACTORS FOR TRACE METALS FROM
CONTROLLED COAL COMBUSTION3
Pollutant
Emission Factor (lb/ton)b
EMISSION FACTOR RATING
Antimony
1.8E-05
A
Arsenic
4.1E-04
A
Beryllium
2.1E-05
A
Cadmium
5.1E-05
A
Chromium
2.6E-04
A
Chromium (VI)
7.9E-05
D
Cobalt
1.0E-04
A
Lead
4.2E-04
A
Magnesium
1.1E-02
A
Manganese
4.9E-04
A
Mercury
8.3E-05
A
Nickel
2.8E-04
A
Selenium
1.3E-03
A
a References 35-53, 62-70. The emission factors were developed from emissions data at eleven
facilities firing bituminous coal, fifteen facilities firing subbituminous coal, and from two facilities
firing lignite. The factors apply to boilers utilizing either venturi scrubbers, spray dryer absorbers, or
wet limestone scrubbers with an electrostatic precipitator (ESP) or Fabric Filter (FF). In addition,
the factors apply to boilers using only an ESP, FF, or venturi scrubber. SCCs = pulverized
coal-fired, dry bottom boilers, 1-01-002-02/22, 1-02-002-02/22, 1-03-002-06/22; pulverized coal, dry
bottom, tangentially-fired boilers, 1-01-002-12/26, 1-02-002-12/26, 1-03-002-16/26; cyclone boilers,
1-01-002-03/23, 1-02-002-03/23, 1-03-002-03/23; and, atmospheric fluidized bed combustors,
circulating bed, 1-01-002-18/38, 1-02-002-18, and 1-03-002-18.
b Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply
by 0.5.
1.1-34
EMISSION FACTORS
10/96
-------
| Table 1.1-18. EMISSION FACTORS FOR CH4, TNMOC AND N20 FROM BITUMINOUS AND SUBBITUMINOUS COAL
COMBUSTION8
m
I
EL
O
o
3
cr
c
w
<-+¦
o'
3
W
O
c
3
CD
CH4b
TNMOCb'c
N2Od
Firing Configuration
see
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
PC-fired, dry bottom,
wall fired
1-01-002-02/22
1-02-002-02/22
1-03-002-06/22
0.04
B
0.06
B
0.03
B
PC-fired, dry bottom,
tangentially fired
1-01-002-12/26
1-02-002-12/26
1-03-002-16/26
0.04
B
0.06
B
0.08
B
PC-fired, wet bottom
1-01-002-01/21
1-02-002-01/21
1-03-002-05/21
0.05
B
0.04
B
0.08
E
Cyclone furnace
1-01-002-03/23
1-02-002-03/23
1-03-002-03/23
0.01
B
0.11
B
0.09e
E
Spreader stoker
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
0.06
B
0.05
B
0.04f
D
Spreader stoker, with multiple
cyclones, and reinjection
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
0.06
B
0.05
B
0.04f
E
Spreader stoker, with multiple
cyclones, no reinjection
1-01-002-04/24
1-02-002-04/24
1-03-002-09/24
0.06
B
0.05
B
0.04f
E
w
-------
dj Table 1.1-18 (cont ).
as
m
w
m
N—I
§
>3
CH4b
TNMOCbc
N2Od
Firing Configuration
SCC
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Overfeed stoker8
1-01-002-05/25
1-02-002-05/25
1-03-002-07/25
0.06
B
0.05
B
0.04f
E
Overfeed stoker, with multiple
cyclones5
1-01-0024)5/25
1-02-002-05/25
1-03-002-07/25
0.06
B
0.05
B
0.04f
E
Underfeed stoker
1-02-002-06
1-03-002-08
0.8
B
1.3
B
0.04f
E
Underfeed stoker, with multiple
cyclone
1-02-002-06
1-03-002-08
0.8
B
1.3
B
0.04f
E
Hand-fed units
1-03-002-14
5
E
10
E
0.04f
E
FBC, bubbling bed
1-01-002-17
1-02-002-17
1-03-002-17
0.06h
E
0.05h
E
3.5h
B
FBC, circulating bed
1-01-002-18
1-02-002-18
1-03-002-18
0.06
E
0.05
E
3.5
B
a Factors represent uncontrolled emissions unless otherwise specified and should be applied to coal feed, as fired. SCC = Source
Classification Code. To convert from lb/ton to kg/Mg, multiply by 0.5.
Reference 32. Nominal values achievable under nonnal operating conditions; values 1 or 2 orders of magnitude higher can occur when
combustion is not complete.
c TNMOC are expressed as C2 to C16 alkane equivalents (Reference 71). Because of limited data, the effects of firing configuration on
TNMOC 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 References 14-15.
c No data found; emission factor for pulverized coal-fired dry bottom boilers used.
_ No data found; emission factor for spreader-stoker boilers used.
5 g Includes traveling grate, vibrating grate, and chain grate stokers,
s* h No data found; emission factor for circulating fluidized bed used.
-------
Table 1.1-19. DEFAULT C02 EMISSION FACTORS FOR U. S, COALS3
EMISSION FACTOR RATING: C
Coal Type
Average %Cb
Conversion Factor0
Emission Factord
(lb/ton coal)
Subbituminous
66.3
72.6
4810
High-volatile bituminous
75.9
72.6
5510
Medium-volatile bituminous
83.2
72.6
6040
Low-volatile bituminous
86.1
72,6
6250
a This table should be used only when an ultimate analysis is not available. If the ultimate analysis is
available, C02 emissions should be calculated by multiplying the %carbon (%C) by 72.6 This
resultant factor would receive a quality rating of "B".
b An average of the values given in References 2,76-77. Each of these references listed average
carbon contents for each coal type (dry basis) based on extensive sampling of U.S. coals.
c Based on the following equation;
44 ton CO? lb CO, i lb CO,
z x 0.99 x 2000 L x 1 72.6 1
12 ton C ton C02 100% ton %C
Where:
44 = molecular weight of C02.
12 = molecular weight of carbon, and
0.99 = fraction of fuel oxidized during combustion (Reference 16).
d To convert from lb/ton to kg/Mg. multiply by 0.5.
10/96
External Combustion Sources
1.1-37
-------
2.0A
1.8A
fe 16A
tS
*5?
a ^
O 6b
I*
-S1
1
0.1A
0.06 A
0.04A
0.02A
0.01A
o
I-?
! .b
® -a
¦a o
4) o
*§.»
0.006A
0.004A „S
CU
s
0.002A
0.001A
Particle diameter ( m)
Figure 1.1-2. Cumulative size-specific emission factors for wet bottom boilers burning pulverized
bituminous coal.
1.1-38
EMISSION FACTORS
10/96
-------
is
1
c
o
"O
4>
§
o
c
D
l.OA
0.9A
0.8A
0.7A
0.6A
0.5A
0.4A
0.3A
0.2A
O.IA
I I I IJ i
ESP\
Uncontrolled
_L
_L
0,1 OA
0.06A
0.04A
0.02A
0.01A
0.006A
0.004A
0.002A
.1 .2 .4 .6 1 2 4 6 10
Particle diameter (um)
20 40 60
0.001 A
100
I
C
©
6
=2
l
p*
5/3
w
J
t/3
Figure 1,1-3. Cumulative size-specific emission factors for cyclone furnaces
burning bituminous coal.
10
9
8
7
6
5
4
3
2
1
0
Multiple cyclone with--~
ftyash re injection
Multiple cyclone without
flyash re injection
T^Baghouse
-
/f / J
/ Uncontrolled
-
A/
^ESP
-
- i—i i i Lsfrfr i i.. i
~i—J- i I i I - 1 i i 1
_J LLL
10,0
6.0
4,0
2,0
1.0
0.6
0.4
0.2
0.1
3?
53 g
||
© -
£1
CO «
W 00
s
II
j} e
£•§
¦a w
I'i
rt>
0.10
006 „
0.04 |
0.02 | ¦
"2 1
0.01 '
0.006 '
0.004
0.002
0.001
.4 .6 1
2 4 6 10
Particle diameter ( m)
20 40 60 100
Figure 1,1-4. Cumulative size-specific emission factors for spreader stokers burning bituminous coal.
10/96
External Combustion Sources
1.1-39
-------
I
<2 if
a £
.2 «
.1 8
|i"
TB "
6
8
7.2
6.4
5.6
4.8
4.0
3.2
2.4
1.6
0.8
.1
J i ¦ i i i 111
Multiple
cyclone
Uncontrolled
' ' '
I 111 I
10
6.0
4.0
2.0
1.0
0.6
0.4
0.2
0.1
.4 .6
1 2 4 6 10 20 40 60 100
Particle diameter ( m)
Figure 1.1-5. Cumulative size-specific emission factors for overfeed stokers burning bituminous coal.
3
I-
«« *o
c 8
o
u g
"d o
fl
5
Uncontrolled
1 2 4 6
Particle diameter ( m)
Figure 1.1-6. Cumulative size-specific emission factors for underfeed stokers
burning bituminous coal.
40 60 100
1.1-40
EMISSION FACTORS
10/96
-------
References For Section 1.1
1. Bartok, B., Sarofina, A. F. (eds), Fossil Fuel Combustion, A Source Book, John Wiley & Sons,
Inc., 1991, p. 239.
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4. Emission Factor Documentation For AP-42 Section 1.1 — Bituminous and Subbituminous
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NC, September 1979.
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10/96
External Combustion Sources
1.1-41
-------
16. G. Marland and R. M, Rotty, Carbon Dioxide Emissions from Fossil Fuels: A Procedure For
Estimation and Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
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28. Standards Of Performance For New Stationary Sources, 36 FR 24876,
December 23, 1971.
1 1-42 EMISSION FACTORS 10/96
-------
29. 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
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30. Application Of Combustion Modifications To Control Pollutant Emissions From
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10/96
External Combustion Sources
1.1-43
-------
43. Draft Final Report. A Study of Toxic Emissions from a Coal-Fired Power Plant Utilizing an
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49. Field Chemical Emissions Monitoring Project: Site 12 Emissions Monitoring. Radian
Corporation, Austin, Texas. November, 1992. (EPRI Report)
50. Field Chemical Emissions Monitoring Project: Site 15 Emissions Monitoring. Radian
Corporation, Austin, Texas. October, 1992. (EPRI Report)
51. Field Chemical Emissions Monitoring Project. Site 101 Emissions Report. Radian
Corporation. Austin, Texas. October, 1994. (EPRI Report)
52. Field Chemical Emissions Monitoring Project: Site 114 Report. Radian Corporation, Austin,
Texas. May, 1994. (EPRI Report)
53. Field Chemical Emissions Monitoring Report: Site 122, Final Report, Task 1 Third Draft.
EPRI RP9028-10. Southern Research Institute, Birmingham, Alabama. May, 1995. (EPRI
Report)
54. Hydrogen Chloride And Hydrogen Fluoride Emission Factors For The NAPAP Inventory,
EPA-600/7-85-041, U. S. Environmental Protection Agency, October 1985.
55. Electric Utility Trace Substances Synthesis Report, Volume J, Report TR-104614, Electric
Power Research Institute, Palo Alto, CA, November 1994.
56. Locating And Estimating Air Emissions From Sources Of Chromium, EPA-450/4-84-007g.
U. S. Environmental Protection Agency, July 1984.
57. Locating And Estimating Air Emissions From Sources Of Formaldehyde, (Revised),
EPA-450/4-91-012, U. S. Environmental Protection Agency, March 1991.
1.1-44 EMISSION FACTORS 10/96
-------
58. Estimating Air Toxics Emissions From Coal And Oil Combustion Sources, EPA-450/2-89-001,
Radian Corporation, Project Officer: Dallas W. Safriet, Research Triangle Park, NC, April
1989.
59. Canadian Coal-Fired Plants, Phase I: Final Report And Appendices, Report for the Canadian
Electrical Association, R&D, Montreal, Quebec, Contract Number 001G194, Report by
Battelle, Pacific Northwest Laboratories, Richland, WA.
60. R. Meij, Auteru dr., The Fate Of Trace Elements At Coal-Fired Plants, Report No. 2561-MOC
92-3641, Rapport te bestellen bij; bibliotheek N.V. KEMA, February 13, 1992.
61. Locating And Estimating Air Emissions From Sources Of Manganese, EPA-450/4-84-007h,
September 1985.
62. Results of the September 10 and 11, 1991 Mercury Removal Tests on the Units 1 & 2, and
Unit 3 Scrubber Systems at the NSP Sherco Plant in Becker, Minnesota. Interpoll
Laboratories, Inc., Circle Pines, Minnesota. October 30, 1991.
63. Results of the November 5, 1991 Air Toxic Emission Study on the No. 1, 3 & 4 Boilers at the
NSP Black Dog Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. January 3, 1992.
64. Results of the January 1992 Air Toxic Emission Study on the No. 2 Boiler at the NSP Black
Dog Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. May 4, 1992.
65. Results of the May 29, 1990 Trace Metal Characterization Study on Units 1 and 2 at the
Sherburne County Generating Station in Becker, Minnesota. Interpoll Laboratories, Inc.,
Circle Pines, Minnesota. July, 1990.
66. Results of the May 1, 1990 Trace Metal Characterization Study on Units 1 and 2 at the
Sherburne County'Generating Station. Interpoll Laboratories, Inc., Circle Pines, Minnesota.
July 18, 1990.
67. Results of the March 1990 Trace Metal Characterization Study on Unit 3 at the Sherburne
County Generating Station. Interpoll Laboratories, Circle Pines, Minnesota. June 7, 1990.
68. Field Chemical Emissions Monitoring Project: Site 19 Emissions Monitoring. Radian
Corporation, Austin, Texas. April, 1993. (EPRI Report)
69. Field Chemical Emissions Monitoring Project: Site 20 Emissions Monitoring. Radian
Corporation, Austin, Texas. March, 1994. (EPRI Report)
70. Characterizing Toxic Emissions from a Coal-Fired Power Plant Demonstrating the AFGD
ICCT Project and a Plant Utilizing a Dry Scrubber /Baghhouse System. Final Draft Report.
Springerville Generating Station Unit No. 2. Southern Research Insititute, Birmingham,
Alabama. December, 1993.
71. Emissions Of Reactive Volatile Organic Compounds From Utility Boilers,
EPA-600/7-80-111, U. S. Environmental Protection Agency, Washington, DC,
May 1980.
10/96
External Combustion Sources
1.1-45
-------
72. EPAJIFP European Workshop On The Emission Of Nitrous Oxide For Fuel Combustion, EPA
Contract No. 68-02-4701, Ruiel-Malmaison, France, June 1-2, 1988.
73. R. Clayton, et al., NOx Field Study, EPA-600/2-89-006, U. S. Environmental Protection
Agency, Research Triangle Park, NC, February 1989.
74. L. E. Amand, and S. Anderson, "Emissions of Nitrous Oxide from Fluidized Bed Boilers",
Presented at the Tenth International Conference on Fluidized Bed Combustor, San Francisco,
CA, 1989,
75. Alternative Control Techniques Document—NOx Emissions From Utility Boilers,
EPA-453/R-94-023, Office of Air Quality Standards, Research Triangle Park, NC, 1994.
76. Alliance Technologies Corporation, Evaluation of Significant Anthropogenic Sources of
Radiatively Important Trace Gases, U. S. Environmental Protection Agency, Office of
Research and Development, Research Triangle Park, NC, 1990.
77. R. A. Winschel, Richard, "The Relationship of Carbon Dioxide Emissions with Coal Rank and
Sulfur Content," Journal of the Air and Waste Management Association, Vol. 40, no. 6, pp.
861-865, June 1990.
1.1-46
EMISSION FACTORS
10/96
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1.2 Anthracite Coal Combustion
1.2.1 Genera!1"5
Coal is a complex combination of organic matter and inorganic ash formed over eons from
successive layers of fallen vegetation. Coals are classified by rank according to their progressive
alteration in the natural metamorphosis from lignite to anthracite. Coal rank depends on volatile
matter, fixed carbon, inherent moisture, and oxygen, although no one parameter defines rank.
Typically coal rank increases as the amount of fixed carbon increases and the amount of volatile
matter decreases.
Anthracite coal is a high-ranking coal with more fixed carbon and less volatile matter than
bituminous, subbituminous, or lignite varieties. Anthracite also has higher ignition and ash fusion
temperatures. In the U.S., nearly all anthracite is mined in northeastern Pennsylvania and consumed in
Pennsylvania and its surrounding states. The only significant amount of anthracite is used for
steam/electric production. Anthracite currently accounts for only a small fraction of the total quantity
of coal combusted in the U.S. The anthracite burned is primarily reclaim from old production as no
new anthracite is mined.
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 16
million tons of culm scattered in piles throughout northeastern Pennsylvania. The heating value of
culm is typically in the 2,500 to 5,000 British thermal units/pound (Btu/lb) range, as compared to
12,000 to 14,000 Btu/lb for anthracite coal.
1.2.2 Firing Practices6"8
Due to its low volatile matter content and non-clinkering characteristics, anthracite coal is
primarily 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 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 burn anthracite coal is the underfeed stoker. Various
types of underfeed stokers are used in industrial boiler applications but the most common for
anthracite coal firing is the single-retort side-dump stoker with stationary grates. In this unit, coal is
fed intermittently to the fuel bed by a ram. In very small units the coal is fed continuously by a
10/96
External Combustion Sources
1.2-1
-------
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 (OFA) is commonly used with underfeed stokers to provide combustion air and turbulence in the
flame zone directly above the active fuel bed.
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 in a wet-
bottom or dry-bottom mode; because of its high ash fusion temperature, anthracite coal is burned in
dry-bottom furnaces.
For anthracite culm, combustion in conventional boiler systems is difficult due to the fuel's
high ash content, high moisture content, and low heating value. However, the burning of culm in an
FBC system was demonstrated at a steam generation plant in Pennsylvania. The FBC system 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 in the bed. Fluidized beds can handle
fuels with moisture contents approaching 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 S02 formed by combustion of fuel
sulfur.
1.2.3 Emissions2,6,8
Emissions from coal combustion depend on coal type and composition, the design type and
capacity of the boiler, the firing conditions, load, the type of control devices, and the level of
equipment maintenance. Emissions from anthracite coal firing primarily include particulate matter
(PM), sulfur oxides (SOx), nitrogen oxides (NOx), and carbon monoxide (CO); and trace amounts of
organic compounds and trace elements.
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, fly ash reinjection,
etc.), and the ash content of the coal. PC-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 fly ash 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.
Sulfur Oxides -
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 SOx. SOx emissions are directly proportional to the sulfur content of fuel. Some minor
differences will occur from unit to unit, however, due to (1) ash partitioning between fly ash and
bottom ash and (2) the sodium content of the coal (which tends to react with and bind coal sulfur in
the bottom ash as sodium sulfite or sodium sulfate). For FBC boilers, SOx emissions are inversely
proportional, in general, to the molar ratio of calcium (in the limestone) to sulfur (in the fuel) added to
the bed.8
1.2-2
EMISSION FACTORS
10/96
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Q
Nitrogen Oxides -
NOx emissions are lower in traveling grate and underfeed stokers compared to PC-fired
boilers. Underfeed and traveling grate stokers have large furnace areas and consequently lower
volumetric- and surface area-based heat release rates. Lower heat release rates reduce peak
combustion temperatures and, hence, contribute to lower NOx emissions. In addition, the partially
staged combustion that naturally occurs in all stokers due to the use of underfire and overfire air
contributes to reduced NOx emissions relative to PC-fired units. The low operating temperatures
which characterize FBC boilers firing culm also favor relatively low NOx emissions. Reducing boiler
load tends to decrease combustion intensity which, in turn, leads to decreased NOx emissions for all
boiler types.
Carbon Monoxide -
CO and total organic compound (TOC) 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 PC-fired units and
higher for underfeed and overfeed stokers due to relative combustion efficiency levels.
1.2.4 Controls6,8
Controls on anthracite-fired boilers have mainly have been applied to reduce PM emissions.
The most efficient particulate controls—fabric filters, electrostatic precipitators (ESP), and scrubbers—
have been installed on large pulverized anthracite-fired boilers. In fabric filters (baghouses),
particulate-laden dust passes through a set of filters mounted inside the collector housing. Dust
particles in the inlet gas are collected on the filters by inertial impaction, diffusion, direct interception,
and sieving. The collection efficiencies of fabric filters or coal-fired boilers can exceed 99 percent.
Particulate collection in an ESP occurs in three steps: suspended particles are given an
electrical charge; the charged particles migrate to a collecting electrode of opposite polarity while
subjected to a diverging electric field; and the collected PM is dislodged from the collecting
electrodes. Removal of the collected PM is accomplished mechanically by rapping or vibrating the
collecting electrodes. When applied to anthracite coal-fired boilers, ESPs are only 90 to 97 percent
efficient, because of the characteristic high resistivity of low sulfur anthracite fly ash. It is reported
that higher efficiencies can be achieved using larger ESPs combined with flue gas conditioning.
The most widely used wet scrubbers for anthracite coal-fired boilers are venturi scrubbers. In
a typical venturi scrubber, the particle-laden gas first contacts the liquor stream in the core and throat
of the venturi section. The gas and liquid streams then pass through the annular orifice formed by the
core and throat, atomizing the liquid into droplets which are impacted by particles in the gas stream.
Impaction results mainly from the high differential velocity between the gas stream and the atomized
droplets. The droplets are then removed from the gas stream by centrifugal action in a cyclone
separator and (if present) a mist eliminator section.
Wet scrubbers have reported PM collection efficiencies of 90 percent or greater. Gaseous
emissions such as S02, NOx, CO, and organics may also be absorbed to a significant extent in a wet
scrubber. Operational problems can occur with wet scrubbers due to clogged spray nozzles, sludge
deposits, dirty recirculation water, improper water levels, and unusually low pressure drops.
Mechanical collectors, or cyclones, use centrifugal separation to remove PM from flue gas streams. At
the entrance of the cyclone, a spin is imparted to the particle-laden gas. This spin creates a centrifugal
force which causes the PM to move away from the axis of rotation and toward the walls of the
cyclone. Particles which contact the walls of the cyclone tube are directed to a dust collection hopper
10/96
External Combustion Sources
1.2-3
-------
where they are deposited. Mechanical collectors typically have PM collection efficiencies up to 80
percent.
Emission factors and ratings for criteria pollutants from anthracite coal combustion are given
in Tables 1.2-1, 1.2-2, and 1.2-3. Tables in this section present emission factors on a weight basis
(lb/ton). To convert to an energy basis (lb/MMBtu), divide by a heating value of 24.6 MMBtu/ton.
Cumulative particle size distribution data for uncontrolled and controlled boilers burning pulverized
anthracite coal are given in Table 1.2-4. Figure 1.2-1 presents cumulative size-specific emission
factors for stokers burning anthracite coal. Emission factors for speciated c-ganic compounds are
given in Table 1.2-5. Emission factors for TOCs and methane from burning anthracite are given in
Table 1.2-6. Emission factors for speciated metals from stoker boilers firing anthracite coal are given
in Table 1.2-7.
1.2.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
An SCC (A2104001000) was provided for residential space heaters.
Supplement B, October 1996
• Text was enhanced concerning anthracite coal.
• Text was enhanced concerning emissions of SOx, NOx, and CO.
• Text was added concerning PM and S02 controls.
• Emission factor tables were rearranged so that criteria pollutants appear first.
• Mathematical errors were corrected for CO, TOC, and mercury .
• Emission factors were corrected for speciated organic compounds.
1.2-4
EMISSION FACTORS
10/96
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Table 1.2-1. EMISSION FACTORS FOR SOx AND
NOx COMPOUNDS FROM UNCONTROLLED ANTHRACITE COAL C0MBUST0RS8
Source Category
SOx
NOx
Emission Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission Factor
(lb/ton)
EMISSION
FACTOR
RATING
Stoker-fired boilers0
(SCC 1-01-001-02, 1-02-001-04, 1-03-001-02)
FBC boilers'1
(no SCC)
Pulverized coal boilerse
(SCC 1-01-001-01, 1-02-001-01, 1-03-001-01)
Residential space heaters®
(SCC A2104001000)
39Sb B
2.9 E
39Sb B
39Sb B
9.0 C
1.8 E
18 B
3 B
a Units are lb of pollutant/ton of coal burned. To convert from lb/ton to kg/Mg. multiply by 0.5. SCC = Source Classification Code.
b S = weight percent sulfur. For example, if the sulfur content is 3.4%, then S = 3.4.
c References 9-10.
d Reference 11. FBC boilers burning culm fuel; all other sources burning anthracite coal.
e Reference 2.
-------
Table 1.2-2. EMISSION FACTORS FOR CO AND CARBON DIOXIDE (C02) FROM
UNCONTROLLED ANTHRACITE COAL COMBUSTORSa
CO
co2
Emission
EMISSION
Emission
EMISSION
Factor
FACTOR
Factor
FACTOR
Source Category
(lb/ton)
RATING
(lb/ton)
RATING
Stoker-fired boilers'5
0.6
B
5,680
C
(SCC 1-01-001-02,
1-02-001-04, 1-03-001-02)
FBC boilersc
0.6
E
ND
NA
(no SCC)
a Units are lb of pollutant/ton of coal burned. To convert from lb/ton to kg/Mg, multiply by 0.5. SCC
= Source Classification Code. ND = no data. NA = not applicable.
b References 2,9,12.
c Reference 11. FBC boilers burning culm fuel; all other sources burning anthracite coal.
1.2-6
EMISSION FACTORS
10/96
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Table 1.2-3, EMISSION FACTORS FOR PM AND LEAD (Pb) FROM UNCONTROLLED ANTHRACITE COAL COMBUSTORS3
Source Category
Filterable PM
Condensiblc PM
Pb
Emission
Factor (lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor (lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor (lb/ton)
EMISSION
FACTOR
RATING
Stoker-fired boilers'5
(SCC 1-01-001-02, 1-02-001-04,
1-03-001-02)
Hand-fired units'1 (SCC 1-02-002-07,
14)3-001-03)
0,8AC C
10 B
0.08A° C
ND NA
8.9 E-03 E
ND NA
a Units are lb of pollutant/ton of coal burned. To convert from lb/ton to kg/Mg, multiply by 0.5. SCC = Source Classification Code. ND =
no data.
NA = not applicable.
b References 9-10,13-14.
c A = ash content of fuel, weight %. For example, if the ash content is 5%, then A = 5.
d Reference 2.
-------
Table 1.2-4. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR DRY BOTTOM
BOILERS BURNING PULVERIZED ANTHRACITE COALa
EMISSION FACTOR RATING: D
Particle Sizeb
(pm)
Cumulative Mass % < Stated Size
Cumulative Emission Factor
As Fired0 (lb/ton)
Uncontrolled
Controlled*1
Uncontrolled
Controlledd
Multiple Cyclone
Baghouse
Multiple Cyclone
Baghouse
15
32
63
79
• 3.2Ae
1.26A
0.016A
10
23
55
67
2.3A
1.10A
0.013A
6
17
46
51
1.7A
0.92A
0.01 OA
2.5
6
24
32
0.6 A
0.48A
0.006A
1.25
2
13
21
0.2A
0.26A
0.004A
1.00
2
10
18
0.2A
0.20A
0.004A
0.625
1
7
f
0.1A
0.14A
f
TOTAL
100
100
100
10A
2A
0.02A
a Reference 15. Source Classification Codes are 1-01-001-01, 1-02-001-01, and 1-03-001-01.
k Expressed as aerodynamic equivalent diameter.
* Units are lb of pollutant/ton of coal burned. To convert from lb/ton to kg/Mg, multiply by 0.5.
Estimated control efficiency for multiple cyclone is 80%; for baghouse, 99.8%.
e A = coal ash weight %, as fired. For example, if ash content is 5%, then A = 5.
f Insufficient data.
-------
5
.S«P -
.18 3
J i
JJL
J_L
.1 .2 .4 .6 1 2 4 6 10 20 40 60 100
Particle diameter ( m)
Figure 1.2-1. Cumulative size-specific emission factors for traveling grate stokers
burning anthracite coal.
10/96
External Combustion Sources
1.2-9
-------
Table 1.2-5. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
FROM ANTHRACITE COAL COMBUSTORS3
EMISSION FACTOR RATING: E
Pollutant
Stoker-Fired BoiIersb
(SCC 1-01-001-02,
1-02-001-04,
1-03-001-02)
Residential Space Heatersc
(SCC A2-10-400-1000)
Emission Factor (lb/ton)
Emission Factor
Range (lb/ton)
Average Emission
Factor (lb/ton)
Acenaphthene
ND
1.1 E-05 - 2.9 E-05
2.2 E-05
Acenaphthylene
ND
1.1 E-05 - 2.2 E-04
8.6 E-05
Anthanthrene
ND
1.5 E-07 - 8.8 E-07
5.7 E-07
Anthracene
ND
7.0 E-06 - 3.7 E-05
2.5 E-05
Benzo(a)anthracene
ND
1.1 E-05 - 1.6 E-04
7.1 E-05
Benzo(a)pyrene
ND
3.1 E-06 - 7,0 E-06
5.3 E-06
Benzo(e)pyrene
ND
3.5 E-06 - 1.0 E-05
6.2 E-06
Benzo(g,h,i,) perylene
ND
3.1 E-06 - 9.5 E-06
5.5 E-06
Benzo(k)fluoranthrene
ND
1.1 E-05 -4.5 E-05
2.5 E-05
Biphenyl
2.5 E-02
ND
ND
Chrysene
ND
1.8 E-05 - 1.8 E-04
8.3 E-05
Coronene
ND
8.8 E-07 - 6.4 E-06
3.9 E-06
Fluoranthrene
ND
7.5 E-05 - 2.7 E-04
1.7 E-04
Fluorene
ND
7.0 E-06 - 4,1 E-05
2.5 E-05
lndeno(123-cd) perylene
ND
3.5 E-06 - 1.1 E-05
6.9 E-06
Naphthalene
1.3 E-01
7.0 E-06 - 4.8 E-04
2.2 E-04
Perylene
ND
6.1 E-07 - 1.8 E-06
1.2 E-06
Phenanthrene
6.8 E-03
7.1 E-05 - 3.4 E-04
2.4 E-04
Pyrene
ND
4.2 E-05 - 1.9 E-04
1.2 E-04
a Units are lb of pollutant/ton of anthracite coal burned.
0.5. SCC = Source Classification Code. ND = no data
o convert from lb/ton to kg/Mg, multiply by
b Reference 13.
c Reference 16.
1.2-10
EMISSION FACTORS
10/96
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Table 1.2-6. EMISSION FACTORS FOR TOC AND METHANE (CH4)
FROM ANTHRACITE COAL C0MBUST0RS3
EMISSION FACTOR RATING: E
Source Category
TOC Emission Factor
(lb/ton)
CH4 Emission Factor
(lb/ton)
Stoker fired boilersb
0.30
ND
(SCC 1-01-001-02,
1-02-001-04, 1-03-001-02)
Residential space heaters0 (A2-10-400-1000)
ND
8
a Units are lb of pollutant/ton of coal burned. To convert from lb/ton to kg/Mg, multiply by 0.5.
SCC = Source Classification Code. ND = no data.
b Reference 13.
c Reference 16.
Table 1.2-7. EMISSION FACTORS FOR SPECIATED METALS FROM ANTHRACITE COAL
COMBUSTION IN STOKER FIRED BOILERS3
EMISSION FACTOR RATING: E
Pollutant
Emission Factor Range (lb/ton)
Average Emission Factor (lb/ton)
Arsenic
BDL - 2.4 E-04
1.9 E-04
Antimony
BDL
BDL
Beryllium
3.0 E-05 - 5.4 E-04
3.1 E-04
Cadmium
4.5 E-05 - 1.1 E-04
7.1 E-05
Chromium
5.9 E-03 - 4.9 E-02
2.8 E-02
Manganese
9.8 E-04 - 5.3 E-03
3.6 E-03
Mercury
8,7 E-05 - 1.7 E-04
1.3 E-04
Nickel
7.8 E-03 - 3.5 E-02
2.6 E-02
Selenium
4.7 E-04 - 2.1 E-03
1.3 E-03
a Reference 13. Units are lb of pollutant/ton of coal burned. To convert from lb/ton to kg/Mg,
multiply by 0.5. Source Classification Codes are 1-01-001-02, 1-02-001-04, and 1-03-001-02.
BDL = below detection limit.
10/96
External Combustion Sources
1.2-11
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References For Section 1.2
1. Minerals Yearbook, 1978-79, Bureau of Mines, U. S. Department of the Interior, Washington.
DC, 1981.
2. Air Pollutant Emission Factors, APTD-0923, U. S. Environmental Protection Agency, Research
Triangle Park, NC, April 1970.
3. P. Bender, D. Samela, W. Smith, G. Tsoumpas, and J. Laukaitis, "Operating Experience at the
Shamokin Culm Burning Steam Generation Plant", Presented at the 76th Annual Meeting of the
Air Pollution Control Association, Atlanta, GA, June 1983.
4. Chemical Engineers' Handbook, Fourth Edition, J. Perry, Editor, McGraw-Hill Book Company,
New York, NY, 1963.
5. B. Bartok and A. F. Sarofim (Eds.), Fossil Fuel Combustion, A Source Book, John Wiley And
Sons, Inc., 1991, p.239.
6. Background Information Document For Industrial Boilers, EPA 450/3-82-006a, U. S.
Environmental Protection Agency, Research Triangle Park, NC, March 1982.
7. Steam; Its Generation And Use, Thirty-Seventh Edition, The Babcock & Wilcox Company, New
York, NY, 1963.
8. Emission Factor Documentation For AP-42 Section 1.2 — 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.
9. Source Sampling Of Anthracite Coal Fired Boilers, RCA-Electronic Components, Lancaster, PA,
Final Report, Scott Environmental Technology, Inc., Plumsteadville, PA, April 1975.
10. Source Sampling Of Anthracite Coal Fired Boilers, Shippensburg State College, Shippensburg,
PA, Final Report, Scott Environmental Technology, Inc, Plumsteadville, PA, May 1975.
11. Design, Construction, Operation, And Evaluation Of A Prototype Culm Combustion Boiler/Heater
Unit, Contract No. AC21-78ET12307, U. S. Dept. of Energy, Morgantown Energy Technology
Center, Morgantown, WV, October 1983.
12. Source Sampling Of Anthracite Coal Fired Boilers, West Chester State College, West Chester,
PA, Pennsylvania Department of Environmental Resources, Harrisburg, PA 1980.
13. Emissions Assessment Of Conventional Stationary Combustion Systems, EPA Contract
No. 68-02-2197, GCA Coip., Bedford, MA, October 1980.
14. Source Sampling Of Anthracite Coal Fired Boilers, Pennhurst Center, Spring City, PA, Final
Report, TRC Environmental Consultants, Inc., Weathersfield, CT, January 23, 1980.
15. Inhalable Particulate Source Category Report For External Combustion Sources, EPA Contract
No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985,
1.2-12
EMISSION FACTORS
10/96
-------
16. Characterization Of Emissions Of PAHs From Residential Coal Fired Space Heaters, Vermont
Agency of Environmental Conservation, 1983.
10/96
External Combustion Sources
1.2-13
-------
1.3 Fuel Oil Combustion
1.3.1 General1"3
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 being 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, and include kerosene and diesel fuels. Being more viscous and less volatile
than distillate oils, the heavier residual oils (Nos. 5 and 6) may need to be heated for ease of handling
and to facilitate proper atomization. Because residual oils are produced from the residue remaining
after the lighter fractions (gasoline, kerosene, and distillate oils) have been removed from the crude oil,
they contain significant quantities of ash, nitrogen, and sulfur. Residual oils are used mainly in utility,
industrial, and large commercial applications.
1.3.2 Firing Practices4
The major boiler configurations for fuel oil-fired combustors are watertube, firetube, cast iron,
and tubeless design. Boilers are classified according to design and orientation of heat transfer
surfaces, burner configuration, and size. These factors can all strongly influence emissions as well as
the potential for controlling emissions.
Watertube boilers arc used in a variety of applications ranging from supplying large amounts
of process steam to providing space heat for industrial facilities. In a watertube boiler, combustion
heat is transferred to water flowing through tubes which line the furnace walls and boiler passes. The
tube surfaces in the furnace (which houses the burner flame) absorb heat primarily by radiation from
the flames. The tube surfaces in the boiler passes (adjacent to the primary furnace) absorb heat
primarily by convective heat transfer.
Firetube boilers are used primarily for heating systems, industrial process steam generators,
and portable power boilers. In firetube boilers, the hot combustion gases flow through the tubes while
the water being heated circulates outside of the tubes. At high pressures and when subjected to large
variations in steam demand, firetube units are more susceptible to structural failure than watertube
boilers. This is because the high-pressure steam in firetube units is contained by the boiler walls
rather than by multiple small-diameter watertubes, which are inherently stronger. As a consequence,
firetube boilers are typically small and are used primarily where boiler loads are relatively constant.
Nearly all firetube boilers are sold as packaged units because of their relatively small size.
A cast iron boiler is one in which combustion gases rise through a vertical heat exchanger and
out through an exhaust duct. Water in the heat exchanger tubes is heated as it moves upward through
the tubes. Cast iron boilers produce low pressure steam or hot water, and generally burn oil or natural
gas. They are used primarily in the residential and commercial sectors.
Another type of heat transfer configuration used on smaller boilers is the tubeless design. This
design incorporates nested pressure vessels with water in between the shells. Combustion gases are
fired into the inner pressure vessel and are then sometimes recirculated outside the second vessel.
10/96
External Combustion Sources
1.3-1
-------
1.3.3 Emissions5
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 noncriteria
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 (S02) and particulate matter (PM) can also be obtained
from measurements taken upstream of APC equipment.
1.3.3.1 Particulate Matter Emissions6"15 -
Particulate matter emissions depend predominantly on the grade of fuel fired. Combustion of
lighter distillate oils results in significantly lower PM formation than does combustion of heavier
residua] oils. Among residual oils, firing of No. 4 or No. 5 oil 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 primarily comprises 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 are 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 particulate emissions in units firing No. 6 oil. At low load
(50 percent of maximum rating) conditions, particulate emissions from utility boilers may be lowered
by 30 to 40 percent and by as much as 60 percent from small industrial and commercial units.
However, no significant particulate emission reductions have been noted at low loads from boilers
firing any of the lighter grades. At very low load conditions (approximately 30 percent of maximum
rating), proper combustion conditions may be difficult to maintain and particulate emissions may
increase significantly.
1.3.3.2 Sulfur Oxides Emissions1"2'6"9'16 -
Sulfur oxides (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 S02. 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 S02, about 1 to 5 percent is
further oxidized to sulfur trioxide (S03), and 1 to 3 percent is emitted as sulfate particulate. S03
readily reacts with water vapor (both in the atmosphere and in flue gases) to form a sulfuric acid mist.
1.3.3.3 Nitrogen Oxides Emissions1"2'6"10'15'17"27 -
Oxides of nitrogen (NOx) 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 (N02). Test data have shown that for most external fossil fuel combustion systems,
over 95 percent of the emitted NOx is in the form of nitric oxide (NO). Nitrous oxide (N20) is not
included in NOx but has recently received increased interest because of atmospheric effects.
1.3-2
EMISSION FACTORS
10/96
-------
Experimental measurements of thermal N0X formation have shown that NOx concentration is
exponentially dependent on temperature, and proportional to N2 concentration in the flame, the square
root of 02 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.
Fuel nitrogen conversion is the more important NOx-forming mechanism in residual oil
boilers. It can account for 50 percent of the total NOx emissions from residual oil firing. The percent
conversion of fuel nitrogen to NOx varies greatly, however; typically from 20 to 90 percent of
nitrogen in oil is converted to NOx, Except in certain large units having unusually high peak flame
temperatures, or in units firing a low nitrogen content residual oil, fuel NOx generally accounts for
over 50 percent of the total NOx generated. Thermal fixation, on the 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 are usually smaller and have lower heat
release rates, the quantity of thermal NOx formed in them is less than that of larger units which
typically bum residual oil 28
A number of variables influence how much NOx is formed by these two mechanisms. One
important variable is firing configuration. NOx emissions from tangentialIy (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 (FGR), 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 oxide 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, only influence the NOx emissions of large oil-fired boilers. Low excess air-
firing is possible in many small boilers, but the resulting NOx reductions are less significant,
1.3.3.4 Carbon Monoxide Emissions29"32 -
The rate of carbon monoxide (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 than larger
combustors have; this leads to reduced flame temperature and combustion intensity and, therefore,
lower combustion efficiency.
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 (02) availability; poor fuel/air mixing; 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.
1.3.3.5 Organic Compound Emissions29"39 -
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
10/96
External Combustion Sources
1.3-3
-------
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
condensable organic compounds. Emissions of VOCs are primarily characterized by the criteria
pollutant class of unbumed vapor phase hydrocarbons. Unbumed 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 polynuelear
aromatic hydrocarbons (PAH or PNA). 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.
1.3.3.6 Trace Element Emissions29"32,40"44 -
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 III of the 1990 Clean Air Act
Amendments are considered. The quantity of trace elements entering the combustion device depends
solely on the fuel composition. The quantity of trace metals emitted from the source 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. In general, the quantity of
any given metal emitted depends on the physical and chemical properties of the element itself;
concentration of the metal in the fuel; the combustion conditions; and the type of particulate control
device used, and its collection efficiency as a function of particle size.
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 to describe this
partitioning have been developed. The classification scheme used by Baig, et al.44 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 emitted in the gas phase.
1.3-4
EMISSION FACTORS
10/96
-------
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, lower 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 02 concentrations is also expected to affect segregating metal emissions from
boilers with particle controls. Lower 02 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.
1.3.3.7 Greenhouse Gases45*50 -
Carbon dioxide (C02), methane (CH4), and nitrous oxide (N20) emissions are all produced
during fuel oil combustion. Nearly all of the fuel carbon (99 percent) in fuel oil is converted to C02
during the combustion process. This conversion is relatively independent of firing configuration.
Although the formation of CO acts to reduce C02 emissions, the amount of CO produced is
insignificant compared to the amount of C02 produced. The majority of the fuel carbon not converted
to C02 is due to incomplete combustion in the fuel stream.
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Formation of N20 is minimized when combustion
temperatures are kept high (above 1475°F) and excess air is kept to a minimum (less than 1 percent).
Additional sampling and research is needed to fully characterize N20 emissions and to understand the
N20 formation mechanism. Emissions can vary widely from unit to unit, or even from the same unit
at different operating conditions. Average emission factors based on reported test data have been
developed for conventional oil combustion systems.
Methane emissions vary with the type of fuel and firing configuration, but are highest during
periods of incomplete combustion or low-temperature combustion, such as the start-up or shut-down
cycle for oil-fired boilers. Typically, conditions that favor formation of N20 also favor emissions of
ch4.
1.3,4 Controls
Control techniques for criteria pollutants from fuel oil combustion may be classified into three
broad categories: fuel substitution, combustion modification, and postcombustion control. Emissions
of noncriteria pollutants such as particulate phase metals have been controlled through the use of post
combustion controls designed for criteria pollutants. Fuel substitution reduces S02 or N0X and
involves burning a fuel with a lower sulfur or nitrogen content, respectively. Particulate matter will
generally be reduced when a lighter grade of fuel oil is burned6,8' Combustion modification
includes any physical or operational change in the furnace or boiler and is applied primarily for NOx
control purposes, although for small units, some reduction in PM emissions may be available through
improved combustion practice. Postcombustion control is a device after the combustion of the fuel
and is applied to control emissions of PM, S02, and NOx.
10/96
External Combustion Sources
1.3-5
-------
1,3,4,1 Particulate Matter Controls51 -
Control of PM emissions from residential and commercial units is accomplished by improving
burner servicing and by incorporating appropriate equipment design changes to improve oil
atomization and con.bustion 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 condensable organic compound emissions are minimized. Particulate matter emissions are more a
result of emitted fly ash with a carbon component in such units. Therefore, postcombustion controls
(mechanical collectors, ESP, fabric filters, etc.) are necessary to reduce PM emissions from these
sources where local regulations dictate.
Mechanical collectors, a prevalent type of control device, are primarily useful in controlling
particulates generated during soot blowing, during upset conditions, or when a very dirty heavy oil is
fired. For these situations, high-efficiency cyclonic collectors can achieve up to 85 percent control of
particulate. Under normal firing conditions, or when a clean oil is combusted, cyclonic collectors are
not nearly so effective because of the high percentage of small particles (less than 3 micrometers in
diameter) emitted.
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.
In fabric filtration, a number of filtering elements (bags) along with a bag cleaning system are
contained in a main shell structure incorporating dust hoppers. The particulate removal efficiency of
the fabric filter system is dependent on a variety of particle and operational characteristics including
particle size distribution, particle cohesion characteristics, and particle electrical resistivity.
Operational parameters that affect collection efficiency include air-to-cloth ratio, operating pressure
loss, cleaning sequence, interval between cleaning, and cleaning intensity. The structure of the fabric
filter, filter composition, and bag properties also affect collection efficiency. Collection efficiencies of
baghouses may be more than 99 percent.
Scrubbing systems have also been installed on oil-fired boilers to control both sulfur oxides
and particulate. These systems can achieve S02 removal efficiencies of 90 to 95 percent and
particulate control efficiencies of 50 to 60 percent.
1.3.4 2 S02 Controls52"53 -
Commercialized postcombustion flue gas desulfurization (FGD) processes use an alkaline
reagent to absorb S02 in the flue gas and produce a sodium or a calcium sulfate compound. These
solid sulfate compounds are then removed in downstream equipment. Flue gas desulfurization
technologies are categorized as wet, semi-dry, or dry depending on the state of the reagent as it leaves
the absorber vessel. These processes are either regenerable (such that the reagent material can be
treated and reused) or 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.
1.3-6
EMISSION FACTORS
10/96
-------
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 on operating variables.
1.3.4.3 NOx Controls41'54"5 ' -
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 fuel NOx typically 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
nitrogen conversion which, in turn, increases fuel NOx. Thus, to reduce fuel NOx formation, the most
common combustion modification technique is to suppress combustion air levels below the theoretical
amount required for complete combustion. The lack of oxygen creates reducing conditions that, given
sufficient time at high temperatures, cause volatile fuel nitrogen to convert to N2 rather than NO.
Several techniques are used to reduce NOx emissions from fuel oil combustion. In addition to
fuel substitution, the primary techniques can be classified into one of two fundamentally different
methods — combustion controls and postcombustion controls. Combustion controls reduce NOx by
suppressing NOx formation during the combustion process while postcombustion controls reduce NOx
emissions after their formation. Combustion controls are the most widely used method of controlling
NOx formation in all types of boilers and include low excess air, burners out of service,
biased-burner firing, flue gas recirculation, overfire air, and low-NOx burners. Postcombustion control
methods include selective noncatalytic reduction (SNCR) and selective catalytic reduction (SCR).
These controls can be used separately, or combined to achieve greater NOx reduction.
Operating at low excess air involves reducing the amount of combustion air to the lowest
possible level while maintaining efficient and environmentally compliant boiler operation, NOx
formation is inhibited because less oxygen is available in the combustion zone. Burners out of service
involves withholding fuel flow to all or part of the top row of burners so that only air is allowed to
pass through. This method simulates air staging, or overfire air conditions, and limits NOx formation
by lowering the oxygen level in the burner area. Biased-burner firing involves firing the lower rows
of burners more fuel-rich than the upper row of burners. This method provides a form of air staging
and limits NOx formation by limiting the amount of oxygen in the firing zone. These methods may
change the normal operation of the boiler and the effectiveness is boiler-specific. Implementation of
these techniques may also reduce operational flexibility; however, they may reduce NOx by 10 to
20 percent from uncontrolled levels.
Flue gas recirculation involves extracting a portion of the flue gas from the economizer section
or air heater outlet and readmitting it to the furnace through the furnace hopper, the burner windbox,
or both. This method reduces the concentration of oxygen in the combustion zone and may reduce
NOx by as much as 40 to 50 percent in some boilers.
Overfire air is a technique in which a percentage of the total combustion air is diverted from
the burners and injected through ports above the top burner level. Overfire air limits NOx by
(1) suppressing thermal NOx by partially delaying and extending the combustion process resulting in
less intense combustion and cooler flame temperatures; (2) a reduced flame temperature that limits
thermal NOx formation, and/or (3) a reduced residence time at peak temperature which also limits
thermal NOx formation.
10/96
External Combustion Sources
1.3-7
-------
Low NOx burners are applicable to tangential and wall-fired boilers of various sizes. They
have been used as a retrofit NOx control for existing boilers and can achieve approximately 35 to
55 percent reduction from uncontrolled levels. They are also used in new boilers to meet NSPS limits.
Low NOx burners can be combined with ovcrfire air to achieve even greater NOx reduction (40 to 60
percent reduction from uncontrolled levels).
SNCR is a postcombustion technique that involves injecting ammonia or urea into specific
temperature zones in the upper furnace or convective pass. The ammonia or urea reacts with NOx in
the flue gas to produce nitrogen and water. The effectiveness of SNCR depends on the temperature
where reagents are injected; mixing of the reagent in the flue gas; residence time of the reagent within
the required temperature window; ratio of reagent to NOx; and the sulfur content of the fuel that may
create sulfur compound that deposit in downstream equipment. There is not as much commercial
experience to base effectiveness on a wide range of boiler types; however, in limited applications, NOx
reductions of 25 to 40 percent have been achieved.
SCR is another postcombustion technique that involves injecting ammonia into the flue gas in
the presence of a catalyst to reduce NOx to nitrogen and water. The SCR reactor can be located at
various positions in the process including before an air heater and particulate control device, or
downstream of the air heater, particulate control device, and flue gas desulfurization systems. The
performance of SCR is influenced by flue gas temperature, fuel sulfur content, ammonia to NOx ratio,
inlet NOx concentration, space velocity, and catalyst condition. NOx emission reductions of 75 to
85 percent have been achieved through the use of SCR on oil-fired boilers operating in the U.S.
Tables 1.3-1 and 1.3-2 present emission factors for uncontrolled criteria pollutants from fuel
oil combustion. Tables in this section present emission factors on a volume basis (lb/103gal). To
convert to an energy basis (lb/MMBtu). divide by a heating value of 150 MMBtu/I03gal for Nos. 4, 5,
6, and residual fuel oil, and 140 MMBtu/103gal for No. 2 and distillate fuel oil. Tables 1.3-3, 1.3-4,
1.3-5, and 1.3-6 present cumulative size distribution data and size-specific emission factors for
particulate emissions from uncontrolled and controlled fuel oil combustion. Figures 1.3-1, 1.3-2, 1.3-
3, and 1.3-4 present size-specific emission factors for particulate emissions from uncontrolled and
controlled fuel oil combustion. Emission factors for N20, POM, and formaldehyde are presented in
Table 1.3-7. Emission factors for speciated organic compounds are presented in Table 1.3-8.
Emission factors for trace elements are given in Table 1.3-9. Emission factors for metals are given in
Table 1.3-10. Default emission factors for C02 are presented in Table 1.3-11 A summary of various
S02 and NOx controls for fuel-oil-fired boilers is presented in Table 1.3-12 and 1.3-13, respectively.
1.3-8
EMISSION FACTORS
10/96
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1.3.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
The formulas presented in the footnotes for filterable PM were moved into the table.
For S02 and S03 emission factors, text was added to the table footnotes to clarify that
"S" is a weight percent and not a fraction. A similar clarification was made to the
CO and N0X footnotes. SCC A2104004/A2104011 was provided for residential
furnaces.
For industrial boilers firing No. 6 and No. 5 oil, the methane emission factor was
changed from 1 to 1.0 to show two significant figures.
For S02 and S03 factors, text was added to the table footnotes to clarify that "S" is a
weight percent and not a fraction.
• The N20, POM, and formaldehyde factors were corrected.
• Table 1.3-10 was incorrectly labeled 1.1-10. This was corrected.
Supplement B, October 1996
• Text was added concerning firing practices.
Factors for N20, POM, and formaldehyde were added.
New data for filterable PM were used to create a new PM factor for residential
oil-fired furnaces.
Many new factors were added for toxic organics, toxic metals from distillate oil, and
toxic metals from residual oil.
A table was added for new C02 emission factors.
10/96
External Combustion Sources
1.3-9
-------
U)
o
Table 1.3-1. CRITERIA POLLUTANT EMISSION FACTORS FOR UNCONTROLLED
FUEL OIL COMBUSTION3
m
(/i
on
^-1
§
TJ
>
o
-4
O
on
ON
so2b
so3c
NOxd
COc/
Filterable PM®
Firing Configuration
(SCC)'
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Utility boilers
No. 6 oil fired, normal firing
(1-01-004-01)
157S
A
5.7S
C
67
A
5
A
9.19(S)+3.22
A
No. 6 oil fired, tangential firing
(1-01-004-04)
157S
A
5.7S
C
42
A
5
A
9.19(S)+3.22
A
No. 5 oil fired, normal firing
(1-01-004-05)
157S
A
5.7S
C
67
A
5
A
10
B
No. 5 oil fired, tangential firing
(1-01-004-06)
157S
A
5.7S
C
42
A
5
A
10
B
No. 4 oil fired, normal firing
(1-01-005-04)
150S
A
5.7S
C
67
A
5
A
7
B
No. 4 oil fired, tangential firing
(1-01-005-05)
150S
A
5.7S
C
42
A
5
A
7
B
No. 6 oil fired (1-02-004-01/02/03)
157S
A
2S
A
55
A
5
A
9.I9(S)f3.22
A
No. 5 oil fired (1-02-004-04)
I57S
A
2S
A
55
A
5
A
10
B
Distillate oil fired
(1-02-005-01/02/03)
142S
A
2S
A
20
A
5
A
2
A
No. 4 oil fired (1-02-005-04)
150S
A
2S
A
20
A
5
A
7
B
Commercial/institutional
No. 6 oil fired (1-03-004-01/02/03)
157S
A
2S
A
55
A
5
A
9.19(S)+3,22
A
No. 5 oil fired (1-03-004-04)
157S
A
2S
A
55
A
5
A
10
B
Distillate oil fired
(1-03-005-01/02/03)
142S
A
2S
A
20
A
5
A
2
A
No. 4 oil fired (1-03-005-04)
150S
A
2S
A
20
A
5
A
7
B
Residential furnace
(A2104004/A2104011)
142S
A
2S
A
18
A
5
A
0.4h
B
-------
Table 1.3-1 (eont).
To convert from lb/103 gal to kg/103 L, multiply by 0.120, SCC = Source Classification Code,
References 1-2,6-9,14,56-60. S indicates that the weight % of sulfur in the oil should be multiplied by the value given. For example, if
the fuel is 1% sulfur, then S = 1.
References 1-2,6-8,16,57-60. S indicates that the weight % of sulfur in the oil should be multiplied by the value given. For example, if
the fuel is 1 % sulfur, then S = 1.
References 6-7,15,19,22,56-62. Expressed as N02. Test results indicate that at least 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 fall 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: lb N02 /103 gal = 20.54 + 104.39(N), where N is the weight % of nitrogen in
the oil. For example, if the fuel is 1% nitrogen, then N = 1.
References 6-8,14,17-19,56-61. CO emissions may increase by factors of 10 to 100 if the unit is improperly operated or not well
maintained.
Emission factors for C02 from oil combustion should be calculated using lb CO2/10 gal oil = 256C (Distillate), 286C (Residual), or 250C
(Kerosene) where C indicates weight % of carbon in the oil. For example, if the fuel is 86% carbon, then C = 86.
References 6-8,10,13-15,56-60,62-63. Filterable PM is that particulate collected on or prior to the filter of an EPA Method 5 (or
equivalent) sampling train. Particulate emission factors for residual oil combustion are, on average, a function of fuel oil sulfur content
where S is the weight % of sulfur in oil. For example, if fuel oil is 1% sulfur, then S = 1.
Based on data from new burner designs. Pre-1970's burner designs may emit filterable PM as high as 3,0 lb/103 gal.
-------
Table 1.3-2, EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS
(TOC), METHANE, AND NONMETHANE TOC (NMTOC) FROM UNCONTROLLED
FUEL OIL COMBUSTION8
EMISSION FACTOR RATING: A
Firing Configuration
(SCC)
TOCb
Emission
Factor
(lb/103 gal)
Methane15
Emission
Factor
(lb/103 gal)
NMTOCb
Emission
Factor
(lb/103 gal)
Utility boilers
No. 6 oil fired, normal firing (1-01-004-01)
1,04
0.28
0.76
No. 6 oil fired, tangential firing (1-01-004-04)
1.04
0.28
0.76
No. 5 oil fired, normal firing (1-01-004-05)
1,04
0.28
0.76
No. 5 oil fired, tangential firing (1-01-004-06)
1.04
0.28
0.76
No. 4 oil fired, normal firing (1-01-005-04)
1.04
0.28
0.76
No. 4 oil fired, tangential firing (1-01-005-05)
1.04
0.28
0.76
Industrial boilers
No. 6 oil fired (1-02-004-01/02/03)
1.28
1.00
0.28
No. 5 oil fired (1-02-004-04)
1.28
1.00
0.28
Distillate oil fired (1-02-005-01/02/03)
0.252
0.052
0.2
No. 4 oil fired (1-02-005-04)
0.252
0.052
0.2
Commercial/institutional/residential combustors
No. 6 oil fired (1-03-004-01/02/03)
1.605
0.475
1.13
No. 5 oil fired (1-03-004-04)
1.605
0.475
1.13
Distillate oil fired (1-03-005-01/02/03)
0.556
0.216
0.34
No. 4 oil fired (1-03-005-04)
0.556
0.216
0,34
Residential furnace (A2104004/A2104011)
2.493
1.78
0.713
® To convert from lb/10 gal to kg/10 L, multiply by 0.12. SCC = Source Classification Code.
References 29-32. Volatile organic compound emissions can increase by several orders of
magnitude if the boiler is improperly operated or is not well maintained.
1.3-12
EMISSION FACTORS
10/96
-------
Table 1.3-3. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS
FOR UTILITY BOILERS FIRING RESIDUAL OIL3
Cumulative Mass %
< Stated Size
Cumulative Emission Factor (lb/103 gal)
Controlled
Uncontrolled®
ESP Controlledd
Scrubber Controlled0
Particle
Size11
(Mm)
Uncon-
trolled
ESP
Scrubber
Emission
Factor
EMISSION
FACTOR
RATING
Emission
Factor
EMISSION
FACTOR
RATING
Emission
Factor
EMISSION
FACTOR
RATING
15
80
75
100
6.7A
C
0.05A
E
0.50A
D
10
71
63
100
5.9 A
C
0.042A
E
0.050A
D
6
58
52
100
4.8A
C
0.035A
E
0.50A
D
2.5
52
41
97
4.3A
C
0.028A
E
0.48A
D
1.25
43
31
91
3.6A
C
0.021 A
E
0.46A
D
1.00
39
28
84
3.3A
C
0.018A
E
0.42A
D
0.625
20
20
64
1.74
C
0.007A
E
0.32A
D
TOTAL
100
100
100
8.3A
C
0.067A
E
0.50A
D
d Reference 26. Source Classification Codes 1-01-004-01/04/05/06 and 1-01-005-04/05. To convert from lb/103 gal to kg/m% multiply by
0.120. ESP = electrostatic precipitator.
b Expressed as aerodynamic equivalent diameter.
c Particulate emission factors for residual oil combustion without emission controls are, on average, a function of fuel oil grade and sulfur
content where S is the weight % of sulfur in the oil. For example, if the fuel is 1.00% sulfur, then S = 1.
A = 9 19(S) + 3.22 lb/10 gal
A = 10 lb/103 gal
A = 7 lb/103 gal
d Estimated control efficiency for ESP is 99.2%.
e Estimated control efficiency for scrubber is 94%
No. 6 oil
No. 5 oil
No. 4 oil
-------
Table 1.3-4. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR INDUSTRIAL
BOILERS FIRING RESIDUAL OIL8
Particle
Sizeb
(Mm)
Cumulative Mass % < Stated Size
Cumulative Emission Factor0 (lb/103 gal)
Uncontrolled
Multiple Cyclone
Controlled
Uncontrolled
Multiple Cyclone ControlIedd
Emission Factor
EMISSION
FACTOR
RATING
Emission Factor
EMISSION
FACTOR
RATING
15
91
100
7.59A
D
1.67A
E
10
86
95
7.17A
D
1.58A
E
6
77
72
6.42A
D
1.17A
E
2.5
56
22
4.67A
D
0.33A
E
1.25
39
21
3.25A
D
0.33A
E
1.00
36
21
3.00A
D
0.33A
E
0.625
30
e
2.50A
D
e
NA
TOTAL
100
100
8.34A
D
1.67A
E
Reference 26. Source Classification Codes 1-02-004-01/02/03/04 and 1-02-005-04. To convert from lb/10 gal to kg/10 L, multiply by
0.120. NA = not applicable.
b Expressed as aerodynamic equivalent diameter.
c Particulate emission factors for residual oil combustion without emission controls are, on average, a function of fuel oil grade and sulfur
content where S is the weight % of sulfur in the oil. For example, if the fuel is 1.0% sulfur, then S = 1.
No. 6 oil: A = 9.19(S) + 3.22 lb/103 gal
No. 5 oil: A = 10 lb/103 gal
No. 4 oil: A = 7 lb/103 gal
d Estimated control efficiency for multiple cyclone is 80%.
e Insufficient data.
-------
Table 1.3-5. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND
SIZE-SPECIFIC EMISSION FACTORS FOR UNCONTROLLED INDUSTRIAL BOILERS FIRING
DISTILLATE OILa
EMISSION FACTOR RATING: E
Particle Sizeb Qim)
Cumulative Mass % < Stated Size
Cumulative Emission Factor
(lb/103 gal)
15
68
1.33
10
50
1.00
6
30
0.58
2.5
12
0.25
1.25
9
0.17
1.00
8
0.17
0.625
2
0.04
TOTAL
100
2.00
Reference 26. Source Classification Codes 1-02-005-01/02/03. To convert from lb/103 gal to
kg/10? L, multiply by 0.12.
b Expressed as aerodynamic equivalent diameter.
Table 1.3-6. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND
SIZE-SPECIFIC EMISSION FACTORS FOR UNCONTROLLED COMMERCIAL BOILERS
BURNING RESIDUAL OR DISTILLATE OILa
EMISSION FACTOR RATING: D
Cumulative Mass % < Stated Size
Cumulative Emission Factor0
(lb/103 gal)
Particle
Sizeh (pm)
Residual
Oil
Distillate
Oil
Residual
Oil
Distillate
Oil
15
78
60
6.50A
1.17
10
62
55
5.17A
1.08
6
44
49
3.67A
1.00
2.5
23
42
1.92A
0.83
1.25
16
38
1.33A
0.75
1.00
14
37
1.17A
0.75
0.625
13
35
1.08A
0.67
TOTAL
100
100
8.34 A
2.00
Reference 26. Source Classification Codes: 1-03-004-01/02/03/04 and 1-03-005-01/02/03/04. To
convert from lb/10 gal to kg/10 L, multiply by 0.12.
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 where S is the weight % of sulfur in the fuel. For
example,
No. 6 oil
No. 5 oil
No. 4 oil
No. 2 oil
if the fuel is 1.0% sulfur, then S
A = 9 19(S) + 3.22 lb/103 gal.
A = 10 lb/103 gal
A = 7 lb/103 gal
A = 2 lb/103 gal
1.
10/96
Externa] Combustion Sources
1.3-15
-------
1.0A
0.9A
0.8A
0.7A
0.6A
O.SA
0.4A
03A
02A
O.IA
0
'ii'it
Uncontrolled
Scrubber
J ' i i i 111
_l_
0.10A
0.09A
0.08A
0.07A
0.06A
0.05A
0.04A
0.03A
0.02A
0.01A
0
1
¦6
§
B -i
O.Ol A
0.006A
0.004A g
1
0.002A §
"¦5 ^
(B
K
0.001A ^ 2
0.0006A? 1
1
Q.P004A 8
B*
0.0002A w
0.0001 A
,4 .6 I 2 4 6 10 20
40 60 100
Particle diameter ( m)
Figure 1.3-1. Cumulative size-specific emission factors for utility boilers firing residual oil.
1.0A
0.9A
O.SA
0.7A
Q
0.6A
W
"sb
O.SA
0.4A
0.3A
0.2A
O.IA
OA
.1
Uncontrolled
J I I I I I I I
.4 .6 1
Multiple
cyclone
0.20A
0.18A
0.16A
0.14A
0.12A
0.1 OA
0.08A
0.06A
0.04A
0.02A
_ujJ i i - i I II
4 6 10 20
40
OA
60 100
Particle diameter ( m)
Figure 1.3-2. Cumulative size-specific emission factors for industrial boilers firing residual oil.
1.3-16
EMISSION FACTORS
10/96
-------
0.25
0.20
0.05
2
4 6 10 20 40 60 100
1
.4 .6 1
.2
Particle diameter ( m)
Figure 1.3-3. Cumulative size-specific emission factors for uncontrolled industrial boilers firing
distillate oil.
ra
o
y
*53
8
€
•5
1.00A
0.90A
0.80A
0.70A
I 3>0.60A
i
I 2 o.SOA
1 0.40 A
0.30A
0.20A
0.1 OA
0
"S
a
.1
Distillate oil
\
J i 11 II ll
Residual oil
I I I I I ll
_L
J L
.4 .6 1
0.25
0.20
0.15
0.10
0.05
0
4 6 10 20 40 60 100
Particle diameter ( m)
Figure 1.3-4. Cumulative size-specific emission factors for uncontrolled commercial boilers
burning residual and distillate oil.
10/96
External Combustion Sources
1.3-17
-------
Table 1.3-7. EMISSION FACTORS FOR NITROUS OXIDE (N20),
POLYCYCLIC ORGANIC MATTER (POM), AND FORMALDEHYDE (HCOH)
FROM FUEL OIL COMBUSTION8
EMISSION FACTOR RATING: E
Firing Configuration
(SCC)
Emission Factor (lb/103 gal)
N2Ob POMc HCOHc
Utility/industrial/commercial boilers
No. 6 oil fired
(1-01-004-01, 1-02-004-01, 1-03-004-01)
Distillate oil fired
(1-01-005-01, 1-02-005-01, 1-03-005-01)
Residential furnaces (A2104004/A2104011)
0.11 0.0011-0.0013d 0.024 - 0.061
0.11 0.0033® 0.035 - 0.061
0.05 ND ND
To convert from lb/10 gal to kg/10 L, multiply by 0.12. SCC = Source Classification Code.
ND = no data.
b References 45-46. EMISSION FACTOR RATING = B
c References 29-32.
d Particulate and gaseous POM.
e Particulate POM only.
1.3-18
EMISSION FACTORS
10/96
-------
Table 1.3-8. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
FROM FUEL OIL COMBUSTION3
Average Emission
EMISSION
Factorb
FACTOR
Organic Compound
(lb/103 Gal)
RATING
Benzene
2.14E-04
C
Ethylbenzene
6.36E-050
E
Formaldehyde*3
3.30E-02
C
Naphthalene
1.13E-03
C
1,1,1 -Triehioroethane
2.36E-040
E
Toluene
6.20E-03
D
o-Xylene
1.09E-04C
E
Acenaphthene
2.I1E-05
C
Acenaphthylene
2.53E-07
D
Anthracene
1.22E-06
C
Benz(a)anthracene
4.01E-06
C
Benzo(b,k)fluoranthene
1.48E-06
c
Benzo(g.h,i)perylene
2.26E-06
c
Chrysene
2.38E-06
c
Dibenzo(a,h) anthracene
1.67E-06
D
Fluoranthene
4.84E-06
C
Fluorene
4.47E-06
C
Indo( 1,2,3-cd)pyrene
2.14E-06
C
Phenanthrene
1.05E-05
C
Pyrene
4.25E-06
C
OCDD
3.10E-09C
E
1 1 1
a Data are for residual oil fired boilers, Source Classification Codes (SCCs) 1-01-004-01/04.
b References 64-72. To convert from lb/103 gal to kg/103 L, multiply by 0.12.
c Based on data from one source test (Reference 67).
d The formaldehyde number presented here is based only on data from utilities using No. 6 oil. The
number presented in Table 1.3-7 is based on utility, commercial, and industrial boilers.
10/96
External Combustion Sources
1.3-19
-------
Table 1.3-9. EMISSION FACTORS FOR TRACE ELEMENTS FROM DISTILLATE
FUEL OIL COMBUSTION SOURCES3
EMISSION FACTOR RATING: E
Firing Configuration
(SCC)
Emission Factor (lb/1012 Btu)
As
Be
Cd
Co
Cr
Hg
Mn
Ni
Pb
Sb
Se
Distillate oil fired
(1-01-005-01,
1-02-005-01,
1-03-005-01)
4.2
2.5
11
ND
48-67
3.0
14
18
8.9
ND
ND
a References 29-32,40-44. 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. To convert from lb/1012 Btu to pg/J, multiply by 0.43. SCC = Source Classification Code.
ND = no data.
-------
Table 1.3-10. EMISSION FACTORS FOR METALS FROM NO. 6 FUEL OIL COMBUSTION3
Metal
Average Emission Factor
(lb/103 Gal)
EMISSION FACTOR
RATING
Antimony
5.25E-03C
E
Arsenic
1.32E-03
C
Barium
2.57E-03
D
Beryllium
2.78E-05
C
Cadmium
3.98E-04
C
Chloride
3.47E-01
D
Chromium
8.45E-04
C
Chromium VI
2.48E-04
c
Cobalt
6.02E-03
D
Copper
1.76E-03
C
Fluoride
3.73E-02
D
Lead
1.51E-03
C
Manganese
3.00E-03
C
Mercury
1.13E-04
C
Molybdenum
7.87E-04
D
Nickel
8.45E-02
C
Phosphorous
9.46E-03
D
Selenium
6.83E-04
C
Vanadium
3.18E-02
D
Zinc
2.91E-02
D
a Data are for residual oil fired boilers, Source Classification Codes (SCCs) 1-01-004-01/04.
b References 64-72. To convert from lb/103 gal to kg/103 L, multiply by 0.12.
c References 29-32,40-44.
10/96
External Combustion Sources
1.3-21
-------
Table 1.3-11. DEFAULT C02 EMISSION FACTORS FOR LIQUID FUELS3
EMISSION FACTOR RATING: B
Fuel Type
%Cb
Densitvc
(lb/gal)
Emission Factor
(lb/103 gal)
No. 1 (kerosene)
No, 2
Low Sulfur No. 6
High Sulfur No. 6
86.25
87.25
87.26
85.14
6.88
7.05
7.88
7.88
21,500
22,300
25,000
24,400
a Based on 99% conversion ol
fuel carbon content to C02. To convert from lb/gal to gram/cm ,
multiply by 0.12. To convert from lb/103 gal to kg/m3, multiply by 0.12.
b Based on an average of fuel carbon contents given in references 73-74.
c References 73, 75.
1.3-22
EMISSION FACTORS
10/96
-------
Table 1.3-12. POSTCOMBUSTION S02 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%
5-430 MMBtu/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.
10/96
External Combustion Sources
1.3-23
-------
US
to
Table 1.3-13. N0V CONTROL OPTIONS FOR OIL-FIRED BOILERS3
m
S
55
C/3
IBM)
o
Z
TJ
>
o
3
?b
cn
Control Technique
Low Excess
Air (LEA)
Staged
Combustion
(SC)
Burners Out
of Service
(BOOS)
Flue Gas
Recirculation
(FGR)
Flue Gas
Recirculation
Plus Staged
Combustion
Description Of Technique
Reduction of combustion air
Fuel-rich firing burners with
secondary combustion air ports
One or more burners on air
only. Remainder of burners
firing fuel-rich
Recirculation of portion of flue
gas to burners
Combined techniques of FGR
and staged combustion
NOx Reduction Potential
(%)
Residual
Oil
Distillate
Oil
Oto 28
Oto 24
20 to 50
17 to 44
10 to 30
ND
15 to 30
58 to 73
25 to 53
73 to 77
Range Of
Application
Generally excess 02
can be reduced to
2.5% representing a
3% drop from
baseline
70-90% burner
stoichiometrics can
be used with proper
installation of
secondary air ports
Most effective on
boilers with 4 or
more burners in a
square pattern.
Up to 25-30% of
flue gas recycled.
Can be implemented
on most design
types.
Maximum FGR
rates set at 25% for
distillate oil and
20% for residual oil.
Commercial Availability/
R&D Status
Available for boilers with
sufficient operational
flexibility.
Technique is applicable on
packaged and field-erected
units. However, not
commercially available for
all design types.
Available.
Available. Best suited for
new units.
Available for boilers with
sufficient operational
flexibility.
Comments
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.
Requires careful selection of
BOOS pattern and control of
air flow. May result in boiler
de-rating unless fuel delivery
system is modified.
Requires extensive
modifications to the burner
and windbox. Possible flame
instability at high FGR rates.
May not be feasible on all
existing boiler types. Best
implemented on new units.
-------
Table 1.3-13 (cant ).
NOv Reduction Potential
(%)
Control Technique
Description Of Technique
Residual
Oil
Distillate
Oil
Range Of
Application
Commercial Availability/
R&D Status
Comments
Load Reduction
(LR)
Reduction of air and fuel flow
to all burners in service
33%
decrease to
25%
increase in
NOx
31%
decrease to
17%
increase in
NOx
Applicable to all
boiler types and
sizes. Load can be
reduced to 25% of
maximum.
Available in retrofit
applications.
Technique not effective when
it necessitates an increase in
excess 02 levels. LR
possibly implemented in new
designs as reduced
combustion intensity (i. e.,
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.
Commercially available.
Specific emissions data from
industrial boilers equipped
with LNB are lacking.
Reduced Air
Preheat (RAP)
Bypass of combustion air
preheater
5 to 16
ND
Combustion air
temperature can be
reduced to ambient
conditions.
Available.
Application of this technique
on new boilers requires
installation of alternate heat
recovery system (e, g„ an
economizer).
Selective
Noncatalytic
Reduction
(SNCR)
Injection of NH3 or urea as a
reducing agent in the flue gas
40 to 70
40 to 70
Applicable for large
packaged and field-
erected watcrtube
boilers. May not be
feasible for fire-tube
boilers.
Commercially offered but
not widely demonstrated on
large boilers.
Elaborate reagent injection,
monitoring, and control
system required. Possible
load restrictions on boilers
and air preheater f'ouli: g
when burning high sulfur oil.
Must have sufficient residence
time at correct temperature.
Conventional
Selective
Catalytic
Reduction (SCR)
Injections of NH3 in the
presence of a catalyst (usually
upstream of air heater).
Up to 90%
(estimated)
Up to 90%
(estimated)
Typically large
boiler designs
Commercially offered but
not widely demonstrated.
Applicable to most boiler
designs as a retrofit
technology or for new boilers.
-------
Table 1.3
-13 (cont.).
Control Technique
Description Of Technique
NOv Reduction Potential
(%)
Range Of
Application
Commercial Availability/
R&D Status
Comments
Residual
Oil
Distillate
Oil
Air Heater (SCR)
Duct SCR
Activated Carbon
SCR
Catalyst-coated baskets in the
air heater.
A smaller version of
conventional SCR is placed in
existing ductwork
Activated carbon catalyst,
installed downstream of air
heater.
40-65 40-65
(estimated) (estimated)
30 30
(estimated) (estimated)
ND ND
Boilers with
rotating-basket air
heaters
Typically large
boiler designs
Typically large
boiler designs
Available but not widely
demonstrated
Available but not widely
demonstrated.
Available but not widely
demonstrated.
Design must address pressure
drop and maintain heat
transfer.
Location of SCR in duct is
temperature dependent.
High pressure drop.
a ND = no data.
-------
References For Section 1.3
1. W. S. Smith, Atmospheric Emissions From Fuel Oil Combustion: An Inventory Guide,
999-AP-2, U, S. Environmental Protection Agency, Washington, DC, November 1962.
2. J. A. Danielson (ed ), Air Pollution Engineering Manual, Second Edition, AP-40,
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3. Fossil Fuel Fired Industrial Boilers — Background Information: Volume 1,
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March 1982.
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Park, NC, April 1993.
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Quality Standards", Code of Federal Regulations, Title 40, Part 50, U. S. Government Printing
Office, Washington DC, 1991.
6. A. Levy, et al., A Field Investigation Of Emissions From Fuel Oil Combustion For Space
Heating, API Bulletin 4099, Battelle Columbus Laboratories, Columbia, OH, November 1971.
7. R. E. Barrett, et al., 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.
8. G. A. Cato, et al., Field Testing: Application Of Combustion Modifications To Control
Pollutant Emissions From Industrial Boilers—Phase /, EPA-650/2-74-078a,
U. S. Environmental Protection Agency, Washington, DC, October 1974.
9. G. A. Cato, et al., Field Testing: Application Of Combustion Modifications To Control
Pollutant Emissions From Industrial Boilers—Phase II. EPA-600/ 2-76-086a,
U. S. Environmental Protection Agency, Washington, DC, April 1976,
10. Particulate Emission Control Systems For Oil Fired Boilers, EPA-450/3-74-063,
U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1974.
11. C. W. Siegmund, "Will Dcsulfurized Fuel Oils Help?", American Society Of Heating,
Refrigerating And Air Conditioning Engineers Journal, 11:29-33, April 1969.
12. F. A. Govan, et al., "Relationships of Particulate Emissions Versus Partial to Full Load
Operations for Utility-sized Boilers", Proceedings Of Third Annual Industrial Air Pollution
Control Conference, Knoxville, TN, March 29-30, 1973.
13. Emission Test Reports, Docket No. OAQPS-78-1, Category II-I-257 through 265, Office Of
Air Quality Planning And Standards, U. S. Environmental Protection Agency, Research
Triangle Park, NC, 1972 through 1974,
14. C. Leavitt, el al., Environmental Assessment Of An Oil Fired Controlled Utility Boiler,
EPA-600/7-80-087, U. S. Environmental Protection Agency, Washington, DC, April 1980.
10/96
External Combustion Sources
1.3-27
-------
15. W. A. Carter and R. J. Tidona, Thirty-day Field Tests of Industrial Boilers:
Site 2—Residual-oil-fired Boiler, EPA-600/7-80-085b, U. S. Environmental Protection Agency,
Washington, DC, April 1980.
16. Primary Sulfate Emissions From Coal And Oil Combustion, EPA Contract No. 68-02-3138,
TRW, Inc., Redondo Beach, CA, February 1980.
17. W. Bartok, et al., Systematic Field Study Of NOx Emission Control Methods For Utility
Boilers, APTD-1163, U. S. Environmental Protection Agency, Research Triangle Park, NC,
December 1971.
18. A. R. Crawford, et al,, Field Testing: Application Of Combustion Modifications To Control
NOx Emissions From Utility Boilers, EPA-650/2-74-066, U. S. Environmental Protection
Agency, Washington, DC, June 1974.
19. J. F. Deffner, et al., Evaluation Of Gulf Econojet Equipment With Respect To Air
Conservation, Report No. 731RC044, Gulf Research and Development Company,
Pittsburgh, PA, December 18, 1972.
20. C. E, Blakeslee and H E. Burbach, "Controlling NOx Emissions From Steam Generators,"
Journal Of The Air Pollution Control Association, 23:37-42, January 1973.
21. R. E. Hall, et al., A Study Of Air Pollutant Emissions From Residential Heating Systems,
EPA-650/2-74-003, U. S. Environmental Protection Agency, Washington, DC, January 1974.
22. R. J. Milligan, et al. Review Of NOx Emission Factors For Stationary Fossil Fuel Combustion
Sources, EPA-450/4-79-021, U. S. Environmental Protection Agency, Research Triangle Park,
NC, September 1979.
23. K. J. Lim, et al., Technology Assessment Report For Industrial Boiler Applications: NOx
Combustion Modification, EPA-600/7-79-178f, U. S. Environmental Protection Agency,
Washington, DC, December 1979.
24. D. W. Pershing, et al., Influence Of Design Variables On The Production Of Thermal And
Fuel NO From Residual Oil And Coal Combustion, Air: Control of NOx and SOx Emissions,
New York, American Institute of Chemical Engineers, 1975.
25. R. Clayton, et al., N20 Field Study, EPA-600/2-89-006, U. S. Environmental Protection
Agency, Research Triangle Park, NC, February 1989.
26. Evaluation Of Fuel-Based Additives For N20 And Air Toxic Control In Fluidized Bed
Combustion Boilers, EPRI Contract No. RP3197-02, Acurex Report No. FR-91-101-/ESD,
(Draft Report) Acurex Environmental, Mountain View, CA, June 17, 1991.
27. Code of Federal Regulations 40, Parts 53 to 60, July 1, 1991.
28. 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.
1.3-28
EMISSION FACTORS
10/96
-------
29. 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.
30. 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.
31. N. F. Suprenant, et al., Emissions Assessment Of Conventional Stationary Combustion System,
Volume IV: Commercial Institutional Combustion Sources, EPA Contract No. 68-02-2197,
GCA Corporation, Bedford, MA, October 1980.
32. N. F. Suprenant, et al., Emissions Assessment Of Conventional Stationary Combustion Systems,
Volume V: Industrial Combustion Sources, EPA Contract No. 68-02-2197,
GCA Corporation, Bedford, MA, October 1980.
33. Particulate Polycyclic Organic Matter, National Academy of Sciences, Washington, DC, 1972.
34. Vapor Phase Organic Pollutants—Volatile Hydrocarbons And Oxidation Products, National
Academy of Sciences, Washington, DC, 1976.
35. H. Knierien, A Theoretical Study Of PCB Emissions From Stationary Sources,
EPA-600/7-76-028, U. S. Environmental Protection Agency, Research Triangle Park, NC,
September 1976.
36. Estimating Air Toxics Emissions From Coal And Oil Combustion Sources, EPA-450/2-89-001,
U. S. Environmental Protection Agency, Research Triangle Park, NC, April 1989.
37. R. P. Hagebrauck, D. J. Von Lehmden, and J. E. Meeker, "Emissions of Polynuclear
Hydrocarbons and Other Pollutants from Heat-Generation and Incineration Process",
J. Air Pollution Control Assoc., 14:267-278, 1964.
38. M. B. Rogozen, et al., Formaldehyde: A Survey Of Airborne Concentration And Sources,
California Air Resources Board, ARB Report No. ARB/R-84-231, 1984.
39. Seeker, W.R, et al., Municipal Waste Combustion Study: Combustion Control OfMSW
Combustors To Minimize Emissions Of Trace Organics, EPA-543-SW-87-021c,
U. S. Environmental Protection Agency, Washington, D.C., May 1987.
40. 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.
41. K. J. Lim, et al., Industrial Boiler Combustion Modification NOx Controls - Volume I
Environmental Assessment, EPA-600/7-81-126a, U. S. Environmental Protection Agency, July
1981.
42. D. H. Klein, et al., "Pathways of Thirty-Seven Trace Elements Through Coal-Fired Power
Plants," Environ. Sci. Technol., 9:973-979, 1975.
43. D. G. Coles, et al., "Chemical Studies of Stack Fly Ash From a Coal-Fired Power Plant,"
Environ. Sci. Technol., 13:455-459, 1979.
10/96
External Combustion Sources
1.3-29
-------
44. S. Baig. et al., Conventional Combustion Environmental Assessment, EPA Contract
No. 68-02-3138, U. S. Environmental Protection Agency, Research Triangle Park, NC, 1981.
45. L. P. Nelson, et al., Global Combustion Sources of Nitrous Oxide Emissions, Research Project
2333-4 Interim Report, Sacramento: Radian Corporation.
46. R. L. Peer, et al., Characterization of Nitrous Oxide Emission Sources, Prepared for the
U. S. EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Corporation, 1995.
47. S. D. Piccot, et al., Emissions and Cost Estimates for Globally Significant Anthropogenic
Combustion Sources ofNOx N20, CH4, CO, and C02, EPA Contract No. 68-02-4288,
Research Triangle Park, NC: Radian Corporation, 1990.
48. G. Marland and R.M. Rotty, Carbon Dioxide Emissions from Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge, TN, 1983.
49. G. Marland and R.M. Rotty, Carbon Dioxide Emissions from Fossil Fuels: A Procedure For
Estimation And Results For 1950-1982, Tellus, 36B: 232-261.
50. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the
Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of
1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy.
51. 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.
52. 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.
53. EPA Industrial Boiler FGD Survey: First Quarter 1979, EPA-600/7-79-067b,
U. S. Environmental Protection Agency, April 1979.
54. J. H. Pohl and A.F. Sarofim, Devolatilization And Oxidation Of Coal Nitrogen (Presented At
The 16th International Symposium On Combustion), August 1976.
55. 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.
56. Environmental Assessment Of Coal And Oil Firing In A Controlled Industrial Boiler,
Volume I, PB 289942, U. S. Environmental Protection Agency, August 1978.
57. Environmental Assessment Of Coal And Oil Firing In A Controlled Industrial Boiler,
Volume 11, EPA-600/7-78-164b, U. S. Environmental Protection Agency, August 1978.
58. Environmental Assessment Of Coal And Oil Firing In A Controlled Industrial Boiler,
Volume 111, EPA-600/7-78-164c, U. S. Environmental Protection Agency, August 1978.
1.3-30 EMISSION FACTORS 10/96
-------
59. Emission Reduction On Two Industrial Boilers With Major Combustion Modifications.
EPA-600/7-78-099a, U. S, Environmental Protection Agency, August 1978.
60. Emission Reduction On Two Industrial Boilers With Major Combustion Modifications, Data
Supplement, EPA-600/7-78-099b, U. S. Environmental Protection Agency, August 1978.
61. Residential Oil Furnace System Optimization, Phase II, EPA-600/2-77-028,
U. S. Environmental Protection Agency, January 1977.
62. Characterization Of Particulate Emissions From Refinery Process Heaters And Boilers,
API Publication No. 4365, June 1983.
63. Industrial Boilers Emission Test Report, Boston Edison Company, Everett, Massachusetts,
EMB Report 81-IBR-15, U. S. Environmental Protection Agency, Office of Air Quality
Planning and Standards, October 1981.
64. Field Chemical Emissions Monitoring Project: Site 13 Emissions Monitoring, EPRI Project
RP3177-1, Radian Corporation, Austin, Texas, February, 1993.
65. Field Chemical Emissions Monitoring Project, Site 112 Emissions Report, Preliminary Draft,
Carnot. Tustin, California, February 24, 1994. (EPRI Report)
66. Field Chemical Emissions Monitoring Project: Emissions Report For sites 103 - 109,
Preliminary Draft Report, Radian Corporation, Austin, Texas, March 1993, (EPRI Report)
67. Field Chemical Emissions Monitoring Project: Site 118 Emissions Report, Preliminary Draft,
Camot, Tustin, California, January 20, 1994. (EPRI Report)
68. Emissions Inventory Testing at Long Beach Auxiliary Boiler for Southern California Edison
Company, Camot, May 1990.
69. Emission Inventory Testing at Alamitos Unit 5 for Southern California Edison Company,
Carnot, May 1990.
70. Air Toxic emissions Testing at Morro Bay Unit 3 for Pacific Gas and Electric Company,
Carnot, May 1990.
71. Emission Inventory Testing at El Segundo Generating Station 1, for Southern California
Edison Company, Carnot, April 1990.
72. Electric Utility Fuel Oil Fired Electric Utility- Boiler Emission Report, for Long Island
Lighting Corporation, Entropy Incorporated, April 1994.
73. Perry, Robert H. and Don Green (1984) Perry's Chemical Engineers'Handbook, Sixth ed.,
New York: McGraw Hill.
74. Steam: Its Generation and Use, Babcock and Wilcox, New York, 1975.
10/96 External Combustion Sources 1.3-31
-------
Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and Area Sources
(1995) U.S. Environmental Protection Agency, AP-42, Fifth Edition. Research Triangle
Park, NC.
EMISSION FACTORS
10/96
-------
1.4 Natural Gas Combustion
1.4.1 General1"2
Natural gas is one of the major fuels used throughout the country. It is used mainly for
industrial process steam and heat production; for residential and commercial space heating; and for
electric power generation. Natural gas consists of a high percentage of methane (generally above
85 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 Section 5.3, Natural Gas Processing). The
average gross heating value of natural gas is approximately 1020 British thermal units per standard
cubic foot (Btu/scf), usually varying from 950 to 1050 Btu/scf.
1 5
1.4.2 Firing Practices'
There are three major types of boilers used for natural gas combustion in the industrial,
commercial, and utility sectors: watertube. firetube, and cast iron. Natural gas is also used in
residential furnaces. Watertube boilers are designed to pass water through the inside of heat transfer
tubes while the outside of the tubes is heated by direct contact with the hot combustion gases. The
watertube design is the most common mechanism used for heat transfer in utility and large industrial
boilers. Watertube boilers are used for a variety of applications, ranging from the provision of large
amounts of process steam, to providing hot water or steam for space heating, to the generation of
high-temperature, high-pressure steam for electricity production.
In firetube boilers, the hot combustion gases flow through die tubes, and the water being
heated circulates outside of the tubes. These boilers are used primarily for heating systems, industrial
process steam, and portable power boilers. Firetube boilers are almost exclusively packaged units.
The two major types of firetube units are firebox boilers and Scotch Marine boilers.
In cast iron boilers, as in firetube boilers, the hot gases are contained inside the tubes and the
water being heated circulates outside the tubes. However, the units are constructed of cast iron rather
than steel. Virtually all cast iron boilers are constructed as package boilers. These boilers are used to
produce either low-pressure steam or hot water, and are most commonly used in small commercial
applications.
In residential furnaces, natural gas and air are combined in a burner and mixed to promote
efficient combustion. Combustion air is supplied by a small fan in forced air furnaces. Hot
combustion gases exchange heat with circulating air before being exhausted from a vent or chimney.
A variety of burner types may be used in residential furnaces, including single port, multiport, inshot,
ribbon, and slotted. Heat exchangers are typically of the sectional or drum types. Materials of
construction for burners and heat exchangers include cast iron, stamped steel, and tube steel.
1.4.3 Emissions3"4
Natural gas is considered to be one of the cleanest of the commonly used fossil fuels. The
emissions from natural gas-fired boilers and furnaces include nitrogen oxides (NOx), carbon
monoxide (CO), and carbon dioxide (C02), and trace amounts of sulfur dioxide (S02), particulate
matter (PM), organic compounds, and other greenhouse gases.
10/96
External Combustion Sources
1.4-1
-------
Nitrogen Oxides -
Nitrogen oxides are the major pollutants of concern when burning natural gas. NOx formed in
combustion processes are due either to thermal fixation of atmospheric nitrogen in the combustion air,
resulting in the formation of thermal NOx, or to the conversion of chemically bound nitrogen in the
fuel, resulting in fuel NOx. Due to its characteristically low fuel nitrogen content, nearly all NOx
emissions from natural gas combustion are thermal NQX. The formation of thermal NOx is affected by
four furnace-zone factors: (1) nitrogen concentration, (2) oxygen concentration, (3) peak temperature,
and (4) time of exposure at peak temperature. The emission trends due to changes in these factors are
fairly consistent for all types of natural gas-fired boilers and furnaces. 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).
Carbon Monoxide -
The rate of CO emissions from boilers depends on the efficiency of natural gas combustion.
In some cases, the addition of NOx control systems such as low NOx burners and flue gas recirculation
(FGR) will reduce combustion efficiency, resulting in higher CO (and trace organics) emissions
relative to uncontrolled boilers.
Sulfur Oxides -
Emissions of S02 from natural gas-fired boilers are low because natural gas typically contains
less than 0.1 percent sulfur. Sulfur-containing me reap tan, however, is added to natural gas for
detection purposes, leading to small amounts of S02 emissions.
Particulate Matter -
Because natural gas is a gaseous fuel, filterable particulate matter emissions are typically low.
Particulate matter (PM) from natural gas combustion has been estimated to be less than 1 micrometer
in size. Particulate matter is composed of filterable and condensable fractions, based on the EPA
Method 5. Filterable and condensable emission rates are of the same order of magnitude for boilers:
for residential furnaces, most of the PM is in the form of condensable material.
Organics -
The rate of trace organic emissions from boilers and furnaces also depends on combustion
efficiency. Organic emissions are minimized by combustion practices that promote high combustion
temperatures, long residence times at those temperatures, and turbulent mixing of fuel and combustion
air. Trace amounts of organic species in the natural gas fuel (e. g., ethylene and benzene) may also
contribute to organic species emissions if they are not completely combusted in the boiler.
Greenhouse Gases -6"11
Carbon dioxide (C02), methane (CH4), and nitrous oxide (N20) emissions are all produced
during natural gas combustion. In properly tuned boilers, nearly all of the fuel carbon (99 percent) in
natural gas is converted to C02 during the combustion process. This conversion is relatively
independent of firing configuration. Although the formation of CO acts to reduce C02 emissions, the
amount of CO produced is insignificant compared to the amount of C02 produced. The majority of
the fuel carbon not converted to C02 is due to incomplete combustion.
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Formation of N20 is minimized when combustion
temperatures are kept high (above 1475°F) and excess air is kept to a minimum (less than 1 percent).
1.4-2
EMISSION FACTORS
10/96
-------
Methane emissions are highest during periods of Iow4emperature combustion or incomplete
combustion, such as the start-up or shut-down cycle for boilers. Typically, conditions that favor
formation of N20 also favor emissions of CH4.
1.4.4 Controls4'12
NOx Controls -
Currently, the two most prevalent combustion 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 two most common types of low NOx burners being applied to natural gas-fired
boilers are staged air burners and staged fuel burners. NOx 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 (FGR) 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 comprises combustion products which act as inerts during combustion of the fuel/air mixture. This
additional mass is heated in the combustion zone, thereby lowering the peak flame temperature and
reducing the amount of NOx formed. To a lesser extent, FGR also reduces NOx formation by
lowering the oxygen concentration in the primary flame zone. The amount of flue gas recirculated is a
key operating parameter influencing NOx emission rates for these systems. Flue gas recirculation is
normally used in combination with specially designed low NOx burners capable of improved flame
holding. When used in combination, these techniques are capable of reducing uncontrolled NOx
emissions by 60 to 90 percent.
Two postcombustion technologies that may be applied to natural gas-fired boilers to reduce
NOx emissions by further amounts are selective noncatalytic reduction (SNCR) and selective catalytic
reduction (SCR). The SNCR system involves injecting ammonia (or urea) into combustion flue gases
(in a specific temperature zone) to reduce NOx emission. The SCR system involves injecting NH3 in
the presence of a catalyst to reduce NOx emissions.
Emission factors for natural gas combustion in boilers and furnaces are presented in
Tables 1.4-1, 1.4-2, 1.4-3, 1.4-4, and 1.4-5.13 Tables in this section present emission factors on a
volume basis (lb/106ft3). To convert to an energy basis (lb/MMBtu), divide by a heating value of
1000 MMBtu/106ft3. 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.
1.4.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
10/96
External Combustion Sources
1.4-3
-------
background report for t/jJs section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5v^2). or.on t\e new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
• The CO emission factor was changed from 27 to 15 lb/106 ft3.
Supplement B, October 1996
• Text was added concerning firing practices.
• Text was added concerning emissions of N0X, S0X, CO, C02, and organics.
• Text was added concerning controls from utility boilers.
• CO emission factors were updated for commercial LNB and N0X for large and small
industrial and utility boilers.
• The condensable PM emission factors was updated for small industrial and commercial
boilers, and the filterable PM emission factor was updated for residential boilers. A
C02 emission factor was added for utility boilers.
• In the table with N0X emission factors, the Low N0X burner factor for utility/large
industrial boilers changed from 81 to 79 lb/106 BTU, and the footnote for the
uncontrolled factor was corrected.
• Figure 1.4-1, the load reduction coefficient as a function of boiler load, was removed.
• N20 emission factors were added.
• New factors were added for toxic organic and toxic metals emissions.
1.4-4
EMISSION FACTORS
10/96
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Table 1.4-1. EMISSION FACTORS FOR SULFUR DIOXIDE (S02), NITROGEN OXIDES (NOx),
AND CARBON MONOXIDE (CO) FROM NATURAL GAS COMBUSTION3
so2b
NO
C
K
COd
N2Oe
Cornbustor Type
F, mission
EMISSION
Emission
EMISSION
Emission
EMISSION
Emission
EMISSION
(Size, I06 Btu/hr Heat Input)
Factor
FACTOR
Factor
FACTOR
Factor
FACTOR
Factor
FACTOR
(SCC)
(lb/106 ft3)
RATING
(lb/106 ft3)
RATING
(lb/106 ft3)
RATING
Ob/106 ft3)
RATING
Utility/large Industrial Boilers (> 100)
(1-01-006-01, 1-01-006-04)
Uncontrolled
0.6
A
550f
A
40
A
2.2
C
Controlled - Low NOx burners
0.6
A
79
D
ND
NA
0,64
E
Controlled - Flue gas recirculation
0.6
A
53
D
ND
NA
NA
NA
Small Industrial Boilers (10 - 100)
(1-02-006-02)
Uncontrolled
0.6
A
140
A
35
A
2.26
E
Controlled - Low NOx burners
0.6
A
83
D
61
D
0.64s
"7
Controlled - Flue gas recirculation
0.6
A
30
C
34
C
NA
NA
Commercial Boilers (0.3 - <10)
(1-03-006-03)
Uncontrolled
0.6
A
100
B
21
C
2.2®
E
Controlled - Low NOx burners
06
A
17
C
15
C
0.64s
E
Controlled - Flue gas recirculation
0.6
A
36
D
ND
NA
NA
NA
Residential Furnaces (<0.3)
(No SCC)
Uncontrolled
0.6
A
94
B
40
B
NA
NA
a Units are lb of pollutant/106 cubic feet natural gas fired. To convert from lb/106 ft3 tokg/106 rtr, multiply by 16.0. Based on an average
natural gas fired higher heating value of 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, SCC = Source
Classification Code. ND = no data. NA = not applicable.
b References 13-14. Based on average sulfur content of natural gas, 2000 gr/106 scf.
0 References 12-13,15-19. Expressed as N02.
d References 5,12-13,17-18,20-21.
e References 6-7.
f For tangentially fired units, use 275 lb/106 ft3. Note; This number was originally developed for AP-42 based on limited data. No
additional data are available to refine this number.
8 No data; based on the factors for utility boilers.
-------
i
OS
Table 1.4-2. EMISSION FACTORS FOR PARTICULATE MATTER (PM)
FROM NATURAL GAS COMBUSTION3
Combustor Type
(Size, 10® Btu/hr Heat Input)
(SCC)
Filterable PMb
Condensable PMC
Emission Factor
(lb/106 ft3)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/106 ft3)
EMISSION
FACTOR
RATING
Utilitv/largc industrial boilers (>100)
(1-0*1-006-01, 1-01-006-04)
Small industrial boilers (10 - 100)
(1-02-006-02)
Commercial boilers (0.3 - <10)
(1-03-006-03)
Residential furnaces (<0.3)
(No SCC)
1-5 B
6.2 B
4.5 C
0.17 C
ND NA
7.8 D
7.4 C
11 D
from lb/10" ft- to kg/10 m , multiply by 16,0. Based on an average natural gas higher heating value of 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. SCC = Source Classification Code. ND = no data. NA = not applicable.
Filterable PM is that particulate matter collected on or prior to the filter of an EPA Method 5 (or equivalent) sampling train.
Condensable PM is that particulate matter collected using EPA Method 202 (or equivalent). Total PM is the sum of the filterable PM and
condensable PM. All PM emissions can be assumed to be less than 10 micrometers in aerodynamic equivalent diameter (PM-10).
5
On
-------
Table 1.4-3. EMISSION FACTORS FOR CARBON DIOXIDE (C02) AND TOTAL ORGANIC COMPOUNDS (TOC) FROM NATURAL
GAS COMBUSTION3
Combustor Type
(Size, 106 Btu/hr Heat Input)
(SCC)
C02b
TOCc
Emission Factor
(lb/106 ft3)
EMISSION
FACTOR
RATING
Emission Factor
(lb/106 ft3)
EMISSION
FACTOR
RATING
Utility/large industrial boilers (>100)
(1-01 -006-01, 1-01-006-04)
Small industrial boilers (10 - 100)
(1-02-006-02)
Commercial boilers (0.3 - <10)
(1-03-006-03)
Residential furnaces
(No SCC)
1.2E+05 B
1.2E+05 B
I.2E+05 B
1.2 E+05 B
l.7d C
5,8e C
5.8 C
11 D
a All factors represent uncontrolled emissions. Units are lb of pollutant/106 cubic feet. To convert from lb/106 ft3 to kg/106 m \ multiply
by 16.0. Based on an average natural gas higher heating value of 1000 Btu/scf. The emission factors in this table may be converted to
other natural gas heating values by multiplying the given factor by the ratio of the specified heating value to this average heating value.
SCC = Source Classification Code. ND = no data. NA = not applicable.
b References 8,15,27-29.
c References 5,13,15,30,
d Reference 30: methane comprises 17% of organic compounds.
e Reference 30: methane comprises 52% of organic compounds.
-------
Table 1.4-4. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS
FROM NATURAL GAS COMBUSTION3
Organic Compound
Average Emission Factor
(lb/million ft3)
Emission Factor Rating
Formaldehyde
1.55E-01b
C
Toluene
2.20E-03C
E
2-Methvlnaphthalene
9.02E-06C
E
Naphthalene
2.40E-04C
E
Fluoranthene
3.01E-06C
E
Phenanthrene
1.00E-050
E
Pyrene
5.01E-06C
E
a Data are based on boilers that were both controlled and uncontrolled for criteria pollutant emissions.
Source Classification Codes 1-01-006-01, 1-01-006-04. To convert from lb/million ft3 to
kg/million irr, multiply by 16.0.
b References 31-36.
c Reference 32. Based on data from one source test.
Table 1.4-5. EMISSION FACTORS FOR METALS FROM NATURAL GAS COMBUSTION3
EMISSION FACTOR RATING; E
Metal
K 'J
Average Emission Factor (lb/million ft )
Arsenic
2.30E-04
Barium
2.40E-03
Chromium
1.10E-03
Cobalt
1.20E-04
Copper
2.51E-04
Lead
2.71E-04
Manganese
3.81E-04
Molybdenum
5.81E-04
Nickel
3.61E-03
Vanadium
3.21E-03
a Data are for natural gas boilers controlled with overfire air and flue gas recirculation.
Source Classification Codes 1-01-006-04.
b Reference 32. Based on data from one source test. To convert from lb/million ft3 to kg/million m3,
multiply by 16.0.
1.4-8
EMISSION FACTORS
10/96
-------
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. J. L. Muhlbaier, "Particulate and Gaseous Emissions From Natural Gas Furnaces and Water
Heaters". Journal Of The Air Pollution Control Association, December 1981.
6. L P. Nelson, et al, Global Combustion Sources Of Nitrous Oxide Emissions, Research Project
2333-4 Interim Report, Sacramento: Radian Corporation, 1991.
7. R. L. Peer, et al.. Characterization Of Nitrous Oxide Emission Sources, Prepared for the
U. S. EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Coiporation, 1995.
8. S. D. Piccot, et al., Emissions and Cost Estimates For Globally Significant Anthropogenic
Combustion Sources Of NOr N20, CH4, CO, and C02. EPA Contract No. 68-02-4288,
Research Triangle Park, NC: Radian Corporation, 1990.
9. G. Marland and R.M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge, TN, 1983.
10. G. Marland and R.M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1950-1982, Tellus, 36B: 232-261.
11. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the
Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of
1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy.
12. 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.
13. 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.
14. Systematic Field Study of NOx Emission Control Methods For Utility Boilers, APTD-1163,
U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1971.
10/96
External Combustion Sources
1.4-9
-------
15. 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.
16. Emissions Test on 200 HP Boiler At Kaiser Hospital in Woodland Hills, Energy Systems
Associates, Tustin, CA, June 1986.
17. Results From Performance Tests: California Milk Producers Boiler No. 5, Energy Systems
Associates, Tustin, CA, November 1984.
18. Source Test For Measurement Of Nitrogen Oxides And Carbon Monoxide Emissions From
Boiler Exhaust At GAF Building Materials, Pacific Environmental Services. Inc., Baldwin
Park, CA, May 1991.
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. 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.
23. 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.
24. 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.
25. N. F. Suprenant, et al., Emissions Assessment Of Conventional Stationary Combustion Systems,
Volume V: Industrial Combustion Sources, EPA Contract No. 68-02-2197, GCA Corporation,
Bedford, MA, October 1980.
26. 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.
27. Private communication from Kim Black (Industrial Combustion) to Ralph Harris (MRI),
Independent Third Party Source Tests, February 7, 1992.
28. Ortech Corporation (1994) Inventory Methods Manual for Estimating Canadian Emissions of
Greenhouse Gases, Prepared for Environment Canada.
29. A. Rosland, Greenhouse Gas Emissions In Norway: Inventories And Estimation Methods,
Oslo: Ministry of Environment, 1993.
1.4-10 EMISSION FACTORS 10/96
-------
30. Compilation Of Air Pollutant Emission Factors, Fourth Edition, AP-42, U. S. Environmental
Protection Agency, Research Triangle Park, NC, September 1985,
31. Field Chemical Emissions Monitoring Project: Emissions Report For sites 103 - 109.
Preliminary- Draft Report, Radian Corporation, Austin, Texas, March 1993. (EPRI Report)
32. Field Chemical Emissions Monitoring Project Site 120 Emissions Report, Preliminary Draft.
Carnot, Tustin, California, February 24, 1995. (EPRI Report)
33. Emissions Inventory Testing at Long Beach Auxiliary Boiler for Southern California Edison
Company, Carnot, May 1990.
34. Emissions Inventory Testing at Alamitos Unit 5 for Southern California Edison Company,
Carnot, May 1990.
35. Air Toxic Emissions Testing at Morro Bay unit 3 for Pacific Gas and Electric Company,
Carnot, May 1990.
36. Emission Inventory Testing at El Segundo Generating Station No. 1 for Southern California
Edison Company, Carnot, April 1990.
10/96
External Combustion Sources
1.4-11
-------
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 composed primarily of 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 90,500 British thermal units per gallon (Btu/gal), after
vaporization; for commercial-grade butane, the value is 97,400 Btu/gal.
The largest market for LPG is the domestic/commercial market, followed by the chemical
industry (where it is used as a petrochemical feedstock) and the agriculture industry. Propane is also
used as an engine fuel as an alternative to gasoline and as a standby fuel for facilities that have
interruptible natural gas service contracts.
1.5.2 Firing Practices2
The combustion processes that use LPG are very similar to those that use natural gas. Use of
LPG in commercial and industrial applications may require a vaporizer to provide the burner with the
proper mix of air and fuel. The burner itself will usually have different fuel injector tips as well as
different fucl-to-air ratio controller settings than a natural gas burner since the LPG stoichiometric
requirements arc different than natural gas requirements. LPG is fired as a primary and backup fuel in
small commercial and industrial boilers and space heating equipment and can be used to generate heat
and process steam for industrial facilities and in most domestic appliances that typically use natural
gas,
1.5.3 Emissions',3"5
1.5.3.1 Criteria Pollutants -
LPG is considered a "clean" fuel because it does not produce visible emissions. However,
gaseous pollutants such as nitrogen oxides (NOx), carbon monoxide (CO), and organic compounds are
produced as are small amounts of sulfur dioxide (S02) and particulate matter (PM). The most
significant factors affecting NOx, CO, and organic emissions are burner design, burner adjustment,
boiler operating parameters, and flue gas venting. Improper design, blocking and clogging of the flue
vent, and insufficient combustion air result in improper combustion and the emission of aldehydes,
CO, hydrocarbons, and other organics. NOx emissions are a function of a number of variables,
including temperature, excess air. fuel and air mixing, and residence time in the combustion zone. The
amount of S02 emitted is directly proportional to the amount of sulfur in the fuel. PM emissions are
very low and result from soot, aerosols formed by condensable emitted species, or boiler scale
dislodged during combustion. Emission factors for LPG combustion are presented in Table 1.5-1.
Table 1.5-1 presents emission factors on a volume basis (lb/103gal). To convert to an energy-
basis (lb/MMBtu), divide by a heating value of 91.5 MMBtu/103gal for propane and 102
MMBtu/103gal for butane.
10/96
External Combustion Sources
1.5-1
-------
1,5.3,2 Greenhouse Gases6"11 -
Carbon dioxide (C02), methane (CH4), and nitrous oxide (N20) emissions are all produced
during LPG combustion. Nearly all of the fuel carbon (99.5 percent) in LPG is converted to C02
during the combustion process. This conversion is relatively independent of firing configuration.
Although the formation of CO acts to reduce C02 emissions, the amount of CO produced is
insignificant compared to the amount of C02 produced. The majority of the 0.5 percent of fuel carbon
not converted to C02 is due to incomplete combustion in the fuel stream.
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Formation of N20 is minimized when combustion
temperatures are kept high (above 1475°F) and excess air is kept to a minimum (less than 1 percent).
Methane emissions are highest during periods of low-temperature combustion or incomplete
combustion, such as the start-up or shut-down cycle for boilers. Typically, conditions that favor
formation of N20 also favor emissions of CH4.
1.5.4 Controls
The only controls developed for LPG combustion are to reduce N0X emissions. N0X controls
have been developed for firetube and watertube boilers firing propane or butane. Vendors are now
guaranteeing retrofit systems to levels as low as 30 to 40 ppm (based on 3 percent oxygen). These
systems use a combination of Iow-NOx burners and flue gas recirculation (FGR). Some burner
vendors use water or steam injection into the flame zone for N0X reduction. This is a trimming
technique which may be necessary during backup fuel periods because LPG typically has a higher
NOx-forming potential than natural gas; conventional natural gas emission control systems may not be
sufficient to reduce LPG emissions to mandated levels. Also, LPG burners are more prone to sooting
under the modified combustion conditions required for low NOx emissions. The extent of allowable
combustion modifications for LPG may be more limited than for natural gas.
One NOx control system that has been demonstrated on small commercial boilers is FGR.
NOx emissions from propane combustion can be reduced by as much as 50 percent by recirculating
about 16 percent of the flue gas. NOx emission reductions of over 60 percent have been achieved
with FGR and low-NOx burners used in combination.
1.5.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
No changes.
Supplement B, October 1996
• Text was added concerning firing practices.
• The C02 emission factor was updated.
• Emission factors were added for N20 and CH4.
1.5-2
EMISSION FACTORS
10/96
-------
Table 1.5-1. EMISSION FACTORS FOR LPG COMBUSTION3
EMISSION FACTOR RATING: E
Butane Emission Factor
(lb/103 gal)
Propane Emission Factor
(lb/103 gal)
Pollutant
Industrial Boilers
(SCC 1-02-010-01)
Commercial
Boilers6
(SCC 1-03-010-01)
Industrial Boilers1'
(SCC 1-02-010-02)
Commercial
Boilersc
(SCC 1-03-010-02)
PM*3
0.6
0.5
0.6
0.4
so2e
0.09S
0.09S
0.10S
0.10S
NO/
21
15
19
14
N2OS
0.9
0.9
0.9
0,9
C02Kj
14,300
14,300
12,500
12,500
CO
3.6
2.1
3.2
1.9
TOC
0.6
0.6
0.5
0.5
o
X
J*
7?
0,2
0.2
0.2
0.2
a Assumes emissions (except SOx and NOx) are the same, on a heat input basis, as for natural gas
combustion. The NOx emission factors have been multiplied by a correction factor of 1.5, which is
the approximate ratio of propane/butane NOx emissions to natural gas NOx emissions. To convert
from lb/103 gal to kg/10" L. multiply by 0.12. SCC = Source Classification Code.
b Heat input capacities generally between 10 and 100 million Btu/hour.
c Heat input capacities generally between 0.3 and 10 million Btu/hour.
d Filterable particulate matter (PM) is that PM collected on or prior to the filter of an EPA Method 5
(or equivalent) sampling train. For natural gas, a fuel with similar combustion characteristics, all
PM is less than 10 (am in aerodynamic equivalent diameter (PM-10).
e S equals the sulfur content expressed in gr/100 ft3 gas vapor. For example, if the butane sulfur
content is 0.18 gr/100 ft3, the emission factor would be (0.09 x 0.18) = 0.016 lb of SO2/103 gal
butane burned.
f Expressed as NO,
g Reference 12,
h Assuming 99,5% conversion of fuel carbon to C02
j EMISSION FACTOR RATING = C.
k Reference 13.
10/96
External Combustion Sources
1.5-3
-------
References For Section 1,5
1. Written Communication from W. Butterbaugh of the National Propane Gas Association, Lisle,
Illinois, to J, McSorley of the U. S. Environmental Protection Agency, Research Triangle Park,
NC, August 19, 1992.
2. Emission Factor Documentation for AP-42 Section 1.5. Liquefied Petroleum Gas Combustion.
April 1993.
3. Air Pollutant Emission Factors, Final Report, Contract No. CPA-22-69-119, Resources
Research, Inc., Reston, VA, Durham, NC, April 1970.
4. Nitrous Oxide Reduction With The Weishaupt Flue Gas Recirculation System, Weishaupt
Research and Development Institute, January 1987.
5. Phone communication memorandum of conversation between B. Lusher of Acurex
Environmental and D. Childress of Suburban/Petrolane, Durham, NC, May 14, 1992.
6. L. P. Nelson, el al., Global Combustion Sources Of Nitrous Oxide Emissions, Research Project
2333-4 Interim Report, Radian Corporation, Sacramento. CA, 1991.
7. R. L. Peer, et al, Characterization Of Nitrous Oxide Emission Sources, EPA Contract No. 68-
D1-0031, Research Triangle Park, NC, 1995.
8. S. D. Piccot, el al., Emissions And Cost Estimates For Globally Significant Anthropogenic
Combustion Sources Of NOr N20. CH4, CO, And C02. EPA Contract No. 68-02-4288,
Research Triangle Park, NC, 1990.
9. G. Marland and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge, TN, 1983.
10. G. Marland and R.M. Rotty. Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1950-1982, Tellus, 36B: 232-261.
11. Sector-Specific Issues And Reporting Methodologies Supporting The General Guidelines For
The Voluntary Reporting Of Greenhouse Gases Under Section 1605(b) Of The Energy Policy
Act Of 1992. Volume 2 of 3, DOE/PO-0028, U.S. Department of Energy, 1994.
12. A. Rosland, Greenhouse Gas Emissions In Norway: Inventories And Estimation Methods,
Ministry of Environment, Oslo, Norway, 1993.
13. Inventory Methods Manual For Estimating Canadian Emissions Of Greenhouse Gases,
Prepared for Environment Canada by Ortech Corporation, 1994.
1.5-4
EMISSION FACTORS
10/96
-------
1.6 Word Waste Combustion In Boilers
1.6.1 General1"5
Hie 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, bark,
sawdust, shavings, chips, mill rejects, sanderdust, or wood trim. Heating values for this waste range
from about 4,000 to 5,000 British thermal units/pound (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 1.0 x 1011 Btu/hour.
c n
1.6.2 Firing Practices
Various boiler firing configurations are used for burning wood waste. One common type of
boiler used in smaller operations is the Dutch oven. This unit is widely used because it can burn fuels
with very high moisture content. Fuel is fed into the oven through an opening in the top of a
refractory-lined furnace. The fuel accumulates in a cone-shaped pile on a flat or sloping grate.
Combustion is accomplished in two stages: (1) drying and gasification, and (2) combustion of gaseous
products. The first stage takes place in the primary furnace, which is separated from the secondary
furnace chamber by a bridge wall. Combustion is completed in the secondary chamber before gases
enter the boiler section. The large mass of refractory helps to stabilize combustion rates but also
causes a slow response to fluctuating steam demand.
In another boiler type, the fuel cell oven, fuel is dropped onto suspended fixed grates and is
fired in a pile. Unlike the Dutch oven, the refractory-lined fuel cell also uses combustion air
preheating and positioning of secondary and tertiary air injection ports to improve boiler efficiency.
Because of their overall design and operating similarities, however, fuel cell and Dutch oven boilers
have comparable emission characteristics.
The firing method most commonly employed for wood-fired boilers with a steam generation
rate larger than 100,000 lb/hr is the spreader stoker. In this boiler type, wood enters the furnace
through a fuel chute and is spread either pneumatically or mechanically across the furnace, where
small pieces of the fuel burn while in suspension. Simultaneously, larger pieces of fuel are spread in a
thin, even bed on a stationary or moving grate. The burning is accomplished in three stages in a
single chamber: (1) moisture evaporation; (2) distillation and burning of volatile matter; and
(3) burning of fixed carbon. This type of boiler has a fast response to load changes, has improved
combustion control, and can be operated with multiple fuels. Natural gas, oil, and/or coal, are often
fired in spreader stoker boilers as auxiliary fuels. The fossil fuels are fired to maintain constant steam
when the wood waste moisture content or mass rate fluctuates and/or to provide more steam than can
be generated from the waste supply alone. Although spreader stokers are the most common stokers
among larger wood-fired boilers, overfeed and underfeed stokers arc also utilized for smaller units.
10/96
External Combustion Sources
1.6-1
-------
Another boiler type sometimes used for wood combustion is the suspension-fired boiler. This
boiler differs from a spreader stoker in that small-sized fuel (normally less than 2 mm) is blown into
the boiler and combusted by supporting it in air rather than on fixed grates. Rapid changes in
combustion rate and, therefore, steam generation rate are possible because the finely divided fuel
particles burn very quickly.
A recent innovation 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 the emissions of unbumed organic
compounds.
1.6.3 Emissions And Controls6*"
The major emission of concern from wood boilers is particulate matter (PM), although other
pollutants, particularly carbon monoxide (CO), volatile organic compounds (VOC), and oxides of
nitrogen (NOx) may be emitted in significant quantities when certain types of wood waste are
combusted or when operating conditions are poor. These emissions depend on a number of variables,
including (1) the composition of the waste fuel burned, (2) furnace design and operating conditions,
and (3) the degree of flyash reinjection employed.
1.6.3.1 Criteria Pollutants
The composition of wood waste and the characteristics of the resulting emissions depend
largely on the industry from which the wood waste originates. Pulping operations, for example,
produce great quantities of bark that may contain more than 70 weight percent moisture, sand, and
other non-combustibles. As a result, bark boilers in pulp mills may emit considerable amounts of
particulate matter to the atmosphere unless they are controlled. On the other hand, some operations,
such as furniture manufacturing, generate a clean, dry wood waste (2 to 20 weight percent moisture)
which produces relatively low particulate emission levels when properly burned. Still other operations,
such as sawmills, burn a varying mixture of bark and wood waste that results in PM emissions
somewhere between these two extremes. Additionally, NQX emissions from bark boilers are typically
low in comparison to NOx emissions from sanderdust-fired boilers at urea formaldehyde process
particleboard plants.
Furnace design and operating conditions are particularly important when firing wood waste.
For example, because of the high moisture content that may be present in wood waste, a larger than
usual area of refractory surface is often necessary to dry the fuel before combustion. In addition,
sufficient secondary air must be supplied over the fuel bed to burn the volatiles that account for most
of the combustible material in the waste. When proper drying conditions do not exist, or when
secondary combustion is incomplete, the combustion temperature is lowered, and increased PM, CO,
and organic compound emissions may result. Significant variations in fuel moisture content can cause
short-term emissions to fluctuate.
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
significantly per unit of wood waste burned. More recent boiler installations typically separate the
1.6-2
EMISSION FACTORS
10/96
-------
collected particulate 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.
1.6.3.2 Greenhouse Gases12"17
Carbon dioxide (C02). methane (CH4), and nitrous oxide (N20) emissions are all produced
during wood waste combustion. Nearly all of the fuel carbon (99 percent) in wood waste is converted
to C02 during the combustion process. This conversion is relatively independent of firing
configuration. Although the formation of CO acts to reduce C02 emissions, the amount of CO
produced is insignificant compared to the amount of C02 produced. The majority of the fuel carbon
not converted to C02 is due to incomplete combustion and is entrained in the bottom ash. C02
emitted from this soure may not increase total atmospheric C02, however, because emissions may be
offset by the offtake of C02 by regrowing biomass.
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Formation of N20 is minimized when combustion
temperatures are kept high (above 1475°F) and excess air is kept to a minimum (less than 1 percent).
N20 emissions for wood waste combustion are not significant except for fluidized bed combustion
(FBC), where localized areas of lower temperatures in the fuel bed produce N20 emissions an order of
magnitude greater than emissions from stokers.
Methane emissions arc highest during periods of low-temperature combustion or incomplete
combustion, such as the start-up or shut-down cycle for boilers. Typically, conditions that favor
formation of N20 also favor emissions of CH4.
1.6.4 Controls
Currently, the four most common control devices used to reduce PM emissions from wood-
fired boilers are mechanical collectors, wet scrubbers, electrostatic precipitators (ESPs), and fabric
filters. The use of multitube cyclone (or multiclone) mechanical collectors provides particulate control
for many fuel-fired 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 varies from 65 to 95 percent. The most widely used wet scrubbers for wood-fired boilers
are venturi scrubbers. With gas-side pressure drops exceeding 15 inches of water, particulate
collection efficiencies of 90 percent or greater have been reported for venturi scrubbers operating on
wood-fired boilers.
Fabric filters (i. e., baghouses) and ESPs are employed when collection efficiencies above
95 percent are required. When applied to wood-fired boilers, ESPs are often used downstream of
mechanical collector precleaners which remove larger-sized particles. Collection efficiencies of 93 to
99.8 percent for PM have been observed for ESPs operating on wood-fired boilers.
A variation of the ESP is the electrostatic gravel bed filter. In this device, PM in flue gases is
removed by impaction with gravel media inside a packed bed; collection is augmented by an
electrically charged grid within the bed. Particulate collection efficiencies are typically near
95 percent.
Fabric filters have had limited applications to wood-fired boilers. The principal drawback to
fabric filtration, as perceived by potential users, is a fire danger arising from the collection of
combustible carbonaceous fly ash. Steps can be taken to reduce this hazard, including the installation
of a mechanical collector upstream of the fabric filter to remove large burning particles of fly ash
10/96
External Combustion Sources
1,6-3
-------
(i. e., "sparklers"). Despite complications, fabric filters are generally preferred for boilers firing salt-
laden wood. This fuel produces fine particulates with a high salt content. Fabric filters are capable of
high fine particle collection efficiencies; in addition, the salt content of the particles has a quenching
effect, thereby reducing fire hazards. In two tests of fabric filters operating on salt-laden wood-fired
boilers, particulate collection efficiencies were above 98 percent.
For stoker and FBC boilers, overfire air ports may be used to lower NOx emissions by staging
the combustion process. In those areas of the U. S. where NOx emissions must be reduced to their
lowest levels, the application of selective noncatalytic reduction (SNCR) to waste wood-fired boilers
has been accomplished; the application of selective catalytic reduction (SCR) is being contemplated.
Both systems are postcombustion 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-to-NOx ratio increased from 0.4 to 3.2.
Emission factors and emission factor ratings for wood waste boilers are summarized in
Tables 1.6-1, 1.6-2, 1.6-3, 1.6-4, and 1.6-5.18-19 Tables in this section present emission factors on a
weight basis (lb/ton). To convert to an energy basis (Ib/MMBtu), divide by a heating value of 9.0
MMBtu/ton. Emission factors are for uncontrolled combustors unless otherwise indicated. Cumulative
particle size distribution data and associated emission factors are presented in Tables 1.6-6 and 1.6-7.
Uncontrolled and controlled size-specific emission factors are plotted in Figure 1.6-1 and Figure 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 4,500 Btu/lb higher heating values.
1.6.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
• Significant figures were added to some PM and PM-10 emission factors.
• In the table with NOx and CO emission factors, text was added in the footnotes to
clarify meaning.
Supplement B, October 1996
• SOx, CH4, N20, C02, speciated organics, and trace elements emission factors were
corrected,
• Several HAP emission factors were updated.
1.6-4
EMISSION FACTORS
10/96
-------
5 Table 16-1. EMISSION FACTORS FOR PARTICULATE MATTER (PM), PARTICULATER MATTER LESS THAN 10 MICRONS
§ (PM-10), AND LEAD (Pb) FROM WOOD WASTE COMBUSTION8
m
a
n>
O
o
cr
c
Cft
5*
d
cn
o
£
O
Ct
PM
b
PM-
10c
Pbd
Source Category
(SCC)
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Bark-fired boilers (1-01-009-01, 1-02-009-01,
1-02-009-04, 1-03-009-01)
Uncontrolled
47
B
16.8
D
2.9 E-03
D
Mechanical collector with flyash reinjection
without flyash reinjection
14
9.0
B
B
11.0
3.24
D
D
ND
ND
NA
NA
Wet scrubber
2.88
D
2.50
D
ND
NA
Wood/bark-fired boilers (1-01-009-02, 1-02-009-02,
1-02-009-05, 1-03-009-02)
Uncontrolled
7.2
C
6.48
E
ND
NA
Mechanical collector with flyash reinjection
without flyash reinjection
6.0
S.4
C
C
5.46
1.72
E
E
3.2 E-04e
3.2 E-Me
D
Wet scrubber
0.48
D
0.432
E
3.5 E-04
D
Electrostatic precipitator
0.04
D
ND
NA
1.6 F.-05
D
Wood-fired boilers (1-01-009-03, 1-02-009-03,
1-02-009-06, 1-03-009-03)
Uncontrolled
8.8
C
ND
NA
ND
NA
Mechanical collector without flyash reinjection
4.2
C
4.4f
D
3.1 E-04
D
Electrostatic precipitator
0.17
D
ND
NA
1.1 E-03
D
a Units are lb of pollutant/ton of wood waste burned. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are based on wet, as-
fired wood waste with average properties of 50 weight % moisture and 4500 Btu/lb higher heating value. PM-10 = particulate matter less than
10 micrometers. SCC = Source Classification Code. ND = no data. NA = not applicable.
References 11,20-24.
c References 1,21,25.
d References 11,21-23,26.
e Due to lead's relative volatility, it is assumed that flyash reinjection does not have a significant effect on lead emissions following mechanical
— collectors.
'v f Based on one test in which 61% of emitted PM was less than 10 micrometer in size.
-------
'o
I
ON
Table 1.6-2. EMISSION FACTORS FOR NITROGEN OXIDES (NOx), SULFUR OXIDES (SOx), AND
CARBON MONOXIDE (CO) FROM WOOD WASTE COMBUSTION8
Source Category
(SCC)
NO*b
SOxc
COd
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Fuel cell/Dutch oven boiler (no SCC)
Stoker boilers (no SCC)
FBC boilers (no SCC)
0.38 C
(0.0033 - 1.5)
1.5 C
(0.66 - 3.6)
2.0 D
0.15 B
(0.02 - 0.4)
0.15 B
(0.02- 0.4)
0.15 B
(0.02 - 0.4)
6.6 C
(0.65 - 21)
13.6 C
(1.9 - 80)
1.4 D
(0.47 - 2.4)
O a Units are lb of pollutant/ton of wood waste burned. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are based on wet, as-
^ fired wood waste with average properties of 50 weight % moisture and 4,500 Btu/lb higher heating value. SCC = Source Classification Code.
FBC = fluidized bed combustion.
Q b References 20-22,27-28. NOx formation is primarily a function of wood nitrogen content. Values is parenthesis represent the range of emission
2 factors.
o c Reference 29. Lower limit of the range (in parentheses) should be used for wood and higher values for bark.
d References 11,20-22,27,30-32, Values is parenthesis represent the range of emission factors.
\©
On
-------
Table 1.6-3. EMISSION FACTORS FOR TOTAL ORGANIC
COMPOUNDS (TOC), METHANE (CH4), NITROUS OXIDE (N20), AND CARBON DIOXIDE
(C02) FROM WOOD WASTE COMBUSTION3
Source Category
(SCC)
TOCb
CH4c
N2Od
O
u
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Fuel cell/Dutch oven
boilers (no SCC)
Stoker boilers
(no SCC)
FBC boilers (no SCC)
0.18 C
0.22 C
ND NA
ND NA
0.1 E
ND NA
ND NA
0.04 D
0.2 E
1900 B
2000 B
1800 B
a Units are lb of pollutant/ton of wood waste burned. To convert from lb/ton to kg/Mg, multiply by 0.5. Emission factors are based on wet, as-
fired wood waste with average properties of 50 weight % moisture and 4500 Btu/lb higher heating value. SCC = Source Classification Code.
FBC = fluidized bed combustion. ND = no data. NA = not applicable.
b References 11,22-23,27. Emissions measured as total hydrocarbons.
c Reference 17.
d References 14-15.
e References 1,11,20-23,27,30-32.
-------
Tabic 1.6-4. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS FROM WOOD
WASTE COMBUSTION3
Organic Compound1"
Average Emission Factor
(lb/ton)
EMISSION FACTOR RATING
Phenols
1.47 E-05°
C
Acenaphthene
4.10 E-06d
C
Fluorene
8.22 E-06e
C
Phenanthrene
5.2 E-05c
B
Anthracene
3.3 E-06f
C
Fluoranthene
1.83 E-058
B
Benzo(a)anthracene
3.27 E-06h
C
Benzo(k)fluoranthene
7.65 E-07»
E
Benzo(b+k)fluoranthene
2.9 E-05k
C
Benzofluoranthenes
1.08 E-06m,n
E
Benzo(a)pyrene
6.75 E-08m,n
E
Benzo(g,h,i)perylenc
1.41 E-06p
D
Chrysene
4.2 E-07*1
C
Indeno( 1,2,3 ,c ,d)py rene
3.6 E-0T
D
Polychlorinated dibenzo-p-dioxins
1.2E-08ks-1
C
Polychlorinated dibenzo-p-furans
5.3 E-OS^8'"
C
Acenaphthylene
4.76 E-05v
B
Methyl anthracene
1.4 E-04m
D
Acrolein
4.0 E-06m
D
Solicyladehyde
2.3 E-05m
D
Benzaldehyde
1.2 E-05m
D
Formaldehyde
8.2 E-03w
B
Acetaldehyde
1.92 E-Q3W
B
Benzene
9.95 E-03x
B
Naphthalene
3.39 E-03y
C
2,3,7,8-Tetrachlorodibenzo-p-dioxin
3.6 E-l lk
D
2-Chlorophenol
5.13 E-07m-n
E
2,4-Dinitrophenol
4.23 E-06m,n
E
Methane
1.12 E-022
D
4-Nitrophenol
2.97 E-06m
E
Trichlorotrifluoroethane
1.96 E-01"
C
Pyrene
1.67 E-05bb
B
a Units are lb of pollutant/ton of wood waste burned. To convert from lb/ton to kg/Mg, multiply
by 0.5. Emission factors are based on wet, as-fired wood waste with average properties of
50 weight % moisture and 4500 Btu/lb higher heating value. Source Classification Codes are
1-01-009-01/02/03, 1-02-009-01/02/03/04/05/06/07, and 1-03-009-01/02/03.
b Pollutants in this table represent organic species measured for wood waste combustors. Other
organic species may also have been emitted but either were not measured or were present at
concentrations below analytical limits.
c References 32-35.
d References 34-39.
1.6-8
EMISSION FACTORS
10/96
-------
Table 1.6-4 (cont.).
e References 34-41.
^ References 34-39,41.
8 References 32-41.
^ References 34,37,39,40.
J References 34,36.
k References 11,19-23,26,31,42.
m Based on data from one source test.
n Reference 35.
p References 35-36,39.
q References 34-35,39-40.
r References 35,39.
s Emission factors are for total dioxins and furans, not toxic equivalents.
1 Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor is
1.3 E-06 lb/ton with a D rating.
u Excludes data from combustion of salt-laden wood. For salt-laden wood, emission factor is
5.5 E-07 lb/ton with a D rating.
v References 32,34-40.
w References 32-41,43.
x References 32-40,43.
y References 32-34,37,40-41.
z Reference 44.
22 References 34,36-38.
bb References 32,34-36,37-41.
10/96
Externa] Combustion Sources
1.6-9
-------
Table 1.6-5. EMISSION FACTORS FOR TRACE ELEMENTS
FROM WOOD WASTE COMBUSTION3
Trace Element1*
Average Emission Factor (lb/ton)
EMISSION FACTOR RATING
Chromium (VI)
4.6 E-05c
D
Copper
3.73 E-04d
B
Zinc
2.51 E-03d
B
Barium
4.4 E-03c
D
Potassium
7.8 E-01e
D
Sodium
1.8 E-02e
D
Iron
4.4 E-02c
D
Lithium
7.0 E-05e
D
Boron
8.0 E-045
D
Chlorine
7.8 E-03e
D
Vanadium
1.2 E-04e
D
Cobalt
1.3 E-04e
D
Thorium
1.7 E-05e
D
Tungsten
1.1 E-056
D
Dysprosium
1.3 E-05e
D
Samarium
2.0 E-05e
D
Neodymium
2.6 E-05e
D
Praseodymium
3.0 E-0Sc
D
Iodine
1,8 E-055
D
Tin
3.1 E-05e
D
Molybdenum
1.9 E-04e
D
Niobium
3.5 E-05e
D
Zirconium
3.5 E-04e
D
Yttrium
5.6 E-05e
D
Rubidium
1.2 E-03e
D
Bromine
3.9 E-04®
D
Germanium
2.5 E-06e
D
Arsenic
8.53 E-05f
B
Cadmium
2.12 E-05f
B
Chromium (Total)
1.56 E-04g
B
Lead
4.45 E-04d
B
Manganese
1.26E-02f
B
Mercury
5.15E-06h
C
Nickel
6.90 E-05I
B
Selenium
4.59 E-05e*
E
a Units are lb of pollutant/ton of wood waste burned. To convert from lb/ton to kg/Mg, multiply
by 0.5. Emission factors are based on wet, as-fired wood waste with average properties of
50 weight % moisture and 4500 Btu/lb higher heating value. Source Classification Codes are
1-010-09-01/02/03, 1-02-009-01/02/03/04/05/06/07, and 1-03-009-01/02/03.
b 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.
c References 11,19-22.
d References 32,34-41.
e Based on data from one source test.
f References 32,34-37,39,41.
8 References 32,34-39,41.
h References 32,34-35,37.
J References 32,34-37,40.
k References 40.
1.6-10
EMISSION FACTORS
10/96
-------
Table 1.6-6. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC
EMISSION FACTORS FOR BARK-FIRED SPREADER STOKER BOILERSa
EMISSION FACTOR RATING: D
Cumulative Mass % < Stated Size
Cumulative Emission Factor0 (lb/ton)
Controlled
Controlled
Particle Sizeh
Multiple
Multiple
Scrubber*"
Multiple
Multiple
Scrubber*'
(pm)
Uncontrolled
Cycloned
Cyclone6
Uncontrolled
Cycloned
Cyclonee
15
42
90
40
92
20.2
12.6
3.6
2.64
10
35
79
36
87
16.8
11.0
3.24
2.50
6
28
64
30
78
13.4
9.0
2.7
2.24
2.5
21
40
19
56
10.0
5.6
1.72
1.62
1.25
15
26
14
29
7.2
3.6
1.26
0.84
1.00
13
21
11
23
6 2
3.0
1.0
0.66
0.625
9
15
8
14
4.4
2.2
0.72
0.40
Total
100
100
100
100
48
14
9.0
2.88
a Reference 45. Emission factors are based on wet, as-fired wood waste with average properties of 50 weight % moisture and 4,500 Btu/lb higher
heating value. Source Classification Codes are 1-01-009-01, 1-02-009-01, 1-02-009-04, and 1-03-009-01.
b Expressed as aerodynamic equivalent diameter.
c Units are lb of pollutant/ton of wood waste bumcd. To convert from lb/ton to kg/Mg, multiply by 0.5.
d With flyash reinjection.
e Without flyash reinjection.
f Assumed control efficiency for scrubber is 94%.
-------
£ Table 1.6-7, CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC
4- EMISSION FACTORS FOR WOOD/BARK-FIRED BOILERS®
KJ
EMISSION FACTOR RATING: E
Cumulative Mass % < Stated Size
Cumulative Emission Factor0 (lb/ton)
Particle
Controlled
Controlled
Sizeb
Multiple
Multiple
Multiple
Multiple
(nm)
Uncontrolled"5
Cyclone®
Cycloner
Scrubber8
DEGF
Uncontrolled11
Cyclone0
Cyclonef
Scrubber®
DEGF8
15
94
96
35
98
77
6.77
5.76
1.90
0.431
0.246
10
90
91
32
98
74
6.48
5.46
1.72
0.432
0.236
6
86
80
27
98
69
6.20
4.80
1.46
0.432
0.220
2.5
76
54
16
98
65
5.47
3.24
0.86
0.432
0.208
1.25
69
30
8
96
61
4.97
1.80
0.44
0.422
0.196
1.00
67
24
6
95
58
4.82
1.44
0.32
0.418
0.186
0.625
ND
16
3
ND
51
ND
0.96
0.162
ND
0.164
Total
100
100
100
100
100
7.2
6.0
5.4
0.44
0.32
^ a Reference 45. Emission factors are based on wet, as-fired wood waste with average properties of 50 weight % moisture and
H 4500 Btu/lb higher heating value. Source Classification Codes are 1-01-009-02, 1-02-009-02, 1-02-009-05, and 1-03-009-02. ND = no data.
pa DEGF = dry electrostatic granular filter.
m b Expressed as aerodynamic equivalent diameter.
c Units are lb of pollutant/ton of wood bark bumed. To convert from lb/ton to kg/Mg, multiply by 0.5.
d From data on underfeed stokers. May also be used as size distribution for wood-fired boilers.
e From data on spreader stokers with flyash re injection.
f From data on spreader stokers without flyash reinjection.
g From data on Dutch ovens. Assumed control efficiency is 94%.
-------
5
vo
0\
O
o
3
cr
c
o
a
c/i
o
8
I
25
20
15
10
0
Multiple cyclone with,
flyash reinjection
Serubbe;
Uncontrolled
Multiple cyclone without
flyash reinjection
J I
-LL
10
9
8
7
6
5
4
3
2
0
Wt
I
a
c
0
tzs
a
Figure 1.6-1. Cumulative size-specific particulate matter emission factors for bark-fired boilers.
-------
4^
w
S
5?
on
O
Z
>
n
H
o
*
C/J
T3
u
la
4>
T3
JU
"o
&
C V
O i$
o g),
0
1
60
3.5
2.8 -
2.1 -
1.4 -
0.7 -
Uncontrolled
0
Dry electrostatic
granular filter
Multiple cyclone
with flyash
reinject ion
J L
\
-Scrubber
J I I I I I I 11
Multiple cyclone
without flyash
reinjection
_l I ''''''
3.0 —i
2.7
2.4
2.1
1.8
.1 .2 .4 .6 1 2 4 6 10
Particle diameter ( m)
20
40 60 100
I*
I
a
•§ if
i*
B a
If
1.2
0.9
0.6
0.3
0
1
O
o
«
c
o
1-5 II "
0
1
00
ft
o.
I
0.220 —i
0.2
0.218
0.216
0.214
0.212
0.210
0.208
0.206
0.204
0.202
3
J®
w 4>
C H
.2 *3
a
R
•S s
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I ^
8 tw
JO Sb
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<73
0.1
0.200 —1
o
jg Figure 1.6-2. Cumulative size-spccific particulate matter emission factors for wood/bark-fired boilers.
-------
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 Particulate 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, et aL "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 S02 Emissions When
Burned As A Fuel", H. Oglesby and R. Blosser, Journal Of The Air Pollution Control Agency,
J0(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. L. P. Nelson, L. M. Russell, and J. J. Watson, "Global Combustion Sources of Nitrous Oxide
Emissions", Research Project 2333-4 Interim Report, Radian Corporation, Sacramento, CA,
1991.
13. Rebecca L. Peer, Eric P. Epner, and Richard S. Billings, Characterization Of Nitrous Oxide
Emission Sources, EPA Contract No. 68-D1-0031, Research Triangle Park, NC, 1995.
14. Steven D. Piccot. Jennifer A. Buzun, and H. Christopher Frey, Emissions And Cost Estimates
For Globally Significant Anthropogenic Combustion Sources Of NOx N20, CH4, CO, And
CO2. EPA Contract No. 68-02-4288, Research Triangle Park, NC, 1990.
10/96
External Combustion Sources
1.6-15
-------
15. G. Marland, and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure
For Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide
Research Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge, TN,
1983.
16. Sector-Specific Issues And Reporting Methodologies Supporting The General Guidelines For
The Voluntary Reporting Of Greenhouse Gases Under Section 1605(b) Of The Energy Policy
Act Of 1992, Volume 2 of 3, U.S. Department of Energy, DOE/PO-0028, 1994.
17. 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.
18. A. Nunn, NOx Emission Factors For Wood Fired Boilers, EPA-600/7-79-219, U. S.
Environmental Protection Agency, September 1979.
19. Hazardous Air Emissions Potential From A Wood-Fired Furnace (and Attachments),
A. J. Hubbard, Wisconsin Department of Natural Resources, Madison, WI, July 1991.
20. Environmental Assessment Of A Wood-Waste-Fired Industrial Watertube Boiler, EPA Contract
No. 68-02-3188, Acurex Corporation, Mountain View, CA, March 1984.
21. Evaluation Test On A Wood Waste Fired Incinerator At Pacific Oroville Power Inc., Test
Report No. C-88-050. California Air Resources Board, Sacramento, CA, May 1990.
22. 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.
23. A Poly cyclic 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.
24. Compilation Of Air Pollutant Emission Factors, Supplement A, Section 1.6, U. S.
Environmental Protection Agency, Research Triangle Park, NC, 1986.
25. 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.
26. 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.
27. 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.
28. H. S. Oglesbv and R. O. Blosser, "Information On The Sulfur Content Of Bark And Its
Contribution To S02 Emissions When Burned As A Fuel", Journal Of The Air Pollution
Control Agency, 30(7):769-772, July 1980.
1.6-16 EMISSION FACTORS 10/96
-------
29. 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,
30. 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.
31. 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,
32. Source Emission Testing of the Wood-Fired Boiler Exhaust at Sierra Pacific, Bumey,
California, Performed for the Timber Association of California, Galston Technical Services,
February 1991.
33. Source Emission Testing of the Wood-fired Boiler #1 Exhaust Stack at Wheelabrator Shasta
Energy Company (TAC Site 9), Anderson, California, Performed for the Timber Association
of California, Galston Technical Services, January 1991.
34. Source Emission Testing of the Wood-fired boiler at Catalyst Hudson, Inc., Anderson
California, Performed for the Timber Association of California, Galston Technical Services,
February 1991.
35. Source Emission Testing of the Wood-fired Boiler at Big Valley Timber Company, Bieber,
California, Performed for the Timber Association of California, Galston Technical Services,
February, 1991.
36. Source Emission Testing of the CE Wood-Fired Boiler at Roseburg Forest Products (TAC Site
#3), Performed for the Timber Association of California, Galston Technical Services, January
1991.
37. Source Emission Testing of the Wood-fired Boiler #3 Exhaust at Georgia Pacific, Fort Bragg,
California, Performed for the Timber Association of California, Galston Technical Services,
February 1991.
38. Source Emission Testing of the Wood-fired Boiler "C" Exhaust at Pacific Timber, Scotia,
California, Performed for the Timber Association of California, Galston Technical Services,
February 1991.
39. Source Emission Testing of the Wood-fired Boiler Exhaust at Bohemia, Inc., Rocklin,
California, Prepared for the Timber Association of California, Galston Technical Services,
December 1990.
40. Source Emission Testing of the Wood-fired Boiler at Yanke Energy, North Fork, California,
Performed for the Timber Association of California, Galston Technical Services, January 1991.
41. Source Emission Testing of the Wood-fired Boiler Exhaust at Miller Redwood Co., Crescent
City, California, Performed for the Timber Association of California, Galston Technical
Services, February 1991.
10/96
External Combustion Sources
1.6-17
-------
42. 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.
I
43. Source Emission Testing of the Wood-fired Boiler #5 Exhaust at Roseburg Forest Products,
Anderson, California, Performed for the Timber Association of California, Galston Technical
Services, January 1991,
44. Nation Council Of The Paper Industry For Air And Stream Improvement, An Air Emission
Database for Wood Product Plant Combustion Units, Technical Bulletin No. 695. April 1995.
45. lnhalable Particulate Source Category Report For External Combustion Sources, EPA
Contract No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985.
I
1.6-18 EMISSION FACTORS
-------
1.7 Lignite Combustion
1.7.1 General1"5
Coal is a complex combination of organic matter and inorganic ash formed over eons from
successive layers of fallen vegetation. Coals are classified by rank according to their progressive
alteration in the natural metamorphosis from lignite to anthracite. Coal rank depends on the volatile
matter, fixed carbon, inherent moisture, and oxygen, although no one parameter defines rank.
Typically coal rank increases as the amount of fixed carbon increases and the amount of volatile
matter decreases,
Lignite is a coal in the early stages of coalification, with properties intermediate to those of
bituminous coal and peat. The two geographical areas of the U. S. with extensive lignite deposits are
centered in the States of North Dakota and Texas. The lignite in both areas has a high moisture
content (20 to 40 weight percent) and a low heating value (5,000 to 7,500 British thermal units per
pound [Btu/lb], on a wet basis). Due to high moisture content and low Btu value, shipping the lignite
would not be feasible; 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 to large pulverized coal (PC) and
cyclone-fired units (greater than 500 megawatt).
The major advantages of firing lignite are that it is relatively abundant (in the North Dakota
and Texas regions), relatively low in cost since it is surface mined, and low in sulfur content which
can reduce the need for postcombustion sulfur emission control devices. The disadvantages are that
more fuel and larger, more capital-intensive facilities are necessary to generate a unit of power with
lignite than is the case with bituminous coal. The disadvantages arise because: (1) lignite's lower
heating value means more fuel must be handled to produce a given amount of power; (2) the energy
and maintenance costs of coal handling equipment are higher; (3) the high inherent moisture content of
lignite decreases boiler efficiency; and (4) the ash characteristics of lignite require more attention to
sootblowing and boiler operation to maintain high availability and reliability.
•5
1.7.2 Firing Practices
In a pulverized lignite-fired boiler, the fuel is fed from the stock pile into bunkers adjacent to
the boiler. From there, the fuel is metered into several pulverizers which grind it to approximately
20u-mesh particle size. A stream of hot air from the air preheater begins the fuel-drying process and
conveys the fuel pneumatically to the burner nozzle where it is injected into the burner zone of the
boiler. Firing configurations of boilers that fire pulverized lignite include tangential, horizontally
opposed, front wall, cyclone, stoker, and fluidized bed combustor.
In the tangential firing method, the pulverized lignite is introduced from the corners of the
boiler in vertical rows of burner nozzles. Such a firing mechanism produces a vortexing flame pattern
which essentially uses the entire furnace enclosure as a burner. In front-wall firing and horizontally
opposed firing boilers, the pulverized coal is introduced into the burner zone through a horizontal row
of burners. This type of firing mechanism produces a more intense combustion pattern than the
tangential design and has a slightly higher heat release rate in the burner zone itself.
10/96
External Combustion Sources
1.7-1
-------
In these methods of firing pulverized lignite, the ash is removed from the furnace both as fly
ash and bottom ash. The bottom of the furnace is often characterized as either wet or dry, depending
on whether the ash is removed as a liquid slag or as a solid. Pulverized coal units have been designed
for both wet and dry bottoms, but the current practice is to design only dry bottom furnaces.
Another type of boiler firing lignite is the cyclone burner, which is a slag-lined
high-temperature vortex burner. The coal is fed from the storage area to a crusher that reduces the
lignite into particles of approximately 0.25 inch in diameter or less. Crushed lignite is partially dried
in the crusher and is then fired in a tangential or vortex pattern into the cyclone burner. The
temperature within the burner is hot enough to melt the ash to form a slag. Centrifugal force from the
vortex flow forces the melted slag to the outside of the burner where it coats the burner walls with a
thin layer of slag. As the solid lignite particles are fed into the burner, they are forced to the outside
of the burner and are imbedded in the slag layer. The solid lignite particles are trapped there until
complete burnout is attained. The ash from the burner is continuously removed through a slag tap
which is flush with the furnace floor.
In a stoker furnace, the lignite is spread across a grate to form a bed which burns until the
lignite is completely burned out. In such a mechanism, the lignite is broken up into approximately
2-inch pieces and is fed into the furnace by one of several feed mechanisms: underfeed, overfeed, or
spreading. In most stoker units, the grate on which the lignite is burned gradually moves from one
end of the furnace to the other. The lignite is spread on the grate in such a fashion that at the end of
the grate only ash remains (i.e., all of the lignite has been burned to the final ash product). When the
ash reaches the end of the grate, it falls into an ash collection hopper and is removed from the furnace.
Stoker furnaces are dry-bottom furnaces and, as such, generally have lower heat release rates and
lower temperature profiles than the corresponding pulverized or cyclone units.
There are two major categories of fluidized bed combustors (FBCs): (1) atmospheric FBCs.
operating at or near ambient pressures, and (2) pressurized FBCs, operating between 4 and
30 atmospheres (60 to 450 pounds per square inch gauge). Pressurized FBC systems are not
considered a demonstrated technology for lignite combustion. The two principal types of atmospheric
FBCs 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, in order to minimize solids carryover or elutriation from the combustor. Circulating FBCs,
however, employ high fluidization velocities to promote the carryover or circulation of the solids.
High temperature cyclones are used in circulating bed FBCs and in some bubbling bed FBCs to
capture the unbumed solid fuel and bed material for return to the primary combustion chamber for
more efficient fuel utilization.
1.7.3 Emissions 2"4,6"13
The emissions generated from firing lignite, as with any coal, include the criteria pollutants
particulate matter (PM), PM less than, or equal to, 10 micrometers in diameter (PM-10), sulfur oxides
(SOx), nitrogen oxides (NOx), carbon monoxide (CO), and total organic compounds (TOC). The other
pollutants generated include greenhouse gases, organics, trace elements, and acid gases.
1.7-2
EMISSION FACTORS
10/96
-------
Particulate Matter Emissions -
Emission levels for PM from lignite combustion are directly related to the ash content of the
lignite and the firing configuration of the boiler. Pulverized coal-fired units fire much or all of the
lignite in suspension. Cyclone furnaces collect much of the ash as molten sl?g in the furnace itself.
Stokers (other than spreader) retain a large fraction of the ash in the fuel bed and bottom ash.
Spreader stokers fire about 15 percent of the coal in suspension and the remainder in a bed.
Sulfur Oxides Emissions -
The SOx emissions from lignite combustion are a function of the sulfur content of the lignite
and the lignite composition (i.e., sulfur content, heating value, and alkali concentration). The
conversion of lignite sulfur to SOx is generally inversely proportional to the concentration of alkali
constituents in the lignite. The alkali content is known to have a great effect on sulfur conversion and
acts as a built-in sorbent for SOx removal.
Nitrogen Oxides Emissions -
The NOx emissions from lignite combustion are mainly a function of the boiler design, firing
configuration, and excess air level. Tangential units, stoker boilers, and FBCs typically produce lower
NOx levels than wall-fired units and cyclones. 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 NOx emission
levels that are comparable to emission levels from small stokers. In most boilers, regardless of firing
configuration, lower excess combustion air results in lower NOx emissions. However, lowering the
amount of excess air in a lignite-fired boiler can also affect the potential for ash fouling.
Carbon Monoxide Emissions'4 -
The CO emission rate 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 maintained, the resulting concentrations of CO (as well as organic
compounds) may increase by several orders of magnitude.
Greenhouse Gases 15-20 -
Carbon dioxide (C02). methane (CH4), and nitrous oxide (N20) emissions are all produced
during lignite combustion. Nearly all of the fiiel carbon (99 percent) in lignite is converted to C02
during the combustion process. This conversion is relatively independent of firing configuration.
Although the formation of CO acts to reduce C02 emissions, the amount of CO produced is
insignificant compared to the amount of C02 produced. The majority of the fuel carbon not converted
to C02 is due to incomplete combustion and is entrained in the bottom ash.
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Formation of N20 is minimized when combustion
temperatures are kept high (above 1475°F) and excess air is kept to a minimum (less than 1 percent).
N20 emissions for lignite combustion are not significant except for fluidized bed combustion, where
localized areas of lower temperatures in the fuel bed produce N20 emissions significantly higher than
emissions from stokers.
Methane emissions vary with the type of coal being fired and firing configuration, but are
highest during periods of incomplete combustion, such as the start-up or shut-down cycle for coal-fired
boilers. Typically, conditions that favor formation of N20 also favor emissions of CH4.
10/96
External Combustion Sources
1.7-3
-------
Organic Compounds -
Trace amounts of organic compounds are emitted during lignite combustion. As with CO
emissions, the rate at which organic compounds are emitted depends on the combustion efficiency of
the boiler. Therefore, combustion modifications that change combustion residence time, temperature,
or turbulence may increase concentrations of organic compounds in the flue gas.
Organic emissions include volatile, semivolatile, and condensable organic compounds either
present in the lignite or formed as a product of incomplete combustion (PIC). Organic emissions are
primarily characterized by the criteria pollutant class of unbumcd vapor-phase hydrocarbons. These
emissions include alkanes, alkenes, aldehydes, alcohols, and substituted benzenes (e.g., benzene,
toluene, xylene, and ethyl benzene).
Polychlorinated dibenzo-p-dioxins and polychlorinated dibenzofiirans (PCDD/PCDF) are
formed during the combustion of lignite. Of primary interest environmentally are tetrachloro- through
octachloro- dioxins and furans. Dioxin and furan emissions are influenced by the extent of destruction
of organics during combustion and through reactions in the air pollution control equipment. The
formation of PCDD/PCDF in air pollution control equipment is primarily dependent on flue gas
temperature, with maximum potential for formation occurring at flue gas temperatures of 450 degrees
to 650 degrees Fahrenheit.
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).
Trace Metals-
Trace metals are also emitted during lignite combustion. The quantity of any given metal
emitted, in general, depends on:
the physical and chemical properties of the metal itself;
the concentration of the metal in the lignite;
the combustion conditions; and
the type of particulate control device used, and its collection efficiency as a function of
particle size.
Acid Gases-
ln addition to SOx and NOx emissions, combustion of lignite also results in emissions of
chlorine and fluorine, primarily in the form of hydrogen chloride (HC1) and hydrogen fluoride (HF).
Lesser amounts of chlorine gas and fluorine gas are also emitted. A portion of the chlorine and
fluorine in the fuel may be absorbed onto fly ash or bottom ash. Both HC1 and HF are water soluble
and are readily controlled by acid gas scrubbing systems.
1.7.4 Controls2"4,6"13
Particulate Matter -
The primary PM control systems for lignite-fired utility boilers are electrostatic precipitators
(ESPs) and fabric filters (baghouses) with collection efficiencies as high as 99.5 percent. Older and
smaller ESPs can have lower collection efficiencies of approximately 95 percent for total PM.
1.7-4
EMISSION FACTORS
10/96
-------
Multiple cyclone collectors and scrubbers are typically used alone, or in series, with an ESP or
baghouse on small industrial stoker boilers and normally achieve 60 to 80 percent collection efficiency
for total PM.
Sulfur Oxides14 -
Flue gas desulfurization (FGD) systems are in current operation on several lignite-fired utility
boilers. Flue gases can be treated through wet, semi-dry, 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). 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 in excess of 90 percent of the incoming SOx. Lime/limestone scrubbers, sodium scrubbers,
spray drying, and dual alkali scrubbing are among the commercially proven FGD techniques.
Spray drying is a dry scrubbing approach in which a solution or slurry of alkaline material is
sprayed into a reaction vessel as a fine mist and mixes with the flue gas. The S02 reacts with the
alkali solution or slurry to form liquid-phase salts. The slurry is dried by the latent heat of the flue
gas to about 1 percent free moisture. The dried alkali continues to react with S02 in the flue gas to
form sulfite and sulfate salts. The spray dryer solids are entrained in the flue gas and carried out of
the dryer to a particulate control device such as an ESP or baghouse.
Limestone may also be injected into the furnace, typically in an FBC, to react with sulfur
dioxide (S02) and form calcium sulfate. An FBC is composed of a bed of inert material that is
suspended or "fluidized" by a stream of air. Lignite is injected into this bed and burned. Limestone is
also injected into this bed where it is calcined to lime and reacts with S02 to form calcium sulfate.
Particulate matter emitted from the boiler is generally captured in a cyclone and recirculated or sent to
disposal. Additional PM control equipment, such as an ESP or baghouse, is used after the cyclone to
further reduce particulate emissions.
Nitrogen Oxides21 -
The most common NOx control technique for lignite-fired boilers is overfire air (OFA) which
involves diverting a portion of the total combustion air (5 to 20 percent) from the burners and
injecting it through dedicated air ports above the top level of burners. OFA can be applied to
tangential-fired, wall-fired, and stoker boilers; however, it cannot be used on cyclone boilers or other
slag-tapping furnaces because it can alter the heat release profile of the boiler which can change the
slagging characteristics of the boiler. Depending on the design of the existing furnace, OFA can be a
retrofit technology that may achieve 20 to 30 percent NOx reduction from uncontrolled levels. It is a
typical NOx control technique used in new Subpart D and Subpart Da boilers.
Another NOx control technique used on lignite-fired boilers is low NOx burners (LNB) which
limit NOx formation by controlling both the stoichiometric and temperature profiles of the combustion
process. LNBs can be retrofit in existing tangential- and wall-fired boilers or installed in new boilers;
however, they are not applicable to cyclone boilers since the fuel is fired in cylindrical chambers in
the cyclone boiler rather than with conventional burners. Depending on boiler design and the desired
NOx level, OFA and LNB can be applied separately, or in combination, to achieve as much as
50-60 percent reduction from uncontrolled levels.
1.7.5 Emission Factors
Uncontrolled emission factors for SOx, NOx, CO, and C02 are presented in Table 1.7-1.
Controlled emission factors for SOx are presented in Table 1.7-2 and for NOx and CO in Table 1.7-3.
10/96
External Combustion Sources
1.7-5
-------
Table 1.7-4 presents uncontrolled emission factors for PM and N20, and controlled emission
factors for PM are shown in Table 1.7-5. Cumulative particle size distributions and particle size-
specific emission factors are provided in Tables 1.7-6 and 1.7-7. In addition, particle size-specific
emission factors are presented graphically in Figures 1.7-1 and 1.7-2.
Tables 1.7-8 through 1.7-10 present emission factors for polynuclear organic matter (POM),
polynuclear aromatic hydrocarbons (PAH), and various organic compounds, respectively.
Table 1.7-14 presents emission factors for hydrogen chloride and hydrogen fluoride.
Table 1.7-11 presents emission factor equations that may be used to estimate controlled and
uncontrolled emissions of nine trace metals. Table 1.7-12 presents uncontrolled emission factors for
trace metals, and Table 1.7-13 presents controlled emission factors. The emission factor equations are
based on statistical correlations among measured trace element concentrations in coal, measured
fractions of ash in coal, and measured particulate emissions. Because these are the major parameters
affecting trace metals emissions, it is recommended that the emission factor equations be used to
estimate uncontrolled and controlled emissions when the inputs to the equations are available. If the
inputs to the emission factor equations are not available for a pollutant and there is an emission factor
in Table 1.7-12 or Table 1.7-13, then the emission factors) could be used to estimate emissions.
Tables in this section present emission factors on both a weight basis (lb/ton) and an energy
basis (lb/1012Btu). Emission factors in units of lb/ton can be converted to units of lb/MMBtu by
multiplying the emission factor by 0.077, assuming a heating value for lignite of 6500 Btu/lb.
1.7.6 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
• In the table for SOx emission factors, the footnote "f1 was moved into the header of
the SOx column, and "other stoker" was clarified as a traveling grate (overfeed) stoke.
Text was added to the same table to clarify that "S" is a weight percent and not a
fraction.
• In the tables for PM factors, text was added to the footnotes to clarify that "A" is a
weight percent and not a fraction.
Supplement B, October 1996
• Text was enhanced concerning lignite coal characteristics.
• Text was updated and enhanced concerning firing practices, emissions, and controls.
• The SOx emission factor was updated and a C02 emission factor was added for all
categories.
• The table containing NOx and CO factors from controlled sources was revised to
present data by appropriate categories.
1.7-6
EMISSION FACTORS
10/96
-------
• New factors for controlled S0X were added.
• All POM factors were revised.
• New tables were added with new HAP emission factors.
• References were editorially corrected.
10/96
External Combustion Sources
1.7-7
-------
Table 1.7-1. EMISSION FACTORS FOR SOx, NOx, CO, AND C02
FROM UNCONTROLLED LIGNITE COMBUSTION8
EMISSION FACTOR RATING: C (except as noted)
tn
S
GO
o
£
o
H
O
z
Firing Configuration
SOx Emission
Factor*7 (lb/ton)
NOx Emission
Factor0 (lb/ton)
CO Emission
j
Factor (lb/ton)
C02 Emission
Factor6 (lb/ton)
Pulverized coal, dry bottom,
tangential (SCC 1-01-003-02)
30S
7.3
ND
72.6C
Pulverized coal, dry bottom,
wall-fired (SCC 1-01-003-01)
30S
11.1
0.25
72.6C
Cyclone (SCC 1-01-003-03)
30S
12.5
ND
72.6C
Spreader stoker
(SCC 1-01-003-06)
30S
5.8
ND
72.6C
Traveling Grate Overfeed stoker
(SCC 1-01-003-04)
30S
ND
ND
72.6C
Atmospheric fluidized bed
(SCC 1-01-003-17/18)
10Sf
3.6
0.158
72.6C
so
as
a To convert from lb/ton to kg/Mg, multiply by 0.5. SCC = Source Classification Code. ND = no data.
b Reference 2. S = Weight % sulfur content of lignite, wet basis. For example, if the sulfur content equals 3.4%, then S = 3.4.
For high sodium ash (Na20 > 8%), use 22S. For low sodium ash (Na20 < 2%), use 34S. If ash sodium content is unknown,
use 30S.
c References 2-3, 8-9, 22-23.
d References 8, 23.
c EMISSION FACTOR RATING: B. C Weight % carbon of lignite, as-fired basis. For example, if carbon content equals
63%, then C = 63. If the %C value is not known, a default C02 emission value of 4600 lb/ton may be used.
f EMISSION FACTOR RATING: D
8 Emission factor is for circulating fluidized bed only SCC = 1-01-003-18.
-------
Table 1.7-2. EMISSION FACTORS FOR SOx FROM CONTROLLED LIGNITE COMBUSTION3
EMISSIONS FACTOR RATING: D (except as noted)
Firing Configuration
Control Device
Emission Factor
(lb/ton)
Subpart D boilers:b
Pulverized coal
(SCC 1 -01 -003-01/-02)
Spray dryer
7.3S
Pulverized coal
(SCC 1-01-003-01/-02)
Wet scrubber
16.8S0
Subpart Da boilers:b
Pulverized coal
(SCC 1-01-003-01/-02)
Spray dryer
7.9S
Pulverized coal
(SCC 1-01-003-01./-02)
Wet scrubber
3.7SC
a References 22-23. S = weight % sulfiir content of lignite, wet basis. To convert from lb/ton to
kg/Mg, multiply by 0.5. SCC = Source Classification Code.
b Subpart D boilers are boilers constructed after August 17, 1971 and with a heat input rate greater
than 250 million Btu per hour (MMBtu/hr). Subpart Da boilers are boilers constructed after
September 18, 1978 and with a heat input rate greater than 250 MMBtu/hr.
c EMISSION FACTOR RATING: C
10/96
External Combustion Sources
1.7-9
-------
Table 1.7-3. EMISSION FACTORS FOR NOx AND CO FROM CONTROLLED
LIGNITE COMBUSTION1
NOxb
COc
Firing Configuration
Control
Device
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/ton)
EMISSION
FACTOR
RATING
Subpart D boi!ers:d
Pulverized coal,
tangential-fired
(SCC 1-01-003-02)
Overfire Air
6.8
C
ND
NA
Pulverized coal,
wall-fired
(SCC 1-01-003-01)
Overfire air
and low
NOx
burners
4.6
C
0.48
D
Subpart Da boilers:d
Pulverized coal,
tangential-fired
(SCC 1-01-003-02)
Overfire Air
6.0
c
0,1
D
a To convert from lb/ton to kg/Mg, multiply by 0.5. SCC = Source Classification Code. ND = no
data. NA = not applicable.
b References 22-23.
c Reference 22.
d Subpart D boilers are boilers constructed after August 17, 1971 and with a heat input rate greater
than 250 million Btu per hour (MMBtu/hr). Subpart Da boilers are boilers constructed after
September 18, 1978 and with a heat input rate greater than 250 MMBtu/hr.
1.7-10
EMISSION FACTORS
10/96
-------
Tabic 1.7-4. EMISSION FACTORS FOR PM AND N20 FROM
UNCONTROLLED LIGNITE COMBUSTION"
EMISSION FACTOR RATING: E (except as notecD
Firing Configuration
PM Emission Factorb
(lb/ton)
N20 Emission Factor0
(lb/ton)
Pulverized coal, dry bottom, tangential
(SCC 1-01-003-02)
6.5A
ND
Pulverized coal, drv bottom, wall fired
(SCC 1-01-003-0*1)
5.1A
ND
Cyclone (SCC 1-01-003-03)
6.7Ad
ND
Spreader stoker (SCC 1-01-003-06)
8.OA
ND
Other stoker (SCC 1-01-003-04)
3.4 A
ND
FBC, Circulating bed
(SCC 1-01-003-18)
ND
2.5
a To convert from lb/ton to kg/Mg. multiply by 0.5. SCC = Source Classification Code.
ND = no data.
b References 6-7. 24-25. A = weight % ash content of lignite, wet basis. For example, if the ash
content is 5%, then A = 5.
c Reference 26.
d EMISSION FACTOR RATING: C
Table 1.7-5. EMISSION FACTORS FOR PM
EMISSIONS FROM CONTROLLED LIGNITE COMBUSTION3
EMISSION FACTOR RATING: C (except as noted)
Firing Configuration
Control Device
PM Emission Factor
(lb/ton)
U
Subpart D Boilers
(SCC 1-01-003-01/-02)
Baghouse
Wet scrubber
0.08A
0.05A
Subpart Da Boilcrsb
(SCC 1-01-003-01/-02)
Wet scrubber
0.01A
FBC. Circulating bed and bubbling bed
(SCC 1-01 -003-17/18)b,c
Limestone addition
0.07A
a References 22-23. A = weight % ash content of lignite, wet basis. For example, if lignite is 2.3%
ash, then A = 2.3. To convert from lb/ton to kg/Mg, multiply by 0.5. SCC = Source Classification
Code.
b Subpart D boilers are boilers constructed before August 17, 1971, and with a heat input rate greater
than 250 million Btu per hour (MMBtu/hr). Subpart Da boilers are boilers constructed after
September 18, 1978. and with a heat input rate greater than 250 MMBtu/hr.
c EMISSION FACTOR RATING: D.
10/96
External Combustion Sources
1.7-11
-------
—I
I
to
Table 1.7-6. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR BOILERS FIRING
PULVERIZED LIGNITE3
EMISSION FACTOR RATING: E
Cumulative Mass % < Stated Size
Cumulative Emission Factor0 (lb/ton)
Particle Sizeh
(Mm)
Uncontrolled
Multiple Cyclone
Controlled
Uncontrolled
Multiple Cyclone
Controlled*1
15
51
77
3.4A
I.OA
10
35
67
2.3A
0.88A
6
26
57
1.7A
0.75A
2.5
10
27
0.66A
0.36A
1.25
7
16
0.47A
0.21A
1.00
6
14
0.40A
0.19A
0.625
3
8
0.19A
0.11A
TOTAL
6.6A
1.3 A
w
g
On
on
i
5
n
H
o
on
a Reference 27. Based on tangential-fired units (Source Classification Code 1-01-003-02). For wall-fired units (Source Classification
Code 1-01-003-01), multiply emission factors in the table by 0.79.
b Expressed as aerodynamic equivalent diameter,
c A = weight % ash content of lignite, wet basis. For example, if lignite is 3.4% ash, then A = 3.4. To convert from lb/ton to kg/Mg, multiply
by 0.5.
J ^
Estimated control efficiency for multiple cyclone is 80%, averaged over all particle sizes.
SO
ON
-------
Table 1.7-7. CUMULATIVE PARTICLE SIZE DISTRIBUTION AND SIZE-SPECIFIC EMISSION FACTORS FOR LIGNITE-FIRED
SPREADER STOKERS®
EMISSION FACTOR RATING: E
Cumulative Mass % < Stated Size
Cumulative Emission Factor0 (lb/ton)
Particle Sizeb
(Mm)
Uncontrolled
Multiple Cyclone
Controlled
Uncontrolled
Multiple Cyclone
Controlled*1
15
28
55
2.2A
0.88A
10
20
41
1.6A
0.66A
6
14
31
1.1A
0.50A
2.5
7
26
0.5 6 A
0.42A
1.25
5
23
0.40A
0.37A
1.00
5
22
0.40A
0.35A
0.625
4
e
0.33A
e
TOTAL
8.0A
1.6A
a Reference 27. Source Classification Code 1-01-003-06.
b Expressed as aerodynamic equivalent diameter.
c A = weight % ash content of lignite, wet basis. For example, if the lignite is 5% ash, then A = 5. To convert from lb/ton to kg/Mg, multiply
by 0.5.
Estimated control efficiency for multiple cyclone is 80%.
e Insufficient data.
-------
Table 1,7-8, EMISSION FACTORS FOR POM FROM CONTROLLED LIGNITE COMBUSTION3
EMISSION FACTOR RATING: E
Firing Configuration
Control Device
Emission Factor (Ib/IO12 Btu)
POM
Pulverized coal
High efficiency cold-side ESP
2.3
(SCC 1-01-003-01)
Pulverized dry bottom
Multi-cyclones
1.8 - 18b
(no SCC)
ESP
2.6b
Cyclone furnace
ESP
0.1 lc - 1.6b
(SCC 1-01-003-03)
Spreader stoker
Multi-cyclones
15c
(SCC 1-01-003-06)
a References 28-29, To convert from lb/1012 Btu to pg/J, multiply by 0 43. SCC = Source
Classification Code. ND = no data.
b Primarily trimethyi propenyl naphthalene,
c Primarily biphenyl.
1.7-14
EMISSION FACTORS
10/96
-------
Table 1.7-9 EMISSION FACTORS FOR POLYNUCLEAR AROMATIC
HYDROCARBONS (PAH) FROM CONTROLLED COAL COMBUSTION3
Pollutant
h
Emission Factor
(lb/ton)
EMISSION FACTOR
RATING
Biphenyl
1.7E-06
D
Acenaphthene
5.1E-07
B
Acenaphthylene
2.5E-07
B
Anthracene
2.1E-07
B
Benzo(a)anthracene
8.0E-08
B
Benzo(a)pyrene
3.8E-08
D
Benzo(b,j,k)fluoranthene
1.1E-07
B
Benzo(g,h,i)pervlene
2.7E-08
D
Chrysene
1.0E-07
C
Fluoranthene
7.1E-07
B
Fluorene
9.1E-07
B
Indeno( l,2,3-cd)pvrene
6.1E-08
C
Naphthalene
1.3E-05
C
Phenanthrene
2.7E-06
B
Pyrene
3.3E-07
B
5-Methyl chry sene
2.2E-08
D
a References 30-40. Factors were developed from emissions data from six sites firing bituminous coal,
four sites firing subbituminous coal, and from one site firing lignite. Factors apply to boilers
utilizing both wet limestone scrubbers or spray dryers with an electrostatic precipitator (ESP) or
fabric filter (FF). The factors also apply to boilers utilizing only an ESP or FF. SCCs = pulverized
coal-fired boilers, 1-01-003-01, 1-02-003-01, 1-03-003-05; pulverized coal tangentially-fired boilers,
1-01-003-02, 1-02-003-02, 1-03-003-06; and cyclone boilers, 1-01-003-03, and 1-02-0*03-03.
b Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply
by 0.5. Emissions are lb of pollutant per ton of coal combusted.
10/96
External Combustion Sources
1.7-15
-------
Table 1.7-10 EMISSION FACTORS FOR VARIOUS ORGANIC COMPOUNDS
FROM CONTROLLED COAL COMBUSTION8
Pollutantb
Emission Factor0
(lb/ton)
EMISSION FACTOR
RATING
Acetaldehyde
5.7E-04
C
Acetophenone
1.5E-05
D
Acrolein
2.9E-04
D
Benzene
1.3E-03
A
Benzyl chloride
7.0E-04
D
Bis(2-ethylhexyl)phthalate (DEHP)
7.3E-05
D
Bromoform
3.9E-05
E
Carbon disulfide
1.3E-04
D
2-Chloroacetophenone
7.0E-06
E
Chlorobenzene
2.2E-05
D
Chloroform
5.9E-05
D
Cumene
5.3E-06
E
Cyanide
2.5E-03
D
2,4-Dinitrotoluene
2.8E-07
D
Dimethyl sulfate
4.8E-05
E
Ethyl benzene
9.4E-05
D
Ethyl chloride
4.2E-05
D
Ethylene dichloride
4.0E-05
E
Ethylene dibromide
1.2E-06
E
Formaldehyde
2.4E-04
A
Hexane
6.7E-05
D
Isophorone
5.8E-04
D
Methyl bromide
1.6E-04
D
Methyl chloride
5.3E-04
D
Methyl ethyl ketone
3.9E-04
D
Methyl hydrazine
1.7E-04
E
Methyl methacrylate
2.0E-05
E
Methyl tert butyl ether
3.5E-05
E
Methylene chloride
2.9E-04
D
1.7-16
EMISSION FACTORS
10/96
-------
Table 1.7-10 (continued)
Pollutant*5
Emission Factor0
(lb/ton)
EMISSION FACTOR
RATING
Phenol
1.6E-05
D
Propionaldehyde
3.8E-04
D
Tetrachloroethylene
4.3E-05
D
Toluene
2.4E-04
A
1,1,1 -Trichloroethane
2.0E-05
E
Styrene
2.5E-05
D
Xylenes
3.7E-05
C
Vinyl acetate
7.6E-06
E
a References 30-48. Factors were developed from emissions data from ten sites firing bituminous
coal, eight sites firing subbituminous coal, and from one site firing lignite. The emission factors are
applicable to boilers using both wet limestone scrubbers or spray dryers and an electrostatic
precipitator (ESP) or fabric filter (FF). In addition, the factors apply to boilers utilizing only an ESP
or FF. SCCs = pulverized coal-fired boilers, 1-01-003-01, 1-02-003-01, 1-03-003-05; pulverized
coal tangential!y-fired boilers, 1-01-003-02, 1-02-003-02, 1-03-003-06; cyclone boilers, 1-01-003-03,
1-02-003-03; and atmospheric fluidized bed combustor, circulating bed, 1-01-003-18. This table is
similar to Table 1.1-13 and is reproduced here for the convenience of the reader.
Pollutants sampled for but not detected in any sampling run include: Carbon tetrachloride- 2 sites;
1,3-Dichloropropylene- 2 sites; N-nitrosodimethylamine- 2 sites; Ethylidene dichloride- 2 sites;
Hexachlorobutadiene- 1 site: Hexachloroethane- 1 site; Propylene dichloride- 2 sites;
1.1,2,2-Tetrachloroethane- 2 sites; 1,1,2-Triehloroethane- 2 sites; Vinyl chloride- 2 sites; and,
Hexachlorobenzcne- 2 sites.
c Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg. multiply
bv 0.5.
10/96
External Combustion Sources
1.7-17
-------
Table 1.7-11, TRACE METAL EMISSION FACTOR EQUATIONS FOR FROM COAL
COMBUSTION®
EMISSION FACTOR EQUATION RATING: Ab
Pollutant
Emission Factor Equation
(lb/1012 Btu)c
Antimony
0.92 * (C/A * PM)0 63
Arsenic
3.1 * (C/A * PM)0 85
Beryllium
1.2 * (C/A * PM)1 1
Cadmium
3.3 * (C/A * PM)0"5
Chromium
3,7 * (C/A * PM)0 58
Cobalt
1.7 * (C/A * PM)0'69
Lead
3.4 * (C/A * PM)0'80
Manganese
3.8 * (C/A * PM)0'60
Nickel
4.4 * (C/A * PM)0'48
a Reference 49. The equations were developed from emissions data from bituminous coal combustion,
subbituminous coal combustion, and from lignite combustion. The equations should be used to
generate factors for controlled boilers when the necessary input information is available. The
emission factor equations are applicable to all typical firing configurations and PM controls for
electric generation (utility), industrial, and commercial/industrial boilers firing bituminous coal,
subbituminous coal, or lignite. Thus, all SCCs for these boilers are assigned to the equations.
b AP-42 criteria for rating emission factors were used to rate the equations.
c The factors produced by the equations should be applied to heat input. To convert from lb/1012 Btu
to kg/joules multiply by 4.31 x 10"16
C = concentration of metal in the coal, parts per million by weight (ppmwt).
A = weight fraction of ash in the coal. For example, 10% ash is 0.1 ash fraction.
PM = Site-specific emission factor for total particulate matter, lb/106 Btu.
1.7-18
EMISSION FACTORS
10/96
-------
O Tabic 1.7-12. EMISSION FACTORS FOR TRACE ELEMENTS FROM UNCONTROLLED LIGNITE COMBUSTION3
EMISSION FACTOR RATING: E
m
a
Q
3
EL
O
o
3
a-
c
fSi
c. a
o
3
KTt
O
e
B
o
yi
Emission Factor (Ib/1012Btu)
Firing Configuration
As
Be
Cd
Cr
Mn
Hg
Ni
Pulverized, wet bottom (no SCC)
2730
131
49 - 77
1220 - 1880
4410
- 16,250
21
154 - 1160
Pulverized, dry bottom (no SCC)
1390
131
49
1500 - 1880
16,200
21
928 - 1160
Cyclone furnace (SCC 1-01-003-03)
235 - 632
131
31
253 - 1880
3,760
21
157 - 1160
Stoker configuration unknown
(no SCC)
ND
118
ND
ND
11,800
21
ND
Spreader stoker (SCC 1-01-003-06)
538 - 1100
ND
23 -47
1130 - 1880
ND
ND
696 - 1160
Traveling grate (overfed) stoker
(SCC 1-01-003-04)
1100 - 2100
ND
47 - 90
ND
ND
ND
ND
"TT
References 28-29. To convert from lb/10 Btu to pg/J, multiply by 0.43. SCC = Source Classification Code. ND = no data.
SO
-------
Table 1.7-13 EMISSION FACTORS FOR TRACE METALS FROM
CONTROLLED COAL COMBUSTION3
Pollutant
Emission Factor (lb/ton)b
EMISSION FACTOR RATING
Antimony
1.8E-05
A
Arsenic
4.1E-04
A
Beryllium
2.1E-05
A
Cadmium
5.1E-05
A
Chromium
2.6E-04
A
Chromium (VI)
7.9E-05
D
Cobalt
1.0E-04
A
Lead
4.2E-04
A
Magnesium
1.1E-02
A
Manganese
4.9E-04
A
Mercury
8.3E-05
A
Nickel
2.8E-04
A
Selenium
1.3E-03
A
a References 30-48, 50-58. The emission factors were developed from emissions data at eleven
facilities firing bituminous coal, fifteen facilities firing subbituminous coal, and from two facilities
firing lignite. The factors apply to boilers utilizing either venturi scrubbers, spray dryer absorbers, or
wet limestone scrubbers with an electrostatic precipitator (ESP) or Fabric Filter (FF). In addition,
the factors apply to boilers using only an ESP, FF. or venturi scrubber. SCCs = pulverized coal-
fired boilers, 1-01-003-01, 1-02-003-01, 1-03-003-05; pulverized coal tangentially-fired boilers,
1-01-003-02, 1-02-003-02, 1-03-003-06; cyclone boilers, 1-01-003-03, 1-02-003-03; and atmospheric
fluidized bed combustor, circulating bed, 1-01-003-18.
h
Emission factor should be applied to coal feed, as fired. To convert from lb/ton to kg/Mg, multiply
by 0.5.
1.7-20
EMISSION FACTORS
10/96
-------
Table 1.7-14. EMISSION FACTORS FOR HYDROGEN CHLORIDE (HCI) AND HYDROGEN FLUORIDE (HF) FROM
COAL COMBUSTION8
EMISSION FACTOR RATING: B
HCI
HF
Firing Configuration
see
Emission Factor (lb/ton)
Emission Factor (lb/ton)
PC-fired
1-01-003-01
1-02-003-01
1-03-003-05
1.2
0.15
PC-fired, tangential
1-01-003-02
1-02-003-02
1-03-003-06
1.2
0.15
Cyclone Furnace
1-01-003-03
1-02-003-03
1.2
0.15
Traveling Grate (overfeed stoker)
1-01-003-04
1-02-003-04
1-03-003-07
1.2
0.15
Spreader Stoker
1-01-003-06
1-02-003-06
1-03-003-09
1.2
0.15
FBC, Circulating Bed
1-01-003-18
1.2
0.15
a Reference 59. The emission factors were developed from bituminous coal, subbituminous coal, and lignite emissions data. To convert from
lb/ton to kg/Mg, multiply by 0.5. The factors apply to both controlled and uncontrolled sources.
-------
3A
2.7A
S 2.4A
Jt ©
§1 2>1A
[I "5 1-8A
• 1 1.5A
TS °
ltL2A
I e 0.9A
$ 0.6A
0.3A
0
Multiple
-
cyclone \
/\ -
1 1 1 1 fTTl 1 1 L_
Uncontrolled
...J i.. i 11 i i i i i i i i i
.1
l.OA
0.9A
0.8A
0.7A
0.6A
0.5A
0.4A
0.3A
0.2A
0.1A
0
.4 .6 1 2 4 6 10
Particle diameter ( m)
20
40 60 100
3
M
h-h
C
o
"1
I 3
§ <3
§ s
0 oo
II
1
1
Figure 1.7-1. Cumulative size-specific emission factors for boilers
firing pulverized lignite.
§
l.OA
0.9A
0.8A
f 1 9- 0.7A
JJ <8 £
fl| 0.6A
s .2
1 w 8
111
lle
O W
0.5A
0.4A
0.3A
0.2A
0.1A
0
Uncontrolled
V
/
I I 1 1 1 I 111 1 1 1 1 11 i 1
Multiple cyclone
i i i i i i i i
.1
.2
.6 1 2 4 6 10
Particle diameter ( m)
20
40 60 100
Figure 1,7-2. Cumulative size-specific emission factors for
lignite-fired spreader stokers.
1.7-22
EMISSION FACTORS
10/96
-------
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, el a!., "Some Studies on Stack Emissions from Lignite Fired Powerplants",
Presented at the 1973 Lignite Symposium, Grand Forks, ND, May 1973.
3. Standards Support And Environmental Impact Statement: Promulgated Standards Of
Performance For Lignite Fired Steam Generators: Volumes I And II, EPA-450/2-76-030a and
030b, U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1976.
4. 1965 Keystone Coal Buyers Manual, McGraw-Hill, Inc., New York, NY, 1965.
5. B. Bartok and A. F. Sarofim (eds ), Fossil Fuel Combustion, A Source Book, John Wiley and
Sons, Inc., 1991, p.239
6. Source Test Data On Lignite-Fired Power Plants, North Dakota State Department of Health,
Bismarck. ND, December 1973.
7. G. H. Gronhovd, el a!., "Comparison Of Ash Fouling Tendencies Of High And Low Sodium
Lignite From A North Dakota Mine", Proceedings of the American Power Conference,
Volume XXVIII, 1966.
8. A. R. Crawford, el 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.
9. 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.
10. Coal Fired Power Plant Trace Element Study, A Three Station Comparison,
U. S. Environmental Protection Agency, Denver, CO, September 1975.
11. 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.
12. C. C. Shih, et al., Emissions Assessment Of Conventional Stationary Combustion Systems,
Volume 111: External Combustion Sources For Electricity Generation, EPA
Contract No. 68-02-2197, TRW Inc., Redondo Beach, CA, November 1980.
13. 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.
14. Emission Factor Documentation For AP-42 Section 1.7, Lignite Combustion, prepared by
Acurex Environmental Corp.. Edward Aul & Associates, Inc., and E. H. Pcchan & Associates,
Inc., EPA Contract No. 68-DO-0120, April 1993,
10/96
External Combustion Sources
1.7-23
-------
15. L. P. Nelson, et al., Global Combustion Sources Of Nitrous Oxide Emissions, Research Project
2333-4 Interim Report, Sacramento: Radian Corporation, 1991.
16. R. L. Peer, et al., Characterization Of Nitrous Oxide Emission Sources, Prepared for the US
EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Corporation, 1995.
17. S. D. Piccot, et al., Emissions And Cost Estimates For Globally Significant Anthropogenic
Combustion Sources OfNOx N20, CH4, CO, And C02, EPA Contract No. 68-02-4288,
Research Triangle Park, NC: Radian Corporation, 1990.
18. G. Marland, and R.M. Rotty Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge, TN, 1983.
19. G. Marland and R. M. Rotty, "Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results for 1950-1982," Tellus, 36B: 232-261.
20. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the
Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of
1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy.
21. S. Stamey-Hall, Radian Corporation, Alternative Control Techniques Document—NOx
Emissions From Utility Boilers, EPA-453/R-94-023, U. S. Environmental Protection Agency,
Research Triangle Park, NC, March 1994.
22. Source Test Data On Lignite-Fired Power Plants, North Dakota State Department of Health,
Bismarck, ND, April 1992.
23. Source Test Data On Lignite-Fired Power Plants, Texas Air Control Board, Austin, TX, April
1992.
24. Source Test Data On Lignite-Fired Cyclone Boilers, North Dakota State Department of Health,
Bismarck, ND, March 1982.
25. 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.
26. M. D. Mann, et al., "Effect Of Operating Parameters On N20 Emissions In A 1-MWCFBC,"
Presented at the 8th Annual Pittsburgh Coal Conference, Pittsburgh, PA, October, 1991.
27. Inhalable Particulate Source Category Report For External Combustion Sources, EPA
Contract No. 68-02-3156, Acurex Corporation, Mountain View, CA, January 1985.
28. 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.
29. G. W. Brooks, et al., Radian Corporation, Locating And Estimating Air Emission From Source
Of Polycyclic Organic Matter (POM), EPA-450/4-84-007p, U. S. Environmental Protection
Agency, Research Triangle Park, NC, May 1988.
1.7-24 EMISSION FACTORS 10/96
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30. Field Chemical Emissions Monitoring Project: Site 22 Emissions Report. Radian Corporation,
Austin, Texas. February, 1994. (EPRI Report)
31. Toxics Assessment Report. Illinois Power Company. Baldwin Power Station- Unit 2.
Baldwin, Illinois. Volumes I- Main Report. Roy F. Weston, Inc. West Chester,
Pennsylvania. December, 1993.
32. Toxics Assessment Report. Minnesota Power Company Boswell Energy Center- Unit 2.
Cohasset, Minnesota. Volume 1- Main Report. Roy F. Weston, Inc. West Chester,
Pennsylvania. December, 1993.
33. Field Chemical Emissions Monitoring Project: Site 11 Emissions Monitoring. Radian
Corporation, Austin, Texas. October, 1992. (EPRI Report)
34. Field Chemical Emissions Monitoring Project: Site 21 Emissions Monitoring. Radian
Corporation, Austin, Texas. August, 1993. (EPRI Report)
35. Field Chemical Emissions Monitoring Project: Site 111 Emissions Report. Radian
Corporation, Austin, Texas. May, 1993. (EPRI Report)
36. Field Chemical Emissions Monitoring Project: Site 115 Emissions Report. Radian
Corporation, Austin, Texas. November, 1994. (EPRI Report)
37. Draft Final Report. A Study of Toxic Emissions from a Coal-Fired Power Plant-Niles Station
No. 2. Volumes One, Two, and Three. Battelle, Columbus, Ohio. December 29, 1993.
38. Final Report. A Study of Toxic Emissions from a Coal-Fired Power Plant Utilizing an
ESP/Wet FGD System. Volumes One, Two, and Three. Battelle, Columbus, Ohio. July
1994,
39. Assessment of Toxic Emissions From a Coal Fired Power Plant Utilizing an ESP. Final
Report- Revision 1. Energy and Environmental Research Corporation, Irvine, California.
December 23, 1993.
40. 500-MW Demonstration of Advanced Wall-Fired Combustion Techniques for the Reduction of
Nitrogen Oxide (NOx) Emissions from Coal-Fired Boilers. Radian Corporation, Austin, Texas.
41. Results of the November 7, 1991 Air Toxic Emission Study on the Nos. 3, 4, 5 & 6 Boilers at
the NSP High Bridge Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. January 3,
1992,
42. Results of the December 1991 Air Toxic Emission Study on Units 6 & 7 at the NSP Riverside
Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. February 28, 1992.
43. Field Chemical Emissions Monitoring Project: Site 10 Emissions Monitoring. Radian
Corporation, Austin, Texas. October, 1992.
44. Field Chemical Emissions Monitoring Project: Site 12 Emissions Monitoring. Radian
Corporation, Austin, Texas. November, 1992,
10/96 External Combustion Sources 1.7-25
-------
45. Field Chemical Emissions Monitoring Project: Site 15 Emissions Monitoring. Radian
Corporation, Austin, Texas. October, 1992.
46. Field Chemical Emissions Monitoring Project: Site 101 Emissions Report. Radian
Corporation, Austin, Texas. October, 1994.
47. Field Chemical Emissions Monitoring Project: Site 114 Report. Radian Corporation, Austin,
Texas. May, 1994.
48. Field Chemical Emissions Monitoring Report: Site 122. Final Report, Task 1 Third Draft.
EPRI RP9028-10. Southern Research Institute, Birmingham, Alabama. May, 1995.
49. Electric Utility Trace Substances Synthesis Report, Volume /, Report TR-104614, Electric
Power Research Institute, Palo Alto, California, November 1994.
50. Results of the September 10 and 11, 1991 Mercury Removal Tests on the Units 1 & 2, and
Unit 3 Scrubber Systems at the NSP Sherco Plant in Becker, Minnesota. Interpoll
Laboratories, Inc., Circle Pines, Minnesota. October 30, 1991.
51. Results of the November 5, 1991 Air Toxic Emission Study on the No. 1, 3 & 4 Boilers at the
NSP Black Dog Plant. Interpoll Laboratories, Inc., Circle Pines, Minnesota. January 3, 1992,
52. Results of the January 1992 Air Toxic Emission Study on the No. 2 Boiler at the NSP Black
Dog Plant, Interpoll Laboratories, Inc., Circle Pines, Minnesota. May 4, 1992,
53. Results of the May 29, 1990 Trace Metal Characterization Study on Units 1 and 2 at the
Sherburne County Generating Station in Becker, Minnesota. Interpoll Laboratories, Inc.,
Circle Pines, Minnesota. July, 1990.
54. Results of the May 1, 1990 Trace Metal Characterization Study on Units 1 and 2 at the
Sherburne County Generating Station. Interpoll Laboratories, Inc., Circle Pines, Minnesota.
July 18, 1990.
55. Results of the March 1990 Trace Metal Characterization Study on Unit 3 at the Sherburne
County Generating Station, Interpoll Laboratories, Circle Pines, Minnesota. June 7, 1990.
56. Field Chemical Emissions Monitoring Project: Site 19 Emissions Monitoring. Radian
Corporation, Austin, Texas. April, 1993. (EPRI Report)
57. Field Chemical Emissions Monitoring Project: Site 20 Emissions Monitoring. Radian
Corporation, Austin, Texas. March, 1994. (EPRI Report)
58. Characterizing Toxic Emissions from a Coal-Fired Power Plant Demonstrating the AFGD
ICCT Project and a Plant Utilizing a Dry Scrubber/Baghhouse System. Final Draft Report.
Springerville Generating Station Unit No. 2. Southern Research Institute, Birmingham,
Alabama. December, 1993.
59. Hydrogen Chloride And Hydrogen Fluoride Emission Factors For The NAPAP Inventory,
EPA-600/7-85-041, U. S. Environmental Protection Agency, October 1985.
1.7-26
EMISSION FACTORS
10/96
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1.8 Bagasse Combustion In Sugar Mills
1.8.1 Process Description1"5
Bagasse is the matted cellulose fiber residue from sugar cane that has been processed in a
sugar mill. Previously, bagasse was burned as a means of solid waste disposal. However, as the cost
of fuel oil, natural gas, and electricity has increased, bagasse has come to be regarded as a fuel rather
than refuse. 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 3,000 and 4,000 British thermal units per pound (Btu/lb) on a
wet, as-ftred basis. Most bagasse has a moisture content between 45 and 55 percent by weight.
The U. S. sugar cane industry is located in the tropical and subtropical regions of Florida,
Texas, Louisiana, Hawaii, and Puerto Rico. Except for Hawaii, where sugar cane production takes
place year round, sugar mills operate seasonally from 2 to 5 months per year.
Sugar cane is a large grass with a bamboo-like stalk that grows 8 to 15 feet tall. Only the
stalk contains sufficient sucrose for processing into sugar. All other parts of the sugar cane
(i. e., leaves, top growth, and roots) are termed "trash". The objective of harvesting is to deliver the
sugar cane to the mill with a minimum of trash or other extraneous material. The cane is normally
burned in the field to remove a major portion of the trash and to control insects and rodents. (See
Section 13.1 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.
1.8.2 Firing Practices
Fuel cells, horseshoe boilers, and spreader stoker boilers are used to burn bagasse. Horseshoe
boilers and fuel cells differ in the shapes of their furnace area but in other respects are similar in
design and operation. In these boilers (most common among older plants), bagasse is gravity-fed
through chutes and piles onto a refractory hearth. Primary and overfire combustion air flows through
ports in the furnace walls; burning begins on the surface pile. Many of these units have dumping
hearths that permit ash removal while the unit is operating.
In more recently built sugar mills, bagasse is burned in spreader stoker boilers. Bagasse fed 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).
10/96
External Combustion Sources
1.8-1
-------
1.8.3 Emissions1"3
The most significant pollutant emitted by bagasse-fired boilers is particulate matter, caused by
the turbulent movement of combustion gases with respect to the burning bagasse and resultant ash.
Emissions of sulfur dioxide (S02) and nitrogen oxides (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, S02 and NOx emissions will increase. Soil characteristics such as particle size can
affect the magnitude of particulate matter (PM) emissions from the boiler. Cane that is improperly
washed or incorrectly prepared can also influence the bagasse ash content. Upsets in combustion
conditions can cause increased emissions of carbon monoxide (CO) and unbumed organics, typically
measured as volatile organic compounds (VOCs) and total organic compounds (TOCs).
1.8.4 Controls
Mechanical collectors and wet scrubbers are commonly used to control particulate emissions
from bagasse-fired boilers. Mechanical collectors may be installed in single cyclone, double cyclone,
or multiple cyclone (i. e., multiclone) arrangements. The reported PM collection efficiency for
mechanical collectors is 20 to 60 percent. Due to the abrasive nature of bagasse fly ash, mechanical
collector performance may deteriorate over time due to erosion if the system is not well maintained.
The most widely used wet scrubbers for bagasse-fired boilers are impingement and venturi
scrubbers. Impingement scrubbers normally operate at gas-side pressure drops of 5 to 15 inches of
water; typical pressure drops for venturi scrubbers are over 15 inches of water. Impingement
scrubbers are in greater use due to their lower energy requirements and fewer operating and
maintenance problems. Reported PM collection efficiencies for both scrubber types are 90 percent or
greater.
Fabric filters and electrostatic precipitators have not been used to a significant extent for
controlling PM from bagasse-fired boilers because both are relatively costly compared to other control
options. Fabric filters also pose a potential fire hazard.
Gaseous emissions (e. g., S02, 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 carbon dioxide (C02)-generating compounds (such as sodium carbonate or calcium
carbonate) are used, C02 emissions will increase.
Fugitive dust may be generated by truck traffic and cane handling operations at the sugar mill.
PM emissions from these sources may be estimated by consulting Section 13.2.
Emission factors and emission factor ratings for bagasse-fired boilers are shown in Table 1.8-1.
Table 1.8-1 presents emission factors on a weight basis (lb/ton). To convert to an energy basis
(lb/MMBtu), divide by a heating value of 7.0 MMBtu/ton.
1.8.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
1.8-2
EMISSION FACTORS
10/96
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background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
No changes.
Supplement B, October 1996
• PM emission factors were revised for boilers controlled with wet scrubbers.
10/96
External Combustion Sources
1.8-3
-------
Table 1.8-1. EMISSION FACTORS FOR BAGASSE-FIRED BOILERS3
Pollutant
Emission Factor (lb/ton)b
EMISSION FACTOR RATING
PMC
Uncontrolled1®
15.6
C
Controlled
Mechanical collector6
8.4
D
Wet scrubber1
1.4
A
PM-10
Controlled
Wet scrubber^
1.36
D
n
o
Uncontrolled®1
1,560
A
NOx
Uncontrolled'
1.2
C
Polycyclic organic matter
Uncontrolled1"
0.001
D
a Source Classification Code is 1-02-011-01.
b Units are lb of pollutant/ton of wet, as-fired bagasse containing approximately 50% moisture, by
weight. If lbs of steam produced is monitored, assume 1 lb of bagasse produces 2 lb of steam, in
lieu of any site-specific conversion data. To convert from lb/ton to kg/Mg, multiply by 0.5.
c Includes only filterable PM (i. e , that particulate collected on or prior to the filter of an EPA
Method 5 for equivalent] sampling train).
d Reference 2.
e References 6-7,
f References 6,8-65.
g Reference 13.
h References 6-13,66. C02 emissions will increase following a wet scrubber in which C02-generating
reagents (such as sodium carbonate or calcium carbonate) are used,
j References 7,13.
k Reference 7. Based on measurements collected downstream of PM control devices which may
have provided some removal of polycyclic organic matter condensed on PM.
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.
1.8-4
EMISSION FACTORS
10/96
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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. Particulate Emissions Test Report: Atlantic Sugar Association, Air Quality Consultants, Inc.,
December 20, 1978.
7. 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.
8. Compliance Stack Test: Gulf and Western Food Products: Report No. 238-S, South Florida
Environmental Services, Inc., February 1980.
9. Compliance Stack Test: Gulf and Western Food Products: Report No. 221-S, South Florida
Environmental Services, Inc., January 1980.
10. Compliance Stack Test: United States Sugar Corporation: Report No. 250-S, South Florida
Environmental Services, Inc., February 1980.
11. Compliance Stack Test: Osceola Farms Company: Report No. 215-S, South Florida
Environmental Services, Inc., December 1979.
12. Source Emissions Survey of Davies Hamakua Sugar Company: Report No. 79-34, Mullins
Environmental Testing Company, May 1979.
13. Emission Test Report: U. S. Sugar Company, Bryant Florida, EPA Contract No. 68-02-2818,
Monsanto Research Corporation, Dayton, OH, May 1980.
14. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubber
Number 6 Boiler: Talisman Sugar Corporation, South Bay, Florida, February 1 and 4, 1991.
15. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubber
Number 5 Boiler: Talisman Sugar Corporation, South Bay, Florida, February 5, 1991.
16. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubber
Number 4 Boiler: Talisman Sugar Corporation, South Bay, Florida, February 11, 1991.
17. Source Test Report For Particulate Emissions Impingement Wet Scrubber Number 3 Boiler:
Atlantic Sugar Association, Belle Glade, Florida, November 27, 1990.
18. Source Test Report For Particulate Emissions Impingement Wet Scrubber Number 4 Boiler:
Atlantic Sugar Association, Belle Glade, Florida, November 29, 1990.
10/96 External Combustion Sources 1.8-5
-------
19. Source Test Report Number 3 Boiler Impingement Wet Scrubber Particulate Emissions: Sugar
Cane Growers Cooperative of Florida, Belle Glade, Florida, December 6, 1990.
20. Source Test Report Number 4 Boiler Impingement Wet Scrubber Particulate Emissions: Sugar
Cane Growers Cooperative of Florida, Belle Glade, Florida, December 11, 1990.
21. Source Test Report For Particulate Emissions Impingement Wet Scrubber Number 5 Boiler:
United States Sugar Cane Corporation, Bryant, Florida, January 13, 1991.
22. Source Test Report For Particulate Emissions Impingement Wet Scrubber Number I Boiler:
United States Sugar Corporation, Bryant, Florida, January 8, 1991.
23. Source Test Report For Particulate Emissions Impingement Wet Scrubber Number 3 Boiler:
United States Sugar Corporation, Bryant, Florida, January 24, 1991.
24. Source Test Report Number 5 Boiler Impingement Wet Scrubbers Particulate Emissions:
Sugar Cane Growers Cooperative of Florida, Belle Glade, Florida, December 5, 1990.
25. Source Test Report Number 8 Boiler Impingement Wet Scrubber Particulate Emissions: Sugar
Cane Growers Cooperative of Florida, Belle Glade, Florida, December 12, 1990.
26. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubbers
Number I Boiler. Sugar Cam Growers Cooperative of Florida, Belle Glade, Florida,
November 19, 1990.
27. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubbers
Number 2 Boiler: Sugar Cane Growers Cooperative of Florida, Belle Glade, Florida,
November 28, 1990.
28. Source Test Report For Particulate Emissions Impingement Wet Scrubber Number 2 Boiler:
U. S. Sugar Corporation, Bryant, Florida, January 23, 1991.
29. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubber Boiler
Number 4: Talisman Sugar Corporation, South Bay, Florida, December 9, 1991.
30. Source Test Report For Particulate Emissions Impingement Wet Scrubber Boiler
Number 8: Sugar Cane Growers Cooperative of Florida Airport Road, Belle Glade, Florida,
November 27, 1991.
31. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubbers Boiler
Number I: Sugar Cane Growers Cooperative of Florida, Belle Glade, Florida,
November 14, 1991.
32. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubbers Boiler
Number 2: Sugar Cane Growers Cooperative of Florida, Belle Glade, Florida,
November 15, 1991.
33. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubbers Boiler
Number 6: Talisman Sugar Corporation, South Bay, Florida, December 11, 1991.
1.8-6 EMISSION FACTORS 10/96
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34, Source Test Report For Particulate Emissions Boilers 3 and 4: Atlantic Sugar Association,
Belle Glade, Florida, November 20 and 21, 1991.
15. Source Test Report For Particulate And Volatile Organic Compound Emissions,
Nominal 10% Soil Feed Impingement Wet Scrubber Boiler Number 1, Bryant, Florida,
December 19, 1991.
36. Source Test Report For Particulate Emissions Impingement Wet Scrubber Boiler
Number 5, Bryant, Florida, March 5, 1992.
37. Source Test Report For Particulate And Volatile Organic Compound Emissions,
Nominal 10% Soil Feed Impingement Wet Scrubber Boiler Number 3, Bryant, Florida,
December 17, 1991.
38. Source Test Report For Particulate Emissions Impingement Wet Scrubber Boiler
Number 4, November 26, 1991.
39. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubbers Boiler
Number 5, November 20, 1991.
40. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubber Boiler
Number 5, Talisman Sugar Corporation, South Bay, Florida, December 10, 1991.
41. Source Test Report For Particulate Emissions Twin Impingement Wet Scrubbers Boiler
Number 3, November 21, 1991.
42. Atlantic Sugar Association Compliance Particulate Emissions Test Report Boiler #2, Belle
Glade, Florida Facility, February 1, 1991.
43. Osceola Farms Company Compliance Particulate Emissions Test Report Boiler *2, Pahokee,
Florida Facility, Februaiy 7, 1991.
44. Particulate Emissions Compliance Test Report Boiler #1: Atlantic Sugar Association, Belle
Glade, Florida Facility, December 11, 1990.
45. Particulate Emissions Testing, Atlantic Sugar Association Boiler #1, Belle Glade, Florida
Facility, December 16, 1991.
46. Particulate Emissions Compliance Test Report Boiler #J, Atlantic Sugar Association, Belle
Glade, Florida Facility, January 8, 1992.
47. Atlantic Sugar Association Particulate Emissions Test Report Boiler #5, January 10, 1991.
48. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #12, South Bay
Florida Facility, December 17, 1991.
49. Particulate Emissions Testing, Atlantic Sugar Association Boiler #2, Belle Glade, Florida
Facility, December 12, 1991.
50. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #11, South Bay
Florida Facility', January 21 & 22, 1992.
10/96 External Combustion Sources 1.8-7
-------
51. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #10, South Bay
Florida Facility, January 29, 30 & 31, 1992.
52. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #6, South Bay
Florida Facility, January 24, 1992.
53. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #14, South Bay
Florida Facility, January 10 & 13, 1992.
54. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #15, South Bay-
Florida Facility, January 8, 1992.
55. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #4, South Bay
Florida Facility, December 11 & 12, 1991.
56. Okeelanta Corporation Compliance Particulate Emissions Test Report Boiler #5, South Bay
Florida Facility, December 12 & 13, 1991.
57. Okeelanta Corporation Particulate Emissions Test Report Boiler #5, December 12, 1990,
58. Okeelanta Corporation Particulate Emissions Test Report Boiler #6,
December 13-14, 1990.
59. Okeelanta Corporation Particulate Emissions Test Report Boiler iUO, January 29-30, 1991.
60. Okeelanta Corporation Particulate Emissions Test Report Boiler #4,
December 10-11, 1990,
61. Okeelanta Corporation Particulate Emissions Test Report Boiler #11, December 6-7, 1990.
62. Particulate Emissions Testing Okeelanta Corporation Boiler #12, January 31 and
February 1, 1991,
63. Okeelanta Corporation Particulate Emissions Test Report Boiler til4, February 4-5, 1991.
64. Okeelanta Corporation Particulate Emissions Test Report Boiler #15, February 8, 1991.
65. Stack Test For Total Gaseous Non-Methane Organic Compounds Report 1371-S Boiler
No. 5 - Bryant, United States Sugar Corporation, February 15, 1990.
66. Source Emissions Survey: Honokaa Sugar Company, Kennedy Engineers, Inc.,
January 19, 1979.
1.8-8
EMISSION FACTORS
10/96
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1.9 Residential Fireplaces
1.9.1 General1"2
Fireplaces are used primarily for aesthetic effects and secondarily as supplemental heating
sources 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 2 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, in cases where combustion is poor, where the outside air is cold, or where the fire is
allowed to smolder (thus drawing air into a residence without producing appreciable radiant heat
energy), a net heat loss may occur in a residence using a fireplace. Fireplace heating efficiency may
be improved by a number of measures that either reduce the excess air rate or transfer back into the
residence some of the heat that would normally be lost in the exhaust gases or through fireplace walls.
As noted above, such measures are commonly incorporated into prefabricated units. As a result, the
energy efficiencies of prefabricated fireplaces are slightly higher than those of masonry fireplaces.
1.9.2 Emissions And Controls
Fireplace emissions, caused mainly by incomplete combustion, include particulate matter (PM)
(mainly PM less than 10 micrometers in diameter [PM-10]), carbon monoxide (CO), sulfur oxides
(SOx), nitrogen oxides (NOx), and volatile organic compounds (VOC). Significant quantities of
unbumt 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
weight.
10/96
External Combustion Sources
1.9-1
-------
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.
Carbon dioxide (C02), methane (CH4), and nitrous oxide (N20) emissions are all produced
during wood combustion in residential fireplaces. Most of the fuel carbon in wood is converted to C02
during the combustion process, but because of ineffecient combustion, low combustion temperatures,
and large amounts of excess air, a much higher ratio of carbon monoxide to C02 is produced than for
combustion of wood in airtight wood stoves or wood-fired boilers. This formation of carbon
monoxide coupled with incomplete combustion acts to slightly reduce C02 emissions compared to
other types of wood combustion.14"19 C02 emitted from this source may not increase total
atmospheric C02. however, because emissions may be offset by the uptake of C02 by regrowing
biomass.
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Although no test data were available, it is assumed
that N20 emissions from residential fireplaces would be significantly higher than either wood stoves or
commercial wood-fired boilers because of the combination of low combustion temperatures and high
amounts of excess air.14"19
Methane emissions are highest during periods of low-temperature combustion or incomplete
combustion, both of which occur often in residential fireplaces. VOC emissions for residential
fireplaces are high compared to other wood combustion sources. Typically, conditions that favor
formation of N20 also favor emissions of CH4.14-19
Another important constituent of wood smoke is creosote. This tar-like substance will burn if
the fire is hot enough, but at insufficient temperatures, it may deposit on surfaces in the exhaust
system, Creosote deposits are a fire hazard 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.
In order to decrease PM and CO emissions from fireplaces, combustion must be improved.
Combustion efficiency improves as bum rate and flame intensity increase. Noncatalytic fireplace
inserts reduce emissions by directing unburned hydrocarbons and CO into an insulated secondary
chamber, where mixing with fresh, preheated makeup air occurs and combustion is enhanced 20
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 bum 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
Table 1.9-1. Table 1.9-1 presents emission factors on a weight basis (lb/ton). To convert from lb/ton
to lb/MMBtu. divide by a heating value of 17.3 MMBtuAon.
1.9-2
EMISSION FACTORS
10/96
-------
1.9.3 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/eig/).
Supplement A, February 1996
No changes.
Supplement B, October 1996
• References for tables were editorially corrected.
• Text was added concerning controls.
• An emission factor was added for N20.
10/96
External Combustion Sources
1.9-3
-------
Table 1.9-1. EMISSION FACTORS FOR WOOD COMBUSTION IN RESIDENTIAL
FIREPLACES3
(SCC 21-04-008-001)
EMISSION
Emission Factor
FACTOR
Device
Pollutant
(lb/ton)
RATING
Fireplace
PM-10b
34.6
B
COc
252.6
B
so,"
0.4
A
NO®
2.6
C
N2Of
0.3
E
co28
3400
C
Total VOCh
229.0
D
POM'
16 E-03
E
Aldehydesk'm
2.4
E
J
k
m
Units are in lb of pollutant/ton of dry wood burned. To convert lb/ton to kg/Mg, multiply by 0.5.
SCC = Source Classification Code.
References 2, 5, 7, 13; contains filterable and condensable PM, PM emissions are considered to be
100% PM-10.
References 2, 4-6, 9, 11, 13.
References 1, 8.
References 4, 6, 9, 11; expressed as N02.
Reference 21.
References 5, 13.
References 1,4, 5. 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.
Data 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.
References For Section 1.9
1.
2,
DeAngelis, D. G., el al., Source Assessment: Residential Combustion Of Wood,
EPA-600/2-80-042b, U. S. Environmental Protection Agency, Cincinnati, OH, March 1980.
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,, "Particulate And Gaseous Emissions From Wood-burning Fireplaces",
Environmental Science And Technology, 76(10):643-67, October 1982.
1.9-4
EMISSION FACTORS
10/96
-------
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.
14. L. P. Nelson, et al., Global Combustion Sources Of Nitrous Oxide Emissions, Research
Project 2333-4 Interim Report, Sacramento: Radian Corporation, 1995.
15. R. L. Peer, et al., Characterization Of Nitrous Oxide Emission Sources, Prepared for the US
EPA Contract 68-D1-0031, Research Triangle Park, NC: Radian Corporation, 1995.
16. S. D. Piccot, et al., Emissions And Cost Estimates For Globally Significant Anthropogenic
Combustion Sources OfNOr Nfi, CH4, CO, And C02, EPA Contract No. 68-02-4288,
Research Triangle Park, NC: Radian Corporation, 1990.
17. G. Marland, and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure
For Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide
Research Division, Office of Energy Research, U.S. Department of Energy, Oak Ridge,
TN, 1983.
18. G. Marland and R. M. Rotty, "Carbon Dioxide Emissions From Fossil Fuels: A Procedure
For Estimation And Results For 1950-1982," Tellus, 36B: 232-261.
10/96
External Combustion Sources
1.9-5
-------
19. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the
Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of
1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy.
20. Guidance Document For Residential Wood Combustion Emission Control Measures,
EPA-4502-89-015, U. S. Environmental Protection Agency, Research Triangle Park, NC,
September 1989.
21. Ortech Corporation, Inventory Methods Manual for Estimating Canadian Emissions of
Greenhouse Gases, prepared for Environment Canada, 1994.
1.9-6
EMISSION FACTORS
10/96
-------
1.10 Residential Wood Stoves
1.10.1 General1"2
Wood stoves are enclosed wood heaters that control burning or burn time by restricting the
amount of air that can be used for combustion; they 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. Based on known variations in construction, combustion, and emission characteristics, there
are five different categories of residential wood burning devices: (1) the conventional wood stove; (2)
the noncatalvtic wood stove; (3) the catalytic wood stove; (4) the pellet stove; and (5) the masonry
heater.
The conventional stove category comprises all stoves without catalytic combustors not included
in the other noncatalvtic categories (i. e., noncatalvtic 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 with various airflow designs may be in this category, such as updraft, downdraft,
crossdraft, and S-flow.
Noncatalvtic wood stoves are those units that do not employ catalysts but that do have
emission reducing technology or features. Typical noncatalvtic 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 bum, 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 1764 lb). Masonry heaters are gaining popularity as a cleaner-buming, heat-
efficient form of primary and supplemental heat, relative to some other types of wood heaters. In a
masonry heater, a complete charge of wood is burned in a relatively short period of time. The use of
masonry materials promotes heat transfer. Thus, radiant heat from the heater warms the surrounding
area for many hours after the fire has burned out.
1 10.2 Emissions
The combustion and pyrolysis of wood in wood stoves produce atmospheric emissions of
particulate matter (PM), CO, nitrogen oxides (NOx), VOC, mineral residues, and to a lesser extent,
sulfur oxides (SOx). The quantities and types of emissions are highly variable, depending on a
10/96
External Combustion Sources
1.10-1
-------
number of factors, including stage of the combustion cycle. During initial burning stages, after a new
wood charge is introduced, emissions (primarily VOCs) increase dramatically. After the initial period
of high burn rate, there is a charcoal stage of the burn cycle characterized by a slower bum rate and
decreased emissions. Emission rates during this stage are cyclical, characterized by relatively long
periods of low emissions and shorter episodes of emission spikes.
Particulate emissions are defined in this discussion as the total catch measured by the EPA
Method 5H (Oregon Method 7) sampling train.1 A small portion of wood stove particulate emissions
includes "solid" particles of elemental carbon and wood. The vast majority of particulate emissions
are 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
SOx are formed by oxidation of sulfur in the wood. NOx are formed by oxidation of fuel and
atmospheric nitrogen. Mineral constituents, such as potassium and sodium compounds, are released
from the wood matrix during combustion.
The high levels of organic compounds and CO emissions result from 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 (CI - C7) (which exist
as gases or which volatilize at ambient conditions) and complex low-volatility substances that
condense at ambient conditions. These low volatility condensable materials generally are considered
to have boiling points below 572°F.
Polycyclic organic matter (POM) is an important component of the condensable 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. These
compounds are classified as hazardous air pollutants under Title III of the 1990 Clean Air Act
Amendments, which contains the sub-group of hydrocarbons called polycyclic aromatic hydrocarbons
(PAH).
1.10.3 Controls4
To decrease PM and CO emissions from wood stoves, combustion efficiency must increase.
Both catalytic and noncatalytic control techniques increase efficiency and decrease emissions.
Catalytic combustors reduce emissions by using a ceramic catalyst coated with a noble metal
(e. g., palladium or platinum) which allows organics and other combustibles to burn at temperatures
much lower than required in a noncatalytic firebox.
Older, noncatalytic wood stoves reduce emissions by directing unbumed hydrocarbons (HCs)
and CO into a secondary chamber, where mixing with fresh, preheated makeup air enhances further
combustion. Current noncatalytic wood stoves inject fresh secondary air into the top of the primary
combustion chamber, allowing ignition of the HCs. Multiple air channels, some with their own
controls, coupled with baffles which trap and retain heat in the top of the firebox facilitate this
combustion.
Emission factors and their ratings for wood combustion in residential wood stoves, pellet
stoves, and masonry heaters are presented in Tables 1.10-1, 1.10-2, 1.10-3, 1.10-4, 1.10-5, 1.10-6, and
1.10-7. Tables in this section present emission factors on a weight basis (lb/ton). To convert to an
energy basis (lb/MMBtu). divide by a heating value of 17.3 MMBtu/ton. The analysis leading to the
revision of these emission factors is contained in the emission factor documentation 4 These tables
1.10-2
EMISSION FACTORS
10/96
-------
include emission factors for criteria pollutants (PM-10, CO, NOx. SOx), carbon dioxide (C02), 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 II stoves are those certified to meet the July 1, 1990, EPA
standards; Phase I stoves meet only the July I, 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.'
The emission factors for PM and CO in Tables 1,10-1 and 1,10-2 are averages, derived
entirely from field test data obtained under actual operating conditions. Still, there is a potential for
higher emissions from some wood stove, pellet stove, and masonry heater models. Particulate
emissions are presented as the total PM 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. Conversions arc employed, as appropriate, for data collected with other methods.
Table 1.10-5 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 that is used, along with emission factors and percent
degradation, to calculate 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.
1.10.4 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A. February 1996
No changes.
Supplement B. October 1996
• Text was added concerning controls.
• Reference 15 was corrected.
• The emission factor for phenanthrene was corrected.
• Information was incorporated concerning methane and nonmethane-HC.
10/96
External Combustion Sources
1.10-3
-------
0
1
Table 1.10-1. EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION3
tn
2
NM
tn
M
o
z
Tl
>
o
3
73
c/>
Pellet Stove Type,0
Masonry Heater,
Emission Factor
Emission Factor
Wood Stove Type
(lb/ton)
(lb/ton)
Emission Factor
(SCC
(SCC
(lb/ton)
21-04-008-053)
21-04-008-055)
EMISSION
Conventional
Noncatalytic
Catalytic
Pollutant/EPA
FACTOR
(SCC
(SCC
(SCC
Certiricationb
RATING
21-04-008-051)
21-04-008-050)
21-04-008-030)
Certified
Exempt
Exempt"1
PM-10®
Pre-Phase I
B
30.6
25.8
24.2
ND
ND
ND
Phase I
B
ND
20.0
19.6
ND
ND
ND
Phase II
B
ND
14.6
16.2
4.2
ND
ND
All
B
30.6
19.6
20.4
4.2
8.8
5.6
CO
Pre-Phase I
B
230.8
ND
ND
ND
ND
ND
Phase I
B
ND
ND
104.4
ND
ND
ND
Phase II
B
ND
140.8
107.0
39.4
ND
ND
All
B
230.8
140.8
104.4
39.4
52.2
149.0
NOx
2.8f
ND
2,0«
13.8«
ND
ND
sox
B
0.4
0.4
0.4
0.4
ND
ND
ccy
C
ND
ND
ND
2952
3671
3849
TOCk
C
83
28
26.6
ND
ND
ND
Methane
C
30
16
11,6
ND
ND
ND
TNMOC
C
53
12
15
ND
ND
ND
so
o\
a To convert from lb/ton to kg/Mg, multiply by 0.5. SCC = Source Classification Code. NT) = no data. TNMOC = total nonmethane organic compounds.
b Pre-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.
0 Certified = Certified pursuant to 1988 NSPS; Exempt = Exempt from 1988 NSPS (i. e., air-to-fuel ratio > 35:1).
d Exempt = Exempt from 1988 NSPS (i. e., device weight >800 kg),
e References 5-18. PM-10 is defined as equivalent to total catch by EPA method 5H train.
f EMISSION FACTOR RATING: C.
s EMISSION FACTOR RATING: E.
h References 12, 15-18.
CO, emitted from this source may not increase total atmospheric C02 because the emissions may be offset by the uptake of COj by rcgrowing biomass.
k References 12, 19-22. Data show a high degree of variability within the source population. Factors may not be accurate for individual sources.
-------
Table 1.10-2. ORGANIC COMPOUND EMISSION FACTORS
FOR RESIDENTIAL WOOD COMBUSTIONab
EMISSION FACTOR RATING: E
Wood Stove Type Emission Factor (lb/ton)
Conventional
Catalytic
Compounds
(SCC 21-04-008-051)
(SCC 21-04-008-030)
Ethane
1.470
1.376
Ethylene
4.490
3.482
Acetylene
1.124
0.564
Propane
0.358
0.158
Propene
1.244
0.734
i-Butane
0.028
0.010
n-Butane
0.056
0.014
Butenes0
1.192
0.714
Pentenesd
0.616
0.150
Benzene
1.938
1,464
Toluene
0.730
0.520
Furan
0.342
0.124
Methyl Ethyl Ketone
0.290
0.062
2-Methyl Furan
0.656
0.084
2,5-Dimethyl Furan
0.162
0.002
Furfural
0.486
0,146
o-Xylene
0.202
0.186
a Reference 19. To convert from lb/ton to
-------
Table 1.10-3. PAH EMISSION FACTORS FOR RESIDENTIAL WOOD COMBUSTION8*
EMISSION FACTOR RATING: E
Stove Type Emission Factor (lb/ton)
Conventional6
Noncatalyticd
Catalytic6
Exempt Pellet^
(SCC
(SCC
(SCC
(SCC
Pollutant
21-04-008-051)
21-04-008-050)
21-04-008-030)
21-04-008-053)
PAH
Acenaphthene
0.010
0.010
0.006
ND
Acenaphthylene
0.212
0.032
0.068
ND
Anthracene
0.014
0.009
0.008
ND
Benzo(a)Anthracene
0.020
<0.001
0.024
ND
Benzo(b)Fluoranthene
0.006
0.004
0.004
2.60 E-05
Benzo(gJi,i)Fluoranthene
ND
0.028
0.006
ND
Benzo(k)Fluoranthene
0.002
<0.001
0.002
ND
Benzo(g,h,i)Perylene
0.004
0.020
0.002
ND
Benzo(a)Pyrene
0.004
0.006
0.004
ND
Benzo(e)Pyrene
0.012
0.002
0.004
ND
Biphcnyl
ND
0.022
ND
ND
Chrysene
0.012
0.010
0,010
7.52 E-05
Dibenzo(a,h)Anthracene
BDL
0.004
0.002
ND
7,12-Dimethylbeiiz(a)Anthracene
ND
0.004
ND
ND
Fluoranthene
0.020
0,008
0.012
5.48 E-05
Fluorene
0.024
0.014
0.014
ND
Indeno( 1,2,3 ,cd)Pyrene
BDL
0.020
0.004
ND
9-Methylanthraccne
ND
0.004
ND
ND
12-Methylbenz(a)Anthracene
ND
0.002
ND
ND
3-Methylchlolanthraie
ND
<0.001
ND
ND
1 -Methy lphenanthrcne
ND
0.030
ND
ND
Naphthalene
0.288
0.144
0.186
ND
Nitronaphthalene
ND
BDL
ND
ND
Perylene
ND
0.002
ND
ND
Phenanthrene
0.078
0.118
0.048
3.32 E-05
Phenanthrol
ND
BDL
ND
ND
Phenol
ND
<0.001
ND
ND
Pyrene
0.024
0.008
0,010
4.84 E-05
PAH Total
0.730
<0.500
0.414
2.38 E-04
a To convert from lb/ton to kg/Mg, multiply by 0.5. SCC = Source Classification Code.
ND = no data. BDL = below detection limit. < = values are below this detection limit.
b 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.
c Reference 19.
d References 20,23-25.
e References 13,19-20,23,26.
f Reference 18. Exempt = Exempt from 1988 NSPS (i. e., air-to-fuel ratio > 35:1).
1.10-6
EMISSION FACTORS
10/96
-------
Table 1.10-4. TRACE ELEMENT EMISSION FACTORS FOR RESIDENTIAL WOOD
COMBUSTION3-15
EMISSION FACTOR RATING: E
Element
Wood Stove Type Emission Factor (lb/ton)
Conventional
(SCC 21-04-008-051)
Noncatalytic
(SCC 21-04-008-050)
Catalytic
(SCC 21-04-008-030)
Cadmium (Cd)
2.2 E-05
2.0 E-05
4,6 E-05
Chromium (Cr)
<1.0 E-06
<1.0 E-06
<1,0 E-06
Manganese (Mn)
1.7 E-04
1.4 E-04
2.2 E-04
Nickel (Ni)
1.4 E-05
2.0 E-05
2,2 E-06
a References 19,25, To convert from lb/ton to kg.'Mg, multiply by 0.5, SCC - Source Classification
Code. < = values are below this detection limit.
b 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 1.10-5. SUMMARY OF WOOD STOVE NET EFFICIENCIES3
Wood Heater Type
Source
Classification
Code
Net Efficiency (%)
Reference
Wood Stoves
Conventional
21-04-008-051
54
16
Noncatalytic
21-04-008-050
68
7,10,16
Catalytic
21-04-008-030
68
16,27
Pellet Stoves
Certifiedb
21-04-008-053
68
9
Exempt0
56
17
Masonry Heaters
All
21-04-008-055
58
18
8 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.
References 5,8,10-11,17-18,28.
b Certified = Certified pursuant to 1988 NSPS.
c Exempt = Exempt from 1988 NSPS (i. e., air-to-fuel ratio >35:1).
10/96
External Combustion Sources
1.10-7
-------
References For Section 1.10
1. Standards Of Performance For New Stationary Sources: New Residential Wood Heaters,
53 FR 557bj February 26, 1988.
2. R. Gay 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. J. A. Rau 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. 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.
5. S. G. Barnett, Field Performance Of Advanced Technology Woods toves In Glens Falls, N.Y.
1988-1989., Vol. 1, New York State Energy Research and Development Authority, Albany,
NY, October 1989.
6. P. G. Burnet, The Northeast Cooperative Woodstove Study, Volume I, EPA-600/7-87-026a, U.
S. Environmental Protection Agency, Cincinnati, OH, November 1987.
7. D. R. Jaasma and M. R. Champion, Field Performance Of Woodburning Stoves In Crested
Butte During The 1989-90 Heating Season, Town of Crested Butte, Crested Butte, CO,
September 1990.
8. S. Dcmbach. Woodstove Field Performance In Klamath Falls, OR, Wood Heating Alliance,
Washington, DC, April 1990.
9. C. A. Simons and S. K. Jones, Performance Evaluation Of The Best Existing Stove Technology
(BEST) Hybrid Woodstove And Catalytic Retrofit Device, Oregon Department Of
Environmental Quality, Portland, OR, July 1989.
10. S. G. Barnett 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.
11. S. G. Barnett, In-Home Evaluation Of Emission Characteristics Of EPA-Certifed High-Tech
Non-Catalytic Woods toves 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.
12. R. C. McCrillis 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.
13. K. E. Leese and S. M. Harkins, Effects Of Burn Rate, Wood Species, Moisture Content And
Weight Of Wood Loaded On Woodstove Emissions, EPA-600/2-89-025, U. S. Environmental
Protection Agency, Cincinnati, OH, May 1989.
1.10-8
EMISSION FACTORS
10/96
-------
14. S. G. Bamett, In-Home Evaluation Of Emissions From A Tulikivi KTU 2100 Masonry Heater,
OMNI Environmental Services, Inc., Beaverton, OR, March 1992.
15. S. G. Bamett, In-Home Evaluation Of Emissions From A Royal Crown 2000 Masonry Heater,
OMNI Environmental Services, Inc., Beaverton, OR, March 1992.
16. S. G. Bamett, In-Home Evaluation Of Emissions From A Biofire 4x3 Masonry Heater, OMNI
Environmental Services, Inc., Beaverton, OR, March 1992.
17. S. G. Bamett 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.
18. S. G. Bamett and P. G. 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.
19. P. G. Bumet, el a I., Effects Of Appliance Type And Operating Variables On Woodstove
Emissions, Vol. I., Report and Appendices 6-C, EPA-600/2-90-001 a, U. S. Environmental
Protection Agency, Cincinnati, OH, January 1990.
20. L. E. Cottone and E. Mesner, Test Method Evaluations And Emissions Testing For Rating
Wood Stoves, EPA-600/2-86-100, U. S. Environmental Protection Agency, Cincinnati, OH.
October 1986.
21. Letter and attachments to Susan Stamey-Hall, Radian Corp. from Robert C. McCrillis, U. S.
EPA concerning VOC emissions from wood stoves. May 8, 1995.
22. Jaasma. D. R, Stem, C. H., and M. Champion, Field Performance Of Woodburning Stove In
Crested Butte Durring The 1991-92 Heating Season, EPA-600/R-94-061, U. S. Environmental
Protection Agency, Research Triangle Park, April 1994.
23. J. M. Allen et ah, Study of the Effectiveness Of A Catalytic Combustion Device On A Wood
Burning Appliance, EPA-600/7-84-046, U. S. Environmental Protection Agency, Research
Triangle Park, NC, March 1984.
24. R. S. Truesdale 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.
25. Residential Wood Heater Test Report, Phase II Testing, Vol. 1, TV A, Division Of Energy,
Construction And Rates, Chattanooga, TN, August 1983.
26. D. G. DeAngelis, 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,
27. C. A. Simons 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.
10/96 External Combustion Sources 110-9
-------
S. G. Bamett, Summary Report Of The In-Home Emissions And Efficiency Performance Of
Five Commercially Available Masonry Heaters, the Masonry Heater Association, Reston, VA,
May 1992,
-10
EMISSION FACTORS
10/96
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1.11 Waste Oil Combustion
1.11.1 General1
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 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. Waste, or used, oil can be bumed in a variety of
combustion systems including industrial boilers; commercial/institutional boilSrs; 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 250,000 British thermal units per hour [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 bum 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 Emissions1
The emissions from burning waste oils reflect the compositional variations of the waste oils.
Potential pollutants include carbon monoxide (CO), sulfur oxides (SOx), nitrogen oxides (NOx),
particulate matter (PM). particles less than 10 micrometers in size (PM-10), toxic metals, organic
compounds, hydrogen chloride, and global warming gases (carbon dioxide [COj], methane [CH4]).
Particulate Matter1 -
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. 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.
Sulfur Oxides1 -
Emissions of SOx are a function of the sulfur content of the fuel. The sulfur content varies
but some data suggest that uncontrolled SOx emissions will increase when waste oil is substituted for a
distillate oil but will decrease when residual oil is replaced.
Chlorinated Organics1 -
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 addition of 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 bum waste oils, the presence of these
compounds in the emission stream cannot be ruled out.
10/96
External Combustion Sources
1.11-1
-------
Other Organics1 -
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 poh chlorinated 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.
1.11.3 Controls1
Emissions can be controlled by the pretreatment of the waste oil to remove the pollutant
precursors or with emission controls to remove the air pollutants. Reduction of emission levels is not
the only purpose of pretreatment of the waste oil. Improvement in combustion efficiency and
reduction of erosion and corrosion of the combustor internal surfaces are important considerations.
The most common pretreatment scheme uses sedimentation followed by filtration. Water and large
particles (greater than 10 microns in diameter) are removed without having much effect on sulfur,
nitrogen, or chlorine contents. Other methods of pretreatment involve clay contacting; demetallization
by acid, solvent, or chemical contacting; and thermal processing to remove residual water and light
ends. These latter processes might be attractive as waste reduction schemes or to recycle the waste
oil, but the added costs probably hinder their use as part of a combustion process.
Blending of waste oil with a virgin fuel oil is practiced frequently and has the same effect as
some of the other pretreatment processes. However, for the purpose of developing emission factors,
blending by itself was assumed to be in the uncontrolled category.
Waste oil serves as a substitute fuel for combustors designed to bum distillate or residual oils.
Therefore, the emission controls are usually those in place when waste oil is first bumed. For small
boilers and space heaters, all of the sources having acceptable test data for determining emission
factors were uncontrolled. For an asphalt plant, PM emissions, which included the dust from drying of
the aggregate, were controlled with a fabric filter.
Emission factors and emission factor ratings for waste oil combustion are shown in
Tables 1.11-1, 1.11-2, 1.11-3, 1.11-4, and 1,11-5. Emission factors have been determined for
emissions from uncontrolled small boilers and space heaters combusting waste oil. These factors
apply to both blended and unblended waste oil fuels when waste oil comprises the majority of the fuel
combusted. If virgin oil comprises the majority of the fuel combusted, the emission factors presented
in Section 1.3, Fuel Oil Combustion, should be used.
Evaporative emissions from waste oil used as a diluent in batch asphalt plants may be
estimated using the procedures outlined in Section 4.5.
Tables in this section present emission factors on a volume basis (lb/103gal). To convert to an
energy basis (lb/MMBtu), divide by the healing value of the oil in units of MMBtu/103gal, if known.
If the heating value is not known, and the waste oil is blended with residual oil, divide by a heating
value of 150 MMBtu/103gal. If the waste oil is blended with distillate oil, divide by a heating value
of 140 MMBtu/103gaJ.
1.11.4 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
1.11-2
EMISSION FACTORS
10/96
-------
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
• An earlier transcription error was corrected and the TOC emission factor was changed
from 0.1 to 1.0 lb/1000 gal.
Supplement B, October 1996
• Math errors were corrected and factors for As, Be, Cd, Cr, Co, and speciated organics
were changed.
• The C02 factors were revised based on a review of existing information.
10/96
External Combustion Sources
1.11-3
-------
Table 1.11-1. EMISSION FACTORS FOR PARTICULATE MATTER (PM), PARTICULATE MATTER LESS THAN
10 MICROMETERS (PM-10), AND LEAD (Pb) FROM WASTE OIL COMBUSTORSa
Source Category
(SCC)
PMb
PM-10C
Pbd
Emission
Factor (lb/103
gal)
EMISSION
FACTOR
RATING
Emission
Factor (lb/103
gal)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Small boilers (1-03-013-02)
Space heaters Vaporizing burner
(1-05-001-14, 1-05-002-14)
Atomizing burner
(1-05-001-13, 1-05-002-13)
64Ad C
2.8A D
66A D
51A C
ND NA
57A E
55Lf D
0.41L D
50L D
C/D
C/3
O
Z
T)
>
o
H
o
on
Classification Code. ND = no data. NA = not applicable.
References 2-5.
Reference 1.
References 4-6.
A = weight % ash in fuel. Multiply numeric value by A to obtain emission factor. For example, if ash content is 5%, then A = 5.
L = weight % lead in fuel. Multiply numeric value by L to obtain emission factor. For example, if lead content is 5%, then L = 5.
o
v©
ON
-------
Table 1.11-2. EMISSION FACTORS FOR NITROGEN OXIDES (NOx), SULFUR OXIDES (SOx),
AND CARBON MONOXIDE (CO) FROM WASTE OIL COMBUSTORS3
Source Category
(SCC)
NOxb
SOxb
COc
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Emission
Factor (lb/103
gal)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Small boilers (1-03-013-02)
Space heaters Vaporizing burner
(1-05-001-14, 1-05-002-14)
Atomizing burner
(1-05-001-13, 1-05-002-13)
19 C
11 D
16 D
147Sd C
100Sd D
107Sd D
5 D
1.7 D
2.1 D
a Units are lb of pollutant/10 gallons of blended waste oil burned. To convert from lb/10 gallons to kg/m , multiply by 0.12. SCC = Source
Classification Code.
References 4, 7,
c References 2, 5.
* 7
S = weight % sulfur in fuel. Multiply numeric value by S to obtain emission factor. For example, if sulfur content is 3.4%, then S = 3.4.
-------
Table 1.11-3. EMISSION FACTORS FOR TOTAL ORGANIC COMPOUNDS (TOC), HYDROGEN
CHLORIDE (HC1), AND CARBON DIOXIDE (C02) FROM WASTE OIL C0MBUST0RS3
m
§
c/j
O
25
>
O
3
JO
C/3
TOCb
HClb
C02c
Source Category
(SCC)
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Emission
Factor (lb/103
gal)
EMISSION
FACTOR
RATING
Emission
Factor
(lb/103 gal)
EMISSION
FACTOR
RATING
Small boilers (1-03-013-02)
1.0
D
66Cld
C
22,000
C
Space heaters Vaporizing burner
(1-05-001-14, 1-05-002-14)
1.0
D
ND
NA
22,000
D
Atomizing burner
(1-05-001-13, 1-05-002-13)
1.0
D
ND
NA
22,000
D
3 Units are lb of pollutant/10 gallons of blended waste oil burned. To convert from lb/10 gallons to kg/m , multiply by 0.12. SCC = Source
Classification Code. ND = no data. NA = not applicable.
b Reference 1.
c References 2-4. Ranges from 18,000 to 25,000 lb of CO2/103gal, depending on carbon content.
d CI = weight % chlorine in fuel. Multiply numeric value by CI to obtain emission factor. For example, if chlorine content is 3%, CI = 3.
o
\o
ON
-------
Table 1.11-4. EMISSION FACTORS FOR SPECIATED METALS FROM WASTE OIL COMBUSTORS"
EMISSION FACTOR RATING: D
Pollutant
Small Boilers Emission Factor
(lb/103 gal)b
(SCC 1-03-013-02)
Space Heaters: Vaporizing Burner
Emission Factor (lb/10 gal)c
(SCC 1-05-001-14, 1-05-002-14)
Space Heaters: Atomizing Burner
Emission Factor (lb/103 gal)c
(SCC 1-05-001-13, 1-05-002-13)
Antimony
BDL
3.4 E-04
4.5 E-03
Arsenic
1.1 E-01
2.5 E-03
6.0 E-02
Beryllium
BDL
BDL
18 E-03
Cadmium
9.3 E-03
1.5 E-04
1.2 E-02
Chromium
2,0 E-02
1.9 E-01
1.8 E-01
Cobalt
2.1 E-04
5.7 E-03
5.2 E-03
Manganese
6.8 E-02
2.2 E-03
5.0 E-02
Nickel
1.1 E-02
5.0 E-02
1.6 E-01
Selenium
BDL
BDL
BDL
Phosphorous
ND
3.6 E-02
ND
a 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. Units are lb of pollutant/103 gallons of waste oil
burned. To convert from lb/103 gallons to kg/m3, multiply by 0.12 BDL = below detection limit. SCC = Source Classification Code. ND =
no data.
b Reference 4.
c References 4-5.
-------
Table 1.11-5. EMISSION FACTORS FOR SPECIATED ORGANIC COMPOUNDS FROM WASTE OIL C0MBUST0RS3
EMISSION FACTOR RATING: D
m
§
53
w
O
2:
>
O
H
O
*
C/5
Pollutant
Space Heaters: Vaporizing Burner
(SCC 1-05-001-14, 1-05-002-14)
Emission Factor (lb/103 gal)
Space Heaters: Atomizing Burner
(SCC 1-05-001-13, 1-05-002-13)
Emission Factor (lb/103 gal)
Phenol
2.4 E-03
2.8 E-05
Dichlorobenzene
8.0 E-07
ND
Naphthalene
1.3 E-02
9.2 E-05
Phenanthrene/anthracene
1.1 E-02
1.0 E-04
Dibutylphthalate
ND
3.4 E-05
Butylbenzylphthalate
5.1 E-04
ND
Bis(2-ethylhexyl)phthalate
2.2 E-03
ND
Pyrene
7.1 E-03
8.3 E-06
Benz(a)anthracene/chrysene
4.0 E-03
ND
Benzo(a)pyrene
4.0 E-03
ND
Trichloroethvlene
ND
ND
3 Reference 4. 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. Units are lb of pollutant/103 gallons
of waste oil burned. To convert from lb/103 gallons to kg/m3, multiply by 0.12. SCC = Source Classification Code. ND = no data.
o
vo
o\
-------
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 Combusk|p,
EPA-600/2-84-150, U. S. Environmental Protection Agency, Cincinnati, OH, September 1984.
3. Used Oil Burned As A Fuel, EPA-SW-892, U. S. Environmental Protection Agency,
Washington, DC, August 1980.
4. 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.
5. "Comparisons of Air Pollutant Emissions from Vaporizing and Air Atomizing Waste Oil
Heaters", Journal Of The Air Pollution Control Association, 33(7), July 1983.
6. "Waste Oil Combustion: An Environmental Case Study", Presented at the 75th Annual
Meeting of the Air Pollution Control Association, June 1982.
7. Chemical Analysis Of Waste Crankcase Oil Combustion Samples, EPA600/7-83-026,
U. S. Environmental Protection Agency, Research Triangle Park, NC, April 1983.
10/96
External Combustion Sources
1.11-9
-------
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).' 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 3 subparts of 40 CFR Part 60. Subpart E
covers MWC units that began construction after 1971 and have capacities to combust over 45 Mg/day
(50 tpd) of MSW. Subpart Ea establishes new source performance standards (NSPS) for MWC units
which began construction or modification after December 20, 1989 and have capacities over
225 Mg/day (250 tpd). An emission guideline (EG) was established under Subpart Ca covering
MWC units which began construction or modification prior to December 20, 1989 and have capacities
of greater than 225 Mg/day (250 tpd). The Subpart Ea and Ca regulations were promulgated on
February 11, 1991.
Subpart E includes a standard for particulate matter (PM), Subparts Ca and Ea currently
establish standards for PM, tetra- through octa- chlorinated dibenzo-p-dioxin/chlorinated
dibenzofurans (CDD/CDF), hydrogen chloride (HC1), sulfur dioxide (S02), nitrogen oxides (NO*)
(Subpart Ea only), and carbon monoxide (CO). Additionally, standards for mercury (Hg), lead (Pb),
cadmium (Cd), and NO, (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 3 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 3 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
10/96
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 Figure 2.1-1, Figure 2.1-2,
and Figure 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 2 chambers as with MOD/SA units, but is
functionally similar to mass burn units 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
EMISSION FACTORS
10/96
-------
o
OS
Overhead
Crane
Steam Drum
Steam
Economizer
Feed
Bin
Air
Pollution
Control
Device
Supei heater
Generator
Water Wall
Section
Drying
Grate
Combustion
_ Grate
Forced Draft Fan
Burnout
Crrate
Stack
Induced Draft Fan
Total Ash
Discharge
Feed Pit
Belt Conveyor
Riddling Conveyor
Vibrating
Conveyor
Secondary
Fan
Quench Tank
K>
Figure 2.1-1, Typical mass burn waterfall combustor.
-------
KJ
I
-P-
m
00
c«
»—t
s
>
n
H
o
5«
-------
VO
On
Overhead
Crane
GO
O
Q.
63
g
So'
•a
o
«>
£2.
Waste Tipping Floor
Stack
Emergency
Stack
Charging
Hopper
Air
Pollution
Control
Device
Drying
Grate
Ignition Grate
Mixing
Chamber
U
/ > i
Forced
Draft
Fan
Overfire
A;r Vibrating
Conveyor
Cooling
Sprays
for Bottom Ash
Quench
Pit
Bottom
Ash
Conveyor
Cooling
Chamber
Ash
Conveyors
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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 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 3 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 2 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 under fire 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 2 or 3 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
10/96
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combustion. Additional heat recovery occurs in the boiler waterwall, superheater, and economizer.
From the economizer, the flue gas is typically routed to APCDs.
2.1.2.3 Mass Burn Refractory Wall Combustors -
Prior to 1970 there were numerous MB/REF MWCs in operation. The purpose of these
plants was to achieve waste reduction; energy recovery was generally not incorporated in their design.
Most of the roughly 25 MB/REF plants that still operate or that were built in the 1970s and 1980s use
electrostatic precipitators (ESPs) to reduce PM emissions, and several have heat recovery boilers.
Most MB/REF combustors have unit sizes of 90 to 270 Mg/day (100 to 300 tpd). It is not expected
that additional plants of this design will be built in the United States.
The MB/REF combustors comprise several designs. One design involves a batch-fed upright
combustor, which may be cylindrical or rectangular in shape. A second design is based on a
rectangular combustion chamber with a traveling, rocking, or reciprocating grate. This type of
combustor is continuously fed and operates in an excess air mode. If the waste is moved on a
traveling grate, it is not sufficiently aerated as it advances through the combustor. As a result, waste
burnout or complete combustion is inhibited by fuel bed thickness, and there is considerable potential
for unburned waste to be discharged into the bottom ash pit. Rocking and reciprocating grate systems
stir and aerate the waste bed as it advances through the combustion chamber, thereby improving
contact between the waste and combustion air and increasing the burnout of combustibles. The
system generally discharges the ash at the end of the grate to a water quench pit for collection and
disposal in a landfill.
Because MB/REF combustors do not contain a heat transfer medium (such as the waterwalls
that are present in modern energy recovery units), they typically operate at higher excess air rates
(150 to 300 percent) than MB/WW combustors (80 to 100 percent). The higher excess air levels are
required to prevent excessive temperatures, which can result in refractory damage, slagging, fouling,
and corrosion problems. One adverse effect of higher excess air levels is the potential for increased
carryover of PM from the combustion chamber and, ultimately, increased stack emission rates. High
PM carryover may also contribute to increased CDD/CDF emissions by providing increased surface
area for downstream catalytic formation to take place. A second problem is the potential for high
excess air levels to quench (cool) the combustion reactions, preventing thermal destruction of organic
species.
An alternate, newer MB/REF combustor is the Volund design (Figure 2.1-3 presents this
MB/REF design). This design minimizes some of the problems of other MB/REF systems. A
refractory arch is installed above the combustion zone to reduce radiant heat losses and improve solids
burnout. The refractory arch also routes part of the rising gases from the drying and combustion
grates through a gas by-pass duct to the mixing chamber. There the gas is mixed with gas from the
burnout grate or kiln. Bottom ash is conveyed to an ash quench pit. Volund MB/REF combustors
operate with 80 to 120 percent excess air, which is more in line with excess air levels in the MB/WW
designs. As a result, lower CO levels and better organics destruction are achievable, as compared to
other MB/REF combustors.
2.1.2.4 Refuse-derived Fuel Combustors -
Refuse-derived fuel combustors burn MSW that has been processed to varying degrees, from
simple removal of bulky and noncombustible items accompanied by shredding, to extensive
processing to produce a finely divided fuel suitable for co-firing in pulverized coal-fired boilers.
Processing MSW to RDF generally raises the heating value of the waste because many of the
noncombustible items we removed.
10/96
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 particulate 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 2 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
10/96
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cyclone separator which recycles unburned waste and inert particles to the lower bed. Some of the
ash is removed from the cyclone with the solids from the bed.
Good mixing is inherent in the FBC design. Fluidized bed combustors have very uniform gas
temperatures and mass compositions in both the bed and in the upper region of the combustor. This
allows the FBCs to operate at lower excess air and temperature levels than conventional combustion
systems. Waste-fired FBCs typically operate at excess air levels between 30 and 100 percent and at
bed temperatures around 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 2 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 2 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 2 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.
10/96
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,
NO, 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, SOj),
- CO,
- NO„ 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 Particulate 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
2.1-12
EMISSION FACTORS
10/96
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conditions, solid fly ash particulates formed from inorganic, noncombustible constituents in MSW are
released into the flue gas. Most of this particulate is captured by the facility's APCD and are not
emitted to the atmosphere.
Particulate matter can vary greatly in size with diameters ranging from less than 1 micrometer
to hundreds of micrometers (/Am). Fine particulates, having diameters less than 10/*m (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 S02. Hydrogen
fluoride (HF), hydrogen bromide (HBr), and sulfur trioxide (S03) are also generally present, but at
much lower concentrations. Concentrations of HCI and S02 in MWC flue gases directly relate to the
chlorine and sulfur content in the waste. The chlorine and sulfur content vary considerably based on
seasonal and local waste variations. Emissions of S02 and HCI 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, HCI and S02 concentrations for mass burn and RDF units are
similar.
10/96
Solid Waste Disposal
2.1-13
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2.1.3.4 Carbon Monoxide -
Carbon monoxide emissions result when all of the carbon in the waste is not oxidized to
carbon dioxide (C02). High levels of CO indicate that the combustion gases were not held at a
sufficiently high temperature in the presence of oxygen (02) for a long enough time to convert CO to
C02. 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 C02 and
H20. 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 02 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 CDDs/CDFs 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 NO,; however, nitrogen dioxide (N02) and nitrous oxide (N,0) are also
formed in smaller amounts. The combination of the compounds is referred to as NO,. Nitrogen
oxides are formed during combustion through (I) oxidation of nitrogen in the waste, and (2) fixation
of atmospheric nitrogen. Conversion of nitrogen in the waste occurs at relatively low temperatures
(less 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 NO,
formed in MWCs is associated with nitrogen in the waste.
2.1.3.6 Organic Compounds -
A variety of organic compounds, including CDDs/CDFs, chlorobenzene (CB),
polychlorinated biphenyls (PCBs), chlorophenols (CPs), and polyaromatic hydrocarbons (PAHs), are
present in MSW or can be formed during the combustion and post-combination processes. Organics
in the flue gas can exist in the vapor phase or can be condensed or absorbed on fine particulates.
Control of organics is accomplished through proper design and operation of both the combustor and
the APCDs.
Based on potential health effects, CDD/CDF has been a focus of many research and
regulatory activities. Due to toxicity levels, attention is most often placed on levels of CDDs/CDFs
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-CDDs/CDFs.
2.1-14
EMISSION FACTORS
10/96
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2.1.4 Controls810
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.,
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., S02 and HQ) 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 kilojoules per coulomb
[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 ensure 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 /wn. As compared to pulverized coal fired combustors, in which only 1 to
3 percent of the fly ash is generally smaller than 1 /tm, 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 /*m. 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 meters per 304.8 cubic meters per minute (square feet
per 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.
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Solid Waste Disposal
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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.
As the flue gas flows through the filter bags, particulate is collected on the filter surface,
mainly through inertial impaction. The collected particulate builds up on the bag, forming a filter
cake. As the thickness of the filter cake increases, the pressure drop across the bag also increases.
Once pressure drop across the bags in a given compartment becomes excessive, that compartment is
generally taken off-line, mechanically cleaned, and then placed back on-line.
Fabric filters are generally differentiated by cleaning mechanisms. Two main filter cleaning
mechanisms are used: reverse-air and pulse-jet. In a reverse-air FF, flue gas flows through
unsupported filter bags, leaving the particulate on the inside of the bags. The particulate builds up to
form a particulate filter cake. Once excessive pressure drop across the filter cake is reached, air is
blown through the filter in the opposite direction, the filter bag collapses, and the filter cake falls off
and is collected. In a pulse-jet FF, flue gas flows through supported filter bags leaving particulate on
the outside of the bags. To remove the particulate filter cake, compressed air is pulsed through the
inside of the filter bag, the filter bag expands and collapses to its pre-pulsed shape, and the filter cake
falls off and is collected.
2.1.4.3 Spray Drying -
Spray dryers (SD) are the most frequently used acid gas control technology for MWCs in the
United States. When used in combination with an ESP or FF, the system can control CDD/CDF,
PM (and metals), S02, and HC1 emissions from MWCs. Spray dryer/fabric filter systems are more
common than SD/ESP systems and are used mostly on new, large MWCs. In the spray drying
process, lime slurry is injected into the SD through either a rotary atomizer or dual-fluid nozzles.
The water in the slurry evaporates to cool the flue gas, and the lime reacts with acid gases to form
calcium salts that can be removed by a PM control device. The SD is designed to provide sufficient
contact and residence time to produce a dry product before leaving the SD adsorber vessel. The
residence time in the adsorber vessel is typically 10 to 15 seconds. The particulate leaving the SD
contains fly ash plus calcium salts, water, and unreacted hydrated lime.
The key design and operating parameters that significantly affect SD performance are SD
outlet temperature and lime-to-acid gas stoichiometric ratio. The SD outlet approach to saturation
temperature is controlled by the amount of water in the slurry. More effective acid gas removal
occurs at lower approach to saturation temperatures, but the temperature must be high enough to
ensure the slurry and reaction products are adequately dried prior to collection in the PM control
device. For MWC flue gas containing significant chlorine, a minimum SD outlet temperature of
around 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 HCI and S02 in the
flue gas. At a ratio of 1.0, the moles of calcium are equal to the moles of incoming HCI and S02.
However, because of mass transfer limitations, incomplete mixing, and differing rates of reaction
(S02 reacts more slowly than HCI), 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.
2.1-16
EMISSION FACTORS
10/96
-------
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, 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 S02 to form alkali salts
(e. g., calcium chloride [CaCl,], calcium fluoride [CaFJ, and calcium sulfite [CaS03]). 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 (Na2C03), and sodium bicarbonate (NaHCO,). 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 2 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, S02 and lime react in the combustor, thus
providing a mechanism for effective removal of SO, 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
10/96
Solid Waste Disposal
2.1-17
-------
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, HQ removal may be lower than with DSL
Potential disadvantages of FSI include fouling and erosion of convective heat transfer surfaces by the
injected sorbent.
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 1- or 2-stage absorber
system. With single-stage scrubbers, the flue gas reacts with an alkaline scrubber liquid to
simultaneously remove HC1 and SO,. With two-stage scrubbers, a low-pH water scrubber for HC1
removal is installed upstream of the alkaline S02 scrubber. The alkaline solution, typically containing
calcium hydroxide (Ca[OHJ,), 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 Oxides 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 (FGR). 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 02 to reduce NO, formation. With
LEA, less air is supplied, which lowers the supply of 02 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 FGR, cooled flue gas and ambient air are mixed to become the combustion air.
This mixing reduces the O, content of the combustion air supply and lowers combustion temperatures.
Due to the lower combustion temperatures present in MWCs, most NO, 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 NO, emissions as compared to higher temperature
combustion devices (i. e., fossil fuel-fired boilers).
With SNCR, ammonia (NH,) or urea is injected into the furnace along with chemical
additives to reduce NO, 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
NO, 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 to 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 NO, formation and promotes reduction of NO, to N2. Natural gas reburning has been
evaluated on both pilot- and full-scale applications and achieved NO, reductions of 50 to 60 percent.
2.1-18
EMISSION FACTORS
10/96
-------
2.1.5 Mercury Controls11"14
Unlike other metals, Hg exists in vapor form at typical APCD operating temperatures. As a
result, collection of Hg in the APCD is highly variable. Factors that affect Hg control are good PM
control, low temperatures in the APCD system, and a sufficient level of carbon in the fly ash.
Higher levels of carbon in the fly ash enhance Hg 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.
Several mercury control technologies have been used on waste combustors in the
United States, Canada, Europe, and Japan. These control technologies include the injection of
activated carbon or sodium sulfide (Na2S) into the flue gas prior to the DSI- or SD-based acid gas
control system, or the use of activated carbon filters.
With activated carbon injection, Hg is adsorbed onto the carbon particle, which is then
captured in the PM control device. Test programs using activated carbon injection on MWCs in the
United States have shown Hg removal efficiencies of 50 to over 95 percent, depending on the carbon
feed rate.
Sodium sulfide injection involves spraying Na2S solution into cooled flue gas prior to the acid
gas control device. Solid mercuric sulfide is precipitated from the reaction of Na,S 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, 2.1-2, 2.1-3, 2.1-4, 2.1-5, 2.1-6, 2.1-7, 2.1-8, and 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 is 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.
10/96
Solid Waste Disposal
2.1-19
-------
JO
£ Table 2.1-1 (Metric Units). PARTICULATE MATTER, METALS, AND ACID GAS EMISSION FACTORS FOR MASS BURN
° AND MODULAR EXCESS AIR COMBUSTORS* "
M
U3
xn
O
z
Ti
>
o
H
O
50
in
Uncontrolled
ESP*
DSI/ESP"
SD/ESP
DSI/FF'
SD/FF"
Pollutant
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
PMh
1.26 E+01
A
1.05 E-01
A
2.95 E-02
E
3.52 E-02
A
8.95 E-02
A
3.11 E-02
A
As"
2.14 E-03
A
1.09 E-05
A
NDk
E
6.85 E-06
A
5.15 E-06
C
2.12 E-05
A
Crf
5.45 E-03
A
3.23 E-04
B
4.44 E-05
E
3.76 E-06
A
1.17 E-05
C
1.36 E-05
A
C.i*
4.49 E-03
A
5.65 E-05
B
1.55 E-05
E
1.30 E-04
A
1.00 E-04
C
1.50 E-05
A
Hgi
2.8 E-03
A
2.8 E-03
A
1.98 E-03
E
1.63 E-03
A
1.10 E-03
C
1.10 E-03
A
Ni"
3.93 E-03
A
5.60 E-05
B
1.61 E-03
E
1.35 E-04
A
7.15 E-05
C
2.58 E-05
A
PW
1.07 E-01
A
1.50 E-03
A
1.45 E-03
E
4.58 E-04
A
1.49 E-04
c
1.31 E-04
A
so2
1.73 E+00
A
ND
NA
4.76 E-01
C
3.27 E-01m
A
7.15 E-01
c
2.77 E-01m
A
HCJi
3.20 E+00
A
ND
NA
1.39 E-01
C
7.90 E-02M
A
3.19 E-01
c
1.06 E-01m
A
* All factors in kg/Mg refuse combusted. Emission factors were calculated from concentrations using an F-factor of 0.26 dscm/joule (J)
and a heating value of 10,466 J/g. Other heating values can be substituted by multiplying the emission factor by the new heating value
and dividing by 10,466 J/g. Source Classification Codes 5-01-001-04, 5-01-001-05, 5-01-001-06,
5-01-001-07, 5-03-001-11, 5-03-001-12, 5-03-001-13, 5-03-001-15. ND = no data. NA = not applicable.
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., SO^.
0 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
SD/FF = Spray Dryer/Fabric Filter
PM = Filterable particulate matter, as measured with EPA Reference Method 5.
Hazardous air pollutants listed in the Clean Air Act.
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.
VO
0\
-------
Table 2.1-2 (English Units). PARTICULATE MATTER, METALS, AND ACID GAS EMISSION FACTORS
FOR MASS BURN AND MODULAR EXCESS AIR COMBUSTORS" "
Uncontrolled
ESP0
DSI/ESpd
SD/ESPe
DSI/FFf
SD/FF8
Pollutant
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
PMh
2.51 E+01
A
2.10 E-01
A
5.90 E-02
E
7.03 E-02
A
1.79 E-01
A
6.20 E-02
A
As>
4.37 E-03
A
2.17 E-05
A
NDk
E
1.37 E-05
A
1.03 E-05
C
4.23 E-06
A
Cd>
1.09 E-02
A
6.46 E-04
B
8.87 E-05
E
7.51 E-05
A
2,34 E-05
c
2.71 E-05
A
Cr'
8.97 E-03
A
1.13 E-04
B
3.09 E-05
E
2.59 E-04
A
2.00 E-04
c
3.00 E-05
A
Hg>
5.6 E-03
A
5.6 E-03
A
3.96 E-03
E
3.26 E-03
A
2.20 E-03
c
2.20 E-03
A
Ni>
7.85 E-03
A
1.12 E-04
B
3.22 E-05
E
2.70 E-04
A
1.43 E-04
c
5.16 E-05
A
PW
2.13 E-01
A
3.00 E-03
A
2.90 E-03
E
9.15 E-04
A
2.97 E-04
c
2.61 E-04
A
so2
3.46 E+00
A
ND
NA
9.51 E-01
C
6.53 E-01m
A
1.43 E-00
c
5.54 E-01m
A
HCP
6.40 E+00
A
ND
NA
2.78 E-01
C
4.58 E-01™
A
6.36 E-01
c
2.11 E-01m
A
" All factors in lb/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. Source Classification Codes 5-01-001-04, 5-01-001-05, 5-01-001-06,
5-01-001-07, 5-03-001-11, 5-03-001-12, 5-03-001-13, 5-03-001-15. ND = no data. NA = not applicable.
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,, SOJ.
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
« SD/FF = Spray Dryer/Fabric Filter
h PM = Filterable particulate matter, as measured with EPA Reference Method 5.
j Hazardous air pollutants listed in the Clean Air Act.
k No data available at levels greater than detection limits.
m Acid gas emissions from SD/ESP- and SD/FF-equipped MWCs are essentially the same. Any differences are due to scatter in the
data.
-------
to
£ Table 2.1-3 (Metric Units). ORGANIC, NITROGEN OXIDES, CARBON MONOXIDE, AND CARBON DIOXIDE EMISSION
10 FACTORS FOR MASS BURN WATERWALL COMBUSTORSab
Pollutant
Uncontrolled
ESP
SD/ESPd
DSI/FP
SD/FF'
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
kg/Mg
EMISSION
FACTOR
RATING
CDD/CDF8
NO/
COh
C02j
8.35 E-07 A
1.83 E+00 A
2.32 E-01 A
9.85 E+02 D
5.85 E-07 A
*
*
3.11 E-07 A
*
*
*
8.0 E-08 C
*
*
*
3.31 E-08 A
#
#
*
m
§ a All factors in kg/Mg refuse combusted. Emission factors were calculated from concentrations using an F-factor of 0.26 dscm/J and a
heating value of 10,466 J/g. Other heating values can be substituted by multiplying the emission factor by the new heating value and
O dividing by 10,466 J/g. Source Classification Codes 5-01-001-05, 5-03-001-12. * = Same as "uncontrolled" for these pollutants.
Z
Ti
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, NO,).
Q 0 ESP = Electrostatic Precipitator
§ d SD/ESP = Spray Dryer/Electrostatic Precipitator
00 e DSI/FF = Duct Sorbent Injection/Fabric Filter
f SD/FF = Spray Dryer/Fabric Filter
g 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 1990 Clean Air Act.
h Control of NOx and CO is not tied to traditional acid gas/PM control devices.
j Calculated assuming a dry carbon content of 26.8% for feed refuse.126,135 C02 emitted from this source may not increase total
atmospheric C02 because emissions may be offset by the uptake of C02 by regrowing biomass.
o
o\
-------
Table 2,1-4 (English Units). ORGANIC, NITROGEN OXIDES, CARBON MONOXIDE, AND CARBON DIOXIDE EMISSION
FACTORS FOR MASS BURN WATERWALL COMBUSTORSab
Pollutant
Uncontrolled
ESP
SD/ESP
DSI/FP
SD/FF'
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
lb/ton
EMISSION
FACTOR
RATING
CDD/CDF8
NOxh
CO"
co2j
1.67 E-06 A
3.56 E+00 A
4.63 E-01 A
1.97 E+03 D
1.17 E-06 A
*
*
#
6.21 E-07 A
*
*
#
1.60 E-07 €
*
*
*
6.61 E-08 A
*
*
*
* All factors in lb/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. Source Classification Codes 5-01-001-05, 5-03-001-12. * = Same as "uncontrolled" for these pollutants.
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, NO J.
0 ESP = Electrostatic Precipitator
d SD/ESP = Spray Dryer/Electrostatic Precipitator
0 DSI/FF = Duct Sorbent Injection/Fabric Filter
f SD/FF = Spray Dryer/Fabric Filter
8 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 the 1990 Clean Air Act.
h Control of NO, and CO is not tied to traditional acid gas/PM control devices.
j Calculated assuming a dry carbon content of 26.8% for feed refuse.126,135 COz emitted from this source may not increase total
atmospheric C02 because emissions may be offset by the uptake of C02 by regrowing biomass.
-------
Table 2.1-5 (Metric And English Units). ORGANIC, NITROGEN OXIDES, CARBON MONOXIDE, AND CARBON DIOXIDE
EMISSION FACTORS FOR MASS BURN ROTARY WATERWALL COMBUSTORSa b
Pollutant
Uncontrolled
ESP
DSI/FFd
SD/FP
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
CDD/CDF*
NO/
CO8
co2h
ND ND NA
1.13 E+00 2.25 E+00 E
3.83 E-01 7.66 E-01 C
9.85 E+02 1.97 E+03 D
ND ND NA
* *
* *
* *
4.58 E-08 9.16 E-08 D
* *
~ *
* *
2.66 E-08 5.31 E-08 B
* #
* *
« *
" Emission factors were calculated from concentrations using an F-factor of 0.26 dscm/J (9,570 dscf/MBtu) and a heating value of
10,466 J/g (4,500 Btu/lb). Other heating values can be substituted by multiplying the emission factor by the new heating value and
dividing by 10,466 J/g (4,500 Btu/lb). Source Classification Codes 5-01-001-06, 5-03-001-13. ND = no data. NA = not applicable.
* = Same as "uncontrolled" for these pollutants.
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/FF = Duct Sorbent Injection/Fabric Filter
c SD/FF = Spray Dryer/Fabric Filter
f 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 the Clean Air Act.
8 Control of NO, and CO is not tied to traditional acid gas/PM control devices.
11 Calculated assuming a dry carbon content of 26.8% for feed refuse."6'1" C02 emitted from this source may not increase total
atmospheric CO, because emissions may be offset by the uptake of C02 by regrowing biomass.
-------
Table 2.1-6 (Metric And English Units), ORGANIC, NITROGEN OXIDES, CARBON MONOXIDE, AND CARBON DIOXIDE
EMISSION FACTORS FOR MASS BURN REFRACTORY WALL COMBUSTORS""
Pollutant
Uncontrolled
ESF
DSI/ESP11
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
CDD/CDP
NO/
C0
co2*
7.50 E-06 1.50 E-05 D
1.23 E+00 2.46 E+00 A
6.85 E-01 1.37 E+00 C
9.85 E+02 1.97 E+03 D
3.63 E-05 7.25 E-05 D
* *
* *
* *
2.31 E-07 4.61 E-07 E
# *
# *
# #
¦ Emission factors were calculated from concentrations using an F-factor of 0.26 dscm/J (9,570 dscf/MBtu) and a heating value of
10,466 J/g (4,500 Btu/lb). Other heating values can be substituted by multiplying the emission factor by the new heating value and
dividing by 10,466 J/g (4,500 Btu/lb). Source Classification Codes 5-01-001-04, 5-03-001-11. * = Same as "uncontrolled" for these
pollutants.
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, NO*).
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 the Clean Air Act.
f Control of NO, and CO is not tied to traditional acid gas/PM control devices.
8 Calculated assuming a dry carbon content of 26.8% for feed refuse.126,135 C02 emitted from this source may not increase total
atmospheric C02 because emissions may be offset by the uptake of C02 by regrowing biomass.
-------
tsJ
Table 2.1-7 (Metric And English Units). ORGANIC, NITROGEN OXIDES, CARBON MONOXIDE, AND CARBON DIOXIDE
EMISSION FACTORS FOR MODULAR EXCESS AIR COMBUSTORS" b
Pollutant
Uncontrolled
ESF
DSI/FF"
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
CDD/CDP
NO/
COf
CO,8
ND ND NA
1.24 E+00 2.47 E+00 A
ND ND NA
9.85 E+02 1.97 E+03 D
1.11 E-06 2.22 E-06 C
* #
* *
* *
3.12 E-08 6.23 E-08 E
* #
# *
* *
H * Emission factors were calculated from concentrations using an F-factor of 0,26 dscm/J (9,570 dscf/MBtu) and a heating value of
10,466 J/g (4,500 Btu/lb). Other heating values can be substituted by multiplying the emission factor by the new heating value and
$ dividing by 10,466 J/g (4,500 Btu/lb). Source Classification Codes 5-01-001-07, 5-03-001-15. ND = no data. NA = not applicable.
O * = Same as "uncontrolled" for these pollutants.
^ 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, NOJ.
h c ESP = Electrostatic Precipitator
§ d DSI/FF = Duct Sorbent Injection/Fabric Filter
00 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 the Clean Air Act.
' Control of NOx and CO is not tied to traditional acid gas/PM control devices.
8 Calculated assuming a dry carbon content of 26.8% for feed refuse126"5 C02 emitted from this source may not increase total atmospheric
C02 because emissions may be offset by the uptake of C02 by regrowing biomass.
©
vB
On
-------
Table 2.1-8 (Metric And English Units). EMISSION FACTORS FOR REFUSE-DERIVED FUEL-FIRED COMBUSTORSab
Uncontrolled
ESP0
SD/ESPd
SD/FFe
EMISSION
EMISSION
EMISSION
EMISSION
FACTOR
FACTOR
FACTOR
FACTOR
Pollutant
kg/Mg
lb/ton
RATING
kg/Mg
lb/ton
RATING
kg/Mg
lb/ton
RATING
kg/Mg
lb/ton
RATING
PMf
3.48 E + 01
6.96 E+01
A
5.17 E-01
1.04 E + 00
A
4.82 E-02
9.65 E-02
B
6.64 E-02
1.33 E-01
B
As8
2.97 E-03
5.94 E-03
B
6.70 E-05
1.34 E-04
D
5.41 E-06
1.08 E-05
D
2.59 E-06h
5.17 E-06h
A
Cd8
4.37 E-03
8.75 E-03
C
1.10 E-04
2.20 E-04
C
4.18 E-05
8.37 E-05
D
1.66 E-05h
3.32 E-05h
A
Cr8
6.99 E-03
1.40 E-02
B
2.34 E-04
4.68 E-04
D
5.44 E-05
1.09 E-04
D
2.04 E-05
4.07 E-05
D
Hg8
2.8 E-03
5.5 E-03
D
2.8 E-03
5.5 E-03
D
2.10 E-04
4.20 E-04
B
1.46 E-04
2.92 E-04
D
Ni8
2.18 E-03
4.36 E-03
C
9.05 E-03
1.81 E-02
D
9.64 E-05
1.93 E-04
D
3.15 E-05*
6.30 E-05i
A
Pb8
1.00 E-01
2.01 E-01
C
1.84 E-03h
3.66 E-03h
A
5.77 E-04
1.16 E-03
B
5.19 E-04
1.04 E-03
D
so2
1.95 E + 00
3.90 E + 00
C
ND
ND
NA
7.99 E-01
1.60E + 00
D
2.21 E-01
4.41 E-01
D
HC18
3.49 E+00
6.97 E + 00
E
*
*
ND
ND
NA
2.64 E-02
5.28 E-02
C
NO„k
2.51 E + 00
5.02 E + 00
A
*
*
*
*
*
*
cok
9.60 E-01
1.92 E + 00
A
~
*
*
*
*
*
co2m
1.34 E+03
2.68 E + 03
E
*
*
*
*
*
*
CDD/CDF"
4.73 E-06
9.47 E-06
D
8.46 E-06
1.69 E-05
B
5.31 E-08
1.06 E-07
D
1.22 E-08
2.44 E-08
E
a Emission factors were calculated from concentrations using an F-factor of 0.26 dscm/J (9,570 dscf/MBtu) and a heating value of 12,792 J/g
(5,500 Btu/lb). Other heating values can be substituted by multiplying the emission factor by the new heating value and dividing by 12,792 J/g
(5,500 Btu/lb). Source Classification Code 5-01-001-03. ND = no data. NA = not applicable. * = Same as uncontrolled for these pollutants.
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 (S02, NOx, CO).
c ESP = Electrostatic Precipitator
d SD/ESP = Spray Dryer/Electrostatic Precipitator
e SD/FF = Spray Dryer/Fabric Filter
f PM = total particulate matter, as measured with EPA Reference Method 5.
E Hazardous air pollutants listed in the Clean Air Act.
h 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 burn and MOD/EA combustors.
j No data available. Values shown are based on emission levels from SD/FF-equipped mass burn combustors.
k Control of NOx and CO is not tied to traditional acid gas/PM control devices.
m Based on source tests from a single facility.120 C02 emitted from this source may not increase total atmospheric C02 because emissions may be offset
by the uptake of C02 by regrowing biomass.
n 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 the Clean Air Act.
-------
Table 2.1-9 (Metric And English Units). EMISSION FACTORS FOR
MODULAR STARVED-AIR COMBUSTORSa b
Uncontrolled
ESP
Pollutant
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
kg/Mg
lb/ton
EMISSION
FACTOR
RATING
PM"
1.72 E+0G
3.43 E+00
B
1.74 E-01
3.48 E-01
B
As*
3.34 E-04
6.69 E-04
C
5.25 E-05
1.05 E-04
D
Cd'
1.20 E-03
2.41 E-03
D
2.30 E-04
4.59 E-04
D
Ci*
1.65 E-03
3.31 E-03
C
3.08 E-04
6.16 E-04
D
Hg,.f
2.8 E-03
5.6 E-03
A
2.8 E-03
5.6 E-03
A
Ni*
2.76 E-03
5.52 E-03
D
5.04 E-04
1.01 E-03
E
Pb*
ND
ND
NA
1.41 E-03
2.82 E-03
C
so2
1.61 E+00
3.23 E+00
E
#
HC1*
1.08 E+00
2.15 E+00
D
*
#
NO*
1.58 E+00
3.16 E+00
B
~
#
CO
1.50 E-01
2.99 E-01
B
*
*
co2h
9.85 E+02
1.97 E+03
D
#
*
CDD/CDF3
1.47 E-06
2.94 E-06
D
1.88 E-06
3.76 E-06
C
1 Emission factors were calculated from concentrations using an F-factor of 0.26 dscm/J (9,570 dscf/MBtu) and a
heating value of 10,466 J/g (4,500 Btu/lb). Other heating values can be substituted by multiplying the emission factor
by the new heating value and dividing by 10,466 J/g (4,500 Btu/lb), Source Classification Codes 5-01-001-01, 5-03-
001-14. ND = no data. NA = not applicable. * = Same as "uncontrolled" for these pollutants.
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, NOJ,
c ESP = Electrostatic Precipitator
d PM = total particulate matter, as measured with EPA Reference Method 5.
* Hazardous air pollutants listed in the Clean Air Act.
r Mercury levels based on emission levels measured at mass bum, MOD/EA, and MOD/SA combustors.
* Control of NO, and CO is not tied to traditional acid gas/PM control devices.
h Calculated assuming a dry carbon content of 26.8% for feed refuse.126,135 C02 emitted from this source may not
increase total atmospheric C02 because emissions may be offset by the uptake of C02 by regrowing biomass.
J 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 the Clean Air Act,
2.1-28
EMISSION FACTORS
10/96
-------
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
0.26 dry standard cubic meters per joule (dscm/J) (9,570 dry standard cubic feet per million British
thermal units [Btu]) and an assumed heating value of the waste of 10,466 J/g (4,500 Btu per pound
[Btu/lb]) for all combustors except RDF, for which a 12,792 J/g (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 making
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 S02, 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 S02, 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 Combustors122134
2.1.7.1 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.
2.1.7.2 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.
10/96
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
lb/ton refuse
4.03 x 106
8.06 x 10'*
/xg/dscm
For PM:
kg/Mg refuse
lb/ton refuse
4.03 x 103
8.06 x 103
mg/dscm
For HC1:
kg/Mg refuse
lb/ton refuse
6.15 x 10'3
1.23 x lO"2
ppmv
For SO2:
kg/Mg refuse
lb/ton refuse
1.07 x 10"2
2.15 x 10'7
ppmv
For NOx:
kg/Mg refuse
lb/ton refuse
7.70 x lO3
1.54 x 10"2
ppmv
For CO:
kg/Mg refuse
lb/ton refuse
4.69 x 103
9.4 x 10"3
ppmv
For C02:
kg/Mg refuse
lb/ton refuse
7.35 x lO"3
1.47 x 10"2
ppmv
At 1% 02.
2,1-30
EMISSION FACTORS
10/96
-------
Table 2.1-11. CONVERSION FACTORS FOR REFUSE-DERIVED FUEL COMBUSTORS
Divide
By To Obtain"
For As, Cd, Cr, Hg, Ni, Pb, and CDD/CDF:
kg/Mg refuse
lb/ton refuse
4.92 x 10"6 /ig/dscm
9.85 x 10-6
For PM:
kg/Mg refuse
lb/ton refuse
4.92 x 10"3 mg/dscm
9.85 x 103
For HC1:
kg/Mg refuse
lb/ton refuse
7.5 x 103 ppmv
1.5 x 10"2
For SO2:
kg/Mg refuse
lb/ton refuse
1.31 x 10"2 ppmv
2.62 x 102
For NOx:
kg/Mg refuse
lb/ton refuse
9.45 x 10"3 ppmv
1.89 x 102
For CO:
kg/Mg refuse
lb/ton refuse
5.75 x 103 ppmv
1.15 x 10"2
For C02:
kg/Mg refuse
lb/ton refuse
9.05 x 103 ppmv
1.81 x 10"2
a At 1% 02.
10/96
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 1 G-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.
2.1.7.3 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.
2.1.7.4 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
10/96
-------
o
gS Table 2.1-12 (Metric And English Units). UNCONTROLLED EMISSION FACTORS FOR REFUSE COMBUSTORS OTHER THAN
MUNICIPAL WASTE"
EMISSION FACTOR RATING: D
o
K>
T3
O
ws
E.
PM
so2
CO
Total Organic
Compounds'1
NO,
Combustor Type
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
Industrial/commercial
Multiple chamber
3.50 E+00
7.00 E+00
1.25 E+00
2.50 E+00
5.00 E+00
1.00 E+01
1.50 E+00
3.00 E+00
1.50 E+00
3.00 E+00
Single chamber
7.50 E+00
1.50 E+01
1.25 E+00
2.50 E+00
1.00 E+01
2.00 E+01
7.50 E+01
1.50 E+01
1.00 E+00
2.00 E+00
Trench
Wood
(SCC 5-01-005-10,
5-03-001-06)
6.50 E+00
1.30 E+01
5.00 E-02
1.00 E-01
ND
ND
ND
ND
2.00 E+00
4.00 E+00
Rubber tires
(SCC 5-01-005-11,
5-03-001-07)
6.90 E+01
1.38 E+02
ND
ND
ND
ND
ND
ND
ND
ND
Municipal refuse
(SCC 5-01-005-12,
5-03-001-09)
1.85 E+01
3.70 E+01
1.25 E+00
2.50 E+00
ND
ND
ND
ND
ND
ND
Flue-fed single chamber
1.50 E+01
3.00 E+01
2.50 E-01
5.00 E-01
1.00 E+01
2.00 E+01
7.50 E+00
1.50 E+01
1.50 E+00
3.00 E+00
Flue-fed (modified)
3.00 E+00
6.00 E+00
2.50 E-01
5.00 E-01
5.00 E+00
1.00 E+01
1.50 E+00
3.00 E+00
5.00 E+00
1.00 E+01
Domestic single chamber
(no SCC)
Without primary burner
1.75 E+01
3.50 E+01
2.50 E-01
5.00 E-01
1.50 E+02
3.00 E+02
5.00 E+01
1.00 E+02
5.00 E-01
1.00 E+00
With primary burner
3.50 E+00
7.00 E+00
2.50 E-01
5.00 E-01
Neg
Neg
1.00 E+00
2.00 E+00
1.00 E+00
2.00 E+00
* References 116-123. ND = no data. SCC = Source Classification Code. Neg = negligible.
b Expressed as methane.
K>
-------
References For Section 2.1
1. Written communication from D. A. Fenn and K. L. Nebel, Radian Corporation, Research
Triangle Park, NC, to W. H. Stevenson, U. S. Environmental Protection Agency, Research
Triangle Park, NC. March 1992.
2. J. Kiser, "The Future Role Of Municipal Waste Combustion", Waste Age, November 1991.
3. September 6, 1991. Meeting Summary: Appendix 1 (Docket No. A-90-45, Item
Number II-E-12).
4. Municipal Waste Combustion Study: Combustion Control Of Organic Emissions,
EPA/530-SW-87-021c, U. S. Environmental Protection Agency, Washington, DC, June 1987.
5. M. Clark, "Minimizing Emissions From Resource Recovery", Presented at the International
Workshop on Municipal Waste Incineration, Quebec, Canada, October 1-2, 1987.
6. Municipal Waste Combustion Assessment: Combustion Control At Existing Facilities,
EPA 600/8-89-058, U. S. Environmental Protection Agency, Research Triangle Park, NC,
August 1989,
7. Municipal Waste Combustors - Background Information For Proposed Standards: Control Of
NOx Emissions, EPA -450/3 -89-27d, U.S. Environmental Protection Agency, Research
Triangle Park, NC, August 1989.
8. Municipal Waste Combustors - Background Information For Proposed Standards: Post
Combustion Technology Performance, U. S. Environmental Protection Agency, August 1989.
9. Municipal Waste Combustion Study - Flue Gas Cleaning Technology, EPA/530-SW-87-021c,
U. S. Environmental Protection Agency, Washington, DC, June 1987.
10. R. Bijetina, et al., "Field Evaluation of Methane de-NOx at Olmstead Waste-to-Energy
Facility", Presented at the 7th Annual Waste-to-Energy Symposium, Minneapolis, MN,
January 28-30, 1992.
11. K. L. Nebel and D. M. White, A Summary Of Mercury Emissions And Applicable Control
Technologies For Municipal Waste Combustors, Research Triangle Park, NC, September,
1991.
12. Emission Test Report: OMSS Field Test On Carbon Injection For Mercury Control,
EPA-600/R-92-192, Office of Air Quality Planning and Standards, U. S. Environmental
Protection Agency, Research Triangle Park, NC, September 1992.
13. J. D. Kilgroe, et al., "Camden Country MWC Carbon Injection Test Results", Presented at
the International Conference on Waste Combustion, Williamsburg, VA, March 1993.
14. Meeting Summary: Preliminary Mercury Testing Results For The Stanislaus County
Municipal Waste Combustor, U. S. Environmental Protection Agency, Research Triangle
Park, NC, November 22, 1991.
2.1-34
EMISSION FACTORS
10/96
-------
15. R. A, Zuriinden, et al., Environmental Test Report, Alexandria/Arlington Resources Recovery
Facility, Units 1, 2, And 3, Report No. 144B, Ogden Martin Systems of
Alexandria/Arlington, Inc., Alexandria, VA, March 9, 1988.
16. R. A. Zuriinden, et al., Environmental Test Report, Alexandria/Arlington Resource Recovery
Facility, Units 1, 2, And 3, Report No. 144A (Revised), Ogden Martin Systems of
Alexandria/Arlington, Inc., Alexandria, VA, January 8, 1988.
17. Environmental Test Report, Babylon Resource Recovery Test Facility, Units 1 And 2, Ogden
Martin Systems of Babylon, Inc., Ogden Projects, Inc., March 1989.
18. Ogden Projects, Inc. Environmental Test Report, Units 1 And 2, Babylon Resource Recovery
Facility, Ogden Martin Systems for Babylon, Inc., Babylon, NY, February 1990.
19. PEI Associates, Inc. Method Development And Testing For Chromium, No. Refuse-to-Energy
Incinerator, Baltimore RESCO, EMB Report 85-CHM8, EPA Contract No. 68-02-3849,
U. S. Environmental Protection Agency, Research Triangle Park, NC, August 1986.
20. Entropy Environmentalists, Inc. Particulate, Sulfur Dioxide, Nitrogen Oxides, Chlorides,
Fluorides, And Carbon Monoxide Compliance Testing, Units 1, 2, And 3, Baltimore RESCO
Company, L. P., Southwest Resource Recovery Facility, RUST International, Inc., January
1985.
21. Memorandum. J. Perez, AM/3, State of Wisconsin, to Files. "Review Of Stack Test
Performed At Barron County Incinerator," February 24, 1987.
22. D. S. Beachler, et al, "Bay County, Florida, Waste-To-Energy Facility Air Emission Tests.
Westinghouse Electric CorporationPresented at Municipal Waste Incineration Workshop,
Montreal, Canada, October 1987.
23. Municipal Waste Combustion, Multi-Pollutant Study. Emission Test Report. Volume I,
Summary Of Results, EPA-600/8-89-064a, Maine Energy Recovery Company, Refuse-Derived
Fuel Facility, Biddeford, ME, July 1989.
24. S. Klamm, et al., Emission Testing At An RDF Municipal Waste Combust or, EPA Contract
No. 68-02-4453, U.S. Environmental Protection Agency, NC, May 6, 1988. (Biddeford)
25. Emission Source Test Report -- Preliminary Test Report On Cattaraugus County, New York
State Department of Environmental Conservation, August 5, 1986.
26. Permit No. 0560-0196 For Foster Wheeler Charleston Resource Recovery, Inc. Municipal
Solid Waste Incinerators A & B, Bureau of Air Quality Control, South Carolina Department
of Health and Environmental Control, Charleston, SC, October 1989.
27. Almega Corporation. Unit 1 And Unit 2, EPA Stack Emission Compliance Tests, May 26, 27,
And 29, 1987, At The Signal Environmental Systems, Claremont, NH, NH/VT Solid Waste
Facility, Prepared for Clark-Kenith, Inc. Atlanta, GA, July 1987.
10/96
Solid Waste Disposal
2.1-35
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28. Entropy Environmentalists, Inc. Stationary Source Sampling Report, Signal Environmental
Systems, Inc., At The Claremont Facility, Claremont, New Hampshire, Dioxins/Furans
Emissions Compliance Testing, Units 1 And 2, Reference No. 5553-A, Signal Environmental
Systems, Inc., Claremont, NH, October 2, 1987.
29. M. D. McDannel, et at, Air Emissions Tests At Commerce Refuse-To-Energy Facility
May 26 - June 5, 1987, County Sanitation Districts of Los Angeles County, Whittier, CA,
July 1987.
30. M. D. McDannel and B. L. McDonald, Combustion Optimization Study At The Commerce
Refuse-To-Energy Facility. Volume I, ESA 20528-557, County Sanitation Districts of
Los Angeles County, Los Angeles, CA, June 1988.
31. M. D. McDannel et al., Results Of Air Emission Test During The Waste-to-Energy Facility,
County Sanitation Districts Of Los Angeles County, Whittier, CA, December 1988.
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32. Radian Corporation. Preliminary Data From October - November 1988 Testing At The
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33. Written communication from M. Hartman, Combustion Engineering, to D. White,
Radian Corporation, Detroit Compliance Tests, September 1990.
34. Interpoll Laboratories. Results Of The November 3-6, 1987 Performance Test On The No. 2
RDF And Sludge Incinerator At The WLSSD Plant In Duluth, Minnesota, Interpoll Report
No. 7-2443, April 25, 1988.
35. D. S. Beachler, (Westinghouse Electric Corporation) and ETS, Inc, Dutchess County
Resource Recovery Facility Emission Compliance Test Report, Volumes 1-5, New York
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36. ETS, Inc. Compliance Test Report For Dutchess County Resource Recovery Facility, May
1989.
37. Written communication and enclosures from W. Harold Snead, City of Galax, VA, to
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38. Cooper Engineers, Inc., Air Emissions Tests Of Solid Waste Combustion A Rotary
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39. B. L. McDonald, et al., Air Emissions Tests At The Hampton Refuse-Fired Stream Generating
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40. Radian Corporation for American Ref-Fuel Company of Hempstead, Compliance Test Report
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41. J. Campbell, Chief, Air Engineering Section, Hillsborough County Environmental Protection
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2.1-36
EMISSION FACTORS
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42. Mitsubishi SCR System for Municipal Refuse Incinerator, Measuring Results At Tokyo-
Hikarigaoka And Iwatsuki, Mitsubishi Heavy Industries, Ltd, July 1987.
43. Entropy Environmentalists, Inc. for Honolulu Resource Recovery Venture, Stationary Source
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44. Ogden Projects, Inc., Environmental Test Report, Indianapolis Resource Recovery Facility,
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45. D. R. Knisley, et al. (Radian Corporation), Emissions Test Report, Dioxin/Furan Emission
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46. Entropy Environmentalists, Inc. Stationary Source Sampling Report, Ogden Martin Systems of
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47. D. D. Ethier, et al. (TRC Environmental Consultants), Air Emission Test Results At The
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48. Written communication from from H. G. Rigo, Rigo & Rigo Associates, Inc., to
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58. Entropy Environmentalists, Inc., Stationary Source Sampling Report, Wheelabrator Millbury,
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59. Entropy Environmentalists, Inc., Emission Test Report, Municipal Waste Combustion
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60. Entropy Environmentalists, Municipal Waste Combustion Multipollutant Study: Emission Test
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61. Entropy Environmentalists, Emission Test Report, Municipal Waste Combustion, Continuous
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62. Entropy Environmentalists, Emissions Testing At Wheelabrator Millbury, Inc. Resource
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63. Radian Corporation, Site-Specific Test Plan And Quality Assurance Project Plan For The
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64. Written communication 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
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65. J. L. Hahn, et al., (Cooper Engineers) and J. A. Finney, Jr., et al., (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
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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. C. L. Anderson, et al. (Radian Corporation), Summary Report, CDD/CDF, Metals and
Particulate, 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-MIN02A, 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 Of MSW 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. A. J. Fossa, 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 Of NOx Emissions, Top-Down Technology Consideration, Fairfield,
NJ, pp. 11, 13, December 15, 1988.
77. Roy F. Weston, 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.
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78. S. Zaitlin, 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. R. Neulicht, (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. Written communication with attachments from Philip Gehring, Plant Manager (Pigeon Point
Energy Generating Facility), to Jack R. Farmer, Director, ESD, 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. D. E. Woodman, 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.
90. Environment Canada, NITEP, Environmental Characterization Of Mass Burning Incinerator
Technology at Quebec City. Summary Report, EPS 3/UP/5, June 1988.
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EMISSION FACTORS
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91. Interpol! Laboratories, Results Of Hie March 21 - 26, 1988, Air Emission Compliance Test On
'The No. 2 Boiler At The Red Wing Station, Test TV (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 Il-V, (Prepared for SEMASS Partnership.), March 1990.
95. D. McClanahan, (Fluor Daniel), A. Licata (Dravo), and J. Busehmann (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. Interpol! 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 Particulate 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. J. L. Hahn, (Ogden Projects, Inc.), Environmental Test Report, Prepared for Stanislaus Waste
Energy Company Crows Landing, CA, OPI Report No. 177R, April 7, 1989.
102. J. L. Hahn, 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.
10/96
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103. R. Seelinger, 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. T. Guest 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. P. M. Maly, et al., Results Of The July 1988 Wilmarth Boiler Characterization Tests, Gas
Research Institute Topical Report No. GRI-89/0109, June 1988-March 1989.
109. J. L. Hahn, (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, Particulate. 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. D. B. Sussman, Ogden Martin System, Inc., Submittal to Air Docket (LE-131), Docket
No. A-89-08, Category IV-M, Washington, DC, October 1990.
114. F. Ferraro, Wheelabrator Technologies, Inc., Data package to D. M. White, Radian
Corporation, February 1991.
115. D. R. Knisley, 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.
116. Entropy Environmentalists, Inc., Stationary Source Sampling Report, Ogden Martin Systems
Of Haverhill, Inc., Lawrence, Massachusetts Thermal Conversion Facility. Particulate,
Dioxins/Furans And Nitrogen Oxides Emission Compliance Testing, September 1987,
2,1-42
EMISSION FACTORS
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117. A. J. Fossa, et al, Phase I Resource Recovery Facility Emission Characterization Study,
Overview Report, New York State Department of Environmental Conservation, Albany, NY,
May 1987.
118. Telephone communciation between D. DeVan, Oneida ERF, and M. A. Vancil, Radian
Corporation. April 4, 1988. Specific collecting area of ESPs.
119. G. M. Higgins, 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. R. Kerr, 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, et al., "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. W. R. Nessen, Systems Study Of Air Pollution From Municipal Incineration, Arthur D. Little,
Inc., Cambridge, MA, March 1970.
130. C. R. Brunner, Handbook Of Incineration Systems, McGraw-Hill, Inc., pp. 10.3-10.4, 1991.
131. Telephone communication between K. Quincey, Radian Corporation, and E. Raulerson,
Florida Department of Environmental Regulations, February 16, 1993.
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132. Telephone communication between K. Nebel and K. Quincey, Radian Corporation, and
M. McDonnold, Simonds Manufacturing, February 16, 1993,
133. Telephone communication between K. Quincey, Radian Corporation, and R. Crochet, Crochet
Equipment Company, February 16 and 26, 1993.
134. Telephone communication between K. Quincey, Radian Corporation, and T. Allen, NC
Division of Environmental Management, February 16, 1993.
135. John Pacy, Methane Gas In Landfills: Liability Or Asset?, Proceedings of the Fourth
National Congress of the Waste Management Technology and Resource and Energy
Recovery, Co-sponsored by the National Solid Wastes Management Association and
U. S. EPA, November 12-14, 1975.
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3.1 Stationary Gas Turbines For Electricity Generation
3.1.1 General1
A gas turbine is an internal combustion engine that operates with rotary rather than
reciprocating motion. Gas turbines are used in a broad scope of applications including electric power
generators, and in various process industries. Gas turbines are available with power outputs ranging in
size from 300 horsepower (hp) to over 268,000 hp, with an average size of 40,200 hp 2 Gas turbines
greater than 4,021 hp that are used in electrical generation are used for continuous, peaking, or standby
power. The primary fuels used are natural gas and distillate (No. 2) fuel oil.3
3.1.2 Process Description1
Gas turbines comprise three major components: compressor, combustor, and power turbine.
Ambient air is drawn in and compressed up to 30 times ambient pressure and directed to the
combustor section where fuel is introduced, ignited, and burned. Combustors can either be annular,
can-annular, or silo. An annular combustor is a doughnut-shaped, single, continuous chamber that
rings the turbine in a plane perpendicular to the air flow. Can-annular combustors are similar to the
annular; however, they incorporate can-shaped chambers rather than a single continuous chamber. A
silo combustor has one or more chambers mounted external to the gas turbine body.2
Hot combustion gases are diluted with additional air from the compressor section and directed
to the turbine section at temperatures up to 2350°F. Energy from the hot, expanding exhaust gases are
then recovered in the form of shaft horsepower, of which more than 50 percent is needed to drive the
internal compressor and the balance of recovered shaft energy is available to drive the external load
unit.2
The heat content of the gases exiting the turbine can either be discarded without heat recovery
(simple cycle); used with a heat exchanger to preheat combustion air entering the combustor can
(regenerative cycle); used with or without supplementary firing, in a heat recovery steam generator to
raise process steam (cogeneration); or used with or without supplementary firing to raise steam for a
steam turbine Rankine cycle (combined cycle or repowering).
Gas turbines may have one, two, or three shafts to transmit power from the inlet air
compression turbine, the power turbine, and the exhaust turbine. Of the four basic turbine operating
cycles (simple, regenerative, cogeneration, and combined cycles), three configurations (1 , 2, or
3 shaft), and three types of combustors (annular, can-annular, and silo) for gas turbines, the majority
of gas turbines used in large stationary installations are either peaking simple cycle two-shaft or base
load combined cycle gas turbines.
If the heat recovery steam generator (HRSG) is not supplementary fuel fired, the simple cycle
input-specific emission factors (pounds per million British thermal unit [lb/MMBtu]) will apply to
cogeneration/combined cycle systems. The output-specific emissions (pounds per horsepower-hour
[lb/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
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3.1-1
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Gas turbines firing distillate 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 ash should be used for flue gas
emission factors assuming all metals pass through the turbine.
3.1.3 Emissions
The primary pollutants from gas turbine engines are nitrogen oxides (NOx) and carbon
monoxide (CO). To a lesser extent, hydrocarbons (HQ and other organic compounds, and particulate
matter (PM), which includes both visible (smoke) and nonvisible emissions are also emitted. Nitrogen
oxide formation is strongly dependent on the high temperatures developed in the combustor. Smoke,
CO, and HC, are primarily the result of incomplete combustion. Ash and metallic additives in the fuel
may also contribute to the particulate loading in the exhaust. Oxides of sulfur (SOx) will only appear
in a significant quantity if heavy oils are fired in the turbine. Emissions of sulfur compounds, mainly
sulfur dioxide (S02), are directly related to the sulfur content of the fuel.
3.1.3.1 Nitrogen Oxides -
Nitrogen oxides formation occurs by two fundamentally different mechanisms. The principal
mechanism with turbines firing gas or distillate fuel is thermal NOx, which arises from the thermal
dissociation and subsequent reaction of nitrogen (N2) and oxygen (02) molecules in the combustion
air. Most thermal NOx is formed in high temperature stoichiometric flame pockets downstream of the
fuel injectors where combustion air has mixed sufficiently with the fuel to produce the peak
temperature fuel/air interface. A component of thermal NOx, called prompt NOx, is formed from early
reactions of nitrogen intermediaries and hydrocarbon radicals from the fuel. The prompt NOx forms
within the flame and is usually negligible compared to the amount of thermal NOx formed. The
second mechanism, fuel NOx, stems from the evolution and reaction of fuel-bound nitrogen
compounds with oxygen. Natural gas has negligible chemically-bound fuel nitrogen (although some
molecular nitrogen is present). Essentially all NOx formed is thermal NOx. Distillate oils have low
levels of fuel-bound nitrogen. These levels usually are significant only for high degrees of NOx
controls where thermal NOx has been suppressed to the level where fuel NOx is significant.
The maximum thermal NOx production occurs at a slightly fuel-lean mixture because of excess
oxygen available for reaction. The control of stoichiometry is critical in achieving reductions in
thermal NOx. The thermal NOx generation also decreases rapidly as the temperature drops below the
adiabatic temperature (for a given stoichiometry). Maximum reduction of thermal NOx generation can
thus be achieved by control of both the combustion temperature and the stoichiometry. Gas turbines
operate with high overall levels of excess air, because turbines use combustion air dilution as the
means to maintain the turbine inlet temperature below design limits. In older gas turbine models,
where combustion is in the form of a diffusion flame, most of the dilution takes place in the can
downstream of the primary flame, so that the high excess air levels are not indicative of the NOx
forming potential. The combustion in conventional can designs is by diffusion flames which are
characterized by regions of near-stoichiometric fuel/air mixtures where temperatures are very high and
the majority of NOx is formed. Since the localized NOx forming regions are at much higher
temperatures than the adiabatic flame temperature for the overall mixture, the rate of NOx formation is
dependent on the fuel/air mixing process. The mixing determines the prevalence of the high
temperature regions as well as the peak temperature attained. Also, operation at full loads gives higher
temperatures in the peak NOx forming regions. Newer model gas turbines use lean, pre-mixed
combustion resulting in lower flame (hot spot) temperature and lower NOx.
3.1-2
EMISSION FACTORS
10/96
-------
Ambiert conditions also affect emissions and power output from turbines more than from
external combustion systems. The operation at high excess air levels and at high pressures increases
the influence of inlet humidity, temperature, and pressure 4 Variations of emissions of 30 percent or
greater have been exhibited with changes in ambient humidity and temperature. Humidity acts to
absorb heat in the primary flame zone through the sensible heat and, if condensation occurs during
compression, the latent heat of vaporization. For a given fuel firing rate, lower ambient temperatures
lower the peak flame temperature, lowering NOx significantly. Lower barometric pressure will also
lower the temperature exiting the compressor turbine which will lower NOx.
3 .1.3.2 Carbon Monoxide and Total Organic Compounds (Hydrocarbons) -
Carbon monoxide and HC emissions both result from incomplete combustion. Carbon
monoxide results when there is insufficient residence time at high temperature to complete the final
step in HC oxidation The oxidation of CO to C02 at gas turbine temperatures is a slow reaction
compared to most HC oxidation reactions. In gas turbines, failure to achieve CO bumout may result
from quenching in the can by the dilution air. With liquid fuels, this can be aggravated by carryover
of larger droplets from the atomizer at the fuel injector. In gas turbines, CO emissions are usually
higher when the unit is run at low loads.
The pollutants commonly classified as HCs can encompass a wide spectrum of volatile and
semi-volatile organic compounds. They are discharged into the atmosphere when some of the fuel
remains unbumed or is only partially burned during the combustion process. With natural gas, some
organics are carried over as unreacted. trace constituents of the gas, while others may be pyrolysis
products of the heavier hydrocarbon constituents. With liquid fuels, large droplet carryover to the
quench zone accounts for much of the unreacted and partially pyrolized organic emissions.
3.1.3.3 Particulate Matter -
Particulate emissions from turbines primarily result from carryover of noncombustible trace
constituents in the fuel. Particulate are typically nondetectable with natural gas firing and marginally
detectable with conventional sampling systems with distillate oil firing because of the low ash content.
Particulate may also be formed from agglomerated soot particles, particularly from liquid fuel firing.
3.1.3.4 Greenhouse Gases - 5-11
Carbon dioxide (C02), methane (CH4). and nitrous oxide (N20) emissions are all produced
during natural gas and distillate oil combustion in gas turbines. Nearly all of the fuel carbon is
converted to C02 during the combustion process (typically 99.5 percent for gas and 99 percent for
distillate oil). This conversion is relatively independent of firing configuration. Although the
formation of CO acts to reduce C02 emissions, the amount of CO produced is insignificant compared
to the amount of C02 produced. The majority of the fuel carbon not converted to C02 is due to
incomplete combustion.
Formation of N20 during the combustion process is governed by a complex series of reactions
and its formation is dependent upon many factors. Formation of N20 is minimized when combustion
temperatures arc kept high (above 1475°F) and excess air is kept to a minimum (less than 1 percent).
Methane emissions vary with the fuel, combustion temperature, and firing configuration, but
are highest during periods of incomplete combustion or low-temperature combustion, such as during
the start-up or shut-down cycle. Typically, conditions that favor formation of N20 also favor
emissions of CH4.
10/96
Stationary Internal Combustion Sources
3.1-3
-------
I "J
3,1.4 Control Technologies
There are three generic types of emission controls in use for gas turbines; wet controls using
steam or water injection to reduce combustion temperatures for NOx control; dry controls using
advanced combustor design to suppress NOx formation and/or promote CO burnout; and post-
combustion catalytic control to selectively reduce NOx and/or oxidize CO formed in the turbine,
3.1.4.1 Water Injection -
Water or steam injection is a mature technology that has been demonstrated as very effective
in suppressing NOx emissions from gas turbines. The effect of steam and water injection is to
increase the theimal mass by dilution and thereby reduce the adiabatic flame temperature and the peak
flame temperature in the NOx forming regions. With water injection, there is additional benefit of
absorbing the latent heat of vaporization from the flame zone. Water or steam is typically injected at
a water-to-fuel weight ratio of less than one. Depending on the initial NOx levels, such rates of
injection may reduce NOx by 60 percent or higher. Wet injection is usually accompanied by an
efficiency penalty (typically 2 to 3 percent) but an increase in power output (typically 5 to 6 percent).
The power increase results because fuel flow is increased to maintain turbine inlet temperature at
manufacturer's specifications. Both CO and HC emissions are increased by large rates of water
injection.
3.1.4.2 Dry Controls -
Since thermal NOx is a function of both temperature (exponentially) and time (linearly), the
bases of dry controls are to either lower the combustor temperature using lean mixtures of air and fuel
and/or staging, or decrease the residence time of the combustor. A combination of methods may be
used to reduce NOx emissions such as; lean combustion; reduced combustor residence time; two stage
lean/lean combustion; or two stage rich/lean combustion.
Most gas turbine combustors were originally designed to operate with a stoichiometric mixture
(theoretical amount of air required to react with the fuel). Lean combustion involves increasing the
air-to-fuel ratio of the mixture so that the peak and average temperature within the combustor will be
less than that of the stoichiometric mixture. A lean mixture of air and fuel can be premixed before
ignition, a stoichiometric mixture can be ignited and additional air can be introduced at a later stage
(staging) creating an overall lean mixture in the turbine, or a combination of both can occur.
Introducing excess air at a later stage not only creates a leaner mixture but it also can reduce the
residence time of the combustor, given enough excess air is added at the later stage to create a mixture
so lean that it will no longer combust. The residence time of a combustor can also be decreased by
increasing the turbulence within the combustor.
Two-stage lean/lean combustors are essentially fuel-staged combustors in which each stage
bums lean. The two-stage lean/lean combustor allows the turbine to operate with an extremely lean
mixture and a stable flame that should not "blow off' or extinguish. A small stoichiometric pilot
flame ignites the premixed gas and provides flame stability. The high NOx emissions associated with
the higher temperature pilot flame is minor side effect compared to the desirable low NQX emissions
generated by the extremely lean mixture.
Two stage rich/lean combustors are essentially air-staged combustors in which the primary
zone is operated fuel rich and the secondary zone is operated fuel lean. The rich mixture will produce
lower temperatures (compared to stoichiometric) and higher concentrations of CO and H2 because of
3.1-4
EMISSION FACTORS
10/96
-------
incomplete combustion. The rich mixture decreases the amount of oxygen available for NOx
generation and the increased CO and H2 concentrations help to reduce some of the NOx formed.
Before entering the secondary zone, the exhaust of the primary zone is quenched (to extinguish the
flame) by large amounts of air and a lean mixture is created. The combustion of the lean mixture is
then completed in the secondary zone.
3.1.4.3 Selective Catalytic Reduction Systems -
Selective catalytic reduction systems selectively reduce NOx emissions by injecting ammonia
(NH3) into the exhaust gas stream upstream of a catalyst. Nitrogen oxides, NHV and 02 react on the
surface of the catalyst to form N2 and H20. The exhaust gas must contain a minimum amount of 02
and be within a particular temperature range (typically 450 to 850°F) in order for the SCR system to
operate properly. The range is dictated by the catalyst, typically made from noble metals, base metal
oxides such as vanadium and titanium, or zeolite-based material. Exhaust gas temperatures greater
than the upper limit (850°F) will cause NOx and NH3 to pass through the catalyst unreacted.
Ammonia emissions, called NH3 slip, may be a consideration when specifying a SCR system.
Ammonia, either in the form of liquid anhydrous ammonia, or aqueous ammonia hydroxide is
stored on site and injected into the exhaust stream upstream of the catalyst. Although a SCR system
can operate alone, it is typically used in conjunction with water/steam injection systems to reduce NOx
emissions to their lowest levels (less than 10 ppm at 15 percent oxygen for SCR and wet injection
systems).
The catalyst and catalyst housing used in SCR systems tend to be very large and dense (in
terms of surface area to volume ratio) because of the high exhaust flow rates and long residence times
required for NOx, 02, and NH3, to react on the catalyst. Most catalysts are configured in a parallel-
plate, "honeycomb" design to maximize the surface area-to-volume ratio of the catalyst. Some SCR
installations are incorporating CO catalytic oxidation modules along with the NOx reduction catalyst
for simultaneous CO/NOx control.
The average gaseous emission factors for uncontrolled gas turbines (firing natural gas and fuel
oil) are presented in Table 3.1-1. There is some variation in emissions over the population of large
uncontrolled gas turbines because of the diversity of engine designs, sizes, and models. Table 3.1-2
presents emission factors for gas turbines controlled with water injection, steam injection, and selective
catalytic reduction. Emission factors for fuel oil-fired turbines controlled with water injection are
given in Table 3.1-3. Table 3.1-4 presents trace element emission factors for distillate oil-fired
turbines.
10/96
Stationary Internal Combustion Sources
3.1-5
-------
3.1.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
• For the PM factors, a footnote was added to clarify that condensables and all PM from
oil- and gas-fired turbines are considered PM-10.
• In the table for large uncontrolled gas turbines, a sentence was added to footnote "e" to
indicate that when sulfur content is not available, 0.6 lb/106 ft3 (0.0006 lb/MMBtu)
can be used.
Supplement B, October 1996
• Text was revised and updated for the general section.
• Text was added regarding firing practices and process description.
• Text was revised and updated for emissions and controls.
• All factors for turbines with SCR-water injection control were corrected.
• The C(>2 factor was revised and a new set of N20 factors were added.
3.1-6
EMISSION FACTORS
10/96
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Table 3.1-1. EMISSION FACTORS pOR LARGE
UNCONTROLLED GAS TURBINES3
Pollutant
EMISSION
FACTOR
RATING1'
Natural Gas
(SCC 2-01-002-01)
Fuel Oil (Distillate)
(SCC 2-01-001-01)
Emission
Factor^
(lb/hp-hr)
(power output)
Emission
Factor
(lb/MMBtu)
(fuel input)
Emission
Factor®
(lb/hp-hr)
(power output)
Emission Factor
(lb/MMBtu)
(fuel input)
NOx
C
3.53 E-03
0.44
5.60 E-03
0.698
CO
D
8.60 E-04
0.11
3.84 E-04
0.048
C02d
B
0.876
109
1.32
165
TOC (as methane)
D
1.92 E-04
0.024
1.37 E-04
0.017
SOx (as S02)e
B
7.52 E-03S
0.94S
8.09 E-03S
1.Q1S
PM-10
Solids
E
1.54 E-04
0.0193
3.04 E-04
0,038
Condensables
E
1.81 E-04
0.0226
1.85 E-04
0.023
Sizing %
<0.05 fm
D
15%
15%
16%
16%
<0.10 (im
D
40%
40%
48%
48%
<0.15 nm
D
63%
63%
72%
72%
<0.20 pm
D
78%
78%
85%
85%
<0.25 nm
D
89%
89%
93%
93%
<1 tun
D
100%
100%
100%
100%
a References 2-3,8-11,13-18. SCC = Source Classification Code. PM-10 = particulate matter less
than or equal to 10 fim aerodynamic diameter; sizing % is expressed in pm. Condensables are also
PM-10 and all PM from oil and gas-fired turbines is less than 1pm in size and therefore are
considered PM-10. To convert lb/hp-hr to g/kw-hr, multiply by 608. To convert from Ib/MMBtu to
ng/J, multiply by 430.
b Ratings reflect limited data and/or a lack of documentation of test results; they may not apply to
specific facilities or populations and should be used with care.
c Calculated from Ib/MMBtu assuming an average heat rate of 8,000 Btu/hp-hr.
d Based on 99.5% conversion of fuel carbon to C02 for natural gas and 99% conversion for No. 2 oil.
e All sulfur in the fuel is assumed to be converted to S02. S = % sulfur in fuel. For example, if
sulfur content in the fuel is 3.4%, then S = 3.4. When sulfur content is not available,
0.6 lb/106 ft3 (0.0006 lb/MMBtu) can be used; however, the equation is more accurate.
10/96
Stationary Internal Combustion Sources
3.1-7
-------
Table 3.1-2. EMISSION FACTORS FOR LARGE
CONTROLLED GAS TURBINES8
(SCC 2-01-002-01)
EMISSION FACTOR RATING: C
Water Injection
(0 8 water/fuel ratio)
Steam Injection
(1.2 water/fuel ratio)
Selective
Catalytic
Reduction
(with water
injection)
Pollutant
Emission
Factor
(lb/hp-hr)
(power output)
Emission
Factor
(lb/MMBtu)
(fuel input)
Emission
Factor
(lb/hp-hr)
(power output)
Emission
Factor
(lb/MMBtu)
(fuel input)
Emission
Factor
(lb/MMBtu)
(fuel input)
NOx
1.10 E-03
0.14
9,75 E-04
0.12
0.0088b
CO
2.07 E-03
0,28
1.16 E-03
0.16
0,0084
N2Oc
2.00 E-05
0,003
2,00 E-05
0.003
ND
TOC
(as methane)
ND
ND
ND
ND
0.014
nh3
ND
ND
ND
ND
0.0065
NMHC
ND
ND
ND
ND
0.0032
Formaldehyded
ND
ND
ND
ND
0,0027
a References 13,19-24. All data are averages of a limited number of tests and may not be typical of
those reductions that can be achieved at a specific location. To convert from lb/hp-hr to g/kw-hr,
multiply by 0.608. To convert from lb/MMBtu to ng/J, multiply by 430. NMHC = nonmethane
hydrocarbons. ND = no data. SCC = Source Classification Code,
b An SCR catalyst reduces NOx by an average of 78%.
c EMISSION FACTOR RATING: E. Based on limited source tests on a single turbine (Reference 5).
Results may not be typical for all locations.
d Hazardous air pollutant listed in the Clean Air Act.
3.1-8
EMISSION FACTORS
10/96
-------
Table 3.1-3. EMISSION FACTORS FOR DISTILLATE OIL-FIRED TURB'NES
CONTROLLED WITH WATER INJECTION3
(SCC 2-01-001-01)
EMISSION FACTOR RATING: E
Pollutant
Water Injection
(0.8 water/fuel ratio)
Emission Factor
(Ib/hp-hr) (power output)
Emission Factor (lb/MMBtu)
(fuel input)
NOx
2.31 E-03
0.290
CO
1.54 E-04
0.0192
TOC (as methane)
3.84 E-05
0.0048
SOxc
_d
d
PM-10e
2.98 E-04
0.0372
a Reference 25. To convert from Ib/hp-hr to g/kw-hr, multiply by 0.608. To convert from lb/MMBtu
to ng/J, multiply by 430. PM-10 = particulate matter < 10 aerometric diameter. SCC = Source
Classification Code.
b Calculated from fuel input assuming an average heat rate of 8,000 Btu/hp-hr.
c EMISSION FACTOR RATING: B
d All sulfur in the fuel is assumed to be converted to SOx.
e All PM is < 1 (.im in size.
10/96
Stationary Internal Combustion Sources
3.1-9
-------
Table 3.1-4. TRACE ELEMENT EMISSION FACTORS FOR
DISTILLATE OIL-FIRED TURBINES3
(SCC 2-01-001-01)
EMISSION FACTOR RATING: Eb
Trace Element
Emission Factor
(lb/MMBtu)
Aluminum
1.5 E-04
Antimony®
2.2 E-05
Arsenic0
4.9 E-06
Barium
2.0 E-05
Beryllium0
3.3 E-07
Boron
6.5 E-05
Bromine
4.2 E-06
Cadmium0
4.2 E-06
Calcium
7.7 E-04
Chromium0
4.7 E-05
Cobalt0
9.1 E-06
Copper
1.3 E-03
Iron
6.0 E-04
Lead0
5.8 E-05
Magnesium
2.3 E-04
Manganese0
3.4 E-04
Mercury0
9.1 E-07
Molybdenum
8.4 E-06
Nickel0
1.2 E-03
Phosphorus0
3.0 E-04
Potassium
4.3 E-04
Selenium0
5.3 E-06
Silicon
1.3 E-03
Sodium
1.4 E-03
Tin
8.1 E-05
Vanadium
4.4 E-06
Zinc
6.8 E-04
a Reference 2. To convert from lb/MMBtu to ng/J, multiply by 430. SCC = Source Classification
Code.
b Ratings reflect limited data; they may not apply to specific facilities or populations and should be
used with care.
c Hazardous air pollutant listed in the Clean Air Act.
3.1-10 EMISSION FACTORS 10/96
-------
References For Section 3.1
1. Alternative Control Techniques Document - NOx Emissions from Stationary Gas Turbines,
EPA 453/R-93-007, January 1993.
2. C. C. Shih, et al., Emissions Assessment Of Conventional Stationary Combustion Systems,
Vol. II: Internal Combustion Sources, EPA-600/7-79-Q29c, U. S. Environmental Protection
Agency, Cincinnati, OH, February 1979.
3. Final Report - Gas Turbine Emission Measurement Program, GASLTR787, General Applied
Science Laboratories, Westbury, NY, August 1974.
4. Standards Support And Environmental Impact Statement, Volume 1: Proposed Standards Of
Performance For Stationary Gas Turbines, EPA-450/2-77-017a, U. S. Environmental
Protection Agency, Research Triangle Park, NC, September 1977.
5. L. P. Nelson, et al., Global Combustion Sources Of Nitrous Oxide Emissions, Research Project
2333-4 Interim Report, Sacramento: Radian Corporation, 1991.
6. R. L. Peer, et al., Characterization Of Nitrous Oxide Emission Sources, U. S. Environmental
Protection Agency, Office of Research and Development, Research Triangle Park, NC, 1995.
7. S. D. Piccot, et al., Emissions And Cost Estimates For Globally Significant Anthropogenic
Combustion Sources OfNOx N20, CH4, CO, And C02, U. S. Environmental Protection
Agency, Office of Research and Development, Research Triangle Park, NC, 1990.
8. G. Marland and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U. S. Department of Energy, Oak Ridge, TN, 1983.
9. G. Marland and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1950-1982, Tellus 36B.232-26I, 1984.
10. Inventory OfU. S. Greenhouse Gas Emissions And Sinks: 1990-1991, EPA-230-R-96-006,
U. S. Environmental Protection Agency, Washington, DC, November 1995.
11. 1PCC Guidelines For National Greenhouse Gas Inventories Workbook, Intergovernmental
Panel on Climate Change/Organization for Economic Cooperation and Development, Paris,
France, 1995.
12. L. M. Campbell and G. S. Shareef, Sourcebook: NOx Control Technology Data, Radian Corp.,
EPA-600/2-91-029, Air and Energy Engineering Research Laboratory, U. S. Environmental
Protection Agency, Research Triangle Park, July 1991.
13. P. C. Malte, el al., NOx Exhaust Emissions For Gas-Fired Turbine Engines,
ASME 90-GT-392, The American Society Of Mechanical Engineers, Bellevue, WA,
June 1990.
10/96
Stationary Internal Combustion Sources
3.1-11
-------
14. C. T. Hare and K. J. Springer, Exhaust Emissions From Uncontrolled Vehicles And Related
Equipment Using Internal Combustion Engines, Part 6: Gas Turbines, Electric Utility Power
Plant, APTD-1495, U, S. Environmental Protection Agency, Research Triangle Park, NC,
February 1974.
15. M. Lieferstein, Summary Of Emissions From Consolidated Edison Gas Turbine, Department
Of Air Resources, City Of New York, NY, November 5, 1975.
16. J. F. Hurley and S. Hersh, Effect Of Smoke And Corrosion Suppressant Additives On
Particulate And Gaseous Emissions From Utility Gas Turbine, EPRJ FP-398, Electric Power
Research Institute, Palo Alto, CA, March 1977.
17. A. R. Crawford, el al., "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, EPA-600/2-76-152c,
U. S. Environmental Protection Agency, Cincinnati, OH, June 1976.
18. D. E. Carl, et al.. "Exhaust Emissions From A 25-MW Gas Turbine Firing Heavy And Light
Distillate Fuel Oils And Natural Gas", presented at the Gas Turbine Conference And Products
Show, Houston, "DC, March 2-6, 1975.
19. G. S. Shareef and D. K Stone. Evaluation Of SCR NOx Controls For Small Natural Gas-
fueled Prime Movers - Phase 1, GRI-90/0138, Gas Research Institute, Chicago, IL, July 1990.
20. R. R. Pease, SCAOMD Engineering Division Report - Status Report On SCR For Gas
Turbines, South Coast Air Quality Management District, Diamond Bar, CA, July 1984,
21. CEMS Certification And Compliance Testing At Chevron USA, Inc. 's Gaviota Gas Plant,
Report PS-89-1837, Chevron USA, Inc., Goleta, CA, June 21, 1989.
22. Emission Testing At The Bonneville Pacific Cogeneration Plant, Report PS-92-2702,
Bonneville Pacific Corporation. Santa Maria, CA. March 1992.
23. Compliance test report on a production gas-fired IC engine, ESA, 19770-462, Procter And
Gamble, Sacramento, CA, December 1986.
24. Compliance test report on a cogeneration facility, CR 75600-2160, Procter And Gamble,
Sacramento, CA, May 1990.
25. R. Larkin and E. B. Higginbotham, Combustion Modification Controls For Stationary Gas
Turbines, Vol. 11: Utility Unit Field Test, EPA 600/7-81-122, U. S. Environmental Protection
Agency, Cincinnati, OH, July 1981.
3.1-12 EMISSION FACTORS 10/96
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3.2 Heavy-duty Natural Gas-fired Pipeline Compressor Engines And Turbines
3.2.1 General1"3
Natural gas-fired internal combustion engines are used in the natural gas industry at pipeline
compressor and storage stations. The engines and gas turbines are used to provide mechanical shaft
power that drives compressors. At pipeline compressor stations, the engine or turbine is used to help
move natural gas from station to station. At storage facilities, they are used to help inject the natural gas
into high pressure underground cavities (natural gas storage fields), e. g., empty oil fields. Although they
can operate at a fairly constant load, pipeline engines or turbines must be able to operate under varying
pipeline requirements. The size of these engines ranges from 800 brake horsepower (bhp) to 5,000 bhp.
For gas turbines, the capacity ranges from 1,000 to 15,000 bhp.
3.2.2 Process Description1"3
Reciprocating engines are separated into 3 design classes: 2-cycle (stroke) lean bum, 2-stroke
ultra lean (clean) burn, 4-stroke lean bum, 4-stroke clean burn, and 4-stroke rich burn. Each of these have
design differences that affect both baseline emissions as well as the potential for emissions control. Two-
stroke engines complete the power cycle in a single crankshaft revolution as compared to the two
crankshaft revolutions required for 4-stroke engines.
In a 2-stroke engine, the air/fuel charge is injected with the piston near the bottom of the power
stroke. The intake ports are then covered or closed, and the piston moves to the top of the cylinder,
thereby compressing the charge. Following ignition and combustion, the power stroke starts with the
downward movement of the piston. Exhaust ports or valves are then uncovered to exhaust the
combustion products, and a new air/fuel charge is injected. Two-stroke engines may be turbocharged
using an exhaust-powered turbine to pressurize the charge for injection into the cylinder and to increase
cylinder scavenging. 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 cycle and the
power/exhaust cycle. These engines may be either naturally aspirated, using the suction from the piston
to entrain the air charge, or turbocharged, using an exhaust-driven 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
stoichiometric air/fuel ratio 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, 2-stroke designs contribute approximately two-thirds of installed capacity.
Almost all of the gas turbines used by the natural gas industry for pipeline and storage facilities
are simple cycle. A gas turbine is an internal combustion engine that operates with rotary rather than
reciprocating motion. Gas turbines are essentially composed of several major components: compressor,
combustor, and power turbine. Natural gas and compressed air (up to 30 atmospheres pressure) are
injected separately into the combustor can, mixed, and reacted.
The hot expanding exhaust gases are then passed into the power turbine to produce usable shaft
energy. The heat content of the exhaust gases exiting the turbine are not commonly utilized with pipeline
10/96
Stationary Internal Combustion Sources
3.2-1
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applications, although other applications use heat recovery steam generators for cogencration or
combined cycle application.
Gas turbines may have one, two, or three shafts to transmit power from the inlet air compression
turbine, the power turbine, and the exhaust turbine. The majority of gas turbines used in pipeline
installations are simple cycle two-shaft gas turbines. There are three types of combustor can design in
use: annular, can-annular, and silo. The type of combustor can design depends on the make/model of the
gas turbine. Several stationary engine designs are aircraft-derivative using an annular or can-annular
design.
3.2.3 Emissions
The primary pollutants from natural gas-fueled reciprocating engines and gas turbines are
nitrogen oxide (NOx), carbon monoxide (CO), and total organic compounds (TOC). Nitrogen oxide
formation is strongly dependent on the high temperatures developed in the cylinder or combustor can.
The other pollutants, CO and HC species, are primarily the result of incomplete combustion. Trace
amounts of metals and non-eombustible inorganic material may be carried over from the lubricating oil,
from engine wear, or from trace constituents in the gas. Sulfiir oxides are very low since sulfur
compounds are removed in the gas treatment plant prior to entry into the pipeline.
3.2.3.1 Nitrogen Oxides -
Nitrogen oxide formation occurs by two fundamentally different mechanisms. The principle
mechanism with gas-fired engines and turbines is thermal NOx, which arises from the thermal
dissociation and subsequent reaction of nitrogen (N2) and oxygen (02) molecules in the combustion air.
Most thermal NOx is formed in high-temperature regions in the cylinder or combustor can where
combustion air has mixed sufficiently with the fuel to produce the peak temperature fuel/air interface. A
component of thermal NOx, called prompt NOx, is formed from early reactions of nitrogen intermediaries
and hydrocarbon radicals from the fuel. The prompt NOx forms within the flame and is usually negligible
compared to the amount of thermal NOx formed. The second mechanism, fuel NOx, stems from the
evolution and reaction of fuel-bound N2 compounds with oxygen. Natural gas has negligible chemically
bound fuel N2 (although some molecular nitrogen) and essentially all NOx formed is thermal NOx. The
formation of prompt NOx can form a significant part of total NOx only under highly controlled situations
where thermal NOx is suppressed. It is more prevalent with rich burn engines. The rates of these
reactions are highly dependent upon the stoichiometric ratio, combustion temperature, and residence time
at the combustion temperature.
The maximum thermal NOx production occurs at a slightly lean fuel/air mixture ratio because of
the excess availability of oxygen for reaction. The control of stoichiometry is critical in achieving
reductions in thermal NOx. Premixing with lean burn reciprocating engines is effective in suppressing
NOx relative to rich burn engines. The thermal NOx generation decreases rapidly as the temperature
drops below the adiabatic temperature. Thus, maximum reduction of thermal NOx generation can be
achieved by control of both the combustion temperature and the stoichiometry.
Gas turbines operate with high overall levels of excess air because turbines use combustion air
dilution as the means to maintain the turbine inlet temperature below design limits. Most of the dilution
takes place in the can downstream of the primary flame, so that high excess air levels are not indicative of
the NOx-forming potential. The combustion in conventional designs is by diffusion flames that are
characterized by regions of near-stoichiometric fuel/air mixtures where temperatures are very high and
the majority of NOx is formed. Since the localized NOx-forming regions are at much higher temperatures
than the adiabatic flame temperature for the overall mixture, the rate of NOx formation is dependent on
3.2-2
EMISSION FACTORS
10/96
-------
the fuel/air mixing process. The mixing determines the prevalence of the high temperature regions as
well as the peak temperature attained.
3.2.3.2 Carbon Monoxide and Total Organic Compounds (Hydrocarbons) -
Carbon monoxide and hydrocarbon emissions both result from the products of incomplete
combustion. Carbon monoxide results when there is insufficient residence time at high temperature to
complete the final step in hydrocarbon oxidation. In reciprocating engines, CO emissions may indicate
early quenching of combustion gases on cylinder walls or valve surfaces. The oxidation of CO to carbon
dioxide (C02) is a slow reaction compared to most hydrocarbon oxidation reactions. In gas turbines,
failure to achieve CO bumout may result from quenching in the can by the dilution air. CO emissions are
usually higher when the unit is run at low loads.
The pollutants commonly classified as hydrocarbons can encompass a wide spectrum of volatile
and semi-volatile organic compounds. They are discharged into the atmosphere when some of the gas
remains unbumed or is only partially burned during the combustion process. With natural gas, some
organics are carryover, unreacted, trace constituents of the gas, while others may be pyrolysis products of
the heavier hydrocarbon constituents. Partially burned hydrocarbons can occur because of poor air/fuel
homogeneity due to incomplete mixing prior to. or dunng. combustion; incorrect air/fuel ratios in the
cylinder during combustion due to maladjustment of the engine fuel system; or low cylinder temperature
due to excessive cooling through the walls or early cooling of the gases by expansion of the combustion
volume caused by piston motion before combustion is completed.
3.2.3.3 Particulate Matter and PM-104 -
Particulate emissions with gas-fired turbines and reciprocating engines are non-detectable with
conventional protocols unless the engines are operated in a sooting condition. Otherwise, particulate
could arise from carryover of non-combustible trace constituents in the gas or from lube oil.
3.2.4 Control Technologies
Three generic control techniques have been developed for reciprocating engines and gas turbines:
parametric controls (timing and operating at a leaner air/fuel ratio for reciprocating engines and water
injection for gas turbines); combustion modification such as advanced engine design for new sources or
major modification to existing sources (clean burn reciprocating head designs and dry gas turbine
eombustor can designs); and postcombustion catalytic NOx reduction (selective catalytic reduction [SCR]
for gas turbines and lean bum reciprocating engines and nonselective catalytic reduction [NSCR] for rich
bum engines).
3.2.4.1 Control Techniques for Rich Bum Reciprocating Engines5 -
Nonselective Catalytic Reduction -
This technique uses the residual hydrocarbons and CO in the rich burn engine exhaust as a
reducing agent for NOx. In NSCR, hydrocarbons will be oxidized by 02 and NOx, hence the designation
"nonselective". This is in contrast to ammonia injection for SCR where ammonia selectively reacts with
NOx. The excess hydrocarbons and NOx pass over a catalyst, usually a noble metal (platinum, rhodium,
or palladium) which reduces the reactants to N2, C02, and H20.
The NSCR technique is effectively limited to engines with normal exhaust oxygen levels of
4 percent or less. This includes 4-cycle naturally aspirated engines and some 4-cycle turbocharged
engines. Engines operating with NSCR require tight air/fuel control to maintain high reduction
effectiveness without high hydrocarbon emissions. To achieve optimum NOx reduction performance, the
engine may need to be run in a richer fuel condition than normal
10/96
Stationary Internal Combustion Sources
3.2-3
-------
Prestratified Charge -
Prestratified charge combustion is a retrofit system that is limited to 4-cycle carbureted natural
gas engines. In this system, controlled amounts of air are introduced into the intake manifold in a
soecified sequence and quantity. This stratification provides both a fuel rich ignition and rapid flame
cooling resulting in reduced formation of NOx.
3.2.4.2 Control Techniques for Lean Burn Reciprocating Engines -
Lean Combustion -
Lean combustion techniques use increased bulk air/fuel ratios to lower peak flame temperature
and reduce NOx formation. Typically, air/fuel ratios are increased from normal levels of 20 to 35 up to
controlled levels of 45 to 50. The upper limit is constrained by the onset of misfiring at the lean limit.
This condition also increases CO and HC emissions.
To maintain acceptable engine performance at lean conditions, high energy ignition systems have
been developed that promote flame stability at very lean conditions. With high energy ignition, a rich
mixture is ignited in a small ignition cell located in the cylinder head. The ignition cell flame passes to
the cylinder where it provides a uniform ignition source. The technique can be retrofit to existing
turbocharged 2- and 4-cycle engines. With new engine designs, NOx reductions of 80 to 90 percent have
been achieved compared to spark ignition designs. In most cases, the NOx reductions have been
accompanied by increases in power output and increased fuel economy.
Selective Catalytic Reduction -
Selective catalytic reduction (SCR) is applicable to lean burn engines. Ammonia (NH3) is
injected upstream of a noble metal, metal oxide or zeolite catalyst to give an NH3: NOx ratio of about 1:1.
The mixture of NH3 and NOx is selectively reduced over the catalyst within a temperature range of 600 to
900°F depending on the catalyst. The major system components are the catalyst and associated housing,
the ammonia storage and delivery system, and the control system. The performance has been less
acceptable than NSCR with rich bum engines, or SCR with gas turbines. The primary difficulty with lean
bum engines has been maintaining air/fuel control, very limited automatic controls, and engine
performance and the inherent variety of engine loading while achieving the necessary exhaust
temperature window for efficient SCR operation.
3.2.4.3 Control Technologies for Gas Turbines -
Water Injection -
Water or steam injection is a technology that has been demonstrated as very effective in
suppressing NOx emissions from gas turbines. The effect of steam and water injection is to increase the
thermal mass by dilution and thereby reduce the adiabatic flame temperature and the peak flame
temperatures in the NOx-forming regions. With water injection, there is the additional benefit of
absorbing the latent heat of vaporization from the flame zone. Water or steam is typically injected at a
water-to-fuel weight ratio of less than 1. Depending on the initial NOx levels, such rates of injection may
reduce NOx by 60 percent or higher. Wet injection is usually accompanied by an efficiency penalty but
an increase in power output. Efficiency penalties of 2 to 3 percent are typical. The power increase results
because fuel flow is increased to maintain turbine inlet temperature at manufacturers' specifications.
Power increases with water or steam injection of 5 to 6 percent are typical. Both CO and HC emissions
are increased by large rates of water injection.
The use of wet injection may be constrained in some applications such as pipeline pumping by
the unavailability of pure water for injection. The choice between water or steam is usually driven by the
availability of steam. Most operators prefer steam because of fewer operational problems, better heat
3.2-4
EMISSION FACTORS
10/96
-------
rate, and increased power augmentation compared to water. The use of water with low mineral content is
a significant cost item with water injection. The reliability of the water treatment system and injection
pumps also can be a major issue in continuous operation under low NOx conditions.
Selective Catalytic Reduction Systems -
Selective catalytic reduction systems are postcombustion technologies that have recently been
applied in limited cases to gas turbines. An SCR system consists of an ammonia storage, feed, and
injection system, and a catalyst and catalyst housing. Selective catalytic reduction systems selectively
reduce NOx emissions by injecting NH3 into the exhaust gas stream upstream of the catalyst. Nitrogen
oxides, NH3, and 02 react on the surface of the catalyst to form N2 and H20. For the SCR system to
operate properly, the exhaust gas must be within a particular temperature range (typically between 450
and 850°F). The temperature range is dictated by the catalyst (typically made from noble metals, base
metal oxides such as vanadium and titanium, and zeolite-based material). Exhaust gas temperatures
greater than the upper limit (850°F) will pass the NOx and ammonia unreacted through the catalyst.
Ammonia emissions, called NH3 slip, are a key consideration when specifying a SCR system. Ammonia,
either in the form of liquid anhydrous ammonia, or aqueous ammonia hydroxide is stored on site and
injected into the exhaust stream upstream of the catalyst. Although an SCR system can operate alone, it
is typically used in conjunction with water/steam injection systems to reduce NOx emissions to their
lowest levels (less than 10 ppm at 15 percent oxygen).
Combustion Modifications -
Several different methods or approaches of reducing NOx emissions from gas turbines are
currently being researched and developed by the manufacturers of gas turbines. Since thermal NOx is a
function of both temperature (exponentially) and time (linearally), the basis of these controls are to either
lower the combustor temperature using lean mixtures air and fuel and/or staging the combustion or
decrease the residence time of the combustor. Some manufacturers use a combination of these methods
to reduce NOx emissions. These methods or approaches are lean combustion; reduced combustor
residence time; two-stage lean/lean combustion; and two-stage rich/lean combustion.
Most gas turbine combustors were originally designed to operate with a stoichiometric mixture
(theoretical amount of air required to react with the fuel). Lean combustion involves increasing the
air/fuel ratio of the mixture so that the peak and average temperature within the combustor will be less
than that of the stoichiometric mixture. A lean mixture of air and fuel can be premixed before ignition, a
stoichiometric mixture can be ignited and additional air can be introduced at a later stage (staging)
creating an overall lean mixture in the turbine, or a combination of both can occur. Introducing excess air
at a later stage not only creates a leaner mixture but can also reduce the residence time of the combustor
(given enough excess air is added at the latter stage to create a mixture so lean that it will no longer
combust). Also, the residence time of a combustor can be decreased by increasing the turbulence within
the combustor.
Two-stage lean/lean combustors are essentially fuel-staged combustors in which each stage bums
lean. The two-stage lean/lean combustor allows the turbine to operate with an extremely lean mixture and
a stable flame that should not "blow off" or extinguish. A small stoichiometric pilot flame ignites the
premixed gas and provides flame stability. The high NOx emissions associated with the higher-
temperature pilot flame is minor compared to the low NOx emissions generated by the extremely lean
mixture.
Two-stage rich/lean combustors are essentially air-staged combustors in which the primary
stage/zone is operated fuel rich and the secondary stage/zone is operated fuel lean. The rich mixture will
produce lower temperatures (compared to stoichiometric) and higher concentrations of CO and H2
because of incomplete combustion. The rich mixture decreases the amount of oxygen available for NOx
10/96
Stationary Internal Combustion Sources
3.2-5
-------
generation and the increased CO and H2 concentrations will help reduce some of the NOx formed. Before
entering the secondary zone, the exhaust of the primary zone is quenched (to extinguish the flame) by
large amounts of air and a lean mixture is now created. The combustion of the lean mixture is then
completed in the secondary zone.
Emission factors for natural gas-fired pipeline compressor engines are presented in Table 3.2-1
for baseline operation and in Tables 3.2-2, 3.2-3, 3.2-4, and 3.2-5 for controlled operation. The factors
for controlled operation are taken from a single source test. Table 3.2-6 lists noncriteria emission factors
for uncontrolled natural gas prime movers.
3.2.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/cfig/).
Supplement A, Februaiy 1996
• In the table for uncontrolled natural gas prime movers, the SCC for 4-cycle lean bum was
changed from 2-01-002-53 to 2-02-002-54. The SCC for 4-cycle rich bum was changed
from 2-02-002-54 to 2-02-02-002-53.
• An SCC (2-02-002-53) was provided for 4-cycle rich bum engines, and the "less than"
symbol (<) was restored to the appropriate factors.
Supplement B, October 1996
• The introduction section was revised.
• Text was added concerning process description of turbines.
• Text was revised concerning emissions and controls.
• References in various tables were editorially corrected.
• The inconsistency between a C02 factor in the table and an equation in the footnote was
corrected.
3.2-6
EMISSION FACTORS
10/96
-------
Table 3.2-1. CRITERIA EMISSION FACTORS FOR UNCONTROLLED NATURAL GAS PRIME MOVERS3
EMISSION FACTOR RATING: A
Gas Turbines
(SCC 2-02-002-01)
2-Cycle Lean Burn
(SCC 2-02-002-52)
4-Cycle Lean Burn
(SCC 2-02-002-54)
4-Cycle Rich Burn
(SCC 2-02-002-53)
Pollutant
Emission Factor
(lb/hp-hr)
(power output)
Emission
Factor
(lb/MMBtu)
(fuel input)
Emission
Factor
(lb/hp-hr)
(power output)
Emission
Factor
(lb/MMBtu)
(fuel input)
Emission
Factor
(lb/hp-hr)
(power output)
Emission
Factor
(lb/MMBtu)
(fuel input)
Emission
Factor
(lb/hp-hi)
(power output)
Emission
Factor
(lb/MMBtu)
(fuel input)
NOx
2.87 E-03
0.34
0.024
2.7
0.026
3.2
0.022
2.3
CO
1.83 E-03
0.17
3.31 E-03
0.38
3.53 E-03
0.42
0.019
1.6
C02b
0.88
109
0.77
109
0.77
109
0.77
109
TOC
3.97 E-04
0.053
0.013
1.5
0.011
1.3
2.65 E-03
0.27
TNMOC
2.20 E-05
0.002
9.48 E-04
0.11
1.59 E-03
0.18
3.09 E-04
0.03
ch4
3.75 E-04
0.051
0.012
1.4
9.04 E-03
1.1
2.43 E-03
0.24
a References 6-13. Factors are based on large population of engines. Factors for individual engines from specific manufacturers may vary.
To convert from lb/hp-hr to kg/kw-hr, multiply by 0.608. To convert from lb/MMBtu to ng/J, multiply by 430. SCC = Source
Classification Code. TNMOC = total nonmethane organic compounds.
b Based on 99.5% conversion of the fuel carbon to C02. C02 [lb/MMBtu] = (3.67)(%CON)(C/E), where %CON = percent conversion of
fuel carbon to C02, C = carbon content of fuel by weight (0.75), and E = energy content of fuel, 0.0250 MMBtu/lb.
-------
Tabic 3.2-2. EMISSION FACTORS FOR CONTROLLED NATURAL GAS PRIME MOVERS:
COMBUSTION MODIFICATIONS ON 2-CYCLE LEAN BURN ENGINE8
(SCC 2-02-002-52)
EMISSION FACTOR RATING: E (except as noted)
m
2
z
*n
>
o
H
o
£
Baseline
Increased Air/Fuel Ratio With Intercooling
Pollutant
Emission Factor
(lb/hp-hr)
Emission Factor
(Ib/MMBtu)
Emission Factor
(lb/hp-hr)
Emission Factor
(lb/MMBtu)
NOx
0.022
2.9
0.011
1.5
CO
2.07 E-03
0.28
3.31 E-03
0.46
co2b
0.77
109
0.77
109
TOC
0.017
2.2
0.019
2.6
TNMOC
0.011
1.6
0.013
1.8
ch4
5.07 E-03
0.68
5.51 E-03
0.75
PM-10
Total (front+back halves)
3.53 E-04
0.046
3.97 E-04
0.055
Solids (front half)
2.16 E-04
0.029
2.87 E-04
0.038
Condensables (back half)
1.26 E-04
0.017
1.28 E-04
0.017
a Reference 10-14,17-19, Factors reflect a single data set and as such baseline emissions for this engine were slightly different from the
uncontrolled emission factor for 2-cycle lean bum engines. To convert from lb/hp-hr to kg/kw-hr, multiply by 0.608. To convert from
Ib/MMBtu to ng/J, multiply by 430. TNMOC = total nonmethane organic compounds. PM-10 = particulate matter < 10 micrometers (pm)
aerodynamic diameter. (All particulate is assumed to be < 1 (am aerodynamic diameter). SCC = Source Classification Code.
b EMISSION FACTOR RATING: A. Based on 99.5% conversion of the fuel carbon to C02. C02flb/MMBtu] = (3.67)(%CON)(C/E),
where %CON = percent conversion of fuel carbon to C02, C = carbon content of fuel by weight (0.75), and E = energy content of fuel,
0.0250 MMBtu/lb. C02 emissions are not affected by controls.
<3
VO
On
-------
g5 Table 3.2-3. EMISSION FACTORS FOR CONTROLLED NATURAL GAS PRIME MOVERS:
NONSELECTIVE CATALYTIC REDUCTION ON 4-CYCLE RICH BURN ENGINE3
(SCC 2-02-002-53)
EMISSION FACTOR RATING: E (except as noted)
Kfi
I.
O
3
5*
o
£L
O
o
3
of
e
o
s
E/5
O
£
€t>
on
U>
k)
i
v©
Pollutant
Inlet
Outlet
Emission Factor
(lb/hp-hr)
Emission Factor
(lb/MMBtu)
Emission Factor
(lb/hp-hr)
Emission Factor
(lb/MMBtu)
NOx
0.017
1.8
5.51 E-03
0.58
CO
0.026
2.8
0.022
2.4
O
o
0.77
109
0.77
109
TOC
7.28 E-04
0.079
4.41 E-04
0.047
nh3
1.10 E-04
0.012
1.81 E-03
0.19
€7 - €16
4.19 E-05
0.0042
9.04 E-06
0.0009
C16+
3.75 E-05
0.004
1.32 E-06
0.0001
PM solids (front half)
6.61 E-06
0.0007
6.61 E-06
0.0007
Benzene0
ND
7.1 E-04
ND
1.1 E-04
Toluenec
ND
2.3 E-04
ND
<2.3 E-05
Xylenes®
ND
<5.9 E-05
ND
<4.0 E-05
Propylene
ND
<1.6 E-04
ND
<1.6 E-04
Naphthalene0
ND
<4.9 E-05
ND
<4.9 E-05
Formaldehyde®
ND
<1.6 E-03
ND
<7.2 E-06
Acetaldehyde®
ND
<6.1 E-05
ND
<4.8 E-06
Acrolein®
ND
<3.7 E-05
ND
<9.6 E-06
-------
Tabic 3.2-3 (cont).
References 8,10-13,15-18. Factors reflect very limited data and as such inlet emissions were slightly different from the uncontrolled emission
factor for 4-cycle rich bum engines. To convert from Ib/hp-hr to kg/kw-hr, multiply by 0.608. To convert from lb/MMBtu to ng/J, multiply
by 430. ND = No data. SCC = Source Classification Code.
EMISSION FACTOR RATING: A. Based on 99.5% conversion of the fuel carbon to C02. C02(lb/MMBtu) = (3.67)(%CON)(C/E), where
%CON = percent conversion of fuel carbon to C02, C = carbon content of fuel by weight (0.75), and E = energy content of fuel,
0.0250 MMBtu/lb. C02 emissions are not affected by controls.
Hazardous air pollutant listed in the Clean Air Act.
-------
Table 3.2-4. EMISSION FACTORS FOR CONTROLLED NATURAL GAS PRIME MOVERS:
SELECTIVE CATALYTIC REDUCTION ON 4-CYCLE LEAN BURN ENGINE®
(SCC 2-02-002-54)
EMISSION FACTOR RATING: E (except as noted)
Pollutant
Inlet
Outlet
Emission Factor
(lb/hp-hr)
Emission Factor
(lb/MMBtu)
Emission Factor
(lb/hp-hr)
Emission Factor
(lb/MMBtu)
NOs
0.042
6.4
7.94 E-03
1.2
CO
2.65 E-03
0.38
2.43 E-03
0.37
o
o
«SJ
cr
0.77
109
0.77
109
nh3
ND
ND
5.95 E-04
0.091
C7 - C16
1.54 E-05
0.0023
6.83 E-06
0.0013
€16+
2.87 E-05
0.0044
5.29 E-06
0.0008
a References 10-13,16-19. Factors reflect very limited data and as such inlet emissions were slightly different from the uncontrolled
emission factor for 4-cycle lean bum engines. To convert from lb/hp-hr to kg/kw-hr multiply by 0.608. To convert from lb/MMBtu to
ng/J, multiply by 430. ND = No data. SCC = Source Classification Code.
b EMISSION FACTOR RATING: A. Based on 99.5% conversion of the fuel carbon to C02. C02 [lb/MMBtu] = (3 .67)(%CON)(C/E),
where %CON = percent conversion of fuel carbon to C02, C = carbon content of fuel by weight (0.75), and E = energy content of fuel,
0.0250 MMBtu/lb. C02 emissions are not affected by controls.
-------
Table 3.2-5. EMISSION FACTORS FOR CONTROLLED NATURAL GAS PRIME MOVERS:
CLEAN BURN AND PRECOMBUSTION CHAMBER ON 2-CYCLE LEAN BURN ENGINE®
(SCC 2-02-002-52)
EMISSION FACTOR RATING: C (except as noted)
Pollutant
Clean Bum
Precombustion Chamber
Emission Factor
(lb/hp-hr)
Emission Factor
(lb/MMBtu)
Emission Factor
(lb/hp-hr)
Emission Factor
(lb/MMBtu)
NOx
5.07 E-03
0.83
6.39 E-03
0.85
CO
2.43 E-03
0.30
5.29 E-03
0.67
o
o
cr
0,77
109
0.77
109
TOC
5.51 E-03
0.77
0.014
1.8
TNMOC
2.65 E-04
0.15
1.94 E-03
0.25
ch4
5.29 E-03
0.62
0.012
1.5
a Reference 7,10-13,17-19. C02 emissions are not affected by controls. To convert from lb/hp-hr to kg/kw-hr, multiply by 0.608. To convert
from lb/MMBtu to ng/J, multiply by 430. TNMOC = total nonmethane organic compounds. SCC = Source Classification Code.
b EMISSION FACTOR RATING: A. Based on 99.5% conversion of the fuel carbon to C02. C02 [lb/MMBtu] = (3.67)(%CON)(C/E), where
%CON = percent conversion of fuel carbon to C02> C = carbon content of fuel bv weight (0.75), and E = energy content of fuel,
0.0250 MMBtu/lb.
OS
-------
Table 3.2-6. NONCRITERIA EMISSION FACTORS FOR
UNCONTROLLED NATURAL GAS 2-CYCLE LEAN BURN ENGINES
EMISSION FACTOR RATING: E
Pollutant
Emission Factors
(lb/hp-hr)
Formaldehydeb
2.93 E-03
Benzeneb
3.62 E-06
Tolueneb
3.62 E-06
Ethylbenzeneb
1.81 E-06
Xylenesb
5.43 E-06
a Reference 20. Source Classification Code 2-02-002-52. Ratings reflect very limited data and may not
apply to specific facilities. To convert from lb/hp-hr to kg/kw-hr, multiply by 0.608.
b Hazardous air pollutant listed in the Clean Air Act.
References For Section 3.2
1. Standards Support And Environmental Impact Statement, Volume J: Proposed Standards Of
Performance For Stationary Gas Turbines, EPA-450/2-77-017a, September 1977.
2. Engines, Turbines, And Compressors Directory, American Gas Association, Catalog #XF0488.
3. 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 Parte, NC, July 1979.
4. Limiting Net Greenhouse Gas Emissions In The United States, Volume II: Energy Responses,
Report for the Office of Environmental Analysis, Office of Policy, Planning and Analysis,
Department of Energy (DOE), DOE/PE-0101 Volume II, September 1991.
5. C. Castaldini, Evaluation Of Water Injection Impacts For Gas Turbine NOx Control At
Compressor Stations, prepared by Acurex Corp. for the Gas Research Institute, GRI-90/0138,
July 1990.
6. N. L. Martin 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), GRI-89/0041, Gas Research Institute,
Chicago, IL, February 1989.
7. R. E. Fanick, et al., Emissions Data For Stationary Reciprocating Engines And Gas Turbines In
Use By The Gas Pipeline Transmission Industry — Phases I & II, Project PR-15-613, Pipeline
Research Committee, American Gas Association, Arlington, VA, April 1988.
8. C. Castaldini, NOx Reduction Technologies For Natural Gas Industry Prime Movers,
GRI-90/0215, Gas Research Institute, Chicago, IL, August 1990.
10/96
Stationary Internal Combustion Sources
3.2-13
-------
9. C. Urban, Compilation Of Emissions Data For Stationary Reciprocating Gas Engines And Gas
Turbines In Use By American Gas Association Member Companies, prepared by Southwest
Research Institute Pipeline Research Committee of the American Gas Association, Project
PR-15-86, May 1980.
10. G. Marl and and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U. S. Department of Energy, Oak Ridge, TN, 1983.
11. G. Marland and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1950-1982, Tellus 36B.232-261, 1984.
12. Inventory Of U. S. Greenhouse Gas Emissions And Sinks: 1990-1991, EPA-230-R-96-006,
U. S. Environmental Protection Agency, Washington, DC, November 1995.
13. 1PCC Guidelines For National Greenhouse Gas Inventories Workbook, Intergovernmental Panel
on Climate Change/Organization for Economic Cooperation and Development, Paris, France,
1995.
14. C. Castaldini. Environmental Assessment Of NOx Control On A Spark-ignited Large Bore
Reciprocating Internal Combustion Engine, EPA-600/7-86-002A, U. S. Environmental
Protection Agency, Cincinnati, OH, January 6, 1986.
15. C Castaldini 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, Cincinnati, OH, June 1984.
16. Air Pollution Source Testing For California AB258S On An Oil Platform Operated By Chevron
USA, Inc. Platform Hope, California, Chevron USA, Inc., Ventura, CA, August 29, 1990.
17. Air Pollution Source Testing For California AB2588 Of Engines At The Chevron USA, Inc.
Carpinteria Facility, Chevron USA, Inc.. Ventura. CA, August 30, 1990.
18. Pooled Source Emission Test Report: Gas FiredIC Engines In Santa Barbara County, ARCO,
Bakersfield, CA, July 1990.
19. C. Castaldini 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.
20. Engines, Turbines, And Compressors Directory, Catalog #XF0488, American Gas Association,
Arlington, VA, 1985.
3.2-14
EMISSION FACTORS
10/96
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3.3 Gasoline And Diesel Industrial Engines
3.3.1 General
The engine category addressed by this section covers a wide variety of industrial applications
of both gasoline and diesel internal combustion (IC) 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 three primary fuels for reciprocating IC
engines are gasoline, diesel fuel oil (No.2), and natural gas. Gasoline is used primarily for mobile and
portable engines. Diesel fuel oil is the most versatile fuel and is used in IC engines of all sizes. The
rated power of these engines covers a rather substantial range, up to 250 horsepower (hp) for gasoline
engines and up to 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 IC 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 2 methods used for stationary reciprocating IC engines: compression ignition (CI)
and spark ignition (SI). This section deals with both types of reciprocating IC engines. All diesel-
fueled engines are compression ignited, and all gasoline-fueled engines are spark ignited.
In CI engines, combustion air is first compression heated in the cylinder, and diesel fuel oil is
then injected into the hot air. Ignition is spontaneous because the air temperature is above the
autoignition temperature of the fuel. SI 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.
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 autoignition. 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.1
3.3.3 Emissions
Most of the pollutants from IC engines are emitted through the exhaust. However, some total
organic compounds (TOC) escape from the crankcase as a result of blowby (gases that 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 TOCs from diesel CI engines enter the
10/96
Stationary Internal Combustion Sources
3.3-1
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atmosphere from the exhaust. Evaporative losses are insignificant in diesel engines due to the low
volatility of diesel fuels.
The primary pollutants from internal combustion engines are oxides of nitrogen (NOx), total
organic compounds (TOC), carbon monoxide (CO), and particulates, which include both visible
(smoke) and nonvisible emissions. Nitrogen oxide formation is directly related to high pressures and
temperatures during the combustion process and to the nitrogen content, if any, of the fuel. The other
pollutants, HC, CO, and smoke, are primarily the result of incomplete combustion. Ash and metallic
additives in the fuel also contribute to the particulate content of the exhaust. Sulfur oxides (SOx) also
appear in the exhaust from IC engines. The sulfur compounds, mainly sulfur dioxide (S02), are
directly related to the sulfur content of the fuel.
3.3.3.1 Nitrogen Oxides -
Nitrogen oxide formation occurs by two fundamentally different mechanisms. The
predominant mechanism with internal combustion engines is thermal NOx which arises from the
thermal dissociation and subsequent reaction of nitrogen (N2) and oxygen (02) molecules in the
combustion air. Most thermal NOx is formed in the high-temperature region of the flame from
dissociated molecular nitrogen in the combustion air. Some NOx, called prompt NOx, is formed in the
early part of the flame from reaction of nitrogen intermediary species, and HC radicals in the flame.
The second mechanism, fuel NOx, stems from the evolution and reaction of fuel-bound nitrogen
compounds with oxygen. Gasoline, and most distillate oils have no chemically-bound fuel N2 and
essentially all NOx formed is thermal NOx.
3.3.3.2 Total Organic Compounds -
The pollutants commonly classified as hydrocarbons are composed of a wide variety of organic
compounds and are discharged into the atmosphere when some of the fuel remains unburned or is only
partially burned during the combustion process. Most unbumed hydrocarbon emissions result from
fuel droplets that were transported or injected into the quench layer during combustion. This is the
region immediately adjacent to the combustion chamber surfaces, where heat transfer outward through
the cylinder walls causes the mixture temperatures to be too low to support combustion.
Partially burned hydrocarbons can occur because of poor air and fuel homogeneity due to
incomplete mixing, before or during combustion: incorrect air/fuel ratios in the cylinder during
combustion due to maladjustment of the engine fuel system; excessively large fuel droplets (diesel
engines); and low cylinder temperature due to excessive cooling (quenching) through the walls or early
cooling of the gases by expansion of the combustion volume caused by piston motion before
combustion is completed.2
3.3.3.3 Carbon Monoxide -
Carbon monoxide is a colorless, odorless, relatively inert gas formed as an intermediate
combustion product that appears in the exhaust when the reaction of CO to C02 cannot proceed to
completion. This situation occurs if there is a lack of available oxygen near the hydrocarbon (fuel)
molecule during combustion, if the gas temperature is too low, or if the residence time in the cylinder
is too short. Hie oxidation rate of CO is limited by reaction kinetics and, as a consequence, can be
accelerated only to a certain extent by improvements in air and fuel mixing during the combustion
process.2"3
3.3-2
EMISSION FACTORS
10/96
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3.3.3.4 Smoke and Particulate Matter -
White, blue, and black smoke may be emitted from IC engines. Liquid particulates appear as
white smoke in the exhaust during an engine cold start, idling, or low load operation. These are
formed in the quench layer adjacent to the cylinder walls, where the temperature is not high enough to
ignite the fuel. Blue smoke is emitted when lubricating oil leaks, often past worn piston rings, into the
combustion chamber and is partially burned. Proper maintenance is the most effective method of
preventing blue smoke emissions from all types of IC engines. The primary constituent of black
smoke is agglomerated carbon particles (soot) formed in regions of the combustion mixtures that are
oxygen deficient.2
3.3.3.5 Sulfur Oxides -
Sulfur oxides emissions are a function of only the sulfur content in the fuel rather than any
combustion variables. In fact, during the combustion process, essentially all the sulfur in the fuel is
oxidized to S02 The oxidation of S02 gives sulfur trioxide (S03), which reacts with water to give
sulfuric acid (H2S04), a contributor to acid precipitation. Sulfuric acid reacts with basic substances to
give sulfates, which are fine particulates that contribute to PM-10 and visibility reduction. Sulfur
oxide emissions also contribute to corrosion of the engine parts.2"3
3.3.4 Control Technologies
Control measures to date are primarily directed at limiting NOx and CO emissions since they
are the primary pollutants from these engines. From a NOx control viewpoint, the most important
distinction between different engine models and types of reciprocating engines is whether they are
rich-burn or lean-bum. Rich-burn engines have an air-to-fuel ratio operating range that is near
stoichiometric or fuel-rich of stoichiometric and as a result the exhaust gas has little or no excess
oxygen. A lean-bum engine has an air-to-fuel operating range that is fuel-lean of stoichiometric;
therefore, the exhaust from these engines is characterized by medium to high levels of 02. The most
common N0X control technique for diesel and dual-fuel engines focuses on modifying the combustion
process. However, selective catalytic reduction (SCR) and nonselective catalytic reduction (NSCR)
which are post-combustion techniques are becoming available. Controls for CO have been partly
adapted from mobile sources.4
Combustion modifications include injection timing retard (ITR), preignition chamber
combustion (PCC), air-to-fuel ratio adjustments, and derating. Injection of fuel into the cylinder of a
CI engine initiates the combustion process. Retarding the timing of the diesel fuel injection causes the
combustion process to occur later in the power stroke when the piston is in the downward motion and
combustion chamber volume is increasing. By increasing the volume, the combustion temperature and
pressure are lowered, thereby lowering NOx formation. ITR reduces NOx from all diesel engines;
however, the effectiveness is specific to each engine model. The amount of NOx reduction with ITR
diminishes with increasing levels of retard.4
Improved swirl patterns promote thorough air and fuel mixing and may include a
precombustion chamber (PCC). A PCC is an antechamber that ignites a fuel-rich mixture that
propagates to the main combustion chamber. The high exit velocity from the PCC results in improved
mixing and complete combustion of the lean air/fuel mixture which lowers combustion temperature,
thereby reducing NOx emissions.4
10/96
Stationary Internal Combustion Sources
3.3-3
-------
The air-to-fuel ratio for each cylinder can be adjusted by controlling the amount of fuel that
enters each cylinder. At air-to-fuel ratios less than stoichiometric (fuel-rich), combustion occurs under
conditions of insufficient oxygen which causes NOx to decrease because of lower oxygen and lower
temperatures. Derating involves restricting the engine operation to lower than normal levels of power
production for the given application. Derating reduces cylinder pressures and temperatures, thereby
lowering NOx formation rates.4
SCR is an add-on NOx control placed in the exhaust stream following the engine and involves
injecting ammonia (NH3) into the flue gas. The NH3 reacts with NOx in the presence of a catalyst to
form water and nitrogen. The effectiveness of SCR depends on fuel quality and engine duty cycle
(load fluctuations). Contaminants in the fuel may poison or mask the catalyst surface causing a
reduction or termination in catalyst activity. Load fluctuations can cause variations in exhaust
temperature and NOx concentration which can create problems with the effectiveness of the SCR
system 4
NSCR is often referred to as a three-way conversion catalyst system because the catalyst
reactor simultaneously reduces NOx, CO, and HC and involves placing a catalyst in the exhaust stream
of the engine. The reaction requires that the 02 levels be kept low and that the engine be operated at
fuel-rich air-to-fuel ratios
The most accurate method for calculating such emissions is on the basis of "brake-specific"
emission factors (pounds per horsepower-hour [lb/hp-hr]). Emissions are the product of the brake-
specific emission factor, the usage in hours, the rated power available, and the load factor (the power
actually used divided by the power available). However, for emission inventory purposes, it is often
easier to assess this activity on the basis of fuel used.
Once reasonable usage and duty cycles for this category were ascertained, emission values
were aggregated to arrive at the factors for criteria and organic pollutants presented. Factors in
Table 3.3-1 are in pounds per million British thermal unit (lb/MMBtu). Emission data for a specific
design type were weighted according to estimated material share for industrial engines. Hie emission
factors in these tables, because of their aggregate nature, are most appropriately applied to a population
of industrial engines rather than to an individual power plant. Table 3.3-2 shows unweighted speciated
organic compound and air toxic emission factors based upon only 2 engines. Their inclusion in this
section is intended for rough order-of-magnitude estimates only.
Table 3.3-3 summarizes whether the various diesel emission reduction technologies (some of
which may be applicable to gasoline engines) will generally increase or decrease the selected
parameter. 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 3.3-3 provides general information on the trends of changes on selected parameters.
3.3-4
EMISSION FACTORS
10/96
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3.3.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarised below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
No changes.
Supplement B, October 1996
• Text was revised concerning emissions and controls.
• The C02 emission factor was adjusted to reflect 98.5 percent conversion efficiency.
10/96
Stationary Internal Combustion Sources
3.3-5
-------
Table 3.3-1. EMISSION FACTORS FOR UNCONTROLLED GASOLINE
AND DIESEL INDUSTRIAL ENGINES®
Pollutant
Gasoline Fuel
(SCC 2-02-003-01, 2-03-003-01)
Diesel Fuel
(SCC 2-02-001-02, 2-03-001-01)
EMISSION
FACTOR
RATING
Emission Factor
(lb/hp-hr)
(power output)
Emission Factor
(lb/MMBtu)
(fuel input)
Emission Factor
(lb/hp-hr)
(power output)
Emission Factor
(lb/MMBtu)
(fuel input)
NOx
0.011
1.63
0.031
4.41
D
CO
0.439
62.7
6.68 E-03
0.95
D
sox
5.91 E-04
0.084
2.05 E-03
0.29
D
PM-10b
7,21 E-04
0.10
2.20 E-03
0,31
D
C02c
1.08
154
1.15
164
B
Aldehydes
4.85 E-04
0.07
4.63 E-04
0.07
D
TOC
Exhaust
0.015
2.10
2.47 E-03
0.35
D
Evaporative
6.61 E-04
0.09
0.00
0.00
E
Crankcase
4.85 E-03
0.69
4.41 E-05
0.01
E
Refueling
1.08 E-03
0.15
0,00
0.00
E
a References 2,5-6,9-14. When necessary, an average brake-specific fuel consumption (BSFC) of
7,000 Btu/hp-hr was used to convert from lb/MMBtu to lb/hp-hr. To convert from lb/hp-hr to
kg/kw-hr, multiply by 0.608. To convert from lb/MMBtu to ng/J, multiply by 430. SCC = Source
Classification Code. TOC = total organic compounds.
b PM-10 = particulate matter less than or equal to 10 pm aerodynamic diameter. All particulate is
assumed to be < 1 ^m in size.
c Assumes 99% conversion of carbon in fuel to C02 with 87 weight % carbon in diesel, 86 weight %
carbon in gasoline, average BSFC of 7,000 Btu/hp-hr, diesel heating value of 19,300 Btu/lb, and
gasoline heating value of 20,300 Btu/lb.
3.3-6
EMISSION FACTORS
10/96
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Table 3.3-2. SPECIATED ORGANIC COMPOUND EMISSION
FACTORS FOR UNCONTROLLED DIESEL ENGINES3
EMISSION FACTOR RATING: E
Pollutant
Emission Factor
(Fuel Input)
(Ib/MMBtu)
j" —
Benzene
9.33 E-04
Tolueneb
4.09 E-04
Xylenes'5
2.85 E-04
Propylene13
2.58 E-03
1,3-Butadienebc
<3.91 E-05
L
Formaldehyde
1.18 E-03
Acetaldehyde
7.67 E-04
Acrolein15
<9.25 E-05
Polycyclic aromatic hydrocarbons (PAH)
Naphthalene1*
8.48 E-05
Acenaphthylene
<5.06 E-06
Acenaphthene
<1.42 E-06
Fluorene
2.92 E-05
Phenanthrene
2.94 E-05
Anthracene
1.87 E-06
Fluoranthene
7.61 E-06
Pyrene
4.78 E-06
Benzo(a)anthracene
1,68 E-06
Chrysene
3.53 E-07
Benzo(b)fluoranthene
<9.91 E-08
Benzo(k)fluoranthene
<1.55 E-07
Benzo(a)pyrene
<1.88 E-07
Indeno( 1,2,3-cd)pyrene
<3.75 E-07
Dibenz(a.h)anthracene
<5.83 E-07
Benzo(g,h,l)perylene
<4.89 E-07
TOTAL PAH
1.68 E-04
a Based on the uncontrolled levels of 2 diesel engines from References 6-7. Source Classification
Codes 2-02-001-02, 2-03-001-01. To convert from Ib/MMBtu to ng/J, multiply by 430.
k Hazardous air pollutant listed in the Clean Air Act.
c Based on data from 1 engine.
10/96
Stationary Internal Combustion Sources
3.3-7
-------
Table 3.3-3. EFFECT OF VARIOUS EMISSION CONTROL TECHNOLOGIES
ON DIESEL ENGINES3
Affected Parameter
Technology
Increase
Decrease
Fuel modifications
Sulfur content increase
PM, wear
Aromatic content increase
PM, NOx
Cetane number
PM, NOx
10% and 90% boiling point
PM
Fuel additives
PM, NOx
Water/Fuel emulsions
NOx
Engine modifications
Injection timing retard
PM, BSFC
NOx, power
Fuel injection pressure
PM, NOx
Injection rate control
NOx, PM
Rapid spill nozzles
PM
Electronic timing & metering
NOx. PM
Injector nozzle geometry
PM
Combustion chamber modifications
NOx, PM
Turbocharging
PM, power
NOx
Charge cooling
NOx
Exhaust gas recirculation
PM, power, wear
NOx
Oil consumption control
PM, wear
Exhaust after-treatment
Particulate traps
PM
Selective catalytic reduction
NOx
Oxidation catalysts
TOC, CO, PM
a Reference 8. PM = particulate matter. BSFC = brake-specific fuel consumption.
3.3-8
EMISSION FACTORS
10/96
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References For Section 3,3
1. H I. Lips, et ai, Environmental Assessment Of Combustion Modification Controls For
Stationary Internal Combustion Engines, EPA-600/7-81-127, U. S, Environmental Protection
Agency, Cincinnati, OH, July 1981.
2. Standards Support And Environmental Impact Statement, Volume 1: Stationary Internal
Combustion Engines, EPA-450/2-78-125a, U. S. Environmental Protection Agency, Research
Triangle Park, NC, July 1979.
3. M. Hoggan, et ai, Air Quality Trends In California's South Coast And Southeast Desert Air
Basins, 1976-1990, Air Quality Management Plan, Appendix II-B, South Coast Air Quality
Management District, July 1991.
4. R B. Snyder, Alternative Control Techniques Document.. NOx Emissions From Stationary
Reciprocating Internal Combustion Engines, EPA-453/R-93-032. U. S. Environmental
Protection Agency, Research Triangle Park, July 1993.
5. C. T. Hare and K. J. Springer, Exhaust Emissions From Uncontrolled Vehicles And Related
Equipment Using Internal Combustion Engines, Part 5: Farm, Construction. And Industrial
Engines, APTD-1494, U. S. Environmental Protection Agency, Research Triangle Park, NC,
October 1973.
6. Pooled Source Emission Test Report: Oil And Gas Production Combustion Sources, Fresno
And Ventura Counties, California, ENSR 7230-007-700, Western States Petroleum
Association, Bakersfield, CA, December 1990.
7. W. E. Qsborn and M. D. McDannel, Emissions Of Air Toxic Species: Test Conducted Under
AB2588 For The Western States Petroleum Association, CR 72600-2061, Western States
Petroleum Association, Glendale, CA, May 1990.
8. Technical Feasibility Of Reducing NOx And Particulate Emissions From Heavy-duty Engines,
CARB Contract A132-085, California Air Resources Board, Sacramento, CA, March 1992.
9. G. Marl and and R. M. Rotty, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1951-1981, DOE/NBB-0036 TR-003, Carbon Dioxide Research
Division, Office of Energy Research, U. S. Department of Energy, Oak Ridge, TN, 1983.
10. A. Rosland. Greenhouse Gas Emissions in Norway: Inventories and Estimation Methods,
Oslo: Ministry of Environment, 1993.
11. Sector-Specific Issues and Reporting Methodologies Supporting the General Guidelines for the
Voluntary Reporting of Greenhouse Gases under Section 1605(b) of the Energy Policy Act of
1992 (1994) DOE/PO-0028, Volume 2 of 3, U.S. Department of Energy.
12. G. Marland and R. M. Rottv, Carbon Dioxide Emissions From Fossil Fuels: A Procedure For
Estimation And Results For 1950-1982, Tellus 36B 232-261, 1984.
13. Inventory Of U. S. Greenhouse Gas Emissions And Sinks: 1990-1991, EPA-230-R-96-006,
U. S. Environmental Protection Agency, Washington, DC, November 1995.
14. IPCC Guidelines For National Greenhouse Gas Inventories Workbook, Intergovernmental
Panel on Climate Change/Organization for Economic Cooperation and Development, Paris,
France, 1995.
10/96
Stationary Internal Combustion Sources
3.3-9
-------
3.4 Large Stationary Diesel And AH Stationary Dual-fuel Engines
3.4.1 General
The primary domestic use of large stationary diesel engines (greater than 600 horsepower fhp])
is in oil and gas exploration and production. These engines, in groups of 3 to 5, 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 (IC) 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 2 ignition methods used in stationary reciprocating IC engines, compression ignition
(CI) and spark ignition (SI). In CI engines, combustion air is first compression heated in the cylinder,
and diesel fuel oil is then injected into the hot air. Ignition is spontaneous because the air temperature
is above the autoignition temperature of the fuel, SI 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. Although all diesel- fueled engines are compression ignited and all gasoline- and gas-fueled
engines are spark ignited, gas can be used in a CI 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 autoignition. 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.1
3.4.3 Emissions And Controls
Most of the pollutants from IC engines are emitted through the exhaust. However, some total
organic compounds (TOC) escape from the crankcase as a result of blowby (gases that are vented
from the oil pan after they have escaped from the cylinder past the piston rings) and from the fuel tank
10/96
Stationary Internal Combustion Sources
3.4-1
-------
and carburetor because of evaporation. Nearly all of the TOCs from diesel CI engines enter the
atmosphere from the exhaust. Crankcase blowby is minor because TOCs 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 (NOx),
hydrocarbons and other organic compounds, carbon monoxide (CO), and particulates, which include
both visible (smoke) and nonvisible emissions. Nitrogen oxide formation is directly related to high
pressures and temperatures during the combustion process and to the nitrogen content, if any, of the
fuel. The other pollutants, HC, CO, and smoke, are primarily the result of incomplete combustion.
Ash and metallic additives in the fuel also contribute to the particulate content of the exhaust. Sulfur
oxides also appear in the exhaust from IC engines. The sulfur compounds, mainly sulfur dioxide
(S02), are directly related to the sulfur content of the fuel.2
3.4.3.1 Nitrogen Oxides -
Nitrogen oxide formation occurs by two fundamentally different mechanisms. The
predominant mechanism with internal combustion engines is thermal NOx which arises from the
thermal dissociation and subsequent reaction of nitrogen (N2) and oxygen (02) molecules in the
combustion air. Most thermal NOx is formed in the high-temperature region of the flame from
dissociated molecular nitrogen in the combustion air. Some NOx, called prompt NOx, is formed in the
early part of the flame from reaction of nitrogen intermediary species, and HC radicals in the flame.
The second mechanism, fuel NOx, stems from the evolution and reaction of fuel-bound nitrogen
compounds with oxygen. Gasoline, and most distillate oils, have no chemically-bound fuel N2 and
essentially all NOx formed is thermal NOx.
3.4.3.2 Total Organic Compounds -
The pollutants commonly classified as hydrocarbons are composed of a wide variety of organic
compounds and are discharged into the atmosphere when some of the fuel remains unburned or is only
partially burned during the combustion process. Most unburned hydrocarbon emissions result from
fuel droplets that were transported or injected into the quench layer during combustion. This is the
region immediately adjacent to the combustion chamber surfaces, where heat transfer outward through
the cylinder walls causes the mixture temperatures to be too low to support combustion.
Partially burned hydrocarbons can occur because of poor air and fuel homogeneity due to
incomplete mixing, before or during combustion; incorrect air/fuel ratios in the cylinder during
combustion due to maladjustment of the engine fuel system; excessively large fuel droplets (diesel
engines); and low cylinder temperature due to excessive cooling (quenching) through the walls or early
cooling of the gases by expansion of the combustion volume caused by piston motion before
combustion is completed.2
3.4.3.3 Carbon Monoxide -
Carbon monoxide is a colorless, odorless, relatively inert gas formed as an intermediate
combustion product that appears in the exhaust when the reaction of CO to C02 cannot proceed to
completion. This situation occurs if there is a lack of available oxygen near the hydrocarbon (fuel)
molecule during combustion, if the gas temperature is too low, or if the residence time in the cylinder
is too short. The oxidation rate of CO is limited by reaction kinetics and, as a consequence, can be
accelerated only to a certain extent by improvements in air and fuel mixing during the combustion
process.2"3
3.4-2
EMISSION FACTORS
10/96
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3.4.3.4 Smoke, Particulate Matter, and PM-10 -
White, blue, and black smoke may be emitted from IC engines. Liquid particulates appear as
white smoke in the exhaust during an engine cold start, idling, or low load operation. These are
formed in the quench layer adjacent to the cylinder walls, where the temperature is not high enough to
ignite the fuel. Blue smoke is emitted when lubricating oil leaks, often past worn piston rings, into the
combustion chamber and is partially burned. Proper maintenance is the most effective method of
preventing blue smoke emissions from all types of IC engines. The primary constituent of black
smoke is agglomerated carbon particles (soot)2
3.4.3.5 Sulfur Oxides -
Sulfur oxide emissions are a function of only the sulfur content in the fuel rather than any
combustion variables. In fact, during the combustion process, essentially all the sulfur in the fuel is
oxidized to S02. The oxidation of S02 gives sulfur trioxide (S03), which reacts with water to give
sulfuric acid (H2S04), a contributor to acid precipitation. Sulfuric acid reacts with basic substances to
give sulfates, which are fine particulates that contribute to PM-10 and visibility reduction. Sulfur
oxide emissions also contribute to corrosion of the engine parts.2,3
Table 3.4-1 contains gaseous emission factors for the pollutants discussed above, expressed in
units of pounds per horsepower-hour (lb/hp-hr), and pounds per million British thermal unit
(lb/MMBtu). Table 3.4-2 shows the particulate and particle-sizing 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 because they are based only on a single engine test; they are to be
used only for rough order of magnitude comparisons.
Table 3.4-5 shows the NOx reduction and fuel consumption penalties for diesel and dual-fueled
engines based on some of the available control techniques. The emission reductions shown are those
that have been demonstrated. The effectiveness of controls on a 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 3.4-5. These techniques include
internal/external exhaust gas recirculation, combustion chamber modification, manifold air cooling, and
turbocharging.
3.4.4 Control Technologies
Control measures to date are primarily directed at limiting NOx and CO emissions since they
are the primary pollutants from these engines. From a NOx control viewpoint, the most important
distinction between different engine models and types of reciprocating engines is whether they are
rich-bum or lean-burn. Rich-burn engines have an air-to-fuel ratio operating range that is near
stoichiometric or fuel-rich of stoichiometric and as a result the exhaust gas has little or no excess
oxygen. A lean-burn engine has an air-to-fuel operating range that is fuel-lean of stoichiometric;
therefore, the exhaust from these engines is characterized by medium to high levels of 02. The most
common NOx control technique for diesel and dual fuel engines focuses on modifying the combustion
process. However, selective catalytic reduction (SCR) and nonselective catalytic reduction (NSCR)
which are post-combustion techniques are becoming available. Control for CO have been partly
adapted from mobile sources.5
Combustion modifications include injection timing retard (ITR), preignition chamber
combustion (PCC), air-to-fuel ratio, and derating. Injection of fuel into the cylinder of a CI engine
initiates the combustion process. Retarding the timing of the diesel fuel injection causes the
combustion process to occur later in the power stroke when the piston is in the downward motion and
10/96
Stationary Internal Combustion Sources
3.4-3
-------
combustion chamber volume is increasing. By increasing the volume, the combustion temperature and
pressure are lowered, thereby lowering NOx formation. ITR reduces NOx from all diesel engines;
however, the effectiveness is specific to each engine model. The amount of NOx reduction with ITR
diminishes with increasing levels of retard.5
Improved swirl patterns promote thorough air and fuel mixing and may include a
precombustion chamber (PCC). A PCC is an antechamber that ignites a fuel-rich mixture that
propagates to the main combustion chamber. The high exit velocity from the PCC results in improved
mixing and complete combustion of the lean air/fuel mixture which lowers combustion temperature,
thereby reducing NOx emissions 5
The air-to-fuel ratio for each cylinder can be adjusted by controlling the amount of fuel that
enters each cylinder. At air-to-fuel ratios less than stoichiometric (fuel-rich), combustion occurs under
conditions of insufficient oxygen which causes NOx to decrease because of lower oxygen and lower
temperatures. Derating involves restricting engine operation to lower than normal levels of power
production for the given application. Derating reduces cylinder pressures and temperatures thereby
lowering NOx formation rates,5
SCR is an add-on NOx control placed in the exhaust stream following the engine and involves
injecting ammonia (NH3) into the flue gas. The NH3 reacts with the NOx in the presence of a catalyst
to form water and nitrogen. The effectiveness of SCR depends on fuel quality and engine duty cycle
(load fluctuations). Contaminants in the fuel may poison or mask the catalyst surface causing a
reduction or termination in catalyst activity. Load fluctuations can cause variations in exhaust
temperature and NOx concentration which can create problems with the effectiveness of the SCR
system.5
NSCR is often referred to as a three-way conversion catalyst system because the catalyst
reactor simultaneously reduces NOx, CO, and HC and involves placing a catalyst in the exhaust stream
of the engine. The reaction requires that the 02 levels be kept low and that the engine be operated at
fuel-rich air-to-fuel ratios.5
3.4.5 Updates Since the Fifth Edition
The Fifth Edition was released in January 1995. Revisions to this section since that date are
summarized below. For further detail, consult the memoranda describing each supplement or the
background report for this section. These and other documents can be found on the CHIEF electronic
bulletin board (919-541-5742), or on the new EFIG home page (http://www.epa.gov/oar/oaqps/efig/).
Supplement A, February 1996
No changes.
Supplement B, October 1996
• Hie general text was updated.
• Controlled N0X factors and PM factors were added for diesel units,
• Math errors were corrected in factors for CO from diesel units and for uncontrolled
N0X from dual fueled units.
3.4-4
EMISSION FACTORS
10/96
-------
Table 3.4-1. GASEOUS EMISSION FACTORS FOR LARGE STATIONARY DIESEL AND ALL
STATIONARY DUAL-FUEL ENGINES8
Diesel Fuel
Dual Fuel"
(SCC 2-02-004-01)
(SCC 2-02-004-02)
Pollutant
Emission Factor
(lb/hp-hr)
(power output)
Emission Factor
(lb/MMBtu)
(fuel input)
EMISSION
FACTOR
RATING
Emission Factor
(lb/hp-hr)
(power output)
Emission Factor
(lb/MMBtu)
(fuel input)
EMISSION
FACTOR
RATING
NOx
Uncontrolled
0.024
3.2
B
0.018
2.7
D
Controlled
0.013°
1.9C
B
ND
ND
NA
CO
5.5 E-03
0.85
C
7.5 E-03
1.16
D
SOxd
8.09 E-03S1
l.OlSj
B
4.06 E-04S, + 9.57
E-03S2
0.05S, + 0.895S2
B
C02e
1.16
165
B
0.772
110
B
PM
0.0007°
0.1c
B
ND
ND
NA
TOC (as CH4)
7.05 E-04
0.09
C
5.29 E-03
0.8
D
Methane
f
f
E
3.97 E-03
0.6
E
Nonmethane
f
f
E
1.32 E-03
0.28
E
a Based on uncontrolled levels for each fael, from References 2,6-7. When necessary, the average heating value of diesel was assumed to be
19,300 Btu/lb with a density of 7.1 lb/gallon. The power output and fuel input values were averaged independently from each other,
because of the use of actual brake-specific fuel consumption (BSFC) values for each data point and of the use of data possibly sufficient to
calculate only 1 of the 2 emission factors (e. g., enough information to calculate lb/MMBtu, but not lb/hp-hr). 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. To convert from lb/hp-hr to kg/kw-hr, multiply by 0.608. To convert from lb/MMBtu to ng/J, multiply by 430. SCC =
Source Classification Code.
b Dual fuel assumes 95% natural gas and 5% diesel fuel.
c References 8-26. Controlled NO„ is by ignition timing retard.
d Assumes that all sulfur in the fuel is converted to S02. = % sulfur in fuel oil; S2 = % sulfur in natural gas. For example, if sulfer
content is 1.5%, then S = 1.5.
e Assumes 100% conversion of carbon in fuel to C02 with 87 weight % carbon in diesel, 70 weight % carbon in natural gas, dual-fuel
mixture of 5% diesel with 95% natural gas, average BSFC of 7,000 Btu/hp-hr, diesel heating value of 19,300 Btu/lb, and natural gas
heating value of 1050 Btu/scf.
Based on data from 1 engine, TOC is by weight 9% methane and 91% nonmethane.
g Assumes that nonmethane organic compounds are 25% of TOC emissions from dual-fuel engines. Molecular weight of nonmethane gas
stream is assumed to be that of methane.
-------
Table 3.4-2. PARTICULATE AND PARTICLE-SIZING
EMISSION FACTORS FOR LARGE UNCONTROLLED STATIONARY DIESEL ENGINES3
EMISSION FACTOR RATING: E
Pollutant
Emission Factor (lb/MMBtu)
(fuel input)
Filterable particulateb
< 1 jm
0.0478
< 3 |im
0.0479
< 10 pm
0.0496
Total filterable particulate
0.0620
Condensable particulate
0.0077
Total PM-10C
0.0573
i
Total particulate
0.0697
a Based on 1 uncontrolled diesel engine from Reference 6. Source Classification Code 2-02-004-
01. The data for the particulate emissions were collected using Method 5, and the particle size
distributions were collected using a Source Assessment Sampling System. To convert from
lb/MMBtu to ng/J. multiply by 430. PM-10 = particulate matter < 10 micrometers (nm)
aero metric diameter.
b Particle size is expressed as aerodynamic diameter.
c Total PM-10 is the sum of filterable particulate less than 10 jjm aerodynamic diameter and
condensable particulate.
d Total particulate is the sum of the total filterable particulate and condensable particulate.
3.4-6
EMISSION FACTORS
10/96
-------
Table 3,4-3, SPECIATED ORGANIC COMPOUND EMISSION FACTORS FOR LARGE
UNCONTROLLED STATIONARY DIESEL ENGINES3
EMISSION FACTOR RATING: E
Pollutant
Emission Factor
(lb/MMBtu)
(fuel input)
Benzene^
7.76 E-04
Tolueneb
2.81 E-04
Xylenes1*
1.93 E-04
Propylene
2.79 E-03
Formaldehyde55
7.89 E-05
Acetaldehydeb
2.52 E-05
Acroleinb
7.88 E-06
"Based on 1 uncontrolled diesel engine from Reference 7. Source Classification
Code 2-02-004-01. Not enough information to calculate the output-specific emission factors of
lb/hp-hr. To convert from Ib/MMBtu to ng/J, multiply by 430.
^Hazardous air pollutant listed in the Clean Air Act.
10/96
Stationary Internal Combustion Sources
3.4-7
-------
Table 3.4-4. PAH EMISSION FACTORS FOR LARGE
UNCONTROLLED STATIONARY DIESEL ENGINES3
EMISSION FACTOR RATING: E
PAH
Emission Factor
(lb/MMBtu)
(fuel input)
Naphthalene15
1.30 E-04
Acenaphthylene
9.23 E-06
Acenaphthene
4.68 E-06
Fluorene
1.28 E-05
Phenanthrene
4.08 E-05
Anthracene
1.23 E-06
Fluoranthene
4.03 E-06
Pyrene
3.71 E-06
Benz(a)anthracene
6.22 E-07
Chrysene
1.53 E-06
Benzo(b)fluoranthene
1.11 E-06
Benzo(k)fiuoranthene
<2.18 E-07
Benzo(a)pvrene
<2.57 E-07
Indeno( 1,2,3 -cd)py rene
<4.14 E-07
Dibenz(a,h)anthracene
<3.46 E-07
Benzo(g,h,l)peryIene
<5.56 E-07
TOTAL PAH
<2.12 E-04
a Based on I uncontrolled diesel engine from Reference 7. Source Classification Code 2-02-004-
01. Not enough information to calculate the output-specific emission factors of lb/hp-hr. To
convert from lb/MMBtu to ng/J, multiply by 430.
b Hazardous air pollutant listed in the Clean Air Act.
3.4-8
EMISSION FACTORS
10/96
-------
Table 3.4-5. N0X REDUCTION AND FUEL CONSUMPTION PENALTIES FOR LARGE
STATIONARY DIESEL AND DUAL-FUEL ENGINES8
Control Approach
Diesel
(SCC 2-02-004-01)
Dual Fuel
(SCC 2-02-004-02)
NOx
Reduction
(%)
ABSFCb
(%)
NOx
Reduction
(%)
ABSFC
(%)
Derate
10%
ND
ND
<20
4
20%
<20
4
ND
ND
25%
5-23
1-5
1 - 33
1-7
Retard
2°
<20
4
<20
3
4°
<40
4
<40
1
8°
28-45
2-8
50-73
3 - 5
Air-to-fuel
3%
ND
ND
<20
0
±10%
7 - 8
3
25-40
1 -3
Water injection (H20/fuel ratio)
50%
25-35
2-4
ND
ND
SCR
80-95
0
80-95
0
a References 1,27-28. The reductions shown are typical and will vary depending on the engine and
duty cycle. SCC = Source Classification Code. ABSFC = change in brake-specific fuel
consumption. ND = no data.
10/96
Stationary Internal Combustion Sources
3.4-9
-------
References For Section 3.4
1. H. I. Lips, et al., Environmental Assessment Of Combustion Modification Controls For
Stationary Internal Combustion Engines, EPA-600/7-81-127, U. S. Environmental Protection
Agency, Cincinnati, OH, July 1981.
2. Standards Support And Environmental Impact Statement, Volume I: Stationary Internal
Combustion Engines, EPA-450/2-78-125a, U. S. Environmental Protection Agency, Research
Triangle Park, NC, July 1979.
3. M. Hoggan, et. al., Air Quality Trends in California's South Coast and Southeast Desert Air
Basins, 1976-1990, "Air Quality Management Plan, Appendix II-B", South Coast Air Quality
Management District, July 1991.
4. Limiting Net Greenhouse Gas Emissions In the United States, Volume 11: Energy' Responses,
report for the Office of Environmental Analysis, Office of Policy, Planning and Analysis,
Department of Energy (DDE), DOE/PE-OIOI Volume II, September 1991.
5. Snyder, R. B., Alternative Control Techniques Document—NOx Emissions from Stationary
Reciprocating Internal Combustion Engines, EPA-453/R-93-032, U. S. Environmental
Protection Agency, Research Triangle Park, July 1993.
6. C. Castaldini, Environmental Assessment OfNOx Control On A Compression Ignition Large
Bore Reciprocating Internal Combustion Engine, Volume I: Technical Results,
EPA-600/7-86/001a, U. S. Environmental Protection Agency, Cincinnati, OH, April 1984.
7. Pooled Source Emission Test Report: Oil And Gas Production Combustion Sources, Fresno
And Ventura Counties, California, ENSR # 7230-007-700, Western States Petroleum
Association, Bakersfield, CA, December 1990.
8. Final Report For An Emission Compliance Test Program On Two Standby Generators Located
At American Car Company, Greenwich, CT, York Services Corp., 1987.
9. Final Report For An Emission Compliance Test Program On A Standby Diesel Generator At
South Central Connecticut Regional Water Authority, West Haven, CT, York Services Corp.,
1988.
10. Air Emission From Stationary Diesel Engines For The Alaska Rural Electric Cooperative
Association, Environmetrics, 1992.
11. Compliance Test Report For Particulate Emissions From A Caterpillar Diesel Generator, St.
Mary's Hospital, Waterburg, CT, TRC Environmental Consultants, 1987.
12. Compliance Measured Particulate Emissions From An Emergency Diesel Generator, Silorsky
Aircraft, United Technologies, Stratford, CT, TRC Environmental Consultants, 1987.
13. Compliance Test Report For Particulate Emissions From A Cummins Diesel Generator,
Colonial Gold Limited Partnership, Hartford, CT, TRC Environmental Consultants, 1988.
14. Compliance Test Report For Particulate Emissions From A Cummins Diesel Generator,
CIGNA Insurance Company, Bloomfield, CT, TRC Environmental Consultants, 1988.
3.4-10
EMISSION FACTORS
10/96
-------
15. Compliance Test Report For Particulate Emission From A Waukesha Diesel Generator, Bristol
Meyers, Wallinsford, CT, TRC Environmental Consultants, 1987.
16. Compliance Test Report For Particulate Emissions From A Cummins Diesel Generator,
Connecticut General Life Insurance, Windsor, CT, TRC Environmental Consultants, 1987.
17. Compliance Measured Particulate Emissions From An Emergency Diesel Generator, Danbury
Hospital, Danbury, CT, TRC Environmental Consultants, 1988.
18. Compliance Test Report For Particulate Emissions From A Caterpillar Diesel Generator,
Colonial Metro Limited Partnership, Hartford, CT, TRC Environmental Consultants, 1988.
19. Compliance Test Report For Particulate Emissions From A Caterpillar Diesel Generator,
Boehringer -Ingelheim Pharmaceuticals, Danbury, CT, TRC Environmental Consultants, 1988.
20. Compliance Test Report For Emissions Of Particulate From An Emergency Diesel Generator,
Meriden - Wallingford Hospital, Meriden, CT, TRC Environmental Consultants, 1987.
21. Compliance Test Report Johnson Memorial Hospital Emergency Generator Exhaust Stack,
Stafford Springs, CT, ROJAC Environmental Services, 1987.
22. Compliance Test Report Union Carbide Corporation Generator Exhaust Stack, Danbury, CT,
ROJAC Environmental Services, 1988.
23. Compliance Test Report Hartford Insurance Company Emergency Generator Exhaust Stack,
Bloomfield, CT, ROJAC Environmental Services, 1987.
24. Compliance Test Report Hartford Insurance Group Emergency Generator Exhaust Stack,
Hartford, CT, ROJAC Environmental Services, 1987.
25. Compliance Test Report Southern New England Telephone Company Emergency Generator
Exhaust Stack, North Haven, CT, ROJAC Environmental Services, 1988.
26. Compliance Test Report Pfizer, Inc. Two Emergency Generator Exhaust Stacks, Groton, CT,
ROJAC Environmental Services, 1987.
27. L. M. Campbell, et al,, Sourcebook: NOx Control Technology Data, Control Technology
Center, EPA-600/2-91-029, U. S. Environmental Protection Agency, Cincinnati, OH,
July 1991.
28. Catalysts For Air Pollution Control, Manufacturers Of Emission Controls Association
(MECA), Washington, DC, March 1992.
10/96
Stationary Internal Combustion Sources
3.4-11
-------
6.2 Adipic Acid
6.2.1 General1"4
Adipic acid, HOOC(CH2)4COOH, is a white crystalline solid used primarily in the
manufacture of nylon-6,6 polyamide and is produced in 4 facilities in the U. S. Worldwide demand
for adipic acid in 1989 was nearly 2 billion megagrams (Mg) (2 billion tons), with growth continuing
at a steady rate.
Adipic acid historically has been manufactured from either cyclohexane or phenol, but shifts
in hydrocarbon markets have nearly resulted in the elimination of phenol as a feedstock in the U. S.
This has resulted in experimentation with alternative feedstocks, which may have commercial
ramifications.
6.2.2 Process Description1,3"4
Adipic acid is manufactured from cyclohexane in two major reactions. The first step, shown
in Figure 6.2-1, is the oxidation of cyclohexane to produce eyclohexanone (a ketone) and
cyclohexanol (an alcohol). This ketone-alcohol (KA) mixture is then converted to adipic acid by
oxidation with nitric acid in the second reaction, as shown in Figure 6.2-2. Following these
2 reaction stages, the wet adipic acid crystals are separated from water and nitric acid. The product
is dried and cooled before packaging and shipping. Dibasic acids (DBA) may be recovered from the
nitric acid solution and sold as a coproduct. The remaining nitric acid is then recycled to the second
reactor.
The predominant method of cyclohexane oxidation is metal-catalyzed oxidation, which
employs a small amount of cobalt, chromium, and/or copper, with moderate temperatures and
pressures. Air, catalyst, cyclohexane, and in some cases small quantities of benzene are fed into
either a multiple-stage column reactor or a series of stirred tank reactors, with a low conversion rate
from feedstock to oxidized product. This low rate of conversion necessitates effective recovery and
recycling of unreacted cyclohexane through distillation of the oxidizer effluent.
The conversion of the intermediates cyclohexanol and eyclohexanone to adipic acid uses the
same fundamental technology as that developed and used since the early 1940s. It entails oxidation
with 45 to 55 percent nitric acid in the presence of copper and vanadium catalysts. This results in a
very high yield of adipic acid. The reaction is exothermic, and can reach an autocatalytic runaway
state if temperatures exceed 150°C (300°F). Process control is achieved by using large amounts of
nitric acid. Nitrogen oxides (NOx) are removed by bleaching with air, water is removed by vacuum
distillation, and the adipic acid is separated from the nitric acid by crystallization. Further refining,
typically recrystallization from water, is needed to achieve polymer-grade material.
6.2.3 Emissions And Controls1,3"7
Emissions from the manufacture of adipic acid consist primarily of organic compounds and
carbon monoxide (CO) from the first reaction, NOx from the second reaction, and particulate matter
from product cooling, drying, storage, and loading. Tables 6.2-1 and 6.2-2 present emission factors
for the processes in Figure 6.2-1 and Figure 6.6-2, respectively. Emissions estimation of in-process
9/96
Organic Chemical Process Industry
6.2-1
-------
Table 6.2-1 (Metric And English Units). UNCONTROLLED EMISSION FACTORS FOR
PRIMARY OXIDATION ADIPIC ACID MANUFACTURE"
EMISSION FACTOR RATING: D
Source
(Cyclohexane -* KA)
TNMOCb
CO
C02
CH4
kg/Mg lb/ton
kg/Mg lb/ton
kg/Mg lb/ton
kg/Mg lb/ton
High-pressure
scrubber
Low-pressure scrubber
7.0° 14b
1.4d 2,8*
25 49
9.0 18
14 28
3.7 7.4
0.08 0.17
0.05 0.09
* Factors are kilograms per megagram (kg/Mg) and pounds per ton Ob/ton) of adipic acid.
KA = ketone-alcohol mixture. TNMOC = total nonmethane organic compounds.
b One TNMOC composition analysis at a third plant utilizing only I scrubber yielded the following
speciation: 46% butane, 16% pentane, 33% cyclohexane, 5% other; this test not used in total
TNMOC emission factor calculation.
c Multiple TNMOC composition analyses from 2 reactors within 1 plant yielded the following
average speciation: 1.6% ethane, 1.2% ethylene, 6.7% propane, 63% butane, 16% pentane,
11% cyclohexane.
d Multiple TNMOC composition analyses from 2 reactors within 1 plant yielded the following
average speciation: 2.3% ethane, 1,7% ethylene, 5.2% propane, 54% butane, 10% pentane,
26% cyclohexane.
6.2-2
EMISSION FACTORS
10/96
-------
Table 6.2-2 (Metric And English Units). UNCONTROLLED EMISSION FACTORS FOR SECONDARY
OXIDATION ADIPIC ACID MANUFACTURE"
EMISSION FACTOR RATING: E (except as noted)
Source
(KA -» Adipic Acid)
TNMOC
CO
O
o
n2o
NO,
PM
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
kg/Mg
lb/ton
Oxidation reactor1"
0.28
0.55
0.25
0.49
60
120
290d
590d
7.0
14
NA
NA
Nitric acid tank fume sweep8
0.007
0.014
0.14
0.28
2.6
5.2
1.3
2.6
0.81
1.6
NA
NA
Adipic acid refiningf g
0.3
0.5
0
0
NA
NA
NA
NA
0.3
0.6
0.1h
0.1h
Adipic acid drying/cooling/
storage
0
0
0
0
NA
NA
NA
NA
0
0
0.4"
0.8h
¦ Factors are kilograms per megagram (kg/Mg) and pounds per ton (lb/ton) of adipic acid. KA = ketone-alcohol mixture.
TNMOC = total nonmethane organic compounds. NA = not applicable.
b One TNMOC composition analysis at a third plant utilizing only 1 scrubber yielded the following speciation: 46% butane,
33% cyclohexane, 5% other; this test not used in total TNMOC emission factor calculation.
c EMISSION FACTOR RATING; D
d EMISSION FACTOR RATING: A. Controls can reduce emissions by 98% (controlled EMISSION FACTOR RATING: E).
e Derived from multiple gas-stream composition analyses at 2 plants, 1 of which can use extended absorption to lower NO* emissions
to 3.2 lb/ton adipic acid.
f Derived from gas-stream composition analysis during 1 stack test.
6 Includes chilling, crystallization, and centrifuging.
h Factors are after baghouse control device; no efficiency given.
-------
SCRUBBER OFFGAS
HIGH
PRESS,
SCRUBBER
DECANTER &
COLUMN VENTS
TANK
VENIS
TANK
VENTS
CYCLO-
HEXANE
NVR
STACK
CATALYST
BOILERS
KA
STORAGE
STORAGE
KA
REFINING
STRIPPING
LOW
PRESS.
SCRUBBER
OXIDATION
KA = ketone-alcohol mixture
Figure 6.2-1. Adipic acid manufacturing process: Oxidation of cyclohexane.
2-4
EMISSION FACTORS
-------
STACK
EMERGENCY
VENT
BOILERS
NITRIC ACID
TANK FUME
SWEEP
CONE
BURNERS
ABSORBER
OFFGAS
FILTER &
BAG FILTER
& SCRUBBER
VENTS
ABSORBER
BLOWER
VENTS
DRYING.
KA
OXIDATION
CRYST.
\SEP'N
CONC.
STILL
BLEACHER
COOLING
LOADING
NITRIC
AC D
CATALYST
TANK VENTS
A
FILTER VENT
DBA CO PRODUCT
RECOVERY
ADIPIC
ACID
ESTERIFI-
CATION
DBE CO-PRODUCT
METHANOL
KA - ketone-aloohol mixture
DBA-dibasic acid
DBE - dibasic esters
Figure 6.2-2. Adipic acid manufacturing process: Nitric acid oxidation of ketone-alcohol mixture.
10/96 Organic Chemical Process Industry 6.2-5
-------
combustion products, fractional distillation evaporation losses, oxidizer effluent streams, and storage
of volatile raw or intermediate materials, is addressed in Chapter 12, "Metallurgical Industry".
I
The waste gas stream from cyclohexane oxidation, after removal of most of the valuable unreacted
cyclohexane by 1 or more scrubbers, will still contain CO, carbon dioxide (COJ, and organic
compounds. In addition, the most concentrated waste stream, which comes from the final distillation
column (sometimes called the "nonvolatile residue"), will contain metals, residues from catalysts, and
volatile and nonvolatile organic compounds. Both the scrubbed gas stream and the nonvolatile residue
may be used as fuel in process heating units. If a caustic soda solution is used as a final purification
step for the KA, the spent caustic waste can be burned or sold as a recovered byproduct. Analyses of
gaseous effluent streams at 2 plants indicate that compounds containing cobalt and chromium, in
addition to normal products of combustion, are emitted when nonvolatile residue is burned. Caproic,
valeric, butyric, and succinic acids are emitted from tanks storing the nonvolatile residue.
Cyclohexanone, cyclohexanol, and hexanol are among the organic compounds emitted from the
cyclohexane recovery equipment (such as decanters and distillation columns.)
The nitric acid oxidation of the KA results in 2 main streams. The liquid effluent, which contains
primarily water, nitric acid, and adipic acid, contains significant quantities of NOx, which are
considered part of the process stream with recoverable economic value. These NOx are stripped from
the stream in a bleaching column using air. The gaseous effluent from oxidation contains NOx, C02,
CO, nitrous oxide (NzO), and DBAs. The gaseous effluent from both the bleacher and the oxidation
reactor typically is passed through an absorption tower to recover most of the NOx, but this process
does not significantly reduce the concentration of N20 in the stream. The absorber offgases and the
fumes from tanks storing solutions high in nitric acid content are controlled by extended absorption at
1 of the 3 plants utilizing cyclohexane oxidation, and by thermal reduction at the remaining 2.
Extended absorption is accomplished by simply increasing the volume of the absorber, by extending
the residence time of the NOx-laden gases with the absorbing water, and by providing sufficient
cooling to remove the heat released by the absorption process. Thermal reduction involves reacting
the NOx with excess fuel in a reducing atmosphere, which is less economical than extended
absorption.
Both scrubbers and bag filters are used commonly to control adipic acid dust particulate emissions
from product drying, cooling, storage, and loading operations. Nitric acid emissions occur from the
product blowers and from the centrifuges and/or filters used to recover adipic acid crystals from the
effluent stream leaving the second reactor. When chlorine is added to product cooling towers, all of
it can typically be assumed to be emitted to the atmosphere. If DBA are recovered from the nitric
acid solution and converted to dibasic esters (DBE) using methanol, methanol emissions will also
occur.
6.2-6
EMISSION FACTORS
10/96
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References For Section 6.2
1. Kirk-Othmer Encyclopedia Of Chemical Technology, "Adipic Acid", Vol. 1, 4th Ed.,
New York, Interscience Encyclopedia, Inc., 1991.
2. 1990 Directory Of Chemical Producers: United States, SRI International, Menlo Park, CA.
3. Alternative Control Techniques Document — Nitric And Adipic Acid Manufacturing Plants,
EPA-450/3-91-026, U. S. Environmental Protection Agency, Research Triangle Park, NC,
December 1991.
4. Confidential written communication from J. M. Rung, E. I. duPont de Nemours & Co., Inc.,
Victoria, TX, to D. Beauregard, U. S. Environmental Protection Agency, Research Triangle
Park, NC, 30 April 1992.
5. Handbook: Control Technologies For Hazardous Air Pollutants, EPA-625/6-91-014,
U. S. Environmental Protection Agency, Cincinnati, OH, June 1991.
6. Confidential written communication letter from C. D. Cary, Allied-Signal Inc., Hopewell,
VA, to D. Beauregard, U. S. Environmental Protection Agency, Research Triangle Park, NC,
9 March 1992.
7. M. H. Thiemens and W. C. Trogler, "Nylon Production: An Unknown Source of
Atmospheric Nitrous Oxide", Science 257:932-934. 1991.
10/96
Organic Chemical Process Industry
6.2-7
-------
9.7 Cotton Ginning
9,7.1 General1"8
Cotton ginning takes place throughout the area of the United States known as the Sunbelt.
Four main production regions can be designated:
• Southeast—Virginia, North Carolina, South Carolina, Georgia, Alabama, and Florida
• Mid-South—Missouri, Tennessee, Mississippi, Arkansas, and Louisiana
• Southwest—Texas and Oklahoma
• West—New Mexico, Arizona, and California
The majority of the ginning facilities are located in Texas, Mississippi, Arkansas, California, and
Louisiana.
The industry trend is toward fewer gins with higher processing capacity. In 1979,
2,332 active gins in the United States produced 14,161,000 bales of cotton. By the 1994/1995
season, the number of cotton gins in the United States dropped to 1,306, but about 19,122,000 bales
were produced. The average volume processed per gin in 1994/1995 was 14,642 bales.
Cotton ginning is seasonal. It begins with the maturing of the cotton crop, which varies by
region, and ends when the crop is finished. Each year the cotton ginning season starts in the lower
Southwest region in midsummer, continues through the south central and other geographical regions
in late summer and early autumn, and ends in the upper Southwest region in late autumn and early
winter. Overall, U. S. cotton is ginned between October 1 and December 31, with the bulk of the
crop from each geographical region being ginned in 6 to 8 weeks. During the remainder of the year,
the gin is idle.
All U. S. cotton in commercial production is now harvested by machines of two types,
picking and stripping. Machine-picked cotton accounts normally for 70 to 80 percent of the total
cotton harvested, while the rest is machine stripped. Machine picking differs from machine stripping
mainly in the method by which the cotton lint and seed are removed from the plant. Machine picking
is done by a spindle picker machine that selectively separates the exposed seed cotton from the open
capsules, or bolls. In contrast, the mechanical stripper removes the entire capsule, with lint plus
bract, leaf, and stem components iit the harvested material.
Strippers collect up to six times more leaves, burs, sticks, and trash than the spindle picker
machines. This higher ratio of trash to lint requires additional equipment for cleaning and trash
extraction. Stripper-harvested cotton may produce 1,000 pounds of trash per 500-pound bale of lint,
compared to 150 pounds of trash per 500-pound bale from spindle picking.
The modular system of seed cotton storage and handling has been rapidly adopted. This
system stores seed cotton in the field after harvesting until the gin is ready to process it. Modules can
also be transported longer distances, allowing gins to increase productivity. In 1994, 78 percent of
the U.S. crop was handled in modules.
6/96
Food And Agricultural Industry
9.7-1
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9.7.2 Process Description"7
Figure 9.7-1 is a flow diagram of a typical cotton-ginning process. Each of the five ginning
steps and associated equipment is described below.
9.7.2.1 Unloading System -
Module trucks and trailers transport cotton from the field to the gin, A pneumatic system
removes the cotton from the trailers, and either a pneumatic system or a module feeder removes the
cotton from modules. A combination conveyer and pneumatic system conveys the cotton to a
separator and feed control unit. Prior to this first separator point, some gins use a stone and green
boll trap for preliminary trash removal. The screen assembly in the separator allows air to escape but
collects the cotton and allows it to fall into the feed control unit. The conveying air flows from the
separator to a cyclone system, where it is cleaned and discharged to the atmosphere.
9.7.2.2 Seed Cotton Cleaning System -
Cotton is subjected to three basic conditioning processes-drying, cleaning, and
extracting-before it is processed for separation of lint and seed. To ensure adequate conditioning,
cotton gins typically use two conditioning systems (drying, cleaning, and extracting) in series.
Seed cotton dryers are designed to reduce lint cotton moisture content to 5 to 8 percent to
facilitate cleaning and fiber/seed separation. A high-pressure fan conveys seed cotton through the
drying system to the first seed cotton cleaner, which loosens the cotton and removes fine particles of
foreign matter (e. g., leaf trash, sand, and dirt). In the second cleaner, large pieces (e. g., sticks,
stems, and burs) are removed from the cotton by a different process, referred to as "extracting".
Different types of extractors may be used, including bur machines, stick machines, stick and bur
machines, stick and green leaf extractors, and extractor/feeders. These machines remove burs, sticks,
stems, and large leaves, pneumatically conveying them to the trash storage area. The cotton is
pneumatically conveyed to the next processing step. Typically, all conveying air is cleaned by a
cyclone before being released to the atmosphere.
9.7.2.3 Overflow System -
After cleaning, the cotton enters a screw conveyor distributor, which apportions the cotton to
the extractor/feeders at a controlled rate. The extractor/feeders drop the cotton into the gin stands at
the recommended processing rates. If the flow of cotton exceeds the limit of the extractor/feeder
systems, the excess cotton flows into the overflow hopper. A pneumatic system (overflow separator)
then returns this cotton back to the screw conveyor distributor, as required. Typically, the air from
this system is routed through a cyclone and cleaned before being exhausted to the atmosphere,
9.7.2.4 Ginning and Lint Handling System -
Cotton enters the gin stand through a "huller front", which performs some cleaning. Saws
grasp the locks of cotton and draw them through a widely spaced set of "huller ribs" that strip off
hulls and sticks. (New gin stands do not have huller ribs.) The cotton locks are then drawn into the
roll box, where fibers are separated from the seeds. After all the fibers are removed, the seeds slide
down the face of the ginning ribs and fall to the bottom of the gin stand for subsequent removal to
storage. Cotton lint is removed from the saws by a rotating brush, or a blast of air, and is conveyed
pneumatically to the lint cleaning system for final cleaning and combing. The lint cotton is removed
from the conveying airstream by a condenser that forms the lint into a batt. The lint batt is fed into
the first lint cleaner, where saws comb the lint cotton again and remove part of the remaining leaf
particles, grass, and motes. Most condensers are covered with fine mesh wire or fine perforated
metal, which acts to filter short lint fibers and some dust from the conveying air.
9.7-2
EMISSION FACTORS
6/96
-------
EMISSIONS
(3-02-004-01)
EMISSIONS
(3-02-004-20)
EMISSIONS
(3-02-004-21)
EMISSIONS
(3-02-004-25)
EMISSIONS
(3-02-004-07)
EMISSIONS
(3-02-004-35)
EMISSIONS
(3-02-004-36)
MOTE TRASH
FAN
MOTE
CLEANER
BALED MOTES
ii::
CYCLONE
ROBBER
SYSTEM
» SOLID WASTE
EMISSIONS
(3-02-004-30)
MOTE FAN
OVERFLOW
SYSTEM
COTTON
SEED
STORAGE
MASTER
TRASH FAN
COTTON
CLEANING
SYSTEM
LINT
COTTON
SYSTEM
NO. 1 LINT
CLEANER'
GIN STANDS
DISTRIBUTOR
NO. 2 LINT
CLEANER*
BALE STORAGE
STICK
MACHINE
NO. 1 DRYER AND
CLEANER
EXTRACTOR/
FEEDER
UNLOADING
SYSTEM
BATTERY
CONDENSER AND
BALING SYSTEM*
NO 2 DRYER AND
CLEANER
(NO, 3 DRYER AND
CLEANER
OPTIONAL)
OPTIONAL PROCESS
TRASH
EXHAUSTSTREAM
PRODUCT STREAM
LOW PRESSURE SIDE
COMPONENTS
Figure 9.7-1. Flow diagram of cotton ginning process.
(Source Classification Codes in parentheses.)
6/96
Food And Agricultural Industry
9.7-3
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9.7.2.5 Battery Condenser And Baling System -
Lint cotton is pneumatically transported from the lint cleaning system to a battery condenser,
which is a drum covered with fine mesh screen or fine perforated metal that separates the lint cotton
from the conveying air. The lint cotton is formed into batts and fed into a baling press, which
compresses the cotton into uniform bales.
Most gins use a double-press box for packaging the cotton into bales. The lint drops into one
press box and fills it while a bale is being pressed and strapped in the other box. Approximately
480 lb (217 kilograms [kg]) of cotton is pressed into a bale before it is wrapped with a cover and
strapped. Modern gins are presently equipped with higher-tonnage bale presses that produce the more
compact universal density cotton bales. In 1995, 96 percent of the U.S. crop was pressed into
universal density bales at the gins. The finished cotton bale is transported to the textile mill for
processing into yarn. Motes are sometimes cleaned and baled also.
9.7.3 Emissions And Controls1"24
Particulate matter (PM) is the primary air pollutant emitted from cotton ginning. Available
data indicate that about 37 percent of the total PM emitted (following control systems) from cotton
ginning is PM less than or equal to 10 microns in aerodynamic diameter (PM-10). The PM is
composed of fly lint, dust, fine leaves, and other trash. Figure 9.7-1 shows the typical PM emission
points in the ginning process. Particulate matter emissions are typically greater at gins processing
stripper-harvested cotton than at gins processing picker-harvested cotton. Also, PM emissions from
the first cotton harvest at a given facility are typically lower than emissions from subsequent harvests.
Control devices used to control PM emissions from cotton ginning operations include
cyclones, fine screen coverings, and perforated metal drums. Cyclones may be used to control the
sources with high pressure exhaust or all of the operations at a gin. Two types of cyclones that are
used are 2D-2D and 1D-3D cyclones. Both the body and the cone of a 2D-2D cyclone are twice as
long as the cyclone diameter. The body of a 1D-3D cyclone is the same length as the diameter, and
the cone length is three times the diameter. In many cases, 1D-3D cyclones display slightly higher
PM control efficiencies than 2D-2D cyclones.
Screen coverings and perforated drums may be used to control PM emissions from sources
with low-pressure exhaust, including the battery condenser and lint cleaners.
Table 9.7-1 presents PM and PM-10 emission factors for cotton gins controlled primarily by
1D-3D or 2D-2D cyclones. Emission factors for lint cleaners and battery condensers with screened
drums or cages are also presented. Emission factors for total gin emissions are shown for two
different gin configurations. The emission factors for "Total No.l" represent total PM and PM-10
emissions from gins with all exhaust streams controlled by high-efficiency cyclones. The emission
factors for "Total No. 2" represent total PM and PM-10 emissions from gins with screened drums or
cages controlling the lint cleaner and battery condenser exhausts and high-efficiency cyclones
controlling all other exhaust streams. The emission factors for the No. 3 dryer and cleaner, cyclone
robber system, and mote trash fan are not included in either total because these processes are not used
at most cotton gins. However, these factors should be added into the total for a particular gin if these
processes are used at that gin.
9.7-4
EMISSION FACTORS
6/96
-------
Table 9.7-1. EMISSION FACTORS FOR COTTON GINS
CONTROLLED WITH HIGH-EFFICIENCY CYCLONES"
EMISSION
EMISSION
Total PM,
FACTOR
PM-10,
FACTOR
Source
lb/bale
RATING
lb/bale
RATING
Unloading fan (SCC 3-02-004-01)
0.29b
D
0.12C
D
No. 1 dryer and cleaner (SCC 3-02-004-20)
0.36d
D
0.12e
D
No. 2 dryer and cleaner (SCC 3-02-004-21)
0.24f
D
0.093s
D
No. 3 dryer and cleaner1" (SCC 3-02-004-22)
0.095
D
0.033
D
Overflow fan* (SCC 3-02-004-25)
0.071
D
0.026
D
Lint cleaners (SCC 3-02-004-07)
with high-efficiency cyclones'5
0.58
D
0.24
D
with screened drums or cages™
1.1
E
ND
NA
Cyclone robber system0 (SCC 3-02-004-30)
0.18
D
0.052
D
Mote fan (SCC 3-02-004-35)
0.28p
D
0.13"
D
Mote trash fanr (SCC 3-02-004-36)
0.077
D
0.021
D
Battery condenser (SCC 3-02-004-08)
with high-efficiency cyclones*
0.039
D
0.014
D
with screened drums or cages™
0.17
E
ND
NA
Master trash fan (SCC 3-02-004-03)
0.54'
D
0.074"
D
Cotton gin total No. P (SCC 3-02-004-10)
2.4
D
0.82
D
Cotton gin total No. 2W (SCC 3-02-004-10)
3.1
E
1.2
E
" Emission factor units are lb of pollutant per bale of cotton processed. Emissions are controlled
by 1D-3D or 2D-2D high-efficiency cyclones unless noted. SCC = source classification code.
ND = no data available. To convert from lb/bale to kg/bale, multiply by 0.45.
h References 13-15,17,19-20,22,24.
c References 13-14,17,22,24.
d References 12-14,17,19,21.
e References 12-14,17,21.
f References 9,12,14,17,19,24.
8 References 9,12,14,17,24.
h References 10,16. Most gins do not include this source, and these emission factors are not
included in the total gin emission factors shown. However, these factors should be added into
the total for a particular gin if this source is part of that gin.
1 References 10,14,17,24.
k References 13-14,17,21-23. Emission factors are included in Total No. 1, but are not included
in Total No. 2.
References 18-20. Emission factors are not included in Total No. 1, but are included in Total
No. 2.
n Reference 22. Most gins do not include this source, and these emission factors are not included
in the total gin emission factors shown. However, these factors should be added into the total for
a particular gin if this source is part of that gin.
p References 11-14,17,19-20,23-24.
q References 11-14,17,24.
r References 10-11,22. Many gins do not include this source, and these emission factors are not
included in the total gin emission factors shown. However, these factors should be added into
the total for a particular gin if these sources are part of that gin.
References 14,16-17,23-24. Emission factors are included in Total No. 1, but are not included
in Total No. 2.
' References 15,19,22.
6/96
Food And Agricultural Industry
9.7-5
-------
Table 9.7-1 (cont.).
u References 15,22.
Total for gins with high-efficiency cyclones on all exhaust streams. Does not include emission
factors for the No. 3 dryer and cleaner, cyclone robber system, mote trash fan, lint cleaners with
screened drums or cages, and battery condenser with screened drums or cages,
w Total for gins with screened drums or cages on the lint cleaners and battery condenser and high-
efficiency cyclones on all other exhaust streams. Does not include emission factors for the No. 3
dryer and cleaner, cyclone robber system, mote trash fan, lint cleaners with high-efficiency
cyclones, and battery condenser with high-efficiency cyclones. PM-10 emissions from lint
cleaners and battery condensers with screened drums or cages are estimated as 50 percent of the
total PM emissions from these sources.
9.7.4 Summary of Terminology
Bale — A compressed and bound package of cotton lint, typically weighing about 480 lb.
Batt — Matted lint cotton.
Boll — The capsule or pod of the cotton plant.
Bur (or burr) — The rough casing of the boll. Often referred to as hulls after separation from
the cotton.
Condenser — A perforated or screened drum device designed to collect lint cotton from the
conveying airstream, at times into a batt.
Cotton — General term used variously to refer to the cotton plant (genus Gossypium);
agricultural crop; harvest product; white fibers (lint) ginned (separated) from the seed; baled produce;
and yarn or fabric products. Cotton is classified as upland or extra long staple depending on fiber
length.
Cottonseed — The seed of the cotton plant, separated from its fibers. The seeds constitute
40 percent to 55 percent of the seed cotton (depending on the amount of trash) and are processed into
oil meal, 1 inters, and hulls, or are fed directly to cattle.
Cvclone — A centrifugal air pollution control device for separating solid particles from an
airstream.
Cyclone robber system - A secondary cyclone trash handling system. These systems are not
used at most cotton gins.
Cylinder cleaner — A machine with rotating spiked drums that open the locks and clean the
cotton by removing dirt and small trash.
Extractor — Equipment for removing large trash pieces (sticks, stems, burs, and leaves). The
equipment may include one or more devices, including a stick machine, bur machine, green-leaf
machine, and a combination machine.
Extractor-feeder — A device that gives seed cotton a final light extraction/cleaning and then
feeds it at a controlled rate to the gin stand.
Fly lint (or lint fly) — Short (less than 50 ^m) cotton fibers, usually emitted from condensers
and mote fan.
9.7-6
EMISSION FACTORS
6/96
-------
Gin stand — The heart of the ginning plant where gin saws (usually several in parallel)
separate the cotton lint from the seeds.
High pressure side — The portion of the process preceding the gin stand (including unloading,
drying, extracting, cleaning, and overflow handling systems) in which material is conveyed by a
higher pressure air, and exhausts are typically controlled by cyclones.
Lint cleaner — A machine for removing foreign material from lint cotton.
Lint cotton — Cotton fibers from which the trash and seeds have been removed by the gin.
Low pressure side — The portion of the process following the gin stand (including lint cotton
cleaning and batt formation process) in which material is conveyed by low pressure air, and exhausts
are typically controlled by condensers.
Mote — A small group of short fibers attached to a piece of the seed or to an immature seed.
Motes may be cleaned and baled.
Picker harvester — A machine that removes cotton lint and seeds from open bolls with
rotating spindles, leaving unopened bolls on the plant. "First pick" cotton is obtained from the initial
harvest of the season. It usually contains less trash than "second pick" cotton, obtained later in the
harvest season. "Ground cotton" is obtained by picking up between the rows at season's end and has
a high trash content.
Seed cotton — Raw cotton, containing lint, seed, and some waste material, as it comes from
the field.
Separator — A mechanical device (e.g., wire screen with rotary rake) that separates seed
cotton from conveying air.
Stripper harvester — A machine that strips all bolls — opened (mature) and unopened
(immature or green) — from the plant; strippers are used on short cotton plants, grown in arid areas
of Texas, Oklahoma, and New Mexico. They collect larger amounts of trash (leaves, stems, and
sticks) than picker harvesters.
References For Section 9.7
1. Airborne Particulate Emissions From Cotton Ginning Operations, A60-5, U. S. Department
Of Health, Education And Welfare, Cincinnati, OH, 1960.
2. Source Assessment: Cotton Gins, EPA-600/2-78-004a, II. S. Environmental Protection
Agency, Cincinnati, OH, January 1978.
3. A. C. Griffin And E. P. Columbus, Dust In Cotton Gins: An Overview, U. S. Cotton
Ginning Laboratory, Stoneville, MS, 1982.
4. W. J. Roddy, "Controlling Cotton Gin Emissions", Journal Of The Air Pollution Control
Association, 28(6):637, June 1978.
5. Written Communication From Phillip J. Wakelyn And Fred Johnson, National Cotton Council
Of America, Washington, DC, To David Reisdorph, Midwest Research Institute, Kansas
City, MO, December 30, 1992.
6. Cotton Ginners Handbook, Agricultural Handbook No. 503, Agricultural Research Service,
U. S. Department Of Agriculture, 1977, U.S. Government Printing Office, Stock
No. 001-000-03678-5.
6/96
Food And Agricultural Industry
9.7-7
-------
7. Written Communication From Fred Johnson And Phillip J. Wakelyn, National Cotton Council
Of America, Memphis, TN, To Dallas Safriet, U. S. Environmental Protection Agency,
Research Triangle Park, NC, October 31, 1995.
8. Emission Factor Documentation, AP-42 Section 9.7, Cotton Ginning, EPA Contract
No, 68-D2-0159, Midwest Research Institute, Cary, NC, June 1996.
9. Westfield Gin-PMIO & Total Particulate Testing-Main Trash Stock Filer Cyclone, #2 Incline
Cyclone, Gin Feed Trash Cyclone, BTC Environmental, Inc., Ventura, CA, November 14-15,
1991.
10. Airways Gin-PMIO & Total Particulate Testing-Motes Trash Cyclone, #5 Incline Cyclone,
Overflow Separator Cyclone, BTC Environmental, Inc., Ventura, CA, November 21-22,
1991.
11. Source Emission Testing-Mount Whitney Cotton Gin, BTC Environmental, Inc., Ventura.
CA, November 29-30, 1990.
12. Source Emission Testing-Stratford Growers, BTC Environmental, Inc., Ventura, CA,
November 27-28, 1990.
13. Source Emission Testing-County Line Gin, BTC Environmental, Inc., Ventura, CA,
December 3-4, 1990.
14. County Line Gin-PMIO & Total Particulate Testing-Motes, Suction, Lint Cleaner, Overflow,
til Drying, Gin Stand Trash, Battery Condenser, And #2 Drying Cyclones, BTC
Environmental, Inc., Ventura, CA, December 8-11, 1991.
15. Westfield Gin-PMIO & Total Particulate Testing-Trash Cyclone, BTC Environmental, Inc.,
Ventura, CA, November 12, 1992.
16. West Valley Cotton Growers-PMIO & Total Particulate Testing-Battery Condenser And It3
Dryer/Cleaner Cyclones, BTC Environmental, Inc., Ventura, CA, October 28, 1993.
17. Dos Palos Cooperative-PMIO <& Total Particulate Testing-Motes, Suction, Lint Cleaner,
Overflow, til Drying, Battery Condenser, And #2 Drying Cyclones, BTC Environmental, Inc.,
Ventura, CA, November 27-29, 1992.
18. Halls Gin Company-Particulate Emissions From Cotton Gin Exhausts, State Of Tennessee
Department Of Health And Environment Division Of Air Pollution Control, Nashville, TN,
October 25-27, 1988.
19. Cotton Gin Emission Tests, Marana Gin, Producers Cotton Oil Company, Marana, Arizona,
EPA-330/2-78-008, National Enforcement Investigations Center, Denver, CO, And
EPA Region IX, San Francisco, CA, May 1978.
20. Emission Test Report, West side Farmers' Cooperative Gin #5, Tranquility, California,
Prepared For U. S. Environmental Protection Agency Division Of Stationary Source
Enforcement, Washington, D.C., PEDCo Environmental, Inc., Cincinnati, OH,
February 1978.
21. Elbow Enterprises-PM-10 And Total Particulate Testing, Lint Cleaner And Dryer til
Cyclones, AIRx Testing, Ventura, CA, November 7-8, 1994.
9.7-8
EMISSION FACTORS
6/96
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22. Stratford Growers, Inc.-PM-lO And Total Particulate Testing, Unloading, Hull Trash, Feeder
Trash, Lint Cleaner, Cyclone Robber System, & Motes Trash Cyclones, AIRx Testing,
Ventura, CA, October 26-28, 1994,
23. Alia Vista Gin-PM-10 And Total Particulate Testing, Battery Condenser, Lint Cleaner, &
Motes Trash Cyclones, AIRx Testing, Ventura, CA, November 3-4, 1994.
24. Dos Palos Coop Gin--PM-10 And Total Particulate Testing, Unloading, Dryer #2, Overflow,
Battery Condenser, & Motes Cyclones, AIRx Testing, Ventura, CA, October 31 Through
November 2, 1994.
6/96
Food And Agricultural Industry
9.7-9
-------
9.9.4 Alfalfa Dehydrating
9.9.4.1 General1 ~2
Dehydrated alfalfa is a meal product resulting from the rapid drying of alfalfa by artificial
means. Alfalfa meal is processed into pellets for use in chicken rations, cattle feed, hog rations, sheep
feed, turkey mash, and other formula feeds. It is important for its protein content, growth and
reproductive factors, pigmenting xanthophylls, and vitamin contributions.
9.9.4.2 Process Description'5
A schematic of a generalized alfalfa dehydrator plant is given in Figure 9.9.4-1. Standing
alfalfa is windrowed in the field lo allow wilting to reduce moisture to an acceptable level balancing
energy requirements, trucking requirements, and dehydrator capacity while maintaining the alfalfa
quality and leaf quantity. The windrowed alfalfa is then chopped and hauled to the dehydration plant.
The truck dumps the chopped alfalfa (wet chops) onto a self-feeder, which carries it into a direct-fired
rotary drum. Within the drum, the wet chops are dried from an initial moisture content of about 30 to
70 percent (by weight, wet basis) to about 6 to 12 percent. Typical combustion gas temperatures
within the gas-fired drum range from 154" to 816°C (300° to 1500°F) at the inlet to 60° to 95°C (140°
to 210°F) at the outlet.
From the drying drum, the dry chops are pneumatically conveyed into a primary cyclone that
separates them from the high-moisture, high-temperature exhaust stream. From the primary cyclone,
the chops arc fed into a hammermill, which grinds the dry chops into a meal. The meal is
pneumatically conveyed from the hammermill into a meal collector cyclone in which the meal is
separated from the airstream and discharged into a holding bin. The exhaust is recycled to a bag filter
(baghouse). The meal is then fed into a pellet mill where it is steam conditioned and extruded into
pellets.
From the pellet mill, the pellets arc cither pneumatically or mechanically conveyed to a cooler,
through which air is drawn to cool the pellets and, in some cases, remove lines. Fines are more
commonly removed using shaker screens located ahead of or following the cooler, with the fines being
conveyed back into the meal collector cyclone, meal bin, or pellet mill. Cyclone separators may be
employed to separate entrained fines in the cooler exhaust and to collect pellets when the pellets are
pneumatically conveyed from the pellet mill to the cooler.
Following cooling and screening, the pellets arc transferred to bulk storage. Dehydrated alfalfa
is most often stored and shipped in pellet form, although the pellets may also be ground in a
hammermill and shipped in meal form. When the finished or ground pellets are pneumatically or
mechanically transferred to storage or loadout, additional cyclones may be used for product airstream
separation.
9.9.4.3 Emissions And Controls1"3,5"7
Particulate matter (PM) is the primary pollutant emitted from alfalfa dehydrating plants,
although some odors may arise from the organic volatiles driven off during drying and pellet
formation. The major source of PM emissions is the primary cyclone following the dryer drum.
9/96
Food And Agricultural Industry
9.9.4-i
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V)
\g
vO
o
PARTICULATE
(3-02-001-04)
PARTICULATE
(3-02-001-03)
PELLET
COOLER
CYCLONE
BAG
FILTER
VOC,
PARTICULATE
(3-02-001-07)
VOC,
PARTICULATE
MEAL
COLLECTOR
PRIMARY
PELLET
COLLECTOR
(3-02-001-11,
3-02-001-12,
3-02-001-15,
3-02-001-17)
LEVELING DRUM
PRIMARY
+*-CYCLONE
MEAL BIN
SCREW I
CONVEYOR 1 1
DRYER
PELLET
Mia
DRUM
PARTICULATE
AIR (3-02-001-20)
SLIDE
SCALE
GRINDER
PRIMARY
BLOWER
STEAM
AIR
BLOWER
STORAGE
BIN
CYCLONE
PNEUMATIC
CONVEYING
FRESH-CUT ALFALFA
(WET CHOPS)
FROM^IEL^
COOLING
FAN
TRUCK OUMP
AND LIFT
FUEL INLET
Figure 9.9.4-1. Generalized flow diagram for an alfalfa dehydration plant.
(Source Classification Code in parentheses.)
STORAGE-
LOADOUT
-------
Lesser emission sources include the downstream cyclone separators and the bagging and loading
operations.
Emission factors for various dryer types utilized in alfalfa dehydrating plants are given in
Table 9.9,4-1, Note that, although these sources are common to many plants, there will be
considerable variation from the generalized flow diagram in Figure 9.9.4-1 depending on the desired
nature of the product, the physical layout of the plant, and the modifications made for air pollution
control.
Table 9,9.4-1. EMISSION FACTORS FOR ALFALFA DEHYDRATION3
EMISSION FACTOR RATING: D
Source
Particulate (PM)
VOC
Ref.
Filterable
Condensible
Triple-pass dryer cyclone
- Gas-fired
4,8
1.0
ND
8-9
(SCC 3-02-001-11)
- Coal-firedh
7,5
ND
ND
13
(SCC 3-02-001-12)
Single-pass dryer cyclone
- Gas-fired
4.1
0.65
ND
10-11
(SCC 3-02-001-15)
- Wood-fired
3.1
1.3
ND
12,14
(SCC 3-02-001-17)
Meal collector cyclone
ND
ND
NA
(SCC 3-02-001-03)
- Bag filter
Pellet collector cyclone
ND
ND
ND
(SCC 3-02-001-07)
Pellet cooler cyclone
ND
ND
NA
(SCC 3-02-001-04)
Storage bin cyclone
ND
ND
NA
(SCC 3-02-001-20)
a Emission factor units are lb/ton of finished pellet produced, unless noted. To convert from
lb/ton to kg/Mg, multiply by 0,5. SCC = Source Classification Code. ND = No data.
NA = Not applicable.
Emission factor based on quantity of dried alfalfa to hammermill.
Air pollution control (and product recovery) is accomplished in alfalfa dehydrating plants in a
variety of ways. A simple, yet effective technique is the proper maintenance and operation of the
alfalfa dehydrating equipment. Particulate emissions can be reduced significantly if the feeder
discharge rates are uniform, if the dryer furnace is operated properly, if proper airflows are employed
in the cyclone collectors, and if the hammermill is well maintained and not overloaded. It is
especially important in this regard not to overdry and possibly burn the chops as this results in the
generation of smoke and increased fines in the grinding and pelletizing operations.
Equipment modification provides another means of particulate control. Existing cyclones can
be replaced with more efficient cyclones and concomitant air flow systems. In addition, the furnace
and burners can be modified or replaced to minimize flame impingement on the incoming green chops.
9/96
Food And Agricultural Industry
9.9.4-3
-------
In plants where the hammermiil is a production bottleneck, a tendency exists to overdry the chops to
increase throughput, which results in increased emissions. Adequate hammermiil capacity can reduce
this practice. Recent improvements in process technique and emission control technology have
reduced particulate emissions from dehydration facilities. Future technology should contribute to
further reductions in particulate emissions.
Secondary control devices can be employed on the cyclone collector exhaust streams.
Generally, this practice has been limited to the installation of secondary cyclones or fabric filters on
the meal collector, pellet collector or pellet cooler cyclones. Primary cyclones are not controlled by
fabric filters because of the high moisture content in the resulting exhaust stream. Medium energy wet
scrubbers are effective in reducing particulate emissions from the primary cyclones, but have only
been installed at a few plants.
Some plants employ cyclone effluent recycle systems for particulate control. One system
skims off the particulate-laden portion of the primary cyclone exhaust and returns it to the alfalfa
dryer. Another system recycles a large portion of the meal collector cyclone exhaust back to the
hammermiil. Both systems can be effective in controlling particulates but may result in operating
problems, such as condensation in the recycle lines and plugging or overheating of the hammermiil.
References For Section 9.9.4
1. Air Pollution From Alfalfa Dehydrating Mills, Technical Report A 60-4, Robert A. Taft
Sanitary Engineering Center, U.S.P.H.S., Department Of Health, Education, And Welfare,
Cincinnati, OH.
2. Schafer, R.D., "How Ohio Is Solving The Alfalfa Dust Problem", AM.A. Archives Of
Industrial Health, 17:67-69, January 1958.
3. Source information supplied by Ken Smith of the American Dehydrators Association, Mission,
KS, December 1975.
4. Written correspondence from W. Cobb, American Alfalfa Processors Association, to
T. Campbell, Midwest Research Institute, Updated alfalfa dehydration process diagram,
May 18, 1995.
5. Telephone conversation with D. Burkholder, Shofstall Alfalfa, and T. Lapp and T. Campbell,
Midwest Research Institute, Clarification of alfalfa dehydration process, June 13, 1995.
6. Emission Factor Development For The Feed And Grain Industry, EPA-450/3-75-054, U. S.
Environmental Protection Agency, Research Triangle Park, NC, October 1974.
7. Particulate Emissions From Alfalfa Dehydrating Plants - Control Costs And Effectiveness,
EPA 650/2-74-007, U. S, Environmental Protection Agency, Research Triangle Park, NC,
January 1974.
8. Source Emissions Report For Gothenburg Feed Products Co., Gothenburg, NE, AirSource
Technologies, Lenexa, KS, October 8, 1993.
9. Source Emissions Report For Shofstall Alfalfa, Alfalfa Dehydrating Facility, Odessa, NE,
AirSource Technologies, Lenexa, KS, October 15, 1993.
9.9.4-4
EMISSION FACTORS
9/96
-------
10. Source Emissions Report For Morrison & Quirk, Inc., Alfalfa Dehydrating Facility, Lyons, NE,
AirSource Technologies, Lenexa, KS, October 15, 1993.
11. Source Emissions Report For Lexington Alfalfa Dehydrators, Inc., Alfalfa Dehydrating
Facility, Darr, NE, AirSource Technologies, Lenexa, KS, October 15, 1993.
12. Stack Particulate Samples Collected At Verhoff Alfalfa, Hoytville, OH, Affiliated
Environmental Services, Inc., Sandusky, OH, September 25, 1992.
13. Emission Test Report For Toledo Alfalfa, Oregon, OH, Owens-Illinois Analytical Services,
Toledo, OH, June 4, 1987.
14. Stack Particulate Samples Collected At Verhoff Alfalfa, Ottawa, OH, Affiliated Environmental
Services, Inc., Sandusky, OH, June 28, 1995.
9/96
Food And Agricultural Industry
9.9.4-5
-------
9.12.1 Malt Beverages
9.12,1.1 Process Description1"4
The production of malt beverages, or beer, comprises four main stages: brewhouse
operations, fermentation, aging or secondary fermentation, and packaging. Figures 9.12.1-1,
9.12.1-2, 9.12,1-3, and 9.12.1-4 show the various stages of a typical brewing process, including
potential emission points.
Breweries typically purchase malted grain (malt) from malting operations. In the malting
process, grain is first soaked in water-filled steeping tanks for softening. After softening, the grain is
transferred to germination tanks, in which the grain germinates, typically over a 1-week period.
From the germination tanks, the grain enters a kiln, which halts germination by drying the grain. To
begin the brewing process, malt (usually barley malt) is transported by truck or rail to a brewery and
is conveyed to storage silos. The malt is then ground into malt flour by malt mills and transferred to
milled malt hoppers. Many small breweries purchase malt flour (malted and milled grain) from
facilities with malt mills. Malt provides the starch-splitting and protein-splitting enzymes that are
necessary to convert grain starches into fermentable sugars.
From the milled malt hoppers, the malt, along with hot water, is fed to the mash tun and
heated to convert grain starches to fermentable sugars. Some large facilities use high-temperature
mashing, which reduces the time required to convert the starches to sugars, but lowers the quantity of
fermentable sugars produced. Most breweries use one of the three principal mashing processes; these
are: double mashing, decoction, and infusion. Double mashing uses grains other than barley
(typically corn and rice) as starch adjuncts. Before being added to the mash tun, the adjunct grains
are broken down through cooking in a cereal cooker for about 1 hour at temperatures ranging from
40° to 10Q°C (104° to 212°F). Some plants do not use cereal cookers, but use additives such as
corn syrup that function as adjunct grains. The malt and adjuncts are then mixed and heated in the
mash tun. Decoction is a method of boiling portions of the mixture (mash) and adding the boiling
portions to the mash tun to raise the overall temperature to about 75°C (167°F). The infusion
process mixes the malt with hot water to maintain a uniform temperature (65° to 75°C [149° to
167°F]) until starch conversion is complete. Mixing, heating times, and temperatures vary among
breweries. The finished product of mashing is a grain slurry, called mash.
From the mash tun, the mash is pumped to a straining tank called a lauter tun, which
separates insoluble grain residues from the mash. The mash enters the lauter tun through a false
bottom where the insoluble grain residues are allowed to settle. The grain sediment acts as a filter for
the mash as it enters the tank. Various other filter agents, such as polypropylene fibers, are also
used. Some large breweries use strainmasters, which are a variation of lauter tuns. The spent grain
(brewers grain) from the lauter tun or strainmaster is conveyed to holding tanks, dried (by some
breweries), and sold as animal feed. Brewers grain dryers are typically fired with natural gas or fuel
oil. The product of the lauter tun is called wort.
The strained wort from the lauter tun is transferred to the brew kettle and is boiled, typically
for about 90 to 120 minutes. Boiling stops the starch-to-sugar conversion, sterilizes the wort,
precipitates hydrolyzed proteins, concentrates the wort by evaporating excess water, and facilitates
chemical changes that affect beer flavor. Hops are added to the wort during the boiling process.
Hops are high in iso-a acids, which impart the characteristic bitter flavor to beer. Some breweries
10/96
Food And Agricultural Industry
9.12,1-1
-------
yo
i—*¦
to
K>
M
VI
in
i—i
O
2
T!
>
9
o
w
Cfl
MALTING
FABRIC FILTER
FABRIC FILTER
GRAIN STORAGE
SILOS
GRAIN (BARLEY)
UNLOADING
MILLED MALT
HOPPER
(3-02-009-15)
MALT Mia
(3-02-009-06)
GRAIN HANDLING
(3-02-009-01)
TO BREWHOUSE
OPERATIONS
o
PM EMISSIONS
0
VOC EMISSIONS
©
ETHANOL EMISSIONS
©
OTHER GASEOUS EMISSIONS
—~
EXHAUST STREAM
PRODUCT OR BYPRODUCT
STREAM
OPTIONAL PROCESS
Figure 9.12.1-1. Typical brewery grain handling and malting operations.
(Source Classification Codes in parentheses.)
\o
as
-------
©
£
rci
>
S3
ex
>
g
B
*¦»
&
v©
to
WORT
WORTCOOLER
TO FERMENTERS
©
*
HOT WORT
SETTUNQTANK
{3-02-009-24)
TRUB
TRUB VESSEL
(3-02-009-26)
©
©
©
©
PM EMISSIONS
VOC EMISSIONS
ETHANOL EMISSIONS
OTHER GASEOUS EMISSIONS
EXHAUST STREAM
PRODUCT OR BYPRODUCT SYSTEM
OPTIONAL PROCESS
HOT WATER
©
GROUND
MALT
©@
4
BREW KETTLE
(3-02-009-07)
I
HOPS
WORT
i nn i cn . .
t
MASHTUN
(3-02-009-21)
CEREAL COOKER
(3-02-008-22)
0
1
LAUTCRTUN
OR STRAINMASTER
(WK-00&-23)
SPENT GRAIN
BREWERS GRAIN
HOLDING TANK
©@©
i
BREWERS GRAIN
DRYER
(3-02-009-30,31)
WET SCRUBBER OR j
OTHER CONTROL DEVICE I
Figure 9.12.1-2. Typical brewhouse operations.
(Source Classification Codes in parentheses.)
-------
0®
:;:i @®®
©©
YEAST PROPAGATION
(3-02-009-40)
YEAST
CO, RECOVERY
SYSTEM
CO2 PURIFICATION
SYSTEM (ACTIVATED CARBON
ADSORPTION OR WET
SCRUBBER)
COOLED
WORT .
ACTIVATED CARBON
REGENERATION
(3-02-009-39)
BRI
COg TO FILLING OPERATIONS
RECOVERED YEAST
©,©
BREWERS
YEAST
BEER
BEER
TO
" FILLING
OPERATIONS
FERMENTERS
(3-02-009-35,-37)
FILTER
OR
CENTRIFUGE
BREWERS YEAST
RECOVERY
(CENTRIFUGE)
BREWERS YEAST
DISPOSAL
OR REUSE
(3-02-009-41)
AGING TANKS
(SECONDARY
FERMENTATION)
(3-02-009-04)
0
PM EMISSIONS
©
VOC EMISSIONS
0
ETHANOL EMISSIONS
O
OTHER GASEOUS EMISSIONS
—~
EXHAUST STREAM
PRODUCT OR BYPRODUCT
STREAM
OPTIONAL PROCESS
Figure 9.12.1-3. Typical fermentation and post-fermentation brewery operations.
(Source Classification Codes in parentheses.)
-------
o
V0
0\
RETURNED
BOTTLES
I
©
i
BOTTLE SOAKER
AND CLEANER
(3-02-009-60)
BOTTLES
hrt
o
o
o.
>
a
o.
>
TO
*¦«_
§
s
l-l
E.
a
c
FROM BEER —fc.
STORAGE
TANKS
CAN FILLING, BOTTLE
FILLING, KEG FILLING
(3-02-000-51,-52,-53,-54,-55)
DAMAGED
AND PARTIALLY]
FILLED CANS
AND BOTTLES
©
PACKAGING
AND
SHIPPING
SPILLED
BEER
BEER SUMP
(3-02-009-63) [
CAN / BOTTLE
CRUSHING
(3-02-009-61)
CANS
CAN/BOTTLE
RECYCUNG
©
PM EMISSIONS
d>
VOC EMISSIONS
©
ETHANOL EMISSIONS
©
OTHER GASEOUS EMISSIONS
—~
EXHAUST STREAM
—~
PRODUCT OR BYPRODUCT SYSTEM
OPTIONAL PROCESS
t
WASTE BEER
STORAGE TANK
(3-02-009-65)
1
, ETHANOl
! REMOVALOR
RECOVERY
(3-02-009-66,-67)
DISCHARGE AS
PROCESS
WASTEWATER
PNEUMATIC CAN
! CONVEYOR
i (3-05-009-62)
M3
Figure 9.12.1-4. Typical filling room operations.
(Source Classification Codes in parentheses.)
o»
K>
-------
add only hop extracts (that contain the desired iso-a acids), and some breweries add hop extracts
during or after the fermentation process. After brewing, the hops are strained from the hot wort, and
the hot wort is pumped to a large settling tank, where it is held to allow the remaining insoluble
material (trub) to settle. The trub is transferred to the spent grain holding tanks. After settling, the
hot wort is pumped to a cooling system (typically a closed system), which cools the liquid to
temperatures ranging from about 7° to 12°C (44° to 54°F). Following cooling, yeast is added to the
cooled wort as it is pumped to the fermenters.
Fermentation takes place in large tanks (fermenters-typically with capacities >.1,000 barrels
for medium to large breweries) that can be either open or closed to the atmosphere. Most closed-tank
fermenters include C02 collection systems, which recover C02 for internal use and remove organic
impurities from the C02; water scrubbers and activated carbon adsorption systems are used to recover
impurities. These closed tank fermenters typically vent emissions to the atmosphere (for a specified
period of time) until the C02 is pure enough to collect. The scrubber water is commonly discharged
as process wastewater, and the activated carbon is typically recharged (regenerated) on-site (the
impurities are typically vented to the atmosphere).
Fermentation is a biological process in which yeast converts sugars into ethyl alcohol
(ethanol), carbon dioxide (C02), and water. Yeasts can ferment at either the bottom or the top of the
fermenter. Saccharomyces carlsbergensis are common bottom-fermenting yeasts used to produce
lager beers. Bottom-fermenting yeasts initially rise to the top of the fermenter, but then flocculate to
the bottom during rapid fermentation. When fermentation moderates, the beer is run off the top of
the fermenter, leaving the bottom-fermenting yeasts at the bottom of the tank. Saccharomyces
cerevisiae are top-fermenting yeasts commonly used to produce ales, porters, and stout beers. Top-
fermenting yeasts rise to the top of the fermenter during rapid fermentation and are skimmed or
centrifuged off the top when fermentation moderates. The type of yeast used and the length of the
fermentation process vary among breweries and types of beer. Most pilsner beers ferment at
temperatures varying from 6° to 20°C (43° to 68°F).
After primary fermentation, waste yeast is typically removed from the liquid (by centrifuges
or other means), and the liquid proceeds to a secondary fermentation or aging process. The liquid is
pumped to aging tanks, a small quantity of freshly fermenting wort is added (at some breweries), and
the mixture is stored at low temperatures (below about 5°C [41 °F]).
Several methods are used for the disposal of yeast, including; recovery of viable yeast for
reuse in the fermentation process, sale to animal feed processors, distillation to recover residual
ethanol, and disposal as process wastewater.
After the beer is aged, solids are typically removed by centrifugation or filtration with
diatomaceous earth filters, and the beer is pumped to final storage (beer storage tanks). From final
storage, the beer is pumped to the packaging (canning and bottling) facility.
Packaging facilities typically include several canning and bottling lines, as well as a keg filling
operation. Most facilities pasteurize beer after canning or bottling, although some facilities package
nonpasteurized products using sterile filling lines. Beer that spills during packaging is typically
collected by a drainage system, and can be processed to remove or recover ethanol before discharge
as process wastewater. Damaged and partially filled cans and bottles are typically collected, crushed,
and recycled. Beer from the damaged cans and bottles can be processed to remove or recover ethanol
before discharge as industrial sewage. The final steps in the process are labeling, packaging for
distribution, and shipping.
9.12.1-6
EMISSION FACTORS
10/96
-------
Microbreweries typically produce beer for on-site consumption, although some have limited
local keg distribution. The beer production process is similar to that of large breweries, although
several processes may be excluded or combined. Most microbreweries purchase bags of either malted
barley or malt flour for use in beer making. Malt flour requires no processing and is added directly
to the mash tun. The facilities that use malted barley typically have a small "cracker" that cracks the
grain prior to mashing. Brewhouse operations (mashing, brewers grain settling, brewing, and trub
settling) may be combined to decrease the number of tanks required. Fermentation tanks and storage
tanks are much smaller than large brewery tanks, with capacities as small as a few barrels. Many
microbrews are held in fermentation tanks for three to four weeks (far longer than most mass-
produced beers). Canning and bottling operations typically are not found in microbreweries.
9.12.1.2 Emissions And Controls1"4
Ethanol is the primary volatile organic compound (VOC) emitted from the production of malt
beverages. Aldehydes, ethyl acetate, other VOCs, C02, and particulate matter (PM) are also
generated and potentially emitted.
Potential VOC emission sources include mash tuns, cereal cookers, lauter tuns or
strainmasters, brew kettles, hot wort settling tanks, yeast storage and propagation (see AP-42
Section 9.13.4), fermenters, spent grain holding tanks, activated charcoal regeneration systems (at
breweries with C02 recovery), aging tanks (sometimes referred to as "ruh" storage tanks), other
storage tanks, and packaging operations. The operations that precede fermentation are sources of
various species of VOC. Post-fermentation operations emit primarily ethanol; however, small
quantities of ethyl acetate and various aldehydes may also be emitted from fermenters and post-
fermentation operations. Other VOC that are emitted from cooking processes (mash tuns, hot wort
tanks, and brew kettles) may include dimethyl sulfide, C5-aldehydes, and myrcene (a hop oil emitted
from brew kettles).
Fermenters are a source of ethanol, other VOC, and C02; large breweries typically recover
C02 for internal use. However, smaller breweries and microbreweries typically vent C02 to the
atmosphere.
Potential sources of PM emissions from breweries include grain malting, grain handling and
processing operations (see AP-42 Section 9.9.1), brewhouse operations, and spent-grain drying.
Emissions from microbreweries consist of the same pollutants as large brewery emissions.
No test data are available to quantify these emissions, but they are expected to be negligible based on
the amount of beer produced in these facilities. Emission control devices are not typically used by
microbreweries.
Process loss controls are used to reduce emissions from malt beverage production. Add-on
emission controls are used to recover C02 in the fermentation process and to control PM emissions
from grain handling and brewers grain drying. Large breweries typically use C02 recovery systems,
which can include water scrubbers or activated carbon beds to remove impurities from the C02. The
scrubber water is typically discharged as process wastewater, and organic impurities collected by the
activated carbon beds are typically released to the atmosphere.
Water scrubbers could potentially be used to control ethanol emissions. However, scrubber
efficiency is based, in part, on the pollutant concentration (200 to 300 parts per million by volume
[ppmv] is needed for minimal efficiency), and the ethanol concentrations in fermentation rooms are
10/96
Food And Agricultural Industry
9.12.1-7
-------
typically very low (about 100 ppmv). Incineration is also an inefficient control measure if pollutant
concentrations are low. Recovery of ethanol vapor by carbon adsorption or other methods is another
control alternative, although the cost of recovery may be high.
Grain handling and processing operations (unloading, conveying, milling, and storage) are
typically controlled by fabric filters. Many smaller breweries purchase malt flour, and do not have
milling operations.
Each brewery is unique, and source to source variations can significantly affect emissions.
These variations result from differences in the brewing process, the type and age of equipment used,
and total production. Brewery emissions are also affected by the unique recipes and time and
temperature differences during various stages of production.
Emission factors for malt beverage production operations are shown in Tables 9.12.1-1 and
9.12.1-2.
Table 9.12.1-1. EMISSION FACTORS FOR MALT BEVERAGES3
Filterable PM
Source/control
PM
EMISSION
FACTOR
RATING
PM-10
EMISSION
FACTOR
RATING
PM-2.5
EMISSION
FACTOR
RATING
Brew kettle*5
(SCC 3-02-009-07)
0.41
E
ND
ND
Brewers grain dryer
(SCC 3-02-009-30,-32)
26c
D
0.33d
D
0.091d
D
Brewers grain diyer with
wet scrubber
(SCC 3-02-009-30,-32)
0.42°
D
0.1 ld
D
0.060d
D
a Emission factor units are lb of pollutant per 1,000 bbl of beer packaged unless noted.
1 bbl = 31 U.S. gallons. ND = no data available. SCC = Source Classification Code.
b Reference 9.
c References 11,13,17. Emission factor units are lb of pollutant per ton of dried grain produced.
d Reference 11. Emission factor units are lb of pollutant per ton of dried grain produced.
9.12.1-8
EMISSION FACTORS
10/96
-------
Table 9.12.1-2. EMISSION FACTORS FOR MALT BEVERAGES4
EMISSION FACTOR RATING: E
Hydrogen
Process
CO
CO,
vocb
Sulfide
Activated carbon regeneration0
ND
ND
0.035
ND
(SCC 3-02-009-39)
Aging tank-fillingd
ND
26
0.57
ND
(SCC 3-02-009-08)
Bottle crushere
ND
ND
0.48
ND
(SCC 3-02-009-61)
Bottle crusher with water sprayse
ND
ND
0.13
ND
(SCC 3-02-009-61)
Bottle filling linef
ND
ND
17
ND
(SCC 3-02-009-53)
Bottle soaker and cleaner®
ND
ND
0.20
ND
(SCC 3-02-009-60)
Brew kettleh
ND
ND
0.64
ND
(SCC 3-02-009-07)
Brewers grain dryer-natural gas-fired
ND
840J
0.73k
ND
(SCC 3-02-009-30)
0.73k
Brewers grain dryer-steam-heated
0.22m
53m
ND
(SCC 3-02-009-32)
Can crusher with pneumatic conveyor"
ND
ND
0.088
ND
(SCC 3-02-009-62)
Can filling linef
ND
ND
14
ND
(SCC 3-02-009-51)
Cereal eookerp
ND
ND
0.0075
ND
(SCC 3-02-009-22)
Fermenter venting: closed fermenterq
ND
2,100
2.0
0.015
(SCC 3-02-009-35)
Hot wort settling tank1"
ND
ND
0.075
ND
(SCC 3-02-009-24)
Keg filling lines
ND
46
0.69
ND
(SCC 3-02-009-55)
Lauter turf
ND
ND
0.0055
ND
(SCC 3-02-009-23)
Mash turf
ND
ND
0.054
ND
(SCC 3-02-009-21)
Open wort cooler1"
ND
ND
0.022
ND
(SCC 3-02-009-25)
Sterilized bottle filling line
ND
4,300'
40"
ND
(SCC 3-02-009-54)
Sterilized can filling line
ND
l,900l
35u
ND
(SCC 3-02-009-52)
10/96
Food And Agricultural Industry
9.12.1-9
-------
Table 9.12.1-2 (cont.).
Process
CO
co7
vocb
Hydrogen
Sulfide
Trub vessel-filling1*
ND
ND
0.25
ND
(SCC 3-02-009-26)
Waste beer storage tanks
ND
ND
ND
ND
(SCC 3-02-009-65)
a Emission factor units are lb of pollutant per 1,000 bbl of beer packaged unless noted.
1 bbl = 31 U.S. gallons. ND = no data available. SCC = Source Classification Code.
b Total organic compounds measured using EPA Method 25A, unless noted otherwise.
Pre-fermentation factors are presented as VOC as propane; post-fermentation factors are presented
as VOC as ethanol because the emissions have been shown to be primarily ethanol.
0 Reference 19. From C02 recovery and purification system on a closed fermenter.
d Reference 6. VOC as ethanol. EMISSION FACTOR RATING: D.
e Reference 15. VOC as ethanol. Emission factor units are lb of pollutant per batch of bottles
crushed. Crusher averages about 34 crushes per day.
f Reference 20. Emission factor represents ethanol emissions measured using both EPA Method 18
and an FTIR analyzer. Factor is reported as VOC because ethanol is essentially the only VOC
emitted from filling operations.
g Reference 14. Emission factor units are lb of pollutant per 1000 cases of bottles washed.
Emission factor represents ethanol emissions measured by GC/FID. Factor is reported as VOC
because ethanol is essentially the only VOC emitted from this operation. EMISSION FACTOR
RATING: D.
h References 9,19. VOC as propane.
j Reference 17. Emission factor units are lb of pollutant per ton of dried grain produced. Emission
factor includes data from dryers controlled by wet scrubbers, which do not control C02 emissions.
EMISSION FACTOR RATING: D
k References 11-13. VOC as propane. Emission factor units are lb of pollutant per ton of dried
grain produced. Emission factor includes data from dryers controlled by wet scrubbers, which do
not control VOC emissions. EMISSION FACTOR RATING: D.
m Reference 11. Emission factor units are lb of pollutant per ton of dried grain produced. Emission
factor includes data from dryers controlled by wet scrubbers, which do not control CO or C02
emissions. EMISSION FACTOR RATING: D.
n Reference 16. VOC as ethanol. Emission factor units are lb of pollutant per gallon of beer
recovered. EMISSION FACTOR RATING: D.
p Reference 19. VOC as propane.
q Reference 10. VOC as ethanol. Emission factors are based on a 24-hour venting period prior to
C02 collection.
r Reference 5. VOC as propane.
s Reference5. VOC as ethanol. EMISSION FACTOR RATING: D.
* Reference5. EMISSION FACTOR RATING: D.
u References 5,7-8,18. VOC as ethanol. Emission factor includes measurements of VOC as ethanol
measured using EPA Method 25A and ethanol measured using both EPA Method 18 and an FTIR
analyzer. EMISSION FACTOR RATING: D.
9.12.1-10
EMISSION FACTORS
10/96
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References For Section 9.12,1
1. Written communication from Brian Shrager, Midwest Research Institute, Cary, NC, to
Dallas Safriet, U. S. Environmental Protection Agency, Research Triangle Park, NC, May 5,
1994.
2. Richard D. Rapoport et al, Characterization Of Fermentation Emissions From California
Breweries, Science Applications, Inc., Los Angeles, CA, October 26, 19B3.
3. Written communication from Jere Zimmerman, Adolph Coors Company, Golden, CO, to
David Reisdorph, Midwest Research Institute, Kansas City, MO, March 11, 1993.
4. Written communication from Arthur J. DeCelle, Beer Institute, Washington, D.C., to
Dallas Safriet, U. S. Environmental Protection Agency, Research Triangle Park, NC,
February 15, 1995.
5. Report On Compliance Testing Performed For Coors Brewing Company, Clean Air
Engineering, Palatine, IL, November 25, 1992.
6. Report On Diagnostic Testing Performed For Coors Brewing Company, Revision 1, Clean Air
Engineering, Palatine, IL, April 6, 1994.
7. Can And Bottle Filler Vent Volatile Organic Compound Test For Coors Brewing Company,
Air Pollution Testing, Inc., Westminster, CO, October 1992.
8. Filler Rooms Diagnostic VOC Test Report For Coors Brewing Company, Air Pollution
Testing, Inc., Westminster, CO, December 1992.
9. Stack Emissions Survey, Adolph Coors Company Brewery Complex, Golden, Colorado,
Western Environmental Services and Testing, Inc., Casper, WY, November, 1990.
10. Stack Emissions Survey, Adolph Coors Company Fermentation - Aging Facilities, Golden,
Colorado, Western Environmental Services and Testing, Inc., Casper, WY, November 1990.
11. Stack Emissions Survey, Adolph Coors Company Brewery Complex, Golden, Colorado,
Western Environmental Services and Testing, Inc., Casper, WY, February 1991.
12. Grain Dryer Diagnostic VOC Report For Coors Brewing Company, Air Pollution Testing,
Inc., Westminster, CO, November 1992.
13. Report On Compliance Testing Performed For Coors Brewing Company, Clean Air
Engineering, Palatine, IL, November 25, 1992.
14. Bottle Wash Soaker Area Ethanol Emissions Source Test Report Performed For Coors Brewing
Company, Acurex Environmental Corporation, Anaheim, CA, July 12, 1993.
15. Volatile Organic Compound Emissions Source Test Report For Coors Brewing Company, Air
Pollution Testing, Inc., Lakewood, CO, August 1993.
10/96
Food And Agricultural Industry
9.12.1-11
-------
16. Crushed Can Conveyor Unit Compliance VOC Test Report For Coors Brewing Company, Air
Pollution Testing, Inc., Lakewood, CO, October 21, 1993.
17. Emission Test Report, Dryers ffl And #4, Anheuser Busch, Inc., Columbus, Ohio, Pollution
Control Science, Miamisburg, OH, December 20, 1983.
18. Source Emissions Testing Report For Coors Brewing Company: Golden, Colorado Facility,
FID/FTIR Ethanol Measurements-Can And Bottle Line Ducts, Air Pollution Testing, Inc.,
Lakewood, CO, April 3-4, 1995.
19. Air Emissions Investigation Report, Miller Brewing Company, Fulton, New York, RTP
Environmental Associates, Inc., Westbury, NY, February 1994,
20. Stationary Source Sampling Report Reference No. 21691, Anheuser-Busch Brewery, Fort
Collins, Colorado, Filling Room Vents, Entropy, Inc., Research Triangle Park, NC,
July 26-28, 1994.
21. Emission Factor Documentation For AP-42 Section 9.12.1, Malt Beverages, Midwest
Research Institute, Cary, NC, October 1996.
9.12.1-12
EMISSION FACTORS
10/96
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11.7 Ceramic Products Manufacturing
11.7.1 General1"3
Ceramics are defined as a class of inorganic, nonmetallic solids that arc subjected to high
temperature in manufacture and/or use. The most common ceramics are composed of oxides, carbides,
and nitrides. Silicides, borides, phosphides, tellurides, and selenides also are used to produce ceramics.
Ceramic processing generally involves high temperatures, and the resulting materials are heat resistant
or refractory.
Traditional ceramics refers to ceramic products that are produced from unrefined clay and
combinations of refined clay and powdered or granulated nonplastic minerals. Often, traditional
ceramics is used to refer to ceramics in which the clay content exceeds 20 percent. The general
classifications of traditional ceramics are described below.
Pottery is sometimes used as a generic term for ceramics that contain clay and are not used for
structural, technical, or refractory purposes.
Wliiteware refers to ceramic ware that is white, ivory, or light gray in color alter firing.
Whiteware is further classified as earthenware, stoneware, chinaware, porcelain, and technical
ceramics.
Earthenware is defined as glazed or unglazed nonvitreous (porous) clay-based ceramic ware.
Applications for earthenware include artware, kitchenware, ovenware, tableware, and tile.
Stoneware is vitreous or semivitreous ceramic ware of fine texture, made primarily from
nonrefractory fire clay or some combination of clays, fluxes, and silica that, when fired, has properties
similar to stoneware made from fire clay. Applications for stoneware include artware, chemicalware,
cookware, drainpipe, kitchenware, tableware, and tile.
Chinaware is vitreous ceramic ware of zero or low absorption after firing that are used for
nontechnical applications. Applications for chinaware include artware, ovenware, sanitarywarc, and
tableware.
Porcelain is defined as glazed or unglazed vitreous ceramic ware used primarily for technical
purposes. Applications for porcelain include artware, ball mill balls, ball mill liners, chemicalware,
insulators, and tableware.
Technical ceramics include vitreous ceramic whiteware used for such products as electrical
insulation, or for chemical, mechanical, structural, or thermal applications.
Ceramic products that are made from highly refined natural or synthetic compositions and
designed to have special properties are referred to as advanced ceramics. Advanced ceramics can be
classified according to application as electrical, magnetic, optical, chemical, thermal, mechanical,
biological, and nuclear.
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11.7-1
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Most ceramic products arc clay-based and are made from a single clay or one or more clays
mixed with mineral modifiers such as quartz and feldspar. The types of commercial clays used for
ceramics are primarily kaolin and ball clay.
11.7.2 Process Description1,3 5
Figure 11.7-1 presents a general process flow diagram for ceramic products manufacturing.
The basic steps include raw material procurement, beneficiation, mixing, forming, green machining,
drying, presinter thermal processing, glazing, firing, final processing, and packaging. The following
paragraphs describe these operations in detail.
11.7.2.1 Raw Material Procurement -
To begin the process, raw materials are transported and stored at the manufacturing facility.
The raw materials used in the manufacture of ceramics range from relatively impure clay materials
mined from natural deposits to ultrahigh purity powders prepared by chemical synthesis. Naturally
occurring raw materials used to manufacture ceramics include silica, sand, quartz, flint, silicates, and
aluminosilicatcs (e. g., clays and feldspar).
11.7.2.2 Beneficiation -
The next step in the process is beneficiation. Although chemically synthesized ceramic
powders also require some beneficiation, the focus of this discussion is on the processes for
beneficiating naturally occurring raw materials. The basic beneficiation processes include
comminution, purification, sizing, classification, calcining, liquid dispersion, and granulation.
Naturally occurring raw materials often undergo some beneficiation at the mining site or at an
intermediate processing facility prior to being transported to the ceramic manufacturing facility.
Comminution entails reducing the particle size of the raw material by crushing, grinding, and
milling or fine grinding. The purpose of comminution is to liberate impurities, break up aggregates,
modify particle morphology and size distribution, facilitate mixing and forming, and produce a more
reactive material for firing. Primary crushing generally reduces material up to 0.3 meter (m) (1 foot
[ft]) in diameter down to 1 centimeter (cm) (0.40 inch [in.]) in diameter. Secondary crushing reduces
particle size down to approximately 1 millimeter (mm) (0.04 in.) in diameter. Fine grinding or milling
reduces the particle size down to as low as 1.0 micrometer (|4in) (4 x 10"5 in.) in diameter. Ball mills
are the most commonly used piece of equipment for milling. However, vibratory mills, attrition mills,
and fluid energy mills also are used. Crushing and grinding typically are dry processes; milling may
be a wet or dry process. In wet milling, water or alcohol commonly is used as the milling liquid.
Several procedures are used to purify the ceramic material. Water soluble impurities can be
removed by washing with deionized or distilled water and filtering, and organic solvents may be used
for removing water-insoluble impurities. Acid leaching sometimes is employed to remove metal
contaminants. Magnetic separation is used to extract magnetic impurities from either dry powders or
wet slurries. Froth flotation also is used to separate undesirable materials.
Sizing and classification separate the material into size ranges. Sizing is most often
accomplished using fixed or vibrating screens. Dry screening can be used to sizes down to 44 |ixn
(0.0017 in., 325 mesh). Dry forced-air sieving and sonic sizing can be used to size dry powders down
to 37 (im (0.0015 in., 400 mesh), and wet sieving can be used for particles down to 25 |im
(0.00098 in., 500 mesh). Air classifiers generally are effective in the range of 420 (jid to 37 pin
11.7-2
EMISSION FACTORS
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RAW MATERIAL
PROCUREMENT
FINAL PROCESSING
(34540640,-70,-00)
FORMING
(3-05-000-30,-31)
PACKAGING
GREEN
MACHINING
(3-05-000-35)
GLAZE
PREPARATION
(345-008-43)
EMISSIONS
PRESINTER THERMAL
PROCESSING
(345-000-40, -41)
PROCESSING ADDmVES-BINDERS.
PLAST1CIZERS, DEFLOCCULAMTS,
SURFACTANTS, ANT1 FOAMING AGENTS
BENEFICtATKJN
• COMMINUTION-CRUSHING, GRINDING, AND MILLING OR FINE GRINDING (345-000-02)
• PURIFICATION-WASHING, ACID LEACHING, MAGNETIC SEPARATION, OR FROTH FLOTATION
• SIZING-VIBRATING SCREENS (3-05406-10)
• CLASSIFICATION-AIR OR LIQUID CLASSIFIERS (3-05400-10)
• CALCINING (3-05406-21,-22,-23,-24)
• LIQUID DISPERSION
• GRANULATION-DIRECT MIXING (34540045) OR SPRAY DRYING (345400-10)
Figure 11.7-1. Process flow diagram for ceramic products manufacturing.
(Source Classification Codes in parentheses.)
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11.7-3
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(0.017 to 0.0015 in., 40 to 400 mesh). However, special air classifiers are available for isolating
particles down to 10 pm (0.00039 in.).
Calcining consists of heating a ceramic material to a temperature well below its melting point
to liberate undesirable gases or other material and to bring about structural transformation to produce
the desired composition and phase product. Calcining typically is carried out in rotary calciners,
heated fluidized beds, or by heating a static bed of ceramic powder in a refractory crucible.
Liquid dispersion of ceramic powders sometimes is used to make slurries. Slurry processing
facilitates mixing and minimizes particle agglomeration. The primary disadvantage of slurry
processing is that the liquid must be removed prior to firing tlie ceramic.
Dry powders often are granulated to improve flow, handling, packing, and compaction.
Granulation is accomplished by direct mixing, which consists of introducing a binder solution during
powder mixing, or by spray drying. Spray dryers generally are gas-fired and operate at temperatures
of 110° to 130°C (230° to 270°F).
11.7.2.3 Mixing -
The purpose of mixing or blunging is to combine the constituents of a ceramic powder to
produce a more chemically and physically homogenous material for forming. Pug mills often are used
for mixing ceramic materials. Several processing aids may be added to the ceramic mix during the
mixing stage. Binders and plastieizers are used in dry powder and plastic forming; in slurry
processing, deflocculants, surfactants, and antifoaming agents are added to improve processing.
Liquids also are added in plastic and slurry processing.
Binders are polymers or colloids that are used to impart strength to green or unfired ceramic
bodies. For dry forming and extrusion, binders amount to 3 percent by weight of the ceramic mixture.
Plastieizers and lubricants are used with some types of binders. Plastieizers increase the flexibility of
the ceramic mix. Lubricants lower frictional forces between particles and reduce wear on equipment.
Water is the most commonly used liquid in plastic and slurry processing. Organic liquids such as
alcohols may also be used in some cases. Deflocculants also are used in slurry processing to improve
dispersion and dispersion stability. Surfactants are used in slurry processing to aid dispersion, and
anti foams are used to remove trapped gas bubbles from the slurry.
11.7.2.4 Forming -
In the forming step, dry powders, plastic bodies, pastes, or slurries are consolidated and
molded to produce a cohesive body of the desired shape and size. Dry forming consists of the
simultaneous compacting and shaping of dry ceramic powders in a rigid die or flexible mold. Dry
forming can be accomplished by dry pressing, isostatic compaction, and vibratory compaction.
Plastic molding is accomplished by extrusion, jiggering, or powder injection molding.
Extrusion is used in manufacturing structural clay products and some refractory products. Jiggering is
widely used in the manufacture of small, simple, axially symmetrical whiteware ceramic such as
cookware, fine cliina, and electrical porcelain. Powder injection molding is used for making small
complex shapes.
Paste forming consists of applying a thick film of ceramic paste on a substrate. Ceramic
pastes are used for decorating ceramic tableware, and forming capacitors and dielectric layers on rigid
substrates for microelectronics.
11.7-4
EMISSION FACTORS
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Slurry forming of ceramics generally is accomplished using slip casting, gelcasting, or tape
casting. In slip casting, a ceramic slurry, which has a moisture content of 20 to 35 percent, is poured
into a porous mold. Capillary suction of the mold draws the liquid from the mold, thereby
consolidating the cast ceramic material. After a fixed time the excess slurry is drained, and the cast is
dried. Slip casting is widely used in the manufacture of sinks and other sanitaryware, figurines,
porous thermal insulation, fine china, and structural ceramics with complex shapes. Gelcasting uses in
situ polymerization of organic monomers to produce a gel that binds ceramic particles together into
complex shapes such as turbine rotors. Tape casting consists of forming a thin film of ceramic slurry
of controlled thickness onto a support surface using a knife edge. Tape casting is used to produce thin
ceramic sheets or tape, which can be cut and stacked to form multilayer ceramics for capacitors and
dielectric insulator substrates.
11.7.2.5 Green Machining -
After forming, the ceramic shape often is machined to eliminate rough surfaces and seams or
to modify the shape. The methods used to machine green ceramics include surface grinding to smooth
surfaces, blanking and punching to cut the shape and create holes or cavities, and laminating for
multilayer ceramics.
11.7.2.6 Drying-
After forming, ceramics must be dried. Drying must be carefully controlled to strike a balance
between minimizing drying time and avoiding differential shrinkage, warping, and distortion. The
most commonly used method of drying ceramics is by convection, in which heated air is circulated
around the ceramics. Air drying often is performed in tunnel kilns, which typically use heat recovered
from the cooling zone of the kiln. Periodic kilns or dryers operating in batch mode also are used.
Convection drying also is carried out in divided tunnel dryers, which include separate sections with
independent temperature and humidity controls. An alternative to air drying is radiation drying in
which microwave or infrared radiation is used to enhance drying.
11.7.2.7 Presinter Thermal Processing -
Prior to firing, ceramics often are heat-treated at temperatures well below firing temperatures.
The purpose of this thermal processing is to provide additional drying, to vaporize or decompose
organic additives and other impurities, and to remove residual, crystalline, and chemically bound
water. Presinter thermal processing can be applied as a separate step, which is referred to as bisque
firing, or by gradually raising and holding the temperature in several stages.
11.7.2.8 Glazing -
For traditional ceramics, glaze coatings often are applied to dried or bisque-fired ceramic ware
prior to sintering. Glazes consist primarily of oxides and can be classified as raw glazes or frit glazes.
In raw glazes, the oxides are in the form of minerals or compounds that melt readily and act as
solvents for the other ingredients. Some of the more commonly used raw materials for glazes are
quartz, feldspars, carbonates, borates, and zircon. A frit is a prereacted glass. Frit manufacturing is
addressed in AP-42 Section 11.14.
To prepare glazes, the raw materials are ground in a ball mill or attrition mill. Glazes
generally are applied by spraying or dipping. Depending on their constituents, glazes mature at
temperatures of 6(X)° to 1500°C (1110° to 2730°F).
11.7.2.9 Firing-
Firing is the process by which ceramics are thermally consolidated into a dense, cohesive body
comprised of line, uniform grains. Tliis process also is referred to as sintering or densification. In
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11.7-5
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general: (1) ceramics witli fine particle size fire quickly and require lower firing temperatures;
(2) dense unfired ceramics fire quickly and remain dense after firing with lower shrinkage; and
(3) irregular shaped ceramics fire quickly. Other material properties that affect firing include material
surface energy, diffusion coefficients, fluid viscosity, and bond strength.
Parameters that affect firing include firing temperature, time, pressure, and atmosphere. A
short firing time results in a product that is porous and has a low density; a short to intermediate firing
time results in fine-grained (i. e., having particles not larger than 0.2 millimeters), high-strength
products; and long firing times result in a coarse-grained products that are more creep resistant.
Applying pressure decreases firing time and makes it possible to fire materials that are difficult to fire
using conventional methods. Oxidizing or inert atmospheres are used to fire oxide ceramics to avoid
reducing transition metals and degrading the finish of the product.
In addition to conventional firing, other methods used include pressure firing, hot forging,
plasma firing, microwave firing, and infrared firing. The following paragraphs describe conventional
and pressure firing, which are the methods used often.
Conventional firing is accomplished by heating the green ceramic to approximately two-thirds
of the melting point of the material at ambient pressure and holding it for a specified time in a
periodic or tunnel kiln. Periodic kilns lire heated and cooled according to prescribed schedules. The
heat for periodic kilns generally is provided by electrical element or by firing with gas or oil.
Tunnel kilns generally have separate zones for cooling, firing, and preheating or drying. The
kilns may be designed so that (1) the air heated in the cooling zone moves into the firing zone and the
combustion gases in Uie firing zone are conveyed to the preheat/drying zone then exhausted, or (2) the
air heated in the cooling zone is conveyed to the preheat/drying zone and the firing zone gases are
exhausted separately. The most commonly used tunnel kiln design is the roller hearth (roller) kiln. In
conventional firing, tunnel kilns generally are fired with gas, oil, coal, or wood. Following firing and
cooling, ceramics are sometimes refired after the application of decals, paint, or ink.
Advanced ceramics often are fired in electric resistance-heated furnaces with controlled
atmospheres. For some products, separate furnaces may be needed to eliminate organic lubricants and
binders prior to firing.
Ceramic products also are manufactured by pressure firing, which is similar to the forming
process of dry pressing except that the pressing is conducted at the firing temperature. Because of its
higher costs, pressure firing is usually reserved for manufacturing ceramics that are difficult to fire to
high density by conventional firing.
11.7.2.10 Final Processing -
Following firing, some ceramic products are processed further to enhance their characteristics
or to meet dimensional tolerances. Ceramics can be machined by abrasive grinding, chemical
polishing, electrical discharge machining, or laser machining. Annealing at high temperature, followed
by gradual cooling can relieve internal stresses within the ceramic and surface stresses due to
machining. In addition, surface coatings are applied to many fired ceramics. Surface coatings are
applied to traditional clay ceramics to create a stronger, impermeable surface and for decoration.
Coatings also may be applied to improve strength, and resistance to abrasion and corrosion. Coatings
can be applied dry, as slurries, by spraying, or by vapor deposition.
11.7-6
EMISSION FACTORS
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11.7,3 Emissions And Controls1'3'5'12"31
The primary pollutants associated witJi raw material beneficiation are particulate matter (PM)
and PM less than lOfiin in aerodynamic diameter (PM-10), Filterable PM and PM-1Q are emitted
from comminution, sizing, classifying, handling, transfer, and storage. In addition, raw material
calciners emit filterable and condensible PM, which may include metals and other inorganic pollutants.
Calciners also emit products of combustion such as nitrogen oxides (NOx), sulfur oxides (SOx), carbon
monoxide (CO), carbon dioxide (C02), and volatile organic compounds (VOC). Emissions of SOx are
a function of the sulfur content of the fuel used to fire the calciners and the sulfur content of the raw
materials used to manufacture ceramics. Emissions of VOC result from incomplete combustion and
volatilization of the organic material associated with the raw material. Other beneficiation processes
that are associated with emissions include acid leaching and granulation. Emissions of hydrochloric
acid (HC1) or other acids may arise from leaching. In addition, PM and products of combustion arc
emitted from spray dryers used for granulation.
Mixing generally is a wet process. However, VOC emissions from this step may arise from
the volatilization of binders, plasticizers, and lubricants. Forming generally is performed in sealed
containers and often is a wet process; emissions from this step in the process are likely to be
negligible. However, tape casters are a source of VOC emissions. For ceramic bodies that are dry-
formed, PM is likely lo be emitted from grinding, punching, and other green machining activities.
Particulate matter emissions consisting of metal and mineral oxides also arise from glaze
preparation, which includes mixing and grinding. Emissions of PM from glaze application also are
likely, if the glaze is applied by spraying.
Emissions associated from green ceramic heat treating processes, which include drying,
presinter thermal processing, and firing, include combustion products and filterable and condensible
PM. Particulate matter emissions consist in part of metals and the inorganic minerals associated with
the raw materials. Emissions of the products of combustion are a function of fuel type, raw material
constituents, process temperature, and other operating parameters.
Emissions of fluorine compounds also are associated with firing. Fluorine is present in
ceramic raw materials in the range of 0.01 to 0.2 percent. As the temperature of green ceramic bodies
reaches 500° to 600°C (930° to 1110°F), the fluorine in the raw material forms hydrogen fluoride (HF)
and other fluorine compounds such as silicon tetrafluoride. Much of the fluorine is released as HF.
However, if lime is present in the ceramic body, HF reacts with the lime to form calcium fluoride
(CaF2), thereby reducing potential HF emissions.
Other emission sources associated with ceramics manufacturing include final processing
operations and fugitive dust sources. The final processing steps include grinding and polishing, which
can emit PM and PM-10, and surface coating, annealing, and chemical treatment, which can emit
VOC. Fugitive dust sources, which consist of vehicular traffic, wind erosion of storage piles, and
materials handling and transfer, emit PM and PM-10.
Several techniques have been used to control PM emissions from the mechanical processing of
ceramic raw materials and finished products. Fabric filters are the most commonly used control
device, but wet scrubbers and electrostatic precipitators (ESPs) also are used. Fabric filters, wet
scrubbers, and ESPs also are used to control emissions from clay calciners and dryers. Venturi
scrubbers and fabric filters are used to control emissions from granulation (spray dryers) and from
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11.7-7
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glaze preparation and application. Afterburners have been used to control VOC emissions from tape
casting operations. Emissions from kilns generally are uncontrolled.
Emissions of HF from kilns can be reduced through process modifications such as increasing
the raw material lime content and reducing kiln draft, kiln exhaust temperature, and kiln residence
time. Dry sorption scrubbing also has been used to control HF emissions in the brick and ceramic
industries in Germany and in the brick industry in the United States. These devices use limestone as a
sorption medium to produce CaF2, which is removed by means of a rotating screen, drum, or fabric
filter. Control efficiencies of 95 to 99 percent have been reported for this type of scrubber.
Table 11.7-1 presents emission factors for PM and lead emissions from various ceramic
products manufacturing processes. Table 11.7.2 present emission factors for S02, NOx, CO, C02,
VOC, HF, and fluoride emissions from ceramic kilns and tape casters.
11.7-8
EMISSION FACTORS
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Tabic 11.7-1. EMISSION FACTORS FOR CERAMIC PRODUCTS
MANUFACTURING OPERATIONS3
EMISSION
EMISSION
Filterable
FACTOR
Lead
FACTOR
Source
PM (lh/ton)b
RATING
(lb/ton)
RATING
Comminution-raw material crushing and
screening line with fabric filter0
0.12
D
ND
NA
(SCC 3-05-00B-02)
Dryerd
2.3
E
ND
NA
(SCC 3-05-008-13)
Cooler1'
0.11
E
ND
NA
(SCC 3-05-008-58)
Granulation-natural gas-fired spray dryer
(SCC 3-05-008-10)
with fabric filter®
0.060
E
ND
NA
with venturi scrubbe/
0.19
D
ND
NA
Firing—natural gas-fired kilng
0.49
D
ND
NA
(SCC 3-05-008-50)
Retiring -natural gas-fired kilnh
0.067
E
ND
NA
(SCC 3-05-008-56)
Ceramic glaze spray booth
(SCC 3-05-008-45)
uncontrolled1
19
E
3.0
E
with wet scrubbed
1.8
D
ND
NA
a Emission factor units are lb of pollutant per ton of fired ceramic produced, unless noted. To convert
from lb/ton to kg/Mg, multiply by 0.5. Factors represent uncontrolled emissions unless noted. SCC
= Source Classification Code. ND = no data. NA = not applicable.
h Filterable PM is that PM collected on the front-half of an EPA Method 5 (or equivalent) sampling
train. Although condcnsible organic and inorganic PM emissions arc expected from dryers and
kilns, no data arc available to estimate these emissions.
c References 12-13. Raw material processing for production of quarry tile, which is an unglazed tile
product similar to structural clay products. Emission factor units are lb of pollutant per ton of
material processed.
d Reference 15.
e Reference 16. Emission factor units are lb of pollutant per ton of dry material produced.
f References 26-29. Emission factor units are lb of pollutant per ton of dry material produced.
8 References 7,9-11,15,23-25.
h Reference 6. Kiln is used for refiring tile after application of decals, paint, or ink screening.
¦> Reference 30. Emission factor units are lb of pollutant per ton of glazed used. Glaze contains
about 24 percent lead oxide.
k References 20-22. Emission factor units are lb of pollutant per ton of glaze used.
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11.7-9
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Table 11,7-2. EMISSION FACTORS FOR GASEOUS POLLUTANT EMISSIONS FROM
CERAMIC PRODUCTS MANUFACTURING3
EMISSION FACTOR RATING: E
Source
S02
NOx
CO
co2
VOCh
HF1"
Fluorides'1
Firing-natural gas-fired kiln
(SCC 3-05-008-50)
44-Sc
0.54f
3.3s
780f
0.43s
0.46h
0.56'
Refiring-natural gas-fired
kilnk"
(SCC 3-05-00X-56)
ND
ND
ND
97
ND
ND
0.019
Forming-tape casters"1
(SCC 3-05-008-31)
ND
ND
ND
ND
58
ND
ND
a Emission factor units are lb of pollutant per ton of ceramic product produced, unless noted. To
convert from lb/ton to kg/Mg, multiply by 0.5. Factors represent uncontrolled emissions unless
noted. SCC = Source Classification Code. ND = no data.
b VOC reported on an "as propane" basis; measured using EPA Method 25A. Emission factor may
include nonphotochemically reactive compounds that arc not considered VOC. No data are
available to estimate emissions of these non-VOC compounds.
c Hydrogen fluoride measured using EPA Method 26A. This compound is listed as a hazardous air
pollutant under Section 112(b) of the Clean Air Act, as amended in November 1990. A mass
balance on flouride will provide a better estimate of HF emissions for individual facilities.
d Total fluorides measured during EPA Method 13A or 13B. Measurements include HF and other
fluorine compounds. A mass balance on flouride will provide a better estimate of fluoride
emissions for individual facilities.
e Reference 10. For facilities using raw material with a sulfur content greater than 0.07 percent. The
variable S represents the raw material sulfur content (percent). For facilities using raw material with
a sulfur content less than or equal to 0.07 percent, use 9.5-S lb/ton to estimate emissions
(References 9,11). Emissions of S02 are dependent on the sulfur content of the raw material and
the fuel used to fire the kiln.
f References 9,11,15. EMISSION FACTOR RATING: D.
g Reference 15. EMISSION FACTOR RATING: D.
h Reference 15.
J References 7,9-11, 23-25.
k Reference 6.
ra Reference 14. Emission factor units are lb of pollutant per ton of formed product. Emissions
controlled by an afterburner.
References For Section 11.7
1. Kirk-Othmer Encyclopedia Of Chemical Technology, Fourth Edition, Volume 5, John Wiley &
Sons, New York, 1992.
2. 1987 Census Of Manufactures, U. S. Department of Commerce, Washington, D.C., May 1990.
3. Ullman's Encyclopedia Of Industrial Chemistry, Fifth Edition, Volume A6.
11.7-10
EMISSION FACTORS
7/96
-------
4. D. W. Rieherson, Modern Ceramic Engineering: Properties Processing, And Use In Design,
Marcel Dekker, Inc., New York, NY, 1982.
5. P. Vincen/ini (ed.), Fundamentals Of Ceramic Engineering, Elsevier Science Publishers, Ltd.,
New York, 1991.
6. Particulate Emission Testing For Florida Tile Corporation, Lawrenceburg, Kentucky,
March 7-8, 1989, Air Systems Testing, Inc., Marietta, GA, April 1989.
7. Particulate Emission Testing For Florida Tile Corporation, Lawrenceburg, Kentucky, April 19,
1989, Air Systems Testing, Inc., Marietta, GA, May 1989.
8. Source Emission Tests At Stark Ceramics, Inc., East Canton, Ohio, No. 3 Kiln Stack,
September 16, 1993, Custom Stack Analysis Company, Alliance, OH, October 1993.
9. Metropolitan Ceramics, Canton, Ohio, Tunnel Kiln #3 Exhaust Stack, Particulate, S02, NOr
Hydrofluoric Acid Emission Evaluation, Conducted - November 17-18, 1993, Envisage
Environmental Incorporated, Richfield, OH, December 16, 1993.
10. Metropolitan Ceramics, Inc., Canton, Ohio, TK1, TK2, TK3 Exhausts, Particulate, Sulfur
Dioxides, & Fluorides Emission Evaluation, Conducted - March 30 & April 14, 1994,
Envisage Environmental Incorporated, Richfield, OH, May 9, 1994.
11. Source Evaluation Results, U. S. Ceramic Tile Company, East Sparta, Ohio, August 11, 1993,
Envisage Environmental Incorporated, Richfield, OH, September 1, 1993.
12. Particulate Emissions Test For American Olean Tile Company, Fayette, AL, Crushing And
Screening Line #1, October 15, 1991, Pensacola POC, Inc., Pensacola, FL, October 1991.
13. Particulate Emissions Test For American Olean Tile Company, Fayette, AL, Crushing And
Screening Line #2, October 16, 1991, Pensacola POC, Inc., Pensacola, FL, October 1991.
14. VOC Emission Test Report For GE Ceramics Tape Casters Fume Oxidizer, Chattanooga, TN,
September 13-15, 1989, IT-Air Quality Services Group, Knoxville, TN, October, 1989.
15. Exhaust Emission Sampling For Norton Company, Soddy-Daisy, TN, April 19-20, 1994,
Armstrong Environmental, Inc., Dallas, TX, April 1994.
16. Particulate Emission Evaluation For Steward, Inc., Chattanooga, TN, March 30, 1993, FBT
Engineering and Environmental Services, Chattanooga, TN, May 1993.
17. D. Brosnan, "Technology and Regulatory Consequences of Fluorine Emissions in Ceramic
Manufacturing", American Ceramic Industry Bulletin, 71 (12), pp 1798-1802, The American
Ceramic Society, Westerville, OH, December 1992.
18. Calciners And Dryers In The Mineral Industries-Background Information For Proposed
Standards, EPA-450/3-85-025a, U. S. Environmental Protection Agency, Research Triangle
Park, NC, October 1985.
7/96
Mineral Products
11.7-11
-------
19. C. Palmonari and G. Timellini, Pollutant Emission Factors For The Ceramic Floor And Wall
Tile Industry, Journal of the Air Pollution Control Association, Volume 32, No. 10, Pittsburgh,
PA, October 1982.
20. Report To American Standard On Stack Particulate Samples Collected At Tiffin, OH (Test
Date August 18, 1992), Affiliated Environmental Services, Inc., Sandusky, OH, August 24,
1992.
21. Report To American Standard On Stack Particulate Samples Collected At Tiffin, OH (Test
Date August 19, 1992), Affiliated Environmental Services, Inc., Sandusky, OH, August 24,
1992.
22. Report To American Standard On Stack Particulate Samples Collected At Tiffin, OH (Test
Date February 8, 1994), Affiliated Environmental Services, Inc., Sandusky, OH, February 15,
1994.
23. Emission Test Report-Plant A, Roller Kiln, May 1994, Document No. 4602-01-02,
Confidential Business Information Files, Contract No 68-D2-0159, Assignment No. 2-01, U. S.
Environmental Protection Agency, Research Triangle Park, NC, June 8, 1995.
24. Emission Test Report (Excerpts)—Plant A, Roller Kiln, June 1993, Document No. 4602-01-02,
Confidential Business Information Files, Contract No 68-D2-0159, Assignment No. 2-01, U. S.
Environmental Protection Agency, Research Triangle Park, NC, June 8, 1995.
25. Emission Test Report (Excerpts)-Platit A, Roller Kiln, February 1992, Document
No. 4602-01-02, Confidential Business Information Files, Contract No 68-D2-0159,
Assignment No. 2-01, U. S. Environmental Protection Agency, Research Triangle Park, NC,
June 8, 1995.
26. Emission Test Report-Plant A, Spray Dryer, October 1994, Document No. 4602-01-02,
Confidential Business Information Files, Contract No 68-D2-0159, Assignment No. 2-01, U. S.
Environmental Protection Agency, Research Triangle Park, NC, June 8, 1995.
27. Emission Test Report (Excerpts)-Plant A, Spray Dryer, April 1994, Document
No. 4602-01-02, Confidential Business Information Files, Contract No 68-D2-0159,
Assignment No. 2-01, U. S. Environmental Protection Agency, Research Triangle Park, NC,
June 8, 1995.
28. Emission Test Report (Excerpts)-Plant A, Spray Dryer, January 1993, Document
No. 4602-01-02, Confidential Business Information Files, Contract No 68-D2-0159,
Assignment No. 2-01, U. S. Environmental Protection Agency, Research Triangle Park, NC,
June 8, 1995.
29. Emission Test Report (Excerpts)-Plant A, Spray Dryer, February 1992, Document
No. 4602-01-02, Confidential Business Information Files, Contract No 68-D2-0159,
Assignment No. 2-01, U. S. Environmental Protection Agency, Research Triangle Park, NC,
June 8, 1995.
11.7-12
EMISSION FACTORS
7/96
-------
30. Stationary Source Sampling Report Reference No. 6445, Lead And Particulate Emissions
Testing, Spray Booth 2A Stack, Entropy Environmentalists, Inc., Research Triangle Park, NC,
September 20, 1989.
31. Emission Factor Documentation For AP-42 Section 11.7, Ceramic Products Manufacturing,
Final Report, EPA Contract No. 68-D2-0159, Midwest Research Institute, Gary, NC, June
1996.
7/96
Mineral Products
11.7-13
-------
12.20 Electroplating
This section addresses the electroplating industry. However, emphasis is placed on chromium
electroplating and chromic acid anodizing because the majority of emissions data and other
information available were for this area of the electroplating industry. Detailed information on the
process operations, emissions, and controls associated with other types of electroplating will be added
to this section as it becomes available. The six-digit Source Classification Code (SCC) for
electroplating is 3-09-010.
12.20.1 Process Description14
Electroplating is the process of applying a metallic coating to an article by passing an electric
current through an electrolyte in contact with the article, thereby forming a surface having properties
or dimensions different from those of the article. Essentially any electrically conductive surface can
be electroplated. Special techniques, such as coating with metallic-loaded paints or silver-reduced
spray, can be used to make nonconductive surfaces, such as plastic, electrically conductive for
electroplating. The metals and alloy substrates electroplated on a commercial scale are cadmium,
chromium, cobalt, copper, gold, indium, iron, lead, nickel, platinum group metals, silver, tin, zinc,
brass, bronze, many gold alloys, lead-tin, nickel-iron, nickel-cobalt, nickel-phosphorus, tin-nickel, tin-
zinc, zinc-nickel, zinc-cobalt, and zinc-iron. Electroplated materials are generally used for a specific
property or function, although there may be some overlap, e. g., a material may be electroplated for
decorative use as well as for corrosion resistance.
The essential components of an electroplating process arc an electrode to be plated (the
cathode or substrate), a second electrode to complete the circuit (the anode), an electrolyte containing
the metal ions to be deposited, and a direct current power source. The electrodes are immersed in the
electrolyte with the anode connected to the positive leg of the power supply and the cathode to the
negative leg. As the current is increased from zero, a point is reached where metal plating begins to
occur on the cathode. The plating tank is either made of or lined with totally inert materials to protect
the tank. Anodes can be either soluble or insoluble, with most electroplating baths using one or the
other type. The majority of power supplies are solid-state silicon rectifiers, which may have a variety
of modifications, such as stepless controls, constant current, and constant voltage. Plate thickness is
dependent on the cathode efficiency of a particular plating solution, the current density, and the
amount of plating time. The following section describes the electroplating process. Following the
description of chromium plating, information is provided on process parameters for other types of
electroplating.
12.20.1.1 Chromium Electroplating -
Chromium plating and anodizing operations include hard chromium electroplating of metals,
decorative chromium electroplating of metals, decorative chromium electroplating of plastics, chromic
acid anodizing, and trivalent chromium plating. Each of these categories of the chromium
electroplating industry is described below.
7/96
Metallurgical Industry
12,20-1
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Hard Chromium Electroplating -
In hard plating, a relatively thick layer of chromium is deposited directly on the base metal
(usually steel) to provide a surface with wear resistance, a low coefficient of friction, hardness, and
corrosion resistance, or to build up surfaces that have been eroded by use. Hard plating is used for
items such as hydraulic cylinders and rods, industrial rolls, zinc die castings, plastic molds, engine
components, and marine hardware.
Figure 12.20-1 presents a process flow diagram for hard chromium electroplating. The process
consists of pretreatment, alkaline cleaning, acid dipping, chromic acid anodizing, and chromium
electroplating. The pretreatment step may include polishing, grinding, and degreasing. Degreasing
consists of either dipping the part in organic solvents, such as trichloroethylene or perchloroethylene,
or using the vapors from organic solvents to remove surface grease. Alkaline cleaning is used to
dislodge surface soil with inorganic cleaning solutions, such as sodium carbonate, sodium phosphate,
or sodium hydroxide. Acid dipping, which is optional, is used to remove tarnish or oxide films
formed in the alkaline cleaning step and to neutralize the alkaline film. Acid dip solutions typically
contain 10 to 30 percent hydrochloric or sulfuric acid. Chromic acid anodic treatment, which also is
optional, cleans the metal surface and enhances the adhesion of chromium in the electroplating step.
The final step in the process is the electroplating operation itself.
The plating tanks typically are equipped with some type of heat exchanger. Mechanical
agitators or compressed air supplied through pipes on the tank bottom provide uniformity of bath
temperature and composition. Chromium electroplating requires constant control of the plating bath
temperature, current density, plating time, and bath composition.
Hexavalent chromium plating baths are the most widely used baths to deposit chromium on
metal. Hexavalent chromium baths are composed of chromic acid, sulfuric acid, and water. The
chromic acid is the source of the hexavalent chromium that reacts and deposits on the metal and is
emitted to the atmosphere. The sulfuric acid in the bath catalyzes the chromium deposition reactions.
The evolution of hydrogen gas from chemical reactions at the cathode consumes 80 to
90 percent of the power supplied to the plating bath, leaving the remaining 10 to 20 percent for the
deposition reaction. When the hydrogen gas evolves, it causes misting at the surface of the plating
bath, which results in the loss of chromic acid to the atmosphere.
Decorative Chromium Electroplating -
Decorative chromium electroplating is applied to metals and plastics. In decorative plating of
metals, the base material generally is plated with layers of copper and nickel followed by a relatively
thin layer of chromium to provide a bright surface with wear and tarnish resistance. Decorative
plating is used for items such as automotive trim, metal furniture, bicycles, hand tools, and plumbing
fixtures.
Figure 12.20-2 presents a process flow diagram for decorative chromium electroplating. The
process consists of pretreatment, alkaline cleaning, and acid dipping, which were described previously,
followed by strike plating of copper, copper electroplating, nickel electroplating, and chromium
electroplating. The copper strike plating step consists of applying a thin layer of copper in a copper
cyanide solution to enhance the conductive properties of the base metal. Following the copper strike
plate, the substrate is acid dipped again, and then electroplated with an undercoat of copper to improve
corrosion resistance and cover defects. Either a copper cyanide or acid copper solution is used in this
step. The substrate then is plated with nickel in two layers (semibright nickel and bright nickel) to
further improve corrosion resistance and activate the surface metal for chromium electroplating.
12.20-2
EMISSION FACTORS
7/96
-------
SUBSTRATE TO BE PLATED
PRETREATMENTSTEP
(POLISHING, GRINDING
AND DEGREASING)*
ALKALINE CLEANING
(3-09-010-14)
o©
©
(T) PM EMISSIONS
VOC EMISSIONS
•SPECIFIC SOURCE CLASSIFICATION CODE
NOT ASSIGNED. REFER TO AP-42
CHAPTER 4 FOR EMISSION FACTORS FOR
DEGREASING.
ACID DIP
(3-09-010-15)
0
CHROMIC ACID ANODIC
TREATMENT
(3-09-010-16)
©
ELECTROPLATING OF
CHROMIUM
(3-09-010-18)
©
HARD CHROMIUM PLATED PRODUCT
7/96
Figure 12.20-1. Flow diagram for a typical hard chromium plating process.3
(Source Classification Codes in parentheses.)
Metallurgical Industry
12.20-3
-------
METAL SUBSTRATE TO BE PLATED
PRETREATMENT STEP
(POLISHING, GRINDING, AND
DEGREASING)*
ALKALINE CLEANING
(3-09-010-14)
ACID DIP
(3-09-010-15)
ACID DIP
(3-09-010-15)
ELECTROPLATING OF COPPER
(3-09-010-42, -45, -48)
0©
t
©
t
©
t
I
STRIKE PLATING OF COPPER
(3-09-010-42)
©
t
©
t
I
©
t
I
©
©
PM EMISSIONS
VOC EMISSIONS
~SPECIFIC SOURCE CLASSIFICATION CODE
NOT ASSIGNED. REFER TO AP-42
CHAPTER 4 FOR EMISSION FACTORS FOR
DEGREASING.
I
I
ELECTROPLATING OF CHROMIUM
(3-09-010-28)
ELECTROPLATING OF BRIGHT
(WATTS) NICKEL
(3-09-010-65)
ELECTROPLATING OF SEMIBRIGHT
(WATTS) NICKEL
(3-09-010-65)
DECORATIVE CHROMIUM PLATED PRODUCT
Figure 12.20-2. Flow diagram for decorative chromium plating on a metal substrate.3
(Source Classification Codes in parentheses.)
12.20-4
EMISSION FACTORS
7/96
-------
Semibright and bright nickel plating both use Watts plating baths. The final step in the process is the
electroplating operation itself.
Decorative electroplating baths operate on the same principle as that of the hard chromium
plating process. However, decorative chromium plating requires shorter plating times and operates at
lower current densities than does hard chromium plating. Some decorative chromium plating
operations use fluoride catalysts instead of sulfuric acid because fluoride catalysts, such as fluosilicate
or fluoborate, have been found to produce higher bath efficiencies.
Most plastics that are electroplated with chromium are formed from acrylonitrile butadiene
styrene (ABS). The process for chromium electroplating of ABS plastics consists of the following
steps: chromic aeid/sulfuric acid etch; dilute hydrochloric acid dip; colloidal palladium activation;
dilute hydrochloric acid dip; electroless nickel plating or copper plating; and chromium electroplating
cycle. After each process step, the plastic is rinsed with water to prevent carry-over of solution from
one bath to another. The electroplating of plastics follows the same cycle as that described for
decorative chromium electroplating.
Chromic Acid Anodizing -
Chromic acid anodizing is used primarily on aircraft parts and architectural structures that are
subject to high stress and corrosion. Chromic acid anodizing is used to provide an oxide layer on
aluminum for corrosion protection, electrical insulation, ease of coloring, and improved dielectric
strength. Figure 12.20-3 presents a flow diagram for a typical chromic acid anodizing process.
There are four primary differences between the equipment used for chromium electroplating
and that used for chromic acid anodizing: chromic acid anodizing requires the rectifier to be fitted
with a rheostat or other control mechanism to permit starting at about 5 V; the tank is the cathode in
the electrical circuit; the aluminum substrate acts as the anode; and sidewall shields typically are used
instead of a liner in the tank to minimize short circuits and to decrease the effective cathode area.
Types of shield materials used are herculite glass, wire safety glass, neoprene, and vinyl chloride
polymers.
Before anodizing, the aluminum must be pretreated by means of the following steps: alkaline
soak, desmutting, etching, and vapor degreasing. The pretreatment steps used for a particular
aluminum substrate depend upon the amount of smut and the composition of the aluminum. The
aluminum substrate is rinsed between pretreatment steps to remove cleaners.
During anodizing, the voltage is applied step-wise (5 V per minute) from 0 to 40 V and
maintained at 40 V for the remainder of the anodizing time. A low starting voltage (i. e., 5 V)
minimizes current surge that may cause "burning" at contact points between the rack and the
aluminum part. The process is effective over a wide range of voltages, temperatures, and anodizing
times. All other factors being equal, high voltages tend to produce bright transparent films, and lower
voltages tend to produce opaque films. Raising the bath temperature increases current density to
produce thicker films in a given time period. Temperatures up to 49°C (120°F) typically are used to
produce films that are to be colored by dyeing. The amount of current varies depending on the size of
the aluminum parts; however, the current density typically ranges from 1,550 to 7,750 A/m2 (144 to
720 A/ft2).
The postanodizing steps include sealing and air drying. Sealing causes hydration of the
aluminum oxide and fills the pores in the aluminum surface. As a result, the elasticity of the oxide
film increases, but the hardness and wear resistance decrease. Sealing is performed by immersing
7/96
Metallurgical Industry
12.20-5
-------
SUBSTRATE TO BE PLATED
O©
l
RINSE
'SPECIFIC SOURCE CLASSIFICATION CODE
NOT ASSIGNED. REFER TO AP-42
CHAPTER 4 FOR EMISSION FACTORS FOR
DEGREASING.
I
RINSE
CHROMIC ACID ANODIZING
(3-09-010-38)
SEALING
ALKALINE CLEANING
(3-09-010-14)
(T) PM EMISSIONS
(?) VOC EMISSIONS
^^ /CDAII r^CfiDCAC
DESMUTTING
ETCHING
VAPOR DEGREASING'
PRETREATMENT STEPS
FINAL PRODUCT
Figure 12.20-3, Flow diagram for a typical chromic acid anodizing process.3
(Source Classification Codes in parentheses.)
12.20-6
EMISSION FACTORS
7/96
-------
aluminum in a water bath at 88° to 99°C (190° to 210°F) for a minimum of 15 minutes. Chromic
acid or other chromates may be added to the solution to help improve corrosion resistance. The
aluminum is allowed to air dry after it is sealed.
Trivalent Chromium Plating -
Trivalent chromium electroplating baths have been developed primarily to replace decorative
hexavalent chromium plating baths. Development of a trivalent bath has proven to be difficult because
trivalent chromium solvates in water to form complex stable ions that do not readily release chromium.
Currently, there are two types of trivalent chromium processes on the market: single-cell and
double-cell. The major differences in the two processes are that the double-cell process solution
contains minimal-to-no chlorides, whereas the single-cell process solution contains a high
concentration of chlorides. In addition, the double-cell process utilizes lead anodes that are placed in
anode boxes that contain a dilute sulfuric acid solution and are lined with a permeable membrane,
whereas the single-cell process utilizes carbon or graphite anodes that are placed in direct contact with
the plating solution. Details on these processes are not available because the trivalent chromium baths
currently on the market are proprietary.
The advantages of the trivalent chromium processes over the hexavalent chromium process are
fewer environmental concerns due to the lower toxicity of trivalent chromium, higher productivity, and
lower operating costs. In the trivalent chromium process, hexavalent chromium is a plating bath
contaminant. Therefore, the bath does not contain any appreciable amount of hexavalent chromium.
The total chromium concentration of trivalent chromium solutions is approximately one-fifth that of
hexavalent chromium solutions. As a result of the chemistry of the trivalent chromium electrolyte,
misting does not occur during plating as it does during hexavalent chromium plating. Use of trivalent
chromium also reduces waste disposal problems and costs.
The disadvantages of the trivalent chromium process are that the process is more sensitive to
contamination than the hexavalent chromium process, and the trivalent chromium process cannot plate
the full range of plate thicknesses that the hexavalent chromium process can. Because it is sensitive to
contamination, the trivalent chromium process requires more thorough rinsing and tighter laboratory
control than does the hexavalent chromium process. Trivalent chromium baths can plate thicknesses
ranging up to 0.13 to 25 ^m (0.005 to 1.0 mils) and, therefore, cannot be used for most hard
chromium plating applications. The hexavalent chromium process can plate thicknesses up to 762 jim
(30 mils).
12.20.1.2 Electroplating-Other Metals -
Brass Electroplating -
Brass, which is an alloy of copper and uzinc, is the most widely used alloy electroplate. Brass
plating primarily is used for decorative applications, but it is also used for engineering applications
such as for plating steel wire cord for steel-belted radial tires. Although all of the alloys of copper
and zinc can be plated, the brass alloy most often used includes 70 to 80 percent copper, with the
balance zinc. Typical brass plating baths include 34 g/L (4.2 oz/gal) of copper cyanide and 10 g/L
(1.3 oz/gal) of zinc cyanide. Other bath constituents include sodium cyanide, soda ash, and ammonia.
Cadmium Electroplating -
Cadmium plating generally is performed in alkaline cyanide baths that are prepared by
dissolving cadmium oxide in a sodium cyanide solution. However, because of the hazards associated
with cyanide use, noncyanide cadmium plating solutions are being used more widely. The primary
noncyanide plating solutions are neutral sulfate, acid fluoborate, and acid sulfate. The cadmium
7/96
Metallurgical Industry
12.20-7
-------
concentration in plating baths ranges from 3.7 to 94 g/L (0.5 to 12.6 oz/gal) depending on the type of
solution. Current densities range from 22 to 970 A/m2 (2 to 90 A/ft2).
Copper Electroplating -
Copper cyanide plating is widely used in many plating operations as a strike. However, its use
for thick deposits is decreasing. For copper cyanide plating, cuprous cyanide must be complexed with
either potassium or sodium to form soluble copper compounds in aqueous solutions. Copper cyanide
plating baths typically contain 30 g/L (4.0 oz/gal) of copper cyanide and either 59 g/L (7.8 oz/gal) of
potassium cyanide or 48 g/L (6.4 oz/gal) of sodium cyanide. Current densities range from 54 to 430
A/m2 (5 to 40 A/ft2). Cathode efficiencies range from 30 to 60 percent
Other types of baths used in copper plating include copper pyrophosphate and copper sulfate
baths. Copper pyrophosphate plating, which is used for plating on plastics and printed circuits,
requires more control and maintenance of the plating baths than copper cyanide plating does.
However, copper pyrophosphate solutions are relatively nontoxic. Copper pyrophosphate plating baths
typically contain 53 to 84 g/L (7.0 to 11.2 oz/gal) of copper pyrophosphate and 200 to 350 g/L (27 to
47 oz/gal) of potassium pyrophosphate. Current densities range from 110 to 860 A/m2 (10 to
80 A/ft2).
Copper sulfate baths, which are more economical to prepare and operate than copper
pyrophosphate baths, are used for plating printed circuits, electronics, rotogravure, and plastics, and for
electroforming and decorative uses. In this type of bath copper and sulfate and sulfuric acid form the
ionized species in solution. Copper sulphate plating baths typically contain 195 to 248 g/L (26 to
33 oz/gal) of copper sulphate and 11 to 75 g/L (1.5 to 10 oz/gal) of sulfuric acid. Current densities
range from 215 to 1,080 A/m2 (20 to 100 A/ft2).
Gold Electroplating -
Gold and gold alloy plating are used in a wide variety of applications. Gold plating solutions
can be classified in five general groups: alkaline gold cyanide, for gold and gold alloy plating; neutral
cyanide gold, for high purity gold plating; acid gold cyanide, for bright hard gold and gold alloy
plating; noncyanide (generally sulfite), for gold and gold plating; and miscellaneous. Alkaline gold
cyanide plating baths contain 8 to 20 g/L (1.1 to 2.7 oz/gal) of potassium gold cyanide and 15 to
100 g/L (2.0 to 13.4 oz/gal) of potassium cyanide. Current densities range from 11 to 86 A/m2 (1.0 to
8 A/ft2) and cathode efficiencies range from 90 to 100 percent.
Neutral gold cyanide plating baths contain 8 to 30 g/L (1.1 to 4.0 oz/gal) of potassium gold
cyanide. Current densities range from 11 to 4,300 A/m2 (1.0 to 400 A/ft2), and cathode efficiencies
range from 90 to 98 percent.
Acid gold cyanide plating baths contain 8 to 16 g/L (1.1 to 2.1 oz/gal) of potassium gold
cyanide. Current densities range from 11 to 4,300 A/m2 (1.0 to 400 A/ft2), and cathode efficiencies
range from 30 to 40 percent.
Indium Electroplating -
In general, indium is electroplated using three types of plating baths: cyanide, sulfamate, and
fluoborate. Indium is the only trivalent metal that can be electrodeposited readily from a cyanide
solution. Cyanide baths are used in applications that require very high throwing power and adhesion.
Indium cyanide plating baths typically contain 33 g/L (4.0 oz/gal) of indium metal and 96 g/L
(12.8 oz/gal) of total cyanide. Current densities range from 162 to 216 A/m2 (15 to 20 A/ft2), and
cathode efficiencies range from 50 to 75 percent.
12.20-8
EMISSION FACTORS
7/96
-------
Indium sulfamate baths are very stable, relatively easy to control, and characterized by a high
cathode efficiency that remains relatively high (90 percent). The plating baths typically contain
105 g/L (14 oz/gal) of indium sulfamate and 26 g/L (3.5 oz/gal) of sulfamic acid. Current densities
range from 108 to 1,080 A/m2 (10 to 100 A/ft2).
Indium fluoborate plating baths typically contain 236 g/L (31.5 oz/gal) of indium fluoborate
and 22 to 30 g/L (2.9 to 4.0 oz/gal) of boric acid. Current densities range from 540 to 1,080 A/m2
(50 to 100 A/ft2), and cathode efficiencies range from 40 to 75 percent.
Nickel Electroplating -
Nickel plating is used for decorative, engineering, and electroforming purposes. Decorative
nickel plating differs from other types of nickel plating in that the solutions contain organic agents,
such as benzene disulfonic acids, benzene trisulfonic acid, naphthalene trisulfonic acid, benzene
sulfonamide, formaldehyde, coumarin, ethylene cyanohydrin, and butynediol. Nickel plating for
engineering applications uses solutions that deposit pure nickel. In nickel plating baths, the total
nickel content ranges from 60 to 84 g/L (8 to 11.2 oz/gal), and boric acid concentrations range from
30 to 37.5 g/L (4 to 5 oz/gal). Current densities range from 540 to 600 A/m2 (50 to 60 A/ft ), and
cathode efficiencies range from 93 to 97 percent.
Palladium and Palladium-Nickel Electroplating -
Palladium plating solutions are categorized as ammoniacal, chelated, or acid. Ammoniacal
palladium plating baths contain 10 to 15 g/L (1.3 to 2.0 oz/gal) of palladium ammonium nitrate or
palladium ammonium chloride, and current densities range from 1 to 25 A/m2 (0.093 to 2.3 A/ft2).
Palladium acid plating baths contain 50 g/L (6.7 oz/gal) of palladium chloride, and current densities
range from 1 to 10 A/m2 (0.093 to 0,93 A/ft).
Palladium alloys readily with other metals, the most important of which is nickel. Palladium
nickel electroplating baths contain 3 g/L (6.7 oz/gal) of palladium metal and 3 g/L (6.7 oz/gal) of
nickel metal.
Platinum Electroplating -
Solutions used for platinum plating are similar to those used for palladium plating. Plating
baths contain 5.0 to 20 g/L (0.68 oz/gal) of either dinitroplatinite sulfate or chloroplatinic acid, and
current densities range from 1 to 20 Aim2 (0.093 to 1.86 A/ft2).
Rhodium Electroplating -
Rhodium plating traditionally has been used as decorative plating in jewelry and silverware.
However, the use of rhodium plating for electronics and other industrial applications has been
increasing in recent years. For decorative plating, rhodium baths contain 1.3 to 2.0 g/L (0.17 to
0.27 oz/gal) of rhodium phosphate or rhodium sulfate concentrate and 25 to 80 ml/L (3.0 to 11 oz/gal)
of phosphoric or sulfuric acid. Current densities typically range from 20 to 100 A/m2 (1.86 to
9.3 A-ft2). For industrial and electronic applications, rhodium plating baths contain approximately
5.0 g/L (0.67 oz/gal) of rhodium metal as sulfate concentrate and 25 to 50 ml/L (3.0 to 7.0 oz/gal) of
sulfuric acid. Current densities typically range from 10 to 30 A/m2 (0.93 to 2.79 A-ft2), and cathode
efficiency ranges from 70 to 90 percent with agitation or 50 to 60 percent without agitation.
Ruthenium Electroplating -
Electroplated ruthenium is a very good electrical conductor and produces a very hard deposit.
Typical plating baths contain approximately 5.3 g/L (0.71 oz/gal) of ruthenium as sulfamate or nitrosyl
7/96
Metallurgical Industry
12.20-9
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sulfamate and 8.0 g/L (1.1 oz/gal) of sulfamic acid. Current densities typically range from 108 to
320 A/m2 (10 to 30 A-ft2), and cathode efficiency is typically about 20 percent.
Silver Electroplating -
Silver plating traditionally has been performed using a cyanide-based plating solution.
Although some noncyanide solutions have been developed, due to various shortcomings, cyanide
solutions still are commonly used. Typical plating baths contain 5.0 to 40 g/L (0.67 to 5.3 oz/gal) of
silver as potassium silver cyanide and 12 to 120 g/L (1.6 to 16 oz/gal) of potassium cyanide. Current
densities typically range from 11 to 430 A/m2 (1 to 40 A-ft2).
Tin-Lead, Lead, and Tin Electroplating -
Fluoborate and fluoboric acid can be used to plate all percentages of tin and lead. Alloys of
tin and lead are most commonly used for plating in the proportions of 60 percent tin and 40 percent
lead. Tin-lead plating baths typically contain 52 to 60 g/L (7.0 to 8.0 oz/gal) of stannous tin, 23 to
30 g/L (3.0 to 4.0 oz/gal) of lead, 98 to 150 g/L (13 to 20 oz/gal) of fluoboric acid, and 23 to 38 g/L
(3.0 to 5.0 oz/gal) of boric acid. Current densities typically range from 270 to 380 A/m2 (25 to
35 A-ft2).
Lead fluoborate plating baths typically contain 340 to 410 g/L (45 to 55 oz/gal) of lead
fluoborate, 195 to 240 g/L (26 to 32 oz/gal) of lead, 15 to 30 g/L (2.0 to 4.0 oz/gal) of fluoboric acid,
and 23 to 38 g/L (3.0 to 5.0 oz/gal) of boric acid. Current densities typically range from 215 to
750 A/m2 (20 to 70 A-ft2).
Tin plating generally is performed using one of three types of plating solutions (stannous
fluoborate, stannous sulfate, or sodium or potassium stannate) or by the halogen tin process. Stannous
fluoborate plating baths include 75 to 110 g/L (10 to 15 oz/gal) of stannous fluoborate, 30 to 45 g/L
(4,0 to 6.0 oz/gal) of tin, 190 to 260 g/L (25 to 35 oz/gal) of fluoboric acid, and 23 to 38 g/L (3.0 to
5.0 oz/gal) of boric acid. Current densities typically range from 215 to 270 A/m2 (20 to 25 A-ft2),
and cathode efficiencies are greater than 95 percent.
Stannous sulfate plating baths include 15 to 45 g/L (2.0 to 6.0 oz/gal) of stannous sulfate, 7.5
to 22.5 g/L (1.0 to 3.0 oz/gal) of stannous tin, and 135 to 210 g/L (18 to 28 oz/gal) of sulfuric acid.
Current densities typically range from 10 to 270 A/m2 (1 to 25 A-ft2), and cathode efficiencies are
greater than 95 percent.
Sodium/potassium stannate plating baths include 90 to 180 g/L (12 to 24 oz/gal) of sodium
stannate or 100 to 200 g/L (13 to 27 oz/gal) of potassium stannate and 40 to 80 g/L (5.3 to 11 oz/gal)
of tin metal. Current densities typically range from 10 to 1,080 A/m2 (1 to 100 A-ft2).
Tin-Nickel Electroplating -
Tin-nickel alloy plating is used in light engineering and electronic applications and is used as
an alternative to decorative chromium plating. Tin-nickel fluoride plating baths contain 49 g/L (6.5
oz/gal) of stannous chloride anhydrous, 300 g/L (40 oz/gal) of nickel chloride, and 56 g/L (7.5 oz/gal)
of ammonium bifluoride. Current densities are typically about 270 A/m2 (25 A-ft2).
Tin-nickel pyrophosphate plating baths contain 28 g/L (3.2 oz/gal) of stannous chloride,
31 g/L (4.2 oz/gal) of nickel chloride, and 190 g/L (26 oz/gal) of potassium pyrophosphate. Current
densities range from 52 to 150 A/m2 (4.8 to 14 A-ft2).
12.20-10
EMISSION FACTORS
7/96
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Zinc Electroplating -
The most widely used zinc plating solutions are categorized as acid chloride, alkaline
noncyanide, and cyanide. The most widely used zinc alloys for electroplating are zinc-nickel, zinc-
cobalt, and zinc-iron. Zinc plating baths contain 15 to 38 g/L (2,0 to 5,0 oz/gal) of acid chloride zinc,
6,0 to 23 g/L (0.80 to 3.0 oz/gal) of alkaline noncyanide zinc, or 7.5 to 34 g/L (1.0 to 4.5 oz/gal) of
cyanide zinc.
Acid zinc-nickel plating baths contain 120 to 130 g/L (16 to 17 oz/gal) of zinc chloride and
110 to 130 g/L (15 to 17 oz/gal) of nickel chloride. Alkaline zinc-nickel plating baths contain 8.0 g/L
(1,1 oz/gal) of zinc metal and 1.6 g/L (0.21 oz/gal) of nickel metal. Current densities range from 5.0
to 40 A/m2 (0,46 to 3,7 A-ft2) and 20 to 100 A/m2 (1.9 to 9.3 A/ft2) for acid and alkaline baths,
respectively.
Acid zinc-cobalt plating baths contain 30 g/L (4.0 oz/gal) of zinc metal and 1.9 to 3.8 g/L
(0.25 to 0,51 oz/gal) of cobalt metal. Alkaline zinc-cobalt plating baths contain 6,0 to 9.0 g/L (0.80 to
1.2 oz/gal) of zinc metal and 0.030 to 0.050 g/L (0.0040 to 0,0067 oz/gal) of cobalt metal. Current
densities range from 1.0 to 500 A/m2 (0.093 to 46 A-ft2) and 20 to 40 A/m2 (1.9 to 3.7 A/ft2) for acid
and alkaline baths, respectively.
Acid zinc-iron plating baths contain 200 to 300 g/L (27 to 40 oz/gal) of ferric sulfate and 200
to 300 g/L (27 to 40 oz/gal) of zinc sulfate. Alkaline zinc-iron plating baths contain 20 to 25 g/L (2.7
to 3.3 oz/gal) of zinc metal and 0.25 to 0.50 g/L (0.033 to 0,067 oz/gal) of iron metal. Current
densities range from 15 to 30 A/m2 (1.4 to 2.8 A-ft2).
12.20.2 Emissions and Controls2"3,43"44
Plating operations generate mists due to the evolution of hydrogen and oxygen gas. The gases
are formed in the process tanks on the surface of the submerged part or on anodes or cathodes. As
these gas bubbles rise to the surface, they escape into the air and may carry considerable liquid with
them in the form of a fine mist. The rate of gassing is a function of the chemical or electrochemical
activity in the tank and increases with the amount of work in the tank, the strength and temperature of
the solution, and the current densities in the plating tanks. Air sparging also can result in emissions
from the bursting of air bubbles at the surface of the plating tank liquid.
Emissions are also generated from surface preparation steps, such as alkaline cleaning, acid
dipping, and vapor degreasing. These emissions are in the form of alkaline and acid mists and solvent
vapors. The extent of acid misting from the plating processes depends mainly on the efficiency of the
plating bath and the degree of air sparging or mechanical agitation. For many metals, plating baths
have high cathode efficiencies so that the generation of mist is minimal. However, the cathode
efficiency of chromium plating baths is very low (10 to 20 percent), and a substantial quantity of
chromic acid mist is generated. The following paragraphs describe the methods used to control
emissions from chromium electroplating. These methods generally apply to other types of plating
operations as well.
Emissions of chromic acid mist from the electrodeposition of chromium from chromic acid
plating baths occur because of the inefficiency of the hexavalent chromium plating process. Only
about 10 to 20 percent of the current applied actually is used to deposit chromium on the item plated;
the remaining 80 to 90 percent of the current applied is consumed by the evolution of hydrogen gas at
the cathode with the resultant liberation of gas bubbles. Additional bubbles are formed at the anode
7/96
Metallurgical Industry
12.20-11
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due to the evolution of oxygen. As the bubbles burst at the surface of the plating solution, a fine mist
of chromic acid droplets is formed.
The principal techniques used to control emissions of chromic acid mist from decorative and
hard chromium plating and chromic acid anodizing operations include add-on control devices and
chemical fiime suppressants. The control devices most frequently used are mist eliminators and wet
scrubbers that are operated at relatively low pressure drops. Because of the corrosive properties of
chromic acid, control devices typically are made of polyvinyl chloride (PVC) or fiberglass.
Chemical fume suppressants are added to decorative chromium plating and chromic acid
anodizing baths to reduce chromic acid mist. Although chemical agents alone are effective control
techniques, many plants use them in conjunction with an add-on control device.
Chevron-blade and mesh-pad mist eliminators are the types of mist eliminators most frequently
used to control chromic acid mist. The most important mechanism by which mist eliminators remove
chromic acid droplets from gas streams is the inertial impaction of droplets onto a stationary set of
blades or a mesh pad. Mist eliminators typically are operated as dry units that are periodically washed
down with water to clean the impaction media.
The wet scrubbers typically used to control emissions of chromic acid mist from chromium
plating, and chromic acid anodizing operations are single and double packed-bed scrubbers. Other
scrubber types used less frequently include fan-separator packed-bed and centrifugal-flow scrubbers.
Scrubbers remove chromic acid droplets from the gas stream by humidifying the gas stream to increase
the mass of the droplet particles, which are then removed by impingement on a packed bed.
Once-through water or recirculated water typically is used as the scrubbing liquid because chromic
acid is highly soluble in water.
Chemical fume suppressants are surface-active compounds that are added directly to chromium
plating and chromic acid anodizing baths to reduce or control misting. Fume suppressants are
classified as temporary or as permanent. Temporary fume suppressants are depleted mainly by the
decomposition of the fume suppressant and dragout of the plating solution, and permanent fume
suppressant are depleted mainly by dragout of the plating solution. Fume suppressants include wetting
agents that reduce misting by lowering the surface tension of the plating or anodizing bath, foam
blankets that entrap chromic acid mist at the surface of the plating solution, or combinations of both a
wetting agent and foam blanket Polypropylene balls, which float on the surface of the plating baths,
also are used as a fume suppressant in chromium plating tanks.
National emission standards to regulate chromium emissions from new and existing hard and
decorative chromium electroplating and chromium anodizing tanks at major and area sources were
promulgated on January 25, 1995 (60 FR 4948). The regulation requires limits on the concentration of
chromium emitted to the atmosphere (or alternative limits on the surface tension of the bath for
decorative chromium electroplating and anodizing tanks) and specifies work practice standards, initial
performance testing, ongoing compliance monitoring, recordkeeping, and reporting requirements.
Table 12.20-1 presents the emission factors for chromium electroplating. The emission factors
are based on total energy input and are presented in units of grains per ampere-hour (grains/A-hr). For
controlled emissions from chromium electroplating operations, each of the add-on control devices used
in the industry generally achieves a narrow range of outlet concentrations of chromium, regardless of
the level of energy input. For this reason, total energy input may not be an appropriate basis for
establishing emission factors for this industry. Therefore, the factors for chromium electroplating tanks
12.20-12
EMISSION FACTORS
7/96
-------
in Table 12.20-1 are presented both as concentrations and in units of total energy input. Emission
rates for controlled emissions should be estimated using the concentration factors and typical exhaust
flow rates for the particular type of exhaust system in question. The factors for controlled emissions
based on total energy input should only be used in the absence of site-specific information.
Table 12.20-2 presents emission factors for chromic acid anodizing. The emission factors are
presented in units of grains per hour per square foot (grains/hr-ft2) of tank surface area. Table 12.20-3
presents particle size distributions for hard chromium electroplating. Table 12.20-4 presents emission
factors for the plating of metals other than chromium.
Emissions from plating operations other than chromium electroplating can be estimated using
the emission factors and operating parameters for chromium electroplating. Equation 1 below
provides an estimate of uncontrolled emissions from nonchromium plating tanks.
EF,„ = 3.3 X 10-' X (EE,„/em) X C„ X D„, (1)
where:
EFm = emission factor for metal "m", grains/dscf;
EEm = electrochemical equivalent for metal "m", A-hr/mil-ft2;
em = cathode efficiency for metal "m", percent;
Cm = bath concentration for metal "m", oz/gal; and
Dm = current density for metal "m", A/ft2.
Equation 2 below provides an estimate of controlled emissions from nonchromium plating tanks.
EFm = 0.028 x EFCr x Cm (2)
where EFm and Cin are as defined above, and
EFCr = emission factor for controlled hard chromium electroplating emissions, grains/dscf.
Equations 1 and 2 estimate emissions from the formation of gas as a result of the electrical
energy applied to the plating tank; the equations do not account for additional emissions that result
from air sparging or mechanical agitation of the tank solution. To estimate uncontrolled emissions due
to air sparging, the following equation should be used:
T).5
Ej = 100 k[R^
(1 - 2a + 9a2)05 + (a - 1)
(1 + 3a) - (1
2a + 9a2)05
(3)
6-45 Rb . 56.7 a ,
a = — k, = — k2
1.79 x 10' 0
(Pi - P.) g
7/96
Metallurgical Industry
12.20-13
-------
where:
Ej = emission factor, grains/bubble;
Rb = average bubble radius, in.;
a = surface tension of bath, pounds force per foot (lbj/ft);
es = speed of sound, ft/sec;
pj = density of liquid, lb/ft3;
pg = density of gas (air), lb/ft3; and
g = acceleration due to gravity, ft/sec2.
Pi
(4)
where:
0.072 R2
a =
o
E2 = emission factor in grains/ft3 of aeration air; and
the other variables are as defined previously.
Substituting typical values for constants cs (1,140 ft/sec), g (32.2 ft/see ), and assuming values for
of 62.4 lb/ft3 and for pg of 0.0763 lb/ft3, Equation 3 can be reduced to the following equation;
T>.5
1.9 o
~WT
(1 - 2a + 9a2)0 5 + (a - 1)
(1 + 3a) - (1 - 2a + 9a2)0 5
Equations 3 and 4 also can be used to estimate emissions from electroless plating operations.
It should be noted that Equations 1 thorough 4 have not been validated using multiple emission tests
and should be used cautiously. Furthermore, the emission factors that are calculated in units of
concentration may not be applicable to plating lines in which there are multiple tanks that introduce
varying amounts of dilution air to a common control device. Finally, Equation 1 does not take into
account the emissions reductions achieved by using fume suppressants. If a fume suppressant is used,
the corresponding emission factor for hard chromium plating with fume suppressant control should be
used with Equation 2 to estimate emissions. Alternately, Equation 1 can be used and the resulting
emissions can be reduced using an assumed control efficiency for hard or decorative chromium
electroplating, depending upon which type of plating operation is more similar to the type of plating
conducted. The control efficiencies for chemical fume suppressants are 78 percent for hard chromium
electroplating controlled and 99.5 percent for decorative chromium plating. Based on the requirements
for the chromium electroplating national emission standard, emissions from decorative chromium
plating baths with chemical fume suppressants are considered to be controlled if the resulting surface
tension is no more than 45 dynes per centimeter (dynes/cm) (3.1 x 10"3 pound-force per foot Pbj/ft]).
Emissions chromium electroplating operations are regulated under the 40 CFR part 63,
subpart N, National Emission Standards for Chromium Emissions From Hard and Decorative
Chromium Electroplating and Chromium Anodizing Tanks. These standards, which were promulgated
on January 25, 1995 (60 FR 4963), limit emissions of total chromium to 0.03 milligrams per dry
standard cubic meter (mg/dscm) (1.3 x 10 5 grains/dscf) from plating tanks at small, hard chromium
electroplating facilities; and to 0.015 mg/dscm (6.6 x 10"6 grains/dscf) from all other hard chromium
plating tanks. Small, hard chromium plating facilities are defined in the rule as those which have a
maximum cumulative rectifier capacity of less than 60 million amp-hr/yr. Total chromium emissions
from decorative chromium plating tanks and chromic acid anodizing tanks are limited to 0.01 mg/dscm
(4.4 x 10"6 grains/dscf), unless a fume suppressant is used and the bath surface tension is maintained
at no more than 45 dynes/cm (3.1 x 10"3 lb/ft).
12.20-14 EMISSION FACTORS 7/96
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Table 12.20-1. EMISSION FACTORS FOR CHROMIUM ELECTROPLATING3
Process
Chromium Compounds1'
EMISSION
FACTOR
RATING
Total PMC
EMISSION
FACTOR
RATING
grains/A-hr
grains/dscf
grains/A-hr
grains/dscf
Hard chromium electroplating*1
(SCC 3-09-010-18)
0.12
NA
B
0.25
NA
C
- with moisture extractor6
NA
0.00014
D
NA
0.00028
E
-- with polypropylene balls'
NA
0.00042
D
NA
0.00088
E
— with fume suppressant®
NA
0.00016
D
NA
0.00034
E
-- with fume suppressant and
polypropylene balls'1
NA
3.0 x 10~s
D
NA
6.3 x 10"5
E
-- with packed-bed scrubber1
NA
2.1 x 10-5
D
NA
4.4 x 10"5
E
— with packed-bed scrubber, fume
suppressant, and polypropylene
balls'1
NA
2.6 x 10"6
D
NA
5.5 x 10~6
E
— with chevron-blade mist
eliminator1"
NA
8.8 x 10~5
D
NA
0.00018
E
- with mesh-pad mist eliminate!*
NA
1.2 x 10"5
D
NA
2.6 x 10"5
E
— with packed-bed scrubber and
mesh-pad eliminator1'
NA
3.2 x 10~8
E
NA
6.7 x 10~8
E
— with composite mesh-pad mist
eliminator''
NA
3.8 x 10"6
D
NA
8.0 x 10~6
E
Decorative chromium c!ectroplatingr
(SCC 3-09-010-28)
0.033
NA
D
0.069
NA
E
-- with fume suppressant*
NA
1.2 x 10*6
D
NA
2.5 x 10"6
E
a For chromium electroplating tanks only. Factors represent uncontrolled emissions unless otherwise
noted. Emission factors based on total energy input in units of grains per ampere-hour
(grains/A-hr) and based on concentrations in units of grains per dry standard cubic foot
(grains/dscf). To convert from grains/A-hr to mg/A-hr multiply by 64.8. To convert grains/dscf to
mg/dscm, multiply by 2,290. To convert grains/A-hr to grains/dscf, multiply by 0.01. To convert
grains/dscf to grains/A-hr multiply by 100. Note that there is considerable uncertainty in these
latter two conversion factors because of differences in tank geometry, ventilation, and control device
performance. For controlled emissions, factors based on concentration should be used whenever
possible. SCC = Source Classification Code. NA = units not applicable.
b Comprised almost completely of hexavalcnt chromium.
c Total PM includes filterable and condensible PM. However, condensible PM is likely to be
negligible. All PM from chromium electroplating sources is likely to be emitted as PM-10. Factors
estimated based on assumption that PM consists entirely of chromic acid mist.
d References 5-13,15,17-18,23-25,28,34.
e References 8,14.
f Reference 10.
8 Reference 15,
h References 18,23-25.
J References 11-13,18,32,34-35.
k References 18, 40-42.
m References 5-7.
11 References 8-10,21,28.
p Reference 37.
q References 11-13.
r References 19-20,25-26.
s References 20, 25-26.
7/96
Metallurgical Industry
12.20-15
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Tabic 12.20-2. EMISSION FACTORS FOR CHROMIC ACID ANODIZING*
Process
Chromium
Compounds,1*
grains/hr-ft
EMISSION
FACTOR
RATING
Total PM,C
grains/hr-ft2
EMISSION
FACTOR
RATING
Chromic acid anodizing''
(SCC 3-09-010-38)
2.0
D
4.2
E
- with polypropylene balls6
1.7
D
3.6
E
- with fume suppressant
0.064
D
0.13
E
- with fume suppressant and
polypropylene balls8
0.025
D
0.053
E
- with packed-bed scrubber11
0.0096
D
0.020
E
- with packed-bed scrubber and
fume suppressant'1
0.00075
D
0.0016
E
- with mesh-pad mist eliminator*
0.0051
E
0.011
E
- with packed-bed scrubber and
mesh pad mist eliminator"1
0.00054
D
0.0011
E
- with wet scrubber, moisture
extractor, and high efficiency
particulate air filter11
0.00048
D
0.0010
E
a For chromium electroplating tanks only. Factors represent uncontrolled emissions unless otherwise
noted. Factors are in units of grains per hour per square foot (grains/hr-ft2) of tank surface area.
SCC = Source Classification Code. To convert from grains/hr-ft2 to mg/hr-m2, multiply by 0.70.
b Comprised almost completely of hexavalent chromium.
c Total PM includes filterable and condensible PM. However, condensible PM is likely to be
negligible. All PM from chromium electroplating sources is likely to be emitted as PM-10. Factors
estimated based on assumption that PM consists entirely of chromic acid mist.
d References 27,29-30,33,42.
e Reference 30.
f References 27,29-30.
8 References 27,30.
h References 33,39.
J Reference 36.
k Reference 21.
m Reference 37.
n Reference 42.
12.20-16
EMISSION FACTORS
7/96
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Table 12.20-3. SUMMARY OF PARTICLE SIZE DISTRIBUTIONS FOR CHROMIUM
ELECTROPLATING3
Uncontrolled
Controlledb
Diameter,
|im
Cumulative Percent Less Than
Diameter,
|am
Cumulative Percent Less Than
Total PMC
Chromium
Compounds'1
Total PMC
Chromium
Compounds'3
<0.5
0
0
<0.49
0
0
0.5
9.1
6.9
0.49
18.5
20.4
2.4
48.3
67.7
2.35
94.7
97.5
8.0
59.3
82.6
7.9
100
99.2
3 Reference 6. Based on C-rated emission data for hard chromium electroplating tanks. Source
Classification Code 3-09-010-18.
b Controlled with chevron-blade mist eliminators.
c Total PM consists of filterable and condensible PM. However, condensible PM is likely to be
negligible.
d Comprised almost completely of hexavalent chromium.
Table 12.20-4. EMISSION FACTORS FOR ELECTROPLATING-OTHER METALS3
EMISSION FACTOR RATING: E
Source
Pollutant
Emission Factor
Ref.
grains/A-hr
grains/dscf
Copper cyanide electroplating tank with mesh-pad mist
eliminator
(SCC 3-09-010-42)
Cyanide
NA
2.7 x 10"6
21
Copper sulfate electroplating tank with wet scrubber
(SCC 3-09-010-45)
Copper
NA
8.1 x 10"5
31
Cadmium cyanide electroplating tank
(SCC 3-09-010-52)
Cadmium
0.040
NA
31
- with mesh-pad mist eliminator
Cyanide
NA
0.00010
21
- with mesh-pad mist eliminator
Cadmium
NA
1.4 x 10-7
21
- with packed-bed scrubber
Cyanide
NA
5.9 x lO-5
22
- with packed-bed scrubber
Cadmium
NA
1.7 x 10"6
22, 31
- with packed-bed scrubber
Ammonia
NA
4.2 x 10"5
22
Nickel electroplating tank
(SCC 3-09-010-68)
Nickel
0.63
NA
31
- with wet scrubber
Nickel
NA
6.7 x 10"6
31
3 Factors represent uncontrolled emissions unless noted. All emission factors in units of grains per
ampere-hour (grains/A-hr) and as concentrations in units of grains per dry standard cubic foot
(grains/dscf). To convert from grains/A-hr to mg/A-hr multiply by 64.8. To convert grains/dscf to
mg/dscm, multiply by 2,290. To convert grains/A-hr to grains/dscf, multiply by 0.01. To convert
grains/dscf to grains/A-hr multiply by 100. Note that there is considerable uncertainty in these latter
two conversion factors because of differences in tank geometry, ventilation, and control device
performance. SCC = Source Classification Code. NA = units not applicable.
7/96
Metallurgical Industry
12.20-17
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REFERENCES FOR SECTION 12.20
1. Horner, J., "Electroplating", Kirk-Othmer Encyclopedia Of Chemical Technology, 4th Ed., Volume
No. 9, John Wiley and Sons, Inc., New York, NY, 1994.
2. Locating And Estimating Air Emissions From Sources Of Chromium (Supplement), EPA
450/2-89-002, U. S. Environmental Protection Agency, Research Triangle Park, NC, August 1989.
3. Chromium Emissions From Chromium Electroplating And Chromic Acid Anodizing Operations-
Background Information For Proposed Standards, EPA 453/R-93-030a, U. S. Environmental
Protection Agency, Research Triangle Park, NC, July 1993.
4. Metal Finishing Guidebook And Directory Issue '93k, Volume 91, Issue 1A, Elsevier Science
Publishing Company, Inc., New York, NY, January 1993.
5. Chromium Electroplaters Test Report: Greensboro Industrial Platers, Greensboro, NC, Entropy
Environmentalists, Inc., Research Triangle Park, NC, Prepared for U. S. Environmental Protection
Agency, Research Triangle Park, NC, EMB Report 86-CEP-l, March 1986.
6. Chromium Electroplaters Test Report: Consolidated Engravers Corporation, Charlotte, NC,
Peer Consultants, Inc., Rockville, MD, Prepared for U. S. Environmental Protection Agency,
Research Triangle Park, NC, EMB Report 87-CEP-9, May 1987.
7. Chromium Electroplaters Test Report: Able Machine Company, Taylors, SC, PEI Associates,
Inc., Cincinnati, OH, Prepared for U. S. Environmental Protection Agency, Research Triangle
Park, NC, EMB Report 86-CEP-3, June 1986.
8. Chromium Electroplaters Test Report: Roll Technology Corporation, Greenville, SC, Peer
Consultants, Dayton, OH, Prepared for U. S. Environmental Protection Agency, Research Triangle
Park, NC, EMB Report 88-CEP-13, August 1988.
9. Chromium Electroplaters Test Report: Precision Machine And Hydraulic, Inc., Worthington, WV,
Peer Consultants, Dayton, OH, Prepared for U. S. Environmental Protection Agency, Research
Triangle Park, NC, EMB Report 88-CEP-14, September 1988.
10. Chromium Electroplaters Test Report: Hard Chrome Specialists, York, PA, Peer Consultants,
Dayton, OH, Prepared for U. S. Environmental Protection Agency, Research Triangle Park, NC,
EMB Report-89-CEP-15, January 1989.
11. Chromium Electroplaters Test Report: Piedmont Industrial Platers, Statesville, NC, Entropy
Environmentalists, Inc., Research Triangle Park, NC, Prepared for U. S. Environmental Protection
Agency, Research Triangle Park, NC, EMB Report 86-CEP-04, September 1986.
12. Chromium Electroplaters Test Report: Steel Heddle, Inc., Greenville, SC, PEI Associates, Inc.,
Cincinnati, OH, Prepared for U. S. Environmental Protection Agency, Research Triangle Park,
NC, EMB Report 86-CEP-2, June 1986.
13. Chromium Electroplaters Test Report: Fusion, Inc., Houston, TX, Peer Consultants, Inc., Dayton,
OH, Prepared for U. S. Environmental Protection Agency, Research Triangle Park, NC, EMB
Report 89-CEP-16, May 1989.
14. Hexalavent Chromium Emission Test Report: Precision Engineering, Seattle, WA, Advanced
Systems Technology, Atlanta, GA, Prepared for U. S. Environmental Protection Agency, Research
Triangle Park, NC, EMB Report 91-CEP-18, December 1991.
12.20-18
EMISSION FACTORS
7/96
-------
15. Emission Test Report: Emission Test Results For Total Chromium Inlet And Outlet Of The South
Fume Scrubber, Monroe Auto Equipment, Hartwell, GA, IEA, Research Triangle Park, NC,
Report No. 192-92-25, February 1992.
16. Chromium Electroplaters Emission Test Report: Remco Hydraulics, Inc., Willits, CA, Advanced
Systems Technology, Atlanta, GA, Prepared for U. S. Environmental Protection Agency, Research
Triangle Park, NC, EMB Report 91-CEP-17, June 1991.
17. NESHAP Screening Method Chromium, Emission Test Report, Roll Technology Corporation,
Greenville, SC, EMB Report No. 87-CEP-6, U. S. Environmental Protection Agency, Research
Triangle Park, NC, September 1987.
18. Chromium Electroplating Emissions Comparison Test: Electric Chromic And Grinding Company,
Santa Fe Springs, CO, Prepared for U. S. Environmental Protection Agency, Research Triangle
Park, NC, EMB Report 91-CEP-20, February 1992.
19. Chromium Electroplaters Test Report: CMC Delco Products Division, Livonia, MI, Peer
Consultants, Inc., Dayton, OH, Prepared for U. S. Environmental Protection Agency, Research
Triangle Park, NC, EMB Report 89-CEP-7, March 1987.
20. Chromium Electroplaters Test Report: Automatic Die Casting Specialties, Inc., St. Clair Shores,
MI, Prepared for II. S. Environmental Protection Agency, Research Triangle Park, NC, EMB
Report 89-CEP-l 1, April 1988.
21. NEESA 2-J65, Chromium, Cyanide, And Cadmium Emission Tests Results, Building 604 Plating
Facility, Source Identification 10-PEN17008406, Naval Aviation Depot, Pensacola, Naval Energy
and Environmental Support Activity, Port Hueneme, CA, January 1991.
22. Charles K. Yee, Source Emissions Tests at Buildings 604 and 3557 at Naval Air Rework Facility,
Pensacola, Florida, Navy Environmental Support Office, Port Hueneme, CA, September 1980.
23. Test Results For Fume Suppressant Certification, M&T Chemical's Fumetrol 101 In Hard
Chrome Plating Tanks, Pacific Environmental Services, Inc., Arcadia, CA, November 1, 1989.
24. Test Results For Fume Suppressant Certification, OMI International Corporation's Foam-Lok L
In Hard Chrome Plating Tanks, Pacific Environmental Services, Inc., Arcadia, CA, November 17,
1989.
25. Test Results For Fume Suppressant Certification, McGean Rohco's Dis Mist NP In Decorative
Chrome Plating Tanks, Pacific Environmental Services, Inc., Arcadia, CA, March 16, 1990.
26. Test Results For Fume Suppressant Certification, Omi International's Zero-Mist In Decorative
Chrome Plating Tanks, Pacific Environmental Services, Inc., Arcadia, CA, July 13, 1990.
27. Test Results For Fume Suppressant Certification, Autochem, Inc., M&T's Fumetrol 101 In
Chrome Anodizing Tanks, Pacific Environmental Services, Inc., Arcadia, CA, March 1990.
28. William E. Powers and Seth Forester, Source Emission Testing Of The Building 195 Plating Shop
At Norfolk Naval Shipyard, Portsmouth, VA, 11-18 March 1985, Naval Energy and
Environmental Support Activity, Port Hueneme, CA, May 1985.
29. Efficiency Of Harshaw Chemical's MSP-ST For Controlling Chrome Emissions From A Chromic
Acid Anodizing Tank, Pacific Environmental Services, Arcadia, CA, March 16, 1989.
7/96
Metallurgical Industry
12.20-19
-------
30. Report of Hexavalent Chromium Emission Testing On The Chromic Acid Anodizing And Tri-Acid
Etching Processes At Buildings 3 And 5, Douglas Aircraft Company, Long Beach, CA,
Engineering-Science, Pasadena, CA, September 14, 1989.
31. Air Toxics Sampling Report Deutsch Engineered Connecting Devices, Oceanside, California,
Kleinfelder, Inc., San Diego, CA, June 28, 1991
32. Emission Test Results for Chromium Emission Rate of the Scrubber inlet at the U.S. Chrome
Corporation Facility, Batavia, New York, IE A, Research Triangle Park, NC, November 11, 1991.
33. Source Test Report for Total Chromium and Hexavalent Chromium From Chromic Acid
Anodizing, General Dynamics-Convair, Lindbergh Field Facility, Building #1, TEAM
Environmental Services, Inc., San Marcos, CA, March 24, 1993.
34. Source Emission Evaluation, Hytek Finishes Company, Chrome Abatement Equipment
Performance Evaluation, Kent, Washington, May 18-19, 1989, Am Test, Inc., Redmond, WA,
July 14, 1989
35. Measurement of Hexavalent Chromium Emissions From Hard Chrome Plating Operations at
Multichrome Company, Inc., Pacific Environmental Services, Inc., Baldwin Park, CA, January 29,
1993.
36. Measurement of Chromium Emissions From Chromic Acid Anodizing Operations In Building 2 At
Naval Aviation Depot, North Island, San Diego, CA, Bcnmol Corporation, San Diego, CA,
October 29, 1991.
37. Measurement of Chromium Emissions From Chromic Acid Anodizing Operations In Building 2 At
Naval Aviation Depot, San Diego, CA, Pacific Environmental Services, Inc., Baldwin Park, CA,
April 8, 1992.
38. NEESA 2-197, Chromium Emission Tests Results, Building 32 Plating Facility, BAAQMD
Authority To Construct: 574, Naval Aviation Depot, Alameda, Naval Energy and Environmental
Support Activity, Port Hueneme, CA, August 1992.
39. Measurement of Chromium Emissions From Chromic Acid Anodizing Operations In Building 2 At
Naval Aviation Depot, San Diego, CA, Pacific Environmental Services, Inc., Baldwin Park, CA,
August 15, 1991.
40. Compliance Test Procedure, Pacific Hard Chrome, Tests Conducted December 3, 1991, Chemical
Data Management Systems, Dublin, CA, January 2, 1991.
41. Compliance Test Results, Babbitt Bearing, Test Date May 27, 1992, Chemical Data Management
Systems, Dublin, CA, 1992.
42. Source Test Measurement Of Chromium Emissions From Chromic Acid Anodizing Tanks At
Boeing Fabrication, 700 15th Street, S.W., Auburn, WA, Pacific Environmental Services, Inc.,
Baldwin Park, CA, September 24, 1991.
43. Emission Factor Documentation for AP-42, Section 12-20, Electroplating, U. S. Environmental
Protection Agency, Research Triangle Park, NC, May 1996.
12,20-20
EMISSION FACTORS
7/96
-------
44. D.S. Azbel, S.L. Lee, and T.S. Lee, Acoustic Resonance Theory For The Rupture of Film Cap Of
A Gas Bubble At A Horizontal Gas-Liquid Interface, Two-Phase Momentum, Heat and Mass
Transfer in Chemical, Process, and Energy Engineering Systems, Volume 1, F. Durst,
G.V. Tsiklauri, and N.H. Afgan, Editors, Hemisphere Publishing Company, Washington, 1979.
7/96
Metallurgical Industry
12.20-21
-------
13.1 Wildfires And Prescribed Burning
13.1.1 General1
A wildfire is a large-scale natural combustion process that consumes various ages, sizes, and
types of flora growing outdoors in a geographical area. Consequently, wildfires are potential sources
of large amounts of air pollutants that should be considered when trying to relate emissions to air
quality.
The size and intensity, even the occurrence, of a wildfire depend directly on such variables as
meteorological conditions, the species of vegetation involved and their moisture content, and the
weight of consumable fuel per acre (available fuel loading). Once a fire begins, the dry combustible
material is consumed first. If the energy release is large and of sufficient duration, the drying of
green, live material occurs, with subsequent burning of this material as well. Under proper
environmental and fuel conditions, this process may initiate a chain reaction that results in a
widespread conflagration.
The complete combustion of wildland fuels (forests, grasslands, wetlands) require a heat flux
(temperature gradient), adequate oxygen supply, and sufficient burning time. The size and quantity of
wildland fuels, meteorological conditions, and topographic features interact to modify the burning
behavior as the fire spreads, and the wildfire will attain different degrees of combustion efficiency
during its lifetime.
The importance of both fuel type and fuel loading on the fire process cannot be
overemphasized. To meet the pressing need for this kind of information, the U. S. Forest Service is
developing a model of a nationwide fuel identification system that will provide estimates of fuel
loading by size class. Further, the environmental parameters of wind, slope, and expected moisture
changes have been superimposed on this fuel model and incorporated into a National Fire Danger
Rating System (NFDRS). This system considers five classes of fuel, the components of which are
selected on the basis of combustibility, response of dead fuels to moisture, and whether the living
fuels are herbaceous (grasses, brush) or woody (trees, shrubs).
Most fuel loading figures are based on values for "available fuel", that is, combustible
material that will be consumed in a wildfire under specific weather conditions. Available fuel values
must not be confused with corresponding values for either "total fuel" (all the combustible material
that would burn under the most severe weather and burning conditions) or "potential fuel" (the larger
woody material that remains even after an extremely high intensity wildfire). It must be emphasized,
however, that the various methods of fuel identification are of value only when they are related to the
existing fuel quantity, the quantity consumed by the fire, and the geographic area and conditions
under which the fire occurs.
For the sake of conformity and convenience, estimated fuel loadings estimated for the
vegetation in the U. S. Forest Service Regions are presented in Table 13.1-1. Figure 13.1-1
illustrates these areas and regions.
10/96
Miscellaneous Sources
13.1-1
-------
Table 13.1-1 (Metric And English Units). SUMMARY OF ESTIMATED FUEL CONSUMED BY
WILDFIRES"
Estimated Average Fuel Loading
National Region1*
Mg/hectare
ton/acre
Rocky Mountain
83
37
Region 1: Northern
135
60
Region 2: Rocky Mountain
67
30
Region 3: Southwestern
22
10
Region 4: Intermountain
40
8
Pacific
43
19
Region 5: California
40
18
Region 6: Pacific Northwest
135
60
Region 10: Alaska
36
16
Coastal
135
60
Interior
25
11
Southern
20
9
Region 8: Southern
20
9
Eastern
25
11
North Central
25
11
Region 9: Conifers
22
10
Hardwoods
27
12
" Reference 1.
b See Figure 13.1-1 for region boundaries.
13.1.2 Emissions And Controls1
It has been hypothesized, but not proven, that the nature and amounts of air pollutant
emissions are directly related to the intensity and direction (relative to the wind) of the wildfire, and
are indirectly related to the rate at which the fire spreads. The factors that affect the rate of spread
are (1) weather (wind velocity, ambient temperature, relative humidity); (2) fuels (fuel type, fuel bed
array, moisture content, fuel size); and (3) topography (slope and profile). However, logistical
problems (such as size of the burning area) and difficulties in safely situating personnel and equipment
close to the fire have prevented the collection of any reliable emissions data on actual wildfires, so
that it is not possible to verify or disprove the hypothesis. Therefore, until such measurements are
made, the only available information is that obtained from burning experiments in the laboratory.
These data, for both emissions and emission factors, are contained in Table 13.1-2. It must be
emphasized that the factors presented here are adequate for laboratory-scale emissions estimates, but
that substantial errors may result if they are used to calculate actual wildfire emissions.
13.1-2
EMISSION FACTORS
10/96
-------
Ogdcn
^San
Francisco
Albuquerque
Atlanta
luneaii
¦ Headquarters
— Regional Boundaries
Figure 13.1-1. Forest areas And U. S. Forest Service Regions.
The emissions and emission factors displayed in Table 13.1-2 are calculated using the
following formulas:
F. = PL
(1)
E. = FA = P.LA
(2)
where:
Fj = emission factor (mass of pollutant/unit area of forest consumed)
P; = yield for pollutant "i" (mass of pollutant/unit mass of forest fuel consumed)
= 8.5 kilograms per megagram (kg/Mg) (17 pound per ton [lb/ton]) for total particulate
= 70 kg/Mg (140 lb/ton) for carbon monoxide
= 12 kg/Mg (24 lb/ton) for total hydrocarbon (as CH4)
= 2 kg/Mg (4 lb/ton) for nitrogen oxides (NOJ
= negligible for sulfur oxides (SOJ
L = fuel loading consumed (mass of forest fuel/unit land area burned)
A = land area burned
Ej = total emissions of pollutant "i" (mass pollutant)
10/96
Miscellaneous Sources
13.1-3
-------
Table 13.1-2. EMISSIONS AND EMISSION FACTORS FOR FOREST WILDFIRES
EMISSION FACTOR RATING: D
m
C/5
C/5
>—I
o
z
Tl
>
o
H
o
JO
c«
Area
Consumed
Wildfire Fuel
Consumption
(Mg/hectare)
Emission Factors (kg/Hectare)
Emissions (Mg)
Geographic Area
By
Wildfire'
(hectares)
Particulate
Carbon
Monoxide
Volatile
Organicsb
Nitrogen
Oxides
Particulate
Carbon
Monoxide
Volatile
Organicsb
Nitrogen
Oxides
Rocky Mountain
313,397
83
706
5,810
996
166
220,907
1,819,237
311,869
51,978
Northern (Region 1)
142,276
135
1,144
9,420
1,620
269
162,268
1,339,283
229,592
38,265
Rocky Mountain
(Region 2)
65,882
67
572
4,710
808
135
37,654
310,086
53,157
8,860
Southwestern
(Region 3)
83,765
22
191
1,570
269
45
15,957
131,417
22,533
3,735
Interniountain
(Region 4)
21,475
40
153
1,260
215
36
3,273
26,953
4,620
770
Pacific
469,906
43
362
2,980
512
85
170,090
1,400,738
240,126
40,021
California (Region 5)
18,997
40
343
2,830
485
81
6,514
53,645
9,196
1,533
Alaska (Region 10)
423,530
36
305
2,510
431
72
129,098
1,063,154
182,255
30,376
Pacific Northwest
(Region 6)
27,380
135
1,144
9,420
1,620
269
31,296
257,738
44,183
7,363
Southern
806,289
20
172
1,410
242
40
138,244
1,138,484
195,168
35,528
Southern (Region 8)
806,289
20
172
1,410
242
40
138,244
1,138,484
195,168
35,528
North Central and
Eastern
94,191
25
210
1,730
296
49
19,739
162,555
27,867
4,644
(Region 9)
141,238
25
210
1,730
296
49
29,598
243,746
41,785
6,964
Eastern Group
(With Region 9)
47,046
25
210
1,730
296
49
9,859
81,191
13,918
2,320
Total
1,730,830
38
324
2,670
458
76
560,552
4,616,317
791,369
131,895
* Consumption data are for 1971.
_ b Expressed as methane,
o
-------
For example, suppose that it is necessary to estimate the total particulate emissions from a
10,000-hectare wildfire in the Southern area (Region 8). From Table 13.1-1, it is seen that the
average fuel loading is 20 Mg/hectare (9 tons/acre). Further, the pollutant yield for particulates is
8.5 kg/Mg (17 lb/ton). Therefore, the emissions are:
E = (8.5 kg/Mg of fuel) (20 Mg of fuel/hectare) (10,000 hectares)
E = 1,700,000 kg = 1,700 Mg
The most effective method of controlling wildfire emissions is, of course, to prevent the
occurrence of wildfires by various means at the land manager's disposal. A frequently used technique
for reducing wildfire occurrence is "prescribed" or "hazard reduction" burning. This type of
managed burn involves combustion of litter and underbrush to prevent fuel buildup under controlled
conditions, thus reducing the danger of a wildfire. Although some air pollution is generated by this
preventive burning, the net amount is believed to be a relatively smaller quantity then that produced
by wildfires.
13.1.3 Prescribed Burning1
Prescribed burning is a land treatment, used under controlled conditions, to accomplish
natural resource management objectives. It is one of several land treatments, used individually or in
combination, including chemical and mechanical methods. Prescribed fires are conducted within the
limits of a fire plan and prescription that describes both the acceptable range of weather, moisture,
fuel, and fire behavior parameters, and the ignition method to achieve the desired effects. Prescribed
fire is a cost-effective and ecologically sound tool for forest, range, and wetland management. Its use
reduces the potential for destructive wildfires and thus maintains long-term air quality. Also, the
practice removes logging residues, controls insects and disease, improves wildlife habitat and forage
production, increases water yield, maintains natural succession of plant communities, and reduces the
need for pesticides and herbicides. The major air pollutant of concern is the smoke produced.
Smoke from prescribed fires is a complex mixture of carbon, tars, liquids, and different
gases. This open combustion source produces particles of widely ranging size, depending to some
extent on the rate of energy release of the fire. For example, total particulate and particulate less than
2.5 micrometers (/im) mean mass cutpoint diameters are produced in different proportions, depending
on rates of heat release by the fire.2 This difference is greatest for the highest-intensity fires, and
particle volume distribution is bimodal, with peaks near 0.3 fim and exceeding 10 ^m.3 Particles
over about 10 /an, probably of ash and partially burned plant matter, are entrained by the turbulent
nature of high-intensity fires.
Burning methods differ with fire objectives and with fuel and weather conditions.4 For
example, the various ignition techniques used to burn under standing trees include: (1) heading fire,
a line of fire that runs with the wind; (2) backing fire, a line of fire that moves into the wind; (3) spot
fires, which burn from a number of fires ignited along a line or in a pattern; and (4) flank fire, a line
of fire that is lit into the wind, to spread laterally to the direction of the wind. Methods of igniting
the fires depend on forest management objectives and the size of the area. Often, on areas of 50 or
more acres, helicopters with aerial ignition devices are used to light broadcast burns. Broadcast fires
may involve many lines of fire in a pattern that allows the strips of fire to burn together over a
sizeable area.
10/96
Miscellaneous Sources
13.1-5
-------
In discussing prescribed burning, the combustion process is divided into preheating, flaming,
glowing, and smoldering phases. The different phases of combustion greatly affect the amount of
emissions produced.5"7 The preheating phase seldom releases significant quantities of material to the
atmosphere. Glowing combustion is usually associated with burning of large concentrations of woody
fuels such as logging residue piles. The smoldering combustion phase is a very inefficient and
incomplete combustion process that emits pollutants at a much higher ratio to the quantity of fuel
consumed than does the flaming combustion of similar materials.
The amount of fuel consumed depends on the moisture content of the fuel.8"9 For most fuel
types, consumption during the smoldering phase is greatest when the fuel is driest. When lower
layers of the fuel are moist, the fire usually is extinguished rapidly.10
The major pollutants from wildland burning are particulate, carbon monoxide, and volatile
organics. Nitrogen oxides are emitted at rates of from 1 to 4 g/kg burned, depending on combustion
temperatures. Emissions of sulfur oxides are negligible.11"12
Particulate emissions depend on the mix of combustion phase, the rate of energy release, and
the type of fuel consumed. All of these elements must be considered in selecting the appropriate
emission factor for a given fire and fuel situation. In some cases, models developed by the U. S.
Forest Service have been used to predict particulate emission factors and source strength.13 These
models address fire behavior, fuel chemistry, and ignition technique, and they predict the mix of
combustion products. There is insufficient knowledge at this time to describe the effect of fuel
chemistry on emissions.
Table 13.1-3 presents emission factors from various pollutants, by fire and fuel configuration.
Table 13.1-4. gives emission factors for prescribed burning, by geographical area within the United
States. Estimates of the percent of total fuel consumed by region were compiled by polling experts
from the Forest Service. The emission factors are averages and can vary by as much as 50 percent
with fuel and fire conditions. To use these factors, multiply the mass of fuel consumed per hectare
by the emission factor for the appropriate fuel type. The mass of fuel consumed by a fire is defined
as the available fuel. Local forestry officials often compile information on fuel consumption for
prescribed fires and have techniques for estimating fuel consumption under local conditions. The
Southern Forestry Smoke Management Guidebook5 and the Prescribed Fire Smoke Management
Guide15 should be consulted when using these emission factors.
The regional emission factors in Table 13.1-4 should be used only for general planning
purposes. Regional averages are based on estimates of the acreage and vegetation type burned and
may not reflect prescribed burning activities in a given state. Also, the regions identified are broadly
defined, and the mix of vegetation and acres burned within a given state may vary considerably from
the regional averages provided. Table 13.1-4 should not be used to develop emission inventories and
control strategies.
To develop state emission inventories, the user is strongly urged to contact that state's federal
land management agencies and state forestry agencies that conduct prescribed burning to obtain the
best information on such activities.
13.1-6
EMISSION FACTORS
10/96
-------
o
g Table 13,1-3 (Metric Units). EMISSION FACTORS FOR PRESCRIBED BURNING*
o
ST
s
8
00
o
C
O
n>
£/>
Fire/Fuel Configuration
Phase
Pollutant (g/kg)
Fuel Mix
(%)
EMISSION
FACTOR
RATING
Particulate
Carbon
Monoxide
Volatile Organics
PM-2.5
PM-10
Total
Methane
Nonmethane
Broadcast logging slash
Hardwood
F
6
T
13
44
2.1
3.8
33
A
S
13
14"
20
146
8.0
7.7
67
A
Fire
11
12b
18
112
6.1
6.4
A
Conifer
Short needle
F
7
8C
12
72
2.3
2.1
33
A
S
14
15"
19
226
7.2
4.2
67
A
Fire
12
13'
17
175
5.6
3.5
A
Long needle
F
6
6"
9
45
1.5
1.7
33
B
S
16
17d
25
166
7.7
5.4
67
B
Fire
13
13d
20
126
5.7
4.2
B
Logging slash debris
Dozer piled conifer
No mineral soild
F
4
4
5
28
1.0
ND
90
B
S
6
7
14
116
8.7
ND
10
B
Fire
4
4
6
37
1.8
ND
B
u>
1
-------
U3
Table 13.1-3 (cont.).
oo
M
C/5
*
O
21
•n
>
n
o
w
00
SO
OS
Pollutant (g/kg)
Particulate
Carbon
Monoxide
Volatile Organics
Fuel Mix
(%)
EMISSION
FACTOR
RATING
Fire/Fuel Configuration
Phase
PM-2,5
PM-10
Total
Methane
Nonmethane
10 to 30% Mineral soil"
S
ND
ND
25
200
ND
ND
ND
D
25% Organic soil"
S
ND
ND
35
250
ND
ND
ND
D
Range fire
Juniper slashf
F
7
8
11
41
2.0
2.7
8.2
B
S
12
13
18
125
10.3
7.8
15.6
B
Fire*
9
10
14
82
6.0
5.2
12.5
B
Sagebrush'
F
15
16
23
78
3.7
3.4
B
S
13
15
23
106
6.2
7.3
B
Fire'
13
15
23
103
6.2
6.9
B
Chaparral shrub
communities*1
F
7
8
16
56
1.7
8.2
A
S
12
13
23
133
6.4
15.6
A
Fire
10
11
20
101
4.5
12.5
A
Line fire
Conifer
Long needle (pine)
Heading'
ND
40
50
200
ND
ND
D
Backing1'
ND
20
20
125
ND
ND
D
Palmetto/gallberryJ
Heading
ND
15
17
150
ND
ND
D
Backing
ND
15
15
100
ND
ND
D
Fire
ND
8 - 22
ND
ND
ND
ND
D
Chaparral1
Heading
8
9
15
62
2.8
3.5
C
Grasslands'
Fire
ND
10
10
75
ND
0
D
-------
Table 13.1-3 (cont.).
o
Of
8
g
00
o
c
8
a References 7-8. Unless otherwise noted, determined by field testing of fires > 1 acre size. F = flaming. S = smoldering. Fire — weighted
average of F and S. ND = no data.
h For PM-10, Reference 7. EMISSION FACTOR RATING: C.
c For PM-10, References 3,7. EMISSION FACTOR RATING: D.
d For PM-10, References 3,7. EMISSION FACTOR RATING: D.
e Reference 12. Determined using laboratory combustion hood.
f Reference 16.
B Fuel mix uncertain, because of short, intense flaming phase. Use fire average for emission inventory purposes.
h References 17-18.
j References 13-14. Determined using laboratory combustion hood.
k References 13-14.
i
\o
-------
Table 13.1-4 (Metric Units). EMISSION FACTORS FOR PRESCRIBED BURNING
BY U. S. REGION
Regional Configuration
And Fuel Type®
Percent
Of Fuelb
Pollutant0
Particulate (g/kg)
CO
PM-2.5
PM-10
PM
Pacific Northwest
Logging slash
Piled slash
42
4
5
6
37
Douglas fir/Western hemlock
24
12
13
17
175
Mixed conifer
19
12
13
17
175
Ponderosa pine
6
13
13
20
126
Hardwood
4
11
12
18
112
Underburning pine
5
30
30
35
163
Average for region
100
9.4
10.3
13.3
111.1
Pacific Southwest
Sagebrush
35
9
15
62
Chaparral
20
8
9
15
62
Pinyon/Juniper
20
13
17
175
Underburning pine
15
30
35
163
Grassland
10
10
10
15
Average for region
100
13.0
17.8
101.0
Southeast
Palmetto/gallbery
35
15
16
125
Underburning pine
30
30
35
163
Logging slash
20
13
20
126
Grassland
10
10
10
75
Other
5
17
17
175
Average for region
100
18.8
21.9
134
13.1-10
EMISSION FACTORS
10/96
-------
Table 13.1-4 (corn.).
Regional Configuration
And Fuel Type"
Percent
of Fuelb
Pollutant*
Particulate (g/kg)
CO
PM-2.5
PM-10
PM
Rocky Mountain
Logging slash
50
4
6
37
Underburning pine
20
30
35
163
Grassland
20
10
10
75
Other
10
17
17
175
Average for region
100
11.9
13.7
83.4
North Central and Eastern
Logging slash
50
13
17
175
Grassland
30
10
10
75
Underburning pine
10
30
35
163
Other
10
17
17
175
Average for region
100
14
16.5
143.8
° Regional areas are generalized, e. g., the Pacific Northwest includes Oregon, Washington, and parts
of Idaho and California. Fuel types generally reflect the ecosystems of a region, but users should
seek advice on fuel type mix for a given season of the year. An average factor for Northern
California could be more accurately described as chaparral, 25%; underburning pine, 15%;
sagebrush, 15%; grassland, 5%; mixed conifer, 25%; and douglas fir/Western hemlock, 15%.
Blanks indicate no data.
b Based on the judgement of forestry experts.
c Adapted from Table 13.1-3 for the dominant fuel types burned.
13.1.4 Wildfires and Prescribed Burning—Greenhouse Gases
Emission factors for greenhouse gases from wildfires and prescribed burning are provided
based on the amount of material burned. Emission factors for methane (CH4) and nitrous oxide (N,0)
based on the mass of material burned are provided in Table 13.1-5. To express emissions based on
area burned, refer to Table 13.1-1 for estimated average fuel loading by region. The CH., emission
factors have been divided into the type of forests being studied for specific plant species. Emissions
of CO, from this source as well as other biogenic sources are part of the carbon cycle, and as such
are typically not included in greenhouse gas emission inventories.
10/96
Miscellaneous Sources
13.1-11
-------
Table 13.1-5. WILDFIRE AND PRESCRIBED BURNING GREENHOUSE GAS
EMISSION FACTORS
EMISSION FACTOR RATING: C
Regional/Fuel Type8
Pollutant Ob/ton)
ch4
n2o
Agricultural Residues
5.4b
Amazon
8.5°
Boreal and Coniferous Forests
11.1°
0.46
Savanna
3.7C
Temperate and Boreal Forests
12.2
* References 19-22. To convert lb/ton to kg/Mg multiply by 0.5.
b For more details see Table 2.5-5 of Section 2.5 Opening Burning.
c Emission factor developed based on combustion efficiency (ratio of carbon released as C02).
References For Section 13.1
1. Development Of Emission Factors For Estimating Atmospheric Emissions From Forest Fires,
EPA-450/3-73-009, U. S. Environmental Protection Agency, Research Triangle Park, NC,
October 1973.
2. D. E. Ward and C. C. Hardy, Advances In The Characterization And Control Of Emissions
From Prescribed Broadcast Fires Of Coniferous Species Logging Slash On Clear cut Units,
EPA DW12930110-01 -3/DOE DE-A179-83BP12869, U. S. Forest Service, Seattle, WA,
January 1986.
3. L. F. Radke, et al., Airborne Monitoring And Smoke Characterization Of Prescribed Fires On
Forest Lands In Western Washington And Oregon, EPA-600/X-83-047, U. S. Environmental
Protection Agency, Cincinnati, OH, July 1983.
4. H. E. Mobley, et al., A Guide For Prescribed Fire In Southern Forests, U.S. Forest Service,
Atlanta, GA, 1973.
5. Southern Forestry Smoke Management Guidebook, SE-10, U. S. Forest Service, Asheville,
NC, 1976.
6. D. E. Ward and C. C. Hardy, "Advances In The Characterization And Control Of Emissions
From Prescribed Fires", Presented at the 77th Annual Meeting Of The Air Pollution Control
Association, San Francisco, CA, June 1984.
7. C. C. Hardy and D. E. Ward, "Emission Factors For Particulate Matter By Phase Of
Combustion From Prescribed Burning", Presented at the Annual Meeting Of The Air
Pollution Control Association Pacific Northwest International Section, Eugene, OR,
November 19-21, 1986.
13.1-12
EMISSION FACTORS
10/96
-------
8. D. V. Sandberg and R. D. Ottmar, "Slash Burning And Fuel Consumption In The Douglas
Fir Subregion", Presented at the 7th Conference On Fire And Forest Meteorology, Fort
Collins, CO, April 1983.
9. D, V. Sandberg, "Progress In Reducing Emissions From Prescribed Forest Burning In
Western Washington And Western Oregon", Presented at the Annual Meeting Of The Air
Pollution Control Association Pacific Northwest International Section, Eugene, OR,
November 19-21, 1986.
10. R. D, Ottmar and D. V. Sandberg, "Estimating 1000-hour Fuel Moistures In The Douglas Fir
Subregion", Presented at the 7th Conference On Fire And Forest Meteorology, Fort Collins,
CO, April 25-28, 1983.
11. D. ¥. Sandberg, et al., Effects Of Fire On Air — A State Of Knowledge Review, WO-9,
U. S, Forest Service, Washington, DC, 1978.
12. C. K. McMahon, "Characteristics Of Forest Fuels, Fires, And Emissions", Presented at the
76th Annual Meeting of the Air Pollution Control Association, Atlanta, GA, June 1983.
13. D. E. Ward, "Source Strength Modeling Of Particulate Matter Emissions From Forest Fires",
Presented at the 76th Annual Meeting Of The Air Pollution Control Association, Atlanta, GA,
June 1983.
14. D. E. Ward, et al., "Particulate Source Strength Determination For Low-intensity Prescribed
Fires", Presented at the Agricultural Air Pollutants Specialty Conference, Air Pollution
Control Association, Memphis, TN, March 18-19, 1974.
15. Prescribed Fire Smoke Management Guide, 420-1, BIFC-BLM Warehouse, Boise, ID,
February 1985.
16. Colin C. Hardy, Emission Factors For Air Pollutants From Range Improvement Prescribed
Burning of Western Juniper And Basin Big Sagebrush, PNW 88-575, Office Of Air Quality
Planning And Standards, U.S. Environmental Protection Agency, Research Triangle Park,
NC, March 1990.
17. Colin C. Hardy And D. R. Teesdale, Source Characterization and Control Of Smoke
Emissions From Prescribed Burning Of California Chaparral, CDF Contract No. 89CA96071,
California Department Of Forestry And Fire Protection, Sacramento, CA 1991.
18. Darold E. Ward And C. C. Hardy, "Emissions From Prescribed Burning Of Chaparral",
Proceedings Of The 1989 Annual Meeting Of The Air And Waste Management Association,
Anaheim, CA June 1989.
19. D. Ward, et al., An Inventory Of Particulate Matter And Air Toxic Emissions From Prescribed
Fires In The U.S.A. For 1989, Proceedings of the Air and Waste Management Association,
1993 Annual Meeting, Denver, CO, p. 10, June 14-18, 1993.
20. W. M. Hao and D. Ward, "Methane Production From Global Biomass Burning", Journal Of
Geophysical Research, 98(07/^:20,657-20,661, pp. 20, 656, November 1993.
10/96
Miscellaneous Sources
13.1-13
-------
21. D. Nance, et al., "Air Borne Measurements Of Gases And Particles From An Alaskan
Wildfire", Journal of Geophysical Research, 98(D8): 14,873-14,882, August 1993.
22. L. Radke, et al., "Particulate And Trace Gas Emissions From Large Biomass Fires In North
America", Global Biomass Burning: Atmospheric, Climatic, And Biospheric Implications, MIT
Press, Cambridge, MA, p. 221, 1991.
13.1-14
EMISSION FACTORS
10/96
-------
14. GREENHOUSE GAS BIOGENIC SOURCES
This chapter contains emission factor information for greenhouse gases on those
source categories that differ substantially from, and hence cannot be grouped with, the other
stationary sources discussed in this publication. Two of these natural emitters, soils and
termites, are truly area sources, with their pollutant-generating process(es) dispersed over
large land areas. The third source, lightning occurs in the atmosphere and results in the
formation of nitrous oxide.
9/96
Greenhouse Gas Biogenic Sources
14,0-1
-------
14.1 Emissions From Soils—Greenhouse Gases
14.1.1 General
A good deal of research has been done to estimate emissions of nitrogen oxides (NOx) from
soils. Although numerous measurements have been made, emissions from soils show variability
based on a number of factors. Differences in soil type, moisture, temperature, season, crop type,
fertilization, and other agricultural practices apparently all play a part in emissions from soils.
Soils emit NOx through biological and abiological pathways, and emission rates can be
categorized either by fertilizer application or land use. Agricultural lands and grasslands are the most
significant emission sources within this category. The quantity of NOx emitted from agricultural land
is dependant on fertilizer application and the subsequent microbial denitrification of the soil.
Microbial denitrification is a natural process in soil, but denitrification is higher when soil has been
fertilized with chemical fertilizers. Both nitrous oxide (N20) and nitric oxide (NO) are emitted from
this source. Emissions of NOx from soils are estimated to be as much as 16 percent of the global
budget of NGX in the troposphere, and as much as 8 percent of the NOx in North America.1 This
section discusses only emissions of N20 from soils. Refer to reference 2 for information on
estimating total NOx from soils using the EPA's Biogenic Emissions Inventory System (BEIS).
14.1.2 Agricultural Soils
The description of the source and the methodology for estimating emissions and emission
factors presented in this section are taken directly from the State Workbook: Methodologies for
Estimating Greenhouse Gas Emissions and the Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990-1994, prepared by the U.S. Environmental Protection Agency's Office of Policy,
Planning and Evaluation (OPPE). A more detailed discussion of the processes and variables affecting
N20 generation from this source can be found in those volumes.3,4
Various agricultural soil management practices contribute to greenhouse gas emissions. The
use of synthetic and organic fertilizers adds nitrogen to soils, thereby increasing natural emissions of
N20. Other agricultural soil management practices such as irrigation, tillage, or the fallowing of land
can also affect trace gas fluxes to and from the soil since soils are both a source and a sink for carbon
dioxide (C02) and carbon monoxide (CO), a sink for methane (CH4), and a source of N20.
However, there is much uncertainty about the direction and magnitude of the effects of these other
practices, so only the emissions from fertilizer use are included in the method presented here.
Nitrous oxide emissions from commercial fertilizer use can be estimated using the following
equation;
N20 Emissions = (FC * EC * 44/28)a
a EMISSION FACTOR RATING: D.
9/96 Miscellaneous Sources
14.1-1
-------
where:
FC = Fertilizer Consumption (tons N-applied);b
EC = Emission Coefficient = 0.0117 tons N20-N/ton N applied; and
44/28 = The molecular weight ratio of N20 to NzO as N (N20/N20-N).
The emission coefficient of 0.0117 tons N/ton N-applied represents the percent of nitrogen
applied as fertilizer that is released into the atmosphere as nitrous oxide. This emission coefficient
was obtained from the Agricultural Research Service of the U.S. Department of Agriculture (USDA),
which estimated that 1.84 kg N20 was emitted per 100 kg of nitrogen applied as fertilizer. After
applying the appropriate conversion, this is equivalent to 0.0117 tons N20-N/ton N-applied.
The total amount of commercial fertilizer consumed in a given state or region is the sum of
all synthetic nitrogen, multiple-nutrient, and organic fertilizer applied (measured in mass units of
nitrogen). Fertilizer data by type and state can be obtained from the Tennessee Valley Authority's
National Fertilizer and Environmental Research Center. In the case of organic fertilizers, such as
manure from livestock operations, data may be available from state or local Agricultural Extension
offices. There may be instances in which fertilizer consumption is given as the total mass of fertilizer
consumed rather than as nitrogen content. In such cases, total mass by fertilizer type may be
converted to nitrogen content using the percentages in Table 14.1-1.
Because agricultural activities fluctuate from year to year as a result of economic, climatic,
and other variables, it is recommended that an average of 3 years of fertilizer consumption be used to
account for extraordinary circumstances.
Example:
For County A, a 3-year average of 16 tons of monoammonium phosphate is applied. As
shown in Table 14.1-1, monoammonium phosphate is 11 percent N.
FC — 16 tons fertilizer * 11% N/ton fertilizer
= 1.76 tons N
where:
FC = Fertilizer consumption
Emissions are calculated by:
N20 Emissions = (1,76 tons N applied) * (0.0117 tons N20) * —
28
= 0.032 tons N20
b In some instances, state fertilizer consumption data may only be provided by fertilizer type and
not aggregated across all types by total N consumed. If this is the case, then analysts must first
determine the amount of N consumed for each fertilizer type (using the percentages in Table 14.1-1)
and then follow the method presented. To obtain total emissions by state, sum across all types.
14.1-2 EMISSION FACTORS 9/96
-------
Table 14.1-1. NITROGEN CONTENT OF PRINCIPAL FERTILIZER MATERIALS3
MATERIAL
% NITROGEN (by wt)
Nitrogen
Ammonia, Anhydrous
82
Ammonia, Aqua
16-25
Ammonium nitrate
33.5
Ammonium nitrate-limestone mixtures
20.5
Ammonium sulfate
21
Ammonium sulfate-nitrate
26
Calcium cyanamide
21
Calcium nitrate
15
Nitrogen solutions
21-49
Sodium nitrate
16
Urea
46
Urea-form
38
Phosphate
Basic slag, Open hearth
b
Bone meal
2-4.5
Phosphoric acid
b
Rock phosphate
b
Superphosphate, Normal
_J>
Superphosphate, Concentrated
b
Superphosphoric acid
b
Potash
b
Potassium chloride (muriate)
b
Potassium magnesium sulfate
b
Potassium sulfate
b
Multiple Nutrient
Ammoniated superphosphate
3-6
Ammonium phosphate-nitrate
27
Ammonium phosphate-sulfate
13-16
Diammonium phosphate
16-21
Monoammonium phosphate
11
Nitric phosphates
14-22
Nitrate of soda-potash
15
Potassium nitrate
13
Wood ashes
b
Blast furnace slag
b
Dolomite
b
Gypsum
_b
Kieserite (emjeo)
b
Limestone
b
Lime-sulfur solution
b
Magnesium sulfate (Epsom salt)
b
Sulftir
b
a Reference 3.
b No, or a negligible amount of, nitrogen present.
9/96
Miscellaneous Sources
14.1-3
-------
14.1.3 Other Soils
The amount of N20 emitted from non-agricultural soils is dependent on the soil's nutrient level and
moisture content.5 It is believed therefore that soils in tropical regions emit far more N20 than soils
in other terrestrial ecosystems.5'6 Because of the variability of soil types and soil moisture levels,
some tropical soils emit more N20 than others.
Global soil N20 flux measurements were compiled from various sources5"8 and used to delineate
soil N20 emission factors.9 Table 14.1-2 presents the mean emission factors developed for 6
ecological regions. These emission factors are based on test data from primarily undisturbed soils.9
14.1.4 Uncertainty3
Scientific knowledge regarding nitrous oxide production and emissions from fertilized soils is
limited. Significant uncertainties exist regarding the agricultural practices, soil properties, climatic
conditions, and biogenic processes that determine how much fertilizer nitrogen various crops absorb,
how much remains in soils after fertilizer application, and in what ways the remaining nitrogen
evolves into either nitrous oxide or gaseous nitrogen and other nitrogen compounds.
A major difficulty in estimating the magnitude of emissions from this source has been the relative
lack of emissions measurement data across a suitably wide variety of controlled conditions, making it
difficult to develop statistically valid estimates of emission factors. Previous attempts have been made
to develop emission factors for different fertilizer and crop types for state and national emission
inventories. However, the accuracy of these emission factors has been questioned. For example,
while some studies indicate that N20 emission rates are higher for ammonium-based fertilizers than
for nitrate, other studies show no particular trend in N20 emissions related to fertilizer types.
Therefore, it is possible that fertilizer type is not the most important factor in determining emissions.
One study suggests that N20 emissions from the nitrification of fertilizers may be more closely
related to soil properties than to the type of fertilizer applied.
There is consensus, however, as to the fact that numerous natural and management factors influence
the biological processes of the soil microorganisms that determine N20 emissions from nitrogen
fertilizer use.
While it is relatively well known how the natural processes individually affect N20 emissions, it is
not well understood how the interaction of the processes affects N20 emissions. Experiments have
shown that in some cases increases in each of the following factors (individually) enhance N20
emissions: pH, soil temperature, soil moisture, organic carbon content, and oxygen supply.
However, the effects on N20 emissions of soil moisture, organic carbon content, and microbial
population together, for example, are not readily predictable.
Management practices may also affect N20 emissions, although these relationships have not been
well quantified. As mentioned, levels of N20 emissions may be dependent on the type of fertilizer
used, although the extent of the effect is not clear, as demonstrated by the wide range of emission
coefficients for individual fertilizer types derived in experiments. Although high fertilizer application
rates may cause higher N20 emission rates, the relationship between fertilizer application rate and
nitrous oxide emissions is not well understood. Deep placement of fertilizer as an application
technique will result in lower N20 emissions than broadcasting or hand placement. One study found
that emissions from fertilizer applied in the fall were higher than emissions from the same fertilizer
applied in the spring, indicating that the timing of fertilizer application can affect N20 emissions.
Tillage practices can also affect N20 emissions. Tilling tends to decrease N20 emissions; no-till and
14.1-4
EMISSION FACTORS
9/96
-------
Table 14.1-2. EMISSION FACTORS FOR N20 FROM NON-AGRICULTURAL SOILS4
EMISSION FACTOR RATING: E
Ecosystem
Emission Factor (lbs N20/acre/yr)b
Tropical forest
3.692
Savanna
2.521
Temperate forest (coniferous)
1.404
Temperate forest (deciduous)
0.563
Grassland
1.503
Shrubs/Woodlands
2.456
8 Reference 9.
b To convert lb N20/acre/yr to g N20/m2/yr, multiply by 0.11208.
use of herbicides may increase N20 emissions. However, limited research at unique sites under
specific conditions has not been able to account for the complex interaction of the factors, making the
effects of combinations of factors difficult to predict.
Emissions may also occur from the contamination of surface and ground water due to nutrient
leaching and runoff from agricultural systems. However, methods to estimate emissions of N20 from
these sources are not included at this time due to a lack of data and emission coefficients for each
contributing activity. Because of the potential relative importance of these N20 emissions, they
should be included in the future as data availability and scientific understanding permit.
References For Section 14.1
1. Air Quality Criteria For NOx, Volume I, EPA 600/8-9 l/049aF, U. S. Environmental
Protection Agency, Research Triangle Park, NC, p. 4-11 to 4-14, 1993.
2. User's Guide For The Urban Airshed Model, Volume IV: User's Manual For The Emission
Preprocessor System 2.0, Part A: Core FORTRAN System EPA-450/4-90-007D(R).
U, S. Environmental Protection Agency, Research Triangle Park, NC. 1990.
3. State Workbook: Methodology For Estimating Greenhouse Gas Emissions,
U.S. Environmental Protection Agency, Office of Policy, Planning and Evaluation,
Washington, DC, p. D9-1 to D9-5, 1995.
4. Inventory Of U.S. Greenhouse Gas Emissions And Sinks: 1990-1993, EPA-230-R-94-014,
U.S. Environmental Protection Agency, Office of Policy, Planning and Evaluation,
Washington, DC, 1994.
5. E. Sanhueza et al, "N20 And NO Emissions From Soils Of The Northern Part Of The
Guayana Shield, Venezuela" J. Geophy. Res., 95:22481-22488, 1990.
6. P.A. Matson, et al., "Sources Of Variation In Nitrous Oxide Flux From Amazonian
Ecosystems", J. Geophys. Res., 95:6789-6798, 1990.
7. R.D. Bowden, et al., "Annual Nitrous Oxide Fluxes From Temperate Forest Soils In The
Northeastern United States", J. Geophys. Res., 95:3997-4005, 1990.
9/96
Miscellaneous Sources
14.1-5
-------
8. D. Campbell, et al., Literature Review Of Greenhouse Gas Emissions From Biogenic Sources,
EPA-600/8-90-071, U. S. Environmental Protection Agency, Office of Research and
Development, Washington DC, 1990.
9. R.L. Peer, et al, Characterization Of Nitrous Oxide Emission Sources, Prepared for the
U. S. Environmental Protection Agency, Air and Energy Engineering Research Laboratory,
Research Triangle Park, NC, 1995,
14,1-6
EMISSION FACTORS
9/96
-------
14.2 Termites—Greenhouse Gases
14.2.1 General1"2
Termites inhabit many different ecological regions, but they are concentrated primarily in
tropical grasslands and forests. Symbiotic micro-organisms in the digestive tracts of termites
(flagellate protozoa in lower termites and bacteria in higher termites) produce methane (CH4).
Estimates of the contribution to the global budget of CH4 from termites vary widely, from negligible
up to 15 percent.
Termite CH4 emissions estimates vary for several reasons. Researchers have taken different
approaches to approximating the number of termites per area for different ecological regions (e.g.,
cultivated land, temperate grassland, tropica) forest) and different species. In addition, the total area
per ecological region is not universally agreed upon, and not all of the area in an ecological region is
necessarily capable of supporting termites. For example, cultivated land in Europe and Canada is
located in a climatic zone where termites cannot survive. Some researchers have tried to estimate the
percentage of each region capable of supporting termites while others have conservatively assumed
that all of the area of a given ecological region can support termites. Finally, the contributions to
atmospheric CH4 from many other related CH4 sources and sinks associated with termite populations
(i. e,, tropical soils) are not well understood.
14.2.2 Emissions3"4
The only pollutant of concern from termite activity is CH4. Emissions of CH4 from termites
can be approximated by an emission factor derived from laboratory test data. Applying these data to
field estimates of termite population to obtain a realistic, large-scale value for CH4 emissions is
suspect, but an order-of-magnitude approximation of CH4 emissions can be made. Termite activity
also results in the production of carbon dioxide (C02). These C02 emissions are part of the regular
carbon cycle, and as such should not be included in a greenhouse gas emissions inventory.
Table 14.2-1 reports typical termite densities per ecological region, and Table 14.2-2 provides
the CH4 emission factors for species typical to each ecological region.
A critical data gap currently exists in determining the activity rate for these emission factors
(which are given in units of mass of CH4 per mass of termite). Estimates of termites per acre are
given in Table 14.2-1, but converting the number of termites into a usable mass is difficult. If the
species of termite is known or can be determined, then the number of termites or the number of
termite nests can be converted into a mass of termites. If the species is not known for a particular
area, then a typical value must be used that is representative of the appropriate ecological region.
Reference 4 provided information on termite density for various North American species, with an
average denisity of 4.86xl0"6 lb/worker termite.
9/96
Miscellaneous Sources
14.2-1
-------
An example calculation to estimate annual emissions from termites on 5,000 acres of cultivated land is
as follows:
5000 acres « "•38l"°6'ermiles = 5.69xl010 termites
acre
< f.a mio 4.86x10 6 lb 1.8xl0"3 lb CH4 j 8760 hr
5.69x10 termites * * * — *
termite 1000 lb termite hr yr
lb CH4
= 4360.39 I
yr
To convert pounds to kilograms, multiply by 0.454,
Table 14.2-1. TYPICAL TERMITE DENSITIES PER ECOLOGICAL REGION4
Ecological Region
106 Termites per Acre
Tropical wet forest
4.05
Tropical moist forest
18.01
Tropical dry forest
12.80
Temperate
2.43
Wood/shrub land
1.74
Wet savanna
17.81
Dry savanna
3.48
Temperate grassland
8.66
Cultivated land
11.38
Desert scrub
0.93
Clearing and burning
27.62
a Reference 3.
14.2-2
EMISSION FACTORS
9/96
-------
Table 14.2-2. METHANE EMISSION FACTORS FOR TERMITES3
EMISSION FACTOR RATING: E
Termite Species
(Ecological Region)
Methane Emissions
(lb CH4/1000 lb termite/hr)
Tropical forest
4.2 E-03
Temperate forest
1.8 E-03
Savanna
8.0 E-03
Temperate grassland
1.8 E-03
Cultivated land
1.8 E-03
Desert scrub
1.0 E-03
a References 5 and 6. Reference 7 suggests the following seasonal variation based on studies of the
species Coptotermes lacteus:
Spring - 22%
Summer -49%
Fall -21%
Winter - 8%
References For Section 14.2
1. I. Fung, et al., "Three-Dimensional Model Synthesis Of The Global Methane Cycle", Journal
Of Geophysical Research, 96:13,033-13,065, July 20, 1991.
2. W. R. Seiler, et al., "Field Studies Of Methane Emissions From Termite Nests Into The
Atmosphere and Measurements Of Methane Uptake By Tropic Soils", Journal Of Atmospheric
Chemistry, 1:171-186, 1984.
3. P. R. Zimmerman, et al., "Termites: A Potentially Large Source Of Atmospheric Methane,
Carbon Dioxide, And Molecular Hydrogen", Science, 218(5):563-565, Nov. 1982.
4. K. Krishna and F. M. Weesner, Biology Of Termites, Volume 1, Academic Press, New York,
1969.
5. Written Communication from M. Saegar, SAIC, to Lee Beck, Project Officer, U. S.
Environmental Protection Agency, regarding Summary Of Data Gaps Associated With County-
Specific Estimates Of CH4 Emissions, July 6, 1992.
6. P. J. Frasser, et al., "Termites And Global Methane — Another Assessment", Journal Of
Atmospheric Chemistry, 4:295-310, 1986.
7. T. M. Lynch, Compilation Of Global Methane Emissions Data, Draft Report, Alliance Tech.
Corp. for U. S. Environmental Protection Agency, Nov. 1991.
» **- "
SL
\A 1 7
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14.3 Lightning Emissions—Greenhouse Gases8
Observations have been made of increased levels of nitrogen oxides (NQX), nitric oxide (NO),
nitrogen dioxide (N02), and nitrous oxide (N20) in the atmosphere after the occurrence and in the
proximity of lightning flashes,1"3 Although lightning is thought to be one of the larger natural
sources of NOx, N20 production by lightning is believed to be substantially less significant,
particularly in comparison to anthropogenic sources.4"5 Estimates for global production of N20 from
lightning range from 1.36 E-02 to 9.98 E-02 Tg.6 Emission factors for this source are uncertain.
Estimates of per-lightning-flash production of NOx (emission factors) require calculations involving
the length of the lightning stroke, the number of strokes per flash, the estimated energy discharge,
and the amount of N20 produced per joule, all of which are under discussion in the literature.
N20 emissions from lightning are based on estimates of the molecules produced per joule for
each lightning stroke 1.1 E+21 molecules/lightning stroke.6
Published estimates for the molecules/joule factors range from 4.3 E+12 to 4.0 E+16.6
Although most researchers use a stroke length of 5 km, stroke length varies. Estimates of the
electrical discharge are based on discharge per meter, so the variability of the lightning stroke adds to
the emission estimate uncertainty. Other factors that are of significance, but that are not included in
this emission factor, are estimates of the number of strokes in a lightning flash (not only are there
multiple strokes, but the energy output varies, as does the length of the stroke), and indications that
the production of N20 depends on electrical discharge conditions, not just the amount of the discharge
energy.7 Estimates for the electrical discharge per lightning flash (as opposed to a lightning stroke)
range from 1.0 E+08 joules/flash to 8.0 E+08 joules/flash.5
Because the first stroke in a lightning flash will release more energy than subsequent strokes,
the energy per flash is estimated by assuming the subsequent strokes release one-quarter the amount
of energy released by the first stroke. Hence the total flash energy is assumed to be 1.75 times that
of the first return stroke.5 The N20 emission factor for each lightning flash is:
0.14 grams N20/flash
The number of lightning flashes within a certain time period and area may be available
through the East Coast lightning detection network,8 satellite data, or from the lightning strike data
archive from the National Lightning Detection Network (GDS) in Tucson, AZ. Several assumptions
must be made in order to estimate the total number of lightning flashes from these sources.9 It is
assumed that not all of the lightning flashes are detected. The East Coast lightning detection network
is estimated to record 0.7 of the lightning flashes that occur. Recorded lightning flashes can then be
corrected by multiplying the recorded lightning flashes by an efficiency factor of 1.43. It is also
assumed that lightning flashes recorded are cloud-to-ground (CG) lightning flashes. Intra-cloud (IC)
flashes can be calculated from CG activity, but vary depending on latitude. It is assumed that about
four IC flashes occur for every CG flash.
The equation to calculate the number of IC flashes from CG activity is:
a This section uses only metric units because that is standard in this field.
9/96 Miscellaneous Sources
14.3-1
-------
IC activity = CG activity
10
'l + —
30
-1
where;
( = latitude of the study area in degrees
References For Section 14.3
1. J. F. Noxon, "Atmospheric Nitrogen Fixation By Lightning", Geophysical Research Letters,
5:463-465, 1976.
2. J. S. Levine, et al., "Tropospheric Sources Of NOx Lightning And Biology", Atmospheric
Environment, 18(9): 1797-1804, 1984.
3. E. Franzblau and C. J. Popp, "Nitrogen Oxides Produced From Lightning", Journal Of
Geophysical Research, 94(D8): 11,089-11,104, 1989.
4. J. A. Logan, "Nitrogen Oxides In The Troposphere: Global And Regional Budgets", Journal
Of Geophysical Research, S8CC15): 10,785-10,807, 1983.
5. W. J. Borucki and W. L. Chameides, "Lightning: Estimates Of The Rates Of Energy
Dissipation And Nitrogen Fixation", Reviews Of Geophysics And Space Physics,
22(4):363-372, 1984.
6. R. D. Hill, et al., "Nitrous Oxide Production By Lightning", Journal Of Geophysical
Research, 89(D1): 1411-1421, 1984.
7. D. K. Brandvold and P. Martinez, "The NOx/NzO Fixation Ration From Electrical
Discharges", Atmospheric Environment, 22(11):2,477-2,480, 1988.
8. R. Orville, et al., "An East Coast Lightning Detection Network", Bulletin Of The American
Meteorological Society, <54:1024, 1983.
9. T. E. Pierce and J. H. Novak, Estimating Natural Emissions for EPA's Regional Oxidant
Model, presented at the EPA/AWMA International Specialty Conference on Emission
Inventory Issues in the 1990s, Durham, N.C., 1991.
14.3-2
EMISSION FACTORS
9/96
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TECHNICAL REPORT DATA
1. REPORT NO. 2.
AP-42, Fifth Edition
3
4. TITLE AND SUBTITLE
Supplement B To
Compilation Of Air Pollutant Emission Factors,
Volume I: Stationary Point And Area Sources
5. REPORT DATE
November 1996
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
9 PERFORMING ORGANIZATION NAME AND ADDRESS
Emission Factor And Inventory Group, EMAD (MD 14)
Office Of Air Quality Planning And Standards
U. S. Environmental Protection Agency
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 document contains emission factors and process information for more than 200 air pollution source categories.
These emission factors have been compiled from source test data, material balance studies, and engineering estimates, and
they can be used judiciously in making emission estimations for various purposes. When specific source test data are
available, they should be preferred over the generalized factors presented in this document.
This Supplement to AP-42 addresses pollutant-generating activity from 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, Stationary Gas Turbines For Electricity
Generation, Heavy-duty Natural Gas-fired Pipeline Compressor Engines And Turbines, Gasoline And Diesel Industrial
Engines, Large Stationary Diesel And All Stationary Dual-fuel Engines, Adipic Acid, Cotton Ginning, Alfalfa Dehydrating,
Malt Beverages, Ceramic Products Manufacturing, Electroplating, Wildfires And Prescribed Burning, Emissions From
Soils—Greenhouse Gases, Termites—Greenhouse Gases, Lightning Emissions—Greenhouse Gases
17. KEY WORDS AND DOCUMENT ANALYSIS
a DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Emission Factors Area Sources
Emission Estimation Criteria Pollutants
Stationary Sources Toxic Pollutants
Point Sources
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (Report¦)
Unclassified
21 NO OF PAGES
406
20. SECURITY CLASS (Pagt)
Unclassified
22. PRICE
EPA Form 2220-1 (R«v.' 4-77)
•it U.S. GOVERNMENT PRINTING OFFICE: 1997-527-090/SS003
PREVIOUS EDITION IS OBSOLETE
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